ARC Energy Trust announces fourth quarter and year-end 2009 results

CALGARY, Feb. 9 /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, 2009.

    
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                                   Three Months Ended     Twelve Months Ended
    For the years ended                December 31             December 31
     December 31                    2009        2008        2009        2008
    -------------------------------------------------------------------------
    FINANCIAL
    (Cdn$ millions, except per
     unit and per boe amounts)
    Revenue before royalties       278.6       300.8       978.2     1,706.4
      Per unit(1)                   1.17        1.38        4.16        7.90
      Per boe                      48.44       50.06       42.18       71.59
    Cash flow from operating
     activities(2)                 143.2       209.4       497.4       944.4
      Per unit(1)                   0.60        0.96        2.11        4.37
      Per boe                      24.90       34.85       21.45       39.62
    Net income                      65.5        82.7       222.8       533.0
      Per unit(3)                   0.28        0.38        0.96        2.50
    Distributions                   70.9       127.2       298.5       570.0
      Per unit(1)                   0.30        0.59        1.28        2.67
      Per cent of cash flow
       from operating
       activities(2)                  50          61          60          60
    Net debt outstanding(4)        902.4       961.9       902.4       961.9
    OPERATING
    Production
      Crude oil (bbl/d)           27,415      28,935      27,509      28,513
      Natural gas (mmcf/d)         189.0       195.1       194.0       196.5
      Natural gas liquids (bbl/d)  3,597       3,858       3,689       3,861
      Total (boe/d)               62,520      65,313      63,538      65,126
    Average prices
      Crude oil ($/bbl)            72.61       56.26       62.24       94.20
      Natural gas ($/mcf)           4.58        7.48        4.18        8.58
      Natural gas liquids ($/bbl)  46.12       45.22       40.67       69.71
      Oil equivalent ($/boe)       48.35       49.93       42.07       71.25
    Operating netback ($/boe)
      Commodity and other
       revenue (before hedging)    48.42       50.06       42.17       71.59
      Transportation costs         (0.92)      (0.86)      (0.89)      (0.80)
      Royalties                    (7.94)      (9.14)      (6.37)     (12.91)
      Operating costs              (9.91)     (10.09)     (10.19)     (10.13)
      Netback (before hedging)     29.65       29.97       24.72       47.75
    -------------------------------------------------------------------------
    TRUST UNITS
    (millions)
    Units outstanding, end of
     period(5)                     239.0       219.2       239.0       219.2
    Weighted average trust
     units(6)                      238.5       218.3       235.4       216.0
    -------------------------------------------------------------------------
    TRUST UNIT TRADING STATISTICS
    (Cdn$, except volumes) based
     on intra-day trading
    High                           21.89       22.55       21.89       33.95
    Low                            19.06       15.01       11.73       15.01
    Close                          19.94       20.10       19.94       20.10
    Average daily volume
     (thousands)                     963       1,523       1,057         975
    -------------------------------------------------------------------------
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    (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 2009 would be $156 million
        ($0.65 per unit) and for the full year 2009 would be $518 million
        ($2.20 per unit). Distributions as a percentage of Cash Flow would be
        58 per cent in 2009.
    (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) For 2009, includes 0.9 million (1.1 million in 2008) exchangeable
        shares exchangeable into 2.720 trust units (2.517 in 2008) each for
        an aggregate 2.4 million (2.7 million in 2008) trust units.
    (6) Includes trust units issuable for outstanding exchangeable shares at
        period end.

    ACCOMPLISHMENTS / FINANCIAL UPDATE

    -   ARC replaced 347 per cent of annual production at an all-in annual
        Finding, Development and Acquisition ("FD&A") cost of $6.44 per
        barrel of oil equivalent ("boe") before consideration of future
        development capital ("FDC") for the proved plus probable reserves
        category. This is the third consecutive year of reducing FD&A costs
        and brings ARC's three year average FD&A prior to FDC down to $9.57
        per boe. FD&A costs including FDC were $11.57 per boe, a 32 per cent
        reduction from the $17 per boe achieved in 2008. Additional
        information on the reserves evaluation can be found in the "ARC
        Energy Trust Releases 2009 Year-end Reserves Information" news
        release dated February 9, 2010 and filed on SEDAR at www.sedar.com.

    -   During the fourth quarter, ARC completed an acquisition for $180
        million in cash consideration, prior to normal closing adjustments,
        of a partnership owning properties in the Ante Creek area. The
        acquisition consisted of producing wells with production of
        approximately 2,000 boe per day and undeveloped land holdings. The
        acquisition closed on December 21, 2009 therefore the financial
        results from the properties have been included in Consolidated
        Financial Statements from that date.

    -   Concurrent with the Ante Creek acquisition, ARC entered into a bought
        deal financing agreement to issue 13 million trust units at $19.40
        per trust unit to raise gross proceeds of approximately $252 million
        and net proceeds of approximately $240 million. The net proceeds of
        the offering were received on January 5, 2010 and were used to reduce
        the outstanding indebtedness of ARC by $240 million.

    -   Production volumes for 2009 averaged 63,538 boe per day, a 2.4 per
        cent decline compared to 2008 production of 65,126 boe per day. This
        decline was due to ARC's reduction of its 2009 capital expenditures
        in response to declining commodity prices. The Trust expects 2010
        full year average production to increase by approximately 13 per cent
        to between 70,500 and 72,500 boe per day with the anticipated start-
        up of a company-owned gas plant in the Dawson area in the second
        quarter of 2010 and a full year of production from the December 2009
        acquisition in Ante Creek.

    -   Cash flow from operating activities for the full year of 2009 was
        $497.4 million, or $2.11 per unit, a significant decline from the
        $944.4 million ($4.37 per unit) achieved in fiscal 2008. This decline
        was primarily due to a 41 per cent decrease in commodity prices in
        2009 compared to 2008. Crude oil prices strengthened in the second
        half of 2009 as the economy showed some positive signs of recovery.
        Natural gas prices remained soft throughout most of 2009 prior to
        recovering somewhat late in the fourth quarter of 2009 ending the
        year at $5.70 per mcf. After payment of distributions the Trust was
        able to fund 54 per cent of the 2009 capital program with cash flow
        from operating activities (73 per cent when including the proceeds
        from the distributions re-investment program ("DRIP")) with the
        remaining portion funded through debt and working capital.

    -   The Trust executed a $359.6 million capital expenditure program in
        2009 that included the purchase of undeveloped land for $7 million
        and $352.6 million of exploration and development activities. A total
        of 120 net wells were drilled on ARC's operated properties with a 99
        per cent success rate. Included in these capital expenditures is $8.1
        million of Alberta Government royalty drilling credits and $3.1
        million for British Columbia summer drilling credits. Without these
        credits, total capital expenditures would have been $370.8 million.

    -   ARC's Board of Directors has approved a $610 million capital program
        for 2010 that will deliver considerable growth. The program will
        include over $264 million slated for the first of many stages of
        production growth and expansion of the Montney assets in Northeast
        British Columbia. Other major resource play development will take
        place at Ante Creek where $72 million has been allocated to drill 14
        horizontal wells and expand facilities and at Pembina where $54
        million will be spent to drill 16 horizontal wells and 16 vertical
        wells targeting the Cardium formation on operated lands. The
        remainder of the budget will focus on ARC's base development areas,
        exploration opportunities and enhanced oil recovery projects. In
        total, ARC plans to drill 211 gross wells on operated properties and
        participate in an additional 91 wells on partner operated properties.
        ARC plans to finance the 2010 capital program through a combination
        of cash flow, existing credit facilities, DRIP proceeds and potential
        minor asset disposition proceeds.

    -   On December 31, 2009, ARC's long-term debt was $846 million. After
        the closing of the equity offering on January 5, 2010, long-term debt
        was reduced to $606 million leaving ARC with approximately $710
        million of unused credit lines. With the current debt level, net debt
        to 2009 cash flow from operating activities is 1.2 times. At current
        forward prices for commodities, ARC is well positioned to finance the
        projected 2010 capital program of $610 million and payout $0.10 per
        trust unit per month of distributions while keeping debt at a very
        manageable level.

    -   ARC has hedged approximately 43,000 mcf per day of natural gas for
        the period of July 1, 2011 to December 31, 2013 at an average price
        of $6.40 per mcf to protect the economics on the ARC owned gas plant
        being constructed at Dawson. Overall, commodity price volatility
        protection has been established for the 2010 capital budget by
        hedging 34 per cent of forecast natural gas volumes at an average
        swap price of $5.85 per mcf and 32 per cent of forecast crude oil
        volumes at an average floor price of US$74.67 per barrel.

    -   ARC plans to convert to a dividend paying corporation effective
        January 1, 2011. The Board of Directors has approved the overall
        strategy and currently the detailed implementation steps are being
        defined. The conversion plans will be mailed to unitholders with a
        unitholder meeting planned for December of 2010. Current plans would
        see a dividend policy similar to the existing distribution policy
        with dividends being paid monthly.

    -   Montney Resource Play Development

        Production from the Dawson area was on budget at an average rate of
        53.6 mmcf per day throughout the fourth quarter and exited the year
        at 59.2 mmcf per day.

        During the fourth quarter of 2009, ARC spent $70.8 million on
        development activities in the Dawson area including drilling seven
        horizontal wells, two of which were completed during the quarter. ARC
        tested six horizontal Dawson wells during the quarter at rates
        between five and nine mmcf per day of natural gas at a flowing
        pressure of 1,200 to 2,200 pounds per square inch. Included in the
        fourth quarter spending is $27.8 million for the Dawson Phase 1 60
        mmcf per day gas plant discussed below.

        For the full year of 2009, ARC drilled 22 horizontal wells in the
        Dawson gas fields that are in various stages of completion. Of
        these wells, eight were on production by year-end, nine wells are in
        the completed and waiting on tie-in category and the remaining five
        wells will be completed early in 2010.

        ARC is participating in a small development project on partner
        operated lands at Sunrise. Four wells have been drilled and
        completed. Production commenced at the end of the fourth quarter and
        is currently producing at approximately 10 mmcf per day net to ARC's
        50 per cent working interest.

        The British Columbia Oil and Gas Commission ("OGC") issued final
        approval for the 60 mmcf per day Dawson Phase 1 gas plant on November
        13, 2009 at which time all on-site construction began. As of January
        31, 2010, the mechanical construction of the plant was approximately
        70 per cent complete and the electrical work was underway. ARC
        expects to complete construction of the plant in early April, with
        start-up commissioning of the plant occurring during the rest of the
        month. Sales gas is expected to be flowing from the plant by early
        May. To date, ARC has spent $57.6 million on the gas plant with an
        additional $5.7 million expected to be spent in 2010 prior to the
        commissioning. ARC is already well underway with plans to build a
        second 60 mmcf per day gas plant at the same location. All long-lead
        time equipment has been ordered and the application to construct the
        plant is being prepared.

    -   Enhanced Oil Recovery Initiatives

        During 2009, ARC spent $25.7 million on enhanced oil recovery ("EOR")
        initiatives and received $2.8 million in government funding for the
        Redwater pilot project for net spending of $22.9 million. Work on the
        Redwater CO(2) pilot project continues and both the CO(2) injection
        and oil production facilities are operating as expected. Results to
        date are encouraging but ARC anticipates that it will take until
        later in 2010 to determine to what extent the pilot has been
        successful in mobilizing incremental volumes of oil. While the pilot
        project may indicate enhanced recovery, the outlook for crude oil
        prices and the cost and availability of CO(2) will be determining
        factors in ARC's ability to achieve commercial viability for a full
        scale EOR scheme at Redwater.
    

MANAGEMENT'S DISCUSSION AND ANALYSIS

This management's discussion and analysis ("MD&A") is ARC management's analysis of its financial performance and significant trends or external factors that may affect future performance. The MD&A is dated February 8, 2010 and should be read in conjunction with the audited Consolidated Financial Statements as at and for the year ended December 31 2009, the MD&A and the audited Consolidated Financial Statements as at and for the year ended December 31, 2008, the MD&A and the unaudited Consolidated Financial Statements for the periods ended March 31, 2009, June 30, 2009 and September 30, 2009 as well as ARC'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 ARC's disclosure under "Non-GAAP Measures" and "Forward-Looking Statements" included at the end of this MD&A.

Executive Overview

ARC Energy Trust ("ARC") or ("the Trust") is an actively managed oil and natural gas entity formed to provide investors with indirect ownership in cash generating energy assets, that currently consist of oil and natural gas assets. The major operating activities of ARC are the development, production and sale of crude oil, natural gas liquids and natural gas.

ARC's main objective is value creation through the development of large oil and natural gas pools. The business strategy and activities that support this objective are:

    
    Resource Plays
    --------------

    -   Acquisition and development of land and producing properties with
        large volumes of oil and gas in place, such as the Montney
        development in Dawson in northeastern British Columbia, Ante Creek in
        northern Alberta and the Cardium formation at Pembina in central
        Alberta.

    Conventional Oil & Gas Production
    ---------------------------------

    -   Maximizing production while controlling operating costs on oil and
        gas wells located within ARC's seven core producing areas all of
        which are located in western Canada. ARC's total production in 2009
        was almost evenly split between commodities with 51 per cent of
        production from natural gas and 49 per cent from oil and gas liquids.
        Conventional oil and gas properties continue to be developed to
        increase the recoverable reserves through development drilling,
        optimization and waterflood programs. Within ARC's core areas many
        properties would be considered "resource plays" due to the
        substantial reserves still in place and the advancement of proved
        horizontal drilling and multi-stage fracture stimulation technology
        to develop these reserves.

    -   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.

    Enhanced Oil Recovery ("EOR")
    -----------------------------

    -   Evaluation and implementation of enhanced oil recovery programs to
        increase ARC's recoverable reserves in existing oil pools. ARC has a
        non-operated interest in the Weyburn and Midale units in
        Saskatchewan. Operators of both these units have implemented CO(2)
        injection programs to increase recoverable oil reserves. In 2008 ARC
        advanced this strategy of enhanced oil recovery with the initiation
        of a CO(2) pilot program at Redwater.
    

ARC's goal is to provide superior long-term returns to unitholders. ARC's structure provides returns to unitholders through both the receipt of monthly cash distributions and the potential for capital appreciation.

Currently, ARC distributes $0.10 per unit per month. The remainder of the cash flow is used to fund reclamation costs, and a portion of capital expenditures. In 2009 cash flow and proceeds from the DRIP program funded $194.3 million of capital expenditures and a net contribution of $4.6 million to the reclamation funds. Since ARC's inception in July 1996 to December 31, 2009, ARC has distributed $3.5 billion or $24.98 per unit.

Capital appreciation for ARC's unitholders would be associated with increased market values for ARC's production and reserves. ARC's management strives to replace or grow both 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. ARC continues to focus on major properties with significant upside, with the objective to replace production declines through internal development opportunities. ARC's normalized reserves per unit have increased by 10 per cent to 1.57 per unit from 1.42 per unit in 2008 while production per thousand trust units decreased slightly from 0.29 to 0.27. Since year-end 2007, ARC has increased normalized reserves per unit by 16 per cent, and normalized production per thousand trust units has declined by 10 per cent while ARC has made distributions of $3.95 per unit or $868.5 million. Details of the calculations for normalized production and reserves per unit are provided in Table 1.

    
    Table 1
    -------------------------------------------------------------------------
    Per Trust Unit                              2009        2008        2007
    -------------------------------------------------------------------------
    Normalized production per unit(1)(2)        0.27        0.29        0.30
    Normalized reserves per unit(1)(3)          1.57        1.42        1.35
    Distributions per unit                     $1.28       $2.67       $2.40
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Normalized indicates that all periods 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 per unit values.
    (2) Production per unit represents daily average production (boe) per
        thousand trust units and is 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), as determined by ARC's independent reserve evaluator
        at period end, divided by period end trust units outstanding
        including trust units issuable for exchangeable shares.
    

ARC's business plan has resulted in significant operational success as seen in Table 2 where ARC's trailing five year annualized return per unit was 12.4 per cent.

    
    Table 2
    -------------------------------------------------------------------------
    Total Returns(1)
    ($ per unit except for                  Trailing    Trailing    Trailing
     per cent)                              One Year  Three Year   Five Year
    -------------------------------------------------------------------------
    Distributions per unit                      1.28        6.35       10.74
    Capital (depreciation) appreciation
     per unit                                  (0.16)      (2.36)       2.04
    Total return per unit                       6.9%       20.0%       79.5%
    Annualized total return per unit            6.9%        6.3%       12.4%
    S&P/TSX Capped Energy Trust Index          43.5%        2.5%        9.1%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Calculated as at December 31, 2009.

    Financial Highlights for the year-ended December 31, 2009

    Table 3
    -------------------------------------------------------------------------
    (Cdn $ millions, except
     per unit and volume data)                  2009        2008    % Change
    -------------------------------------------------------------------------
    Cash flow from operating activities        497.4       944.4         (47)
    Cash flow from operating activities
     per unit(1)                                2.11        4.37         (52)
    Net income                                 222.8       533.0         (58)
    Net income per unit(2)                      0.96        2.50         (62)
    Distributions per unit(3)                   1.28        2.67         (52)
    Distributions as a per cent of cash
     flow from operating activities               60          60           -
    Average daily production (boe/d)(4)       63,538      65,126          (2)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Per unit amounts are based on weighted average trust units
        outstanding plus trust units issuable for exchangeable shares at
        period 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 distribution
        record 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.
    

2009 Guidance and Financial Highlights

Table 4 is a summary of ARC's 2009 and 2010 Guidance and a review of 2009 actual results compared to guidance.

    
    Table 4
    -------------------------------------------------------------------------
                                    2009        2009                    2010
                                Guidance      Actual  % Variance    Guidance
    -------------------------------------------------------------------------
    Production (boe/d)           63,000-      63,538           -     70,500-
                                  64,000                              72,500
    -------------------------------------------------------------------------
    Expenses ($/boe):
      Operating costs              10.50       10.19          (3)      10.30
      Transportation                0.90        0.89          (1)       1.00
      G&A expenses (cash &
       non-cash)(1)                 2.10        2.26           8        2.85
      Interest                      1.30        1.11         (15)       1.40
    Capital expenditures
     ($ millions)                    365         360          (1)        610
    Annual weighted average
     trust units and trust
     units issuable (millions)(2)    238         235          (1)        254
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) 2009 G&A guidance amount of $2.10 per boe included $1.75 per boe for
        cash G&A costs, $0.55 per boe for cash Whole Unit Plan costs and a
        recovery of $0.20 per boe for the non-cash portion of the Whole Unit
        Plan. 2010 G&A guidance amount of $2.85 per boe includes $2 per
        boe for cash G&A costs, $0.90 per boe for cash Whole Unit Plan costs
        and a recovery of $0.05 per boe for the non-cash portion of the Whole
        Unit Plan.
    (2) 2010 Annual weighted average trust units has been revised to reflect
        the increase in the equity offering that closed in January 2010 from
        10.1 million to 13 million units.
    

Actual results for 2009 are in-line with guidance amounts with the exception of the following:

G&A expenses - total cash G&A costs were $0.04 per boe below guidance however actual non-cash Whole Unit Plan costs were nil for the year whereas the guidance amount was estimating a recovery of $0.20 per boe. The difference is due to ARC's December 31, 2009 closing trust unit price that was higher than the amount estimated when calculating the original guidance amount.

Interest expense - was below guidance for the full year of 2009 due to ARC's ability to cash fund more capital expenditures in the last half of 2009 with the uplift in commodity prices, therefore drawing less funds from debt and saving on interest expense.

The 2010 Guidance provides unitholders with information on management's expectations for results of operations, excluding any acquisitions or dispositions for 2010. Readers are cautioned that the 2010 Guidance may not be appropriate for other purposes.

Cash Flow from Operating Activities

Cash flow from operating activities decreased by 47 per cent in 2009 to $497.4 million from $944.4 million in 2008. Decreases in crown royalties and a cash gain on risk management contracts were more than offset by the 41 per cent ($29.18 per boe) decrease in commodity prices relative to the full year of 2008 as well as a two per cent decrease in volumes during the period. The decrease in 2009 cash flow from operating activities is detailed in Table 5.

    
    Table 5
    -------------------------------------------------------------------------
                                                         ($ per
                                         ($ millions) trust unit)  (% Change)
    -------------------------------------------------------------------------
    2008 Cash flow from Operating
     Activities                                944.4        4.37           -
    -------------------------------------------------------------------------
    Volume variance                            (46.2)      (0.21)         (5)
    Price variance                            (682.0)      (3.15)        (72)
    Cash (losses) and gains on risk
     management contracts                       95.1        0.44          10
    Royalties                                  159.9        0.74          17
    Expenses:
      Transportation                            (1.6)      (0.01)       (0.2)
      Operating(1)                               6.1        0.03         0.6
      Cash G&A                                   7.7        0.04         0.8
      Interest                                   7.2        0.03         0.8
      Taxes                                     (0.3)          -           -
      Realized foreign exchange loss             1.9        0.01         0.2
    Weighted average trust units                   -       (0.22)          -
    Non-cash and other items(2)                  5.2        0.02           -
    -------------------------------------------------------------------------
    2009 Cash flow from Operating
     Activities                                497.4        2.09           -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Excludes non-cash portion of Whole Unit Plan expense recorded in
        operating costs.
    (2) Includes the changes in non-cash working capital and expenditures on
        site restoration and reclamation.
    

2010 Cash Flow from Operating Activities Sensitivity

Table 6 illustrates sensitivities to pre-hedged operating income items with operational changes and changes to the business environment and the resulting impact on cash flows from operating activities in total and per trust unit:

    
    Table 6
    -------------------------------------------------------------------------
                                                       Impact on Annual Cash
                                                        flow from operating
                                                            activities(4)
    Business Environment(1)               Assumption      Change      $/Unit
    -------------------------------------------------------------------------
    Oil price (US$WTI/bbl)(2)(3)           $   75.00   $    1.00   $    0.04
    Natural gas price (Cdn$AECO/mcf)(2)(3) $    5.50   $    0.10   $    0.03
    Cdn$/US$ exchange rate(2)(3)(5)             1.05   $    0.01   $    0.03
    Interest rate on debt(2)               %    4.00   %     1.0   $    0.01
    Operational
    Liquids production volume (bbl/d)         31,500   %     1.0   $    0.03
    Gas production volumes (mmcf/d)            240.0   %     1.0   $    0.01
    Operating expenses per boe             $   10.30   %     1.0   $    0.01
    Cash G&A and LTIP expenses per boe     $    2.85   %    10.0   $    0.03
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Calculations are performed independently and may not be indicative of
        actual results that would occur when multiple variables change at the
        same time.
    (2) Prices and rates are indicative of published forward prices and rates
        at the time of this MD&A. The calculated impact on annual cash flow
        from operating activities would only be applicable within a limited
        range of these amounts.
    (3) Analysis does not include the effect of hedging contracts.
    (4) Assumes constant working capital.
    (5) Includes impact of foreign exchange on crude oil prices that are
        presented in U.S. dollars. This amount does not include a foreign
        exchange impact relating to natural gas prices as they are presented
        in Canadian dollars in this sensitivity.
    

Net Income

Net income in 2009 was $222.8 million ($0.96 per unit), a decrease of $310.2 million from $533 million ($2.50 per unit) in 2008. Net income for 2009 reflects the lower commodity price environment in the current year and includes certain non-cash items that served to increase net income in the current year.

In 2009, ARC recorded a $69 million non-cash foreign exchange gain on U.S. denominated debt ($60.4 million net of future income taxes) as compared to a non-cash loss of $88.5 million ($77.4 million net of future income taxes) recorded for the same period in 2008.

In 2009, ARC recorded a $1.7 million net cash recovery for non-recoverable accounts receivable ($1.3 million net of future income taxes) as compared to a $32 million ($24 million net of future income taxes) non-cash expense for non-recoverable amounts recorded in 2008.

The above amounts were offset by a $7.7 million ($5.8 million net of future income taxes) non-cash loss on unrealized risk management contracts recorded in 2009 as compared to a $68 million ($51 million net of future income taxes) non-cash unrealized gain recorded for the same period in 2008.

Production

Production volumes averaged 63,538 boe per day in 2009 compared to 65,126 boe per day in 2008 as detailed in Table 7. The decrease in 2009 production is a result of the reduction of the capital expenditure program.

    
    Table 7
    -------------------------------------------------------------------------
    Production                                  2009        2008    % Change
    -------------------------------------------------------------------------
    Light & medium crude oil (bbl/d)          26,423      27,239          (3)
    Heavy oil (bbl/d)                          1,086       1,274         (15)
    Natural gas (mmcf/d)                       194.0       196.5          (1)
    NGL (bbl/d)                                3,689       3,861          (4)
    -------------------------------------------------------------------------
    Total production (boe/d)(1)               63,538      65,126          (2)
    % Natural gas production                      51          50           2
    % Crude oil and liquids production            49          50          (2)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Reported production for a period may include minor adjustments from
        previous production periods.
    

Light and medium crude oil production decreased to 26,423 boe per day compared to 27,239 boe per day in 2008, while heavy oil production declined by 188 boe per day. Compared to 2008, the total crude oil production is down approximately 1,000 barrels per day. Natural gas production was 194 mmcf per day in 2009, a decrease of one per cent from the 196.5 mmcf per day produced in 2008. This slight decline was primarily due to plant turnarounds completed at third party facilities that shut-in gas production.

ARC's objective is to maintain annual production through the drilling of wells and other development activities to the full extent possible, while giving consideration to capital spending constraints and the economics of developing ARC's resources. In fulfilling this objective, there may be fluctuations in production depending on the timing of new wells coming on-stream. During 2009, ARC drilled 145 gross wells (120 net wells) on operated properties; 37 gross oil wells, and 108 gross natural gas wells with a 99 per cent success rate.

ARC expects that 2010 full year production will average approximately 70,500 to 72,500 boe per day and that a total of 211 gross wells (195 net) will be drilled by ARC on operated properties with participation in an additional 91 gross wells (18 net) to be drilled on ARC's non-operated properties. ARC estimates that the 2010 drilling program and the start-up of a new gas plant in the Dawson area will increase production in 2010 by 11 per cent to 14 per cent over 2009 production levels. The planned capital expenditures for 2010 have been increased to approximately $610 million from actual expenditures of $360 million in 2009, which were scaled back from an original 2009 planned budget of $585 million due to the significant decline in commodity prices.

Table 8 summarizes ARC's production by core area:

    
    Table 8
    -------------------------------------------------------------------------
                                                     2009
    Production                     Total         Oil         Gas         NGL
    Core Area(1)                  (boe/d)     (bbl/d)    (mmcf/d)     (bbl/d)
    -------------------------------------------------------------------------
    Central AB                     6,984       1,279        27.7       1,083
    N.E. BC & N.W. AB             13,794         715        74.4         672
    Northern AB                    9,004       4,096        24.5         821
    Pembina & Redwater            13,560       9,412        19.0         978
    S.E. AB & S.W. Sask.           8,841       1,027        46.9          13
    S.E. Sask. & MB               11,357      10,980         1.5         122
    -------------------------------------------------------------------------
    Total                         63,538      27,509       194.0       3,689
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
                                                     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
    N.E. BC & N.W. AB             12,678         802        67.6         613
    Northern AB                    9,791       4,516        26.1         921
    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
    -------------------------------------------------------------------------
    (1) Provincial references: AB is Alberta, BC is British Columbia, Sask.
        is Saskatchewan, MB is Manitoba, N.E. is northeast, N.W. is
        northwest, S.E. is southeast and S.W. is southwest.
    

Revenue

Revenue decreased to $978.2 million in 2009, $728.2 million lower than 2008 revenues of $1.7 billion. The decrease in realized oil prices accounted for $333.5 million of the $358.1 million decline in oil revenue with only $24.6 million of the decrease attributable to lower oil volumes. Natural gas revenue decreased by $320.8 million of which $316.5 million was attributable to decreased realized prices with the balance of $4.3 million attributed to lower natural gas volumes in 2009.

A breakdown of revenue is outlined in Table 9:

    
    Table 9
    -------------------------------------------------------------------------
    Revenue
    ($ millions)                                2009        2008    % Change
    -------------------------------------------------------------------------
    Oil revenue                                625.0       983.1         (36)
    Natural gas revenue                        296.0       616.8         (52)
    NGL revenue                                 54.8        98.5         (44)
    -------------------------------------------------------------------------
    Total commodity revenue                    975.8     1,698.4         (43)
    Other revenue                                2.4         8.0         (70)
    Total revenue                              978.2     1,706.4         (43)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

Commodity Prices Prior to Hedging

    
    Table 10
    -------------------------------------------------------------------------
                                                2009        2008    % Change
    -------------------------------------------------------------------------
    Average Benchmark Prices
    AECO gas ($/mcf)(1)                         4.13        8.13         (49)
    WTI oil (US$/bbl)(2)                       61.93       99.66         (38)
    Cdn$ / US$ foreign exchange rate            1.13        1.05           8
    WTI oil (Cdn$/bbl)                         69.70      104.30         (33)
    -------------------------------------------------------------------------
    ARC Realized Prices Prior to Hedging
    Oil ($/bbl)                                62.24       94.20         (34)
    Natural gas ($/mcf)                         4.18        8.58         (51)
    NGL ($/bbl)                                40.67       69.71         (42)
    -------------------------------------------------------------------------
    Total commodity revenue before
     hedging ($/boe)                           42.07       71.25         (41)
    Other revenue ($/boe)                       0.11        0.34         (68)
    Total revenue before hedging ($/boe)       42.18       71.59         (41)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Represents the AECO monthly posting.
    (2) WTI represents posting price of West Texas Intermediate oil.
    

Oil prices continued to recover in the second half of 2009 with US$WTI prices averaging $76.17 per bbl in the fourth quarter, and $68.29 per bbl in the third quarter compared to $51.46 per bbl for the first half of 2009. Despite this recovery, prices for oil on average in 2009 were down 38 per cent compared to 2008 as detailed in Table 10. ARC's oil production consists predominantly of light and medium crude oil while heavy oil accounts for less than five per cent of ARC's crude oil production. The realized price for ARC's oil, before hedging, was $62.24 per bbl, a 34 per cent reduction over the 2008 realized price of $94.20 per bbl.

Natural gas prices softened throughout 2009 with a strengthening in the fourth quarter. Alberta AECO Hub natural gas prices, which are commonly used as an industry reference, averaged $4.13 per mcf in 2009 compared to $8.13 per mcf in 2008. ARC's realized gas price, before hedging, decreased by 51 per cent to $4.18 per mcf compared to $8.58 per mcf throughout 2008. ARC's realized gas price is based on prices received at the various markets in which ARC 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. Natural gas prices started to recover in the fourth quarter of 2009 with posted prices in the month of December registering over $5 per mcf. In addition, the forward curve for natural gas prices has strengthened to reflect 2010 prices of approximately $6 per mcf. Management is pursuing strategic initiatives to capitalize on strengthening forward prices, where possible in order to protect the economics of the 2010 capital program.

Prior to hedging activities, ARC's total realized commodity price was $42.17 per boe in 2009, a 41 per cent decrease from the $71.59 per boe in 2008.

Risk Management and Hedging Activities

ARC maintains an ongoing risk management program to reduce the volatility of revenues in order to increase the certainty of cash flows, and to protect acquisition and capital expenditures economics.

Gain or loss on risk management contracts comprise realized and unrealized gains or losses on contracts that do not meet the accounting definition requirements of an effective hedge, even though ARC 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 Consolidated Statements of Income and Deficit.

Lower natural gas prices in 2009 resulted in realized cash gains of $28.5 million on natural gas risk management contracts as ARC's contracted prices were higher than market prices during the year. Realized cash losses of $14.8 million were recorded on ARC's crude oil risk management contracts as a result of premiums paid during 2009, and small losses recorded on ARC's fixed price swap contracts where the market oil price rose above the contracted price. In addition, ARC realized a $4.8 million cash gain on interest rate risk management contracts.

ARC's 2009 results include an unrealized total mark-to-market loss of $7.7 million with a net unrealized mark-to-market loss position of $4.8 million as at December 31, 2009. The mark-to-market values represent the market price to buy-out ARC's contracts as of December 31, 2009 and may differ from what will eventually be realized.

Table 11 summarizes the total gain (loss) on risk management contracts for the year-over-year change as of the 2009 year-end:

    
    Table 11
    -------------------------------------------------------------------------
    Risk Management    Crude         Foreign
     Contracts         Oil &  Natural   Curr-          Inter-   2009    2008
    ($ millions)     Liquids     Gas    ency  Power(3)   est   Total   Total
    -------------------------------------------------------------------------
    Realized cash
     (loss) gain on
      contracts(1)     (14.8)   28.5     2.0    (1.1)    4.8    19.4   (75.7)
    Unrealized gain
     (loss) on
     contracts(2)        5.0    (2.5)      -    (4.8)   (5.4)   (7.7)   68.0
    -------------------------------------------------------------------------
    Total (loss) gain
     on risk management
     contracts          (9.8)   26.0     2.0    (5.9)   (0.6)   11.7    (7.7)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Realized cash gains and losses represent actual cash settlements or
        receipts under the respective contracts.
    (2) The unrealized gain (loss) on contracts represents the change in fair
        value of the contracts during the period.
    (3) Amounts presented in Table 11 exclude a $1.5 million realized loss
        and an unrealized loss of $3.8 million for ARC's power contracts that
        have been designated as effective hedges for accounting purposes.
        Realized gains and losses on these contracts are recorded in
        operating costs and unrealized gains and losses are recorded in the
        Consolidated Statement of Comprehensive Income and Accumulated Other
        Comprehensive Income.
    

ARC currently limits the amount of forecast production that can be hedged to a maximum 50 per cent with the balance of production being sold at market prices. In addition, project specific hedges may be entered into from time to time to protect the economics of certain capital expenditures. Table 12 is an indicative summary of ARC's positions for crude oil and natural gas as at December 31, 2009.

    
    Table 12
    -------------------------------------------------------------------------
    Hedge Positions
    As at December 31,
     2009(1)(2)                         Q1 2010                Q2 2010
    -------------------------------------------------------------------------
    Crude Oil                    US$/bbl     bbl/day     US$/bbl     bbl/day
    -------------------------------------------------------------------------
    Sold Call                      95.36       9,000       96.81       8,000
    Bought Put                     76.17       9,000       77.19       8,000
    Sold Put                       62.80       2,000       62.80       2,000
    -------------------------------------------------------------------------
    Natural Gas                 Cdn$/mcf     mcf/day    Cdn$/mcf     mcf/day
    -------------------------------------------------------------------------
    Sold Call                       5.92      75,825        5.77      95,825
    Bought Put                      5.92      75,825        5.77      95,825
    Sold Put                           -           -           -           -
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
    Hedge Positions
    As at December 31,
     2009(1)(2)                         Q3 2010(3)             Q4 2010
    -------------------------------------------------------------------------
    Crude Oil                    US$/bbl     bbl/day     US$/bbl     bbl/day
    -------------------------------------------------------------------------
    Sold Call                      96.81       8,000       96.81       8,000
    Bought Put                     77.19       8,000       77.19       8,000
    Sold Put                       62.80       2,000       62.80       2,000
    -------------------------------------------------------------------------
    Natural Gas                 Cdn$/mcf     mcf/day    Cdn$/mcf     mcf/day
    -------------------------------------------------------------------------
    Sold Call                       5.77      95,825        5.92      75,825
    Bought Put                      5.77      95,825        5.92      75,825
    Sold Put                           -           -           -           -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) The prices and volumes noted above represent averages for several
        contracts and the average price for the portfolio of options listed
        above does not have the same payoff profile as the individual option
        contracts. Viewing the average price of a group of options is purely
        for indicative purposes. The natural gas price shown translates all
        NYMEX positions to an AECO equivalent price.
    (2) In addition to positions shown here, ARC has entered into additional
        basis positions until October 2012. Please refer to note 13 in the
        Notes to the Consolidated Financial Statements for full details of
        ARC's risk management positions as of December 31, 2009.
    (3) During the last half of 2009, ARC took advantage of favorable forward
        curve pricing for natural gas and entered into a long-term contract
        for a small portion of future forecast production. In addition to
        contracts listed above, ARC has entered into fixed price swaps
        starting in 2011 and ending in December 2013 at an average price of
        $6.40 per mcf for 42,654 mcf per day.
    

Table 12 should be interpreted as follows using the first quarter 2010 crude oil hedges as an example. To accurately analyze ARC's hedge position, contracts need to be modeled separately as using average prices and volumes may be misleading.

    
    -   If the market price is below $62.80, ARC will receive $76.17 less the
        difference between $62.80 and the market price on 2,000 bbl per day.
        For example, if the market price is $62.75, ARC will receive $76.12
        on 2,000 bbl per day.
    -   If the market price is between $62.80 and $76.17, ARC will receive
        $76.17 on 9,000 bbl per day.
    -   If the market price is between $76.17 and $95.36, ARC will receive
        the market price on 9,000 bbl per day.
    -   If the market price exceeds $95.36, ARC will receive $95.36 on 9,000
        bbl per day.
    

Operating Netbacks

ARC's operating netback, before realized hedging gains and losses, decreased 48 per cent to $24.72 per boe in 2009 compared to $47.75 per boe in 2008. The decrease in netbacks is due mainly to reduced commodity prices partially offset by the corresponding reduction in royalties in the period.

ARC's 2009 netback, after realized hedging gains and losses, was $25.26 per boe, a 43 per cent decrease from 2008. The 2009 netback includes net gains recorded on ARC's crude oil and natural gas risk management contracts during 2009 of $0.54 per boe compared to a net loss of $3.17 per boe recorded for the same period in 2008.

The components of operating netbacks are summarized in Table 13:

    
    Table 13
    -------------------------------------------------------------------------
                               Crude   Heavy                    2009    2008
    Netbacks                     Oil     Oil     Gas     NGL   Total   Total
    ($ per boe)               ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
    -------------------------------------------------------------------------
    Weighted average sales
     price                     62.51   55.74    4.18   40.67   42.07   71.25
    Other revenue                  -       -       -       -    0.10    0.34
    -------------------------------------------------------------------------
    Total revenue              62.51   55.74    4.18   40.67   42.17   71.59
    Royalties                  (9.63)  (5.34)  (0.50) (13.03)  (6.37) (12.91)
    Transportation             (0.18)  (1.15)  (0.26)      -   (0.89)  (0.80)
    Operating costs(1)        (12.88) (12.46)  (1.33)  (7.85) (10.19) (10.13)
    -------------------------------------------------------------------------
    Netback prior to hedging   39.82   36.79    2.09   19.79   24.72   47.75
    Realized (loss) gain on
     risk management
     contracts(2)              (1.65)      -    0.40        -   0.54   (3.17)
    -------------------------------------------------------------------------
    Netback after hedging      38.17   36.79    2.49    19.79  25.26   44.58
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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.
    (2) Realized loss on risk management contracts include the settlement
        amounts for crude oil and natural gas and power contracts. Foreign
        exchange and interest contracts are excluded from the net back
        calculation.
    

Royalties as a percentage of pre-hedged commodity revenue net of transportation decreased to 15.4 per cent ($6.37 per boe) in 2009 compared to 18.2 per cent ($12.91 per boe) in 2008.

The Alberta Government's Alberta Royalty Framework ("Framework" or "ARF") took effect January 1, 2009 and provides for sliding scale crown royalty rates, whereby rates increase in high commodity price environments and decrease in low commodity price environments. The 2009 royalty rate is in line with management's expectations due to the low natural gas price environment. The recovery of crude oil prices in the second half of 2009 has resulted in higher oil crown royalty payments as compared to the first half of 2009, while natural gas crown royalty payments were low until December of 2009 when prices started to increase more significantly.

Royalty rates in the other western provinces vary due to production levels and price but to a lesser extent than Alberta royalty rates. Table 14 estimates the royalties applicable to production from ARC's properties at various price levels.

    
    Table 14
    -------------------------------------------------------------------------
                 Provincial Royalty Rates - Forecast for 2010
    -------------------------------------------------------------------------
    Edmonton posted oil (Cdn/$/bbl)(1)           $60         $80        $100
    AECO natural gas (Cdn$/mcf)(1)             $4.00       $5.50       $6.50
    -------------------------------------------------------------------------
    Alberta royalty rate                       12.6%       18.1%       22.6%
    Saskatchewan royalty rate(2)               17.9%       17.9%       17.9%
    British Columbia royalty rate(2)           17.0%       17.0%       17.0%
    Manitoba royalty rate(2)                   13.0%       13.0%       13.0%
    -------------------------------------------------------------------------
    Total Corporate Royalty Rate               14.6%       17.8%       20.4%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Canadian dollar denominated prices before quality differentials.
    (2) Royalty rate includes Crown, Freehold and Gross Override royalties
        for all jurisdictions in which ARC operates.
    

Following the implementation of the ARF, the Alberta Government introduced certain transitional rates and incentive programs to provide royalty relief to producers and in turn encourage continued drilling activity in the province. ARC is eligible for the Alberta programs assuming the necessary criteria are met and required elections are filed. The drilling credit program applies to new wells drilled between April 1, 2009 and March 31, 2011. At year-end, ARC has accrued credits of $8.1 million and estimates it will generate a maximum $16.5 million credit over the life of the program based on forward looking prices. ARC is automatically eligible for the reduced royalty rate incentive on new production for wells coming on production between April 1, 2009 and March 31, 2011. These wells will receive a crown royalty rate of five per cent subject to certain production limits.

During 2009, the British Columbia government announced a new stimulus package designed to attract investment and produce immediate economic benefits for the province. The stimulus package included royalty incentives in the form of reduced royalty rates for wells drilled in the province between September 1, 2009 and June 30, 2010, and modifications to the existing deep well drilling program to increase available credits and expand depth criteria whereby additional wells may qualify for the program. ARC estimates that the deep well drilling credits could save approximately $1 million per horizontal well drilled. These credits will be recorded as a reduction to royalty expense to the extent that royalties are incurred on the well drilled. The royalty reduction program will result in a two per cent maximum royalty rate for a period of 12 months. Management estimates that for wells that do not qualify for the drilling credit program, the reduced royalty incentive could generate savings of $1 million per well at natural gas prices of $3 per mcf to $2.5 million per well at natural gas prices of $7 per mcf. Wells that qualify for the drilling credit program must draw down the drilling credit before qualifying for the reduced royalty program. Management plans to drill 20 wells in British Columbia on operated properties during the incentive period in order to maximize the total benefit to ARC and its unitholders. New wells drilled that will qualify for the two per cent royalty incentive are expected to come on production in the third and fourth quarters of 2010.

Operating costs remained flat at $10.19 per boe compared to $10.13 per boe in 2008 with the costs associated with operating new wells brought on stream offset by lower electricity costs and cost savings and efficiency programs achieved by the operations team.

Looking ahead to 2010, ARC expects to incur full year operating costs of $10.30 per boe or approximately $270 million based on annual production of between 70,500 and 72,500 boe per day.

General and Administrative Expenses ("G&A") and Trust Unit Incentive Compensation

G&A, prior to long-term incentive payments under the Whole Unit Plan and net of overhead recoveries on operated properties, increased 4.9 per cent to $40.7 million in 2009 from $38.8 million in 2008. The modest increase in G&A expenses was primarily due to a decrease in operating recoveries of $1.4 million resulting from lower levels of capital spending during 2009.

Cash G&A in 2010 is expected to increase by approximately $10.6 million with increases in compensation and additional staff hires required to exploit our growth opportunities including the Montney, Ante Creek and Pembina assets as well as additional rent costs for the Calgary office relocation. ARC's Calgary office lease on its existing space terminates in May of 2010 and ARC has secured new space at a competitive rate on a 14 year term. ARC has committed to additional space in the new premises to accommodate future growth and expansion that will result in higher year-over-year cash G&A costs. ARC has hired an agent to sublet near-term excess space to partially offset this additional cost.

ARC paid out $16.6 million under the Whole Unit Plan in 2009 compared to $28.2 million in 2008 ($11.7 million and $21.3 million of the payouts were allocated to G&A in 2009 and 2008, respectively, and the remainder to operating costs and property, plant and equipment). The reduced payments in 2009 are a result of the decline in ARC's unit price observed throughout 2009 and specifically in March and September when cash payments were made. The next cash payment under the Whole Unit Plan is scheduled to occur in March 2010.

Table 15 is a breakdown of G&A and trust unit incentive compensation expense under the Whole Unit Plan:

    
    Table 15
    -------------------------------------------------------------------------
    G&A and Trust Unit Incentive Compensation
    Expense
    ($ millions except per boe)                 2009        2008    % Change
    -------------------------------------------------------------------------
    G&A expenses                                56.1        55.6           1
    Operating recoveries                       (15.4)      (16.8)         (8)
    -------------------------------------------------------------------------
    Cash G&A expenses before Whole Unit Plan    40.7        38.8           5
    Cash Expense - Whole Unit Plan              11.7        21.3         (45)
    -------------------------------------------------------------------------
    Cash G&A expenses including Whole
     Unit Plan                                  52.4        60.1         (13)
    Accrued compensation - Whole Unit Plan      (0.1)        1.1        (109)
    -------------------------------------------------------------------------
    Total G&A and trust unit incentive
     compensation expense                       52.3        61.2         (15)
    -------------------------------------------------------------------------
    Total G&A and trust unit incentive
     compensation expense per boe               2.26        2.57         (12)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

A non-cash Whole Unit Plan recovery ("non-cash compensation recovery") of $0.1 million ($nil per boe) was recorded in 2009 compared to an expense of $1.1 million ($0.05 per boe) in 2008. The recovery in 2009 relates to the estimated costs of the plan to December 31, 2009, offset by a reversal of the accrual for the cash payments made during the year.

Whole Unit Plan

The Whole Unit Plan is designed to offer each employee, officer and director (the "plan participants") cash compensation in relation to the value of a specified number of underlying trust units. The Whole Unit Plan consists of Restricted Trust Units ("RTUs") for which the number of units is fixed and will vest over a period of three years and Performance Trust Units ("PTUs") for which the number of units is variable and will vest at the end of three years.

Upon vesting, the plan participant is entitled to receive a cash payment based on the fair value of the underlying trust units plus accrued distributions. The cash compensation issued upon vesting of the PTUs is dependent upon the total return performance of ARC 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. A performance multiplier is applied to the PTUs based on the percentile rank of ARC's total unitholder return compared to its peers. The performance multiplier ranges from zero, if ARC's performance ranks in the bottom quartile, to two for top quartile performance.

Table 16 shows the changes to the Whole Unit Plan during the year of RTUs and PTUs outstanding:

    
    Table 16
    -------------------------------------------------------------------------
    Whole Unit Plan
    (units in thousands and $ millions     Number of   Number of  Total RTUs
     except per unit)                           RTUs        PTUs    and PTUs
    -------------------------------------------------------------------------
    Balance, beginning of period                 756         959       1,715
    Granted in the period                        703         635       1,338
    Vested in the period                        (355)       (261)       (616)
    Forfeited in the period                      (52)        (28)        (80)
    -------------------------------------------------------------------------
    Balance, end of period(1)                  1,052       1,305       2,357
    Estimated distributions to vesting date(2)   183         318         501
    -------------------------------------------------------------------------
    Estimated units upon vesting after
     distributions                             1,235       1,623       2,858
    Performance multiplier(3)                      -         1.2           -
    -------------------------------------------------------------------------
    Estimated total units upon vesting         1,235       1,996       3,231
    -------------------------------------------------------------------------
    Trust unit price at December 31, 2009      19.94       19.94       19.94
    Estimated total value upon vesting          24.6        39.8        64.4
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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 1.2 at December 31, 2009 based on an average calculation of all
        outstanding grants. The performance multiplier is assessed each
        period end based on actual results of ARC relative to its peers
        except during the first year of each grant where a performance
        multiplier of 1.0 is used.
    

The value associated with the RTUs and PTUs is expensed in the statement of income over the vesting period with the expense amount being determined by the trust unit price, the number of PTUs to be issued on vesting, and distributions. In periods where substantial trust unit price fluctuation occurs, ARC's G&A expense is subject to significant volatility.

Table 17 is a summary of the range of future expected payments under the Whole Unit Plan based on variability of the performance multiplier and units outstanding as at December 31, 2009:

    
    Table 17
    -------------------------------------------------------------------------
    Value of Whole Unit Plan as at
     December 31, 2009                            Performance multiplier
    (units thousands and $ millions          --------------------------------
     except per unit)                              -         1.0         2.0
    -------------------------------------------------------------------------
    Estimated trust units to vest
      RTUs                                     1,235       1,235       1,235
      PTUs                                         -       1,623       3,246
    -------------------------------------------------------------------------
    Total units(1)                             1,235       2,858       4,482
    -------------------------------------------------------------------------
      Trust unit price(2)                      19.94       19.94       19.94
      Trust unit distributions per month(2)     0.10        0.10        0.10
    -------------------------------------------------------------------------
    Value of Whole Unit Plan upon vesting(3)    24.6        57.0        89.4
    -------------------------------------------------------------------------
      2010                                      11.0        19.7        28.4
      2011                                       8.2        16.8        25.3
      2012                                       5.4        20.5        35.7
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Includes additional estimated units to be issued for accrued
        distributions to vesting date.
    (2) Values will fluctuate over the vesting period based on the volatility
        of the underlying trust unit price and distribution levels. Assumes a
        future trust unit price of $19.94 and $0.10 per trust unit
        distributions based on the unit price and distribution levels in
        place at December 31, 2009.
    (3) Upon vesting, a cash payment is made equivalent to the value of the
        underlying trust units. The payment is made on vesting dates in March
        and September of each year and at that time is reflected as a
        reduction of cash flow from operating activities.
    

Due to the variability in the future payments under the plan, ARC estimates that between $24.6 million and $89.4 million will be paid out from 2010 through 2012 based on the current trust unit price, distribution levels and ARC's market performance relative to its peers.

Provision for Non-recoverable Accounts Receivable

For the year ended December 31, 2009, ARC recorded a recovery of $1.7 million for amounts received on balances previously included in ARC's allowance for doubtful accounts. The recovery includes $1.2 million for settlement of oil revenues that were previously due from SemCanada Crude ("SemCanada"), a counterparty that marketed a portion of ARC's production, and had filed for protection under the Companies' Creditors Arrangement Act in 2008. The remaining $0.5 million is composed of $0.6 million recovered from one counterparty and $0.1 million written off for balances deemed uncollectable from various counterparties.

Interest and Financing Charges

Interest and financing charges decreased to $25.7 million in 2009 from $32.9 million in 2008 due to a decrease in short-term interest rates as well as a reduction in debt outstanding. As at December 31, 2009, ARC had $846.1 million of long-term debt outstanding, of which $340.9 million was fixed at a weighted average rate of 5.9 per cent and $505.2 million, including the working capital facility, was floating at current market rates plus a credit spread of 60 to 65 basis points. Forty-six per cent (US$369.1 million) of ARC's debt outstanding is denominated in U.S. dollars. ARC's credit facility is a three year facility maturing in April 2011. Management's current expectation is that the current credit spread would increase upon renewal by 150 to 250 basis points.

Foreign Exchange Gains and Losses

ARC recorded a gain of $70 million in 2009 on foreign exchange transactions compared to a loss of $89.4 million in 2008. These amounts include both realized and unrealized foreign exchange gains and losses.

Realized foreign exchange gains or losses arise from U.S. denominated transactions such as interest payments, debt repayments and hedging settlements. There was a $1 million cash realized foreign exchange gain during the year, as well as a net non-cash realized gain of $2.7 million was recorded relating to debt repayments of $17.2 million made during the year. These debt repayments were financed with ARC's credit facility and therefore are considered to be non-cash transactions.

Unrealized foreign exchange gains and losses are due to revaluation of U.S. denominated debt balances. The volatility of the Canadian dollar during the reporting period has a direct impact on the unrealized component of the foreign exchange gain or loss. The unrealized gain or loss impacts net income but does not impact cash flow from operating activities as it is a non-cash amount. From December 31, 2008 to December 31, 2009, the Cdn$/US$ exchange rate decreased from 1.22 to 1.05 resulting in an unrealized gain of $66.3 million on U.S. dollar denominated debt.

Taxes

In 2009, a future income tax recovery of $32.8 million was included in income compared to a recovery of $4.5 million in 2008. The current year recovery primarily relates to property, plant and equipment, and is a result of the depletion deduction claimed for accounting purposes exceeding the tax pools claimed for income tax purposes. The current year recovery attributable to property, plant and equipment is partially offset by a future income tax liability relating to the unrealized foreign exchange gain on long-term debt. In 2009, ARC's expected future corporate income tax rate decreased marginally from 25.3 per cent to 25.1 per cent.

The corporate income tax rate applicable to 2009 is 29 per cent; however, ARC and its subsidiaries did not pay any cash income taxes for fiscal 2009. Due to ARC'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 ARC.

Management continues to work on the plan for converting ARC Energy Trust to a corporation on January 1, 2011. After the conversion, the corporation would expect to allocate its cash flow among funding a portion of capital expenditures, periodic debt repayments, site reclamation expenditures, and cash payments to shareholders in the form of dividends. Current taxes payable by ARC after converting to a corporation will be subject to normal corporate tax rates. Taxable income as a corporation will vary depending on total income and expenses and vary with changes to commodity prices, costs and claims for both accumulated tax pools and tax pools associated with current year expenditures. As ARC has accumulated $2.2 billion of income tax pools, ARC expects that taxable income will be reduced or potentially eliminated for the initial period post conversion. The $2.2 billion of income tax pools (detailed in Table 18) are deductible at various rates and annual deductions associated with the initial tax pools will decline over time.

    
    Table 18
    -------------------------------------------------------------------------
    Income Tax                 Cdn $ millions at
     Pool type                    December, 2009        Annual deductibility
    -------------------------------------------------------------------------
    Canadian Oil and Gas
     Property Expense                      951.6       10% declining balance
    Canadian Development Expense           391.1       30% declining balance
    Canadian Exploration Expense           105.6                        100%
    Undepreciated Capital Cost             432.2     Primarily 25% declining
                                                                     balance
    Non-Capital Losses                     181.9                        100%
    Research and Experimental
     Expenditures                            0.8                        100%
    Other                                   15.2           Various rates, 7%
                                                    declining balance to 20%
    -------------------------------------------------------------------------
    Total Federal Tax Pools              2,078.4
    -------------------------------------------------------------------------
    Additional Alberta Tax Pools           155.5          Various rates, 25%
                                                   declining balance to 100%
    -------------------------------------------------------------------------
    Total Federal and Provincial Pools   2,233.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

Returns to shareholders post conversion will be impacted by the reduction of cash flow required to pay current income taxes, if any. Over the long-term, we would expect Canadian investors who hold their trust units in a taxable account to be relatively indifferent on an after tax basis as to whether ARC is structured as a corporation or as a trust in 2011. However, Canadian tax deferred investors (those holding their trust units in a tax deferred vehicle such as an RRSP, RRIF or pension plan) and foreign investors will realize a lower after tax return on distributions in taxable years after 2011 due to the introduction of the SIFT Tax should ARC stay as a trust, and their inability to claim the dividend tax credit if ARC converts to a corporation.

If a conversion from the trust structure to a corporation is approved by the unitholders, ARC expects there will be an opportunity to convert trust units to shares of the new corporation in a non-taxable manner; however, unitholders should consult their own tax advisor for details on the direct impact to themselves.

Depletion, Depreciation and Accretion of Asset Retirement Obligation

The depletion, depreciation and accretion ("DD&A") rate increased to $16.66 per boe in 2009 from $15.93 per boe in 2008. ARC posted a large increase in proved reserves at year-end 2009; however, these reserves were offset by a significant increase in the future development costs required to convert proven undeveloped reserves to proven producing reserves.

A breakdown of the DD&A rate is summarized in Table 19:

    
    Table 19
    -------------------------------------------------------------------------
    DD&A Rate
    ($ millions except per boe amounts)         2009        2008    % Change
    -------------------------------------------------------------------------
    Depletion of oil & gas assets(1)           377.1       370.3           2
    Accretion of asset retirement
     obligation(2)                               9.3         9.3           -
    -------------------------------------------------------------------------
    Total DD&A                                 386.4       379.6           2
    DD&A rate per boe                          16.66       15.93           5
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Includes depletion of the capitalized portion of the asset retirement
        obligation that was capitalized to the property, plant and equipment
        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. ARC has determined that there was no goodwill impairment as of December 31, 2009.

Capital Expenditures and Net Acquisitions

Capital expenditures, excluding acquisitions and dispositions, totaled $359.6 million in 2009, compared to $548.6 million in 2008. This amount was incurred on drilling and completions, geological, geophysical, facilities expenditures and corporate office costs.

Of the total amount spent in 2009, $204.8 million was spent in ARC's resource plays, including $188.9 million for the Montney resource play in Northeast British Columbia. A total of $120.3 million was spent on ARC's conventional oil & gas properties, $22.9 million was spent on ARC's enhanced oil recovery initiatives, and the balance of $11.6 million was spent on leasehold improvements for ARC's new office space in downtown Calgary.

Included in the above capital expenditures is $8.1 million of Alberta Government royalty drilling credits recorded for the full year of 2009, as well as $3.1 million for British Columbia summer drilling credits relating to 2007 and 2008 drilling programs. Without these credits, capital expenditures would have been $370.8 million.

In addition to the total capital expenditures during the year, ARC completed a corporate acquisition to purchase directly and indirectly all of the units of a general partnership formed to hold oil and gas assets in Ante Creek and other areas of northern Alberta ("Ante Creek") for $180 million in cash prior to normal closing adjustments. The acquisition consisted of producing wells with production of approximately 2,000 boe per day and undeveloped land holdings. This acquisition closed on December 21, 2009, and therefore financial results from the properties have been included in consolidated financial statements from that date.

ARC completed net property dispositions of both producing property and undeveloped land of $20.5 million that included a previously disclosed disposition of non-core assets in southeast Saskatchewan for proceeds of $33.5 million.

A breakdown of capital expenditures and net acquisitions is shown in Table 20:

    
    Table 20
    -------------------------------------------------------------------------
    Capital Expenditures
    ($ millions)                                2009        2008    % Change
    -------------------------------------------------------------------------
    Geological and geophysical                  13.7        27.1         (49)
    Drilling and completions                   214.3       305.4         (30)
    Plant and facilities                       110.0        90.4          22
    Undeveloped land                             7.0       122.4         (94)
    Other capital                               14.6         3.3         342
    -------------------------------------------------------------------------
    Total capital expenditures                 359.6       548.6         (34)
    -------------------------------------------------------------------------
    Producing property acquisitions(1)           8.2         1.4         100
    Undeveloped land property acquisitions      14.5        53.5         (73)
    Producing property dispositions(1)         (37.3)       (0.2)       (100)
    Undeveloped land property dispositions      (5.9)       (3.7)         59
    Corporate acquisition(2)                   178.9           -         100
    -------------------------------------------------------------------------
    Total capital expenditures
     and net acquisitions                      518.0       599.6         (14)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Value is net of post-closing adjustments.
    (2) Represents total consideration for the transactions, including fees
        but is prior to the related future income tax liability and asset
        retirement cost obligation.
    

Approximately 73 per cent of the $359.6 million capital program in 2009 was financed with cash flow from operating activities and proceeds from the distribution re-investment plan ("DRIP") compared to 91 per cent in 2008. Including proceeds from the net dispositions, capital expenditures were 51 per cent funded internally with the remaining 49 per cent funded through debt and working capital.

    
    Table 21
    -------------------------------------------------------------------------
    Source of Funding of Capital Expenditures and Net Acquisitions
    ($ millions)
    -------------------------------------------------------------------------
                                   2009                       2008
    -------------------------------------------------------------------------
                        Capital      Net    Total  Capital      Net    Total
                         Expend-  Acquis-  Expend-  Expend-  Acquis-  Expend-
                         itures   itions   itures   itures   itions   itures
    -------------------------------------------------------------------------

    Expenditures          359.6    158.4    518.0    548.6     51.0    599.6
    -------------------------------------------------------------------------
    Per cent funded by:
    Cash flow from
     operating activities   54%        -      38%      68%        -      62%
    Proceeds from
     Distribution
     re-investment plan
     ("DRIP")               19%        -      13%      23%        -      21%
    Debt                    27%     100%      49%       9%     100%      17%
    -------------------------------------------------------------------------
                           100%     100%     100%     100%     100%     100%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

Asset Retirement Obligation and Reclamation Fund

At December 31, 2009, ARC recorded an Asset Retirement Obligation ("ARO") of $149.9 million ($141.5 million at December 31, 2008) for future abandonment and reclamation of ARC'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. A significant portion of the costs are projected to be incurred in years 2050 to 2060. The future liability is then discounted at a weighted average risk adjusted credit rate of 6.5 per cent to reflect ARC's cost of borrowing for the year ended December 31, 2009.

Included in the December 31, 2009 ARO balance was a $4 million increase relating to the acquisition of the Ante Creek assets, a $3.8 million increase related to development activities and changes in estimates, $9.3 million for accretion expense in the year and a reduction of $8.7 million for actual abandonment expenditures incurred during 2009.

ARC has established two reclamation funds to finance future asset retirement obligations; one fund has been restricted to finance obligations specifically associated with the Redwater property, with the main fund financing all other obligations. 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 ARC's properties. Minimum contributions to the Redwater fund over the next 46 years will be approximately $86 million. The main fund has no minimum contribution requirement, however, the Board of Directors has approved voluntary contributions that currently result in annual contributions of $6 million.

ARC's reclamation funds totaled $33.2 million as at December 31, 2009, compared to $28.2 million as at December 31, 2008. Under the terms of ARC'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 ARC's capital structure is outlined in Table 22, as at December 31, 2009 and 2008:

    
    Table 22
    -------------------------------------------------------------------------
    Capital Structure and Liquidity
    ($ millions except per cent and               December 31,   December 31,
     ratio amounts)                                      2009           2008
    -------------------------------------------------------------------------
    Long-term debt                                      846.1          901.8
    Working capital deficit(1)                           56.3           60.1
    -------------------------------------------------------------------------
    Net debt obligations(2)                             902.4          961.9
    Market value of trust units and exchangeable
     shares(3)                                        4,765.7        4,405.9
    -------------------------------------------------------------------------
    Total capitalization(4)                           5,668.1        5,367.8
    -------------------------------------------------------------------------
    Net debt as a percentage of total capitalization    15.9%          17.9%
    Net debt to cash flow from operating activities       1.8            1.0
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Working capital is calculated as current liabilities less the current
        assets as they appear on the Consolidated Balance Sheets, and
        excludes current unrealized amounts pertaining to risk management
        contracts and the current portion of future income taxes.
    (2) Net debt is a non-GAAP measure and therefore it may not be comparable
        with the calculation of similar measures for other entities.
    (3) 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
        $19.94 and $20.10 for 2009 and 2008, respectively.
    (4) 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 ARC.
    

At December 31, 2009, ARC had total credit facilities of $1.3 billion with $846.1 million currently outstanding resulting in unused credit available of $470.5 million. On January 5, 2010 ARC closed on an equity offering of 13 million units that raised net proceeds of approximately $240 million that were used to reduce ARC's outstanding debt. As a result, ARC's credit available as at January 5, 2010 increased to approximately $710 million.

The credit facility syndicate includes 11 domestic and international banks. ARC's debt agreements contain a number of covenants all of which were met as at December 31, 2009. These agreements are available at www.sedar.com. The major financial covenants are described below:

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

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

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

ARC's long-term strategy is to keep debt at less than 2.0 times cash flow from operating activities and under 20 per cent of total capitalization. This strategy resulted in manageable debt to cash flow levels in 2009. Debt to trailing cash flow from operating activities of 1.0 times at December 31, 2008 increased to 1.8 times with the significant decline in commodity prices and cash flow in 2009, but were well below the debt covenant levels of 3.0 times. In 2010, with closing of the equity offering the debt to cash flow from operating activities, ratio declined to 1.2 times. The expectation is increasing production volumes and commodity prices will result in further declines in this ratio during the course of the year.

The weak global economic situation in 2008 and 2009 impacted ARC along with all other oil and gas entities by restricting access to capital and increasing borrowing costs. The credit situation improved dramatically during the third and fourth quarters of 2009 in the three markets that ARC typically uses to raise capital; equity, bank debt and long-term notes.

ARC entered into a bought deal equity offering with a group of underwriters on December 14, 2009, with the intent of issuing 10.3 million units and raising approximately $189 million of net proceeds. Due to the excess demand by both institutional and retailer investors, ARC agreed to increase the size of the offering to 13 million units and raised approximately $240 million of net proceeds. The pricing, discount and fees paid for this equity offering, were similar to those for offerings prior to the 2008/2009 recession period.

Credit conditions in the debt markets have improved dramatically in the last six months. Based on discussions with the 11 banks in ARC's revolving credit syndicate, management believes that ARC could expect to renew the $800 million credit facility on or before its maturity on April 1, 2011, at the same or larger dollar amount for a three year term. Costs of borrowing under our bank credit facilities comprise two items: first, the underlying interest rate on Bankers' Acceptances (CDN dollar loans) or LIBOR rates (U.S. denominated borrowings) and second, the credit spread to ARC. The credit spread to ARC in 2008 and 2009 ranged between 60 and 65 basis points. Upon renewal of our credit facilities, management would expect to pay a credit spread of approximately 1.5 per cent to 2.5 per cent. When added to the current three month BA rate, this would put the cost of borrowing under the revolving credit facility below three per cent, keeping bank debt ARC's lowest cost of capital. In addition to paying interest on the outstanding debt under the revolving syndicated credit facility all borrowers including ARC are charged a standby fee for the amount of the undrawn facility currently equal to 13.5 basis points. It is management's expectation that this fee will also increase upon renewal. Due to the increase of this fee, ARC will prudently establish excess credit lines to facilitate future operations and minor acquisitions with the view of increasing credit capacity when required to facilitate larger acquisitions. Bankers' Acceptance rates and LIBOR rates are at all time lows and it is expected these rates will increase as the economy recovers and central banks raise interest rates in an effort to stem inflation.

ARC also accesses long-term debt from large institutional investors by issuing long-term notes with an average term normally of five to 10 years. The cost of this debt is based upon two factors: first, the current rate of long-term government bonds and second, ARC's credit spread. Similar to bank credit spreads, these spreads increased significantly in 2008 and early 2009 but are now declining. ARC's average interest rate on its outstanding long-term notes is 5.9 per cent with the last series of notes issued in 2009 at a blended rate of 7.5 per cent. Based upon recent issues by ARC's peers, management believes ARC could access additional funds by issuing long-term notes at a rate similar to or lower than our historical average of 5.9 per cent.

ARC expects to finance its 2010 capital program with cash flow from operating activities, proceeds from the DRIP and existing credit capacity. If ARC undertook any major acquisitions, management would finance the transactions with a combination of debt and equity in a cost effective manner.

Unitholders' Equity

At December 31, 2009, there were 239 million trust units issued and issuable for exchangeable shares, an increase of 19.8 million trust units from December 31, 2008 due mostly to the issuance of 15.5 million trust units as part of an equity offering in February 2009 for net proceeds of $240 million.

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 2009, ARC raised proceeds of $67 million and issued 4.1 million trust units pursuant to the DRIP at an average price of $16.21 per unit.

On December 14, 2009 ARC entered into an agreement to sell 13 million trust units at $19.40 per trust unit to raise gross proceeds of approximately $252 million and net proceeds of approximately $240 million on a bought deal basis. This equity offering was made concurrent with ARC agreeing to purchase properties for $180 million at Ante Creek. The net proceeds of the offering were not received until January 5, 2010 at which time they reduced the outstanding indebtedness of ARC by $240 million.

Distributions

ARC declared distributions of $298.5 million ($1.28 per unit), representing 60 per cent of 2009 cash flow from operating activities compared to distributions of $570 million ($2.67 per unit) representing 60 per cent of cash flow from operating activities in 2008.

The following items may be deducted from cash flow from operating activities to arrive at distributions to unitholders:

    
    -   a portion of capital expenditures;
    -   annual contribution to the reclamation funds;
    -   debt principal repayments;
    -   income taxes if any; and
    -   certain obligations for future payments relative to the long-term
        incentive compensation under the Whole Unit Plan.
    

Cash flow from operating activities and distributions in total and per unit are summarized in Table 23:

    
    Table 23
    -------------------------------------------------------------------------
    Cash flow from operating                     %                       %
    activities and              2009    2008  Change    2009    2008  Change
    distributions               ($ millions)            ($ per unit)
    -------------------------------------------------------------------------
    Cash flow from operating
     activities                497.4   944.4     (47)   2.11    4.37     (52)

    Net reclamation fund
     contributions(1)           (4.6)   (2.2)    100   (0.01)  (0.01)      -

    Capital expenditures
     funded with cash flow
     from operating
     activities               (194.3) (372.2)    (48)  (0.83)  (1.72)    (52)

    Other(2)                       -       -       -    0.01    0.03     (67)
    -------------------------------------------------------------------------
    Distributions              298.5   570.0     (48)   1.28    2.67     (52)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Includes interest income earned on the reclamation fund balances that
        is retained in the reclamation funds.
    (2) Other represents the difference due to distributions paid being based
        on actual trust units outstanding at each distribution date whereas
        per unit cash flow from operating activities, reclamation fund
        contributions and capital expenditures funded with cash flow from
        operated activities, are based on weighted average outstanding trust
        units in the period.
    

ARC continually assesses distribution levels, in light of commodity prices, capital expenditure programs and production volumes, to ensure that distributions are in line with the long-term strategy and objectives of ARC 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. ARC'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 ARC's financial flexibility is maintained by a review
        of ARC'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 ARC to use debt to finance
        these expenditures. In 2009, ARC funded 54 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 ARC's capital expenditure program is dependent on
        the commodity price environment and is subject to the approval and
        discretion of the Board of Directors.
    

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 24 illustrates the comparison of distributions to net income as a measure of long-term sustainability. With the decline in commodity prices in 2009 relative to 2008, distributions were reduced from $0.15 per unit per month in December 2008, to $0.12 per unit per month in January 2009, and subsequently to the current rate of $0.10 per unit per month in May 2009.

    
    Table 24
    -------------------------------------------------------------------------
    Net income and Distributions
    ($ millions except per cent)                2009        2008        2007
    -------------------------------------------------------------------------
    Net income                                 222.8       533.0       495.3
    Distributions                              298.5       570.0       498.0
    -------------------------------------------------------------------------
    Excess (Shortfall)                         (75.7)      (37.0)       (2.7)
    Excess (Shortfall) as per cent
     of net income                              (34%)        (7%)        (1%)
    -------------------------------------------------------------------------
    Cash flow from operating activities        497.4       944.4       704.9
    Distributions as a per cent of cash
     flow from operating activities              60%         60%         71%
    Average distribution per unit per month    $0.11       $0.22       $0.20
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    

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.

    
    Table 25
    -------------------------------------------------------------------------
                                                         Taxable   Return of
    Calendar Year                      Distributions     Portion     Capital
    -------------------------------------------------------------------------
    2010 YTD(2)                                 0.10        0.10           -
    2009                                        1.28        1.24        0.04
    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                               $ 25.08     $ 18.17     $  6.91
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Based on distributions paid and payable in 2006.
    (2) Based on distributions declared at January 31, 2010 and estimated
        taxable portion of 2010 distributions of 97 per cent.
    

Please refer to the Trust's website at www.arcresources.com for details of the monthly distribution amounts and distribution dates for 2010.

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 2009, distributions declared in the calendar year will be 97 per cent return on capital or $1.24 per unit for the year (taxable) and three per cent return of capital or $0.04 per unit for the year (tax deferred). For a more detailed breakdown, please visit our website at www.arcresources.com.

Environmental Initiatives Impacting ARC

There are no new material environmental initiatives impacting ARC at this time.

Contractual Obligations and Commitments

ARC has contractual obligations in the normal course of operations including purchase of assets and services, operating agreements, transportation commitments, sales commitments, royalty obligations, lease rental obligations and employee agreements. These obligations are of a recurring, consistent nature and impact ARC's cash flows in an ongoing manner. ARC also has contractual obligations and commitments that are of a less routine nature as disclosed in Table 26.

    
    Table 26
    -------------------------------------------------------------------------
                                            Payments due by period
    -------------------------------------------------------------------------
                                  1 year      2-3      4-5   Beyond    Total
                                            years    years  5 years
    -------------------------------------------------------------------------
    Debt repayments(1)              34.8    571.7    107.4    132.2    846.1
    Interest payments(2)            20.1     35.5     24.2     20.8    100.6
    Reclamation fund
     contributions(3)                4.9      8.9      7.7     64.2     85.7
    Purchase commitments            41.2     37.1     15.9     14.9    109.1
    Transportation commitments(4)    4.8     26.6     24.2      7.1     62.7
    Operating leases                 4.0     13.0     14.9     74.4    106.3
    Risk management contract
     premiums(5)                     1.6        -        -        -      1.6
    -------------------------------------------------------------------------
    Total contractual obligations  111.4    692.8    194.3    313.6  1,312.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Long-term and short-term debt, excluding interest.
    (2) Fixed interest payments on senior secured notes.
    (3) Contribution commitments to a restricted reclamation fund associated
        with the Redwater property.
    (4) Fixed payments for transporting production from the Dawson gas plant,
        expected to be operational in early second quarter of 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 ARC's commitments related to its risk management program and have been recorded at fair market value at December 31, 2009 on the balance sheet as part of risk management contracts. In addition to the premiums, ARC has commitments related to its risk management program.

ARC enters into commitments for capital expenditures in advance of the expenditures being made. At any given point in time, it is estimated that ARC 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. ARC's 2010 capital budget has been approved by the Board at $610 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 2010 capital budget of $610 million includes $20 million for leasehold development costs related to ARC's new office space in downtown Calgary. These costs will be incurred throughout the first half of 2010. The operating lease commitments for the new space begin in the first quarter of 2010 and are included in Table 26.

ARC 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 ARC's financial position or results of operations and therefore the commitment table (Table 26) does not include any commitments for outstanding litigation and claims.

ARC has certain sales contracts with aggregators whereby the price received by ARC 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

ARC 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, 2009.

    
    Fourth Quarter Financial and Operational Results

    -   During the fourth quarter, ARC completed an acquisition for $180
        million in cash consideration prior to normal closing adjustments of
        a partnership owning properties in the Ante Creek area. The
        acquisition consisted of producing wells with production of
        approximately 2,000 boe per day and undeveloped land holdings. This
        acquisition closed on December 21, 2009 and therefore financial
        results from the properties have been included in the Consolidated
        Financial Statements from that date.

    -   Announced concurrent with the Ante Creek acquisition was a bought
        deal financing where ARC entered into an agreement to sell 13 million
        trust units at $19.40 per trust unit to raise gross proceeds of
        approximately $252 million and net proceeds of approximately $240
        million. The net proceeds of the offering were received on January 5,
        2010 at which time they reduced the outstanding indebtedness of ARC
        by $240 million.

    -   ARC's fourth quarter production was 62,520 boe per day, a decrease of
        2,793 boe per day from the fourth quarter of 2008 production of
        65,313. The decrease in production is attributable, in large part, to
        the natural declines on ARC's properties as a result of the reduced
        capital spending throughout 2009.

    -   ARC spent $117.3 million on capital expenditures before net
        acquisitions in the fourth quarter compared to $169.4 million in
        2008. ARC had an active fourth quarter drilling 39 gross wells (38
        net wells) on operated properties with a 100 per cent success rate.
        Included in ARC's fourth quarter capital expenditures is $20.8
        million incurred on the Dawson phase 1 60 mmcf per day gas plant
        scheduled to be commissioned early in the second quarter of 2010.

    -   The fourth quarter netback before hedging decreased slightly to
        $29.65 per boe as compared to $29.97 for the same period of 2008.
        While ARC's realized crude oil price was 29 per cent higher in the
        fourth quarter of 2009 than the same period in 2008, the realized
        natural gas price was 39 per cent lower than in the fourth quarter of
        2008.

    -   Cash G&A expenses before payments made under the Whole Unit Plan in
        the fourth quarter decreased to $1.73 per boe as compared to $1.78
        for the same period in 2008. The decrease in 2009 is attributable to
        a decreased bonus accrual in 2009 reflecting the lower overall
        commodity price environment observed throughout 2009.

    Table 27
    -------------------------------------------------------------------------
    Fourth Quarter Financial and
     Operational Highlights
    (Cdn$ millions except per
     unit and per cent)                      Q4 2009     Q4 2008    % Change
    -------------------------------------------------------------------------
    Production (boe/d)                        62,520      65,313          (4)
    Cash flow from operating activities        143.2       209.4         (32)
      Per unit                             $    0.61   $    0.96         (36)
    Distributions                               70.9       127.2         (44)
      Per unit                             $    0.30   $    0.58         (48)
      Per cent of cash flow from
       operating activities                       50          61         (18)
    Net income                                  65.5        82.7         (21)
      Per unit                             $    0.28   $    0.38         (26)
    -------------------------------------------------------------------------
    Prices
      WTI (US$/bbl)                            76.17       58.75          30
      Cdn$/US$ exchange rate                    1.06        1.21         (12)
      Realized oil price (Cdn $/bbl)           72.61       56.26          29
      AECO gas monthly index (Cdn $/mcf)        4.23        6.79         (38)
      Realized gas price (Cdn $/mcf)            4.58        7.48         (39)
    -------------------------------------------------------------------------
    Operating netback ($/boe)
      Revenue, before hedging                  48.42       50.06          (3)
      Royalties                                (7.94)      (9.14)        (13)
      Transportation                           (0.92)      (0.86)          7
      Operating costs                          (9.91)     (10.09)         (2)
      Netback (before hedging)                 29.65       29.97          (1)
      Cash hedging gain (loss)                 (0.47)       2.38        (120)
      Netback (after hedging)                  29.18   $   32.35         (10)
    -------------------------------------------------------------------------
    Capital expenditures                       117.3       169.4         (31)
    Net acquisitions and dispositions(1)       180.0        27.6         552
    Capital funded with cash flow from
     operating activities (per cent)              73          65          12
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Represents total consideration for the transactions, including fees
        but is prior to the related future income tax liability and asset
        retirement cost obligation.
    

Critical Accounting Estimates

ARC 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.

ARC'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 ARC 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.
    

ARC 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 ARC's environmental, health and safety policies.

Disclosure Controls and Procedures

As of December 31, 2009, an internal evaluation was carried out of the effectiveness of ARC'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 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 ARC 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 ARC in the reports that it files or submits under the Exchange Act or under Canadian Securities Legislation is accumulated and communicated to ARC'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 ARC'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 ARC's internal control over financial reporting was effective as of December 31, 2009. The effectiveness of ARC's internal control over financial reporting as of December 31, 2009 has been audited by Deloitte & Touche LLP, as reflected in their report for 2009. No changes were made to the Trust's internal control over financial reporting during the year ending December 31, 2009, 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, 2009, ARC adopted Section 3064, Goodwill and Intangible Assets issued by the Canadian Institute of Chartered Accountants ("CICA"). Section 3064 establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets subsequent to its initial recognition. This new section has no current impact on ARC or its Consolidated Financial Statements. This standard was adopted prospectively.

Effective December 31, 2009, ARC adopted CICA issued amendments to Handbook Section 3862, Financial Instruments - Disclosures. The amendments include enhanced disclosures relating to the fair value of financial instruments and the liquidity risk associated with financial instruments. Section 3862 now requires that all financial instruments measured at fair value be categorized into one of three hierarchy levels. Refer to Note 13 Financial Instruments and Risk Management for enhanced fair value disclosures and Note 9 Financial Liabilities and Liquidity Risk for liquidity risk disclosures. The amendments are consistent with recent amendments to financial instrument disclosure standards in IFRS.

Future Accounting Changes

Business Combinations

The CICA issued Handbook Section 1582 "Business Combinations" that replaces the previous business combinations standard. Under this guidance, the purchase price used in a business combination is based on the fair value of shares exchanged at the market price at acquisition date. Under the current standard, the purchase price used is based on the market price of shares for a reasonable period before and after the date the acquisition is agreed upon and announced. In addition, the guidance generally requires all acquisition costs to be expensed. Current standards allow for the capitalization of these costs as part of the purchase price. This new Section also addresses contingent liabilities, which will be required to be recognized at fair value on acquisition, and subsequently remeasured at each reporting period until settled. Currently, standards require only contingent liabilities that are payable to be recognized. The new guidance requires negative goodwill to be recognized in earnings rather than the current standard of deducting from non-current assets in the purchase price allocation. This standard applies prospectively to business combinations on or after January 1, 2011 with earlier application permitted. ARC is currently assessing the impact of the standard.

Consolidated Financial Statements and Non-controlling Interest

The CICA issued Handbook Sections 1601 "Consolidated Financial Statements", and 1602 "Non-controlling Interests", which replaces existing guidance under Section 1600 "Consolidated Financial Statements". Section 1601 establishes standards for the preparation of Consolidated Financial Statements. Section 1602 provides guidance on accounting for a non-controlling interest in a subsidiary in Consolidated Financial Statements subsequent to a business combination. These standards will be effective for ARC for business combinations occurring on or after January 1, 2011, with early application permitted. ARC is currently assessing the impact of the standard.

International Financial Reporting Standards ("IFRS")

In October 2009, the Accounting Standards Board ("AcSB") issued a third and final IFRS Omnibus Exposure Draft confirming that publicly accounting enterprises will be required to apply IFRS, in full and without modification, for financial periods beginning on January 1, 2011. The adoption date of January 1, 2011 will require the restatement, for comparative purposes, of amounts reported by ARC for the year ended December 31, 2010, including the opening balance sheet as at January 1, 2010.

ARC has commenced the process to transition from current Canadian GAAP to IFRS. Internal staff has been appointed to lead the conversion project along with sponsorship from the leadership team. Resource requirements have been identified and all IFRS requirements will be met with internal employees supplemented with consultants as required. Regular progress reporting to the Audit Committee of the Board of Directors on the status of the IFRS conversion has been implemented along with scheduled training sessions throughout 2010. At this time, ARC has begun the process of training key personnel within the accounting and finance functions as well as the management team. This has occurred through external IFRS oil and gas training and workshops that have been attended by key members of the accounting and finance team in 2009 and early 2010. A training session has been scheduled for the Audit Committee in June, 2010.

ARC's project consists of three key phases:

    
    -   Scoping and diagnostic phase - this phase involves performing a high
        level impact analysis to identify areas that may be affected by the
        transition to IFRS. The results of this analysis are priority ranked
        according to complexity and the amount of time required to assess the
        impact of changes in transitioning to IFRS.

    -   Impact analysis and evaluation phase - during this phase, items
        identified in the diagnostic are addressed according to the priority
        levels assigned to them. This phase involves analysis of policy
        choices allowed under IFRS and their impact on the financial
        statements. In addition, certain potential differences are further
        investigated to assess whether there may be a broader impact to ARC's
        debt agreements, compensation arrangements or management reporting
        systems. The conclusion of the impact analysis and evaluation phase
        will require the audit committee of the Board of Directors to review
        and approve all accounting policy choices as proposed by management.

    -   Implementation phase - involves implementation of all changes
        approved in the impact analysis phase and will include changes to
        information systems, business processes, modification of agreements
        and training of all staff who are impacted by the conversion.
    

ARC has completed the scoping and diagnostic phase and has prepared draft analysis for the impact analysis and evaluation phase. Management has not yet finalized its accounting policies and as such is unable to quantify the impact of adopting IFRS on the financial statements. In addition, due to anticipated changes to IFRS and International Accounting Standards prior to ARC's adoption of IFRS, management's plan is subject to change based on new facts and circumstances that arise after the date of this MD&A.

First-Time Adoption of IFRS

IFRS 1, "First-Time Adoption of International Financial Reporting Standards" ("IFRS 1"), provides entities adopting IFRS for the first time with a number of optional exemptions and mandatory exceptions in certain areas to the general requirement for full retrospective application of IFRS. Management is analyzing the various accounting policy choices available and will implement those determined to be the most appropriate for ARC which at this time are summarized as follows:

    
    -   Business Combinations - IFRS 1 would allow ARC to use the IFRS rules
        for business combinations on a prospective basis rather than re-
        stating all business combinations. The IFRS business combination
        rules converge with the new CICA Hanbook section 1582 that is also
        effective for ARC on January 1, 2011, however, early adoption is
        permitted.

    -   Property, Plant and Equipment ("PP&E") - IFRS 1 provides the option
        to value the PP&E assets at their deemed cost being the Canadian
        GAAP net book value assigned to these assets as at the date of
        transition, January 1, 2010. This amendment is permissible for
        entities, such as ARC, who currently follow the full cost accounting
        guideline under Canadian GAAP that accumulates all oil and gas
        assets into one cost centre. Under IFRS, ARC's PP&E assets must be
        divided into smaller cost centers. The net book value of the assets
        on the date of transition will be allocated to the new cost centers
        on the basis of ARC's reserve volumes or values at that point in
        time.

    -   Share-Based Payments - IFRS 1 allows ARC an exemption on IFRS 2,
        "Share-Based Payments" to equity instruments granted on or before
        November 2, 2002 or which vested before ARC's transition date to
        IFRS.
    

The transition from Canadian GAAP to IFRS is a significant undertaking that may materially affect our reported financial position and results of operations. At this time, ARC has identified key differences that will impact the financial statements as follows:

    
    -   Re-classification of Exploration and Evaluation ("E&E") expenditures
        from PP&E - Upon transition to IFRS, ARC will re-classify all E&E
        expenditures that are currently included in the PP&E balance on the
        Consolidated Balance Sheet. This will consist of the book value for
        ARC's undeveloped land that relates to exploration properties. E&E
        assets will not be depleted and must be assessed for impairment when
        indicators suggest the possibility of impairment.

    -   Calculation of depletion expense for PP&E assets - Upon transition to
        IFRS, ARC has the option to calculate depletion using a reserve base
        of proved reserves or both proved and probable reserves, as compared
        to the Canadian GAAP method of calculating depletion using only
        proved reserves. ARC has not concluded at this time which method for
        calculating depletion will be used.

    -   Impairment of PP&E assets - Under IFRS, impairment of PP&E must be
        calculated at a more granular level than what is currently required
        under Canadian GAAP. Impairment calculations will be performed at the
        cash generating unit level using either total proved or proved plus
        probable reserves.

    -   Due to the recent withdrawal of the exposure draft on IAS 12 Income
        Taxes in November 2009 and the issuance of the exposure draft on IAS
        37 Provisions, Contingent Liabilities and Contingent Assets in
        January 2010, Management is still determining the impact of these
        revised standards on its IFRS transition and expects to have all
        additional potential material impact areas identified during the
        first quarter of 2010 and approved by the audit committee during the
        second quarter of 2010.
    

In addition to accounting policy differences, ARC's transition to IFRS will impact the internal controls over financial reporting, the disclosure controls and procedures, ARC's business activities and IT systems as follows:

    
    -   Internal controls over financial reporting ("ICFR") - As the review
        of ARC's accounting policies is completed, an assessment will be
        made to determine changes required for ICFR. As an example,
        additional controls will be implemented for the IFRS 1 changes such
        as the allocation of ARC's PP&E as well as the process for re-
        classifying ARC's E&E expenditures from PP&E. This will be an
        ongoing process through 2010 to ensure that all changes in
        accounting policies include the appropriate additional controls and
        procedures for future IFRS reporting requirements.

    -   Disclosure controls and procedures - Throughout the transition
        process, ARC will be assessing stakeholders' information
        requirements and will ensure that adequate and timely information is
        provided so that all stakeholders are kept apprised. Management
        anticipates to deliver investor presentations during the fourth
        quarter of 2011 to explain the differences between the historical
        Canadian GAAP statements and the IFRS statements.

    -   Business activities - Management has been cognizant of the upcoming
        transition to IFRS and as such has worked with our counterparties
        and lenders to ensure that agreement references to Canadian GAAP
        statements are modified to allow for IFRS statements. Based on the
        expected changes to ARC's accounting policies at this time, there
        are no foreseen issues with the existing wording of debts covenants
        and related agreements as a result of the conversion to IFRS.
        During the 2010 quarterly meetings held with ARC's lenders there
        will be an update on IFRS as it relates to ARC and management will
        continue to monitor these areas closely as final policy choices are
        made.

    -   IT systems - ARC has completed most of the system updates required
        in order to ready the company for IFRS reporting. The modifications
        were not significant, however, deemed critical in order to allow for
        reporting of both Canadian GAAP and IFRS statements in 2010 as well
        as the modifications required to track PP&E costs and E&E costs with
        a more granular level of detail for IFRS reporting. Additional
        system modifications may be required based on final policy
        choices. Additional system modifications may be required based on
        final policy choices.
    

Non-GAAP Measures

Management uses certain key performance indicators ("KPIs") and industry benchmarks such as distributions as a per cent of cash flow from operating activities, operating netbacks ("netbacks"), total capitalization, finding, development and acquisition costs, recycle ratio, reserve life index, reserves per unit and production per unit, net asset value and total returns to analyze financial and operating performance. Management feels that these KPIs and benchmarks are key measures of profitability and overall sustainability for ARC. 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 MD&A 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 MD&A contains forward-looking information and statements pertaining to the following: all of the matters under the heading "2009 Guidance and Financial Highlights" which contains guidance for 2010, the future expenditure plans for 2010 and expected production under the heading "Production", the expected benefits from various incentive plans instituted in the provinces of Alberta and British Columbia and future operating costs under the heading "Operating Netbacks", the expected increase in cash G&A in 2010 and the expected payments in 2010 under the Whole Unit Plan under the heading "General and Administrative Expenses ("G&A") and Trust Unit Incentive Compensation", the increase in interest rates in 2010 as a result of the renewal of our credit facility under the heading "Interest and Financing Charges" and the costs and opportunity for renewal of the bank facility and other information relating to financing the 2010 capital expenditures under the heading: "Capitalization, Financial Resources and Liquidity", the payment of income taxes in the future by ARC and the availability of a non-taxable conversion of trust unit to shares on the conversion of the trust structure to a corporation under the heading "Taxes", and a number of other matters, including the amount of future asset retirement; 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; ARC's income tax pools and the future impact of the implementation of IFRS on ARC's financial statements.

The forward-looking information and statements contained in this MD&A reflect several material factors and expectations and assumptions of ARC including, without limitation: that ARC will continue to conduct its operations in a manner consistent with past operations; the general continuance of current industry conditions; the continuance of existing (and in certain circumstances, the implementation of proposed) tax, royalty and regulatory regimes; the accuracy of the estimates of ARC's reserves and resource volumes; certain commodity price and other cost assumptions; and the continued availability of adequate debt and equity financing and cash flow to fund its planned expenditures; ARC believes the material factors, expectations and assumptions reflected in the forward-looking information and statements are reasonable but no assurance can be given that these factors, expectations and assumptions will prove to be correct.

The forward-looking information and statements included in this MD&A 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 MD&A and in ARC's Annual Information Form).

The forward-looking information and statements contained in this MD&A speak only as of the date of this MD&A, 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)              2009     2008     2007     2006     2005
    -------------------------------------------------------------------------
    FINANCIAL
    Revenue before royalties       978.2  1,706.4  1,251.6  1,230.5  1,165.2
      Per unit(1)                   4.16     7.90     5.95     6.02     6.10
    Cash flow from operating
     activities(2)                 497.4    944.4    704.9    734.0    616.7
      Per unit - basic(1)           2.11     4.37     3.35     3.59     3.23
      Per unit - diluted            2.11     4.37     3.35     3.58     3.20
    Net income                     222.8    533.0    495.3    460.1    356.9
      Per unit - basic(3)           0.96     2.50     2.39     2.28     1.90
      Per unit - diluted            0.96     2.50     2.39     2.27     1.88
    Distributions                  298.5    570.0    498.0    484.2    376.6
      Per unit(4)                   1.28     2.67     2.40     2.40     1.99
    Total assets                 3,914.5  3,766.7  3,533.0  3,479.0  3,251.2
    Total liabilities            1,540.1  1,624.6  1,491.3  1,550.6  1,415.5
    Net debt outstanding(5)        902.4    961.9    752.7    739.1    578.1
    Weighted average trust
     units (millions)(6)           235.4    216.0    210.2    204.4    191.2
    Trust units outstanding
     and issuable at period
     end (millions)(6)             239.0    219.2    213.2    207.2    202.0
    -------------------------------------------------------------------------
    CAPITAL EXPENDITURES
    Geological and geophysical      13.7     27.1     14.9     11.4      9.2
    Land                             7.0    122.4     77.5     32.4      9.1
    Drilling and completions       214.3    305.4    229.5    240.5    191.8
    Plant and facilities           110.0     90.4     72.1     77.6     55.0
    Other capital                   14.6      3.3      3.2      2.6      3.7
    Total capital expenditures     359.6    548.6    397.2    364.5    268.8
    Property acquisitions
     (dispositions), net           (20.5)    51.0     42.5    115.2     91.3
    Corporate acquisitions(7)      178.9        -        -     16.6    505.0
    Total capital expenditures
     and net acquisitions          518.0    599.6    439.7    496.3    865.1
    -------------------------------------------------------------------------
    OPERATING
    Production
      Crude oil (bbl/d)           27,509   28,513   28,682   29,042   23,282
      Natural gas (mmcf/d)         194.0    196.5    180.1    179.1    173.8
      Natural gas liquids (bbl/d)  3,689    3,861    4,027    4,170    4,005
      Total (boe per day 6:1)     63,538   65,126   62,723   63,056   56,254
    Average prices
      Crude oil ($/bbl)            62.24    94.20    69.24    65.26    61.11
      Natural gas ($/mcf)           4.18     8.58     6.75     6.97     8.96
      Natural gas liquids ($/bbl)  40.67    69.71    54.79    52.63    49.92
      Oil equivalent ($/boe)       42.07    71.25    54.54    53.33    56.54
    -------------------------------------------------------------------------
    RESERVES
    (company interest)(8)
    Proved plus probable
     reserves
      Crude oil and NGL (mbbl)   153,413  153,020  158,341  162,193  163,385
      Natural gas (bcf)          1,353.2  1,012.2    768.2    743.6    741.7
      Total (mboe)               378,953  321,723  286,370  286,125  286,997
    -------------------------------------------------------------------------
    TRUST UNIT TRADING
    (based on intra-day trading)
    Unit prices
      High                         21.89    33.95    23.86    30.74    27.58
      Low                          11.73    15.01    18.90    19.20    16.55
      Close                        19.94    20.10    20.40    22.30    26.49
    Average daily volume
     (thousands)                   1,057      975      597      706      656
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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)                                          2009
    -------------------------------------------------------------------------
    FINANCIAL                                  Q4       Q3       Q2       Q1
    Revenue before royalties                278.6    239.2    235.2    225.2
      Per unit(1)                            1.17     1.01     0.99     0.98
    Cash flow from operating activities(2)  143.2    125.6    104.3    124.3
      Per unit - basic(1)                    0.60     0.53     0.44     0.54
      Per unit - diluted                     0.60     0.53     0.44     0.54
    Net income                               65.5     68.9     66.1     22.3
      Per unit - basic(3)                    0.28     0.29     0.28     0.10
      Per unit - diluted                     0.28     0.29     0.28     0.10
    Distributions                            70.9     70.6     75.0     82.0
      Per unit(4)                            0.30     0.30     0.32     0.36
    Total assets                          3,914.5  3,642.9  3,672.5  3,733.1
    Total liabilities                     1,540.1  1,278.4  1,323.1  1,392.1
    Net debt outstanding(5)                 902.4    705.4    737.6    781.5
    Weighted average trust units(6)         238.5    237.7    236.6    228.9
    Trust units outstanding and
     issuable(6)                            239.0    238.1    237.1    236.0
    -------------------------------------------------------------------------
    CAPITAL EXPENDITURES
    Geological and geophysical                2.9      3.0      5.0      2.8
    Land                                      2.0      4.5      0.2      0.2
    Drilling and completions                 66.1     61.0     18.6     68.5
    Plant and facilities                     35.3     26.1     23.6     25.1
    Other capital                            11.0      1.6      1.5      0.6
    Total capital expenditures              117.3     96.2     48.9     97.2
    Property acquisitions (dispositions)
     net                                      1.1    (30.1)     2.3      6.2
    Corporate acquisitions(7)               178.9        -        -        -
    Total capital expenditures and net
     acquisitions                           297.3     66.1     51.2    103.4
    -------------------------------------------------------------------------
    OPERATING
    Production
      Crude oil (bbl/d)                    27,415   26,921   26,917   28,806
      Natural gas (mmcf/d)                  189.0    193.1    200.2    193.8
      Natural gas liquids (bbl/d)           3,597    3,717    3,679    3,764
      Total (boe per day 6:1)              62,520   62,824   63,969   64,872
    Average prices
      Crude oil ($/bbl)                     72.61    67.74    62.74    46.44
      Natural gas ($/mcf)                    4.58     3.25     3.73     5.20
      Natural gas liquids ($/bbl)           46.12    38.92    38.89    38.86
      Oil equivalent ($/boe)                48.35    41.31    40.32    38.40
    -------------------------------------------------------------------------
    TRUST UNIT TRADING
    (based on intra-day trading)
    Unit prices
    High                                    21.89    20.20    19.25    20.90
    Low                                     19.06    15.48    14.12    11.73
    Close                                   19.94    20.20    17.81    14.15
    Average daily volume (thousands)          963    1,038      988    1,240
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    (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
    Corporate acquisitions(7)                   -        -        -        -
    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
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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.



    CONSOLIDATED BALANCE SHEETS (unaudited)
    As at December 31

    (Cdn$ millions)                                         2009        2008
    -------------------------------------------------------------------------
    ASSETS
    Current assets
      Cash and cash equivalents (Note 5)               $       -   $    40.0
      Accounts receivable (Note 6)                         115.9       110.0
      Prepaid expenses                                      18.2        16.8
      Risk management contracts (Note 13)                    5.9        24.4
      Future income taxes (Note 15)                          7.1         3.9
    -------------------------------------------------------------------------
                                                           147.1       195.1
    Reclamation funds (Note 7)                              33.2        28.2
    Risk management contracts (Note 13)                      3.2         9.2
    Property, plant and equipment (Note 8)               3,573.4     3,376.6
    Goodwill                                               157.6       157.6
    -------------------------------------------------------------------------
    Total assets                                       $ 3,914.5   $ 3,766.7
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    LIABILITIES
    Current liabilities
      Accounts payable and accrued liabilities
       (Note 9)                                        $   166.7   $   194.4
      Distributions payable                                 23.7        32.5
      Risk management contracts (Note 13)                   12.9        23.5
    -------------------------------------------------------------------------
                                                           203.3       250.4
    Risk management contracts (Note 13)                      1.0         3.4
    Long-term debt (Note 10)                               846.1       901.8
    Accrued long-term incentive compensation (Note 21)      10.9        14.2
    Asset retirement obligations (Note 11)                 149.9       141.5
    Future income taxes (Note 15)                          328.9       313.3
    -------------------------------------------------------------------------
    Total liabilities                                    1,540.1     1,624.6
    -------------------------------------------------------------------------

    COMMITMENTS AND CONTINGENCIES (Note 22)
    SUBSEQUENT EVENT (Note 23)

    NON-CONTROLLING INTEREST
      Exchangeable shares (Note 16)                         36.0        42.4

    UNITHOLDERS' EQUITY
      Unitholders' capital (Note 17)                     2,917.6     2,600.7
      Deficit (Note 18)                                   (578.6)     (502.9)
      Accumulated other comprehensive (loss)
       income (Note 18)                                     (0.6)        1.9
    -------------------------------------------------------------------------
    Total unitholders' equity                            2,338.4     2,099.7
    -------------------------------------------------------------------------
    Total liabilities and unitholders' equity          $ 3,914.5   $ 3,766.7
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    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             December 31             December 31
     per unit amounts)              2009        2008        2009        2008
    -------------------------------------------------------------------------
    REVENUES
    Oil, natural gas and
     natural gas liquids      $    278.6  $    300.8  $    978.2  $  1,706.4
    Royalties                      (45.6)      (54.9)     (147.8)     (307.7)
    -------------------------------------------------------------------------
                                   233.0       245.9       830.4     1,398.7
    Gain (loss) on risk
     management contracts
     (Note 13)
      Realized                      (1.7)       32.8        19.4       (75.7)
      Unrealized                     0.2        42.0        (7.7)       68.0
    -------------------------------------------------------------------------
                                   231.5       320.7       842.1     1,391.0
    -------------------------------------------------------------------------

    EXPENSES
      Transportation                 5.3         5.2        20.6        19.0
      Operating                     57.0        60.7       236.2       241.5
      General and administrative    13.8        14.0        52.3        61.2
      Provision for non-
       recoverable accounts
       receivable (Note 6)          (1.3)       14.0        (1.7)       32.0
      Interest and financing
       charges (Note 10)             5.9         8.1        25.7        32.9
      Depletion, depreciation
       and accretion
       (Notes 8 and 11)             96.1        96.2       386.4       379.6
      (Gain) loss on foreign
       exchange (Note 14)           (9.7)       61.2       (70.0)       89.4
    -------------------------------------------------------------------------
                                   167.1       259.4       649.5       855.6
    -------------------------------------------------------------------------

    Capital and other taxes         (0.1)          -        (0.3)          -
    Future income tax recovery
     (Note 15)                       1.9        22.3        32.8         4.5
    -------------------------------------------------------------------------
    Net income before non-
     controlling interest           66.2        83.6       225.1       539.9
    Non-controlling interest
     (Note 16)                      (0.7)       (0.9)       (2.3)       (6.9)
    -------------------------------------------------------------------------
    Net income                $     65.5  $     82.7  $    222.8  $    533.0
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Deficit, beginning of
     period                   $   (573.2) $   (458.4) $   (502.9) $   (465.9)
    Distributions paid or
     declared (Note 19)            (70.9)     (127.2)     (298.5)     (570.0)
    -------------------------------------------------------------------------
    Deficit, end of period
     (Note 18)                $   (578.6) $   (502.9) $   (578.6) $   (502.9)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Net income per unit
     (Note 17)
      Basic and Diluted       $     0.28  $     0.38  $     0.96  $     2.50
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    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
                                       December 31             December 31
    (Cdn$ millions)                 2009        2008        2009        2008
    -------------------------------------------------------------------------

    Net income                $     65.5  $     82.7  $    222.8  $    533.0

    Other comprehensive (loss)
     income, net of tax
      Losses and gains on
       financial instruments
       designated as cash
       flow hedges(1)               (0.5)        0.6        (3.9)       (2.2)
      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)                     0.3        (0.9)        1.1        (2.9)
      Net unrealized gains
       (losses) on available-
       for-sale reclamation
       funds' investments(4)           -           -         0.3        (0.1)
    -------------------------------------------------------------------------
    Other comprehensive (loss)
     income                         (0.2)       (0.3)       (2.5)        4.8
    -------------------------------------------------------------------------
    Comprehensive income      $     65.3  $     82.4  $    220.3  $    537.8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Accumulated other
     comprehensive (loss)
     income, beginning of
     period                         (0.4)        2.2         1.9        (2.9)
    Other comprehensive (loss)
     income                         (0.2)       (0.3)       (2.5)        4.8
    -------------------------------------------------------------------------
    Accumulated other
     comprehensive (loss)
     income, end of period
     (Note 18)                $     (0.6) $      1.9  $     (0.6) $      1.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Amounts are net of tax of $0.1 million and $1.3 million,
        respectively, for the three months and twelve months ended
        December 31, 2009 (net of tax of $0.2 million and $0.8 million,
        respectively, for the three and twelve months ended December 31,
        2008).
    (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 $0.1 million and $0.4 million,
        respectively, for the three and twelve months ended December 31, 2009
        (net of tax of $0.3 million and $1 million, respectively, for the
        three and twelve months ended December 31, 2008).
    (4) Nominal future income tax impact for the three months ended
        December 31, 2009 and $0.1 million for the twelve months ended
        December 31, 2009 (nominal for the three and twelve months ended
        December 31, 2008).

    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)                 2009        2008        2009        2008
    -------------------------------------------------------------------------

    CASH FLOWS FROM OPERATING
     ACTIVITIES
    Net income                $     65.5  $     82.7  $    222.8  $    533.0
    Add items not involving
     cash:
      Non-controlling interest
       (Note 16)                     0.7         0.9         2.3         6.9
      Future income tax
       recovery (Note 15)           (1.9)      (22.3)      (32.8)       (4.5)
      Depletion, depreciation
       and accretion
       (Notes 8 and 11)             96.1        96.2       386.4       379.6
      Non-cash (gain) loss on
       risk management
       contracts (Note 13)          (0.2)      (42.0)        7.7       (68.0)
      Non-cash (gain) loss on
       foreign exchange
       (Note 14)                    (8.8)       61.6       (69.0)       88.5
      Non-cash trust unit
       incentive compensation
       expense (recovery)
       (Note 21)                     4.7        (4.2)        0.6         1.0
    Expenditures on site
     restoration and reclamation
     (Note 11)                      (4.8)       (4.7)       (8.7)      (12.4)
    Change in non-cash working
     capital                        (8.1)       41.2       (11.9)       20.3
    -------------------------------------------------------------------------
                                   143.2       209.4       497.4       944.4
    -------------------------------------------------------------------------

    CASH FLOWS FROM FINANCING
     ACTIVITIES
    Issue of long-term debt
     under revolving credit
     facilities, net               224.5       164.0      (120.7)      105.9
    Issue of Senior Secured Notes      -           -       152.9           -
    Repayment of Senior Secured
     Notes                          (6.3)       (7.1)      (18.9)       (7.1)
    Issue of trust units             0.5         0.5       255.0         4.9
    Trust unit issue costs          (0.5)          -       (13.8)          -
    Cash distributions paid
     (Note 19)                     (56.1)     (117.6)     (242.3)     (458.8)
    Change in non-cash working
     capital                        (4.3)       (1.5)        1.6        (0.4)
    -------------------------------------------------------------------------
                                   157.8        38.3        13.8      (355.5)
    -------------------------------------------------------------------------

    CASH FLOWS FROM INVESTING
     ACTIVITIES
    Corporate acquisition
     (Note 4)                     (178.9)          -      (178.9)          -
    Acquisition of petroleum
     and natural gas properties     (1.1)      (27.6)      (11.8)      (51.2)
    Proceeds on disposition
     of petroleum and natural
     gas properties                    -           -        32.3         0.2
    Capital expenditures          (116.5)     (169.9)     (359.4)     (548.1)
    Net reclamation fund
     contributions (Note 7)         (1.5)       (1.3)       (4.6)       (2.2)
    Change in non-cash working
     capital                        (3.0)        3.5       (28.8)       45.4
    -------------------------------------------------------------------------
                                  (301.0)     (195.3)     (551.2)     (555.9)
    -------------------------------------------------------------------------
    INCREASE (DECREASE) IN CASH
     AND CASH EQUIVALENTS              -        52.4       (40.0)       33.0
    CASH AND CASH EQUIVALENTS,
     BEGINNING OF PERIOD               -       (12.4)       40.0         7.0
    -------------------------------------------------------------------------
    CASH AND CASH EQUIVALENTS,
     END OF PERIOD            $        -  $     40.0  $        -  $     40.0
    -------------------------------------------------------------------------
    See accompanying notes to the Consolidated Financial Statements



    NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

    December 31, 2009 and 2008
    (all tabular amounts in Cdn$ millions, except per unit amounts)

    1.  STRUCTURE OF THE TRUST

        ARC Energy Trust ("ARC" or "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 ARC are the holders of the
        Trust units.

        ARC 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"). The Trust
        Indenture was amended on June 7, 1999 to convert ARC from a closed-
        end to an open-ended investment Trust. The current business of ARC
        includes investment in energy business-related assets including, but
        not limited to, petroleum and natural gas-related assets, gathering,
        processing and transportation assets. The operations of ARC 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"). Effective January 1, 2011, ARC will be required
        to prepare Consolidated Financial Statements in accordance with
        International Financial Reporting Standards ("IFRS").

        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 ARC'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 ARC and
        its subsidiaries. Any reference to "the Trust" or "ARC" 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 ARC are recognized when title
        passes from ARC to its customers.

        Transportation

        Costs paid by ARC 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

        ARC conducts many of its oil and gas production activities through
        jointly controlled operations and the financial statements reflect
        only ARC'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.

        Whole Trust Unit Incentive Plan Compensation

        ARC 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 ARC.
        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
        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 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.

        ARC 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.

        ARC has not incorporated an estimated forfeiture rate for RTUs and
        PTUs that will not vest, rather it 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 an other than temporary decline in market
        value.

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

        ARC follows the full cost method of accounting. All costs of
        exploring, developing, enhancing 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

        ARC 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 ARC's
        proved reserves. Cash flows are calculated based on third party
        quoted forward prices, adjusted for ARC's contract prices and quality
        differentials.

        Upon recognition of impairment, ARC 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. ARC'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 ARC'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

        ARC 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 compared to the book value of the reporting entity.
        If the fair value of the entity is less than the book value,
        impairment is measured by allocating the fair value to the
        identifiable assets and liabilities as if the entity had been
        acquired in a business combination for a purchase price equal to its
        fair value. The excess of the fair value 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

        ARC 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

        ARC 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 ARC and
        ARC'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 net income after
        non-controlling interest 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, ARC
           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. ARC classifies its reclamation
           funds as available-for-sale assets.

           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. ARC 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.

        ARC 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.

        ARC 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 ARC 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. ARC considers all of these
        transactions to be effective economic hedges; however, most of ARC'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, ARC
        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 obtained. 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, ARC 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, ARC 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. ARC 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

        ARC must record non-controlling interest when exchangeable shares
        issued by a subsidiary of ARC 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, 2009, ARC adopted Section 3064, Goodwill and
        Intangible Assets issued by the Canadian Institute of Chartered
        Accountants ("CICA"). Section 3064 establishes standards for the
        recognition, measurement, presentation and disclosure of goodwill and
        intangible assets subsequent to its initial recognition. This new
        section has no current impact on ARC or its Consolidated Financial
        Statements. This standard was adopted prospectively.

        Effective December 31, 2009, ARC adopted CICA issued amendments to
        Handbook Section 3862, Financial Instruments - Disclosures. The
        amendments include enhanced disclosures relating to the fair value of
        financial instruments and the liquidity risk associated with
        financial instruments. Section 3862 now requires that all financial
        instruments measured at fair value be categorized into one of three
        hierarchy levels. Refer to Note 13 Financial Instruments and Risk
        Management for enhanced fair value disclosures and Note 9 Financial
        Liabilities and Liquidity Risk for liquidity risk disclosures. The
        amendments are consistent with recent amendments to financial
        instrument disclosure standards in IFRS.

        Future Accounting Changes


        A.  Business Combinations

        The CICA issued Handbook Section 1582 "Business Combinations" that
        replaces the previous business combinations standard. Under this
        guidance, the purchase price used in a business combination is based
        on the fair value of shares exchanged at the market price at
        acquisition date. Under the current standard, the purchase price used
        is based on the market price of shares for a reasonable period before
        and after the date the acquisition is agreed upon and announced. In
        addition, the guidance generally requires all acquisition costs to be
        expensed. Current standards allow for the capitalization of these
        costs as part of the purchase price. This new Section also addresses
        contingent liabilities, which will be required to be recognized at
        fair value on acquisition, and subsequently remeasured at each
        reporting period until settled. Currently, standards require only
        contingent liabilities that are payable to be recognized. The new
        guidance requires negative goodwill to be recognized in earnings
        rather than the current standard of deducting from non-current assets
        in the purchase price allocation. This standard applies prospectively
        to business combinations on or after January 1, 2011 with earlier
        application permitted. ARC is currently assessing the impact of the
        standard.

        B.  Consolidated Financial Statements and Non-controlling Interest

        The CICA issued Handbook Sections 1601 "Consolidated Financial
        Statements", and 1602 "Non-controlling Interests", which replaces
        existing guidance under Section 1600 "Consolidated Financial
        Statements". Section 1601 establishes standards for the preparation
        of Consolidated Financial Statements. Section 1602 provides guidance
        on accounting for a non-controlling interest in a subsidiary in
        Consolidated Financial Statements subsequent to a business
        combination. These standards will be effective for ARC for business
        combinations occurring on or after January 1, 2011 with early
        application permitted. ARC is currently assessing the impact of the
        standard.

    4.  CORPORATE ACQUISITIONS

        On December 21, 2009, ARC acquired all of the issued and outstanding
        shares of two legal entities - 1504793 Alberta Ltd. and PetroBakken
        General Partnership No. 1 (collectively "Ante Creek") - for total
        consideration of $178.9 million. The allocation of the purchase price
        and consideration paid were as follows:

        Net Assets Acquired
        ---------------------------------------------------------------------
          Property, plant and equipment                           $    231.0
          Asset retirement obligations                                  (4.0)
          Future income taxes                                          (48.1)
        ---------------------------------------------------------------------
        Total net assets acquired                                 $    178.9
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Consideration Paid
        ---------------------------------------------------------------------
          Cash and fees paid                                      $    178.9
        ---------------------------------------------------------------------
        Total consideration paid                                  $    178.9
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The acquisition of Ante Creek has been accounted for as an asset
        acquisition pursuant to EIC - 124.

        The future income tax liability on acquisition was based on the
        difference between the fair value of the acquired net assets of
        $178.9 million and the associated tax basis of $35.8 million.

        These Consolidated Financial Statements incorporate the results of
        operations of the acquired Ante Creek properties from December 21,
        2009.

    5.  CASH AND CASH EQUIVALENTS

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

    6.  FINANCIAL ASSETS AND CREDIT RISK

        Credit risk is the risk of financial loss to ARC if a partner or
        counterparty to a product sales contract or financial instrument
        fails to meet its contractual obligations. ARC is exposed to credit
        risk with respect to its cash equivalents, accounts receivable,
        reclamation funds, and risk management contracts. Most of ARC's
        accounts receivable relate to oil and natural gas sales and are
        subject to typical industry credit risks. ARC 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
            ARC's credit policy; and
        -   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, 2009 pertains to accrued revenue for December 2009
        production volumes. ARC transacts with a number of oil and natural
        gas marketing companies and commodity end users ("commodity
        purchasers"). Commodity purchasers and marketing companies typically
        remit amounts to ARC 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, 2009, no
        one counterparty accounted for more than 25 per cent of the total
        accounts receivable balance and the largest commodity purchaser
        receivable balance is fully secured with Letters of Credit.

        For the year ended December 31, 2009, ARC recorded a recovery of
        $1.7 million for amounts received on balances previously included in
        ARC's allowance for doubtful accounts. The recovery includes
        $1.2 million for settlement of oil revenues that were previously due
        from SemCanada Crude ("SemCanada"), a counterparty that marketed a
        portion of ARC's production and had filed for protection under the
        Companies' Creditors Arrangement Act in 2008. The remaining
        $0.5 million is composed of $0.6 million recovered from one
        counterparty and $0.1 million written off for balances deemed
        uncollectable from various counterparties.

        ARC's allowance for doubtful accounts was $0.8 million as at
        December 31, 2009 and $32 million as at December 31, 2008. In 2008,
        ARC recorded a provision for the full receivable of $30.6 million due
        from SemCanada. As noted above, upon settlement of the SemCanada oil
        revenue claim, ARC recovered $1.2 million and has written off the
        balance in the allowance of $28.8 million. As at December 31, 2009,
        $0.6 million remains in the allowance for the SemCanada gas revenue
        claim. The remaining movement of $1.2 million is composed of
        $0.6 million settled on balances previously included in the provision
        and $0.6 million written off for balances deemed uncollectable.
        During the twelve months of 2009 ARC did not record any additional
        provision for non-collectible accounts receivable.

        When determining whether amounts that are past due are collectable,
        management assesses the credit worthiness 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, 2009, $4.4 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.

    7.  RECLAMATION FUNDS

        ---------------------------------------------------------------------
                              December 31, 2009         December 31, 2008
        ---------------------------------------------------------------------
                          Unrestricted  Restricted  Unrestricted  Restricted
        ---------------------------------------------------------------------
        Balance, beginning
         of year            $    11.2    $    17.0    $    14.4   $     11.7
        Contributions             6.2          5.3          5.8          5.9
        Reimbursed
         expenditures(1)         (5.9)        (1.8)        (9.7)        (1.0)
        Interest earned
         on funds                 0.7          0.1          0.8          0.4
        Net unrealized gains
         and losses on
         available-for-sale
         investments              0.4            -         (0.1)           -
        ---------------------------------------------------------------------
        Balance, end of
         year(2)            $    12.6    $    20.6    $    11.2    $    17.0
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) Amount differs from actual expenditures incurred by ARC due to
            timing differences and discretionary reimbursements.
        (2) As at December 31, 2009 the unrestricted reclamation fund held
            $0.2 million in cash and cash equivalents (nil at December 31,
            2008), with the balance held in investment grade assets.

        ARC has established two reclamations funds to finance future asset
        retirement obligations; one fund has been restricted to finance
        obligations specifically associated with the Redwater property, with
        the unrestricted fund financing all other obligations. 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 2008) based upon
        properties owned as at December 31, 2009. 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, 2009 and December 31, 2008, nominal
        amounts relating to available-for-sale reclamation fund assets were
        classified from accumulated other comprehensive income into earnings.
        As at December 31, 2009 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.

    8.  PROPERTY, PLANT AND EQUIPMENT

        ---------------------------------------------------------------------
                                                   December 31,  December 31,
                                                          2009          2008
        ---------------------------------------------------------------------
        Property, plant and equipment, at cost      $  6,242.8    $  5,668.9
        Accumulated depletion and depreciation        (2,669.4)     (2,292.3)
        ---------------------------------------------------------------------
        Property, plant and equipment, net          $  3,573.4    $  3,376.6
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The calculation of 2009 depletion and depreciation included an
        estimated $1,060 million ($872 million in 2008) for future
        development costs associated with proved undeveloped reserves and
        excluded $268.9 million ($287.5 million in 2008) for the book value
        of unproved properties.

        ARC performed a ceiling test calculation at December 31, 2009 to
        assess the recoverable value of property plant and equipment
        ("PP&E"). Based on the calculation, the value of future net revenues
        from ARC's reserves exceeded the carrying value of ARC's PP&E at
        December 31, 2009. The benchmark prices used in the calculation were
        as follows:

                                   WTI Oil         AECO Gas         Cdn$/US$
        Year                      (US$/bbl)     (Cdn$/mmbtu)  Exchange Rates
        ---------------------------------------------------------------------
        2010                         80.00             5.96             0.95
        2011                         83.00             6.79             0.95
        2012                         86.00             6.89             0.95
        2013                         89.00             6.95             0.95
        2014                         92.00             7.05             0.95
        2015                         93.84             7.16             0.95
        2016                         95.72             7.42             0.95
        2017                         97.64             7.95             0.95
        2018                         99.59             8.52             0.95
        2019                        101.58             8.69             0.95
        ---------------------------------------------------------------------
        Remainder(1)                  2.0%             2.0%             0.95
        ---------------------------------------------------------------------
        (1) Percentage change represents the change in each year after 2019
            to the end of the reserve life.


    9.  FINANCIAL LIABILITIES AND LIQUIDITY RISK

        Liquidity risk is the risk that ARC will not be able to meet its
        financial obligations as they become due. ARC 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 ARC's financial liabilities.

        The following table details ARC's financial liabilities as at
        December 31, 2009:

        ---------------------------------------------------------------------
        ($ millions)          1 year     2 - 3     4 - 5    Beyond     Total
                                         years     years   5 years
        ---------------------------------------------------------------------
        Accounts payable
         and accrued
         liabilities(1)        166.7         -         -         -     166.7
        Distributions
         payable(2)             18.9         -         -         -      18.9
        Risk management
         contracts(3)           14.8       2.1         -         -      16.9
        Senior secured
         notes and interest     47.1     109.9     131.6     152.9     441.5
        Revolving credit
         facilities                -     497.3         -         -     497.3
        Working capital
         facility                7.9         -         -         -       7.9
        Accrued long-term
         incentive
         compensation(1)        28.4      36.0         -         -      64.4
        ---------------------------------------------------------------------
        Total financial
         liabilities           283.8     645.3     131.6     152.9   1,213.6
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (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 gross at their future value.

        ARC 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,
                                                          2009          2008
        ---------------------------------------------------------------------
        Syndicated credit facilities:
          Cdn$ denominated(1)                       $    423.0    $    399.5
          US$ denominated                                 74.3         240.6
        Working capital facility                           7.9           2.1
        Senior secured notes:
        Master Shelf Agreement
          5.42% US$ Note                                  78.5          91.9
          4.94% US$ Note                                   6.3          14.7
        2004 Note Issuance
          4.62% US$ Note                                  54.5          76.5
          5.10% US$ Note                                  65.4          76.5
        2009 Note Issuance
          7.19% US$ Note                                  70.6             -
          8.21% US$ Note                                  36.6             -
          6.50% Cdn$ Note                                 29.0             -
        ---------------------------------------------------------------------
        Total long-term debt outstanding            $    846.1    $    901.8
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) Syndicated credit facility balance was reduced on January 5,
            2010. Refer to Note 23 for further details.

        Credit Facilities

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

        Borrowings under the syndicated credit facility bear interest at bank
        prime (2.25 per cent at December 31, 2009, four per cent at
        December 31, 2008) or, at ARC's option, Canadian dollar bankers'
        acceptances or U.S. dollar LIBOR loans, plus a stamping fee. At the
        option of ARC, the lenders will review the syndicated credit facility
        each year and determine whether they will extend the revolving period
        for another year. In the event that the syndicated credit facility is
        not extended at any time before the maturity date, the loan balance
        will become repayable on the maturity date. The maturity date of the
        current syndicated credit facility is April 15, 2011. All drawings
        under the facility are subject to stamping fees. These stamping fees
        vary between a minimum of 60 basis points ("bps") to a maximum of
        110 bps. During 2009, the weighted-average interest rate under the
        credit facility was 1.1 per cent (3.8 per cent in 2008).

        Senior Secured Notes Issued Under a Master Shelf Agreement

        These senior secured notes were issued in two separate tranches
        pursuant to an Uncommitted Master Shelf Agreement. The terms and
        rates of these senior secured notes are summarized below:

        ---------------------------------------------------------------------
                        Remaining    Coupon    Maturity      Principal
        Issue Date      Principal    Rate      Date          Payment Terms
        ---------------------------------------------------------------------
        October 19,     US$6.0       4.94%     October 19,   Five equal
         2002                                   2010         installments
                                                             beginning
                                                             October 19, 2006
        December 15,    US$75.0      5.42%     December 15,  Eight equal
         2005                                   2017         installments
                                                             beginning
                                                             December 15,
                                                             2010
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        In the second quarter of 2009 ARC extended its Uncommitted Master
        Shelf Agreement from May 2009 to April 2012. The extended agreement
        allows for an aggregate draw of up to US$225 million in 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.

        Senior Secured Notes not Subject to the Master Shelf Agreement

        2004 Note Issuance

        These notes were issued on April 27, 2004 via a private placement in
        two tranches. The terms and rates of these senior secured notes are
        summarized below.

        2009 Note Issuance

        These notes were issued on April 14, 2009 via a private placement in
        three tranches. The terms and rates of these senior secured notes are
        summarized below.

        ---------------------------------------------------------------------
                        Remaining    Coupon    Maturity
        Issue Date      Principal    Rate      Date          Payment Terms
        ---------------------------------------------------------------------
        April 27,       US$52.1      4.62%     April 27,     Six equal
         2004                                   2014         installments
                                                             beginning
                                                             April 27, 2009
        April 27,       US$62.5      5.10%     April 27,     Five equal
         2004                                   2016         installments
                                                             beginning
                                                             April 27, 2012
        April 14,       US$67.5      7.19%     April 14,     Five equal
         2009                                   2016         installments
                                                             beginning
                                                             April 14, 2012
        April 14,       US$35.0      8.21%     April 14,     Five equal
         2009                                   2021         installments
                                                             beginning
                                                             April 14, 2017
        April 14,       Cdn$29.0     6.50%     April 14,     Five equal
         2009                                   2016         installments
                                                             beginning
                                                             April 14, 2012
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Credit Capacity

        The following table summarizes ARC's available credit capacity and
        the current amounts drawn as at December 31, 2009:

        ---------------------------------------------------------------------
                                            Credit
                                          Capacity        Drawn    Remaining
        ---------------------------------------------------------------------
        Syndicated Credit Facility      $    800.0   $    497.3   $    302.7
        Working Capital Facility              25.0          7.9         17.1
        Senior Secured Notes Subject
         to a Master Shelf Agreement(1)      235.5         84.8        150.7
        Senior Secured Notes Not Subject
         to a Master Shelf Agreement         256.1        256.1            -
        ---------------------------------------------------------------------
        Total                           $  1,316.6   $    846.1   $    470.5
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) Total credit capacity is US$225 million.

        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
            trailing twelve month net income before non-cash items and
            interest expense;
        -   Long-term debt, letters of credit, and subordinated debt not to
            exceed four times trailing twelve month 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 ARC enters into a material acquisition whereby the
        purchase price exceeds 10 per cent of the book value of ARC's assets,
        the ratio in the first covenant is increased to 3.5 times, while the
        third covenant is increased to 55% for the subsequent six month
        period. As at December 31, 2009, ARC had $2 million in letters of
        credit ($1.9 million in 2008), no subordinated debt, and was in
        compliance with all covenants.

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

        Supplemental disclosures

        The fair value of all senior secured notes as at December 31, 2009,
        is $347.3 million compared to a carrying value of $340.9 million
        ($289.9 million compared to $259.6 million as at December 31, 2008),
        and is calculated as the present value of principal and interest
        payments discounted at ARC's credit adjusted risk free rate.

        Amounts of US$16.4 million due under the senior secured notes
        (includes US$6 million attributable to the Master Shelf Agreement)
        and $7.9 million due under ARC's working capital facility in the next
        12 months have not been included in current liabilities as management
        has the ability and intent to refinance this amount through the
        syndicated credit facility.

        Interest paid during 2009 was $2.6 million more than interest expense
        ($1.6 million more in 2008).

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

    11. ASSET RETIREMENT OBLIGATIONS

        The total future asset retirement obligations were estimated by
        management based on ARC'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. ARC has estimated the net present value of its total
        asset retirement obligations to be $149.9 million as at December 31,
        2009 ($141.5 million in 2008) based on a total future undiscounted
        liability of $1.36 billion ($1.32 billion in 2008). At December 31,
        2009 management estimates that these payments are expected to be made
        over the next 51 years with the majority of payments being made in
        years 2050 to 2060. ARC's weighted average credit adjusted risk free
        rate of 6.5 per cent (6.6 per cent in 2008) and an inflation rate of
        two per cent (two per cent in 2008) 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 ARC's asset retirement obligations:

        ---------------------------------------------------------------------
                                                   December 31,  December 31,
                                                          2009          2008
        ---------------------------------------------------------------------
        Balance, beginning of year                  $    141.5    $    140.0
        Increase in liabilities relating to
         corporate acquisitions                            4.0             -
        Increase in liabilities relating to
         development activities                            1.7           2.0
        Increase in liabilities relating to
         change in estimate                                2.1           2.6
        Settlement of reclamation liabilities
         during the year                                  (8.7)        (12.4)
        Accretion expense                                  9.3           9.3
        ---------------------------------------------------------------------
        Balance, end of year                        $    149.9    $    141.5
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    12. CAPITAL MANAGEMENT

        The objective of ARC when managing its capital is to maintain a
        conservative structure that will allow it 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

        ARC 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 ARC's capital structure, management's objective is to
        limit net debt to less than two times annualized cash flow from
        operating activities and 20 per cent of total capitalization. As at
        December 31, 2009 ARC's net debt to annualized cash flow from
        operating activities ratio is 1.8 and its net debt to total
        capitalization ratio is 15.9 per cent.

        ---------------------------------------------------------------------
        ($ millions, except per unit               December 31,  December 31,
         and per cent amounts)                            2009          2008
        ---------------------------------------------------------------------
        Long-term debt                                   846.1         901.8
        Accounts payable and accrued liabilities         166.7         194.4
        Distributions payable                             23.7          32.5
        Cash and cash equivalents, accounts
         receivable and prepaid expenses                (134.1)       (166.8)
        ---------------------------------------------------------------------
        Net debt obligations(1)                          902.4         961.9
        ---------------------------------------------------------------------

        Trust units outstanding and issuable for
         exchangeable shares (millions)                  239.0         219.2
        Trust unit price(2)                              19.94         20.10
        ---------------------------------------------------------------------
        Market capitalization(1)                       4,765.7       4,405.9
        Net debt obligations(1)                          902.4         961.9
        ---------------------------------------------------------------------
        Total capitalization(1)                        5,668.1       5,367.8
        ---------------------------------------------------------------------

        Net debt as a percentage of total
         capitalization                                  15.9%         17.9%
        Net debt obligations to annualized cash
         flow from operating activities                    1.8           1.0
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) Market capitalization, net debt obligations and total
            capitalization as presented do not have any standardized meaning
            prescribed by Canadian GAAP and therefore may not be comparable
            with the calculation of similar measures for other entities.
        (2) TSX close price as at December 31, 2009 and December 31, 2008
            respectively.

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

        In addition to internal capital management ARC is subject to various
        covenants under its credit facilities. Compliance with these
        covenants is monitored on a quarterly basis and as at December 31,
        2009 ARC is in compliance with all covenants. Refer to Note 10 for
        further details.

    13. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

        Financial Instrument Classification and Measurement

        Financial instruments of ARC carried on the Consolidated Balance
        Sheet are carried at amortized cost with the exception of cash and
        cash equivalents, reclamation fund assets and risk management
        contracts, which are carried at fair value. With the exception of
        ARC'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, 2009. The fair value of the
        ARC's senior secured notes is disclosed in Note 10.

        All of ARC's cash and cash equivalents, risk management contracts,
        and reclamation fund investments are transacted in active markets.
        ARC classifies the fair value of these transactions according to the
        following hierarchy based on the amount of observable inputs used to
        value the instrument.

        -   Level 1 - Quoted prices are available in active markets for
            identical assets or liabilities as of the reporting date. Active
            markets are those in which transactions occur in sufficient
            frequency and volume to provide pricing information on an ongoing
            basis.
        -   Level 2 - Pricing inputs are other than quoted prices in active
            markets included in Level 1. Prices in Level 2 are either
            directly or indirectly observable as of the reporting date. Level
            2 valuations are based on inputs, including quoted forward prices
            for commodities, time value and volatility factors, which can be
            substantially observed or corroborated in the marketplace.
        -   Level 3 - Valuations in this level are those with inputs for the
            asset or liability that are not based on observable market data.

        ARC's cash and cash equivalents, reclamation fund assets and risk
        management contracts have been assessed on the fair value hierarchy
        described above. ARC's cash and cash equivalents and reclamation fund
        assets are classified as Level 1 and risk management contracts as
        Level 2. Assessment of the significance of a particular input to the
        fair value measurement requires judgment and may affect the placement
        within the fair value hierarchy level.

        Market Risk Management

        ARC is exposed to a number of market risks that are part of its
        normal course of business. ARC has a risk management program in place
        that includes financial instruments as disclosed in the risk
        management section of this note.

        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 ARC's business plan by
        mitigating adverse changes in commodity prices, interest rates and
        foreign exchange rates.

        In the sections below, ARC has prepared sensitivity analyses in an
        attempt to demonstrate the effect of changes in these market risk
        factors on ARC'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

        ARC's operational results and financial condition 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, 2009. The sensitivity is based on a $15 increase and $15
        decrease in the price of US$ WTI crude oil and a $1.50 increase and
        $1.50 decrease in the price of Cdn$ 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, 2009 and ARC's next reporting date.

        ---------------------------------------------------------------------
                   Increase in Commodity Price   Decrease in Commodity Price
        ---------------------------------------------------------------------
                     Crude oil     Natural gas     Crude oil     Natural gas
        ---------------------------------------------------------------------
        Net income
         (decrease)
         increase   $    (21.7)    $    (54.6)    $     19.1     $      54.1
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        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 ARC'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

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

        If interest rates applicable to floating rate debt at December 31,
        2009 were to have increased by 50 bps (0.5 per cent) it is estimated
        that ARC's net income would decrease by $1.9 million. Management does
        not expect interest rates to decrease.

        Foreign Exchange Risk

        North American oil and natural gas prices 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 ARC has U.S. dollar
        denominated debt and interest obligations of which future cash
        repayments are directly impacted by the exchange rate in effect on
        the repayment date. Variations in the Canadian/U.S. dollar exchange
        rate could also have a positive or negative impact on distributions
        to unitholders.

        The following table demonstrates the effect of exchange rate
        movements on net income due to changes in the fair value of risk
        management contracts in place at December 31, 2009 as well as the
        unrealized gain or loss on revaluation of outstanding US$ denominated
        debt. The sensitivity is based on a $0.10 Cdn$/US$ increase and $0.10
        Cdn$/US$ decrease in the foreign exchange rate.

        ---------------------------------------------------------------------
                                                  Increase in    Decrease in
                                                Cdn$/US$ rate  Cdn$/US$ rate
        ---------------------------------------------------------------------
        Increase gain/decrease loss
         (increase loss/decrease gain) on
         risk management contracts                 $      1.5     $     (1.5)
        (Increase loss/decrease gain)
         increase gain/decrease loss on
         foreign exchange                               (28.6)          29.5
        ---------------------------------------------------------------------
        Net income (decrease) increase             $    (27.1)    $     28.0
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Increases and decreases in foreign exchange rates applicable to US$
        payables and receivables would have a nominal impact on ARC's net
        income for the period ended December 31, 2009.

        Risk Management Contracts

        ARC uses a variety of derivative instruments to reduce its exposure
        to fluctuations in commodity prices, foreign exchange rates, interest
        rates and power prices. ARC considers all of these transactions to be
        effective economic hedges; however, the majority of ARC'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, 2009 that do not qualify for hedge accounting:

        ---------------------------------------------------------------------
        Financial WTI Crude Oil Option Contracts(1)
        ---------------------------------------------------------------------
                                                  Bought      Sold      Sold
                                         Volume      Put       Put      Call
        Term                   Contract   bbl/d  US$/bbl   US$/bbl   US$/bbl
        ---------------------------------------------------------------------
        1-Jan-10 31-Mar-10       Collar   1,000   $65.00         -    $80.00
        1-Jan-10 31-Dec-10       Collar   4,000   $70.00         -    $90.00
        1-Jan-10 31-Dec-10       Collar   2,000   $75.00         -    $95.00
        1-Jan-10 31-Dec-10 3-way collar   2,000   $80.00    $60.00    $95.00
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) Monthly average

        ---------------------------------------------------------------------
        Financial AECO Natural Gas Swap Contracts(2)
        ---------------------------------------------------------------------
                                                         Sold
                                            Volume       Swap
        Term                   Contract       GJ/d    Cdn$/GJ
        ---------------------------------------------------------------------
        1-Jan-10 31-Dec-10         Swap     80,000      $5.61
        1-Jan-11 31-Dec-13         Swap     20,000      $6.16
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (2) AECO 7a monthly index

        ---------------------------------------------------------------------
        Financial NYMEX Natural Gas Swap Contracts(3)
        ---------------------------------------------------------------------

                                            Volume  Sold Swap
        Term                   Contract    mmbtu/d  US$/mmbtu
        ---------------------------------------------------------------------
        1-Apr-10 31-Oct-10         Swap     20,000      $6.00
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (3) Last 3 Day Settlement

        ---------------------------------------------------------------------
        Financial Basis Swap Contract(4)
        ---------------------------------------------------------------------
                                                  Volume    Basis Swap
        Term                        Contract     mmbtu/d     US$/mmbtu
        ---------------------------------------------------------------------
        1-Jan-10 31-Oct-10    Basis Swap-L3d      50,000      ($1.0430)
        1-Nov-10 31-Oct-11     Basis Swap-Ld      15,000      ($0.4850)
        1-Nov-11 31-Oct-12     Basis Swap-Ld      15,000      ($0.4067)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (4) Receive Nymex Last Day (Ld) or Last 3 Day (L3d); pay AECO 7a
            monthly index

        ---------------------------------------------------------------------
        US$ Debt Repayment Contracts
        ---------------------------------------------------------------------
                                           Notional
                                             Volume        Swap         Swap
        Settlement Date    Contract    US$ millions    Cdn$/US$     US$/Cdn$
        ---------------------------------------------------------------------
        21-Jan-10          Forward            20.00     $1.0480      $0.9542
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        ---------------------------------------------------------------------
        Financial Electricity Heat Rate Contracts(5)
        ---------------------------------------------------------------------
                                                                        Heat
                              Volume  AESO Power   AECO 5a  multiplied  Rate
        Term       Contract     MWh      $/MWh       $/GJ       by    GJ/MWh
        ---------------------------------------------------------------------
        1-Jan-10   Heat Rate            Receive   Pay AECO
         31-Dec-10  Swap        10        AESO       5a               x 9.15
        1-Jan-11   Heat Rate            Receive   Pay AECO
         31-Dec-11  Swap        15        AESO       5a               x 9.08
        1-Jan-12   Heat Rate            Receive   Pay AECO
         31-Dec-13  Swap        10        AESO       5a               x 9.15
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (5) Alberta Power Pool (monthly average 24x7); AECO 5a monthly index

        ---------------------------------------------------------------------
        Financial Electricity Contracts(6)
        ---------------------------------------------------------------------
                                         Volume   Bought Swap
        Term                  Contract      MWh      Cdn$/MWh
        ---------------------------------------------------------------------
        1-Jan-10 31-Dec-12        Swap       5        $72.495
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (6) Alberta Power Pool (monthly average 24x7); AECO 5a monthly index

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

        ---------------------------------------------------------------------
        Financial Electricity Contracts(7)
        ---------------------------------------------------------------------
                                         Volume    Bought Swap
        Term                  Contract      MWh       Cdn$/MWh
        ---------------------------------------------------------------------
        1-Jan-10 31-Dec-10        Swap       5          $63.00
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (7) Alberta Power Pool (monthly average 24x7), AECO 5a monthly index

        At December 31, 2009, the fair value of the contracts that were not
        designated as accounting hedges was a loss of $4.3 million. ARC
        recorded a gain on risk management contracts of $11.7 million in the
        statement of income for the year ended December 31, 2009
        ($7.7 million loss in 2008). This amount includes the realized and
        unrealized gains and losses on risk management contracts that do not
        qualify as effective accounting hedges.

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

        ---------------------------------------------------------------------
                                                   December 31,  December 31,
                                                          2009          2008
        ---------------------------------------------------------------------
        Fair value, beginning of year               $      3.4    $    (64.6)
        Fair value, end of year(1)                        (4.3)          3.4
        ---------------------------------------------------------------------
        Change in fair value of contracts in the year     (7.7)         68.0
        Realized gain (loss) in the year                  19.4         (75.7)
        ---------------------------------------------------------------------
        Gain (loss) on risk management contracts    $     11.7    $     (7.7)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) Intrinsic value of risk management contracts not designated as
            effective accounting hedges equals a loss of $3.5 million at
            December 31, 2009 ($0.9 million loss at December 31, 2008).

        During 2007 ARC entered into treasury rate lock contracts in order to
        manage ARC's interest rate exposure on future debt issuances. During
        2008 it was determined that the previously anticipated debt issuance
        was no longer expected to occur and the associated treasury rate lock
        contracts were unwound at a loss of $13.6 million. The loss was
        reclassified from Other Comprehensive Income ("OCI"), net of tax
        $10 million and recognized in net income.

        ARC's electricity contracts are intended to manage price risk on
        electricity consumption. Portions of ARC's financial electricity
        contracts were designated as effective accounting hedges on their
        respective contract dates. A realized loss of $1.5 million for the
        year ended December 31, 2009 (gain of $3.9 million in 2008) has been
        included in operating costs on these electricity contracts. The
        accumulated unrealized fair value loss of $0.5 million on these
        contracts has been recorded on the Consolidated Balance Sheet at
        December 31, 2009 with the movement in fair value recorded in OCI,
        net of tax. The fair value movement for the year ended December 31,
        2009 is an unrealized loss of $3.8 million. As at December 31, 2009
        all of the unrealized fair value loss is attributed to contracts that
        will settle over the next twelve months. The following table
        reconciles the movement in the fair value of ARC's financial risk
        management contracts that have been designated as effective
        accounting hedges:

        ---------------------------------------------------------------------
                                                   December 31,  December 31,
                                                          2009          2008
        ---------------------------------------------------------------------
        Fair value, beginning of year               $      3.3    $     (3.4)
        Change in fair value of financial
         electricity contracts                            (3.8)         (0.7)
        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(1)                  $     (0.5)   $      3.3
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) Intrinsic value of risk management contracts designated as
           effective accounting hedges equals a loss of $0.5 million at
           December 31, 2009 ($3.4 million gain at December 31, 2008).


    14. GAIN (LOSS) ON FOREIGN EXCHANGE

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

        ---------------------------------------------------------------------
                                           Three Months        Twelve Months
                                               Ended               Ended
                                            December 31         December 31
        ---------------------------------------------------------------------
                                          2009      2008      2009      2008
        ---------------------------------------------------------------------
        Unrealized gain (loss) on
         US$ denominated debt         $    5.7  $  (63.9) $   66.3  $  (90.8)
        Realized gain on US$
         denominated debt repayments       3.1       2.3       2.7       2.3
        ---------------------------------------------------------------------
        Total non-cash gain (loss) on
         US$ denominated transactions      8.8     (61.6)     69.0     (88.5)
        Realized cash gain (loss) on
         US$ denominated transactions      0.9       0.4       1.0      (0.9)
        ---------------------------------------------------------------------
        Total foreign exchange gain
         (loss)                       $    9.7  $  (61.2) $   70.0  $  (89.4)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    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 March 4, 2009
        legislation was passed providing that the provincial component of the
        tax on ARC is to be calculated based on the general provincial rate
        in each province in which ARC has a permanent establishment. This is
        the same way that a corporation would calculate its provincial tax
        rate. The provincial component of the tax was substantively enacted
        as of December 31, 2009 but was not substantively enacted as of
        December 31, 2008. ARC has reflected a reduced tax rate in the
        calculation of future income taxes in 2009.

        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,
                                                          2009          2008
        ---------------------------------------------------------------------
        Income before future income tax recovery
         and non-controlling interest               $    192.3    $    535.4
        ---------------------------------------------------------------------
        Canadian statutory rate(1)                       29.0%         32.4%
        ---------------------------------------------------------------------
        Expected income tax expense at statutory
         rates                                            55.8         173.4
        Effect on income tax of:
          Net income of ARC                              (86.0)       (181.2)
          Effect of change in corporate tax rate           7.2          (8.9)
          Unrealized loss (gain) on foreign exchange      (9.7)         13.4
          Change in estimated pool balances               (0.7)         (1.0)
          Other non-deductible items                       0.6          (0.2)
        ---------------------------------------------------------------------
        Future income tax recovery                  $    (32.8)   $     (4.5)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (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,
                                                          2009          2008
        ---------------------------------------------------------------------
        Future tax liabilities:
          Capital assets in excess of tax value     $    418.3    $    381.4
          Risk management contracts                          -           1.7
          Other comprehensive income                         -           0.8
          Long-term debt                                   8.5           0.2
        Future tax assets:
          Asset retirement obligations                   (37.6)        (35.8)
          Non-capital losses                             (49.9)        (24.4)
          Risk management contracts                       (1.1)            -
          Other comprehensive loss                        (0.1)            -
          Trust unit incentive compensation expense       (8.2)         (8.3)
          Attributed Canadian royalty income              (4.5)         (4.6)
          CEC, SR&ED pools and deductible share
           issue costs                                    (3.6)         (1.6)
        ---------------------------------------------------------------------
        Net future income tax liability             $    321.8    $    309.4
        ---------------------------------------------------------------------
        Net future income tax asset, current        $      7.1    $      3.9
        Net future income tax liability, long-term  $    328.9    $    313.3
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The petroleum and natural gas properties and facilities owned by ARC
        have an approximate tax basis of $2.23 billion ($2.07 billion in
        2008) available for future use as deductions from taxable income.
        Included in this tax basis are estimated non-capital loss carry
        forwards of $181.9 million ($86.9 million in 2008) that expire in the
        years 2027 through 2029. The following is a summary of the estimated
        ARC tax pools:

        ---------------------------------------------------------------------
                                                   December 31,  December 31,
                                                          2009          2008
        ---------------------------------------------------------------------
        Canadian oil and gas property expenses      $    951.6    $  1,001.3
        Canadian development expenses                    391.1         360.7
        Canadian exploration expenses                    105.6          41.5
        Undepreciated capital costs                      432.2         414.5
        Non-capital losses                               181.9          86.9
        SR&ED tax pools                                    0.8           0.3
        Other                                             15.2           7.0
        ---------------------------------------------------------------------
        Estimated tax basis, federal                   2,078.4       1,912.2
        ---------------------------------------------------------------------
        Provincial tax pools                             155.5         155.9
        ---------------------------------------------------------------------
        Estimated tax basis, federal and provincial $  2,233.9    $  2,068.1
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        No current income taxes were paid or payable in both 2009 and 2008.

    16. EXCHANGEABLE SHARES

        ARC 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 10 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 ARC for Trust units on August 28, 2012. The ARL
        Exchangeable Shares are publicly traded.

        ---------------------------------------------------------------------
                                                   December 31,  December 31,
        (units thousands)                                 2009          2008
        ---------------------------------------------------------------------
        Balance, beginning of year                       1,092         1,310
        Exchanged for trust units(1)                      (221)         (218)
        ---------------------------------------------------------------------
        Balance, end of year                               871         1,092
        Exchange ratio, end of year                    2.71953       2.51668
        Trust units issuable upon conversion,
         end of year                                     2,369         2,748
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) During 2009, 220,573 ARL exchangeable shares were converted to
            trust units at an average exchange ratio of 2.59547, compared to
            218,455 exchangeable shares at an average exchange ratio of
            2.36901 during the year ended 2008.

        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 2009 and
        2008:

        ---------------------------------------------------------------------
                                                   December 31,  December 31,
                                                          2009          2008
        ---------------------------------------------------------------------
        Non-controlling interest, beginning
         of year                                    $     42.4    $     43.1
        Reduction of book value for conversion to
         trust units                                      (8.7)         (7.6)
        Current period net income attributable to
         non-controlling interest                          2.3           6.9
        ---------------------------------------------------------------------
        Non-controlling interest, end of year             36.0          42.4
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Accumulated earnings attributable to
         non-controlling interest                   $     43.3    $     41.0
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    17. UNITHOLDERS' CAPITAL

        ARC is authorized to issue 650 million Trust units of which
        236.6 million units were issued and outstanding as at December 31,
        2009 (216.4 million as at December 31, 2008).

        ARC 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.

        ARC is an open ended mutual fund under which unitholders have the
        right to request redemption directly from ARC. 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, 2009   December 31, 2008
        ---------------------------------------------------------------------
                                        Number              Number
                                      of trust            of trust
        (units thousands)                units         $     units         $
        ---------------------------------------------------------------------
        Balance, beginning of year     216,435   2,600.7   210,232   2,465.7
        Issued for cash                 15,474     253.0         -         -
        Issued on conversion of ARL
         exchangeable shares (Note 16)     572       8.6       517       7.6
        Issued on exercise of
         employee rights                     -         -       238       4.2
        Distribution reinvestment
         program                         4,134      67.0     5,448     123.2
        Trust unit issue costs, net
         of tax(1)                           -     (11.7)        -         -
        ---------------------------------------------------------------------
        Balance, end of year(2)        236,615   2,917.6   216,435   2,600.7
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) Amount is net of tax of $2.1 million for the period ended
            December 31, 2009.
        (2) The number of Trust units outstanding increased significantly on
            January 5, 2010. Refer to Note 23 for further details.

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

        ---------------------------------------------------------------------
                                           Three Months        Twelve Months
                                               Ended               Ended
                                            December 31         December 31
        ---------------------------------------------------------------------
        (units thousands)                 2009      2008      2009      2008
        ---------------------------------------------------------------------
        Weighted average trust
         units(1)                      236,138   215,579   233,025   213,259
        Trust units issuable on
         conversion of exchangeable
         shares(2)                       2,369     2,748     2,369     2,748
        Dilutive impact of rights(3)         -         2         -        50
        ---------------------------------------------------------------------
        Diluted trust units and
         exchangeable shares           238,507   218,329   235,394   216,057
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) Weighted average trust units exclude trust units issuable for
            exchangeable shares.
        (2) Diluted trust units include trust units issuable for outstanding
            exchangeable shares at the year-end exchange ratio.
        (3) There are no rights outstanding as of December 31, 2009 and
            therefore, no dilutive impact. Previously outstanding rights were
            dilutive and therefore were included in the diluted unit
            calculation for 2008.

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

    18. DEFICIT AND ACCUMULATED OTHER COMPREHENSIVE (LOSS) INCOME

        ---------------------------------------------------------------------
                                                   December 31,  December 31,
                                                          2009          2008
        ---------------------------------------------------------------------
        Accumulated earnings                        $  2,946.9    $  2,724.1
        Accumulated distributions                     (3,525.5)     (3,227.0)
        ---------------------------------------------------------------------
        Deficit                                         (578.6)       (502.9)
        Accumulated other comprehensive (loss) income     (0.6)          1.9
        ---------------------------------------------------------------------
        Deficit and accumulated other comprehensive
         (loss) income                              $   (579.2)   $   (501.0)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

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

        ---------------------------------------------------------------------
                                                   December 31,  December 31,
                                                          2009          2008
        ---------------------------------------------------------------------
        Unrealized gains and losses on financial
         instruments designated as cash flow
         hedges                                     $     (0.7)   $      2.0
        Net unrealized gains and losses on
         available-for-sale reclamation funds'
         investments                                       0.1          (0.1)
        ---------------------------------------------------------------------
        Accumulated other comprehensive (loss)
         income, end of year                        $     (0.6)   $      1.9
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    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        Twelve Months
                                               Ended               Ended
                                            December 31         December 31
        ---------------------------------------------------------------------
                                          2009      2008      2009      2008
        ---------------------------------------------------------------------
        Cash flow from operating
         activities                  $   143.2 $   209.4 $   497.4 $   944.4
        Deduct:
          Cash withheld to fund
           current period capital
           expenditures                  (70.8)    (80.9)   (194.3)   (372.2)
          Net reclamation fund
           contributions                  (1.5)     (1.3)     (4.6)     (2.2)
        ---------------------------------------------------------------------
        Distributions(1)                  70.9     127.2     298.5     570.0
        Accumulated distributions,
         beginning of period           3,454.6   3,099.8   3,227.0   2,657.0
        ---------------------------------------------------------------------
        Accumulated distributions,
         end of period               $ 3,525.5 $ 3,227.0 $ 3,525.5 $ 3,227.0
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Distributions per unit(2)    $    0.30 $    0.59 $    1.28 $    2.67
        Accumulated distributions
         per unit, beginning of
         period                      $   24.68 $   23.11 $   23.70 $   21.03
        Accumulated distributions
         per unit, end of period(3)  $   24.98 $   23.70 $   24.98 $   23.70
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) Distributions include accrued and non-cash amounts of
            $14.9 million and $56.2 million for the three and twelve months
            ended December 31, 2009, respectively ($9.7 million and
            $111.2 million for the same periods in 2008).
        (2) Distributions per trust unit reflect the sum of the per trust
            unit amounts declared monthly to unitholders.
        (3) Accumulated distributions per unit reflect the sum of the per
            trust unit amounts declared monthly to unitholders since the
            inception of ARC in July 1996.


    20. TRUST UNIT INCENTIVE RIGHTS PLAN

        The Trust Unit Incentive Rights Plan (the "Rights Plan") was
        established in 1999 and authorized ARC 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 the Whole
        Trust Unit Incentive Plan (see Note 21). During 2008 the remaining
        238,000 rights were exercised, at a weighted average exercise price
        of $10.40. As at December 31, 2008 all rights issued under the Rights
        Plan had been exercised or cancelled.

    21. WHOLE TRUST UNIT INCENTIVE PLAN

        The Whole Trust Unit Incentive Plan (the "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 ARC compared to its peers
        based on a performance multiplier. The performance multiplier is
        based on the percentile rank of ARC'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.

        During the year, cash payments of $16.6 million were made to
        employees relating to the Whole Unit Plan compared to $28.2 million
        in 2008. In October 2008, vesting periods were revised from April and
        October to March and September of each year commencing in 2009.

        Non-cash compensation expense associated with the Whole Unit Plan is
        determined based on the intrinsic value of the Whole Trust Units at
        each period end and is expensed in the statement of income and
        capitalized on the balance sheet over the vesting period. As the
        value of the RTUs and PTUs is dependent upon the trust unit price,
        the expense recorded may fluctuate over time.

        ARC recorded non-cash compensation expense of $(0.1) million and
        $0.7 million to general and administrative and operating expenses,
        respectively, and capitalized $0.1 million to property, plant and
        equipment in the year ended December 31, 2009 for the estimated
        change in the Plan liability ($1.1 million, $(0.1) million, and
        $0.6 million for the year ended December 31, 2008). The non-cash
        compensation expense was based on the December 31, 2009 unit price of
        $19.94 ($20.10 at December 31, 2008), accrued distributions, a
        performance multiplier, and the estimated number of units to be
        issued on maturity.

        The following table summarizes the RTU and PTU movement for the year
        ended December 31, 2009:

        ---------------------------------------------------------------------
        (thousands)                         Number of RTUs    Number of PTUs
        ---------------------------------------------------------------------
        Balance, beginning of year                     756               959
        Granted                                        703               635
        Vested                                        (355)             (261)
        Forfeited                                      (52)              (28)
        ---------------------------------------------------------------------
        Balance, end of year                         1,052             1,305
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        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,
                                                          2009          2008
        ---------------------------------------------------------------------
        Balance, beginning of year                  $     31.9    $     30.3
        Change in net liabilities in the year
          General and administrative expense              (0.1)          1.1
          Operating expense                                0.7          (0.1)
          Property, plant and equipment                    0.1           0.6
        ---------------------------------------------------------------------
        Balance, end of year(1)                     $     32.6    $     31.9
        ---------------------------------------------------------------------
        Current portion of liability(2)                   22.4          18.8
        ---------------------------------------------------------------------
        Accrued long-term incentive compensation    $     10.9    $     14.2
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) Includes $0.7 million of recoverable amounts recorded in accounts
            receivable as at December 31, 2009 ($1.1 million for 2008).
        (2) Included in accounts payable and accrued liabilities on the
            Consolidated Balance Sheet.

    22. COMMITMENTS AND CONTINGENCIES

        Following is a summary of ARC's contractual obligations and
        commitments as at December 31, 2009:

        ---------------------------------------------------------------------
                                             Payments Due by Period
        ---------------------------------------------------------------------
                                             2011-    2013-   There-
        ($ millions)                2010     2012     2014    after    Total
        ---------------------------------------------------------------------
        Debt repayments(1)          34.8    571.7    107.4    132.2    846.1
        Interest payments(2)        20.1     35.5     24.2     20.8    100.6
        Reclamation fund
         contributions(3)            4.9      8.9      7.7     64.2     85.7
        Purchase commitments        41.2     37.1     15.9     14.9    109.1
        Transportation
         commitments(4)              4.8     26.6     24.2      7.1     62.7
        Operating leases             4.0     13.0     14.9     74.4    106.3
        Risk management
         contract premiums(5)        1.6        -        -        -      1.6
        ---------------------------------------------------------------------
        Total contractual
         obligations               111.4    692.8    194.3    313.6  1,312.1
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        (1) Long-term and short-term debt.
        (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 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, ARC 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, 2009 on
        the balance sheet as part of risk management contracts.

        ARC enters into commitments for capital expenditures in advance of
        the expenditures being made. At a given point in time, it is
        estimated that ARC 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. ARC's 2010 capital budget has been approved by the Board at
        $610 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 2010 capital budget of $610 million includes approximately
        $20 million for leasehold development costs related to ARC's new
        office space in downtown Calgary. The operating lease commitments for
        the new space are included in the table above.

        ARC 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 ARC'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 5, 2010 ARC issued 13 million trust units at a price of
        $19.40 per trust unit for total net proceeds of approximately
        $240 million. A portion of the net proceeds has been used to repay
        bank indebtedness of approximately $180 million which was incurred to
        fund the Ante Creek purchase outlined in Note 4, with the remainder
        used to repay other outstanding bank indebtedness.

    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 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.

ARC Energy Trust is one of Canada's largest conventional oil and gas royalty trusts with a current enterprise value of approximately $6 billion. The Trust currently has an interest in oil and gas production of approximately 65,000 barrels of oil equivalent per day from seven 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 RESOURCES LTD.

    John P. Dielwart,
    Chief Executive Officer
    

%SEDAR: 00015954E %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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