ARC Energy Trust announces fourth quarter and year-end 2007 results



    CALGARY, Feb. 14 /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, 2007.

    
                                    Three Months Ended   Twelve Months Ended
                                         December 31           December 31
                                       2007       2006       2007       2006
    -------------------------------------------------------------------------
    FINANCIAL
    ($CDN millions, except per
     unit and per boe amounts)
    Revenue before royalties          338.0      292.5    1,251.6    1,230.5
      Per unit(1)                      1.59       1.42       5.95       6.02
      Per boe                         57.42      49.95      54.67      53.46
    Cash flow from operating
     activities(2)                    173.7      159.3      704.9      734.0
      Per unit(1)                      0.82       0.77       3.35       3.59
      Per boe                         29.51      27.22      30.79      31.89
    Net income                        106.3       56.6      495.3      460.1
      Per unit(3)                      0.51       0.28       2.39       2.28
    Distributions                     125.8      122.3      498.0      484.2
      Per unit(1)                      0.60       0.60       2.40       2.40
      Per cent of cash flow from
       operating activities(2)           72         77         71         66
    Net debt outstanding(4)           752.7      739.1      752.7      739.1
    Total capital expenditures
     and net acquisitions             144.3      214.9      439.7      496.3
    OPERATING
    Production
      Crude oil (bbl/d)              28,682     29,605     28,682     29,042
      Natural gas (mmcf/d)            187.4      179.5      180.1      179.1
      Natural gas liquids (bbl/d)     4,067      4,144      4,027      4,107
      Total (boe/d)                  63,989     63,663     62,723     63,056
    Average prices
      Crude oil ($/bbl)               77.53      58.26      69.24      65.26
      Natural gas ($/mcf)              6.32       6.99       6.75       6.97
      Natural gas liquids ($/bbl)     62.75      46.51      54.79      52.63
      Oil equivalent ($/boe)          57.26      49.82      54.54      53.33
    Operating netback ($/boe)
      Commodity and other revenue
       (before hedging)(5)            57.42      49.95      54.67      53.46
      Transportation costs            (0.69)     (0.64)     (0.72)     (0.63)
      Royalties                      (10.46)     (8.80)     (9.59)     (9.66)
      Operating costs                 (9.64)     (9.13)     (9.54)     (8.49)
      Netback (before hedging)        36.63      31.37      34.82      34.68
    -------------------------------------------------------------------------
    TRUST UNITS
    (millions)
    Units outstanding,
     end of period                    210.2      204.3      210.2      204.3
    Units issuable for
     exchangeable shares                2.9        2.9        2.9        2.9
    Total units outstanding and
     issuable for exchangeable
     shares, end of period            213.2      207.2      213.2      207.2
    Weighted average units(6)         212.5      206.5      210.2      204.4
    -------------------------------------------------------------------------
    TRUST UNIT TRADING STATISTICS
    ($CDN, except volumes) based
     on intra-day trading
    High                              21.55      29.22      23.86      30.74
    Low                               18.90      19.20      18.90      19.20
    Close                             20.40      22.30      20.40      22.30
    Average daily volume
     (thousands)                        624      1,125        597        706
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (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 2007 would be $194 million
        ($0.91 per unit) and year-to-date 2007 Cash Flow would be
        $728.8 million ($3.47 per unit). Distributions as a percentage of
        Cash Flow would be 65 per cent for the fourth quarter of 2007 and 68
        per cent for year-to-date 2007. Please refer to the non-GAAP measures
        section in the MD&A for further details.
    (3) Net income per unit is based on net income after non-controlling
        interest divided by weighted average trust units outstanding
        (excluding trust units issuable for exchangeable shares).
    (4) Net debt excludes current unrealized amounts pertaining to risk
        management contracts and the current portion of future income taxes.
    (5) Includes other revenue.
    (6) Includes trust units issuable for outstanding exchangeable shares at
        period end.


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

    -  Cash flow from operating activities in the fourth quarter of 2007
       increased nine per cent to $173.7 million ($0.82 per unit) from
       $159.4 million ($0.77 per unit) in the same period of 2006. Excluding
       changes in working capital and site restoration and reclamation
       expenditures, Cash Flow increased 11 per cent to $194 million
       ($0.91 per unit) from $174.4 million ($0.85 per unit) in the fourth
       quarter of 2006, principally due to a 15 per cent increase in the
       Trust's average realized commodity price.

    -  Prior to hedging activities, ARC's total realized commodity price was
       $57.26 per boe in the fourth quarter of 2007, compared to $49.82 per
       boe received prior to hedging in the fourth quarter of 2006 as a
       result of high oil prices that were partially offset by softer gas
       prices in 2007. ARC's total realized price for the full year in 2007
       was $54.54 per boe, a two per cent increase over 2006 realized prices.
       Although U.S. dollar denominated oil prices were high throughout the
       second half of the year, the strengthening of the Canadian dollar
       throughout the third quarter of 2007 offset the increase in U.S.
       dollar denominated oil prices.

    -  Production volume averaged 62,723 boe per day in 2007 compared to
       63,056 boe per day in 2006. Achieving the Trust's goal of maintaining
       consistent production in 2007 proved to be a challenge for the Trust
       as access to third party processing facilities was periodically
       restricted throughout the year. Late in the fourth quarter of 2007,
       the Trust brought on new production in both the Dawson and Pouce
       areas, achieving exit production of 65,000 boe per day in December
       2007.

    -  The Trust had an active fourth quarter, drilling 77 gross wells
       (69 net wells) on operated properties with a 100 per cent success
       rate. For the full year of 2007, the Trust drilled 278 gross wells
       (220 net wells) on operated properties; 99 gross oil wells, three
       water injection wells, and 172 gross natural gas wells with a
       99 per cent success rate.

    -  Capital expenditures for the fourth quarter, including $42.6 million
       for land purchases, were $139.3 million, bringing year-to-date capital
       expenditures to $397.2 million. Seventy-seven per cent of full year
       capital expenditures have been funded from cash flow from operating
       activities and the proceeds from the Distribution Re-investment Plan
       ("DRIP"). The remaining 23 per cent of capital expenditures along with
       minor acquisitions of $42.5 million in 2007 were entirely funded
       through debt.

    -  The majority of the $42.6 million spent on land in the fourth quarter
       (year-to-date $77.5 million), was spent in the Dawson area of British
       Columbia to purchase land adjacent to a new gas discovery that ARC
       made at Sunrise. The Sunrise 9-13-78-18W6 discovery well encountered
       150 metres of greater than three per cent porosity gas bearing rock in
       the Montney formation. Although testing is not complete, ARC believes
       the well confirms the presence of a large gas resource associated with
       the Sunrise lands.

    -  The Trust recorded all-in annual Finding, Development and Acquisition
       ("FD&A") cost of $19.00 per barrel of oil equivalent ("boe") in 2007
       before consideration of future development capital ("FDC") for the
       proved plus probable reserves category.  This is a 15 per cent
       reduction from the $22.42 per boe FD&A cost realized in 2006.
       Including FDC, the FD&A cost was $20.03 per boe. The three year
       average FD&A cost is $16.57 per boe for the proved plus probable
       category before FDC; including FDC, the three year average FD&A cost
       is $19.19 per boe. For additional information please refer to the
       reserves news release dated February 14, 2008 (posted on
       www.sedar.com).

    -  Based on our operating netback of $34.82 per boe, the one year recycle
       ratio is 1.8 times, using $19 per boe proved plus probable FD&A cost
       prior to FDC.

    -  The Trust distributed $125.8 million in the fourth quarter of 2007
       with full year distributions of $498 million. The Trust announced 2008
       first quarter distributions will remain at $0.20 per unit per month, a
       level that has been maintained since October 2005. Since inception in
       1996, the Trust has distributed $21.03 per unit for a total of
       $2.66 billion.

    -  Subsequent to year-end 2007, ARC purchased a 50 per cent working
       interest in five sections of land at Sunrise in northeastern British
       Columbia that are contiguous to the lands purchased during 2007.

    -  The Trust posted record net income of $495.3 million in 2007 that is
       an eight per cent increase over the $460.1 million recorded in
       2006.

    NEW BOARD APPOINTMENT
    ---------------------

    -  ARC is pleased to announce the appointment of James C. Houck to ARC's
       Board of Directors, effective February 14, 2008. Mr. Houck is an
       independent businessman with over 25 years of energy industry
       experience, most recently as President & CEO of Western Oil Sands. The
       majority of his business career was spent with ChevronTexaco Inc,
       where he held a number of senior officer positions, including
       President, Worldwide Power and Gasification, Inc, and Vice President
       and General Manager, Alternate Energy Dept.  Earlier in his career,
       Mr. Houck held various positions of increasing responsibility in
       Texaco's conventional oil and gas operations. Mr. Houck, with his
       experience in the oil and gas sector will be an asset to our Board.

    REGULATORY CHANGES
    ------------------

    -  On October 25, 2007, the Alberta Government announced increases in the
       royalty rates that will result in an approximate 10 per cent increase
       in the Trust's royalty rates from approximately 18 per cent of revenue
       to 20 per cent of revenue commencing on January 1, 2009. The impact of
       the royalty increase was to decrease the net present value of the
       Trust's reserves by approximately two to three per cent when using a
       10 per cent discount rate and using GLJ forecast prices as at
       January 1, 2008. The New Alberta Royalty Framework will impact future
       drilling decisions in order for the Trust to maintain acceptable rates
       of return on its capital deployed.

    -  On October 30, 2007, the Finance Minister announced, as part of the
       2007 Economic Statement, changes to the tax system including reduction
       of the corporate income tax rate from 22.1 per cent to 15 per cent by
       2012. The reductions will be phased in between 2008 and 2012.
       Legislation enacting the measures announced in the Economic Statement
       received Royal Assent on December 14, 2007. The reduction in the
       general corporate tax rate will also apply to the taxation of Income
       Trusts, reducing the combined federal and deemed provincial tax rate
       for distributions to 28 per cent in 2012.
    

    MANAGEMENT'S DISCUSSION AND ANALYSIS
    ------------------------------------
    This management's discussion and analysis ("MD&A") is the Trust
management's analysis of its financial performance and significant trends or
external factors that may affect future performance. It is dated February 13,
2008 and should be read in conjunction with the audited consolidated financial
statements for the year ended December 31, 2007 and the audited consolidated
financial statements and MD&A for the year ended December 31, 2006 and MD&A
for the quarters ended March 31, 2007, June 30, 2007, September 30, 2007 as
well as the Trust's Annual Information Form.
    The MD&A contains forward-looking statements and readers are cautioned
that the MD&A should be read in conjunction with the Trust's disclosure under
"Forward-Looking Statements" included at the end of this MD&A.

    Non-GAAP Measures

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

    Executive Overview

    ARC Energy Trust ("the Trust") is one of the top 20 producers of
conventional oil and gas in western Canada. In terms of oil and gas entities
operating in western Canada and listed on the Toronto Stock Exchange, ARC
ranks 14 with a total capitalization as at February 13, 2008 of $5.7 billion
based on a closing unit price of $23.15.
    It is the Trust's objective to provide superior and sustainable long-term
returns to unitholders by focusing on the key strategic objectives of the
business plan. The Trust, which to date has conducted business exclusively in
western Canada, acquires, develops and optimizes oil and natural gas
properties to generate a cash flow stream. The Trust at December 31, 2007,
held an interest in an excess of 18,000 wells with approximately 6,400 wells
operated by the Trust and the remainder operated by joint venture partners,
primarily major oil and gas companies. ARC's 2007 production averaged 62,723
boe per day of which 74 per cent was operated by the Trust. The Trust's
business plan is to continually develop its reserves and/or acquire new
reserves in order to maintain its productive capacity while distributing the
remainder of its cash flows to unitholders in the form of monthly
distributions. The Trust employs a conservative payout policy to provide for
cash funding of a portion of ongoing capital development programs and
maintaining low debt levels to facilitate further growth.
    The key objectives of the Trust's business plan are identified below. The
Trust was successful in meeting all of its objectives in 2007 as discussed
below and will continue to focus on these items in 2008.

    
    -  Managing commodity price risk - Commodity prices are by far the key
       variable in determining the profitability of the Trust. Each $1 per
       barrel change in the Canadian price of oil impacts the annual revenue
       of the Trust by approximately $10 million and each $0.25 per mcf
       change in natural gas prices at AECO impacts annual revenue by
       $16 million. Commodity prices are outside of management's control,
       however, it is a strategic objective of the Trust to maintain a
       balanced production profile between natural gas and crude oil. Also,
       the Trust maintains an active risk management program to
       protect a portion of cash flows giving greater certainty to
       distributions and increasing the certainty that acceptable rates of
       returns are achieved on capital deployed during the course of the
       year.

    -  Replacing annual reserves - The Trust's proved plus probable reserves
       were maintained after producing 22.9 mmboe throughout 2007. As at
       December 31, 2007 company interest reserves of 286.4 mmboe were within
       one per cent of the 286.1 mmboe recorded as at December 31, 2006. The
       reserves were slightly increased through a combination of the $397.2
       million 2007 capital development program and property acquisitions
       (net of dispositions) of $42.5 million. The Trust recorded all-in
       annual Finding, Development and Acquisition ("FD&A") cost of $19.00
       per barrel of oil equivalent ("boe") in 2007 before consideration of
       future development capital ("FDC") for the proved plus probable
       reserves category.  This is a 15 per cent reduction from the $22.42
       per boe FD&A cost realized in 2006. Including FDC, the FD&A cost was
       $20.03 per boe. For additional information please refer to the
       reserves news release dated February 14, 2008 (posted on
       www.sedar.com).

    -  Ensuring acquisitions are strategic and enhance unitholder returns -
       The Trust added producing properties in southeast Saskatchewan that
       were synergistic with the Trust's existing operations in 2007 and also
       significantly increased its land ownership in northeastern British
       Columbia providing an increase in its inventory of future development
       opportunities.

    -  Controlling costs - The Trust has been diligent in ensuring that costs
       incurred for capital projects were reasonable and competitive amongst
       service providers, which has led to a moderate cost savings throughout
       2007. The Trust drills approximately 300 wells per year that are added
       to its operating base. It is expected that operating costs will
       continue to increase over time as there is a high percentage of fixed
       costs for the Trust's properties that results in a trend of increasing
       operating costs as new production is brought on to replace declines on
       existing properties.

    -  Conservatively utilizing debt - The Trust's net debt levels were
       under 15 per cent of total capitalization and debt to 2007 cash flow
       from operating activities was less than 1.1 times for the year ended
       2007. The Trust's debt levels are one of the lowest in the oil and
       gas sector.

    -  Continuously developing the expertise of our staff and seeking to hire
       and retain the best in the industry - The Trust runs an active
       training and development program for its employees and encourages
       personal development. The Trust continues to assess compensation
       levels in the industry to ensure that the Trust's compensation is
       competitive in order to attract and retain the best employees. The
       Trust's long-term incentive plan for employees is directly tied to the
       Trust's units providing alignment between employees and investors.

    -  Building relationships and conducting business in a way that is viewed
       as fair and equitable - ARC employees, leadership team and directors
       work hard to build the ARC "franchise value" through honest,
       transparent dealings with our business partners. "Treating all people
       with respect" is a key message inside and outside the organization.
       This basic business fundamental allows us to build enduring
       relationships with joint venture partners, land owners, investors,
       banks and lending institutions, governments and the investment
       community.

    -  Promoting the use of proven and effective technologies - The Trust
       continues to research new technologies in an effort to conduct its
       operations in the most efficient and cost effective manner. The Trust
       has committed a portion of its 2008 capital expenditure budget towards
       continued research into tertiary recovery methods.

    -  Being an industry leader in health, safety and environmental
       performance - The Trust continues to focus on operating
       in a safe, reliable and responsible fashion. The Trust is committed to
       the platinum level of CAPP Stewardship reporting and continues to
       achieve Gold Level Champion reporter status under the Canada Climate
       Change voluntary climate registry initiative. The Trust's commitment
       to pursue additional CO(2) injection opportunities is expected to have
       the two-fold benefit of enhanced recovery of reserves and the capture
       and containment of CO(2) emissions that will benefit the environment.
       The Trust's commitment to safety is evidenced by zero lost time
       incidents for both employees and contract employees of the Trust in
       2007.

    -  Continuing to actively support local initiatives in the communities in
       which we live and work - The Trust is very actively involved in
       charitable and philanthropic causes both in Calgary and in the rural
       communities in which it operates. ARC continued to be a strong
       supporter of the United Way, Alberta Cancer Foundation, Canadian
       Sport Centre Calgary, Alberta Children's Hospital and many
       community organizations in rural centres. The Trust allocates up to
       0.5 per cent of its net income for donations, which resulted in $1.8
       million of cash donations made to charitable organizations in 2007.
       The Trust also provided business expertise and employee volunteers to
       charities.
    
    Historical Performance

    Management and the Trust's directors are committed to providing superior
long-term returns to unitholders. In the future the Trust's business strategy
will continue to be reviewed to address changes in the business and regulatory
environment in order to ensure that unitholder value is optimized. The Trust,
while primarily focused on adding value through internal development of
drilling opportunities, continually looks to execute minor property
acquisitions and dispositions in order to enhance and streamline the Trust's
portfolio of oil and natural gas assets. The Trust will continue to assess
larger accretive acquisition opportunities. Acquisitions are evaluated
internally and acquisitions in excess of $25 million are subject to Board
approval.

    The following chart illustrates ARC's production and reserves per unit
that have been achieved while making distributions over the last three years,
of $6.79 per unit or $1.4 billion.

    
    -------------------------------------------------------------------------
    Per Trust Unit                                2007       2006       2005
    -------------------------------------------------------------------------
    Normalized production per unit(1)             0.30       0.31       0.32
    Normalized reserves per unit(1)               1.35       1.40       1.51
    Distributions per unit                       $2.40      $2.40      $1.99
    -------------------------------------------------------------------------

    (1) Normalized indicates that all years as presented have been adjusted
        to reflect a net debt to capitalization of 15 per cent. It is assumed
        that additional trust units were issued (or repurchased) at a period
        end price for the reserves per unit calculation and at an annual
        average price for the production per unit calculation in order to
        achieve a net debt balance of 15 per cent of total capitalization
        each year. The normalized amounts are presented to enable
        comparability of annual per unit values.
    

    The result of the Trust's business plan has been providing unitholders
with the following one, three and five year returns, on the basis of
reinvestment of distributions in trust units as follows:

    
    -------------------------------------------------------------------------
    Total Returns                                           Three
    ($ per unit except for per cent)          One Year       Year  Five Year
    -------------------------------------------------------------------------
    Distributions per unit                     $  2.40    $  6.79    $ 10.39
    Capital appreciation per unit              $ (1.90)   $  2.50    $  8.50
    Total return per unit                      $  0.50    $  9.29    $ 18.89
    Annualized total return per unit           %   2.3    %  15.3    %  24.3
    -------------------------------------------------------------------------
    

    To the end of 2007, the Trust has provided cumulative distributions of
$21.03 per unit and capital appreciation of $10.40 per unit for a total return
of $31.43 per unit (21.9 per cent annualized total return) for unitholders who
invested in the Trust at inception in 1996. The Trust has announced 2008
distributions of $0.20 per unit per month through March 2008.

    Regulatory Changes

    Beyond 2008, regulatory issues include the implementation of new royalty
rates for production in the Province of Alberta in 2009. The Alberta
Government announced increases in the royalty rates in 2007 that will result
in an approximate 10 per cent increase in the Trust's royalty rates from
approximately 18 per cent of revenue to 20 per cent of revenue commencing on
January 1, 2009. The impact of the royalty increase was to decrease the net
present value of the Trust's reserves by approximately two to three per cent
when using a 10 per cent discount rate and using GLJ forecast prices as at
January 1, 2008. The New Alberta Royalty Framework will impact future drilling
decisions in order for the Trust to maintain acceptable rates of return on its
capital deployed.
    Further, the Trust will be subject to a Federal income tax on
distributions commencing on January 1, 2011. The Trust's management is
reviewing the options for structural changes and working closely with legal
and business advisors to determine a course of action and potential
restructuring to maximize value in the best interest of unitholders.

    2007 Annual Financial and Operational Results

    Following is a discussion of ARC's 2007 annual financial and operating
results.

    Financial Highlights

    
    -------------------------------------------------------------------------
    (CDN $ millions, except
     per unit and volume data)                    2007       2006   % Change
    -------------------------------------------------------------------------
    Cash flow from operating activities          704.9      734.0         (4)
    Cash flow from operating activities
     per unit(1)                                  3.35       3.59         (7)
    Net income                                   495.3      460.1          8
    Net income per unit(2)                        2.39       2.28          5
    Distributions per unit(3)                     2.40       2.40          -
    Distributions as a per cent of cash
     flow from operating activities                 71         66          8
    Average daily production (boe/d)(4)         62,723     63,056         (1)
    -------------------------------------------------------------------------

    (1) Per unit amounts are based on weighted average trust units
        outstanding plus trust units issuable for exchangeable shares at
        year-end.
    (2) Based on net income after non-controlling interest divided by
        weighted average trust units outstanding excluding trust units
        issuable for exchangeable shares.
    (3) Based on number of trust units outstanding at each cash distribution
        date.
    (4) Reported production amount is based on company interest before
        royalty burdens. Where applicable in this MD&A natural gas has been
        converted to barrels of oil equivalent ("boe") based on 6 mcf:1 bbl.
        The boe rate is based on an energy equivalent conversion method
        primarily applicable at the burner tip and does not represent a value
        equivalent at the well head. Use of boe in isolation may be
        misleading.
    

    Net Income

    Net income in 2007 was $495.3 million ($2.39 per unit), an increase of
$35.2 million from $460.1 million ($2.28 per unit) in 2006. This resulted from
a $13 million gain on the sale of the Trust's long-term investment as well as
a significant future income tax recovery of $121.3 million, attributed to the
reduction in legislated future corporate income tax rates in addition to
recording a future tax asset for tax legislation commencing in 2011 related to
ARC Energy Trust.

    Cash Flow from Operating Activities

    Cash flow from operating activities decreased by four per cent in 2007 to
$704.9 million from $734 million in 2006. The decrease in 2007 cash flow from
operating activities is detailed in the following table.

    
    -------------------------------------------------------------------------
                                                           ($ per
                                                            trust         (%
                                           ($ millions)      unit)  variance)
    -------------------------------------------------------------------------
    2006 Cash flow from Operating Activities     734.0       3.59
    -------------------------------------------------------------------------
    Volume variance                               (6.5)     (0.03)        (1)
    Price variance                                27.6       0.14          4
    Cash gains on risk management contracts      (15.1)     (0.07)        (2)
    Royalties                                      2.8       0.01          -
    Expenses:
      Transportation                              (1.9)     (0.01)         -
      Operating(1)                               (23.9)     (0.11)        (3)
      Cash G&A                                    (9.6)     (0.05)        (1)
      Interest                                    (5.2)     (0.03)        (1)
      Taxes                                        0.4          -          -
      Realized foreign exchange gain              (0.4)         -          -
    Weighted average trust units                     -      (0.10)         -
    Non-cash and other items(2)                    2.7       0.01          -
    -------------------------------------------------------------------------
    2007 Cash flow from Operating Activities     704.9       3.35         (4)
    -------------------------------------------------------------------------

    (1) Excludes non-cash portion of LTIP expense recorded in operating
        costs.
    (2) Includes the changes in non-cash working capital and expenditures on
        site restoration and reclamation.


    Production

    Production volume averaged 62,723 boe per day in 2007 compared to 63,056
boe per day in 2006 as detailed in the table below. Late in the fourth quarter
of 2007, the Trust brought on new production in both the Dawson and Pouce
areas, achieving exit production of 65,000 boe per day in December 2007.

    -------------------------------------------------------------------------
    Production                                    2007       2006   % Change
    -------------------------------------------------------------------------
    Light & medium crude oil (bbl/d)            27,366     27,674         (1)
    Heavy oil (bbl/d)                            1,316      1,368        (13)
    Natural gas (mcf/d)                        180,086    179,067          1
    NGL (bbl/d)                                  4,027      4,170         (3)
    -------------------------------------------------------------------------
    Total production (boe/d)(1)                 62,723     63,056         (1)
    % Natural gas production                        48         47
    % Crude oil and liquids production              52         53
    -------------------------------------------------------------------------

    (1) Reported production for a period may include minor adjustments
        from previous production periods.
    

    Oil production decreased slightly to 28,682 boe per day from 29,042 boe
per day in 2006. Natural gas production was 180.1 mmcf per day in 2007,
essentially unchanged from the 179.1 mmcf per day produced in 2006. The stable
production was a result of ARC's active 2007 internal drilling program
particularly in northern and southeast Alberta as well as southwestern
Saskatchewan. The Trust drilled six horizontal natural gas wells in the Dawson
area as well as 144 natural gas wells in southeastern Alberta and southwestern
Saskatchewan during 2007.
    The Trust's objective is to maintain annual production through the
drilling of wells and other development activities. In fulfilling this
objective, there may be fluctuations in production depending on the timing of
new wells coming on-stream. During 2007, the Trust drilled 278 gross wells
(220 net wells) on operated properties; 99 gross oil wells, three water
injection wells and 172 gross natural gas wells with a 99 per cent success
rate.
    The Trust expects that 2008 full year production will be approximately
63,000 boe per day and that 310 gross wells (252 net wells) will be drilled by
ARC on operated properties with participation in an additional 140 gross wells
to be drilled on the Trust's non-operated properties. The Trust estimates that
the 2008 drilling program will add sufficient production from new wells to
offset production declines on existing properties.
    The following table summarizes the Trust's production by core area:

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

    -------------------------------------------------------------------------
                                                        2006
    Production                        Total        Oil        Gas        NGL
    Core Area(1)                     (boe/d)    (bbl/d)   (mmcf/d)    (bbl/d)
    -------------------------------------------------------------------------
    Central AB                        8,206      1,553       31.3      1,433
    Northern AB & BC                 18,897      6,194       67.6      1,452
    Pembina & Redwater               13,950      9,453       20.0      1,157
    S.E. AB & S.W. Sask.             10,743      1,071       58.0          9
    S.E. Sask. & MB                  11,260     10,771        2.2        119
    -------------------------------------------------------------------------
    Total                            63,056     29,042      179.1      4,170
    -------------------------------------------------------------------------

    (1) Provincial references: AB is Alberta, BC is British Columbia, Sask.
        is Saskatchewan, MB is Manitoba, S.E. is southeast and S.W. is
        southwest.


    Commodity Prices Prior to Hedging

    -------------------------------------------------------------------------
                                                  2007       2006   % Change
    -------------------------------------------------------------------------
    Average Benchmark Prices
    AECO gas ($/mcf)(1)                           6.61       6.98         (5)
    WTI oil (US$/bbl)(2)                         72.37      66.25          9
    USD/CAD foreign exchange rate                 0.94       0.88          7
    WTI oil (CDN $/bbl)                          77.35      75.00          3
    -------------------------------------------------------------------------
    ARC Realized Prices Prior to Hedging
    Oil ($/bbl)                                  69.24      65.26          6
    Natural gas ($/mcf)                           6.75       6.97         (3)
    NGL ($/bbl)                                  54.79      52.63          4
    -------------------------------------------------------------------------
    Total commodity revenue
     before hedging ($/boe)                      54.54      53.33          2
    Other revenue ($/boe)                         0.13       0.13          -
    Total revenue before hedging ($/boe)         54.67      53.46          2
    -------------------------------------------------------------------------

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

    Although oil prices have achieved record highs throughout 2007 peaking at
US$95.58 per barrel and averaging US$72.37 per barrel for the full year, the
strengthening of the Canadian dollar relative to the U.S. dollar was
responsible for eroding most of the gains and negatively impacted the price of
oil in Canadian dollar terms. The price of oil in U.S. dollars increased by
nine per cent for the full year of 2007, however, the Canadian dollar
equivalent increased by only three per cent. The foreign exchange rate reached
record highs in 2007 with the Canadian dollar peaking at an exchange rate of
1.09 Canadian per U.S. dollar in November 2007. The average USD/CAD foreign
exchange rate was 0.94 for the full year of 2007 and the Canadian dollar
closed on December 31, 2007 at 1.01 per U.S. dollar. The negative correlation
between the Canadian dollar and U.S. dollar denominated West Texas
Intermediate oil prices should lessen the impact on the Trust of any future
declines in the price of oil.
    The Trust's oil production consists predominantly of light and medium
crude oil while heavy oil accounts for less than three per cent of the Trust's
liquids production. The realized price for the Trust's oil, before hedging,
increased six per cent to $69.24 from $65.26 for the full year of 2006.
    Alberta AECO Hub natural gas prices, which are commonly used as an
industry reference, averaged $6.61 per mcf in 2007 compared to $6.98 per mcf
in 2006. Natural gas prices were stronger in the first half of the year but
declined throughout the third and fourth quarters. ARC's realized gas price,
before hedging, decreased by three per cent to $6.75 per mcf compared to
$6.97 per mcf in 2006. ARC's realized gas price is based on prices received at
the various markets in which the Trust sells its natural gas. ARC's natural
gas sales portfolio consists of gas sales priced at the AECO monthly index,
the AECO daily spot market, eastern and mid-west United States markets and a
portion to aggregators.
    Prior to hedging activities, ARC's total realized commodity price was
$54.67 per boe in 2007, a two per cent increase from the $53.46 per boe
received prior to hedging in 2006.

    
    Revenue

    Revenue increased to a historical high of $1.25 billion in 2007. The
increase in revenue was attributable to higher realized oil prices which were
partially offset by lower realized natural gas prices as compared to 2006.

    A breakdown of revenue is as follows:

    -------------------------------------------------------------------------
    Revenue
    ($ millions)                                  2007       2006   % Change
    -------------------------------------------------------------------------
    Oil revenue                                  724.9      691.8          5
    Natural gas revenue                          443.4      455.7         (3)
    NGL revenue                                   80.5       80.1          -
    -------------------------------------------------------------------------
    Total commodity revenue                    1,248.8    1,227.6          2
    Other revenue                                  2.9        2.9          -
    Total revenue                              1,251.7    1,230.5          2
    -------------------------------------------------------------------------
    

    Risk Management and Hedging Activities

    ARC continues to maintain an ongoing risk management program to reduce
the volatility of revenues in order to increase the certainty of
distributions, protect acquisition economics, and fund capital expenditures.
The risk management program was revised in 2005 to maintain a significant
portion of upside price participation on production volumes that has resulted
in cash hedging gains, net of premiums, of $14.1 million in 2007 and $29.3
million in 2006.
    The Trust currently limits the amount of forecast production that can be
hedged to 50 per cent with the other 50 per cent of production being sold for
market prices.
    During 2007, the WTI U.S. dollar posted oil price increased to a high of
US$95.98 per barrel with an annual average posted price of US$72.37 per
barrel. From a corporate perspective this has had a positive impact on the
Trust's revenue, however, this has resulted in a loss recorded for the Trust's
oil risk management contracts. During 2007 ARC had an unrealized total
mark-to-market loss year-over-year of $55.9 million with a net unrealized
mark-to-market liability of $68 million as at December 31, 2007. The
mark-to-market values represent the market price to buy-out the Trust's
contracts as of December 31, 2007 and may be different from what will
eventually be realized.
    The most significant portion of ARC's total unrealized mark-to-market
position at year end was a $35.3 million loss relating to the Redwater and
NPCU hedged volumes of 5,000 bbl per day, which limits upside price potential
to $85 and $90 per barrel in 2008 and 2009 respectively. When these properties
were acquired in 2005, the acquisition economics were based on crude oil
prices of approximately CAD$57.50 per barrel. The remainder of the mark-to-
market loss results in potential settling of commodity, foreign exchange and
interest rates above the level of the Trust's hedges as disclosed in Note 11
to the Consolidated Financial Statements.
    During 2007 ARC entered into a number of hedging transactions including
the following:

    
    -   Energy equivalent swap: ARC has entered into an energy equivalent
        swap in order to shift its price exposure to be more heavily weighted
        towards crude oil for the period of April 1 through October 31, 2008.
        Through the use of financial contracts, ARC has rebalanced its price
        exposure from a forecasted 50:50 to a 52:48 oil-gas weighting. ARC
        achieved this rebalancing by selling AECO natural gas at $7.10 per GJ
        and buying crude oil at CDN$73.95 per barrel.

    -   In light of the significant increase in value of the Canadian dollar
        during the last 12 months, ARC implemented a program to lock in
        exchange rates on future principal repayments on U.S. dollar
        denominated senior secured notes. These transactions effectively lock
        in the unrealized foreign exchange gains on the U.S. denominated
        debt. Although the unrealized foreign exchange gains will continue to
        fluctuate quarter-to-quarter with changes in the exchange rate, these
        financial transactions have effectively fixed the economic gains of
        the change in exchange rates from the rate at which the U.S.
        denominated debt was issued and the rate at which the future payments
        have been committed. At the end of the year ARC had US$218 million of
        U.S. denominated senior secured debt outstanding (CDN$215.5 million)
        requiring annual principal repayments of varying amounts extending
        until December 15, 2017. As at December 31, 2007, ARC had locked in
        the foreign exchange rate for a total of US$127.2 million of its
        principal repayments in years 2012 through 2017 at an average rate
        with the Canadian dollar slightly greater than par (1.02 CAD$/US$).

    -   Natural gas protection through to March 2009: In the fall of 2007 ARC
        entered into natural gas collars to protect prices as far out as
        March 2009. For the period from November 2008 to March 2009, ARC has
        purchased NYMEX natural gas puts at $8.50 per mmbtu and sold calls at
        $11.00 per mmbtu.

    The percentage of forecast volumes hedged in 2008 is: 43 per cent in the
first quarter, 36 per cent in the second quarter, 26 per cent in the third
quarter and 23 per cent in the fourth quarter.

    The following table is an indicative summary of the Trust's positions for
crude oil, natural gas and related foreign exchange for the next twelve months
as at December 31, 2007.

    -------------------------------------------------------------------------
    Hedge Positions
    As at December 31, 2007(1)(2)
                                          Q1 2008               Q2 2008
    -------------------------------------------------------------------------
    Crude Oil                       US$/bbl    bbl/day    US$/bbl    bbl/day
    -------------------------------------------------------------------------
    Sold Call                         94.08     19,000      89.04     13,000
    Bought Put                        75.14     20,000      70.47     15,500
    Sold Put                          54.91     11,500      54.96     11,500
    -------------------------------------------------------------------------
    Natural Gas                     CDN$/GJ     GJ/day    CDN$/GJ     GJ/day
    -------------------------------------------------------------------------
    Sold Call                          8.02     47,478       8.41     41,101
    Bought Put                         6.87     47,478       6.64     41,101
    Sold Put                           4.75     10,551       4.97     31.101
    -------------------------------------------------------------------------
    Foreign Exchange                CAD/USD   $Million    CAD/USD   $Million
    -------------------------------------------------------------------------
    Bought Put                       1.0750        3.0     1.0750        3.0
    Sold Put                         1.0300        3.0     1.0300        3.0
    Swap                                  -          -          -          -
    -------------------------------------------------------------------------


    -------------------------------------------------------------------------
                                          Q3 2008               Q4 2008
    -------------------------------------------------------------------------
    Crude Oil                       US$/bbl    bbl/day    US$/bbl    bbl/day
    -------------------------------------------------------------------------
    Sold Call                         90.00     10,000      90.00     10,000
    Bought Put                        68.13     10,000      68.13     10,000
    Sold Put                          51.07      7,000      51.07      7,000
    -------------------------------------------------------------------------
    Natural Gas                     CDN$/GJ     GJ/day    CDN$/GJ     GJ/day
    -------------------------------------------------------------------------
    Sold Call                          8.41     41,101       8.88     27,840
    Bought Put                         6.64     41,101       6.82     27,840
    Sold Put                           4.97     31,101       5.04     10,480
    -------------------------------------------------------------------------
    Foreign Exchange                CAD/USD   $Million    CAD/USD   $Million
    -------------------------------------------------------------------------
    Bought Put                       1.0750        3.0          -          -
    Sold Put                         1.0300        3.0          -          -
    Swap                                  -          -          -          -
    -------------------------------------------------------------------------

    (1) The prices and volumes noted above represents averages for several
        contracts and the average price for the portfolio of options listed
        above does not have the same payoff profile as the individual option
        contracts. Viewing the average price of a group of options is purely
        for indicative purposes. The natural gas price shown translates all
        NYMEX positions to an AECO equivalent price. In addition to positions
        shown here, ARC has entered into additional basis positions.
    (2) Please refer to the Trust's website at www.arcenergytrust.com under
        "Hedging Program" within the "Investor Relations" section for details
        on the Trust's hedging positions as of December 31, 2007.

    The above table should be interpreted as follows using the first quarter
2008 Crude oil hedges as an example. To accurately analyze the Trust's hedge
position, contracts need to be modeled separately as using average prices and
volumes may be misleading.

    -   If the market price is below $54.91, ARC will receive $75.14 less the
        difference between $54.91 and the market price on 11,500 barrels per
        day. For example if the market price is $54.90, the Trust will
        receive $75.13 on 11,500 barrels per day.

    -   If the market price is between $54.91 and $75.14, ARC will receive
        $75.14 on 20,000 barrels per day.

    -   If the market price is between $75.14 and $94.08, ARC will receive
        the market price on 20,000 barrels per day.

    -   If the market price exceeds $94.08, ARC will receive $94.08 on 19,000
        barrels per day and the market price for the remaining 1,000 hedged
        volumes.
    

    Gain or Loss on Risk Management Contracts

    Gain or loss on risk management contracts comprise realized and
unrealized gains or losses on risk management contracts that do not meet the
accounting definition requirements of an effective hedge, even though the
Trust considers all risk management contracts to be effective economic hedges.
Accordingly, gains and losses on such contracts are shown as a separate
category in the statement of income.
    ARC realized gains on natural gas contracts throughout the year as a
result of soft prices where ARC's floor protection level exceeded the market
price. ARC's crude oil contracts posted a loss for the year of $5.7 million as
a result of record high oil prices that exceeded some of the Trust's ceiling
contracts during the second half of the year. On foreign exchange and interest
rates, ARC realized gains during the last three quarters of the year
particularly on U.S. dollar put-spreads that protected ARC from an
appreciating Canadian dollar.

    The following is a summary of the total gain (loss) on risk management
contracts for the year-over-year change as of the 2007 year-end:

    
    -------------------------------------------------------------------------
                                                    Interest
    Risk Management Contracts  Crude Oil  Natural  & Foreign   2007     2006
    ($ millions)               & Liquids      Gas   Currency  Total    Total
    -------------------------------------------------------------------------
    Realized cash gain (loss)
     on contracts(1)                (5.7)    15.4      4.4     14.1     29.3
    Unrealized gain (loss)
     on contracts(2)               (60.2)    (2.9)     7.2    (55.9)    (4.6)
    -------------------------------------------------------------------------
    Total gain (loss) on risk
     management contracts          (65.9)    12.5     11.6    (41.8)    24.7
    -------------------------------------------------------------------------

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

    Operating Netbacks

    The Trust's operating netback, after realized hedging gains, decreased one
per cent to $35.44 per boe in 2007 compared to $35.95 per boe in 2006. The
decrease in netbacks in 2007 is primarily due to a decrease in the realized
gain on risk management contracts, a decrease in gas prices, as well as an
increase in operating costs and transportation. These items were partially
offset by a decrease in royalties and an increase in revenues as a result of
higher oil prices in 2007.

    The components of operating netbacks are shown below:

    -------------------------------------------------------------------------
                               Crude   Heavy                    2007    2006
    Netbacks                     Oil     Oil     Gas     NGL   Total   Total
    ($ per boe)               ($/bbl) ($/bbl) ($/mcf) ($/bbl) ($/boe) ($/boe)
    -------------------------------------------------------------------------
    Weighted average
     sales price               70.20   49.17    6.75   54.79   54.54   53.33
    Other revenue                  -       -       -       -    0.13    0.13
    Total revenue              70.20   49.17    6.75   54.79   54.67   53.46
    Royalties                 (11.33)  (4.34)  (1.25) (14.90)  (9.59)  (9.66)
    Transportation             (0.27)  (1.09)  (0.20)      -   (0.72)  (0.63)
    Operating costs(1)        (11.84) (12.16)  (1.26)  (7.73)  (9.54)  (8.49)
    -------------------------------------------------------------------------
    Netback prior to hedging   46.76   31.58    4.04   32.16   34.82   34.68
    Realized gain (loss) on
     risk management contracts (0.07)      -    0.23       -    0.62    1.27
    -------------------------------------------------------------------------
    Netback after hedging      46.69   31.58    4.27   32.16   35.44   35.95
    -------------------------------------------------------------------------

    (1) Operating expenses are composed of direct costs incurred to operate
        oil and gas wells. A number of assumptions have been made in
        allocating these costs between oil, heavy oil, natural gas and
        natural gas liquids production.
    

    Royalties as a percentage of pre-hedged commodity revenue net of
transportation costs remained constant at 18 per cent for both 2007 and 2006
at $9.59 per boe and $9.66 per boe respectively. The Trust has made a
preliminary assessment of the impact of the new Alberta Royalty legislation
effective January 1, 2009 and we estimate that the total royalties payable on
the Trust's production will increase by approximately 10 per cent at current
commodity prices calculated using expected 2009 production rates. This
estimate will vary based on prices, production decline of existing wells and
performance and location of new wells drilled. The 10 per cent increase in
royalties payable which equates to approximately a two per cent increase in
the Trust's royalty rate takes into account that approximately 37 per cent of
the Trust's production is outside the Province of Alberta. The royalty change
in 2009 on a property by property basis is highly variable with decreased
royalties on some properties, primarily shallow gas wells, and a doubling of
royalties on Alberta high rate oil production properties. The New Alberta
Royalty Framework will impact future drilling decisions in order for the Trust
to maintain acceptable rates of return on its capital deployed.
    Operating costs increased to $9.54 per boe compared to $8.49 per boe in
2006. Total operating costs increased $23 million or, 12 per cent, in 2007.
This increase was due to a combination of costs including the additional
operating costs associated with approximately 300 new wells brought on stream
in 2007, increased labour costs for field staff and some service providers
particularly in northern operations, increased electricity consumption and
costs for well re-activations in the Redwater and NPCU areas. There are a high
percentage of fixed operating costs for the Trust's properties resulting in a
trend of increased operating costs on a per boe basis as the properties'
production declines over time. The Trust estimates that full year 2008
operating costs will be approximately $235 million or approximately $10.20 per
boe based on annual production of approximately 63,000 boe per day.
    Transportation costs increased 14 per cent to $0.72 per boe in 2007
compared to $0.63 per boe in 2006 as a result of ongoing challenges in
Saskatchewan where shipping restrictions are in place for the Enbridge
pipeline. The Trust is required to truck all new production that exceeds our
historical capacity for the Enbridge pipeline. Investors can expect
transportation prices to increase again once the winter drilling program
begins and new production levels increase. An expansion of the Enbridge
pipeline is expected to be completed sometime in early 2008, however,
transportation costs for 2008 are still expected to increase to $0.80 per boe
based on annual production of 63,000 boe per day.

    General and Administrative Expenses and Trust Unit Incentive Compensation

    G&A net of overhead recoveries on operated properties increased four per
cent to $49.1 million in 2007 from $47.1 million in 2006. Increases in G&A
expenses for 2007 were due to increased staff levels, higher compensation
costs and increased long-term incentive benefits. As a result of a tight
labour market, the costs associated with hiring, compensating and retaining
employees and consultants have risen. The anticipated increase in G&A costs
was partially offset by higher overhead recoveries attributed to high levels
of capital and operating activity throughout 2007 and as a result of
incremental overhead charged on new and existing operated properties.
    The Trust paid out $12.7 million under the Whole Trust Unit Incentive
Plan ("Whole Unit Plan") in 2007 compared to $5.2 million in 2006
($9.6 million and $3.5 million of the payouts were allocated to G&A in 2007
and 2006, respectively, and the remainder to operating costs and property,
plant and equipment). The higher cash payment in 2007 resulted from the
Trust's first payments for performance units issued under the plan in 2004.
The next cash payment under the Whole Unit Plan is scheduled to occur in April
2008.

    The following is a breakdown of G&A and trust unit incentive compensation
expense:

    
    -------------------------------------------------------------------------
    G&A and Trust Unit Incentive
     Compensation Expense
    ($ millions except per boe)                   2007       2006   % Change
    -------------------------------------------------------------------------
    G&A expenses                                  52.7       45.8         15
    Operating recoveries                         (16.4)     (12.9)        27
    -------------------------------------------------------------------------
    Cash G&A expenses before Whole Unit Plan      36.3       32.9         10
    Cash Expense - Whole Unit Plan                 9.6        3.5        174
    -------------------------------------------------------------------------
    Cash G&A expenses including Whole Unit Plan   45.9       36.4         26
    -------------------------------------------------------------------------
    Accrued compensation - Rights Plan               -        2.5       (100)
    Accrued compensation - Whole Unit Plan         3.2        8.2        (61)
    -------------------------------------------------------------------------
    Total G&A and trust unit incentive
     compensation expense                         49.1       47.1          4
    -------------------------------------------------------------------------
    Total G&A and trust unit incentive
     compensation expense per boe                 2.15       2.05          5
    -------------------------------------------------------------------------
    

    A non-cash trust unit incentive compensation expense ("non-cash
compensation expense") of $3.2 million ($0.14 per boe) was recorded in 2007
compared to $10.7 million ($0.47 per boe) in 2006. This non-cash amount
relates to estimated costs of the Whole Unit Plan to December 31, 2007. The
2006 amounts also include estimated costs of the Trust Unit Incentive Rights
Plan ("Rights Plan") that was fully expensed at December 31, 2006 with the
exception of a small portion recorded in March 2007.

    Rights Plan

    The rights plan was replaced by a Whole Unit Plan during 2004 after which
no further rights under the rights plan were issued. The Rights Plan, provided
employees, officers and independent directors the right to purchase units at a
specified price. The rights have a five year term and vest equally over three
years. The exercise price of the rights is adjusted downwards from time to
time by the amount that distributions to unitholders, in any calendar quarter
exceed 2.5 per cent of the Trust's net book value of property, plant and
equipment. During 2007, 0.1 million rights were exercised and 0.2 million
rights remained outstanding as at December 31, 2007. All of the rights have
been fully expensed since March 31, 2007 and are scheduled to expire on or
before December 31, 2008.

    Whole Unit Plan

    In March 2004, the Board of Directors approved a new Whole Unit Plan to
replace the Rights Plan for new awards granted subsequent to the first quarter
of 2004. The new Whole Unit Plan results in employees, officers and directors
(the "plan participants") receiving cash compensation in relation to the value
of a specified number of underlying units. The Whole Unit Plan consists of
Restricted Trust Units ("RTUs") for which the number of units is fixed and
will vest over a period of three years and Performance Trust Units ("PTUs")
for which the number of units is variable and will vest at the end of three
years.
    Upon vesting, the plan participant is entitled to receive a cash payment
based on the fair value of the underlying trust units plus accrued
distributions. The cash compensation issued upon vesting of the PTUs is
dependent upon the performance of the Trust compared to its peers and
indicated by the performance multiplier. The performance multiplier is based
on the percentile rank of the Trust's total unitholder return compared to its
peers. Total return is calculated as the sum of the change in the market price
of the trust units in the period plus the amount of distributions in the
period. The performance multiplier ranges from zero, if ARC's performance
ranks in the bottom quartile, to two for top quartile performance.

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

    
    -------------------------------------------------------------------------
    Whole Unit Plan
    (units in thousands and $ millions       Number of  Number of  Total RTUs
     except per unit)                             RTUs       PTUs   and PTUs
    -------------------------------------------------------------------------
    Balance, beginning of year                     648        683      1,331
    Granted in the year                            422        362        784
    Vested in the year                            (286)      (110)      (396)
    Forfeited in the year                          (38)       (32)       (70)
    -------------------------------------------------------------------------
    Balance, end of year(1)                        746        903      1,649
    -------------------------------------------------------------------------
    Estimated distributions to vesting date(2)     226        249        475
    Estimated units upon vesting
     after distributions                           972      1,152      2,124
    Performance multiplier(3)                        -        1.7          -
    -------------------------------------------------------------------------
    Estimated total units upon vesting             972      1,958      2,931
    -------------------------------------------------------------------------
    Trust unit price at December 31, 2007       $20.40     $20.40     $20.40
    Estimated total value upon vesting           $19.8      $39.9      $59.8
    -------------------------------------------------------------------------

    (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 1.7 at December 31, 2007 based on a weighted average calculation
        of all outstanding grants. The performance multiplier is assessed
        each period end based on actual results of the Trust relative to its
        peers.

    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 unit price, the number of PTUs to be issued on vesting, and distributions.
Therefore, the expense recorded in the statement of income fluctuates over
time.
    Below is a summary of the range of future expected payments under the
Whole Unit Plan based on variability of the performance multiplier:

    -------------------------------------------------------------------------
    Value of Whole Unit Plan as at
     December 31, 2007                             Performance Multiplier
                                               ------------------------------
    (units thousands and $ millions
     except per unit)                                -        1.0        2.0
    -------------------------------------------------------------------------
    Estimated trust units to vest
      RTUs                                         972        972        972
      PTUs                                           -      1,253      2,513
    -------------------------------------------------------------------------
    Total units(1)                                 972      2,225      3,485
    -------------------------------------------------------------------------
      Trust unit price(2)                       $20.40     $20.40     $20.40
      Trust unit distributions per month(2)      $0.20      $0.20      $0.20
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Value of Whole Unit Plan upon vesting         19.8       45.4       71.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
      Officers                                     2.1       13.9       25.8
      Directors                                    1.5        1.5        1.5
      Staff                                       16.2       30.0       43.8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total payments under Whole Unit Plan(3)       19.8       45.4       71.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
      2008                                         8.8       16.0       23.1
      2009                                         6.9       14.9       23.0
      2010                                         4.1       14.5       25.0
    -------------------------------------------------------------------------

    (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
        future trust unit price of $20.40 per trust unit and distributions of
        $0.20 per unit per month based on current levels.
    (3) Upon vesting, a cash payment is made equivalent to the value of the
        underlying trust units. The payment is made on vesting dates in April
        and October of each year and at that time is reflected as a reduction
        of cash flow from operating activities.
    

    Due to the variability in the future payments under the plan, the Trust
estimates that between $19.8 million and $71.1 million will be paid out from
2008 through 2010 based on the current trust unit price, distribution levels
and the Trust's market performance relative to its peers.

    Interest Expense

    Interest expense increased to $36.9 million in 2007 from $31.8 million in
2006 due to an increase in short-term interest rates, and higher debt balances
as a result of the Trust's capital expenditure and acquisitions activity which
was funded $135.7 million with debt. As at December 31, 2007, the Trust had
$714.5 million of debt outstanding, of which $215.5 million was fixed at a
weighted average rate of 5.1 per cent and $499 million was floating at current
market rates plus a credit spread of 60 basis points. Fifty-two per cent of
the Trust's debt is denominated in U.S. dollars. The cumulative decline of
1.25 per cent in the U.S. interest rates announced in January 2008 by the
Federal Reserve Board should result in lower borrowing costs for the Trust in
2008.

    Foreign Exchange Gains and Losses

    The Trust recorded a gain of $69.4 million ($3.03 per boe) on foreign
exchange transactions compared to a loss of $4.2 million ($0.18 per boe) in
2006. These amounts include both realized and unrealized foreign exchange
gains and losses.
    Unrealized foreign exchange gains and losses are due to revaluation of
U.S. denominated debt balances. The volatility of the Canadian dollar during
the reporting period has a direct impact on the unrealized component of the
foreign exchange gain or loss. The unrealized gain/loss impacts net income but
does not impact cash flow from operating activities as it is a non-cash
amount. From December 31, 2006 to December 31, 2007, the CAD$/US$ exchange
rate has increased from 0.86 to 1.01 creating an unrealized gain of
$64.6 million on U.S. dollar denominated debt.
    Realized foreign exchange gains or losses arise from U.S. denominated
transactions such as interest payments, debt repayments and hedging
settlements. Included in the 2007 realized foreign exchange gain was a gain of
$5 million relating, in part, to a repayment of US$6 million of debt in
October 2007. The debt was issued in 2002 when the CAD$/US$ foreign exchange
rate was approximately 0.64 and strengthened considerably to 1.04 on repayment
in 2007.

    Taxes

    In 2007, a future income tax recovery of $121.3 million was included in
income compared to an $87.1 million recovery in 2006. The significant increase
in the future income tax recovery in 2007 was due to the legislated reduction
in the future corporate income tax rates in the fourth quarter of 2007 whereby
the Trust's expected future corporate income tax rate decreased to 25.8 per
cent from the 29.4 per cent prior to the rate reduction. The future income tax
recovery in 2006 was also due to legislated reductions in the future corporate
income tax rates.
    At December 31, 2007, the Trust and the Trust's subsidiaries had tax
pools of approximately $1.84 billion. The tax pools consist of $1.66 billion
of tangible and intangible capital assets, $13.8 million of non-capital loss
carry-forwards which expire at various periods to 2026, and $171.4 million of
other tax pools. Included in the above tax basis are the Trust's tax pools of
approximately $537.7 million.
    On October 31, 2006, the Finance Minister announced the Federal
Government's plan regarding the taxation of Income Trusts. Currently,
distributions paid to unitholders, other than returns of capital, are claimed
as a deduction by the Trust in arriving at taxable income whereby tax is
eliminated at the Trust level and is paid by the unitholders. The Trust tax
legislation that received Royal Assent on June 22, 2007, will result in a two-
tiered tax structure whereby distributions would first be subject to the
federal corporate income tax rate plus a deemed 13 per cent provincial income
tax at the Trust level commencing in 2011 (or earlier, if trusts that were
publicly traded as of October 31, 2006 exceed the normal growth guidelines
announced by the Minister on December 15, 2006), and then unitholders would be
subject to tax on the distribution as if it were a taxable dividend paid by a
taxable Canadian corporation. As a result, the future tax position of the
Trust, the parent entity, is now required to be reflected in the consolidated
future income tax calculation. The Trust recorded a $35.6 million one time
increase in earnings and a corresponding decrease to its future income tax
liability in the second quarter as a result of timing differences within the
Trust that had not been previously recognized. The initial recognition of
$35.6 million comprised $24.7 million for pre-2007 generated temporary
differences and $10.9 million for temporary differences relating to the
current year.
    On October 30, 2007, the Finance Minister announced, as part of the 2007
Economic Statement, changes to the tax system including reduction of the
corporate income tax rate from 22.1 per cent to 15 per cent by 2012. The
reductions will be phased in between 2008 and 2012. Legislation enacting the
measures announced in the Economic Statement received Royal Assent on
December 14, 2007. The reduction in the general corporate tax rate will also
apply to the taxation of Income Trusts, reducing the combined federal and
deemed Provincial tax rate for distributions to 28 per cent in 2012.
    The Federal Government has also indicated that they will seek to
collaborate with the provinces and territories to reach a combined federal-
provincial-territorial statutory corporate income tax rate of 25 per cent,
reflecting a 10 per cent provincial rate, equal to the current Alberta tax
rate. It is uncertain whether this collaboration will also affect the tax on
Income Trusts by reducing the proposed deemed provincial rate of 13 per cent.
    On December 20, 2007, the Finance Minister announced technical amendments
to provide some clarification to the Trust tax legislation. As part of the
announcement the Minister indicated that the federal government intends to
provide legislation in 2008 to permit Income Trusts to convert to taxable
Canadian corporations without any undue tax consequences to investors or the
Trust.
    Management and the Board of Directors continue to review the impact of
this tax on our business strategy and while there has not been a decision as
to ARC's future direction at this time we are of the opinion that the
conversion from a trust to a corporation may be the most logical and tax
efficient alternative for ARC unitholders. We expect future technical
interpretations and details will further clarify the legislation. At the
present time, ARC believes that if structural or other similar changes are not
made, the after-tax distribution amount in 2011 to taxable Canadian investors
will remain approximately the same, however, will decline for both tax-
deferred Canadian investors (RRSPs, RRIFs, pension plans, etc.) and foreign
investors.
    The Trust tax rate applicable to 2007 is 34 per cent; however, the
application of the Trust tax should be deferred until 2011 as the Trust has
not exceeded the normal growth guidelines announced by the Minister. The Trust
does not anticipate that the Trust taxation legislation guidelines, which
limit the growth of the Trust up to 2011, will impair the Trust's ability to
annually replace or grow reserves in the next three years as the guidelines
allow sufficient growth targets. The corporate income tax rate applicable to
2007 is 32.1 per cent, however the Trust and its subsidiaries did not pay any
material cash income taxes for fiscal 2007. Due to the Trust's structure,
currently, both income tax and future tax liabilities are passed on to the
unitholders by means of royalty payments made between ARC Resources and the
Trust.
    Federal capital taxes were eliminated effective January 1, 2006 pursuant
to the Federal Government budget of May 2, 2006.

    Depletion, Depreciation and Accretion of Asset Retirement Obligation

    The depletion, depreciation and accretion ("DD&A") rate increased to
$16.23 per boe in 2007 from $15.64 per boe in 2006. The higher DD&A rate is
driven by an increase in the Trust's property, plant and equipment ("PP&E")
value on the Trust's balance sheet along with an increase in the future
development costs and a small decrease in the proved reserves recorded in the
Trust's January 1, 2008 reserve report.

    
    A breakdown of the DD&A rate is a follows:

    -------------------------------------------------------------------------
    DD&A Rate
    ($ millions except
     per boe amounts)                             2007       2006   % Change
    -------------------------------------------------------------------------
    Depletion of oil & gas assets(1)             360.0      348.9          3
    Accretion of asset retirement obligation(2)   11.5       11.1          4
    -------------------------------------------------------------------------
    Total DD&A                                   371.5      360.0          3
    DD&A rate per boe                            16.23      15.64          4
    -------------------------------------------------------------------------

    (1) Includes depletion of the capitalized portion of the asset retirement
        obligation that was capitalized to the PP&E balance and is being
        depleted over the life of the reserves.
    (2) Represents the accretion expense on the asset retirement obligation
        during the year.
    

    Goodwill

    The goodwill balance of $157.6 million arose as a result of the
acquisition of Star Oil and Gas in 2003. The goodwill balance was determined
based on the excess of total consideration paid plus the future income tax
liability less the fair value of the assets for accounting purposes acquired
in the transaction.
    Accounting standards require that the goodwill balance be assessed for
impairment at least annually or more frequently if events or changes in
circumstances indicate that the balance might be impaired. If such impairment
exists, it would be charged to income in the period in which the impairment
occurs. The Trust has determined that there was no goodwill impairment as of
December 31, 2007.

    Capital Expenditures and Net Acquisitions

    Total capital expenditures, excluding acquisitions and dispositions,
totaled $397.2 million in 2007 compared to $364.5 million in 2006. This amount
was incurred on drilling and completions, geological, geophysical and
facilities expenditures, and undeveloped acreage. The $77.5 million purchases
of undeveloped land in 2007 have increased the Trust's land holdings to
536,232 net acres that will help sustain the drilling opportunities of the
Trust which will, if successful, provide future production and reserves.
    In addition to capital expenditures on development activities, the Trust
completed net property acquisitions of $42.5 million in 2007. The most
significant property acquisition was the purchase of properties in southeast
Saskatchewan late in the third quarter for $24.8 million. The acquisition
contributed approximately 350 boe per day of incremental production to the
Trust's fourth quarter results.
    During the year, the Trust drilled 278 gross wells (220 net wells) on
operated properties; consisting of 99 gross oil wells, three water injection
wells, and 172 gross natural gas wells most of which were shallow gas wells
with a success rate of 99 per cent. In addition, the Trust participated in
156 gross wells (33 net wells) drilled by other operators.
    Proved plus probable oil and gas reserves were effectively maintained at
286.4 mmboe at year-end 2007 as a result of the Trust's 2007 capital
expenditure program and property acquisitions.
    Over the course of 2006 and 2007, the Trust has spent $762 million on
capital expenditures, a portion of which has funded the following activities:

    
    -   At our Dawson area in British Columbia, ARC spent $99 million of
        capital to drill, complete and tie in 10 horizontal and 13 vertical
        wells. ARC also expanded its compression facilities and signed a
        long-term contract with a third party processor to facilitate
        processing additional gas volumes in the area. ARC's production grew
        from 19 mmcf per day to 45 mmcf per day over the two year period. In
        addition, ARC has been building for the future by spending $100
        million on acquiring 44,000 net acres of undeveloped land in the
        area.

    -   At our Ante Creek area, ARC has focused on a combination of infill
        and highly successful stepout pool extension drilling. ARC has spent
        $61 million on drilling, completions, tie-ins, facilities, and land
        purchases. ARC drilled 25 wells that resulted in positive reserves
        growth and record production in the area of 5,100 boe per day for the
        month of December 2007.

    -   In Southeast Saskatchewan we have spent $108 million and increased
        production as a result of drilling 41 wells in the area including 35
        new horizontal oil wells two successful exploration locations and one
        new vertical injection well.

    -   ARC's 2007 exit production at Redwater was 4,300 boe per day, which
        represents a 20 per cent increase over production at the time that
        ARC closed the Redwater acquisition in December 2005. To achieve
        these results, ARC invested $20 million focused mainly on a
        combination of optimization and reactivation projects and the
        drilling of infill vertical wells that were identified through
        seismic data acquired in 2006.

    -   ARC drilled 313 net wells in our Southeast Alberta and Southwest
        Saskatchewan area including 305 shallow gas wells and eight new oil
        wells.

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

    -------------------------------------------------------------------------
    Capital Expenditures
    ($ millions)                                  2007       2006   % Change
    -------------------------------------------------------------------------
    Geological and geophysical                    14.9       11.4         31
    Drilling and completions                     229.5      240.5         (5)
    Plant and facilities                          72.1       77.6         (7)
    Undeveloped land                              77.5       32.4        139
    Other capital                                  3.2        2.6         23
    -------------------------------------------------------------------------
    Total capital expenditures                   397.2      364.5          9
    -------------------------------------------------------------------------
    Producing property acquisitions(1)            47.1      124.0        (62)
    Producing property dispositions(1)            (4.6)      (8.8)        48
    Corporate acquisitions(2)                        -       16.6       (100)
    -------------------------------------------------------------------------
    Total capital expenditures
     and net acquisitions                        439.7      496.3        (11)
    -------------------------------------------------------------------------

    (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, asset
        retirement obligation and working capital assumed on acquisition.

    Approximately 49 per cent of the $397.2 million capital program was
financed with cash flow from operating activities in 2007 compared to 65 per
cent in 2006. Property acquisitions were financed through debt and working
capital.

    -------------------------------------------------------------------------
    Source of Funding of Capital Expenditures and Net Acquisitions
    ($ millions)
    -------------------------------------------------------------------------
                                   2007                       2006
    -------------------------------------------------------------------------
                       Develop-      Net    Total Develop-      Net    Total
                           ment   Acqui-  Expend-     ment   Acqui-  Expend-
                        Capital  sitions   itures  Capital  sitions   itures
    -------------------------------------------------------------------------
    Expenditures          397.2     42.5    439.7    364.5    131.8    496.3
    -------------------------------------------------------------------------
    Per cent funded by:
    Cash flow from
     operating
     activities             49%        -      44%      65%        -      48%
    Proceeds from DRIP
     and Rights Plan        28%        -      25%      30%        -      22%
    Debt                    23%     100%      31%       5%     100%      30%
    -------------------------------------------------------------------------
                           100%     100%     100%     100%     100%     100%
    -------------------------------------------------------------------------
    

    ARC has announced a $395 million capital expenditure budget for 2008 that
consists of a robust drilling and development program on its diverse asset
base. The 2008 capital budget is being deployed as a balanced drilling program
of low and moderate risk wells, well tie-ins and other related costs, and the
acquisition of undeveloped land. The Trust continues to focus on major
properties with significant upside, with the objective to replace production
declines through internal development opportunities. The 2008 capital
expenditure budget anticipates the drilling of 252 net operated wells and the
addition of new production from the capital development program to replace
declines at existing properties and develop the recently acquired land
holdings in the Dawson area of British Columbia. The 2008 capital budget also
allows for a portion of spending to further research and pursue Enhanced
Recovery Initiatives such as CO(2) injection and NGC development. Current
projections of cash flows, low debt levels and a strong working capital
position provide the Trust with the financial flexibility to fund the 2008
capital expenditure program.

    Long-Term Investment

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

    Asset Retirement Obligation and Reclamation Fund

    At December 31, 2007, the Trust has recorded an Asset Retirement
Obligation ("ARO") of $140 million ($177.3 million at December 31, 2006) for
future abandonment and reclamation of the Trust's properties. The ARO
decreased in 2007 as a result of a change in management's estimate of the
timing of when costs will be incurred. The estimated ARO includes assumptions
in respect of actual costs to abandon wells or reclaim the property as well as
annual inflation factors in order to calculate the undiscounted total future
liability. The undiscounted total future liability has increased to
$1.3 billion as at December 31, 2007 as compared to $1 billion at December 31,
2006, as a significant portion of the costs are now projected to be incurred
in years 2048 to 2058 as compared to years 2017 to 2021 as estimated on
December 31, 2006. The present value impact of this change in estimate
resulted in a $34.4 million reduction in the ARO balance at December 31, 2007.
    Included in the December 31, 2007 ARO balance is a $3.8 million increase
related to development activities in 2007. The ARO liability was also
increased by $11.5 million for accretion expense in 2007 ($11.1 million in
2006) and was reduced by $18.2 million ($10.6 million in 2006) for actual
abandonment expenditures incurred in 2007.
    As a result of the Redwater acquisition in December 2005, the Trust set
up a second reclamation fund (the "Redwater Fund") in 2006 to fund future
abandonment obligations attributed solely to the Redwater properties. The
Trust makes annual contributions to the Redwater fund and may utilize the
funds only for abandonment activities for the Redwater property. With the
addition of the Redwater Fund, the Trust now maintains two reclamation funds
that together held $26.1 million at December 31, 2007. Future contributions
for the two funds will vary over time in order to provide for the total
estimated future abandonment and reclamation costs that are to be incurred
upon abandonment of the Trust's properties. The Trust currently estimates that
$220 million will be contributed to the funds over the next 50 years to
provide for future abandonment and reclamation costs.
    In total, ARC contributed $12.1 million cash to its reclamation funds in
2007 ($12.1 million in 2006) and earned interest of $1.4 million ($1 million
in 2006) on the fund balances. The fund balances were reduced by $18.1 million
for cash-funded abandonment expenditures in 2007 ($5.7 million in 2006). Under
the terms of the Trust's investment policy, reclamation fund investments and
excess cash can only be invested in Canadian or U.S. Government securities,
investment grade corporate bonds, or investment grade short-term money market
securities.

    
    Capitalization, Financial Resources and Liquidity

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

    -------------------------------------------------------------------------
    Capital Structure and Liquidity
    ($ millions except per unit
     and per cent amounts)                                   2007       2006
    -------------------------------------------------------------------------
    Amount drawn under revolving credit facilities          499.0      426.1
    Senior secured notes                                    215.5      261.0
    Working capital deficit excluding short-term debt(1)     38.2       52.0
    -------------------------------------------------------------------------
    Net debt obligations                                    752.7      739.1
    -------------------------------------------------------------------------
    Trust units outstanding and issuable for
     exchangeable shares (thousands)                        213.2      207.2
    Market price per unit at end of year                    20.40      22.30
    Market value of trust units and exchangeable share    4,349.3    4,620.0
    -------------------------------------------------------------------------
    Total capitalization(2)                               5,102.0    5,359.1
    -------------------------------------------------------------------------
    Net debt as a percentage of total capitalization        14.8%      13.8%
    Net debt obligations                                    752.7      739.1
    Cash flow from operating activities                     704.9      734.0
    Net debt to cash flow from operating activities           1.1        1.0
    -------------------------------------------------------------------------

    (1) The working capital deficit excludes the balances for the current
        portion of risk management contracts and the current portion of
        future income taxes.
    (2) Total capitalization as presented does not have any standardized
        meaning prescribed by Canadian GAAP and therefore it may not be
        comparable with the calculation of similar measures for other
        entities. Total capitalization is not intended to represent the total
        funds from equity and debt received by the Trust.

    The Trust has a syndicated three year revolving credit facility allowing
for maximum borrowing of up to $800 million. The debt is secured by all the
Trust's oil and gas properties and has the following major covenants:

    -------------------------------------------------------------------------
    Covenant                             Position as at December 31, 2007
    -------------------------------------------------------------------------
    Long-term debt and letters of        Long-term debt and letters of credit
    credit not to exceed three times     of 0.9 times annualized net income
    annualized net income before         before non-cash items and interest
    non-cash items and interest expense  expense
    -------------------------------------------------------------------------
    Long-term debt, letters of credit    Long-term debt, letters of credit
    and subordinated debt not to exceed  and subordinated debt of 0.9 times
    four times annualized net income     annualized net income before
    before non-cash items and interest   non-cash items and interest expense
    expense
    -------------------------------------------------------------------------
    Long-term debt and letters of        Long-term debt and letters of credit
    credit not to exceed 50 per cent of  of 26.5 per cent of the sum of
    the sum of the book of value of      unitholders' equity, long-term debt,
    unitholders' equity, long-term debt, letters of credit, and subordinated
    letters of credit, and subordinated  debt
    debt
    -------------------------------------------------------------------------
    

    As indicated by the above table, the Trust is not close to breaching any
of its covenants and has additional potential borrowing capacity above the
$800 credit facility. The Trust's objective is to limit debt to under
2.0 times cash flow from operating activities and 20 per cent of total
capitalization. In addition to the $800 million credit facility, the Trust has
outstanding senior secured notes in the amount of $215.5 million as at
December 31, 2007, which do not reduce the available borrowings under the
credit facility. The Trust had $4.8 million of letters of credit outstanding
at December 31, 2007 and no subordinated debt. As at December 31, 2007, the
Trust was in compliance with all covenants.
    During the third quarter the Trust entered into treasury lock contracts
in order to manage its interest rate exposure on future debt issuances.
Treasury locks enable the Trust to synthetically secure current market rates
for a future fixed rate funding. These instruments hedge only the underlying
treasury yield and not the credit spread applicable to ARC that is determined
at the time of issuance. Based on the transactions completed during the
quarter the Trust has locked in an effective U.S. ten year treasury rate of
4.8082 per cent on a notional amount of US$125 million. As at December 31,
2007 the mark-to-market value of these contracts was CDN$7.4 million loss.
    The Trust intends to finance its $395 million 2008 capital program with
cash flow from operating activities and the proceeds of the DRIP with any
remainder financed with debt. If necessary, ARC has access to additional
capital through its current credit facility, a new issue of senior secured
notes, or by issuing equity. In the event that the Trust enters into a
material acquisition where the purchase price exceeds 10 per cent of the book
value of the Trust's assets, the ratios in the first two covenants above are
increased to 3.5 and 5.5 times, respectively.

    Unitholders' Equity

    At December 31, 2007, there were 213.2 million trust units issued and
issuable for exchangeable shares, an increase of six million trust units from
December 31, 2006. The increase in number of trust units outstanding is mainly
attributable to the 5.6 million trust units issued pursuant to the DRIP during
2007 at an average price of $19.93 per trust unit.
    The Trust had 0.2 million rights outstanding as of December 31, 2007
under an employee plan where further rights issuances were discontinued in
2004. The rights have a five-year term and vested equally over three years
from the date of grant. The remaining rights may be exercised to purchase
trust units at an average adjusted exercise price of $8.50 per unit as at
December 31, 2007. All of the rights were fully vested at December 31, 2007
and will expire on or before December 31, 2008.
    The Whole Unit Plan introduced in 2004 is a cash compensation plan for
employees, officers and directors of the Trust and does not involve any units
being issued from treasury. The Trust has made provisions whereby employees
may elect to have units purchased for them on the market with the cash
received upon vesting.
    Unitholders electing to reinvest distributions or make optional cash
payments to acquire trust units from treasury under the DRIP may do so at a
five per cent discount to the prevailing market price with no additional fees
or commissions. During 2007, the Trust raised proceeds of $110.7 million and
issued 5.6 million trust units pursuant to the DRIP.

    Distributions

    ARC declared distributions of $498 million ($2.40 per unit), representing
71 per cent of 2007 cash flow from operating activities compared to
distributions of $484.2 million ($2.40 per unit), representing 66 per cent of
cash flow from operating activities in 2006.
    Monthly distributions for 2007 were $0.20 per unit. Revisions, if any, to
the monthly distribution are normally announced on a quarterly basis in the
context of prevailing and anticipated commodity prices at that time.
    The following items may be deducted from cash flow from operating
activities to arrive at distributions to unitholders:

    
    -   The portion of capital expenditures that are funded with cash flow
        from operating activities. In 2007, the Trust withheld 27 per cent of
        2007 cash flow from operating activities to fund 49 per cent of the
        capital program excluding acquisitions. The remaining portion of
        capital expenditures was financed by proceeds from the DRIP program
        and debt.

    -   An annual contribution to the reclamation funds, with $13.5 million
        being contributed in 2007 including interest earned on the fund
        balances. The reclamation funds are segregated bank accounts or
        subsidiary trusts and the balances will be drawn on in future periods
        as the Trust incurs abandonment and reclamation costs over the life
        of its properties.

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

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

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

    -   The Trust has certain obligations for future payments relative to
        employee long-term incentive compensation. Presently, the Trust
        estimates that $19.8 million to $71.1 million will be paid out
        pursuant to such commitments in 2008 through 2010 subject to vesting
        provisions and future performance of the Trust. These amounts will
        reduce cash flow from operating activities and may in turn reduce
        distributions in future periods.

    Cash flow from operating activities and distributions in total and per
unit were as follows:

    -------------------------------------------------------------------------
    Cash flow from operating                  %                          %
     activities and          2007     2006  Change      2007     2006  Change
     distributions             ($ millions)               ($ per unit)
    -------------------------------------------------------------------------
    Cash flow from
     operating
     activities             704.9    734.0     (4)      3.35     3.59     (7)
    Reclamation fund
     contributions(1)       (13.5)   (13.1)     3      (0.06)   (0.06)     -
    Capital expenditures
     funded with cash
     flow from operating
     activities            (193.4)  (236.7)   (18)     (0.92)   (1.16)   (21)
    Other(2)                    -        -      -       0.03     0.03      -
    -------------------------------------------------------------------------
    Distributions           498.0    484.2      3       2.40     2.40      -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

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

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

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

    -   To ensure that the Trust's financial flexibility is maintained by a
        review of the Trust's debt to equity and debt to cash flow from
        operating activities levels. The use of cash flow from operating
        activities to fund capital development activities reduces the
        requirements of the Trust to use debt to finance these expenditures.
        In 2007 the Trust funded 49 per cent of capital development
        activities with 27 per cent of cash flow from operating activities.
        The actual amount of cash flows withheld to fund the Trust's capital
        expenditure program is dependent on the commodity price environment
        and is at the discretion of the Board of Directors.

    The actual amount of future monthly distributions is proposed by
management and is subject to the approval and discretion of the Board of
Directors. The Board reviews future distributions in conjunction with their
review of quarterly financial and operating results.
    Monthly distributions for the first quarter of 2008 have been set at $0.20
per unit subject to monthly review based on commodity price fluctuations.
Revisions, if any, to the monthly distribution are normally announced on a
quarterly basis in the context of prevailing and anticipated commodity prices
at that time.

    Historical Distributions by Calendar Year

    The following table presents distributions paid and payable for each
calendar period.

    -------------------------------------------------------------------------
    Calendar Year        Distributions    Taxable Portion  Return of Capital
    -------------------------------------------------------------------------
    2008 YTD(2)                   0.20               0.20               0.00
    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                  $21.23             $14.41              $6.82
    -------------------------------------------------------------------------

    (1) Based on distributions paid and payable in 2006.
    (2) Based on distributions declared at January 31, 2008 and estimated
        taxable portion of 2008 distributions of 98 per cent.
    

    Please refer to the Trust's website at www.arcenergytrust.com for details
on 2007 monthly distributions and distribution dates for 2008.

    Taxation of Distributions

    Distributions comprise a return of capital portion (tax deferred) and a
return on capital portion (taxable). The return of capital component reduces
the cost basis of the trust units held. For 2007, distributions paid in the
calendar year will be 97 per cent return on capital or $2.32 per unit for the
year (taxable) and three per cent return of capital or $0.08 per unit for the
year (tax deferred). For a more detailed breakdown, please visit our website
at www.arcenergytrust.com.

    Per Unit Results and Sustainability

    Due to natural production declines, the Trust must continually develop
its reserves and/or acquire new reserves in an effort to maintain reserves,
production and cash flow levels on which distributions are paid. The Trust
facilitates this by withholding a portion of cash flow from operating
activities to fund a portion of ongoing capital development activities and
maintain moderate debt levels; this is evidenced by the Trust's moderate
payout of distributions as compared to cash flow from operating activity
levels. Oil and gas royalty trusts hold assets that are depleting and
unitholders should expect production, revenue, cash flows and distributions to
decline over the long-term if reserves cannot be economically replaced. The
Trust has an inventory of internal development prospects that we expect will
enable the Trust to maintain production for a minimum period of two years. The
Trust measures its sustainability and success in terms of per unit
distributions, production, reserves, and cash flow from operating activities
in addition to the ability to maintain low debt levels and the annual
replacement of reserves.
    Following is a summary of the historical debt-adjusted production and
reserves per unit and reserve life index ("RLI") on which the Trust assesses
performance and sustainability:

    
    -------------------------------------------------------------------------
                                                                      3 Year
    Per trust unit ratios              2007       2006       2005      Total
    -------------------------------------------------------------------------
    Production per unit(1):
    Unadjusted                         0.30       0.31       0.29          -
    Debt-adjusted(3)                   0.26       0.27       0.26          -
    Normalized(4)                      0.30       0.31       0.32          -
    -------------------------------------------------------------------------
    Reserves per unit(2):
    Unadjusted                         1.34       1.38       1.42          -
    Debt-adjusted(3)                   1.15       1.19       1.28          -
    Normalized(4)                      1.35       1.40       1.51          -
    -------------------------------------------------------------------------
    Reserve life index(5)              12.5       12.4       12.9          -
    Cash flow from operating
     activities per unit              $3.35      $3.59      $3.23     $10.17
    Distributions per unit            $2.40      $2.40      $1.99      $6.79
    Distributions as a per cent
     of cash flow from operating
     activities                          71         66         61         66
    Per cent of cash flow from
     operating activities retained       29         34         39         34
    -------------------------------------------------------------------------

    (1) Represents daily average production per thousand units. Calculated
        based on annual daily average production divided by weighted average
        trust units outstanding including trust units issuable for
        exchangeable shares.
    (2) Calculated based on proved plus probable reserves divided by period
        end trust units outstanding including trust units issuable for
        exchangeable shares.
    (3) Debt-adjusted indicates that all years as presented have been
        adjusted to reflect a nil net debt to capitalization. It is assumed
        that additional trust units were issued at a period end price for the
        reserves per unit calculation and at an annual average price for the
        production per unit calculation in order to reduce the net debt
        balance to zero in each year. The debt-adjusted amounts are presented
        to enable comparability of annual per unit values.
    (4) Normalized indicates that all years as presented have been adjusted
        to reflect a net debt to capitalization of 15 per cent. It is assumed
        that additional trust units were issued (or repurchased) at a period
        end price for the reserves per unit calculation and at an annual
        average price for the production per unit calculation in order to
        achieve a net debt balance of 15 per cent of total capitalization
        each year. The normalized amounts are presented to enable
        comparability of annual per unit values.
    (5) Calculated based on proved plus probable reserves divided by annual
        2008 production estimate of 63,000 boe per day for 2007 RLI.
    

    During the 2005 to 2007 time period the Trust's normalized production per
unit has decreased only slightly from 0.32 to 0.30 boe of daily average
production per thousand trust units. Normalized reserves per unit have
decreased just over 10 per cent during this time to 1.35 from 1.51 boe of
proved plus probable reserves per trust unit. These levels of production and
reserves per unit occurred even with the payout of $1.4 billion of
distributions ($6.79 per trust unit and 66 per cent of cash flow from
operating activities) during the 2005 through 2007 time period. This indicates
that the Trust has grown production levels to help offset natural production
declines and developed its reserve base. The normalized production per unit is
a key measure as it indicates the ability to generate cash flows from core
operations that in turn impacts the level of cash that may be distributed to
unitholders. The Trust expects to replace production in 2008 from internal
development opportunities.
    To compare the Trust's results with oil and gas companies that retain all
of their cash flow from operating activities to grow production and reserves,
the Trust looks at normalized and distribution-adjusted production and
reserves per unit which calculates the total reserves and production per
initial investment with the assumption that distributions are reinvested
through the DRIP plan. Consequently, the reserves and production per initial
investment increase over time as the investor's number of trust units increase
with distribution reinvestment. The Trust's normalized daily average
production per initial investment has increased from 0.35 boe per thousand
trust units in 2005 to 0.40 in 2007, while normalized reserves per initial
investment have increased from 1.66 boe at January 1, 2005 to 1.82 boe at
December 31, 2007. Based on the assumption of re-investment of the
distributions for additional trust units, one trust unit purchased on January
1, 2005 would have grown to 1.35 trust units on December 31, 2007. A
unitholder can replicate this by participating in the DRIP so that the number
of units they own increases over time.
    The Trust's RLI decreased slightly to 12.5 years in 2007 from 12.9 years
in 2005. The RLI is a measure of the remaining average life of the reserves
based on a current production estimate for 2008 of 63,000 boe per day. The
Trust's high RLI is indicative of the high quality of assets and the
relatively low production decline rate of the properties. The acquisition of
the Redwater and NPCU properties in 2005 resulted in an increase in the RLI
due to the long reserve life of the properties. In addition, the Trust has
been able to replace reserves through the drill bit throughout 2006 and 2007
as no significant acquisitions have been completed during that time and yet
the Trust produced almost 46 million barrels of oil equivalent during those
two years. A high RLI is key for a royalty trust as it is indicates the
potential sustainability of production levels and cash flows over a longer
period of time.
    The Trust's distribution policy centres around the goal of providing a
consistent and sustainable level of distributions to unitholders and to
provide for future growth. The Trust has maintained distributions at $0.20 per
unit per month since October 2005. This consistent level of distributions has
allowed the Trust to finance $193.4 million of capital expenditures through
cash flow from operating activities in 2007. In addition, low natural gas
prices and high Canadian dollar values observed in 2007, which negatively
impacted the Trust's cash flow from operating activities, did not cause the
Trust to cut distributions - this was an anomaly amongst the Trust's peers.
The Trust's distribution as a per cent of cash flow from operating activities
for 2007 was 71 per cent. The moderate level of distributions is indicative of
the Trust's commitment to fund ongoing development activities with cash flow
from operating activities to enable long-term sustainability.
    An additional 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
the associated reserves. 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, it is expected that there will be
deviations between annual net income and distributions. The following table
illustrates the annual shortfall of distributions to net income as a measure
of long-term sustainability.

    
    -------------------------------------------------------------------------
    Net income and distributions                                    Trailing
    ($ millions except per cent)       2007       2006       2005    3 years
    -------------------------------------------------------------------------
    Net income                        495.3      460.1      356.9    1,312.3
    Distributions                     498.0      484.2      376.6    1,358.8
    -------------------------------------------------------------------------
    Shortfall                          (2.7)     (24.1)     (19.7)     (46.5)
    Shortfall as
     per cent of net income             (1%)       (5%)       (6%)       (4%)
    Distributions as a per
     cent of cash flow from
     operating activities               71%        66%        61%        66%
    -------------------------------------------------------------------------

    Contractual Obligations and Commitments

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

    -------------------------------------------------------------------------
    Commitments                    Payments due by period
                           ----------------------------------------
                                       2009-      2011-
    ($ millions)            2008       2010       2012  Thereafter     Total
    -------------------------------------------------------------------------
    Debt repayments(1)       5.9      540.8       51.5      116.3      714.5
    Interest payments(2)    11.0       20.2       15.5       13.7       60.4
    Reclamation fund
     contributions(3)        5.8       10.2        8.9       71.9       96.8
    Purchase commitments    10.1        4.1        4.0        6.0       24.2
    Operating leases(4)      6.2        8.9       12.4       88.1      115.6
    Risk Management
     contract premiums(5)   13.2        2.3          -          -       15.5
    -------------------------------------------------------------------------
    Total contractual
     obligations            52.2      586.5       92.3      296.0    1,027.0
    -------------------------------------------------------------------------

    (1) Long-term and short-term debt, excluding interest. In the event that
        the credit facility is not extended at any time before the maturity
        date, the loan balance will become payable on the maturity date which
        is April 15, 2010.
    (2) Fixed interest payments on senior secured notes.
    (3) Contribution commitments to a restricted reclamation fund associated
        with the Redwater property acquired in 2005.
    (4) Available option expiring February 2008 to reduce office lease
        commitment.
    (5) Fixed premiums to be paid in future periods on certain risk
        management contracts.
    

    The above noted risk management contract premiums are part of the Trust's
commitments related to its risk management program. In addition to the above
premiums, the Trust has commitments related to its risk management program. As
the premiums are part of the underlying risk management contract, they have
been recorded at fair market value at December 31, 2007 on the balance sheet
as part of risk management contracts.
    The Trust enters into commitments for capital expenditures in advance of
the expenditures being made. At a given point in time, it is estimated that
the Trust has committed to capital expenditures equal to approximately one
quarter of its capital budget by means of giving the necessary authorizations
to incur the capital in a future period. The Trust's 2008 capital budget has
been approved by the Board at $395 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 above noted operating leases include amounts for the Trust's head
office lease. The current lease expires in May 2010. In December 2007, the
Trust entered into a 13 year lease commitment beginning in 2010 for office
space in a new building that is under construction in downtown Calgary. The
new lease commitment is reflected in the table above.
    The Trust is involved in litigation and claims arising in the normal
course of operations. Management is of the opinion that pending litigation
will not have a material adverse impact on the Trust's financial position or
results of operations and therefore the commitment table does not include any
commitments for outstanding litigation and claims.
    The Trust has certain sales contracts with aggregators whereby the price
received by the Trust is dependent upon the contracts entered into by the
aggregator. This commitment has not been disclosed in the commitment table as
it is of a routine nature and is part of normal course of operations.

    Off Balance Sheet Arrangements

    The Trust has certain lease agreements, all of which are reflected in the
Contractual Obligations and Commitments table above, which were entered into
in the normal course of operations. All leases have been treated as operating
leases whereby the lease payments are included in operating expenses or G&A
expenses depending on the nature of the lease. No asset or liability value has
been assigned to these leases in the balance sheet as of December 31, 2007.

    Fourth Quarter Financial and Operational Results

    The Trust had an active fourth quarter with $139.3 million spent on
capital development activities that contributed to quarterly average
production of 63,989 boe per day. The Trust distributions were 72 per cent of
cash flow from operating activities. The remaining 28 per cent was used to
fund $44.5 million of the fourth quarter capital development program and make
contributions to the reclamation fund. The fourth quarter was an active one
for the Trust with the drilling of 77 gross wells on operated properties and
new production coming on-stream in the Dawson area of British Columbia.

    
    -   The Trust's fourth quarter production was 63,989 boe per day, a
        slight increase from the fourth quarter of 2006 where production was
        63,663. As compared to the third quarter of 2007, the Trust's
        production increased five per cent or 2,881 boe per day. This was
        primarily as a result of approximately 350 boe per day from an
        acquisition that the Trust completed late in the third quarter of
        2007 as well as new production in the Dawson area of British Columbia
        of approximately 1,400 boe per day.

    -   The Trust spent $139.3 million on capital development activities and
        undeveloped land in the fourth quarter compared to $121.9 million in
        2006. The Trust had a very active fourth quarter with the drilling of
        77 gross wells (69 net wells) on operated properties with a 100 per
        cent success rate. The Trust expanded its inventory of undeveloped
        land acreage with the purchase of $42.6 million of land in the fourth
        quarter. The land acquired was in core areas where the Trust has
        identified strategic development opportunities.

    -   The fourth quarter netback before hedging increased 17 per cent to
        $36.63 per boe as compared to $31.37 for the same period of 2006.
        Record high oil prices, offset by increased royalties and operating
        costs lower gas prices contributed to the high netback recorded for
        the quarter.

    -   Cash G&A expenses in the fourth quarter increased to $1.96 per boe as
        compared to $1.74 for the same period in 2006. The majority of the
        increase is attributable to a larger whole unit plan payment made in
        October of 2007.

    -------------------------------------------------------------------------
    Fourth Quarter Financial and
     Operational Highlights
    (CDN$ millions except per
     unit and per cent)                        Q4 2007    Q4 2006   % Change
    -------------------------------------------------------------------------
    Production (boe/d)                          63,989     63,663          1
    Cash flow from operating
     activities                                  173.7      159.3          9
      Per unit                               $    0.82  $    0.77         (6)
    Distributions                                125.8      122.3          3
      Per unit                               $    0.60  $    0.60          -
      Per cent of cash flow from
       operating activities                         72         77         (6)
    Net income                                   106.3       56.6         88
      Per unit                               $    0.51  $    0.28         82
    -------------------------------------------------------------------------
    Prices
      WTI (US$/bbl)                              90.63      60.22         50
      USD/CAD exchange rate                       1.02       0.87         17
      Realized oil price (CDN $/bbl)             77.53      58.26         33
      AECO gas monthly index (CDN $/mcf)          6.00       6.36         (6)
      Realized gas price (CDN $/mcf)              6.32       6.99        (10)
    -------------------------------------------------------------------------
    Operating netback ($/boe)
      Revenue, before hedging                    57.42      49.94         15
      Royalties                                 (10.46)     (8.80)        19
      Transportation                             (0.69)     (0.64)         8
      Operating costs                            (9.64)     (9.13)         6
      Netback (before hedging)                   36.63      31.37         17
      Cash hedging gain (loss)                   (0.20)      1.68       (112)
      Netback (after hedging)                $   36.43  $   33.05         10
    -------------------------------------------------------------------------
    Capital expenditures                         139.3      121.9         14
    Capital funded with cash flow from
     operating activities (per cent)                32         28         14
    -------------------------------------------------------------------------

    Critical Accounting Estimates

    The Trust has continuously evolved and documented its management and
internal reporting systems to provide assurance that accurate, timely internal
and external information is gathered and disseminated.

    The Trust's financial and operating results incorporate certain estimates
including:

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

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

    Disclosure Controls and Procedures

    As of December 31, 2007, an internal evaluation was carried out of the
effectiveness of the Trust's disclosure controls and procedures as defined in
Rule 13a-15 under the US Securities Exchange Act of 1934 and as defined in
Canada by Multilateral Instrument 52-109, Certification of Disclosure in
Issues' Annual and Interim Filings. Based on that evaluation, the President
and Chief Executive Officer and the Senior Vice President Finance and Chief
Financial Officer concluded that the disclosure controls and procedures are
effective to ensure that the information required to be disclosed in the
reports that the Trust files or submits under the Exchange Act or under
Canadian Securities legislation is recorded, processed, summarized and
reported, within the time periods specified in the rules and forms therein.
Disclosure controls and procedures include, without limitation, controls and
procedures designed to ensure that the information required to be disclosed by
the Trust in the reports that it files or submits under the Exchange Act or
under Canadian Securities legislation is accumulated and communicated to the
Trust's management, including the senior executive and financial officers, as
appropriate to allow timely decisions regarding the required disclosure.

    Internal Controls over Financial Reporting

    Internal control over financial reporting is a process designed to
provide reasonable assurance that all assets are safeguarded, transactions are
appropriately authorized and to facilitate the preparation of relevant,
reliable and timely information. Because of its inherent limitations, internal
control over financial reporting may not prevent or detect misstatements.
Management has assessed the effectiveness of the company'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 Multilateral Instrument 52-
109, Certification of Disclosure in Issues' Annual and Interim Filings. The
assessment was based on the framework in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission. Management concluded that the Trust's internal control over
financial reporting was effective as of December 31, 2007. The effectiveness
of the Trust's internal control over financial reporting as of December 31,
2007 has been audited by Deloitte & Touche LLP, as reflected in their report
for 2007. No changes were made to our internal controls over financial
reporting during the year ending December 31, 2007, that have materially
affected, or are reasonably likely to materially affect, our internal controls
over financial reporting.

    Financial Reporting Update

    During 2007, the Trust completed the implementation of the new CICA
Handbook Section 1530, Comprehensive Income, Section 3251, Equity, Section
3855, Financial Instruments - Recognition and Measurement, Section 3861,
Financial Instruments - Disclosure and Presentation, and Section 3865, Hedges
that deal with the presentation of equity, recognition, measurement,
disclosure, and presentation of financial instruments, and comprehensive
income. As required by the new standards, adoption has been applied
prospectively as at January 1, 2007 and prior periods have not been restated.
The adoption of these standards has had no material impact on the Trust's Net
Income or Cash Flows. See notes 3 and 11 in the Notes to the Consolidated
Financial Statements for further details.

    Accounting Changes
    Section 1506 permits voluntary changes in accounting policy only if they
result in financial statements that provide more reliable and relevant
information. Changes in policy are applied retrospectively unless it is
impractical to determine the period or cumulative impact of the change.
Corrections of prior period errors are applied retrospectively and changes in
accounting estimates are applied prospectively by including these changes in
net income. In addition, disclosure is required for all future accounting
changes when an entity has not applied a new source of GAAP that has been
issued but is not yet effective.

    Future Accounting Changes
    On December 1, 2006, the CICA issued three new accounting standards:
Handbook Section 1535, Capital Disclosures, Section 3862, Financial
Instruments - Disclosures, and Section 3863, Financial Instruments -
Presentation. These new standards will be effective on January 1, 2008.
    Section 1535 specifies the disclosure of an entity's objectives, policies
and processes for managing capital, quantitative data about what the entity
regards as capital, whether the entity has complied with any capital
requirements, and if it has not complied, the consequences of such
non-compliance. This Section is expected to have minimal impact on the Trust's
financial statements.
    Sections 3862 and 3863 specify standards of presentation and enhanced
disclosure on financial instruments. Increased disclosure will be required on
the nature and extent of risks arising from financial instruments and how the
entity manages those risks.
    In February 2008, the CICA issued Section 3064, Goodwill and Intangible
Assets, replacing Section 3062, Goodwill and Other Intangible Assets and
Section 3450, Research and Development Costs. The new Section will be
effective on January 1, 2009. Section 3064 establishes standards for the
recognition, measurement, presentation and disclosure of goodwill and
intangible assets subsequent to its initial recognition. Standards concerning
goodwill are unchanged from the standards included in the previous Section
3062. The Trust is currently evaluating the impact of the adoption of this new
Section, however does not expect a material impact on its Consolidated
Financial Statements.

    Update on Legislation Changes Impacting the Trust

    Broad-based Federal Tax Reductions

    On October 30, 2007 the Federal Government presented the fall economic
statement that proposed significant reductions in corporate income tax rates
from 22.1 per cent to 15 per cent. The reductions will be phased in between
2008 and 2012. In addition, the Government announced that it plans to
collaborate with the provinces and territories to reach a 25 per cent combined
federal-provincial-territorial statutory corporate income tax rate. The
reduction in the federal rate will also reduce the SIFT tax rate to 28 per
cent as compared to the rate of 31.5 per cent previously announced.

    Alberta Government Royalty Regime

    In September 2007, the Alberta Government announced the results of the
royalty review that was performed by an independent panel and on October 25,
2007, the Alberta Government announced The New Royalty Framework,
("framework"), which will take effect on January 1, 2009 and is projected by
the government to increase royalties by approximately $1.4 billion in 2010 or
an increase of 20 per cent over revenue forecasts by the Alberta Government
for that year. Subsequent to that time the Alberta Government has made some
concessions to the proposed royalty increases and industry is still awaiting
final legislation in order to fully assess the impact. Our understanding is
that at current commodity prices the increases comprise an average 57 per cent
increase in conventional oil royalties and a 10 per cent increase in gas
royalties. The maximum royalty rates increasing from the current maximums of
30 per cent and 35 per cent for old and new tier rates respectively to rates
that will range up to 50 per cent.
    The framework proposes new, simplified royalty formulas for conventional
oil and natural gas that will operate on sliding scales which are determined
by commodity prices and well productivity. The formulas eliminate the
conventional oil and natural gas tiers and several royalty exemption and
relief programs. Enhanced Oil Recovery and Innovative Energy Technology
Program Royalty relief programs have been retained.
    Based on our current estimates, the Trust expects that the total
corporate royalties payable will increase by approximately 10 per cent in
2009. This estimate will vary based on prices, production decline of existing
wells and performance and location of new wells drilled. The 10 per cent
increase in royalties payable, which equates to approximately a two per cent
increase in the Trust's overall royalty rate, takes into account that greater
than 37 per cent of the Trust's forecast production is from outside the
Province of Alberta. The royalty change in 2009 on a property by property
basis is highly variable with decreased royalties on some properties,
primarily shallow gas wells, and a doubling of royalties on Alberta high rate
oil production properties. The New Alberta Royalty Framework will impact
future drilling decisions in order for the Trust to maintain acceptable rates
of return on its capital deployed. The Trust reviews all of its capital
expenditures on a project by project basis; with higher royalties in the
Province of Alberta, projects previously deemed economic may no longer meet
the Trust's investment objectives.

    Federal Government's Trust Tax Legislation

    In 2007, the Federal Government introduced and passed into law Trust
taxation that will result in a tax of 28 per cent (previously 31.5 per cent as
discussed above) on all Trust distributions commencing January 1, 2011. Cash
flow earned by the Trust and not distributed has always been and continues to
form part of taxable income at the Trust level, which may result in cash taxes
being paid if there are not sufficient tax pool claims and deductions obtained
upon incurring capital expenditures or acquiring assets.
    The Trust recorded a $35.6 million one time increase in earnings and a
corresponding decrease to its future income tax liability as a result of
timing differences within the Trust that have not been previously recognized
as the Trust's tax pools were in excess of the net book value of the Trust's
assets. The initial recognition of $35.6 million comprises $24.7 million for
pre-2007 generated temporary differences and $10.9 million for temporary
differences relating to the current year. This amount was recorded in the
second quarter results and is reflected in the 2007 year-to-date results.
    Management and the Board of Directors continue to review the impact of
this tax on our business strategy and while there has not been a decision as
to ARC's future direction at this time we are of the opinion that the
conversion from a trust to a corporation may be the most logical and tax
efficient alternative for ARC unitholders. We expect future technical
interpretations and details will further clarify the legislation. At the
present time, ARC believes that if structural or other similar changes are not
made, the after-tax distribution amount in 2011 to taxable Canadian investors
will remain approximately the same, however, will decline for both tax-
deferred Canadian investors (RRSPs, RRIFs, pension plans, etc.) and foreign
investors.

    Climate Change Programs

    On March 8, 2007, the Alberta government introduced legislation to reduce
greenhouse gas emission intensity. Bill 3 states that facilities emitting more
than 100,000 tonnes of greenhouse gases per year must reduce their emissions
intensity by 12 per cent over the average emissions levels of 2003, 2004 and
2005; if they are not able to do so, these facilities are required to pay
$15 per tonne for every tonne above the 12 per cent target, effective as of
July 1, 2007. At this time, the Trust has determined that the impact of this
legislation would be minimal based on ARC's existing facilities ownership.
    In April 2007, the Federal Government announced a new climate change plan
that calls for greenhouse gas emissions to be reduced by 20 per cent below
current levels by 2020. Firms may employ the following strategies to achieve
the targets. They will be able to:

    
    -   make in-house reductions;
    -   take advantage of domestic emissions trading;
    -   purchase offsets;
    -   use the Clean Development Mechanism under the Kyoto Protocol; and,
    -   invest in a technology fund.
    

    The Trust is waiting for additional information so as to fully assess
what impact, if any, this new legislation will have on its operations.
    On January 24, 2008 the Alberta Government announced their plan to reduce
projected emissions in the province by 50 per cent under the new climate
change plan by 2050. This will result in real reductions of 14 per cent below
2005 levels. The Alberta Government stated they will form a
government-industry council to determine a go-forward plan for implementing
technologies, which will significantly reduce greenhouse gas emissions by
capturing air emissions from industrial sources and locking them permanently
underground in deep rock formations.
    In addition the plan calls for energy conservation by individuals and for
increased investment in clean energy technologies and incentives for expanding
the use of renewable and alternative energy sources such as bioenergy, wind,
solar power, hydrogen and geothermal energy. Initiatives under this theme will
account for 18 per cent of Alberta's reductions. A detailed implementation
plan will be developed and released in the spring of 2008.

    United States Proposed Changes to Qualifying Dividends

    A bill was introduced into United States Congress on March 23, 2007 that
could deny qualified dividend income treatment to the distributions made by
the Trust to its U.S. unitholders. The bill is in the first step of the
legislative process and it is uncertain whether it will eventually be passed
into law in its current form. If the bill is passed in its current form,
distributions received by U.S. unitholders would no longer qualify for the
15 per cent qualified dividend tax rate.

    2007 Review and 2008 Guidance

    Following is a summary of the Trust's 2008 Guidance issued by way of news
release on November 7, 2007 (posted on www.sedar.com) and a review of 2007
actual results compared to 2007 Guidance:

    
    -------------------------------------------------------------------------
                                       2007     Actual                  2008
                                 Guidance(1)      2007   % Change   Guidance
    -------------------------------------------------------------------------
    Production (boe/d)               63,000     62,723          -     63,000
    -------------------------------------------------------------------------
    Expenses ($/boe):
      Operating costs                  9.50       9.54          -      10.20
      Transportation                   0.70       0.72          3       0.80
      G&A expenses(2)                  2.25       2.15         (4)      2.55
      Interest                         1.70       1.61         (5)      1.90
    Capital expenditures
     ($ millions)(3)                    350        397         13        395
    Weighted average trust
     units and units issuable
     (millions)                         210        210          -        216
    -------------------------------------------------------------------------

    (1) 2007 Guidance shown is the revised amounts from the Trust's third
        quarter MD&A.
    (2) G&A expenses originally split out non-cash expenses with a guidance
        estimate of $0.10 per boe compared to actual results of $0.14 per
        boe.
    (3) 2008 Capital Expenditure Guidance was revised on January 8, 2008. The
        additional $40 million is earmarked for the Trust's Montney resource
        play.

    The 2008 Guidance is issued to provide unitholders with information as to
management's expectations for results of operations for 2008. Readers are
cautioned that the 2008 Guidance may not be appropriate for other purposes.

    Actual 2007 results were in line with 2007 guidance with only minor
exceptions as follows:

    -   Transportation costs were higher than guidance due to additional
        trucking costs incurred in the fourth quarter in the Saskatchewan
        areas.
    -   Cash G&A expenses were lower than guidance due to higher operating
        recoveries attributed to high levels of capital and operating
        activity in the fourth quarter. This was offset by non-cash G&A
        expenses that were higher than guidance as a result of an increase in
        the Trust's performance multiplier at year-end.
    -   Interest expense was slightly lower than guidance due to the fact
        that the majority of the Trust's debt is denominated in U.S. dollars.
        With the strengthening of the Canadian dollar throughout 2007, the
        Trust's Canadian equivalent of U.S. dollar interest payments was
        reduced.
    -   Capital expenditures exceeded guidance by $47 million, which
        comprised unbudgeted purchases of land in the Dawson area of British
        Columbia in the third and fourth quarters of 2007 for $71.3 million
        that were offset by cost savings of approximately $20 million on the
        Trust's original 2007 capital budget amount.

    2008 Operating Income Sensitivity

    Below is a table that illustrates sensitivities to pre-hedged operating
income items with operational changes and changes to the business environment:

    -------------------------------------------------------------------------
                                                            Impact on Annual
                                                             Cash flow from
                                                               operating
                                                              activities(2)
    Business Environment                    Assumption     Change     $/Unit
    -------------------------------------------------------------------------
    Oil price (US$WTI/bbl)(1)                 $  85.00  $    1.00  $    0.04
    Natural gas price (CDN $AECO/mcf)(1)      $   6.50  $    0.10  $    0.03
    USD/CAD exchange rate                   `     1.03  $    0.01  $    0.05
    Interest rate on debt                        5.75%  %     1.0  $    0.02
    Operational
    Liquids production volume (bbl/d)           32,100  %     1.0  $    0.03
    Gas production volumes (mmcf/d)              185.0  %     1.0  $    0.02
    Operating expenses per boe                $  10.20  %     1.0  $    0.01
    Cash G&A expenses per boe                 $   2.55  %    10.0  $    0.03
    -------------------------------------------------------------------------

    (1) Analysis does not include the effect of hedging contracts.
    (2) Assumes constant working capital.
    

    Forward-Looking Statements

    This discussion and analysis contains forward-looking statements as to
the Trust's internal projections, expectations or beliefs relating to future
events or future performance within the meaning of the "safe harbour"
provisions of the United States Private Securities Litigation Reform Act of
1995 and the Securities Act (Ontario). In some cases, forward-looking
statements can be identified by terminology such as "may", "will", "should",
"expects", "projects", "plans", "anticipates" and similar expressions and in
particular, includes the material under the heading "2007 Review and 2008
Guidance". These statements represent management's expectations or beliefs
concerning, among other things, future operating results and various
components thereof or the economic performance of ARC Energy Trust ("ARC" or
"the Trust"). The projections, estimates and beliefs contained in such
forward-looking statements are based on management's assumptions relating to
the production performance of ARC's oil and gas assets, the cost and
competition for services throughout the oil and gas industry in 2007, the
continuation of ARC's historical experience with expenses and production,
changes in the capital expenditure budgets relating to undeveloped land or
reserve acquisitions and the continuation of the current regulatory and tax
regime in Canada, and necessarily involve known and unknown risks and
uncertainties, including the business risks discussed in this MD&A and related
to management's assumptions set forth herein, which may cause actual
performance and financial results in future periods to differ materially from
any projections of future performance or results expressed or implied by such
forward-looking statements. Accordingly, readers are cautioned that events or
circumstances could cause actual results to differ materially from those
predicted. Other than the 2008 Guidance that is updated and discussed
quarterly, the Trust does not undertake to update any forward looking
information in this document whether as to new information, future events or
otherwise except as required by securities laws and regulations.


    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)      2007       2006       2005       2004       2003
    -------------------------------------------------------------------------
    FINANCIAL
    Revenue before
     royalties           1,251.6    1,230.5    1,165.2      901.8      743.2
      Per unit(1)           5.95       6.02       6.10       4.85       4.80
    Cash flow from
     operating
     activities(2)         704.9      734.0      616.7      446.4      405.3
      Per unit - basic(1)   3.35       3.59       3.23       2.40       2.62
      Per unit - diluted    3.35       3.58       3.20       2.38       2.54
    Net income             495.3      460.1      356.9      241.7      284.6
      Per unit - basic(3)   2.39       2.28       1.90       1.32       1.88
      Per unit - diluted    2.39       2.27       1.88       1.31       1.82
    Distributions          498.0      484.2      376.6      330.0      279.3
      Per unit(4)           2.40       2.40       1.99       1.80       1.80
    Total assets         3,533.0    3,479.0    3,251.2    2,305.0    2,281.8
    Total liabilities    1,491.3    1,550.6    1,415.5      755.7      730.0
    Net debt
     outstanding(5)        752.7      739.1      578.1      264.8      262.1
    Weighted average trust
     units (millions)(6)   210.2      204.4      191.2      186.1      154.7
    Trust units outstanding
     and issuable
     at period end
     (millions)(6)         213.2      207.2      202.0      188.8      182.8
    -------------------------------------------------------------------------
    CAPITAL EXPENDITURES
    Geological and
     geophysical            14.9       11.4        9.2        5.4        5.7
    Land                    77.5       32.4        9.1        4.1        4.0
    Drilling and
     completions           229.5      240.5      191.8      140.4      106.2
    Plant and facilities    72.1       77.6       55.0       41.1       36.5
    Other capital            3.2        2.6        3.7        2.8        3.4
    Total capital
     expenditures          397.2      364.5      268.8      193.8      155.8
    Property
     acquisitions
     (dispositions), net    42.5      115.2       91.3      (58.2)    (161.6)
    Corporate
     acquisitions(7)           -       16.6      505.0       72.0      721.6
    Total capital
     expenditures and
     net acquisitions      439.7      496.3      865.1      207.6      715.8
    -------------------------------------------------------------------------
    OPERATING
    Production
      Crude oil (bbl/d)   28,682     29,042     23,282     22,961     22,886
      Natural gas
       (mmcf/d)            180.1      179.1      173.8      178.3      164.2
      Natural gas
       liquids (bbl/d)     4,027      4,170      4,005      4,191      4,086
      Total (boe per
       day 6:1)           62,723     63,056     56,254     56,870     54,335
    Average prices
      Crude oil ($/bbl)    69.24      65.26      61.11      47.03      36.90
      Natural gas ($/mcf)   6.75       6.97       8.96       6.78       6.40
      Natural gas
       liquids ($/bbl)     54.79      52.63      49.92      39.04      32.19
      Oil equivalent
       ($/boe)             54.54      53.33      56.54      43.13      37.29
    -------------------------------------------------------------------------
    RESERVES
    (company interest)(8)
    Proved plus probable
     reserves
      Crude oil and NGL
       (mbbl)            158,341    162,193    163,385    123,226    129,663
      Natural gas (bcf)    768.2      743.6      741.7      724.5      720.2
      Total (mboe)       286,370    286,125    286,997    243,974    249,704
    -------------------------------------------------------------------------
    TRUST UNIT TRADING
    (based on intra-day
     trading)
    Unit prices
      High                 23.86      30.74      27.58      17.98      14.87
      Low                  18.90      19.20      16.55      13.50      10.89
      Close                20.40      22.30      26.49      17.90      14.74
    Average daily volume
     (thousands)             597        706        656        420        430
    -------------------------------------------------------------------------

    (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)                                   2007
    -------------------------------------------------------------------------
    FINANCIAL                            Q4         Q3         Q2         Q1
    Revenue before royalties          338.0      300.2      305.6      307.8
      Per unit(1)                      1.59       1.42       1.46       1.48
    Cash flow from operating
     activities(2)                    173.7      179.6      179.4      172.3
      Per unit - basic(1)              0.82       0.85       0.86       0.83
      Per unit - diluted               0.82       0.85       0.86       0.83
    Net income                        106.3      120.8      184.9       83.3
      Per unit - basic(3)              0.51       0.58       0.90       0.41
      Per unit - diluted               0.51       0.58       0.89       0.41
    Distributions                     125.8      125.0      124.1      123.1
      Per unit(4)                      0.60       0.60       0.60       0.60
    Total assets                    3,533.0    3,460.8    3,432.8    3,540.1
    Total liabilities               1,491.3    1,421.4    1,415.3    1,526.6
    Net debt outstanding(5)           752.7      699.8      653.9      729.7
    Weighted average trust units(6)   212.5      210.9      209.5      207.9
    Trust units outstanding and
     issuable(6)                      213.2      211.7      210.2      208.7
    -------------------------------------------------------------------------
    CAPITAL EXPENDITURES
    Geological and geophysical          3.0        2.9        4.1        4.9
    Land                               42.6       33.0        1.7        0.2
    Drilling and completions           75.2       73.4       25.8       55.1
    Plant and facilities               17.9       21.1       16.3       16.8
    Other capital                       0.6        1.5        0.6        0.5
    Total capital expenditures        139.3      131.9       48.5       77.5
    Property acquisitions
     (dispositions) net                 5.0       27.3       10.0        0.2
    Corporate acquisitions(7)             -          -          -          -
    Total capital expenditures
     and net acquisitions             144.3      159.2       58.5       77.7
    -------------------------------------------------------------------------
    OPERATING
    Production
      Crude oil (bbl/d)              28,682     28,437     28,099     29,520
      Natural gas (mmcf/d)            187.4      173.3      176.7      183.0
      Natural gas liquids (bbl/d)     4,067      3,795      4,088      4,161
      Total (boe per day 6:1)        63,989     61,108     61,637     64,175
    Average prices
      Crude oil ($/bbl)               77.53      73.40      65.21      60.79
      Natural gas ($/mcf)              6.32       5.52       7.38       7.75
      Natural gas liquids ($/bbl)     62.75      55.64      52.76      48.04
      Oil equivalent ($/boe)          57.26      53.28      54.37      53.18
    -------------------------------------------------------------------------
    TRUST UNIT TRADING
    (based on intra-day trading)
    Unit prices
    High                              21.55      22.60      23.86      23.02
    Low                               18.90      19.00      20.78      20.05
    Close                             20.40      21.17      21.74      21.25
    Average daily volume (thousands)    624        503        599        658
    -------------------------------------------------------------------------


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

                                                         2006
    -------------------------------------------------------------------------
    FINANCIAL                            Q4         Q3         Q2         Q1
    Revenue before royalties          292.5      312.3      306.7      318.9
      Per unit(1)                      1.42       1.52       1.51       1.58
    Cash flow from operating
     activities(2)                    159.4      203.4      182.2      189.0
      Per unit - basic(1)              0.77       0.99       0.89       0.93
      Per unit - diluted               0.77       0.98       0.89       0.93
    Net income                         56.6      116.9      182.5      104.1
      Per unit - basic(3)              0.28       0.58       0.91       0.52
      Per unit - diluted               0.28       0.58       0.91       0.52
    Distributions                     122.3      121.4      120.6      119.9
      Per unit(4)                      0.60       0.60       0.60       0.60
    Total assets                    3,479.0    3,335.8    3,277.8    3,279.7
    Total liabilities               1,550.6    1,371.3    1,339.9    1,434.1
    Net debt outstanding(5)           739.1      579.7      567.4      598.9
    Weighted average trust units(6)   206.5      205.1      203.7      202.5
    Trust units outstanding and
     issuable(6)                      207.2      205.7      204.4      203.1
    -------------------------------------------------------------------------
    CAPITAL EXPENDITURES
    Geological and geophysical          3.7        2.2        2.8        2.7
    Land                               11.8        1.4       14.3        4.9
    Drilling and completions           79.1       76.2       29.8       55.4
    Plant and facilities               26.5       24.6       10.9       15.6
    Other capital                       0.8        0.5        0.8        0.5
    Total capital expenditures        121.9      104.9       58.6       79.1
    Property acquisitions
     (dispositions) net                76.4        8.4        2.8       27.6
    Corporate acquisitions(7)          16.6          -          -          -
    Total capital expenditures
     and net acquisitions             214.9      113.3       61.4      106.7
    -------------------------------------------------------------------------
    OPERATING
    Production
      Crude oil (bbl/d)              29,605     29,108     27,805     29,651
      Natural gas (mmcf/d)            179.5      173.4      178.5      185.0
      Natural gas liquids (bbl/d)     4,144      4,166      4,247      4,120
      Total (boe per day 6:1)        63,663     62,178     61,803     64,600
    Average prices
      Crude oil ($/bbl)               58.26      71.84      71.86      59.53
      Natural gas ($/mcf)              6.99       6.10       6.35       8.40
      Natural gas liquids ($/bbl)     46.51      56.60      54.44      52.91
      Oil equivalent ($/boe)          49.82      54.45      54.42      54.74
    -------------------------------------------------------------------------
    TRUST UNIT TRADING
    (based on intra-day trading)
    Unit prices
    High                              29.22      30.74      28.61      27.51
    Low                               19.20      25.25      24.35      25.09
    Close                             22.30      27.21      28.00      27.36
    Average daily volume (thousands)  1,125        614        548        546
    -------------------------------------------------------------------------

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


    CONSOLIDATED BALANCE SHEETS

    As at December 31

    (CDN$ millions)                                          2007       2006
    -------------------------------------------------------------------------
    ASSETS
    Current assets
      Cash                                              $     7.0  $     2.8
      Accounts receivable                                   162.5      129.8
      Prepaid expenses                                       15.0       18.4
      Risk management contracts (Note 11)                    13.1       25.7
      Future income taxes (Note 13)                           4.0          -
    -------------------------------------------------------------------------
                                                            201.6      176.7
    Reclamation funds (Note 5)                               26.1       30.9
    Risk management contracts (Note 11)                       4.7          -
    Property, plant and equipment (Note 6)                3,143.0    3,093.8
    Long-term investment (Note 7)                               -       20.0
    Goodwill                                                157.6      157.6
    -------------------------------------------------------------------------
    Total assets                                        $ 3,533.0  $ 3,479.0
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    LIABILITIES
    Current liabilities
      Accounts payable and accrued liabilities (Note 8) $   180.6  $   162.1
      Distributions payable                                  42.1       40.9
      Risk management contracts (Note 11)                    57.6       34.4
    -------------------------------------------------------------------------
                                                            280.3      237.4
    Risk management contracts (Note 11)                      28.2          -
    Long-term debt (Note 9)                                 714.5      687.1
    Accrued long-term incentive compensation (Note 19)       12.1       14.6
    Asset retirement obligations (Note 10)                  140.0      177.3
    Future income taxes (Note 13)                           316.2      434.2
    -------------------------------------------------------------------------
    Total liabilities                                     1,491.3    1,550.6
    -------------------------------------------------------------------------

    COMMITMENTS AND CONTINGENCIES (Note 21)

    NON-CONTROLLING INTEREST
      Exchangeable shares (Note 14)                          43.1       40.0

    UNITHOLDERS' EQUITY
      Unitholders' capital (Note 15)                      2,465.7    2,349.2
      Contributed surplus (Note 18)                           1.7        2.4
      Deficit (Note 16)                                    (465.9)    (463.2)
      Accumulated other comprehensive loss
       (Notes 3 and 16)                                      (2.9)         -
    -------------------------------------------------------------------------
    Total unitholders' equity                             1,998.6    1,888.4
    -------------------------------------------------------------------------
    Total liabilities and unitholders' equity           $ 3,533.0  $ 3,479.0
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See accompanying notes to the consolidated financial statements


    CONSOLIDATED STATEMENTS OF INCOME AND DEFICIT

    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)                 2007       2006       2007       2006
    -------------------------------------------------------------------------
    REVENUES
      Oil, natural gas, and
       natural gas liquids         $  338.0  $   292.5  $ 1,251.6  $ 1,230.5
      Royalties                       (61.6)     (51.5)    (219.4)    (222.3)
    -------------------------------------------------------------------------
                                      276.4      241.0    1,032.2    1,008.2
      (Loss) gain on risk
       management contracts
       (Note 11)
        Realized                       (1.2)       9.8       14.1       29.3
        Unrealized                    (47.9)       3.9      (55.9)      (4.6)
    -------------------------------------------------------------------------
                                      227.3      254.7      990.4    1,032.9
    -------------------------------------------------------------------------

    EXPENSES
      Transportation                    4.0        3.8       16.4       14.5
      Operating                        56.7       53.5      218.4      195.4
      General and administrative       15.0       10.1       49.1       47.1
      Interest on long-term debt
       (Note 9)                         9.2        8.7       36.9       31.8
      Depletion, depreciation and
       accretion (Notes 6 and 10)      95.0       96.2      371.5      360.0
      (Gain) loss on foreign
       exchange (Note 12)              (3.2)      21.2      (69.4)       4.2
    -------------------------------------------------------------------------
                                      176.7      193.5      622.9      653.0
    -------------------------------------------------------------------------

    Gain on sale of investment
     (Note 7)                             -          -       13.3          -
    Capital and other taxes               -          -          -       (0.3)
    Future income tax recovery
     (expense) (Note 13)               57.2       (3.7)     121.3       87.1
    -------------------------------------------------------------------------
    Net income before non-
     controlling interest             107.8       57.5      502.1      466.7
    Non-controlling interest
     (Note 14)                         (1.5)      (0.9)      (6.8)      (6.6)
    -------------------------------------------------------------------------
    Net income                     $  106.3  $    56.6  $   495.3  $   460.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Deficit, beginning of period  $  (446.4) $  (397.5) $  (463.2) $  (439.1)
    Distributions paid or
     declared (Note 17)              (125.8)    (122.3)    (498.0)    (484.2)
    -------------------------------------------------------------------------
    Deficit, end of period
     (Note 16)                    $  (465.9) $  (463.2) $  (465.9) $  (463.2)
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    -------------------------------------------------------------------------
    Net income per unit (Note 20)
      Basic                       $    0.51  $    0.28  $    2.39  $    2.28
      Diluted                     $    0.51  $    0.27  $    2.39  $    2.27
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See accompanying notes to the consolidated financial statements


    CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME AND ACCUMULATED OTHER
    COMPREHENSIVE LOSS

    For the three and twelve months ended December 31

                                     Three months ended   Twelve months ended
                                         December 31           December 31
    ($CDN millions)                    2007       2006       2007       2006
    -------------------------------------------------------------------------
    Net income                    $   106.3  $    56.6  $   495.3  $   460.1
    Other comprehensive loss,
     net of tax
      Loss on financial
       instruments designated
       as cash flow hedges(1)          (6.4)         -       (7.4)         -
      Gains and losses on
       financial instruments
       designated as cash flow
       hedges in prior periods
       realized in net income in
       the current period(2)           (0.5)         -       (0.3)         -
      Net unrealized gains
       (losses) on available-
       for-sale reclamation funds'
       investments(3)                   0.1          -       (0.1)         -
    -------------------------------------------------------------------------
    Other comprehensive loss           (6.8)         -       (7.8)         -
    -------------------------------------------------------------------------
    Comprehensive income          $    99.5  $    56.6  $   487.5  $   460.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    Accumulated other comprehensive
     income, beginning of period        3.9          -          -          -
    Application of initial adoption       -          -        4.9          -
    Other comprehensive loss           (6.8)         -       (7.8)         -
    -------------------------------------------------------------------------
    Accumulated other comprehensive
     loss, end of period (Note 16) $   (2.9)         -  $    (2.9)         -
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (1) Amounts are net of tax recovery of $2.4 million and $2.7 million,
        respectively, for the three and twelve months ended December 31,
        2007.
    (2) Amounts are net of tax liability of $0.2 and $0.1 million,
        respectively, for the three and twelve months ended December 31,
        2007
    (3) Nominal future income tax impact.

    See accompanying notes to consolidated financial statements.


    CONSOLIDATED STATEMENTS OF CASH FLOWS

    For the three and twelve months ended December 31

                                     Three months ended   Twelve months ended
                                         December 31           December 31
    ($CDN millions)                    2007       2006       2007       2006
    -------------------------------------------------------------------------
    CASH FLOWS FROM OPERATING
     ACTIVITIES
    Net income                    $   106.3  $    56.6  $   495.3  $   460.1
    Add items not involving cash:
      Non-controlling interest
       (Note 14)                        1.5        0.9        6.8        6.6
      Future income tax (recovery)
       expense (Note 13)              (57.2)       3.7     (121.3)     (87.1)
      Depletion, depreciation and
       accretion (Notes 6 and 10)      95.0       96.2      371.5      360.0
      Non-cash loss (gain) on risk
       management contracts (Note 11)  47.9       (3.9)      55.9        4.6
      Non-cash (gain) loss on foreign
       exchange (Note 12)              (3.1)      21.0      (69.6)       4.5
      Non-cash trust unit incentive
       compensation (Notes 18 and 19)   3.6       (0.1)       3.5       11.9
      Gain on sale of investment
       (Note 7)                           -          -      (13.3)         -
    Expenditures on site restoration
     and reclamation (Note 10)         (3.6)      (4.0)     (18.2)     (10.6)
    Change in non-cash working
     capital                          (16.7)     (11.1)      (5.7)     (16.0)
    -------------------------------------------------------------------------
                                      173.7      159.3      704.9      734.0
    -------------------------------------------------------------------------

    CASH FLOWS FROM FINANCING
     ACTIVITIES
    Issuance of long-term debt
     under revolving credit
     facilities, net                   99.1      167.1      104.2      162.7
    Repayment of senior
     secured notes                     (5.8)      (6.8)      (5.8)      (6.8)
    Issue of trust units                0.8        2.2        3.7       14.4
    Trust unit issue costs                -       (0.2)         -       (0.2)
    Cash distributions paid
     (Note 17)                        (99.1)     (95.7)    (388.4)    (389.6)
    Payment of retention bonuses          -          -       (1.0)      (1.0)
    Change in non-cash
     working capital                   (0.9)      (2.7)       0.4          -
    -------------------------------------------------------------------------
                                       (5.9)      63.9     (286.9)    (220.5)
    -------------------------------------------------------------------------

    CASH FLOWS FROM INVESTING
     ACTIVITIES
    Corporate acquisitions, net of
     cash received (Note 4)               -      (16.6)         -      (16.6)
    Acquisition of petroleum and
     natural gas properties            (5.1)     (76.6)     (43.7)    (117.4)
    Proceeds on disposition of
     petroleum and natural gas
     properties                           -          -        1.2        2.1
    Capital expenditures             (138.9)    (121.8)    (396.5)    (362.7)
    Long-term investment (Note 7)         -          -       33.3      (20.0)
    Net reclamation fund withdrawals
     (contributions) (Note 5)           0.2       (1.9)       4.7       (7.4)
    Change in non-cash working
     capital                          (17.0)      (3.9)     (12.8)      11.3
    -------------------------------------------------------------------------
                                     (160.8)    (220.8)    (413.8)    (510.7)
    -------------------------------------------------------------------------
    INCREASE IN CASH                    7.0        2.4        4.2        2.8
    CASH, BEGINNING OF PERIOD             -        0.4        2.8          -
    CASH, END OF PERIOD           $     7.0  $     2.8  $     7.0  $     2.8
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    See accompanying notes to the consolidated financial statements



    NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
    December 31, 2007 and 2006
    (all tabular amounts in CDN$ millions, except per unit and volume
    amounts)

    1.  STRUCTURE OF THE TRUST

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

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

    2.  SUMMARY OF ACCOUNTING POLICIES

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

        In particular, the amounts recorded for depletion, depreciation and
        accretion of the petroleum and natural gas properties and for asset
        retirement obligations are based on estimates of reserves and future
        costs. By their nature, these estimates, and those related to future
        cash flows used to assess impairment, are subject to measurement
        uncertainty and the impact on the financial statements of future
        periods could be material.

        Principles of Consolidation

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

        Revenue Recognition

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

        Transportation

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

        Joint Venture

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

        Depletion and Depreciation

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

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

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

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

        Unit Based Compensation

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

        Whole Trust Unit Incentive Plan Compensation

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

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

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

        Cash Equivalents

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

        Reclamation Funds

        Reclamation funds hold investment grade assets and cash and cash
        equivalents. In accordance with Section 3855, 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. Section 3855
        became effective January 1, 2007 as described in Note 3.

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

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

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

        Impairment

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

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

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

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

        Goodwill

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

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

        Asset Retirement Obligations

        The Trust recognizes an Asset Retirement Obligation ("ARO") in the
        period in which it is incurred when a reasonable estimate of the fair
        value can be made. On a periodic basis, management will review these
        estimates and changes, if any, to the estimate will be applied on a
        prospective basis. 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 ARO
        are charged against the ARO to the extent of the liability recorded.

        Income Taxes

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

        Basic and Diluted per Trust Unit Calculations

        Basic net income per unit is computed by dividing the net income by
        the weighted average number of trust units outstanding during the
        period. Diluted net income per unit amounts are calculated based on
        net income before non-controlling interest divided by dilutive trust
        units. Dilutive trust units are arrived at by taking weighted average
        trust units and trust units issuable on conversion of exchangeable
        shares, and giving effect 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.

        Derivative Financial Instruments

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

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

        For derivative instruments that do qualify as effective accounting
        hedges, policies and procedures are in place to ensure that the
        required documentation and approvals are in place. This documentation
        specifically ties the derivative financial instruments to their use,
        and in the case of commodities, to the mitigation of market price
        risk associated with cash flows expected to be generated. When
        applicable, the Trust also identifies all relationships between
        hedging instruments and hedged items, as well as its risk management
        objective and the strategy for undertaking hedge transactions. This
        would include linking the particular derivative to specific assets
        and liabilities on the Consolidated Balance Sheet or to specific firm
        commitments or forecasted transactions. Where specific hedges are
        executed, the Trust assesses, both at the inception of the hedge and
        on an ongoing basis, whether the derivative used in the particular
        hedging transaction is effective in offsetting changes in fair value
        or cash flows of the hedged item. For accounting treatment of gains
        on losses on derivative instruments that qualify as effective
        accounting hedges refer to Note 3 - Hedges.

        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 income in the period in which they arise.

        Non-Controlling Interest

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

    3.  NEW ACCOUNTING POLICIES

        Effective January 1, 2007, the Trust adopted six new accounting
        standards that were issued by the Canadian Institute of Chartered
        Accountants ("CICA"): Handbook Section 1530, Comprehensive Income,
        Section 3855, Financial Instruments - Recognition and Measurement,
        Section 3861, Financial Instruments - Disclosure and Presentation,
        Section 3865, Hedges, Section 3251, Equity and Section 1506,
        Accounting Changes. These new accounting standards have been adopted
        prospectively and, accordingly, comparative amounts for prior periods
        have not been restated. The standards provide requirements for the
        recognition, measurement and disclosure of financial instruments, the
        use of hedge accounting and the presentation of equity.

        Comprehensive Income

        Section 1530 introduces Comprehensive Income, which consists of Net
        Income and Other Comprehensive Income (Loss) ("OCI"). Comprehensive
        Income includes changes in Unitholders' Equity from transactions and
        other events with non-owner sources, and OCI includes unrealized
        gains and losses on financial assets classified as available-for-sale
        and changes in the fair value of the effective portion of cash flow
        hedging instruments that qualify for hedge accounting. These items
        are excluded from Net Income calculated in accordance with GAAP. The
        Consolidated Statements of Comprehensive Income includes Accumulated
        Other Comprehensive Income (Loss) ("AOCI"), and the changes in these
        items during the three and twelve month periods ended December 31,
        2007. Cumulative changes in OCI are included in AOCI, which is
        presented as a new category within Unitholders' Equity on the
        Consolidated Balance Sheet.

        Financial Instruments - Recognition and Measurement

        Section 3855 establishes standards for recognizing and measuring
        financial assets, financial liabilities and non-financial
        derivatives. Under this standard, all financial instruments are
        required to be measured at fair value on initial recognition.
        Measurement in subsequent periods depends on whether the financial
        instrument has been classified as held-for-trading, available-for-
        sale, held-to-maturity, loans and receivables, or other financial
        liabilities.

           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 recognized immediately in Net Income. With the exception of
           risk management contracts that qualify for hedge accounting, the
           Trust classifies all risk management contracts as held-for-
           trading. Cash is 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 OCI, net of
           tax. Amounts recognized in OCI for available-for-sale financial
           assets are transferred to net income when the asset is
           derecognized or when there is an other than temporary asset
           impairment. A portion of the Trust's reclamation fund is
           classified as available-for-sale financial 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. The Trust classifies a
           portion of its reclamation fund investments to held-to-maturity,
           accounts receivables to loans and receivables, and accounts
           payable, distributions payable and long-term debt to other
           financial liabilities.

        The Section allows an entity to designate any financial instrument
        as held-for-trading, which by characteristic and intended use may
        be classified under another category. The Trust has chosen not to
        make any such designations.

        Transaction costs are expensed as incurred for financial instruments
        excluding long-term debt. The Trust has elected to capitalize costs
        incurred relating to debt issuances and to amortize these costs over
        the term of the associated debt using the effective interest rate
        method.

        The Trust has elected January 1, 2003 as the effective date to
        identify and measure embedded derivatives in financial and non-
        financial contracts that are not closely related to the host
        contracts. No adjustments were required for embedded derivatives on
        adoption of this standard.

        Financial Instruments - Disclosure and Presentation

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

        Hedges

        Section 3865 specifies the criteria that must be satisfied in order
        for hedge accounting to be applied and the accounting for fair value
        and cash flow hedges. Hedge accounting is discontinued prospectively
        when the derivative no longer qualifies as an effective hedge, or the
        derivative is terminated or sold, or upon the sale or early
        termination of the hedged item. The Trust has currently designated
        its financial electricity contracts and treasury rate lock contracts
        as effective cash flow hedges. The Trust assesses, both at the
        inception of the hedge and on an ongoing basis, whether the
        derivative used in the particular hedging transaction is effective in
        offsetting changes in cash flows of the hedged item.

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

        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 Net Income.

        Equity

        Section 3251 establishes standards for the presentation of equity and
        changes in equity during the reporting period. This section specifies
        that changes in equity for the period arising from Net Income, OCI,
        other changes in deficit, changes in contributed surplus, and changes
        in unitholders' capital must be presented separately.

        Impact

        As a result of these changes in accounting policies, on January 1,
        2007 the Trust recorded $4.9 million to application of initial
        adoption in AOCI to reflect the opening fair value of its cash flow
        hedges, net of tax, which was previously not recorded on the
        consolidated financial statements. The Trust has also recorded an
        increase of $7 million to its risk management asset and an increase
        of $2.1 million to its future income tax liability.

        Accounting Changes

        Section 1506 permits voluntary changes in accounting policy only if
        they result in financial statements that provide more reliable and
        relevant information. Changes in policy are applied retrospectively
        unless it is impractical to determine the period or cumulative impact
        of the change. Corrections of prior period errors are applied
        retrospectively and changes in accounting estimates are applied
        prospectively by including these changes in Net Income. In addition,
        disclosure is required for all future accounting changes when an
        entity has not applied a new source of GAAP that has been issued but
        is not yet effective.

        Future Accounting Changes

        On December 1, 2006, the CICA issued three new accounting standards:
        Section 1535, Capital Disclosures, Section 3862, Financial
        Instruments - Disclosures, and Section 3863, Financial Instruments -
        Presentation. These new standards will be effective on January 1,
        2008.

        Section 1535 specifies the disclosure of an entity's objectives,
        policies and processes for managing capital, quantitative data about
        what the entity regards as capital, whether the entity has complied
        with any capital requirements, and if it has not complied, the
        consequences of such non- compliance. This Section is expected to
        have minimal impact on the Trust's financial statements.

        Sections 3862 and 3863 specify standards of presentation and enhanced
        disclosures on financial instruments. These Sections will require the
        Trust to increase disclosure on the nature and extent of risks
        arising from financial instruments and how the entity manages those
        risks.

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

    4.  CORPORATE ACQUISITIONS

        On December 6, 2006 the Trust completed a minor corporate acquisition
        for net cash consideration of $16.6 million. There was no goodwill
        recognized with this acquisition. Substantially all of the
        consideration was applied against property, plant and equipment, with
        a nominal amount applied against working capital items.

    5.  RECLAMATION FUNDS

                                 December 31, 2007         December 31, 2006
    -------------------------------------------------------------------------
                          Unrestricted  Restricted  Unrestricted  Restricted
    -------------------------------------------------------------------------
    Balance, beginning
     of period               $    24.8   $     6.1     $    23.5   $       -
    Contributions                  6.2         5.9           6.0         6.1
    Reimbursed expendi-
     tures(1)                    (17.5)       (0.6)         (5.7)          -
    Interest earned on
     funds                         1.1         0.3           1.0           -
    Net unrealized losses
     on available-for-sale
     investments                  (0.2)          -             -           -
    -------------------------------------------------------------------------
    Balance, end of
     period(2)               $    14.4   $    11.7     $    24.8   $     6.1
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

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

        (2) As at December 31, 2007 the unrestricted reclamation fund held
            $1.5 million in cash and cash equivalents ($15 million at
            December 31, 2006), with the balance held in investment grade
            assets.

        An unrestricted reclamation fund was established to fund future asset
        retirement obligation costs. In addition, the Trust has created a
        restricted reclamation fund associated with the Redwater property
        acquired in 2005. Contributions to the restricted and unrestricted
        reclamation funds and interest earned on the balances have been
        deducted from the cash distributions to the unitholders. The Board of
        Directors of ARC Resources has approved voluntary contributions to
        the unrestricted reclamation fund over a 20-year period that
        currently results in minimum annual contributions of $6 million
        ($6 million in 2006) based upon properties owned as at December 31,
        2007. Contributions to the restricted reclamation fund will vary over
        time and have been disclosed in Note 21. 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 12 months ended December 31, 2007 no amounts relating to
        available-for-sale reclamation fund assets were classified from
        accumulated other comprehensive loss into the statement of income.

    6.  PROPERTY, PLANT AND EQUIPMENT

                                                          2007          2006
        ---------------------------------------------------------------------
        Property, plant and equipment, at cost       $ 5,065.0     $ 4,655.3
        Accumulated depletion and depreciation        (1,922.0)     (1,561.5)
        ---------------------------------------------------------------------
        Property, plant and equipment, net           $ 3,143.0     $ 3,093.8
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The calculation of 2007 depletion and depreciation included an
        estimated $549 million ($547 million in 2006) for future development
        costs associated with proved undeveloped reserves and excluded
        $173.7 million ($108.9 million in 2006) for the book value of
        unproved properties.

        The Trust performed a ceiling test calculation at December 31, 2007
        to assess the recoverable value of property plant and equipment
        (PP&E). Based on the calculation, the value of future net revenues
        from the Trust's reserves exceeded the carrying value of the Trust's
        PP&E at December 31, 2007. The benchmark prices used in the
        calculation were as follows:

                                   WTI Oil         AECO Gas          USD/CAD
        Year                      ($US/bbl)     (CDN$/mmbtu)  Exchange Rates
        ---------------------------------------------------------------------
        2008                         92.00             6.75             1.00
        2009                         88.00             7.55             1.00
        2010                         84.00             7.60             1.00
        2011                         82.00             7.60             1.00
        2012                         82.00             7.60             1.00
        2013                         82.00             7.60             1.00
        2014                         82.00             7.80             1.00
        2015                         82.00             7.97             1.00
        2016                         82.02             8.14             1.00
        2017                         83.66             8.31             1.00
        2018                         85.33             8.48             1.00
        ---------------------------------------------------------------------
        Remainder(1)                  2.0%             2.0%             1.00
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (1) Percentage change represents the change in each year after 2018
            to the end of the reserve life.

    7.  LONG-TERM INVESTMENT

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

    8.  ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
                                                             2007       2006
        ---------------------------------------------------------------------
        Trade accounts payable                          $    32.5  $    39.0
        Accrued liabilities                                 127.7      108.8
        Current portion of accrued long-term
         incentive compensation                              18.2       11.5
        Interest payable                                      2.2        1.8
        Retention bonuses                                       -        1.0
        ---------------------------------------------------------------------
        Total accounts payable and accrued liabilities  $   180.6  $   162.1
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The current portion of accrued long-term incentive compensation
        represents the current portion of the Trust's estimated liability for
        the Whole Unit Plan as at December 31, 2007 (see Note 19). This
        amount is payable in 2008.

    9.  LONG-TERM DEBT

                                                             2007       2006
        ---------------------------------------------------------------------
        Revolving credit facilities
          Syndicated credit facility - CDN denominated  $   344.9  $   196.6
          Syndicated credit facility - US denominated       154.1      228.4
          Working capital facility                              -        1.1
        Senior secured notes
          5.42% USD Note                                     74.1       87.4
          4.94% USD Note                                     17.8       28.0
          4.62% USD Note                                     61.8       72.8
          5.10% USD Note                                     61.8       72.8
        ---------------------------------------------------------------------
        Total long-term debt outstanding                $   714.5  $   687.1
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        Revolving Credit Facilities

        During 2007, the Trust renewed its $800 million secured, annually
        extendible, financial covenant-based three year syndicated credit
        facility. The revolving credit facility's security is in the form of
        a floating charge on all lands and assignments and a negative pledge
        on petroleum and natural gas properties. The Trust also has in place
        a $25 million demand working capital facility.

        Borrowings under the credit facility bear interest at bank prime (six
        per cent at December 31, 2007 and December 31, 2006) or, at the
        Trust's option, Canadian dollar bankers' acceptances or U.S. dollar
        LIBOR loans, plus a stamping fee. At the option of the Trust, the
        lenders will review the credit facility each year and determine
        whether they will extend the revolving period for another year. In
        the event that the credit facility is not extended at anytime before
        the maturity date, the loan balance will become repayable on the
        maturity date. The maturity date of the current credit facility is
        April 15, 2010. All drawings under the facility are subject to
        stamping fees that vary between 60 bps and 110 bps depending on
        certain consolidated financial ratios.

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

        5.42 Per Cent and 4.94 Per Cent Senior Secured USD Notes

        These senior secured notes were issued in two separate issues
        pursuant to an Uncommitted Master Shelf Agreement. The US$18 million
        senior secured notes were issued in 2002, bear interest at 4.94 per
        cent, have a remaining final term of 2.8 years (remaining average
        term of 1.8 years) and require equal principal repayments of
        US$6 million over a three year period commencing in 2008. The
        US$75 million senior secured notes were issued in 2005, bear interest
        at 5.42 per cent, have a remaining final term of 10 years (remaining
        weighted average term of 6.6 years) and require equal principal
        repayments over an eight year period commencing in 2010.

        4.62 Per Cent and 5.10 Per Cent Senior Secured USD Notes

        These notes were issued on April 27, 2004 via a private placement in
        two tranches of US$62.5 million each. The first tranche of
        US$62.5 million bears interest at 4.62 per cent and has a remaining
        final term of 6.3 years (remaining weighted average term of 3.9
        years) and require equal principal repayments over a six year period
        commencing 2009. Immediately following the issuance, the Trust
        entered into interest rate swap contracts that effectively changed
        the interest rate from fixed to floating (see Note 11). The second
        tranche of US$62.5 million bears interest at 5.10 per cent and has a
        remaining final term of 8.3 years (remaining weighted average term of
        6.4 years). Repayments of the notes will occur over a five year
        period commencing in 2012.

        Debt Covenants

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

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

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

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

        In the event that the Trust enters into a material acquisition
        whereby the purchase price exceeds 10 per cent of the book value of
        the Trust's assets, the ratios in the first two covenants above are
        increased to 3.5 and 5.5 times respectively, while the third covenant
        is increased to 55 per cent for the subsequent six month period. As
        at December 31, 2007, the Trust had $4.8 million in letters of credit
        ($4.7 million in 2006), no subordinated debt, and was in compliance
        with all covenants.

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

        During 2007, the weighted-average effective interest rate under the
        credit facility was 5.5 per cent (5.3 per cent in 2006).

        Amounts due under the working capital facility and the senior secured
        notes in the next 12 months have not been included in current
        liabilities as management has the ability and intent to refinance
        this amount through the syndicated credit facility.

        Interest paid during 2007 was $1.8 million less than interest
        expense. The difference between interest paid and interest expense in
        2006 was nominal.

    10. ASSET RETIREMENT OBLIGATIONS

        The total future asset retirement obligations were estimated by
        management based on the Trust's net ownership interest in all wells
        and facilities, estimated costs to reclaim and abandon the wells and
        facilities and the estimated timing of the costs to be incurred in
        future periods. The Trust has estimated the net present value of its
        total asset retirement obligations to be $140 million as at
        December 31, 2007 ($177.3 million in 2006) based on a total future
        undiscounted liability of $1.29 billion ($1.04 billion in 2006). At
        December 31, 2007 management estimates that these payments are
        expected to be made over the next 51 years with the bulk of payments
        being made in years 2048 to 2058. At December 31, 2006 management had
        estimated that the expenditures would be made over 61 years with the
        bulk of payments being made in years 2017 to 2021 and 2057 to 2067.
        The Trust's weighted average credit adjusted risk free rate of 6.6
        per cent (6.5 per cent in 2006) and an inflation rate of 2.0 per cent
        (2.0 per cent in 2006) were used to calculate the present value of
        the asset retirement obligations. During the year, no gains or losses
        were recognized on settlements of asset retirement obligations.

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

                                                             2007       2006
        ---------------------------------------------------------------------
        Balance, beginning of year                      $   177.3  $   165.1
        Increase in liabilities relating to corporate
         acquisitions                                           -        4.9
        Increase in liabilities relating to
         development activities                               3.8        2.8
        (Decrease) increase in liabilities relating to
         change in estimate                                 (34.4)       4.0
        Settlement of liabilities during the year           (18.2)     (10.6)
        Accretion expense                                    11.5       11.1
        ---------------------------------------------------------------------
        Balance, end of year                            $   140.0  $   177.3
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    11. FINANCIAL INSTRUMENTS

        The Trust is exposed to a number of financial risks that are part of
        its normal course of business. The Trust has a risk management
        program in place that includes financial instruments as disclosed in
        this note. ARC's risk management program is overseen by an
        experienced risk management committee based on guidelines approved by
        the board of directors. The objective of the risk management program
        is to mitigate the Trust's exposure to the following financial risks:

        Commodity Price Risks

        The Trust's operational results and financial condition, and
        therefore the amount of distributions paid to unitholders, are
        dependent on the commodity prices received for oil and natural gas
        production and the price paid for electricity. Commodity prices have
        fluctuated widely during recent years and are determined by weather,
        economic and, in the case of oil prices, geopolitical factors. Any
        movement in commodity prices could have an effect on the Trust's
        financial condition and therefore on the distributions to
        unitholders. ARC manages the risks associated with changes in
        commodity prices by entering into risk management contracts.

        Variations in Interest Rates

        The Trust has both fixed and variable interest debt. Changes in
        interest rates could result in a significant increase or decrease in
        the amount the Trust pays to service variable interest debt,
        potentially impacting distributions to unitholders. Changes in
        interest rates could also result in fair value risk on the Trust's
        senior secured notes. This risk is mitigated due to the fact that the
        Trust does not intend to settle its fixed rate debt prior to
        maturity. ARC manages the risk associated with changes in interest
        rates by entering into financial swaps in order to lock in favorable
        fixed or floating rates.

        Variations in Foreign Exchange Rates

        World commodity prices are quoted in U.S. dollars, therefore the
        price received by Canadian producers is affected by the Canadian/U.S.
        dollar exchange rate that may fluctuate over time. Variations in the
        exchange rate of the Canadian dollar could have significant positive
        or negative impact on distributions to unitholders. ARC has initiated
        certain risk management contracts to mitigate these risks.

        Credit Risk

        The Trust is exposed to credit risk with respect to its accounts
        receivable and risk management contracts. Most of the Trust's
        accounts receivable relate to oil and natural gas sales and are
        exposed to typical industry credit risks. The Trust manages this
        credit risk by entering into sales contracts with only established
        entities and reviewing its exposure to individual entities on a
        regular basis. The Trust minimizes credit risk on risk management
        contracts by entering into agreements with counterparties that are of
        investment grade.

        The Trust has a legal right to offset asset and liability positions
        with some of its counterparties. In situations where there is a legal
        right to offset, balances are still shown gross on the Consolidated
        Balance Sheet as it is not the Trust's intention to net settle. Only
        in situations of credit default would these asset and liability
        positions be shown net on the Consolidated Balance Sheet.

        Maximum credit risk is calculated as the total positive value of
        accounts receivable and risk management contracts at the balance
        sheet date less any liability amounts where there is a legal right to
        offset, to the extent that there are positive value accounts
        receivable or risk management contracts with the same counterparty.
        The following table details the Trust's maximum credit risk as at
        December 31:

                                                             2007       2006
        ---------------------------------------------------------------------
        Trade Accounts Receivable                       $   159.5  $   129.8
        Risk Management Contracts                             6.8       21.9
        ---------------------------------------------------------------------
        Maximum Credit Exposure                         $   166.3  $   151.7
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        While the Trust is exposed to the above credit losses due to the
        potential non-performance of its counterparties, the Trust considers
        the risk of this remote.

        Financial Instruments

        Financial Instruments of the Trust carried on the Consolidated
        Balance Sheet are carried at cost with the exception of reclamation
        fund assets classified as available-for-sale and risk management
        contracts, which are carried at fair value. Except for those items
        noted in the table below there were no significant differences
        between the carrying value of financial instruments and their
        estimated fair values, at December 31:

                                        Carrying Value            Fair Value
                                       2007       2006       2007       2006
        ---------------------------------------------------------------------
        Reclamation Fund Assets
         classified as available-
         for-sale(1)              $     8.1  $     5.2  $     8.1  $     5.2
        Reclamation Fund Assets
         classified as held-to-
         maturity(1)                   18.0       25.7       17.8       27.7
        Senior secured notes(2)       215.5      261.0      226.1      257.0
        ---------------------------------------------------------------------

        (1)   Fair value obtained from third parties, determined directly by
              reference to quoted market prices.
        (2)   Fair Value calculated as the present value of future principal
              and interest payments discounted at the Trust's credit adjusted
              risk free rate.

        Risk Management Contracts

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

        Following is a summary of all risk management contracts in place as
        at December 31, 2007 that do not qualify for hedge accounting:

    Financial WTI Crude Oil Contracts

                                             Bought    Sold     Sold  Bought
                                    Volume      Put     Put     Call    Call
    Term                   Contract  bbl/d  US$/bbl US$/bbl  US$/bbl US$/bbl
    -------------------------------------------------------------------------
    Jan 08 - Mar 08          Collar  2,000    92.50        -   110.00      -
    Jan 08 - Mar 08          Collar  2,000    92.50        -   105.00      -
    Jan 08 - Mar 08  Covered Collar  2,000    90.00        -   105.00 120.00
    Jan 08 - Mar 08      Bought Put    500    84.00        -        -      -
    Jan 08 - Mar 08  3 - Way Collar  1,000    84.00    69.00   105.00      -
    Jan 08 - Mar 08      Put Spread    500    83.00    68.00        -      -
    Jan 08 - Mar 08  3 - Way Collar  1,000    79.00    66.00   105.00      -
    Jan 08 - Jun 08  3 - Way Collar  1,000    65.00    52.50    82.50      -
    Jan 08 - Jun 08  3 - Way Collar  1,000    65.00    52.50    85.00      -
    Jan 08 - Jun 08          Collar  1,000    65.00        -    85.00      -
    Jan 08 - Dec 08  3 - Way Collar  1,000    70.00    55.00    90.00      -
    Jan 08 - Dec 08  3 - Way Collar  1,000    67.50    52.50    85.00      -
    Jan 08 - Dec 08          Collar  1,000    67.50        -    85.00      -
    Jan 08 - Dec 08  3 - Way Collar  2,000    61.50    50.00    85.00      -
    Jan 08 - Dec 08  3 - Way Collar  1,000    61.30    50.00    85.00      -
    Jan 08 - Dec 08  3 - Way Collar  2,000    61.00    50.00    85.00      -
    Apr 08 - Jun 08          Collar  2,000    90.00        -   110.00      -
    Apr 08 - Jun 08      Put Spread    500    85.00    70.00        -      -
    Apr 08 - Jun 08      Put Spread    500    85.00    69.00        -      -
    Apr 08 - Jun 08      Put Spread    500    84.00    68.00        -      -
    Apr 08 - Jun 08      Put Spread  1,000    79.00    66.00        -      -
    Jul 08 - Dec 08          Collar  2,000    85.00        -   107.50      -
    Jan 09 - Dec 09  3 - Way Collar  5,000    55.00    40.00    90.00      -
    -------------------------------------------------------------------------


    Financial AECO Natural Gas Option Contracts

                                             Bought     Sold     Sold
                                    Volume      Put      Put     Call
    Term                   Contract   GJ/d  CDN$/GJ  CDN$/GJ  CDN$/GJ
    -------------------------------------------------------------------------
    Apr 08 - Oct 08          Collar 10,000     7.00        -     9.00
    Apr 08 - Oct 08  3 - Way Collar 10,000     7.00     5.75     9.00
    -------------------------------------------------------------------------


    Financial NYMEX Natural Gas Contracts

                                             Bought     Sold     Sold
                                    Volume      Put      Put     Call
                                     mmbtu      US$      US$      US$
    Term                   Contract     /d   /mmbtu   /mmbtu   /mmbtu
    -------------------------------------------------------------------------
    Jan 08 - Mar 08  3 - Way Collar 10,000     9.25     6.25    10.00
    Jan 08 - Mar 08          Collar 20,000     8.50        -    10.00
    Jan 08 - Mar 08          Collar  5,000     7.85        -     9.40
    Jan 08 - Mar 08          Collar  5,000     8.25        -     9.25
    Jan 08 - Mar 08          Collar  5,000     8.00        -     9.00
    Apr 08 - Oct 08  3 - Way Collar 10,000     8.00     6.00     9.60
    Apr 08 - Oct 08  3 - Way Collar 10,000     7.80     6.20     9.50
    Nov 08 - Mar 09          Collar 20,000     8.50        -    11.00
    -------------------------------------------------------------------------


    Financial Basis Swap Contract: receive NYMEX (Last 3 Day); pay AECO
    (Monthly)
                                              Basis
                                    Volume     Swap
                                     mmbtu      US$
    Term                   Contract     /d   /mmbtu
    -------------------------------------------------------------------------
    Jan 08 - Oct 08      Basis Swap 50,000  (1.1930)
    Nov 08 - Oct 10      Basis Swap 50,000  (1.0430)
    -------------------------------------------------------------------------


    Energy Equivalent Swap

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

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


    Financial Foreign Exchange Contracts

                                      Noti-                    Bought   Sold
                                      onal     Swap     Swap      Put    Put
                                    Volume     CDN$      US$     CDN$   CDN$
    Term                   Contract MM US$     /US$    /CDN$     /US$   /US$
    -------------------------------------------------------------------------
    USD Option Contracts
    Jan 08 - Dec 08      Put Spread   12.0        -        -   1.0750 1.0300
    -------------------------------------------------------------------------


    USD Long-term Principal Debt Repayment Contracts

                                      Noti-                    Bought   Sold
                                      onal     Swap     Swap      Put    Put
                                    Volume     CDN$      US$     CDN$   CDN$
    Settlement Date        Contract MM US$     /US$    /CDN$     /US$   /US$
    -------------------------------------------------------------------------
    December 17, 2012       Forward   9.38   0.9324  (1.0725)       -      -
    April 27, 2013          Forward  10.42   0.9454  (1.0578)       -      -
    April 27, 2013          Forward  12.50   0.9430  (1.0604)       -      -
    December 15, 2013       Forward   9.38   0.9520  (1.0504)       -      -
    April 27, 2014          Forward  10.42   0.9743  (1.0264)       -      -
    April 27, 2014          Forward  12.50   0.9615  (1.0400)       -      -
    December 15, 2014       Forward   9.38   0.9825  (1.0178)       -      -
    April 27, 2015          Forward  12.50   0.9825  (1.0178)       -      -
    December 15, 2015       Forward   9.40   0.9980  (1.0020)       -      -
    April 27, 2016          Forward  12.50   1.0180  (0.9823)       -      -
    December 15, 2017       Forward   9.40   1.0184  (0.9819)       -      -
    December 15, 2016        Collar   9.40        -        -   1.0600 1.0000
    -------------------------------------------------------------------------


    Financial Interest Rate Contracts(1)(2)

                                      Prin-   Fixed
                                     cipal   Annual         Spread on
    Term                   Contract MM US$  Rate (%)      3 Mo. LIBOR
    -------------------------------------------------------------------------
    Jan 08 - Apr 14            Swap   30.5     4.62            38 bps
    Jan 08 - Apr 14            Swap   32.0     4.62         (25.5 bps)
    -------------------------------------------------------------------------

    (1) Starting in 2009, the notional amount of the contracts decreases
        annually until 2014. The Trust pays the floating interest rate based
        on a three month LIBOR plus a spread and receives the fixed interest
        rate.
    (2) Starting in 2009 a mutual put exists where both parties have the
        right to call on the other party to pay the then current mark-to-
        market value of the contract.


        Following is a summary of all risk management contracts in place as
        at December 31, 2007 that qualify for hedge accounting:

    Financial Electricity Contracts(3)(4)

                                    Volume     Swap
    Term                   Contract    MWh CDN$/MWh
    -------------------------------------------------------------------------
    Jan 08 - Dec 08            Swap   15.0    60.17
    Jan 09 - Dec 09            Swap   15.0    59.33
    Jan 10 - Dec 10            Swap    5.0    63.00
    -------------------------------------------------------------------------

    (3) Contracted volume is based on a 24/7 term.
    (4) Includes margin provision on 5 MWh per year if contract value exceeds
        $30M. If exercised a letter of credit would be issued for values in
        excess of $30 million.


    USD Note Treasury Rate Locks
                                 Principal          Interest
    Settlement Date                 MM US$           Rate (%)
    -------------------------------------------------------------------------
    February 15, 2008                125.0          4.8082(5)
    -------------------------------------------------------------------------

    (5) Rate is based on 10 year US Treasury Bond


        During the year the Trust entered into treasury rate lock contracts
        in order to manage the Trust's interest rate exposure on future debt
        issuances. These contracts have been designated as effective
        accounting hedges on their respective contract dates and hedge
        accounting has been applied. The unrealized fair value loss on these
        contracts of $7.4 million has been recorded on the Consolidated
        Balance Sheet at December 31, 2007 with the movement in the fair
        value recorded in OCI, net of tax. Ineffectiveness as at December 31,
        2007 is nominal and was calculated by considering the present value
        of future cash flows on the original treasury rate lock contract and
        the rate effective on the contract at December 31, 2007. The maximum
        expected term for which the Trust is hedging its interest rate risk
        exposure is 10 years, which is the expected term of the future debt
        issuance. It is expected that a $0.8 million fair value loss will be
        reclassified to Net Income within the next 12 months.

        The Trust's fixed price electricity contracts are intended to manage
        price risk on electricity consumption. All fixed price electricity
        contracts were designated as effective accounting hedges on their
        respective contract dates. A realized loss of $0.1 million and gain
        of $0.4 million for the three months and twelve months ended
        December 31, 2007 respectively (gain of $2.4 million and $3.4 million
        respectively in 2006) on the electricity contracts has been included
        in operating costs. The unrealized fair value gain on the electricity
        contracts of $4 million has been recorded on the Consolidated Balance
        Sheet at December 31, 2007 with the movement in fair value recorded
        in OCI, net of tax. The fair value movement as at December 31, 2007
        amounts to an unrealized loss of $3 million. $1.9 million of this
        gain is expected to be recognized in income over the next 12 months.

        The Trust has entered into interest rate swap contracts to manage the
        Company's interest rate exposure on debt instruments. Prior to 2007,
        these contracts were designated as effective accounting hedges on the
        contract date. At January 1, 2007 the Trust elected to cease applying
        hedge accounting to these contracts.

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

                                               December 31       December 31
                                                      2007              2006
        ---------------------------------------------------------------------
        Fair value, beginning of year(1)         $    (8.7)        $    (4.1)
        Fair value, end of year(1)(2)                (64.6)             (8.7)
        ---------------------------------------------------------------------
        Change in fair value of contracts
         in the year                                 (55.9)             (4.6)
        Realized gains in the year                    14.1              29.3
        ---------------------------------------------------------------------
        (Loss) gain on risk management
         contracts(1)                            $   (41.8)        $    24.7
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (1)   For 2007 the fixed price electricity and treasury rate lock
              contracts that were accounted for as effective accounting
              hedges were excluded. For 2006 the fixed price electricity
              contract and interest rate swap contracts that were accounted
              for as effective accounting hedges were excluded.
        (2)   Intrinsic value of risk management contracts not designated as
              effective accounting hedges equals a loss of $47.6 million at
              December 31, 2007 ($5.3 million loss in 2006).

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

                                               December 31       December 31
                                                      2007              2006
        ---------------------------------------------------------------------
        Fair value, beginning of year            $     7.0         $    (0.2)
        Fair value, end of year                       (3.4)              7.0
        ---------------------------------------------------------------------
        Change in fair value of contracts
         in the year(3)                          $   (10.4)        $     7.2
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (3) In 2006 fair value amounts relating to risk management contracts
            that qualified for hedge accounting were not recorded on the
            Consolidated Balance Sheet.

        At December 31, 2007, the fair value of the contracts that were not
        designated as accounting hedges was a loss of $64.6 million. The
        Trust recorded a loss on risk management contracts of $41.8 million
        in the Statement of Income for the year ended 2007 ($24.7 million
        gain in 2006). This amount includes the realized and unrealized gains
        and losses on risk management contracts that do not qualify as
        effective accounting hedges.

        The fair values of all risk management contracts are determined using
        published price quotations in an active market through a valuation
        model. Significant inputs into this model include forward curves on
        commodity prices, interest rates and foreign exchange rates.

    12. GAIN (LOSS) ON FOREIGN EXCHANGE

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

                                                             2007       2006
        ---------------------------------------------------------------------
        Unrealized gain (loss) on US$ denominated debt  $    64.6  $    (7.1)
        Realized gain on US$ denominated debt
         repayments                                           5.0        2.6
        ---------------------------------------------------------------------
        Total non-cash gain (loss) on US$ denominated
         transactions                                        69.6       (4.5)
        Realized cash (loss) gain on US$ denominated
         transactions                                        (0.2)       0.3
        ---------------------------------------------------------------------
        Total foreign exchange gain (loss)              $    69.4  $    (4.2)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    13. 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. Currently, distributions
        paid to unitholders, other than returns of capital, are claimed as a
        deduction by the Trust in arriving at taxable income whereby tax is
        eliminated at the Trust level and is paid by the unitholders. As a
        result, the future tax position of the Trust, the parent entity, is
        now required to be reflected in the consolidated future income tax
        calculation. The Trust recorded a $24.7 million one time increase in
        earnings and a corresponding decrease to its future income tax
        liability as a result of timing differences within the Trust that had
        not been previously recognized.

        On October 30, 2007, the Finance Minister announced a reduction of
        the corporate income tax rate from 22.1 per cent to 15 percent by
        2012. The reductions will be phased in between 2008 and 2012.
        Legislation enacting the measures received Royal Assent on
        December 14, 2007. The reduction in the general corporate tax rate
        will also apply to the taxation of Income Trusts, reducing the
        combined federal and deemed Provincial tax rate for distributions to
        28 per cent in 2012.

        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:

                                                             2007       2006
        ---------------------------------------------------------------------
        Income before future income tax
         recovery                                       $   380.8  $   379.6
        Canadian statutory rate(1)                          34.3%      34.5%
        ---------------------------------------------------------------------
        Expected income tax expense at statutory rates      130.6      130.9
        Effect on income tax of:
          Net income of the Trust                          (163.6)    (138.0)
          Effect of change in corporate tax rate            (41.3)     (62.2)
          Initial recognition of Trust tax pools            (24.7)         -
          Unrealized (gain) loss on foreign exchange        (10.4)       1.2
          Change in estimated pool balances                  (7.0)     (10.0)
          Non-taxable portion of gains/losses                (2.1)         -
          Resource allowance                                    -      (10.7)
          Non-deductible crown charges                          -        1.2
          Other non-deductible items                         (2.8)       0.5
        ---------------------------------------------------------------------
        Future income tax recovery                      $  (121.3) $   (87.1)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

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


        The net future income tax liability comprises the following:

                                                             2007       2006
        ---------------------------------------------------------------------
        Future tax liabilities:
          Capital assets in excess of tax value         $   371.6  $   509.8
          Long-term debt                                     11.9        4.0
        Future tax assets:
          Asset retirement obligations                      (36.1)     (52.1)
          Risk management contracts                         (16.7)      (2.5)
          Accrued long-term incentive compensation           (7.8)      (7.7)
          Non-capital losses                                 (3.8)      (5.3)
          Attributed Canadian royalty income                 (4.6)     (10.4)
          Cumulative eligible capital and deductible
           share issue costs                                 (1.6)      (1.6)
          Other comprehensive loss                           (0.7)         -
        ---------------------------------------------------------------------
        Net future income tax liability                 $   312.2  $   434.2
        ---------------------------------------------------------------------
        Current portion of net future income tax
          liability                                     $    (4.0) $       -
        Long-term portion of net future income tax
          liability                                     $   316.2  $   434.2
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        The petroleum and natural gas properties and facilities owned by the
        Trust have an approximate tax basis of $1.84 billion
        ($1.58 billion in 2006) available for future use as deductions from
        taxable income. Included in this tax basis are estimated non-capital
        loss carry forwards of $13.8 million ($18.2 million in 2006) that
        expire in the years 2010 through 2026. The following is a summary of
        the estimated Trust's tax pools:

        The 2006 comparative tax pools have been restated to include the tax
        pools of the Trust and of the Trust's subsidiaries. The 2006 tax
        pools disclosed in the prior year for the Trust's subsidiaries were
        $1.03 billion. In addition, the Trust itself had an approximate tax
        basis of $545.1 million as at December 31, 2006.

                                                             2007       2006
        ---------------------------------------------------------------------
        Canadian oil and gas property expenses          $   816.5  $   734.0
        Canadian development expenses                       326.1      285.9
        Canadian exploration expenses                        52.5       27.7
        Undepreciated capital cost                          460.2      389.0
        Non-capital losses                                   13.8       18.2
        Provincial tax pools                                161.1      104.5
        Other                                                10.3       16.8
        ---------------------------------------------------------------------
        Estimated tax basis                             $ 1,840.5  $ 1,576.1
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        No current income taxes were paid or payable in both 2007 and 2006.

        14. EXCHANGEABLE SHARES

        The ARC Resources exchangeable shares ("ARL Exchangeable Shares")
        were issued on January 31, 2001 at $11.36 per exchangeable share as
        partial consideration for the Startech Energy Inc. acquisition. The
        issue price of the exchangeable shares was determined based on the
        weighted average trading price of Trust units preceding the date of
        announcement of the acquisition. The ARL Exchangeable Shares had an
        exchange ratio of 1:1 at the time of issuance.

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

        ARL EXCHANGEABLE SHARES (thousands)                  2007       2006
        ---------------------------------------------------------------------
        Balance, beginning of year                          1,433      1,595
        Exchanged for Trust units                            (123)      (162)
        ---------------------------------------------------------------------
        Balance, end of year                                1,310      1,433
        Exchange ratio, end of year                       2.24976    2.01251
        ---------------------------------------------------------------------
        Trust units issuable upon conversion, end of year   2,947      2,884
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        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 2007 and
        2006:

                                                             2007       2006
        ---------------------------------------------------------------------
        Non-controlling interest, beginning of year     $    40.0  $    37.5
        Reduction of book value for conversion to
         Trust units                                         (3.7)      (4.1)
        Current year net income attributable to
         non-controlling interest                             6.8        6.6
        ---------------------------------------------------------------------
        Non-controlling interest, end of year           $    43.1  $    40.0
        ---------------------------------------------------------------------
        Accumulated earnings attributable to
         non-controlling interest                       $    34.1  $    27.3
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    15. UNITHOLDERS' CAPITAL

        The Trust is authorized to issue 650 million Trust units of which
        210.2 million units were issued and outstanding as at December 31,
        2007 (204.3 million as at December 31, 2006).

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

        The Trust is an open ended mutual fund under which unitholders have
        the right to request redemption directly from the Trust. Trust units
        tendered by holders are subject to redemption under certain terms and
        conditions including the determination of the redemption price at the
        lower of the closing market price on the date units are tendered or
        90 per cent of the weighted average trading price for the 10 day
        trading period commencing on the tender date. Cash payments for 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.

                                          2007                  2006
        ---------------------------------------------------------------------
                                  Number of             Number of
                                      Trust                 Trust
                                      Units                 Units
                                 (thousands)         $ (thousands)         $
        ---------------------------------------------------------------------
        Balance, beginning of
         year                       204,289    2,349.2    199,104    2,230.8
        Issued for cash                   -          -          1          -
        Issued on conversion of
         ARL exchangeable shares
         (Note 14)                      261        3.7        310        4.1
        Issued on exercise of
         employee rights (Note 18)      131        2.1        978       18.4
        Distribution reinvestment
         program                      5,551      110.7      3,896       96.1
        Trust unit issue costs            -          -          -       (0.2)
        ---------------------------------------------------------------------
        Balance, end of year        210,232    2,465.7    204,289    2,349.2
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

    16. DEFICIT AND ACCUMULATED OTHER COMPREHENSIVE LOSS

        The deficit balance is composed of the following items:

                                                  2007                  2006
        ---------------------------------------------------------------------
        Accumulated earnings                 $ 2,191.1             $ 1,695.8
        Accumulated distributions             (2,657.0)             (2,159.0)
        ---------------------------------------------------------------------
        Deficit                              $  (465.9)            $  (463.2)

        Accumulated other comprehensive loss      (2.9)                    -
        ---------------------------------------------------------------------
        Deficit and accumulated other
         comprehensive loss                  $  (468.8)            $  (463.2)
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

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

                                                  2007                  2006
        ---------------------------------------------------------------------
        Unrealized losses on financial
         instruments designated as cash
         flow hedges                         $    (2.8)                    -
        Net unrealized losses on available-
         for-sale reclamation funds'
         investments                              (0.1)                    -
        ---------------------------------------------------------------------
        Accumulated other comprehensive
         loss, end of year                   $    (2.9)             $      -
        ---------------------------------------------------------------------

    17. RECONCILIATION OF CASH FLOW FROM OPERATING ACTIVITIES AND
        DISTRIBUTIONS

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

                                     Three months ended   Twelve months ended
                                         December 31           December 31
                                       2007       2006       2007       2006
        ---------------------------------------------------------------------
        Cash flow from operating
         activities               $   173.7  $   159.3  $   704.9  $   734.0
        Deduct:
          Cash withheld to fund
           current period capital
           expenditures               (44.5)     (33.6)    (193.4)    (236.7)
          Reclamation fund
           contributions and
           interest earned on fund
           balances                   (3.4)      (3.4)     (13.5)     (13.1)
        ---------------------------------------------------------------------
        Distributions(1)              125.8      122.3      498.0      484.2
        Accumulated distributions,
         beginning of period        2,531.2    2,036.7    2,159.0    1,674.8
        ---------------------------------------------------------------------
        Accumulated distributions,
         end of period            $ 2,657.0  $ 2,159.0  $ 2,657.0  $ 2,159.0
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------
        Distributions per unit(2) $    0.60  $    0.60  $    2.40  $    2.40
        Accumulated distributions
         per unit, beginning of
         period                   $   20.43  $   18.03  $   18.63  $   16.23
        ---------------------------------------------------------------------
        Accumulated distributions
         per unit, end of
         period(3)                $   21.03  $   18.63  $   21.03  $   18.63
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (1)   Distributions include non-cash amounts of $27 million and
              $110 million for the three and twelve months ended December 31,
              2007, respectively ($26 million and $94 million for the same
              periods in 2006, respectively) relating to the distribution
              reinvestment program.
        (2)   Distributions per trust unit reflect the sum of the per trust
              unit amounts declared monthly to unitholders.
        (3)   Accumulated distributions per unit reflect the sum of the per
              trust unit amounts declared monthly to unitholders since the
              inception of the Trust in July 1996.

    18. TRUST UNIT INCENTIVE RIGHTS PLAN

        The Trust Unit Incentive Rights Plan (the "Rights Plan") was
        established in 1999 and authorized the Trust to grant up to 8,000,000
        rights to its employees, independent directors and long-term
        consultants to purchase Trust units, of which 7,866,088 were granted
        to December 31, 2007. The initial exercise price of rights granted
        under the Rights Plan could not be less than the market price of the
        Trust units as at the date of grant and the maximum term of each
        right was not to exceed ten years. In general, the rights have a five
        year term and vest equally over three years commencing on the first
        anniversary date of the grant. In addition, the exercise price of the
        rights is to be adjusted downwards from time to time by the amount,
        if any, that distributions to unitholders in any calendar quarter
        exceeds 2.5 per cent (ten per cent annually) of the Trust's net book
        value of property, plant and equipment (the "Excess Distribution"),
        as determined by the Trust.

        During 2007, 2006 and 2005, the Trust did not grant any rights as the
        Rights Plan was replaced with a Whole Unit Plan during 2004 (see Note
        19). The existing Rights Plan will be in place until the remaining
        0.2 million rights outstanding as at December 31, 2007 are exercised
        or cancelled.

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

                                          2007                  2006
        ---------------------------------------------------------------------
                                              Weighted              Weighted
                                     Number    Average      Number   Average
                                  of Rights   Exercise   of Rights  Exercise
                                 (thousands)  Price ($) (thousands) Price ($)
        ---------------------------------------------------------------------
        Balance, beginning of year      369       9.47       1,349     10.22
        Exercised                      (131)     10.77        (978)    12.19
        Cancelled                         -          -          (2)    10.07
        ---------------------------------------------------------------------
        Balance before reduction
         of exercise price              238       9.41         369     10.40
        Reduction of exercise
         price(1)                         -      (0.91)          -     (0.93)
        ---------------------------------------------------------------------
        Balance, end of year            238       8.50         369      9.47
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (1) The holder of the right has the option to exercise rights held
            at the original grant price or a reduced exercise price.

        All rights outstanding are exercisable and have a remaining
        contractual life of 0.4 years.

        The Trust recorded a nominal amount of compensation expense for the
        year ($2.5 million in 2006) for the cost associated with the rights.
        Of the 3,013,569 rights issued on or after January 1, 2003 that were
        subject to recording compensation expense, 357,999 rights have been
        cancelled and 2,419,239 rights have been exercised to December 31,
        2007.

        The following table reconciles the movement in the contributed
        surplus balance for 2007 and 2006:

        ---------------------------------------------------------------------
                                                  2007                  2006
        ---------------------------------------------------------------------
        Balance, beginning of year           $     2.4             $     6.4
        Compensation expense                         -                   2.5
        Net benefit on rights exercised(1)        (0.7)                 (6.5)
        ---------------------------------------------------------------------
        Balance, end of year                 $     1.7             $     2.4
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

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

    19. WHOLE TRUST UNIT INCENTIVE PLAN

        In March 2004, the Board of Directors, upon recommendation of the
        Compensation Committee, approved a new Whole Trust Unit Incentive
        Plan (the "Whole Unit Plan") to replace the existing Trust Unit
        Incentive Rights Plan for new awards granted subsequent to March 31,
        2004. The new Whole Unit Plan will result 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
        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 notional accrued
        distributions. The cash compensation issued upon vesting of the PTUs
        is dependent upon the future performance of the Trust compared to its
        peers based on a performance multiplier. The performance multiplier
        is based on the percentile rank of the Trust's Total Unitholder
        Return. The cash compensation issued upon vesting of the PTUs may
        range from zero to two times the value of the PTUs originally
        granted.

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

        The Trust recorded non-cash compensation expense of $3.2 million and
        $0.3 million to general and administrative and operating expenses,
        respectively, and capitalized $0.7 million to property, plant and
        equipment in the twelve months ended December 31, 2007 for the
        estimated cost of the plan ($8.2 million, $1.1 million, and
        $1.8 million for the twelve months ended December 31, 2006). The non-
        cash compensation expense was based on the December 31, 2007 unit
        price of $20.40 ($22.30 in 2006), accrued distributions, a weighted
        average performance multiplier of 1.7 (2.0 in 2006), and the number
        of units to be issued on maturity.

        The following table summarizes the RTU and PTU movement for the
        twelve months ended December 31, 2007 and 2006:

                                     2007                      2006
        ---------------------------------------------------------------------
                            Number of    Number of    Number of    Number of
                                 RTUs         PTUs         RTUs         PTUs
                           (thousands)  (thousands)  (thousands)  (thousands)
        ---------------------------------------------------------------------
        Balance, beginning
         of year                  648          683          479          391
        Vested                   (286)        (110)        (180)           -
        Granted                   422          362          373          303
        Forfeited                 (38)         (32)         (24)         (11)
        ---------------------------------------------------------------------
        Balance, end of year      746          903          648          683
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

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

                                                             2007       2006
        ---------------------------------------------------------------------
        Balance, beginning of year                      $    26.1  $    15.0
        Change in liabilities in the year
          General and administrative expense                  3.2        8.2
          Operating expense                                   0.3        1.1
          Property, plant and equipment                       0.7        1.8
        ---------------------------------------------------------------------
        Balance, end of year                            $    30.3  $    26.1
        ---------------------------------------------------------------------
        Current portion of liability (Note 8)                18.2       11.5
        ---------------------------------------------------------------------
        Long-term liability                             $    12.1  $    14.6
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        During the year $12.7 million in cash payments were made to employees
        relating to the Whole Unit Plan ($5.2 million in 2006).

    20. BASIC AND DILUTED PER TRUST UNIT CALCULATIONS

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

                                     Three months ended   Twelve months ended
                                         December 31           December 31
                                       2007       2006       2007       2006
        ---------------------------------------------------------------------
        Weighted average trust
         units(1)                   209,520    203,580    207,287    201,554
        Trust units issuable on
         conversion of exchangeable
         shares(2)                    2,947      2,884      2,947      2,884
        Dilutive impact of
         rights(3)                      135        323        174        711
        ---------------------------------------------------------------------
        Dilutive trust units and
         exchangeable shares        212,602    206,787    210,408    205,149
        ---------------------------------------------------------------------
        ---------------------------------------------------------------------

        (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 period end exchange
              ratio.
        (3)   All outstanding rights were dilutive and therefore have been
              included in the diluted unit calculation for both 2007 and
              2006.

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

    21. COMMITMENTS AND CONTINGENCIES

        Following is a summary of the Trust's contractual obligations and
        commitments as at December 31, 2007:

    -------------------------------------------------------------------------
                                    Payments Due by Period ($millions)
    -------------------------------------------------------------------------
                             2008  2009-2010  2011-2012  Thereafter    Total
    Debt repayments(1)        5.9      540.8       51.5       116.3    714.5
    Interest payments(2)     11.0       20.2       15.5        13.7     60.4
    Reclamation fund
     contributions(3)         5.8       10.2        8.9        71.9     96.8
    Purchase commitments     10.1        4.1        4.0         6.0     24.2
    Operating leases(4)       6.2        8.9       12.4        88.1    115.6
    Risk management
     contract premiums(5)    13.2        2.3          -           -     15.5
    -------------------------------------------------------------------------
    Total contractual
     obligations             52.2      586.5       92.3       296.0  1,027.0
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    (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 acquired in 2005.
    (4)    Includes an available option expiring February 2008 to reduce a
           portion of office lease commitments.
    (5)    Fixed premiums to be paid in future periods on certain risk
           management contracts.

        The above noted risk management contract premiums are part of the
        Trust's commitments related to its risk management program. In
        addition to the above premiums, the Trust has commitments related to
        its risk management program (see Note 11). As the premiums are part
        of the underlying risk management contract, they have been recorded
        at fair market value at December 31, 2007 on the balance sheet as
        part of risk management contracts.

        The Trust enters into commitments for capital expenditures in advance
        of the expenditures being made. At a given point in time, it is
        estimated that the Trust has committed to capital expenditures equal
        to approximately one quarter of its capital budget by means of giving
        the necessary authorizations to incur the capital in a future period.
        The Trust's 2008 capital budget has been approved by the Board at
        $395 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 Trust is involved in litigation and claims arising in the normal
        course of operations. Management is of the opinion that pending
        litigation will not have a material adverse impact on the Trust's
        financial position or results of operations and therefore the
        following table does not include any commitments for outstanding
        litigation and claims.

        The Trust has certain sales contracts with aggregators whereby the
        price received by the Trust is dependent upon the contracts entered
        into by the aggregator. This commitment has not been disclosed in the
        commitment table as it is of a routine nature and is part of normal
        course of operations.
    

    ARC Energy Trust is one of Canada's largest conventional oil and gas
royalty trusts with an enterprise value of approximately $5.7 billion. The
Trust expects full year 2008 oil and gas production to average approximately
63,000 barrels of oil equivalent per day from six core areas in western
Canada. ARC Energy Trust trades on the TSX under the symbol AET.UN and its
exchangeable shares trade under the symbol ARX.

    ADVISORY - In the interests of providing ARC unitholders and potential
investors with information regarding ARC, including management's assessment of
ARC's future plans and operations, certain information contained in this
document are forward-looking statements within the meaning of the "safe
harbour" provisions of the United States Private Securities Litigation Reform
Act of 1995 and the Ontario Securities Commission. Forward-looking statements
in this document include, but are not limited to, ARC's internal projections,
expectations or beliefs concerning future operating results, and various
components thereof; the production and growth potential of its various assets,
estimated total production and production growth for 2008 and beyond; the
sources, deployment and allocation of expected capital in 2008; and the
success of future development drilling prospects. Readers are cautioned not to
place undue reliance on forward-looking statements, as there can be no
assurance that the plans, intentions or expectations upon which they are based
will occur. By their nature, forward-looking statements involve numerous
assumptions, known and unknown risks and uncertainties, both general and
specific, that contribute to the possibility that the predictions, forecasts,
projections and other forward-looking statements will not occur, which may
cause ARC's actual performance and financial results in future periods to
differ materially from any estimates or projections of future performance or
results expressed or implied by such forward-looking statements.

    ARC RE

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

For further information:

For further information: about ARC Energy Trust, please visit our
website www.arcresources.com or contact: Investor Relations, E-mail:
ir@arcresources.com, Telephone: (403) 503-8600, Fax: (403) 509-6417, Toll Free
1-888-272-4900, Suite 2100, 440 - 2nd Avenue S.W., Calgary, AB, T2P 5E9


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