News Releases

Advantage Announces Release of Fourth Quarter and Year Ended December 31, 2007 Financial Results and Reserves

Mar 7, 2008


    (TSX: AVN.UN, NYSE: AAV)

    CALGARY, March 6 /CNW/ - Advantage Energy Income Fund ("Advantage" or the
"Fund") is pleased to announce the financial and operating results and
reserves for the year ended December 31, 2007.
    A conference call will be held on Friday, March 7, 2008 at 9:00 a.m. MST
(11:00 a.m. EST). The conference call can be accessed toll-free at
1-866-334-4934 and a slide presentation is available on our website. A replay
of the call will be available from approximately 2:00 p.m. EST on March 7,
2008 until approximately midnight, April 5, 2008 and can be accessed by
dialing toll free 1-866-245-6755. The passcode required for playback is
645732. A live web cast of the conference call will be accessible via the
Internet on Advantage's website at www.advantageincome.com.Acquisition of Sound Energy Trust

    -   Advantage completed a highly synergistic and accretive acquisition of
        Sound Energy Trust which closed on September 5, 2007.

    -   The acquisition added proven plus probable reserves of 31.4 million
        boe at a cost of $14.77 per boe.

    -   In addition, the acquisition significantly increased Advantage's
        undeveloped land base, tax pools, and exposure to light oil. The
        acquisition provides a significant number of low risk drilling
        locations, facilities consolidation opportunities and 83 sections of
        land at Glacier in Northwest Alberta with potential for natural gas
        resource play development in the Montney formation.

    Successful 2007 Drilling Program and Efficient Reserves Additions

    -   Overall, the Fund replaced 379% of annual production at a Finding,
        Development & Acquisition cost of $15.19 per proven plus probable
        boe, excluding changes in future development capital, and $15.90 per
        proven plus probable boe, including changes in future development
        capital.

    -   Drill bit reserve additions resulted in strong Finding & Development
        ("F&D") costs of $16.96 per proven plus probable boe, excluding
        changes in future development capital. The three year F&D average is
        $15.91 per proven plus probable boe, excluding changes in future
        development capital. The Fund replaced 80% of its production through
        the drill bit.

    -   Strong operational execution throughout the year resulted in the
        drilling of 112 gross (64.8 net) wells in 2007 at a 99% success rate.
        During the fourth quarter of 2007 a total of 32 gross (16.6 net)
        wells were drilled at a 100% success rate.

    -   With the inclusion of Sound's assets and opportunities, Advantage's
        drilling inventory grew to over 750 locations representing over
        5 years of drilling within our land base.

    -   The Fund's proven plus probable reserve life index remains among the
        highest in the natural gas weighted sector at 12.1 years.

    -   The Fund's Net Asset Value, before tax increased to $12.96 per unit
        at a 10% discount factor.

    Commodity Prices

    -   Crude oil prices strengthened in 2007 due to continued global demand
        growth which was partly offset by the rising Canadian dollar.

    -   Declining natural gas prices, the rising Canadian dollar and
        increased service costs were key factors leading to lower revenue and
        cash flow levels in the latter part of 2007 due to our natural gas
        production weighting. This was partly offset by our natural gas
        hedging program which generated gains of $16.5 million in the second
        half of 2007.

    -   The outlook for gas prices has since improved with colder weather in
        early 2008. Key factors that are contributing to a more optimistic
        view on prices for the remainder of 2008 include a 7 year low in
        natural gas drilling activity in Canada, projections for lower LNG
        deliveries into the U.S. in 2008 and higher demand for natural gas
        fired electrical generation.

    Hedging

    -   For 2008, we have secured approximately 51% of our net natural gas
        production at an average Canadian floor price of $7.43 per mcf
        (currently equivalent to NYMEX US$8.43 per mcf) and 38% of our oil
        production at an average floor price of Canadian $94.07 per bbl
        (currently equivalent to NYMEX WTI US$95.95 per bbl).

    -   The primary purpose of our hedging program is to i) reduce cash flow
        volatility and ii) ensure that our capital program is substantially
        funded out of cash flow.

    Federal Government Tax Fairness Proposal

    -   On October 31, 2006 the Canadian Federal Government announced its
        intention to impose a tax on income trusts beginning in 2011. This
        announcement has continued to create uncertainty among the Trust
        sector resulting in consolidation and a drive to consider alternate
        structures.

    -   Advantage remains in a very strong position given our considerable
        tax pool base of $1.7 billion which is available to shield future
        taxes for many years after 2011 and also provides the Fund with more
        options as alternatives to the Royalty Trust structure are
        considered.

    -   It is the Fund's intention to continue to be a cash distributing
        entity after 2010. We will continue to closely monitor industry
        dynamics and are considering a number of alternative structures in
        order to maximize after-tax value for Unitholders.

    Alberta's Royalty Program Changes

    -   On October 25, 2007, the Alberta Government issued a proposal to
        increase provincial royalties in 2009 on oil sands and conventional
        oil and natural gas production. Advantage's analysis indicates a
        minimal impact on the Fund due to the number of lower rate wells
        within our long life assets which will receive favorable treatment.

    Advantage is Well positioned for 2008

    -   The market was filled with uncertainty in 2007 including reduced
        access to capital resulting from the Federal Government's October
        2006 announcement and soft natural gas prices. Advantage responded in
        2007 by completing a highly accretive acquisition, protecting our
        cash flow through commodity price hedging and adjusting our
        distributions to reduce the payout ratio to position the Fund for
        growth opportunities in 2008 and beyond.

    -   With our cash flow stream protected through commodity price hedging
        in 2008 and the current distribution level, we expect to
        substantially fund our capital program out of cash flow and preserve
        flexibility for additional opportunities throughout the year.

    -   Our 2008 capital program includes a strong suite of attractive
        development drilling locations at Martin Creek, Nevis, Willesden
        Green, Chip Lake, Sunset, Southern Alberta and Southeast
        Saskatchewan. In addition, further delineation drilling is planned
        for our Montney formation natural gas resource property at Glacier in
        Northwest Alberta (located directly adjacent to the very successful
        Swan Lake Pool development).

    -   Our underlying strengths continue to place Advantage in an enviable
        position:

        -  Long-life asset base and stable production platform,
        -  High quality drilling inventory that exceeds 5 years,
        -  Superior technical and administrative team that is highly
           motivated to create Unitholder value,
        -  Considerable tax pool base, and
        -  Reduced payout ratio.

    First Quarter 2008 Drilling Highlights

    -   Execution of the 2008 winter drilling program is on schedule and
        costs are on-track.

    -   At Martin Creek in Northeast British Columbia a 10 well drilling
        program is nearing completion and results are anticipated to meet
        expectations.

    -   At Glacier in Northwest Alberta, 4 vertical delineation wells have
        been drilled into the Montney formation where completions and testing
        are underway with an additional well currently drilling. Advantage's
        83 section land block contains several existing Montney well
        penetrations and extensive 3-dimensional seismic coverage. Our plans
        for the balance of 2008 include additional vertical wells which will
        be required to assess the potential for future horizontal well
        development and production. This approach is similar to the
        development plan conducted at the adjacent Swan Lake and Tupper pool
        projects, where significant Montney development is occurring.

    -   At Nevis, Alberta horizontal drilling for light oil in the newer
        western development area has been 100% successful with initial
        production rates at or above expectations. A multi-year drilling
        inventory and enhanced oil recovery potential exists on this
        property.

    -   To date 53 gross (31.2 net) wells have been drilled in 2008 at a 97%
        success rate.

    -   The Fund has significant behind pipe volumes as a result of these
        activities which will be brought on-stream in the second quarter and
        throughout 2008.As a final remark, we wish to acknowledge the dedication and hard work
from all of our directors, employees and personnel who continued to strive for
success despite a year of commodity price and political uncertainty.
    We look forward to 2008 with much optimism and confidence in our Fund.Financial and Operating Highlights

    Year ended
     December 31,               2007      2006      2005      2004      2003

    Financial ($000 except
     per unit and per boe
     amounts)

    Revenue before
     royalties(1)            557,358   419,727   376,572   241,481   166,075
      per Trust Unit(2)         4.66      5.18      6.65      5.89      5.44
      per boe                  50.97     48.41     51.27     38.92     36.81
    Funds from operations    271,143   214,758   211,541   126,478    94,735
      per Trust Unit(3)         2.22      2.65      3.72      3.05      3.09
      per boe                  24.79     24.78     28.80     20.39     21.01
    Net income (loss)         (7,535)   49,814    75,072    24,038    38,503
      per Trust Unit(2)        (0.06)     0.62      1.33      0.59      1.26
    Distributions declared   215,194   217,246   177,366   117,655    83,382
    per Trust Unit(3)           1.77      2.66      3.12      2.82      2.71
    Expenditures on property
     and equipment           148,725   159,487   103,229   107,893    76,212
    Working capital
     deficit(4)               28,087    42,655    31,612    56,408    47,143
    Bank indebtedness        547,426   410,574   252,476   267,054   102,968
    Convertible debentures
     (face value)            224,612   180,730   135,111   148,450    99,984
    Trust Units outstanding
     at end of year          138,269   105,390    57,846    49,675    36,717
    Basic weighted average
     Trust Units             119,604    80,958    56,593    41,008    30,536

    Operating

    Daily Production
      Natural gas (mcf/d)    116,998    94,074    78,561    77,188    57,631
      Crude oil and NGLs
       (bbls/d)               10,462     8,075     7,029     4,084     2,756
      Total boe/d @ 6:1    29,962    23,754    20,123    16,949    12,361
    Average pricing
     (including hedging)
      Natural gas ($/mcf)       7.21      6.86      7.98      6.08      6.07
      Crude oil & NGLs
       ($/bbl)                 65.38     62.44     57.58     46.58     38.14
    Proved plus probable
     reserves(5)
      Natural gas (bcf)        546.4     442.7     286.9     296.9     237.4
      Crude oil & NGLs
       (mbbls)                61,131    47,524    36,267    34,316    13,697
      Total mboe             152,203   121,317    84,082    83,799    53,271
      Reserve life index
       (years)(6)               12.1      11.4      12.0       9.9       9.1


    (1) includes realized derivative gains and losses
    (2) based on basic weighted average Trust Units outstanding
    (3) based on Trust Units outstanding at each distribution record date
    (4) working capital deficit excludes derivative assets and liabilities
    (5) 2007, 2006, 2005 and 2004 represents company interest reserves with
        2003 being gross working interest reserves
    (6) based on Q4 production rates


                                   RESERVESAdvantage's year end reserve evaluation is based on an independent
engineering study conducted by Sproule Associates Limited ("Sproule")
effective December 31, 2007 and prepared in accordance with National
Instrument 51-101 ("NI 51-101").
    Reserves included herein are stated on a Company Interest basis (before
royalty burdens and including royalty interests receivable) unless noted
otherwise. This report contains several cautionary statements that are
specifically required by NI 51-101. In addition to the detailed information
disclosed in this press release more detailed information on a net interest
basis (after royalty burdens and including royalty interests) and on a gross
interest basis (before royalty burdens and excluding royalty interests) will
be included in Advantage's Annual Information Form ("AIF") and will be
available at www.advantageincome.com and www.sedar.com.Highlights - Company Interest Reserves (Working Interests plus Royalty
    Interests Receivable)

    -   The Fund's net asset value at December 31, 2007 is $12.96 per Unit,
        (using a 10% discount factor).

    -   Proved plus probable ("P+P") reserve life index remains among the
        highest in the gas weighted sector at 12.1 years.

    -   Replaced 379% of annual production at an all-in Finding, Development
        & Acquisition ("FD&A") cost of $15.19 per P+P boe before
        consideration of future development capital. Including future
        development capital, the FD&A cost was $15.90 per P+P boe. This
        includes the acquisition of Sound Energy Trust, which was effective
        September 5, 2007.

                                                   December 31,  December 31,
                                                       2007          2006
    -------------------------------------------------------------------------
    Proved plus probable reserves (mboe)               152,203       121,317
    Present Value of reserves discounted at 10%,
     proved plus probable ($000)                    $2,462,610    $1,850,073
    Net Asset Value per Unit discounted at 10%          $12.96        $12.29
    Reserve Life Index (proved plus probable -
     years)(1)                                            12.1          11.4
    Reserves per Unit (proved plus probable)(2)           1.10          1.15
    Bank debt per boe of reserves(3)                     $3.60         $3.38
    Convertible debentures per boe of reserves(3)        $1.48         $1.49

    (1) Based on Q4 average production.
    (2) Based on 138.3 million Units outstanding at December 31, 2007, and
        105.6 million Units outstanding as December 31, 2006.
    (3) BOE's may be misleading, particularly if used in isolation. In
        accordance with NI 51-101, a BOE conversion ratio for natural gas of
        6 Mcf: 1 bbl has been used which is based on an energy equivalency
        conversion method primarily applicable at the burner tip and does not
        represent a value equivalency at the wellhead.


    Company Interest Reserves - Summary as at December 31, 2007


                             Light &            Natural               Oil
                             Medium     Heavy     Gas     Natural    Equiv-
                              Oil        Oil    Liquids     Gas       alent
                             (mbbl)    (mbbl)    (mbbl)    (mmcf)    (mboe)
    -------------------------------------------------------------------------
    Proved

    Developed Producing       22,222     1,840     6,714   288,398    78,842
    Developed Non-producing      473       129       268    13,098     3,054
    Undeveloped                3,622       297       941    52,927    13,680
    Total Proved              26,317     2,266     7,923   354,423    95,576
    -------------------------------------------------------------------------
    Probable                  17,540     3,282     3,803   192,013    56,627
    Total Proved + Probable   43,857     5,548    11,726   546,436   152,203
    -------------------------------------------------------------------------


    Present Value of Future Net Revenue using Sproule price and cost
    forecasts before taxes(1) ($000)

                                        Before Income Taxes Discounted at
                                          0%            5%            10%
    -------------------------------------------------------------------------
    Proved
    Developed Producing              $ 2,680,441   $ 1,904,687   $ 1,526,798
    Developed Non-producing               83,654        67,773        56,479
    Undeveloped                          298,697       217,260       155,502
    Total Proved                       3,062,792     2,189,720     1,738,779
    -------------------------------------------------------------------------
    Probable                           2,038,534     1,100,986       723,831
    Total Proved + Probable          $ 5,101,326   $ 3,290,706   $ 2,462,610
    -------------------------------------------------------------------------

    Present Value of Future Net Revenue using Sproule price and cost
    forecasts after taxes(1) ($000)

                                         After Income Taxes Discounted at
                                          0%            5%            10%
    -------------------------------------------------------------------------
    Proved
    Developed Producing              $ 2,680,441   $ 1,904,687   $ 1,526,798
    Developed Non-producing               83,654        67,773        56,479
    Undeveloped                          298,697       217,260       155,502
    Total Proved                       3,062,792     2,189,720     1,738,779
    -------------------------------------------------------------------------
    Probable                           1,725,276     1,009,487       691,310
    Total Proved + Probable          $ 4,788,068   $ 3,199,208   $ 2,430,090
    -------------------------------------------------------------------------

    (1) Advantage's crude oil, natural gas and natural gas liquid reserves
        were evaluated using Sproule's product price forecast effective
        December 31, 2007 prior to, interests, debt services charges and
        general and administrative expenses. It should not be assumed that
        the discounted future revenue estimated by Sproule represents the
        fair market value of the reserves.Sproule Price Forecasts

    The present value of future net revenue at December 31, 2007 was based
upon crude oil and natural gas pricing assumptions prepared by Sproule
effective December 31, 2007. These forecasts are adjusted for reserve quality,
transportation charges and the provision of any applicable sales contracts.
The price assumptions used over the next seven years are summarized in the
table below:Alberta
                                                 AECO-C    Henry Hub
                              WTI     Edmonton   Natural    Natural
                             Crude      Light      Gas       Gas    Exchange
                              Oil     Crude Oil  ($Cdn/    ($US/      Rate
    Year                   ($US/bbl) ($Cdn/bbl)   mmbtu)    mmbtu) ($US/$Cdn)
    -------------------------------------------------------------------------
    2008                       89.61     88.17      6.51      7.56      1.00
    2009                       86.01     84.54      7.22      8.27      1.00
    2010                       84.65     83.16      7.69      8.74      1.00
    2011                       82.77     81.26      7.70      8.75      1.00
    2012                       82.26     80.73      7.61      8.66      1.00
    2013                       82.81     81.25      7.78      8.83      1.00
    2014                       84.46     82.88      7.96      9.01      1.00Net Asset Value using Sproule price and cost forecasts

    The following net asset value ("NAV") table shows what is normally
referred to as a "produce-out" NAV calculation under which the current value
of the Fund's reserves would be produced at forecast future prices and costs.
The value is a snapshot in time and is based on various assumptions including
commodity prices and foreign exchange rates that vary over time.($000, except per Unit amounts)       0%            5%           10%
    -------------------------------------------------------------------------
    Net asset value per Unit before
     taxes(1) - December 31, 2006        $ 30.39       $ 17.92       $ 12.29
    -------------------------------------------------------------------------
    Present value proved and probable
     reserves                        $ 5,101,326   $ 3,290,706   $ 2,462,610
    Undeveloped acreage and
     seismic(2)                          111,559       111,559       111,559
    Working capital (deficit)             (9,634)       (9,634)       (9,634)
    Convertible debentures              (224,612)     (224,612)     (224,612)
    Bank debt                           (547,426)     (547,426)     (547,426)

    Net asset value - December 31,
     2007                            $ 4,431,213   $ 2,620,593   $ 1,792,497
    -------------------------------------------------------------------------
    Net asset value per Unit after
     taxes(1) - December 31, 2007    $     32.05   $     18.95   $     12.96
    -------------------------------------------------------------------------

    (1) Based on 138.3 million Units  outstanding at December 31, 2007, and
        105.6 million Units outstanding at December 31, 2006.
    (2) Internal estimate


    Gross Working Interest Reserves - Summary as at December 31, 2007

                             Light &            Natural               Oil
                             Medium     Heavy     Gas     Natural    Equiv-
                              Oil        Oil    Liquids     Gas       alent
                             (mbbl)    (mbbl)    (mbbl)    (mmcf)    (mboe)
    -------------------------------------------------------------------------
    Proved
    Developed Producing       22,060     1,814    6,646    285,551    78,111
    Developed Non-producing      473       126      266     12,814     3,001
    Undeveloped                3,621       297      928     52,568    13,608
    Total Proved              26,154     2,237    7,840    350,933    94,720
    -------------------------------------------------------------------------
    Probable                  17,477     3,271    3,773    190,613    56,289
    Total Proved + Probable   43,630     5,508   11,613    541,546   151,009
    -------------------------------------------------------------------------



    Gross Working Interest Reserves Reconciliation

                             Light &            Natural               Oil
                             Medium     Heavy     Gas     Natural    Equiv-
                              Oil        Oil    Liquids     Gas       alent
    Proved                   (mbbl)    (mbbl)    (mbbl)    (mmcf)    (mboe)
    -------------------------------------------------------------------------
    Opening balance
     Dec. 31, 2006            19,935     1,908     7,375   292,779    78,015
    Extensions                   327        55       232    14,694     3,062
    Improved recovery            678         0       197    14,716     3,328
    Discoveries                   24         0         9       636       139
    Economic factors             370         1      (105)     (572)      170
    Technical revisions          177      (562)      (95)   (2,710)     (930)
    Acquisitions               7,348     1,083     1,093    74,094    21,872
    Dispositions                   0         0         0         0         0
    Production                (2,705)     (248)     (866)  (42,704)  (10,936)
    -------------------------------------------------------------------------
    Closing balance at
     Dec. 31, 2007            26,154     2,237     7,840   350,933    94,720
    -------------------------------------------------------------------------

                             Light &            Natural               Oil
                             Medium     Heavy     Gas     Natural    Equiv-
                              Oil        Oil    Liquids     Gas       alent
    Proved + Probable        (mbbl)    (mbbl)    (mbbl)    (mmcf)    (mboe)
    -------------------------------------------------------------------------
    Opening balance
     Dec. 31, 2006            33,521     2,596    11,208   439,345   120,549
    Extensions                 1,667        68       519    30,191     7,285
    Improved recovery          1,322         0       546    44,193     9,234
    Discoveries                   41         0        11       795       184
    Economic factors             493         2      (133)    1,048       537
    Technical revisions       (1,271)     (674)   (1,110)  (32,510)   (8,472)
    Acquisitions              10,562     3,764     1,438   101,188    32,628
    Dispositions                   0         0         0         0         0
    Production                (2,705)     (248)     (866)  (42,704)  (10,936)
    -------------------------------------------------------------------------
    Closing balance at
     Dec. 31, 2007            43,630      5,508   11,613   541,546   151,009
    -------------------------------------------------------------------------

    Finding, Development & Acquisitions Costs ("FD&A")(1)

    FD&A Costs - Gross Working Interest Reserves excluding Future Development
    Capital

                                                  Proved   Proved + Probable
    -------------------------------------------------------------------------
    Capital expenditures ($000)                $ 148,725           $ 148,725
    Acquisitions net of dispositions ($000)      479,955             479,955
    -------------------------------------------------------------------------
    Total capital ($000)                       $ 628,680           $ 628,680
    -------------------------------------------------------------------------

    Total mboe, end of period
                                                  94,720             151,009
    Total mboe, beginning of period               78,015             120,549
    Production, mboe                              10,936              10,936
    -------------------------------------------------------------------------
    Reserve additions, mboe                       27,641              41,396
    -------------------------------------------------------------------------

    FD&A costs ($/boe)                         $   22.74           $   15.19

    Three year average FD&A Costs ($/boe)      $   27.51           $   19.20

    F&D costs ($/boe)                          $   25.78           $   16.96

    Three year average F&D costs ($/boe)       $   22.02           $   15.91


    NI 51-101
    FD&A Costs - Gross Working Interest Reserves including Future Development
    Capital

                                                  Proved   Proved + Probable
    -------------------------------------------------------------------------
    Capital expenditures ($000)                $ 148,725           $ 148,725
    Acquisitions net of dispositions ($000)      479,955             479,955
    Net change in Future Development Capital       6,517              29,517
    -------------------------------------------------------------------------
    Total capital ($000)                       $ 635,197           $ 658,197
    -------------------------------------------------------------------------
    Reserve additions, mboe                       27,641              41,396
    -------------------------------------------------------------------------

    FD&A costs ($/boe)                         $   22.98           $   15.90

    Three year average FD&A Costs ($/boe)      $   27.94           $   20.21

    F&D costs ($/boe)                          $   26.91           $   20.33

    Three year average F&D costs ($/boe)       $   23.21           $   19.68

    (1) Under NI 51-101, the methodology to be used to calculate FD&A costs
        includes incorporating changes in future development capital ("FDC")
        required to bring the proved undeveloped and probable reserves to
        production. For continuity, Advantage has presented herein FD&A costs
        calculated both excluding and including FDC.The aggregate of the exploration and development costs incurred in the
most recent financial year and the change during that year in estimated future
development costs generally will not reflect total finding and development
costs related to reserves additions for that year. Changes in forecast FDC
occur annually as a result of development activities, acquisition and
disposition activities and capital cost estimates that reflect Sproule's best
estimate of what it will cost to bring the proved undeveloped and probable
reserves on production.
    In all cases, the FD&A number is calculated by dividing the identified
capital expenditures by the applicable reserve additions. Boes may be
misleading, particularly if used in isolation. A boe conversion ratio of 6
MCF:1 BBL is based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value equivalency at the
wellhead.Land Inventory at December 31, 2007

                                         Developed Acres   Undeveloped Acres
                                         Gross       Net     Gross       Net
    -------------------------------------------------------------------------
    Alberta                          1,238,745   647,934   789,914   429,360
    British Columbia                   159,486    73,877   109,807    64,153
    Saskatchewan                        50,660    38,312   226,301   192,071
    -------------------------------------------------------------------------
    Total Acreage                    1,448,891   760,123 1,126,022   685,584
    -------------------------------------------------------------------------


                     MANAGEMENT'S DISCUSSION & ANALYSISThe following Management's Discussion and Analysis ("MD&A"), dated as of
March 5, 2008, provides a detailed explanation of the financial and operating
results of Advantage Energy Income Fund ("Advantage", the "Fund", "us", "we"
or "our") for the quarter and year ended December 31, 2007 and should be read
in conjunction with the audited consolidated financial statements. The
consolidated financial statements have been prepared in accordance with
Canadian generally accepted accounting principles ("GAAP") and all references
are to Canadian dollars unless otherwise indicated. All per barrel of oil
equivalent ("boe") amounts are stated at a conversion rate of six thousand
cubic feet of natural gas being equal to one barrel of oil or liquids.

    Non-GAAP Measures

    The Fund discloses several financial measures in the MD&A that do not
have any standardized meaning prescribed under GAAP. These financial measures
include funds from operations, funds from operations per Trust Unit and cash
netbacks. Management believes that these financial measures are useful
supplemental information to analyze operating performance, leverage and
provide an indication of the results generated by the Fund's principal
business activities prior to the consideration of how those activities are
financed or how the results are taxed. Investors should be cautioned that
these measures should not be construed as an alternative to net income, cash
provided by operating activities or other measures of financial performance as
determined in accordance with GAAP. Advantage's method of calculating these
measures may differ from other companies, and accordingly, they may not be
comparable to similar measures used by other companies.
    Funds from operations, as presented, is based on cash provided by
operating activities before expenditures on asset retirement and changes in
non-cash working capital. Funds from operations per Trust Unit is based on the
number of Trust Units outstanding at each distribution record date. Cash
netbacks are dependent on the determination of funds from operations and
include the primary cash revenues and expenses on a per boe basis that
comprise funds from operations. Funds from operations reconciled to cash
provided by operating activities is as follows:Three months ended              Year ended
                           December 31                 December 31
    ($000)                 2007      2006 %change      2007      2006 %change
    -------------------------------------------------------------------------
    Cash provided
     by operating
     activities       $  83,366  $ 65,495    27%  $ 249,132 $ 229,087     9%
    Expenditures on
     asset retirement     2,116     3,462  (39)%      6,951     5,974    16%
    Changes in non-
     cash working
     capital             (4,963)   (6,220) (20)%     15,060   (20,303)(174)%
    -------------------------------------------------------------------------
    Funds from
     operations       $  80,519  $ 62,737    28%  $ 271,143 $ 214,758    26%
    -------------------------------------------------------------------------Forward-Looking Information

    The information in this report contains certain forward-looking
statements. These statements relate to future events or our future
performance. All statements other than statements of historical fact may be
forward-looking statements. Forward-looking statements are often, but not
always, identified by the use of words such as "seek", "anticipate", "plan",
"continue", "estimate", "expect", "may", "will", "project", "predict",
"potential", "targeting", "intend", "could", "might", "should", "believe",
"would" and similar expressions. These statements involve substantial known
and unknown risks and uncertainties, certain of which are beyond Advantage's
control, including: the impact of general economic conditions; industry
conditions; changes in laws and regulations including the adoption of new
environmental laws and regulations and changes in how they are interpreted and
enforced; fluctuations in commodity prices and foreign exchange and interest
rates; stock market volatility and market valuations; volatility in market
prices for oil and natural gas; liabilities inherent in oil and natural gas
operations; uncertainties associated with estimating oil and natural gas
reserves; competition for, among other things, capital, acquisitions of
reserves, undeveloped lands and skilled personnel; incorrect assessments of
the value of acquisitions; changes in income tax laws or changes in tax laws,
royalty regimes and incentive programs relating to the oil and gas industry
and income trusts; geological, technical, drilling and processing problems and
other difficulties in producing petroleum reserves; obtaining required
approvals of regulatory authorities and other risk factors set forth in
Advantage's Annual Information Form which is available at
www.advantageincome.com or www.sedar.com. Advantage's actual results,
performance or achievement could differ materially from those expressed in, or
implied by, such forward-looking statements and, accordingly, no assurances
can be given that any of the events anticipated by the forward-looking
statements will transpire or occur or, if any of them do, what benefits that
Advantage will derive from them. Except as required by law, Advantage
undertakes no obligation to publicly update or revise any forward-looking
statements.

    Acquisition of Sound Energy Trust

    On September 5, 2007, the previously announced acquisition of Sound
Energy Trust ("Sound") was completed. The financial and operational
information for the quarter and year ended December 31, 2007 reflects
operations from the Sound properties effective from the closing date,
September 5, 2007.
    The acquisition was accomplished through a Plan of Arrangement (the
"Arrangement") by the exchange of each Sound Trust Unit for 0.30 of an
Advantage Trust Unit or, at the election of the holder of Sound Trust Units,
$0.66 in cash and 0.2557 of an Advantage Trust Unit. In addition, all Sound
Exchangeable Shares were exchanged for Advantage Trust Units on the same ratio
based on the conversion ratio in effect at the effective date of the
Arrangement. Advantage issued 16,977,184 Trust Units and paid $21.4 million
cash as consideration to acquire Sound. The transaction is accretive to
Advantage's Unitholders on a production, cash flow, reserves and net asset
value basis and has significantly increased Advantage's tax pool position to a
total of approximately $1.7 billion, and Safe Harbour expansion room to
approximately $2.0 billion. Sound's higher oil weighting, synergy with many of
Advantage's core properties and significant undeveloped land holdings of
approximately 400,000 net undeveloped acres will further enhance the operating
platform of Advantage.Overview
                        Three months ended              Year ended
                           December 31                 December 31
    ($000)                 2007      2006 %change      2007      2006 %change
    -------------------------------------------------------------------------
    Cash provided
     by operating
     activities
     ($000)            $ 83,366  $ 65,495    27%  $ 249,132 $ 229,087     9%
    Funds from
     operations
     ($000)            $ 80,519  $ 62,737    28%  $ 271,143 $ 214,758    26%
      per Trust
       Unit(1)         $   0.58  $   0.59   (2)%  $    2.22 $    2.63  (16)%
    Net income
     (loss) ($000)     $ 13,795  $  8,736    58%  $  (7,535)$  49,814 (115)%
      per Trust Unit
       - Basic         $   0.10  $   0.08    25%  $   (0.06)$    0.62 (110)%
       - Diluted       $   0.10  $   0.08    25%  $   (0.06)$    0.61 (110)%

    (1) Based on Trust Units outstanding at each distribution record date.Cash provided by operating activities increased 27%, funds from
operations increased 28%, and funds from operations per Trust Unit modestly
decreased 2% for the three months ended December 31, 2007, as compared to the
same period of 2006. For the year ended December 31, 2007, cash provided by
operating activities increased 9%, funds from operations increased 26%, and
funds from operations per Trust Unit decreased 16%. Cash provided by operating
activities and funds from operations for the quarter and year were positively
impacted by increased revenues due to additional production from the Sound
acquisition and the year was further impacted by a full year of production
from the Ketch acquisition that closed in 2006. Funds from operations per
Trust Unit decreased during the periods due to a higher average number of
Trust Units outstanding. The weighted average number of Trust Units has
increased 32% for the three months and 48% for the year ended in 2007 compared
to 2006, mainly due to the Sound acquisition, the Trust Unit financing in the
first quarter of 2007 and the distribution reinvestment plan. When compared to
the third quarter of 2007, funds from operations increased 29% due to
production increases of 17% from the acquisition of Sound and stronger
commodity prices. Natural gas prices, excluding hedging, increased 11% and
crude oil and NGL prices, excluding hedging, increased 6% for the fourth
quarter of 2007 as compared to the prior quarter. The Fund also realized net
derivative gains of $5.2 million in the three months and $18.6 million for the
year ended December 31, 2007 which also helped to strengthen cash provided by
operating activities and funds from operations.
    Net income for the quarter increased 58% over prior year due to higher
crude oil prices and higher production from the Sound acquisition, offset
somewhat by higher costs from the acquisition and general growth of the Fund.
Net income for the year decreased to a net loss for the twelve months ended
December 31, 2007 primarily due to higher operating costs, as well as non-cash
expenses such as amortization of the management contract internalization and
higher depletion and depreciation expense. The primary factor that causes
significant variability of Advantage's cash provided by operating activities,
funds from operations, and net income is commodity prices. Refer to the
section "Commodity Prices and Marketing" for a more detailed discussion of
commodity prices and our price risk management.Distributions
                        Three months ended              Year ended
                           December 31                 December 31
    ($000)                 2007      2006 %change      2007      2006 %change
    -------------------------------------------------------------------------
    Distributions
     declared ($000)   $ 57,875  $ 58,791   (2)%  $ 215,194 $ 217,246   (1)%
      per Trust
       Unit (1)        $   0.42  $   0.56  (25)%  $    1.77 $    2.66  (33)%

    (1) Based on Trust Units outstanding at each distribution record date.Total distributions declared decreased 2% for the three months and 1% for
the year ended December 31, 2007 when compared to the same periods in 2006.
Total distributions declared are slightly lower as a result of the decreases
in the distribution per Trust Unit in January and December 2007. The decreases
in per Trust Unit distributions are offset by additional distributions due to
the increased Trust Units outstanding from the continued growth and
development of the Fund. Since natural gas prices were very weak during the
2006/2007 winter season, we reduced the distribution level in January 2007 and
as natural gas prices continued to show prolonged weakness throughout 2007, we
decreased the distribution level further in December 2007 to more
appropriately reflect the current commodity price environment. Distributions
per Trust Unit were $0.42 for the three months and $1.77 for the year ended
December 31, 2007, representing a decrease of 25% and 33% from same periods in
2006. The monthly distribution is currently $0.12 per Trust Unit. To mitigate
the persisting risk associated with lower commodity prices and the resulting
negative impact on cash flows, the Fund implemented a hedging program with 51%
of natural gas production and 38% of crude oil production, net of royalties,
hedged for 2008. See "Commodity Price Risk" section for a more detailed
discussion of our price risk management.
    Distributions from the Fund to Unitholders are entirely discretionary and
are determined by Management and the Board of Directors. We closely monitor
our distribution policy considering forecasted cash flows, optimal debt
levels, capital spending activity, taxability to Unitholders, working capital
requirements, and other potential cash expenditures. Distributions are
announced monthly and are based on the cash available after retaining a
portion to meet such spending requirements. The level of distributions are
primarily determined by cash flows received from the production of oil and
natural gas from existing Canadian resource properties and will be susceptible
to the risks and uncertainties associated with the oil and natural gas
industry generally. If the oil and natural gas reserves associated with the
Canadian resource properties are not supplemented through additional
development or the acquisition of additional oil and natural gas properties,
our distributions will decline over time in a manner consistent with declining
production from typical oil and natural gas reserves. Therefore, distributions
are highly dependent upon our success in exploiting the current reserve base
and acquiring additional reserves. Furthermore, monthly distributions we pay
to Unitholders are highly dependent upon the prices received for such oil and
natural gas production. Oil and natural gas prices can fluctuate widely on a
month-to-month basis in response to a variety of factors that are beyond our
control. Declines in oil or natural gas prices will have an adverse effect
upon our operations, financial condition, reserves and ultimately on our
ability to pay distributions to Unitholders. The Fund attempts to mitigate the
volatility in commodity prices through our hedging program. It is our
long-term objective to provide stable and sustainable distributions to the
Unitholders, while continuing to grow the Fund. However, given that funds from
operations can vary significantly from month-to-month due to these factors,
the Fund may utilize various financing alternatives as an interim measure to
maintain stable distributions.
    For Canadian and U.S. holders of Advantage Trust Units, the distributions
paid for 2007 were 100% taxable. All Unitholders of the Fund are encouraged to
consult their tax advisors as to the proper treatment of Advantage
distributions for income tax purposes.Revenue

                    Three months ended              Year ended
                        December 31                 December 31
    ($000)             2007      2006   %change    2007      2006    %change
    -------------------------------------------------------------------------
    Natural gas
     excluding
     hedging         $ 73,662  $ 74,309   (1)%  $ 286,777  $ 231,548     24%
    Realized hedging
     gains              8,762     4,046   117%     20,933      4,164    403%
    -------------------------------------------------------------------------
    Natural gas
     including
     hedging         $ 82,424  $ 78,355     5%  $ 307,710  $ 235,712     31%
    -------------------------------------------------------------------------
    Crude oil and
     NGLs excluding
     hedging         $ 87,079  $ 48,051    81%  $ 251,987  $ 182,882     38%
    Realized
     hedging gains
     (losses)          (3,552)    1,133  (414)%    (2,339)     1,133   (306)%
    -------------------------------------------------------------------------
    Crude oil and
     NGLs including
     hedging         $ 83,527  $ 49,184    70%  $ 249,648  $ 184,015     36%
    -------------------------------------------------------------------------
    Total revenue    $165,951  $127,539    30%  $ 557,358  $ 419,727     33%
    -------------------------------------------------------------------------Natural gas revenues, excluding hedging, have decreased 1% for the three
months and increased 24% for the year ended December 31, 2007, compared to
2006. The decrease in natural gas revenues for the three months is mainly due
to a 10% decrease in natural gas prices, excluding hedging, offset by an
equivalent 10% increase in production, primarily from the Sound acquisition.
Conversely, the increase in natural gas revenues for the 2007 year is mainly
due to the inclusion of a full year of production from the Ketch merger that
closed in 2006 and production from the Sound acquisition since September 5,
2007, while natural gas prices remained fairly constant. Crude oil and NGL
revenues, excluding hedging, have increased by 81% for the three months and
38% for the year ended December 31, 2007, compared to 2006. Crude oil and NGL
revenue increased due to additional production from the Sound acquisition and
the inclusion of a full year of production from the Ketch merger combined with
an increase in crude oil and NGL prices of 34% for the three months and 6% for
the year ended December 31, 2007. For the three months and year ended
December 31, 2007, the Fund recognized natural gas and crude oil net hedging
gains of $5.2 million and $18.6 million primarily due to derivative contracts
in place that offset commodity prices fluctuations which can jeopardize
revenues and corresponding distributions.Production

                    Three months ended              Year ended
                        December 31                 December 31
                       2007      2006   %change    2007      2006    %change
    -------------------------------------------------------------------------
    Natural gas
     (mcf/d)          128,556   117,134    10%    116,998     94,074     24%
    Crude oil
     (bbls/d)          10,410     7,148    46%      8,090      6,273     29%
    NGLs (bbls/d)       2,485     2,422     3%      2,372      1,802     32%
    -------------------------------------------------------------------------
    Total (boe/d)      34,321    29,092    18%     29,962     23,754     26%
    -------------------------------------------------------------------------
    Natural gas (%)       63%       67%               65%        66%
    Crude oil (%)         30%       25%               27%        26%
    NGLs (%)               7%        8%                8%         8%The Fund's total daily production averaged 34,321 boe/d for the three
months and 29,962 boe/d for the year ended December 31, 2007, an increase of
18% and 26%, respectively, compared with the same periods of 2006. Natural gas
production increased 10%, crude oil production increased 46%, and NGLs
production increased 3% for the fourth quarter of 2007. For the year ended
December 31, 2007, natural gas production increased 24%, crude oil production
increased 29%, and NGLs production increased 32%. Production for the quarter
increased due to the additional properties from the Sound acquisition. The
increase in production for the year ended December 31, 2007 has been primarily
attributed to a full year of production from the Ketch acquisition which
closed June 23, 2006 and production from the Sound acquisition which closed
September 5, 2007. Production for the fourth quarter increased 17% from the
third quarter of 2007 also due to a full quarter of production from the
acquisition of Sound.
    Our successful first quarter 2007 drilling program at Martin Creek,
followed by continued success at Sunset, Nevis, Willesden Green, as well as
other areas in Southern Alberta and Saskatchewan throughout the year has
helped offset natural declines. In addition, our flattening production
platform, resulting from our continued focus on long life assets, is
contributing to a stable operating foundation. For 2008 we expect production
to average approximately 32,000 to 34,000 boe/d, weighted 62% to natural gas.
Approximately 55% of our capital spending will be directed to natural gas and
45% toward light oil projects which will enable us to increase our crude oil
production and capitalize on the stronger crude oil pricing environment.Commodity Prices and Marketing

    Natural Gas

                    Three months ended              Year ended
                        December 31                 December 31
    ($/mcf)            2007      2006   %change    2007      2006    %change
    -------------------------------------------------------------------------
    Realized natural
     gas prices
      Excluding
       hedging       $   6.23  $   6.90  (10)%  $    6.72  $    6.74       -
      Including
       hedging       $   6.97  $   7.27   (4)%  $    7.21  $    6.86      5%

    AECO monthly
     index           $   6.00  $   6.36   (6)%  $    6.61  $    6.98     (5)%Realized natural gas prices, excluding hedging, decreased 10% for the
three months and remained constant for the year ended December 31, 2007, as
compared to 2006. The price of natural gas is primarily based on supply and
demand fundamentals in the North American marketplace; however market
speculation activity has increased price volatility. Natural gas prices
declined for the current quarter and continued to remain weak for the entire
2007 year, as in 2006, due to exceedingly high storage levels, mild summer and
winter weather and a lack of storm activity in the Gulf of Mexico.  Fourth
quarter natural gas inventory levels remained well above average, causing
continued downward pressure on commodity prices. However, early 2008 has
brought colder weather and significant inventory withdrawals have been
experienced, resulting in a rebound of natural gas prices. Natural gas storage
levels are now closer to expectation and only slightly above the five-year
average. In addition, there has been a tighter supply of natural gas, putting
further upward pressure on prices. These developments have been encouraging
and we continue to believe that the long-term pricing fundamentals for natural
gas remain strong. These fundamentals include (i) the continued strength of
crude oil prices, which has eliminated the economic advantage of fuel
switching away from natural gas evidenced by the increase in proposed gas
fired electrical generation facilities, (ii) significantly less natural gas
drilling in Canada projected for 2008, which will reduce productivity to
offset declines, (iii) the increasing focus on resource style natural gas
wells, which have high initial declines and require a higher threshold
economic price than conventional gas drilling and (iv) the demand for natural
gas for the Canadian oil sands projects.Crude Oil and NGLs

                    Three months ended              Year ended
                        December 31                 December 31
    ($/bbl)            2007      2006   %change    2007      2006    %change
    -------------------------------------------------------------------------
    Realized crude
     oil prices
      Excluding
       hedging       $  74.19  $  56.10    32%  $   67.71  $   63.85      6%
      Including
       hedging       $  70.48  $  57.82    22%  $   66.92  $   64.34      4%

    Realized NGLs
     prices
      Excluding
       hedging       $  70.09  $  50.09    40%  $   60.12  $   55.81      8%

    Realized crude
     oil and NGLs
     prices
      Excluding
       hedging       $  73.40  $  54.58    34%  $   65.99  $   62.05      6%
      Including
       hedging       $  70.40  $  55.86    26%  $   65.38  $   62.44      5%

    WTI ($US/bbl)    $  90.63  $  60.21    51%  $   72.37  $   66.35      9%
    $US/$Canadian
     exchange rate   $   1.02  $   0.88    16%  $    0.94  $    0.88      7%Realized crude oil and NGLs prices, excluding hedging, increased 34% for
the three months and 6% for the year ended December 31, 2007, as compared to
the same periods of 2006. Advantage's crude oil prices are based on the
benchmark pricing of West Texas Intermediate Crude ("WTI") adjusted for
quality, transportation costs and $US/$Canadian exchange rates. For the three
months and year ended December 31, 2007, WTI increased 51% and 9%,
respectively, with momentous increases experienced in the fourth quarter of
2007. Advantage's realized crude oil price has not changed to the same extent
as WTI due to the strengthening of the Canadian dollar relative to the US
dollar and widened Canadian crude oil differentials relative to WTI. The price
of WTI fluctuates based on worldwide supply and demand fundamentals. There has
been significant price volatility experienced over the last several years
whereby WTI has reached historic high levels. Many developments have resulted
in the current price levels, including significant continuing geopolitical
issues and general market speculation. In fact, the impact of market
fundamentals has diminished as geopolitical events and speculation has
prevailed. As a result, prices have remained strong throughout 2007 and into
early 2008. With the current high price levels, it is notable that demand has
remained resilient even as the United States, the world's largest crude oil
consumer, experiences an economic slowdown. Regardless whether the current
price level is sustainable or just a short-term anomaly, we believe that the
pricing fundamentals for crude oil remain strong with many factors affecting
the continued strength including (i) supply management and supply restrictions
by the OPEC cartel, (ii) ongoing civil unrest in Venezuela, Nigeria, and the
Middle East, (iii) strong world wide demand, particularly in China, India and
the United States and (iv) North American refinery capacity constraints.

    Commodity Price Risk

    The Fund's operational results and financial condition will be dependent
on the prices received for oil and natural gas production. Oil and natural gas
prices have fluctuated widely during recent years and are determined by
economic and, in the case of oil prices, political factors. Supply and demand
factors, including weather and general economic conditions as well as
conditions in other oil and natural gas regions, impact prices. Any movement
in oil and natural gas prices could have an effect on the Fund's financial
condition and therefore on the distributions to holders of Advantage Trust
Units. As current and future practice, Advantage has established a financial
hedging strategy and may manage the risk associated with changes in commodity
prices by entering into derivatives. These commodity price risk management
activities could expose Advantage to losses or gains. To the extent that
Advantage engages in risk management activities related to commodity prices,
it will be subject to credit risk associated with counterparties with which it
contracts. Credit risk is mitigated by entering into contracts with only
stable, creditworthy parties and through frequent reviews of exposures to
individual entities.
    We have been active in entering new financial contracts to protect future
cash flows and currently the Fund has the following derivatives in place:Description of
     Derivative           Term              Volume           Average Price
    -------------------------------------------------------------------------
    Natural gas -
     AECO
      Fixed price    November 2007
                      to March 2008      7,109 mcf/d            Cdn$9.54/mcf
      Fixed price    April 2008 to
                      October 2008      14,217 mcf/d            Cdn$6.85/mcf
      Fixed price    April 2008 to
                      October 2008       9,478 mcf/d            Cdn$7.25/mcf
      Fixed price    April 2008 to
                      October 2008      14,217 mcf/d            Cdn$7.83/mcf
      Fixed price    April 2008 to
                      March 2009        14,217 mcf/d            Cdn$7.10/mcf
      Fixed price    April 2008 to
                      March 2009        14,217 mcf/d            Cdn$7.06/mcf
      Fixed price    November 2008
                      to March 2009     14,217 mcf/d            Cdn$7.77/mcf
      Fixed price    November 2008
                      to March 2009      4,739 mcf/d            Cdn$8.10/mcf
      Collar         November 2007
                      to March 2008      9,478 mcf/d    Floor   Cdn$8.44/mcf
                                                      Ceiling  Cdn$10.29/mcf
      Collar         November 2007
                      to March 2008      7,109 mcf/d    Floor   Cdn$8.70/mcf
                                                      Ceiling  Cdn$10.71/mcf

    Crude oil - WTI
      Fixed price    February 2008
                      to January 2009   2,000 bbls/d           Cdn$90.93/bbl
      Fixed price    April 2008 to
                      March 2009        2,500 bbls/d           Cdn$97.15/bbl
      Collar         February 2008
                      to January 2009   2,000 bbls/d  Sold put Cdn$70.00/bbl
                                                     Purchased
                                                      call    Cdn$105.00/bbl
                                                          Cost  Cdn$1.52/bblAs at December 31, 2007 the fair value of the derivatives outstanding was
a net asset of approximately $2.2 million. For the year ended December 31,
2007, $11.0 million was recognized in income as an unrealized derivative loss
due to changes in the fair value and settlement of such contracts since
December 31, 2006. For the same period we recognized in income a realized
derivative gain of $18.6 million upon the settlement of these financial
contracts, which partially alleviated lower revenue from continued weak
natural gas prices. As a result of the Sound acquisition, the Fund assumed
several derivatives which had an estimated net fair value on closing of
$2.8 million. The change in fair value of these derivatives since acquisition
to the end of the period has been recognized in income as an unrealized
derivative gain or loss. The valuation of the derivatives is the estimated
fair value to settle the contracts as at December 31, 2007 and is based on
pricing models, estimates, assumptions and market data available at that time.
The actual gain or loss realized on eventual cash settlement can vary
materially due to subsequent fluctuations in commodity prices as compared to
the valuation assumptions. The Fund does not apply hedge accounting and
current accounting standards require changes in the fair value to be included
in the consolidated statement of income and comprehensive income as an
unrealized derivative gain or loss with a corresponding derivative asset and
liability recorded on the balance sheet.
    The Fund has fixed the commodity price on anticipated production as
follows:Approximate
                          Production Hedged,       Average        Average
    Commodity              Net of Royalties      Floor Price   Ceiling Price
    -------------------------------------------------------------------------
    Natural gas - AECO
      January to March 2008        22%          Cdn$8.85/mcf   Cdn$10.19/mcf
      April to June 2008           66%          Cdn$7.22/mcf    Cdn$7.22/mcf
      July to September 2008       64%          Cdn$7.22/mcf    Cdn$7.22/mcf
      October to December 2008     53%          Cdn$7.32/mcf    Cdn$7.32/mcf
      -----------------------------------------------------------------------
      Total 2008                   51%          Cdn$7.43/mcf    Cdn$7.58/mcf
      -----------------------------------------------------------------------
      January to March 2009        46%          Cdn$7.39/mcf    Cdn$7.39/mcf

    Crude Oil - WTI
      January to March 2008        13%         Cdn$90.93/bbl   Cdn$90.93/bbl
      April to June 2008           47%         Cdn$94.39/bbl   Cdn$94.39/bbl
      July to September 2008       46%         Cdn$94.39/bbl   Cdn$94.39/bbl
      October to December 2008     46%         Cdn$94.39/bbl   Cdn$94.39/bbl
      -----------------------------------------------------------------------
      Total 2008                   38%         Cdn$94.07/bbl   Cdn$94.07/bbl
      -----------------------------------------------------------------------
      January to March 2009        32%         Cdn$95.84/bbl   Cdn$95.84/bbl



    Royalties

                    Three months ended              Year ended
                        December 31                 December 31
                       2007      2006   %change    2007      2006    %change
    -------------------------------------------------------------------------
    Royalties, net
     of Alberta
     Royalty Credit
     ($000)          $ 27,099  $ 23,349    16%  $  98,614  $  76,456     29%
      per boe        $   8.58  $   8.72   (2)%  $    9.02  $    8.82      2%
    As a percentage
     of revenue,
     excluding
     hedging            16.9%     19.1% (2.2)%      18.3%      18.4%  (0.1)%Advantage pays royalties to the owners of mineral rights from which we
have leases. The Fund currently has mineral leases with provincial
governments, individuals and other companies. Royalties for 2006 are shown net
of the Alberta Royalty Credit, which was a royalty rebate provided by the
Alberta government to certain producers and was eliminated effective
January 1, 2007. Royalties have increased in total for the 2007 periods due to
the increase in revenue from higher production related to acquisitions but
remains comparable on a per boe basis. Royalties as a percentage of revenue,
excluding hedging, remained consistent for the year as compared to 2006 but
decreased in the fourth quarter of 2007 due to the lower natural gas prices
experienced by Advantage during the last six months of the year. We expect the
royalty rate to be in the range of 17% to 19% for 2008 given the current
environment.
    On October 25, 2007, the Alberta Provincial Government announced changes
to royalties for conventional oil, natural gas and oil sands that will become
effective January 1, 2009. Given the methodology used in the new royalty
regime, royalties and as a result, cash flows will be affected by depths and
productivity of wells. In addition, royalties are price sensitive with higher
royalty levels applying when commodity prices are higher. A review of the
initial information released by the Alberta Provincial Government indicates
that lower rate natural gas wells will see a benefit of lower royalties while
conventional oil will be subject to an increase in royalties but is again less
punitive at lower rates. Commodity prices and individual well production rates
are both key factors in the calculation. The majority of Advantage's
production in Alberta comes from lower rate wells due to well-established
large, long life properties. In addition, we have a significant presence in
British Columbia and Saskatchewan. Therefore, early indications are that the
impact may not be significant based on our current production and the current
commodity price environment. Advantage continues to analyze the impact of the
decision and will take the new royalty regime into consideration in preparing
future development projects. Project economics are evaluated taking into
consideration all relevant factors including the new royalty regime given the
commodity pricing environment anticipated. Those projects that maximize return
to Advantage Unitholders will continue to be selected for development.Operating Costs

                    Three months ended              Year ended
                        December 31                 December 31
                       2007      2006   %change    2007      2006    %change
    -------------------------------------------------------------------------
    Operating costs
     ($000)          $ 39,330  $ 27,803    41%  $ 127,309  $  82,911     54%
      per boe        $  12.46  $  10.39    20%  $   11.64  $    9.56     22%Total operating costs increased 41% for the three months and 54% for the
year ended December 31, 2007 as compared to 2006, mainly due to increased
production from the Ketch acquisition which was completed June 23, 2006 and
the Sound acquisition, which closed on September 5, 2007. Operating costs per
boe increased 20% for the three months and 22% for the year ended December 31,
2007, mainly due to lower production levels related to third party turnaround
activity, an extended spring break-up, increased service and supply costs as
the industry experienced overall cost increases, and higher relative operating
costs from recent acquisitions. However, fourth quarter 2007 per boe operating
costs came in modestly lower than our expectation of $12.50 to $13.50, due to
optimization initiatives put in place by the Fund in 2007. We will continue to
be opportunistic and proactive in pursuing programs that will improve our
operating cost structure. Consistent with this strategy, the Fund entered
hedges for power costs, one of our more significant operating costs, of 3.0 MW
at $54.00/MWh for 2008. We expect that operating costs per boe will be in the
range of $12.50 to $13.30 for the 2008 year.General and Administrative

                    Three months ended              Year ended
                        December 31                 December 31
                       2007      2006   %change    2007      2006    %change
    -------------------------------------------------------------------------
    General and
     administrative
     expense ($000)  $  7,173  $  4,586    56%  $  21,449  $  13,738     56%
      per boe        $   2.27  $   1.71    33%  $    1.96  $    1.58     24%
    Employees at
     December 31                                      172        135     27%General and administrative ("G&A") expense has increased 56% for the
three months and year ended December 31, 2007, as compared to 2006. G&A per
boe increased 33% for the three months and 24% for the year when compared to
the same periods of 2006. G&A expense for the year ended December 31, 2007 has
increased overall and per boe primarily due to an increase in staff levels
that have resulted from the Ketch and Sound acquisitions and general growth of
the Fund. Additionally, the Ketch acquisition was conditional on Advantage
internalizing the external management contract structure and eliminating all
related fees for a more typical employee compensation arrangement. The new
employee compensation plan has resulted in higher G&A expense, including unit-
based compensation, which is offset by the elimination of future management
fees and performance incentive. Prior to elimination of the management
contract, the quarterly management fee and annual performance incentive were
not included within G&A.
    Current employee compensation includes salary, benefits, a short-term
incentive plan and a long-term incentive plan. The long-term incentive plan
consists of a Restricted Trust Unit Plan (the "Plan"), as approved by the
Unitholders on June 23, 2006, and Trust Units issuable for the retention of
certain employees of the Fund. The purpose of the long-term compensation plans
is to retain and attract employees, to reward and encourage performance, and
to focus employees on operating and financial performance that results in
lasting Unitholder return.
    The Plan authorizes the Board of Directors to grant Restricted Trust
Units ("RTUs") to directors, officers, or employees of the Fund. The number of
RTUs granted is based on the Fund's Trust Unit return for a calendar year and
compared to a peer group approved by the Board of Directors. The Trust Unit
return is calculated at the end of the year and is primarily based on the
year- over-year change in the Trust Unit price plus distributions. The RTU
grants vest one third immediately on grant date, with the remaining two thirds
vesting evenly on the following two yearly anniversary dates. The holders of
RTUs may elect to receive cash upon vesting in lieu of the number of Trust
Units to be issued, subject to consent of the Fund. Compensation cost related
to the Plan is based on the "fair value" of the RTUs at the grant date and is
recognized as compensation expense over the service period. This valuation
incorporates the period end Trust Unit price, the estimated number of RTUs to
vest, and certain management estimates. The maximum fair value of RTUs granted
in any one calendar year is limited to 175% of the base salaries of those
individuals participating in the Plan for such period. As the Fund did not
meet the 2007 or 2006 grant thresholds, there were no RTU grants made during
these years and no related compensation expense has been recognized.
    For the year ended December 31, 2007, the Fund has accrued unit-based
compensation expense of $0.9 million in general and administrative expense and
has capitalized $0.3 million related to Trust Units issuable for the retention
of certain employees of the Fund.Management Fee, Performance Incentive, and Management Internalization

                    Three months ended              Year ended
                        December 31                 December 31
                       2007      2006   %change    2007      2006    %change
    -------------------------------------------------------------------------
    Management
     fee ($000)      $      -  $      -      -  $       -  $     887  (100)%
      per boe        $      -  $      -      -  $       -  $    0.10  (100)%
    Performance
     incentive
     ($000)          $      -  $      -      -  $       -  $   2,380  (100)%
    Management
     internalization
     ($000)          $  2,534  $  5,497  (54)%  $  15,708  $  13,449     17%Prior to the Ketch merger, the Manager received both a management fee and
a performance incentive fee as compensation pursuant to the Management
Agreement approved by the Board of Directors. As a condition of the merger
with Ketch, the Fund and the Manager reached an agreement to internalize the
management contract arrangement. As part of the agreement, Advantage agreed to
purchase all of the outstanding shares of the Manager pursuant to the terms of
the Arrangement, thereby eliminating the management fee and performance
incentive effective April 1, 2006. The Trust Unit consideration issued in
exchange for the outstanding shares of the Manager was placed in escrow for a
3-year period and is being deferred and amortized into income as management
internalization expense over the specific vesting periods during which
employee services are provided. The management internalization is lower for
the quarter since one third vested and was paid in June 2007 while two thirds
remains outstanding.Interest

                    Three months ended              Year ended
                        December 31                 December 31
                       2007      2006   %change    2007      2006    %change
    -------------------------------------------------------------------------
    Interest expense
     ($000)          $  7,917  $  5,414    46%  $  24,351  $  18,258     33%
      per boe        $   2.51  $   2.02    24%  $    2.23  $    2.11      6%
    Average effective
     interest rate       6.2%      5.5%   0.7%       5.7%       5.1%    0.6%
    Bank indebtedness
     at December 31
     ($000)                                     $ 547,426  $ 410,574     33%

    Interest expense has increased 46% for the three months and 33% for the
year ended December 31, 2007, as compared to 2006. Interest expense per boe
has increased 24% for the three months and 6% for the year ended December 31,
2007. The increase in total interest expense is primarily attributable to a
higher average debt level associated with the growth of the Fund, an increase
in the average effective interest rates and increased bank indebtedness
assumed on the Ketch and Sound acquisitions. We monitor the debt level to
ensure an optimal mix of financing and cost of capital that will provide a
maximum return to Unitholders. Our current credit facilities have been a
favorable financing alternative with an effective interest rate of only 5.7%
for the year ended December 31, 2007. The Fund's interest rates are primarily
based on short term Bankers Acceptance rates plus a stamping fee.

    Interest and Accretion on Convertible Debentures

                    Three months ended              Year ended
                        December 31                 December 31
                       2007      2006   %change    2007      2006    %change
    -------------------------------------------------------------------------
    Interest on
     convertible
     debentures
     ($000)          $  4,426  $  3,289    35%  $  14,867  $  11,210     33%
      per boe        $   1.40  $   1.23    14%  $    1.36  $    1.29      5%
    Accretion on
     convertible
     debentures
     ($000)          $    721  $    604    19%  $   2,569  $   2,106     22%
      per boe        $   0.23  $   0.23     -   $    0.23  $    0.24    (4)%
    Convertible
     debentures
     maturity
     value at
     December 31
     ($000)                                     $ 224,612  $ 180,730     24%

    Interest on convertible debentures has increased 35% for the three months
and 33% for the year ended December 31, 2007, as compared to 2006. Accretion
on convertible debentures has increased 19% for the three months and 22% for
the year ended December 31, 2007. The increases in total interest and
accretion are due to Advantage assuming Sound's 8.75% and 8.00% convertible
debentures and Ketch's 6.50% convertible debentures in the 2006 merger. The
increased interest and accretion from the additional debentures has been
slightly offset due to the exchange of convertible debentures to Trust Units
during 2006 that pay distributions rather than interest. Interest per boe for
the quarter is higher as our convertible debentures outstanding have slightly
increased relative to our level of production.

    Cash Netbacks

                                          Three months ended
                                              December 31
                                    2007                      2006
                              $000        per boe       $000        per boe
    -------------------------------------------------------------------------
    Revenue               $   160,741  $     50.91  $   122,360  $     45.72
    Realized gain on
     derivatives                5,210         1.65        5,179         1.93
    Royalties, net of
     Alberta Royalty
     Credit                   (27,099)       (8.58)     (23,349)       (8.72)
    Operating costs           (39,330)      (12.46)     (27,803)      (10.39)
    -------------------------------------------------------------------------
    Operating             $    99,522  $     31.52  $    76,387  $     28.54
    General and
     administrative(1)         (7,029)       (2.23)      (4,586)       (1.71)
    Management fee                  -            -            -            -
    Interest                   (7,917)       (2.51)      (5,414)       (2.02)
    Interest on
     convertible
     debentures(1)             (3,536)       (1.12)      (3,289)       (1.23)
    Income and capital
     taxes                       (521)       (0.16)        (361)       (0.13)
    -------------------------------------------------------------------------
    Funds from operations $    80,519  $     25.50  $    62,737  $     23.45
    -------------------------------------------------------------------------



    Cash Netbacks

                                              Year ended
                                              December 31
                                    2007                      2006
                              $000        per boe       $000        per boe
    -------------------------------------------------------------------------
    Revenue               $   538,764  $     49.27  $   414,430  $     47.80
    Realized gain on
     derivatives               18,594         1.70        5,297         0.61
    Royalties, net of
     Alberta Royalty
     Credit                   (98,614)       (9.02)     (76,456)       (8.82)
    Operating costs          (127,309)      (11.64)     (82,911)       (9.56)
    -------------------------------------------------------------------------
    Operating             $   331,435  $     30.31  $   260,360  $     30.03
    General and
     administrative(1)        (20,520)       (1.88)     (13,738)       (1.58)
    Management fee                  -            -         (887)       (0.10)
    Interest                  (24,351)       (2.23)     (18,258)       (2.11)
    Interest on
     convertible
     debentures(1)            (13,977)       (1.28)     (11,210)       (1.29)
    Income and capital
     taxes                     (1,444)       (0.13)      (1,509)       (0.17)
    -------------------------------------------------------------------------
    Funds from operations $   271,143  $     24.79  $   214,758  $     24.78
    -------------------------------------------------------------------------
    (1) General and administrative expense and interest on convertible
        debentures exclude unit-based compensation and non-cash interest
        expense.Funds from operations of Advantage for the quarter ended December 31,
2007 increased to $80.5 million from $62.7 million in the prior year. Funds
from operations for the year ended December 31, 2007 increased to
$271.1 million from $214.8 million compared to 2006. The cash netback per boe
for the three months ended December 31, 2007 increased 9% from $23.45 to
$25.50 for the quarter, but remained comparable for the year ended December
31, 2007. The higher cash netback per boe for the three months ended December
31, 2007 is primarily due to higher revenues, resulting from additional
production from the accretive Sound acquisition and strong oil prices offset
somewhat by lower natural gas prices as well as higher operating and general
and administrative costs. Operating costs have steadily increased over the
past year due to significantly higher field costs associated with supplies and
services that have resulted from the high level of industry activity, an
overall industry labour cost increase, and higher relative operating costs
from recent acquisitions. However, it is noteworthy that due to several of our
initiatives this year, operating costs for the quarter were less than
anticipated. The increased general and administrative costs are due to higher
staff levels and general growth of the Fund. When compared to the third
quarter of 2007, funds from operations per boe increased 10%, again mainly due
to the acquisition of Sound.Depletion, Depreciation and Accretion

                    Three months ended                Year ended
                        December 31                   December 31
                      2007      2006  % change      2007      2006  % change
    -------------------------------------------------------------------------
    Depletion,
     depreciation
     & accretion
     ($000)       $ 78,149  $ 63,521       23%  $272,175  $194,309       40%
      per boe     $  24.75  $  23.73        4%  $  24.89  $  22.41       11%Depletion and depreciation of fixed assets is provided on the
"unit-of-production" method based on total proved reserves. Accretion
represents the increase in the asset retirement obligation liability each
reporting period due to the passage of time. The depletion, depreciation and
accretion ("DD&A") provision has increased 23% for the three months and 40%
for the year ended December 31, 2007. The higher DD&A is due to considerable
increases in daily production volumes, mainly from the Ketch and Sound
acquisitions and the increase in the DD&A rate per boe compared to the prior
year. The increased DD&A rate per boe was due to a higher valuation assigned
for reserves from recent acquisitions than accumulated from prior acquisitions
and development activities. We evaluate the recoverability of our petroleum
and natural gas assets each reporting period to ensure the carrying amount
does not exceed the fair value. When the carrying amount is not assessed to be
recoverable, an impairment loss is recognized. There has been no impairment of
the Fund's petroleum and natural gas properties under Canadian GAAP since
inception.

    Taxes

    Current taxes paid or payable for the quarter ended December 31, 2007
amounted to $0.5 million, comparable to the $0.4 million expensed for the same
period of 2006. The higher current taxes are due to the increased Saskatchewan
properties and activity within these properties from the Ketch and Sound
acquisitions. Current taxes primarily represent Saskatchewan resource
surcharge, which is based on the petroleum and natural gas revenues within the
province of Saskatchewan.
    Future income taxes arise from differences between the accounting and tax
bases of the assets and liabilities. For the year ended December 31, 2007, the
Fund recognized a future income tax reduction of $24.6 million compared to
$37.1 million for 2006. Under the Fund's current structure, payments are made
between the operating company and the Fund transferring income tax obligations
to Unitholders and as a result no cash income taxes would be paid by the
operating company or the Fund prior to 2011. However, the Specified Investment
Flow-Through Entity ("SIFT") tax legislation was enacted on June 22, 2007
altering the tax treatment by subjecting income trusts to a two-tier tax
structure, similar to that of corporations, whereby the taxable portion of
distributions paid by trusts will be subject to tax at the trust level and at
the Unitholder level. The rules are effective for tax years beginning in 2011
for existing publicly-traded trusts. The impact of the new tax law is
reflected in 2007 and resulted in an additional future income tax expense of
$42.9 million. As at December 31, 2007, we had a future income tax liability
balance of $66.7 million, compared to $61.9 million at December 31, 2006.
Canadian generally accepted accounting principles require that a future income
tax liability be recorded when the book value of assets exceeds the balance of
tax pools. It further requires that a future tax liability be recorded on an
acquisition when a corporation acquires assets with associated tax pools that
are less than the purchase price. As a result of the Sound acquisition,
Advantage recorded a future tax liability of $29.4 million.
    On December 14, 2007, the Federal government enacted legislation phasing
in corporate income tax rate reductions which will reduce federal tax rates
from 22.1% to 15.0% by 2012. Rate reductions will also apply to the new tax on
distributions of income trusts and other specified investment flow-through
entities as of 2011, reducing the tax rate in 2011 to 29.5% and in 2012 to
28.0%.  These rates include a deemed provincial rate of 13%.
    The Fund has approximately $1.7 billion in tax pools and deductions at
December 31, 2007, which can be used to reduce the amount of taxes paid by
Advantage.  The Fund and Advantage Oil & Gas Ltd. ("AOG") had the following
estimated tax pools in place at December 31, 2007:December 31, 2007
                                                 Estimated Tax Pools
                                                    ($ millions)
                                                    ------------
    Undepreciated Capital Cost                      $       641
    Canadian Oil and Gas Property Expenses                  462
    Canadian Development Expenses                           435
    Canadian Exploration Expenses                            65
    Non-capital losses                                       76
    Other                                                    25
                                                    ------------
                                                    $     1,704
                                                    ------------Contractual Obligations and Commitments

    The Fund has contractual obligations in the normal course of operations
including purchases of assets and services, operating agreements,
transportation commitments, sales contracts and convertible debentures. These
obligations are of a recurring and consistent nature and impact cash flow in
an ongoing manner. The following table is a summary of the Fund's remaining
contractual obligations and commitments. Advantage has no guarantees or
off-balance sheet arrangements other than as disclosed.Payments due by period
    ($ millions)               Total    2008    2009    2010    2011    2012
    -------------------------------------------------------------------------
    Building leases           $ 16.6  $  5.3  $  4.1  $  4.1  $  1.8  $  1.3
    Capital leases               8.1     1.9     2.1     2.2     1.9       -
    Pipeline/transportation      6.0     4.4     1.3     0.3       -       -
    Convertible debentures(1)  224.6     5.4    87.0    69.9    62.3       -
    -------------------------------------------------------------------------
    Total contractual
     obligations              $255.3  $ 17.0  $ 94.5  $ 76.5  $ 66.0  $  1.3
    -------------------------------------------------------------------------
    (1) As at December 31, 2007, Advantage had $224.6 million convertible
        debentures outstanding. Each series of convertible debentures are
        convertible to Trust Units based on an established conversion price.
        The Fund expects that the obligations related to convertible
        debentures will be settled either directly or indirectly through the
        issuance of Trust Units.
    (2) Bank indebtedness of $547.4 million has been excluded from the
        contractual obligations table as the credit facilities constitute a
        revolving facility for a 364 day term which is extendible annually
        for a further 364 day revolving period at the option of the
        syndicate. If not extended, the revolving credit facility is
        converted to a two year term facility with the first payment due one
        year and one day after commencement of the term.



    Liquidity and Capital Resources

    The following table is a summary of the Fund's capitalization structure.

    ($000, except as otherwise indicated)                  December 31, 2007
    -------------------------------------------------------------------------
    Bank indebtedness (long-term)                                $   547,426
    Working capital deficit(1)                                        28,087
    -------------------------------------------------------------------------
    Net debt                                                     $   575,513
    -------------------------------------------------------------------------
    Trust Units outstanding (000)                                    138,269
    Trust Unit closing market price ($/Trust Unit)               $      8.73
    -------------------------------------------------------------------------
    Market value                                                 $ 1,207,088
    -------------------------------------------------------------------------
    Capital lease obligations (long-term)                        $     5,653
    Convertible debentures maturity value (long-term)                219,220
    -------------------------------------------------------------------------
    Total capitalization                                         $ 2,007,474
    -------------------------------------------------------------------------
    (1) Working capital deficit includes accounts receivable, prepaid
        expenses and deposits, accounts payable and accrued liabilities,
        distributions payable, and the current portion of capital lease
        obligations and convertible debentures.Unitholders' Equity and Convertible Debentures

    Advantage has utilized a combination of Trust Units, convertible
debentures and bank debt to finance acquisitions and development activities.
    As at December 31, 2007, the Fund had 138.3 million Trust Units
outstanding. On February 14, 2007 Advantage issued 7,800,000 Trust Units, plus
an additional 800,000 Trust Units upon exercise of the Underwriters'
over-allotment option on March 7, 2007, at $12.80 per Trust Unit for
approximate net proceeds of $104.1 million (net of Underwriters' fees and
other issue costs of $6.0 million). The net proceeds of the offering were used
to pay down bank indebtedness and to subsequently fund capital and general
corporate expenditures. On September 5, 2007, Advantage issued 16,977,184
Trust Units as partial consideration for the acquisition of Sound. As at March
5, 2008, Advantage had 139.0 million Trust Units issued and outstanding.
    On July 24, 2006, Advantage adopted a Premium Distribution™,
Distribution Reinvestment and Optional Trust Unit Purchase Plan (the "Plan").
For Unitholders that elect to participate in the Plan, Advantage will settle
the monthly distribution obligation through the issuance of additional Trust
Units at 95% of the Average Market Price (as defined in the Plan). Unitholder
enrollment in the Premium Distribution™ component of the Plan effectively
authorizes the subsequent disposal of the issued Trust Units in exchange for a
cash payment equal to 102% of the cash distributions that the Unitholder would
otherwise have received if they did not participate in the Plan. During the
year ended December 31, 2007, 4,028,252 Trust Units were issued as a result of
the Plan, generating $46.7 million reinvested in the Fund and representing an
approximate 18% participation rate.
    As at December 31, 2007, the Fund had $224.6 million convertible
debentures outstanding that were convertible to 9.8 million Trust Units based
on the applicable conversion prices. During the year ended December 31, 2007,
$24,000 debentures were converted resulting in the issuance of 1,386 Trust
Units and all of the remaining $1,470,000 10% convertible debentures matured
on November 1, 2007 and were settled with the issuance of 127,493 Trust Units.
    Due to the acquisition of Sound, $59,513,000 8.75% and $41,035,000 8.00%
convertible debentures were assumed by Advantage on September 5, 2007. As a
result of the change in control of Sound, the Fund was required by the
debenture indentures to make an offer to purchase all of the outstanding
convertible debentures assumed from Sound as at a price equal to 101% of the
principal amount plus accrued and unpaid interest. On October 17, 2007, the
expiry date of the offer, 911,709 Trust Units were issued and $19.9 million in
total cash consideration was paid in exchange for $29,665,000 8.75%
convertible debentures and 2,220,289 Trust Units were issued in exchange for
$25,507,000 8.00% convertible debentures. As at March 5, 2008, the convertible
debentures have not changed from December 31, 2007.
    Effective June 25, 2002, a Trust Units Rights Incentive Plan for external
directors of the Fund was established and approved by the Unitholders of
Advantage. A total of 500,000 Trust Units have been reserved for issuance
under the plan with an aggregate of 400,000 rights granted since inception.
The initial exercise price of rights granted under the plan may not be less
than the current market price of the Trust Units as of the date of the grant
and the maximum term of each right is not to exceed ten years with all rights
vesting immediately upon grant. At the option of the rights holder, the
exercise price of the rights can be adjusted downwards over time based upon
distributions paid by the Fund to Unitholders. In exchange for an equivalent
number of Trust Units, 37,500 Series B Trust Unit Rights were exercised in the
second quarter of 2007. As at March 5, 2008, 150,000 Series B Trust Unit
Rights remain outstanding.
    As a result of the new SIFT tax legislation, an income trust is permitted
to double its market capitalization as it stands on October 31, 2006 by
growing a maximum of 40% in 2007 and 20% for the years 2008 to 2010. Any
unused expansion from the prior year can be brought forward into the following
year until the new tax rules take effect. In addition, an income trust may
replace debt that was outstanding as of October 31, 2006 with new equity or
issue new, non-convertible debt without affecting the normal growth
percentage. An income trust may also merge with another income trust without a
change to their normal growth percentage, provided there is no net addition to
equity as a result of the merger. As of October 31, 2006, the Fund had an
approximate market capitalization of $1.6 billion and bank indebtedness of
$0.4 billion. Therefore, as a result of the "normal growth" guidelines, the
Fund is permitted to issue $2.0 billion of new equity from October 31, 2006 to
January 1, 2011, which we believe is adequate for any growth we expect to
incur.

    Bank Indebtedness, Credit Facility and Other Obligations

    At December 31, 2007, Advantage had bank indebtedness outstanding of
$547.4 million. The Fund has a $710 million credit facility agreement
consisting of a $690 million extendible revolving loan facility and a
$20 million operating loan facility. The current credit facilities are secured
by a $1 billion floating charge demand debenture, a general security agreement
and a subordination agreement from the Fund covering all assets and cash
flows.
    At December 31, 2007, Advantage had a working capital deficiency of
$28.1 million. Our working capital includes items expected for normal
operations such as trade receivables, prepaids, deposits, trade payables and
accruals as well as the current portion of capital lease obligations and
convertible debentures. Working capital varies primarily due to the timing of
such items, the current level of business activity including our capital
program, commodity price volatility, and seasonal fluctuations. Advantage has
no unusual working capital requirements. We do not anticipate any problems in
meeting future obligations as they become due given the strength of our funds
from operations. It is also important to note that working capital is
effectively integrated with Advantage's operating credit facility, which
assists with the timing of cash flows as required.
    In the second quarter of 2007, Advantage entered a new lease arrangement
that resulted in the recognition of a fixed asset addition and capital lease
obligation of $4.1 million. The lease obligation bears interest at 5.8% and is
secured by the related equipment. The lease term expires June 2011 with a
final purchase obligation of $1.5 million at which time ownership of the
equipment will transfer to Advantage. We entered a second lease arrangement
during the third quarter of 2007 that resulted in the recognition of a fixed
asset addition and capital lease obligation of $1.8 million. This lease
obligation bears interest at 6.7% and is also secured by the related
equipment. The lease term expires August 2010 with a final payment obligation
of $0.7 million. Distributions to Unitholders are not permitted if the Fund is
in default of this capital lease.
    On September 5, 2007, Advantage assumed two capital lease obligations in
the acquisition of Sound resulting in the recognition of capital lease
obligations of $1.6 million. Both of the assumed lease obligations bear
interest at 5.6% and are secured by the related equipment. The lease terms
expire December 2009 and April 2010 with a total final payment obligation of
$0.9 million.Capital Expenditures
                                Three months ended            Year ended
                                    December 31               December 31
    ($000)                       2007         2006         2007         2006
    -------------------------------------------------------------------------
    Land and seismic      $        64  $       522  $     3,270  $     5,261
    Drilling, completions
     and workovers             30,020       42,612       94,786      113,146
    Well equipping and
     facilities                 9,971       17,690       48,296       39,437
    Other                         878          285        2,373        1,643
    -------------------------------------------------------------------------
                          $    40,933  $    61,109  $   148,725  $   159,487
    Acquisition of Sound
     Energy Trust                 (67)           -       22,307            -
    Property acquisitions       3,200           46       16,051          244
    Property dispositions        (610)           -       (1,037)      (8,727)
    -------------------------------------------------------------------------
    Total capital
     expenditures         $    43,456  $    61,155  $   186,046  $   151,004
    -------------------------------------------------------------------------Advantage's growth strategy has been to acquire properties in or near
areas where we have large land positions, shallow to medium depth drilling
opportunities, and a balance of year round access. We focus on areas where
past activity has yielded long-life reserves with high cash netbacks. With the
integration of the Ketch and Sound assets, Advantage is very well positioned
to selectively exploit the highest value-generating drilling opportunities
given the size, strength and diversity of our asset base. As a result, the
Fund has a high level of flexibility to distribute its capital program and
ensure a risk-balanced platform of projects. Our preference is to operate a
high percentage of our properties such that we can maintain control of capital
expenditures, operations and cash flows.
    For the three month period ended December 31, 2007, the Fund spent a net
$40.9 million and drilled a total of 16.6 net (32 gross) wells at a 100%
success rate. Total capital spending in the quarter included $7.1 million at
Nevis, $5.7 million at Chip Lake, $5.3 million at Martin Creek, $3.9 million
at Southeast Saskatchewan and $3.4 million at Willesden Green. For the year
ended December 31, 2007, the Fund spent a net $148.7 million and drilled a
total of 64.8 net (112 gross) wells at a 99% success rate. Total capital
spending for the year included $33.6 million at Martin Creek, $26.2 million at
Nevis, $17.5 million at Willesden Green, $10.5 million in Southeast
Saskatchewan, $8.5 million at Chip Lake, and $7.2 million at Sunset.
    Property acquisitions year to date include a $12.9 million property
acquisition in the first quarter for producing properties and undeveloped land
at the Fund's core area, Nevis, and a $3.2 million property acquisition in the
Boundary Lake area during the fourth quarter. Costs of $22.3 million were
incurred related to the Sound acquisition representing the cash portion paid
due to the exercise of the cash option offered to Sound Unitholders and other
costs.
    The following table summarizes the various funding requirements during
the years ended December 31, 2007 and 2006 and the sources of funding to meet
those requirements.Sources and Uses of Funds
                                                              Year ended
                                                              December 31
    ($000)                                                 2007         2006
    -------------------------------------------------------------------------
    Sources of funds
      Funds from operations                         $   271,143  $   214,758
      Units issued, net of costs                        104,215      141,908
      Increase in bank indebtedness                      28,893            -
      Property dispositions                               1,037        8,727
      Decrease in working capital                             -       27,222
    -------------------------------------------------------------------------
                                                    $   405,288  $   392,615
    -------------------------------------------------------------------------
    Uses of funds
      Distributions to Unitholders                  $   170,915  $   185,015
      Expenditures on property and equipment            148,725      159,487
      Acquisition of Sound Energy Trust                  22,307            -
      Debentures redeemed                                19,406            -
      Increase in working capital                        17,749            -
      Property acquisitions                              16,051          244
      Expenditures on asset retirement                    6,951        5,974
      Reduction of capital lease obligations              3,184        1,019
      Decrease in bank indebtedness                           -       30,767
      Acquisition of Ketch Resources Trust                    -       10,109
    -------------------------------------------------------------------------
                                                    $   405,288  $   392,615
    -------------------------------------------------------------------------

    Annual Financial Information

    The following is a summary of selected financial information of the Fund
for the periods indicated.

                                        Year ended   Year ended   Year ended
                                           Dec. 31,     Dec. 31,     Dec. 31,
                                              2007         2006         2005
    -------------------------------------------------------------------------
    Total revenue (before royalties)
     ($000)                            $   557,358  $   419,727  $   376,572
    Net income (loss) ($000)           $    (7,535) $    49,814  $    75,072
      per Trust Unit - Basic           $     (0.06) $      0.62  $      1.33
                     - Diluted         $     (0.06) $      0.61  $      1.32
    Total assets ($000)                $ 2,422,280  $ 1,981,587  $ 1,012,847
    Long term financial liabilities
     ($000)(1)                         $   768,060  $   581,698  $   379,903
    Distributions declared per Trust
     Unit                              $      1.77  $      2.66  $      3.12

    (1) Long term financial liabilities exclude asset retirement obligations
        and future income taxes.



    Quarterly Performance

                                                     2007
    ($000, except as
     otherwise indicated)          Q4           Q3           Q2           Q1
    -------------------------------------------------------------------------
    Daily production
      Natural gas (mcf/d)     128,556      115,991      108,978      114,324
      Crude oil and NGLs
       (bbls/d)                12,895       10,014        8,952        9,958
      Total (boe/d)            34,321       29,346       27,115       29,012
    Average prices
      Natural gas ($/mcf)
        Excluding hedging $      6.23  $      5.62  $      7.54  $      7.61
      Including hedging   $      6.97  $      6.35  $      7.52  $      8.06
      AECO monthly index  $      6.00  $      5.62  $      7.37  $      7.46
      Crude oil and NGLs
       ($/bbl)
        Excluding hedging $     73.40  $     69.03  $     61.84  $     56.84
      Including hedging   $     70.40  $     68.51  $     61.93  $     58.64
      WTI (US$/bbl)       $     90.63  $     75.33  $     65.02  $     58.12
    Total revenues (before
     royalties)           $   165,951  $   130,830  $   125,075  $   135,502
    Net income (loss)     $    13,795  $   (26,202) $     4,531  $       341
      per Trust Unit
       - basic            $      0.10  $     (0.22) $      0.04  $      0.00
       - diluted          $      0.10  $     (0.22) $      0.04  $      0.00
    Funds from operations $    80,519  $    62,345  $    62,634  $    65,645
    Distributions
     declared             $    57,875  $    55,017  $    52,096  $    50,206


                                                     2006
    ($000, except as
     otherwise indicated)          Q4           Q3           Q2           Q1
    -------------------------------------------------------------------------
    Daily production
      Natural gas (mcf/d)     117,134      122,227       70,293       65,768
      Crude oil and NGLs
       (bbls/d)                 9,570        9,330        6,593        6,760
      Total (boe/d)            29,092       29,701       18,309       17,721
    Average prices
      Natural gas ($/mcf)
        Excluding hedging $      6.90  $      5.89  $      6.18  $      8.69
      Including hedging   $      7.27  $      5.90  $      6.18  $      8.69
      AECO monthly index  $      6.36  $      6.03  $      6.28  $      9.31
      Crude oil and NGLs
       ($/bbl)
        Excluding hedging $     54.58  $     67.77  $     68.69  $     58.26
      Including hedging   $     55.86  $     67.77  $     68.69  $     58.26
      WTI (US$/bbl)       $     60.21  $     70.55  $     70.75  $     63.88
    Total revenues (before
     royalties)           $   127,539  $   124,521  $    80,766  $    86,901
    Net income (loss)     $     8,736  $     1,209  $    23,905  $    15,964
      per Trust Unit
       - basic            $      0.08  $      0.01  $      0.38  $      0.27
       - diluted          $      0.08  $      0.01  $      0.38  $      0.27
    Funds from operations $    62,737  $    63,110  $    42,281  $    46,630
    Distributions
     declared             $    58,791  $    60,498  $    53,498  $    44,459The table above highlights the Fund's performance for the fourth quarter
of 2007 and also for the preceding seven quarters. Production significantly
increased in the third quarter of 2006 as the Ketch acquisition that closed on
June 23, 2006 was fully integrated with Advantage. The second quarter of 2007
encountered a temporary production decrease as expected due to several
facility turnarounds that had been planned for that period. The third quarter
of 2007 includes the financial and operating results from the acquired Sound
properties for 26 days, and fourth quarter of 2007 includes the full
integration of the Sound properties. Advantage's revenues and funds from
operations increased significantly beginning in the third quarter of 2006
primarily due to the production from the merger with Ketch and surged again in
the fourth quarter of 2007 due to the Sound acquisition, partially offset by
lower natural gas prices. Net income was lower in the first three quarters of
2007 due to reduced natural gas prices realized during the periods,
amortization of the management internalization consideration and increased
depletion and depreciation expense due to the Ketch and Sound mergers. Net
income increased in the fourth quarter of 2007 due to the full integration of
the Sound acquisition and stronger crude oil prices.

    Critical Accounting Estimates

    The preparation of financial statements in accordance with GAAP requires
Management to make certain judgments and estimates. Changes in these judgments
and estimates could have a material impact on the Fund's financial results and
financial condition.
    Management relies on the estimate of reserves as prepared by the Fund's
independent qualified reserves evaluator. The process of estimating reserves
is critical to several accounting estimates. The process of estimating
reserves is complex and requires significant judgments and decisions based on
available geological, geophysical, engineering and economic data. These
estimates may change substantially as additional data from ongoing development
and production activities becomes available and as economic conditions impact
crude oil and natural gas prices, operating costs, royalty burden changes, and
future development costs. Reserve estimates impact net income through
depletion and depreciation of fixed assets, the provision for asset retirement
costs and related accretion expense, and impairment calculations for fixed
assets and goodwill. The reserve estimates are also used to assess the
borrowing base for the Fund's credit facilities. Revision or changes in the
reserve estimates can have either a positive or a negative impact on net
income and the borrowing base of the Fund.
    Management's process of determining the provision for future income
taxes, the provision for asset retirement obligation costs and related
accretion expense, and the fair values assigned to any acquired company's
assets and liabilities in a business combination is based on estimates. These
estimates are significant and can include reserves, future production rates,
future crude oil and natural gas prices, future costs, future interest rates,
future tax rates and other relevant assumptions. Revisions or changes in any
of these estimates can have either a positive or a negative impact on asset
and liability values and net income.

    Financial Reporting Update

    Convergence of Canadian GAAP with International Financial Reporting
    Standards

    In 2006, Canada's Accounting Standards Board ("AcSB") issued a strategic
plan that will result in Canadian GAAP, as it applies to publicly accountable
entities, being converged with International Financial Reporting Standards
over a transitional period, initially indicated to be five years. The AcSB
released a detailed implementation plan in May 2007 and the Fund will consider
the effects that this implementation plan might have on the consolidated
financial statements during the transition period.

    Capital Disclosures

    The CICA has issued section 1535 "Capital Disclosures", which will be
effective January 1, 2008 for the Fund. Section 1535 will require the Fund to
provide additional disclosures relating to capital and how it is managed. It
is not anticipated that the adoption of section 1535 will impact the amounts
reported in the Fund's financial statements as they primarily relate to
disclosure.

    Controls and Procedures

    The Fund has established procedures and internal control systems to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in
accordance with GAAP. Management of the Fund is committed to providing timely,
accurate and balanced disclosure of all material information about the Fund.
Disclosure controls and procedures are in place to ensure all ongoing
reporting requirements are met and material information is disclosed on a
timely basis. The Chief Executive Officer and Vice-President, Finance and
Chief Financial Officer, individually, sign certifications that the financial
statements, together with the other financial information included in the
regular filings, fairly present in all material respects the financial
condition, results of operations, and cash flows as of the dates and for the
periods presented in the filings. The certifications further acknowledge that
the filings do not contain any untrue statement of a material fact or omit to
state a material fact required to be stated or that is necessary to make a
statement not misleading in light of the circumstances under which it was
made, with respect to the period covered by the filings. During 2007, there
were no significant changes that would materially affect, or are reasonably
likely to materially affect, the internal controls over financial reporting.
    Because of inherent limitations, internal control over financial
reporting may not prevent or detect misstatements and even those systems
determined to be effective can provide only reasonable assurance with respect
to the financial statement preparation and presentation. Further, projections
of any evaluation of effectiveness to future periods are subject to the risk
that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.

    Evaluation of Disclosure Controls and Procedures

    The Fund has established a Disclosure Committee consisting of seven
executive members with the responsibility of overseeing the Fund's disclosure
practices and designing disclosure controls and procedures to ensure that all
material information is communicated to the Disclosure Committee. All written
public disclosures are reviewed and approved by at least one member of the
Disclosure Committee prior to issuance. Additionally, the Disclosure Committee
assists the Chief Executive Officer and Chief Financial Officer of the Fund in
making certifications with respect to the disclosure controls of the Fund
required under applicable regulations and ensures that the Board of Directors
is promptly and fully informed regarding potential disclosure issues facing
the Fund.
    The Fund's Management is responsible for establishing and maintaining
effective internal control over financial reporting. Management of Advantage,
including our Chief Executive Officer and Vice-President, Finance and Chief
Financial Officer, has evaluated the effectiveness of the design and operation
of the disclosure controls and procedures as of December 31, 2007. Based on
that evaluation, Management has concluded that the disclosure controls and
procedures are effective as of the end of the period, in all material
respects. It should be noted that while the Chief Executive Officer and Chief
Financial Officer believe that the Fund's design of disclosure controls and
procedures provide a reasonable level of assurance that they are effective,
they do not expect that the disclosure controls and procedures or internal
control over financial reporting will prevent all errors and fraud. A control
system does not provide absolute, but rather is designed to provide
reasonable, assurance that the objective of the control system is met.

    Corporate Governance

    The Board of Directors' mandate is to supervise the management of the
business and affairs of the Fund including the business and affairs of the
Fund delegated to AOG. In particular, all decisions relating to: (i) the
acquisition and disposition of properties for a purchase price or proceeds in
excess of $5 million; (ii) the approval of annual operating and capital
expenditure budgets; and (iii) the establishment of credit facilities and the
issuance of additional Trust Units, will be made by the Board.
    Computershare Trust Company of Canada, the Trustee of the Fund, has
delegated certain matters to the Board of Directors. These include all
decisions relating to issuance of additional Trust Units and the determination
of the amount of distributions. Any amendment to any material contract to
which the Fund is a party will require the approval of the Board of Directors
and, in some cases, Unitholder approval.
    The Board of Directors meets regularly to review the business and affairs
of the Fund and AOG and to make any required decisions. The Board of Directors
consists of ten members, seven of whom are unrelated to the Fund. The
Independent Reserve Evaluation Committee and Audit Committee each have three
members, all of whom are independent. The Human Resources, Compensation and
Corporate Governance Committee has four members, all of whom are independent.
One member of the Audit Committee has been designated a "Financial Expert" as
defined in applicable regulatory guidance. In addition, the Chairman of the
Board is not related and is not an executive officer of the Fund.
    The Board of Directors approved and Management implemented a Code of
Business Conduct and Ethics. The purpose of the code is to lay out the
expectation for the highest standards of professional and ethical conduct from
our directors, officers and employees. The code reflects our commitment to a
culture of honesty, integrity and accountability and outlines the basic
principles and policies with which all employees are expected to comply. Our
Code of Business Conduct and Ethics is available on our website at
www.advantageincome.com.
    As a Canadian issuer listed on the New York Stock Exchange (the "NYSE"),
Advantage is not required to comply with most of the NYSE rules and listing
standards and instead may comply with domestic requirements. As a foreign
private issuer, Advantage is only required to comply with four of the NYSE
Rules: (i) have an audit committee that satisfies the requirements of the
United States Securities Exchange Act of 1934; (ii) the Chief Executive
Officer must promptly notify the NYSE in writing after an executive officer
becomes aware of any material non-compliance with the applicable NYSE Rules;
(iii) submit an executed annual written affirmation, as well as an interim
affirmation each time a change occurs to the audit committee; and (iv) provide
a brief description of any significant differences between its corporate
governance practices and those followed by U.S. companies listed under the
NYSE. Advantage has reviewed the NYSE listing standards and confirms that its
corporate governance practices do not differ significantly from such
standards.
    A further discussion of the Fund's corporate governance practices can be
found in the Management Proxy Circular.

    Outlook

    The Fund's 2008 Budget, as approved by the Board of Directors, retains a
high degree of activity and focus on drilling in many of our key properties
where a high level of success was realized through 2007. Capital has also been
directed to delineate a natural gas resource play at Glacier in Northwest
Alberta and to accommodate facility expansions and enhanced recovery schemes
as necessary. New drill bit additions are expected to be more effective in
replacing production as corporate declines have continued to subside
throughout 2007. Advantage's production now contains very little flush
production from high impact wells and concentrated drilling programs (from
2004 and 2005 activities) creating a balanced and predictable platform.
    During the fourth quarter of 2007, production was on-track and operating
costs were lower than expected. We realized some impact to our production due
to third party related facilities outages in December, however, continued
efforts in operating cost optimization is providing efficiency gains. For
2008, we are forecasting production to be in the range of 32,000 to
34,000 boe/d. Advantage's 2008 capital expenditures budget is estimated to be
approximately $125 to $145 million with approximately 143 gross (88 net)
wells. An active winter program at Martin Creek, Glacier, Nevis and Willesden
Green will be followed by a relatively even paced program in Q3 and Q4 of
2008. Capital spending is estimated to be split evenly between oil and gas
activities.
    Per unit operating costs on an annual basis are expected to range between
the $12.50 to $13.30/boe range. Advantage is continuing with several operating
cost reduction initiatives throughout 2008 to help offset these increases and
we have begun to realize some key achievements in this area. We expect
industry servicing and maintenance costs to generally remain stable in 2008
with some potential for natural gas related costs to increase during the
latter part of 2008 if natural gas prices strengthen at that time.
    On October 25, 2007, the Alberta Provincial Government announced changes
to royalties for conventional oil, natural gas and oil sands that will become
effective January 1, 2009. Preliminary indications are that the changes will
have a negligible impact on Advantage since we have a significant number of
lower rate wells within our long life properties producing in Alberta.
Advantage also has a significant Horseshoe Canyon coal bed methane drilling
inventory that can be pursued which will also have a favorable royalty
treatment due to lower rate per well characteristics. Our exposure in
Northeast British Columbia and Saskatchewan also affords us further
flexibility with mitigating the royalty impact in our capital program. We
expect our royalty rates to range from 17% to 19% in 2008.
    Advantage's funds from operations in 2008 will continue to be impacted by
the volatility of crude oil and natural gas prices and the $US/$Canadian
exchange rate. Additional hedging has been completed for 2008 to i) stabilize
cash flows and ii) ensure that the Fund's capital program is substantially
funded out of cash flow. Approximately 51% of our natural gas production, net
of royalties, is now hedged for the 2008 calendar year at a floor of
$7.43/mcf. Advantage has also hedged 38% of its 2008 crude oil production, net
of royalties, at an average price of $94.07/bbl.
    Advantage will continue to follow its strategy of acquiring properties
that provide low risk development opportunities and enhance long-term cash
flow. Advantage will also continue to focus on low cost production and reserve
additions through low to medium risk development drilling opportunities that
have arisen as a result of the acquisitions completed in prior years and from
the significant inventory of drilling opportunities that has resulted from the
Ketch and Sound mergers.
    Looking forward, Advantage's high quality assets combined with a greater
than five year drilling inventory, hedging program and excellent tax pools
provides many options for the Fund and we are committed to maximizing value
generation for our Unitholders.

    Sensitivities

    The following table displays the current estimated sensitivity on funds
from operations and funds from operations per Trust Unit to changes in
production, commodity prices, exchange rates and interest rates for 2008.Annual
                                                                 Funds from
                                                      Annual     Operations
                                                    Funds from      per
                                                    Operations   Trust Unit
                                                      ($000)   ($/Trust Unit)
    -------------------------------------------------------------------------
    Natural gas
      AECO monthly price change of $1.00/mcf        $    17,800  $      0.12
      Production change of 6.0 mmcf/d               $     7,200  $      0.05
    Crude oil and NGLs
      WTI price change of US$10.00/bbl              $    27,900  $      0.20
      Production change of 1,000 bbls/d             $    22,200  $      0.16
    $US/$Canadian exchange rate change of $0.01     $     5,900  $      0.04
    Interest rate change of 1%                      $     5,600  $      0.04Additional Information

    Additional information relating to Advantage can be found on SEDAR at
www.sedar.com and the Fund's website at www.advantageincome.com. Such other
information includes the annual information form, the annual information
circular - proxy statement, press releases, material contracts and agreements,
and other financial reports. The annual information form will be of particular
interest for current and potential Unitholders as it discusses a variety of
subject matter including the nature of the business, structure of the Fund,
description of our operations, general and recent business developments, risk
factors, reserves data and other oil and gas information.CONSOLIDATED FINANCIAL STATEMENTS

    Consolidated Balance Sheets
                                                   December 31,  December 31,
    (thousands of dollars)                                2007          2006
    -------------------------------------------------------------------------
    Assets
    Current assets
      Accounts receivable                          $    95,474   $    79,537
      Prepaid expenses and deposits                     21,988        16,878
      Derivative asset (note 12)                         7,027         9,840
    -------------------------------------------------------------------------
                                                       124,489       106,255
    Deposit on property acquisition                          -         1,410
    Derivative asset (note 12)                             174           593
    Fixed assets (note 4)                            2,177,346     1,753,058
    Goodwill (note 3)                                  120,271       120,271
    -------------------------------------------------------------------------
                                                   $ 2,422,280   $ 1,981,587
    -------------------------------------------------------------------------
    Liabilities
    Current liabilities
      Accounts payable and accrued liabilities     $   122,087   $   116,109
      Distributions payable to Unitholders              16,592        18,970
      Current portion of capital lease obligations
       (note 5)                                          1,537         2,527
      Current portion of convertible debentures
       (note 6)                                          5,333         1,464
      Derivative liability (note 12)                     2,242             -
    -------------------------------------------------------------------------
                                                       147,791       139,070
    Derivative liability (note 12)                       2,778             -
    Capital lease obligations (note 5)                   5,653           305
    Bank indebtedness (note 7)                         547,426       410,574
    Convertible debentures (note 6)                    212,203       170,819
    Asset retirement obligations (note 8)               60,835        34,324
    Future income taxes (note 9)                        66,727        61,939
    -------------------------------------------------------------------------
                                                     1,043,413       817,031
    -------------------------------------------------------------------------
    Unitholders' Equity
    Unitholders' capital (note 10)                   2,027,065     1,592,758
    Convertible debentures equity component (note 6)     9,632         8,041
    Contributed surplus (note 10)                        2,005           863
    Accumulated deficit (note 11)                     (659,835)     (437,106)
    -------------------------------------------------------------------------
                                                     1,378,867     1,164,556
    -------------------------------------------------------------------------
                                                   $ 2,422,280   $ 1,981,587
    -------------------------------------------------------------------------
    Commitments (note 14)

    see accompanying Notes to Consolidated Financial Statements



    Consolidated Statements of Income (Loss),
    Comprehensive Income and Accumulated Deficit

                                                    Year ended    Year ended
    (thousands of dollars, except                  December 31,  December 31,
     for per Trust Unit amounts)                          2007          2006
    -------------------------------------------------------------------------
    Revenue
      Petroleum and natural gas                    $   538,764   $   414,430
      Realized gain on derivatives (note 12)            18,594         5,297
      Unrealized gain (loss) on derivatives (note 12)  (11,049)       10,242
      Royalties, net of Alberta Royalty Credit         (98,614)      (76,456)
    -------------------------------------------------------------------------
                                                       447,695       353,513
    -------------------------------------------------------------------------
    Expenses
      Operating                                        127,309        82,911
      General and administrative                        21,449        13,738
      Management fee (note 13)                               -           887
      Performance incentive (note 13)                        -         2,380
      Management internalization (note 13)              15,708        13,449
      Interest                                          24,351        18,258
      Interest and accretion on convertible
       debentures                                       17,436        13,316
      Depletion, depreciation and accretion            272,175       194,309
    -------------------------------------------------------------------------
                                                       478,428       339,248
    -------------------------------------------------------------------------
    Income (loss) before taxes and non-controlling
     interest                                          (30,733)       14,265
    Future income tax reduction (note 9)               (24,642)      (37,087)
    Income and capital taxes (note 9)                    1,444         1,509
    -------------------------------------------------------------------------
                                                       (23,198)      (35,578)
    -------------------------------------------------------------------------
    Net income (loss) before non-controlling interest   (7,535)       49,843
    Non-controlling interest                                 -            29
    -------------------------------------------------------------------------
    Net income (loss) and comprehensive income (loss)   (7,535)       49,814
    Accumulated deficit, beginning of year            (437,106)     (269,674)
    Distributions declared                            (215,194)     (217,246)
    -------------------------------------------------------------------------
    Accumulated deficit, end of year               $  (659,835)  $  (437,106)
    -------------------------------------------------------------------------
    Net income (loss) per Trust Unit (note 10)
      Basic                                        $     (0.06)  $      0.62
      Diluted                                      $     (0.06)  $      0.61
    -------------------------------------------------------------------------

    see accompanying Notes to Consolidated Financial Statements



    Consolidated Statements of Cash Flows

                                                    Year ended    Year ended
                                                   December 31,  December 31,
    (thousands of dollars)                                2007          2006
    -------------------------------------------------------------------------
    Operating Activities
    Net income (loss)                              $    (7,535)  $    49,814
    Add (deduct) items not requiring cash:
      Unrealized loss (gain) on derivatives             11,049       (10,242)
      Unit-based compensation                              929             -
      Performance incentive                                  -         2,380
      Management internalization                        15,708        13,449
      Non-cash interest expense                            890             -
      Accretion on convertible debentures                2,569         2,106
      Depletion, depreciation and accretion            272,175       194,309
      Future income tax                                (24,642)      (37,087)
      Non-controlling interest                               -            29
    Expenditures on asset retirement                    (6,951)       (5,974)
    Changes in non-cash working capital                (15,060)       20,303
    -------------------------------------------------------------------------
    Cash provided by operating activities              249,132       229,087
    -------------------------------------------------------------------------
    Financing Activities
    Units issued, net of costs (note 10)               104,215       141,908
    Debentures redeemed (note 6)                       (19,406)            -
    Increase (decrease) in bank indebtedness            28,893       (30,767)
    Reduction of capital lease obligations              (3,184)       (1,019)
    Distributions to Unitholders                      (170,915)     (185,015)
    -------------------------------------------------------------------------
    Cash used in financing activities                  (60,397)      (74,893)
    -------------------------------------------------------------------------
    Investing Activities
    Expenditures on property and equipment            (148,725)     (159,487)
    Property acquisitions                              (16,051)         (244)
    Property dispositions                                1,037         8,727
    Acquisition of Sound Energy Trust (note 3)         (22,307)            -
    Acquisition of Ketch Resources Trust (note 3)            -       (10,109)
    Changes in non-cash working capital                 (2,689)        6,919
    -------------------------------------------------------------------------
    Cash used in investing activities                 (188,735)     (154,194)
    -------------------------------------------------------------------------
    Net change in cash                                       -             -
    Cash, beginning of year                                  -             -
    -------------------------------------------------------------------------
    Cash, end of year                              $         -   $         -
    -------------------------------------------------------------------------
    Supplementary Cash Flow Information
      Interest paid                                $    42,017   $    34,680
      Taxes paid                                   $     2,062   $     1,783

    see accompanying Notes to Consolidated Financial Statements



    NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

    December 31, 2007

    All tabular amounts in thousands except as otherwise indicated

    1.  Business and Structure of the Fund

        Advantage Energy Income Fund ("Advantage" or the "Fund") was formed
        on May 23, 2001 as a result of a plan of arrangement. For Canadian
        tax purposes, Advantage is an open-ended unincorporated mutual fund
        trust created under the laws of the Province of Alberta pursuant to a
        Trust Indenture originally dated April 17, 2001, and as occasionally
        amended, between Advantage Oil & Gas Ltd. ("AOG") and Computershare
        Trust Company of Canada, as trustee. The Fund commenced operations on
        May 24, 2001. The beneficiaries of the Fund are the holders of the
        Trust Units (the "Unitholders").

        The principal undertaking of the Fund is to indirectly acquire and
        hold interests in petroleum and natural gas properties and assets
        related thereto. The business of the Fund is carried on by its
        wholly-owned subsidiary, AOG. The Fund's primary assets are currently
        the common shares of AOG, a royalty in the producing properties of
        AOG (the "AOG Royalty") and notes of AOG (the "AOG Notes"). The
        Fund's strategy, through AOG, is to minimize exposure to exploration
        risk while focusing on growth through acquisition and development of
        producing crude oil and natural gas properties.

        The purpose of the Fund is to distribute available cash flow to
        Unitholders on a monthly basis in accordance with the terms of the
        Trust Indenture. The Fund's available cash flow includes principal
        repayments and interest income earned from the AOG Notes, royalty
        income earned from the AOG Royalty, and any dividends declared on the
        common shares of AOG less any expenses of the Fund including interest
        on convertible debentures. Cash received on the AOG Notes, AOG
        Royalty and common shares of AOG result in the effective transfer of
        the economic interest in the properties of AOG to the Fund. However,
        while the royalty is a contractual interest in the properties owned
        by AOG, it does not confer ownership in the underlying resource
        properties. Distributions from the Fund to Unitholders are entirely
        discretionary and are determined by Management and the Board of
        Directors. We closely monitor our distribution policy considering
        forecasted cash flows, optimal debt levels, capital spending
        activity, taxability to Unitholders, working capital requirements,
        and other potential cash expenditures. Distributions are announced
        monthly and are based on the cash available after retaining a portion
        to meet such spending requirements. The level of distributions are
        primarily determined by cash flows received from the production of
        oil and natural gas from existing Canadian resource properties and
        are highly dependent upon our success in exploiting the current
        reserve base and acquiring additional reserves. Furthermore, monthly
        distributions we pay to Unitholders are highly dependent upon the
        prices received for such oil and natural gas production. It is our
        long-term objective to provide stable and sustainable distributions
        to the Unitholders, while continuing to grow the Fund.

    2.  Summary of Significant Accounting Policies

        The Management of the Fund prepares its consolidated financial
        statements in accordance with Canadian generally accepted accounting
        principles ("Canadian GAAP") and all amounts are stated in Canadian
        dollars. The preparation of consolidated financial statements
        requires Management to make estimates and assumptions that affect the
        reported amount of assets, liabilities and equity and disclosures of
        contingencies at the date of the consolidated financial statements
        and the reported amounts of revenues and expenses during the period.
        The following significant accounting policies are presented to assist
        the reader in evaluating these consolidated financial statements and,
        together with the notes, should be considered an integral part of the
        consolidated financial statements.

        (a) Consolidation and joint operations

        These consolidated financial statements include the accounts of the
        Fund and all subsidiaries, including AOG. All intercompany balances
        and transactions have been eliminated.

        The Fund conducts exploration and production activities jointly with
        other participants. The accounts of the Fund reflect its
        proportionate interest in such joint operations.

        (b) Fixed assets

           (i) Petroleum and natural gas properties

           The Fund follows the "full cost" method of accounting in
           accordance with the guideline issued by the Canadian Institute of
           Chartered Accountants ("CICA") whereby all costs associated with
           the acquisition of and the exploration for and development of
           petroleum and natural gas reserves, whether productive or
           unproductive, are capitalized in a Canadian cost centre and
           charged to income as set out below. Such costs include lease
           acquisition, drilling and completion, production facilities, asset
           retirement costs, geological and geophysical costs and overhead
           expenses related to exploration and development activities.

           Gains or losses are not recognized upon disposition of petroleum
           and natural gas properties unless crediting the proceeds against
           accumulated costs would result in a change in the rate of
           depletion and depreciation of 20% or more.

           Depletion of petroleum and natural gas properties and depreciation
           of lease, well equipment and production facilities is provided on
           accumulated costs using the "unit-of-production" method based on
           estimated net proved petroleum and natural gas reserves, before
           royalties, as determined by independent engineers. For purposes of
           the depletion and depreciation calculation, proved petroleum and
           natural gas reserves are converted to a common unit-of-measure on
           the basis of one barrel of oil or liquids being equal to six
           thousand cubic feet of natural gas.

           The depletion and depreciation cost base includes total
           capitalized costs, less costs of unproved properties, plus a
           provision for future development costs of proved undeveloped
           reserves. Costs of acquiring and evaluating unproved properties
           are excluded from depletion calculations until it is determined
           whether or not proved reserves are attributable to the properties
           or impairment occurs.

           Petroleum and natural gas assets are evaluated in each reporting
           period to determine that the carrying amount in a cost centre is
           recoverable and does not exceed the fair value of the properties
           in the cost centre (the "ceiling test"). The carrying amounts are
           assessed to be recoverable when the sum of the undiscounted net
           cash flows expected from the production of proved reserves, the
           lower of cost and market of unproved properties and the cost of
           major development projects exceeds the carrying amount of the cost
           centre. When the carrying amount is not assessed to be
           recoverable, an impairment loss is recognized to the extent that
           the carrying amount of the cost centre exceeds the sum of the
           discounted net cash flows expected from the production of proved
           and probable reserves, the lower of cost and market of unproved
           properties and the cost of major development projects of the cost
           centre. The net cash flows are estimated using expected future
           product prices and costs and are discounted using a risk-free
           interest rate. There has been no impairment of the Fund's
           petroleum and natural gas properties since inception.

           (ii) Furniture and equipment

           The Fund records furniture and equipment at cost and provides
           depreciation on the declining balance method at a rate of 20% per
           annum which is designed to amortize the cost of the assets over
           their estimated useful lives.

        (c) Goodwill

        Goodwill is the excess purchase price of a business over the fair
        value of identifiable assets and liabilities acquired. Goodwill is
        stated at cost less impairment and is not amortized. Goodwill
        impairment is assessed at year-end, or as economic events dictate, by
        comparing the fair value of the reporting unit (the Fund) to its
        carrying value, including goodwill. If the fair value of the Fund is
        less than its carrying value, a goodwill impairment loss is
        recognized by allocating the fair value of the Fund to the
        identifiable assets and liabilities as if the Fund had been acquired
        in a business acquisition for a purchase price equal to the fair
        value. The excess of the fair value of the Fund over the values
        assigned to the identifiable assets and liabilities is the implied
        fair value of the goodwill. Any excess of the carrying value of the
        goodwill over the implied fair value is the impairment amount and is
        charged to income in the period incurred. There has been no
        impairment of the Fund's goodwill since inception.

        (d) Distributions

        Distributions are calculated on an accrual basis and are paid to
        Unitholders monthly.

        (e) Financial instruments

        Effective January 1, 2007, the Fund adopted CICA Handbook sections
        3855 "Financial Instruments - Recognition and Measurement", 3862
        "Financial Instruments - Disclosures", 3863 "Financial Instruments -
        Presentation", and 3865 "Hedges".

        Section 3855 "Financial Instruments - Recognition and Measurement"
        establishes criteria for recognizing and measuring financial
        instruments including financial assets, financial liabilities and
        non-financial derivatives. Under this standard, all financial
        instruments must initially be recognized at fair value on the balance
        sheet. Measurement of financial instruments subsequent to the initial
        recognition, as well as resulting gains and losses, are recorded
        based on how each financial instrument was initially classified. The
        Fund has classified each identified financial instrument into the
        following categories: held for trading, loans and receivables, held
        to maturity investments, available for sale financial assets, and
        other financial liabilities. Held for trading financial instruments
        are measured at fair value with gains and losses recognized in
        earnings immediately. Available for sale financial assets are
        measured at fair value with gains and losses, other than impairment
        losses, recognized in other comprehensive income and transferred to
        earnings when the asset is derecognized. Loans and receivables, held
        to maturity investments and other financial liabilities are
        recognized at amortized cost using the effective interest method and
        impairment losses are recorded in earnings when incurred. Upon
        adoption and with all new financial instruments, an election is
        available that allows entities to classify any financial instrument
        as held for trading. Only those financial assets and liabilities that
        must be classified as held for trading by the standard have been
        classified as such by the Fund. As the Fund frequently utilizes non-
        financial derivative instruments to manage market risk associated
        with volatile commodity prices, such instruments must be classified
        as held for trading and recorded on the balance sheet at fair value
        as derivative assets and liabilities. Section 3865 "Hedges" provides
        an alternative to recognizing gains and losses on derivatives in
        earnings if the instrument is designated as part of a hedging
        relationship and meets the necessary criteria. Under the alternative
        hedge accounting treatment, gains and losses on derivatives
        classified as effective cash flow hedges are included in other
        comprehensive income until the time at which the hedged item is
        realized. The Fund does not utilize derivative instruments for
        speculative purposes but has elected not to apply hedge accounting.
        Therefore, gains and losses on these instruments are recorded as
        unrealized gains and losses on derivatives in the consolidated
        statement of income, comprehensive income and accumulated deficit in
        the period they occur and as realized gains and losses on derivatives
        when the contracts are settled. Since unrealized gains and losses on
        derivatives are non-cash items, there is no impact on the statement
        of cash flows as a result of their recognition.

        In some instances, derivative financial instruments can be embedded
        within other contracts. Embedded derivatives within a host contract
        must be recorded separately from the host contract when their
        economic characteristics and risks are not clearly and closely
        related to those of the host contract, the terms of the embedded
        derivatives are the same as those of a freestanding derivative, and
        the combined contract is not classified as held for trading or
        designated at fair value. The Fund selected January 1, 2003, as its
        accounting transition date for any potential embedded derivatives and
        has not identified any embedded derivatives that would require
        separation from the host contract and fair value accounting.

        Transaction costs are frequently attributed to the acquisition or
        issue of a financial asset or liability. Section 3855 requires that
        such transaction costs incurred on held for trading financial
        instruments be expensed immediately. For other financial instruments,
        an entity can adopt an accounting policy of either expensing
        transaction costs as they occur or adding such transaction costs to
        the fair value of the financial instrument. The Fund has chosen a
        policy of adding transaction costs to the fair value initially
        recognized for financial assets and liabilities that are not
        classified as held for trading.

        The Fund has adopted the new standards prospectively as required
        which allows amendments to the carrying values of financial
        instruments, effective as of the adoption date, to be recognized as
        an adjustment to the beginning balance of accumulated deficit. As the
        new standards have not resulted in any significant changes to the
        recognition and measurement of the Fund's financial instruments, no
        adjustment to accumulated deficit was required. The new standards
        also require several additional disclosures in the notes to the
        financial statements. Among the disclosures required, the Fund must
        disclose the exposure to various risks associated with financial
        instruments and the policies that exist to manage these risks.

        (f) Comprehensive income

        Effective January 1, 2007, the Fund adopted CICA Handbook section
        1530 "Comprehensive Income". Comprehensive income consists of net
        income and other comprehensive income ("OCI") with amounts included
        in OCI shown net of tax. Accumulated other comprehensive income is a
        new equity category comprised of the cumulative amounts of OCI. To
        date, the Fund does not have any adjustments in OCI and therefore
        comprehensive income is currently equal to net income.

        (g) Convertible debentures

        The Fund's convertible debentures are financial liabilities
        consisting of a liability with an embedded conversion feature. As
        such, the debentures are segregated between liabilities and equity
        based on the relative fair market value of the liability and equity
        portions. Therefore, the debenture liabilities are presented at less
        than their eventual maturity values. The liability and equity
        components are further reduced for issuance costs initially incurred.
        The discount of the liability component as compared to maturity value
        is accreted by the "effective interest" method over the debenture
        term and expensed accordingly. As debentures are converted to Trust
        Units, an appropriate portion of the liability and equity components
        are transferred to Unitholders' capital.

        (h) Asset retirement obligations

        The Fund follows the "asset retirement obligation" method of
        recording the future cost associated with removal, site restoration
        and asset retirement costs. The fair value of the liability for the
        Fund's asset retirement obligations is recorded in the period in
        which it is incurred, discounted to its present value using the
        Fund's credit adjusted risk-free interest rate and the corresponding
        amount recognized by increasing the carrying amount of fixed assets.
        The asset recorded is depleted on a "unit-of-production" basis over
        the life of the reserves consistent with the Fund's depletion and
        depreciation policy for petroleum and natural gas properties. The
        liability amount is increased each reporting period due to the
        passage of time and the amount of accretion is charged to income in
        the period. Revisions to the estimated timing of cash flows or to the
        original estimated undiscounted cost could also result in an increase
        or decrease to the obligation. Actual costs incurred upon settlement
        of the retirement obligations are charged against the obligation to
        the extent of the liability recorded.

        (i) Income taxes

        The Fund is considered an open-ended unincorporated mutual fund trust
        under the Income Tax Act (Canada). Any taxable income is allocated to
        the Unitholders and therefore no provision for current income taxes
        relating to the Fund is included in these financial statements.

        The Fund and its subsidiaries follow the "liability" method of
        accounting for income taxes. Under this method future tax assets and
        liabilities are determined based on differences between financial
        reporting and income tax bases of assets and liabilities, and are
        measured using substantially enacted tax rates and laws expected to
        apply when the differences reverse. The effect on future tax assets
        and liabilities of a change in tax rates is recognized in net income
        in the period in which the change is substantially enacted.

        (j) Unit-based compensation

        Advantage accounts for compensation expense based on the "fair value"
        of rights granted under its unit-based compensation plans. The Fund
        has Trust Units held in escrow relating to the management
        internalization (note 13) as well as a unit-based compensation plan
        for external directors of the Fund, a Restricted Trust Unit Plan and
        Trust Units issuable for the retention of certain employees of the
        Fund (note 10).

        The escrowed Trust Units relating to the management internalization
        vest equally over three years, the period during which employees are
        required to provide service to receive the Trust Units. Therefore,
        the management internalization consideration is being deferred and
        amortized into income as management internalization expense over the
        specific vesting periods during which employee services are provided,
        including an estimate of future Trust Unit forfeitures.

        Awards under the external directors' unit-based compensation plan
        vest immediately with associated compensation expense recognized in
        the current period earnings and estimated forfeiture rates are not
        incorporated in the determination of fair value. The compensation
        expense results in the creation of contributed surplus until the
        rights are exercised. Consideration paid upon the exercise of the
        rights together with the amount previously recognized in contributed
        surplus is recorded as an increase in Unitholders' capital.

        Advantage's current employee compensation includes a Restricted Trust
        Unit Plan (the "Plan"), as approved by the Unitholders on June 23,
        2006, and Trust Units issuable for the retention of certain employees
        of the Fund. The Plan authorizes the Board of Directors to grant
        Restricted Trust Units ("RTUs") to directors, officers, or employees
        of the Fund. The number of RTUs granted is based on the Fund's Trust
        Unit return for a calendar year and compared to a peer group approved
        by the Board of Directors. The Trust Unit return is calculated at the
        end of the year and is primarily based on the year-over-year change
        in the Trust Unit price plus distributions. The RTU grants vest one
        third immediately on grant date, with the remaining two thirds
        vesting evenly on the following two yearly anniversary dates. The
        holders of RTUs may elect to receive cash upon vesting in lieu of the
        number of Trust Units to be issued, subject to consent of the Fund.
        Compensation cost related to the Plan is recognized as compensation
        expense over the service period and incorporates the period end Trust
        Unit price, the estimated number of RTUs to vest, and certain
        management estimates. The maximum amount of RTUs granted in any one
        calendar year is limited to 175% of the base salaries of those
        individuals participating in the Plan for such period.

        (k) Revenue recognition

        Revenue associated with the sale of crude oil, natural gas and
        natural gas liquids is recognized when the title and risks pass to
        the purchaser, normally at the pipeline delivery point for natural
        gas and at the wellhead for crude oil.

        (l) Per Trust Unit amounts

        Net income per Trust Unit is calculated using the weighted average
        number of Trust Units outstanding during the year. Diluted net income
        per Trust Unit is calculated using the "if-converted" method to
        determine the dilutive effect of convertible debentures and
        exchangeable shares and the "treasury stock" method for trust unit
        rights granted to directors and the management internalization
        escrowed Trust Units.

        (m) Measurement uncertainty

        The amounts recorded for depletion and depreciation of property and
        equipment, the provision for asset retirement obligation costs and
        related accretion expense, impairment calculations for fixed assets
        and goodwill, derivative fair value calculations, future income tax
        provisions, as well as fair values assigned to any identifiable
        assets and liabilities in business combinations are based on
        estimates. These estimates are significant and include proved and
        probable reserves, future production rates, future crude oil and
        natural gas prices, future costs, future interest rates, fair value
        assessments, and other relevant assumptions. By their nature, these
        estimates are subject to measurement uncertainty and the effect on
        the consolidated financial statements of changes in such estimates in
        future years could be material.

        (n) Accounting changes

        Effective January 1, 2007, the Fund adopted the revised
        recommendations of CICA section 1506 "Accounting Changes". The new
        recommendations permit voluntary changes in accounting policy only if
        they result in financial statements which provide more reliable and
        relevant information. Accounting policy changes 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 the changes in earnings. The
        guidance was effective for all changes in accounting polices, changes
        in accounting estimates and corrections of prior period errors
        initiated in periods beginning on or after January 1, 2007.

        (o) Recent accounting pronouncements issued but not implemented

        The CICA has issued section 1535 "Capital Disclosures", which will be
        effective January 1, 2008 for the Fund. Section 1535 will require the
        Fund to provide additional disclosures relating to capital and how it
        is managed. It is not anticipated that the adoption of section 1535
        will impact the amounts reported in the Fund's financial statements
        as they primarily relate to disclosure.

        (p) Comparative figures

        Certain comparative figures have been reclassified to conform to the
        current year's presentation.

    3.  Acquisitions

        (a) Sound Energy Trust

        On September 5, 2007, Advantage acquired all of the issued and
        outstanding Trust Units and Exchangeable Shares of Sound Energy Trust
        ("Sound") for $21.4 million cash consideration, 16,977,184 Advantage
        Trust Units and $0.9 million of acquisition costs. Sound Unitholders
        and Exchangeable Shareholders could elect to receive 0.30 Advantage
        Trust Units for each Sound Trust Unit or receive $0.66 in cash and
        0.2557 Advantage Trust Units for each Sound Trust Unit. All of the
        Sound Exchangeable Shares were exchanged for Advantage Trust Units on
        the same ratio as the Sound Trust Units based on the conversion ratio
        in effect at the effective date of the acquisition. Sound was an
        energy trust engaged in the development, acquisition and production
        of, natural gas and crude oil in western Canada. The acquisition is
        being accounted for using the "purchase method" with the results of
        operations included in the consolidated financial statements as of
        the closing date of the acquisition.

        The purchase price has been allocated as follows:

        Net assets acquired and
        liabilities assumed:            Consideration:

        Fixed assets      $  509,656    16,977,184 Trust Units    $  228,852
                                         issued
        Accounts
         receivable           27,433    Cash                          21,403
        Prepaid expenses
         and deposits          3,873    Acquisition costs incurred       904
        Derivative asset,                                         -----------
         net                   2,797                              $  251,159
        Bank indebtedness   (107,959)                             -----------
        Convertible
         debentures         (101,553)
        Accounts payable
         and accrued
         liabilities         (35,396)
        Future income taxes  (29,430)
        Asset retirement
         obligations         (16,695)
        Capital lease
         obligations          (1,567)
                          -----------
                          $  251,159
                          -----------

        The value of the Trust Units issued as consideration was determined
        based on the weighted average trading value of Advantage Trust Units
        during the two-day period before and after the terms of the
        acquisition were agreed to and announced. The allocation of the
        purchase price has been revised due to the realization of estimates
        and is subject to further refinement as additional cost estimates and
        tax balances are finalized.

        (b) Ketch Resources Trust

        On June 23, 2006, Advantage acquired all of the issued and
        outstanding Trust Units of Ketch Resources Trust ("Ketch") in return
        for 32,870,465 Advantage Trust Units, utilizing an exchange ratio of
        0.565 Advantage Trust Units for each Ketch Trust Unit outstanding.
        Ketch was an energy trust engaged in the development, acquisition and
        production of, natural gas and crude oil in western Canada. The
        acquisition is being accounted for using the "purchase method" with
        the results of operations included in the consolidated financial
        statements as of the closing date of the acquisition. The purchase
        price has been allocated as follows:

        Net assets acquired and
         liabilities assumed:           Consideration:

        Fixed assets      $  877,463    32,870,465 Trust Units    $  688,636
                                         issued
        Goodwill              74,798    Acquisition costs incurred    10,109
                                                                  -----------
        Accounts receivable   55,806                              $  698,745
        Prepaid expenses                                          -----------
         and deposits          6,406
        Cash                   2,713
        Bank indebtedness   (191,578)
        Convertible
         debentures          (69,952)
        Accounts payable     (46,834)
        Asset retirement
         obligations          (7,930)
        Capital lease
         obligation           (2,147)
                          -----------
                          $  698,745
                          -----------

        The value of the Trust Units issued as consideration was determined
        based on the weighted average trading value of Advantage Trust Units
        during the two-day period before and after the terms of the
        acquisition were agreed to and announced.

    4.  Fixed Assets

                                                     Accumulated
                                                   Depletion and   Net Book
        December 31, 2007                 Cost      Depreciation     Value
        ---------------------------------------------------------------------
        Petroleum and natural gas
         properties                    $ 3,016,243  $   844,671  $ 2,171,572
        Furniture and equipment             10,548        4,774        5,774
        ---------------------------------------------------------------------
                                       $ 3,026,791  $   849,445  $ 2,177,346
        ---------------------------------------------------------------------

                                                     Accumulated
                                                   Depletion and   Net Book
        December 31, 2006                 Cost      Depreciation     Value
        ---------------------------------------------------------------------
        Petroleum and natural gas
         properties                    $ 2,324,948  $   576,707  $ 1,748,241
        Furniture and equipment              8,175        3,358        4,817
        ---------------------------------------------------------------------
                                       $ 2,333,123  $   580,065  $ 1,753,058
        ---------------------------------------------------------------------

        During the year ended December 31, 2007, Advantage capitalized
        general and administrative expenditures directly related to
        exploration and development activities of $9,653,000 (2006 -
        $6,444,000).

        Costs of $60,238,000 (2006 - $43,467,000) for unproved properties
        have been excluded from the calculation of depletion expense, and
        future development costs of $190,146,000 (2006 - $123,464,000) have
        been included in costs subject to depletion.

        The Fund performed a ceiling test calculation at December 31, 2007 to
        assess the recoverable value of fixed assets. Based on the
        calculation, the carrying amounts are recoverable as compared to the
        sum of the undiscounted net cash flows expected from the production
        of proved reserves based on the following benchmark prices:

                                            WTI        Exchange
                                         Crude Oil       Rate      AECO Gas
        Year                             ($US/bbl)    ($US/$Cdn) ($Cdn/mmbtu)
        ---------------------------------------------------------------------
        2008                               $ 89.61      $  1.00      $  6.51
        2009                               $ 86.01      $  1.00      $  7.22
        2010                               $ 84.65      $  1.00      $  7.69
        2011                               $ 82.77      $  1.00      $  7.70
        2012                               $ 82.26      $  1.00      $  7.61
        2013                               $ 82.81      $  1.00      $  7.78
        ---------------------------------------------------------------------
        Approximate escalation rate after
         2013                                 2.0%            -         2.0%
        ---------------------------------------------------------------------

        Benchmark prices are adjusted for a variety of factors such as
        quality differentials to determine the expected price to be realized
        by the Fund when performing the ceiling test calculation.

    5.  Capital Lease Obligations
        The Fund has capital leases on a variety of fixed assets. Future
        minimum lease payments at December 31, 2007 consist of the following:

        2008                                                         $ 1,906
        2009                                                           2,040
        2010                                                           2,200
        2011                                                           1,925
        ---------------------------------------------------------------------
                                                                       8,071
        Less amounts representing interest                              (881)
        ---------------------------------------------------------------------
                                                                       7,190
        Current portion                                               (1,537)
        ---------------------------------------------------------------------
                                                                     $ 5,653
        ---------------------------------------------------------------------

        On June 23, 2006, Advantage assumed a total capital lease obligation
        of $2.1 million in the acquisition of Ketch (note 3). The lease ends
        in March 2008 and interest expense is recognized at 5.3%.

        During the second quarter of 2007, Advantage entered a new lease
        arrangement that resulted in the recognition of a fixed asset
        addition and capital lease obligation of $4.1 million. The lease
        obligation bears interest at 5.8% and is secured by the related
        equipment. The lease term expires June 2011 with a final purchase
        obligation of $1.5 million at which time ownership of the equipment
        will transfer to Advantage.

        Effective September 4, 2007, Advantage entered a new lease
        arrangement that resulted in the recognition of a fixed asset
        addition and capital lease obligation of $1.8 million. The lease
        obligation bears interest at 6.7% and is secured by the related
        equipment. The lease term expires August 2010 with a final payment
        obligation of $0.7 million. Distributions to Unitholders are not
        permitted if the Fund is in default of such capital lease.

        On September 5, 2007, Advantage assumed two capital lease obligations
        in the acquisition of Sound (note 3) resulting in the recognition of
        capital lease obligations of $1.6 million. Both of the lease
        obligations bear interest at 5.6% and are secured by the related
        equipment. The lease terms expire December 2009 and April 2010 with a
        total final payment obligation of $0.9 million.

        Fixed assets subject to capital leases are depreciated on a "unit-of-
        production" basis over the life of the reserves consistent with the
        Fund's depletion and depreciation policy for petroleum and natural
        gas properties and is included in depletion and depreciation expense.

    6.  Convertible Debentures

        The convertible unsecured subordinated debentures pay interest semi-
        annually and are convertible at the option of the holder into Trust
        Units of Advantage at the applicable conversion price per Trust Unit
        plus accrued and unpaid interest. The details of the convertible
        debentures including fair market values initially assigned and
        issuance costs are as follows:

                                        10.00%     9.00%     8.25%     8.75%
        ---------------------------------------------------------------------
        Trading symbol                  AVN.DB   AVN.DBA   AVN.DBB   AVN.DBF
        Issue date                     Oct. 18,   July 8,   Dec. 2,  June 10,
                                          2002      2003      2003      2004
        Maturity date                  Matured    Aug. 1,   Feb. 1,  June 30,
                                                    2008      2009      2009
        Conversion price               Matured  $  17.00  $  16.50  $  34.67
        Liability component           $ 52,722  $ 28,662  $ 56,802  $ 48,700
        Equity component                 2,278     1,338     3,198    11,408
        ---------------------------------------------------------------------
        Gross proceeds                  55,000    30,000    60,000    60,108
        Issuance costs                  (2,495)   (1,444)   (2,588)        -
        ---------------------------------------------------------------------
        Net proceeds                  $ 52,505  $ 28,556  $ 57,412  $ 60,108
        ---------------------------------------------------------------------


                               7.50%     6.50%     7.75%     8.00%     Total
        ---------------------------------------------------------------------
        Trading symbol       AVN.DBC   AVN.DBE   AVN.DBD   AVN.DBG
        Issue date           Sep. 15,   May 18,  Sep. 15,  Nov. 13,
                                2004      2005      2004      2006
        Maturity date         Oct. 1,  June 30,   Dec. 1,  Dec. 31,
                                2009      2010      2011      2011
        Conversion price    $  20.25  $  24.96  $  21.00  $  20.33
        Liability component $ 71,631  $ 66,981  $ 47,444  $ 14,884  $387,826
        Equity component       3,369     2,971     2,556    26,561    53,679
        ---------------------------------------------------------------------
        Gross proceeds        75,000    69,952    50,000    41,445   441,505
        Issuance costs        (3,190)        -    (2,190)        -   (11,907)
        ---------------------------------------------------------------------
        Net proceeds        $ 71,810  $ 69,952  $ 47,810  $ 41,445  $429,598
        ---------------------------------------------------------------------

        The convertible debentures are redeemable prior to their maturity
        dates, at the option of the Fund, upon providing 30 to 60 days
        advance notification. The redemption prices for the various
        debentures, plus accrued and unpaid interest, is dependent on the
        redemption periods and are as follows:

        Convertible                                                Redemption
        Debenture   Redemption Periods                                Price
        ---------------------------------------------------------------------
        9.00%       After August 1, 2007 and before
                    August 1, 2008                                    $1,025
        ---------------------------------------------------------------------
        8.25%       After February 1, 2007 and on or before
                    February 1, 2008                                  $1,050
                    After February 1, 2008 and before
                    February 1, 2009                                  $1,025
        ---------------------------------------------------------------------
        8.75%       After June 30, 2007 and on or before
                    June 30, 2008                                     $1,050
                    After June 30, 2008 and before June 30, 2009      $1,025
        ---------------------------------------------------------------------
        7.50%       After October 1, 2007 and on or before
                    October 1, 2008                                   $1,050
                    After October 1, 2008 and before October 1, 2009  $1,025
        ---------------------------------------------------------------------
        6.50%       After June 30, 2008 and on or before
                    June 30, 2009                                     $1,050
                    After June 30, 2009 and before June 30, 2010      $1,025
        ---------------------------------------------------------------------
        7.75%       After December 1, 2007 and on or before
                    December 1, 2008                                  $1,050
                    After December 1, 2008 and on or before
                    December 1, 2009                                  $1,025
                    After December 1, 2009 and before
                    December 1, 2011                                  $1,000
        ---------------------------------------------------------------------
        8.00%       After December 31, 2009 and on or before
                    December 31, 2010                                 $1,050
                    After December 31, 2010 and before
                    December 31, 2011                                 $1,025
        ---------------------------------------------------------------------

        The balance of debentures outstanding at December 31, 2007 and
        changes in the liability and equity components during the years ended
        December 31, 2007 and 2006 are as follows:

                                        10.00%     9.00%     8.25%     8.75%
        ---------------------------------------------------------------------
        Debentures outstanding        $      -  $  5,392  $  4,867  $ 29,839
        ---------------------------------------------------------------------
        Liability component:
          Balance at Dec. 31, 2005    $  2,453  $  7,259  $  8,150  $      -
          Assumed on Ketch acquisition       -         -         -         -
          Accretion of discount             30       107       103         -
          Converted to Trust Units      (1,019)   (2,131)   (3,577)        -
        ---------------------------------------------------------------------
          Balance at Dec. 31, 2006       1,464     5,235     4,676         -
          Assumed on Sound acquisition       -         -         -    48,700
          Accretion of discount             22        98        91        96
          Converted to Trust Units      (1,486)        -         -        (8)
          Redeemed for cash                  -         -         -   (19,406)
        ---------------------------------------------------------------------
          Balance at Dec. 31, 2007    $      -  $  5,333  $  4,767  $ 29,382
        ---------------------------------------------------------------------
        Equity component:
          Balance at Dec. 31, 2005    $    100  $    323  $    441  $      -
          Assumed on Ketch acquisition       -         -         -         -
          Converted to Trust Units         (41)      (94)     (193)        -
        ---------------------------------------------------------------------
          Balance at Dec. 31, 2006          59       229       248         -
          Assumed on Sound acquisition       -         -         -    11,408
          Converted to Trust Units           -         -         -   (10,556)
          Expired                          (59)        -         -         -
        ---------------------------------------------------------------------
          Balance at Dec. 31, 2007    $      -  $    229  $    248  $    852
        ---------------------------------------------------------------------


                               7.50%     6.50%     7.75%     8.00%     Total
        ---------------------------------------------------------------------
        Debentures
         outstanding        $ 52,268  $ 69,952  $ 46,766  $ 15,528  $224,612
        ---------------------------------------------------------------------
        Liability component:
          Balance at Dec. 31,
           2005             $ 62,321  $      -  $ 45,898  $      -  $126,081
          Assumed on Ketch
           acquisition             -    66,981         -         -    66,981
          Accretion of
           discount              897       380       589         -     2,106
          Converted to
           Trust Units       (13,436)        -    (2,722)        -   (22,885)
        ---------------------------------------------------------------------
          Balance at Dec. 31,
           2006               49,782    67,361    43,765         -   172,283
          Assumed on Sound
           acquisition             -         -         -    14,884    63,584
          Accretion of
           discount              889       731       595        47     2,569
          Converted to Trust
           Units                   -         -         -         -    (1,494)
          Redeemed for cash        -         -         -         -   (19,406)
        ---------------------------------------------------------------------
          Balance at Dec. 31,
           2007             $ 50,671  $ 68,092  $ 44,360  $ 14,931  $217,536
        ---------------------------------------------------------------------
        Equity component:
          Balance at Dec. 31,
           2005             $  2,865  $      -  $  2,430  $      -  $  6,159
          Assumed on Ketch
           acquisition             -     2,971         -         -     2,971
          Converted to Trust
           Units                (617)        -      (144)        -    (1,089)
        ---------------------------------------------------------------------
          Balance at Dec. 31,
           2006                2,248     2,971     2,286         -     8,041
          Assumed on Sound
           acquisition             -         -         -    26,561    37,969
          Converted to Trust
           Units                   -         -         -   (25,763)  (36,319)
          Expired                  -         -         -         -       (59)
        ---------------------------------------------------------------------
          Balance at Dec. 31,
           2007             $  2,248  $  2,971  $  2,286  $    798  $  9,632
        ---------------------------------------------------------------------

        As part of the acquisition of Ketch (note 3), the 6.50% convertible
        debentures, originally issued May 18, 2005, were assumed by Advantage
        on June 23, 2006.

        Due to the acquisition of Sound (note 3), 8.75% and 8.00% convertible
        debentures were assumed by Advantage on September 5, 2007. As a
        result of the change in control of Sound, the Fund was required by
        the debenture indentures to make an offer to purchase all of the
        outstanding convertible debentures assumed from Sound at a price
        equal to 101% of the principal amount plus accrued and unpaid
        interest. On October 17, 2007, the expiry date of the offer, 911,709
        Trust Units were issued and $19.9 million in total cash consideration
        was paid in exchange for $29,665,000 8.75% convertible debentures and
        2,220,289 Trust Units were issued in exchange for $25,507,000 8.0%
        convertible debentures.

        During the year ended December 31, 2007, $24,000 debentures (2006 -
        $24,333,000) were converted resulting in the issuance of 1,386 Trust
        Units (2006 - 1,286,901 Trust Units) and all of the remaining
        $1,470,000 10% convertible debentures matured on November 1, 2007 and
        were settled with the issuance of 127,493 Trust Units.

    7.  Bank Indebtedness

        Advantage has a credit facility agreement with a syndicate of
        financial institutions which provides for a $690 million extendible
        revolving loan facility and a $20 million operating loan facility.
        The loan's interest rate is based on either prime, US base rate,
        LIBOR or bankers' acceptance rates, at the Fund's option, subject to
        certain basis point or stamping fee adjustments ranging from 0.00% to
        1.25% depending on the Fund's debt to cash flow ratio. The credit
        facilities are secured by a $1 billion floating charge demand
        debenture, a general security agreement and a subordination agreement
        from the Fund covering all assets and cash flows. The credit
        facilities are subject to review on an annual basis with the next
        renewal due in June 2008. Various borrowing options are available
        under the credit facilities, including prime rate-based advances, US
        base rate advances, US dollar LIBOR advances and bankers' acceptances
        loans. The credit facilities constitute a revolving facility for a
        364 day term which is extendible annually for a further 364 day
        revolving period at the option of the syndicate. If not extended, the
        revolving credit facility is converted to a two year term facility
        with the first payment due one year and one day after commencement of
        the term. The credit facilities contain standard commercial covenants
        for facilities of this nature. The only financial covenant is a
        requirement for AOG to maintain a minimum cash flow to interest
        expense ratio of 3.5:1, determined on a rolling four quarter basis.
        Breach of any covenant will result in an event of default in which
        case AOG has 20 days to remedy such default. If the default is not
        remedied or waived, and if required by the majority of lenders, the
        administrative agent of the lenders has the option to declare all
        obligations of AOG under the credit facilities to be immediately due
        and payable without further demand, presentation, protest, or notice
        of any kind. Distributions by AOG to the Fund (and effectively by the
        Fund to Unitholders) are subordinated to the repayment of any amounts
        owing under the credit facilities. Distributions to Unitholders are
        not permitted if the Fund is in default of such credit facilities or
        if the amount of the Fund's outstanding indebtedness under such
        facilities exceeds the then existing current borrowing base. Interest
        payments under the debentures are also subordinated to indebtedness
        under the credit facilities and payments under the debentures are
        similarly restricted. For the year ended December 31, 2007, the
        effective interest rate on the outstanding amounts under the facility
        was approximately 5.7% (2006 - 5.1%).

    8.  Asset Retirement Obligations

        The Fund's asset retirement obligations result from net ownership
        interests in petroleum and natural gas assets including well sites,
        gathering systems and processing facilities. The Fund estimates the
        total undiscounted and inflated amount of cash flows required to
        settle its asset retirement obligations is approximately
        $243.9 million which will be incurred between 2008 to 2057. A credit-
        adjusted risk-free rate of 7% and an inflation factor of 2% were used
        to calculate the fair value of the asset retirement obligations.

        A reconciliation of the asset retirement obligations is provided
        below:

                                                     Year ended   Year ended
                                                    December 31, December 31,
                                                           2007         2006
        ---------------------------------------------------------------------
        Balance, beginning of year                  $    34,324  $    21,263
        Accretion expense                                 2,795        1,684
        Assumed in Sound acquisition (note 3)            16,695            -
        Assumed in Ketch acquisition (note 3)                 -        7,930
        Liabilities incurred                             13,972        9,421
        Liabilities settled                              (6,951)      (5,974)
        ---------------------------------------------------------------------
        Balance, end of year                        $    60,835  $    34,324
        ---------------------------------------------------------------------

    9.  Income Taxes

        The taxable income of the Fund is comprised of interest income
        related to the AOG Notes and royalty income from the AOG Royalty less
        deductions for Canadian Oil and Gas Property Expense, Trust Unit
        issue costs, and interest on convertible debentures. Given that
        taxable income of the Fund is allocated to the Unitholders, no
        provision for current income taxes relating to the Fund is included
        in these financial statements. On December 14, 2007, the Federal
        government enacted legislation phasing in corporate income tax rate
        reductions which will reduce federal tax rates from 22.1% to 15.0% by
        2012. Rate reductions will also apply to the new tax on distributions
        of income trusts and other specified investment flow-through entities
        as of 2011, reducing the tax rate in 2011 to 29.5% and in 2012 to
        28.0%. These rates include a deemed provincial rate of 13%.

        The provision for income taxes varies from the amount that would be
        computed by applying the combined Canadian federal and provincial
        income tax rates for the following reasons:

                                                     Year ended   Year ended
                                                    December 31, December 31,
                                                           2007         2006
        ---------------------------------------------------------------------
        Income (loss) before taxes                  $   (30,733) $    14,265
        ---------------------------------------------------------------------
        Canadian combined federal and provincial
         income tax rates                                32.57%       34.78%
        Expected income tax expense (recovery) at
         statutory rates                                (10,011)       4,961
        Increase (decrease) in income taxes
         resulting from:
          Amounts included in trust income              (57,766)     (39,940)
          Change in enacted tax rates                       550       (5,692)
          Management internalization                      4,554        4,678
          Specified Investment Flow-Through              42,862            -
          Non-deductible Crown charges                        -        6,925
          Resource allowance                                  -       (8,108)
          Other                                          (4,831)          89
        ---------------------------------------------------------------------
        Future income tax reduction                     (24,642)     (37,087)
        Income and capital taxes                          1,444        1,509
        ---------------------------------------------------------------------
                                                    $   (23,198) $   (35,578)
        ---------------------------------------------------------------------

        The components of the future income tax liability are as follows:

                                                    December 31, December 31,
                                                           2007         2006
        ---------------------------------------------------------------------
        Fixed assets in excess of tax basis         $    29,240  $    85,648
        Asset retirement obligations                    (16,330)     (10,141)
        Non-capital tax loss carry forward              (20,369)      (8,851)
        Trust assets in excess of tax basis              82,642            -
        Other                                            (8,456)      (4,717)
        ---------------------------------------------------------------------
        Future income tax liability                 $    66,727  $    61,939
        ---------------------------------------------------------------------

        AOG has a non-capital tax loss carry forward of approximately
        $76 million of which $1 million expires in 2008, $18 million in 2011,
        $11 million in 2012 and $46 million after 2020.

    10. Unitholders' Equity

        (a) Unitholders' capital

            (i)  Authorized

                 Unlimited number of voting Trust Units

            (ii) Issued

                                                Number of Units       Amount
        ---------------------------------------------------------------------
        Balance at December 31, 2005                 57,846,324  $   681,574
        2005 non-cash performance incentive             475,263       10,544
        Issued on conversion of debentures            1,286,901       23,974
        Issued on conversion of exchangeable shares     127,014        2,398
        Issued on exercise of Trust Unit rights         122,500          682
        Issued for Ketch acquisition (note 3)        32,870,465      688,636
        Management internalization                    1,913,842       38,716
        2006 non-cash performance incentive             117,662        2,380
        Distribution reinvestment plan                2,005,499       27,722
        Issued for cash, net of costs                 8,625,000      141,399
        ---------------------------------------------------------------------
        Balance at December 31, 2006                105,390,470    1,618,025
        Issued on conversion of debentures              128,879        1,494
        Issued on exercise of Trust Unit rights          37,500          562
        Issued for cash, net of costs                 8,600,000      104,094
        Distribution reinvestment plan                4,028,252       46,657
        Issued for Sound acquisition, net of costs
         (note 3)                                    16,977,184      228,583
        Issued on offer to purchase Sound debentures
         (note 6)                                     3,131,998       37,209
        Management internalization forfeitures          (24,909)        (503)
        ---------------------------------------------------------------------
                                                    138,269,374  $ 2,036,121
        ---------------------------------------------------------------------
        Management internalization escrowed Trust
         Units                                                        (9,056)
        ---------------------------------------------------------------------
        Balance at December 31, 2007                             $ 2,027,065
        ---------------------------------------------------------------------

        On January 20, 2006, Advantage issued 475,263 Trust Units to satisfy
        the obligation related to the 2005 year end performance incentive
        fee.

        On June 23, 2006, Advantage issued 32,870,465 Trust Units as
        consideration for the acquisition of Ketch (note 3). Concurrent with
        the Ketch acquisition, Advantage internalized the external management
        contract structure and eliminated all related fees for total original
        consideration of 1,933,208 Advantage Trust Units initially valued at
        $39.1 million and subject to escrow provisions over a 3-year period,
        vesting one-third each year beginning June 23, 2007 (note 13). For
        the year ended December 31, 2007, a total of 24,909 Trust Units
        issued for the management internalization were forfeited (2006 -
        19,366 Trust Units) and $15.7 million has been recognized as
        management internalization expense (2006 - $13.4 million). As at
        December 31, 2007, 1,193,622 Trust Units remain held in escrow
        (December 31, 2006 - 1,822,098 Trust Units). The Fund also issued
        117,662 Trust Units on June 23, 2006, valued at $2.4 million, to
        satisfy the final obligation related to the 2006 first quarter
        performance fee.

        On July 24, 2006, Advantage announced that it adopted a Premium
        Distribution™, Distribution Reinvestment and Optional Trust Unit
        Purchase Plan (the "Plan"). The Plan commenced with the monthly cash
        distribution payable on August 15, 2006 to Unitholders of record on
        July 31, 2006. For eligible Unitholders that elect to participate in
        the Plan, Advantage will settle the monthly distribution obligation
        through the issuance of additional Trust Units at 95% of the Average
        Market Price (as defined in the Plan). Unitholder enrollment in the
        Premium Distribution™ component of the Plan effectively authorizes
        the subsequent disposal of the issued Trust Units in exchange for a
        cash payment equal to 102% of the cash distributions that the
        Unitholder would otherwise have received if they did not participate
        in the Plan. During the year ended December 31, 2007, 4,028,252 Trust
        Units (2006 - 2,005,499 Trust Units) were issued under the Plan,
        generating $46.7 million (2006 - $27.7 million) reinvested in the
        Fund.

        On August 1, 2006, Advantage issued 7,500,000 Trust Units, plus an
        additional 1,125,000 Trust Units upon full exercise of the
        Underwriters' over-allotment option on August 4, 2006, at $17.30 per
        Trust Unit for net proceeds of $141.4 million (net of Underwriters'
        fees and other issue costs of $7.8 million). The net proceeds of the
        offering were used to pay down bank indebtedness and to subsequently
        fund capital and general corporate expenditures.

        On February 14, 2007 Advantage issued 7,800,000 Trust Units, plus an
        additional 800,000 Trust Units upon exercise of the Underwriters'
        over-allotment option on March 7, 2007, at $12.80 per Trust Unit for
        approximate net proceeds of $104.1 million (net of Underwriters' fees
        and other issue costs of $6.0 million).

        On September 5, 2007, Advantage issued 16,977,184 Trust Units, valued
        at $228.9 million, as partial consideration for the acquisition of
        Sound (note 3). Trust Unit issuance costs of $0.3 million were
        incurred for the Sound acquisition.

        Due to the acquisition of Sound (note 3), 8.75% and 8.00% convertible
        debentures were assumed by Advantage on September 5, 2007. As a
        result of the change in control of Sound, the Fund was required by
        the debenture indentures to make an offer to purchase all of the
        outstanding convertible debentures assumed from Sound at a price
        equal to 101% of the principal amount plus accrued and unpaid
        interest. On October 17, 2007, the expiry date of the offer, 911,709
        Trust Units were issued and $19.9 million in total cash consideration
        was paid in exchange for $29,665,000 8.75% convertible debentures and
        2,220,289 Trust Units were issued in exchange for $25,507,000 8.0%
        convertible debentures.

        (b) Contributed surplus

                                                     Year ended   Year ended
                                                    December 31, December 31,
                                                           2007         2006
        ---------------------------------------------------------------------
        Balance, beginning of year                  $       863  $     1,036
        Unit-based compensation                           1,255            -
        Expiration of convertible debentures equity
         component                                           59            -
        Exercise of Trust Unit Rights                      (172)        (173)
        ---------------------------------------------------------------------
        Balance, end of year                        $     2,005  $       863
        ---------------------------------------------------------------------

        (c) Trust Units Rights Incentive Plan

        Effective June 25, 2002, a Trust Units Rights Incentive Plan for
        external directors of the Fund was established and approved by the
        Unitholders of Advantage. A total of 500,000 Trust Units have been
        reserved for issuance under the plan with an aggregate of 400,000
        rights granted since inception. The initial exercise price of rights
        granted under the plan may not be less than the current market price
        of the Trust Units as of the date of the grant and the maximum term
        of each right is not to exceed ten years with all rights vesting
        immediately upon grant. At the option of the rights holder, the
        exercise price of the rights can be adjusted downwards over time
        based upon distributions paid by the Fund to Unitholders.

                                                               Series B
                                                         Number        Price
        ---------------------------------------------------------------------
        Balance at December 31, 2005                    225,000  $     13.63
        Exercised                                       (37,500)           -
        Reduction of exercise price                           -        (2.66)
        ---------------------------------------------------------------------
        Balance at December 31, 2006                    187,500        10.97
        Exercised                                       (37,500)           -
        Reduction of exercise price                           -        (1.77)
        ---------------------------------------------------------------------
        Balance at December 31, 2007                    150,000  $      9.20
        ---------------------------------------------------------------------
        Expiration date                                     June 17, 2008
        ---------------------------------------------------------------------

        (d) Unit-based compensation

        Advantage's current employee compensation includes a Restricted Trust
        Unit Plan (the "Plan"), as approved by the Unitholders on June 23,
        2006, and Trust Units issuable for the retention of certain employees
        of the Fund. The purpose of the long-term compensation plans is to
        retain and attract employees, to reward and encourage performance,
        and to focus employees on operating and financial performance that
        results in lasting Unitholder return.

        The Plan authorizes the Board of Directors to grant Restricted Trust
        Units ("RTUs") to directors, officers, or employees of the Fund. The
        number of RTUs granted is based on the Fund's Trust Unit return for a
        calendar year and compared to a peer group approved by the Board of
        Directors. The Trust Unit return is calculated at the end of the year
        and is primarily based on the year-over-year change in the Trust Unit
        price plus distributions. The RTU grants vest one third immediately
        on grant date, with the remaining two thirds vesting evenly on the
        following two yearly anniversary dates. The holders of RTUs may elect
        to receive cash upon vesting in lieu of the number of Trust Units to
        be issued, subject to consent of the Fund. As the Fund did not meet
        the 2007 or 2006 grant thresholds, there were no RTU grants made
        during these years.

        For the year ended December 31, 2007, the Fund has accrued unit-based
        compensation expense of $0.9 million recorded in general and
        administrative expense (December 31, 2006 - nil) and has capitalized
        $0.3 million (December 31, 2006 - nil) related to Trust Units
        issuable for the retention of certain employees of the Fund.

        (e) Net income (loss) per Trust Unit

        The calculation of basic and diluted net income (loss) per Trust Unit
        are derived from both income (loss) available to Unitholders and
        weighted average Trust Units outstanding calculated as follows:

                                                     Year ended   Year ended
                                                    December 31, December 31,
                                                           2007         2006
        ---------------------------------------------------------------------
        Income (loss) available to Unitholders
          Basic and Diluted                         $    (7,535) $    49,814
        ---------------------------------------------------------------------
        Weighted average Trust Units outstanding
          Basic                                     119,604,019   80,958,455
          Trust Units Rights Incentive Plan -
           Series A                                           -       43,548
          Trust Units Rights Incentive Plan -
           Series B                                           -       78,287
          Management Internalization                          -      113,556
        ---------------------------------------------------------------------
          Diluted                                   119,604,019   81,193,846
        ---------------------------------------------------------------------

        The calculation of diluted net income per Trust Unit excludes all
        series of convertible debentures for the years as the impact would be
        anti-dilutive. Total weighted average Trust Units issuable in
        exchange for the convertible debentures and excluded from the diluted
        net income per Trust Unit calculation for the year ended December 31,
        2007 were 9,083,663 (2006 - 7,182,276). As at December 31, 2007, the
        total convertible debentures outstanding were immediately convertible
        to 9,847,253 Trust Units (2006 - 8,334,453).

        All of the Series B Trust Unit Rights and Management Internalization
        escrowed Trust Units have been excluded from the calculation of
        diluted net income per Trust Unit for the year ended December 31,
        2007, as the impact would be anti-dilutive. Total weighted average
        Trust Units issuable in exchange for the Series B Trust Unit Rights
        and Management Internalization escrowed Trust Units and excluded from
        the diluted net income per Trust Unit calculation for the year ended
        December 31, 2007 were 42,918 and 582,861, respectively. All of the
        remaining Series A Trust Unit Rights were exercised July 7, 2006.

        Exchangeable Shares have been excluded from the calculation of
        diluted net income per Trust Unit for the year ended December 31,
        2006 as the impact would have been anti-dilutive. All of the
        remaining Exchangeable Shares were redeemed May 9, 2006. Total
        weighted average Trust Units issuable in exchange for the
        Exchangeable Shares and excluded from the diluted net income per
        Trust Unit calculation for the year ended December 31, 2006 were
        36,448.

    11. Accumulated Deficit

        Accumulated deficit consists of accumulated income and accumulated
        distributions for the Fund since inception as follows:

                                                    December 31, December 31,
                                                           2007         2006
        ---------------------------------------------------------------------
        Accumulated Income                          $   219,988  $   227,523
        Accumulated Distributions                      (879,823)    (664,629)
        ---------------------------------------------------------------------
        Accumulated Deficit                         $  (659,835) $  (437,106)
        ---------------------------------------------------------------------

        The Fund has historically paid distributions in excess of accumulated
        income as distributions are typically based on cash flows generated
        in the period while accumulated income is based on such cash flows
        less other non-cash charges such as depletion, depreciation, and
        accretion expense recorded on the original investment in petroleum
        and natural gas properties and management internalization expense.
        For the year ended December 31, 2007 the Fund declared $215.2 million
        in distributions representing $1.77 per distributable Trust Unit
        (2006 - $217.2 million in distributions representing $2.66 per
        distributable Trust Unit).

    12. Financial Instruments

        Financial instruments of the Fund include accounts receivable,
        deposits, accounts payable and accrued liabilities, distributions
        payable to Unitholders, bank indebtedness, convertible debentures and
        derivative assets and liabilities.

        Accounts receivable and deposits are classified as loans and
        receivables and measured at amortized cost. Accounts payable and
        accrued liabilities, distributions payable to Unitholders and bank
        indebtedness are all classified as other liabilities and similarly
        measured at amortized cost. As at December 31, 2007, there were no
        significant differences between the carrying amounts reported on the
        balance sheet and the estimated fair values of these financial
        instruments due to the short terms to maturity and the floating
        interest rate on the bank indebtedness.

        The Fund has convertible debenture obligations outstanding, of which
        the liability component has been classified as other liabilities and
        measured at amortized cost. The convertible debentures have different
        fixed terms and interest rates (note 6) resulting in fair values that
        will vary over time as market conditions change. As at December 31,
        2007, the estimated fair value of the total outstanding convertible
        debenture obligation was $215.4 million (December 31, 2006 -
        $180.0 million). The fair value of the liability component of
        convertible debentures was determined primarily based on a discounted
        cash flow model assuming no future conversions and continuation of
        current interest and principal payments as well as taking into
        consideration the current public trading activity of such debentures.
        The Fund applied discount rates of between 7 and 8% considering
        current available market information, assumed credit adjustments, and
        various terms to maturity.

        Advantage has an established strategy to manage the risk associated
        with changes in commodity prices by entering into derivatives, which
        are recorded at fair value as derivative assets and liabilities with
        gains and losses recognized through earnings. As the fair value of
        the contracts varies with commodity prices, they give rise to
        financial assets and liabilities. The fair values of the derivatives
        are determined through valuation models completed by third parties.
        Various assumptions based on current market information were used in
        these valuations, including settled forward commodity prices,
        interest rates, foreign exchange rates, volatility and other relevant
        factors. The actual gains and losses realized on eventual cash
        settlement can vary materially due to subsequent fluctuations in
        commodity prices as compared to the valuation assumptions.

        Credit Risk

        Accounts receivable, deposits, and derivative assets are subject to
        credit risk exposure and the carrying values reflect Management's
        assessment of the associated maximum exposure to such credit risk.
        Substantially all of the Fund's accounts receivable are due from
        customers and joint operation partners concentrated in the Canadian
        oil and gas industry. As such, accounts receivable are subject to
        normal industry credit risks. Advantage mitigates such credit risk by
        closely monitoring significant counterparties and dealing with a
        broad selection of partners that diversify risk within the sector.
        The Fund's deposits are primarily due from the Alberta Provincial
        government and are viewed by Management as having minimal associated
        credit risk. To the extent that Advantage enters derivatives to
        manage commodity price risk, it may be subject to credit risk
        associated with counterparties with which it contracts. Credit risk
        is mitigated by entering into contracts with only stable,
        creditworthy parties and through frequent reviews of exposures to
        individual entities. In addition, the Fund generally enters into
        derivative contracts with investment grade institutions that are
        members of Advantage's credit facility syndicate to further mitigate
        associated credit risk.

        Liquidity Risk

        The Fund is subject to liquidity risk attributed from accounts
        payable and accrued liabilities, distributions payable to
        Unitholders, bank indebtedness, convertible debentures, and
        derivative liabilities. Accounts payable and accrued liabilities,
        distributions payable to Unitholders and derivative liabilities are
        primarily due within one year of the balance sheet date and Advantage
        does not anticipate any problems in satisfying the obligations due to
        the strength of cash provided by operating activities and the
        existing credit facility. The Fund's bank indebtedness is subject to
        a $710 million credit facility agreement which mitigates liquidity
        risk by enabling Advantage to manage interim cash flow fluctuations.
        The credit facility constitutes a revolving facility for a 364 day
        term which is extendible annually for a further 364 day revolving
        period at the option of the syndicate. If not extended, the revolving
        credit facility is converted to a two year term facility with the
        first payment due one year and one day after commencement of the
        term. The terms of the credit facility are such that it provides
        Advantage adequate flexibility to evaluate and assess liquidity
        issues if and when they arise. Additionally, the Fund regularly
        monitors liquidity related to obligations by evaluating forecasted
        cash flows, optimal debt levels, capital spending activity, working
        capital requirements, and other potential cash expenditures. This
        continual financial assessment process further enables the Fund to
        mitigate liquidity risk.

        Advantage has several series of convertible debentures outstanding
        that mature from 2008 to 2011 (note 6). Interest payments are made
        semi-annually with excess cash provided by operating activities. As
        the debentures become due, the Fund can satisfy the obligations in
        cash or issue Trust Units at a price determined in the applicable
        debenture agreements. This settlement alternative allows the Fund to
        adequately manage liquidity, plan available cash resources and
        implement an optimal capital structure.

        To the extent that Advantage enters derivatives to manage commodity
        price risk, it may be subject to liquidity risk as derivative
        liabilities become due. While the Fund has elected not to follow
        hedge accounting, derivative instruments are not entered for
        speculative purposes and Management closely monitors existing
        commodity risk exposures. As such, liquidity risk is mitigated since
        any losses actually realized are subsidized by increased cash flows
        realized from the higher commodity price environment.

        Interest Rate Risk

        The Fund is exposed to interest rate risk to the extent that bank
        indebtedness is at a floating rate of interest and the Fund's maximum
        exposure to interest rate risk is based on the effective interest
        rate and the current carrying value of the bank indebtedness. The
        Fund monitors the interest rate markets to ensure that appropriate
        steps can be taken if interest rate volatility compromises the Fund's
        cash flows. A 1% interest rate fluctuation for the year ended
        December 31, 2007 could potentially have impacted net income by
        approximately $3.0 million for that period.

        Price and Currency Risk

        Advantage's derivative assets and liabilities are subject to both
        price and currency risks as their fair values are based on
        assumptions including forward commodity prices and foreign exchange
        rates. The Fund enters derivative financial instruments to manage
        commodity price risk exposure relative to actual commodity production
        and does not utilize derivative instruments for speculative purposes.
        Changes in the price assumptions can have a significant effect on the
        fair value of the derivative assets and liabilities and thereby
        impact net income. It is estimated that a 10% change in the forward
        natural gas prices used to calculate the fair value of the natural
        gas derivatives at December 31, 2007 could impact net income by
        approximately $8.7 million for the year ended December 31, 2007. As
        well, a change of 10% in the forward crude oil prices used to
        calculate the fair value of the crude oil derivatives at December 31,
        2007 could impact net income by $3.7 million for the year ended
        December 31, 2007. A change of 10% in the forward power prices used
        to calculate the fair value of the power derivatives at December 31,
        2007 could impact net income by $0.1 million for the year ended
        December 31, 2007. A similar change in the currency rate assumption
        underlying the derivatives fair value does not have a material impact
        on net income.

        As at December 31, 2007 the Fund had the following derivatives in
        place:

        Description of
        Derivative           Term           Volume            Average Price
        ---------------------------------------------------------------------
        Natural gas - AECO

          Fixed price   November 2007    7,109 mcf/d            Cdn$9.54/mcf
                        to March 2008
          Fixed price   April 2008      14,217 mcf/d            Cdn$6.85/mcf
                        to October 2008
          Fixed price   April 2008      14,217 mcf/d            Cdn$7.10/mcf
                        to March 2009
          Fixed price   April 2008      14,217 mcf/d            Cdn$7.06/mcf
                        to March 2009
          Fixed price   November 2008   14,217 mcf/d            Cdn$7.77/mcf
                        to March 2009
          Collar        November 2007    9,478 mcf/d      Floor Cdn$8.44/mcf
                        to March 2008                  Ceiling Cdn$10.29/mcf

          Collar        November 2007
                        to March 2008    7,109 mcf/d      Floor Cdn$8.70/mcf
                                                       Ceiling Cdn$10.71/mcf
        Crude oil - WTI

          Fixed price   February 2008   2,000 bbls/d           Cdn$90.93/bbl
                        to January 2009
          Collar        February 2008   2,000 bbls/d  Sold put Cdn$70.00/bbl
                        to January 2009         Purchase call Cdn$105.00/bbl
                                                           Cost Cdn$1.52/bbl
        Electricity - Alberta Pool Price

          Fixed price   January 2008          3.0 MW           Cdn$54.00/MWh
                        to December 2008

        As at December 31, 2007, the fair value of the derivatives
        outstanding resulted in an asset of approximately $7,201,000
        (December 31, 2006 - $10,433,000) and a liability of approximately
        $5,020,000 (December 31, 2006 - nil). For the year ended December 31,
        2007, $11,049,000 was recognized in income as an unrealized
        derivative loss (December 31, 2006 - $10,242,000 unrealized
        derivative gain) and $18,594,000 was recognized in income as a
        realized derivative gain (December 31, 2006 - $5,297,000).

        As a result of the Sound acquisition (note 3), the Fund assumed
        several derivatives, which had an estimated net fair market value of
        $2,797,000 on closing.

    13. Management Fee, Performance Incentive, and Management Internalization

        Concurrent with the Ketch acquisition (note 3), Advantage
        internalized the external management contract structure and
        eliminated all related fees. The Fund reached an agreement with
        Advantage Investment Management Ltd. ("AIM" or the "Manager") to
        purchase all of the outstanding shares of AIM pursuant to the terms
        of the Plan of Arrangement for total original consideration of
        1,933,208 Advantage Trust Units. The Trust Units were initially
        valued at $39.1 million using the weighted average trading value for
        Advantage Trust Units on the Unitholder approval date of June 22,
        2006 and are subject to escrow provisions over a 3-year period,
        vesting one-third each year beginning in 2007. The management
        internalization consideration is being deferred and amortized into
        income as management internalization expense over the specific
        vesting periods during which employee services are provided,
        including an estimate of future Trust Unit forfeitures. For the year
        ended December 31, 2007, a total of 24,909 Trust Units issued for the
        management internalization were forfeited (2006 - 19,366 Trust Units)
        and $15.7 million has been recognized as management internalization
        expense (2006 - $13.4 million). As at December 31, 2007, 1,193,622
        Trust Units remain held in escrow (2006 - 1,822,098 Trust Units). The
        Fund also issued 117,662 Trust Units to satisfy the final obligation
        related to the 2006 first quarter performance fee along with
        $0.9 million in cash to settle the first quarter management fee. AIM
        agreed to forego fees from the period April 1, 2006 to the closing of
        the Arrangement.

        Prior to the internalization, the Manager received both a management
        fee and a performance incentive fee as compensation pursuant to the
        Management Agreement approved by the Board of Directors. Management
        fees were calculated based on 1.5% of operating cash flow defined as
        revenues less royalties and operating costs and were paid quarterly.

        The Manager of the Fund was also entitled to earn an annual
        performance incentive fee when the Fund's total annual return
        exceeded 8%. The total annual return was calculated at the end of the
        year by dividing the year-over-year change in Unit price plus cash
        distributions by the opening Unit price, as defined in the Management
        Agreement. Ten percent of the amount of the total annual return in
        excess of 8% was multiplied by the market capitalization (defined as
        the opening Unit price multiplied by the weighted average number of
        Trust Units outstanding during the year) to determine the performance
        incentive fee. The Management Agreement provided an option to the
        Manager to receive the performance incentive fee in equivalent Trust
        Units. The Manager exercised the option and on January 20, 2006, the
        Fund issued 475,263 Advantage Trust Units at the closing Unit price
        of $22.19 to satisfy the 2005 performance fee obligation. The Manager
        did not receive any form of compensation in respect of acquisition or
        divestiture activities nor was there any form of stock option or
        bonus plan for the Manager or the employees of Advantage outside of
        the management and performance fees prior to the internalization. The
        management fees and performance fees were shared amongst all
        management and employees.

    14. Commitments

        Advantage has several lease commitments relating to office buildings.
        The Fund has assumed office lease commitments from prior corporate
        acquisitions and has renegotiated leases to accommodate the growth of
        the Fund. The estimated annual minimum operating lease rental
        payments for buildings are as follows:

        2008                                                     $     5,319
        2009                                                           4,111
        2010                                                           4,127
        2011                                                           1,731
        2012                                                           1,314
        ---------------------------------------------------------------------
                                                                 $    16,602
        ---------------------------------------------------------------------

    15. Reconciliation of Financial Statements to United States Generally
        Accepted Accounting Principles

        The consolidated financial statements of Advantage have been prepared
        in accordance with accounting principles generally accepted in
        Canada. Canadian GAAP, in most respects, conforms to generally
        accepted accounting principles in the United States. Any differences
        in accounting principles between Canadian GAAP and US GAAP, as they
        apply to Advantage, are not material, except as described below.

        (a) Unit-based compensation

        Advantage accounts for compensation expense based on the fair value
        of the equity awards on the grant date and the initial fair value is
        not subsequently remeasured. Advantage's unit-based compensation
        consists of a Trust Units Rights Incentive Plan, Trust Units held in
        escrow subject to service requirement provisions, and Trust Units
        issuable for the retention of certain employees of the Fund. The
        initial fair value is expensed over the vesting period of the Trust
        Units or rights granted.

        Under US GAAP, the Fund adopted SFAS 123® "Share-Based Payment" on
        January 1, 2006 using the modified prospective approach and applies
        the fair value method of accounting for all Unit-based compensation
        granted after January 1, 2006. A US GAAP difference exists as unit-
        based compensation grants are considered liability awards for US GAAP
        and equity awards for Canadian GAAP. Under US GAAP, the fair value of
        a liability award is measured at the grant date and is subsequently
        remeasured at each reporting period. When the rights are exercised
        and the Trust Units vested, the amount recorded as a liability is
        recognized as temporary equity and the fair value at adoption of the
        new standard has been charged to income as the cumulative effect of a
        change in accounting policy.

        (b) Convertible debentures

        The Fund applies CICA 3863 "Financial Instruments - Presentation" in
        accounting for convertible debentures which results in their
        classification as liabilities. The convertible debentures also have
        an embedded conversion feature which must be segregated between
        liabilities and equity, based on the relative fair market value of
        the liability and equity portions. Therefore, the debenture
        liabilities are presented at less than their eventual maturity
        values. The liability and equity components are further reduced for
        issuance costs initially incurred. The discount of the liability
        component, net of issuance costs, as compared to maturity value is
        accreted by the effective interest method over the debenture term. As
        debentures are converted to Trust Units, an appropriate portion of
        the liability and equity components are transferred to Unitholders'
        capital. Interest and accretion expense on the convertible debentures
        are shown on the Consolidated Statements of Income.

        Under US GAAP, the entire convertible debenture balance would be
        shown as a liability. The embedded conversion feature would not be
        accounted for separately as a component of equity. Additionally,
        under US GAAP, issuance costs are generally shown as a deferred
        charge rather than netted from the convertible debenture balance. As
        a result of these US GAAP differences, the convertible debenture
        balance in liabilities represents the actual maturity value of the
        outstanding debentures. Issuance costs are shown separately as a
        deferred charge and are amortized to interest expense over the term
        of the debenture. Given that the convertible debentures are carried
        at maturity value, it is not necessary to accrete the balance over
        the term of the debentures which results in an expense reduction.
        Interest and accretion on convertible debentures represents interest
        expense on the convertible debentures and amortization of the
        associated deferred issuance costs.

        (c) Depletion and depreciation

        For Canadian GAAP, depletion of petroleum and natural gas properties
        and depreciation of lease and well equipment is provided on
        accumulated costs using the unit-of-production method based on
        estimated net proved petroleum and natural gas reserves, before
        royalties, based on forecast prices and costs.

        US GAAP provides for a similar accounting methodology except that
        estimated net proved petroleum and natural gas reserves are net of
        royalties and based on constant prices and costs. Therefore,
        depletion and depreciation under US GAAP will be different since
        changes to royalty rates will impact both proved reserves and
        production and differences between constant prices and costs as
        compared to forecast prices and costs will impact proved reserve
        volumes. Additionally, differences in depletion and depreciation will
        result in divergence of net book value for Canadian GAAP and US GAAP
        from year-to-year and impact future depletion and depreciation
        expense as well as the net book value utilized for future ceiling
        test calculations.

        (d) Ceiling test

        Under Canadian GAAP, petroleum and natural gas assets are evaluated
        each reporting period to determine that the carrying amount is
        recoverable and does not exceed the fair value of the properties in
        the cost centre (the "ceiling test"). The carrying amounts are
        assessed to be recoverable when the sum of the undiscounted net cash
        flows expected from the production of proved reserves, the lower of
        cost and market of unproved properties and the cost of major
        development projects exceeds the carrying amount of the cost centre.
        When the carrying amount is not assessed to be recoverable, an
        impairment loss is recognized to the extent that the carrying amount
        of the cost centre exceeds the sum of the discounted net cash flows
        expected from the production of proved and probable reserves, the
        lower of cost and market of unproved properties and the cost of major
        development projects of the cost centre. The cash flows are estimated
        using expected future product prices and costs and are discounted
        using a risk-free interest rate. For Canadian GAAP purposes,
        Advantage has not recognized an impairment loss since inception.

        Under US GAAP, the carrying amounts of petroleum and natural gas
        assets, net of deferred income taxes, shall not exceed an amount
        equal to the sum of the present value of estimated net future after-
        tax cash flows of proved reserves (at current prices and costs as of
        the balance sheet date) computed using a discount factor of ten
        percent plus the lower of cost or estimated fair value of unproved
        properties. Any excess is charged to expense as an impairment loss.
        Under US GAAP, Advantage recognized an impairment loss of
        $49.5 million in 2001, $28.3 million net of tax, and an impairment
        loss of $535.4 million in 2006, $477.8 million net of tax. The
        impairment loss decreases net book value of property and equipment
        which reduces depletion and depreciation expense subsequently
        recorded as well as future ceiling test calculations.

        (e) Income tax

        The future income tax accounting standard under Canadian GAAP is
        substantially similar to the deferred income tax approach as required
        by US GAAP. Pursuant to Canadian GAAP, substantively enacted tax
        rates are used to calculate future income tax, whereas US GAAP
        applies enacted tax rates. However, there were no tax rate
        differences for the years ended December 31, 2007 and 2006. The
        differences between Canadian GAAP and US GAAP relate to future income
        tax impact on GAAP differences for fixed assets.

        Under US GAAP, an entity that is subject to income tax in multiple
        jurisdictions is required to disclose income tax expense in each
        jurisdiction. The total amount of income taxes in 2006 and 2007 is
        entirely at the provincial level.

        (f) Unitholders' equity

        Unitholders' equity of Advantage consists primarily of Trust Units.
        The Trust Units are redeemable at any time on demand by the holders,
        which is required for the Fund to retain its Canadian mutual fund
        trust status. The holders are entitled to receive a price per Trust
        Unit equal to the lesser of: (i) 85% of the simple average of the
        closing market prices of the Trust Units, on the principal market on
        which the Trust Units are quoted for trading, during the 10 trading-
        day period commencing immediately after the date on which the Trust
        Units are surrendered for redemption; and (ii) the closing market
        price on the principal market on which the Trust Units are quoted for
        trading on the redemption date. For Canadian GAAP purposes, the Trust
        Units are considered permanent equity and are presented as a
        component of Unitholders' equity.

        Under US GAAP, it is required that equity with a redemption feature
        be presented as temporary equity between the liability and equity
        sections of the balance sheet. The temporary equity is shown at an
        amount equal to the redemption value based on the terms of the Trust
        Units. Changes in the redemption value from year-to-year are charged
        to deficit. All components of Unitholders' equity related to Trust
        Units are eliminated. When calculating net income per Trust Unit,
        increases in the redemption value during a period results in a
        reduction of net income available to Unitholders while decreases in
        the redemption value increases net income available to Unitholders.
        For the years ended December 31, 2007 and 2006, net income available
        to Unitholders was increased by $390.3 million and $898.0 million
        corresponding to changes in the Trust Units redemption value for the
        respective periods.

        A continuity schedule of significant equity accounts for each
        reporting period is required disclosure under US GAAP. The following
        table is a continuity of deficit, the Fund's only significant equity
        account:

                                                     Year ended   Year ended
        Deficit                                     December 31, December 31,
        (thousands of Canadian dollars)                    2007         2006
        ---------------------------------------------------------------------

        Balance, beginning of year                  $  (402,158) $  (665,627)
        Net income (loss) and comprehensive income
         (loss)                                          50,610     (417,274)
        Distributions declared                         (215,194)    (217,246)
        Change in redemption value of temporary
         equity                                         390,349      897,989
        ---------------------------------------------------------------------
        Balance, end of year                        $  (176,393) $  (402,158)
        ---------------------------------------------------------------------

        (g) Balance Sheet Disclosure

        US GAAP requires disclosure of certain line items for balances that
        would be aggregated in the Canadian GAAP financials. The following
        are the additional line items to be disclosed for accounts receivable
        and accounts payable:

                                                    December 31, December 31,
        (thousands of Canadian dollars)                    2007         2006
        ---------------------------------------------------------------------
        Accounts receivable
          Trade receivables                         $    94,959  $    78,698
          Other receivables                                 515          839
        ---------------------------------------------------------------------
        Total accounts receivable                   $    95,474  $    79,537
        ---------------------------------------------------------------------



                                                    December 31, December 31,
        (thousands of Canadian dollars)                    2007         2006
        ---------------------------------------------------------------------
        Accounts payable and accrued liabilities
          Accounts payable                          $    72,691  $    75,500
          Accrued liabilities                            48,994       39,999
          Other payables                                    402          610
        ---------------------------------------------------------------------
        Total accounts payable and accrued
         liabilities                                $   122,087  $   116,109
        ---------------------------------------------------------------------

        (h) Statements of cash flow

        The differences between Canadian GAAP and US GAAP have not resulted
        in any significant variances concerning the statements of cash flows
        as reported.

        (i) Ketch acquisition

        On June 23, 2006, Advantage acquired all of the issued and
        outstanding Trust Units of Ketch to benefit from an increase in
        property diversification, the ability to pursue a greater range of
        high impact growth opportunities available to a larger entity and
        complimentary summer/winter drilling programs. The merger provides
        increased liquidity and presence in the Canadian markets as well as
        greater exposure to the United States capital markets for previous
        Ketch Unitholders through Advantage's NYSE listing.

        The purchase price for the acquisition and resulting goodwill is due
        to both US and Canadian GAAP requiring the purchase price to be
        determined using Trust Unit prices at the announcement date, while
        the fair value of the assets and liabilities is determined at the
        closing date of the acquisition. As commodity prices decreased
        significantly between the announcement and closing dates, the fair
        value of the assets acquired also decreased and as a result, goodwill
        was recorded.

        (j) Sound acquisition

        On September 5, 2007, Advantage acquired all of the issued and
        outstanding Trust Units and Exchangeable Shares of Sound. The
        accounting for business combinations is effectively the same under US
        and Canadian GAAP. However, the purchase price under US GAAP is
        different as a result of AOG realizing a future income tax asset from
        previously unrecognized temporary differences. The purchase price
        under US GAAP has been allocated as follows:

        Net assets acquired and liabilities
        assumed:                               Consideration:

        Fixed assets             $ 480,226     16,977,184 Trust
                                                Units issued       $ 228,852
        Future income tax asset     29,430     Cash                   21,403
        Accounts receivable         27,433     Acquisition costs
                                                incurred                 904
        Prepaid expenses and                                       ----------
         deposits                    3,873                         $ 251,159
        Derivative asset, net        2,797                         ----------
        Bank indebtedness         (107,959)
        Convertible debentures    (101,553)
        Accounts payable and
         accrued liabilities       (35,396)
        Future income tax
         liability                 (29,430)
        Asset retirement
         obligations               (16,695)
        Capital lease obligations   (1,567)
                                 ----------
                                 $ 251,159
                                 ----------

        (k) Recent US Accounting Pronouncements Issued But Not Implemented

        SFAS 157 Fair Value Measurements: This Statement defines fair value,
        establishes a framework for measuring fair value in GAAP, and expands
        disclosures about fair value measurements. This Statement applies
        under other accounting pronouncements that require or permit fair
        value measurements. Accordingly, this Statement does not require any
        new fair value measurements. The implementation effective date for
        this standard is as of the beginning of the first interim or annual
        reporting period that begins after November 15, 2007. The Fund has
        assessed the impact of this interpretation and does not anticipate
        any significant impact on the consolidated financial statements.

        SFAS 141 ® Business Combinations: This Statement requires assets
        and liabilities acquired in a business combination, contingent
        consideration, and certain acquired contingencies to be measured at
        their fair values as of the date of acquisition. In addition,
        acquisition-related and restructuring costs are to be recognized
        separately from the business combination. This standard applies to
        business combinations entered into after January 1, 2009. The Fund
        has not yet assessed the full impact, if any, of this standard on the
        consolidated financial statements.

        The application of US GAAP would have the following effect on net
        income as reported:

        Consolidated Statements of Income and
        Comprehensive Income                         Year ended   Year ended
        (thousands of Canadian dollars,             December 31, December 31,
         except for per Trust Unit amounts)                2007         2006
        ---------------------------------------------------------------------
        Net income (loss) - Canadian GAAP, as
         reported                                   $    (7,535) $    49,814
        US GAAP Adjustments:
          General and administrative - note 15(a)           606        1,453
          Management internalization - note 15(a)         7,450        4,684
          Interest and accretion on convertible
           debentures - note 15(b)                        1,741        1,254
          Depletion, depreciation and accretion -
           notes 15(c) and (d)                           72,990     (528,734)
          Future income tax reduction - note 15(e)      (24,642)      55,526
        ---------------------------------------------------------------------
        Net income (loss) before cumulative effect
         of a change in accounting principle             50,610     (416,003)
        Cumulative effect of a change in accounting
         principle - note 15(a)                               -       (1,271)
        ---------------------------------------------------------------------
        Net income (loss) and comprehensive income
         (loss) - US GAAP                           $    50,610  $  (417,274)
        ---------------------------------------------------------------------
        Net income (loss) per Trust Unit before
         cumulative effect of a change in accounting
         principle - US GAAP:
          Basic                                     $      0.42  $     (5.14)
          Diluted                                   $      0.42  $     (5.14)
        Net income (loss) per Trust Unit before
         change in redemption value of Trust Units -
         US GAAP:
          Basic                                     $      0.42  $     (5.15)
          Diluted                                   $      0.42  $     (5.15)
        Net income per Trust Unit - US GAAP:
          Basic                                     $      3.69  $      5.94
          Diluted                                   $      3.54  $      5.59
        ---------------------------------------------------------------------

        The application of US GAAP would have the following effect on the
        balance sheets as reported:

        Consolidated Balance   December 31, 2007         December 31, 2006
        Sheets                 -----------------         -----------------
        (thousands of        Canadian           US     Canadian           US
         Canadian dollars)       GAAP         GAAP         GAAP         GAAP
        ---------------------------------------------------------------------
        Assets
          Deferred charge
           - note 15(b)   $         -  $     1,984  $         -  $     2,810
          Fixed assets, net
           - notes 15(c)
           and (d)          2,177,346    1,673,251    1,753,058    1,205,465

        Liabilities and
         Unitholders'
         Equity
          Current portion of
           convertible
           debentures
           - note 15(b)         5,333        5,392        1,464        1,485
          Trust Unit
           liability
           - note 15(a)             -        7,515            -        7,633
          Convertible
           debentures
           - note 15(b)       212,203      219,674      170,819      179,245
          Future income
           taxes
           - note 15(e)        66,727            -       61,939            -
          Temporary equity
           - note 15(f)             -    1,104,831            -    1,067,790
          Unitholders'
           capital
           - note 15(f)     2,027,065            -    1,592,758            -
          Convertible
           debentures
           equity
           component
           - note 15(b)         9,632            -        8,041            -
          Contributed
           surplus
           - note 15(a)         2,005            -          863            -
          Accumulated
           deficit
           - note 15(f)      (659,835)    (176,393)    (437,106)    (402,158)


    Advisory

    The information in this release contains certain forward-looking
statements. These statements relate to future events or our future
performance. All statements other than statements of historical fact may be
forward-looking statements. Forward-looking statements are often, but not
always, identified by the use of words such as "seek", "anticipate", "plan",
"continue", "estimate", "expect", "may", "will", "project", "predict",
"potential", "targeting", "intend", "could", "might", "should", "believe",
"would" and similar expressions. These statements involve substantial known
and unknown risks and uncertainties, certain of which are beyond Advantage's
control, including: the impact of general economic conditions; industry
conditions; changes in laws and regulations including the adoption of new
environmental laws and regulations and changes in how they are interpreted and
enforced; fluctuations in commodity prices and foreign exchange and interest
rates; stock market volatility and market valuations; volatility in market
prices for oil and natural gas; liabilities inherent in oil and natural gas
operations; uncertainties associated with estimating oil and natural gas
reserves; competition for, among other things, capital, acquisitions, of
reserves, undeveloped lands and skilled personnel; incorrect assessments of
the value of acquisitions; changes in income tax laws or changes in tax laws
and incentive programs relating to the oil and gas industry and income trusts;
geological, technical, drilling and processing problems and other difficulties
in producing petroleum reserves; and obtaining required approvals of
regulatory authorities. Advantage's actual results, performance or achievement
could differ materially from those expressed in, or implied by, such
forward-looking statements and, accordingly, no assurances can be given that
any of the events anticipated by the forward-looking statements will transpire
or occur or, if any of them do, what benefits that Advantage will derive from
them. Except as required by law, Advantage undertakes no obligation to
publicly update or revise any forward-looking statements.%SEDAR: 00016522E          %CIK: 0001259995



For further information:

For further information: Investor Relations, Toll free: 1-866-393-0393,
Advantage Energy Income Fund, 700, 400 -3rd Avenue SW, Calgary, Alberta, T2P
5E9, Phone: (403) 718-8100, Fax: (403) 718-8300, Web Site:
www.advantageincome.com, E-mail: advantage@advantageincome.com


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