News Releases

Advantage Announces 3rd Quarter Results, Conference Call & Webcast on November 13, 2007

Nov 13, 2007


    CALGARY, Nov. 12 /CNW/ - Advantage Energy Income Fund (TSX: AVN.UN)
("Advantage" or the "Fund") is pleased to announce its unaudited operating and
financial results for the third quarter ended September 30, 2007.
    A conference call will be held on Tuesday, November 13, 2007 at 9:00 a.m.
MST (11:00 a.m. EST). The conference call can be accessed toll-free at
1-866-334-4934. A replay of the call will be available from approximately 2:00
p.m. EST on November 13, 2007 until approximately midnight, November 28, 2007
and can be accessed by dialing toll free 1-866-245-6755. The passcode required
for playback is 271037. A live web cast of the conference call will be
accessible via the Internet on Advantage's website at www.advantageincome.com.Financial and Operating Highlights

                              Three        Three        Nine         Nine
                              months       months       months       months
                              ended        ended        ended        ended
                            September    September    September    September
                             30, 2007     30, 2006     30, 2007     30, 2006
    -------------------------------------------------------------------------
    Financial ($000)
    Revenue before
     royalties(1)           $ 130,830    $ 124,521    $ 391,407    $ 292,188
      per Trust Unit(2)     $    1.09    $    1.26    $    3.43    $    3.97
      per boe               $   48.46    $   45.57    $   50.32    $   48.75
    Funds from operations   $  62,345    $  63,110    $ 190,624    $ 152,021
      per Trust Unit(3)     $    0.51    $    0.63    $    1.64    $    2.04
      per boe               $   23.10    $   23.10    $   24.52    $   25.37
    Net income (loss)       $ (26,202)   $   1,209    $ (21,330)   $  41,078
      per Trust Unit(2)     $   (0.22)   $    0.01    $   (0.19)   $    0.56
    Distributions declared  $  55,017    $  60,498    $ 157,319    $ 158,455
      per Trust Unit(3)     $    0.45    $    0.60    $    1.35    $    2.10
    Expenditures on
     property and equipment $  32,418    $  49,607    $ 107,792    $  98,378
    Working capital
     deficit(4)             $  24,666    $  33,340    $  24,666    $  33,340
    Bank indebtedness       $ 521,144    $ 372,514    $ 521,144    $ 372,514
    Convertible debentures
     (face value)           $ 281,273    $ 180,730    $ 281,273    $ 180,730
    Operating
    Daily Production
      Natural gas (mcf/d)     115,991      122,227      113,104       86,303
      Crude oil and NGLs
       (bbls/d)                10,014        9,330        9,641        7,571
      Total boe/d @
       6:1                     29,346       29,701       28,492       21,955
    Average prices
    (including hedging)
      Natural gas ($/mcf)   $    6.35    $    5.90    $    7.30    $    6.68
      Crude oil and NGLs
       ($/bbl)              $   68.51    $   67.77    $   63.11    $   65.24
    Supplemental (000)
    Trust Units outstanding
     at end of period         133,847      104,055      133,847      104,055
    Trust Units issuable
      Convertible
       Debentures              12,069        8,334       12,069        8,334
      Trust Units Rights
       Incentive Plan             150          188          150          188
    Trust Units outstanding
     and issuable at end of
     period                   146,066      112,577      146,066      112,577
    Basic weighted average
     Trust Units              120,080       98,781      114,132       73,544

    (1) includes realized hedging 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



                           MESSAGE TO UNITHOLDERS

    Highlights for the third quarter 2007 include:

    -   On September 5, 2007, the acquisition of Sound Energy Trust
        successfully closed. Results of operations from Sound have been
        included with Advantage's results from September 5, 2007. This highly
        accretive and synergistic transaction provides stable production, a
        large suite of under-capitalized assets and more oil opportunities.
        Our drilling inventory has increased to well over five years (750
        locations) and tax pools increased to $1.6 billion.

    -   Production volumes were on track with expectations for the third
        quarter of 2007. Volumes increased 8% to 29,346 boe/d compared to the
        second quarter of 2007 mainly due to the inclusion of 26 days of
        Sound Energy Trust volumes in the third quarter. New wells were also
        tied-in during the latter part of the quarter that resulted from our
        highly successful drilling program which had a 100% success rate in
        the third quarter. Negative impacts on production in the third
        quarter resulted from significant third party facility maintenance
        outages and wet weather during the early part of the quarter which
        delayed the tie-in and drilling of new oil and gas wells. In
        addition, approximately 400 boe/d of natural gas production was
        temporarily curtailed at Glacier due to third party facility
        constraints. This production is anticipated to return in the latter
        part of the fourth quarter.

    -   Natural gas production for the third quarter of 2007 increased 6% to
        116.0 mmcf/d compared to 109.0 mmcf/d reported in the second quarter
        of 2007. Crude oil and natural gas liquids production increased 12%
        to 10,014 bbls/d compared to 8,952 bbls/d in the second quarter of
        2007.

    -   Distributions declared as a percent of funds from operations
        increased slightly to 88% for the third quarter compared to 83% for
        the second quarter of 2007 despite a 25% decrease in natural gas
        prices. Reduced natural gas prices from the previous quarter were
        partially offset by hedging gains and the inclusion of 26 days of
        accretive cash flow from the Sound properties in the third quarter.
        Distributions declared as a percent of funds from operations is 83%
        for the nine months ended September 30, 2007, which is on-track with
        expectations.

    -   The Fund declared three distributions during the quarter totaling
        $0.45 per Trust Unit. Since inception, the Fund has distributed
        $821.9 million or $15.84 per Trust Unit.

    -   Funds from operations for the third quarter of 2007 was $62.3 million
        or $0.51 per Trust Unit compared to $62.6 million or $0.54 per Trust
        Unit for the second quarter of 2007. The lower funds from operations
        per unit is due to the issuance of additional Trust Units related to
        the Sound acquisition with only 26 days of realized revenue in the
        quarter and weaker natural gas prices.

    -   Capital spending during Q3 2007 was a net $32.4 million. During the
        quarter a total of 18.3 net (31 gross) wells were drilled at a 100%
        success rate.

    -   Per unit operating costs in Q3 2007 have increased by 4% to
        $11.40/boe when compared to Q2 2007. Q3 costs were higher due to the
        higher operating cost structure of the Sound assets acquired. Total
        operating costs have increased by 14% from Q2 2007 and 28% from Q3 of
        2006 which reflects higher industry costs as well as higher operating
        costs associated with the Sound assets.

    Alberta Royalty Program Changes

    -   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 that are producing in Alberta. As a result of our diverse
        asset base, we also have 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 of that play. Our exposure in Northeast British
        Columbia and Saskatchewan also affords us further flexibility with
        mitigating the royalty impact in our capital program.

    Hedging Position

    -   Advantage has layered in several hedges on both natural gas and oil
        which provides floor protection through summer 2007 and winter
        2007/2008 for natural gas.

    -   Given current weakness in natural gas prices, Advantage is well
        positioned through to March 2008. For the fourth quarter of 2007, the
        Fund currently has approximately 42% of our net natural gas
        production hedged at an average floor price of $8.09/mcf and an
        average ceiling of $9.42/mcf. For the first quarter of 2008,
        Advantage has 22% of our net natural gas production hedged at a floor
        price of $8.85/mcf and a ceiling of $10.19/mcf.

    -   Advantage has been opportunistic with respect to hedging and will
        continue to monitor the forward prices to protect cash flow. We
        anticipate hedging approximately 50% of our production in 2008.

    Looking Forward

    -   We are reiterating our guidance for a 2007 exit production rate of
        approximately 35,000 boe/d for 2007. On an annual basis, we expect to
        average approximately 30,000 boe/d for 2007.

    -   Operating costs are expected to be approximately $12.50 to $13.50 on
        a per boe basis for the fourth quarter of 2007 with the inclusion of
        the Sound assets. Sound's assets have higher operating costs but have
        a greater exposure to oil which provides improved netbacks given the
        current crude oil pricing environment. Advantage will continue to
        aggressively pursue optimization initiatives to reduce costs.
        Industry service and supply costs may subside in the future as
        significant reductions in drilling activity could lead to a more
        competitive market.

    -   Royalty rates are expected to remain in the 19% to 20% range for
        2007.

    -   We are directing approximately 80% of our capital spending toward
        more oil projects for the remainder of the 2007 year due to continued
        higher crude oil pricing. Total exploration and development capital
        for 2007 is expected to approximate $150 million. Advantage's highly
        attractive and large drilling inventory allows flexibility in our
        capital allocation and an ability to high grade our projects.

    -   Advantage has exceptional tax pool coverage which will help reduce
        the amount of tax leakage to Unitholders for several years after
        2011. Including the acquisition of Sound, the Fund has approximately
        $1.6 billion in tax pools which was one of the highest in the sector
        as a multiple of estimated annual cash flow.

    -   Advantage is well positioned for upside opportunities in this
        'buyer's market' with an estimated safe harbour of $2 billion.MANAGEMENT'S DISCUSSION & ANALYSIS

    The following Management's Discussion and Analysis ("MD&A"), dated as of
November 12, 2007, provides a detailed explanation of the financial and
operating results of Advantage Energy Income Fund ("Advantage", the "Fund",
"us", "we" or "our") for the three and nine months ended September 30, 2007
and should be read in conjunction with the consolidated financial statements
contained within this interim report and the audited financial statements and
MD&A for the year ended December 31, 2006. 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             Nine months ended
                       September 30                  September 30
                      2007      2006  % change      2007      2006  % change
    -------------------------------------------------------------------------
    Cash provided
     by operating
     activities   $ 65,314  $ 78,971     (17)%  $165,766  $163,592        1%
    Expenditures
     on asset
     retirement      1,128     1,065        6%     4,835     2,512       92%
    Changes in
     non-cash
     working
     capital        (4,097)  (16,926)    (76)%    20,023   (14,083)   (242)%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Funds from
     operations   $ 62,345  $ 63,110      (1)%  $190,624  $152,021       25%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------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
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 three and nine months ended September 30, 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 consideration to acquire Sound. The transaction is accretive to
Advantage's Unitholders on a production, cash flow, reserves and net asset
value basis and will significantly increase Advantage's tax pool position to a
total of approximately $1.6 billion, and Safe Harbour expansion room is
anticipated to be 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. The combined trust has an
estimated enterprise value of $2.3 billion.Overview

                   Three months ended             Nine months ended
                       September 30                  September 30
                      2007      2006  % change      2007      2006  % change
    -------------------------------------------------------------------------
    Cash provided
     by operating
     activities
     ($000)       $ 65,314  $ 78,971     (17)%  $165,766  $163,592        1%
    Funds from
     operations
     ($000)       $ 62,345  $ 63,110      (1)%  $190,624  $152,021       25%
      per Trust
       Unit(1)    $   0.51  $   0.63     (19)%  $   1.64  $   2.04     (20)%
    Net income
     (loss)
     ($000)       $(26,202) $  1,209  (2,267)%  $(21,330) $ 41,078    (152)%
      per Trust
       Unit
        - Basic   $  (0.22) $   0.01  (2,300)%  $  (0.19) $   0.56    (134)%
        - Diluted $  (0.22) $   0.01  (2,300)%  $  (0.19) $   0.56    (134)%

    (1) Based on Trust Units outstanding at each distribution record date.Cash provided by operating activities decreased 17%, funds from
operations decreased 1%, and funds from operations per Trust Unit decreased
19% for the three months ended September 30, 2007, as compared to the same
period of 2006. For the nine months ended September 30, 2007, cash provided by
operating activities increased 1%, funds from operations increased 25%, and
funds from operations per Trust Unit decreased 20%. Cash provided by operating
activities and funds from operations for the quarter has been primarily
negatively impacted by lower natural gas prices and higher operating costs.
However, cash provided by operating activities and funds from operations for
the nine months has significantly benefited from the increased production,
particularly due to the Ketch acquisition in the second quarter of 2006. Funds
from operations per Trust Unit has been impacted during the periods due to
lower funds from operations relative to a higher average number of Trust Units
outstanding. The weighted average number of Trust Units has increased 22% and
55% for the three and nine months ended in 2007 compared to 2006, mainly due
to the Sound acquisition in 2007, the Ketch acquisition, the Fund's Trust Unit
financing in the first quarter of 2007 and the distribution reinvestment plan.
When compared to the second quarter of 2007, funds from operations was
comparable as production increased 8%, mainly due to the acquisition of Sound,
and was offset by decreased realized natural gas prices before hedging of 25%.
Reduced natural gas prices were partially mitigated by increased realized
crude oil and NGL prices before hedging of 12% and an increase in realized
hedging gains of $7.3 million.
    Net income decreased to a net loss for both the three and nine months
ended September 30, 2007, compared to 2006. The lower net income has been
primarily due to additional future income tax expense related to the new tax
legislation concerning income trusts, higher operating costs, as well 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             Nine months ended
                       September 30                  September 30
                      2007      2006  % change      2007      2006  % change
    -------------------------------------------------------------------------
    Distributions
     declared
     ($000)       $ 55,017  $ 60,498      (9)%  $157,319  $158,455      (1)%
      per Trust
       Unit(1)    $   0.45  $   0.60     (25)%  $   1.35  $   2.10     (36)%

     (1) Based on Trust Units outstanding at each distribution record date.Total distributions declared decreased 9% for the three months and 1% for
the nine months ended September 30, 2007 when compared to the same periods in
2006. Total distributions declared are slightly lower as a result of the
decrease in the distribution per Trust Unit in January 2007, being offset by
the increased Trust Units outstanding from the continued growth and
development of the Fund. Since natural gas prices had been very weak during
the 2006/2007 winter season, we reduced the distribution level to more
appropriately reflect the commodity price environment. Distributions per Trust
Unit were $0.45 for the three months and $1.35 for the nine months ended
September 30, 2007, representing a decrease of 25% and 36% from same periods
in 2006. The monthly distribution is currently $0.15 per Trust Unit. To
mitigate the persisting risk associated with lower natural gas prices and the
resulting negative impact on distributions, the Fund implemented a hedging
program in 2006 with 56% of natural gas hedged for April to October 2007. See
"Commodity Price Risk" section for a more detailed discussion of our price
risk management.
    Distributions 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.Revenue
                   Three months ended             Nine months ended
                       September 30                  September 30
    ($000)            2007      2006  % change      2007      2006  % change
    -------------------------------------------------------------------------
    Natural gas
     excluding
     hedging      $ 60,022  $ 66,228      (9)%  $213,115  $157,239       36%
    Realized
     hedging
     gains           7,687       118    6,414%    12,171       118   10,214%
    -------------------------------------------------------------------------
    Natural gas
     including
     hedging      $ 67,709  $ 66,346        2%  $225,286  $157,357       43%
    -------------------------------------------------------------------------
    Crude oil
     and NGLs
     excluding
     hedging      $ 63,598  $ 58,175        9%  $164,908  $134,831       22%
    Realized
     hedging
     gains
     (losses)         (477)        -         -     1,213         -         -
    -------------------------------------------------------------------------
    Crude oil
     and NGLs
     including
     hedging      $ 63,121  $ 58,175        9%  $166,121  $134,831       23%
    -------------------------------------------------------------------------
    Total
     revenue      $130,830  $124,521        5%  $391,407  $292,188       34%
    -------------------------------------------------------------------------Natural gas revenues, excluding hedging, have decreased 9% for the three
months and increased 36% for the nine months ended September 30, 2007,
compared to 2006. The decrease in natural gas revenues, excluding hedging, for
the three months is mainly due to a 5% decrease in natural gas production and
realized natural gas prices from the same period in 2006. Conversely, the
increase in natural gas revenues, excluding hedging, for the nine month period
ended in 2007 is mainly due to increased production from the inclusion of a
full nine months of production from the Ketch merger and a modest increase in
the realized natural gas price of 3% compared to 2006. Crude oil and NGL
revenues, excluding hedging, have increased by 9% for the three months and 22%
for the nine months ended September 30, 2007, compared to 2006. Crude oil and
NGL revenue increased due to additional production revenues from the Sound
acquisition since September 5, 2007 and the inclusion of a full nine months of
production from the Ketch merger. For the three and nine months ended
September 30, 2007, the Fund recognized natural gas and crude oil net hedging
gains of $7.2 million and $13.4 million primarily due to effective hedging
contracts in place that offset weaker commodity prices experienced during
2007, particularly natural gas prices.Production

                   Three months ended             Nine months ended
                       September 30                  September 30
                      2007      2006  % change      2007      2006  % change
    -------------------------------------------------------------------------
    Natural gas
     (mcf/d)       115,991   122,227      (5)%   113,104    86,303       31%
    Crude oil
     (bbls/d)        7,750     6,982       11%     7,308     5,978       22%
    NGLs (bbls/d)    2,264     2,348      (4)%     2,333     1,593       46%
    -------------------------------------------------------------------------
    Total (boe/d)   29,346    29,701      (1)%    28,492    21,955       30%
    -------------------------------------------------------------------------
    Natural gas (%)    66%       69%                 66%       66%
    Crude oil (%)      26%       24%                 26%       27%
    NGLs (%)            8%        7%                  8%        7%The Fund's total daily production averaged 29,346 boe/d for the three
months and 28,492 boe/d for the nine months ended September 30, 2007, a
decrease of 1% and an increase of 30%, respectively, compared with the same
periods of 2006. Natural gas production decreased 5%, crude oil production
increased 11%, and NGLs production decreased 4% for the third quarter of 2007.
For the nine months ended September 30, 2007, natural gas production increased
31%, crude oil production increased 22%, and NGLs production increased 46%.
Production for the quarter is similar to the prior year as natural production
declines have been primarily offset by capital development activity and
additional production from the Sound properties for the 26 days since closing
the acquisition. The increase in production year to date for 2007 from 2006
has been primarily attributed to a full nine months of production from the
Ketch acquisition in 2007, which closed June 23, 2006, and the Sound
acquisition which contributed 26 days of production. Production for the third
quarter increased 8% from the second quarter of 2007 due to the acquisition of
Sound. This was offset by a significant amount of 3rd party facility outages
that were anticipated and wet weather during July that delayed tie-ins of oil
and gas wells.
    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, 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 the remainder of the year, we are directing our drilling
activity toward crude oil projects with an estimated exit rate of production
of approximately 35,000 boe/d.Commodity Prices and Marketing

    Natural Gas

                   Three months ended            Nine months ended
                       September 30                  September 30
    ($/mcf)           2007      2006  % change      2007      2006  % change
    -------------------------------------------------------------------------
    Realized natural
     gas prices
      Excluding
       hedging     $ 5.62     $ 5.89      (5)%    $ 6.90    $ 6.67        3%
      Including
       hedging     $ 6.35     $ 5.90        8%    $ 7.30    $ 6.68        9%
    AECO monthly
     index         $ 5.62     $ 6.03      (7)%    $ 6.81    $ 7.19      (5)%Realized natural gas prices, excluding hedging, decreased 5% for the
three months and increased 3% for the nine months ended September 30, 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 have
declined due to high storage injections, mild summer weather and lack of storm
activity in the Gulf of Mexico. Inventory levels remain higher than the five
year average, causing continued downward pressure on commodity prices which
decreased significantly through the summer and have been continuing to
decrease since the end of 2006. Although it appears that we can expect
prolonged weak natural gas prices in the short-term, 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 2007 and 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            Nine months ended
                       September 30                  September 30
    ($/bbl)           2007      2006  % change      2007      2006  % change
    -------------------------------------------------------------------------
    Realized crude
     oil prices
      Excluding
       hedging     $ 70.22   $ 69.77        1%   $ 64.60   $ 66.97      (4)%
      Including
       hedging     $ 69.55   $ 69.77         -   $ 65.21   $ 66.97      (3)%
    Realized NGLs
     prices
      Excluding
       hedging     $ 64.95   $ 61.84        5%   $ 56.55   $ 58.73      (4)%
    Realized crude
     oil and NGLs
     prices
      Excluding
       hedging     $ 69.03   $ 67.77        2%   $ 62.65   $ 65.24      (4)%
      Including
       hedging     $ 68.51   $ 67.77        1%   $ 63.11   $ 65.24      (3)%
    WTI ($US/bbl)  $ 75.33   $ 70.55        7%   $ 66.22   $ 68.42      (3)%
    $US/$Canadian
     exchange rate $  0.96   $  0.89        8%   $  0.91   $  0.88        3%Realized crude oil and NGLs prices, excluding hedging, increased 2% for
the three months and decreased 4% for the nine months ended September 30,
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 and nine months ended September 30, 2007, WTI increased 7% and
decreased 3%, respectively, with significant increases experienced in the
third quarter of 2007. Advantage's realized crude oil price has not changed to
the same extent as WTI due to the change in foreign exchange rates and changes
in 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 continue to increase. With the
current high price levels, it is notable that demand has remained resilient.
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.Currently, the Fund has the following derivatives in place:

    Description of
     Derivative           Term             Volume            Average Price
    -------------------------------------------------------------------------
    Natural gas
     - AECO
      Fixed price     April 2007 to
                       October 2007     9,478 mcf/d             Cdn$7.16/mcf
      Fixed price     April 2007 to
                       October 2007     9,478 mcf/d             Cdn$7.55/mcf
      Fixed price     November 2007 to
                       March 2008       7,109 mcf/d             Cdn$9.54/mcf
      Collar          March 2007 to
                       December 2007    9,478 mcf/d      Floor  Cdn$7.91/mcf
                                                       Ceiling  Cdn$9.50/mcf
      Collar          May 2007 to
                       December 2007    4,739 mcf/d      Floor  Cdn$7.91/mcf
                                                       Ceiling  Cdn$9.50/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

      Collar          January 2007 to
                       December 2007     500 bbls/d      Floor  US$70.00/bbl
                                                       Ceiling  US$74.30/bbl
      Collar          March 2007 to
                       December 2007   1,000 bbls/d      Floor  US$57.00/bbl
                                                       Ceiling  US$70.00/bbl
      Collar          April 2007 to
                       December 2007     500 bbls/d      Floor  US$60.00/bbl
                                                       Ceiling  US$71.50/bblAs at September 30, 2007 the fair value of the derivatives outstanding
was a net asset of approximately $11.3 million. For the nine months ended
September 30, 2007, $2.0 million was recognized in income as an unrealized
derivative loss due to a decrease in the fair value from December 31, 2006 and
$13.4 million was recognized in income as a realized derivative gain, which
partially alleviated lower revenue from reduced commodity prices, particularly
natural gas. As a result of the Sound acquisition, the Fund assumed several of
these 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 September 30, 2007 and is based on
pricing models, estimates, assumptions and market data available at that time.
The actual gain or loss realized on 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 or liability recorded on the
balance sheet.
    In addition, the Fund has the following physical natural gas contracts in
place that are not recognized on the balance sheet at fair value, but instead
have gains and losses recognized in earnings as the contracts settle:Description
     of Physical
     Contract            Term                Volume         Average Price
    -------------------------------------------------------------------------
    Natural gas
     - AECO
      Collar   April 2007 to October 2007  4,739 mcf/d    Floor Cdn$7.12/mcf
                                                        Ceiling Cdn$8.67/mcf
      Collar   April 2007 to October 2007  4,739 mcf/d    Floor Cdn$6.86/mcf
                                                        Ceiling Cdn$9.13/mcf
      Collar   April 2007 to October 2007  9,478 mcf/d    Floor Cdn$7.39/mcf
                                                        Ceiling Cdn$9.63/mcf
      Collar   April 2007 to October 2007  9,478 mcf/d    Floor Cdn$6.33/mcf
                                                        Ceiling Cdn$7.20/mcfAlthough the Fund has several fixed price contracts expiring soon, we
will be closely monitoring commodity markets and will pursue new opportunities
to enter contracts that will mitigate commodity price changes for 2008.

    Currently, the Fund has fixed the commodity price on anticipated
production as follows:Approximate
                                   Production
                                 Hedged, Net of
    Commodity                      Royalties    Minimum Price  Maximum Price
    -------------------------------------------------------------------------
    Natural gas - AECO
      April 2007 to October 2007       56%      Cdn$7.14/mcf   Cdn$8.18/mcf
      November 2007 to March 2008      27%      Cdn$8.71/mcf   Cdn$10.08/mcf
    Crude Oil - WTI
      April 2007 to October 2007       17%      US$64.05/bbl   US$85.58/bbl
      November 2007 to December 2007   19%      US$61.00/bbl   US$71.45/bbl


    Royalties

                   Three months ended             Nine months ended
                       September 30                  September 30
                      2007      2006  % change      2007      2006  % change
    -------------------------------------------------------------------------
    Royalties, net
     of Alberta
     Royalty
     Credit
     ($000)       $ 22,601  $ 22,945      (1)%  $ 71,515  $ 53,107       35%
       per boe    $   8.37  $   8.40         -  $   9.19  $   8.86        4%
    As a percentage
     of revenue,
     excluding
     hedging         18.3%     18.4%    (0.1)%     18.9%     18.2%      0.7%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 are comparable for the quarter and have increased for the
nine months ended September 30, 2007 due to the increase in revenue from
higher production. Royalties as a percentage of revenue, excluding hedging,
have increased slightly from the 2006 period due to the inclusion of slightly
higher royalty rate properties from the Ketch acquisition. We expect the
royalty rate to remain comparable for the remainder of 2007.
    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, the effect on cash flow will be affected by depths and productivity of
wells and makes them 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             Nine months ended
                       September 30                  September 30
                      2007      2006  % change      2007      2006  % change
    -------------------------------------------------------------------------
    Operating
     costs ($000) $ 30,790  $ 24,369       26%  $ 87,979  $ 55,108       60%
      per boe     $  11.40  $   8.92       28%  $  11.31  $   9.19       23%Total operating costs increased 26% for the three months and 60% for the
nine months ended September 30, 2007 as compared to 2006, mainly due to
increased production from the Ketch acquisition which was completed June 23,
2006. Total operating costs also increased slightly for the Sound acquisition
with 26 days of costs included in the three and nine months ended
September 30, 2007. Operating costs per boe increased 28% for the three months
and 23% for the nine months ended September 30, 2007, mainly due to lower
production levels related to second quarter third party turnaround activity
that extended into the third quarter, an extended spring break-up, and
increased service and supply costs as the industry experienced overall cost
increases. However, third quarter 2007 per unit operating costs increased by
only 4% when compared to the three months ended June 30, 2007 with the
inclusion of Sound and higher maintenance costs which are typical for the
period. We will continue to be opportunistic and proactive in pursuing
optimization initiatives that will improve our operating cost structure. The
Fund has been active in preserving the price of power costs by hedging 3.5 MW
at $56.68/MWh for 2007 and 3.0 MW at $54.00/MWh for 2008, which represents a
significant portion of our power usage. We anticipate additional savings in
the newly acquired higher operating cost Sound properties combined with
existing Advantage properties. We expect that operating costs per boe will be
in the range of $12.50 to $13.50 for the fourth quarter of 2007 which will
include the full impact of the Sound acquisition.General and Administrative

                   Three months ended             Nine months ended
                       September 30                  September 30
                      2007      2006  % change      2007      2006  % change
    -------------------------------------------------------------------------
    General and
     administrative
     expense
     ($000)       $  4,543  $  4,766      (5)%  $ 13,491  $  9,152       47%
      per boe     $   1.68  $   1.74      (3)%  $   1.73  $   1.53       13%General and administrative ("G&A") expense has decreased 5% for the three
months and increased 47% for the nine months ended September 30, 2007, as
compared to 2006. G&A per boe decreased 3% for the three months and increased
13% for the nine months when compared to the same periods of 2006. G&A expense
for the nine months ended September 30, 2007 has increased overall and per boe
primarily due to an increase in staff levels that have resulted from the
June 23, 2006 Ketch acquisition and 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 that 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.

    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 result 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. No RTUs have been
granted under the Plan at this time and accordingly, no compensation expense
relating to the RTUs has been recognized in the interim financial statements.
Once the calendar year is completed and the final Trust Unit return is
calculated for the return period RTUs may be granted and consequently,
compensation expense may be recognized at that time. As the Fund did not meet
the 2006 grant thresholds, there was no RTU grant made for the 2006 year.
    For the nine months ended September 30, 2007, the Fund has accrued
unit-based compensation expense of $0.8 million 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          Nine months ended
                           September 30                September 30
                         2007      2006  % change    2007      2006 % change
    -------------------------------------------------------------------------
    Management fee
     ($000)           $      -  $      -      -   $      -  $    887  (100)%
      per boe         $      -  $      -      -   $      -  $   0.15  (100)%
    Performance
     incentive ($000) $      -  $      -      -   $      -  $  2,380  (100)%
    Management
     internalization
     ($000)           $  2,455  $  7,428   (67)%  $ 13,174  $  7,952     66%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           Nine months ended
                          September 30                September 30
                         2007      2006  % change    2007      2006  % change
    -------------------------------------------------------------------------
    Interest expense
     ($000)           $  6,242  $  5,711      9%  $ 16,434  $ 12,844     28%
    per boe           $   2.31  $   2.09     11%  $   2.11  $   2.14    (1)%
    Average effective
     interest rate        5.9%      5.2%    0.7%      5.6%      5.0%    0.6%
    Bank indebtedness
     at September 30
     ($000)                                       $521,144  $372,514     40%Interest expense has increased 9% for the three months and 28% for the
nine months ended September 30, 2007, as compared to 2006. Interest expense
per boe has increased 11% for the three months and decreased 1% for the nine
months ended September 30, 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 Sound and Ketch 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 5.6% for the nine months ended September 30, 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          Nine months ended
                          September 30                September 30
                         2007      2006  % change    2007      2006 % change
    -------------------------------------------------------------------------
    Interest on
     convertible
     debentures
     ($000)           $  3,910  $  3,308     18%  $ 10,441  $  7,921     32%
      per boe         $   1.45  $   1.21     20%  $   1.34  $   1.32      2%
    Accretion on
     convertible
     debentures
     ($000)           $    644  $    604      7%  $  1,848  $  1,502     23%
      per boe         $   0.24  $   0.22      9%  $   0.24  $   0.25    (4)%
    Convertible
     debentures
     maturity
     value at
     September 30
     ($000)                                       $281,273  $180,730     56%Interest on convertible debentures has increased 18% for the three months
and 32% for the nine months ended September 30, 2007, as compared to 2006.
Accretion on convertible debentures has increased 7% for the three months and
23% for the nine months ended September 30, 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
and accretion per boe for the quarter is higher as our convertible debentures
outstanding has slightly increased relative to our level of production.Cash Netbacks
                                               Three months ended
                                                   September 30
                                             2007                2006
                                         $000    per boe     $000    per boe
    -------------------------------------------------------------------------
    Revenue                           $123,620  $  45.79  $124,403  $  45.53
    Realized gain on derivatives         7,210      2.67       118      0.04
    Royalties, net of Alberta
     Royalty Credit                    (22,601)    (8.37)  (22,945)    (8.40)
    Operating costs                    (30,790)   (11.40)  (24,369)    (8.92)
    -------------------------------------------------------------------------
    Operating                         $ 77,439  $  28.69  $ 77,207  $  28.25

    General and administrative          (4,543)    (1.68)   (4,766)    (1.74)
    Management fee                           -         -         -         -
    Interest                            (6,242)    (2.31)   (5,711)    (2.09)
    Interest on convertible
     debentures                         (3,910)    (1.45)   (3,308)    (1.21)
    Income and capital taxes              (399)    (0.15)     (312)    (0.11)
    -------------------------------------------------------------------------
    Funds from operations             $ 62,345  $  23.10  $ 63,110  $  23.10
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------


                                                 Nine months ended
                                                   September 30
                                             2007                2006
                                         $000    per boe     $000    per boe
    -------------------------------------------------------------------------
    Revenue                           $378,023  $  48.60  $292,070  $  48.73
    Realized gain on derivatives        13,384      1.72       118      0.02
    Royalties, net of Alberta
     Royalty Credit                    (71,515)    (9.19)  (53,107)    (8.86)
    Operating costs                    (87,979)   (11.31)  (55,108)    (9.19)
    -------------------------------------------------------------------------
    Operating                         $231,913  $  29.82  $183,973  $  30.70

    General and administrative         (13,491)    (1.73)   (9,152)    (1.53)
    Management fee                           -         -      (887)    (0.15)
    Interest                           (16,434)    (2.11)  (12,844)    (2.14)
    Interest on convertible
     debentures                        (10,441)    (1.34)   (7,921)    (1.32)
    Income and capital taxes              (923)    (0.12)   (1,148)    (0.19)
    -------------------------------------------------------------------------
    Funds from operations             $190,624  $  24.52  $152,021  $  25.37
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------Funds from operations of Advantage for the quarter ended September 30,
2007 decreased to $62.3 million from $63.1 million in the prior year. Funds
from operations for the nine months ended September 30, 2007 increased to
$190.6 million from $152.0 million compared to 2006. The cash netback per boe
for the three months ended September 30, 2007 remained comparable to the same
quarter of 2006, but decreased 3% from $25.37 to $24.52 for the nine months
ended September 30, 2007. The lower cash netback per boe for the nine months
ended September 30, 2007 is primarily due to higher royalties and operating
costs. Operating costs have steadily increased over the past year due to
significantly higher field costs associated with supplies and services that
has resulted from the high level of industry activity and an overall industry
labour cost increase. Although we have experienced significant upward pressure
on operating costs, it is notable that operating costs per boe for the quarter
remained comparable to the second quarter of 2007. When compared to the second
quarter of 2007, funds from operations was similar as production increased 8%,
mainly due to the acquisition of Sound, and was offset by decreased realized
natural gas prices before hedging of 25%. Reduced natural gas prices were
partially mitigated by increased realized crude oil and NGL prices before
hedging of 12% and an increase in realized hedging gains of $7.3 million.Depletion, Depreciation and Accretion

                       Three months ended           Nine months ended
                          September 30                September 30
                         2007      2006  % change    2007      2006  % change
    -------------------------------------------------------------------------

    Depletion,
     depreciation &
     accretion ($000) $ 68,743  $ 67,601      2%  $194,026  $130,788     48%
      per boe         $  25.46  $  24.74      3%  $  24.94  $  21.82     14%Depletion and depreciation of property and equipment is provided on the
"unit-of-production" method based on total proved reserves. The depletion,
depreciation and accretion ("DD&A") provision has increased 2% for the three
months and 48% for the nine months ended September 30, 2007. The nine months
increase is due to the considerable increases of daily production volumes,
mainly from the Ketch acquisition 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.

    Taxes

    Current taxes paid or payable for the quarter ended September 30, 2007
amounted to $0.4 million, which is comparable to the $0.3 million expensed for
the same period of 2006. 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 nine months ended September 30,
2007, the Fund recognized an income tax expense of $0.2 million compared to a
reduction of $17.5 million for 2006. The impact of the Specified Investment
Flow-Through Entity ("SIFT") tax legislation is reflected in 2007 and resulted
in future income tax expense of $13.8 million. The new tax law has altered the
tax treatment of income trusts 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. As at September 30, 2007, we had a future
income tax liability balance of $84.1 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
$22.0 million.
    On October 30, 2007, the Federal government announced proposed corporate
income tax rate reductions effective January 1, 2008 to be phased in over the
next five years to 2012. These rate reductions will apply to the new tax on
distributions of income trusts and other specified investment flow-through
entities as of 2011 with a proposed rate reduction of 2% from the current 2011
tax rate and an additional 1.5% rate reduction in 2012. The Fund is currently
assessing the impact of such proposed income tax rate reductions and will
recognize a future income tax reduction once the proposed rate reductions are
substantively enacted.

    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.2011 &
                                           Payments due by period      there-
    ($ millions)               Total    2007    2008    2009    2010   after
    -------------------------------------------------------------------------

    Building leases           $ 30.1  $  1.2  $  6.3  $  6.7  $  6.7  $  9.2
    Capital leases               8.7     0.7     1.9     2.0     2.2     1.9
    Pipeline/transportation      7.8     1.7     4.8     1.2     0.1       -
    Convertible debentures (1) 281.3     1.5     5.4   116.6    70.0    87.8
    -------------------------------------------------------------------------
    Total contractual
     obligations              $327.9  $  5.1  $ 18.4  $126.5  $ 79.0  $ 98.9
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
     (1) As at September 30, 2007, Advantage had $281.3 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 $521.1 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)                 September 30, 2007
    -------------------------------------------------------------------------
    Bank indebtedness (long-term)                             $      521,144
    Working capital deficit (1)                                       24,666
    -------------------------------------------------------------------------
    Net debt                                                  $      545,810
    -------------------------------------------------------------------------
    Trust Units outstanding (000)                                    133,847
    Trust Unit closing market price ($/Trust Unit)            $        12.22
    -------------------------------------------------------------------------
    Market value                                              $    1,635,610
    -------------------------------------------------------------------------
    Capital lease obligation (long-term)                      $        5,969
    Convertible debentures maturity value (long-term)                274,401
    -------------------------------------------------------------------------
    Total capitalization                                      $    2,461,790
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (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 September 30, 2007, the Fund had 133.8 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 to
finalize the acquisition of Sound. As at November 12, 2007, Advantage had
137.5 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
nine months ended September 30, 2007, 2,862,545 Trust Units were issued as a
result of the Plan, generating $34.3 million reinvested in the Fund and
representing an approximate 19% participation rate.
    As at September 30, 2007, the Fund had $281.3 million convertible
debentures outstanding that were convertible to 12.1 million Trust Units based
on the applicable conversion prices. During the nine months ended
September 30, 2007, $5,000 of convertible debentures were converted resulting
in the issuance of 375 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 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 November 12,
2007, the Fund had $224.6 million convertible debentures outstanding due to
the additional conversion of $19,000 convertible debentures to 1,011 Trust
Units and the maturity of $1,470,000 of the 10% convertible debentures
exchanged for 127,458 Trust Units on November 1, 2007.

    Bank Indebtedness, Credit Facility and Other Obligations

    At September 30, 2007, Advantage had bank indebtedness outstanding of
$521.1 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 September 30, 2007, Advantage had a working capital deficiency of
$24.7 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.
    During the quarter ended September 30, 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. On
September 5, 2007, Advantage assumed two capital lease obligations in the
acquisition of Sound resulting in the recognition of a capital lease
obligation 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.Capital Expenditures

                                      Three months ended   Nine months ended
                                          September 30        September 30
    ($000)                               2007      2006      2007      2006
    -------------------------------------------------------------------------
    Land and seismic                  $    221  $  1,461  $  4,142  $  4,739
    Drilling, completions and
     workovers                          22,156    35,819    64,766    70,534
    Well equipping and facilities        9,751    11,560    38,325    21,747
    Other                                  290       767       559     1,358
    -------------------------------------------------------------------------
                                      $ 32,418  $ 49,607  $107,792  $ 98,378
    Acquisition of Sound Energy Trust   22,374         -    22,374         -
    Property acquisitions                    -       198    12,851       198
    Property dispositions                    -    (8,727)     (427)   (8,727)
    -------------------------------------------------------------------------
    Total capital expenditures        $ 54,792  $ 41,078  $142,590  $ 89,849
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------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 preserve 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 September 30, 2007, the Fund spent a net
$32.4 million and drilled a total of 18.3 net (31 gross) wells at a 100%
success rate. During the quarter we drilled 3 net (3 gross) oil wells and 2
net (2 gross) gas wells at Nevis, 2.8 net (4 gross) oil wells at Sunset, 1 net
(1 gross) each oil and gas well at Willesden Green, 3 net (3 gross) gas wells
at Girouxville, as well as several wells at other minor properties. Total
capital spending in the quarter included $8.7 million at Nevis, $5.9 million
at Willesden Green, $3.6 million at Sunset, $2.4 million at Martin Creek and
$1.6 million in Southeast Saskatchewan. 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
$22.4 million related to the Sound acquisition in the third quarter which
represents the cash portion paid due to the exercise of the cash option
offered to Sound unitholders.
    Capital spending, before property acquisitions and dispositions, for the
nine months ended September 30, 2007 was below our internal plans due to
prolonged wet weather resulting in a long spring break-up and restricted
access. The reduced spending has been partially responsible for delays in
bringing on expected production in the second and third quarters of 2007.
However, the Fund still anticipates spending the full capital budget for the
2007 year, in addition to the Sound acquisition.
    The following table summarizes the various funding requirements during
the nine months ended September 30, 2007 and the sources of funding to meet
those requirements.Sources and Uses of Funds

                                                           Nine months ended
    ($000)                                                September 30, 2007
    -------------------------------------------------------------------------
    Sources of funds
      Funds from operations                                     $    190,624
      Units issued, net of costs                                     104,240
      Increase in bank indebtedness                                    2,611
      Property dispositions                                              427
    -------------------------------------------------------------------------
                                                                $    297,902
    -------------------------------------------------------------------------
    Uses of funds
      Distributions to Unitholders                              $    121,900
      Expenditures on property and equipment                         107,792
      Increase in working capital                                     25,566
      Acquisition of Sound Energy Trust                               22,374
      Property acquisitions                                           12,851
      Expenditures on asset retirement                                 4,835
      Reduction of capital lease obligations                           2,584
    -------------------------------------------------------------------------
                                                                $    297,902
    -------------------------------------------------------------------------

    Quarterly Performance


    ($000, except as otherwise                       2007               2006
     indicated)                             Q3        Q2        Q1        Q4
    -------------------------------------------------------------------------
    Daily production
      Natural gas (mcf/d)              115,991   108,978   114,324   117,134
      Crude oil and NGLs (bbls/d)       10,014     8,952     9,958     9,570
      Total (boe/d)                     29,346    27,115    29,012    29,092
    Average prices
      Natural gas ($/mcf)
        Excluding hedging             $   5.62  $   7.54  $   7.61  $   6.90
        Including hedging             $   6.35  $   7.52  $   8.06  $   7.27
        AECO monthly index            $   5.62  $   7.37  $   7.46  $   6.36
      Crude oil and NGLs ($/bbl)
        Excluding hedging             $  69.03  $  61.84  $  56.84  $  54.58
        Including hedging             $  68.51  $  61.93  $  58.64  $  55.86
        WTI (US$/bbl)                 $  75.33  $  65.02  $  58.12  $  60.21
    Total revenues (before royalties) $130,830  $125,075  $135,502  $127,539
    Net income (loss)                 $(26,202) $  4,531  $    341  $  8,736
     per Trust Unit - basic           $  (0.22) $   0.04  $   0.00  $   0.08
                    - diluted         $  (0.22) $   0.04  $   0.00  $   0.08
    Funds from operations             $ 62,345  $ 62,634  $ 65,645  $ 62,737
    Distributions declared            $ 55,017  $ 52,096  $ 50,206  $ 58,791


    ($000, except as otherwise                       2006               2005
     indicated)                             Q3        Q2        Q1        Q4
    -------------------------------------------------------------------------
    Daily production
      Natural gas (mcf/d)              122,227    70,293    65,768    72,587
      Crude oil and NGLs (bbls/d)        9,330     6,593     6,760     7,106
      Total (boe/d)                     29,701    18,309    17,721    19,204
    Average prices
      Natural gas ($/mcf)
        Excluding hedging             $   5.89  $   6.18  $   8.69  $  11.68
        Including hedging             $   5.90  $   6.18  $   8.69  $  10.67
        AECO monthly index            $   6.03  $   6.28  $   9.31  $  11.68
      Crude oil and NGLs ($/bbl)
        Excluding hedging             $  67.77  $  68.69  $  58.26  $  60.14
        Including hedging             $  67.77  $  68.69  $  58.26  $  59.53
        WTI (US$/bbl)                 $  70.55  $  70.75  $  63.88  $  60.04
    Total revenues (before royalties) $124,521  $ 80,766  $ 86,901  $110,172
    Net income (loss)                 $  1,209  $ 23,905  $ 15,964  $ 25,846
     per Trust Unit - basic           $   0.01  $   0.38  $   0.27  $   0.45
                    - diluted         $   0.01  $   0.38  $   0.27  $   0.45
    Funds from operations             $ 63,110  $ 42,281  $ 46,630  $ 60,906
    Distributions declared            $ 60,498  $ 53,498  $ 44,459  $ 43,265The table above highlights the Fund's performance for the third quarter
of 2007 and also for the preceding seven quarters. During the first quarter of
2006 we experienced a decrease in daily production due to a one-time
adjustment for several payout wells, restricted production on wells in Chip
Lake and Nevis, and some minor non-core property dispositions that occurred in
2005. Production increased in the second quarter of 2006 as some prior quarter
issues were resolved and the addition of eight days of production from the
Ketch properties. Production further increased in the third quarter of 2006 as
the Ketch acquisition 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 the period. The third quarter
of 2007 includes the financial and operating results from the acquired Sound
properties for 26 days. 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, offset by lower natural gas
prices. Net income has been lower during the last four quarters 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 merger.

    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 property and equipment, 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.

    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 the third
quarter of 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.

    Outlook

    The Fund's 2007 Budget, as approved by the Board of Directors, retained a
high degree of activity and focused on drilling in many of our key properties
where a high level of success was realized through 2006. Capital has also been
directed to accommodate facility expansions and further develop 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 through the first nine months of 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 third quarter of 2007, we realized significant impacts to our
production due to third party plant outages. Wet weather through July affected
the tie-in of new well production and reduced capital activity in the second
and third quarters of 2007. Overall, we expect annual production in 2007 to be
approximately 30,000 boe/d with a year-end exit rate of approximately
35,000 boe/d.
    Advantage's 2007 capital expenditures is estimated to be approximately
$150 million which includes activity for the Sound assets during the fourth
quarter of 2007. For the remainder of 2007, our capital program will be
directed mainly at oil opportunities due to the continued strong commodity
prices.
    Per unit operating costs for 2007 are estimated to be in the $11.60 to
$12.00/boe range and $12.50 to $13.50/boe range for the fourth quarter with
the full impact of the Sound acquisition that had higher operating cost
properties. Higher property taxes, surface rentals and additional trucking
costs due to continued pipeline restrictions in Southeast Saskatchewan have
been realized so far in 2007. Advantage is undertaking several operating cost
reduction initiatives throughout 2007 to help offset these increases and we
have begun to realize some key achievements in this area.
    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. For
2007, we estimate our royalty rate to be approximately 19-20%.
    Advantage's funds from operations in 2007 will continue to be impacted by
the volatility of crude oil and natural gas prices and the $US/$Canadian
exchange rate. 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 acquisitions.
    Looking forward, Advantage's high quality assets combined with a greater
than five year drilling inventory, hedging program and significant tax pools
provides many options for the Fund and we are committed to maximizing value
generation for our Unitholders.

    Additional 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.


    November 12, 2007Consolidated Financial Statements

    Consolidated Balance Sheets
                                                  September 30,  December 31,
    (thousands of dollars)                                2007          2006
    -------------------------------------------------------------------------
                                                    (unaudited)
    Assets
    Current assets
      Accounts receivable                           $   89,564    $   79,537
      Prepaid expenses and deposits                     19,688        16,878
      Derivative asset (note 11)                        12,692         9,840
    -------------------------------------------------------------------------
                                                       121,944       106,255
    Deposit on property acquisition                          -         1,410
    Derivative asset (note 11)                             189           593
    Fixed assets (note 3)                            2,194,515     1,753,058
    Goodwill                                           120,271       120,271
    -------------------------------------------------------------------------
                                                    $2,436,919    $1,981,587
    -------------------------------------------------------------------------
    Liabilities
    Current liabilities
      Accounts payable and accrued liabilities      $  105,234    $  116,109
      Distributions payable to Unitholders              20,077        18,970
      Current portion of capital lease
       obligations (note 4)                              1,821         2,527
      Current portion of convertible debentures
       (note 5)                                          6,786         1,464
      Derivative liability (note 11)                     1,607             -
    -------------------------------------------------------------------------
                                                       135,525       139,070
    Capital lease obligations (note 4)                   5,969           305
    Bank indebtedness (note 6)                         521,144       410,574
    Convertible debentures (note 5)                    230,924       170,819
    Asset retirement obligations (note 7)               53,737        34,324
    Future income taxes (note 8)                        84,113        61,939
    -------------------------------------------------------------------------
                                                     1,031,412       817,031
    -------------------------------------------------------------------------
    Unitholders' Equity
    Unitholders' capital (note 9)                    1,973,513     1,592,758
    Convertible debentures equity component (note 5)    46,010         8,041
    Contributed surplus (note 9)                         1,739           863
    Accumulated deficit (note 10)                     (615,755)     (437,106)
    -------------------------------------------------------------------------
                                                     1,405,507     1,164,556
    -------------------------------------------------------------------------
                                                    $2,436,919    $1,981,587
    -------------------------------------------------------------------------
    Commitments (note 12)

    see accompanying Notes to Consolidated Financial Statements



    Consolidated Statements of Income,
    Comprehensive Income and Accumulated Deficit

                                   Three       Three        Nine        Nine
                                  months      months      months      months
    (thousands of dollars,         ended       ended       ended       ended
     except for per Trust       Sept. 30,   Sept. 30,   Sept. 30,   Sept. 30,
     Unit amounts) (unaudited)      2007        2006        2007        2006
    -------------------------------------------------------------------------
    Revenue
      Petroleum and natural
       gas                    $  123,620  $  124,403  $  378,023  $  292,070
      Realized gain on
       derivatives (note 11)       7,210         118      13,384         118
      Unrealized gain (loss)
       on derivatives (note 11)      (53)     13,725      (1,956)     14,257
      Royalties, net of
       Alberta Royalty Credit    (22,601)    (22,945)    (71,515)    (53,107)
    -------------------------------------------------------------------------
                                 108,176     115,301     317,936     253,338
    -------------------------------------------------------------------------
    Expenses
      Operating                   30,790      24,369      87,979      55,108
      General and administrative   4,543       4,766      13,491       9,152
      Unit-based compensation
       (note 9)                      156           -         785           -
      Management fee                   -           -           -         887
      Performance incentive            -           -           -       2,380
      Management
       internalization (note 9)    2,455       7,428      13,174       7,952
      Interest                     6,242       5,711      16,434      12,844
      Interest and accretion
       on convertible
       debentures                  4,554       3,912      12,289       9,423
      Depletion, depreciation
       and accretion              68,743      67,601     194,026     130,788
    -------------------------------------------------------------------------
                                 117,483     113,787     338,178     228,534
    -------------------------------------------------------------------------
    Income (loss) before taxes
     and non-controlling
     interest                     (9,307)      1,514     (20,242)     24,804
    Future income tax expense
     (reduction)                  16,496          (7)        165     (17,451)
    Income and capital taxes         399         312         923       1,148
    -------------------------------------------------------------------------
                                  16,895         305       1,088     (16,303)
    -------------------------------------------------------------------------
    Net income (loss) before
     non-controlling interest    (26,202)      1,209     (21,330)     41,107
    Non-controlling interest           -           -           -          29
    -------------------------------------------------------------------------
    Net income (loss) and
     comprehensive income (loss) (26,202)      1,209     (21,330)     41,078
    Accumulated deficit,
     beginning of period        (534,536)   (327,762)   (437,106)   (269,674)
    Distributions declared       (55,017)    (60,498)   (157,319)   (158,455)
    -------------------------------------------------------------------------
    Accumulated deficit, end
     of period                $ (615,755) $ (387,051) $ (615,755) $ (387,051)
    -------------------------------------------------------------------------
    Net income (loss) per
     Trust Unit (note 9)
      Basic                   $    (0.22) $     0.01  $    (0.19) $     0.56
      Diluted                 $    (0.22) $     0.01  $    (0.19) $     0.56
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

    see accompanying Notes to Consolidated Financial Statements



    Consolidated Statements of Cash Flows

                                   Three       Three        Nine        Nine
                                  months      months      months      months
                                   ended       ended       ended       ended
    (thousands of dollars)      Sept. 30,   Sept. 30,   Sept. 30,   Sept. 30,
    (unaudited)                     2007        2006        2007        2006
    -------------------------------------------------------------------------

    Operating Activities

    Net income (loss)         $  (26,202) $    1,209  $  (21,330) $   41,078
    Add (deduct) items not
     requiring cash:
      Unrealized loss (gain)
       on derivatives                 53     (13,725)      1,956     (14,257)
      Unit-based compensation        156           -         785           -
      Performance incentive            -           -           -       2,380
      Management
       internalization             2,455       7,428      13,174       7,952
      Accretion on convertible
       debentures                    644         604       1,848       1,502
      Depletion, depreciation
       and accretion              68,743      67,601     194,026     130,788
      Future income tax           16,496          (7)        165     (17,451)
      Non-controlling interest         -           -           -          29
    Expenditures on asset
     retirement                   (1,128)     (1,065)     (4,835)     (2,512)
    Changes in non-cash
     working capital               4,097      16,926     (20,023)     14,083
    -------------------------------------------------------------------------
    Cash provided by
     operating activities         65,314      78,971     165,766     163,592
    -------------------------------------------------------------------------
    Financing Activities
    Units issued, net of costs
     (note 9)                       (246)    152,200     104,240     152,673
    Increase (decrease) in
     bank indebtedness            35,373    (128,323)      2,611     (68,827)
    Reduction of capital
     lease obligations              (514)       (371)     (2,584)       (642)
    Distributions to
     Unitholders                 (42,595)    (63,359)   (121,900)   (152,106)
    -------------------------------------------------------------------------
    Cash used in financing
     activities                   (7,982)    (39,853)    (17,633)    (68,902)
    -------------------------------------------------------------------------
    Investing Activities
    Expenditures on property
     and equipment               (32,418)    (49,607)   (107,792)    (98,378)
    Property acquisitions              -        (198)    (12,851)       (198)
    Property dispositions              -       8,727         427       8,727
    Acquisition of Ketch
     Resources Trust                   -           -           -     (10,236)
    Acquisition of Sound
     Energy Trust (note 2)       (22,374)          -     (22,374)          -
    Changes in non-cash
     working capital              (2,540)      1,960      (5,543)      5,395
    -------------------------------------------------------------------------
    Cash used in investing
     activities                  (57,332)    (39,118)   (148,133)    (94,690)
    -------------------------------------------------------------------------
    Net change in cash                 -           -           -           -
    Cash, beginning of period          -           -           -           -
    -------------------------------------------------------------------------
    Cash, end of period       $        -  $        -  $        -  $        -
    -------------------------------------------------------------------------
    Supplementary Cash Flow
     Information
      Interest paid           $    6,977  $    9,602  $   24,153  $   25,294
      Taxes paid              $      244  $      176  $    1,074  $    1,446

    see accompanying Notes to Consolidated Financial Statements



                 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

    September 30, 2007 (unaudited)

    All tabular amounts in thousands except for Trust Units and per Trust
    Unit amounts

    The interim consolidated financial statements of Advantage Energy Income
    Fund ("Advantage" or the "Fund") have been prepared by management in
    accordance with Canadian generally accepted accounting principles using
    the same accounting policies as those set out in note 2 to the
    consolidated financial statements for the year ended December 31, 2006,
    except as described below. The interim consolidated financial statements
    should be read in conjunction with the audited consolidated financial
    statements of Advantage for the year ended December 31, 2006 as set out
    in Advantage's Annual Report.

    1. Changes in Accounting Policies

    (a) 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 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.

        (b) Comprehensive Income

        Effective January 1, 2007, the Fund adopted CICA Handbook section
        1530 "Comprehensive Income". The Fund has adopted this section
        retroactively and there were no changes to prior periods.
        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.

        (c) 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.

        (d) 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.

        (e) Comparative Figures

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

    2.  Acquisition of 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 $1.0 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                 Consideration:
         liabilities assumed:

        Fixed assets           $  501,476       16,977,184 Trust
        Accounts receivable        27,237        Units issued     $  228,852
        Prepaid expenses and                     Cash                 21,404
         deposits                   3,930       Acquisition costs
        Derivative asset, net       2,797        incurred                970
        Bank indebtedness        (107,959)                        -----------
        Convertible debentures   (101,553)                        $  251,226
        Accounts payable and                                      -----------
         accrued liabilities      (34,431)
        Future income taxes       (22,009)
        Asset retirement
         obligations              (16,695)
        Capital lease
         obligations               (1,567)
                               -----------
                               $  251,226
                               -----------

        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 is subject to refinement as certain cost estimates are
        realized and the tax balances are finalized.

    3.  Fixed Assets

                                                  Accumulated
                                                 Depletion and    Net Book
        September 30, 2007               Cost     Depreciation      Value
        ---------------------------------------------------------------------
        Petroleum and natural gas
         properties                  $ 2,957,081   $   768,005   $ 2,189,076
        Furniture and equipment            9,671         4,232         5,439
        ---------------------------------------------------------------------
                                     $ 2,966,752   $   772,237   $ 2,194,515
        ---------------------------------------------------------------------

                                                  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 nine months ended September 30, 2007, Advantage
        capitalized general and administrative expenditures and unit-based
        compensation directly related to exploration and development
        activities of $6.0 million (September 30, 2006 - $4.0 million).

    4.  Capital Lease Obligations

        The Fund has capital leases on a variety of fixed assets. Future
        minimum lease payments at September 30, 2007 consist of the
        following:

        2007                   $      708
        2008                        1,906
        2009                        2,040
        2010                        2,200
        2011                        1,925
        ----------------------------------
                                    8,779

        Less amounts
         representing interest       (989)
        ----------------------------------
                                    7,790

        Current portion            (1,821)
        ----------------------------------
                               $    5,969
        ----------------------------------

        During the second quarter 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 2) 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.

        The amortization of fixed assets subject to capital leases is
        recorded in depletion and depreciation expense.

    5.  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          Nov. 1,      Aug. 1,      Feb. 1,     June 30,
                                 2007         2008         2009         2009
        Conversion price  $     13.30  $     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%
        --------------------------------------------------------
        Trading symbol        AVN.DBC      AVN.DBE      AVN.DBD
        Issue date            Sep. 15,      May 18,     Sep. 15,
                                 2004         2005         2004
        Maturity date          Oct. 1,     June 30,      Dec. 1,
                                 2009         2010         2011
        Conversion price  $     20.25  $     24.96  $     21.00
        Liability
         component        $    71,631  $    66,981  $    47,444
        Equity component        3,369        2,971        2,556
        --------------------------------------------------------
        Gross proceeds         75,000       69,952       50,000
        Issuance costs         (3,190)           -       (2,190)
        --------------------------------------------------------
        Net proceeds      $    71,810  $    69,952  $    47,810
        --------------------------------------------------------


                               8.00%         Total
        -------------------------------------------
        Trading symbol        AVN.DBG
        Issue date            Nov. 13,
                                 2006
        Maturity date         Dec. 31,
                                 2011
        Conversion price  $     20.33
        Liability
         component        $    14,884  $   387,826
        Equity component       26,561       53,679
        -------------------------------------------
        Gross proceeds         41,445      441,505
        Issuance costs              -      (11,907)
        -------------------------------------------
        Net proceeds           $ 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
        ---------------------------------------------------------------------
            10.00%           After November 1, 2006
                             and before November 1, 2007            $1,025
        ---------------------------------------------------------------------
            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 September 30, 2007 and
        changes in the liability and equity components during the nine months
        ended September 30, 2007 are as follows:

                               10.00%        9.00%        8.25%        8.75%
        ---------------------------------------------------------------------
        Debentures
         outstanding      $     1,480  $     5,392  $     4,867  $    59,513
        ---------------------------------------------------------------------
        Liability
         component:
          Balance at
           Dec. 31, 2006  $     1,464  $     5,235  $     4,676  $         -
          Assumed on Sound
           acquisition              -            -            -       48,700
          Accretion of
           discount                19           73           68           21
          Converted to
           Trust Units             (5)           -            -            -
        ---------------------------------------------------------------------
          Balance at
           Sep. 30, 2007  $     1,478  $     5,308  $     4,744  $    48,721
        ---------------------------------------------------------------------
        Equity
         component:
          Balance at
           Dec. 31, 2006  $        59  $       229  $       248  $         -
          Assumed on Sound
           acquisition              -            -            -       11,408
          Converted to
           Trust Units              -            -            -            -
        ---------------------------------------------------------------------
          Balance at
           Sep. 30, 2007  $        59  $       229  $       248  $    11,408
        ---------------------------------------------------------------------


                                7.50%        6.50%        7.75%
        --------------------------------------------------------
        Debentures
         outstanding      $    52,268  $    69,952  $    46,766
        --------------------------------------------------------
        Liability
         component:
          Balance at
           Dec. 31, 2006  $    49,782  $    67,361  $    43,765
          Assumed on
           Sound
           acquisition              -            -            -
          Accretion of
           discount               665          546          446
          Converted to
           Trust Units              -            -            -
        --------------------------------------------------------
          Balance at
           Sep. 30, 2007  $    50,447  $    67,907  $    44,211
        --------------------------------------------------------
        Equity
         component:
          Balance at
           Dec. 31, 2006  $     2,248  $     2,971  $     2,286
          Assumed on
           Sound
           acquisition              -            -            -
          Converted to
           Trust Units              -            -            -
        --------------------------------------------------------
          Balance at
           Sep. 30, 2007  $     2,248  $     2,971  $     2,286
        --------------------------------------------------------


                                8.00%        Total
        -------------------------------------------
        Debentures
         outstanding      $    41,035  $   281,273
        -------------------------------------------
        Liability
         component:
          Balance at
           Dec. 31, 2006  $         -  $   172,283
          Assumed on
           Sound
           acquisition         14,884       63,584
          Accretion of
           discount                10        1,848
          Converted to
           Trust Units              -           (5)
        -------------------------------------------
          Balance at
           Sep. 30, 2007  $    14,894  $   237,710
        -------------------------------------------
        Equity
         component:
          Balance at
           Dec. 31, 2006  $         -  $     8,041
          Assumed on
           Sound
           acquisition         26,561       37,969
          Converted to
           Trust Units              -            -
        -------------------------------------------
          Balance at
           Sep. 30, 2007  $    26,561  $    46,010
        -------------------------------------------

        Due to the acquisition of Sound (note 2), 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 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 nine months ended September 30, 2007, $5,000 debentures
        (September 30, 2006 - $24,333,000) were converted resulting in the
        issuance of 375 Trust Units (September 30, 2006 - 1,286,901 Trust
        Units).

    6.  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 Advantage Oil & Gas Ltd. ("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 nine months ended September 30, 2007, the
        effective interest rate on the outstanding amounts under the facility
        was approximately 5.6% (September 30, 2006 - 5.0%).

    7.  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 $217.5
        million which will be incurred between 2007 to 2057. An inflation
        rate of 2% and a credit-adjusted risk-free rate of 7% were used to
        calculate the fair value of the asset retirement obligations.

        A reconciliation of the asset retirement obligations is provided
        below:

                                                   September 30, December 31,
                                                           2007         2006
        ---------------------------------------------------------------------
        Balance, beginning of period                $    34,324  $    21,263
        Accretion expense                                 1,854        1,684
        Assumed in Ketch acquisition                          -        7,930
        Assumed in Sound acquisition (note 2)            16,695            -
        Liabilities incurred                              5,699        9,421
        Liabilities settled                              (4,835)      (5,974)
        ---------------------------------------------------------------------
        Balance, end of period                      $    53,737  $    34,324
        ---------------------------------------------------------------------

    8.  Income Taxes

        On June 12, 2007 the Federal government's bill regarding the taxation
        of distributions from trusts beginning January 1, 2011 received a
        third reading and on June 22, 2007 received Royal Assent, thus
        becoming fully enacted. As a result, a net expense of $13.8 million
        was recognized in the future income tax provision for the nine months
        ended September 30, 2007.

    9.  Unitholders' Equity

        (a)   Unitholders' Capital

              (i)   Authorized

                    Unlimited number of voting Trust Units

              (ii)  Issued

                                                     Number of
                                                       Units        Amount
        ---------------------------------------------------------------------
        Balance at December 31, 2006                105,390,470  $ 1,618,025
        Issued on conversion of debentures                  375            5
        Issued on exercise of Trust Unit rights          37,500          562
        Distribution reinvestment plan                2,862,545       34,313
        Issued for cash, net of costs                 8,600,000      104,094
        Issued for Sound acquisition,
         net of costs (note 2)                       16,977,184      228,608
        Management internalization forfeitures          (21,459)        (434)
        ---------------------------------------------------------------------
                                                    133,846,615  $ 1,985,173
        ---------------------------------------------------------------------
        Management internalization escrowed
         Trust Units                                                 (11,660)
        ---------------------------------------------------------------------
        Balance at September 30, 2007                            $ 1,973,513
        ---------------------------------------------------------------------

        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).

        During the nine months ended September 30, 2007, 2,862,545 Trust
        Units were issued under the Premium Distribution(™), Distribution
        Reinvestment, and Optional Trust Unit Purchase Plan, generating
        $34.3 million reinvested in the Fund.

        On June 23, 2006, 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. 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 nine
        months ended September 30, 2007, a total of 21,459 Trust Units issued
        for the management internalization were forfeited and $13.2 million
        has been recognized as management internalization expense. As at
        September 30, 2007, 1,197,077 Trust Units remain held in escrow.

        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 2). Trust Unit issuance costs of $0.2 million were
        incurred for the Sound acquisition.

        (b)   Trust Units Rights Incentive Plan

                                                  Series B
                                            Number        Price
        --------------------------------------------------------
        Balance at December 31, 2006       187,500  $     10.97
        Exercised                          (37,500)           -
        Reduction of exercise price              -        (1.35)
        --------------------------------------------------------
        Balance at September 30, 2007      150,000  $      9.62
        --------------------------------------------------------

        Expiration date                        June 17, 2008
        --------------------------------------------------------

        (c)   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
        result 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. No RTUs have been granted
        under the Plan at this time and accordingly, no compensation expense
        relating to the RTUs has been recognized in the interim financial
        statements. Once the calendar year is completed and the final Trust
        Unit return is calculated for the return period, RTUs may be granted
        and consequently, compensation expense may be recognized at that
        time. As the Fund did not meet the 2006 grant thresholds, there was
        no RTU grant made for the 2006 year.

        For the nine months ended September 30, 2007, the Fund has accrued
        unit-based compensation expense of $0.8 million and has capitalized
        $0.3 million related to Trust Units issuable for the retention of
        certain employees of the Fund.

        (d)   Net Income (Loss) per Trust Unit

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

                             Three        Three         Nine         Nine
                             months       months       months       months
                             ended        ended        ended        ended
                            Sep. 30,     Sep. 30,     Sep. 30,     Sep. 30,
                              2007         2006         2007         2006
        ---------------------------------------------------------------------
        Income (loss)
         available to
         Unitholders
          Basic           $   (26,202) $     1,209  $   (21,330) $    41,078
        ---------------------------------------------------------------------
          Diluted         $   (26,202) $     1,209  $   (21,330) $    41,078
        ---------------------------------------------------------------------

        Weighted average
         Trust Units
         outstanding
          Basic           120,079,919   98,780,595  114,131,771   73,544,345
          Trust Units
           Rights
           Incentive
           Plan
           - Series A               -            -            -       58,223
          Trust Units
           Rights
           Incentive
           Plan
           - Series B               -       63,111            -       86,621
          Management
           internalization          -       55,069            -       28,944
        ---------------------------------------------------------------------
          Diluted         120,079,919   98,898,775  114,131,771   73,718,133
        ---------------------------------------------------------------------

        The calculation of diluted net income (loss) per Trust Unit excludes
        all series of convertible debentures for the three and nine months
        ended September 30, 2007 and 2006 as well as all of the Series B
        Trust Unit Rights and Management Internalization escrowed Trust Units
        for the three and nine months ended September 30, 2007 as the impact
        would be anti-dilutive. All of the remaining Series A Trust Unit
        Rights were exercised July 7, 2006. Total weighted average Trust
        Units issuable in exchange for the convertible debentures and
        excluded from the diluted net income (loss) per Trust Unit
        calculation for the three and nine months ended September 30, 2007
        were 9,389,620 and 8,690,007, respectively (September 30, 2006 -
        8,337,771 and 6,793,997, respectively). As at September 30, 2007, the
        total convertible debentures outstanding were immediately convertible
        to 12,069,078 Trust Units (September 30, 2006 - 8,334,453).

    10. Accumulated Deficit

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

                                                   September 30, December 31,
                                                           2007         2006
        ---------------------------------------------------------------------
        Accumulated Income                          $   206,193  $   227,523
        Accumulated Distributions                      (821,948)    (664,629)
        ---------------------------------------------------------------------
        Accumulated Deficit                         $  (615,755) $  (437,106)
        ---------------------------------------------------------------------

        For the nine months ended September 30, 2007, the Fund declared
        $157.3 million in distributions, representing $1.35 per distributable
        Trust Unit (nine months ended September 30, 2006 - $158.5 million
        representing $2.10 per distributable Trust Unit).

    11. 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 September 30, 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 5) resulting in fair values that
        will vary over time as market conditions change. As at September 30,
        2007, the estimated fair value of the total outstanding convertible
        debenture obligation was $281.2 million (December 31, 2006 - $180.0
        million). The fair value of the liability component of convertible
        debentures was determined based on a discounted cash flow model
        assuming no future conversions and continuation of current interest
        and principal payments. 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 hedging strategy and manages 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 value 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
        all 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 funds from operations 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 2007 to 2011 (note 5). Interest payments are made
        semi-annually with excess funds from 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 option 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 nine months ended
        September 30, 2007 could potentially have impacted net income by
        approximately $1.9 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 September 30, 2007 could impact net income by
        approximately $2.2 million for the nine months ended September 30,
        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 September
        30, 2007 could impact net income by $0.9 million for the nine months
        ended September 30, 2007. A change of 10% in the forward power prices
        used to calculate the fair value of the power derivatives at
        September 30, 2007 could impact net income by $0.2 million for the
        nine months ended September 30, 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 September 30, 2007 the Fund had the following derivatives in
        place:

        Description of
        Derivative           Term            Volume            Average Price
        ---------------------------------------------------------------------

        Natural gas - AECO

          Fixed price    April 2007 to
                          October 2007     9,478 mcf/d          Cdn$7.16/mcf
          Fixed price    April 2007 to
                          October 2007     9,478 mcf/d          Cdn$7.55/mcf
          Fixed price    November 2007
                         to March 2008     7,109 mcf/d          Cdn$9.54/mcf
          Collar         March 2007 to
                         December 2007     9,478 mcf/d    Floor Cdn$7.91/mcf
                                                        Ceiling Cdn$9.50/mcf
          Collar           May 2007 to
                         December 2007     4,739 mcf/d    Floor Cdn$7.91/mcf
                                                        Ceiling Cdn$9.50/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

          Collar       January 2007 to
                         December 2007      500 bbls/d    Floor US$70.00/bbl
                                                        Ceiling US$74.30/bbl
          Collar         March 2007 to
                         December 2007    1,000 bbls/d    Floor US$57.00/bbl
                                                        Ceiling US$70.00/bbl
          Collar         April 2007 to
                         December 2007      500 bbls/d    Floor US$60.00/bbl
                                                        Ceiling US$71.50/bbl
        Electricity - Alberta Pool Price

          Fixed price    April 2006 to
                         December 2007          0.5 MW         Cdn$60.79/MWh
          Fixed price  January 2007 to
                         December 2007          3.0 MW         Cdn$56.00/MWh
          Fixed price  January 2008 to
                         December 2008          3.0 MW         Cdn$54.00/MWh


        As at September 30, 2007 the fair value of the derivatives
        outstanding resulted in an asset of approximately $12,881,000
        (December 31, 2006 - $10,433,000) and a liability of approximately
        $1,607,000 (December 31, 2006 - nil). For the nine months ended
        September 30, 2007, $1,956,000 was recognized in income as an
        unrealized derivative loss (September 30, 2006 - $14,257,000
        unrealized derivative gain) and $13,384,000 was recognized in income
        as a realized derivative gain (September 30, 2006 - $118,000 realized
        derivative gain).

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

        In addition, the Fund has the following physical natural gas
        contracts in place that are not recognized on the balance sheet at
        fair value, but instead have gains and losses recognized in earnings
        as the contracts settle:

        Description of
        Physical Contract    Term             Volume            Average Price
        ---------------------------------------------------------------------

        Natural gas - AECO

          Collar         April 2007 to
                          October 2007     4,739 mcf/d     Floor Cdn$7.12/mcf
                                                         Ceiling Cdn$8.67/mcf
          Collar         April 2007 to
                          October 2007     4,739 mcf/d     Floor Cdn$6.86/mcf
                                                         Ceiling Cdn$9.13/mcf
          Collar         April 2007 to
                          October 2007     9,478 mcf/d     Floor Cdn$7.39/mcf
                                                         Ceiling Cdn$9.63/mcf
          Collar         April 2007 to
                          October 2007     9,478 mcf/d     Floor Cdn$6.33/mcf
                                                         Ceiling Cdn$7.20/mcf


    12. Commitments

        Advantage has several lease commitments relating to office buildings.
        As a result of the Sound acquisition (note 2), Advantage assumed one
        office lease and has renegotiated additional leases to accommodate
        the growth of the Fund. The estimated annual minimum operating lease
        rental payments for the buildings are as follows:

        2007                                 $     1,187
        2008                                       6,283
        2009                                       6,710
        2010                                       6,725
        2011                                       4,280
        2012 & thereafter                          4,868
        -------------------------------------------------
                                             $    30,053
        -------------------------------------------------


    Directors                               Legal Counsel

    Steven E. Balog(2)                   Burnet, Duckworth and Palmer LLP
    Gary F. Bourgeois
    Kelly I. Drader                      Abbreviations
    Robert B. Hodgins(1)
    John A. Howard(2)                    bbls - barrels
    Andy J. Mah                          bbls/d - barrels per day
    Ronald A. McIntosh(1)(2)             boe - barrels of oil equivalent
    Sheila H. O'Brien(3)                 (6 mcf = 1 bbl)
    Carol D. Pennycook(1)(3)             boe/d - barrels of oil equivalent
    Steven B. Sharpe(3)                  per day
    Rodger A. Tourigny(1)(3)             mcf - thousand cubic feet
    (1) Member of Audit Committee        mcf/d - thousand cubic feet per day
    (2) Member of Reserve Evaluation     mmcf - million cubic feet
        Committee                        mmcf/d - million cubic feet per day
    (3) Member of Human Resources,       gj - gigajoules
        Compensation & Corporate         NGLs - natural gas liquids
        Governance Committee             WTI - West Texas Intermediate
                                         TM - denotes trademark of Canaccord
    Officers                                  Capital Corporation

    Kelly I. Drader, CEO
    Andy J. Mah, President and COO       Corporate Offices
    Patrick J. Cairns, Senior Vice
    President                            Petro-Canada Centre
    Gary F. Bourgeois, Vice President,   Suite 3100,
    Corporate Development                150 - 6 Avenue SW
    Peter A. Hanrahan, Vice President,   Calgary, Alberta T2P 3Y7
    Finance & CFO                        (403) 261-8810
    David Cronkhite, Vice President,
    Operations                           800, 2 St. Clair Avenue East
    Weldon M. Kary, Vice President,      Toronto, Ontario M4T 2T5
    Geosciences and Land                 (416) 945-6636
    Neil Bokenfohr, Vice President,
    Exploitation                         Transfer Agent

    Corporate Secretary                  Computershare Trust Company of
                                         Canada
    Jay P. Reid, Partner
    Burnet, Duckworth and Palmer LLP     Contact Us

    Operating Company                    Toll free: 1-866-393-0393
                                         Visit our website at
    Advantage Oil & Gas Ltd.             www.advantageincome.com

    Auditors                             Toronto Stock Exchange Trading
                                         Symbols
    PricewaterhouseCoopers LLP
                                         Trust Units: AVN.UN
    Bankers                              10% Convertible Debentures: AVN.DB
                                         9% Convertible Debentures: AVN.DBA
    The Bank of Nova Scotia              8.25% Convertible Debentures:
    National Bank of Canada              AVN.DBB
    Bank of Montreal                     7.5% Convertible Debentures: AVN.DBC
    Royal Bank of Canada                 7.75% Convertible Debentures:
    Canadian Imperial Bank of Commerce   AVN.DBD
    Union Bank of California,            6.50% Convertible Debentures:
    Canada Branch                        AVN.DBE
    Société Générale, Canada Branch      8.75% Convertible Debentures:
    Alberta Treasury Branches            AVN.DBF
                                         8% Convertible Debentures: AVN.DBG
    Independent Reserve Evaluators
                                         New York Stock Exchange Trading
    Sproule Associates Limited           Symbol

                                         Trust Units: AAV%SEDAR: 00016522E          %CIK: 0001259995



For further information:

For further information: Toll free: 1-866-393-0393; Visit our website at
www.advantageincome.com


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