News Releases

Advantage Announces 2nd Quarter Results, Conference Call & Webcast on August 15, 2007

Aug 14, 2007


    CALGARY, Aug. 14 /CNW/ - Advantage Energy Income Fund (TSX: AVN.UN)
("Advantage" or the "Fund") is pleased to announce its unaudited operating and
financial results for the first quarter ended June 30, 2007.
    A conference call will be held on Wednesday August 15, 2007 at
9:00 a.m. MST (11:00 a.m. EST). The conference call can be accessed toll-free
at 1-866-334-3876. A replay of the call will be available from approximately
2:00 p.m. EST on August 15, 2007 until approximately midnight, August 29, 2007
and can be accessed by dialing toll free 1-866-245-6755. The passcode required
for playback is 486433. 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        Six         Six
                                 months      months      months      months
                                 ended       ended       ended       ended
                                June 30,    June 30,    June 30,    June 30,
                                  2007        2006        2007        2006
    -------------------------------------------------------------------------
    Financial ($000)
    Revenue before royalties   $ 125,075   $  80,766   $ 260,577   $ 167,667
      per Trust Unit(1)        $    1.10   $    1.29   $    2.35   $    2.76
      per boe                  $   50.69   $   48.48   $   51.31   $   51.42
    Funds from operations      $  62,634   $  42,281   $ 128,279   $  88,911
      per Trust Unit(2)        $    0.54   $    0.62   $    1.13   $    1.41
      per boe                  $   25.38   $   25.39   $   25.26   $   27.27
    Net income                 $   4,531   $  23,905   $   4,872   $  39,869
      per Trust Unit(1)        $    0.04   $    0.38   $    0.04   $    0.66
    Distributions declared     $  52,096   $  53,498   $ 102,302   $  97,957
      per Trust Unit(2)        $    0.45   $    0.75   $    0.90   $    1.50
    Payout ratio (%)                 83%        127%   $     80%   $    110%
    Expenditures on property
     and equipment             $  25,678   $  27,782   $  75,374   $  48,771
    Working capital
     deficit(3)                $  11,512   $  13,774   $  11,512   $  13,774
    Bank indebtedness          $ 377,812   $ 500,837   $ 377,812   $ 500,837
    Convertible debentures
     (face value)              $ 180,725   $ 180,795   $ 180,725   $ 180,795
    Operating
    Daily Production
      Natural gas (mcf/d)        108,978      70,293     111,636      68,043
      Crude oil and NGLs
       (bbls/d)                    8,952       6,593       9,452       6,676
      Total boe/d @ 6:1        27,115      18,309      28,058      18,017
    Average prices (including
     hedging)
      Natural gas ($/mcf)      $    7.52   $    6.18   $    7.80   $    7.39
      Crude oil and NGLs
       ($/bbl)                 $   61.93   $   68.69   $   60.21   $   63.44
    Supplemental (000)
    Trust Units outstanding at
     end of period               116,091      94,689     116,091      94,689
    Trust Units issuable
      Convertible Debentures       8,334       8,339       8,334       8,339
      Trust Units Rights
       Incentive Plan                150         273         150         273
    Trust Units outstanding and
     issuable at end of period   124,575     103,301     124,575     103,301
    Basic weighted average
     Trust Units                 113,854      62,710     111,108      60,803

    (1) based on basic weighted average Trust Units outstanding
    (2) based on Trust Units outstanding at each distribution record date
    (3) working capital deficit excludes derivative assets and liabilities


                           MESSAGE TO UNITHOLDERS

    Highlights for the second quarter 2007 include:

    -   Production volumes in the second quarter of 2007 increased 48% to
        27,115 boe/d compared to 18,309 boe/d in the second quarter of 2006.
        Production volumes in the second quarter of 2007 are higher due to
        volumes from the Ketch acquisition, which closed June 23, 2006.

    -   Natural gas production for the second quarter of 2007 increased 55%
        to 109.0 mmcf/d compared to 70.3 mmcf/d reported in the second
        quarter of 2006. Crude oil and natural gas liquids production
        increased 36% to 8,952 bbls/d compared to 6,593 bbls/d in the second
        quarter of 2006.

    -   Q2 2007 payout ratio decreased to 83% compared to 127% for the same
        period in 2006. The decreased payout ratio is a result of previous
        distribution adjustments and Q2 2006 including only eight days of
        Ketch cash flows in funds from operations while a full month of
        distributions were paid on the corresponding Trust Units issued for
        the acquisition. Our year to date payout ratio is 80% for the six
        months ended June 30, 2007, which is on-track with expectations and
        results from our hedging gains and solid operational performance.

    -   The Fund declared three distributions during the quarter totaling
        $0.45 per Trust Unit. Since inception, the Fund has distributed
        $766.9 million or $15.39 per Trust Unit.

    -   Funds from operations for the second quarter of 2007 was
        $62.6 million or $0.54 per Trust Unit compared to $42.3 million or
        $0.62 per Trust Unit for the same period of 2006.

    -   Capital spending during Q2 2007 included the drilling of 5.8 net
        (10 gross) wells at a 100% success rate. Drilling activity in the
        current quarter amounted to $8 million and $10 million was directed
        to complete facilities work and well completions resulting from our
        highly successful Q1 2007 program. Additionally, $7 million was spent
        on land, seismic and other non-operated activities for total
        exploitation and development capital of $25.7 million in the quarter.
        Success continued in our light oil program at Nevis, Southeast
        Saskatchewan and Sunset and with our gas drilling at Northville and
        Willesden Green.

    -   Per unit operating costs in Q2 2007 have decreased by 6% to
        $10.91/boe when compared to Q1 2007. Q1 costs were higher than normal
        due to winter freezing conditions that created significant one-time
        expenditures. Total operating costs have decreased by 11% from
        Q1 2007 and we are actively pursuing optimization opportunities to
        improve the cost structure.

    Hedging Position

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

    -   Given current weakness in natural gas prices, Advantage is well
        positioned through Q3 & Q4 2007. The Fund currently has approximately
        54% of our net natural gas production hedged for summer at an average
        floor price of $7.08/mcf and an average ceiling of $8.09/mcf. In
        addition, 14% of our net crude oil production has been hedged for the
        same period at an average floor of US$65.00/bbl and a ceiling of
        US$90.00/bbl.

    -   For the winter months and extending into the spring of 2008,
        Advantage has 28% 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.

    Looking Forward

    -   We are reiterating our guidance range of 27,500 to 29,500 boe/d for
        2007. We expect to trend towards the lower end of this range due to
        delays created by the extremely wet weather conditions experienced
        this spring and the continuing third party outages that will occur
        this summer.

    -   Operating costs are expected to be approximately $10.50 to $11.50 on
        a per boe basis due to reduced production through the Q2 and Q3
        periods. However, total operating costs have decreased by 11% in
        Q2 when compared to Q1 2007. Reduced industry drilling activity in
        the last half of 2007 may have a cascade effect of reducing service &
        related costs.

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

    -   Capital spending will be directed toward more oil projects in the
        second half of 2007 due to continued higher crude oil pricing. Total
        exploration and development capital for 2007 is expected to be
        unchanged at $125 to $145 million. Advantage's highly attractive and
        large drilling inventory allows flexibility in our capital
        allocation.

    -   Advantage has exceptional tax pool coverage which will help reduce
        the amount of tax leakage to Unitholders for several years after
        2011. As of December 31, 2006, the Fund had approximately
        $1.2 billion in tax pools which was one of the highest in the sector
        as a percentage of market capitalization.

    Proposed Business Combination with Sound Energy Trust:

    -   On July 9, 2007, Advantage and Sound Energy Trust ("Sound") announced
        that their respective boards of directors had unanimously approved an
        agreement for the business combination of Advantage and Sound. The
        combined trust, which will retain the Advantage name and management,
        will have an initial enterprise value of approximately $2.5 billion.
        The combination will be 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 will be exchanged
        for Advantage Trust Units on the same ratio based on the conversion
        ratio in effect at the effective date of the Arrangement. The
        Arrangement is expected to close in early September 2007.

    -   The key benefits of the transaction are:

        -  Highly accretive on a production, cash flow, reserves and net
           asset value per Trust Unit basis;

        -  Improvement in Advantage's payout ratio;

        -  The Sound assets have a high degree of operating synergies with
           key Advantage properties through facilities optimization
           opportunities and by significantly increasing the number of low
           risk drilling locations. In addition, the net undeveloped land
           inventory increases 111% to 760,000 net acres;

        -  Advantage's tax pools will increase 35% to over $1.6 billion which
           will be one of the highest in the sector relative to market
           capitalization;

        -  Sound's hedging program complements Advantage's hedging program.
           Sound has 55% of their net natural gas production hedged at a
           floor price of $7.91/mcf for Q4 2007; and

        -  The combined entity is estimated to have 2007 exit rate production
           of approximately 35,000 to 36,500 boe/d and a proved plus probable
           reserve life index of approximately 11.8 years using 2007
           estimated exit rate production.MANAGEMENT'S DISCUSSION & ANALYSIS

    The following Management's Discussion and Analysis ("MD&A"), dated as of
August 14, 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 six months ended June 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 and per Trust Unit, cash netbacks, and payout
ratio. 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. Both cash
netbacks and payout ratio are dependent on the determination of funds from
operations. Cash netbacks include the primary cash revenues and expenses on a
per boe basis that comprise funds from operations. Payout ratio represents the
distributions declared for the period as a percentage of funds from
operations. Funds from operations reconciled to cash provided by operating
activities is as follows:Three months ended           Six months ended
                           June 30                     June 30
                        2007      2006  % change    2007      2006  % change
    -------------------------------------------------------------------------
    Cash provided by
     operating
     activities       $ 49,932  $ 44,741     12%  $100,452  $ 84,621     19%
    Expenditures on
     asset retirement     (302)      414  (173)%     3,707     1,447    156%
    Changes in non-cash
     working capital    13,004    (2,874) (552)%    24,120     2,843    748%
    -------------------------------------------------------------------------
    Funds from
     operations       $ 62,634  $ 42,281     48%  $128,279  $ 88,911     44%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------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.

    Proposed Business Combination with Sound Energy Trust

    On July 9, 2007, the Fund and Sound Energy Trust ("Sound") announced that
their respective boards of directors had unanimously approved an agreement for
the business combination of Advantage and Sound. The combined trust, which
will retain the Advantage name, will be led by the existing Advantage
management team.
    The combination will be 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 will be exchanged for Advantage Trust Units on the same
ratio based on the conversion ratio in effect at the effective date of the
Arrangement. The transaction exchange ratio reflected a premium to Sound
Unitholders of 11.3% based on the respective closing price for each trust on
July 6, 2007. 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. Sound Unitholders will receive a significant premium to
recent trading prices and the opportunity to participate in a larger, more
liquid entity with long-life, high-netback assets leading to better
diversification. The combined trust will have an estimated enterprise value of
$2.5 billion.
    Successful completion of the business combination is subject to stock
exchange, court and regulatory approvals and the approval by at least
two-thirds of Sound's Unitholders and Sound Exchangeable Shareholders. It is
anticipated that the Sound Unitholder meeting required to approve the
Arrangement will be held, and the Arrangement is expected to close, in early
September 2007, and that Sound Unitholders will receive Advantage's September
distribution payable on October 15, 2007. An information circular dated August
2, 2007 has been prepared by Sound and mailed to Sound Unitholders.
    The Arrangement prohibits Sound from soliciting or initiating any
discussion regarding any other business combination or sale of material
assets, contains provisions to Advantage to match competing, unsolicited
proposals and, subject to certain conditions, provides for a $12 million
termination fee payable to Advantage.Overview

                      Three months ended           Six months ended
                           June 30                     June 30
                        2007      2006  % change    2007      2006  % change
    -------------------------------------------------------------------------
    Cash provided by
     operating
     activities
     ($000)           $ 49,932  $ 44,741     12%  $100,452  $ 84,621     19%
    Funds from
     operations
     ($000)           $ 62,634  $ 42,281     48%  $128,279  $ 88,911     44%
      per Trust
       Unit(1)        $   0.54  $   0.62   (13)%  $   1.13  $   1.41   (20)%
    Net income ($000) $  4,531  $ 23,905   (81)%  $  4,872  $ 39,869   (88)%
      per Trust Unit
        - Basic       $   0.04  $   0.38   (89)%  $   0.04  $   0.66   (94)%
        - Diluted     $   0.04  $   0.38   (89)%  $   0.04  $   0.65   (94)%

    (1) Based on Trust Units outstanding at each distribution record date.Cash provided by operating activities increased 12%, funds from
operations increased 48%, and funds from operations per Trust Unit decreased
13% for the three months ended June 30, 2007, as compared to the same period
of 2006. For the six months ended June 30, 2007, cash provided by operating
activities increased 19%, funds from operations increased 44%, and funds from
operations per Trust Unit decreased 20%. The increase in cash provided by
operating activities and funds from operations has been primarily due to the
merger with Ketch Resources Trust ("Ketch") that closed on June 23, 2006. The
financial and operating results from the acquired Ketch properties are
included in all 2007 figures but only eight days of these cash flows are
included in the three and six month periods ended June 30, 2006, thereby
explaining most variances. Conversely, funds from operations per Trust Unit
has been negatively impacted during the periods due to higher operating costs
and a higher average number of Trust Units outstanding. Operating costs per
boe were $11.26 in the first six months of 2007, an increase of 19% compared
to $9.43 for the same period of 2006. However, operating costs per boe
decreased 6% from $11.59 in the first quarter of 2007 to $10.91 in the second
quarter. The weighted average number of Trust Units has increased 82% from
2006 to 2007 mainly due to the Ketch acquisition, the Fund's recent Trust Unit
financing in the first quarter of 2007 and the distribution reinvestment plan.
The financings have improved the bank indebtedness and provide financial
flexibility. Net income decreased 81% for the three months and 88% for the six
months ended June 30, 2007, compared to 2006. The lower net income has been
primarily due to 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           Six months ended
                           June 30                     June 30
                        2007      2006  % change    2007      2006  % change
    -------------------------------------------------------------------------
    Distributions
     declared ($000)  $ 52,096  $ 53,498    (3)%  $102,302  $ 97,957      4%
      per Trust
       Unit(1)        $   0.45  $   0.75   (40)%  $   0.90  $   1.50   (40)%
    Payout ratio (%)       83%      127%   (44)%       80%      110%   (30)%

    (1) Based on Trust Units outstanding at each distribution record date.Total distributions decreased 3% for the three months and increased 4%
for the six months ended June 30, 2007 when compared to the same periods in
2006. Total distributions are similar as a result of the decrease in the
distributions 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 have been very weak during the 2006/2007 winter
season, we reduced the distribution level to more appropriately reflect the
current commodity price environment. Distributions per Trust Unit were $0.45
for the three months and $0.90 for the six months ended June 30, 2007,
representing a decrease of 40% from 2006. This reduction positively impacted
the payout ratio for the second quarter of 2007, which was 83%, down from 127%
during the same period of 2006. For the six months ended June 30, 2007, the
payout ratio was 80%, significantly lower than the 110% payout ratio
experienced during the same period of 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 54% 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           Six months ended
                           June 30                     June 30
    ($000)              2007      2006  % change    2007      2006  % change
    -------------------------------------------------------------------------
    Natural gas
     excluding
     hedging          $ 74,760  $ 39,553     89%  $153,093  $ 91,011     68%
    Realized hedging
     gains (losses)       (136)        -       -     4,484         -       -
    -------------------------------------------------------------------------
    Natural gas
     including
     hedging          $ 74,624  $ 39,553     89%  $157,577  $ 91,011     73%
    -------------------------------------------------------------------------
    Crude oil and
     NGLs excluding
     hedging          $ 50,371  $ 41,213     22%  $101,310  $ 76,656     32%
    Realized hedging
     gains                  80         -       -     1,690         -       -
    -------------------------------------------------------------------------
    Crude oil and
     NGLs including
     hedging          $ 50,451  $ 41,213     22%  $103,000  $ 76,656     34%
    -------------------------------------------------------------------------
    Total revenue     $125,075  $ 80,766     55%  $260,577  $167,667     55%
    -------------------------------------------------------------------------

    Natural gas revenues, excluding hedging, have increased 89% for the three
months and 68% for the six months ended June 30, 2007, compared to 2006. Crude
oil and NGL revenues, excluding hedging, have increased by 22% for the three
months and 32% for the six months ended June 30, 2007. Revenues have increased
due to additional production from the Ketch merger as well as stronger natural
gas prices in the second quarter of 2007. For the six months ended June 30,
2007, the Fund recognized natural gas and crude oil hedging gains of
$6.2 million primarily attributable to weak commodity prices during the first
quarter of 2007.

    Production

                      Three months ended           Six months ended
                           June 30                     June 30
                        2007      2006  % change    2007      2006  % change
    -------------------------------------------------------------------------
    Natural gas
     (mcf/d)           108,978    70,293     55%   111,636    68,043     64%
    Crude oil (bbls/d)   6,615     5,321     24%     7,083     5,467     30%
    NGLs (bbls/d)        2,337     1,272     84%     2,369     1,209     96%
    -------------------------------------------------------------------------
    Total (boe/d)       27,115    18,309     48%    28,058    18,017     56%
    -------------------------------------------------------------------------
    Natural gas (%)        67%       64%               67%       63%
    Crude oil (%)          24%       29%               25%       30%
    NGLs (%)                9%        7%                8%        7%The Fund's total daily production averaged 27,115 boe/d for the three
months and 28,058 boe/d for the six months ended June 30, 2007, an increase of
48% and 56%, respectively, compared with the same periods of 2006. Natural gas
production increased 55%, crude oil production increased 24%, and NGLs
production increased 84% for the second quarter of 2007. For the six months
ended June 30, 2007, natural gas production increased 64%, crude oil
production increased 30%, and NGLs production increased 96%. The increase in
production from 2006 has been primarily attributed to the Ketch acquisition,
which closed June 23, 2006.
    For the second quarter, production decreased 7% from the first quarter of
2007. Our successful first quarter 2007 drilling program at Martin Creek,
Nevis, Chigwell, and Willesden Green, as well as other areas in Southern
Alberta and Saskatchewan, has moderately offset declines. In addition, our
flattening production platform, resulting from our continued focus on long
life assets, is contributing to a stable operating foundation. Significant
third party facility outages were realized during the quarter as well as a
prolonged spring break-up, which was exacerbated by very wet weather
conditions.
    For the remainder of the year, we expect a major third party plant
turnaround and other smaller facility outages during the third quarter, which
will impact production levels.Commodity Prices and Marketing

    Natural Gas

                      Three months ended           Six months ended
                           June 30                     June 30
    ($/mcf)             2007      2006  % change    2007      2006  % change
    -------------------------------------------------------------------------
    Realized natural
     gas prices
      Excluding
       hedging         $  7.54   $  6.18     22%   $  7.58   $  7.39      3%
      Including
       hedging         $  7.52   $  6.18     22%   $  7.80   $  7.39      6%

    AECO monthly index $  7.37   $  6.28     17%   $  7.42   $  7.78    (5)%Realized natural gas prices, excluding hedging, increased 22% for the
three months and 3% for the six months ended June 30, 2007, as compared to
2006. The price of natural gas is primarily based on supply and demand
fundamentals in the North American marketplace. The 2006/2007 winter was
generally mild, with inventory levels remaining higher than average, causing
continued downward pressure on commodity prices. Natural gas prices have
subsequently declined further due to significant summer inventory injections
and excess supply concerns resulting from mild summer weather and lack of
storm activity in the Gulf of Mexico. 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,
(ii) significantly less natural gas drilling in Canada projected for 2007,
which will reduce productivity to offset declines and (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.Crude Oil and NGLs

                      Three months ended           Six months ended
                           June 30                     June 30
    ($/bbl)             2007      2006  % change    2007      2006  % change
    -------------------------------------------------------------------------
    Realized crude
     oil prices
      Excluding
       hedging         $ 64.23   $ 71.14   (10)%   $ 61.48   $ 65.16    (6)%
      Including
       hedging         $ 64.37   $ 71.14   (10)%   $ 62.79   $ 65.16    (4)%
    Realized NGLs
     prices
      Excluding
       hedging         $ 55.05   $ 58.43    (6)%   $ 52.47   $ 55.67    (6)%
    Realized crude oil
     and NGLs prices
      Excluding
       hedging         $ 61.84   $ 68.69   (10)%   $ 59.22   $ 63.44    (7)%
      Including
       hedging         $ 61.93   $ 68.69   (10)%   $ 60.21   $ 63.44    (5)%
    WTI ($US/bbl)      $ 65.02   $ 70.75    (8)%   $ 61.59   $ 67.33    (9)%
    $US/$Canadian
     exchange rate     $  0.91   $  0.90      1%   $  0.88   $ 0.88       0%Realized crude oil and NGLs prices, excluding hedging, decreased 10% for
the three months and 7% for the six months ended June 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 six months ended June 30, 2007, WTI decreased 8% and 9%, respectively,
compared to 2006. Advantage's realized crude oil price has not changed to the
same extent as WTI due to the 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
geopolitical issues. Early in 2006, prices were strong due to concerns
regarding the lack of North American refining capacity, and the continued
strength of global demand. The mild 2005/2006 winter and the surge in crude
imports to North America resulted in significantly higher inventories that
prompted a relative price decrease during the end of 2006. Prices have
strengthened once again in early 2007 due to continued civil unrest in the
Middle East and production restrictions by the OPEC cartel. With the current
high price levels, it is notable that demand has remained resilient. 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      9,478 mcf/d             Cdn$7.16/mcf
                      October 2007
      Fixed price    April 2007 to      9,478 mcf/d             Cdn$7.55/mcf
                      October 2007
      Fixed price    November 2007      7,109 mcf/d             Cdn$9.54/mcf
                      to March 2008
      Collar         November 2007      9,478 mcf/d      Floor  Cdn$8.44/mcf
                      to March 2008                    Ceiling Cdn$10.29/mcf
      Collar         November 2007      7,109 mcf/d      Floor  Cdn$8.70/mcf
                      to March 2008                    Ceiling Cdn$10.71/mcf

    Crude oil - WTI

      Collar         October 2006 to   1,000 bbls/d      Floor  US$65.00/bbl
                      September 2007                   Ceiling  US$90.00/bblAs at June 30, 2007 the fair value of the derivatives outstanding was an
asset of approximately $8,530,000. For the six months ended June 30, 2007,
$1,903,000 was recognized in income as an unrealized derivative loss due to a
decrease in the fair value from December 31, 2006 and $6,174,000 was
recognized in income as a realized derivative gain, which partially alleviated
lower revenue from reduced commodity prices. The valuation of the derivatives
is the estimated fair value to settle the contracts as at June 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 with 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      4,739 mcf/d      Floor  Cdn$7.12/mcf
                      October 2007                     Ceiling  Cdn$8.67/mcf
      Collar         April 2007 to      4,739 mcf/d      Floor  Cdn$6.86/mcf
                      October 2007                     Ceiling  Cdn$9.13/mcf
      Collar         April 2007 to      9,478 mcf/d      Floor  Cdn$7.39/mcf
                      October 2007                     Ceiling  Cdn$9.63/mcf
      Collar         April 2007 to      9,478 mcf/d      Floor  Cdn$6.33/mcf
                      October 2007                     Ceiling  Cdn$7.20/mcf


    Currently, the Fund has fixed the commodity price on anticipated
production as follows:

                           Approximate
                        Production Hedged,      Minimum           Maximum
    Commodity            Net of Royalties        Price             Price
    -------------------------------------------------------------------------

    Natural gas - AECO
      Summer 2007              54%           Cdn$7.08/mcf       Cdn$8.09/mcf
      Winter 2007/2008         28%           Cdn$8.85/mcf      Cdn$10.19/mcf
    Crude Oil - WTI
      Summer 2007              14%           US$65.00/bbl       US$90.00/bbl


    Royalties

                      Three months ended           Six months ended
                           June 30                     June 30
                        2007      2006  % change    2007      2006  % change
    -------------------------------------------------------------------------
    Royalties, net of
     Alberta Royalty
     Credit ($000)    $ 22,749  $ 13,822     65%  $ 48,914  $ 30,162     62%
      per boe         $   9.22  $   8.30     11%  $   9.63  $   9.25      4%
    As a percentage
     of revenue,
     excluding hedging   18.2%     17.1%    1.1%     19.2%     18.0%    1.2%Advantage pays royalties to the owners of mineral rights from which we
have leases. The Fund currently has mineral leases with provincial
governments, individuals and other companies. Royalties for 2006 are shown net
of the Alberta Royalty Credit, which was a royalty rebate provided by the
Alberta government to certain producers and was eliminated effective
January 1, 2007. Royalties have increased in total due to the increase in
revenue from higher production and have increased on a per boe basis due to
higher natural gas prices. 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.Operating Costs

                      Three months ended           Six months ended
                           June 30                     June 30
                        2007      2006  % change    2007      2006  % change
    -------------------------------------------------------------------------
    Operating costs
     ($000)           $ 26,919  $ 15,673     72%  $ 57,189  $ 30,739     86%
      per boe         $  10.91  $   9.41     16%  $  11.26  $   9.43     19%Total operating costs increased 72% for the three months and 86% for the
six months ended June 30, 2007 as compared to 2006, mainly due to increased
production from the Ketch acquisition. Operating costs per boe increased 16%
for the three months and 19% for the six months ended June 30, 2007, mainly
due to temporary decreases in production levels related to second quarter
turnaround activity, an extended and unusually wet spring break-up, and
increased service and supply costs as the industry experienced an overall
labour cost increase. However, per unit operating costs decreased by 6% and
total operating costs decreased 11% when compared to the three months ended
March 31, 2007. This decrease reflects the absence of one-time cold weather
related costs but is offset by lower production levels. We will continue to be
opportunistic and proactive in pursuing optimization initiatives that will
improve our operating cost structure. A significant operating cost that
Advantage has been successful in partially stabilizing is electricity
associated with field operations. The Fund has been active in preserving the
price of power by hedging 3.5 MW at $56.68/MWh for 2007 and 3.0 MW at
$54.00/MWh for 2008, which represents a substantial portion of our power
usage. We expect that operating costs per boe will be in the range of $10.50
to $11.50 for the 2007 year.General and Administrative

                      Three months ended           Six months ended
                           June 30                     June 30
                        2007      2006  % change    2007      2006  % change
    -------------------------------------------------------------------------
    General and
     administrative
     expense ($000)   $  4,232  $  2,420     75%  $  8,948  $  4,386    104%
      per boe         $   1.72  $   1.45     19%  $   1.76  $   1.34     31%General and administrative ("G&A") expense has increased 75% for the
three months and 104% for the six months ended June 30, 2007, as compared to
2006. G&A per boe increased 19% for the three months and 31% for the six
months when compared to the same periods of 2006. G&A expense has increased
overall and per boe primarily due to an increase in staff levels that have
resulted from the 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 six months ended June 30, 2007, the Fund has accrued unit-based
compensation expense of $0.6 million and has capitalized $0.2 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           Six months ended
                           June 30                     June 30
                        2007      2006  % change    2007      2006  % change
    -------------------------------------------------------------------------
    Management fee
     ($000)           $      -  $     55  (100)%  $      -  $    887  (100)%
      per boe         $      -  $   0.03  (100)%  $      -  $   0.27  (100)%
    Performance
     incentive ($000) $      -  $   (300) (100)%  $      -  $  2,380  (100)%
    Management
     internalization
     ($000)           $  5,350  $    524    921%  $ 10,719  $    524   1946%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.Interest

                      Three months ended           Six months ended
                           June 30                     June 30
                        2007      2006  % change    2007      2006  % change
    -------------------------------------------------------------------------
    Interest expense
     ($000)           $  5,005  $  3,940     27%  $ 10,192  $  7,133     43%
      per boe         $   2.03  $   2.36   (14)%  $   2.01  $   2.19    (8)%
    Average effective
     interest rate        5.4%      4.9%    0.5%      5.4%      4.9%    0.5%
    Bank indebtedness
     at June 30 ($000)                            $377,812  $500,837   (25)%Interest expense has increased 27% for the three months and 43% for the
six months ended June 30, 2007, as compared to 2006. Interest expense per boe
has decreased 14% for the three months and 8% for the six months ended
June 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 the merger with
Ketch, which included the assumption of Ketch's additional bank indebtedness.
Interest expense per boe has decreased as we have reduced our bank
indebtedness relative to our level of production. The bank indebtedness at
June 30, 2007 decreased 25% from the prior year as we issued Trust Units in
early 2007 to reduce debt. 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 5.4% for the three and six
months ended June 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           Six months ended
                           June 30                     June 30
                        2007      2006  % change    2007      2006  % change
    -------------------------------------------------------------------------
    Interest on
     convertible
     debentures
     ($000)           $  3,293  $  2,268     45%  $  6,531  $  4,613     42%
      per boe         $   1.33  $   1.36    (2)%  $   1.29  $   1.41    (9)%
    Accretion on
     convertible
     debentures
     ($000)           $    605  $    437     38%  $  1,204  $    898     34%
      per boe         $   0.25  $   0.26    (4)%  $   0.24  $   0.28   (14)%
    Convertible
     debentures
     maturity value at
     June 30 ($000)                               $180,725  $180,795      0%Interest on convertible debentures has increased 45% for the three months
and 42% for the six months ended June 30, 2007, as compared to 2006. Accretion
on convertible debentures has increased 38% for the three months and 34% for
the six months ended June 30, 2007. The increases in total interest and
accretion are due to Advantage assuming Ketch's 6.50% convertible debentures
in the 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 has decreased as our convertible
debentures outstanding has reduced relative to our level of production. During
the six months ended June 30, 2007, $5,000 convertible debentures were
converted resulting in the issuance of 375 Trust Units.Cash Netbacks

                                           Three months ended
                                                 June 30
                                       2007                    2006
                                  $000       per boe      $000       per boe
    -------------------------------------------------------------------------
    Revenue                    $ 125,131    $  50.71   $  80,766    $  48.48
    Realized gain (loss)
     on derivatives                  (56)      (0.02)          -           -
    Royalties, net of Alberta
     Royalty Credit              (22,749)      (9.22)    (13,822)      (8.30)
    Operating costs              (26,919)     (10.91)    (15,673)      (9.41)
    -------------------------------------------------------------------------
    Operating                  $  75,407    $  30.56   $  51,271    $  30.77
    General and administrative    (4,232)      (1.72)     (2,420)      (1.45)
    Management fee                     -           -         (55)      (0.03)
    Interest                      (5,005)      (2.03)     (3,940)      (2.36)
    Interest on convertible
     debentures                   (3,293)      (1.33)     (2,268)      (1.36)
    Income and capital taxes        (243)      (0.10)       (307)      (0.18)
    -------------------------------------------------------------------------
    Funds from operations      $  62,634    $  25.38   $  42,281    $  25.39
    -------------------------------------------------------------------------


                                           Six months ended
                                                 June 30
                                       2007                    2006
                                  $000       per boe      $000       per boe
    -------------------------------------------------------------------------
    Revenue                    $ 254,403    $  50.09   $ 167,667    $  51.42
    Realized gain (loss)
     on derivatives                6,174        1.22           -           -
    Royalties, net of Alberta
     Royalty Credit              (48,914)      (9.63)    (30,162)      (9.25)
    Operating costs              (57,189)     (11.26)    (30,739)      (9.43)
    -------------------------------------------------------------------------
    Operating                  $ 154,474   $   30.42   $ 106,766    $  32.74
    General and administrative    (8,948)      (1.76)     (4,386)      (1.34)
    Management fee                     -           -        (887)      (0.27)
    Interest                     (10,192)      (2.01)     (7,133)      (2.19)
    Interest on convertible
     debentures                   (6,531)      (1.29)     (4,613)      (1.41)
    Income and capital taxes        (524)      (0.10)       (836)      (0.26)
    -------------------------------------------------------------------------
    Funds from operations      $ 128,279    $  25.26   $  88,911    $  27.27
    -------------------------------------------------------------------------Funds from operations of Advantage for the quarter ended June 30, 2007
increased to $62.6 million from $42.3 million in the prior year. Funds from
operations for the six months ended June 30, 2007 increased to $128.3 million
from $88.9 million compared to 2006. The cash netback per boe for the three
months ended June 30, 2007 remained comparable to the same quarter of 2006,
but decreased 7% from $27.27 to $25.26 for the six months ended June 30, 2007.
The lower cash netback per boe for the six months ended June 30, 2007 is
primarily due to higher operating costs. Operating costs per boe for the six
months ended June 30, 2007 were $11.26, an increase of 19% from the $9.43
experienced in 2006. 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 decreased 6% compared to the three months ended
March 31, 2007.Depletion, Depreciation and Accretion

                      Three months ended           Six months ended
                           June 30                     June 30
                        2007      2006  % change    2007      2006  % change
    -------------------------------------------------------------------------
    Depletion,
     depreciation &
     accretion ($000) $ 61,365  $ 33,164     85%  $125,283  $ 63,187     98%
      per boe         $  24.87  $  19.91     25%  $  24.67  $  19.38     27%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 85% for the three
months and 98% for the six months ended June 30, 2007 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 higher
DD&A per boe was due to a higher valuation for the Ketch reserves than
accumulated from prior acquisitions and development activities.

    Taxes

    Current taxes paid or payable for the quarter ended June 30, 2007
amounted to $0.2 million, 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 six months ended June 30, 2007,
the Fund recognized an income tax reduction of $16.3 million compared to a
reduction of $17.4 million for 2006. The impact of the Specified Investment
Flow-Through Entity ("SIFT") tax legislation is reflected in the second
quarter of 2007. The new tax law includes altering 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 June 30, 2007, we had a future income tax
liability balance of $45.6 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.

    Contractual Obligations and Commitments

    The Fund has contractual obligations in the normal course of operations
including purchases of assets and services, operating agreements,
transportation commitments, sales contracts and convertible debentures. These
obligations are of a recurring and consistent nature and impact cash flow in
an ongoing manner. The following table is a summary of the Fund's remaining
contractual obligations and commitments. Advantage has no guarantees or
off-balance sheet arrangements other than as disclosed.Payments due by period         2011 &
                                                                      there-
    ($ millions)          Total    2007     2008     2009     2010    after
    -------------------------------------------------------------------------
    Building leases      $  4.3   $  1.1   $  1.4   $  0.8   $  0.8   $  0.2
    Capital leases          5.6      1.0      1.1      0.8      0.8      1.9
    Pipeline/
     transportation         4.7      1.9      2.1      0.6      0.1        -
    Convertible
     debentures(1)        180.7      1.4      5.4     57.1     70.0     46.8
    -------------------------------------------------------------------------
    Total contractual
     obligations         $195.3   $  5.4   $ 10.0   $ 59.3   $ 71.7   $ 48.9
    -------------------------------------------------------------------------
    (1) As at June 30, 2007, Advantage had $180.7 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 $377.8 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)                      June 30, 2007
    -------------------------------------------------------------------------
    Bank indebtedness (long-term)                               $    377,812
    Working capital deficit(1)                                        11,512
    -------------------------------------------------------------------------
    Net debt                                                    $    389,324
    -------------------------------------------------------------------------
    Trust Units outstanding (000)                                    116,091
    Trust Unit closing market price ($/Trust Unit)              $      15.00
    -------------------------------------------------------------------------
    Market value                                                $  1,741,365
    -------------------------------------------------------------------------
    Capital lease obligation (long-term)                        $      3,429
    Convertible debentures maturity value (long-term)                179,245
    -------------------------------------------------------------------------
    Total capitalization                                        $  2,313,363
    -------------------------------------------------------------------------
    (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 June 30, 2007, the Fund had 116.1 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. As at August 14, 2007, Advantage had 116.3 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
six months ended June 30, 2007, 2,076,686 Trust Units were issued as a result
of the Plan, generating $24.6 million reinvested in the Fund and representing
an approximate 23% participation rate.
    As at June 30, 2007, the Fund had $180.7 million convertible debentures
outstanding that were convertible to 8.3 million Trust Units based on the
applicable conversion prices. During the six months ended June 30, 2007,
$5,000 of convertible debentures were converted resulting in the issuance of
375 Trust Units and as at August 14, 2007, the convertible debentures
outstanding have not changed from June 30, 2007.

    Bank Indebtedness, Credit Facility and Other Obligations

    At June 30, 2007, Advantage had bank indebtedness outstanding of
$377.8 million. The Fund has a $600 million credit facility agreement
consisting of a $580 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 June 30, 2007, Advantage had a working capital deficiency of
$11.5 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 June 30, 2007, Advantage entered a new lease
arrangement that resulted in the recognition of a fixed asset addition and
capital lease obligation of $4.1 million. The lease obligation bears interest
at 5.8% and is secured by the related equipment. The lease term expires
June 2011 with a final purchase obligation of $1.5 million at which time
ownership of the equipment will transfer to Advantage. In addition, Advantage
has one other capital lease outstanding that was assumed from a prior
corporate acquisition.Capital Expenditures

                                 Three months ended       Six months ended
                                       June 30                 June 30
    ($000)                        2007        2006        2007        2006
    -------------------------------------------------------------------------
    Land and seismic           $   1,581   $   1,050   $   3,921   $   3,278
    Drilling, completions
     and workovers                15,475      20,708      42,610      34,715
    Well equipping and
     facilities                    8,464       5,899      28,574      10,187
    Other                            158         125         269         591
    -------------------------------------------------------------------------
                               $  25,678   $  27,782   $  75,374  $   48,771
    Property acquisitions              -           -      12,851           -
    Property dispositions              -           -        (427)          -
    -------------------------------------------------------------------------
    Total capital expenditures $  25,678   $  27,782   $  87,798   $  48,771
    -------------------------------------------------------------------------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 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 June 30, 2007, the Fund spent a net
$25.7 million. Approximately $6.1 million was expended on facility completion
and $15.5 million was expended on drilling and completion operations where the
Fund drilled a total of 5.8 net (10 gross) wells at a 100% success rate.
During the quarter we drilled 1 net (1 gross) oil well at Nevis, 1 net
(1 gross) oil well at Chigwell, 1 net (1 gross) gas well at Black, 0.6 net
(3 gross) oil wells at Lashburn, 0.7 net (1 gross) oil well at Sunset, as well
as several wells at other minor properties. Total capital spending in the
quarter included $3.8 million at Nevis, $3.0 million at Martin Creek,
$3.0 million in Southeast Saskatchewan, $2.5 million at Willesden Green,
$2.4 million at Sunset, and $2.4 million at Red Deer. The $12.9 million
property acquisition in the first quarter was for producing properties and
undeveloped land at the Fund's core area, Nevis.
    Capital spending, before property acquisitions and dispositions, for the
six months ended June 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 quarter of 2007. However, the Fund still
anticipates spending the full capital budget for the 2007 year, in addition to
the Sound business combination.
    The following table summarizes the various funding requirements during
the six months ended June 30, 2007 and the sources of funding to meet those
requirements.Sources and Uses of Funds

                                                            Six months ended
    ($000)                                                    June 30, 2007
    -------------------------------------------------------------------------
    Sources of funds
      Funds from operations                                      $   128,279
      Units issued, net of costs                                     104,486
      Property dispositions                                              427
    -------------------------------------------------------------------------
                                                                 $   233,192
    -------------------------------------------------------------------------
    Uses of funds
      Distributions to Unitholders                               $    79,305
      Expenditures on property and equipment                          75,374
      Decrease in bank indebtedness                                   32,762
      Increase in working capital                                     27,123
      Property acquisitions                                           12,851
      Expenditures on asset retirement                                 3,707
      Reduction of capital lease obligations                           2,070
    -------------------------------------------------------------------------
                                                                 $   233,192
    -------------------------------------------------------------------------


    Quarterly Performance

    ($000, except as                    2007                    2006
     otherwise indicated)          Q2          Q1          Q4          Q3
    -------------------------------------------------------------------------
    Daily production
      Natural gas (mcf/d)        108,978     114,324     117,134     122,227
      Crude oil and NGLs
       (bbls/d)                    8,952       9,958       9,570       9,330
      Total (boe/d)               27,115      29,012      29,092      29,701
    Average prices
      Natural gas ($/mcf)
        Excluding hedging      $    7.54   $    7.61   $    6.90   $    5.89
        Including hedging      $    7.52   $    8.06   $    7.27   $    5.90
        AECO monthly index     $    7.37   $    7.46   $    6.36   $    6.03
      Crude oil and NGLs
       ($/bbl)
        Excluding hedging      $   61.84   $   56.84   $   54.58   $   67.77
        Including hedging      $   61.93   $   58.64   $   55.86   $   67.77
        WTI (US$/bbl)          $   65.02   $   58.12   $   60.21   $   70.55
    Total revenues (before
     royalties)                $ 125,075   $ 135,502   $ 127,539   $ 124,521
    Net income                 $   4,531   $     341   $   8,736   $   1,209
      per Trust Unit - basic   $    0.04   $    0.00   $    0.08   $    0.01
                     - diluted $    0.04   $    0.00   $    0.08   $    0.01
    Funds from operations      $  62,634   $  65,645   $  62,737   $  63,110
    Distributions declared     $  52,096   $  50,206   $  58,791   $  60,498
    Payout ratio (%)                 83%         76%         94%         96%


    ($000, except as                    2006                    2005
     otherwise indicated)          Q2          Q1          Q4          Q3
    -------------------------------------------------------------------------
    Daily production
      Natural gas (mcf/d)         70,293      65,768      72,587      75,994
      Crude oil and NGLs
       (bbls/d)                    6,593       6,760       7,106       7,340
      Total (boe/d)               18,309      17,721      19,204      20,006
    Average prices
      Natural gas ($/mcf)
        Excluding hedging      $    6.18   $    8.69   $   11.68   $    8.25
        Including hedging      $    6.18   $    8.69   $   10.67   $    7.79
        AECO monthly index     $    6.28   $    9.31   $   11.68   $    8.15
      Crude oil and NGLs
       ($/bbl)
        Excluding hedging      $   68.69   $   58.26   $   60.14   $   66.00
        Including hedging      $   68.69   $   58.26   $   59.53   $   61.10
        WTI (US$/bbl)          $   70.75   $   63.88   $   60.04   $   63.17
    Total revenues (before
     royalties)                $  80,766   $  86,901   $ 110,172   $  95,715
    Net income                 $  23,905   $  15,964   $  25,846   $  18,674
      per Trust Unit - basic   $    0.38   $    0.27   $    0.45   $    0.33
                     - diluted $    0.38   $    0.27   $    0.45   $    0.32
    Funds from operations      $  42,281   $  46,630   $  60,906   $  55,575
    Distributions declared     $  53,498   $  44,459   $  43,265   $  43,069
    Payout ratio (%)                127%         95%         71%         77%The table above highlights the Fund's performance for the second quarter
of 2007 and also for the preceding seven quarters. During 2005 and early 2006,
production continued to experience normal declines until a more significant
decrease occurred in the first quarter of 2006 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 with the addition of eight
days of production from the Ketch properties and further increased in the
third quarter of 2006 as the acquisition was fully integrated with Advantage.
Production in the second quarter of 2007 temporarily decreased as expected due
to several facility turnarounds that had been planned for the period.
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. During 2006, the payout ratio was higher relative to prior
quarters as a result of considerably weak natural gas prices relative to the
distribution level. Additionally, the timing of the Ketch merger significantly
increased the payout ratio for the second quarter of 2006 as the arrangement
closed prior to the June record date resulting in the payment of a full month
distribution to Ketch Unitholders whereas funds from operations for June only
included eight days of cash flows from the Ketch properties. The payout ratio
in the first and second quarters of 2007 are lower as we reduced the
distribution level in January 2007 to reflect current commodity prices.

    Critical Accounting Estimates

    The preparation of financial statements in accordance with GAAP requires
Management to make certain judgments and estimates. Changes in these judgments
and estimates could have a material impact on the Fund's financial results and
financial condition. Management relies on the estimate of reserves as prepared
by the Fund's independent qualified reserves evaluator. The process of
estimating reserves is critical to several accounting estimates. The process
of estimating reserves is complex and requires significant judgments and
decisions based on available geological, geophysical, engineering and economic
data. These estimates may change substantially as additional data from ongoing
development and production activities becomes available and as economic
conditions impact crude oil and natural gas prices, operating costs, royalty
burden changes, and future development costs. Reserve estimates impact net
income through depletion and depreciation of 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 second
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 has established a 2007 Budget, as approved by the Board of
Directors, that retains a high degree of activity and will focus on drilling
in many of our key properties where a high level of success was realized
through 2006. Capital will also be 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 quarter 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 second quarter of 2007, we expected and realized a significant
impact to our production due to a major third party plant turnaround. This was
exacerbated by prolonged wet weather throughout the spring which affected new
well tie-ins and routine well servicing. The reduced capital activity in the
second quarter will affect the third quarter of 2007. We also expect another
major third party plant turnaround to occur which will significantly affect
our Lookout Butte property. These turnarounds combined with well payouts are
expected to result in an impact of approximately 400 boe/d to the 2007 annual
average production. Overall, we expect production in 2007 to trend toward the
lower end of our guidance of 27,500 to 29,500 boe/d.
    Advantage's 2007 capital expenditures budget of $120 to $145 million
includes the drilling, completion and tie-in of 107 gross wells (64 net). For
the remainder of 2007, our capital program will be directed mainly at oil
opportunities due to the continued strong commodity prices. At Sunset, in
Northern Alberta, four light oil wells are planned to follow-up the successful
2006 development drilling program and capital will also be required to expand
water flood facilities in this light oil pool. In Central Alberta, drilling
will continue at Nevis for 40 degree light oil where horizontal drilling in
2006 and early 2007 showed excellent results. A net 15 sections of land were
added through deals with industry third parties in 2006 bringing the total
land under control to 37.5 net sections in this property. A second development
drilling program in the western portion of the Nevis property is underway and
facilities will be constructed to accommodate production additions. Additional
gas opportunities will be pursued in the Central Alberta areas targeting down
spacing and follow-up to successes. In Southern Alberta and Southeast
Saskatchewan, 13 wells (10 net) will be drilled for oil targets in 2007.
    Per unit operating costs are forecasted to be closer to the $10.50 to
$11.50/boe range. Higher property taxes, surface rentals and additional
trucking costs due to continued pipeline restrictions in Southeast
Saskatchewan are expected to continue in 2007. We experienced a 6% reduction
in the per unit costs and an 11% reduction in total operating costs when
comparing Q2 to Q1 2007. However, the per unit cost reduction is partly offset
by lower production volumes in Q2 due to the wet weather and third party
outages. 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.
    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 merger. The synergy of larger size and the
complementary winter/summer drilling programs with the Ketch merger is
providing benefits in terms of securing services, flexibility and quality of
our capital program.
    Looking forward, Advantage's high quality assets, three year drilling
inventory, hedging program and excellent tax pools provides many options for
the Fund and we are committed to maximizing value generation for our
Unitholders.

    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.


    August 14, 2007Consolidated Financial Statements

    Consolidated Balance Sheets
                                                       June 30,  December 31,
    (thousands of dollars)                                2007          2006
    -------------------------------------------------------------------------
                                                    (unaudited)
    Assets
    Current assets
      Accounts receivable                           $    68,200  $    79,537
      Prepaid expenses and deposits                      15,983       16,878
      Derivative asset (note 9)                           8,139        9,840
    -------------------------------------------------------------------------
                                                         92,322      106,255
    Deposit on property acquisition                           -        1,410
    Derivative asset (note 9)                               391          593
    Fixed assets (note 2)                             1,725,315    1,753,058
    Goodwill                                            120,271      120,271
    -------------------------------------------------------------------------
                                                    $ 1,938,299  $ 1,981,587
    -------------------------------------------------------------------------
    Liabilities
    Current liabilities
      Accounts payable and accrued liabilities      $    75,344  $   116,109
      Distributions payable to Unitholders               17,414       18,970
      Current portion of capital lease obligations
       (note 3)                                           1,466        2,527
      Current portion of convertible debentures
       (note 4)                                           1,471        1,464
    -------------------------------------------------------------------------
                                                         95,695      139,070
    Capital lease obligations (note 3)                    3,429          305
    Bank indebtedness (note 5)                          377,812      410,574
    Convertible debentures (note 4)                     172,011      170,819
    Asset retirement obligations                         36,014       34,324
    Future income taxes (note 6)                         45,608       61,939
    -------------------------------------------------------------------------
                                                        730,569      817,031
    -------------------------------------------------------------------------
    Unitholders' Equity
    Unitholders' capital (note 7)                     1,732,693    1,592,758
    Convertible debentures equity component (note 4)      8,041        8,041
    Contributed surplus (note 7)                          1,532          863
    Accumulated deficit (note 8)                       (534,536)    (437,106)
    -------------------------------------------------------------------------
                                                      1,207,730    1,164,556
    -------------------------------------------------------------------------
                                                    $ 1,938,299  $ 1,981,587
    -------------------------------------------------------------------------
    Commitments (note 10)
    Subsequent Event (note 11)

    see accompanying Notes to Consolidated Financial Statements



    Consolidated Statements of Income,
    Comprehensive Income and Accumulated Deficit

                                   Three       Three         Six         Six
                                  months      months      months      months
    (thousands of dollars,         ended       ended       ended       ended
     except for per Trust        June 30,    June 30,    June 30,    June 30,
     Unit amounts) (unaudited)      2007        2006        2007        2006
    -------------------------------------------------------------------------
    Revenue
      Petroleum and natural
       gas                     $ 125,131   $  80,766   $ 254,403   $ 167,667
      Realized gain (loss) on
       derivatives (note 9)          (56)          -       6,174           -
      Unrealized gain (loss)
       on derivatives (note 9)    10,126         532      (1,903)        532
      Royalties, net of
       Alberta Royalty Credit    (22,749)    (13,822)    (48,914)    (30,162)
    -------------------------------------------------------------------------
                                 112,452      67,476     209,760     138,037
    -------------------------------------------------------------------------
    Expenses
      Operating                   26,919      15,673      57,189      30,739
      General and
       administrative              4,232       2,420       8,948       4,386
      Unit-based compensation
       (note 7)                      629           -         629           -
      Management fee                   -          55           -         887
      Performance incentive            -        (300)          -       2,380
      Management internalization
       (note 7)                    5,350         524      10,719         524
      Interest                     5,005       3,940      10,192       7,133
      Interest and accretion on
       convertible debentures      3,898       2,705       7,735       5,511
      Depletion, depreciation
       and accretion              61,365      33,164     125,283      63,187
    -------------------------------------------------------------------------
                                 107,398      58,181     220,695     114,747
    -------------------------------------------------------------------------
    Income (loss) before taxes
     and non-controlling
     interest                      5,054       9,295     (10,935)     23,290
    Future income tax expense
     (reduction)                     280     (14,917)    (16,331)    (17,444)
    Income and capital taxes         243         307         524         836
    -------------------------------------------------------------------------
                                     523     (14,610)    (15,807)    (16,608)
    -------------------------------------------------------------------------
    Net income before non-
     controlling interest          4,531      23,905       4,872      39,898
    Non-controlling interest           -           -           -          29
    -------------------------------------------------------------------------
    Net income and comprehensive
     income                        4,531      23,905       4,872      39,869
    Accumulated deficit,
     beginning of period        (486,971)   (298,169)   (437,106)   (269,674)
    Distributions declared       (52,096)    (53,498)   (102,302)    (97,957)
    -------------------------------------------------------------------------
    Accumulated deficit, end
     of period                 $(534,536)  $(327,762)  $(534,536)  $(327,762)
    -------------------------------------------------------------------------
    Net income per Trust Unit
     (note 7)
      Basic                    $    0.04   $    0.38   $    0.04   $    0.66
      Diluted                  $    0.04   $    0.38   $    0.04   $    0.65
    -------------------------------------------------------------------------

    see accompanying Notes to Consolidated Financial Statements



    Consolidated Statements of Cash Flows

                                   Three       Three         Six         Six
                                  months      months      months      months
                                   ended       ended       ended       ended
    (thousands of dollars)       June 30,    June 30,    June 30,    June 30,
     (unaudited)                    2007        2006        2007        2006
    -------------------------------------------------------------------------
    Operating Activities
    Net income                 $   4,531   $  23,905   $   4,872   $  39,869
    Add (deduct) items not
     requiring cash:
      Unrealized loss (gain)
       on derivatives            (10,126)       (532)      1,903        (532)
      Unit-based compensation        629           -         629           -
      Performance incentive            -        (300)          -       2,380
      Management
       internalization             5,350         524      10,719         524
      Accretion on convertible
       debentures                    605         437       1,204         898
      Depletion, depreciation
       and accretion              61,365      33,164     125,283      63,187
      Future income taxes            280     (14,917)    (16,331)    (17,444)
      Non-controlling interest         -           -           -          29
    Expenditures on asset
     retirement                      302        (414)     (3,707)     (1,447)
    Changes in non-cash working
     capital                     (13,004)      2,874     (24,120)     (2,843)
    -------------------------------------------------------------------------
    Cash provided by operating
     activities                   49,932      44,741     100,452      84,621
    -------------------------------------------------------------------------
    Financing Activities
    Units issued, net of costs
     (note 7)                        386         473     104,486         473
    Increase (decrease) in
     bank indebtedness            23,369      33,195     (32,762)     59,496
    Reduction of capital lease
     obligations                  (1,719)       (183)     (2,070)       (271)
    Distributions to
     Unitholders                 (39,767)    (44,693)    (79,305)    (88,747)
    -------------------------------------------------------------------------
    Cash used in financing
     activities                  (17,731)    (11,208)     (9,651)    (29,049)
    -------------------------------------------------------------------------
    Investing Activities
    Expenditures on property
     and equipment               (25,678)    (27,782)    (75,374)    (48,771)
    Property acquisitions              -           -     (12,851)          -
    Property dispositions              -           -         427           -
    Acquisition of Ketch
     Resources Trust                   -     (10,236)          -     (10,236)
    Changes in non-cash
     working capital              (6,523)      4,485      (3,003)      3,435
    -------------------------------------------------------------------------
    Cash used in investing
     activities                  (32,201)    (33,533)    (90,801)    (55,572)
    -------------------------------------------------------------------------
    Net change in cash                 -           -           -           -
    Cash, beginning of period          -           -           -           -
    -------------------------------------------------------------------------
    Cash, end of period        $       -   $       -   $       -   $       -
    -------------------------------------------------------------------------
    Supplementary Cash Flow
     Information
      Interest paid            $  10,171   $   9,049   $  17,176   $  15,692
      Taxes paid               $     469   $     741   $     830   $   1,270

    see accompanying Notes to Consolidated Financial Statements



                 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

    June 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.  Fixed Assets

                                                  Accumulated
                                                 Depletion and     Net Book
        June 30, 2007                    Cost     Depreciation       Value
        ---------------------------------------------------------------------
        Petroleum and natural gas
         properties                  $ 2,421,038   $   700,256   $ 1,720,782
        Furniture and equipment            8,445         3,912         4,533
        ---------------------------------------------------------------------
                                     $ 2,429,483   $   704,168   $ 1,725,315
        ---------------------------------------------------------------------

                                                  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 six months ended June 30, 2007, Advantage capitalized
        general and administrative expenditures and unit-based compensation
        directly related to exploration and development activities of
        $3,943,000 (June 30, 2006 - $1,775,000).

    3.  Capital Lease Obligations

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

        2007                                 $     1,002
        2008                                       1,079
        2009                                         773
        2010                                         773
        2011                                       1,925
        -------------------------------------------------
                                                   5,552
        Less amounts representing interest          (657)
        -------------------------------------------------
                                                   4,895
        Current portion                           (1,466)
        -------------------------------------------------
                                             $     3,429
        -------------------------------------------------

        During the quarter ended June 30, 2007, Advantage entered a new lease
        arrangement that resulted in the recognition of a fixed asset
        addition and capital lease obligation of $4.1 million. The lease
        obligation bears interest at 5.8% and is secured by the related
        equipment. The lease term expires June 2011 with a final purchase
        obligation of $1.5 million at which time ownership of the equipment
        will transfer to Advantage.

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

    4.  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%        7.75%
        ---------------------------------------------------------------------
        Issue date            Oct. 18,      July 8,      Dec. 2,     Sep. 15,
                                 2002         2003         2003         2004
        Maturity date          Nov. 1,      Aug. 1,      Feb. 1,      Dec. 1,
                                 2007         2008         2009         2011
        Conversion price  $     13.30  $     17.00  $     16.50  $     21.00
        Liability
         component        $    52,722  $    28,662  $    56,802  $    47,444
        Equity component        2,278        1,338        3,198        2,556
        ---------------------------------------------------------------------
        Gross proceeds         55,000       30,000       60,000       50,000
        Issuance costs         (2,495)      (1,444)      (2,588)      (2,190)
        ---------------------------------------------------------------------
        Net proceeds      $    52,505  $    28,556  $    57,412  $    47,810
        ---------------------------------------------------------------------

                                7.50%        6.50%       Total
        -------------------------------------------------------
        Issue date            Sep. 15,      May 18,
                                 2004         2005
        Maturity date          Oct. 1,     June 30,
                                 2009         2010
        Conversion price  $     20.25  $     24.96
        Liability
         component        $    71,631  $    66,981  $  324,242
        Equity component        3,369        2,971      15,710
        -------------------------------------------------------
        Gross proceeds         75,000       69,952     339,952
        Issuance costs         (3,190)           -     (11,907)
        -------------------------------------------------------
        Net proceeds      $    71,810  $    69,952  $  328,045
        -------------------------------------------------------

        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                 $1,025
                             and before November 1, 2007
        ---------------------------------------------------------------------
            9.00%            After August 1, 2006 and               $1,050
                             on or before August 1, 2007
                             After August 1, 2007 and               $1,025
                             before August 1, 2008
        ---------------------------------------------------------------------
            8.25%            After February 1, 2007 and             $1,050
                             on or before February 1, 2008
                             After February 1, 2008 and             $1,025
                             before February 1, 2009
        ---------------------------------------------------------------------
            7.75%            After December 1, 2007 and             $1,050
                             on or before December 1, 2008
                             After December 1, 2008 and             $1,025
                             on or before December 1, 2009
                             After December 1, 2009 and             $1,000
                             before December 1, 2011
        ---------------------------------------------------------------------
            7.50%            After October 1, 2007 and              $1,050
                             on or before October 1, 2008
                             After October 1, 2008 and              $1,025
                             before October 1, 2009
        ---------------------------------------------------------------------
            6.50%            After June 30, 2008 and                $1,050
                             on or before June 30, 2009
                             After June 30, 2009 and                $1,025
                             before June 30, 2010
        ---------------------------------------------------------------------

        The balance of debentures outstanding at June 30, 2007 and changes in
        the liability and equity components during the six months ended
        June 30, 2007 are as follows:

                               10.00%        9.00%        8.25%        7.75%
        ---------------------------------------------------------------------
        Debentures
         outstanding      $     1,480  $     5,392  $     4,867  $    46,766
        ---------------------------------------------------------------------
        Liability
         component:
          Balance at
           Dec. 31, 2006  $     1,464  $     5,235  $     4,676  $    43,765
          Accretion of
           discount                12           48           45          296
          Converted to
           Trust Units             (5)           -            -            -
        ---------------------------------------------------------------------
          Balance at
           June 30, 2007  $     1,471  $     5,283  $     4,721  $    44,061
        ---------------------------------------------------------------------
        Equity component:
          Balance at
           Dec. 31, 2006  $        59  $       229  $       248  $     2,286
          Converted to
           Trust Units              -            -            -            -
        ---------------------------------------------------------------------
          Balance at
           June 30, 2007  $        59  $       229  $       248  $     2,286
        ---------------------------------------------------------------------

                                7.50%        6.50%        Total
        --------------------------------------------------------
        Debentures
         outstanding      $    52,268  $    69,952  $   180,725
        --------------------------------------------------------
        Liability
         component:
          Balance at
           Dec. 31, 2006  $    49,782  $    67,361  $   172,283
          Accretion of
           discount               441          362        1,204
          Converted to
           Trust Units              -            -           (5)
        --------------------------------------------------------
          Balance at
           June 30, 2007  $    50,223  $    67,723  $   173,482
        --------------------------------------------------------
        Equity component:
          Balance at
           Dec. 31, 2006  $     2,248  $     2,971  $     8,041
          Converted to
           Trust Units              -            -            -
        --------------------------------------------------------
          Balance at
           June 30, 2007  $     2,248  $     2,971  $     8,041
        --------------------------------------------------------

        During the six months ended June 30, 2007, $5,000 debentures
        (June 30, 2006 - $24,268,000) were converted resulting in the
        issuance of 375 Trust Units (June 30, 2006 - 1,282,015 Trust Units).

    5.  Bank Indebtedness

        Advantage has a credit facility agreement with a syndicate of
        financial institutions which provides for a $580 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 last
        review and renewal completed in June 2007. 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 six months ended June 30, 2007, the
        effective interest rate on the outstanding amounts under the facility
        was approximately 5.4% (June 30, 2006 - 4.9%).

    6.  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 $5.5 million
        was recognized in the future income tax provision for the three
        months ended June 30, 2007.

    7.  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               2,076,686        24,553
        Issued for cash, net of costs                8,600,000       104,096
        Management internalization forfeitures         (14,139)         (286)
        ---------------------------------------------------------------------
                                                   116,090,892   $ 1,746,955
        ---------------------------------------------------------------------
        Management internalization escrowed
         Trust Units                                                 (14,262)
        ---------------------------------------------------------------------
        Balance at June 30, 2007                                 $ 1,732,693
        ---------------------------------------------------------------------

        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 six months ended June 30, 2007, 2,076,686 Trust Units were
        issued under the Premium Distribution™, Distribution
        Reinvestment, and Optional Trust Unit Purchase Plan, generating
        $24.6 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 six
        months ended June 30, 2007, a total of 14,139 Trust Units issued for
        the management internalization were forfeited and $10.7 million has
        been recognized as management internalization expense. As at June 30,
        2007, 1,204,397 Trust Units remain held in escrow.

        (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               -       (0.90)
        --------------------------------------------------------
        Balance at June 30, 2007            150,000    $  10.07
        --------------------------------------------------------

        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 six months ended June 30, 2007, the Fund has accrued unit-
        based compensation expense of $0.6 million and has capitalized
        $0.2 million related to Trust Units issuable for the retention of
        certain employees of the Fund.

        (d) Net Income per Trust Unit

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

                              Three        Three         Six          Six
                              months       months       months       months
                              ended        ended        ended        ended
                             June 30,     June 30,     June 30,     June 30,
                               2007         2006         2007         2006
        ---------------------------------------------------------------------
        Income available
         to Unitholders
          Basic           $     4,531  $    23,905  $     4,872  $    39,869
          Exchangeable
           Shares                   -            -            -           29
        ---------------------------------------------------------------------
          Diluted         $     4,531  $    23,905  $     4,872  $    39,898
        ---------------------------------------------------------------------
        Weighted average
         Trust Units
         outstanding
          Basic           113,854,335   62,710,027  111,108,403   60,802,526
          Trust Units
           Rights
           Incentive Plan
           - Series A               -       83,254            -       83,339
          Trust Units
           Rights
           Incentive Plan
           - Series B          43,259       84,205       39,487       95,366
          Exchangeable
           Shares                   -       41,693            -       73,500
          Management
           internalization    223,495            -      152,844            -
        ---------------------------------------------------------------------
          Diluted         114,121,089   62,919,179  111,300,734   61,054,731
        ---------------------------------------------------------------------

        The calculation of diluted net income per Trust Unit excludes all
        series of convertible debentures for the three and six months ended
        June 30, 2007 and June 30, 2006 as the impact would be anti-dilutive.
        There were no Exchangeable Shares remaining in 2007. Total weighted
        average Trust Units issuable in exchange for the convertible
        debentures and excluded from the diluted net income per Trust Unit
        calculation for the three and six months ended June 30, 2007 were
        8,334,353 and 8,334,403, respectively (June 30, 2006 - 5,856,596 and
        6,009,316, respectively). As at June 30, 2007, the total convertible
        debentures outstanding were immediately convertible to 8,334,077
        Trust Units (June 30, 2006 - 8,339,339).

    8.  Accumulated Deficit

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

                                                       June 30,  December 31,
                                                          2007          2006
        ---------------------------------------------------------------------
        Accumulated Income                          $  232,395    $  227,523
        Accumulated Distributions                     (766,931)     (664,629)
        ---------------------------------------------------------------------
        Accumulated Deficit                         $ (534,536)   $ (437,106)
        ---------------------------------------------------------------------

        For the six months ended June 30, 2007, the Fund declared
        $102.3 million in distributions, representing $0.90 per distributable
        Trust Unit (six months ended June 30, 2006 - $98.0 million
        representing $1.50 per distributable Trust Unit).

    9.  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 June 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 4) resulting in fair values that
        will vary over time as market conditions change. As at June 30, 2007,
        the estimated fair value of the total outstanding convertible
        debenture obligation was $181.9 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 $600 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 4). 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 six months ended
        June 30, 2007 could potentially have impacted interest expense 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 June 30, 2007 could impact net income by
        approximately $2.5 million for the six months ended June 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 June 30,
        2007 could impact net income by $0.1 million for the six months ended
        June 30, 2007. A change of 10% in the forward power prices used to
        calculate the fair value of the power derivatives at June 30, 2007
        could impact net income by $0.2 million for the six months ended
        June 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 June 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            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          October 2006 to
                       September 2007    1,000 bbls/d     Floor US$65.00/bbl
                                                        Ceiling US$90.00/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 June 30, 2007 the fair value of the derivatives outstanding was
        an asset of approximately $8,530,000 (December 31, 2006 -
        $10,433,000). For the six months ended June 30, 2007 $1,903,000 was
        recognized in income as an unrealized derivative loss (June 30, 2006
        - $532,000 unrealized derivative gain) and $6,174,000 was recognized
        in income as a realized derivative gain (June 30, 2006 - nil).

        In addition, the Fund has the following physical natural gas
        contracts in place with 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


    10. Commitments

        Advantage has lease commitments relating to office buildings. The
        estimated annual minimum operating lease rental payments for the
        buildings are as follows:

        2007                                 $     1,116
        2008                                       1,385
        2009                                         779
        2010                                         779
        2011                                         195
        -------------------------------------------------
                                             $     4,254
        -------------------------------------------------

    11. Subsequent Event

        On July 9, 2007, the Fund and Sound Energy Trust ("Sound") announced
        that their respective boards of directors had unanimously approved an
        agreement for the business combination of Advantage and Sound. The
        combined trust will continue to operate under the name Advantage
        Energy Income Fund and will be led by the existing Advantage
        management team. Successful completion of the business combination is
        subject to stock exchange, court and regulatory approvals and the
        approval by at least two-thirds of Sound's Unitholders and Sound
        Exchangeable Shareholders. It is anticipated that the Sound
        Unitholder meeting required to approve the Arrangement will be held,
        and the Arrangement is expected to close, in early September 2007,
        and that Sound Unitholders will receive Advantage's September
        distribution payable on October 15, 2007.

        The combination will be 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 will be exchanged for
        Advantage Trust Units on the same ratio based on the conversion ratio
        in effect at the effective date of the Arrangement. The acquisition
        will be accounted for using the purchase method whereby the assets
        acquired and liabilities assumed are recorded at their fair values
        with the excess of the aggregate consideration over the fair value of
        the identifiable net assets allocated to goodwill, if applicable.

        The Arrangement prohibits Sound from soliciting or initiating any
        discussion regarding any other business combination or sale of
        material assets, contains provisions to Advantage to match competing,
        unsolicited proposals and, subject to certain conditions, provides
        for a $12 million termination fee payable to Advantage.


    Directors                            Legal Counsel

    Gary F. Bourgeois                    Burnet, Duckworth and Palmer LLP
    Kelly I. Drader
    Robert B. Hodgins(1)                 Abbreviations
    John A. Howard(2)
    Andy J. Mah                          bbls - barrels
    Ronald A. McIntosh(1)(2)             bbls/d - barrels per day
    Sheila O'Brien(3)                    boe - barrels of oil equivalent
    Carol D. Pennycook(1)(3)             (6 mcf = 1 bbl)
    Steven Sharpe(3)                     boe/d - barrels of oil equivalent
    Rodger A. Tourigny(1)(3)             per day
                                         bcf - billion cubic feet
    (1) Member of Audit Committee        mcf - thousand cubic feet
    (2) Member of Reserve Evaluation     mcf/d - thousand cubic feet per day
        Committee                        mmcf - million cubic feet
    (3) Member of Human Resources,       mmcf/d - million cubic feet per day
        Compensation & Corporate         gj - gigajoules
        Governance Committee             NGLs - natural gas liquids
                                         WTI - West Texas Intermediate
    Officers                             TM - denotes trademark of Canaccord
                                         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
    KPMG 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
    Alberta Treasury Branches            New York Stock Exchange Trading
                                         Symbol
    Independent Reserve Evaluators
                                         Trust Units: AAV
    Sproule Associates Limited%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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