Glacier Production Increased, Lower Operating Costs and Alberta Royalty Incentives Enhance Montney Drilling Economics

(TSX: AAV, NYSE: AAV)

CALGARY, Aug. 12 /PRNewswire-FirstCall/ - Advantage Oil & Gas Ltd. ("Advantage" or the "Corporation") is pleased to announce its unaudited operating and financial results for the second quarter ended June 30, 2010.

                                   Three       Three         Six         Six
                                  months      months      months      months
                                   ended       ended       ended       ended
    Financial and Operating      June 30,    June 30,    June 30,    June 30,
     Highlights                     2010        2009        2010        2009
    -------------------------------------------------------------------------

    Financial ($000, except
     as otherwise indicated)
    Revenue before
     royalties(1)             $   96,377  $  114,659  $  195,154  $  237,609
      per share(2)            $     0.59  $     0.79  $     1.20  $     1.65
      per boe                 $    41.75  $    40.59  $    45.00  $    42.59
    Funds from operations     $   45,605  $   51,590  $   95,945  $  107,181
     per share(2)             $     0.28  $     0.35  $     0.59  $     0.73
     per boe                  $    19.76  $    18.26  $    22.12  $    19.21
    Net loss                  $  (22,279) $  (37,810) $   (9,124) $  (18,920)
      per share(2)            $    (0.14) $    (0.26) $    (0.06) $    (0.13)
    Expenditures on fixed
     assets                   $   19,549  $   15,719  $   88,899  $   68,362
    Working capital
     deficit(3)               $   20,831  $  131,913  $   20,831  $  131,913
    Bank indebtedness         $  273,529  $  644,100  $  273,529  $  644,100
    Convertible debentures
     (maturity value)         $  148,544  $  184,489  $  148,544  $  184,489
    Shares outstanding at end
     of period (000)             163,303     145,198     163,303     145,198
    Basic weighted average
     shares (000)                163,264     144,681     163,143     144,189
    Operating
    Daily Production
      Natural gas (mcf/d)        107,821     124,990      97,640     121,498
      Crude oil and NGLs
       (bbls/d)                    7,395      10,212       7,683      10,575
      Total boe/d @ 6:1        25,365      31,044      23,956      30,825
    Average prices (including
     hedging)
      Natural gas ($/mcf)     $     5.58  $     5.63  $     6.15  $     6.06
      Crude oil and NGLs
       ($/bbl)                $    61.80  $    54.51  $    62.12  $    54.53

    (1) includes realized derivative gains and losses
    (2) based on basic weighted average shares outstanding
    (3) working capital deficit includes accounts receivable, prepaid
        expenses and deposits, accounts payable and accrued liabilities, and
        the current portion of capital lease obligations and convertible
        debentures


                           MESSAGE TO SHAREHOLDERS


    Financial Results Supported by Increased Production, Lower Operating
    --------------------------------------------------------------------
    Costs & Strong Hedging Gains
    ----------------------------
    -   Funds from operations for the second quarter of 2010 was $45.6
        million or $0.28 per share. Funds from operations was supported by
        increased production, lower operating costs, and hedging gains
        partially offset by a 2009 royalty adjustment. As compared to the
        second quarter of 2009, total funds from operations decreased 12%
        primarily due to the sale of approximately 8,100 boe/d of assets in
        July 2009; however, funds from operations per boe grew 8% to
        $19.76/boe due to Advantage's improving cost structure.
    -   Average daily production during the second quarter of 2010 increased
        13% to 25,365 boe/d compared to the first quarter of 2010. Production
        rates increased due to the ramp-up of our Glacier production from 25
        mmcf/d to approximately 50 mmcf/d, partially offset by approximately
        500 boe/d of lower production during the second quarter due to the
        disposition of non-core natural gas weighted assets representing
        production of 1,700 boe/d. Advantage's corporate production increased
        by approximately 15% through drill bit growth as compared to the
        third quarter of 2009, after adjusting for asset dispositions of
        8,100 boe/d completed in July 2009.
    -   Total operating costs for the second quarter of 2010 decreased 30% to
        $24.6 million and decreased 14% on a per boe basis to $10.64/boe as
        compared to $35.0 million or $12.40/boe during the second quarter of
        2009. Per boe operating costs decreased 5% as compared to the first
        quarter of 2010. Operating costs per boe have decreased as a result
        of the disposition of higher cost non-core assets, an increasing
        contribution of low cost production from Glacier and the continued
        optimization of our other assets. Operating costs in the second
        quarter of 2010 were slightly impacted by higher workover and
        maintenance costs and additional costs required for the start-up of
        our new Glacier gas plant.
    -   Total royalties paid during the second quarter of 2010 decreased 5%
        as compared to the same period in 2009. The royalty rate as a
        percentage of revenue was 15.1% as compared to 14.4% in the first
        quarter of 2010. An increase in the royalty rate during the second
        quarter was due to a 2009 Alberta gas cost allowance annual
        adjustment which was paid during the period. Going forward, we
        anticipate corporate royalty rates to decrease due to the recently
        announced changes in the Alberta Royalty framework and benefits from
        the royalty incentive programs resulting from our ongoing drilling
        program at Glacier.
    -   For the three and six months ended June 30, 2010, our hedging program
        contributed a net gain of $15.5 million and $24.7 million to funds
        from operations, respectively. Advantage's consistent hedging program
        has helped to stabilize and enhance our cash flow for capital
        reinvestment requirements.
    -   In the last twelve months we have reduced our bank indebtedness by
        58% and our convertible debentures outstanding by 19%. As at June 30,
        2010, Advantage's bank debt was $273.5 million on a credit facility
        of $525 million resulting in an unutilized capacity of approximately
        $251.5 million. A total of $148.5 million of convertible debentures
        remain outstanding of which $62.3 million will mature in December
        2011 and the balance of $86.2 million will mature in January 2015.

    -   Net capital expenditures during the second quarter of 2010 amounted
        to $19.5 million for a total of $88.9 million for the first six
        months of 2010. Approximately 83% of our capital program for the
        first half of 2010 was invested at Glacier whereby we successfully
        completed Phase II of our development program in the second quarter
        of 2010 which increased production capability to approximately 50
        mmcf/d. Actual capital spending was less than our total capital
        budget for the first six months of 2010 as we reduced Glacier costs
        and improved well results. The remaining capital expenditures
        included 4.5 net (5 gross) light oil wells in Saskatchewan, 2.8 net
        (3 gross) wells at Nevis and 2.8 net (4 gross) wells at Sunset in
        support of our light oil water flood project development.

    Glacier Production Increases to 50 mmcf/d with Reduced Operating Costs
    ----------------------------------------------------------------------
    during Q2 2010
    --------------
    -   Total gross raw inlet volumes at our Glacier gas plant increased to
        average 51 mmcf/d (8,500 boe/d) subsequent to our press release on
        April 19, 2010 when we announced that our new 100% working interest
        gas plant was brought on-stream. Advantage's net sales production
        from Glacier during this period averaged approximately 48 mmcf/d
        (8,000 boe/d). Glacier operating costs decreased from approximately
        $8.75/boe ($1.45/mcf) to approximately $3.00/boe ($0.50/mcf) during
        the quarter which has significantly improved the netbacks realized
        for our Montney gas production. Operating costs at Glacier are
        anticipated to further decrease through 2010 as additional start-up
        costs were included in the second quarter of 2010.
    -   The Glacier gas plant is currently producing at its peak capacity
        with several Montney wells constrained due to facility capacity and
        several wells have yet to be brought on production that will replace
        declines through the remainder of 2010.
    -   Since December 2009, twelve new operated Upper Montney horizontal
        wells have been brought on-stream which have demonstrated an average
        30 day IP rate of 5 mmcf/d per well. Three of these wells have
        averaged over 8 mmcf/d with one well at 9.6 mmcf/d, despite facility
        capacity constraints.
    -   Capital investment at Glacier during the second quarter of 2010 was
        $15.0 million for a total of $74.2 million during the first six
        months of 2010. Capital expenditures required to attain our 50 mmcf/d
        target were lower than anticipated due to i) our successful drilling
        program in 2009 and 2010 which demonstrated well productivities that
        exceeded internal expectations and ii) reduced drilling and
        completion costs.

    Glacier Expansion to 100 mmcf/d (16,667 boe/d) On-Track
    -------------------------------------------------------
    -   The expansion of our Glacier property to 100 mmcf/d is underway with
        the deployment of 4 drilling rigs. To date, 6 net (6 gross) new
        Montney horizontal wells have been drilled and are awaiting
        completion out of our Phase III total program of 28 net (28 gross)
        wells.
    -   A total of 4 net (4 gross) wells remaining from our first quarter of
        2010 drilling program have been completed since spring break-up.
        Results continue to be strong with test rates ranging from 5.9 to
        11.2 mmcf/d and flowing pressures of 464 psig to 1,385 psig. A total
        of 38 mmcf/d of new productive capability has already been tested
        and is awaiting future tie-in. An additional 1 net (1 gross) well
        from Phase II is awaiting completion at this time.
    -   Fabrication of a new processing train to facilitate expansion of our
        Glacier gas plant to 100 mmcf/d has commenced and we are anticipating
        equipment delivery to our plant site by year-end with construction to
        begin in the first quarter of 2011. The targeted on-stream date for
        our expanded Glacier plant is the second quarter of 2011.

    Alberta Royalty Incentives Improves Montney Netbacks and Drilling
    -----------------------------------------------------------------
    Economics
    ---------
    -   On May 27, 2010, the Alberta Government announced royalty changes
        which included incentives that have a positive long-term impact on
        the netbacks and drilling economics for our Montney development at
        Glacier. We view the Montney as being one of North America's most
        economic gas plays with very strong investment returns at Glacier
        supported by low operating costs and a favorable royalty structure.
    -   The most significant impact at Glacier is the change to the Natural
        Gas Deep Drilling Program ("NGDDP") in which the qualifying vertical
        depth has been reduced to 2,000 metres (from 2,500 metres) and the
        program has been made a permanent feature of the Alberta royalty
        framework.
    -   As a result, all Montney horizontal wells drilled at Glacier after
        May 1, 2010 will qualify for a royalty incentive of $2.7 to $3.4
        million based on a typical Glacier Montney horizontal well (total
        length of 4,200 to 4,500 metres). As a result, the effective royalty
        rate for a new Glacier Montney well is estimated to be less than 7%
        for the producing life of the well.
    -   These changes have substantially enhanced the future drilling
        economics and the value of Montney drilling locations. Advantage
        estimates that the drilling economics of our Montney resource at
        Glacier generates a before-tax rate of return in excess of 15% at
        natural gas prices of $3.00 Cdn per mcf. This is due to the
        operating cost efficiencies provided by our 100% working interest
        gas plant, the decreasing capital cost structure, the contiguous
        nature of our extensive land block and the substantial economic
        enhancement created by the recent changes to the Alberta Royalty
        incentives.


    Additional 'Stacked' Formations above the Montney Provides Future
    -----------------------------------------------------------------
    Potential
    ---------
    -   To date, Advantage has a total of 38 net (47 gross) horizontal wells
        and 20 net (21 gross) vertical wells penetrating the Montney
        formation at Glacier. All of these wellbores have provided valuable
        uphole information in regard to conventional and resource formations
        which are 'stacked' directly above the Montney over our extensive
        Glacier land block. At this time, we have natural gas indications in
        numerous wellbores which will be evaluated in the future through
        either new wells or recompletions of existing wells in a staggered
        pace to our Montney development. Future Montney drilling locations
        will serve to further de-risk the geographical extent of these
        additional stacked formations. No new reserves were included for any
        of the potential formations located above the Montney in our year-end
        2009 reserve report.
    -   Advantage's first Nikanassin horizontal well was drilled before
        spring break-up. Completion operations were conducted recently;
        however, mechanical difficulties encountered during the drilling and
        completion did not allow for an optimal evaluation of the well. The
        horizontal well confirmed the presence of natural gas and will be
        further evaluated. A decision to re-attempt the completion, drill
        another horizontal well or utilize an existing wellbore will be
        determined later in the year. Advantage continues to be optimistic on
        the resource potential of the Nikanassin and other formations which
        are present over our extensive land block at Glacier.

    Hedging Update
    --------------
    -   Advantage's hedging program includes 59% of our net natural gas
        production for 2010 hedged at an average price of Cdn$7.46 AECO per
        mcf. For 2011, Advantage has hedged approximately 28% of our net
        production at an average price of Cdn$6.30 AECO per mcf.
    -   For 2010 we have hedged 34% of our net crude oil production at Cdn
        $67.83 per bbl and for 2011 we have hedged 33% of our net crude oil
        production at Cdn$88.90 per bbl.
    -   Additional details on our hedging program are available at our
        website at www.advantageog.com.

    Looking Forward
    ---------------
    -   Our current corporate strategy is to focus on the development of our
        Montney natural gas resource play at Glacier, maintain financial
        flexibility and optimize our cost structure and operating
        efficiencies to deliver economic growth, particularly during lower
        commodity price cycles as we are currently experiencing. The enhanced
        financial flexibility resulting from the non-core asset dispositions
        provides further support to our corporate strategy.
    -   Looking forward, Advantage is well positioned to deliver growth in
        shareholder value. With a current inventory in excess of 500 Montney
        drilling locations at Glacier and a growing inventory of
        opportunities in our light oil and other natural gas assets,
        Advantage is in an enviable position to provide economic growth.
    -   Our guidance for the twelve months ending June 2011 is as follows:


    -------------------------------------------------------------------------
                                                                  Total
                             H2 2010           H1 2011          12 Months
    -------------------------------------------------------------------------
    Production Average
     (boe/d)             23,000 - 23,800   26,600 - 27,200   24,800 - 25,500
    -------------------------------------------------------------------------
    Royalty Rate (%)        13% - 15%         13% - 15 %        13% - 15%
    -------------------------------------------------------------------------
    Operating Costs
     ($/boe)             $ 9.75 - $10.25    $8.50 - $9.00     $9.10 - $9.65
    -------------------------------------------------------------------------
    Capital
     Expenditures *
     ($ million)           $120 - $130        $70 - $80        $190 - $210*
    -------------------------------------------------------------------------
    * - Capital expenditures are net of total drilling credits of
          $19 million over the 12 month period.

MANAGEMENT'S DISCUSSION & ANALYSIS

The following Management's Discussion and Analysis ("MD&A"), dated as of August 12, 2010, provides a detailed explanation of the financial and operating results of Advantage Oil & Gas Ltd. ("Advantage", the "Corporation", "us", "we" or "our") for the three and six months ended June 30, 2010 and should be read in conjunction with the unaudited consolidated financial statements for the six months ended June 30, 2010 and the audited consolidated financial statements and MD&A for the year ended December 31, 2009. 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.

Forward-Looking Information

This MD&A contains certain forward-looking statements, which are based on our current internal expectations, estimates, projections, assumptions and beliefs. 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 or related expressions. These statements are not guarantees of future performance.

In particular, forward-looking statements included in this MD&A include, but are not limited to, statements with respect to spending and capital budgets; capital expenditure programs; the focus of capital expenditures; availability of funds for our capital program; expectations regarding the ability to raise capital and to continually add to reserves through acquisitions and development; the size of, and future net revenues from, reserves; our future operating and financial results; supply and demand for oil and natural gas; projections of market prices and costs; areas of operations; the performance characteristics of our properties; average production and projected exit rates; average royalty rates; and the amount of general and administrative expenses. In addition, statements relating to "reserves" or "resources" are deemed to be forward-looking statements, as they involve the implied assessment, based on certain estimates and assumptions, that the resources and reserves described can be profitably produced in the future.

These forward-looking statements involve substantial known and unknown risks and uncertainties, many of which are beyond our control, including changes in general economic, market and business conditions; stock market volatility; changes to legislation and regulations and how they are interpreted and enforced, changes to investment eligibility or investment criteria; our ability to comply with current and future environmental or other laws; actions by governmental or regulatory authorities including increasing taxes, changes in investment or other regulations; changes in tax laws, royalty regimes and incentive programs relating to the oil and gas industry; the effect of acquisitions; our success at acquisition, exploitation and development of reserves; unexpected drilling results, changes in commodity prices, currency exchange rates, capital expenditures, reserves or reserves estimates and debt service requirements; the occurrence of unexpected events involved in the exploration for, and the operation and development of, oil and gas properties; hazards such as fire, explosion, blowouts, cratering, and spills, each of which could result in substantial damage to wells, production facilities, other property and the environment or in personal injury; changes or fluctuations in production levels; competition from other producers; the lack of availability of qualified personnel or management; and ability to access sufficient capital from internal and external sources. Many of these risks and uncertainties are described in the Corporation's Annual Information Form which is available at www.sedar.com and www.advantageog.com. Readers are also referred to risk factors described in other documents Advantage files with Canadian securities authorities.

With respect to forward-looking statements contained in this MD&A, Advantage has made assumptions regarding: conditions in general economic and financial markets; effects of regulation by governmental agencies; current commodity prices and royalty regimes; future exchange rates; royalty rates; future operating costs; availability of skilled labour; availability of drilling and related equipment; timing and amount of capital expenditures; and the impact of increasing competition.

Management has included the above summary of assumptions and risks related to forward-looking information provided in this MD&A in order to provide shareholders with a more complete perspective on Advantage's future operations and such information may not be appropriate for other purposes. Advantage's actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them do so, what benefits that Advantage will derive there from. Readers are cautioned that the foregoing lists of factors are not exhaustive. These forward-looking statements are made as of the date of this MD&A and Advantage disclaims any intent or obligation to update publicly any forward-looking statements, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws.

Non-GAAP Measures

The Corporation 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 cash netbacks. Management believes that these financial measures are useful supplemental information to analyze operating performance and provide an indication of the results generated by the Corporation'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. Cash netbacks are dependent on the determination of funds from operations and include the primary cash revenues and expenses on a per boe basis that comprise funds from operations. Funds from operations reconciled to cash provided by operating activities is as follows:

                      Three months ended           Six months ended
                             June 30                     June 30
    ($000)               2010      2009  % change    2010      2009  % change
    -------------------------------------------------------------------------
    Cash provided by
     operating
     activities       $ 49,550  $ 38,956     27%  $ 98,690  $ 80,835     22%
    Expenditures on
     asset retirement      469     1,045   (55)%     1,861     3,622   (49)%
    Changes in
     non-cash working
     capital            (4,414)   11,589  (138)%    (4,606)   22,724  (120)%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Funds from
     operations       $ 45,605  $ 51,590   (12)%  $ 95,945  $107,181   (10)%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------

Overview

                      Three months ended           Six months ended
                             June 30                     June 30
                         2010      2009  % change    2010      2009  % change
    -------------------------------------------------------------------------
    Cash provided by
     operating
     activities
     ($000)           $ 49,550  $ 38,956     27%  $ 98,690  $ 80,835     22%
    Funds from
     operations
     ($000)           $ 45,605  $ 51,590   (12)%  $ 95,945  $107,181   (10)%
      per share(1)    $   0.28  $   0.35   (20)%  $   0.59  $   0.73   (19)%
      per boe         $  19.76  $  18.26      8%  $  22.12  $  19.21     15%

    (1) Based on basic weighted average shares outstanding.

In July 2009 we closed two major asset dispositions for net proceeds of $243.2 million representing production of approximately 8,100 boe/d. On May 31 and June 3, 2010, we closed two additional asset dispositions of non-core natural gas weighted properties for net proceeds of $66.1 million, subject to further adjustments, and representing production of approximately 1,700 boe/d. The net proceeds from the various dispositions were utilized to reduce outstanding debt. As a result of the dispositions, total funds from operations decreased for the three and six months ended June 30, 2010 compared to the same periods of 2009 with all revenues and expenses generally impacted. As the two most recent dispositions closed near the end of the second quarter of 2010, they have had a modest impact on this quarter and will be completely excluded from our financial and operating results for the third quarter of 2010.

Funds from operations per boe increased when compared to 2009 primarily due to stronger crude oil prices and a continued reduction in operating costs. Although crude oil prices improved and had a positive impact on revenues, natural gas prices were comparable to 2009 and remained low. Through our successful commodity price risk management program, we were able to realize significant gains on derivatives that helped to offset the continued weak natural gas prices and improved funds from operations. When comparing the current quarter to the first quarter of 2010, our funds from operations per boe decreased 20% to $19.76/boe from $24.83/boe as commodity prices significantly decreased during this quarter. Funds from operations per share decreased from 2009 due to the decrease in total funds from operations and the increase in shares outstanding attributable to 17 million shares issued in July 2009. Cash provided by operating activities has increased relative to 2009 due to the decrease in funds from operations being more than offset by changes in working capital.

As a result of asset dispositions completed in 2009 and 2010 and changes in commodity prices, historical financial and operating performance may not be indicative of future performance.

The primary factor that causes significant variability of the Corporation'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.

Revenue

                      Three months ended           Six months ended
                             June 30                     June 30
    ($000)               2010      2009  % change    2010      2009  % change
    -------------------------------------------------------------------------
    Natural gas
     excluding
     hedging          $ 37,349  $ 40,482    (8)%  $ 78,659  $ 97,342   (19)%
    Realized hedging
     gains              17,435    23,516   (26)%    30,101    35,902   (16)%
    -------------------------------------------------------------------------
    Natural gas
     including
     hedging          $ 54,784  $ 63,998   (14)%  $108,760  $133,244   (18)%
    -------------------------------------------------------------------------
    Crude oil and NGLs
     excluding
     hedging          $ 43,516  $ 51,939   (16)%  $ 91,766  $ 94,683    (3)%
    Realized hedging
     gains (losses)     (1,923)   (1,278)    50%    (5,372)    9,682  (155)%
    -------------------------------------------------------------------------
    Crude oil and NGLs
     including
     hedging          $ 41,593  $ 50,661   (18)%  $ 86,394  $104,365   (17)%
    -------------------------------------------------------------------------
    Total revenue(1)  $ 96,377  $114,659   (16)%  $195,154  $237,609   (18)%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    (1) Total revenue excludes unrealized derivative gains and losses.

Natural gas, crude oil and NGL revenues, excluding hedging, were negatively impacted for the three and six months ended June 30, 2010, as compared to 2009 primarily due to lower production attributable to our asset dispositions that closed in the third quarter of 2009 and the second quarter of 2010. Natural gas prices, excluding hedging, for the three months ended June 30, 2010 were modestly higher as compared to the same period of 2009 while for the six months ended June 30, 2010 they were comparable to the prior year. Natural gas prices have been relatively weak for the last two years due to many factors including the poor global economy that has generally reduced demand, higher North American natural gas production, and mild weather conditions that have increased natural gas inventory. Crude oil and NGL prices, excluding hedging, have been higher for 2010 as compared to 2009 which has partially offset reduced revenues from the overall lower production. Given the relatively lower natural gas price environment, our commodity price risk management program has delivered realized natural gas hedging gains of $17.4 million and $30.1 million for the three and six months ended June 30, 2010, respectively. As crude oil prices have increased, we have realized crude oil hedging losses of $1.9 million and $5.4 million for the three and six months ended June 30, 2010, respectively. The Corporation enters derivative contracts whereby realized hedging gains and losses partially offset commodity price fluctuations, which can positively or negatively impact revenues. The realized natural gas hedging gains have been significant and helped us stabilize cash flows and ensure that our capital expenditure program is substantially funded by such cash flows.

Production

                      Three months ended           Six months ended
                             June 30                     June 30
                         2010      2009  % change    2010      2009  % change
    -------------------------------------------------------------------------
    Natural gas
     (mcf/d)           107,821   124,990   (14)%    97,640   121,498   (20)%
    Crude oil (bbls/d)   5,231     7,989   (35)%     5,370     8,331   (36)%
    NGLs (bbls/d)        2,164     2,223    (3)%     2,313     2,244      3%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Total (boe/d)       25,365    31,044   (18)%    23,956    30,825   (22)%
    -------------------------------------------------------------------------
    -------------------------------------------------------------------------
    Natural gas (%)        71%       67%               68%       66%
    Crude oil (%)          21%       26%               22%       27%
    NGLs (%)                8%        7%               10%        7%

Production was lower for 2010 as compared to 2009 primarily due to asset dispositions completed during these years. We closed property dispositions representing 8,100 boe/d in the third quarter of 2009 and 1,700 boe/d during the second quarter of 2010. As the most recent dispositions closed near the end of the second quarter of 2010, they have had a modest impact on this quarter and will be completely excluded from our financial and operating results for the third quarter of 2010. The lower average daily production was partially offset by production increases at Glacier, whereby our corporate average daily production of 25,365 boe/d for the second quarter of 2010 increased 13% above the 22,533 boe/d produced during the first quarter of 2010. On April 19, 2010 we announced that our new 100% working interest gas plant at Glacier ("Glacier gas plant") was brought on-stream ahead of schedule with production rates exceeding 50 mmcf/d (8,300 boe/d). This milestone represents another key step in the development of our significant Montney reserves and resource potential at Glacier. As a result of completing construction early, we were able to start commissioning the plant in March which resulted in production outages during that month to facilitate the tie-in of the gas plant and new pipelines.

We have now commenced Phase III of our Glacier development project which is targeting to increase production to 100 mmcf/d (16,667 boe/d) by the second quarter of 2011 and includes an active drilling program during the remainder of 2010 and into 2011. New production at Glacier will be brought on-stream to replace declines during the balance of 2010 and significant increases will be realized once facilities and infrastructure expansion work is completed in the second quarter of 2011. Therefore, we expect production to average approximately 23,000 to 23,800 boe/d for the second half of 2010.

Commodity Prices and Marketing

Natural Gas

                      Three months ended           Six months ended
                             June 30                     June 30
    ($/mcf)              2010      2009  % change    2010      2009  % change
    -------------------------------------------------------------------------
    Realized natural
     gas prices
      Excluding
       hedging        $   3.81  $   3.56      7%  $   4.45  $   4.43      -%
      Including
       hedging        $   5.58  $   5.63    (1)%  $   6.15  $   6.06      1%
    AECO monthly
     index            $   3.86  $   3.66      5%  $   4.60  $   4.64    (1)%

Realized natural gas prices, excluding hedging, were 7% higher for the three months ended June 30, 2010 and comparable for the six months ended June 30, 2010 as compared to the same periods of 2009. However, our realized natural gas prices, excluding hedging, for this quarter decreased 28% from the first quarter of 2010. Although natural gas prices have continued to remain weak, our commodity hedging strategy has resulted in realized natural gas prices, including hedging, that well exceed current market prices. This has significantly mitigated the negative impact from lower natural gas prices and has protected our cash flows and resulting capital expenditure program.

During 2009 and 2010, natural gas prices have remained low from continued high US domestic natural gas production, mild weather conditions, and the ongoing poor global economy that has negatively impacted demand. These factors have resulted in higher inventory placing considerable downward pressure on natural gas prices. Heading into the 2009/2010 winter season, we saw strong inventory withdraws which helped to modestly strengthen prices relative to the prior lows experienced during the majority of 2009. However, as we exited the winter, natural gas prices have significantly weakened again and AECO gas is presently trading at approximately $3.43/mcf. Although we continue to believe in the longer-term pricing fundamentals for natural gas, we are concerned about the strength and timing of the North American economic recovery which is linked to industrial demand for natural gas. We continue to monitor these market developments closely and will be proactive in implementing an appropriate hedging strategy to mitigate the volatility in our cash flow as a result of fluctuations in natural gas prices.

Crude Oil and NGL

                      Three months ended           Six months ended
                             June 30                     June 30
    ($/bbl)              2010      2009  % change    2010      2009  % change
    -------------------------------------------------------------------------
    Realized crude
     oil prices
      Excluding
       hedging        $  70.54  $  61.13     15%  $  72.80  $  52.74     38%
      Including
       hedging        $  66.50  $  59.37     12%  $  67.27  $  59.17     14%
    Realized NGLs
     prices
      Excluding
       hedging        $  50.45  $  37.06     36%  $  50.17  $  37.30     35%
    Realized crude oil
     and NGL prices
      Excluding
       hedging        $  64.66  $  55.89     16%  $  65.98  $  49.47     33%
      Including
       hedging        $  61.80  $  54.51     13%  $  62.12  $  54.53     14%
    WTI ($US/bbl)     $  77.98  $  59.62     31%  $  78.38  $  51.46     52%
    $US/$Canadian
     exchange rate    $   0.97  $   0.86     13%  $   0.97  $   0.83     17%

Realized crude oil and NGL prices, excluding hedging, increased 16% and 33% for the three and six months ended June 30, 2010, as compared to the same periods of 2009. As compared to the first quarter of 2010, realized crude oil and NGL prices, excluding hedging, have decreased 4% for the second quarter of 2010. Advantage's realized crude oil price may not change to the same extent as West Texas Intermediate ("WTI"), due to changes in the $US/$Canadian exchange rate and changes in Canadian crude oil differentials relative to WTI.

The price of WTI fluctuates based on worldwide supply and demand fundamentals. There has been significant price volatility experienced over the last several years whereby WTI reached historic high levels in the first half of 2008, followed by a record decline in the latter half of the year and into early 2009, the result of demand destruction brought on by the global recession. There was improvement during the last half of 2009 which has continued into 2010, and WTI is currently trading at approximately US$76/bbl. However, we have also seen a constant strengthening of the $US/$Canadian exchange rate during 2009 and 2010 such that our increase in realized price has been less than the improvement in WTI. We continue to believe that the long-term pricing fundamentals for crude oil will remain strong with supply management by the OPEC cartel and strong relative demand from many developing countries, such as China and India.

Commodity Price Risk

The Corporation's financial results and condition will be dependent on the prices received for oil and natural gas production. Oil and natural gas prices have fluctuated widely and are determined by economic and 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 Corporation's financial condition and performance. Advantage has an established financial hedging strategy and may manage the risk associated with changes in commodity prices by entering into derivative contracts. Although these commodity price risk management activities could expose Advantage to losses or gains, entering derivative contracts helps us to stabilize cash flows and ensures that our capital expenditure program is substantially funded by such cash flows. 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. In addition, the Corporation only enters into derivative contracts with major banks that are members of our credit facility syndicate and international energy firms to further mitigate associated credit risk. Our credit facilities also prohibit the Corporation from entering into any derivative contract where the term of such contract exceeds three years. Further, the aggregate of such contracts cannot hedge greater than 60% of total estimated petroleum and natural gas production over two years and 50% over the third year.

We have been active in entering financial contracts to protect future cash flows and currently the Corporation has the following derivatives in place:

    Description of
     Derivative                Term                  Volume     Average Price
    -------------------------------------------------------------------------
    Natural gas -
     AECO
      Fixed price  January 2010 to December 2010  18,956 mcf/d   Cdn$7.29/mcf
      Fixed price     April 2010 to January 2011  18,956 mcf/d   Cdn$7.25/mcf
      Fixed price  January 2011 to December 2011   9,478 mcf/d   Cdn$6.24/mcf
      Fixed price  January 2011 to December 2011   9,478 mcf/d   Cdn$6.24/mcf
      Fixed price  January 2011 to December 2011   9,478 mcf/d   Cdn$6.26/mcf

    Crude oil -
     WTI
      Fixed price     April 2010 to January 2011  2,000 bbls/d  Cdn$69.50/bbl
      Fixed price  January 2011 to December 2011  1,500 bbls/d  Cdn$91.05/bbl

The derivative contracts have allowed us to fix the commodity price on anticipated production, net of royalties, as follows:

                               Approximate Production              Average
    Commodity                Hedged, Net of Royalties(1)            Price
    -------------------------------------------------------------------------
    Natural gas - AECO
      July to September 2010             47%                    Cdn$7.27/mcf
      October to December 2010           48%                    Cdn$7.27/mcf
      -----------------------------------------------------------------------
      Total 2010                         59%                    Cdn$7.46/mcf
      -----------------------------------------------------------------------

      January to March 2011              40%                    Cdn$6.43/mcf
      April to June 2011                 25%                    Cdn$6.24/mcf
      July to September 2011             24%                    Cdn$6.24/mcf
      October to December 2011           24%                    Cdn$6.24/mcf
      -----------------------------------------------------------------------
      Total 2011                         28%                    Cdn$6.30/mcf
      -----------------------------------------------------------------------
    Crude Oil - WTI
      July to September 2010             37%                   Cdn$69.50/bbl
      October to December 2010           37%                   Cdn$69.50/bbl
      -----------------------------------------------------------------------
      Total 2010                         34%                   Cdn$67.83/bbl
      -----------------------------------------------------------------------

      January to March 2011              41%                   Cdn$84.42/bbl
      April to June 2011                 30%                   Cdn$91.05/bbl
      July to September 2011             31%                   Cdn$91.05/bbl
      October to December 2011           31%                   Cdn$91.05/bbl
      -----------------------------------------------------------------------
      Total 2011                         33%                   Cdn$88.90/bbl
      -----------------------------------------------------------------------

    (1) Approximate production hedged is based on our estimated average
        production by quarter, net of royalty payments.

For the six months ended June 30, 2010, we recognized in income a net realized derivative gain of $24.7 million (June 30, 2009 - $45.6 million net realized derivative gain) on settled derivative contracts as a result of average market prices decreasing below our established average hedge prices. As at June 30, 2010, the fair value of the derivative contracts outstanding and to be settled was a net asset of approximately $33.0 million, an increase of $15.8 million from the $17.2 million net asset recognized as at December 31, 2009. For the six months ended June 30, 2010, this $15.8 million increase was recognized in income as an unrealized derivative gain (June 30, 2009 - $0.2 million unrealized derivative loss). The valuation of the derivatives is the estimated fair value to settle the contracts as at June 30, 2010 and is based on pricing models, estimates, assumptions and market data available at that time. As such, the recognized amounts are not cash and the actual gains or losses realized on eventual cash settlement can vary materially due to subsequent fluctuations in commodity prices and foreign exchange rates as compared to the valuation assumptions. The Corporation does not apply hedge accounting and current accounting standards require changes in the fair value to be included in the consolidated statements of income and comprehensive income as an unrealized derivative gain or loss with a corresponding derivative asset and liability recorded on the balance sheet. These derivative contracts will settle in 2010 and 2011 corresponding to when the Corporation will receive revenues from production.

Royalties

                      Three months ended           Six months ended
                             June 30                     June 30
                         2010      2009  % change    2010      2009  % change
    -------------------------------------------------------------------------
    Royalties ($000)  $ 12,197  $ 12,791    (5)%  $ 25,055  $ 28,871   (13)%
      per boe         $   5.28  $   4.53     17%  $   5.78  $   5.17     12%
    As a percentage
     of revenue,
     excluding hedging   15.1%     13.8%    1.3%     14.7%     15.0%  (0.3)%

Advantage pays royalties to the owners of mineral rights from which we have leases. The Corporation currently has mineral leases with provincial governments, individuals and other companies. Royalty expense includes the impact of gas cost allowance ("GCA"), which is a reduction of royalties payable to the Alberta Provincial Government to recognize capital and operating expenditures incurred in the gathering and processing of their share of natural gas production and does not generally fluctuate with natural gas prices. Total royalties paid decreased for the three and six months ended June 30, 2010 compared to the same periods of 2009 due to lower revenue from reduced production attributable to our asset dispositions. Royalties as a percentage of revenue, excluding hedging, increased modestly for the quarter as compared to the same period of 2009 due to an annual adjustment related to 2009 GCA. However, royalties as a percentage of revenue, excluding hedging, have generally decreased due to the nature of our capital development activities at Glacier that result in natural gas production at lower royalty rates.

Our average corporate royalty rates are significantly impacted by the Alberta Provincial Government's royalty framework that was effective January 1, 2009 for conventional oil, natural gas and oil sands whereby Alberta royalties are now affected by depths, productivity of wells, and commodity prices. Additionally, the Alberta Provincial Government implemented a number of drilling incentive programs with reduced royalty rates over a period of time for qualifying wells. The majority of our wells brought on production since April 1, 2009 qualify under these incentive programs and benefit from a reduced 5% royalty rate on the first 500 mmcf produced or one-year, whichever comes first, and a drilling credit of $200 per metre drilled that reduces capital spending and is limited to 40% of corporate crown royalties paid during the program term. The drilling credit incentives are effective for qualifying wells drilled and brought on production from April 1, 2009 to March 31, 2011. The reduced 5% royalty rate program became a permanent incentive based on the Alberta Government's announcement of March 11, 2010 which will significantly benefit our Glacier development program for wells drilled after March 31, 2011.

On May 27, 2010 the Alberta Government announced changes in the Natural Gas Deep Drilling Program ("NGDDP") which reduces the vertical depth requirement to 2,000 metres (from 2,500 metres) and makes the program permanent. As a result, all of our Montney horizontal wells at Glacier drilled after May 1, 2010 will qualify for the NGDDP which is estimated to provide an additional royalty incentive of $2.7 to $3.4 million for a typical horizontal well (a typical Advantage horizontal well at Glacier is 4,200 to 4,500 metres in total length). This royalty incentive is recognized through a reduced 5% royalty rate until the total incentive is realized. This significantly lowers the natural gas price threshold required to drill economic wells and substantially improves the value of future reserves and upside potential at Glacier.

As a result of the changes in the royalty incentives and royalty curves, we estimate an effective royalty rate of less than 7% for the life of our new Glacier wells. We expect our corporate royalty rate to be in the range of 13% to 15% for the second half of 2010. Alberta royalty rates will continue to fluctuate based on commodity prices, individual well productivity, and our ongoing capital development plans.

Operating Costs

                      Three months ended           Six months ended
                             June 30                     June 30
                         2010      2009  % change    2010      2009  % change
    -------------------------------------------------------------------------
    Operating costs
     ($000)           $ 24,560  $ 35,030   (30)%  $ 47,276  $ 71,061   (33)%
      per boe         $  10.64  $  12.40   (14)%  $  10.90  $  12.74   (14)%

Total operating costs and operating costs per boe decreased for the three and six months ended June 30, 2010 as compared to the same periods of 2009. The lower overall total operating costs has been primarily due to reduced production from our asset dispositions completed in the third quarter of 2009 and the second quarter of 2010. Additional benefits are being realized from increased lower operating cost production at Glacier during the second quarter of 2010 offset by some additional workover and maintenance costs incurred during the period. We anticipate that corporate operating costs will further decrease as a result of lower cost production resulting from our Glacier gas plant (100% Advantage working interest) that was completed in the second quarter of 2010. Operating costs at Glacier during the second quarter of 2010 was approximately $3.00/boe which has significantly improved the netbacks realized from our Montney gas production. We estimate that operating costs at Glacier will be further reduced when production reaches 100 mmcf/d to a target of approximately $1.75/boe. We will seek further opportunities to improve our operating cost structure and expect corporate operating costs for the second half of 2010 to be between $9.75 and $10.25/boe.

General and Administrative

                      Three months ended           Six months ended
                             June 30                     June 30
                         2010      2009  % change    2010      2009  % change
    -------------------------------------------------------------------------
    General and
     administrative
      Cash expense
       ($000)         $  7,247  $  7,456    (3)%  $ 12,691  $ 13,539    (6)%
        per boe       $   3.14  $   2.64     19%  $   2.93  $   2.43     21%
      Non-cash expense
       ($000)         $  3,380  $    392    762%  $  7,131  $  1,689    322%
        per boe       $   1.46  $   0.14    943%  $   1.64  $   0.30    447%
      Employees at
       June 30                                         129       158   (18)%

Cash general and administrative ("G&A") expense for the six months ended June 30, 2010 has decreased 6% as compared to the same period of 2009 partially due to cost savings and reduced staff levels attributable to the asset dispositions. However, as a result of lower production due to the asset dispositions, the cash G&A expense per boe actually increased.

Advantage's compensation plan includes a Restricted Share Performance Incentive Plan ("RSPIP" or the "Plan") as approved by the shareholders with the purpose to retain and attract employees, to reward and encourage performance, and to focus employees on operating and financial performance that results in lasting shareholder return. The Plan authorizes the Board of Directors to grant restricted shares to service providers of the Corporation, including directors, officers, employees and consultants. The number of restricted shares granted is based on the Corporation's share price return for a twelve-month period and compared to the performance of a peer group approved by the Board of Directors. The share price return is calculated at the end of each and every quarter and is primarily based on the twelve-month change in the share price. If the share price return for a twelve-month period is positive, a restricted share grant will be calculated based on the return. If the share price return for a twelve-month period is negative, but the return is still within the top two-thirds of the approved peer group performance, the Board of Directors may grant a discretionary restricted share award. Compensation cost related to the Plan is recognized as equity-based compensation expense within G&A expense over the service period and incorporates the share grant price, the estimated number of restricted shares to vest, and certain management estimates. For the six months ended June 30, 2010, we granted 1,758,928 restricted shares at an average grant price of $7.10 per restricted share and recognized $8.6 million of equity-based compensation expense, including a non-cash amount of $7.1 million, related to restricted shares granted to service providers. During the first six months of 2010 we issued 557,550 shares to service providers in accordance with the vesting provisions of the Plan. As at June 30, 2010, 3,138,125 restricted shares remain unvested and will vest to service providers over the next three years with a total of $11.9 million in compensation cost to be recognized over the future service periods.

Management Internalization

                      Three months ended           Six months ended
                             June 30                     June 30
                         2010      2009  % change    2010      2009  % change
    -------------------------------------------------------------------------
    Management
     internalization
     ($000)           $      -  $    760  (100)%  $      -  $  1,724  (100)%
      per boe         $      -  $   0.27  (100)%  $      -  $   0.31  (100)%

In 2006, Advantage Energy Income Fund (the "Fund") and Advantage Investment Management Ltd. (the "Manager") reached an agreement to internalize a pre-existing management contract arrangement. As part of the agreement, the Fund 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 three-year period and was deferred and amortized into income as management internalization expense over the specific vesting periods. As of June 23, 2009, the final Trust Units held in escrow vested and there is no subsequent management internalization expense recognized.

Interest on Bank Indebtedness

                      Three months ended           Six months ended
                             June 30                     June 30
                         2010      2009  % change    2010      2009  % change
    -------------------------------------------------------------------------
    Interest expense
     ($000)           $  3,043  $  3,439   (12)%  $  6,805  $  8,355   (19)%
      per boe         $   1.32  $   1.22      8%  $   1.57  $   1.50      5%
    Average effective
     interest rate        4.5%      2.2%    2.3%      5.2%      2.8%    2.4%
    Bank indebtedness
     at June 30 ($000)                            $273,529  $644,100   (58)%

Total interest expense has decreased for both the three and six months ended June 30, 2010 as compared to 2009. During the first half of 2009, Advantage experienced significantly lower average interest rates as bank lending rates declined in response to rate reductions enacted by central banks to stimulate the economy. This reduced interest expense was partially offset by additional interest expense on a higher average debt balance during that period. In June 2009 our credit facility was renewed and was subject to generally higher basis point and stamping fee adjustments as was typically applied by financial institutions at that time. Therefore, our average effective interest rate is now higher; however, this has been significantly offset by lower interest expense on the reduced bank indebtedness that resulted from the third quarter 2009 asset dispositions and equity financing and the December 2009 5.0% convertible debenture issuance. Our revolving credit facility was again renewed in June 2010 and is now subject to basis point and stamping fee adjustments ranging from 1.25% to 3.75% depending on the Corporation's debt to cash flow ratio. The Corporation's interest rates are primarily based on short term bankers acceptance rates plus a stamping fee. We monitor the debt level to ensure an optimal mix of financing and cost of capital that will provide a maximum return to our shareholders. Our current credit facilities have been a favorable financing alternative with an effective interest rate of 5.2% for the six months ended June 30, 2010.

Interest and Accretion on Convertible Debentures

                      Three months ended           Six months ended
                             June 30                     June 30
                         2010      2009  % change    2010      2009  % change
    -------------------------------------------------------------------------
    Interest on
     convertible
     debentures
     ($000)           $  3,451  $  4,009   (14)%  $  6,835  $  7,978   (14)%
      per boe         $   1.50  $   1.42      6%  $   1.58  $   1.43     10%
    Accretion on
     convertible
     debentures
     ($000)           $  1,116  $    681     64%  $  2,220  $  1,363     63%
      per boe         $   0.48  $   0.24    100%  $   0.51  $   0.24    113%
    Convertible
     debentures
     maturity value at
     June 30 ($000)                               $148,544  $184,489   (19)%

Interest on convertible debentures for the three and six months ended June 30, 2010 has decreased compared to 2009 due to the maturity of the 8.25% debentures on February 1, 2009, the 8.75% debentures on June 30, 2009, and the 7.50% debentures on October 1, 2009. The reduced interest has been partially offset by additional interest on our new 5.00% convertible debentures that were issued on December 31, 2009. Accretion on convertible debentures has increased for the three and six months ended June 30, 2010 as compared to the same periods of 2009 due to the higher accretion expense on the new 5.00% convertible debentures as a result of the greater value assigned to the equity component of the debenture representing the conversion option available to debentureholders. Interest and accretion expense will decrease in future periods as the 6.50% debentures matured on June 30, 2010.

Depletion, Depreciation and Accretion

                      Three months ended           Six months ended
                             June 30                     June 30
                         2010      2009  % change    2010      2009  % change
    -------------------------------------------------------------------------
    Depletion,
     depreciation and
     accretion ($000) $ 58,875  $ 72,177   (18)%  $110,896  $142,099   (22)%
      per boe         $  25.51  $  25.55      -%  $  25.57  $  25.47      -%

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