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Advantage Announces Year End 2010 Reserves

March 7, 2011

Glacier Reserves Increase to 1 Tcf

(TSX: AAV, NYSE: AAV)

CALGARY, March 7 /PRNewswire/ – Advantage Oil & Gas Ltd. (“Advantage” or the
“Company”) is pleased to announce its year end reserves as of December
31, 2010.  Sproule Associates Ltd. (“Sproule”) was engaged as an
independent qualified reserve evaluator to evaluate Advantage’s year
end reserves (the “Sproule Report”) in accordance with National
Instrument 51-101 (“NI 51-101″) and the Canadian Oil and Gas Evaluation
Handbook (“COGE Handbook”). Year end financial and operating
information will be released on or about March 22, 2011 and
accordingly, all references to year end 2010 financial and operating
data are estimates and are unaudited.  Reserves included in the press
release is stated on a working interest basis unless otherwise
indicated.

Highlights

        --  Our 2010 capital program added 26.4 mmboe of Proven & Probable
            ("2P") reserves at a Finding and Development ("F&D") cost of
            $10.97/boe including the change in Future Development Capital
            ("FDC"). Advantage's three year corporate F&D cost of
            $12.43/boe (2P including the change in FDC) reflects the strong
            organic growth achieved since 2008 at Glacier.
        --  Reserve additions in 2010 were driven by our continued success
            at Glacier where total 2P reserves now exceed 1 Tcf (167.4
            mmboe) and comprise 69% of total Company working interest
            reserves.
        --  Production and test results at Glacier are exceeding
            expectations with a 2010 exit production rate of 10,000 boe/d
            (60 mmcf/d).  An additional 19,667 boe/d (118 mmcf/d) of
            production capacity currently exists which includes test
            results from 22 of our 28 Phase III Montney wells (100% working
            interest).  The remaining 6 Phase III Montney wells have been
            drilled and are waiting on completions and testing which is
            expected to be undertaken by the end of Q2 2011.
        --  Proven reserves represent 59% of total Company 2P reserves
            compared to 46% in 2009 due primarily to our 2010 development
            program at Glacier which led to a significant increase in
            proven reserves.
        --  Advantage's December 31, 2010 Net Asset Value is $13.63/share
            at a 10% discount rate pre-tax. The 2P Reserve Life Index
            ("RLI") is 27.5 years using our estimated fourth quarter 2010
            average production rate.
        --  The one year recycle ratio is 2.4 using the Finding,
            Development and Acquisition ("FD&A") cost of $10.89/boe (2P
            including the change in FDC) and our 2010 operating netback of
            $25.65/boe.

Glacier Phase III Development Program Exceeding Expectations

2010 Exit Production Ahead of Guidance

        --  Production performance at Glacier was higher than anticipated
            and resulted in a 2010 exit rate of 10,000 boe/d (60 mmcf/d)
            which exceeded our guidance.

Additional 118 mmcf/d of Production Capacity

        --  An additional 19,667 boe/d (118 mmcf/d) of production capacity
            currently exists which includes test results from 22 of our 28
            Phase III Montney wells (100% working interest) and existing
            wells that are shut-in due to facility capacity.  An additional
            6 gross (6 net) wells have been drilled and are waiting on
            completions and testing which is expected to be undertaken by
            the end of Q2 2011.
        --  We anticipate that only 12 Phase III wells will be required to
            initially achieve our 100 mmcf/d target with the remaining
            Phase III wells to be brought on-stream as required to offset
            declines and maintain production.
        --  Expansion of our Glacier gas plant to 100 mmcf/d is anticipated
            to reduce operating costs to approximately $1.80/boe
            ($0.30/mcf) as the majority of the operating costs are fixed in
            nature.
        --  All of our Phase III wells qualify for the Alberta Natural Gas
            Deep Drilling Program ("NGDDP") which will result in an
            effective royalty rate of 5% for these wells.

Test Results Continue to Improve

        --  Optimization of drilling and completion practices combined with
            improved geological knowledge at Glacier have significantly
            increased the horizontal well test rates through each of our
            development phases.
        --  The following table summarizes the average Upper Montney test
            rates for Phases I, II and III:

                                  Phase I      Phase II       Phase III
                               (2008 - 2009) (2009 - 2010) (2010 - Present)

    Number of gross Upper               8            25              20
    Montney wells

    Average test rate per well
    (mmcf/d)(1)                       3.7           7.3             8.3

    Average number of fracs             8            10              13
    per well

((1) )Test rates have been normalized to a common flowing pressure of 435 psi
for comparative purposes

        --  In 2010, we increased the number of fracs per horizontal well
            and optimized our frac design program which continued to
            improve well test rates.  In addition, we have drilled more
            wells on pad configurations which has reduced the drilling
            costs per well.  These changes helped to offset cost increases
            observed in 2010 due primarily to the increased demand on
            completion services driven by higher levels of multi-frac
            applications.
        --  As part of our Phase III drilling program, further delineation
            in the Upper Montney has confirmed the continuation of high
            quality reservoir characteristics to the extreme northeast and
            southeast areas of our land block which further proved up
            significant undrilled acreage.  Wells located along the western
            portion of our land block continues to demonstrate the strong
            results we observed in 2009.
        --  In the Lower Montney, Advantage has drilled and completed a
            total of 10 gross (6.7 net) horizontal wells since 2008. An
            additional 2 Lower Montney wells have been drilled and will be
            completed and tested by the end of Q2 2011.  To date, the
            average 30 day initial production rate in the Lower Montney has
            been less than the Upper Montney at Glacier. However, the Lower
            Montney wells are demonstrating a shallower decline which
            indicates significant reserve potential. We also believe that
            opportunities exist to increase the initial well productivity
            through improved frac design technology.  The Lower Montney is
            present over our entire Glacier land block and provides a
            significant opportunity for future reserves growth.
        --  In the Middle Montney, Advantage is encouraged by the resource
            potential which has been proven to be productive elsewhere in
            the Montney fairway.  Future plans include horizontal well
            drilling targeted to specifically delineate and test this
            interval.  No reserves have been assigned to the Middle Montney
            interval in the 2010 Sproule Report.

Drilling Success Increases Glacier Reserves to 1 Tcf

        --  Advantage's drilling and development program at Glacier has
            resulted in a 22% increase in Glacier 2P reserves from 137.4
            mmboe (0.82 Tcf) at December 31, 2009 to 167.4 mmboe (1.04 Tcf)
            at December 31, 2010. Proven reserves represent 57% of Glacier
            total 2P reserves compared to 37% in 2009.
        --  Drilling results at Glacier have demonstrated that our Montney
            development is among the top tier natural gas resource
            developments in North America.  Glacier 2Preserve additions
            have been very efficient with three year F&D cost (including
            the change in FDC) of $10.75/boe and 2009 and 2010 F&D cost of
            $10.38/boe and $9.29/boe, respectively.  Glacier provedreserve
            additions have an associated three year F&D cost (including the
            change in FDC) of $17.13/boe and 2009 and 2010 F&D cost of
            $25.16/boe and $11.14/boe, respectively (including the change
            in FDC).  The attractive cost structure at Glacier combined
            with a multi-decade drilling inventory provides a strong
            foundation to drive future development beyond 100 mmcf/d of
            production.
        --  The value assigned by Sproule at Glacier increased 19% to $1.4
            billion as at December 31, 2010 (at a 10% discount factor
            pre-tax).  Sproule's average natural gas price forecast (AECO
            Canadian spot price) for the years 2011 through 2015 is
            approximately 25% lower ($1.81/mcf) than the forecast used by
            Sproule for the same years in its 2009 reserve evaluation.  The
            key factors at Glacier that more than offset the Sproule price
            forecast decrease are:

                  i)   increased reserves;

                  ii)  reduced operating costs; and

                       the positive impact of the NGDDP where the effective
                  iii) royalty rate on a new Glacier Montney well is
                       anticipated to be approximately 5% over the life of
                       the well.
        --  Sproule included a total of 259 developed and undeveloped
            non-producing wells in the reserve report with an average
            reserve assignment of 4.1 bcf for an Upper Montney well and an
            average reserve assignment of 2.7 bcf for a Lower Montney well.

Advantage is Well Positioned for Future Organic Growth

        --  Drilling results at our cornerstone Glacier property have
            demonstrated that our Montney development is among the top tier
            natural gas resource developments in North America. The
            attractive cost structure at Glacier which includes low
            operating costs and low royalty rates combined with a
            multi-decade drilling inventory provides a strong foundation to
            drive future development beyond 100 mmcf/d of production.
        --  Advantage's near term objective is to complete the expansion
            work at Glacier to increase production to 100 mmcf/d in Q2
            2011. Facility construction is on-schedule with well
            completions and equipping underway.  Upon completion of our
            expansion to 100 mmcf/d, a review of well performance, facility
            capacity and actual costs will be undertaken by Advantage to
            assess the timing and capital requirements for the next phase
            of growth at Glacier.
        --  Advantage will provide additional corporate guidance and
            communicate future development plans on or about mid-year 2011.

Reserves

Advantage engaged our independent qualified reserves evaluator Sproule
Associates Ltd. (“Sproule”) to update the reserves analysis for the
Company in accordance with National Instrument 51-101 and the COGE
Handbook.

Reserves and production information included herein is stated on a
Company Interest basis (before royalty burdens and including royalty
interests receivable) unless noted otherwise. This report contains
several cautionary statements that are specifically required by NI
51-101. In addition to the detailed information disclosed in this press
release, more detailed information on a net interest basis (after
royalty burdens and including royalty interests) and on a gross
interest basis (before royalty burdens and excluding royalty interests)
will be included in Advantage’s Annual Information Form (“AIF”) and
will be available at www.advantageog.com and www.sedar.com in the coming weeks.

Highlights – Company Interest Reserves (Working Interests plus Royalty
Interests Receivable)


                                       December 31, 2010  December 31, 2009

    Proved plus probable reserves
    (mboe)                                        244,291           233,292

    Present Value of 2P reserves
    discounted at 10%, before tax
    ($000)(1)                                  $2,515,972        $2,773,428

    Net Asset Value per Share
    discounted at 10%, before tax (2)              $13.63            $15.07

    Reserve Life Index (proved plus
    probable - years) (3)                            27.5              28.2

    Reserves per Share (proved plus
    probable) (2)                                    1.48              1.43

    Bank debt per boe of reserves (4)               $1.18             $1.06

    Convertible debentures per boe of
    reserves (4)                                    $0.61             $0.94

    (1) Assumes that development of each property will occur, without
        regard to the likely availability to the Company of funding
        required for that development.

    (2) Based on 164.092 million Shares outstanding at December 31, 2010,
        and 162.746 million Shares outstanding as December 31, 2009.

    (3) Based on Q4 average production and company interest reserves.

    (4) Using boe's may be misleading, particularly if used in isolation.
        In accordance with NI 51-101, a boe conversion ratio for natural
        gas of 6 mcf: 1 bbl has been used which is based on an energy
        equivalency conversion method primarily applicable at the burner
        tip and does not represent a value equivalency at the wellhead.

Company Interest Reserves (Working Interests plus Royalty Interests
Receivable)

Summary as at December 31, 2010


                                          Natural                   Oil
                     Light &   Heavy Oil     Gas    Natural Gas  Equivalent
                   Medium Oil    (mbbl)   Liquids      (mmcf)      (mboe)
                     (mbbl)                (mbbl) 

    Proved                                                                 

    Developed           10,540      1,447     4,464      208,206     51,152
    Producing 

    Developed              751        150       129       28,672      5,809
    Non-producing 

    Undeveloped          2,795         95       621      499,788     86,809

    Total Proved        14,086      1,692     5,214      736,666    143,770

    Probable            10,289      2,853     2,626      508,519    100,521

    Total Proved +      24,375      4,545     7,840    1,245,185    244,291
    Probable 

Gross Working Interest Reserves (Working Interest only)

Summary as at December 31, 2010


                                          Natural                  Oil
                    Light &   Heavy Oil  Gas Liquids   Natural  Equivalent
                  Medium Oil    (mbbl)     (mbbl)       Gas       (mboe)
                    (mbbl)                             (mmcf)

    Proved                                                                

    Developed          10,319      1,417       4,432    207,695     50,783
    Producing 

    Developed             749        147         129     28,562      5,785
    Non-producing

    Undeveloped         2,795         90         621    499,783     86,803

    Total Proved       13,862      1,654       5,181    736,040    143,371

    Probable           10,182      2,833       2,615    507,929    100,285

    Total Proved       24,044      4,487       7,796  1,243,969    243,656
    + Probable

Present Value of Future Net Revenue using Sproule price and cost
forecasts
((1)(2))
($000)


                               Before Income Taxes Discounted at

                                   0%           10%          15%

    Proved                                                        

    Developed Producing      $ 1,408,498    $ 819,727    $ 690,677

    Developed Non-producing      158,270       89,107       73,543

    Undeveloped                1,653,020      525,190      304,641

    Total Proved               3,219,789    1,434,024    1,068,861

    Probable                   3,410,239    1,081,948      741,772

    Total Proved + Probable  $ 6,630,028  $ 2,515,972  $ 1,810,633

    (1) Advantage's crude oil, natural gas and natural gas liquid reserves
        were evaluated using Sproule's product price forecast effective
        December 31, 2010 prior to the provision for income taxes,
        interests, debt services charges and general and administrative
        expenses. It should not be assumed that the discounted future
        revenue estimated by Sproule represents the fair market value of
        the reserves.

    (2) Assumes that development of each property will occur, without
        regard to the likely availability to the Company of funding
        required for that development.

Sproule Price Forecasts

The present value of future net revenue at December 31, 2010 was based
upon crude oil and natural gas pricing assumptions prepared by Sproule
effective December 31, 2010. These forecasts are adjusted for reserve
quality, transportation charges and the provision of any applicable
sales contracts. The price assumptions used over the next seven years
are summarized in the table below:


             WTI      Edmonton   Alberta AECO-C   Henry Hub     Exchange
          Crude Oil    Light       Natural Gas    Natural Gas     Rate
    Year  ($US/bbl)   Crude Oil    ($Cdn/mmbtu)   ($US/mmbtu)  ($US/$Cdn)
                      ($Cdn/bbl)

    2011     88.40       93.08           4.04           4.44       0.932

    2012     89.14       93.85           4.66           5.01       0.932

    2013     88.77       93.43           4.99           5.32       0.932

    2014     88.88       93.54           6.58           6.80       0.932

    2015     90.22       94.95           6.69           6.90       0.932

    2016     91.57       96.38           6.80           7.00       0.932

    2017     92.94       97.84           6.91           7.11       0.932

Net Asset Value using Sproule price and cost forecasts (Before Income
Taxes)

The following net asset value (“NAV”) table shows what is normally
referred to as a “produce-out” NAV calculation under which the current
value of the Company’s reserves would be produced at forecast future
prices and costs. The value is a snapshot in time and is based on
various assumptions including commodity prices and foreign exchange
rates that vary over time.


                                      Before Income Taxes Discounted at  

    ($000, except per Share                0%           10%          15%
    amounts) 

    Net asset value per Share(1) -      $  45.55      $ 15.07     $  10.09
    December 31, 2009  

    Present value proved and         $ 6,630,028  $ 2,515,972  $ 1,810,633
    probable reserves 

    Undeveloped acreage and seismic
    (2)                                  199,800      199,800      199,800

    Working capital (deficit) and       (41,839)     (41,839)     (41,839)
    other 

    Convertible debentures             (148,544)    (148,544)    (148,544)

    Bank debt                          (288,852)    (288,852)    (288,852)

    Net asset value - December 31,   $ 6,350,593  $ 2,236,537  $ 1,531,198
    2010

    Net asset value per Share (1) -
    December 31, 2010                    $ 38.70      $ 13.63       $ 9.33

    (1) Based on 164.092 million Shares outstanding at December 31, 2010,
        and 162.746 million Shares outstanding at December 31, 2009.

    (2) Internal estimate

Gross Working Interest Reserves Reconciliation


                    Light &     Heavy    Natural Gas   Natural      Oil
                   Medium Oil    Oil      Liquids        Gas     Equivalent
    Proved           (mbbl)     (mbbl)     (mbbl)      (mmcf)      (mboe)

    Opening
    balance Dec.        15,602    2,466        5,266    507,206     107,868
    31, 2009

    Extensions             345        3           42    141,744      24,014

    Improved                 0        0            0          0           0
    recovery

    Infill                 176      233           91      5,916       1,485
    Drilling

    Discoveries              0        0            0          0           0

    Economic              (93)      (8)         (67)   (40,732)     (6,957)
    factors 

    Technical            (430)     (49)          678    178,521      29,952
    revisions

    Acquisitions             0        0           16        213          52

    Dispositions         (167)    (709)         (68)   (19,758)     (4,237)

    Production         (1,570)    (282)        (776)   (37,070)     (8,807)

    Closing
    balance at          13,862    1,654        5,181    736,040     143,371
    Dec. 31, 2010 

                     Light &     Heavy   Natural Gas   Natural      Oil
                   Medium Oil    Oil       Liquids       Gas     Equivalent
    Proved +         (mbbl)     (mbbl)     (mbbl)      (mmcf)      (mboe)
    Probable 

    Opening
    balance Dec.        29,125    5,836        7,749  1,137,322     232,264
    31, 2009

    Extensions             795        4           46    209,799      35,811

    Improved                 0        0            0          0           0
    recovery

    Infill                 230        0          138      7,959       1,694
    Drilling 

    Discoveries              0        0            0          0           0

    Economic             (154)     (13)         (89)   (33,158)     (5,782)
    factors

    Technical          (4,121)     (41)          802   (11,766)     (5,321)
    revisions 

    Acquisitions            0         0           25        331          80

    Dispositions         (260)  (1,017)         (99)   (29,448)     (6,284)

    Production         (1,570)    (282)        (776)   (37,070)     (8,807)

    Closing
    balance at          24,044    4,487        7,796  1,243,969     243,656
    Dec. 31, 2010 

Finding, Development & Acquisitions Costs (“FD&A”) ((1)(2)(3))

2010 FD&A Costs – Gross Working Interest Reserves excluding Future
Development Capital


                                              Proved   Proved + Probable

    Capital expenditures ($000)             $ 223,308          $ 223,308

    Acquisitions net of dispositions         (69,676)           (69,676)
    ($000)       

    Total capital ($000)                    $ 153,632          $ 153,632

    Total mboe, end of year                   143,371            243,656

    Total mboe, beginning of year             107,868            232,264

    Production, mboe                            8,807              8,807

    Reserve additions, mboe                    44,310             20,199

    2010 FD&A costs ($/boe)                    $ 3.47             $ 7.61

    2009 FD&A costs ($/boe)                  $ (4.55)           $ (1.08)

    Three year average FD&A costs ($/boe)      $ 4.32             $ 2.78

    2010 F&D costs ($/boe)                     $ 4.60             $ 8.46

    2009 F&D costs ($/boe)                    $ 10.46             $ 2.49

    Three year average F&D costs ($/boe)       $ 6.42             $ 4.17

NI 51-101
2010 FD&A Costs – Gross Working Interest Reserves including Future
Development Capital


                                               Proved   Proved + Probable

    Capital expenditures ($000)               $ 223,308          $ 223,308

    Alberta Drilling Incentives                 (3,258)            (3,258)
    ($000)                              

    Acquisitions net of dispositions ($000)    (69,676)           (69,676)

    Net change in Future Development Capital    339,907             69,493
    ($000) 

    Total capital ($000)                      $ 490,281          $ 219,867

    Reserve additions, mboe                      44,310             20,199

    2010 FD&A costs ($/boe)                     $ 11.06            $ 10.89

    2009 FD&A costs ($/boe)                     $ 22.50            $ 10.14

    Three year average FD&A costs ($/boe)       $ 17.13            $ 13.24

    2010 F&D costs ($/boe)                      $ 11.55            $ 10.97

    2009 F&D costs ($/boe)                      $ 10.58             $ 9.82

    Three year average F&D costs ($/boe)        $ 16.43            $ 12.43

    (1) Under NI 51-101, the methodology to be used to calculate FD&A costs
        includes incorporating changes in future development capital
        ("FDC") required to bring the proved undeveloped and probable
        reserves to production. For continuity, Advantage has presented
        herein FD&A costs calculated both excluding and including FDC.

    (2) The aggregate of the exploration and development costs incurred in
        the most recent financial year and the change during that year in
        estimated future development costs generally will not reflect total
        finding and development costs related to reserves additions for
        that year. Changes in forecast FDC occur annually as a result of
        development activities, acquisition and disposition activities and
        capital cost estimates that reflect Sproule's best estimate of what
        it will cost to bring the proved undeveloped and probable reserves
        on production.

    (3) In all cases, the FD&A number is calculated by dividing the
        identified capital expenditures by the applicable reserve
        additions.  Boes may be misleading, particularly if used in
        isolation.  A boe conversion ratio of 6 MCF:1 BBL is based on an
        energy equivalency conversion method primarily applicable at the
        burner tip and does not represent a value equivalency at the
        wellhead.

Advisory

The information in this press release contains certain forward-looking
statements, including within the meaning of the United States Private
Securities Litigation Reform Act of 1995. These statements relate to
future events or our future intentions or 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”, “demonstrate”, “expect”, “may”, “will”,
“project”, “predict”, “potential”, “targeting”, “intend”, “could”,
“might”, “should”, “believe”, “would” and similar expressions and
include statements relating to, among other things expected plans and
timing of drilling and completion of wells, expected increases and
rates of production, expected plans to expand facilities and
projections with respect to individual wells, regions, properties or
projects. These statements involve substantial known and unknown risks
and uncertainties, certain of which are beyond Advantage’s control,
including: the impact of general economic conditions; industry
conditions; changes in laws and regulations including the adoption of
new environmental laws and regulations and changes in how they are
interpreted and enforced; fluctuations in commodity prices and foreign
exchange and interest rates; stock market volatility and market
valuations; volatility in market prices for oil and natural gas;
liabilities inherent in oil and natural gas operations; uncertainties
associated with estimating oil and natural gas reserves; competition
for, among other things, capital, acquisitions of reserves, undeveloped
lands and skilled personnel; incorrect assessments of the value of
acquisitions; changes in income tax laws or changes in tax laws and
incentive programs relating to the oil and gas industry and income
trusts; geological, technical, drilling and processing problems and
other difficulties in producing petroleum reserves; and obtaining
required approvals of regulatory authorities. Advantage’s actual
decisions, activities, 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.  For additional risk factors in respect of Advantage and
its business, please refer to its Annual Information Form dated March
16, 2010 which is available on SEDAR at
www.sedar.com and www.advantageog.com.

References in this press release to initial test production rates,
initial “productivity”, initial “flow” rates, “flush” production rates
and “behind pipe production” are useful in confirming the presence of
hydrocarbons, however such rates are not determinative of the rates at
which such wells will commence production and decline thereafter. While
encouraging, readers are cautioned not to place reliance on such rates
in calculating the aggregate production for Advantage.

Barrels of oil equivalent (boe) may be misleading, particularly if used
in isolation. A boe conversion ratio has been calculated using a
conversion rate of six thousand cubic feet of natural gas to one
barrel.  “Tcf” stands for trillion cubic feet of natural gas and “bcf”
stands for billion cubic feet of natural gas. Such conversion rates are
based on an energy equivalency conversion method application at the
burner tip and do not represent an economic value equivalency at the
wellhead.

The Corporation discloses several financial measures 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.

Where any disclosure of reserves data is made in this press release that
does not reflect all reserves of Advantage, the reader should note that
the estimates of reserves and future net revenue for individual
properties or groups of properties may not reflect the same confidence
level as estimates of reserves and future net revenue for all
properties, due to the effects of aggregation.

SOURCE Advantage Oil & Gas Ltd.


Source: newswire



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