News Releases

Advantage Announces Year End 2011 Reserves, Glacier Phase IV Drilling Program Update and Results of an Updated Glacier Resource Assessment

Mar 15, 2012

(TSX: AAV, NYSE: AAV)

Year-End 2011 Advantage Reserve Highlights

CALGARY, March 15, 2012 /CNW/ - 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"). The Sproule Report includes only Advantage's 'stand-alone' reserves and excludes the assets in Longview Oil Corp. (See "Appendix A - Reserve Summary".)  Reserves are stated on a working interest basis unless otherwise indicated.  Advantage's year-end financial and operating information will be released on or about March 22, 2012 and accordingly, all references to year end 2011 financial and operating data are estimates and are unaudited.

  • Our 2011 capital program replaced 220% of production adding 18.6 mmboe of Proven & Probable ("2P") reserves at a Finding and Development ("F&D") cost of $8.85/boe including the change in Future Development Capital ("FDC").
  • Advantage's three year corporate F&D cost of $9.90/boe (2P reserves including the change in FDC) reflects the strong organic growth achieved at Glacier.
  • Proven reserves represent 64% of total Company 2P reserves compared to 59% in 2010 due to increasing recognition of solid well production trends at Glacier and higher confidence in recoverable reserves across a larger portion of our land block.
  • The one year recycle ratio is 1.9x using our F&D cost of $8.85/boe (2P reserves including the change in FDC) and an operating netback of $17.09/boe which excludes any contributions from Longview and commodity hedging impacts in 2011.
  • Advantage's December 31, 2011 Net Asset Value is $9.35/share at a 10% discount rate pre-tax (includes Longview shares at market value).  The 2P Reserve Life Index ("RLI") is 26.4 years using our estimated 2011 Q4 average production rate.

Highly Efficient Glacier 2P Reserves Additions at F&D Cost of $7.41/boe

  • Glacier reserves increased by 10% to 1.102 Tcf (183.7 mmboe) at a F&D cost of $7.41/boe (2P reserves including the change in FDC) and comprise 84% of total Advantage 2P reserves.
  • Glacier 2P reserve additions have been very efficient with three year F&D cost (including the change in FDC) of $9.03/boe.
  • Proven reserves increased by 22% to 0.70 Tcf which now represents 64% of total Glacier 2P reserves.  Proven developed producing ("PDP") reserves increased by 88% to 0.15 Tcf.
  • The increase in reserves resulted primarily from Sproule's recognition of strong production performance in both the Upper Montney and Lower Montney formations and continued drilling success. This led to a significant reclassification of probable to proven reserves and an increase in the reserves assigned per well specifically in the PDP category for the Upper Montney and for undeveloped locations in the Lower Montney.
  • The recycle ratio at Glacier is 2.4x based on 2011 F&D cost of $7.41/boe.
  • The value assigned by Sproule at Glacier is $1.175 billion as at December 31, 2011 (at a 10% discount factor pre-tax).
  • The continuing conversion of our Montney resource to higher category reserves through delineation drilling, longer term production performance and lower operating costs demonstrates the repeatability and high quality of our Montney asset at Glacier.

Phase IV Drilling Program Update

  • Our Phase IV drilling program began in late July 2011 and included drilling Upper Montney wells and "evaluation wells" to investigate additional layers of Montney potential specifically in the Middle Montney and to test new completion techniques in the Lower Montney.
  • To date, our Phase IV drilling program has resulted in drilling a total of 29 wells (28.5 net) of which 22 wells (21.5 net) are in the Upper Montney, 5 wells are in the Middle Montney and 2 wells are in the Lower Montney.  As of March 15, 2012, completions and well tests have been conducted on 11 (10.5 net) Upper Montney wells and 4 Middle Montney wells. The remaining wells will be completed and tested after spring break-up.
  • Current behind pipe volumes are estimated to be 37 mmcf/d including wells that have been tested and existing wells that are currently restricted as a result of our 100 mmcf/d Glacier gas plant capacity.  An additional 14 Montney wells have been drilled and are awaiting completion.

Upper Montney Drilling Reaffirms High Productivity & Repeatability

  • As part of our Phase IV drilling program, we have completed and tested 11 wells (10.5 net) in the Upper Montney which have extended our delineation efforts across the Glacier land block with wells testing the northeast, northwest and south east areas.
  • Well test results have continued to demonstrate high productivity with an average production test rate (calculated at the end of each 90 hour flow test) of 7.8 mmcf/d at 1,100 psi flowing pressure based on the last 11 wells (10.5 net) in the Upper Montney. An additional 11 Upper Montney wells are awaiting completion and testing. Some of these wells will be completed with different completion techniques which are anticipated to further improve well performance and reserves.
  • Historical and recent production rates reaffirm the strong production trends of the Upper Montney which have been recognized by Sproule in their year-end 2011 reserve report.
  • Since 2008, Advantage has drilled 79 gross (72.9 net) Upper Montney wells at Glacier with the initial wells approaching 3.5 years of production history.

Middle Montney Well Tests Reveals Liquids Potential

  • To date, Advantage has drilled a total of 5 wells of which 4 wells have been completed and tested with an additional 3 recompletions undertaken in existing vertical wellbores to evaluate the Middle Montney.
  • Our evaluation wells in the Middle Montney targeted 3 potential layers to commence vertical delineation of the thick Montney formation at Glacier. These wells were drilled to investigate flow potential and address the question of an appropriate "porosity cut-off" (the minimum porosity in the rock that will contribute to production and future reserves) in our Montney formation at Glacier.  This data is important to help calibrate the future resource and reserves potential at Glacier.
  • Natural gas test rates from the horizontal wells in the Middle Montney were lower than anticipated, however, the natural gas liquids ("NGL's") content was much higher than we expected. Based on the results and geological information obtained from these wells, we believe that our completion design was not optimal.  Additional geological and engineering work is currently underway to refine our understanding of these layers and optimize the completion design which we believe could improve results.
  • Three vertical well recompletions were undertaken in one of the Middle Montney layers prior to drilling our horizontal wells. The recompletions were located across the core of our land block and demonstrated natural gas well test rates which were comparable to vertical wells in the Upper Montney at Glacier.  Initial reservoir pressure data indicated that this layer is approximately 35% over-pressured compared to a normal pressure gradient which is beneficial to the potential resource/reserves per meter of formation.
  • The 4 horizontal wells drilled into the 3 Middle Montney layers demonstrated well production test rates between 1.1 to 4.4 mmcf/d at an average flowing pressure of 350 psi (calculated at the end of each 90 hour flow test).  Significant natural gas liquids content was observed in the gas analyses and free condensate was noted on flow back from 3 of the 4 wells.  Liquid yields are internally estimated to range from 25 bbls/mmcf to 50 bbls/mmcf assuming a shallow cut refrigeration process.  Liquid yields can be increased through construction of a higher cost facility which involves a deep cut liquids extraction process.   We estimate liquid yields would increase to the range of 57 bbls/mmcf to 90 bbls/mmcf assuming a deep cut liquids extraction process.  The propane, butane and condensate components are estimated to comprise 46% to 60% of the liquid yield in a deep cut liquids extraction process.
  • A fifth horizontal well has been drilled and is awaiting completion which we will conduct after re-evaluating the rock data and completion designs.
  • We believe that our low operating cost and royalty structure at Glacier could provide significant benefits to reduce threshold economics in support of a potential liquids rich Middle Montney program. Several options are available for liquids processing including undertaking modifications at our existing Glacier gas plant, accessing the nearby Alliance pipeline which accommodates NGL's or use of current pipeline interconnections to a third party deep cut facility which has spare processing capacity.
  • We are encouraged with our initial results in the Middle Montney specifically with the discovery of NGL's.  We caution that we are very early in this evaluation and more delineation and analysis will have to be undertaken in order to ascertain the drilling economics of the three Middle Montney layers.

Lower Montney

  • Two new horizontal wells have been drilled and are awaiting completion which are expected to be conducted after spring break-up.  A comprehensive internal review of frac techniques used in the adjacent Montney properties has been conducted and this information will be incorporated into our completion design to optimize the large resource potential that resides in the Lower Montney.
  • Our existing Lower Montney wells that were drilled in 2008 continue to exhibit shallow production declines and support a large resource potential which we view as indicative of another opportunity to grow reserves at Glacier.

Updated Glacier Montney Resource Assessment Increases TPIIP to 10 Tcf

  • Sproule was engaged to conduct an updated Montney resource assessment for Glacier.  Our initial resource assessment as of February 28, 2009 was undertaken when only 8 horizontal Montney wells were tested at Glacier.  Sproule's latest resource assessment includes all available information as of February 29, 2012. (See "Appendix B - Reserve and Resource Definitions.")

Sproule Resource Assessment Results

(All reserve and resource volumes indicated are 'sales' except where otherwise indicated)

  • Sproule's updated resource assessment dated February 29, 2012, resulted in a 320% increase in Total Petroleum Initially In Place ("TPIP") to 10.07 Tcf gross raw (9.33 Tcf raw AAV working interest).
  • The 2P reserves plus contingent resource best estimate increased by 90% to 2.49 TCF which represents only 27% of the TPIIP. Our year end 2011 2P Montney reserves of 1.096 Tcf represents only 12% of the TPIIP.
  • The contingent resource assessment includes 0.61 Tcf of resources (best estimate) in the Middle Montney which previously had no assignment.
  • Sproule also identified NGL's Initially In Place ("NGLIIP") of 156.34 million bbls and an ultimate recoverable resource best estimate of 50.8 million bbls based on an estimated liquid yield of 32 to 40 bbls/mmcf for the Middle Montney formation.
  • The following three tables summarize the results of Sproule's updated resource assessment:
Resource Categories (AAV working interest, Raw) (1) Tcf
Total Petroleum Initially In Place (TPIIP) 9.33
Discovered Petroleum Initially in Place (DPIIP) (2) 7.49
Undiscovered Petroleum Initially in Place (UPIIP) (3) 1.84

(1)      TPIIP, DPIIP and UPIIP have been estimated using a zero percent porosity cut-off (sandstone log scale).  The Montney formation is approximately 300 meters thick at Glacier. Sproule's analysis identified 6 potential layers consisting of 1 layer in the Upper Montney, 3 layers in the Middle Montney and 2 layers in the Lower Montney. With the exception of the lowest layer in the Lower Montney, all other layers exist across the entire Glacier land block.
(2)      There is no certainty that it will be commercially viable to produce any portion of the resources.
(3)      There is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resources.
Reserves & Contingent Resources (AAV working interest, Sales) (1) (2) Low Estimate Best Estimate High Estimate
Natural Gas      
Reserves (Tcf) (3) (4) 0.699 1.096 1.260
Contingent Resources (Tcf) (5) (7) 1.071 1.394 2.291
Total Reserves Plus Contingent Resources (Tcf) 1.770 2.490 3.551
Natural Gas Liquids (6)      
Reserves (mbbls) 0.0 0.0 0.0
Contingent Resources (mbbls) (7) 19,225 27,854 41,967

(1)      All DPIIP other than cumulative production, reserves and contingent resources have been categorized as unrecoverable.
(2)      Recoverable gas volumes were estimated using a 4 well per section development in each of the 6 layers within the Montney formation at Glacier.  Recovery factors were assigned to each layer based on the actual production performance of the Upper and Lower Montney as reference and then adjusting the recovery factor for each layer to reflect differing geological characteristics.
(3)      Reserves have only been assigned primarily to the Upper Montney and Lower Montney, with a nominal volume assigned to the Middle Montney for vertical well recompletions.
(4)      For reserves, the Low Estimate are proved reserves, the Best Estimate are 2P reserves and the High Estimate are 2P plus possible reserves. Cumulative production of 52 bcf have been added to the reserves volumes.
(5)      Contingent resources are assigned to the Upper Montney, Middle Montney and Lower Montney. Contingent resources for each section and layer were assigned if there was a sustained gas test within 2 miles of the section, otherwise, the resource was classified as prospective undiscovered resources.
(6)      Liquid yields are unique to each layer and were estimated based on the gas composition of gas samples from each layer.
(7)      The contingencies Sproule identified to convert contingent resource into reserves are specific to each layer and generally include the following :
  1. Development maturity including the number of sustained well tests and the amount of production information.  Sproule identified that even the Upper Montney is still in the early stages of development and that not all sections have been tested at Glacier.
  2. The lack of infrastructure to facilitate full development in the short term including the required processing facilities to extract NGL's in certain Montney layers.
  3. Economic contingencies dictating a slower pace of development with current gas prices in sections that are farther from existing gas gathering infrastructure in the Upper Montney and Lower Montney and lower initial rates in the Middle Montney layers which may be partially offset by higher liquid yields.
Prospective Resources (AAV working interest, Sales) (1) (2) (3) Low Estimate Best Estimate High Estimate
Natural gas (Tcf) 0.389 0.578 0.852
Natural gas liquids (mbbls) 15,616 22,960 33,526

(1)      All UPIIP other than prospective resources have been categorized as unrecoverable
(2)      Recoverable gas volumes were estimated using a 4 well per section development in each of the 6 layers within the Montney formation at Glacier.  Recovery factors were assigned to each layer based on the production performance of the Upper and Lower Montney as reference and then adjusting each layer to reflect differing geological characteristics.
(3)      Prospective resources were assigned to the Middle Montney and Lower Montney if there were no sustained gas tests within 2 miles of the section.
  • Our high quality asset at Glacier contains significant scope and scale as validated by Sproule's resource assessment and is underpinned with one of the lowest cost structures in Western Canada which provides Advantage with a significant drilling inventory.  Our recent drilling which involved lateral and vertical delineation through the very thick Montney formation across our contiguous land block has added another dimension to Glacier, specifically with the Middle Montney.  We estimate that the current drilling inventory at Glacier to be in excess of 900 wells.
  • Sproule's findings confirms the considerable potential that exists at Glacier to go significantly beyond current 2P reserves and  highlights the growth potential of our world class unconventional Montney natural gas resource play.

Appendix A - Reserve Summary

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 summary 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. Note that the December 31, 2010 figures below include the assets sold to Longview Oil Corp. on April 14, 2011.

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

  December 31, 2011  December 31, 2010
     
Proved plus probable reserves (mboe)  218,386  244,291
Present Value of 2P reserves discounted at 10%, before tax ($000)(1)  $1,483,679  $2,515,972
Net Asset Value per Share discounted at 10%, before tax (2)  $9.35  $13.63
Reserve Life Index (proved plus probable - years) (3)  26.4  27.5
Reserves per Share (proved plus probable) (2)  1.31  1.48
Bank debt per boe of reserves (4)  $0.66  $1.18
Convertible debentures per boe of reserves (4)  $0.40  $0.61

(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 166.304 million Shares outstanding at December 31, 2011, and 164.092 million Shares outstanding as December 31, 2010.
(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. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

Company Interest Reserves (Working Interests plus Royalty Interests Receivable)

Summary as at December 31, 2011

      Natural   Oil
  Light & Medium Oil Heavy Oil Gas Liquids Natural Gas Equivalent
  (mbbl) (mbbl) (mbbl) (mmcf) (mboe)
Proved          
Developed Producing 1,458 19 2,407 245,879 44,863
Developed Non-producing 38 - 7 17,371 2,941
Undeveloped 48 - 297 556,097 93,028
Total Proved 1,544 19 2,711 819,347 140,832
Probable 898 10 1,177 452,822 77,554
Total Proved + Probable 2,442 29 3,888 1,272,169 218,386

 

Gross Working Interest Reserves (Working Interest only)
Summary as at December 31, 2011

      Natural   Oil
  Light & Medium Oil Heavy Oil Gas Liquids Natural Gas Equivalent
  (mbbl) (mbbl) (mbbl) (mmcf) (mboe)
Proved          
Developed Producing 1,375 6 2,374 244,430 44,493
Developed Non-producing 38 - 7 17,259 2,922
Undeveloped 48 - 297 556,092 93,027
Total Proved 1,461 6 2,678 817,781 140,442
Probable 870 5 1,165 452,262 77,416
Total Proved + Probable 2,331 11 3,843 1,270,043 217,858

 

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 $737,412 $476,330   $404,290
Developed Non-producing 64,615 35,282   28,459
Undeveloped 1,545,887 399,105   198,522
         
Total Proved 2,347,914 910,718   631,272
         
Probable 2,227,996 572,961   367,629
Total Proved + Probable $4,575,910 $1,483,679   $998,900
(1) Advantage's crude oil, natural gas and natural gas liquid reserves were evaluated using Sproule's product price forecast effective December 31, 2011 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, 2011 was based upon crude oil and natural gas pricing assumptions prepared by Sproule effective December 31, 2011. 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 Light Alberta AECO-C Henry Hub Exchange  
    Crude Oil Crude Oil Natural Gas Natural Gas Rate
Year   ($US/bbl) ($Cdn/bbl) ($Cdn/mmbtu) ($US/mmbtu) ($US/$Cdn)
2012   98.07 96.87 3.16 3.55 1.012
2013   94.90 93.75 3.78 4.18 1.012
2014   92.00 90.89 4.13 4.54 1.012
2015   97.42 96.23 5.53 5.95 1.012
2016   99.37 98.16 5.65 6.07 1.012
2017   101.35 100.12 5.77 6.19 1.012
2018   103.38 102.12 5.89 6.32 1.012

 

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 amounts)   0%   10%   15%      
Net asset value per Share (1) - December 31, 2010   $38.70   $13.63   $9.33      
Present value proved and probable reserves   $4,575,910   $1,483,679   $998,900
             
Undeveloped acreage and seismic (2)   $71,630   $71,630   $71,630
             
Working capital (deficit) and other   (70,564)   (70,564)   (70,564)
Convertible debentures   (86,250)   (86,250)   (86,250)
Bank debt   (141,705)   (141,705)   (141,705)
             
Longview shares at market value   298,034   298,034   298,034
Net asset value - December 31, 2011   $4,647,055   $1,554,824   $1,070,045
Net asset value per Share (1) - December 31, 2011   $27.94   $9.35   $6.43

(1) Based on 166.304 million Shares outstanding at December 31, 2011, and 164.092 million Shares outstanding at December 31, 2010.
(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. 31, 2010  13,862 1,654 5,181 736,040 143,371
Extensions 28 - 1 12,227 2,067
Improved recovery - - - - -
Infill Drilling 1 - 8 15,819 2,645
Discoveries - - - - -
Economic factors 8 (2) (129) (19,932) (3,445)
Technical revisions 63 (26) (575) 145,316 23,681
Acquisitions - - 1 19 4
Dispositions (12,277) (1,619) (1,463) (27,756) (19,985)
Production  (224) (1) (346) (43,952) (7,896)
           
Closing balance at Dec. 31, 2011  1,461  2,678  817,781  140,442

  Light & Heavy Natural Gas Natural Oil  
  Medium Oil Oil Liquids Gas Equivalent
Proved + Probable (mbbl) (mbbl) (mbbl) (mmcf) (mboe)
Opening balance Dec. 31, 2010  24,044 4,487 7,796 1,243,969 243,656
Extensions 38 - 2 29,346 4,931
Improved recovery - - - - -
Infill Drilling 2 - 11 20,747 3,470
Discoveries - - - - -
Economic factors 24 8 (151) (20,900) (3,603)
Technical revisions (438) (61) (1,007) 91,631 13,766
Acquisitions - - 1 27 5
Dispositions (21,115) (4,422) (2,463) (50,825) (36,471)
Production (224) (1) (346) (43,952) (7,896)
           
Closing balance at Dec. 31, 2011 2,331 11 3,843 1,270,043 217,858

 

Finding, Development & Acquisitions Costs ("FD&A") (1)(2)(3)
2011 FD&A Costs - Gross Working Interest Reserves excluding Future Development Capital

    Proved   Proved + Probable
Capital expenditures ($000)   $202,148   $202,148
Acquisitions net of dispositions ($000)   (547,007)   (547,007)
Total capital ($000)   $(344,859)   $(344,859)
         
Total mboe, end of year   140,442   217,858
Total mboe, beginning of year   143,371   243,656
Production, mboe   7,896   7,896
Reserve additions, mboe   4,967   (17,902)
         
2011 FD&A costs ($/boe)   $(69.42)   $19.27
2010 FD&A costs ($/boe)    $3.47   $7.61
Three year average FD&A costs ($/boe) $(4.05)   $(3.74)
2011 F&D costs ($/boe)    $8.10   $10.89
2010 F&D costs ($/boe)   $4.60   $8.46
Three year average F&D costs ($/boe)   $5.51   $4.23

 

NI 51-101
2011 FD&A Costs - Gross Working Interest Reserves including Future Development Capital

    Proved   Proved + Probable
Capital expenditures ($000)   $202,148   $202,148
Acquisitions net of dispositions ($000)   (547,007)   (547,007)
Net change in Future Development Capital ($000)   42,053   (37,932)
Total capital ($000)   ($302,806)   ($382,791)
Reserve additions, mboe   4,967   (17,902)
2011 FD&A costs ($/boe)   ($60.95)   $21.38
2010 FD&A costs ($/boe)   $11.06   $10.89
Three year average FD&A costs ($/boe)   $8.46   $7.51
2011 F&D costs ($/boe)   $9.79   $8.85
2010 F&D costs ($/boe)   $11.55   $10.97
Three year average F&D costs ($/boe)   $13.10   $9.90

(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. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

Appendix B — Reserve and Resource Definitions

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable.  Reserves are classified according to the degree of certainty associated with the estimates as follows:

Proved Reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves.

Resources encompasses all petroleum quantities that originally existed on or within the earth's crust in naturally occurring accumulations, including Discovered and Undiscovered (recoverable and unrecoverable) plus quantities already produced. "Total resources" is equivalent to "Total Petroleum Initially-In-Place". Resources are classified in the following categories:

Total Petroleum Initially-In-Place ("TPIIP") is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered.

Discovered Petroleum Initially-In-Place ("DPIIP") is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of discovered petroleum initially in place includes production, reserves, and contingent resources; the remainder is unrecoverable.

Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development but which are not currently considered to be commercially recoverable due to one or more contingencies.

Undiscovered Petroleum Initially-In-Place ("UPIIP") is that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be discovered. The recoverable portion of undiscovered petroleum initially in place is referred to as "prospective resources" and the remainder as "unrecoverable."

Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects.

Unrecoverable is that portion of DPIIP and UPIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.

Uncertainty Ranges are described by the Canadian Oil and Gas Evaluation Handbook as low, best, and high estimates for reserves and resources as follows:

Low Estimate: This is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods are used, there should be at least a 90 percent probability (P90) that the quantities actually recovered will equal or exceed the low estimate.

Best Estimate: This is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability (P50) that the quantities actually recovered will equal or exceed the best estimate.

High Estimate: This is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability (P10) that the quantities actually recovered will equal or exceed the high estimate.

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, "90 hour flow test" 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. Such rates are not necessarily indicative of long term performance or of ultimate recovery. 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. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

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.

 

 

 

For further information:

Investor Relations
Toll free: 1-866-393-0393

ADVANTAGE OIL & GAS LTD.
700, 400 -3rd Avenue SW
Calgary, Alberta
T2P 4H2
Phone:  (403) 718-8000
Fax:      (403) 718-8300
Web Site: www.advantageog.com
E-mail:  ir@advantageog.com


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