News Releases

Advantage Announces Year End 2010 Reserves

Mar 7, 2011

Glacier Reserves Increase to 1 Tcf

(TSX: AAV, NYSE: AAV)

CALGARY, March 7 /CNW/ - 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
(2008 - 2009)
Phase II
(2009 - 2010)
Phase III
(2010 - Present)
Number of gross Upper Montney wells 8 25 20
Average test rate per well (mmcf/d) (1) 3.7 7.3 8.3
Average number of fracs per well 8 10 13

(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 2P reserve 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 proved reserve 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
              iii) the positive impact of the NGDDP where the effective 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

 
 
 
 
Light & Medium Oil 
(mbbl)
 
Heavy Oil 
 (mbbl)
Natural  
Gas Liquids 
 (mbbl) 
 
Natural Gas 
(mmcf)
Oil
Equivalent
 (mboe) 
Proved                 
Developed Producing  10,540 1,447 4,464 208,206 51,152
Developed Non-producing  751 150 129 28,672 5,809
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 + Probable  24,375 4,545 7,840 1,245,185 244,291

Gross Working Interest Reserves (Working Interest only)

Summary as at December 31, 2010

 
 
 
 
Light & Medium Oil 
(mbbl)
 
Heavy Oil 
 (mbbl)
Natural  
Gas Liquids
 (mbbl) 
 
 Natural Gas 
(mmcf)
Oil
Equivalent
 (mboe) 
Proved                 
Developed Producing  10,319  1,417  4,432  207,695  50,783
Developed Non-producing  749  147  129  28,562  5,785
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 + Probable  24,044  4,487  7,796  1,243,969  243,656

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:



Year 
WTI 
Crude Oil 
($US/bbl)
Edmonton Light 
Crude Oil
 ($Cdn/bbl)
Alberta AECO-C 
Natural Gas
 ($Cdn/mmbtu)
Henry Hub 
Natural Gas
 ($US/mmbtu) 
Exchange
Rate
($US/$Cdn)
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 amounts)  0%  10%  15%
Net asset value per Share (1) - December 31, 2009   $  45.55   $ 15.07  $  10.09
Present value proved and probable reserves  $ 6,630,028  $ 2,515,972  $ 1,810,633
       
Undeveloped acreage and seismic (2)   199,800   199,800  199,800
       
Working capital (deficit) and other   (41,839)  (41,839)  (41,839)
Convertible debentures   (148,544)  (148,544)  (148,544)
Bank debt   (288,852)   (288,852)  (288,852)
       
Net asset value - December 31, 2010  $ 6,350,593  $ 2,236,537  $ 1,531,198
       
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

 
 
Proved
Light & 
Medium Oil
 (mbbl) 
Heavy
 Oil 
(mbbl)
 Natural Gas
Liquids
 (mbbl)
 Natural
 Gas
 (mmcf)
 Oil
 Equivalent
 (mboe)
Opening balance Dec. 31, 2009  15,602  2,466  5,266  507,206  107,868
           
Extensions  345  3  42  141,744  24,014
Improved recovery  0  0 0 0 0
Infill Drilling  176  233  91  5,916  1,485
Discoveries  0  0  0  0 0
Economic factors  (93)  (8) (67)  (40,732)  (6,957)
Technical revisions  (430)  (49)  678 178,521 29,952
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 Dec. 31, 2010  13,862  1,654 5,181  736,040  143,371
           
 
 
Proved + Probable 
Light &
Medium Oil 
(mbbl)
 Heavy
Oil
 (mbbl) 
 Natural Gas
 Liquids
(mbbl)
 Natural
 Gas
 (mmcf)
 Oil
 Equivalent
 (mboe)
Opening balance Dec. 31, 2009  29,125  5,836  7,749  1,137,322 232,264
           
Extensions  795  4 46  209,799 35,811
Improved recovery  0  0 0  0 0
Infill Drilling  230  0 138 7,959 1,694
Discoveries  0  0  0  0  0
Economic factors  (154)  (13)  (89)  (33,158)  (5,782)
Technical revisions  (4,121) (41) 802  (11,766)  (5,321)
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 Dec. 31, 2010  24,044 4,487 7,796  1,243,969  243,656

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 ($000)        (69,676)    (69,676)
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 ($000)                               (3,258)            (3,258)
Acquisitions net of dispositions ($000 (69,676)  (69,676)
Net change in Future Development Capital ($000 339,907  69,493
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.

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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