Athabasca Oil Sands Corp. Announces Independent Reserves and Resources Report and Operations Update

CALGARY, June 24, 2011 /CNW/ - Athabasca Oil Sands Corp. (TSX: ATH) is pleased to announce its reserves and contingent resources have increased, the tests at Dover West are progressing and the board of directors has approved an increase to the budget for, and an acceleration of the appraisal and development program in, the Alberta Deep Basin.

Bitumen Reserves and Contingent Resources Grow

Athabasca drilled 89 delineation wells at Hangingstone, Dover West, Birch and Grosmont during the 2010-2011 winter programs and increased its net resource volumes by approximately 10% to 9.672 billion barrels of contingent resource (best estimate) and 289 million barrels of probable reserves compared to the independent estimates at December 31, 2010.  The third-party independent evaluation reports were prepared by GLJ Petroleum Consultants Ltd. (GLJ) and DeGolyer and MacNaughton Canada Limited (D&M) with effective dates of April 30, 2011.

Sveinung Svarte, president and CEO, says the increase in Athabasca's resources is a reflection of both the successful drilling program and the quality of its vast land base.  "I am very pleased to see that we continue to add significant resources through organic growth. This demonstrates the technical excellence and capability of the organization as we move into the development stage of certain projects."

Based on the independent evaluation reports of GLJ and D&M and the assumptions made therein, the estimated before tax net present value (NPV) of future net revenue, discounted at 9.0%, of Athabasca's contingent resources (best estimate) ($31.3 billion) and probable plus possible reserves ($2.1 billion) is approximately $33.4 billion. Summary details regarding Athabasca's bitumen reserve and contingent resources and the associated NPV of future net revenues are included in the attached Schedule "A".

The largest addition in resources was in the Birch area, northwest of Fort McMurray, where the company saw an increase of approximately 64% of contingent resource (best estimate).  The resource figure for the area is now 1.9 billion barrels contingent resource (best estimate), which is believed to be sufficient to support a project with plateau production of 155,000 barrels/day.

"We knew Birch was a promising area," Svarte says. "We are excited with the results after one drilling season, especially knowing there are large parts of the area which are relatively unexplored and which could add further upside."

Dover West Tests Progressing

Last winter, Athabasca started the testing of the bitumen bearing Leduc carbonate reservoir in the Dover West area.  The first test was based on steam injection and successfully resulted in the addition of 140 million barrels of contingent resource (best estimate).

The company also completed the construction of a thermal assisted gravity drainage (TAGD) heating field test pilot where two horizontal wells are being heated using electrical cables as the heating source.  An area of the Leduc Reef has been heating for approximately 10 weeks and four observation wells indicate that the heat is spreading, as the company's modeling had predicted.  Production results from the test are expected as soon as the area can be accessed on winter roads.

Deep Basin Program

Athabasca is also actively involved in the Deep Basin area, in northwestern Alberta, where it holds more than one million acres of promising acreage for light oil and liquids-rich gas resource play. The initial approved drilling program consisted of six wells. Of these, four have been drilled and three have been completed using multi-stage fracture stimulation, while the fourth well will be completed in the upcoming weeks.

"Our board of directors recently approved an additional $61.5 million to the 2011 capital expenditure budget for an expanded work program which includes additional wells, 3D seismic and geological studies focusing on the Montney, Nordegg and Duvernay formations," Svarte says. "Athabasca is planning to drill a total of 14 wells during 2011.  The acceleration and expansion of the program is based on the results from the company's initial wells, further geological studies and drilling results from offsetting operators."

"The company expects to continue to expand the Deep Basin program," adds Bill Gallacher, chairman of the board, "while keeping capital expenditures at a disciplined level.  The land position we hold in the Deep Basin is also a tribute to the excellent work done by Athabasca's geosciences team. They recognized the unique potential of this area and acquired a large land position at reasonable prices."

According to Gallacher, the production of light oil and liquids-rich gas is very complementary to Athabasca's core bitumen business. "High quality geoscience, reservoir and drilling departments are fundamental to the company's success in bitumen and light oil.  The production of light oil and liquids-rich gas are also excellent natural hedges for diluents and gas needed in the oil sands business."

Company Hires Development Employees

The company is pleased to announce the appointment of Richard Koshman to the newly-created position of vice president, projects.  He has successfully delivered steam assisted gravity drainage (SAGD) projects.  Koshman will work with the asset teams on each oil sands project, from the regulatory application through construction to production.

Athabasca has filed three regulatory applications with the Energy Resources Conservation Board (ERCB) for the MacKay River commercial project (40% working interest), Dover commercial project (40% working interest) and Hangingstone pilot (100% working interest). The company intends to file two more regulatory applications in the Dover West asset area during 2011 and expects to receive approval for the 150,000 barrels/day MacKay River project later this year. The detailed engineering is on-going and the company is expected to be ready to build these projects.

Athabasca continues to hire key employees with thorough SAGD implementation experience from Canada's leading oil sands operators.  There are about 150 employees on staff today and that number is expected to grow to approximately 200 by year-end.

Athabasca is a dynamic company poised to unlock bitumen from Canada's vast oil sands region and light oil and liquids-rich gas from its Deep Basin play in northern Alberta.  It has excellent assets, a large resource base with ample upside, talented people and is well financed.  It also has a diverse portfolio of short, mid and long-term assets.

Athabasca's common shares trade on the Toronto Stock Exchange (TSX) under the symbol ATH. For more information visit: http://www.aosc.com.

Athabasca's Annual General Meeting
Date:    Friday, June 24, 2011
Time:    10:00 a.m. MT (12:00 p.m. ET)
Venue:    Strand Tivoli Room
  The Metropolitan Centre
  333 - 4th Avenue S.W., Calgary, Alberta
To view the live video-stream webcast or archived event, please visit:
http://event.on24.com/r.htm?e=321761&s=1&k=76A06C1A1D7CC4DB8925AF1BBE3E63A9
The webcast will be archived for approximately 365 days.

Reader Advisory
This News Release contains forward-looking information that involves various risks, uncertainties and other factors. All statements other than statements of historical fact are forward-looking statements. The use of any of the words "anticipate", "plan", "continue", "estimate", "expect", "may", "will", "project", "should", "believe", "predict", "pursue" and "potential" and similar expressions are intended to identify forward-looking statements. The forward-looking information is not historical fact, but rather is based on AOSC's current plans, objectives, goals, strategies, estimates, assumptions and projections about AOSC's industry, business and future financial results. These statements involve known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in such forward-looking statements. No assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this News Release should not be unduly relied upon. These statements speak only as of the date of this News Release. In particular, this News Release may contain forward-looking statements pertaining to the following: AOSC's capital expenditure programs; the estimated quantity of AOSC's Probable and Possible Reserves and Contingent Resources; AOSC's drilling plans; AOSC's plans for, and results of, exploration and development activities; AOSC's estimated future commitments; proposed experimental testing in the Dover West area and the results there from; business plans; AOSC's plans with respect to the Hangingstone, Dover West, Birch and Grosmont assets and the timing for receipt of any regulatory applications or approvals. With respect to forward-looking statements and forward-looking information contained in this News Release, assumptions have been made regarding, among other things: AOSC's ability to obtain qualified staff and equipment in a timely and cost-efficient manner; the regulatory framework governing royalties, taxes and environmental matters in the jurisdictions in which AOSC conducts and will conduct its business; the applicability of technologies for the recovery and production of AOSC's reserves and resources; future capital expenditures to be made by AOSC; future sources of funding for AOSC's capital programs; AOSC's future debt levels; geological and engineering estimates in respect of AOSC's reserves and resources; the geography of the areas in which AOSC is conducting exploration and development activities;  and AOSC's ability to obtain financing on acceptable terms. Actual results could differ materially from those anticipated in these forward-looking statements as a result of the risk factors set forth above and in the Company's Annual Information Form dated March 28, 2011, which is available on the SEDAR website at www.sedar.com ("AIF"), including: fluctuations in market prices for crude oil, natural gas and bitumen blend; general economic, market and business conditions; variations in foreign exchange and interest rates; factors affecting potential profitability; the global financial crisis; uncertainties inherent in estimating quantities of reserves and resources; AOSC's status and stage of development; uncertainties inherent in Steam Assisted Gravity Drainage ("SAGD"), Cyclic Steam Stimulation ("CSS"), Thermal Assisted Gravity Drainage ("TAGD") and other bitumen recovery processes; the potential impact of the exercise of the Put/Call Options (as defined in the AIF) on AOSC; failure to meet development schedules and potential cost overruns; increases in operating costs rendering projects uneconomic; the effect of diluent and natural gas supply constraints and increases in the costs thereof; gas over bitumen issues; environmental risks and hazards and the cost of compliance with environmental regulations, including greenhouse gas regulations and potential Canadian and U.S. climate change legislation; failure to obtain or retain key personnel; the substantial capital requirements of AOSC's projects; the need to obtain regulatory approvals and maintain compliance with regulatory requirements; extent of, and cost of compliance with, current and future government laws and regulations; changes to royalty regimes; political risks; failure to accurately estimate abandonment and reclamation costs; risks inherent in AOSC's operations, including those related to exploration, development and production of oil sands and other petroleum reserves and resources, including the production of oil sands reserves and resources using SAGD, CSS, TAGD or other in-situ technologies; the potential for management estimates and assumptions to be inaccurate; long term reliance on third parties and defaults by counter parties; the potential lack of available drilling equipment and limitations on access to AOSC's assets; aboriginal claims; seasonality; hedging risks; risks associated with maintaining systems of internal controls; insurance risks; claims made in respect of AOSC's operations, properties or assets; competition risks arising from future acquisition activities; volatility in the market price of the common shares. In addition, information and statements in this News Release relating to "reserves" and "resources" are deemed to be forward-looking information and statements, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated, and that the reserves and resources described can be profitably produced in the future. The assumptions relating to AOSC's reserves and resources are contained in the reports of GLJ Petroleum Consultants Ltd. dated effective April 30, 2011 and  DeGolyer and MacNaughton Canada Limited dated effective April 30, 2011. The risks and uncertainties referred to above are described in more detail in AOSC's AIF which is available on the SEDAR website at www.sedar.com.  See also AOSC's financial statements and Management's Discussion and Analysis for the year ended December 31, 2010 and the most recently completed financial quarter, which are also available on SEDAR. Readers are cautioned that the foregoing list of risk factors should not be construed as exhaustive. The forward-looking statements included in this News Release are expressly qualified by this cautionary statement. AOSC does not undertake any obligation to publicly update or revise any forward-looking statements except as required by applicable securities laws.

Schedule "A"

Hangingstone Project, MacKay Phase 1 and Dover Phase 1 Reserves Based on Forecast Prices and Costs(4)(5)(6)

    RESERVES SUMMARY
    BITUMEN   TOTAL OIL EQUIVALENT
RESERVES CATEGORY   Company
Gross(1)
(mbbl)
  Company
Net(1)
(mbbl)
  Company
Gross(1)
(mbbl)
  Company
Net(1)
(mbbl)
                 
PROBABLE                
      Dover   137,144   105,570   137,144   105,570
      MacKay   113,919   87,033   113,919   87,033
Hangingstone   37,805   29,928   37,805   29,928
TOTAL PROBABLE(2)   288,868   222,531   288,868   222,531
                 
POSSIBLE                
      Dover   18,275   12,476   18,275   12,476
      MacKay   25,801   17,455   25,801   17,455
Hangingstone   2,673   1,865   2,673   1,865
TOTAL POSSIBLE(3)   46,749   31,796   46,749   31,796
                 
TOTAL PROBABLE PLUS POSSIBLE(2)(3)   335,617   254,327   335,617   254,327

 

 

Summary of Net Present Values of Future Net Revenue Based on Forecast Prices and Costs(4)(5)(6)

     Before Income Tax Discounted at (%/year)
RESERVES
CATEGORY
  0%
(MM$)
  5%
(MM$)
  9%
(MM$)
  10%
(MM$)
  15%
(MM$)
  20%
(MM$)
                         
PROBABLE                        
    Dover   3,808   1,753   972   840   399   171
    MacKay   3,325   1,510   841   729   352   152
Hangingstone   699   406   243   210   77   (12)
    Other Tax Pools   -   -       -   -   -
TOTAL PROBABLE(2)   7,832   3,668   2,056   1,779   829   311
                         
POSSIBLE                        
    Dover   823   279   133   112   56   33
    MacKay   1,249   363   155   128   57   33
Hangingstone   88   56   38   34   20   9
    Other Tax Pools   -   -       -   -   -
TOTAL POSSIBLE(3)   2,160   698   326   274   133   75
                         
TOTAL PROBABLE
    PLUS
    POSSIBLE(2)(3)(5)
  9,992   4,367   2,382   2,053   961   386

 

 

    After Income Taxes Discounted at (%/year)
RESERVES
CATEGORY
  0%
(MM$)
  5%
(MM$)
  9%
(MM$)
  10%
(MM$)
  15%
(MM$)
  20%
(MM$)
                           
PROBABLE                          
    Dover   2,842   1,274   680   580   247   76
    MacKay   2,485   1,100   591   505   219   66
Hangingstone   493   261   136   109   6   (63)
    Other Tax Pools   137   88   65   61   44   33
TOTAL PROBABLE(2)   5,957   2,723   1,473   1,256   516   112
                           
POSSIBLE                          
    Dover   620   211   102   87   44   28
    MacKay   935   273   118   98   45   27
Hangingstone   76   46   30   28   14   5
    Other Tax Pools     1   1   1   1   1   1
TOTAL POSSIBLE(3)   1,632   531   250   214   104   61
                         
TOTAL PROBABLE
   PLUS
   POSSIBLE(2)(3)(5)
  7,589   3,255   1,723   1,469   620   173

Notes:
(1)      "Gross Reserves" are the Company's working interest (operating or non-operating) share before deducting royalties and without including any royalty interests of the Company. "Net Reserves" are the Company's working interest (operating or non-operating) share after deduction of royalty obligations, plus the Company's royalty interests in reserves.
(2)      "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 Reserves plus Probable Reserves.
(3)      "Possible Reserves" are those additional reserves that are less certain to be recovered than Probable Reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of Proved Reserves plus Probable Reserves plus Possible Reserves.
(4)      The pricing assumptions used in the GLJ Report and the D&M Report with respect to values of future net revenue as well as the inflation rates used for operating and capital costs are set forth below under "- GLJ - April 1, 2011 Pricing Assumptions". GLJ is an independent qualified reserves evaluator appointed pursuant to NI 51-101.
(5)      Totals may not add due to rounding.
(6)      The Company's investments in the Dover and MacKay assets are accounted for by the equity method and the Reserve and future net revenue estimates set out above reflect the Company's indirect 40% working interests in the MacKay and Dover assets which are held directly by the Company's wholly owned subsidiaries, AOSC (MacKay) and AOSC (Dover), respectively.

Contingent Resources:

The table below summarizes the Company's Contingent Resources and associated future net revenues as of April 30, 2011, as evaluated by GLJ in the GLJ Report and by D&M in the D&M Report, respectively.

It should not be assumed that the estimates of recovery, production and net revenue presented in the tables below represent the fair market value of Athabasca's bitumen resources. There is no assurance that the forecast prices and cost assumptions will be realized and variances could be material. The actual resources may be greater than or less than the estimates provided. The contingencies which currently prevent the classification of the Contingent Resources disclosed in the table as reserves consist of: further facility design, preparation of firm development plans, and regulatory applications (including associated reservoir studies and delineation drilling), and Company approvals. There is no certainty that it will be commercially viable to produce any portion of the Contingent Resources.

Both the GLJ Report and the D&M Report are based on GLJ's April 1, 2011 pricing (see GLJ - April 1, 2011 Pricing Assumptions below).

Contingent Resources(1 (10), (13)(15) (mmbbls)
  Low Estimate(2) Best Estimate(3) High Estimate(4)
GLJ Report (5)      
  Established Technology        
    MacKay 345 573 983
    Dover 772 1,221 1,616
    Dover West Clastics 1,284 1,991 2,867
      2,401 3,785 5,466
   Technology Under Development(8)         
    Dover West Leduc Carbonates N/A (9) 2,866 4,977
    Grosmont (14) N/A(9) 418 1,876
  Total GLJ Report   2,401 7,070 12,319
         
D&M Report (6)        
  Established Technology      
    Birch 1,344 1,885 2,614
    Hangingstone 642 718 906
  Total D&M Report 1,986 2,603 3,520
TOTAL COMPANY5, 6, 7 4,387 9,672 15,839

 

 

      Before Income Tax Discounted at (%/year)
CONTINGENT
RESOURCE
CATEGORY
  mmbbl   0%
(MM$)
  5%
(MM$)
  9%
(MM$)
  10%
(MM$)
  15%
(MM$)
  20%
(MM$)
Best Estimate                            
GLJ Report(5)                            
Existing Technology                            
Dover (10) (16)   1,221   42,629   10,870   4,355   3,526   1,301   477
Dover West Clastics   1,991   59,066   14,924   5,590   4,400   1,245   143
MacKay(10) (16)    573   16,117   4,755   2,034   1,666   640   241
                             
Technology under
Development(8)
                           
Dover West Carbonates   2,866   92,733   27,975   12,188   10,023   3,906   1,474
Grosmont (14)   418   9,808   2,191   603   411   (53)   (168)
Other Tax Pools   -   -   -   -   -   -   -
                             
D&M Report(6)                            
Existing Technology                            
Birch   1,885   67,729   15,870   4,958   3,581   150   (905)
Hangingstone(12)   718   28,500   5,998   1,621   1,082   (154)   (488)
                                    
Total Best Estimate (7) 
(13)(14)
  9,672   316,582   82,583   31,348   24,690   7,035   774

 

 

      After Income Tax Discounted at (%/year)
CONTINGENT
RESOURCE
CATEGORY
  mmbbl   0%
(MM$)
  5%
(MM$)
  9%
(MM$)
  10%
(MM$)
  15%
(MM$)
  20%
(MM$)
Best Estimate                            
GLJ Report(5)                            
Existing Technology                            
Dover (10) (16)   1,221   31,790   7,924   3,078   2,466   834   242
Dover West Clastics   1,991   43,929   10,673   3,758   2,887   604   (164)
MacKay(10) (16)    573   11,957   3,412   1,402   1,134   393   113
                             
Technology under
Development(8)
                           
Dover West Carbonates   2,866   69,174   20,461   8,676   7,067   2,542   768
Grosmont (14)   418   7,292   1,494   316   177   (144)   (207)
Other Tax Pools   -   458   71   34   30   23   18
                             
D&M Report(6)                            
Existing Technology                            
Birch   1,885   50,079   11,372   3,208   2,180   (420)   (1,175)
Hangingstone(12)   718   20,975   4,407   1,040   631   (359)   (605)
                                    
Total Best Estimate (7)
(13)(14)
  9,672   235,654   59,815   21,512   16,571   3,473   (1,009)

Notes:
(1)      "Contingent Resources" are defined in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") as 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. Contingencies may include factors such as economic, legal, environmental, political and regulatory matters or a lack of markets. It is also appropriate to classify as "Contingent Resources" the estimated discovered recoverable quantities associated with a project in the early evaluation stage. Contingent Resources are further classified in accordance with the level of certainty associated with the estimates and may be sub classified based on project maturity and/or characterized by their economic status. The volumes of contingent bitumen resources in the above table were calculated at the outlet of the proposed extraction plant and are the Company's working interest (operating or non-operating) share before deduction of royalty obligations.
(2)      "Low Estimate" is a classification of estimated resources described in the COGE Handbook as being 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 a 90% probability (P90) that the quantities actually recovered will equal or exceed the Low Estimate.
(3)      "Best Estimate" is a classification of estimated resources described in the COGE Handbook as being 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 a 50% probability (P50) that the quantities actually recovered will equal or exceed the Best Estimate.
(4)      "High Estimate" is a classification of estimated resources described in the COGE Handbook as being 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 a 10% probability (P10) that the quantities actually recovered will equal or exceed the High Estimate.
(5)      Based on the GLJ Report dated effective as of April 30, 2011.
(6)      Based on the D&M Report dated effective as of April 30, 2011.
(7)      These volumes are arithmetic sums of multiple estimates of contingent bitumen resources, which statistical principles indicate may be misleading as to volumes that may actually be recovered. Readers should give attention to the estimates of individual classes of resources and appreciate the differing probabilities of recovery associated with each class as explained. In particular, readers should be aware that the likelihood of attaining the sum of the High Estimate is extremely low and of the Low Estimate quite high.
(8)      The Company's resources at its Dover West Carbonates and Grosmont assets are contained in carbonate reservoirs. Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam Stimulation (CSS), the recovery processes being considered to develop these assets, are considered by GLJ to be "technology under development" in carbonate reservoirs. The successful development of the Company's carbonate reservoirs depends on, among other things, the successful development and application of SAGD, Thermal Assisted Gravity Drainage (TAGD) and CSS or other recovery processes to carbonate reservoirs. Although the technology has been developed for application to non-carbonate reservoirs, there are no known successful commercial projects that use SAGD, TAGD or CSS to recover bitumen from carbonate formations and there exists a large range in the expected recoverable volumes, the lower end of which may not be economically viable. The principal risks associated with SAGD and CSS recovery in carbonate reservoirs are: (i) the possibility of unexpected steam channelling which would increase steam requirements resulting in increased costs and potentially reduced economically recoverable bitumen volumes; and (ii) potential mechanical operating problems due to production of fines which could cause wellbore plugging and reduced bitumen production rates and potential interruption of surface production operations. Although the technical risks associated with "technology under development" have been accounted for in the GLJ Report, the timeline for verification of "technology under development" has inherent uncertainty. The Company is also testing TAGD as an alternate bitumen recovery process in the Dover West Carbonates. The principal risk associated with TAGD recovery in carbonate reservoirs is to prove TAGD as a commercially viable bitumen recovery process. Development will involve significant capital expenditures and a lengthy time to project payout and project payout is not assured. If a pilot project and/or the technology under development do not demonstrate potential commerciality in carbonate reservoirs then the Company's projects on these assets may not proceed and this may occur only after significant expenditures have been incurred by the Company. With respect to the Company's Grosmont asset, the Company's strategy is to continue delineation drilling efforts in the area in order to increase the resource base. The Company has not prepared a development plan or timeline for the Grosmont area, and is monitoring industry activity toward demonstrating successful development and production methods for the Grosmont Formation. See "Independent Reserve and Resource Evaluations".
(9)      The GLJ Report does not calculate the discounted future net revenues associated with the Dover West Carbonates and Grosmont assets in the Low Estimate case because GLJ does not believe that a high certainty or Low Estimate case would be economic. Readers should be aware that if calculated, the discounted future net revenues associated with the Dover West Carbonates and Grosmont assets in the Low Estimate would likely be negative since the Low Estimate result would be realized only after considerable capital has been invested.
(10)      There is no certainty that it will be commercially viable to produce any portion of the resources.
(11)      These figures do not include the Probable and Possible Reserves volumes and values that have been assigned by GLJ to Phase 1 of the MacKay Oil Sands Project and to Phase 1 of the Dover Oil Sands Project. See "Reserves above.
(12)      These figures do not include the Probable and Possible Reserves volumes and values that have been assigned by D&M to Hangingstone Project. See "Reserves" above.
(13)      Totals may not add due to rounding.
(14)      Athabasca's strategy is to continue delineation drilling efforts in the Grosmont area in order to increase the resource base at this asset. Athabasca has not prepared a development plan or timeline for the Grosmont area, and is monitoring industry activity toward demonstrating successful development and production methods for the Grosmont Formation. Other than as noted above, Athabasca has no current plans to pursue the development of the Grosmont asset and the net present value shown here should therefore not be considered to be a reasonable assessment of the current value of the Grosmont asset to the Company.
(15)      The resource estimates set out above reflect the Company's 100% working interest in the Hangingstone, Dover West and Birch assets, 40% working interests in the MacKay and Dover assets and 50% working interest in the Grosmont asset.
(16)      [The Company's investments in Dover and MacKay are accounted for by the equity method and the resource and future net revenue estimates set out above reflect only the Company's 40% working interests in the MacKay and Dover areas which are respectively held directly by  the Company's wholly owned subsidiaries, AOSC (MacKay) and AOSC (Dover).

GLJ - April 1, 2011 Pricing Assumptions (1), (2)

                                     
    Oil Sands
Inflation   %
  Bank of
Canada Average 
Noon Rate
$US/$Cdn 
  West Texas Intermediate
Crude Oil at Cushing
Oklahoma Current   
$US/bbl   
  Light,Sweet Crude Oil
(40 API,0.3%S)
at Edmonton
Current   
$Cdn/bbl   
  LLB Crude
Oil Stream Quality
at Hardisty
Current  
$Cdn/bbl  
  Dil-bit
Quality Differential
Current 
$Cdn/bbl 
  Diluent
at Field
Current(3)
$Cdn/bbl
  Sandstones
0.42857
Bitumen
Wellhead
Current  
$Cdn/bbl  
  Carbonates
0.46
Bitumen
Wellhead
Current(4)   
$Cdn/bbl  
2011
2012
  2.0
2.0
  0.980
0.980
  105.00
102.00
  103.06
101.02
  80.90
81.32
  -3.50
-2.75
  118.34
110.05
  51.12
56.35
  51.75
55.18
2013   2.0   0.980   100.00   100.51   80.91   -2.00   108.52   57.49   56.38
2014   2.0   0.980   100.00   101.02   81.32   -1.25   109.04   62.64   61.63
2015   2.0   0.980   100.00   101.12   81.40   -1.25   109.14   62.71   61.70
2016   2.0   0.980   100.00   101.12   81.40   -1.28   109.14   62.68   61.67
2017   2.0   0.980   101.36   102.51   82.52   -1.30   110.56   64.70   63.71
2018   2.0   0.980   103.38   104.57   84.18   -1.33   112.66   66.14   65.13
2019   2.0   0.980   105.45   106.68   85.88   -1.35   114.82   67.96   66.94
2020   2.0   0.980   107.56   108.84   87.61   -1.38   117.01   69.45   68.42
2021   2.0   0.980   109.71   111.02   89.36   -1.41   119.23   72.04   71.01
2022   2.0   0.980   111.91   113.24   91.15   -1.44   121.49   73.58   72.54
2023   2.0   0.980   114.14   115.50   92.97   -1.46   123.80   75.15   74.10
2024+   2.0   0.980   +2.0%/yr   +2.0%/yr   +2.0%/yr       +2.0%/yr   +2.0%/yr   +2.0%/yr

Notes
(1)      Blending Ratio = 1 bbl bitumen: 0.42857 bbl Diluent for Bitumen Netback pricing. This blending ratio equates to a bitumen blend (dilbit) comprised of 30% condensate and 70% bitumen.
(2)      Blending Ratio = 1 bbl bitumen: 0.46 bbl Diluent for Carbonates Bitumen Netback pricing. This blending ratio equates to a bitumen blend (dilbit) comprised of 31.5% condensate and 68.5% bitumen.
(3)      Includes diluent transportation and postings premiums of Cdn$6.00/bbl.
(4)      Net of transportation costs of Cdn$3.50/bbl from 2011 through 2013, Cdn$3.50/bbl from 2014 through 2016, Cdn$2.75/bbl from 2017 through 2018, Cdn$2.50 from 2019through 2020, and Cdn$1.75/bbl thereafter.

 

For further information:

Media & Financial Community
Heather Douglas
Vice President, Communications & External Affairs 
(403) 532-7408
hdouglas@aosc.com

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Athabasca Oil Sands Corp

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