Netherland, Sewell & Associates, Inc., independent reserve evaluators, completed an evaluation of 100% of Compton’s petroleum and natural gas reserves as at December 31, 2009 in accordance with the provisions of National Instrument 51-101. As required by National Instrument 51-101, Compton filed Form 51-101 F1 as part of its Annual Information Form (“AIF”).  The AIF is considered comprehensive.  Certain information has been summarized below regarding the Corporation’s operations.  Compton’s extended disclosure contained in the AIF is available on both the SEDAR website and Compton’s website.

 

Reserves experienced a downward revision mainly due to Compton’s investment strategy of managing its capital expenditure program within available cash flow. In addition, some proved undeveloped producing and probable reserves in the Plains Belly River area were moved to the possible category until Management completes a reserve review to determine optimal drainage requirements. These technical revisions had a minor impact on reserve values. Value changes were mainly due to changes in the commodity price deck and the inclusion of a 5% overriding royalty in 2009.

 

2009 Reserve Summary (1)
Company Working Interest before Royalties

 

Summary of Estimated Reserve Volumes - Forecast Prices and Costs (1)

    Oil   Gas   NGL   Sulphur   Total
December 31, 2009   (MBbl)   (MMcf)   (MBbl)   (MLt)   (MBoe)
Proved
    Producing
    Non-Producing
    Undeveloped		  
3,688
37
54		  
370,386
35,502
90,656		  
7,184
449
1,633		  
1,770
56
141		  
74,372
6,459
16,937
Total proved   3,779   495,544   9,266   1,966   97,768
Probable   2,808   340,388   6,174   862   66,575
Total proved plus probable   6,587   836,932   15,440   2,828   164,343
(1) Numbers may not add due to rounding.

  • Proved reserves comprise 59% of total proved plus probable reserves, a slight increase from 2008
  • Proved reserve life index (“RLI”) is 13.6 years and proved plus probable RLI is 22.9 years

Compton’s total proved reserve base is comprised of 85% natural gas and 15% liquids.  Proved producing reserves comprise 76% of total proved reserves, and total proved reserves account for 59% of the proved plus probable reserves. The Corporation has a total proved RLI of 13.6 years and a proved plus probable RLI of 22.9 years, based on current production of 19,700 boe/d.

 

After giving effect to property sales, production, extensions and revisions, 2009 reserves decreased by approximately 27 MMBoe or 21% on a proved basis, and 51 MMBoe or 24% on a proved plus probable basis as compared to 2008. During 2009, Compton produced 7.6 MMBoe and sold approximately 10.1 MMBoe of proved reserves.

 

Net Present Value of Reserves (1)

December 31, 2009 Future net revenue
before income taxes discounted at a rate of
($000)   0%   10%   15%
Proved
    Producing
    Non-producing
    Undeveloped
$
2,471,721
208,483
388,983
$
915,989
86,224
125,285
$
711,953
63,808
77,757
Total proved $ 3,015,186   1,127,499   853,518
Probable   1,840,044   567,018   368,029
Total proved plus probable $ 4,855,230 $ 1,694,516 $ 1,221,547

(1) Forecast prices and costs; before income taxes; numbers may not add due to rounding.

 

Future net revenues are calculated based upon estimated revenues less royalties, operating costs, future development costs, and well abandonment costs.  Estimated income taxes have not been deducted.  The net present value should not be considered the current market value of Compton’s reserves or the costs that would be incurred to obtain equivalent reserves.

 

At December 31, 2009, future net revenue from Compton’s reserves decreased 31% from year-end 2008 on a total proved basis and 34% on a total proved and probable basis, discounted at 10%. The decrease in proved valuation is primarily due to the change in forecasted prices between the two years (58%) and the inclusion of the overriding royalty (30%). On a proved plus probable basis, these factors accounted for 53% and 31% of the decrease, respectively.

 

Reserve Reconciliation - Forecast Prices and Costs
  Crude Oil, NGLs
& Sulphur		 Natural Gas Total
  Proved
(Mbbl)		 Probable
(Mbbl)		   Proved
(Bcf)		 Probable
Bcf)		   Proved
(MMcf)		 Probable
(Mboe)		 Proved +
Probable
(Mboe)
December 31, 2008
Extensions
Improved Recovery
Technical revisions
Discoveries
Acquisitions
Dispositions
Economic
Production		 17,591
24
-
(572)
-
-
(679)
(136)
(1,217)		 11,329
216
-
(1,238)
-
-
(415)
(48)
-		   640
4
-
(90)
-
-
(13)
(7)
(39)
 479
7
-
(102)
-
-
(42)
(2)
-		   124,324
611
-
(15,530)
-
-
(2,773)
(1,226)
(7,637)		 91,164
1,355
-
(18,203)
-
-
(7,346)
(396)
-		 215,488
1,966
-
(33,733)
-
-
(10,119)
(1,622)
(7,637)
December 31, 2009 15,011 9,844   497 340   97,768 66,575 164,343

(1) Forecast prices and costs; numbers may not add due to rounding.

 

Technical revisions relate to adjustments in performance forecasts based on current production profiles, lease expiries, changes in development upside based on new data obtained, and available capital. Aggregate negative technical revisions, related to December 31, 2009 reserve bookings, were 15.6 MMBoe on a proved basis and 18.1 MMBoe on a proved and probable basis.

 

Proved undeveloped producing reserves were reduced by 9%, primarily due to performance of producing Plains Belly River wells and High River Basal Quartz wells. Total proved reserves were reduced a total of 21%. In addition to the Belly River and Basal Quartz well performance, the number of PUD locations in the Belly River was reduced from four to two wells per section. Management took a prudent approach and reduced the current spacing, modifying the prior assumption that every section would require four wells to optimally drain reserves. As a result of Compton’s reduced capital program, some proved undeveloped producing and probable reserves were moved to the possible category to better align with the timing of reserves as per the guidelines in COGEH, which are referenced in National Instrument 51-101.

 

Proved plus probable reserves declined by 24%. In addition to the removal of the Belly River proved undeveloped locations, the fourth well per section probable locations were removed. In aggregate, approximately 400 locations in the Plains Belly River area were eliminated, accounting for 48% of the proved plus probable reserve reduction.

 

Net Asset Value

Net asset value was $1.91 per basic common share on a proved basis and $4.07 per basic common share on a proved plus probable basis, based on the independently estimated reserve value, outstanding debt as of December 31, 2009 and the number of outstanding shares at that time.