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Supplementary Financial Information for Oil and Gas Producing Activities
12 Months Ended
Dec. 31, 2011
Supplementary Financial Information for Oil and Gas Producing Activities  
Supplementary Financial Information for Oil and Gas Producing Activities

(10) Supplementary Financial Information for Oil and Gas Producing Activities

Results of Operations from Oil and Gas Producing Activities

        The Company's natural gas interests consist of royalty and non-operating working interests in wells drilled on the Company's approximately 3,800 acres of land located in Johnson County, Texas in the Barnett Shale Formation. The Company also has royalty and non-operating working interests in wells drilled from drillsites on the Company's property under a lease covering approximately 538 acres of land contiguous to the Company's Johnson County, Texas property. The following sets forth certain information with respect to the Company's results of operations and costs incurred for its natural gas interests for the years ended December 31, 2011, 2010 and 2009:

 
  2011   2010   2009  

Results of Operations

                   

Revenues

  $ 12,878   $ 7,425   $ 6,925  

Production and operating costs

    2,269     1,421     1,514  

Depreciation and depletion

    1,402     1,172     1,001  
               

Results of operations before income taxes

    9,207     4,832     4,410  

Income tax expense

    2,664     1,410     1,226  
               

Results of operations (excluding corporate overhead and interest costs)

  $ 6,543   $ 3,422   $ 3,184  
               

Costs Incurred

                   

Development costs incurred

  $ 927   $ 2,204   $ 1,262  

Exploration costs

             

Capitalized asset retirement costs

  $ 3   $ 4   $ 3  

Property acquisition costs

          $ 22  

Capitalized Costs

                   

Natural gas properties—proved

  $ 18,220   $ 17,295   $ 15,080  

Less: accumulated depreciation and depletion

    5,997     4,593     3,419  
               

Net capitalized costs for natural gas properties

  $ 12,223   $ 12,702   $ 11,661  
               

Unaudited Oil and Natural Gas Reserve and Standardized Measure Information

        The independent petroleum engineering firm of DeGolyer and MacNaughton has been retained by the Company to estimate its proved natural gas reserves as of December 31, 2011. No events have occurred since December 31, 2011 that would have a material effect on the estimated proved reserves.

        The following information is presented with regard to the Company's natural gas reserves, all of which are proved and located in the United States. These rules require inclusion, as a supplement to the basic financial statements, of a standardized measure of discounted future net cash flows relating to proved gas reserves. The standardized measure, in management's opinion, should be examined with caution. The basis for these disclosures is independent petroleum engineers' reserve studies, which contain imprecise estimates of quantities and rates of production of reserves. Revision of estimates can have a significant impact on the results. Also, development and production improvement costs in one year may significantly change previous estimates of proved reserves and their valuation. Values of unproved properties and anticipated future price and cost increases or decreases are not considered. Therefore, the standardized measure is not necessarily a "best estimate" of the fair value of gas properties or of future net cash flows.

        In calculating the future net cash flows for its royalty and non-operating working interests in the table below as of December 31, 2011, 2010 and 2009, the Company utilized 12-month average prices, as now required by US GAAP, of $4.56, $4.52 and $4.04 per MCF of natural gas and $49.58, $38.71 and $23.20 per BBL of natural gas liquids, respectively. Utilizing year-end prices of natural gas and natural gas liquids as of December 31, 2011, 2010 and 2009 would have resulted in proved reserves of 10.2, 13.1 and 13.8 BCF of natural gas and 1.5, 1.3 and 1.9 MMBBLS of natural gas liquids, respectively.

  • Unaudited Summary of Changes in Proved Reserves

 
  Natural Gas
(BCF)
2011
  Natural Gas
Liquids
(MMBBLS)
2011
  Natural Gas
(BCF)
2010
  Natural Gas
Liquids
(MMBBLS)
2010
  Natural Gas
(BCF)
2009
  Natural Gas
Liquids
(MMBBLS)
2009
 

Proved reserves—beginning of year

    12.3     1.2     13.3     1.8     16.4     0.6  

Revisions of previous estimates

    (0.8 )   0.5     (0.6 )   (0.6 )   (2.6 )   1.1  

Extensions and discoveries

            0.4         0.5     0.1  

Production

    (1.2 )   (0.2 )   (0.8 )       (1.0 )    
                           

Proved reserves—end of year

    10.3     1.5     12.3     1.2     13.3     1.8  
                           

Proved developed reserves—end of year

    10.3     1.5     11.7     1.2     8.9     1.2  
                           
  • Unaudited Standardized Measure of Discounted Future Net Cash Flows

 
  2011   2010   2009  

Future estimated gross revenues

  $ 120,920   $ 102,198   $ 96,187  

Future estimated production and development costs

    (32,138 )   (31,406 )   (28,035 )
               

Future estimated net revenues

    88,782     70,792     68,152  

Future estimated income tax expense

    (25,627 )   (20,174 )   (19,588 )
               

Future estimated net cash flows

    63,155     50,618     48,564  

10% annual discount for estimated timing of cash flows

    (33,207 )   (24,162 )   (25,488 )
               

Standardized measure of discounted future estimated net cash flows

  $ 29,948   $ 26,456   $ 23,076  
               
  • Unaudited Changes in Standardized Measure of Discounted Future Net Cash Flows

 
  2011   2010   2009  

Standardized measure—beginning of year

  $ 26,456   $ 23,076   $ 30,719  

Net change in sales prices and production costs

    2,403     8,689     (12,735 )

Sales of natural gas produced, net of production costs

    (12,878 )   (5,992 )   (5,065 )

Extensions and discoveries, net of related costs

        1,737     3,357  

Future development costs

        (716 )   (2,094 )

Net change due to changes in quantity estimates

    4,086     (5,488 )   7,789  

Previously estimated development costs incurred

    925     1,549     272  

Net change in income taxes

    (1,609 )   (1,237 )   3,012  

Accretion of discount

    3,211     2,962     1,623  

Timing of production of reserves and other

    7,354     1,876     (3,802 )
               

Standardized measure—end of year

  $ 29,948   $ 26,456   $ 23,076