Annual report pursuant to section 13 and 15(d)

Supplementary Oil and Gas Information (unaudited)

v2.3.0.11
Supplementary Oil and Gas Information (unaudited)
12 Months Ended
Dec. 31, 2011
Supplementary Oil and Gas Information (unaudited) [Abstract]  
Supplementary Oil and Gas Information (unaudited)
15. Supplementary Oil and Gas Information (unaudited)

Costs Incurred. Costs incurred in oil and gas property acquisition, exploration and development activities and related depletion per equivalent unit-of-production were as follows:

 

                 
    2010     2011  

Acquisition costs:

               

Unproved properties

  $ —       $ 132,945  

Proved properties

    —         10,942,751  

Exploration costs

    —         —    

Development costs

    —         —    

Asset retirement obligation

    —         639,176  
   

 

 

   

 

 

 

Total costs incurred

  $ —       $ 11,075,696  
   

 

 

   

 

 

 

Depletion per bble of production

  $ —       $ 22.72  
   

 

 

   

 

 

 

Supplemental Oil and Gas Reserve Information

The reserve information presented below is based on estimates of net proved reserves as of December 31, 2011 that were prepared by the Company’s independent petroleum engineering firm, Ryder Scott Company, in accordance with guidelines established by the SEC.

Proved oil and gas reserves are the estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made). Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Changes in Proved Reserves

The Company did not have any proved reserves prior to 2011. The following table sets forth information regarding the Company’s estimated total proved and oil and gas reserve quantities for the year ended December 31, 2011:

 

                         
    Oil
(Bbl)
    Gas
(Mcf)
    Equivalent
(Bble)
 

Balance, December 31, 2010

    —         —         —    

Purchases of oil and gas reserves in place

    495,159       2,007,328       829,714  

Sale of oil and gas reserves in place

    (110,151 )     (1,141,550 )     (300,409 )

Production

    (9,990 )     (38,477 )     (16,403 )
   

 

 

   

 

 

   

 

 

 

Balance, December 31, 2011

    375,018       827,301       512,902  
   

 

 

   

 

 

   

 

 

 

Proved reserves, December 31, 2011:

                       

Proved developed

    290,038       604,476       390,784  
   

 

 

   

 

 

   

 

 

 

Proved undeveloped

    84,980       222,825       122,118  
   

 

 

   

 

 

   

 

 

 

 

Standardized Measure

Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes such information is essential for a proper understanding and assessment of the data presented.

Future cash inflows are computed by applying the SEC-mandated 12 month arithmetic average of the first of month price for January through December 31, 2011, which resulted in benchmark prices of $96.19 per barrel for crude oil and $4.12 per MMbtu for natural gas. Prices were further adjusted for transportation, quality and basis differentials, which resulted in an average price used as of December 31, 2011 of $83.79 per barrel of oil and $5.84 per Mcf for natural gas.

The assumptions used to compute estimated future cash inflows do not necessarily reflect the Company’s expectations of actual revenues or costs, nor their present worth. In addition, variations from the expected production rate also could result directly or indirectly from factors outside of the Company’s control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.

Future development and production costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.

Future income tax expenses are computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the Company’s proved oil and gas reserves. Permanent differences in oil and gas related tax credits and allowances are recognized.

A 10% annual discount rate was used to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

The following table presents the standardized measure of discounted future net cash flows related to proved oil and gas reserves as of December 31, 2011:

 

         

Future cash inflows

  $ 36,256,572  

Future production costs

    (14,467,156 )

Future development costs

    (964,486 )

Future income taxes

    (4,623,201 )
   

 

 

 

Future net cash flows

    16,137,729  

10% annual discount

    (7,795,729 )
   

 

 

 

Standardized measure of discounted future net cash flows

  $ 8,342,000  
   

 

 

 

The present value (at a 10% annual discount) of future net cash flows from the Company’s proved reserves is not necessarily the same as the current market value of its estimated oil and gas reserves. The Company bases the estimated discounted future net cash flows from its proved reserves on average prices realized in the preceding year and on costs in effect at the end of the year. However, actual future net cash flows from the Company’s oil and gas properties will also be affected by factors such as actual prices the Company receives for oil and gas, the amount and timing of actual production, supply of and demand for oil and gas and changes in governmental regulations or taxation.

 

The timing of both the Company’s production and incurrence of expenses in connection with the development and production of oil and gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% annual discount factor the Company uses when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and gas industry in general.

A summary of changes in the standardized measure of discounted future net cash flows is as follows for the year ended December 31, 2011:

 

         

Standardized measure of discounted future net cash flows, beginning of year

  $ —    

Sales of oil and gas, net of production costs and taxes

    (440,596 )

Changes in estimated future development costs

    (918,376 )

Purchases of reserves in place

    15,846,975  

Sales of reserves in place

    (3,622,558 )

Net changes in future income taxes

    (2,523,445 )
   

 

 

 

Standardized measure of discounted future net cash flows, end of year

  $ 8,342,000