Annual report pursuant to Section 13 and 15(d)

Supplemental Oil and Gas Reserve Information (Unaudited)

Supplemental Oil and Gas Reserve Information (Unaudited)
12 Months Ended
Dec. 31, 2017
Extractive Industries [Abstract]  
Supplemental Oil and Gas Reserve Information (Unaudited)

Note 14 - Supplemental Oil and Gas Reserve Information (Unaudited) 


The Company’s oil and gas properties and proved reserves are located in the United States.


Results of operations from oil and gas producing activities


The results of operations from the Company’s oil and gas producing activities for the years ended December 31, 2017 and 2016 are summarized below:


    December 31,  
    2017     2016  
Net revenues from production:                
Sales of oil and gas production to third parties   $ 155,161     $  
Production costs:                
Oil and gas lease operating expense     (252,753 )      
Depletion, depreciation, amortization, accretion, and impairment expense     (1,525,784 )      
Income tax expense              
Results of operations   $ (1,623,376 )   $  


Results of operations for producing activities comprise all activities associated with our exploration for and production of oil and gas. Net revenues from production include only the revenues from the production and sale of oil, natural gas, natural gas liquids, and residue gas. Production costs are those incurred to operate and maintain wells and related equipment and facilities used in oil and gas operations. Income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion, and amortization allowances, after giving effect to permanent differences. The results of operations exclude general office overhead, and interest expense attributable to oil and gas activities.


Capitalized costs


Capitalized costs and accumulated depletion, depreciation, and amortization relating to the Company’s oil and gas producing activities as of December 31, 2017 and 2016 are summarized below:


    2017     2016  
Unproved properties not being amortized   $ 2,509,274     $ 1,181,421  
Proved properties subject to amortization   $ 10,762,380       10,352,014  
Accumulated depreciation, depletion, and amortization   $ (18,016 )        
Net capitalized costs   $ 13,253,638     $ 11,533,435  


Costs incurred in oil and gas property acquisition, exploration, and development activities


The following table summarizes the Company’s costs incurred in property acquisition, exploration and development activities for the year ended December 31, 2017:


Proved acreage   $ 18,653  
Producing assets     580,158  
Incomplete construction     1,501,369  
Exploration costs     (148,533 )
Development costs      
Net capitalized costs   $ 1,951,647  


Estimated quantities of proved reserves


The supplemental unaudited presentation of proved reserve quantities and related standardized measure of discounted future net cash flows provides estimates only and does not purport to reflect realizable values or fair market values of the Company’s reserves. The Company emphasizes that reserves estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and gas properties. Accordingly, significant changes to these estimates can be expected as future information becomes available. All of the Company’s reserves are located in the United States.


Proved reserves are those estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment, and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Proved undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure is required to rend them capable of production.


The standardized measure of discounted future net cash flows is computed by applying the average first day of the month price of oil and gas during the 12 month period before the end of the year (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and gas reserves, less the estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already legislated) to be incurred on pretax net cash flows less tax basis of the properties and available credits, and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10 percent per year to reflect the estimated timing of the future cash flows.


The reserves estimates set forth below were prepared by a third party engineering firm using reserves definitions and pricing requirements prescribed by the SEC. Chapman Petroleum Engineering Ltd. (“Chapman”) prepared our reserves report at January 1, 2018. Chapman is an independent consultant, does not own any interest in the Company’s properties, and is not engaged contingent upon the value of the Company’s properties. Chapman prepared reserves estimates under a discounted cash flow analysis of estimated future net revenue, applying knowledge of concepts including uncertainty and risk, probability and statistics, and deterministic and probabilistic estimation methods in properly using and applying reserves definitions. The data utilized were furnished to Chapman by the Company or obtained from public data sources. Chapman is a professional engineering firm specializing in the technical and financial evaluation of oil and gas assets.


Estimated quantities of oil and natural gas reserves 


The following table sets forth certain data pertaining to changes in reserves quantities of the proved, proved developed, and proved undeveloped reserves for the years ended December 31, 2017 and 2016.


    December 31,  
    Crude Oil     Natural Gas     Crude Oil     Natural Gas  
    (MSTB)     (MCF)     (MSTB)     (MCF)  
    2017     2017     2016     2016  
TOTAL PROVED RESERVES                                
Beginning of year     1,622       811              
Purchases of minerals in place                 1,622       811  
Sales of minerals in place                        
Extensions and discoveries     4,174       8,353              
Revisions of previous estimates     (1,620     (811            
Production     (2 )                  
End of period     4,174       8,353       1,622       811  
PROVED DEVELOPED RESERVES                                
Proved developed producing                        
Proved developed nonproducing                 193       97  
End of period     4,174       8,353       1,622       811  
Total proved undeveloped     4,174       8,353       1,429       714  


Standardized measure of discounted future net cash flows


As required by the Financial Accounting Standards Board, the standardized measure of discounted future net cash flows is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to net proved reserves. The standardized measure includes costs for future dismantlement, abandonment, and rehabilitation obligations. The Company believes the standardized measure does not provide a reliable estimate of the Company’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions, which represent discrete points in time and may cause significant variability in cash flows from year to year as prices change.


Net cash flows at December 31,   2017     2016  
Future cash inflows   $ 268,949,000     $ 74,093,600  
Future production costs     (103,926,000 )     (17,313,400 )
Future development costs     (48,000,000 )     (19,750,000 )
Future income tax expense     (23,275,919 )     (12,590,268 )
Future net cash flows     93,747,081       24,439,932  
10% annual discount for estimated timing of cash flow     (68,046,395 )     (14,908,800 )
Standard measure of discounted future net cash flows related to proved reserves   $ 25,700,686     $ 9,531,132  


Changes in standardized measure of discounted future net cash flows


The principal sources of changes in the standardized measure of the future net cash flows for the years ended December 31, 2017 and 2016 are:


Balance, beginning of period   $ 9,531,132  
Sales and transfers of oil and gas produced during the period     97,592  
Sales of minerals in place      
Purchases of minerals in place      
Net change in sales price, net of production costs     (4,564,023 )
Net changes due to extensions and discoveries     50,755,047  
Changes in estimated future development costs     (25,709,147 )
Previously estimated development costs incurred during the period      
Net change due to revisions in quantity estimates     (16,007,121 )
Other     11,284,522  
Accretion of discount     3,599,200  
Net change in income tax     (3,286,516 )
Balance, end of period   $ 25,700,686