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UNAUDITED SUPPLEMENTARY INFORMATION
12 Months Ended
Dec. 31, 2014
Unaudited Supplementary Information  
Unaudited supplementary information

December 31, 2014 and 2013

 

Investment in oil and gas properties for 2014 is detailed as follows:

 

    2014     2013  
Property acquisition costs   $ 7,222,793     $ 6,274,154  
Development costs     11,368,536       3,885,730  
Exploratory costs   $ -0-     $ -0-  

 

Oil and Natural Gas Reserves

 

Reserve Estimates

 

SEC Case. The following tables sets forth, as of December 31, 2014, our estimated net proved oil and natural gas reserves, the estimated present value (discounted at an annual rate of 10%) of estimated future net revenues before future income taxes (PV-10) and after future income taxes (Standardized Measure) of our proved reserves and our estimated net probable oil and natural gas reserves, each prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with assumptions prescribed by the Securities and Exchange Commission (“SEC”).  All of our reserves are located in the United States.

 

The PV-10 value is a widely used measure of value of oil and natural gas assets and represents a pre-tax present value of estimated cash flows discounted at ten percent. PV-10 is considered a non-GAAP financial measure as defined by the SEC. We believe that our PV-10 presentation is relevant and useful to our investors because it presents the estimated discounted future net cash flows attributable to our proved reserves before taking into account the related future income taxes, as such taxes may differ among various companies.  We believe investors and creditors use PV-10 as a basis for comparison of the relative size and value of our proved reserves to the reserve estimates of other companies. PV-10 is not a measure of financial or operating performance under GAAP and neither it nor the Standardized Measure is intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.

 

Our PV-10 at December 31, 2014 and 2013 is materially reconciled to our Standardized Measure of discounted cash flows at those dates by reducing the PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at December 31, 2014 and 2013, respectively, were $678,904 and $7,093,985.

 

The estimates of our proved reserves and the PV-10 set forth herein reflect estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions at December 31, 2014. For purposes of determining prices, we used the average of prices received for each month within the 12-month period ended December 31, 2014, adjusted for quality and location differences, which was $91.48 per barrel of oil and $4.35 per MCF of gas.  This average historical price is not a prediction of future prices. The amounts shown do not give effect to non-property related expenses, such as corporate general administrative expenses and debt service, future income taxes or to depreciation, depletion and amortization.

 

    December 31, 2014     December 31, 2014  
    Reserves     Future Net Revenue (M$)  
                            Present Value Discounted  
Category   Oil (Bbls)     Gas (Mcf)     Total (BOE)     Total     at 10%  
                               
Proved Developed     120,000       687,000       234,500     $ 9,909     $ 7,670  
Proved Undeveloped     794,400       3,104,000       1,311,733     $ 32,585     $ 16,026  
Total Proved     914,400       3,791,000       1,546,233       42,494       23,696  
                                         
Standardized Measure of Future Net Cash Flows Related to Proved Oil and Gas Properties     $ 23,019  
Probable Undeveloped     912.400       0       912,400     $ 22,779     $ 8,558  

 

    December 31, 2013     December 31, 2013  
    Reserves     Future Net Revenue (M$)  
                            Present Value Discounted  
Category   Oil (Bbls)     Gas (Mcf)     Total (BOE)     Total     at 10%  
                               
Proved Developed     113,092       313,251       165,301     $ 8,861     $ 6,117  
Proved Undeveloped     930,069       2,826,344       1,401,126     $ 44,699     $ 20,408  
Total Proved     1,043,161       3,139,595       1,566,427     $ 53,560     $ 26,525  
                                         
Standardized Measure of Future Net Cash Flows Related to Proved Oil and Gas Properties   $ 19,691  
                                         
Probable Undeveloped     657,800       0       657,800     $ 33,571     $ 16,253  

 

BOE equivalents are determined by combining barrels of oil with MCF of gas divided by six.

 

The decrease of 89,393 BOE (89,285 for our Hunton Project and 108 for our Marcelina Project) in proved undeveloped reserves comes from the third party engineering studies of the Cimarron and Chisholm Trail AMI's in Oklahoma which were acquired by the Company in 2013 and engineering studies for our Marcelina Project.  

 

No reserve value for the Ring Project is included in 2014 reserve tables presented above since the company believes this project is still considered to be in the testing phase.

  

Standardized Measure of Oil & Gas Quantities - Volume Rollforward  
Years Ended December 31, 2014 and 2013  
                         
The following table sets forth the Company’s net proved reserves, including the changes therein, and proved developed reserves:  
                         
    2014     2013  
    Oil (Bbls)     Gas (Mcf)     Oil (Bbls)     Gas (Mcf)  
TOTAL PROVED RESERVES:                        
Beginning of period     1,043,161       3,139,594       417,549       -  
Acquisition     -       -       572,461       3,139,595  
Extensions and discoveries     312,579       -       101,180       -  
Revisions of previous estimates     (388,485 )     821,150       (34,743 )     3,539  
Production     (52,855 )     (170,094 )     (13,286 )     (3,540 )
End of period     914,400       3,790,650       1,043,161       3,139,594  
                                 
                                 
PROVED DEVELOPED RESERVES                                
Proved developed producing     102,479       488,410       64,858       108,001  
Proved developed nonproducing     17,521       198,710       48,234       205,250  
Total     120,000       687,120       113,092       313,251  
                                 
Total PUD     794,400       3,103,530       930,069       2,826,344  

 

The preceding table shows significant decrease in the Acquisition category for 2014 as compared to 2013. The 2013 Acquisition increase is all related to the working interest acquired in the Cimarron and the Chisholm Trail AMI's with Husky Ventures in Oklahoma during 2013. During 2014 the company focused on expanding its participation in the Chisholm Trail and Cimarron AMI’S in Oklahoma which accounts for the increase in Extensions and Discoveries for 2014.

 

The 2013 Revisions of Previous Estimates are composed of revisions to the proved producing and proved undeveloped reserves.

 

The downward revision of 388,485 BO results primarily from eliminating two Eagle Ford wells (which are now considered uneconomic at current prices) from reserve report calculations for the Company’s properties in the Marcelina Creek Project in Texas. This reflects a reduction of 366,366 BO offset directly by an increase in reserves of 60,159 BO from the currently producing wells. The Johnson #1 is the largest contributor, with an increase of reserves of 56,783 BO. The Johnson #2 and #4 account for an additional increase of 3,376 BO. The remaining difference comes from reserve adjustments in the well data for the Oklahoma Properties reserve calculations for 2014.

 

The positive revision of 821,150 MCF of gas is attributable to gas production increase from the development activity in the Chisholm Trail and Cimarron AMI’s in Oklahoma where the Company focused on expanding its participation in 2014 drilling and development. Gas reserves can be fully attributable to our Oklahoma joint venture operations.  Most of our wells in the program are horizontally drilled wells that produce from the Hunton rock which requires a fracking stimulation to achieve the maximum production rates.  Typically these wells have a relatively high initial production rates, but decline rapidly.  Three wells in our Oklahoma ventures contribute 244.8 MMcf of the total improvement.  As a result of the PDP wells success the offsetting PUD wells are expected to be significant contributors as well.  Our other producing wells in Oklahoma are evenly spread.

 

Standardized Measure of Oil & Gas Quantities  
Year Ended December 31, 2014 & 2013  
             
The standardized measure of discounted future net cash flows relating            
to proved oil and natural gas reserves is as follows :   2014     2013  
             
Future cash inflows   $ 106,027,440     $ 119,629,906  
Future production costs     (30,383,390 )     (31,656,853 )
Future development costs     (33,148,780 )     (34,152,898 )
Future income tax expense     (978,776 )     (11,264,101 )
Future net cash flows     41,516,494       42,556,054  
10% annual discount for estimated                
timing of cash flows     (18,497,528 )     (22,865,456 )
Standardized measure of discounted future                
net cash flows related to proved reserves   $ 23,018,966     $ 19,690,598  
                 
                 
A summary of the changes in the standardized measure of discounted                
future net cash flows applicable to proved oil and natural gas reserves                
is as follows :                
                 
Balance, beginning of year   $ 19,690,598     $ 2,909,000  
Sales and transfers of oil and gas produced during the period     (4,310,813 )     (905,125 )
Net change in sales and transfer prices and in production (lifting) costs related to future production     (9,497,301 )     (1,647,568 )
Net change due to purchases of minerals in place     -       30,474,988  
Net change due to extensions and discoveries     14,340,815       22,411,372  
Changes in estimated future development costs     (13,990,412 )     (17,355,723 )
Previously estimated development costs incurred during the period     15,980,816       (3,181,356 )
Net change due to revisions in quantity estimates     (12,814,002 )     (4,633,853 )
Other     2,487,713       (1,468,500 )
Accretion of discount     4,715,661       (318,085 )
Net change in income taxes     6,415,891       (6,594,552 )
Balance, end of year   $ 23,018,966     $ 19,690,598  

 

Due to the inherent uncertainties and the limited nature of reservoir data, both proved and probable reserves are subject to change as additional information becomes available. The estimates of reserves, future cash flows, and present value are based on various assumptions, including those prescribed by the SEC, and are inherently imprecise. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses, and quantities of recoverable oil and natural gas reserves may vary substantially from these estimates.

 

In estimating probable reserves, it should be noted that those reserve estimates inherently involve greater risk and uncertainty than estimates of proved reserves. While analysis of geoscience and engineering data provides reasonable certainty that proved reserves can be economically producible from known formations under existing conditions and within a reasonable time, probable reserves involve less certainty than reserves with a higher classification due to less data to support their ultimate recovery. Probable reserves have not been discounted for the additional risk associated with future recovery.  Prospective investors should be aware that as the categories of reserves decrease with certainty, the risk of recovering reserves at the PV-10 calculation increases.  The reserves and net present worth discounted at 10% relating to the different categories of proved and probable have not been adjusted for risk due to their uncertainty of recovery and thus are not comparable and should not be summed into total amounts.

  

Reserve Estimation Process, Controls and Technologies

 

The reserve estimates, including PV-10 estimates, set forth above were prepared by Netherland, Sewell & Associates, Inc. with respect to the Company’s Marcelina Creek Project in Texas, and PeTech Enterprises, Inc. for the Company’s properties in Oklahoma.  A copy of their full reports with regard to our reserves is attached as Exhibit 99.1 to this annual report on Form 10-K.  These calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC financial accounting and reporting standards.

 

Our Chairman of our Board of Directors is an experienced and qualified geoscience professional with a degree in geophysical science, but we do not have any employees with specific reservoir engineering qualifications in the company.  Our Chairman and Chief Executive Officer worked closely with Netherland, Sewell & Associates, Inc. and PeTech Enterprises Inc. in connection with their preparation of our reserve estimates, including assessing the integrity, accuracy, and timeliness of the methods and assumptions used in this process.

 

The reserves estimates for the Marcelina Creek Project included herein have been independently evaluated by Netherland, Sewell & Associates, Inc. (NSAI), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies.  NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699.  Within NSAI, the technical person primarily responsible for preparing the estimates set forth in the NSAI reserves report incorporated herein is Mr. Neil H. Little.  Mr. Little, a Licensed Professional Engineer in the State of Texas (No. 117966), has been practicing consulting petroleum engineering at NSAI since 2011 and has over 9 years of prior industry experience.  He graduated from Rice University in 2002 with a Bachelor of Science Degree in Chemical Engineering and from the University of Houston in 2007 with a Master of Business Administration Degree.   Mr. Little meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; Mr. Little is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

 

PeTech Enterprises, Inc. (“PeTech”), who provided reserve estimates for our Oklahoma Properties, is a Texas based profitable, family owned oil and gas production and Investment Company that provides reservoir engineering, economics and valuation support to energy banks, energy companies and law firms as an expert witness.  The company has been in business since 1982.  Amiel David is the President of PeTech and the primary technical person in charge of the estimates of reserves and associated cash flow and economics on behalf of the company for the results presented in its reserves report to us.  He has a PhD in Petroleum Engineering from Stanford University.   He is a registered Professional Engineer in the state of Texas (PE #50970), granted in 1982, a member of the Society of Petroleum Engineers and a member of the Society of Petroleum Evaluation Engineers.

 

Results of Operations for Oil and Gas Producing Activities                        
For the Year Ended December 31, 2014   Total     Texas     Oklahoma     Kansas  
                         
                         
Oil and Gas revenue   $ 5,455,555     $ 1,136,373     $ 3,997,379     $ 321,803  
                                 
                                 
Production costs     1,253,090       516,451       634,739       101,900  
Depreciation, depletion, and amortization     2,736,562       709,533       1,995,531       31,498  
Exploration expenses     -       -       -       -  
      3,989,652       1,225,984       2,630,270       133,398  
                                 
Income tax expense     -       -       -       -  
                                 
                                 
Results of Operations (excluding corporate overhead                                
           and interest costs)   $ 1,465,903     $ (89,611 )   $ 1,367,109     $ 188,405