NOTE 12. SUPPLEMENTAL INFORMATION RELATING TO OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development. Amounts reported as costs incurred include both capitalized costs and costs charged to expense during the year for oil and gas property acquisition, exploration and development activities. Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to cost estimates during the year. Exploration costs presented below include the costs of drilling and equipping successful exploration wells, as well as dry hole costs, leasehold impairments, geological and geophysical expenses, and the costs of retaining undeveloped leaseholds. Development costs include the costs of drilling and equipping development wells, and construction of related production facilities.

In 2014, the Company has incurred in a capital cost of $675,426 on Noack’s lease, drilling seven (7) wells and reworking an existing well.

In 2015, the Company incurred a capital costs related to non-production related repairs of $65,450 on the Noack’s lease. In addition, they purchased ownership interests in the SUDS and TLSAU fields.

Capitalized costs. Capitalized costs include the cost of properties, equipment and facilities for oil and natural-gas producing activities. Capitalized costs for proved properties include costs for oil and natural-gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and gas leaseholds and geological and geophysical expenses where no proved reserves have been identified.

Oil and Gas Reserve Information. MKM Engineering, an independent engineering firm, prepared the estimates of the proved reserves, future production, and income attributable to the leasehold interests as of December 31, 2015 and 2014. The estimated proved net recoverable reserves presented below include only those quantities that were expected to be commercially recoverable at prices and costs in effect at the balance sheet dates under the then existing regulatory practices and with conventional equipment and operating methods. Proved Developed Reserves represent only those reserves estimated to be recovered through existing wells. Proved Undeveloped Reserves include those reserves that may be recovered from new wells on undrilled acreage or from existing wells on which a relatively major expenditure for recompletion or secondary recovery operations is required. All of the Company’s Proved Reserves are located onshore in the continental United States of America.

Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and gas properties. Estimates of fair value should also consider unproved reserves, anticipated future oil and gas prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is subjective and imprecise.

The following table sets forth estimates of the proved oil and gas reserves (net of royalty interests) for the Company and changes therein, for the periods indicated.

The net increase –after production of 5,663 bbls– of “Total Proved Reserves” in the amount of 438,283 bbls from December 31, 2014 to December 31, 2015 was primarily because the Company acquired reserves in TSLAU and SUDS fields. This was offset by a reduction in reserve estimates in the Noack field by 65,450 barrels of oil. This resulted in an overall increase of 438,283 barrels of oil of “net proved reserves”. 

The following table sets forth estimates of the proved developed and proved undeveloped oil and gas reserves (net of royalty interests) for the Company and changes therein, for the period indicates.

The increases in Proved Undeveloped (PUD) reserves were all due to the SUDS and TLSAU acquisitions.

Standardized Measure of Discounted Future Net Cash Flows. The Standardized Measure related to proved oil and gas reserves is summarized below. Future cash inflows were computed by applying a twelve month average of the first day of the month prices to estimated future production, less estimated future expenditures (based on year end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expense. Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows, less the tax basis of properties involved. Future net cash flows are discounted at a rate of 10% annually to derive the standardized measure of discounted future net cash flows. This calculation procedure does not necessarily result in an estimate of the fair market value or the present value of the Company.

Standardized Measure of Oil and Gas

The following table sets forth the changes in standardized measure of discounted future net cash flows relating to proved oil and gas reserves for the periods indicated.