| Supplemental Oil and Gas Disclosures (Unaudited) | Note 11 – Supplemental Oil
and Gas Disclosures (Unaudited) Capitalized Costs Relating to
Oil and Gas Producing Activities The estimates of proved oil and gas
reserves utilized in the preparation of these statements were prepared by Ralph E. Davis, using reserve definitions and pricing
requirements prescribed by the SEC. The Company used a combination of production performance and offset analogies, along with estimated
future operating and development costs as provided by the Company and based upon historical costs adjusted for known future changes
in operations or developmental plans, to estimate our reserves. There are numerous uncertainties inherent
in estimating quantities of proved reserves, projecting future rates of production and projecting the timing of development expenditures,
including many factors beyond our control. The reserve data represents only estimates. Reservoir engineering is a subjective process
of estimating underground accumulations of natural gas and oil that cannot be measured in an exact manner. The accuracy of any
reserve estimate is a function of the quality of available data and of engineering and geological interpretations and judgment.
All estimates of proved reserves are determined according to the rules prescribed by the SEC. These rules indicate that the standard
of “reasonable certainty” be applied to the proved reserve estimates. This concept of reasonable certainty implies
that as more technical data becomes available, a positive, or upward, revision is more likely than a negative, or downward, revision.
Estimates are subject to revision based upon a number of factors, including reservoir performance, prices, economic conditions
and government restrictions. In addition, results of drilling, testing and production subsequent to the date of an estimate may
justify revision of that estimate. Reserve estimates are often different from the quantities of natural gas and oil that are ultimately
recovered. The meaningfulness of reserve estimates is highly dependent on the accuracy of the assumptions on which they were based.
In general, the volume of production from natural gas and oil properties we own declines as reserves are depleted. Except to the
extent we conduct successful development activities or acquire additional properties containing proved reserves, or both, our proved
reserves will decline as reserves are produced. There have been no major discoveries or other events, favorable or adverse, that
may be considered to have caused a significant change in the estimated proved reserves since February 28, 2017. The Company emphasizes
that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information
becomes available. In addition, a portion of the Company’s proved reserves are proved developed non-producing and proved
undeveloped, which increases the imprecision inherent in estimating reserves which may ultimately be produced. All of the Company’s reserves
are located in the United States.
February 28, 2017 February 29, 2016
Proved oil and gas properties $ 955,316 $ 1,005,392
Unproved oil and gas properties - -
Accumulated depreciation, depletion and amortization (56,340 ) (34,279 )
Total acquisition, development and exploration costs $ 898,976 $ 971,113 Costs Incurred in Oil and Gas
Property Acquisition, Exploration, and Development Activities At February 28, 2017 and February 29,
2016, unevaluated costs of $0 were excluded from the depletion base.
February 28, 2017 February 29, 2016
Acquisition of properties – proved $ 381,067 $ 381,067
Acquisition of properties – unproved - -
Exploration costs 88,000 88,000
Development costs 536,325 536,325
Disposition/sale 50,076 -
Total costs incurred $ 955,316 $ 1,005,392 Estimated Quantities of Proved
Oil and Gas Reserves The following table sets forth proved
oil and gas reserves together with the changes therein, proved developed reserves and proved undeveloped reserves for the years
ended February 28, 2017 and February 29, 2016. Units of oil are in thousands of barrels (MBbls) and units of gas are in millions
of cubic feet (MMcf). Gas is converted to barrels of oil equivalents (MBoe) using a ratio of six Mcf of gas per Bbl of oil.
2017 2016
Oil Gas BOE Oil Gas BOE
Proved reserves:
Beginning of year 142 115 161 - - -
Revisions - - - - - -
Extensions and discoveries - - - - - -
Purchases of minerals-in-place 137 103 155 146 128 167
Sales of minerals-in-place - - - - - -
Production (2 ) (11 ) (4 ) (4 ) (13 ) (6 )
End of year 277 207 312 142 115 161
Proved developed reserves:
Beginning of year 12 38 18 - - -
End of year 12 38 18 12 38 18
Proved behind pipe reserves:
Beginning of year 54 14 57 - - -
End of year 54 14 57 54 14 57
Proved undeveloped reserves:
Beginning of year 76 63 86 - - -
End of year 76 63 86 76 63 86 Standardized Measure of Discounted
Future Net Cash Flows and Changes Therein Relating to Proved Reserves The standardized measure of discounted
future net cash flows, in management’s opinion, should be examined with caution. The basis for this table is the reserve
studies prepared by the Company’s independent petroleum engineering consultants, which contain imprecise estimates of quantities
and rates of future production of reserves. Revisions of previous year estimates can have a significant impact on these results.
Also, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates
of proved reserves and their valuation. Therefore, the standardized measure of discounted future net cash flow is not necessarily
indicative of the fair value of the Company’s proved oil and natural gas properties. Future cash inflows for 2017 were computed
by applying the average price for the year to the year-end quantities of proved reserves. The 2017 average price for the year was
calculated using the 12-month period prior to the ending date of the period covered by the report, determined as an un-weighted
arithmetic average of the first-day-of-the-month price for each month within such period. Adjustment in this calculation for future
price changes is limited to those required by contractual arrangements in existence at the end of each reporting year. Future development,
abandonment and production costs were computed by estimating the expenditures to be incurred in developing and producing proved
oil and natural gas reserves at the end of the year, based on year-end costs, assuming continuation of year-end economic conditions.
Future income tax expense was computed by applying statutory rates, less the effects of tax credits for each period presented,
and to the difference between pre-tax net cash flows relating to the Company’s proved reserves and the tax basis of proved
properties, after consideration of available net operating loss and percentage depletion carryovers. Discounted future net cash
flows have been calculated using a ten percent discount factor. Discounting requires a year-by-year estimate of when future expenditures
will be incurred and when reserves will be produced. The estimated present value of future
cash flows relating to prove reserves is extremely sensitive to prices used at any measurement period. The prices used for each
commodity for the years ended February 28, 2017 and February 29, 2016 as adjusted, were as follows:
Oil (Bbl) Using NYMEX WTI Gas (Mcf) Using NYMEX Henry Hub
2017 (average price) $ 43.05 $ 1.55
2016 (average price) $ 47.31 $ 2.63 The information provided in the tables
set out below does not represent management’s estimate of the Company’s expected future cash flows or of the value
of the Company’s proved oil and gas reserves. Estimates of proved reserve quantities are imprecise and change over time as
new information becomes available. Moreover, probable and possible reserves, which may become proved in the future, are excluded
from the calculations. The arbitrary valuation prescribed under ASC No. 932 requires assumptions as to the timing and amount of
future development and production costs. The calculations should not be relied upon as an indication of the Company’s future
cash flows or of the value of its oil and gas reserves. The following table sets forth the standardized
measure of discounted future net cash flows relating to proven reserves for the years ended February 28, 2017 and February 29,
2016 respectively (stated in thousands):
2017 2016
Future cash inflows $ 6,114 $ 6102
Future costs:
Production costs (718 ) (794 )
Future tax expense (286 ) (294 )
Future development costs (1,093 ) (1,112 )
Future net cash flows 4,017 3,901
10% annual discount for estimated timing of cash flows (1,473 ) (1,533 )
Standardized measure of discounted net cash flows $ 2,544 $ 2,369 Summary of Changes in Standardized
Measure of Discounted Future Net Cash Flows The following table summarizes the principal
sources of change in the standardized measure of discounted future estimated net cash flows at 10% per annum for the years ended
February 28, 2017 and February 29, 2016, respectively (stated in thousands):
2017 2016
Increase (decrease):
Beginning of year $ - $ -
Sales of oil produced, net of production costs 77 406
Net changes in sales and transfer prices and in production costs and production costs related to future production - -
Previously estimated development costs incurred during the period - -
Changes in future development costs - -
Revisions of previous quantity estimates due to prices and performance - -
Accretion of discount - -
Discoveries, net of future production and development costs associated with these extensions and discoveries - -
Purchases and sales of minerals in place 2,467 1,963
Timing and other - -
End of year |
