| Oil and Gas Reserve Data (Unaudited) | 15. Oil and Gas Reserve Data (Unaudited) The estimates of the Company’s proved
oil and gas reserves, which are located entirely within the United States, were prepared in accordance with the generally accepted
petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. The estimates as of March
31, 2019 and 2018 were based on evaluations prepared by Russell K. Hall and Associates, Inc. The services provided by Russell K.
Hall and Associates, Inc. are not audits of our reserves but instead consist of complete engineering evaluations of the respective
properties. For more information about their evaluations performed, refer to the copy of their report filed as an exhibit to this
Annual Report on Form 10-K. Management emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries
are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected
to change as additional information becomes available in the future. The following table summarizes the prices utilized
in the reserve estimates for 2019 and 2018. Commodity prices utilized for the reserve estimates prior to adjustments for location,
grade and quality are as follows:
March 31,
2019 2018
Prices utilized in the reserve estimates before adjustments:
Oil per Bbl $ 59.52 $ 49.94
Natural gas per MMBtu $ 3.07 $ 3.00 The Company’s total estimated proved
reserves at March 31, 2019 were approximately 1.937 MBOE of which 54% was oil and natural gas liquids and 46% was natural gas. Changes in Proved Reserves
Oil Natural Gas
Proved Developed and Undeveloped Reserves:
As of April 1, 2017 2,124,000 6,681,000
Revision of previous estimates (850,000 ) (915,000 )
Purchase of minerals in place - -
Extensions and discoveries 110,000 191,000
Sales of minerals in place (152,000 ) (151,000 )
Production (35,000 ) (319,000 )
As of March 31, 2018 1,197,000 5,487,000
Revision of previous estimates (293,000 ) (430,000 )
Purchase of minerals in place - -
Extensions and discoveries 171,000 619,000
Sales of minerals in place - -
Production (35,000 ) (295,000 )
As of March 31, 2019 1,040,000 5,381,000 Proved developed reserves are those expected
to be recovered through existing wells, equipment and operating methods. Proved undeveloped reserves (“PUD”) are proved
reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major
expenditure is required for recompletion within a five years of the date of their initial recognition. Moreover, the Company may
be required to write down its proved undeveloped reserves if the operators do not drill on the reserves within the required five-year
timeframe. The downward revision of oil and natural gas is primarily the result of restructuring the plans for development of an
operated property in Ector County, Texas due to market conditions partially offset by pricing and successful development in the
Delaware and Midland Basins. Reserves written off due to the five year limitation are primarily in the Bakken Field in Billings
County, North Dakota which are on a lease held by production and are still in place to be developed in the future. Summary of Proved Developed and Undeveloped
Reserves as of March 31, 2019 and 2018
Oil Natural Gas
Proved Developed Reserves:
As of April 1, 2017 399,880 4,107,950
As of March 31, 2018 390,740 4,103,390
As of March 31, 2019 376,600 3,823,440
Proved Undeveloped Reserves:
As of April 1, 2017 1,724,420 2,572,960
As of March 31, 2018 805,980 1,383,120
As of March 31, 2019 663,860 1,557,250 At March 31, 2019, the Company reported estimated
PUDs of 923 MBOE, which accounted for 48% of its total estimated proved oil and gas reserves. This figure primarily consists of
a projected 152 new wells (679 MBOE) operated by others, 13 wells are currently being drilled with plans for 79 wells to follow
in 2020, 46 wells in 2021 and 14 wells in 2022. The cost of these projects would be funded, to the extent possible, from existing
cash balances, cash flow from operations and bank borrowings. The remainder may be funded through non-core asset sales and/or sales
of our common stock. The following table discloses the Company’s
progress toward the conversion of PUDs during fiscal 2019. The following table discloses the Company’s
progress toward the conversion of PUDs during fiscal 2019. Progress of Converting Proved Undeveloped
Reserves
Oil & Natural Gas Future
(BOE) Development Costs
PUDs, beginning of year 1,036,503 $ 12,009,331
Revision of previous estimates (306,406 ) (3,246,620 )
Sales of reserves - -
Conversions to PD reserves (63,808 ) (828,262 )
Additional PUDs added 257,116 1,203,111
PUDs, end of year 923,405 $ 9,137,560 Estimated future net cash flows represent an
estimate of future net revenues from the production of proved reserves using average prices for 2019 and 2018 along with estimates
of the operating costs, production taxes and future development costs necessary to produce such reserves. No deduction has been
made for depreciation, depletion or any indirect costs such as general corporate overhead or interest expense. Operating costs and production taxes are estimated
based on current costs with respect to producing oil and natural gas properties. Future development costs including abandonment
costs are based on the best estimate of such costs assuming current economic and operating conditions. The future cash flows estimated
to be spent to develop the Company’s share of proved undeveloped properties through March 31, 2024 are $9,137,560. Income tax expense is computed based on applying
the appropriate statutory tax rate to the excess of future cash inflows less future production and development costs over the current
tax basis of the properties involved, less applicable carryforwards. The future net revenue information assumes
no escalation of costs or prices, except for oil and natural gas sales made under terms of contracts which include fixed and determinable
escalation. Future costs and prices could significantly vary from current amounts and, accordingly, revisions in the future could
be significant. The current reporting rules require that year
end reserve calculations and future cash inflows be based on the 12-month average market prices for sales of oil and gas on the
first calendar day of each month during the fiscal year discounted at 10% per year and assuming continuation of existing economic
conditions. The average prices used for fiscal 2019 were $53.71 per bbl of oil and $2.77 per mcf of natural gas. The average prices
used for fiscal 2018 were $50.63 per bbl of oil and $3.03 per mcf of natural gas. The standardized measure of discounted future
net cash flows is computed by applying the 12-month unweighted average of the first day of the month pricing for oil and natural
gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production
of proved oil and natural gas reserves, less estimated future expenditures (based on year end costs) to be incurred in developing
and producing the proved reserves, discounted using a rate of 10% per year to reflect the estimated timing of the future cash flows.
Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and natural gas properties
plus available carryforwards and credits and applying the current tax rate to the difference. The basis for this table is the reserve studies
prepared by an independent petroleum engineering consultant, which contain imprecise estimates of quantities and rates of 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 proved oil and gas properties. The following information is based on the Company’s
best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of March 31, 2019 and 2018
in accordance with ASC 932, “Extractive Activities – Oil and Gas” which requires the use of a 10% discount rate.
This information is not the fair market value, nor does it represent the expected present value of future cash flows of the Company’s
proved oil and gas reserves. Standardized Measure of Discounted Future
Net Cash Flows Relating to Proved Reserves:
March 31
2019 2018
Future cash inflows $ 70,766,000 $ 77,221,000
Future production costs and taxes (19,355,000 ) (20,080,000 )
Future development costs (9,424,000 ) (12,009,000 )
Future income taxes (5,767,000 ) (6,413,000 )
Future net cash flows 36,220,000 38,719,000
Annual 10% discount for estimated timing of cash flows (16,968,000 ) (19,843,000 )
Standardized measure of discounted future net cash flows $ 19,252,000 $ 18,876,000 Changes in Standardized Measure of Discounted
Future Net Cash Flows Relating to Proved Oil and Gas Reserves:
March 31
2019 2018
Sales of oil and gas produced, net of production costs $ (1,711,000 ) $ (1,580,000 )
Net changes in price and production costs 36,000 6,967,000
Changes in previously estimated development costs 1,923,000 16,196,000
Revisions of quantity estimates (6,901,000 ) (23,969,000 )
Net change due to purchases and sales of minerals in place - (1,744,000 )
Extensions and discoveries, less related costs 4,333,000 1,240,000
Net change in income taxes 61,000 3,057,000
Accretion of discount 2,200,000 2,527,000
Changes in timing of estimated cash flows and other 435,000 (2,901,000 )
Changes in standardized measure 376,000 (207,000 )
Standardized measure, beginning of year 18,876,000 19,083,000
Standardized measure, end of year $ 19,252,000 $ 18,876,000 |
