Oil and Gas Reserve Data (Unaudited)

12 Months Ended

Mar. 31, 2018

Extractive Industries [Abstract]

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, 2018 were based on evaluations prepared by Russell K. Hall and Associates, Inc. The estimates as of March 31, 2017 were based on evaluations prepared by Joe C. Neal and Associates, Petroleum and Environmental Engineering Consultants. 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 2018 and 2017. Commodity prices utilized for the reserve estimates prior to adjustments for location, grade and quality are as follows:

	March 31,
	2018		2017
Prices utilized in the reserve estimates before adjustments:
Oil per Bbl	$	49.94	$	44.10
Natural gas per MMBtu	$	3.00	$	2.74

The Company’s total estimated proved reserves at March 31, 2018 were approximately 2.111 MBOE of which 57% was oil and natural gas liquids and 43% was natural gas.

Changes in Proved Reserves:

	Oil (Bbls)			Natural Gas (Mcf)
Proved Developed and Undeveloped Reserves:
As of April 1, 2016		1,084,000			5,801,000
Revision of previous estimates		205,000			946,000
Purchase of minerals in place		-			-
Extensions and discoveries		962,000			1,380,000
Sales of minerals in place		(92,000	)		(1,090,000	)
Production		(35,000	)		(356,000	)
As of March 31, 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

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 a non-producing leasehold interest in Martin County, Texas located in the Eastern Permian Basin 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 Newark East field in Denton County, Texas 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, 2018 and 2017:

	Oil (Bbls)		Natural Gas (Mcf)
Proved Developed Reserves:
As of April 1, 2016		350,180		4,406,060
As of March 31, 2017		399,880		4,107,950
As of March 31, 2018		390,740		4,103,390
Proved Undeveloped Reserves:
As of April 1, 2016		734,170		1,395,220
As of March 31, 2017		1,724,420		2,572,960
As of March 31, 2018		805,980		1,383,120

At March 31, 2018, the Company reported estimated PUDs of 1,037 MBOE, which accounted for 49% of its total estimated proved oil and gas reserves. This figure primarily consists of a projected 102 new wells (937 MBOE), 4 of which the Company operates with reserves of 205 MBOE, which will be drilled on existing acreage in the Goldsmith field where the Company currently operates 3 wells. The Company projects these 4 operated wells will be drilled in fiscal 2019.

Regarding the remaining 98 PUD locations operated by others (732 MBOE), 7 wells are currently being drilled with plans for 38 wells to follow in 2019, 33 wells in 2020 and 24 wells in 2021. The cost of these projects would be funded, to the extent possible, from existing cash balances and cash flow from operations. 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 2018.

Progress of Converting Proved Undeveloped Reserves:

	Oil & Natural Gas			Future
	(BOE)			Development Costs
PUDs, beginning of year		2,153,248		$	28,809,230
Revision of previous estimates		(998,890	)		(16,475,396	)
Sales of reserves		(159,759	)		(2,043,502	)
Conversions to PD reserves		(70,453	)		(445,406	)
Additional PUDs added		112,357			2,164,405
PUDs, end of year		1,036,503		$	12,009,331

Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using average prices for 2018 and 2017 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, 2023 are $12,009,331.

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 2018 were $50.63 per bbl of oil and $3.031 per mcf of natural gas. The average prices used for fiscal 2017 were $43.88 per bbl of oil and $2.561 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, 2018 and 2017 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
	2018			2017
Future cash inflows	$	77,221,000		$	110,778,000
Future production costs and taxes		(20,080,000	)		(27,267,000	)
Future development costs		(12,009,000	)		(28,809,000	)
Future income taxes		(6,413,000	)		(13,386,000	)
Future net cash flows		38,719,000			41,316,000
Annual 10% discount for estimated timing of cash flows		(19,843,000	)		(22,233,000	)
Standardized measure of discounted future net cash flows	$	18,876,000		$	19,083,000

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves:

	March 31
	2018			2017
Sales of oil and gas produced, net of production costs	$	(1,580,000	)	$	(1,459,000	)
Net changes in price and production costs		6,967,000			1,849,000
Changes in previously estimated development costs		16,196,000			970,000
Revisions of quantity estimates		(23,969,000	)		(404,000	)
Net change due to purchases and sales of minerals in place		(1,744,000	)		(2,380,000	)
Extensions and discoveries, less related costs		1,240,000			6,994,000
Net change in income taxes		3,057,000			(3,959,000	)
Accretion of discount		2,527,000			1,612,000
Changes in timing of estimated cash flows and other		(2,901,000	)		1,962,000
Changes in standardized measure		(207,000	)		5,185,000
Standardized measure, beginning of year		19,083,000			13,898,000
Standardized measure, end of year	$	18,876,000		$	19,083,000