Oil and Gas Reserve Data (Unaudited)

12 Months Ended

Mar. 31, 2017

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 guidelines established by the SEC. The estimates as of March 31, 2017, 2016, and 2015 are based on evaluations prepared by Joe C. Neal and Associates, Petroleum and Environmental Engineering Consultants. Management emphasizes that reserve estimates are inherently imprecise and are expected to change as new information becomes available and as economic conditions in the industry change.

Proved reserves are estimated quantities of oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

The Company’s total estimated proved reserves at March 31, 2017 were approximately 3.238 MBOE of which 66% was oil and natural gas liquids and 34% was natural gas.

Changes in Proved Reserves:

	Oil (Bbls)			Natural Gas (Mcf)
Proved Developed and Undeveloped Reserves:
As of April 1, 2014		502,000			6,259,000
Revision of previous estimates		(90,000	)		(665,000	)
Purchase of minerals in place		43,000			795,000
Extensions and discoveries		235,000			269,000
Sales of minerals in place		-			-
Production		(30,000	)		(369,000	)
As of March 31, 2015		660,000			6,289,000
Revision of previous estimates		(13,000	)		(736,000	)
Purchase of minerals in place		-			-
Extensions and discoveries		479,000			665,000
Sales of minerals in place		(3,000	)		(9,000	)
Production		(39,000	)		(408,000	)
As of March 31, 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

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. The upward revision of oil and natural gas is primarily the result of pricing and successful development in the Delaware and Midland Basins. Reserves written off due to the five year limitation are primarily in the Cotton Valley Sand field in Limestone and Freestone Counties, Texas which are on leases 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, 2017, 2016 and 2015:

	Oil (Bbls)		Natural Gas (Mcf)
Proved Developed Reserves:
As of April 1, 2014		294,620		4,081,470
As of March 31, 2015		283,670		4,584,790
As of March 31, 2016		350,180		4,406,060
As of March 31, 2017		399,880		4,107,950
Proved Undeveloped Reserves:
As of April 1, 2014		206,930		2,177,810
As of March 31, 2015		376,070		1,703,790
As of March 31, 2016		734,170		1,395,220
As of March 31, 2017		1,724,420		2,572,960

At March 31, 2017, the Company reported estimated PUDs of 2,153 MBOE, which accounted for 67% of its total estimated proved oil and gas reserves. This figure primarily consists of a projected 72 new wells (1,655 MBOE), 6 of which the Company operates with reserves of 1,234 MBOE. Four of the wells the Company operates (202 MBOE), 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. The remaining 2 wells the Company operates are in the Midland Basin on acreage held by production. We project these 2 wells to be drilled in 2020.

Regarding the remaining 66 PUD locations operated by others (421 BOE), 3 wells are currently being drilled with plans for 22 wells to follow in 2018, 20 wells in 2019, 19 wells in 2020 and 2 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.

As of March 31, 2017, 2016 and 2015 reserves were computed using the 12-month unweighted average of the first-day-of-the-month prices, in accordance with current SEC rules.

The following table discloses the Company’s progress toward the conversion of PUDs during fiscal 2017.

Progress of Converting Proved Undeveloped Reserves:

	Oil & Natural Gas			Future
	(BOE)			Development Costs
PUDs, beginning of year		966,707		$	9,617,160
Revision of previous estimates		122,762			1,467,427
Sales of reserves		(82,318	)		(228,586	)
Conversions to PD reserves		(13,515	)		(284,067	)
Additional PUDs added		1,159,612			18,237,296
PUDs, end of year		2,153,248		$	28,809,230

Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using average prices for 2017, 2016 and 2015 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, 2022 are $28,809,230.

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 2017 were $43.88 per bbl of oil and $2.561 per mcf of natural gas. The average prices used for fiscal 2016 were $41.76 per bbl of oil and $1.998 per mcf of natural gas. The average prices used for fiscal 2015 were $74.84 per bbl of oil and $3.595 per mcf of natural gas.

The standardized measure of discounted future net cash flows were computed by applying 12-month average prices for oil and gas (with consideration of price changes only to the extent provided by contractual arrangements in existence at year end) to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on the year end statutory tax rates with consideration of future tax rates already legislated) to be incurred on pretax net cash flows less tax basis of the properties and available credits and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10%.

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 standardized measure of discounted future cash flows at March 31, 2017, 2016 and 2015, which represents the present value of estimated future cash flows using a discount rate of 10% a year, follows:

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves:

	March 31
	2017			2016			2015
Future cash inflows	$	110,778,000		$	57,318,000		$	72,238,000
Future production costs and taxes		(27,267,000	)		(14,571,000	)		(19,569,000	)
Future development costs		(28,809,000	)		(9,617,000	)		(6,617,000	)
Future income taxes		(13,386,000	)		(4,569,000	)		(9,254,000	)
Future net cash flows		41,316,000			28,561,000			36,798,000
Annual 10% discount for estimated timing of cash flows		(22,233,000	)		(14,663,000	)		(17,860,000	)
Standardized measure of discounted future net cash flows	$	19,083,000		$	13,898,000		$	18,938,000

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

	March 31
	2017			2016			2015
Sales of oil and gas produced, net of production costs	$	(1,459,000	)	$	(1,240,000	)	$	(2,036,000	)
Net changes in price and production costs		1,849,000			(12,510,000	)		(4,066,000	)
Changes in previously estimated development costs		970,000			3,701,000			2,627,000
Revisions of quantity estimates		(404,000	)		(602,000	)		(3,718,000	)
Net change due to purchases and sales of minerals in place		(2,380,000	)		(105,000	)		2,777,000
Extensions and discoveries, less related costs		6,994,000			5,174,000			4,607,000
Net change in income taxes		(3,959,000	)		2,539,000			654,000
Accretion of discount		1,612,000			2,370,000			2,474,000
Changes in timing of estimated cash flows and other		1,962,000			(4,367,000	)		(3,710,000	)
Changes in standardized measure		5,185,000			(5,040,000	)		(391,000	)
Standardized measure, beginning of year		13,898,000			18,938,000			19,329,000
Standardized measure, end of year	$	19,083,000		$	13,898,000		$	18,938,000