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Oil and Gas Reserve Data (Unaudited)

12 Months Ended

Mar. 31, 2014

14. 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, 2014, 2013, and 2012 are based on evaluations prepared by Joe C. Neal and Associates, Petroleum 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.

Changes in Proved Reserves:

	Oil (Bbls)			Natural Gas (Mcf)
Proved Developed and Undeveloped Reserves:
As of April 1, 2011		290,000			8,757,000
Revision of previous estimates		33,000			(183,000	)
Purchase of minerals in place		19,000			-
Extensions and discoveries		23,000			267,000
Sales of minerals in place		-			-
Production		(19,000	)		(396,000	)
As of March 31, 2012		346,000			8,445,000
Revision of previous estimates		(10,000	)		(589,000	)
Purchase of minerals in place		48,000			71,000
Extensions and discoveries		5,000			318,000
Sales of minerals in place		-			-
Production		(23,000	)		(401,000	)
As of March 31, 2013		366,000			7,844,000
Revision of previous estimates		12,000			(1,404,000	)
Purchase of minerals in place		50,000			18,000
Extensions and discoveries		101,000			163,000
Sales of minerals in place		-			-
Production		(27,000	)		(362,000	)
As of March 31, 2014		502,000			6,259,000

Proved developed reserves are those expected to be recovered through existing wells, equipment and operating methods. Proved undeveloped reserves ("PUD") are proved reserves 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 downward revision of natural gas is primarily the result of SEC rules which require such reserves to be developed within five years.

Summary of Proved Developed and Undeveloped Reserves as of March 31, 2014, 2013 and 2012:

	Oil (Bbls)		Natural Gas (Mcf)
Proved Developed Reserves:
As of April 1, 2011		159,975		4,964,061
As of March 31, 2012		194,620		5,359,670
As of March 31, 2013		237,420		4,807,020
As of March 31, 2014		294,620		4,081,470

Proved Undeveloped Reserves:
As of April 1, 2011		130,187		3,792,974
As of March 31, 2012		151,730		3,085,060
As of March 31, 2013		128,290		3,037,180
As of March 31, 2014		206,930		2,177,810

As of March 31, 2014, 2013 and 2012 reserves were computed using the 12-month unweighted average of the first-day-of-the-month prices, in accordance with current SEC rules.

At March 31, 2014, the Company reported estimated PUDs of 3.4 bcfe, which accounted for 37% of its total estimated proved oil and gas reserves. This figure primarily consists of a projected 54 new wells (1.9 bcfe), 3 of which we operate, and 1 new zone behind pipe from a currently producing wellbore (.4 bcfe) that the Company also operates. The Company's timetable for this well is totally dependent on the life of the currently producing zone. After the current zone has depleted, the Company will open the new productive zone. Of the 3 wells the Company operates (1.1 bcfe), all 3 have additional productive zones behind pipe (.3 bcfe). Also, there is potential to commingle the new zones in the new wells with prior permission from the Railroad Commission. The Company projects 2 operated wells will be drilled in fiscal 2015, with the 1 remaining well in fiscal 2016. Regarding the remaining 51 PUD locations operated by others (.8 bcfe), 5 wells are currently being drilled and 2 locations are currently being prepared to drill with plans for 10 wells to follow in 2015, 30 wells in 2016 and 4 wells in 2017.

Included in proved undeveloped reserves at March 31, 2014 are approximately .8 bcfe of reserves which have remained undeveloped for more than five years. This consists of one drilling location in an area where the Company has long-standing operations and this location is currently held by production from other wells in which the Company owns. The Company plans to drill this well during fiscal 2015.

The following table discloses the Company's progress toward the conversion of PUDs during fiscal 2014.

Progress of Converting Proved Undeveloped Reserves:

	Oil & Natural Gas			Future
	(Mcfe)			Development Costs
PUDs, beginning of year		3,806,941		$	4,541,517
Revision of previous estimates		(982,517	)		(1,130,163	)
Conversions to PD reserves		(126,642	)		(288,264	)
Additional PUDs added		721,580			1,497,230
PUDs, end of year		3,419,362		$	4,620,320

Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using average prices for 2014, 2013 and 2012 along with estimates of the operating costs, production taxes and future development and abandonment costs (less salvage value) 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, 2019 are $4,826,362.

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 2014 were $94.23 per bbl of oil and $3.67 per mcf of natural gas. The average prices used for fiscal 2013 were $85.53 per bbl of oil and $2.76 per mcf of natural gas. The average prices used for fiscal 2012 were $93.75 per bbl of oil and $3.83 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, 2014, 2013 and 2012, 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
	2014			2013			2012
Future cash inflows	$	70,252,000		$	52,900,000		$	64,783,000
Future production costs and taxes		(20,647,000	)		(14,893,000	)		(16,031,000	)
Future development costs		(4,826,000	)		(4,850,000	)		(4,530,000	)
Future income taxes		(9,801,000	)		(6,374,000	)		(9,920,000	)
Future net cash flows		34,978,000			26,783,000			34,302,000
Annual 10% discount for estimated timing of cash flows		(15,649,000	)		(12,414,000	)		(14,946,000	)
Standardized measure of discounted future net cash flows	$	19,329,000		$	14,369,000		$	19,356,000

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

	March 31
	2014			2013			2012
Sales of oil and gas produced, net of production costs	$	(2,762,000	)	$	(1,982,000	)	$	(2,298,000	)
Net changes in price and production costs		2,464,000			(5,881,000	)		(375,000	)
Changes in previously estimated development costs		270,000			1,150,000			1,353,000
Revisions of quantity estimates		(657,000	)		(811,000	)		1,344,000
Net change due to purchases and sales of minerals in place		1,332,000			1,471,000			390,000
Extensions and discoveries, less related costs		3,802,000			321,000			1,449,000
Net change in income taxes		(1,997,000	)		2,178,000			(596,000	)
Accretion of discount		1,779,000			2,495,000			2,265,000
Changes in timing of estimated cash flows and other		729,000			(3,928,000	)		(1,828,000	)
Changes in standardized measure		4,960,000			(4,987,000	)		1,704,000
Standardized measure, beginning of year		14,369,000			19,356,000			17,652,000
Standardized measure, end of year	$	19,329,000		$	14,369,000		$	19,356,000

- Definition

Tabular disclosure of the net quantities of an enterprise's interests in proved developed and undeveloped reserves of (a) crude oil (including condensate and natural gas liquids), (b) natural gas (including coal bed methane), (c) synthetic oil, (d) synthetic gas, and (e) other nonrenewable natural resources that are intended to be upgraded during the period as of the beginning of the period, changes in quantities during the period, and as of the end of the period.

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