Oil and Gas Reserve Data (Unaudited)

12 Months Ended

Mar. 31, 2013

Extractive Industries [Abstract]

Oil and Gas Reserve Data (Unaudited)

13. Oil and Gas Reserve Data (Unaudited)

The estimates of our 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, 2013, 2012, and 2011 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, 2010		240,000	8,405,000
	Revision of previous estimates	22,000	130,000
	Purchase of minerals in place	45,000	545,000
	Extensions and discoveries	-	136,000
	Sales of minerals in place	-	-
	Production	(17,000)	(459,000)
As of March 31, 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

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.

Summary of Proved Developed and Undeveloped Reserves as of March 31, 2013, 2012 and 2011:

	Oil (Bbls)	Natural Gas (Mcf)
Proved Developed Reserves:
As of April 1, 2010	141,980	5,017,342
As of March 31, 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
Proved Undeveloped Reserves:
As of April 1, 2010	98,088	3,388,248
As of March 31, 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, 2013, 2012 and 2011 reserves were computed using the 12-month unweighted average of the first-day-of-the-month prices, in accordance with revised guidelines of the SEC applicable to reserves estimates as of year-end 2010.

At March 31, 2013, we reported estimated PUDs of 3.8 bcfe, which accounted for 38% of our total estimated proved oil and gas reserves. This figure primarily consists of a projected 33 new wells (2.6 bcfe), 4 of which we operate, and 1 new zone behind pipe from a currently producing wellbore (.4 bcfe) that we also operate. Our timetable for this well is totally dependent on the life of the currently producing zone. After the current zone has depleted, we will open the new productive zone. Of the 4 wells we operate (1.9 bcfe), all 4 have additional productive zones behind pipe (.6 bcfe). Also, there is potential to commingle the new zones in the new wells with prior permission from the Railroad Commission. We drilled 1 operated well during fiscal 2012 and completed the well in fiscal 2013. We project 1 operated well will be drilled in fiscal 2014, with the three (3) remaining wells in fiscal 2015. Regarding the remaining 29 PUD locations operated by others (.8 bcfe), three (3) wells are currently being drilled and three (3) locations are currently being prepared to drill with plans for eleven (11) wells to follow in 2014, nine (9) wells in 2015 and three (3) wells in 2016.

Included in proved undeveloped reserves at March 31, 2013 are approximately 1.5 bcfe of reserves which have remained undeveloped for more than five years. These primarily consist of two drilling locations in an area where we have long-standing operations and these locations are currently held by production from other wells in which Mexco owns. As of March 31, 2011, these reserves consisted of three drilling locations projected to be drilled one per year during the fiscal years of 2012, 2013 and 2014. We drilled 1 of these wells during fiscal 2012 and during fiscal 2013, completed the well and turned it on for production. Our timetable for the two remaining wells is to drill one during fiscal 2014 and one during fiscal 2015.

The following table discloses our progress toward the conversion of PUDs during fiscal 2013.

Progress of Converting Proved Undeveloped Reserves:

	Oil & Natural Gas	Future
	(Mcfe)	Development Costs
PUDs, beginning of year	3,995,462	$       4,307,550
Revision of previous estimates	(412,155)	(185,185)
Conversions to PD reserves	(155,700)	(228,198)
Additional PUDs added	379,334	647,350
PUDs, end of year	3,806,941	$       4,541,517

Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using average prices for 2013, 2012 and 2011 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 our share of proved undeveloped properties through March 31, 2018 are $4,541,517.

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 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 average prices used for fiscal 2011 were $77.27 per bbl of oil and $3.88 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 our proved oil and gas properties.

The standardized measure of discounted future cash flows at March 31, 2013, 2012 and 2011, 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
	2013	2012	2011
Future cash inflows	$    52,900,000	$   64,783,000	$   56,413,000
Future production costs and taxes	(14,893,000)	(16,031,000)	(11,086,000)
Future development costs	(4,850,000)	(4,530,000)	(4,029,000)
Future income taxes	(6,374,000)	(9,920,000)	(9,118,000)
Future net cash flows	26,783,000	34,302,000	32,180,000
Annual 10% discount for estimated timing of cash flows	(12,414,000)	(14,946,000)	(14,528,000)
Standardized measure of discounted future net cash flows	$ 14,369,000	$ 19,356,000	$ 17,652,000

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

	March 31
	2013	2012	2011
Sales of oil and gas produced, net of production costs	$ (1,982,000)	$ (2,298,000)	$ (2,119,000)
Net changes in price and production costs	(5,881,000)	(375,000)	1,590,000
Changes in previously estimated development costs	1,150,000	1,353,000	830,000
Revisions of quantity estimates	(811,000)	1,344,000	1,088,000
Net change due to purchases and sales of minerals in place	1,471,000	390,000	1,976,000
Extensions and discoveries, less related costs	321,000	1,449,000	165,000
Net change in income taxes	2,178,000	(596,000)	(1,076,000)
Accretion of discount	2,495,000	2,265,000	1,809,000
Changes in timing of estimated cash flows and other	(3,928,000)	(1,828,000)	(771,000)
Changes in standardized measure	(4,987,000)	1,704,000	3,492,000
Standardized measure, beginning of year	19,356,000	17,652,000	14,160,000
Standardized measure, end of year	$   14,369,000	$   19,356,000	$   17,652,000