Note J - Oil and gas reserves information (unaudited):

The estimates of proved oil and gas reserves utilized in the preparation of the financial statements are estimated in accordance with guidelines established by the SEC and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions with no provision for price and cost escalations over prices and costs existing at year-end except by contractual arrangements.

The Company emphasizes that reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. The Company’s policy is to amortize capitalized oil and gas costs on the unit of production method, based upon these reserve estimates. The amortization was $2.80 per Mcf during the twelve month period ended June 30, 2013, as compared to $2.70 per Mcf and $2.48 per Mcf during the same periods in 2012 and 2011, respectively. It is reasonably possible that, because of changes in market conditions or the inherent imprecision of these reserve estimates, that the estimates of future cash inflows, future gross revenues, the amount of oil and gas reserves, the remaining estimated lives of the oil and gas properties, or any combination of the above may be increased or reduced in the near term.

If reduced, the carrying amount of capitalized oil and gas properties may be reduced materially in the near term.

The following unaudited table sets forth proved oil and gas reserves, all within the United States, at June 30, 2013, 2012 and 2011 together with the changes therein:

Proved reserves

	Natural Gas (Mcf)
	2013		2012		2011
Proved developed and undeveloped reserves:
Beginning of year	23,339,985		57,692,086		29,157,280
Revisions of previous estimates	353,722		(51,465,506	)	(2,429,214	)
Extensions and discoveries	10,439,327		19,357,720		32,445,450
Less: Production	(1,141,474	)	(2,244,315	)	(1,481,430	)
Disposals of reserves in place	—		—		—
End of year	32,991,560		23,339,985		57,692,086

	Oil, condensate (Bbls)
	2013		2012		2011
Proved developed and undeveloped reserves:
Beginning of year	427,633		1,199		8,647
Revisions of previous estimates	(177,553	)	344		(4,742	)
Extensions and discoveries	146,291		427,190		—
Less: Production	(863	)	(1,100	)	(2,706	)
Disposals of reserves in place	—		—		—
End of year	395,508		427,633		1,199

	Natural Gas Liquids (Bbls)
	2013		2012		2011
Proved developed and undeveloped reserves:
Beginning of year	1,313,566		—		—
Revisions of previous estimates	(279,169	)	1,312		—
Purchases of reserves in place	—		—		—
Extensions and discoveries	603,602		1,313,531		—
Less: Production	(2,525	)	(1,277	)	—
Disposals of reserves in place	—		—		—
End of year	1,635,474		1,313,566		—

	Natural Gas (Mcfs)
	2013	2012	2011

Proved developed reserves:
Beginning of year	3,982,265	6,634,236	2,666,610
End of year	4,899,388	3,982,265	6,634,236

Proved undeveloped reserves:
Beginning of year	19,357,720	51,057,850	26,490,670
End of year	28,092,173	19,357,720	51,057,850

	Oil (Bbls)
	2013	2012	2011

Proved developed reserves:
Beginning of year	443	1,199	1,166
End of year	1,835	44	1,199

Proved undeveloped reserves:
Beginning of year	427,190	—	7,481
End of year	393,673	427,190	—

	Natural Gas Liquids (Bbls)
	2013	2012	2011

Proved developed reserves:
Beginning of year	35	—	—
End of year	11,205	35	—

Proved undeveloped reserves:
Beginning of year	1,313,531	—	—
End of year	1,624,269	1,313,531	—

The Company’s Louisiana acreage lies atop the center of what is known in our industry as the “Haynesville Shale Play” (which we refer to as the “Bossier/Haynesville shale” elsewhere herein), one of the most prolific dry gas recent field discoveries in the United States; and also includes the Cotton Valley sand formation, a formation with gas, NGL and oil. The discovery of the existence of the Bossier/Haynesville shale formations in the Company’s acreage in fiscal 2008, in an environment of strong pricing for dry natural gas, led to a shift in strategy away from concentrating solely on the development of the Cotton Valley and other shallow formations in our Bethany Longstreet and Johnson Branch fields, and to commencement of the development of the Bossier/Haynesville shale acreage. Development slowed in fiscal 2009, due to deteriorated economic conditions, a harsh debt and equity environment, stubbornly high field operation costs, and a collapse in the pricing of natural gas.

The strategic transactions consummated by the Company in the first half of fiscal 2010 repositioned the Company for increased development of the Bossier/Haynesville shale on its acreage. And, development activity did gain some momentum by the second half of fiscal 2010, with increased activity and development undertaken by EXCO as well as other third party operators of the Bossier/Haynesville shale through fiscal 2011, despite a depressed commodity market for natural gas. The continued deterioration of pricing for dry natural gas, which has persisted through fiscal 2013, brought a halt to additional development of the Bossier/Haynesville shale on Company acreage. As in fiscal 2012, in fiscal 2013, dry natural gas pricing was so low that the Company could not recognize any Proven Undeveloped locations in the Bossier/Haynesville shale; however, the Bossier/Haynesville shale remains a prolific dry gas field and a significant asset to the Company upon a correction in commodity pricing.

While natural gas commodity pricing reached lows not seen in recent history, oil and NGL pricing was relatively strong for fiscal 2013. Due to the increase in NGL prices, we are now for the second year listing them separately from oil and natural gas in the notes to our financial statements. A variety of horizontal development in the Cotton Valley sand in and around our Northwest Louisiana acreage commenced in fiscal 2013. Based upon production for the horizontal development, and the oil being produced along with dry natural gas and NGL, the Company has approximately 36 Proven Undeveloped locations in the Cotton Valley sand for its June 30, 2013, SEC Reserve Report.

The “Revisions of previous estimates” amount of 353,722 Mcf in fiscal 2013 was primarily due to the increased estimated ultimate recovery of the Bossier/Haynesville shale Proved Producing horizontal wells, from approximately 4 Bcf to 6 Bcf of natural gas, based on performance rates.

The “Extensions and discoveries” amount of 10,439,327 Mcf in fiscal 2013 was primarily due to new proved undeveloped offset locations in which the Company maintains a working interest based upon the ability to utilize 160 acre spacing per unit for horizontally-drilled and completed Cotton Valley wells. The reserve estimates attributable to these new proved undeveloped locations were listed under “Extensions and discoveries.”

Standardized measure of discounted future net cash flows relating to proved reserves:

The Standardized Measure of discounted future net cash flows (discounted at 10%) from production of proved reserves was developed as follows:

· An estimate was made of the quantity of proved reserves and the future periods in which they are expected to be produced based on year-end economic conditions.

· In accordance with SEC guidelines, the engineers’ estimates of future net revenues from our proved properties and the present value thereof for fiscal 2013 are made using the twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. Prior year estimates were not required to be restated and reflect previously disclosed estimates using year-end prices. These prices are held constant throughout the life of the properties. Oil and natural gas prices are adjusted for each lease for quality, contractual agreements, lease use shrinkage and regional price variations.

· The future gross revenue streams were reduced by estimated future operating costs (including production and ad valorem taxes) and future development and abandonment costs, all of which were based on current costs in effect at June 30 of the year presented and held constant throughout the life of the properties.

· Future income taxes were calculated by applying the statutory federal and state income tax rate to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to oil and gas operations.

At June 30, 2013, future plugging and abandonment costs, on a present value basis, are estimated to be approximately $169,300, which was less than 0.5% of the PV-10 value shown on our June 30, 2013 Reserve Report of $39,025,000. Therefore, it was determined that the plugging and abandonment costs were not a material disclosure in the filing.

The resulting future net cash flows were discounted using a rate of 10% per annum (Table 1). The standardized measure of discounted net cash flow amounts contained in the following tabulation does not purport to represent the fair market value of the Company’s oil and gas proved by drilling or production history. There are significant uncertainties inherent in estimating timing and amount of future costs. In addition, the method of valuation utilized is based on current prices and costs and the use of a 10% discount rate, and is not necessarily appropriate for determining fair value (Table 2).

The following is the estimated standardized measure relating to proved oil and gas reserves at June 30, 2013, 2012 and 2011:

Table 1	2013			2012			2011
Future cash flows	$	242,990,435		$	179,704,719		$	261,446,375
Future production costs	(29,432,000		)	(32,485,700		)	(43,345,400		)
Future development costs	(111,455,400		)	(72,969,420		)	(126,835,250		)
Future severance tax expense	(13,268,035		)	(4,526,463		)	(4,330,356		)
Future income taxes	—			—			—
Future net cash flows	$	88,835,000		$	69,723,136		$	86,935,369
Ten percent annual discount for estimated timing of net cash flows	(49,787,200		)	(39,746,927		)	(40,024,625		)
Standardized measure of discounted future net cash flows	$	39,047,800		$	29,976,209		$	46,910,744

The following is an analysis of changes in the estimated standardized measure of proved reserves during the years ended June 30, 2013, 2012 and 2011:

Table 2	2013			2012			2011
Changes from:
Sale of oil and gas produced	$	(1,971,234	)	$	(4,967,776	)	$	(4,275,771	)
Net changes in prices and production costs	(695,805		)	(56,534,586		)	(12,465,909		)
Extensions and discoveries	12,195,100			24,472,000			19,367,520
Revision of previous quantity estimates	11,285,959			(17,572,834		)	(6,450,989		)
Accretion of discounts	2,997,621			4,691,074			6,475,729
Net change in income taxes	526,854			1,975,312			(2,178,009		)
Disposals of reserves in place	—			—			—
Development costs incurred that reduced future development costs	—			—			(321,688		)
Changes in future development costs	48,872,306			(42,558,894		)	(604,579		)
Changes in timing of production and other	(64,139,210		)	73,561,169			(17,392,850		)
Change in standardized measure	$	9,071,591		$	(16,934,535	)	$	(17,846,546	)