Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited)

Costs incurred for oil and natural gas property acquisition, exploration and development activities

The following table summarizes costs incurred and capitalized in oil and natural gas property acquisition, exploration and development activities. Property acquisition costs are those costs incurred to lease property, including both undeveloped leasehold and the purchase of reserves in place. Exploration costs include costs of identifying areas that may warrant examination and examining specific areas that are considered to have prospects containing oil and natural gas reserves, including costs of drilling exploratory wells, geological and geophysical costs and carrying costs on undeveloped properties. Development costs are incurred to obtain access to proved reserves, including the cost of drilling. Exploration and development costs also include amounts incurred due to the recognition of asset retirement obligations of $576,039, $66,976 and $65,575 during the years ended June 30, 2015, 2014, and 2013, respectively.



	For the Years Ended June 30,
	2015		2014		2013
Oil and natural gas activities
Property acquisition costs:
Proved property	$	—	$	—	$	26,449
Unproved property	—		47,344		195,599
Exploration costs	—		757,423		4,356,640
Development costs	10,975,637		18,566		79,035
Total costs incurred for oil and natural gas activities	$	10,975,637	$	823,333	$	4,657,723

Estimated Net Quantities of Proved Oil and Natural Gas Reserves

The following estimates of the net proved oil and natural gas reserves of our oil and gas properties located entirely within the United States of America are based on evaluations prepared by third-party reservoir engineers. Reserve volumes and values were determined under the method prescribed by the SEC for our fiscal years ended June 30, 2015, 2014, and 2013, which requires the application of the previous 12 months unweighted arithmetic average first-day-of-the-month price, and current costs held constant throughout the projected reserve life, when estimating whether reserve quantities are economical to produce.

Proved oil and natural gas reserves are estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed oil and natural gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. There are uncertainties inherent in estimating quantities of proved oil and natural gas reserves, projecting future production rates, and timing of development expenditures. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered.

Estimated quantities of proved oil and natural gas reserves and changes in quantities of proved developed and undeveloped reserves for each of the periods indicated were as follows:



	Crude Oil (Bbls)		Natural Gas Liquids (Bbls)		Natural Gas (Mcf)		BOE
Proved developed and undeveloped reserves:
June 30, 2012	11,638,618		492,473		7,860,156		13,441,116
Revisions of previous estimates (a)	1,826,053		975,515		27,679		2,806,181
Sales of minerals in place	(485,536	)	(480,832	)	(7,726,032	)	(2,254,038	)
Production (sales volumes)	(196,380	)	(7,271	)	(139,006	)	(226,819	)
June 30, 2013	12,782,755		979,885		22,797		13,766,440
Revisions of previous estimates (b)	(1,919,052	)	1,269,588		2,412,677		(247,350	)
Improved recovery, extensions and discoveries	17,146		32,731		498,044		132,884
Sales of minerals in place	(184,722	)	—		—		(184,722	)
Production (sales volumes)	(169,783	)	(3,516	)	(26,655	)	(177,742	)
June 30, 2014	10,526,344		2,278,688		2,906,863		13,289,510
Revisions of previous estimates (c)	(64,074	)	156,195		(2,894,703	)	(390,330	)
Improved recovery, extensions and discoveries	—		—		—		—
Sales of minerals in place	—		—		—		—
Production (sales volumes)	(450,294	)	(1,288	)	(7,221	)	(452,786	)
June 30, 2015	10,011,976		2,433,595		4,939		12,446,394
Proved developed reserves:
June 30, 2012	7,670,934		111,978		1,499,382		8,032,809
June 30, 2013	10,077,522		8,539		22,797		10,089,861
June 30, 2014	7,858,224		32,164		481,042		7,970,562
June 30, 2015	7,347,231		1,572		4,939		7,349,626
Proved undeveloped reserves:
June 30, 2012	3,967,684		380,495		6,360,774		5,408,307
June 30, 2013	2,705,233		971,346		—		3,676,579
June 30, 2014	2,668,120		2,246,524		2,425,821		5,318,948
June 30, 2015	2,664,745		2,432,023		—		5,096,768

(a) A significant upward reserve revision occurred in the Delhi Field during fiscal 2013 as a result of (1) revised geological maps based on production results and acquired seismic data, (2) inclusion of an additional reservoir with similar features, production history and suitability for EOR, and (3) inclusion of natural gas processing at Delhi.

(b) Significant reserve revisions occurred in the Delhi Field during fiscal 2014. As a result of an adverse fluid release event in the Field, 1,817,224 BBLs of oil reserves were reclassified from proved to probable category based on the operator's decision to defer CO₂ injections in certain parts of the Field. There was a positive revision of 1,679,481 BOE, which was comprised of 1,275,178 BBLs of natural gas liquids and 2,425,821 MCF of natural gas as a result of an improved design for the gas plant in the Delhi Field. The plant is expected to significantly increase recoveries of these products, particularly natural gas, which was not previously planned to be extracted from the injection volumes.

(c) The 2,894,703 negative fiscal 2015 revision for natural gas primarily reflects a 2,246,524 MCF negative revision for the Delhi Field gas plant together with a 452,786 MCF negative revision at the Giddings Field for a well that was lost due to excessive formation solids that kept interfering with pumping. The gas plant revision resulted from a decision during the current fiscal year to use the methane production internally to reduce field operating costs rather than selling it into the market. The 156,195 BBL positive natural gas liquids revision primarily reflects 185,499 BBL positive revision for better recovery from the redesigned gas plant, partly offset by a 29,304 BBL negative revision due to the lost Giddings well.

Standardized Measure of Discounted Future Net Cash Flows

Future oil and natural gas sales and production and development costs have been estimated using prices and costs in effect at the end of the years indicated, as required by ASC 932, Disclosures about Oil and Gas Producing Activities ("ASC 932"). ASC 932 requires that net cash flow amounts be discounted at 10%. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing our proved oil and natural gas reserves assuming continuation of existing economic conditions. Future income tax expenses are computed by applying the appropriate period-end statutory tax rates to the future pretax net cash flow relating to our proved oil and natural gas reserves, less the tax basis of the related properties. The future income tax expenses do not give effect to tax credits, allowances, or the impact of general and administrative costs of ongoing operations relating to the Company's proved oil and natural gas reserves. Changes in the demand for oil and natural gas, inflation, and other factors make such estimates inherently imprecise and subject to substantial revision. The table below should not be construed to be an estimate of the current market value of our proved reserves.

The standardized measure of discounted future net cash flows related to proved oil and natural gas reserves as of June 30, 2015, 2014, and 2013 are as follows:



	For the Years Ended June 30,
	2015			2014			2013
Future cash inflows	$	807,030,282		$	1,193,515,075		$	1,436,980,607
Future production costs and severance taxes	(309,225,333		)	(475,387,931		)	(510,902,614		)
Future development costs	(49,691,006		)	(46,154,178		)	(60,742,406		)
Future income tax expenses	(123,888,665		)	(195,581,510		)	(275,113,560		)
Future net cash flows	324,225,278			476,391,456			590,222,027
10% annual discount for estimated timing of cash flows	(165,028,739		)	(250,313,784		)	(283,001,328		)
Standardized measure of discounted future net cash flows	$	159,196,539		$	226,077,672		$	307,220,699

Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the previous 12 months unweighted arithmetic average first-day-of-the-month commodity prices for each year and reflect adjustments for lease quality, transportation fees, energy content and regional price differentials.



	Year Ended June 30,
	2015				2014				2013
	Oil (Bbl)		Gas (MMBtu)		Oil (Bbl)		Gas (MMBtu)		Oil (Bbl)		Gas (MMBtu)
NYMEX prices used in determining future cash flows	$	71.88	$	3.44	$	100.37	$	4.10	$	91.51	$	3.44

The NGL price utilized for future cash inflows was based on the historical price received.

A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved crude oil, natural gas liquids, and natural gas reserves is as follows:



	For the Years Ended June 30,
	2015			2014			2013
Balance, beginning of year	$	226,077,672		$	307,220,699		$	283,597,493
Net changes in sales prices and production costs related to future production	(88,043,095		)	(73,439,526		)	(35,184,725		)
Changes in estimated future development costs	(9,585,405		)	9,848,614			(566,125		)
Sales of oil and gas produced during the period, net of production costs	(18,538,016		)	(16,479,934		)	(19,569,182		)
Net change due to extensions, discoveries, and improved recovery	—			775,574			—
Net change due to revisions in quantity estimates	(9,391,321		)	(23,757,788		)	64,817,544
Net change due to sales of minerals in place	—			(3,150,277		)	(34,119,027		)
Development costs incurred during the period	7,785,095			—			747,656
Accretion of discount	31,974,540			45,896,187			41,678,733
Net change in discounted income taxes	34,157,767			58,073,450			10,175,957
Net changes in timing of production and other (a)	(15,240,698		)	(78,909,327		)	(4,357,625		)
Balance, end of year	$	159,196,539		$	226,077,672		$	307,220,699

(a) Due to the June 2013 adverse fluid release event in the Delhi Field, the operator had expressed plans to produce the Delhi Field at lower production rates. The decision to produce these reserves at lower rates over a longer period of time did not materially change the total quantities expected to be recovered, but resulted in a significant reduction in the discounted value of these reserves as of June 30, 2014.