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 related to 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 $471,864, $140,151 and $576,039 during the years ended June 30, 2017, 2016, and 2015, respectively.



	For the Years Ended June 30,
	2017		2016		2015
Oil and Natural Gas Activities
Property acquisition costs:
Proved property	$	—	$	—	$	—
Unproved property (a)	—		596,500		—
Exploration costs	—		—		—
Development costs	7,554,579		19,093,200		10,975,637
Total costs incurred for oil and natural gas activities	$	7,554,579	$	19,689,700	$	10,975,637

(a) As described in Note 17 — Delhi Field Litigation Settlement, we received a 23.9% working interest in the non-producing Mengel Interval with an estimated fair value of $596,500. This cost is included in properties subject to amortization.

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. Reserves volumes and values were determined under the method prescribed by the SEC for our fiscal years ended June 30, 2017, 2016, and 2015, 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 life of the property, when estimating whether reserves 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, 2014	10,526,344		2,278,688		2,906,863		13,289,510
Revisions of previous estimates (a)	(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
Revisions of previous estimates (b)	(765,385	)	(198,233	)	(3,319	)	(964,171	)
Improved recovery, extensions and discoveries	—		—		—		—
Sales of minerals in place	—		—		—		—
Production (sales volumes)	(658,041	)	(491	)	(1,620	)	(658,802	)
June 30, 2016	8,588,550		2,234,871		—		10,823,421
Revisions of previous estimates (c)	508,123		(504,733	)	16		3,390
Improved recovery, extensions and discoveries	—		—		—		—
Sales of minerals in place	—		—		—		—
Production (sales volumes)	(724,523	)	(43,907	)	(16	)	(768,433	)
June 30, 2017	8,372,150		1,686,231		—		10,058,378
Proved developed reserves:
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
June 30, 2016	7,168,249		—		—		7,168,249
June 30, 2017	6,617,389		1,332,803		—		7,950,192
Proved undeveloped reserves:
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
June 30, 2016	1,420,301		2,234,871		—		3,655,172
June 30, 2017	1,754,761		353,425		—		2,108,186

(a) The 2,894,703 revision for natural gas in fiscal 2015 primarily reflects a 2,246,524 MCF reduction for the Delhi field NGL plant together with a 452,786 MCF revision at the Giddings Field for a well that was lost due to mechanical issues. The NGL plant revision resulted from a decision to change in the plant design 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 NGL plant, partly offset by a 29,304 BBL negative revision from the lost Giddings well.

(b) The negative revision results primarily from the removal of proved undeveloped reserves in the far eastern part of the Delhi field, referred to as Test Site 6, which were deemed uneconomic under the lower SEC price case utilized at the end of the period.

(c) The positive crude oil revision resulted from better production performance during fiscal 2017 and the expectation of greater ultimate recoveries of oil from the Delhi field. The negative NGL revision results primarily from lower expectations for ultimate NGL recoveries from the plant based on production data after the plant commenced production.

Standardized Measure of Discounted Future Net Cash Flows

Future oil and natural gas sales and production and development costs have been estimated using, respectively, trailing 12 month unweighted arithmetic average first-day-of-the-month prices, and costs in effect at the end of the years indicated, as required by ASC 932, Extractive Activities - Oil and Gas ("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, 2017, 2016, and 2015 are as follows:



	For the Years Ended June 30,
	2017			2016			2015
Future cash inflows	$	425,094,736		$	383,491,193		$	807,030,282
Future production costs and severance taxes	(213,115,443		)	(179,182,565		)	(309,225,333		)
Future development costs	(22,631,856		)	(16,595,047		)	(49,691,006		)
Future income tax expenses	(47,055,551		)	(45,713,438		)	(123,888,665		)
Future net cash flows	142,291,886			142,000,143			324,225,278
10% annual discount for estimated timing of cash flows	(59,354,333		)	(64,042,824		)	(165,028,739		)
Standardized measure of discounted future net cash flows	$	82,937,553		$	77,957,319		$	159,196,539

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,
	2017			2016			2015
	Oil (Bbl)		Gas (MMBtu)	Oil (Bbl)		Gas (MMBtu)	Oil (Bbl)		Gas (MMBtu)
NYMEX prices used in determining future cash flows	$	48.85	n/a	$	42.91	n/a	$	71.88	$	3.44

There were no natural gas reserves in 2017 and 2016. The NGL prices utilized for future cash inflows were based on historical prices received, where available. For the Delhi NGL plant, we utilized historical prices for the expected mix and net pricing of natural gas liquid products.

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,
	2017			2016			2015
Balance, beginning of year	$	77,957,319		$	159,196,539		$	226,077,672
Net changes in sales prices and production costs related to future production	19,821,288			(120,832,747		)	(88,043,095		)
Changes in estimated future development costs	(1,626,833		)	74,991			(9,585,405		)
Sales of oil and gas produced during the period, net of production costs	(23,649,087		)	(17,079,363		)	(18,538,016		)
Net change due to extensions, discoveries, and improved recovery	—			—			—
Net change due to revisions in quantity estimates	(2,206,287		)	(18,821,014		)	(9,391,321		)
Net change due to sales of minerals in place	—			—			—
Development costs incurred during the period	2,632,547			16,327,883			7,785,095
Accretion of discount	10,086,904			21,870,650			31,974,540
Net change in discounted income taxes	(5,045,279		)	36,598,239			34,157,767
Net changes in timing of production and other	4,966,981			622,141			(15,240,698		)
Balance, end of year	$	82,937,553		$	77,957,319		$	159,196,539