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

12 Months Ended

Jun. 30, 2012

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

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

Note 17 — 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. Development costs also include amounts incurred due to the recognition of asset retirement obligations, of $93,522, $15,000 and $85,871, during the years ended June 30, 2012, 2011 and 2010, respectively.

		For the Years Ended June 30
		2012			2011			2010
Oil and Natural Gas Activities
Property acquisition costs:
Proved property		$	115,637		$	465,176		$	391,785
Unproved property		5,544,217			523,591			185,154
Exploration costs		3,016,924			215,660			2,354,239
Development costs		238,463			2,200,905			890,116
Total costs incurred for oil and natural gas activities		$	8,915,241		$	3,405,332		$	3,821,294

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, 2012, 2011 and 2010, which requires the application of the previous 12-month 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, 2009		945,948		1,054,294		6,358,788		3,060,040
Revisions of previous estimates		(113,487	)	(19,147	)	430,145		(60,943	)
Improved recovery, extensions and discoveries		9,451,758		29,300		381,695		9,544,674
Production (sales volumes)		(29,749	)	(27,820	)	(407,674	)	(125,515	)
June 30, 2010		10,254,470		1,036,627		6,762,954		12,418,256
Revisions of previous estimates		1,475,918		(84,154	)	3,273,846		1,937,405
Improved recovery, extensions and discoveries		—		—		779,556		129,926
Sales of minerals in place		(104,577	)	(221,469	)	(1,173,850	)	(521,688	)
Production (sales volumes)		(57,965	)	(18,704	)	(238,607	)	(116,437	)
June 30, 2011		11,567,846		712,300		9,403,899		13,847,462
Revisions of previous estimates		84,219		(212,677	)	(1,295,893	)	(344,440	)
Improved recovery, extensions and discoveries		137,634		5,461		18,925		146,249
Sales of minerals in place		—		—		—		—
Production (sales volumes)		(151,081	)	(12,611	)	(266,775	)	(208,155	)
June 30, 2012		11,638,618		492,473		7,860,156		13,441,116

Proved developed reserves:
June 30, 2009		104,731		141,372		1,106,028		430,441
June 30, 2010		706,053		157,302		1,536,858		1,119,498
June 30, 2011		4,986,337		100,900		1,543,401		5,344,471
June 30, 2012		7,670,934		111,978		1,499,382		8,032,809

During our fiscal year ended June 30, 2012, total proved reserves decreased 0.4 million BOE from 13,847,462 BOE at June 30, 2011 to 13,441,116 BOE at June 30, 2012. The decrease is primarily attributable to our production, downward revisions of 127 MBOE for our Woodford properties in Oklahoma and 369 MBOE for lease terminations in Giddings Fields, partially offset by a 210 MBOE upward revision at Delhi and 146 MBOE for extensions in South Texas and acquired well bores in the Giddings Fields. The upward revision in proved oil reserves in the Delhi Field is due primarily to a slight acceleration in the projected reversion date of our approximately 24% working interest based on performance to date.

During our fiscal year ended June 30, 2011, total proved reserves increased 1.4 million BOE from 12,418,256 BOE at June 30, 2010 to 13,847,462 BOE at June 30, 2012. The increase is primarily attributable to upward revisions in both the Delhi Field and our Giddings Field, partially offset by sales in place of reserves in the Giddings Field. The upward revision of 1,475,918 BO in proved oil reserves is due primarily to a more than two year acceleration in the projected reversion date of our 24% working interest, based on operating performance to date. The upward revision of 3,273,846 Mcf is primarily due to re-categorizing probable reserves into the proved category for our properties in the Giddings Field, as a result of drilling results during the year. Sales in place of 521,688 BOE in the Giddings Field are primarily due to the industry drilling joint venture we entered into early in the year.

Total proved reserves increased 9.4 million BOE from 3,060,040 BOE at June 30, 2009 to 12,418,256 BOE at June 30, 2010. The increase is primarily attributable to improved recovery of 9,411,841 barrels of proved oil reserves added to our properties in the Delhi Field, based on approximately $300 million of development capital spent by the Operator since project inception, the start-up of CO2 injection operations during fiscal year 2010, and oil production response during fiscal year 2010. The additions to our properties in the Delhi Field along with extensions in Giddings and Oklahoma of 127,905 BOE, were offset by production of 125,515 BOE and negative revisions of 60,943 BOE primarily related to the transfer of four well locations in the Lopez Field in South Texas from the proved classification to probable during 2010.

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, 2012, 2011 and 2010 are as follows:

		For the Years Ended June 30
		2012			2011			2010
Future cash inflows		$	1,355,686,188		$	1,161,278,060		$	827,902,260

Future production costs and severance taxes		(458,716,938		)	(379,493,392		)	(222,826,052		)

Future development costs		(38,458,724		)	(40,571,895		)	(34,024,112		)

Future income tax expenses		(296,703,838		)	(278,455,798		)	(213,063,769		)
Future net cash flows		561,806,688			462,756,975			357,988,327
10% annual discount for estimated timing of cash flows		(278,209,195		)	(234,309,020		)	(196,361,678		)

Standardized measure of discounted future net cash flows		$	283,597,493		$	228,447,954		$	161,626,649

Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the previous 12-month 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,
		2012						2011						2010
		Oil (Bbl)			Gas (MMBtu)			Oil (Bbl)			Gas (MMBtu)			Oil (Bbl)			Gas (MMBtu)
Commodity prices used in determining future cash flows		$	95.67		$	3.15		$	90.09		$	4.21		$	75.76		$	4.10

The NGL price that was utilized was based on the historical price received versus the NYMEX basis oil price.

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
		2012			2011			2010
Balance, beginning of year		$	228,447,954		$	161,626,649		$	23,549,791
Net changes in sales prices and production costs related to future production		76,942,613			57,178,860			3,935,863
Changes in estimated future development costs		6,340,123			(16,028,728		)	(3,502,403		)

Sales of oil and gas produced during the period, net of production costs		(16,187,039		)	(6,151,549		)	(3,356,822		)

Net change due to purchases of minerals in place		—			—			—

Net change due to extensions, discoveries, and improved recovery		1,606,122			623,446			236,828,138

Net change due to revisions in quantity estimates		(11,975,496		)	56,766,220			(934,602		)

Net change due to sales of minerals in place		—			(8,233,734		)	—

Development costs incurred during the period		(2,639,398		)	2,416,565			—

Accretion of discount		22,568,868			26,597,834			3,582,622

Net change in discounted income taxes		(15,026,628		)	(42,490,270		)	(91,991,767		)

Other		(6,479,626		)	(3,857,339		)	(6,484,171		)

Balance, end of year		$	283,597,493		$	228,447,954		$	161,626,649