Supplementary Information on Oil, Ngl and Natural Gas Reserves (Unaudited)

12 Months Ended

Sep. 30, 2012

Supplementary Information on Oil, Ngl and Natural Gas Reserves (Unaudited) [Abstract]

SUPPLEMENTARY INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES (UNAUDITED)

11. SUPPLEMENTARY INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES (UNAUDITED)

Aggregate Capitalized Costs

The aggregate amount of capitalized costs of oil and natural gas properties and related accumulated depreciation, depletion and amortization as of September 30 is as follows:

	2012			2011
Producing properties	$	275,997,569		$	230,554,198
Non-producing minerals		9,018,731			8,792,980
Non-producing leasehold		1,123,812			1,102,988
Exploratory wells in progress		8,018			1,204,382
		286,148,130			241,654,548
Accumulated depreciation, depletion and amortization		(164,652,199	)		(145,664,726	)
Net capitalized costs	$	121,495,931		$	95,989,822

Costs Incurred

For the years ended September 30, the Company incurred the following costs in oil and natural gas producing activities:

	2012		2011		2010
Property acquisition costs	$	20,404,465	$	5,140,862	$	742,005
Exploration costs		1,210,417		4,837,451		530,931
Development costs		24,578,943		17,310,808		10,685,088
	$	46,193,825	$	27,289,121	$	11,958,024

In 2012, $17.4 million of the property acquisition costs related to the acquisition of certain assets in the Arkansas Fayetteville Shale which closed on October 25, 2011. Approximately $3.9 million of 2011 property acquisition costs relates to the acquisition of mineral acreage with proved reserves.

Estimated Quantities of Proved Oil, NGL and Natural Gas Reserves

The following unaudited information regarding the Company’s oil, NGL and natural gas reserves is presented pursuant to the disclosure requirements promulgated by the SEC and the FASB.

Proved oil and natural gas reserves are those quantities of oil and natural gas which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be

the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

The independent consulting petroleum engineering firm of DeGolyer and MacNaughton of Dallas, Texas, calculated the Company’s oil, NGL and natural gas reserves as of September 30, 2012, 2011 and 2010 (see Exhibits 23 and 99).

The Company’s net proved oil, NGL and natural gas reserves, all of which are located in the United States, as of September 30, 2012, 2011 and 2010, have been estimated by the Company’s Independent Consulting Petroleum Engineering Firm. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principals and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history.

All of the reserve estimates are reviewed and approved by our Vice President and COO, who reports directly to our President and CEO. Mr. Blanchard, our COO, holds a Bachelor of Science Degree in Petroleum Engineering from the University of Oklahoma. Before joining the Company, he was sole proprietor of a consulting petroleum engineering firm, spent 10 years as Vice President of the Mid-Continent business unit of Range Resources Corporation and spent several years as an engineer with Enron Oil and Gas. He is an active member of the Society of Petroleum Engineers (SPE) with over 26 years of oil and gas industry experience, including engineering assignments in several field locations.

Our COO and internal staff work closely with our Independent Consulting Petroleum Engineers to ensure the integrity, accuracy and timeliness of data furnished to them for their reserves estimation process. We provide historical information to our Independent Consulting Petroleum Engineers for all properties such as ownership interest, oil and gas production, well test data, commodity prices, operating costs and handling fees, and development costs. Throughout the year, our team meets regularly with representatives of our Independent Consulting Petroleum Engineers to review properties and discuss methods and assumptions.

When applicable, the volumetric method was used to estimate the original oil in place (OOIP) and the original gas in place (OGIP). Structure and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data was available and when circumstances justified, material balance and other engineering methods were used to estimate OOIP or OGIP.

Estimates of ultimate recovery were obtained after applying recovery factors to OOIP or OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties and the production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors. An analysis of reservoir performance, including production rate, reservoir pressure and gas-oil ratio behavior, was used in the estimation of reserves.

For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline curves, reserves were estimated only to the limits of economic production or to the limit of the production licenses as appropriate.

Accordingly, these estimates should be expected to change, and such changes could be material and occur in the near term as future information becomes available.

Net quantities of proved, developed and undeveloped oil, NGL and natural gas reserves are summarized as follows:

	Proved Reserves
	Oil			NGL (1)			Natural Gas
	(Barrels)			(Barrels)			(Mcf)
September 30, 2009		920,873			—			54,027,810
Revisions of previous estimates		47,999			—			15,762,883
Divestitures		(487	)		—			(7,778	)
Extensions, discoveries and other additions		59,003			—			36,689,882
Production		(102,379	)		—			(8,302,342	)
September 30, 2010		925,009			—			98,170,455
Revisions of previous estimates		(59,360	)		791,648			769,676
Acquisitions		—			—			3,189,520
Extensions, discoveries and other additions		82,230			—			8,005,990
Production		(104,141	)		—			(8,297,657	)
September 30, 2011		843,738			791,648			101,837,984
Revisions of previous estimates		8,627			(76,794	)		(27,389,752	)
Acquisitions		—			—			19,075,529
Extensions, discoveries and other additions		373,097			172,602			29,062,593
Production		(153,143	)		(98,714	)		(9,072,298	)
September 30, 2012		1,072,319			788,742			113,514,056

(1) 2011 was the first year the Company had sufficient volumes of NGL to warrant reserve volumes disclosure. These NGL are associated with the rapid increase in drilling activity in western Oklahoma and the Texas Panhandle, which includes many plays (horizontal Granite Wash, Hogshooter Wash, Cleveland, Marmaton, Tonkawa and the Anadarko Basin Woodford Shale) producing significant volumes of NGL.

The prices used to calculate reserves and future cash flows from reserves for oil, NGL and natural gas, respectively, were as follows: September 30, 2012 - $89.41/Bbl, $35.70/Bbl, $2.51/Mcf ; September 30, 2011 - $90.28/Bbl, $38.91/Bbl, $3.81/Mcf. The prices used to calculate reserves and future cash flows from reserves for oil and natural gas, respectively, were as follows: September 30, 2010 - $69.23/Bbl, $4.33/Mcf.

The revisions of previous estimates from 2011 to 2012 were primarily the result of:

(1) Positive performance revisions of 3,613,707 Mcfe, of which 1,644,157 Mcfe were proved developed revisions principally attributable to properties in western Oklahoma. The

remaining 1,969,550 Mcfe were proved undeveloped revisions principally attributable to higher proved reserves per well in the Company’s shale resource plays including the Fayetteville Shale, Southeastern Oklahoma Woodford Shale and the Anadarko Basin Woodford Shale.

(2) Negative gas pricing revisions of 31,412,464 Mcfe, which included 7,073,763 Mcfe of negative revisions due to proved developed wells reaching their economic limits earlier than previously projected due to current product prices. Negative revisions of 24,338,701 Mcfe were due to certain proved undeveloped locations, primarily in the Fayetteville Shale, Southeastern Oklahoma Woodford Shale and the Anadarko Basin Woodford Shale, becoming uneconomic at current product prices.

Extensions, discoveries and other additions from 2011 to 2012 are principally attributable to:

(1) The Company’s ongoing development of conventional oil, NGL and natural gas plays utilizing horizontal drilling, including the Granite Wash and Cleveland plays in western Oklahoma and the Texas Panhandle, as well as the Marmaton and Tonkawa plays in western Oklahoma.

(2) The Company’s ongoing development of unconventional natural gas plays utilizing horizontal drilling, including the Arkansas Fayetteville Shale and to a much lesser extent, the Southeastern Oklahoma Woodford Shale.

(3) The Company’s ongoing development of unconventional oil, NGL and natural gas plays utilizing horizontal drilling, in the Anadarko Basin Woodford Shale and Ardmore Basin Woodford Shale in western and southern Oklahoma.

(4) The Company’s ongoing development of conventional oil plays utilizing vertical drilling, in the Mississippian play in northern Oklahoma, the Spraberry play in West Texas and the Yeso play in southeastern New Mexico.

(5) PUD additions principally in the Fayetteville Shale play in Arkansas and the Anadarko Basin Woodford Shale play in western Oklahoma.

	Proved Developed Reserves						Proved Undeveloped Reserves
	Oil		NGL		Natural Gas		Oil		NGL		Natural Gas
	(Barrels)		(Barrels)		(Mcf)		(Barrels)		(Barrels)		(Mcf)
September 30, 2010		861,240		—		57,344,190		63,769		—		40,826,265
September 30, 2011		759,989		386,774		60,193,878		83,749		404,874		41,644,106
September 30, 2012		849,548		494,160		65,733,119		222,771		294,582		47,780,937

The following details the changes in proved undeveloped reserves for 2012 (Mcfe):

Beginning proved undeveloped reserves	44,575,844
Proved undeveloped reserves transferred to proved developed	(5,393,421	)
Revisions	(22,369,152	)
Extensions and discoveries	24,458,980
Purchases	9,612,804
Ending proved undeveloped reserves	50,885,055

The beginning PUD reserves were 44.6 Bcfe. A total of 5.4 Bcfe (12% of the beginning balance) were transferred to proved developed producing during 2012. An additional 24.3 Bcfe (55% of the beginning balance) were removed during 2012 as the result of becoming uneconomic at 2012 prices(revisions due to pricing). A total of 29.7 Bcfe (67% of the beginning balance) of PUD reserves were moved out of the category during 2012 as either the result of being transferred to proved developed or removed as uneconomic. Only one PUD location from 2008, representing 1% of total 2012 PUD reserves remains in the PUD category while 45 PUD locations from 2009, representing 11% of total 2012 PUD reserves remain in the PUD category. The 46 PUD locations from 2008 and 2009 represent 8% of the Company’s current total of 589 PUD locations. We anticipate that all the Company’s PUD locations will be drilled and converted to PDP within five years of the date they were added. However, in the event that there are undrilled PUD locations at the end of the five year period, it is our intent to remove the reserves associated with those locations from our proved reserves as revisions.

Standardized Measure of Discounted Future Net Cash Flows

Accounting Standards prescribe guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Company has followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying the trailing unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs to the estimated quantities of oil, natural gas and NGL to be produced. Actual future prices and costs may be materially higher or lower than the unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced based on continuation of the economic conditions applied for such year.

Estimated future income taxes are computed using current statutory income tax rates including consideration for the current tax basis of the properties and related carry forwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the FASB and, as such, do not necessarily reflect our expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates reflect the valuation process.

	2012			2011			2010
Future cash inflows	$	408,694,869		$	494,523,456		$	489,691,155
Future production costs		(135,516,703	)		(146,168,829	)		(148,727,914	)
Future development costs		(33,167,310	)		(43,425,811	)		(52,975,820	)
Asset retirement obligation		(2,122,950	)		(1,843,875	)		(1,730,369	)
Future income tax expense		(83,543,516	)		(107,111,317	)		(99,118,090	)
Future net cash flows		154,344,390			195,973,624			187,138,962
10% annual discount		(86,930,102	)		(117,591,190	)		(114,638,553	)
Standardized measure of discounted future net cash flows	$	67,414,288		$	78,382,434		$	72,500,409

Changes in the standardized measure of discounted future net cash flow are as follows:

	2012			2011			2010
Beginning of year	$	78,382,434		$	72,500,409		$	53,746,508
Changes resulting from:
Sales of oil, NGL and natural gas, net of production costs		(30,226,927	)		(33,570,621	)		(34,429,083	)
Net change in sales prices and production costs		(45,178,377	)		(2,697,833	)		30,806,970
Net change in future development costs		4,618,147			4,177,910			(26,093,254	)
Net change in asset retirement obligation		(134,604	)		(51,098	)		(48,185	)
Extensions and discoveries		34,216,533			11,938,029			53,274,047
Revisions of quantity estimates		(27,419,576	)		7,046,873			28,946,810
Acquisitions (divestitures) of reserves-in-place		20,160,327			4,480,858			(15,706	)
Accretion of discount		13,644,203			12,523,091			8,066,959
Net change in income taxes		10,735,694			(5,329,092	)		(25,807,417	)
Change in timing and other, net		8,616,434			7,363,908			(15,947,240	)
Net change		(10,968,146	)		5,882,025			18,753,901
End of year	$	67,414,288		$	78,382,434		$	72,500,409