Supplementary Information On Oil And Natural Gas Reserves (Unaudited)

12 Months Ended

Sep. 30, 2011

Information On Oil And Natural Gas Producing Activities/Supplementary Information On Oil And Natural Gas Reserves (Unaudited) [Abstract]

SUPPLEMENTARY INFORMATION ON OIL AND NATURAL GAS RESERVES (UNAUDITED)

11. SUPPLEMENTARY INFORMATION ON OIL 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:

	2011			2010
Producing properties	$	230,554,198		$	207,928,578
Non-producing minerals		8,792,980			7,744,767
Non-producing leasehold		1,102,988			1,360,264
Exploratory wells in progress		1,204,382			511,299
		241,654,548			217,544,908
Accumulated depreciation, depletion and amortization		(145,664,726	)		(131,529,373	)
Net capitalized costs	$	95,989,822		$	86,015,535

Costs Incurred

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

	2011		2010		2009
Property acquisition costs	$	5,140,862	$	742,005	$	382,239
Exploration costs		4,837,451		530,931		1,647,456
Development costs		17,310,808		10,685,088		26,411,704
	$	27,289,121	$	11,958,024	$	28,441,399

Approximately $3.9 million of 2011 property acquisition costs relates to the acquisition of mineral acreage with proved reserves.

The following unaudited information regarding the Company’s oil 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 and natural gas reserves as of September 30, 2011 and 2010 (see Exhibits 23 and 99). Reserves as of September 30, 2009, were calculated by Pinnacle Energy Services, L.L.C. of Oklahoma City, Oklahoma.

The Company’s net proved oil and natural gas reserves, all of which are located in the United States, as of September 30, 2011, 2010 and 2009, have been estimated by the Company’s Independent Consulting Petroleum Engineering Firms (as noted above). All studies have been prepared in accordance with regulations prescribed by the SEC and generally accepted geological and engineering methods by the petroleum industry.

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 25 years of oil and gas industry experience, including engineering assignments in several field locations.

Our COO and internal staff of professionals 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 value based 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.

Estimated Quantities of Proved Oil and Natural Gas Reserves

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

	Proved Reserves
	Oil (Barrels)			NGL (1) (Barrels)		Natural Gas (Mcf)
September 30, 2008		989,957			—		48,150,671
Revisions of previous estimates		(30,266	)		—		589,308
Divestitures		(3,593	)		—		(316,884	)
Extensions and discoveries		92,935			—		14,714,703
Production		(128,160	)		—		(9,109,988	)
September 30, 2009		920,873			—		54,027,810
Revisions of previous estimates		47,999			—		15,762,883
Divestitures		(487	)		—		(7,778	)
Extensions and discoveries		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 and discoveries		82,230			—		8,005,990
Production		(104,141	)		—		(8,297,657	)
September 30, 2011		843,738			791,648		101,837,984

(1) 2011 is 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, which includes many plays (horizontal Granite Wash, Hogshooter Wash, Cleveland, Marmaton, Tonkawa and the Anadarko Basin “Cana” Woodford Shale) producing significant volumes of NGL.

The prices used to calculate reserves and future cash flows from reserves for oil, natural gas liquids and natural gas, respectively, were as follows: 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; September 30, 2009 – $66.96/Bbl, $2.86/Mcf (these natural gas prices are representative of local pipelines in Oklahoma).

The revisions of previous estimates were primarily the result of:

(1) Positive performance revisions of 9,681,460 Mcfe, which were principally attributable to properties in the southeast Oklahoma Woodford Shale and the Arkansas Fayetteville Shale. These revisions are principally the result of actual well performance on both new and existing wells exceeding the performance projections in the prior estimates. The improved performance in the new wells can be attributed to enhanced fracture stimulation and completion techniques and increased horizontal lateral lengths.

(2) Revisions related to the inclusion of natural gas liquids and the associated reduction in natural gas volumes due to the conversion of previously reported gas volumes into NGL volumes. The Company reported NGL reserves for the first time in the 2011 year-end report. Panhandle’s increased drilling activity over the last 12-18 months in several western Oklahoma plays which produce significant NGL, have resulted in meaningful NGL production and reserves for the Company, necessitating inclusion in the reserve calculation.

(3) Negative gas pricing revisions of 8,911,784 Mcfe, which included revisions due to producing wells reaching their economic limits earlier than previously projected and revisions due to proved undeveloped locations, primarily in the southeast Oklahoma Woodford Shale, becoming uneconomic at current product prices.

Extensions and discoveries are principally attributable to:

(1) The Company’s ongoing development of unconventional natural gas and natural gas liquids plays utilizing horizontal drilling, including the Anadarko Basin Woodford Shale.

(2) The Company’s ongoing development of unconventional natural gas plays utilizing horizontal drilling, including the Arkansas Fayetteville Shale and the southeast Oklahoma Woodford Shale.

(3) The Company’s ongoing development of conventional oil, natural gas liquids 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 Hogshooter Wash, Marmaton and Tonkawa plays 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, 2009		882,987		—		45,036,460		37,886		—		8,991,350
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

The following details the changes in proved undeveloped reserves for 2011 (Mcfe):

Beginning proved undeveloped reserves	41,208,879
Proved undeveloped reserves transferred to proved developed	(5,190,555	)
Revisions	995,953
Extensions and discoveries	4,744,630
Purchases	2,816,937
Ending proved undeveloped reserves	44,575,844

The beginning 2011 PUD reserves were 41,208,879 Mcfe. A total of 5,190,555 Mcfe (12.6% of the beginning balance) were transferred to proved developed during 2011. An additional 5,553,576 Mcfe (13.5% of the beginning balance) were removed during 2011 as the result of becoming uneconomic at 2011 product prices. A total of 10,744,131 Mcfe (26.1% of the beginning balance) of PUD reserves were moved out of the category during 2011 as the result of either being transferred to proved developed or removed as uneconomic. Only one PUD location from 2007 and one PUD location from 2008 remain in the PUD category. We anticipate that all the Company’s remaining PUD locations will be drilled and converted to PDP within 5 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 as of September 30, 2010 and 2011, are determined by applying the trailing unweighted 12-month arithmetic average of the first-day-of-the- month oil and natural gas prices and year-end costs to the estimated quantities of natural gas and oil 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 oil and natural gas prices and year-end costs used. Amounts as of September 30, 2009, were determined using year-end prices and costs. 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 carryforwards, 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.

	2011		2010		2009
Future cash inflows	$	494,523,456	$	489,691,155	$	216,181,210
Future production costs		146,168,829		148,727,914		62,102,230
Future development costs		43,425,811		52,975,820		5,412,470
Asset retirement obligation		1,843,875		1,730,369		1,620,225
Future income tax expense		107,111,317		99,118,090		43,832,666
Future net cash flows		195,973,624		187,138,962		103,213,619
10% annual discount		117,591,190		114,638,553		49,467,111
Standardized measure of discounted future net cash flows	$	78,382,434	$	72,500,409	$	53,746,508

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

	2011			2010			2009
Beginning of year	$	72,500,409		$	53,746,508		$	78,794,725
Changes resulting from:
Sales of oil and natural gas, net of production costs (1)		(33,570,621	)		(34,429,083	)		(28,524,453	)
Net change in sales prices and production costs		(2,697,833	)		30,806,970			(59,790,799	)
Net change in future development costs		4,177,910			(26,093,254	)		7,769,930
Net change in asset retirement obligation		(51,098	)		(48,185	)		(63,536	)
Extensions and discoveries		11,938,029			53,274,047			21,677,448
Revisions of quantity estimates		7,046,873			28,946,810			587,215
Acquisitions/divestitures of reserves-in-place		4,480,858			(15,706	)		(480,535	)
Accretion of discount		12,523,091			8,066,959			12,110,733
Net change in income taxes		(5,329,092	)		(25,807,417	)		15,389,517
Change in timing and other, net		7,363,908			(15,947,240	)		6,276,263
Net change		5,882,025			18,753,901			(25,048,217	)
End of year	$	78,382,434		$	72,500,409		$	53,746,508

(1) Sales of natural gas includes associated natural gas liquids