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:



	2015		2014

Producing properties	$	441,141,337	$	418,237,512
Non-producing minerals		8,088,134		8,247,509
Non-producing leasehold		204,101		302,631
Exploratory wells in progress		1,762		1,710,577
		449,435,334		428,498,229
Accumulated depreciation, depletion and amortization		(227,165,334)		(204,045,504)
Net capitalized costs	$	222,270,000	$	224,452,725

Costs Incurred

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



	2015		2014		2013

Property acquisition costs	$	146,261	$	83,405,404	$	1,242,615
Exploration costs		898,818		2,013,231		-
Development costs		24,931,571		34,219,072		27,938,160
	$	25,976,650	$	119,637,707	$	29,180,775

In 2014, $81.5 million of property acquisition costs related to the Eagle Ford Shale acquisition.

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, 2015, 2014 and 2013.

The Company’s net proved oil, NGL and natural gas reserves, all of which are located in the contiguous United States, as of September 30, 2015, 2014 and 2013, 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. Paul 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 29 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	Natural Gas
	(Barrels)	(Barrels)	(Mcf)
September 30, 2012	1,072,319	788,742	113,514,056

Revisions of previous estimates	(90,968)	141,081	(2,697,853)
Acquisitions (divestitures)	-	-	1,660,649
Extensions, discoveries and other additions	896,036	798,200	30,698,644
Production	(234,084)	(111,897)	(10,886,329)
September 30, 2013	1,643,303	1,616,126	132,289,167

Revisions of previous estimates	(50,025)	469,897	(3,917,380)
Acquisitions (divestitures)	5,882,886	884,889	8,191,448
Extensions, discoveries and other additions	439,802	276,957	16,702,684
Production	(346,387)	(207,688)	(10,773,559)
September 30, 2014	7,569,579	3,040,181	142,492,360

Revisions of previous estimates	(1,697,309)	(425,300)	(31,273,207)
Acquisitions (divestitures)	-	-	-
Extensions, discoveries and other additions	1,619,285	516,679	18,740,114
Production	(453,125)	(210,960)	(9,745,223)
September 30, 2015	7,038,430	2,920,600	120,214,044

The prices used to calculate reserves and future cash flows from reserves for oil, NGL and natural gas, respectively, were as follows: September 30, 2015 - $55.27/Bbl, $19.10/Bbl, $2.84/Mcf ; September 30, 2014 - $96.94/Bbl, $31.45/Bbl, $4.04/Mcf; September 30, 2013 - $89.06/Bbl, $27.28/Bbl, $3.33/Mcf.

The revisions of previous estimates from 2014 to 2015 were primarily the result of:

Negative pricing revisions of 44.8 Bcfe resulting from:

12.4 Bcfe of negative proved developed revisions primarily due to wells reaching their projected economic limits much earlier than projected in 2014.

32.4 Bcfe of negative proved undeveloped revisions principally attributable to the removal of dry gas reserves in the Arkansas Fayetteville Shale which are no longer projected to be developed within five years from the date they were added to the proved undeveloped reserves due to low commodity prices.

Positive performance revisions of 0.7 Bcfe.

Extensions, discoveries and other additions from 2014 to 2015 are principally attributable to:

The Company’s participation in ongoing development of unconventional natural gas utilizing horizontal drilling in the Arkansas Fayetteville Shale.

The Company’s participation in ongoing development of conventional oil, NGL and natural gas plays including the Granite Wash play in western Oklahoma as well as minor activity in other areas.

The Company’s participation in ongoing development of unconventional oil, NGL and natural gas plays utilizing horizontal drilling in the Woodford Shale in western and southern Oklahoma as well as minor activity in other areas.

The addition of 27.1 Bcfe of PUD reserves principally in the Anadarko Basin Woodford and Springer shales in western and southern Oklahoma and the Eagle Ford Shale in South Texas. These additions result from reservoir delineation that occurred through continuing development and additional well performance data in each of the referenced plays.



	Proved Developed Reserves			Proved Undeveloped Reserves
	Oil	NGL	Natural Gas	Oil	NGL	Natural Gas
	(Barrels)	(Barrels)	(Mcf)	(Barrels)	(Barrels)	(Mcf)

September 30, 2013	1,037,721	764,321	82,298,833	605,582	851,805	49,990,334
September 30, 2014	2,890,678	1,564,859	88,512,767	4,678,901	1,475,322	53,979,593
September 30, 2015	2,725,077	1,466,834	82,899,159	4,313,353	1,453,766	37,314,885

The following details the changes in proved undeveloped reserves for 2015 (Mcfe):



Beginning proved undeveloped reserves	90,904,931
Proved undeveloped reserves transferred to proved developed	(13,642,311)
Revisions	(32,417,179)
Extensions and discoveries	27,072,158
Purchases	-
Ending proved undeveloped reserves	71,917,599

Beginning PUD reserves were 90.9 Bcfe. A total of 13.6 Bcfe (15% of the beginning balance) were transferred to proved developed producing during 2015. The 32.4 Bcfe (36% of the beginning balance) of negative revisions to PUD reserves was a negative pricing revision. A total of 46.1 Bcfe (51% of the beginning balance) of PUD reserves were moved out of the category during 2015 as either the result of being transferred to proved developed or removed due to low commodity prices. No PUD locations from 2010 and 2011 remain in the PUD category and there are only nine remaining PUD locations from 2012. The Company’s total PUD locations decreased from 788 in 2014 to 409 in 2015. 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, PUD locations and associated reserves which are no longer projected to be drilled within five years from the date they were added to the proved undeveloped reserves will be removed as revisions at the time that determination is made, and 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. There were 27.1 Bcfe of PUD reserve additions principally in the Anadarko Basin Woodford and Springer shales in western and southern Oklahoma and the Eagle Ford Shale in South Texas. These additions result from reservoir delineation that occurred through continuing development and additional well performance data in each of the referenced plays.

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 affect the valuation process.



	2015		2014		2013

Future cash inflows	$	786,295,155	$	1,405,400,261	$	630,332,900
Future production costs		(311,933,151)		(423,512,430)		(216,584,982)
Future development and asset retirement costs		(124,857,957)		(146,465,509)		(50,572,218)
Future income tax expense		(123,007,909)		(308,149,182)		(131,397,192)
Future net cash flows		226,496,138		527,273,140		231,778,508

10% annual discount		(144,904,927)		(322,490,636)		(130,103,612)
Standardized measure of discounted
future net cash flows	$	81,591,211	$	204,782,504	$	101,674,896

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



	2015		2014		2013
Beginning of year	$	204,782,504	$	101,674,896	$	67,414,288
Changes resulting from:
Sales of oil, NGL and natural gas, net of production costs		(35,359,204)		(66,239,618)		(46,909,635)
Net change in sales prices and production costs		(211,336,729)		164,240,162		47,270,404
Net change in future development and asset retirement costs		9,569,985		(46,593,511)		(7,363,224)
Extensions and discoveries		34,327,400		44,308,910		54,101,830
Revisions of quantity estimates		(51,375,950)		(3,235,695)		(3,150,420)
Acquisitions (divestitures) of reserves-in-place		-		102,945,609		2,198,612
Accretion of discount		37,000,855		17,646,314		11,473,819
Net change in income taxes		102,592,290		(90,457,070)		(27,464,341)
Change in timing and other, net		(8,609,940)		(19,507,493)		4,103,563
Net change		(123,191,293)		103,107,608		34,260,608
End of year	$	81,591,211	$	204,782,504	$	101,674,896