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:

	2016			2015

Producing properties	$	434,469,093		$	441,141,337
Non-producing minerals		7,364,630			8,088,134
Non-producing leasehold		204,101			204,101
Exploratory wells in progress		5,917			1,762
		442,043,741			449,435,334
Accumulated depreciation, depletion and amortization		(251,004,735	)		(227,165,334	)
Net capitalized costs	$	191,039,006		$	222,270,000

Costs Incurred

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

	2016		2015		2014

Property acquisition costs	$	-	$	146,261	$	83,405,404
Exploration costs		21,049		898,818		2,013,231
Development costs		5,075,710		24,931,571		34,219,072
	$	5,096,759	$	25,976,650	$	119,637,707

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, 2016, 2015 and 2014.

The Company’s net proved oil, NGL and natural gas reserves, which are located in the contiguous United States (except for an insignificant amount of international overrides), as of September 30, 2016, 2015 and 2014, 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 30 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 (such as ownership interest, oil and gas production, well test data, commodity prices, operating costs and handling fees, and development costs) for all properties to our Independent Consulting Petroleum Engineers. 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, 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

Revisions of previous estimates		(1,552,010	)		(1,192,143	)		(47,068,144	)
Acquisitions (divestitures)		-			-			-
Extensions, discoveries and other additions		303,922			65,306			16,864,075
Production		(364,252	)		(171,060	)		(8,284,377	)
September 30, 2016		5,426,090			1,622,703			81,725,598

The prices used to calculate reserves and future cash flows from reserves for oil, NGL and natural gas, respectively, were as follows: September 30, 2016 - $36.77/Bbl, $12.22/Bbl, $1.97/Mcf; September 30, 2015 - $55.27/Bbl, $19.10/Bbl, $2.84/Mcf; September 30, 2014 - $96.94/Bbl, $31.45/Bbl, $4.04/Mcf.

The revisions of previous estimates from 2015 to 2016 were primarily the result of:

•

Negative pricing revisions of 64.4 Bcfe resulting from:

17.5 Bcfe of negative proved developed revisions primarily due to wells reaching their projected economic limits much earlier than projected in 2015.

46.9 Bcfe of negative PUD revisions principally attributable to the removal of PUD locations and associated reserves throughout the Company’s operating areas, primarily Fayetteville Shale and Anadarko Basin Woodford Shale, which are no longer projected to be developed within five years from the date they were added to the PUD reserves due to low commodity prices. The Company’s 2016 PUD locations now stand at 106, as compared to 409 PUD locations in 2015.

•

Positive performance revisions of .9 Bcfe.

Extensions, discoveries and other additions from 2015 to 2016 are principally attributable to:

•

Proved developed reserve extensions, discoveries and other additions of 2.5 Bcfe principally resulting from the Company’s participation in unconventional oil, NGL and natural gas in the Anadarko Woodford Shale in central and western Oklahoma and the Bakken Shale in North Dakota.

•

The addition of 16.6 Bcfe of PUD reserves principally in the southeastern Oklahoma Woodford. These southeastern Oklahoma Woodford additions are the PUD reserves assigned to eight wells the Company approved to drill in late 2016. Drilling operations are underway on four wells and all eight wells are projected to begin producing in early 2017.

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

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
September 30, 2016		1,980,519		1,095,256		62,929,047		3,445,571		527,447		18,796,551

The following details the changes in proved undeveloped reserves for 2016 (Mcfe):

Beginning proved undeveloped reserves	71,917,599
Proved undeveloped reserves transferred to proved developed	(1,806,525	)
Revisions	(44,108,114	)
Extensions and discoveries	16,631,699
Purchases	-
Ending proved undeveloped reserves	42,634,659

Beginning PUD reserves were 71.9 Bcfe. A total of 1.8 Bcfe (3% of the beginning balance) were transferred to proved developed producing during 2016. The 44.1 Bcfe (61% of the beginning balance) of negative revisions to PUD reserves is attributable to a 46.9 Bcfe negative PUD revisions principally attributable to the removal of PUD locations and associated reserves throughout the Company’s operating areas which are no longer projected to be developed within five years from the date they were added to the PUD reserves due to low commodity prices. These negative revisions were somewhat offset by a positive performance revisions of 2.8 Bcfe. A total of 45.9 Bcfe (64% of the beginning balance) of PUD reserves were moved out of the category during 2016 as either a result of being transferred to proved developed or removed due to low commodity prices. No PUD locations from 2012 remain in the PUD category and there are only two remaining PUD locations from 2013. The Company’s total PUD locations decreased from 409 in 2015 to 106 in 2016. As a point of reference, the Company participated in 58 wells in 2016, 35 of which were conversions from PUD to PDP. 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 PUD reserves will be removed as revisions at the time that determination is made. 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. The Company added 16.6 Bcfe of PUD reserves in 2016, principally in the southeastern Oklahoma Woodford. These southeastern Oklahoma Woodford Shale additions are the PUD reserves assigned to eight wells the Company approved to drill in late 2016. Drilling operations are underway on four wells, and all eight are projected to begin producing in early 2017.

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, NGL and natural gas 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.

	2016			2015			2014

Future cash inflows	$	380,263,695		$	786,295,155		$	1,405,400,261
Future production costs		(182,948,045	)		(311,933,151	)		(423,512,430	)
Future development and asset retirement costs		(72,431,842	)		(124,857,957	)		(146,465,509	)
Future income tax expense		(38,674,100	)		(123,007,909	)		(308,149,182	)
Future net cash flows		86,209,708			226,496,138			527,273,140

10% annual discount		(56,439,589	)		(144,904,927	)		(322,490,636	)
Standardized measure of discounted future net cash flows	$	29,770,119		$	81,591,211		$	204,782,504

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

	2016			2015			2014
Beginning of year	$	81,591,211		$	204,782,504		$	101,674,896
Changes resulting from:
Sales of oil, NGL and natural gas, net of production costs		(16,749,632	)		(35,359,204	)		(66,239,618	)
Net change in sales prices and production costs		(86,198,778	)		(211,336,729	)		164,240,162
Net change in future development and asset retirement costs		21,636,258			9,569,985			(46,593,511	)
Extensions and discoveries		11,640,704			34,327,400			44,308,910
Revisions of quantity estimates		(41,716,689	)		(51,375,950	)		(3,235,695	)
Acquisitions (divestitures) of reserves-in-place		-			-			102,945,609
Accretion of discount		14,424,032			37,000,855			17,646,314
Net change in income taxes		44,533,277			102,592,290			(90,457,070	)
Change in timing and other, net		609,736			(8,609,940	)		(19,507,493	)
Net change		(51,821,092	)		(123,191,293	)		103,107,608
End of year	$	29,770,119		$	81,591,211		$	204,782,504