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The following Management’s Discussion and Analysis (“MD&A”) of Financial Condition and Results of Operations should be read in conjunction with a review of Part II, Item 8 - Revised Financial Statements and Supplementary Data included in Exhibit 99.3. Certain statements contained in this MD&A may be deemed to be forward-looking statements. See “Safe Harbor Statement” included in our Annual Report on Form 10-K filed with the Securities and Exchange Commission (“SEC”) on December 12, 2016.

The Company’s principal line of business is to explore for, develop, acquire, produce and sell oil, NGL and natural gas. Results of operations are dependent primarily upon the Company’s: existing reserve quantities; costs associated with acquiring, exploring for and developing new reserves; production quantities and related production costs; and oil, NGL and natural gas sales prices.

Fiscal 2016 oil, NGL and natural gas production decreased 20%, 19% and 15%, respectively, from that of 2015. The decrease in oil production was primarily the result of the production decline in the Eagle Ford Shale, which was not offset by new production in the play due to significantly reduced drilling activity. To a lesser extent, declining production from various fields in western Oklahoma, the Texas Panhandle and the Northern Oklahoma Mississippian contributed to the decrease. NGL production volume decreases were largely the result of production decline in the Anadarko Woodford Shale in western and central Oklahoma and the Anadarko Basin Granite Wash in western Oklahoma and the Texas Panhandle. Natural gas production volume decreases were primarily the result of declining production in the Fayetteville Shale. To a lesser extent, declining production from the Anadarko Basin Granite Wash and the southeastern Oklahoma Woodford Shale also contributed to the decrease.

As of September 30, 2016, the Company owned an average 3.5% net revenue interest in 45 wells that were drilling or testing.

The 2016 production decreases in oil, NGL and natural gas, combined with lower oil, NGL and natural gas prices, resulted in a 42% decrease in revenues from the sale of oil, NGL and natural gas. Based on recent forward strip pricing, the Company currently anticipates 2017 average oil, NGL and natural gas prices will be higher than their corresponding average prices in 2016.

The Company’s proved developed oil, NGL and natural gas reserves decreased in 2016, compared to 2015, by 26.7 Bcfe, or 25%. The decrease was primarily due to negative pricing revisions.

Other than the lease of office space, the Company had no off balance sheet arrangements during 2016 or prior years.

	For the Year Ended September 30,
		Percent		Percent
	2016	Incr. or (Decr.)	2015	Incr. or (Decr.)	2014
Production:
Oil (Bbls)	364,252	(20%)	453,125	31%	346,387
NGL (Bbls)	171,060	(19%)	210,960	2%	207,688
Natural Gas (Mcf)	8,284,377	(15%)	9,745,223	(10%)	10,773,559
Mcfe	11,496,249	(16%)	13,729,733	(3%)	14,098,009
Average Sales Price:
Oil (per Bbl)	$36.70	(31%)	$53.12	(43%)	$93.68
NGL (per Bbl)	$12.60	(31%)	$18.25	(44%)	$32.31
Natural Gas (per Mcf)	$1.92	(30%)	$2.73	(33%)	$4.05
Mcfe	$2.73	(31%)	$3.97	(32%)	$5.88

The Company recorded net loss of $10,286,884, or $0.61 per share, in 2016, compared to net income of $9,321,341, or $0.56 per share, in 2015. Revenues decreased in 2016 primarily due to lower oil, NGL and natural gas sales and decreased gains on derivative contracts partially offset by increased lease bonuses received.

Expenses increased in 2016 mainly from a larger provision for impairment and higher DD&A partially offset by a decrease in LOE and production taxes and an increase in gain on sale of assets.

Oil, NGL and natural gas sales decreased $23,122,561, or 42%, for 2016, as compared to 2015. The decrease was due to decreased oil, NGL and natural gas prices of 31%, 31% and 30%, respectively, coupled with lower oil, NGL and natural gas volumes of 20%, 19% and 15%, respectively, in 2016.

The decrease in oil production was primarily the result of natural production decline in the Eagle Ford Shale, which was not offset by new production in the play due to significantly reduced drilling activity. To a lesser extent, declining production from various fields in western Oklahoma, the Texas Panhandle and the Northern Oklahoma Mississippian contributed to the decrease.

NGL production volume decreases were largely the result of natural production decline in the Anadarko Woodford Shale in western and central Oklahoma and the Anadarko Basin Granite Wash in western Oklahoma and the Texas Panhandle.

Natural gas production volume decreases were primarily the result of naturally declining production in the Fayetteville Shale. To a lesser extent, declining production from the Anadarko Basin Granite Wash and the southeastern Oklahoma Woodford Shale also contributed to the decrease.

	2016		2015
First quarter		3,143,400		3,737,483
Second quarter		2,786,303		3,455,265
Third quarter		2,887,821		3,315,899
Fourth quarter		2,678,725		3,221,086
Total		11,496,249		13,729,733

Lease bonuses and rentals increased $5,725,390 in 2016. The increase was mainly due to the Company leasing 4,057 net mineral acres in Cochran County, Texas, 663 net mineral acres in Blaine, Canadian, Custer and Dewey Counties, Oklahoma, and 706 net mineral acres in Grady and McClain Counties, Oklahoma, in 2016. In 2015, the Company leased 2,407 net mineral acres in Andrews and Winkler Counties, Texas.

Gains on derivative contracts decreased $13,908,861 in 2016. The decrease was mainly due to the oil and, to a lesser extent, natural gas collars and fixed price swaps being more beneficial in 2015, as NYMEX oil and natural gas futures had fallen further below the floor of the collars and the fixed prices of the swaps. As of September 30, 2016, the Company’s natural gas costless collar contracts and natural gas fixed price swaps have expiration dates of October 2016 through December 2017; the oil costless collar contracts have expiration dates of October 2016 through March 2017.

Income from partnerships decreased $512,878 in 2016. This change was primarily due to the Company selling the assets from some of its partnerships in 2016. This was also coupled with lower oil, NGL and natural gas pricing during 2016, as compared to 2015.

LOE decreased $3,882,319 or 22% in 2016. LOE costs per Mcfe of production decreased from $1.27 in 2015 to $1.18 in 2016. The total LOE decrease was largely due to decreased field operating costs of $2,604,510 in 2016, compared to 2015. Field operating costs were $.70 per Mcfe in 2016, compared to $.78 per Mcfe in 2015, a 10% decrease. This decrease in rate was principally the result of operating efficiencies gained in the Eagle Ford Shale field due to the addition of a salt water disposal system and electrification of the field, as well as fewer workovers.

The decrease in LOE related to field operating costs was coupled with a decrease in handling fees (primarily gathering, transportation and marketing costs) of $1,277,809 in 2016, as compared to 2015. The decrease in the amount in 2016 is the result of decreased oil, NGL and natural gas production and sales. On a per Mcfe basis, these fees decreased $.01. Natural gas sales bear the large majority of the handling fees. Handling fees are charged either as a percent of sales or based on production volumes.

Production taxes decreased $630,670 or 37% in 2016, as compared to 2015. The decrease in amount was primarily the result of decreased oil, NGL and natural gas sales of $23,122,561 during 2016. Production taxes as a percentage of oil, NGL and natural gas sales increased slightly from 3.1% in 2015 to 3.4% in 2016. The increase in tax rate was the result of the expiration of production tax discounts on some of the Company’s horizontally drilled wells in Oklahoma and Arkansas, as well as the increased proportionate sales coming from Texas and North Dakota, where initial tax rates are higher. The low overall production tax rate in both years was due to a large proportion of the Company’s oil and natural gas revenues coming from horizontally drilled wells, which are eligible for reduced Oklahoma and Arkansas production tax rates in the first few years of production.

DD&A increased $666,426 in 2016. DD&A per Mcfe was $2.13 in 2016, compared to $1.74 in 2015. DD&A increased $4,541,529 as the result of a $.39 increase in the DD&A rate. This rate increase was principally due to lower oil, NGL and natural gas prices utilized in the reserve calculations during 2016, as compared to 2015, shortening the economic life of wells thus resulting in lower projected remaining reserves on a significant number of wells causing increased units of production DD&A. An offsetting decrease of $3,875,103 was due to oil, NGL and natural gas production volumes decreasing 16% collectively in 2016, compared to 2015.

Provision for impairment increased $6,992,080 in 2016, as compared to 2015. During 2016, impairment of $12,001,271 was recorded on 44 fields primarily in Oklahoma, Kansas and Texas. Two fields in western Oklahoma and the Texas Panhandle accounted for $7,548,533 or 63% of the impairment due mainly to declining oil, NGL and natural gas prices. During 2015, impairment of $5,009,191 was recorded on 27 fields primarily in Oklahoma, Kansas and Texas. One oil field in Hemphill County, Texas, accounted for $1,846,488 of the impairment due mainly to declining oil prices.

Loss (gain) on asset sales and other was a net gain of $2,624,642 in 2016, as compared to a net gain of $398,994 in 2015. The net gain in 2016 was largely due to the gain on sale of assets from two of the Company’s partnerships. The net gain in 2015 was mainly the result of a lawsuit settlement related to participation rights on some of the Company’s mineral acreage in Arkansas.

Interest expense decreased $205,864 in 2016, as compared to 2015. The decrease was due to a lower outstanding debt balance in 2016.

G&A decreased $199,592 in 2016, as compared to 2015. This decrease was primarily the result of lower legal and technical consulting fees in 2016.

The 2016 benefit for income taxes of $7,711,000 was based on a pre-tax loss of $17,997,884, as compared to a provision for income taxes of $4,836,000 in 2015, based on a pre-tax income of $14,157,341. The effective tax rate for 2016 was 43%, compared to an effective tax rate for 2015 of 34%. When a provision for income taxes is recorded, federal and Oklahoma excess percentage depletion decreases the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is recorded, as was the case in 2016.

The Company recorded net income of $9,321,341, or $0.56 per share, in 2015, compared to net income of $25,001,462, or $1.49 per share, in 2014. Revenues decreased in 2015 primarily due to lower oil, NGL and natural gas sales, partially offset by increased gains on derivative contracts and increased lease bonuses received.

Expenses increased in 2015 due mainly to higher LOE, DD&A, interest expense and provision for impairment, partially offset by a decrease in production taxes and an increase in other miscellaneous income.

Oil, NGL and natural gas sales decreased $28,312,614, or 34%, for 2015, as compared to 2014. The decrease was due to decreased oil, NGL and natural gas prices of 43%, 44% and 33%, respectively coupled with lower gas volumes of 10%, offset by increased oil and NGL volumes of 31% and 2%, respectively, in 2015.

The oil production volume increase was primarily the result of the Company’s acquisition of producing properties in the Eagle Ford Shale in South Texas in June 2014 and the associated horizontal drilling on that leasehold. To a lesser extent, Woodford Shale drilling in the Anadarko Basin in western and southern Oklahoma and drilling in the Bakken Shale in North Dakota contributed to the increase. The increase in oil production volumes during 2015 was partially offset by naturally declining oil production from the Company’s properties in Oklahoma and the Texas Panhandle.

The NGL production volume increase was primarily the result of Woodford Shale drilling in the Anadarko Basin in western and southern Oklahoma, the Eagle Ford Shale acquisition and subsequent drilling and drilling in the Bakken Shale in North Dakota. The increase in NGL production volumes during 2015 was largely offset by naturally declining NGL production from the Company’s properties in Oklahoma and the Texas Panhandle.

The natural gas production volume decrease was largely the result of naturally declining production in the Fayetteville Shale, which was not offset by new production in the play due to significantly reduced drilling activity. Declining production from several of the Company’s properties in western Oklahoma and the Texas Panhandle, as well as from the southeastern Oklahoma Woodford, also contributed to the decrease. Lower production volumes were partially offset by production increases in the Anadarko Basin Woodford in western and southern Oklahoma and the Eagle Ford Shale in South Texas.

	2015		2014
First quarter		3,737,483		3,509,270
Second quarter		3,455,265		3,496,222
Third quarter		3,315,899		3,309,394
Fourth quarter		3,221,086		3,783,123
Total		13,729,733		14,098,009

Lease bonuses and rentals increased $1,587,067 in 2015. The increase was mainly due to the Company leasing 2,407 net mineral acres in Andrews and Winkler Counties, Texas, for $1.2 million. There were no significant leases of the Company’s mineral acreage in 2014.

Gains on derivative contracts increased $13,575,092 in 2015. The increase in gains was mainly due to the oil and natural gas collars and fixed price swaps being more beneficial in 2015, as NYMEX oil and natural gas futures had fallen further below the floor of the collars and the fixed prices of the swaps. As of September 30, 2015, the Company’s natural gas costless collar contracts have expiration dates of October and December 2015; the oil costless collar contracts and the oil fixed price swaps have an expiration date of December 2015.

LOE increased $3,559,616 or 26% in 2015. LOE costs per Mcfe of production increased from $0.99 in 2014 to $1.27 in 2015. The total LOE increase was primarily due to increased field operating costs of $3,598,103 in 2015, compared to 2014. Field operating costs increased mainly due to the acquisition of the Eagle Ford Shale properties and additional wells drilled in late 2014 and during 2015. Field operating costs were $.78 per Mcfe in 2015, compared to $.50 per Mcfe in 2014, a 56% increase. This increase in rate was principally the result of the significant number

of oil and NGL rich wells drilled in recent years. These wells have higher lifting costs than our overall well population, which is and has been heavily gas weighted for several years.

The increase in LOE related to field operating costs was partially offset by a decrease in handling fees (primarily gathering, transportation and marketing costs) on natural gas of $38,487 in 2015, as compared to 2014. On a per Mcfe basis, these fees increased $.01 due to increased fees in areas that are currently being drilled. Natural gas sales bear the large majority of the handling fees. Handling fees are charged either as a percent of sales or based on production volumes.

Production taxes decreased $991,816 or 37% in 2015, as compared to 2014. The decrease in amount was primarily the result of decreased oil, NGL and natural gas sales of $28,312,614 during 2015. Production taxes as a percentage of oil, NGL and natural gas sales decreased slightly from 3.3% in 2014 to 3.1% in 2015. The low overall production tax rate was due to a large proportion of the Company’s oil and natural gas revenues coming from horizontally drilled wells, which are eligible for reduced Oklahoma and Arkansas production tax rates.

DD&A increased $1,924,237 in 2015. DD&A per Mcfe was $1.74 in 2015, compared to $1.55 in 2014. DD&A increased $2,496,240 as the result of a $.19 increase in the DD&A rate. This rate increase was principally due to higher per Mcfe finding costs experienced in oil and liquids rich areas where the Company has added production, as well as much lower oil, NGL and natural gas prices utilized in the reserve calculations during 2015, as compared to 2014, resulting in lower projected remaining reserves on a significant number of wells. An offsetting decrease of $572,003 was due to oil, NGL and natural gas production volumes decreasing 3% collectively in 2015, compared to 2014.

Provision for impairment increased $3,913,115 in 2015, as compared to 2014. During 2015, impairment of $5,009,191 was recorded on 27 fields primarily in Oklahoma, Kansas and Texas. One oil field in Hemphill County, Texas, accounted for $1,846,488 of the impairment due mainly to declining oil prices. During 2014, impairment of $1,096,076 was primarily recorded on 10 small fields in Oklahoma and Texas.

Loss (gain) on asset sales and other was a net gain of $398,994 in 2015, as compared to a net loss of $8,378 in 2014. The net gain in 2015 was mainly the result of a lawsuit settlement of approximately $331,000 related to participation rights on some of the Company’s mineral acreage in Arkansas. The net loss in 2014 was primarily the result of a loss on the sale of marginal properties partially offset by higher interest income from operators.

Interest expense increased $1,088,187 in 2015, as compared to 2014. The increase was primarily due to a larger average outstanding debt balance in 2015. The debt was used to purchase the Eagle Ford Shale properties on June 17, 2014.

The 2015 provision for income taxes of $4,836,000 was based on a pre-tax income of $14,157,341, as compared to a provision for income taxes of $11,820,000 in 2014, based on a pre-tax income of $36,821,462. The effective tax rate for 2015 was 34%, compared to an effective tax rate for 2014 of 32%. The Company’s utilization of excess percentage depletion, which is a permanent tax benefit, decreased the provision for income taxes and reduced the effective tax rate below the statutory rate for both years.

At September 30, 2016, the Company had positive working capital of $2,098,460, as compared to positive working capital of $8,907,437 at September 30, 2015.

Cash and cash equivalents were $471,213 as of September 30, 2016, compared to $603,915 at September 30, 2015, a decrease of $132,702. Cash flows for the 12 months ended September 30 are summarized as follows:

Net cash provided (used) by:
	2016			2015			Change
Operating activities	$	22,639,151		$	47,624,914		$	(24,985,763	)
Investing activities		565,617			(31,642,385	)		32,208,002
Financing activities		(23,337,470	)		(15,888,369	)		(7,449,101	)
Increase (decrease) in cash and cash equivalents	$	(132,702	)	$	94,160		$	(226,862	)

Net cash provided by operating activities decreased $24,985,763 during 2016, as compared to 2015, the result of the following:

Net cash used in investing activities decreased $32,208,002 during 2016, as compared to 2015, due to:

Net cash used in financing activities increased $7,449,101 during 2016, as compared to 2015, the result of the following:

Capital expenditures to drill and complete wells decreased $26,814,390 (87%) in 2016, as compared to 2015. In the Eagle Ford Shale oil play in South Texas and in the Arkansas Fayetteville Shale natural gas play there was very limited drilling activity on the Company’s acreage in 2016. The Company received 58 well proposals in fiscal 2016, and working interest participation decisions were as follows: 20 wells met the Company’s participation criteria and elections were made to participate; 34 wells did not meet participation criteria with no participation elected; and 4 wells did not meet participation criteria, but election was made to participate with only one acre, in order to receive well information. The drilling activity decrease resulted in the 87% decline in capital expenditures.

Drilling began in August 2016 and continues into fiscal 2017 on the eight wells proposed on Company owned mineral acres in the southeast Oklahoma Woodford Shale play. The Company agreed to participate in these wells with an average 20% working interest, which combined with the royalty interest to be received on the portion of the minerals leased, will average net revenue interests of 27.4%. The Company’s capital obligation to drill and complete these eight wells is approximately $7.4 million. Completion of all eight wells is projected to be in the second quarter of fiscal 2017.

Panhandle recently received notice from an operator in the core of the STACK/CANA play of their plans to drill six wells in one unit beginning in December 2016. Panhandle has elected to participate with 17.5% working interest and a 16.25% net revenue interest in these six

Woodford Shale wells. The operator plans to drill the wells with two rigs and projects will begin producing early in the third fiscal quarter of 2017.

Pad drilling is scheduled to resume on our Eagle Ford leasehold acreage in our second fiscal quarter of 2017. The operator plans to move in one rig and drill a ten-well program. This activity should occur over a roughly six to seven month period. Panhandle will have 16% working interest in six of the wells that are entirely located on our acreage and approximately 8.2% working interest in the other four that are roughly half on our acreage.

Activity from these three plays is expected to significantly increase our capital expenditures in fiscal 2017 compared to fiscal 2016. Capital expenditures on these wells in fiscal 2017 are expected to be partially funded by utilization of the Company’s credit facility.

Oil, NGL and natural gas production volumes decreased 16% on an Mcfe basis during 2016, as compared to 2015. Low drilling activity during 2016 resulted in new production coming on line falling considerably short of replacing the natural decline of existing wells.

Oil production decreased 20%, primarily the result of the production decline in the Eagle Ford Shale, which was not offset by new production in the play due to significantly reduced drilling activity. Declining production from various fields in western Oklahoma, the Texas Panhandle and the Northern Oklahoma Mississippian also contributed to the decrease, to a lesser extent.

NGL production decreased 19%, largely the result of production decline in the Anadarko Woodford Shale in western and central Oklahoma and the Anadarko Basin Granite Wash in western Oklahoma and the Texas Panhandle.

Natural gas production decreased 15%, principally due to declining production in the Fayetteville Shale. To a lesser extent, declining production from the Anadarko Basin Granite Wash and the southeastern Oklahoma Woodford Shale also contributed to the decrease.

As of September 30, 2016, the Company owned an average 3.5% net revenue interest in 45 wells that were drilling or testing. Of these 45 wells, only four of the southeast Oklahoma Woodford Shale wells are included as the other four had not yet begun drilling.

Since the Company is not the operator of any of its oil and natural gas properties, it is extremely difficult for us to predict levels of future participation in the drilling and completion of new wells and their associated capital expenditures. This makes 2017 capital expenditures for drilling and completion projects difficult to forecast.

The Company received lease bonus payments during 2016 totaling approximately $8 million. The Company has also received $4.5 million during 2016 from the sale of properties. Cash provided by these and other operating activities allowed the Company to fund all overhead costs, capital expenditures, treasury stock purchases and dividend payments, while also reducing the Company’s outstanding borrowings on the credit facility by $20.5 million during 2016. Looking forward, the cash flow benefit from bonus payments associated with the leasing of drilling rights on the Company’s mineral acreage is very difficult to project as the Company’s mineral acreage position is so diverse and spread across several states. However, management

will continue to strategically evaluate the merit of leasing certain of the Company’s mineral acres.

With continued oil and natural gas price volatility, management continues to evaluate opportunities for product price protection through additional hedging of the Company’s future oil and natural gas production. See Note 1 to the financial statements included in Exhibit 99.3 attached to this Form 8-K for a complete list of the Company’s outstanding derivative contracts.

The use of the Company’s cash provided by operating activities and resultant change to cash is summarized in the table below:

	Twelve months ended
	9/30/2016
Cash provided by operating activities	$	22,639,151
Cash used for (provided by):
Capital expenditures - drilling and completion of wells		3,986,235
Quarterly dividends of $.04 per share		2,677,305
Treasury stock purchases		117,165
Net payments (borrowings) on credit facility		20,500,000
Proceeds from sales of assets		(4,501,726	)
Other investing activities		(7,126	)
Net cash used		22,771,853
Net increase (decrease) in cash	$	(132,702	)

Outstanding borrowings on the credit facility at September 30, 2016, were $44,500,000.

Looking forward, the Company intends to fund overhead costs, capital additions related to the drilling and completion of wells, treasury stock purchases, if any, and dividend payments primarily from cash provided by operating activities, cash on hand and borrowings utilizing our bank credit facility. Any excess cash is intended to be used to reduce existing bank debt. The Company had availability ($35,500,000 at September 30, 2016) under its revolving credit facility and was in compliance with its debt covenants (current ratio, debt to trailing 12 month EBITDA, as defined, and dividends as a percent of operating cash flow). Non-cash expenses (such as impairment) are excluded from the EBITDA calculation. The debt covenants require a maximum ratio of the Company’s debt to EBITDA of 4:1. As of September 30, 2016, the debt to EBITDA ratio was 1.82:1.

The borrowing base under the credit facility was redetermined in December 2016 and left unchanged at $80 million, which is a level that is expected to provide ample liquidity for the Company to continue to employ its normal operating strategies.

Based on expected capital expenditure levels, anticipated cash provided by operating activities for 2017, combined with availability under its credit facility, the Company has sufficient liquidity to fund its ongoing operations.

The Company has a credit facility with a group of banks headed by Bank of Oklahoma (BOK) consisting of a revolving loan of $200,000,000, which is subject to a semi-annual borrowing base determination. The current borrowing base is $80,000,000 and is secured by certain of the Company’s properties with a carrying value of $166,720,207 at September 30, 2016. The revolving loan matures on November 30, 2018. Borrowings under the revolving loan are due at maturity. The revolving loan bears interest at the BOK prime rate plus a range of 0.375% to 1.125%, or 30 day LIBOR plus a range of 1.875% to 2.625% annually. At September 30, 2016, the effective rate was 2.73%. The election of BOK prime or LIBOR is at the Company’s discretion. The interest rate spread from LIBOR or the prime rate increases as a larger percent of the loan value of the Company’s oil and natural gas properties is advanced.

Determinations of the borrowing base are made semi-annually, whenever BOK believes there has been a material change in the value of the Company’s oil and natural gas properties or upon reasonable request by the Company. The loan agreement contains customary covenants, which, among other things, require periodic financial and reserve reporting and limit the Company’s incurrence of indebtedness, liens, dividends and acquisitions of treasury stock and require the Company to maintain certain financial ratios. At September 30, 2016, the Company was in compliance with these covenants and projects compliance during 2017.

The table below summarizes the Company’s contractual obligations and commitments as of September 30, 2016:

	Payments due by period
Contractual Obligations			Less than						More than
and Commitments	Total		1 Year		1-3 Years		3-5 Years		5 Years
Long-term debt obligations	$	44,500,000	$	-	$	44,500,000	$	-	$	-
Building lease	$	743,686	$	204,089	$	416,938	$	122,659	$	-

The Company’s building lease is accounted for as an operating lease and therefore the leased asset and associated liabilities of future rent payments are not included on the Company’s balance sheets.

At September 30, 2016, the Company’s derivative contracts were in a net liability position of $428,271. The ultimate settlement amounts of the derivative contracts are unknown because they are subject to continuing market risk. Please read Item 7A – “Quantitative and Qualitative Disclosures about Market Risk” and Note 1 to the financial statements included in Exhibit 99.3 attached to this Form 8-K for additional information regarding the derivative contracts.

As of September 30, 2016, the Company’s estimate for asset retirement obligations was $2,958,048. Asset retirement obligations represent the Company’s share of the future expenditures to plug and abandon the wells in which the Company owns a working interest at the end of their economic lives. These amounts were not included in the schedule above due to the uncertainty of timing of the obligations. Please read Note 1 to the financial statements included

in Exhibit 99.3 attached to this Form 8-K for additional information regarding the Company’s asset retirement obligations.

Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. However, the accounting principles used by the Company generally do not change the Company’s reported cash flows or liquidity. Existing rules must be interpreted and judgments made on how the specifics of a given rule apply to the Company.

The more significant reporting areas impacted by management’s judgments and estimates are: crude oil, NGL and natural gas reserve estimation; derivative contracts; impairment of assets; oil, NGL and natural gas sales revenue accruals; refundable production taxes and provision for income taxes. Management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists, consultants and historical experience in similar matters. Actual results could differ from the estimates as additional information becomes known. The oil, NGL and natural gas sales revenue accrual is particularly subject to estimate inaccuracies due to the Company’s status as a non-operator on all of its properties. As such, production and price information obtained from well operators is substantially delayed. This causes the estimation of recent production and prices used in the oil, NGL and natural gas revenue accrual to be subject to future change.

Management considers the estimation of the Company’s crude oil, NGL and natural gas reserves to be the most significant of its judgments and estimates. These estimates affect the unaudited standardized measure disclosures included in Note 11 to the financial statements included in Exhibit 99.3 attached to this Form 8-K as well as DD&A and impairment calculations. Changes in crude oil, NGL and natural gas reserve estimates affect the Company’s calculation of DD&A, asset retirement obligations and assessment of the need for asset impairments. On an annual basis, with a semi-annual update, the Company’s Independent Consulting Petroleum Engineer, with assistance from Company staff, prepares estimates of crude oil, NGL and natural gas reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing prices which are updated through the current period. In accordance with the SEC rules, the reserve estimates were based on average individual product prices during the 12-month period prior to September 30 determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices were defined by contractual arrangements, excluding escalations based upon future conditions. Based on the Company’s 2016 DD&A, a 10% change in the DD&A rate per Mcfe would result in a corresponding $2,448,757 annual change in DD&A expense. Crude oil, NGL and natural gas prices are volatile and largely affected by worldwide production and consumption and are

outside the control of management. However, projected future crude oil, NGL and natural gas pricing assumptions are used by management to prepare estimates of crude oil, NGL and natural gas reserves and future net cash flows used in asset impairment assessments and in formulating management’s overall operating decisions.

The Company has elected to utilize the successful efforts method of accounting for its oil and natural gas exploration and development activities. This means exploration expenses, including geological and geophysical costs, non-producing lease impairment, rentals and exploratory dry holes, are charged against income as incurred. Costs of successful wells and related production equipment and developmental dry holes are capitalized and amortized by property using the unit-of-production method (the ratio of oil, NGL and natural gas volumes produced to total proved or proved developed reserves is used to amortize the remaining asset basis on each producing property) as oil, NGL and natural gas is produced. The Company’s exploratory wells are all on-shore and primarily located in the Mid-Continent area. Generally, expenditures on exploratory wells comprise less than 10% of the Company’s total expenditures for oil and natural gas properties. This accounting method may yield significantly different operating results than the full cost method.

The Company has entered into oil and natural gas costless collar contracts and oil and natural gas fixed swap contracts. These instruments are intended to reduce the Company’s exposure to short-term fluctuations in the price of oil and natural gas. Collar contracts set a fixed floor price and a fixed ceiling price and provide payments to the Company if the index price falls below the floor or require payments by the Company if the index price rises above the ceiling. Fixed swap contracts set a fixed price and provide for payments to the Company if the index price is below the fixed price, or require payments by the Company if the index price is above the fixed price. These contracts cover only a portion of the Company’s oil and natural gas production and provide only partial price protection against declines in oil and natural gas prices. These derivative instruments expose the Company to risk of financial loss and may limit the benefit of future increases in prices. All of the Company’s derivative contracts are with Bank of Oklahoma and are secured under its credit facility with Bank of Oklahoma.

The Company is required to recognize all derivative instruments as either assets or liabilities in the balance sheet at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and resulting designation. At September 30, 2016, the Company had no derivative contracts designated as cash flow hedges, and therefore, changes in the fair value of derivatives are reflected in earnings.

All long-lived assets, principally oil and natural gas properties, are monitored for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its estimated future net cash flows. The evaluations involve significant judgment, since the results are based on estimated future events, such as: inflation rates; future sales prices

for oil, NGL and natural gas; future production costs; estimates of future oil, NGL and natural gas reserves to be recovered and the timing thereof; economic and regulatory climates and other factors. The Company estimates future net cash flows on its oil and natural gas properties utilizing differentially adjusted forward pricing curves for oil, NGL and natural gas and a discount rate in line with the discount rate we believe is most commonly used by market participants (10% for all periods presented). The need to test a property for impairment may result from significant declines in sales prices or unfavorable adjustments to oil, NGL and natural gas reserves. A further reduction in oil, NGL and natural gas prices (which are reviewed quarterly) or a decline in reserve volumes (which are re-evaluated semi-annually) would likely lead to additional impairment that may be material to the Company. Should product price expectations decline below levels seen at September 30, 2016, in future periods, impairment charges significantly greater than the Company has incurred in prior periods could result. Any assets held for sale are reviewed for impairment when the Company approves the plan to sell. Estimates of anticipated sales prices are highly judgmental and subject to material revision in future periods. Because of the uncertainty inherent in these factors, the Company cannot predict when or if future impairment charges will be recorded.

Non-producing oil and natural gas leases are assessed for impairment on a property-by-property basis for individually significant balances and on an aggregate basis for individually insignificant balances. If the assessment indicates an impairment, a loss is recognized by providing a valuation allowance at the level at which impairment was assessed. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms and potential shifts in business strategy employed by management. In the case of individually insignificant balances, the amount of the impairment loss recognized is determined by amortizing the portion of these properties’ costs, which the Company believes will not be transferred to proved properties over the remaining lives of the leases. Impairment loss is charged to exploration costs when recognized. As of September 30, 2016, the remaining carrying cost of non-producing oil and natural gas leases was $153,884.

The Company does not operate its oil and natural gas properties and, therefore, receives actual oil, NGL and natural gas sales volumes and prices (in the normal course of business) more than a month later than the information is available to the operators of the wells. This being the case, on wells with greater significance to the Company, the most current available production data is gathered from the appropriate operators, and oil, NGL and natural gas index prices local to each well are used to estimate the accrual of revenue on these wells. Obtaining timely production data on all other wells from the operators is not feasible; therefore, the Company utilizes past production receipts and estimated sales price information to estimate its accrual of revenue on all other wells each quarter. The oil, NGL and natural gas sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for oil, NGL and natural gas. These variables could lead to an over or under accrual of oil, NGL and natural gas sales at the end of any particular quarter. Based on past history, the Company’s estimated accruals have been materially accurate.

The estimation of the amounts of income tax to be recorded by the Company involves interpretation of complex tax laws and regulations, as well as the completion of complex calculations, including the determination of the Company’s percentage depletion deduction, if any. To calculate the exact excess percentage depletion allowance, a well-by-well calculation is, and can only be, performed at the end of each fiscal year. During interim periods, an estimate is made taking into account historical data and current pricing. The Company has certain state net operating loss carry forwards (NOLs) that are recognized as tax assets when assessed as more likely than not to be utilized before their expiration dates. Criteria such as expiration dates, future excess state depletion and reversing taxable temporary differences are evaluated to determine whether the NOLs are more likely than not to be utilized before they expire. If any NOLs are determined to no longer be more likely than not to be utilized, then a valuation allowance is recognized to reduce the tax benefit of such NOLs. As of September 30, 2016, the Company had no valuation allowances on NOLs. Although the Company’s management believes its tax accruals are adequate, differences may occur in the future depending on the resolution of pending and new tax matters.

The above description of the Company’s critical accounting policies is not intended to be an all-inclusive discussion of the uncertainties considered and estimates made by management in applying generally accepted accounting principles and policies. Results may vary significantly if different policies were used or required and if new or different information becomes known to management.

Oil, NGL and natural gas prices historically have been volatile, and this volatility is expected to continue. Uncertainty continues to exist as to the direction of oil, NGL and natural gas price trends, and there remains a wide divergence in the opinions held in the industry. The Company can be significantly impacted by changes in oil and natural gas prices. The market price of oil, NGL and natural gas in 2017 will impact the amount of cash generated from operating activities, which will in turn impact the level of the Company’s capital expenditures and production. Excluding the impact of the Company’s 2017 derivative contracts (see below), the price sensitivity for each $0.10 per Mcf change in wellhead natural gas price is approximately $828,438 for operating revenue based on the Company’s prior year natural gas volumes. The price sensitivity in 2017 for each $1.00 per barrel change in wellhead oil is approximately $364,252 for operating revenue based on the Company’s prior year oil volumes.

The Company periodically utilizes derivative contracts to reduce its exposure to unfavorable changes in natural gas and oil prices. The Company does not enter into these derivatives for speculative or trading purposes. All of our outstanding derivative contracts are with Bank of Oklahoma and are secured. These arrangements cover only a portion of the

Company’s production and provide only partial price protection against declines in natural gas and oil prices. These derivative contracts expose the Company to risk of financial loss and limit the benefit of future increases in prices. For the Company’s natural gas fixed price swaps, a change of $.10 in the NYMEX Henry Hub forward strip pricing would result in a change to pre-tax operating income of approximately $146,000. For the Company’s natural gas collars, a change of $.10 in the NYMEX Henry Hub forward strip pricing would result in a change to pre-tax operating income of approximately $247,000. For the Company’s oil collars, a change of $1.00 in the NYMEX WTI forward strip prices would result in a change to pre-tax operating income of approximately $51,000. See Note 1 to the financial statements included in Exhibit 99.3 attached to this Form 8-K for additional information regarding the derivative contracts.

Operating income could also be impacted, to a lesser extent, by changes in the market interest rates related to the Company’s credit facility. The revolving loan bears interest at the BOK prime rate plus from 0.375% to 1.125%, or 30 day LIBOR plus from 1.875% to 2.625%. At September 30, 2016, the Company had $44,500,000 outstanding under this facility and the effective interest rate was 2.73%. At this point, the Company does not believe that its liquidity has been materially affected by the debt market uncertainties noted in the last few years and the Company does not believe that its liquidity will be impacted in the near future.