phx-10k_20171106.htm

This exhibit does not reflect events occurring after the filing date of Panhandle Oil and Gas Inc.’s Annual Report on Form 10-K for the year ended September 30, 2016, other than to give effect to the reclassification of our proceeds from leasing fee mineral acreage on the Statements of Cash Flows and deferred income taxes on the Balance Sheets and does not modify or update the disclosures therein in anyway, other than described above.

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934 (the “Exchange Act”) as a process designed by, or under the supervision of, the Company’s principal executive and principal financial officers and effected by the Company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, and includes those policies and procedures that:

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. Internal control over financial reporting cannot provide absolute assurance of achieving financial reporting objectives because of its inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements may not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.

The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of September 30, 2016. In making this assessment, the Company’s management used the criteria set forth in Internal Control – Integrated Framework (as updated in 2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our assessment, management has concluded that, as of September 30, 2016, the Company’s internal control over financial reporting was effective based on those criteria.

Our independent registered public accounting firm has issued an attestation report on our internal control over financial reporting. This report appears on the following page.

We have audited Panhandle Oil and Gas Inc.’s internal control over financial reporting as of September 30, 2016, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). Panhandle Oil and Gas Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

In our opinion, Panhandle Oil and Gas Inc. maintained, in all material respects, effective internal control over financial reporting as of September 30, 2016, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheets of Panhandle Oil and Gas Inc. as of September 30, 2016 and 2015, and the related statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended September 30, 2016 and our report dated December 12, 2016 expressed an unqualified opinion thereon.

We have audited the accompanying balance sheets of Panhandle Oil and Gas Inc. (the Company) as of September 30, 2016 and 2015, and the related statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended September 30, 2016. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Panhandle Oil and Gas Inc. at September 30, 2016 and 2015, and the results of its operations and its cash flows for each of the three years in the period ended September 30, 2016, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Panhandle Oil and Gas Inc.’s internal control over financial reporting as of September 30, 2016, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated December 12, 2016, expressed an unqualified opinion thereon.

	September 30,
	2016			2015
Liabilities and Stockholders' Equity
Current Liabilities:
Accounts payable	$	2,351,623		$	2,028,746
Derivative contracts, net		403,612			-
Accrued liabilities and other		1,718,558			1,330,901
Total current liabilities		4,473,793			3,359,647

Long-term debt		44,500,000			65,000,000

Deferred income taxes		30,676,007			40,636,007

Asset retirement obligations		2,958,048			2,824,944

Derivative contracts, net		24,659			-

Stockholders' equity:
Class A voting common stock, $.0166 par value; 24,000,000 shares authorized; 16,863,004 issued at September 30, 2016 and 2015		280,938			280,938
Capital in excess of par value		3,191,056			2,993,119
Deferred directors' compensation		3,403,213			3,084,289
Retained earnings		112,482,284			125,446,473
		119,357,491			131,804,819

Treasury stock, at cost; 262,708 shares at September 30, 2016, and 302,623 shares at September 30, 2015		(4,165,672	)		(4,800,144	)
Total stockholders' equity		115,191,819			127,004,675

Total liabilities and stockholders' equity	$	197,824,326		$	238,825,273

	Year ended September 30,
	2016			2015			2014
Revenues:
Oil, NGL and natural gas sales	$	31,411,353		$	54,533,914		$	82,846,528
Lease bonuses and rentals		7,735,785			2,010,395			423,328
Gains (losses) on derivative contracts		(86,355	)		13,822,506			247,414
Income from partnerships		2,400			515,278			893,954
		39,063,183			70,882,093			84,411,224
Costs and expenses:
Lease operating expenses		13,590,089			17,472,408			13,912,792
Production taxes		1,071,632			1,702,302			2,694,118
Exploration costs		31,589			48,404			86,017
Depreciation, depletion and amortization		24,487,565			23,821,139			21,896,902
Provision for impairment		12,001,271			5,009,191			1,096,076
Loss (gain) on asset sales and other		(2,624,642	)		(398,994	)		8,378
Interest expense		1,344,619			1,550,483			462,296
General and administrative		7,139,728			7,339,320			7,433,183
Bad debt expense (recovery)		19,216			180,499			-
		57,061,067			56,724,752			47,589,762
Income (loss) before provision (benefit) for income taxes		(17,997,884	)		14,157,341			36,821,462
Provision (benefit) for income taxes		(7,711,000	)		4,836,000			11,820,000

Net income (loss)	$	(10,286,884	)	$	9,321,341		$	25,001,462


Basic and diluted earnings (loss) per common share	$	(0.61	)	$	0.56		$	1.49

	Class A voting				Capital in			Deferred
	Common Stock				Excess of			Directors'			Retained			Treasury			Treasury
	Shares		Amount		Par Value			Compensation			Earnings			Shares			Stock			Total
Balances at September 30, 2013		16,863,004	$	280,938	$	2,447,424		$	2,756,526		$	96,454,449			(400,496	)	$	(6,283,851	)	$	95,655,486

Purchase of treasury stock		-		-		-			-			-			(7,444	)		(122,044	)		(122,044	)
Issuance of treasury shares to ESOP		-		-		161,363			-			-			11,428			179,762			341,125
Restricted stock awards		-		-		659,320			-			-			-			-			659,320
Distribution of restricted stock to officers and directors		-		-		(406,764	)		-			-			24,148			367,966			(38,798	)
Common shares to be issued to directors for services		-		-		-			353,825			-			-			-			353,825
Dividends declared ($.16 per share)		-		-		-			-			(2,661,723	)		-			-			(2,661,723	)
Net income (loss)		-		-		-			-			25,001,462			-			-			25,001,462

Balances at September 30, 2014		16,863,004	$	280,938	$	2,861,343		$	3,110,351		$	118,794,188			(372,364	)	$	(5,858,167	)	$	119,188,653
Purchase of treasury stock		-		-		-			-			-			(12,719	)		(242,313	)		(242,313	)
Issuance of treasury shares to ESOP		-		-		3,437			-			-			11,455			181,676			185,113
Restricted stock awards		-		-		895,127			-			-			-			-			895,127
Distribution of restricted stock to officers and directors		-		-		(782,832	)		-			-			48,633			766,301			(16,531	)
Distribution of deferred directors' compensation		-		-		16,044			(328,415	)		-			22,372			352,359			39,988
Common shares to be issued to directors for services		-		-		-			302,353			-			-			-			302,353
Dividends declared ($.16 per share)		-		-		-			-			(2,669,056	)		-			-			(2,669,056	)
Net income (loss)		-		-		-			-			9,321,341			-			-			9,321,341

Balances at September 30, 2015		16,863,004	$	280,938	$	2,993,119		$	3,084,289		$	125,446,473			(302,623	)	$	(4,800,144	)	$	127,004,675
Purchase of treasury stock		-		-		-			-			-			(7,477	)		(117,165	)		(117,165	)
Issuance of treasury shares to ESOP		-		-		19,068			-			-			11,418			181,090			200,158
Restricted stock awards		-		-		781,479			-			-			-			-			781,479
Distribution of restricted stock to officers and directors		-		-		(601,779	)		-			-			35,257			559,175			(42,604	)
Distribution of deferred directors' compensation		-		-		(831	)		(10,541	)		-			717			11,372			-
Common shares to be issued to directors for services		-		-		-			329,465			-			-			-			329,465
Dividends declared ($.16 per share)		-		-		-			-			(2,677,305	)		-			-			(2,677,305	)
Net income (loss)		-		-		-			-			(10,286,884	)		-			-			(10,286,884	)

Balances at September 30, 2016		16,863,004	$	280,938	$	3,191,056		$	3,403,213		$	112,482,284			(262,708	)	$	(4,165,672	)	$	115,191,819

	Year ended September 30,
	2016			2015			2014
Operating Activities

Net income (loss)	$	(10,286,884	)	$	9,321,341		$	25,001,462
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization		24,487,565			23,821,139			21,896,902
Impairment		12,001,271			5,009,191			1,096,076
Provision for deferred income taxes		(9,960,000	)		2,672,000			6,610,000
Exploration costs		31,589			48,404			86,017
Gain from leasing fee mineral acreage		(7,732,023	)		(2,007,993	)		(422,818	)
Proceeds from leasing fee mineral acreage		8,049,434			2,053,900			477,144
Net (gain) loss on sales of assets		(2,688,408	)		-			149,062
Income from partnerships		(2,400	)		(515,278	)		(893,954	)
Distributions received from partnerships		33,201			736,280			1,129,324
Common stock contributed to ESOP		200,158			185,113			341,125
Common stock (unissued) to Directors' Deferred Compensation Plan		329,465			302,353			353,825
Restricted stock awards		781,479			895,127			659,320
Bad debt expense (recovery)		19,216			180,499			-
Cash provided (used) by changes in assets and liabilities:
Oil, NGL and natural gas sales receivables		2,589,146			8,151,379			(2,506,708	)
Fair value of derivative contracts		4,639,035			(2,308,922	)		(1,476,644	)
Refundable income taxes		262,023			(345,897	)		-
Refundable production taxes		476,001			149,995			576,537
Other current assets		(167,021	)		102,812			(224,830	)
Accounts payable		(811,749	)		(343,186	)		252,860
Income taxes payable		-			(523,843	)		(284,149	)
Accrued liabilities		388,053			40,500			279,195
Total adjustments		32,926,035			38,303,573			28,098,284
Net cash provided by operating activities		22,639,151			47,624,914			53,099,746

	Year ended September 30,
	2016			2015			2014
Investing Activities

Capital expenditures, including dry hole costs	$	(3,986,235	)	$	(30,800,625	)	$	(38,612,788	)
Acquisition of working interest properties		-			(308,180	)		(83,253,952	)
Acquisition of minerals and overrides		-			-			(56,250	)
Investments in partnerships		50,126			(533,580	)		(597,149	)
Proceeds from sales of assets		4,501,726			-			92,000
Net cash used in investing activities		565,617			(31,642,385	)		(122,428,139	)

Financing Activities

Borrowings under debt agreement		12,339,101			25,833,116			99,846,333
Payments of loan principal		(32,839,101	)		(38,833,116	)		(30,108,589	)
Purchases of treasury stock		(117,165	)		(242,313	)		(122,044	)
Payments of dividends		(2,677,305	)		(2,669,056	)		(2,661,723	)
Excess tax benefit on stock-based compensation		(43,000	)		23,000			17,000
Net cash provided by (used in) financing activities		(23,337,470	)		(15,888,369	)		66,970,977
Increase (decrease) in cash and cash equivalents		(132,702	)		94,160			(2,357,416	)
Cash and cash equivalents at beginning of year		603,915			509,755			2,867,171
Cash and cash equivalents at end of year	$	471,213		$	603,915		$	509,755

Supplemental Disclosures of Cash Flow Information

Interest paid (net of capitalized interest)	$	1,365,474		$	1,558,885		$	380,451
Income taxes paid, net of refunds received	$	2,029,977		$	3,009,939		$	5,477,147

Supplemental schedule of noncash investing and financing activities:
Additions and revisions, net, to asset retirement obligations	$	14,095		$	70,529		$	225,453

Gross additions to properties and equipment	$	5,118,733		$	26,183,115		$	120,284,639
Net (increase) decrease in accounts payable for properties and equipment additions		(1,132,498	)		4,925,690			1,638,351
Capital expenditures, including dry hole costs	$	3,986,235		$	31,108,805		$	121,922,990

Through management of its fee mineral and leasehold acreage, the Company’s principal line of business is to explore for, develop, acquire, produce and sell oil, NGL and natural gas. Panhandle’s mineral and leasehold properties and other oil and natural gas interests are all located in the contiguous United States, primarily in Arkansas, New Mexico, North Dakota, Oklahoma and Texas, with properties located in several other states. The Company also owns immaterial international overriding royalty interests. The Company’s oil, NGL and natural gas production is from interests in 6,233 wells located principally in Arkansas, Oklahoma and Texas. The Company is not the operator of any wells. Approximately 51% of oil, NGL and natural gas revenues were derived from the sale of natural gas in 2016. Approximately 72% of the Company’s total sales volumes in 2016 were derived from natural gas. Substantially all the Company’s oil, NGL and natural gas production is sold through the operators of the wells. From time to time, the Company sells certain non-material, non-core or small-interest oil and natural gas properties in the normal course of business.

Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts and disclosures reported in the financial statements and accompanying notes. Actual results could differ from those estimates.

Of these estimates and assumptions, management considers the estimation of crude oil, NGL and natural gas reserves to be the most significant. These estimates affect the unaudited standardized measure disclosures, as well as DD&A and impairment calculations. On an annual basis, with a semi-annual update, the Company’s Independent Consulting Petroleum Engineer, with assistance from the Company, 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. For DD&A purposes, and as required by the guidelines and definitions established by the SEC, 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. For impairment purposes, projected future crude oil, NGL and natural gas prices as estimated by management are used. Crude oil, NGL and natural gas prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Management uses projected future crude oil, NGL and natural gas

pricing assumptions to prepare estimates of crude oil, NGL and natural gas reserves used in formulating management’s overall operating decisions.

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. Timely obtaining 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 accrual has been materially accurate.

Cash and cash equivalents consist of all demand deposits and funds invested in short-term investments with original maturities of three months or less.

The Company sells oil, NGL and natural gas to various customers, recognizing revenues as oil, NGL and natural gas is produced and sold. Charges for compression, marketing, gathering and transportation of natural gas are included in lease operating expenses.

The Company uses the sales method of accounting for natural gas imbalances in those circumstances where it has underproduced or overproduced its ownership percentage in a property. Under this method, a receivable or liability is recorded to the extent that an underproduced or overproduced position in a well cannot be recouped through the production of remaining reserves. At September 30, 2016 and 2015, the Company had no material natural gas imbalances.

Substantially all of the Company’s accounts receivable are due from purchasers of oil, NGL and natural gas or operators of the oil and natural gas properties. Oil, NGL and natural gas sales receivables are generally unsecured. This industry concentration has the potential to impact our overall exposure to credit risk, in that the purchasers of our oil, NGL and natural gas and the operators of the properties in which we have an interest may be similarly affected by changes in economic, industry or other conditions. During 2016 and 2015, the Company recognized a reserve for bad debt expense of $19,216 and $180,499, respectively.

The Company follows the successful efforts method of accounting for oil and natural gas producing activities. Intangible drilling and other costs of successful wells and development dry holes are capitalized and amortized. The costs of exploratory wells are initially capitalized, but charged against income, if and when the well does not commercially produce. Oil and natural gas mineral and leasehold costs are capitalized when incurred.

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.

It is common business practice in the petroleum industry to prepay drilling costs before spudding a well. The Company frequently fulfills these prepayment requirements with cash payments, but at times will utilize letters of credit to meet these obligations. As of September 30, 2016, the Company had no outstanding letters of credit.

When the Company leases its mineral acreage to a third-party company, it retains a royalty interest in any future revenues from the production and sale of oil, NGL or natural gas, and often receives an up-front, non-refundable, cash payment (lease bonus) in addition to the retained royalty interest. A royalty interest does not bear any portion of the cost of drilling, completing or operating a well; these costs are borne by the working interest owners. The Company sometimes leases only a portion of its mineral acres in a tract and retains the right to participate as a working interest owner with the remainder.

The Company recognizes revenue from mineral lease bonus payments when it has received an executed lease agreement with a third-party company transferring the rights to explore for and produce any oil or natural gas they may find within the term of the lease, the payment has been collected, and the Company has no obligation to refund the payment. The Company accounts for its lease bonuses in accordance with the guidance set forth in ASC 932, and it recognizes the lease bonus as a cost recovery with any excess above its cost basis in the mineral being treated as a gain. The excess of lease bonus above the mineral basis is shown in the lease bonuses and rentals line item on the Company’s Statements of Operations.

The Company has entered into fixed swap contracts and costless collar 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 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 derivative instruments have settled or will settle based on the prices below.

The Company has elected not to complete the documentation requirements necessary to permit these derivative contracts to be accounted for as cash flow hedges. The Company’s fair value of derivative contracts was a net liability of $428,271 as of September 30, 2016, and a net asset of $4,210,764 as of September 30, 2015. Realized and unrealized gains and (losses) are recorded in gains (losses) on derivative contracts on the Company’s Statement of Operations.

The fair value amounts recognized for the Company’s derivative contracts executed with the same counterparty under a master netting arrangement may be offset. The Company has the choice to offset or not, but that choice must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for the derivative contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Balance Sheets. The following table summarizes and reconciles the Company's derivative contracts’ fair values at a gross level back to net fair value presentation on the

Company's Balance Sheets at September 30, 2016, and September 30, 2015. The Company has offset all amounts subject to master netting agreements in the Company's Balance Sheets at September 30, 2016, and September 30, 2015.

The fair value of derivative assets and derivative liabilities is adjusted for credit risk only if the impact is deemed material. The impact of credit risk was immaterial for all periods presented.

Fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, i.e., an exit price. To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs include the following: (i) quoted prices for similar assets or liabilities in active markets; (ii) quoted prices for identical or similar assets or liabilities in markets that are not active; (iii) inputs other than quoted prices that are observable for the asset or liability; or (iv) inputs that are derived principally from, or corroborated by, observable market data by correlation or other means. Level 3 inputs are unobservable inputs for the financial asset or liability.

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis.

Level 2 – Market Approach - The fair values of the Company’s swaps are based on a third-party pricing model which utilizes inputs that are either readily available in the public market, such as natural gas curves, or can be corroborated from active markets. These values are based upon future prices, time to maturity and other factors. These values are then compared to the values given by our counterparties for reasonableness.

Level 3 – The fair values of the Company’s costless collar contracts are based on a pricing model which utilizes inputs that are unobservable or not readily available in the public market. These values are based upon future prices, volatility, time to maturity and other factors. These values are then compared to the values given by our counterparties for reasonableness.

The significant unobservable inputs for Level 3 derivative contracts include market volatility and credit risk of counterparties. Changes in these inputs will impact the fair value measurement of our derivative contracts. An increase (decrease) in the forward prices and volatility of oil and natural gas prices will decrease (increase) the fair value of oil and natural gas derivatives, and adverse changes to our counterparties’ creditworthiness will decrease the fair value of our derivatives.

The following table represents quantitative disclosures about unobservable inputs for Level 3 Fair Value Measurements.

A reconciliation of the Company’s derivative contracts classified as Level 3 measurements is presented below.

The following table presents impairments associated with certain assets that have been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy.

At September 30, 2016, and September 30, 2015, the fair value of financial instruments approximated their carrying amounts. Financial instruments include long-term debt, which valuation is classified as Level 3 and is based on a valuation technique that requires inputs that are both unobservable and significant to the overall fair value measurement. The fair value

measurement of our long-term debt is valued using a discounted cash flow model that calculates the present value of future cash flows pursuant to the terms of the debt agreements and applies estimated current market interest rates. The estimated current market interest rates are based primarily on interest rates currently being offered on borrowings of similar amounts and terms. In addition, no valuation input adjustments relating to nonperformance risk for the debt agreements were considered necessary.

Depreciation, depletion and amortization of the costs of producing oil and natural gas properties are generally computed using the unit-of-production method primarily on an individual property basis using proved or proved developed reserves, as applicable, as estimated by the Company’s Independent Consulting Petroleum Engineer. The Company’s capitalized costs of drilling and equipping all development wells, and those exploratory wells that have found proved reserves, are amortized on a unit-of-production basis over the remaining life of associated proved developed reserves. Lease costs are amortized on a unit-of-production basis over the remaining life of associated total proved reserves. Depreciation of furniture and fixtures is computed using the straight-line method over estimated productive lives of five to eight years.

Non-producing oil and natural gas properties include non-producing minerals, which had a net book value of $3,349,567 and $4,016,465 at September 30, 2016 and 2015, respectively, consisting of perpetual ownership of mineral interests in several states, with 91% of the acreage in Arkansas, New Mexico, North Dakota, Oklahoma and Texas. As mentioned, these mineral rights are perpetual and have been accumulated over the 90-year life of the Company. There are approximately 198,489 net acres of non-producing minerals in more than 6,442 tracts owned by the Company. An average tract contains approximately 29 acres, and the average cost per acre is $40. Since inception, the Company has continually generated an interest in several thousand oil and natural gas wells using its ownership of the fee mineral acres as an ownership basis. There continues to be significant drilling and leasing activity each year on these mineral interests. Non-producing minerals are being amortized straight-line over a 33-year period. These assets are considered a long-term investment by the Company, as they do not expire (as do oil and natural gas leases). Given the above, management concluded that a long-term amortization was appropriate and that 33 years, based on past history and experience, was an appropriate period. Due to the fact that the minerals consist of a large number of properties, whose costs are not individually significant, and because virtually all are in the Company’s core operating areas, the minerals are being amortized on an aggregate basis.

The Company recognizes impairment losses for long-lived assets when indicators of impairment are present and the undiscounted cash flows are not sufficient to recover the assets’ carrying amount. The impairment loss is measured by comparing the fair value of the asset to its carrying amount. Fair values are based on discounted cash flow as estimated by the Company. The Company's estimate of fair value of its oil and natural gas properties at September 30, 2016, is based on the best information available as of that date, including estimates of forward oil, NGL and natural gas prices and costs. The Company’s oil and natural gas properties were reviewed for impairment on a field-by-field basis, resulting in the recognition of impairment provisions of $12,001,271, $5,009,191 and $1,096,076 for 2016, 2015 and 2014, respectively. A further reduction in oil, NGL and natural gas prices or a decline in reserve volumes may lead to

additional impairment in future periods that may be material to the Company. Should product price expectations decline in future periods below levels seen at September 30, 2016, impairment charges significantly greater than the Company has incurred in prior periods could result.

During 2016, 2015 and 2014, interest of $24,929, $148,493 and $172,499, respectively, was included in the Company’s capital expenditures. Interest of $1,344,619, $1,550,483 and $462,296, respectively, was charged to expense during those periods. Interest is capitalized using a weighted average interest rate based on the Company’s outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using the unit-of-production method.

Insignificant investments in partnerships and limited liability companies (LLC) that maintain specific ownership accounts for each investor and where the Company holds an interest of 5% or greater, but does not have control of the partnership or LLC, are accounted for using the equity method of accounting.

The Company owns interests in oil and natural gas properties, which may require expenditures to plug and abandon the wells upon the end of their economic lives. The fair value of legal obligations to retire and remove long-lived assets is recorded in the period in which the obligation is incurred (typically when the asset is installed at the production location). When the liability is initially recorded, this cost is capitalized by increasing the carrying amount of the related properties and equipment. Over time the liability is increased for the change in its present value, and the capitalized cost in properties and equipment is depreciated over the useful life of the remaining asset. The Company does not have any assets restricted for the purpose of settling the asset retirement obligations.

The following table shows the activity for the years ended September 30, 2016 and 2015, relating to the Company’s asset retirement obligations:

As the Company is directly involved in the extraction and use of natural resources, it is subject to various federal, state and local provisions regarding environmental and ecological matters. Compliance with these laws may necessitate significant capital outlays. The Company

does not believe the existence of current environmental laws, or interpretations thereof, will materially hinder or adversely affect the Company’s business operations; however, there can be no assurances of future effects on the Company of new laws or interpretations thereof. Since the Company does not operate any wells where it owns an interest, actual compliance with environmental laws is controlled by the well operators, with Panhandle being responsible for its proportionate share of the costs involved. Panhandle carries liability and pollution control insurance. However, all risks are not insured due to the availability and cost of insurance.

Environmental liabilities, which historically have not been material, are recognized when it is probable that a loss has been incurred and the amount of that loss is reasonably estimable. Environmental liabilities, when accrued, are based upon estimates of expected future costs. At September 30, 2016 and 2015, there were no such costs accrued.

Earnings (loss) per share is calculated using net income (loss) divided by the weighted average number of common shares outstanding, plus unissued, vested directors’ deferred compensation shares during the period.

The Company recognizes current compensation costs for its Deferred Compensation Plan for Non-Employee Directors (the “Plan”). Compensation cost is recognized for the requisite directors’ fees as earned and unissued stock is recorded to each director’s account based on the fair market value of the stock at the date earned. The Plan provides that upon retirement, termination or death of the director or upon a change in control of the Company, the shares accrued under the Plan will be issued to the director.

In accordance with guidance on accounting for employee stock ownership plans, the Company records the fair market value of the stock contributed into its ESOP as expense.

Restricted stock awards to officers provide for cliff vesting at the end of three or five years from the date of the awards. These restricted stock awards can be granted based on service time only (non-performance based) or subject to certain share price performance standards (performance based). Restricted stock awards to the non-employee directors provide for quarterly vesting during the calendar year of the award. The fair value of the awards on the grant date is ratably expensed over the vesting period in accordance with accounting guidance.

The estimation of 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. 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 regulations. Deferred income taxes are computed using the liability method and are provided on all temporary differences between the financial basis and the tax basis of the Company’s assets and liabilities.

The threshold for recognizing the financial statement effect of a tax position is when it is more likely than not, based on the technical merits, that the position will be sustained by a taxing authority. Recognized tax positions are initially and subsequently measured as the largest amount of tax benefit that is more likely than not to be realized upon ultimate settlement with a taxing authority. The Company files income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Subject to statutory exceptions that allow for a possible extension of the assessment period, the Company is no longer subject to U.S. federal, state, and local income tax examinations for fiscal years prior to 2013.

The Company includes interest assessed by the taxing authorities in interest expense and penalties related to income taxes in general and administrative expense on its Statements of Operations. For fiscal September 30, 2016, 2015 and 2014, the Company recorded interest and penalties of $12,799, $17 and $0, respectively. The Company does not believe it has any significant uncertain tax positions.

In May 2014, the FASB issued Accounting Standard Update (ASU) 2014-09, Revenue from Contracts with Customers, which will supersede nearly all existing revenue recognition guidance under GAAP. The standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. We are evaluating our existing revenue recognition policies to determine whether any contracts in the scope of the guidance will be affected by the new requirements. The standard is effective for us on October 1, 2018. The standard allows for either “full retrospective” adoption, meaning the standard is applied to all of the periods presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements. We are currently evaluating the transition method that will be elected.

In April 2015, the FASB issued ASU 2015-03 on the presentation of debt issuance costs. The update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs is not affected by the update. For public entities, the guidance is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. This update is not expected to have a material impact on our financial statements.

In August 2015, the FASB issued ASU 2015-15 which allows for line-of-credit arrangements to be handled consistently with the presentation of debt issuance costs update issued in April 2015. For public entities, the guidance is effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. This update is not expected to have a material impact on our financial statements.

In November 2015, the FASB issued ASU 2015-17 on the presentation of deferred income tax assets and liabilities. The update requires that deferred income tax assets and liabilities be classified as noncurrent in the balance sheet. For public entities, the guidance is effective for fiscal years beginning after December 15, 2016, including interim periods within

those fiscal years. The Company early adopted ASU 2015-17 as of December 31, 2016, on a retrospective basis to all prior balance sheet periods presented; however, the adoption of ASU 2015-17 has been reflected in these re-casted 2016 and 2015 financial statements on a retrospective basis to all prior balance sheet periods presented. As a result of the adoption, the Company reclassified $310,900 as of September 30, 2016, from "Deferred income taxes" in current assets to “Deferred income taxes” in long term liabilities and $1,517,100 as of September 30, 2015 from “Deferred income taxes” in current liabilities to “Deferred income taxes” in long term liabilities on the balance sheets. Adoption of ASU 2015-17 had no impact on the Company's current and previously reported shareholders' equity, results of operations or cash flows. The affected prior period deferred income tax account balances presented throughout this report on Form 10-K have been adjusted to reflect the retroactive adoption of ASU 2015-17.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities. The new guidance is intended to improve the recognition and measurement of financial instruments. The new guidance is effective for public companies for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. We are assessing the potential impact that this update will have on our financial statements.

In February 2016, the FASB issued its new lease accounting guidance in ASU 2016-02, Leases (Topic 842). Under the new guidance, lessees will be required to recognize the following for all leases (with the exception of short-term leases) at the commencement date: 1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and 2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The new lease guidance simplified the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and lease liabilities. Lessees will no longer be provided with a source of off-balance sheet financing. For public entities, the guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application is permitted for all public business entities upon issuance. Lessees (for capital and operating leases) and lessors (for sales-type, direct financing, and operating leases) must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. Lessees and lessors may not apply a full retrospective transition approach. We are assessing the potential impact that this update will have on our financial statements.

In March 2016, the FASB has issued ASU 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. The new guidance is intended to improve the accounting for employee share-based payments and affect all organizations that issue share-based payment awards to their employees. Several aspects of the accounting for share-based payment award transactions are simplified, including: (a) income tax consequences; (b) classification of awards as either equity or liabilities; and (c) classification on the statement of cash flows. For public entities, the guidance is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Early

adoption is permitted for any organization in any interim or annual period. We are assessing the potential impact that this update will have on our financial statements.

In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments, which addresses certain issues where diversity in practice was identified and may change how an entity classifies certain cash receipts and cash payments on its statement of cash flows. The new guidance also clarifies how the predominance principle should be applied when cash receipts and cash payments have aspects of more than one class of cash flows. This guidance will generally be applied retrospectively and is effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those years. Early adoption is permitted. All of the amendments in ASU 2016-15 are required to be adopted at the same time. The Company early adopted ASU 2016-15 as of December 31, 2016; however, the adoption of ASU 2016-15 has been reflected in these re-casted 2016, 2015 and 2014 financial statements on a retrospective basis to all prior Statements of Cash Flows presented. As a result of the adoption, the Company reclassified “Proceeds from leasing fee mineral acreage”, which totaled $8,049,434, $2,053,900 and $477,144 for the years ended September 30, 2016, 2015 and 2014, respectively, from Investing Activities to Operating Activities on the Statements of Cash Flows as these transactions are made in our normal course of business and represent operating activities based on the application of the predominance principle. As another result of this adoption, we are also electing to classify our distributions received from equity method investments using the Cumulative Earnings Approach. Distributions received are considered returns on investment and classified as cash inflows from operating activities, unless the investor’s cumulative distributions received less distributions received in prior periods that were determined to be returns of investment exceed cumulative equity in earnings recognized by the investor. When such an excess occurs, the current-period distribution up to this excess should be considered a return of investment and classified as cash inflows from investing activities. This election did not have any impact on our cash flow statements as the Company was already applying this approach. Adoption of ASU 2016-15 had no impact on the Company's current and previously reported shareholders' equity, results of operations or balance sheets. The affected prior period balances in the Statements of Cash Flows presented throughout this report on Form 10-K have been adjusted to reflect the retroactive adoption of ASU 2016-15.

Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date are not expected to have a material impact on our financial statements upon adoption.

The Company leases office space in Oklahoma City, Oklahoma, under the terms of an operating lease expiring in April 2020. Future minimum rental payments under the terms of the lease are $204,089, $206,665, $210,273 and $122,659 in 2017, 2018, 2019 and 2020, respectively. Total rent expense incurred by the Company was $202,083 in 2016, $198,238 in 2015 and $202,134 in 2014.

The difference between the provision (benefit) for income taxes and the amount which would result from the application of the federal statutory rate to income before provision (benefit) for income taxes is analyzed below for the years ended September 30:

Deferred tax assets and liabilities, resulting from differences between the financial statement carrying amounts and the tax basis of assets and liabilities, consist of the following at September 30:

At September 30, 2016, the Company had an income tax benefit of $259,981 related to Oklahoma state income tax net operating loss (OK NOL) carry forwards expiring from 2029 to 2031. There is no valuation allowance for the OK NOL’s as management believes they will be utilized before they expire.

The Company has a $200,000,000 credit facility with a group of banks headed by Bank of Oklahoma (BOK) with a current borrowing base of $80,000,000 and a maturity date of November 30, 2018. The credit facility is subject to a semi-annual borrowing base determination, wherein BOK applies their commodity pricing forecast to the Company’s reserve forecast and determines a borrowing base. The facility is secured by certain of the Company’s properties with a net book value of $166,720,207 at September 30, 2016. The interest rate is based on BOK prime plus from 0.375% to 1.125%, or 30 day LIBOR plus from 1.875% to 2.625%. The election of BOK prime or LIBOR is at the Company’s discretion. The interest rate spread from BOK prime or LIBOR will be charged based on the ratio of the loan balance to the borrowing base. The interest rate spread from LIBOR or the prime rate increases as a larger percent of the borrowing base is advanced. At September 30, 2016, the effective interest rate was 2.73%.

The Company’s debt is recorded at the carrying amount on its balance sheet. The carrying amount of the Company’s revolving credit facility approximates fair value because the interest rates are reflective of market rates.

Determinations of the borrowing base are made semi-annually (June and December) or whenever the banks, in their sole discretion, believe that there has been a material change in the value of the oil and natural gas properties. In December 2016, the borrowing base was redetermined by the banks and was left unchanged at $80,000,000. The loan agreement contains customary covenants which, among other things, require periodic financial and reserve reporting and place certain limits on the Company’s incurrence of indebtedness, liens, payment of dividends and acquisitions of treasury stock. In addition, the Company is required to maintain certain financial ratios, a current ratio (as defined) of no less than 1.0 to 1.0 and a funded debt to EBITDA (trailing twelve months as defined) of no more than 4.0 to 1.0. At September 30, 2016, the Company was in compliance with the covenants of the loan agreement and had $35,500,000 of availability under its outstanding credit facility.

Upon approval by the shareholders of the Company’s 2010 Restricted Stock Plan in March 2010, the Board approved purchase of up to $1.5 million of the Company’s Common Stock, from time to time, equal to the aggregate number of shares of Common Stock awarded pursuant to the Company’s 2010 Restricted Stock Plan, contributed by the Company to its ESOP and credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors. Effective May 2014, the board of directors approved for management to make these purchases of the Company’s Common Stock at their discretion. The Board’s approval included an initial authorization to purchase up to $1.5 million of Common Stock, with a provision for subsequent authorizations without specific action by the Board. As the amount of Common Stock purchased under any authorization reaches $1.5 million, another $1.5 million is automatically authorized for Common Stock purchases unless the Board determines otherwise. Pursuant to these resolutions adopted by the Board, the purchase of additional $1.5 million increments of the Company’s Common Stock became authorized and approved effective March 2011, March 2012, and June 2013. As of September 30, 2016, $4,997,790 had been spent under the current program to purchase 345,208 shares. The shares are held in treasury and are accounted for using the cost method. On September 30 each year, treasury shares contributed to the Company’s ESOP on behalf of the ESOP participants were 11,418 in 2016, 11,455 in 2015 and 11,428 in 2014.

The Company’s ESOP was established in 1984 and is a tax qualified, defined contribution plan that serves as the Company’s sole retirement plan for all its employees. Company contributions are made at the discretion of the Board and, to date, all contributions have been made in shares of Company Common Stock. The Company contributions are allocated to all ESOP participants in proportion to their compensation for the plan year, and 100% vesting occurs after three years of service. Any shares that do not vest are treated as forfeitures and are distributed among other vested employees. For contributions of Common Stock, the Company records as expense the fair market value of the stock contributed. The 323,555 shares of the Company’s Common Stock held by the plan as of September 30, 2016, are allocated to individual participant accounts, are included in the weighted average shares outstanding for purposes of earnings-per-share computations and receive dividends.

Annually, outside directors may elect to be included in the Panhandle Oil and Gas Inc. Deferred Directors’ Compensation Plan for Non-Employee Directors (the “Plan”). The Plan provides that each outside director may individually elect to be credited with future unissued shares of Company Common Stock rather than cash for all or a portion of the annual retainers, Board meeting fees and committee meeting fees, and may elect to receive shares, if and when issued, over annual time periods up to ten years. These unissued shares are recorded to each director’s deferred compensation account at the closing market price of the shares (i) on the dates of the Board and committee meetings, and (ii) on the payment dates of the annual retainers. Only upon a director’s retirement, termination, death, or a change-in-control of the Company will the shares recorded for such director under the Plan be issued to the director. The promise to issue such shares in the future is an unsecured obligation of the Company. As of September 30, 2016, there were 272,564 shares (253,712 shares at September 30, 2015) recorded under the Plan. The deferred balance outstanding at September 30, 2016, under the Plan was $3,403,213 ($3,084,289 at September 30, 2015). Expenses totaling $329,465, $302,353 and $353,825 were charged to the Company’s results of operations for the years ended September 30, 2016, 2015 and 2014, respectively, and are included in general and administrative expense in the accompanying Statement of Operations.

In March 2010, shareholders approved the Panhandle Oil and Gas Inc. 2010 Restricted Stock Plan (2010 Stock Plan), which made available 200,000 shares of Common Stock to

provide a long-term component to the Company’s total compensation package for its officers and to further align the interest of its officers with those of its shareholders. In March 2014, shareholders approved an amendment to increase the number of shares of common stock reserved for issuance under the 2010 Stock Plan from 200,000 shares to 500,000 shares and to allow the grant of shares of restricted stock to our directors. The 2010 Stock Plan is designed to provide as much flexibility as possible for future grants of restricted stock so the Company can respond as necessary to provide competitive compensation in order to retain, attract and motivate officers of the Company and to align their interests with those of the Company’s shareholders.

In June 2010, the Company began awarding shares of the Company’s Common Stock as restricted stock (non-performance based) to certain officers. The restricted stock vests at the end of the vesting period and contains nonforfeitable rights to receive dividends and voting rights during the vesting period. The fair value of the shares was based on the closing price of the shares on their award date and will be recognized as compensation expense ratably over the vesting period. Upon vesting, shares are expected to be issued out of shares held in treasury.

In December 2010, the Company also began awarding shares of the Company’s Common Stock, subject to certain share price performance standards (performance based), as restricted stock to certain officers. Vesting of these shares is based on the performance of the market price of the Common Stock over the vesting period. The fair value of the performance shares was estimated on the grant date using a Monte Carlo valuation model that factors in information, including the expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance shares. Compensation expense for the performance shares is a fixed amount determined at the grant date and is recognized over the vesting period regardless of whether performance shares are awarded at the end of the vesting period. Should the shares vest, they are expected to be issued out of shares held in treasury.

In May 2014, the Company also began awarding shares of the Company’s Common Stock as restricted stock (non-performance based) to its non-employee directors. The restricted stock vests quarterly during the calendar year of the award and contains nonforfeitable rights to receive dividends and voting rights during the vesting period. The fair value of the shares was based on the closing price of the shares on their award date and will be recognized as compensation expense ratably over the vesting period. Upon vesting, shares are expected to be issued out of shares held in treasury.

The following table summarizes the Company’s pre-tax compensation expense for the years ended September 30, 2016, 2015 and 2014, related to the Company’s performance based and non-performance based restricted stock.

A summary of the Company’s unrecognized compensation cost for its unvested performance based and non-performance based restricted stock and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table.

A summary of the status of unvested shares of restricted stock awards and changes is presented below:

	Performance Based Unvested Restricted Shares			Weighted Average Grant-Date Fair Value		Non- Performance Based Unvested Restricted Shares			Weighted Average Grant-Date Fair Value
Unvested shares as of September 30, 2013		93,190		$	8.82		59,768		$	14.53

Granted		36,558			8.07		20,022			20.47
Vested		(720	)		9.77		(23,437	)		17.21
Forfeited		(16,844	)		9.77		-			-
Unvested shares as of September 30, 2014		112,184		$	8.42		56,353		$	15.52

Granted		35,485			12.18		22,028			19.25
Vested		(10,209	)		9.73		(38,415	)		16.58
Forfeited		(25,209	)		9.73		-			-
Unvested shares as of September 30, 2015		112,251		$	9.20		39,966		$	16.56

Granted		40,446			9.32		26,478			16.37
Vested		(10,197	)		7.59		(23,433	)		16.91
Forfeited		(28,083	)		7.59		-			-
Unvested shares as of September 30, 2016		114,417		$	9.79		43,011		$	16.25

Virtually all oil and natural gas producing activities of the Company are conducted within the contiguous United States (principally in Arkansas, Oklahoma and Texas) and represent substantially all of the business activities of the Company.

The following table shows sales through various operators/purchasers during 2016, 2015 and 2014.

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:

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

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

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:

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

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

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.

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.

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

The following is a summary of the Company’s unaudited quarterly results of operations.

Management’s Annual Report on Internal Control Over Financial Reporting		3

Report of Registered Public Accounting Firm on Internal Control Over Financial Reporting		4

Report of Independent Registered Public Accounting Firm		5

Balance Sheets As of September 30, 2016 and 2015		6

Statements of Operations for the Years Ended September 30, 2016, 2015 and 2014		8

Statements of Stockholders’ Equity for the Years Ended September 30, 2016, 2015 and 2014		9

Statements of Cash Flows for the Years Ended September 30, 2016, 2015 and 2014		10

Notes to Financial Statements		12

	September 30,
	2016			2015
Assets
Current Assets:
Cash and cash equivalents	$	471,213		$	603,915
Oil, NGL and natural gas sales receivables (net of allowance for uncollectable accounts)		5,287,229			7,895,591
Refundable income taxes		83,874			345,897
Refundable production taxes		-			476,001
Derivative contracts, net		-			4,210,764
Other		419,037			252,016
Total current assets		6,261,353			13,784,184

Properties and equipment at cost, based on successful efforts accounting:
Producing oil and natural gas properties		434,469,093			441,141,337
Non-producing oil and natural gas properties		7,574,649			8,293,997
Furniture and fixtures		1,069,658			1,393,559
		443,113,400			450,828,893
Less accumulated depreciation, depletion and amortization		(251,707,749	)		(228,036,803	)
Net properties and equipment		191,405,651			222,792,090

Investments		157,322			2,248,999

Total assets	$	197,824,326		$	238,825,273

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
January - December 2015	100,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $4.10 ceiling
January - December 2015	70,000 Mmbtu	NYMEX Henry Hub	$3.25 floor / $4.00 ceiling
April - October 2015	50,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $4.00 ceiling
May - October 2015	70,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $3.95 ceiling
Oil costless collars
July - December 2015	10,000 Bbls	NYMEX WTI	$80.00 floor / $86.50 ceiling
Oil fixed price swaps
April - December 2015	5,000 Bbls	NYMEX WTI	$94.56
July - December 2015	7,000 Bbls	NYMEX WTI	$93.91

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
April - October 2016	200,000 Mmbtu	NYMEX Henry Hub	$1.95 floor / $2.40 ceiling
October - December 2016	70,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.05 ceiling
October - December 2016	50,000 Mmbtu	NYMEX Henry Hub	$2.90 floor / $3.40 ceiling
November 2016 - March 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.25 floor / $3.65 ceiling
November 2016 - March 2017	80,000 Mmbtu	NYMEX Henry Hub	$2.25 floor / $3.95 ceiling
November 2016 - March 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.60 floor / $3.25 ceiling
January - June 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.85 floor / $3.35 ceiling
January - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.47 ceiling
January - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.00 floor / $3.35 ceiling
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.80 floor / $3.35 ceiling
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$2.75 floor / $3.35 ceiling
Natural gas fixed price swaps
October 2016	100,000 Mmbtu	NYMEX Henry Hub	$2.410
October 2016 - March 2017	25,000 Mmbtu	NYMEX Henry Hub	$3.200
November 2016 - April 2017	80,000 Mmbtu	NYMEX Henry Hub	$2.955
January - December 2017	25,000 Mmbtu	NYMEX Henry Hub	$3.100
April - December 2017	50,000 Mmbtu	NYMEX Henry Hub	$3.070
Oil costless collars
July - December 2016	3,000 Bbls	NYMEX WTI	$35.00 floor / $49.00 ceiling
October - December 2016	3,000 Bbls	NYMEX WTI	$40.00 floor / $47.25 ceiling
October 2016 - March 2017	3,000 Bbls	NYMEX WTI	$40.00 floor / $58.50 ceiling
October 2016 - March 2017	3,000 Bbls	NYMEX WTI	$45.00 floor / $54.00 ceiling
October 2016 - March 2017	3,000 Bbls	NYMEX WTI	$45.00 floor / $55.50 ceiling

	9/30/2016												9/30/2015
	Fair Value (a)												Fair Value (a)
	Commodity Contracts												Commodity Contracts
	Current Assets			Current Liabilities			Non-Current Assets			Non-Current Liabilities			Current Assets
Gross amounts recognized	$	68,235		$	471,847		$	4,759		$	29,418		$	4,210,764
Offsetting adjustments		(68,235	)		(68,235	)		(4,759	)		(4,759	)		-
Net presentation on Balance Sheets	$	-			403,612		$	-			24,659		$	4,210,764

		/s/ Ernst & Young LLP

Oklahoma City, Oklahoma
December 12, 2016

		/s/ Ernst & Young LLP

Oklahoma City, Oklahoma
December 12, 2016, except for the impact of the matters discussed in Note 1 pertaining to the adoption of ASU 2015-17 and ASU 2016-15, as to which the date is November 6, 2017

	Fair Value Measurement at September 30, 2016
	Quoted Prices in Active Markets		Significant Other Observable Inputs			Significant Unobservable Inputs			Total Fair
	(Level 1)		(Level 2)			(Level 3)			Value
Financial Assets (Liabilities):
Derivative Contracts - Swaps	$	-	$	(111,613	)	$	-		$	(111,613	)
Derivative Contracts - Collars	$	-	$	-		$	(316,658	)	$	(316,658	)

	Fair Value Measurement at September 30, 2015
	Quoted Prices in Active Markets		Significant Other Observable Inputs		Significant Unobservable Inputs		Total Fair
	(Level 1)		(Level 2)		(Level 3)		Value
Financial Assets (Liabilities):
Derivative Contracts - Swaps	$	-	$	2,319,515	$	-	$	2,319,515
Derivative Contracts - Collars	$	-	$	-	$	1,891,249	$	1,891,249

Instrument Type	Unobservable Input	Range	Weighted Average			Fair Value Assets (Liabilities) September 30, 2016

Oil Collars	Oil price volatility curve	0% - 25.87%		15.06	%	$	(99,005	)
Natural Gas Collars	Natural gas price volatility curve	0% - 32.76%		22.50	%	$	(217,653	)

	Derivatives
Net Asset (Liability) Balance of Level 3 as of October 1, 2015	$	1,891,249
Total gains or (losses):
Included in earnings		(4,200,367	)
Included in other comprehensive income (loss)		-
Purchases, issuances and settlements		1,992,460
Transfers in and out of Level 3		-
Net Asset (Liability) Balance of Level 3 as of September 30, 2016	$	(316,658	)

	2016			2015
Asset Retirement Obligations as of beginning of the year	$	2,824,944		$	2,638,470
Accretion of Discount		128,722			126,769
Wells Acquired or Drilled		17,338			78,110
Wells Sold or Plugged		(12,956	)		(18,405	)
Asset Retirement Obligations as of end of the year	$	2,958,048		$	2,824,944

	2016		2015
Deferred tax liabilities:
Financial basis in excess of tax basis, principally intangible drilling costs capitalized for financial purposes and expensed for tax purposes	$	33,656,415	$	41,880,691
Derivative contracts		-		1,637,987
		33,656,415		43,518,678
Deferred tax assets:
State net operating loss carry forwards		259,981		323,536
AMT credit carry forwards		-		164,478
Deferred directors' compensation		1,273,279		1,149,217
Restricted stock expense		494,776		457,934
Derivative contracts		166,597		-
Other		785,775		787,506
		2,980,408		2,882,671
Net deferred tax liabilities	$	30,676,007	$	40,636,007

Year	Shares		Amount
2016		11,418	$	200,158
2015		11,455	$	185,113
2014		11,428	$	341,125

	Unrecognized Compensation Cost		Weighted Average Period (in years)
Performance based, restricted stock	$	207,856		1.69
Non-performance based, restricted stock		304,409		1.52
Total	$	512,265

	2016			2015		2014
Current:
Federal	$	2,166,000		$	2,053,000	$	4,996,000
State		83,000			111,000		214,000
		2,249,000			2,164,000		5,210,000
Deferred:
Federal		(8,597,000	)		2,033,000		5,702,000
State		(1,363,000	)		639,000		908,000
		(9,960,000	)		2,672,000		6,610,000
	$	(7,711,000	)	$	4,836,000	$	11,820,000

	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

	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

	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

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

	Fiscal 2016
	Quarter Ended
	December 31			March 31			June 30			September 30
Revenues	$	11,462,125		$	7,587,091		$	9,862,578		$	10,151,389
Income (loss) before provision for income taxes	$	(5,167,118	)	$	(12,013,161	)	$	(1,730,795	)	$	913,190
Net income (loss)	$	(2,799,118	)	$	(7,438,161	)	$	(786,795	)	$	737,190
Earnings (loss) per share	$	(0.17	)	$	(0.44	)	$	(0.05	)	$	0.05

	Fiscal 2015
	Quarter Ended
	December 31			March 31			June 30			September 30
Revenues	$	30,999,170		$	14,679,034		$	11,748,888		$	13,455,001
Income (loss) before provision for income taxes	$	14,875,761		$	627,207		$	(496,946	)	$	(848,681	)
Net income (loss)	$	10,233,761		$	704,207		$	(728,946	)	$	(887,681	)
Earnings (loss) per share	$	0.61		$	0.04		$	(0.04	)	$	(0.05	)