PHX Minerals (PHX) 10-K 13 Dec 19 2019 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Sep. 30, 2019	Dec. 01, 2019	Mar. 31, 2019
Document And Entity Information [Abstract]
Entity Registrant Name	PANHANDLE OIL & GAS INC
Entity Central Index Key	0000315131
Trading Symbol	PHX
Document Type	10-K
Document Period End Date	Sep. 30, 2019
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--09-30
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity File Number	001-31759
Entity Tax Identification Number	731055775
Entity Address, Address Line One	Grand Centre
Entity Address, Address Line Two	Suite 300
Entity Address, Address Line Three	5400 N. Grand Blvd
Entity Address, City or Town	Oklahoma City
Entity Address, State or Province	OK
Entity Address, Postal Zip Code	73112
City Area Code	(405)
Local Phone Number	948-1560
Entity Common Stock, Shares Outstanding		16,339,255
Entity Public Float			$ 246,376,520

Balance Sheets

Balance Sheets - USD ($)	Sep. 30, 2019	Sep. 30, 2018
Current Assets:
Cash and cash equivalents	$ 6,160,691	$ 532,502
Oil, NGL and natural gas sales receivables (net of allowance for uncollectable accounts)	4,377,646	7,101,629
Refundable income taxes	1,505,442	33,165
Derivative contracts, net	2,256,639
Other	177,037	578,880
Total current assets	14,477,455	8,246,176
Properties and equipment at cost, based on successful efforts accounting:
Producing oil and natural gas properties	354,718,398	427,448,584
Non-producing oil and natural gas properties	14,599,023	12,563,519
Other	1,722,080	1,529,770
Gross properties and equipment, at cost, based on successful efforts accounting	371,039,501	441,541,873
Less accumulated depreciation, depletion and amortization	(259,314,590)	(243,257,472)
Net properties and equipment	111,724,911	198,284,401
Investments	205,076	219,109
Derivative contracts, net	237,505
Total assets	126,644,947	206,749,686
Current Liabilities:
Accounts payable	665,160	881,130
Derivative contracts, net		3,064,046
Accrued liabilities and other	2,433,466	1,791,950
Total current liabilities	3,098,626	5,737,126
Long-term debt	35,425,000	51,000,000
Deferred income taxes	5,976,007	18,088,007
Asset retirement obligations	2,835,781	2,809,378
Derivative contracts, net		349,970
Stockholders' equity:
Class A voting common stock, $0.01666 par value; 24,000,000 shares authorized; 16,897,306 issued at September 30, 2019; 16,896,881 issued at September 30, 2018	281,509	281,502
Capital in excess of par value	2,967,984	2,824,691
Deferred directors' compensation	2,555,781	2,950,405
Retained earnings	81,848,301	125,266,945
Stockholders' Equity	87,653,575	131,323,543
Treasury stock, at cost; 558,051 shares at September 30, 2019; 145,467 shares at September 30, 2018	(8,344,042)	(2,558,338)
Total stockholders' equity	79,309,533	128,765,205
Total liabilities and stockholders' equity	$ 126,644,947	$ 206,749,686

Balance Sheets (Parenthetical)

Balance Sheets (Parenthetical) - $ / shares	Sep. 30, 2019	Sep. 30, 2018
Statement Of Financial Position [Abstract]
Common stock, par value	$ 0.01666	$ 0.01666
Common stock, shares authorized	24,000,000	24,000,000
Common stock, shares issued	16,897,306	16,896,881
Treasury stock, shares	558,051	145,467

Statements Of Operations

Statements Of Operations - USD ($)	12 Months Ended
	Sep. 30, 2019		Sep. 30, 2018	Sep. 30, 2017
Revenues:
Revenues	$ 39,410,036
Gains (losses) on derivative contracts	6,105,145		$ (4,932,068)	$ 1,249,840
Gain on asset sales	18,973,426			26,105
Revenues	66,035,685		45,034,264	46,361,154
Costs and expenses:
Lease operating expenses	12,488,425		13,460,278	12,682,969
Production taxes	1,902,636		2,089,050	1,548,399
Depreciation, depletion and amortization	18,196,583		18,395,040	18,397,548
Provision for impairment	76,824,337	[1]	0	662,990	[1]
Interest expense	1,995,789		1,748,101	1,275,138
General and administrative	8,565,243		7,342,441	7,441,242
Loss on asset sales and other expense (income)	288,610		102,685	131,935
Total costs and expenses	120,261,623		43,137,595	42,140,221
Income (loss) before provision (benefit) for income taxes	(54,225,938)		1,896,669	4,220,933
Provision (benefit) for income taxes	(13,481,000)		(12,739,000)	689,000
Net income (loss)	$ (40,744,938)		$ 14,635,669	$ 3,531,933
Basic and diluted earnings (loss) per common share	$ (2.43)		$ 0.86	$ 0.21
Oil, NGL and Natural Gas [Member]
Revenues:
Revenues	$ 39,410,036		$ 48,385,335	$ 39,935,912
Lease Bonuses and Rental Income [Member]
Revenues:
Revenues	$ 1,547,078		$ 1,580,997	$ 5,149,297
[1]	At the end of each quarter, the Company assessed the carrying value of its producing properties for impairment. This assessment utilized estimates of future cash flows or fair value (selling price) less cost to sell if the property is held for sale. Significant judgments and assumptions in these assessments include estimates of future oil, NGL and natural gas prices using a forward NYMEX curve adjusted for projected inflation, locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values.

Statements Of Stockholders' Equ

Statements Of Stockholders' Equity - USD ($)	Total	Class A voting Common Stock [Member]	Capital in Excess of Par Value [Member]	Deferred Directors' Compensation [Member]	Retained Earnings [Member]	Treasury Stock [Member]
Balances at Sep. 30, 2016	$ 115,191,819	$ 280,938	$ 3,191,056	$ 3,403,213	$ 112,482,284	$ (4,165,672)
Balances, shares at Sep. 30, 2016		16,863,004
Balances, Treasury shares at Sep. 30, 2016						(262,708)
Net income (loss)	3,531,933				3,531,933
Purchase of treasury stock	(601,853)					$ (601,853)
Purchase of treasury stock, shares						(25,742)
Issuance of treasury shares to ESOP	312,380		93,192			$ 219,188
Issuance of treasury shares to ESOP, shares						13,125
Restricted stock awards	597,940		597,940
Dividends declared ($0.16 per share)	(2,684,001)				(2,684,001)
Distribution of restricted stock to officers and directors	663		(1,010,275)			$ 1,010,938
Distribution of restricted stock to officers and directors, shares						63,121
Distribution of deferred directors' compensation			(145,469)	(301,962)		$ 447,431
Distribution of deferred directors' compensation, shares						27,216
Common shares to be issued to directors for services	358,658			358,658
Balances at Sep. 30, 2017	116,707,539	$ 280,938	2,726,444	3,459,909	113,330,216	$ (3,089,968)
Balances, shares at Sep. 30, 2017		16,863,004
Balances, Treasury shares at Sep. 30, 2017						(184,988)
Net income (loss)	14,635,669				14,635,669
Purchase of treasury stock	(1,219,228)					$ (1,219,228)
Purchase of treasury stock, shares						(63,404)
Issuance of treasury shares to ESOP	382,174		19,509			$ 362,665
Issuance of treasury shares to ESOP, shares						20,632
Restricted stock awards	655,414		655,414
Dividends declared ($0.16 per share)	(2,698,940)				(2,698,940)
Distribution of restricted stock to officers and directors	862	$ 21	(845,788)			$ 846,629
Distribution of restricted stock to officers and directors, shares		1,278				50,455
Distribution of deferred directors' compensation		$ 543	269,112	(811,219)		$ 541,564
Distribution of deferred directors' compensation, shares		32,599				31,838
Common shares to be issued to directors for services	301,715			301,715
Balances at Sep. 30, 2018	$ 128,765,205	$ 281,502	2,824,691	2,950,405	125,266,945	$ (2,558,338)
Balances, shares at Sep. 30, 2018		16,896,881
Balances, Treasury shares at Sep. 30, 2018	(145,467)					(145,467)
Net income (loss)	$ (40,744,938)				(40,744,938)
Purchase of treasury stock	(7,454,000)					$ (7,454,000)
Purchase of treasury stock, shares						(515,972)
Issuance of treasury shares to ESOP	372,274		(25,830)			$ 398,104
Issuance of treasury shares to ESOP, shares						26,629
Restricted stock awards	771,797		771,797
Dividends declared ($0.16 per share)	(2,673,706)				(2,673,706)
Distribution of restricted stock to officers and directors	413	$ 7	(394,824)			$ 395,230
Distribution of restricted stock to officers and directors, shares		425				24,360
Distribution of deferred directors' compensation	(3)		(207,850)	(667,115)		$ 874,962
Distribution of deferred directors' compensation, shares						52,399
Common shares to be issued to directors for services	272,491			272,491
Balances at Sep. 30, 2019	$ 79,309,533	$ 281,509	$ 2,967,984	$ 2,555,781	$ 81,848,301	$ (8,344,042)
Balances, shares at Sep. 30, 2019		16,897,306
Balances, Treasury shares at Sep. 30, 2019	(558,051)					(558,051)

Statements Of Stockholders' E_2

Statements Of Stockholders' Equity (Parenthetical) - $ / shares	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Statement Of Stockholders Equity [Abstract]
Dividends per share	$ 0.16	$ 0.16	$ 0.16

Statements Of Cash Flows

Statements Of Cash Flows - USD ($)	12 Months Ended
	Sep. 30, 2019		Sep. 30, 2018	Sep. 30, 2017
Operating Activities
Net income (loss)	$ (40,744,938)		$ 14,635,669	$ 3,531,933
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	18,196,583		18,395,040	18,397,548
Impairment	76,824,337	[1]	0	662,990	[1]
Provision for deferred income taxes	(12,112,000)		(12,963,000)	375,000
Gain from leasing fee mineral acreage	(1,546,298)		(1,520,262)	(5,147,957)
Proceeds from leasing fee mineral acreage	1,565,649		1,564,225	5,194,290
Net (gain) loss on sales of assets	(18,730,197)		660,597	94,889
Common stock contributed to ESOP	372,274		382,174	312,380
Common stock (unissued) to Directors' Deferred Compensation Plan	272,491		301,715	358,658
Fair value of derivative contracts	(5,908,160)		3,930,175	(944,430)
Restricted stock awards	771,797		655,414	597,940
Other	19,085		6,326	(5,783)
Cash provided (used) by changes in assets and liabilities:
Oil, NGL and natural gas sales receivables	2,723,983		483,856	(2,298,256)
Refundable income taxes	(1,472,277)		456,780	(406,071)
Other current assets	21,116		57,752	165,557
Accounts payable	105,217		(140,600)	(103,389)
Other non-current assets	7,166		(62,295)
Accrued liabilities	639,856		100,328	(27,107)
Total adjustments	61,750,622		12,308,225	17,226,259
Net cash provided by operating activities	21,005,684		26,943,894	20,758,192
Investing Activities
Capital expenditures	(3,526,007)		(11,590,135)	(25,807,897)
Acquisition of minerals and overrides	(5,662,869)		(11,327,371)
Investments in partnerships	(1,648)		3,354	(23,563)
Proceeds from sales of assets	19,515,735		1,085,137	723,700
Net cash used in investing activities	10,325,211		(21,829,015)	(25,107,760)
Financing Activities
Borrowings under debt agreement	16,642,481		29,017,800	27,809,185
Payments of loan principal	(32,217,481)		(30,239,800)	(20,087,185)
Purchases of treasury stock	(7,454,000)		(1,219,228)	(601,853)
Payments of dividends	(2,673,706)		(2,698,940)	(2,684,001)
Net cash provided by (used in) financing activities	(25,702,706)		(5,140,168)	4,436,146
Increase (decrease) in cash and cash equivalents	5,628,189		(25,289)	86,578
Cash and cash equivalents at beginning of year	532,502		557,791	471,213
Cash and cash equivalents at end of year	6,160,691		532,502	557,791
Supplemental Disclosures of Cash Flow Information
Interest paid (net of capitalized interest)	2,031,762		1,730,461	1,212,878
Income taxes paid (net of refunds received)	103,279		(232,782)	720,072
Supplemental schedule of noncash investing and financing activities:
Additions and revisions, net, to asset retirement obligations	27,782		17,216	624,893
Gross additions to properties and equipment	9,248,415		21,711,279	25,406,894
Net (increase) decrease in accounts payable for properties and equipment additions	(59,539)		1,206,227	401,003
Capital expenditures, including dry hole costs	$ 9,188,876		$ 22,917,506	$ 25,807,897
[1]	At the end of each quarter, the Company assessed the carrying value of its producing properties for impairment. This assessment utilized estimates of future cash flows or fair value (selling price) less cost to sell if the property is held for sale. Significant judgments and assumptions in these assessments include estimates of future oil, NGL and natural gas prices using a forward NYMEX curve adjusted for projected inflation, locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values.

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	12 Months Ended
	Sep. 30, 2019
Accounting Policies [Abstract]
Summary Of Significant Accounting Policies	1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Nature of Business 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 Oklahoma, North Dakota, Texas, Arkansas and New Mexico, with properties located in several other states. The Company’s oil, NGL and natural gas production is from interests in 6,496 wells located principally in Oklahoma, Texas, Arkansas and North Dakota. The Company does not operate any wells. Approximately 46%, 9% and 45% of oil, NGL and natural gas revenues were derived from the sale of oil, NGL and natural gas, respectively, in 2019. Approximately 19%, 13% and 68% of the Company’s total sales volumes in 2019 were derived from oil, NGL and natural gas, respectively. 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. Use of Estimates 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. The Company’s Independent Consulting Petroleum Engineer, with assistance from the Company, prepares estimates of crude oil, NGL and natural gas reserves on an annual basis, with a semi-annual update. These estimates are 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. Basis of Presentation Certain amounts (loss (gain) on asset sales and other in the Statements of Operations and presentation of deferred tax assets and liabilities in Note 4: Income Taxes) in the prior years have been reclassified to conform to the current year presentation. Cash and Cash Equivalents Cash and cash equivalents consist of all demand deposits and funds invested in short-term investments with original maturities of three months or less. Oil, NGL and Natural Gas Sales 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. Accounts Receivable and Concentration of Credit Risk 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 2019, 2018 and 2017 the Company The Company’s was not material. Oil and Natural Gas Producing Activities 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 reach commercial production levels. Oil and natural gas mineral and leasehold costs are capitalized when incurred. Leasing of Mineral Rights The Company generates lease bonuses by leasing its mineral interests to exploration and production companies. A lease agreement represents the Company's contract with a third party and generally conveys the rights to any oil, NGL or natural gas discovered, grants the Company a right to a specified royalty interest and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Company has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. The Company accounts for its lease bonuses as conveyances 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 income. 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. Derivatives 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 at September 30, 2019 and 2018, were with Bank of Oklahoma and Koch Supply and Trading LP. The Company’s derivative contracts with Bank of Oklahoma are secured under its credit facility with Bank of Oklahoma. The derivative contracts with Koch are unsecured. The derivative instruments have settled or will settle based on the prices below. Derivative contracts in place as of September 30, 2019 Production volume Contract period covered per month Index Contract price Natural gas fixed price swaps July - December 2019 100,000 Mmbtu NYMEX Henry Hub $2.960 July - December 2019 100,000 Mmbtu NYMEX Henry Hub $2.950 July - December 2019 100,000 Mmbtu NYMEX Henry Hub $2.995 July 2019 - March 2020 100,000 Mmbtu NYMEX Henry Hub $2.982 August - December 2019 100,000 Mmbtu NYMEX Henry Hub $3.004 January - December 2020 80,000 Mmbtu NYMEX Henry Hub $2.750 Oil costless collars January - December 2019 1,000 Bbls NYMEX WTI $50.00 floor / $60.00 ceiling January - December 2019 2,000 Bbls NYMEX WTI $60.00 floor / $69.25 ceiling July - December 2019 3,000 Bbls NYMEX WTI $60.00 floor / $70.75 ceiling July 2019 - June 2020 2,000 Bbls NYMEX WTI $65.00 floor / $76.15 ceiling January - June 2020 2,000 Bbls NYMEX WTI $60.00 floor / $67.00 ceiling January - December 2020 2,000 Bbls NYMEX WTI $55.00 floor / $62.00 ceiling Oil fixed price swaps January - December 2019 1,000 Bbls NYMEX WTI $56.15 January - December 2019 2,000 Bbls NYMEX WTI $56.71 January - December 2019 1,000 Bbls NYMEX WTI $58.56 July - December 2019 2,000 Bbls NYMEX WTI $56.85 July - December 2019 5,000 Bbls NYMEX WTI $58.50 July - December 2019 1,000 Bbls NYMEX WTI $60.60 January - December 2020 2,000 Bbls NYMEX WTI $55.28 January - December 2020 2,000 Bbls NYMEX WTI $58.65 January - December 2020 2,000 Bbls NYMEX WTI $60.00 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 asset of $2,494,144 as of September 30, 2019, and a net liability of $3,414,016 as of September 30, 2018. Realized and unrealized gains and (losses) are recorded in gains (losses) on derivative contracts on the Company’s Statement of Operations. The portion of the gain (loss) on derivatives settled in cash for 2019, 2018 and 2017 was $196,985 (net received), $1,001,893 (net paid) and $305,410 (net received), respectively. 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, 2019, and September 30, 2018. The Company has offset all amounts subject to master netting agreements in the Company's Balance Sheets at September 30, 2019, and September 30, 2018. 9/30/2019 9/30/2018 Fair Value Fair Value Commodity Contracts Commodity Contracts Current Non-Current Assets Current Current Liabilities Non-Current Liabilities Gross amounts recognized $ 2,256,639 $ 237,505 $ 42,150 $ 3,106,196 $ 349,970 Offsetting adjustments - - (42,150 ) (42,150 ) - Net presentation on Balance Sheets $ 2,256,639 $ 237,505 $ - $ 3,064,046 $ 349,970 The fair value of derivative assets and derivative liabilities is adjusted for credit risk. The impact of credit risk was immaterial for all periods presented. Fair Value Measurements 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: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2: Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity fixed-price swaps and commodity options (i.e. price collars). The Company uses an option pricing valuation model for option derivative contracts that considers various inputs including: future prices, time value, volatility factors, counterparty credit risk and current market and contractual prices for the underlying instruments. The values calculated are then compared to the values given by counterparties for reasonableness. Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and unobservable (or less observable) from objective sources (supported by little or no market activity). The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis. Fair Value Measurement at September 30, 2019 Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs Total (Level 1) (Level 2) (Level 3) Value Financial Assets (Liabilities): Derivative Contracts - Swaps $ - $ 1,892,954 $ - $ 1,892,954 Derivative Contracts - Collars $ - $ 601,190 $ - $ 601,190 Fair Value Measurement at September 30, 2018 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 $ - $ (2,317,069 ) $ - $ (2,317,069 ) Derivative Contracts - Collars $ - $ (1,096,947 ) $ - $ (1,096,947 ) 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. Year Ended September 30, 2019 2018 2017 Fair Value Impairment Fair Value Impairment Fair Value Impairment Producing Properties (a) $ 9,101,032 $ 76,824,337 $ - $ - $ 567,077 $ 662,990 (a) At the end of each quarter, the Company assessed the carrying value of its producing properties for impairment. This assessment utilized estimates of future cash flows or fair value (selling price) less cost to sell if the property is held for sale. Significant judgments and assumptions in these assessments include estimates of future oil, NGL and natural gas prices using a forward NYMEX curve adjusted for projected inflation, locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values. At September 30, 2019, and September 30, 2018, the carrying values of cash and cash equivalents, receivables, and payables are considered to be representative of their respective fair values due to the short-term maturities of those instruments. Properties and Equipment Depreciation, Depletion and Amortization 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 $9,673,787 and $8,025,015 at September 30, 2019 and 2018, respectively, consisting of perpetual ownership of mineral interests in several states, with 91% of the acreage in Oklahoma, North Dakota, Texas, Arkansas and New Mexico. As mentioned, these mineral rights are perpetual and have been accumulated over the 93-year life of the Company. There are approximately 197,468 net acres of non-producing minerals in more than 6,688 tracts owned by the Company. An average tract contains approximately 30 acres, and the average cost per acre is $73. 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 on these mineral interests each year. 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 Company’s mineral ownership consists 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 (by mineral deed). When a new well is drilled on our mineral acreage, all of the non-producing mineral costs for the associated mineral deed are transferred to producing minerals and are amortized straight-line over a 20-year period (insignificant fields are amortized over 10-year period). Management has historically chosen to move non-producing mineral costs in this manner, as it is very difficult for the Company, as a non-operator, to predict well spacing and timing of drilling on all of the minerals that we have purchased over the long life of the Company. Given that we are moving all of the costs to the first new well drilled on each mineral deed, we believe that a straight-line amortization over a 20-year period is appropriate as these wells and future development will deplete these assets over a fairly long period. Impairment 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 At the end of 2019, impairment of $76,560,376 was recorded on our Eagle Ford assets. The remaining $263,961 of impairment was taken on other assets. The impairment on the Eagle Ford assets was caused by the Company making the strategic decision to cease participating with a working interest on its mineral and leasehold acreage going forward and therefore removing all working interest PUDs from the Company’s reserve reports. The removal of the PUDs caused the Eagle Ford assets to fail the step one test for impairment, as its undiscounted cash flows were not high enough to cover the book basis of the assets. These assets were written down to their fair market value as required by GAAP. The Company determined the fair value based on discounted cash flows of the properties as well as active market bids received from interested potential buyers. The discounted cash flows of the properties were prepared using NYMEX strip pricing as of year-end, using a discount rate of 10% for proved developed and assigning no value to undeveloped locations. Market bids received from interested potential buyers corroborated the fair value of the discounted cash flows as of year-end. The fair value was determined to be $9.1 million based on the discounted cash flows and market quotes. The Company decided not to sell the assets after the marketing process was complete, as we believed that the market conditions were not ideal for selling at that time and that the highest and best use of the assets was to continue to own and produce out the Eagle Ford properties. 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. Divestitures During the 2019 fiscal year, the Company sold 112 non-core wells and 890 net mineral and non-participating royalty interest acres for $19,515,735 and recorded a net gain on sales of $18,730,197. The total net book value that was removed from the Balance Sheets due to these sales was approximately $786,000. On the Statements of Operations, the net gain is reflected in the Gain on asset sales line item with a balance of $18,973,426 with an offset to the Loss on asset sales line item in the amount of $243,228. During the 2018 fiscal year, the Company sold 324 non-core marginal wells for $1,085,137 and recorded a net loss on the sales of $660,597. The total net book value that was removed from the Balance Sheets due to these sales was approximately $1.7 million. The loss on sales was included in the Loss on asset sales and other line of the Statements of Operations. Acquisitions During the 2019 fiscal year, the Company acquired mineral acreage in the cores of the Bakken in North Dakota and the STACK and SCOOP plays in Oklahoma. The Company acquired a total of 790 net mineral acres for $5.7 million or an average of approximately $7,200 per net mineral acre. These mineral purchases were accounted for as asset acquisitions. During the 2018 fiscal year, the Company acquired mineral acreage in the cores of the Bakken in North Dakota and the STACK and SCOOP plays in Oklahoma. The Company acquired a total of 4,306 net mineral acres for $11.3 million or an average of approximately $2,600 per net mineral acre. These mineral purchases were accounted for as asset acquisitions. Capitalized Interest During 2019 Accrued Liabilities The following table shows the balances for the years ended September 30, 2019 and 2018, relating to the Company’s accrued liabilities: Year Ended September 30, 2019 2018 Accrued compensation $ 1,446,710 $ 905,445 Revenues payable 396,954 253,850 Accrued ad valorem 260,550 317,105 Other 329,252 315,550 Total accrued liabilities $ 2,433,466 $ 1,791,950 The increase in accrued compensation is primarily due to the one-time severance with the Company’s former CEO of approximately $670,000 upon his resignation towards the end of fiscal 2019. This increase was somewhat offset by a decrease in the overall bonus accrual for 2019 as compared to 2018. The increase in revenues payable was primarily due to oil, NGL and natural gas revenues received on properties sold during 2019 that related to production after the effective date of the sale. Asset Retirement Obligations 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, 2019 and 2018, relating to the Company’s asset retirement obligations: 2019 2018 Asset retirement obligations as of beginning of the year $ 2,809,378 $ 3,196,889 Wells acquired or drilled 27,783 17,215 Wells sold or plugged (134,090 ) (542,892 ) Accretion of discount 132,710 138,166 Asset retirement obligations as of end of the year $ 2,835,781 $ 2,809,378 As a non-operator, we do not control the plugging of wells in which we have a working interest and are not involved in the negotiation of the terms of the plugging contracts. Our estimate relies on information that we can gather from outside sources as well as relevant information that we receive directly from operators. Environmental Costs 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 (on working interest wells only). 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, 2019 and 2018, there were no such costs accrued. Earnings (Loss) Per Share of Common Stock 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. Share-based Compensation 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 only upon retirement, termination or death of the director or upon a change in control of the Company, the shares accrued under the Plan may 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 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. Income Taxes 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 Tax Cuts and Jobs Act was enacted on December 22, 2017. The Act reduced the U.S. federal corporate tax rate from 35% to 21%. As of September 30, 2018, we completed our estimates accounting for the tax effects of the Act. Based on these estimates, we recognized an amount which was included as a component of income tax expense (benefit) from continuing operations in 2018. We remeasured certain deferred tax assets and liabilities based on the rates at which they are expected to reverse in the future, which is generally 21%. The amount recorded related to the remeasurement of our deferred tax balance was $12,464,000 income tax benefit. The Company’s provision for income taxes differs from the statutory rate primarily due to estimated federal and state benefits generated from estimated excess federal and Oklahoma percentage depletion, which are permanent tax benefits. Excess percentage depletion, both federal and Oklahoma, can only be taken in the amount that it exceeds cost depletion which is calculated on a unit-of-production basis. Both excess federal percentage depletion, which is limited to certain production volumes and by certain income levels, and excess Oklahoma percentage depletion, which has no limitation on production volume, reduce estimated taxable income or add to estimated taxable loss projected for any year. Federal and Oklahoma excess percentage depletion, when a provision for income taxes is expected for the year, decreases the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is expected for the year. The benefits of federal and Oklahoma excess percentage depletion and excess tax benefits and deficiencies of stock-based compensation are not directly related to the amount of pre-tax income (loss) recorded in a period. Accordingly, in periods where a recorded pre-tax income or loss is relatively small, the proportional effect of these items on the effective tax rate may be significant. The effective tax rate for the year ended September 30, 2018, was a 672% benefit, as compared to a 25% benefit for the year ended September 30, 2019. 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 2016. 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, 201

Commitments

Commitments	12 Months Ended
	Sep. 30, 2019
Commitments And Contingencies Disclosure [Abstract]
Commitments	2. COMMITMENTS 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 $122,659, $0 and $0 in 2020, 2021 and 2022, respectively. Total rent expense incurred by the Company was $218,899 in 2019, $215,803 in 2018 and $206,366 in 2017.

Revenues

Revenues	12 Months Ended
	Sep. 30, 2019
Revenue From Contract With Customer [Abstract]
Revenues	3. REVENUES Lease bonus income The Company also earns income from lease bonuses. The Company generates lease bonus income by leasing its mineral interests to exploration and production companies. A lease agreement represents the Company's contract with a third party and generally conveys the rights to any oil, NGL or natural gas discovered, grants the Company a right to a specified royalty interest and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Company has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. The Company accounts for its lease bonuses as conveyances 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 rental income line item on the Company’s Statements of Operations. Oil and natural gas derivative contracts See Note 1 for discussion of the Company’s accounting for derivative contracts. Adoption of new revenue recognition and disclosure guidance In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) which generally requires an entity to identify performance obligations in its contracts, estimate the amount of consideration to be received in the transaction price, allocate the transaction price to each separate performance obligation and recognize revenue as obligations are satisfied. Additionally, the standard requires expanded disclosures related to revenue recognition. Subsequent to the issuance of ASU 2014-09, the FASB issued additional guidance to assist entities with implementation efforts, including the issuance of ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), The Company adopted the new revenue recognition and presentation guidance 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 and utilizes a cumulative effect adjustment to retained earnings in the period of adoption to account for prior period effects rather than restating previously reported results. The Company chose to use the modified retrospective method upon adoption and has applied the guidance only to contracts that are not complete at the date of initial application. Adoption of the new guidance had no cumulative effect impact on the Company's retained earnings at October 1, 2018. The standard did not have a material effect on the timing or measurement of the Company's revenue recognition or its financial position, results of operations, net income and cash flows. Additionally, the application of ASU 2016-08’s gross versus net presentation guidance did not impact the Company’s presentation of revenues and expenses. As the Company’s interests in oil and natural gas properties are non-operated interests or royalty interests, the Company evaluated its agreements with operators in connection with the ASC 606 principal versus agent indicators. Consistent with previous conclusions under ASC 605, the Company concluded that the operators act as an agent in the transfer of commodities to third-party customers. This determination required judgment in the application of the guidance for principal versus agent under ASC 606. Revenues from Contracts with Customers Oil, NGL and natural gas sales Sales of oil, NGL and natural gas are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location. The price the Company receives for natural gas and NGL is tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies. These market indices are determined on a monthly basis. Each unit of commodity is considered a separate performance obligation; however, as consideration is variable, the Company utilizes the variable consideration allocation exception permitted under the standard to allocate the variable consideration to the specific units of commodity to which they relate. Disaggregation of oil, NGL and natural gas revenues The following table presents the disaggregation of the Company's oil, NGL and natural gas revenues for the year ended September 30, 2019. Year Ended September 30, 2019 Royalty Interest Working Interest Total Oil revenue $ 7,057,906 $ 11,072,081 $ 18,129,987 NGL revenue 1,148,033 2,549,920 3,697,953 Natural gas revenue 5,785,686 11,796,410 17,582,096 Oil, NGL and natural gas sales $ 13,991,625 $ 25,418,411 $ 39,410,036 Performance obligations The Company satisfies the performance obligations under its oil and natural gas sales contracts upon delivery of its production and related transfer of title to purchasers. Upon delivery of production, the Company has a right to receive consideration from its purchasers in amounts that correspond with the value of the production transferred. Allocation of transaction price to remaining performance obligations Oil, NGL and natural gas sales As the Company has determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. The Company has utilized the practical expedient in ASC 606, which permits the Company to allocate variable consideration to one or more but not all performance obligations in the contract if the terms of the variable payment relate specifically to the Company’s efforts to satisfy that performance obligation and allocating the variable amount to the performance obligation is consistent with the allocation objective under ASC 606. Additionally, the Company will not disclose variable consideration subject to this practical expedient Prior-period performance obligations and contract balances The Company records revenue in the month production is delivered to the purchaser. As a non-operator, the Company has limited control and visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered. As a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the Oil, NGL and natural gas sales receivables line item in the accompanying Balance Sheets. The difference between the Company's estimates and the actual amounts received for oil, NGL and natural gas sales is recorded in the quarter that payment is received from the third party. For the years ended September 30, 2019, 2018 and 2017, revenue recognized in these reporting periods related to performance obligations satisfied in prior reporting periods was immaterial and considered a change in estimate.

Income Taxes

Income Taxes	12 Months Ended
	Sep. 30, 2019
Income Tax Disclosure [Abstract]
Income Taxes	4. INCOME TAXES The Company’s provision (benefit) for income taxes is detailed as follows: 2019 2018 2017 Current: Federal $ (1,388,000 ) $ 204,000 $ 314,000 State 19,000 20,000 - (1,369,000 ) 224,000 314,000 Deferred: Federal (9,763,000 ) (13,240,000 ) 390,000 State (2,349,000 ) 277,000 (15,000 ) (12,112,000 ) (12,963,000 ) 375,000 $ (13,481,000 ) $ (12,739,000 ) $ 689,000 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: 2019 2018 2017 Provision (benefit) for income taxes at statutory rate $ (11,387,447 ) $ 465,253 $ 1,477,327 Percentage depletion (431,340 ) (577,780 ) (570,801 ) State income taxes, net of federal provision (benefit) (1,986,850 ) 36,980 3,900 Effect of graduated rates - - 85,644 Restricted stock tax benefit 185,000 (69,000 ) (238,000 ) Deferred directors compensation benefit (38,000 ) (134,000 ) (79,000 ) Law change (a) - (12,464,000 ) - Other 177,637 3,547 9,930 $ (13,481,000 ) $ (12,739,000 ) $ 689,000 (a) This is the tax effect of the Tax Cuts and Jobs Act (enacted in December 2017) on our deferred tax liabilities. This Act reduced the U.S. federal corporate tax rate from 35% to 21%. 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: 2019 2018 Deferred tax liabilities: Financial basis in excess of tax basis, principally intangible drilling costs capitalized for financial purposes and expensed for tax purposes $ 8,885,776 $ 23,885,522 Derivative contracts 619,392 - 9,505,168 23,885,522 Deferred tax assets: State net operating loss carry forwards 431,977 551,435 AMT credit carry forwards 1,387,042 2,936,457 Asset retirement obligations 459,810 420,761 Deferred directors' compensation 602,394 693,592 Restricted stock expense 119,697 238,477 Derivative contracts - 839,573 Business interest limitation 358,110 - Other 170,131 117,220 3,529,161 5,797,515 Net deferred tax liabilities $ 5,976,007 $ 18,088,007 Included in state net operating loss carry forwards at September 30, 2019, the Company had a deferred tax asset of $381,906 related to Oklahoma state income tax net operating loss (OK NOL) carry forwards expiring in 2037. There is no valuation allowance for the OK NOLs, as management believes they will be utilized before they expire. The AMT carry forwards do not have an expiration date. The corporate alternative minimum tax was repealed by The Tax Cuts and Jobs Act (enacted on December 22, 2017). Taxpayers with AMT credit carryovers can use the credits to offset regular tax liability for any taxable year. In addition, the AMT credit is refundable in any taxable year beginning after 2017 and before 2022 in an amount equal to 50% (100% in the case of taxable years beginning in 2021) of the excess of the minimum tax credit for the taxable year over the amount of the credit allowable for the year against regular tax liability. Thus, the Company’s entire AMT credit carryforward amounts are fully refundable by 2023. The Company also had a deferred asset of $358,110 related to business interest limitations. This deferred asset does not expire and the Company does not have a valuation allowance for this asset, as we believe that it will be utilized in the future.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Sep. 30, 2019
Debt Disclosure [Abstract]
Long-Term Debt	5. LONG-TERM DEBT 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 $70,000,000 and a maturity date of November 30, 2022. 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 $74,435,747 at September 30, 2019. The interest rate is based on BOK prime plus from 0.50% to 1.25%, or 30-day LIBOR plus from 2.00% to 2.75%. 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, 2019, the effective interest rate was 4.34%. 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 (usually June and December) or whenever the banks, in their sole discretion, believe that there has been a material change in the value of the Company’s oil and natural gas properties. The borrowing base for the credit facility was redetermined in August 2019 by the banks and reduced to $70,000,000. 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. The loan agreement sets limits on dividend payments and stock repurchases if those payments would cause the leverage ratio to go above 2.75 to 1.0. In addition, the Company is required to maintain certain financial ratios, a current ratio (as defined by the bank agreement – current assets includes availability under outstanding credit facility) of no less than 1.0 to 1.0 and a funded debt to EBITDA (trailing 12 months as defined by the bank agreement – traditional EBITDA with the unrealized gain or loss on derivative contracts also removed from earnings) of no more than 4.0 to 1.0. At September 30, 2019, the Company was in compliance with the covenants of the loan agreement and had $34,575,000 of availability under its outstanding credit facility.

Stockholders' Equity

Stockholders' Equity	12 Months Ended
	Sep. 30, 2019
Stockholders Equity Note [Abstract]
Stockholders' Equity	6. STOCKHOLDERS’ EQUITY Upon approval by the stockholders of the Company’s 2010 Restricted Stock Plan in March 2010, as amended in May 2018, the board of directors approved to continue to allow management to repurchase up to $1.5 million of the Company’s common stock at their discretion. The repurchase of an additional $1.5 million of the Company’s common stock continues to be authorized and approved effective when the previous amount is utilized. The Board added language to clarify that this is intended to be an evergreen provision. The number of shares allowed to be purchased by the Company under the repurchase program is no longer capped at an amount equal to the aggregate number of shares of common stock (i) awarded pursuant to the Company’s Amended 2010 Restricted Stock Plan, (ii) contributed by the Company to its ESOP, and (iii) credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors. For the year ended September 30, 2019, $7,454,000 had been spent to purchase 515,972 shares. The shares are held in treasury and are accounted for using the cost method.

Earnings (Loss) Per Share

Earnings (Loss) Per Share	12 Months Ended
	Sep. 30, 2019
Earnings Per Share [Abstract]
Earnings (Loss) Per Share	7. EARNINGS (LOSS) PER SHARE The following table sets forth the computation of earnings (loss) per share. Year Ended September 30, 2019 2018 2017 Numerator for basic and diluted earnings (loss) per share: Net income (loss) $ (40,744,938 ) $ 14,635,669 $ 3,531,933 Denominator for basic and diluted earnings per share: Weighted average shares (including for 2019, 2018 and 2017, unissued, vested directors' shares of 168,586, 205,736 and 253,603, respectively) 16,743,746 16,952,664 16,900,185

Employee Stock Ownership Plan

Employee Stock Ownership Plan	12 Months Ended
	Sep. 30, 2019
Share Based Arrangements To Obtain Goods And Services [Abstract]
Employee Stock Ownership Plan	8. EMPLOYEE STOCK OWNERSHIP PLAN The Company’s ESOP was established in 1984 and is a tax qualified, defined contribution plan that serves as the sole retirement plan for all its employees to which the Company makes contributions. 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. Compensation expense is equal to the contributions for each year. The 182,337 shares of the Company’s Common Stock held by the plan as of September 30, 2019, are allocated to individual participant accounts, are included in the weighted average shares outstanding for purposes of earnings-per-share computations and receive dividends. Contributions to the plan consisted of: Year Shares Amount 2019 26,629 $ 372,274 2018 20,632 $ 382,174 2017 13,125 $ 312,380

Deferred Compensation Plan For

Deferred Compensation Plan For Directors	12 Months Ended
	Sep. 30, 2019
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Deferred Compensation Plan For Directors	9. DEFERRED COMPENSATION PLAN FOR DIRECTORS Annually, independent 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 independent 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, 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, 2019, there were 179,226 shares (212,574 shares at September 30, 2018) recorded under the Plan. The deferred balance outstanding at September 30, 2019, under the Plan was $2,555,781 ($2,950,405 at September 30, 2018). Expenses totaling $272,491, $301,715 and $358,658 were charged to the Company’s results of operations for the years ended September 30, 2019, 2018 and 2017, respectively, and are included in general and administrative expense in the accompanying Statements of Operations.

Restricted Stock Plan

Restricted Stock Plan	12 Months Ended
	Sep. 30, 2019
Restricted Stock Plan [Abstract]
Restricted Stock Plan	10. RESTRICTED STOCK PLAN In March 2010, stockholders 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 stockholders. In March 2014, stockholders 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, as amended, 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 stockholders. 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 awards 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. Compensation expense for the restricted stock awards is recognized in G&A. Forfeitures of awards are recognized when they occur. The dilutive impact of all restricted stock plans is immaterial for all periods presented. The following table summarizes the Company’s pre-tax compensation expense for the years ended September 30, 2019, 2018 and 2017, related to the Company’s performance based and non-performance based restricted stock. Year Ended September 30, 2019 2018 2017 Performance based, restricted stock $ 367,091 $ 276,272 $ 233,122 Non-performance based, restricted stock 404,706 379,142 364,818 Total compensation expense $ 771,797 $ 655,414 $ 597,940 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. Unrecognized Compensation Cost Weighted Average (in years) Performance based, restricted stock $ 105,592 1.95 Non-performance based, restricted stock 166,100 1.36 Total $ 271,692 Upon vesting, shares are expected to be issued out of shares held in treasury. A summary of the status of, and changes in, unvested shares of restricted stock awards and changes is presented below: Performance Based Unvested Restricted Awards Weighted Average Grant-Date Fair Value Non- Performance Based Restricted Awards Weighted Average Grant-Date Fair Value Unvested shares as of September 30, 2016 114,417 $ 9.78 43,011 $ 16.25 Granted 20,531 14.27 16,426 24.41 Vested (34,672 ) 8.07 (28,449 ) 18.02 Forfeited (1,186 ) 8.07 (5,991 ) 17.04 Unvested shares as of September 30, 2017 99,090 $ 11.33 24,997 $ 19.41 Granted 29,099 11.34 19,918 20.77 Vested (35,485 ) 12.18 (16,248 ) 19.34 Forfeited - - - - Unvested shares as of September 30, 2018 92,704 $ 11.00 28,667 $ 20.40 Granted 43,287 8.24 27,978 15.61 Vested - - (24,785 ) 18.30 Forfeited (89,321 ) 10.08 (13,153 ) 18.23 Unvested shares as of September 30, 2019 46,670 $ 10.21 18,707 $ 17.54 The intrinsic value of the vested shares in 2019 was $368,259.

Information On Oil And Natural

Information On Oil And Natural Gas Producing Activities	12 Months Ended
	Sep. 30, 2019
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Information On Oil And Natural Gas Producing Activities	11. INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES The oil and natural gas producing activities of the Company are conducted within the contiguous United States (principally in Oklahoma, Texas, Arkansas and North Dakota) and represent substantially all of the business activities of the Company. The following table shows sales, by percentage, through various operators/purchasers during 2019, 2018 and 2017. 2019 2018 2017 Company A 23 % 24 % 18 % Company B 8 % 16 % 3 % Company C 8 % 11 % 8 % Company D 5 % 7 % 13 % The loss of any of these major purchasers of oil, NGL and natural gas production could have a material adverse effect on the ability of the Company to produce and sell its oil, NGL and natural gas production.

Subsequent Events

Subsequent Events	12 Months Ended
	Sep. 30, 2019
Subsequent Events [Abstract]
Subsequent Events	12. SUBSEQUENT EVENTS On November 14, 2019, Panhandle closed on the sale of 530 net mineral acres in Eddy County, New Mexico, for $3.4 million. On November 22, 2019, Panhandle signed a PSA to acquire 704 net mineral acres in Kingfisher, Canadian and Garvin Counties, Oklahoma, for a purchase price of $9.65 million (subject to normal closing adjustments). We expect to close on this purchase by the end of the calendar year and it will be mostly funded with cash from our like-kind exchange sales.

Supplementary Information On Oi

Supplementary Information On Oil, NGL And Natural Gas Reserves	12 Months Ended
	Sep. 30, 2019
Extractive Industries [Abstract]
Supplementary Information On Oil, NGL And Natural Gas Reserves	13. SUPPLEMENTARY INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES (UNAUDITED) Aggregate Capitalized Costs The aggregate amount of capitalized costs of oil and natural gas properties and related accumulated depreciation, depletion and amortization as of September 30 is as follows: 2019 2018 Producing properties $ 354,718,398 $ 427,448,584 Non-producing minerals 14,413,899 12,378,395 Non-producing leasehold 185,124 185,124 Exploratory wells in progress - - 369,317,421 440,012,103 Accumulated depreciation, depletion and amortization (258,063,849 ) (242,169,604 ) Net capitalized costs $ 111,253,572 $ 197,842,499 Costs Incurred For the years ended September 30, the Company incurred the following costs in oil and natural gas producing activities: 2019 2018 2017 Property acquisition costs $ 6,235,905 $ 11,409,673 $ 20,190 Exploration costs - - - Development costs 3,012,095 10,291,476 25,382,377 $ 9,248,000 $ 21,701,149 $ 25,402,567 Estimated Quantities of Proved Oil, NGL and Natural Gas Reserves The following unaudited information regarding the Company’s oil, NGL and natural gas reserves is presented pursuant to the disclosure requirements promulgated by the SEC and the FASB . Proved oil and natural gas reserves are those quantities of oil and natural gas which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes: (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated natural gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. The independent consulting petroleum engineering firm of DeGolyer and MacNaughton of Dallas, Texas, prepared the Company’s oil, NGL and natural gas reserves estimates as of September 30, 2019, 2018 and 2017. The Company’s net proved oil, NGL and natural gas reserves, which are located in the contiguous United States, as of September 30, 2019, 2018 and 2017, 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 principles 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 of Operations, Freda Webb. Ms. Webb holds a Bachelor of Science degree in Mechanical Engineering from the University of Oklahoma, a Master of Science degree in Petroleum Engineering from the University of Southern California and a Professional Engineering License in Petroleum Engineering in the State of Oklahoma. Ms. Webb has more than 36 years of experience in the oil and gas industry. Before joining the Company, she was sole proprietor of a consulting petroleum engineering firm and a mineral acquisition company. Ms. Webb held various positions of increasing responsibility at Southwestern Energy Company and Occidental Petroleum Corporation, with reservoir engineering assignments in several field locations across the United States. She is an active member of the Society of Petroleum Engineers (SPE). Our Vice President of Operations 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, 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 Total (Barrels) (Barrels) (Mcf) Bcfe September 30, 2016 5,426,090 1,622,703 81,725,598 124.0 Revisions of previous estimates 253,481 407,250 13,651,501 17.6 Acquisitions (divestitures) (37,724 ) (12,953 ) (669,064 ) (1.0 ) Extensions, discoveries and other additions 178,497 541,557 34,681,614 39.0 Production (310,677 ) (173,858 ) (8,194,529 ) (11.1 ) September 30, 2017 5,509,667 2,384,699 121,195,120 168.6 Revisions of previous estimates (1,407,995 ) 303,728 (29,247 ) (6.7 ) Acquisitions (divestitures) 236,690 24,765 (1,782,949 ) (0.2 ) Extensions, discoveries and other additions 1,982,624 476,174 9,400,374 24.2 Production (336,564 ) (255,176 ) (8,721,262 ) (12.3 ) September 30, 2018 5,984,422 2,934,190 120,062,036 173.6 Revisions of previous estimates (3,266,351 ) (890,046 ) (35,644,135 ) (60.6 ) Acquisitions (divestitures) (322,023 ) (18,881 ) (948,496 ) (3.0 ) Extensions, discoveries and other additions 313,241 164,276 3,891,262 6.8 Production (329,199 ) (216,259 ) (7,086,761 ) (10.4 ) September 30, 2019 2,380,090 1,973,280 80,273,906 106.4 The prices used to calculate reserves and future cash flows from reserves for oil, NGL and natural gas, respectively, were as follows: September 30, 2019 - $54.40/Bbl, $19.30/Bbl, $2.48/Mcf; September 30, 2018 - $62.86/Bbl, $26.13/Bbl, $2.56/Mcf; September 30, 2017 - $46.31/Bbl, $17.55/Bbl, $2.81/Mcf. The revisions of previous estimates from 2018 to 2019 were primarily the result of: • Negative pricing revisions of 4.4 Bcfe, primarily resulting from oil and natural gas wells currently projected to reach their economic limits earlier than was projected in 2018 due to lower oil prices and higher natural gas price deducts in 2019 relative to 2018; proved developed revisions of 4.3 Bcfe and PUD revisions of 0.1 Bcfe. • Negative revisions of 56.2 Bcfe. Proved undeveloped negative revisions of 48.2 Bcfe were the result of the Company implementing the new strategy of not participating with a working interest in future drilling programs, which resulted in removal of undeveloped leasehold wells, including the Eagle Ford Shale, and lowering the net revenue interest on previously planned working interest wells on our mineral acreage to a royalty revenue interest only. These proved undeveloped locations remaining are in active areas of our core mineral acreage. Proved developed revisions were negative 8.0 Bcfe, principally due to lower performance of our high-interest Woodford gas wells drilled in 2017 in the Arkoma Stack and, to a lesser extent, lower performance of the Fayetteville Shale gas properties in Arkansas. Acquisitions and divestitures were the result of: • The acquisition of 0.8 Bcfe, predominately in the active drilling program of the Bakken in North Dakota; 0.5 Bcfe were proved developed and 0.3 Bcfe were proved undeveloped. • The sale of 3.8 Bcfe, predominately in the Permian Basin in Texas and New Mexico; 2.2 Bcfe were proved developed and 1.6 Bcfe were proved undeveloped. Extensions, discoveries and other additions from 2018 to 2019 are principally attributable to: • Proved developed reserve extensions, discoveries and other additions of 2.1 Bcfe a) The Company’s royalty interest ownership in the ongoing development of unconventional oil, NGL and natural gas utilizing extended horizontal drilling in the Woodford Shale in the STACK, SCOOP and Arkoma Stack in Oklahoma. b) The Company’s royalty interest ownership in ongoing development of unconventional oil, NGL and natural gas utilizing horizontal drilling in the STACK Meramec play in the Anadarko Basin in western Oklahoma. c) The Company’s royalty interest ownership in ongoing development of conventional and unconventional oil, NGL and natural gas utilizing horizontal drilling in the Permian Basin. • The addition of 4.7 Bcfe of PUD reserves within the Company’s active drilling program areas of 1) the STACK Meramec in western Oklahoma 2) the SCOOP Woodford Shale in western Oklahoma, 3) the Woodford Shale in the Arkoma Stack, 4) the Marmaton in Ellis County, Oklahoma, and 5) the Yeso in Eddy County, New Mexico. • Production of 10.4 Bcfe from the Company’s oil and natural gas properties. Proved Developed Reserves Proved Undeveloped Reserves Oil NGL Natural Oil NGL Natural (Barrels) (Barrels) (Mcf) (Barrels) (Barrels) (Mcf) September 30, 2017 2,201,528 1,768,425 87,861,043 3,308,139 616,274 33,334,077 September 30, 2018 2,334,587 2,085,706 83,151,954 3,649,835 848,484 36,910,082 September 30, 2019 1,863,096 1,747,242 67,713,193 516,994 226,038 12,560,713 The following details the changes in proved undeveloped reserves for 2019 (Mcfe): Beginning proved undeveloped reserves 63,899,996 Proved undeveloped reserves transferred to proved developed (1,763,402 ) Revisions (48,404,716 ) Extensions and discoveries 4,679,986 Sales (1,648,780 ) Purchases 255,821 Ending proved undeveloped reserves 17,018,905 For the fiscal year ending September 30, 2019, our beginning PUD reserves were 63.9 Bcfe. In 2019, a total of 1.8 Bcfe (3% of the beginning balance) was transferred to proved developed. The 48.4 Bcfe (76% of the beginning balance) of negative revisions to PUD reserves were pricing revisions of 0.2 Bcfe and a revision of 48.2 Bcfe, predominately resulting from the removal of oil, NGL and natural gas reserves associated with working interest in Eagle Ford wells and working interests in wells in STACK, SCOOP and Arkoma Stack plays consistent with the Company implementing the strategy to no longer participate with working interests moving forward. The proved undeveloped locations remaining are royalty interest only and are in active areas of our core mineral acreage. We anticipate that all the Company’s current 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 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 4.7 Bcfe of royalty interest PUD reserves in 2019 within the active drilling program areas of 1) the SCOOP Woodford Shale in western Oklahoma, 2) the Anadarko Basin STACK Meramec in western Oklahoma, 3) the Marmaton in Ellis County, Oklahoma, 4) the Arkoma Stack in eastern Oklahoma and 5) the Yeso in Eddy County, New Mexico. These additions result from continuing development and additional well performance data in each of the referenced plays. Additionally, the Company purchased 0.3 Bcfe in the Bakken in North Dakota and sold 1.6 Bcfe, predominately in the Permian Basin in Texas and New Mexico. Standardized Measure of Discounted Future Net Cash Flows Accounting Standards prescribe guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves. The Company has followed these guidelines, which are briefly discussed below. Future cash inflows and future production and development costs are determined by applying the trailing unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs to the estimated quantities of oil, NGL and natural gas to be produced. Actual future prices and costs may be materially higher or lower than the unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which they are expected to be produced, based on continuation of the economic conditions applied for such year. Estimated future income taxes are computed using current statutory income tax rates, including consideration for the current tax basis of the properties and related carry forwards, giving effect to permanent differences and tax credits. The resulting future net cash flows are reduced to present value amounts by applying a 10% annual discount factor. The assumptions used to compute the standardized measure are those prescribed by the FASB and, as such, do not necessarily reflect our expectations of actual revenue to be derived from those reserves nor their present worth. The limitations inherent in the reserve quantity estimation process, as discussed previously, are equally applicable to the standardized measure computations since these estimates affect the valuation process. 2019 2018 2017 Future cash inflows $ 366,697,321 $ 759,899,074 $ 637,509,599 Future production costs (153,935,373 ) (259,413,766 ) (256,193,675 ) Future development and asset retirement costs (1,917,937 ) (89,518,449 ) (93,133,683 ) Future income tax expense (47,788,416 ) (95,872,182 ) (102,193,819 ) Future net cash flows 163,055,595 315,094,677 185,988,422 10% annual discount (77,494,066 ) (158,768,823 ) (105,155,847 ) Standardized measure of discounted future net cash flows $ 85,561,529 $ 156,325,854 $ 80,832,575 Changes in the standardized measure of discounted future net cash flows are as follows: 2019 2018 2017 Beginning of year $ 156,325,854 $ 80,832,575 $ 29,770,119 Changes resulting from: Sales of oil, NGL and natural gas, net of production costs (25,072,122 ) (32,836,007 ) (25,783,055 ) Net change in sales prices and production costs (76,588,460 ) 47,533,281 37,186,619 Net change in future development and asset retirement costs 43,607,535 1,580,942 (7,939,156 ) Extensions and discoveries 7,074,245 34,667,557 38,582,908 Revisions of quantity estimates (60,308,497 ) (8,391,223 ) 15,282,587 Acquisitions (divestitures) of reserves-in-place (3,134,783 ) (307,472 ) (962,667 ) Accretion of discount 20,457,930 12,602,209 4,789,294 Net change in income taxes 23,413,194 (3,057,128 ) (27,070,430 ) Change in timing and other, net (213,367 ) 23,701,120 16,976,356 Net change (70,764,325 ) 75,493,279 51,062,456 End of year $ 85,561,529 $ 156,325,854 $ 80,832,575

Quarterly Results Of Operations

Quarterly Results Of Operations (Unaudited)	12 Months Ended
	Sep. 30, 2019
Quarterly Financial Information Disclosure [Abstract]
Quarterly Results Of Operations	14. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED) The following is a summary of the Company’s unaudited quarterly results of operations. Fiscal 2019 Quarter Ended December March 31 June 30 September 30 Revenues $ 26,328,994 $ 7,636,213 $ 16,342,394 $ 15,728,084 Income (loss) before provision for income taxes $ 16,306,940 $ (2,061,334 ) $ 5,919,236 $ (74,390,780 ) Net income (loss) $ 12,735,940 $ (1,931,334 ) $ 4,604,236 $ (56,153,780 ) Earnings (loss) per share $ 0.75 $ (0.11 ) $ 0.28 $ (3.35 ) Fiscal 2018 Quarter Ended December 31 March 31 June 30 September 30 Revenues $ 12,490,526 $ 11,421,258 $ 9,557,937 $ 11,564,543 Income (loss) before provision for income taxes $ 1,074,939 $ 1,046,176 $ (984,093 ) $ 759,647 Net income (loss) $ 13,784,939 $ 1,070,176 $ (775,093 ) $ 555,647 Earnings (loss) per share $ 0.81 $ 0.06 $ (0.05 ) $ 0.04

Summary Of Significant Accoun_2

Summary Of Significant Accounting Policies (Policies)	12 Months Ended
	Sep. 30, 2019
Accounting Policies [Abstract]
Nature Of Business	Nature of Business 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 Oklahoma, North Dakota, Texas, Arkansas and New Mexico, with properties located in several other states. The Company’s oil, NGL and natural gas production is from interests in 6,496 wells located principally in Oklahoma, Texas, Arkansas and North Dakota. The Company does not operate any wells. Approximately 46%, 9% and 45% of oil, NGL and natural gas revenues were derived from the sale of oil, NGL and natural gas, respectively, in 2019. Approximately 19%, 13% and 68% of the Company’s total sales volumes in 2019 were derived from oil, NGL and natural gas, respectively. 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.
Use Of Estimates	Use of Estimates 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. The Company’s Independent Consulting Petroleum Engineer, with assistance from the Company, prepares estimates of crude oil, NGL and natural gas reserves on an annual basis, with a semi-annual update. These estimates are 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.
Basis Of Presentation	Basis of Presentation Certain amounts (loss (gain) on asset sales and other in the Statements of Operations and presentation of deferred tax assets and liabilities in Note 4: Income Taxes) in the prior years have been reclassified to conform to the current year presentation.
Cash And Cash Equivalents	Cash and Cash Equivalents Cash and cash equivalents consist of all demand deposits and funds invested in short-term investments with original maturities of three months or less.
Oil, NGL And Natural Gas Sales	Oil, NGL and Natural Gas Sales 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.
Accounts Receivable And Concentration Of Credit Risk	Accounts Receivable and Concentration of Credit Risk 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 2019, 2018 and 2017 the Company The Company’s was not material.
Oil And Natural Gas Producing Activities	Oil and Natural Gas Producing Activities 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 reach commercial production levels. Oil and natural gas mineral and leasehold costs are capitalized when incurred.
Leasing Of Mineral Rights	Leasing of Mineral Rights The Company generates lease bonuses by leasing its mineral interests to exploration and production companies. A lease agreement represents the Company's contract with a third party and generally conveys the rights to any oil, NGL or natural gas discovered, grants the Company a right to a specified royalty interest and requires that drilling and completion operations commence within a specified time period. Control is transferred to the lessee and the Company has satisfied its performance obligation when the lease agreement is executed, such that revenue is recognized when the lease bonus payment is received. The Company accounts for its lease bonuses as conveyances 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 income. 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.
Derivatives	Derivatives 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 at September 30, 2019 and 2018, were with Bank of Oklahoma and Koch Supply and Trading LP. The Company’s derivative contracts with Bank of Oklahoma are secured under its credit facility with Bank of Oklahoma. The derivative contracts with Koch are unsecured. The derivative instruments have settled or will settle based on the prices below. Derivative contracts in place as of September 30, 2019 Production volume Contract period covered per month Index Contract price Natural gas fixed price swaps July - December 2019 100,000 Mmbtu NYMEX Henry Hub $2.960 July - December 2019 100,000 Mmbtu NYMEX Henry Hub $2.950 July - December 2019 100,000 Mmbtu NYMEX Henry Hub $2.995 July 2019 - March 2020 100,000 Mmbtu NYMEX Henry Hub $2.982 August - December 2019 100,000 Mmbtu NYMEX Henry Hub $3.004 January - December 2020 80,000 Mmbtu NYMEX Henry Hub $2.750 Oil costless collars January - December 2019 1,000 Bbls NYMEX WTI $50.00 floor / $60.00 ceiling January - December 2019 2,000 Bbls NYMEX WTI $60.00 floor / $69.25 ceiling July - December 2019 3,000 Bbls NYMEX WTI $60.00 floor / $70.75 ceiling July 2019 - June 2020 2,000 Bbls NYMEX WTI $65.00 floor / $76.15 ceiling January - June 2020 2,000 Bbls NYMEX WTI $60.00 floor / $67.00 ceiling January - December 2020 2,000 Bbls NYMEX WTI $55.00 floor / $62.00 ceiling Oil fixed price swaps January - December 2019 1,000 Bbls NYMEX WTI $56.15 January - December 2019 2,000 Bbls NYMEX WTI $56.71 January - December 2019 1,000 Bbls NYMEX WTI $58.56 July - December 2019 2,000 Bbls NYMEX WTI $56.85 July - December 2019 5,000 Bbls NYMEX WTI $58.50 July - December 2019 1,000 Bbls NYMEX WTI $60.60 January - December 2020 2,000 Bbls NYMEX WTI $55.28 January - December 2020 2,000 Bbls NYMEX WTI $58.65 January - December 2020 2,000 Bbls NYMEX WTI $60.00 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 asset of $2,494,144 as of September 30, 2019, and a net liability of $3,414,016 as of September 30, 2018. Realized and unrealized gains and (losses) are recorded in gains (losses) on derivative contracts on the Company’s Statement of Operations. The portion of the gain (loss) on derivatives settled in cash for 2019, 2018 and 2017 was $196,985 (net received), $1,001,893 (net paid) and $305,410 (net received), respectively. 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, 2019, and September 30, 2018. The Company has offset all amounts subject to master netting agreements in the Company's Balance Sheets at September 30, 2019, and September 30, 2018. 9/30/2019 9/30/2018 Fair Value Fair Value Commodity Contracts Commodity Contracts Current Non-Current Assets Current Current Liabilities Non-Current Liabilities Gross amounts recognized $ 2,256,639 $ 237,505 $ 42,150 $ 3,106,196 $ 349,970 Offsetting adjustments - - (42,150 ) (42,150 ) - Net presentation on Balance Sheets $ 2,256,639 $ 237,505 $ - $ 3,064,046 $ 349,970 The fair value of derivative assets and derivative liabilities is adjusted for credit risk. The impact of credit risk was immaterial for all periods presented.
Fair Value Measurements	Fair Value Measurements 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: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. The Company considers active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2: Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that the Company values using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity fixed-price swaps and commodity options (i.e. price collars). The Company uses an option pricing valuation model for option derivative contracts that considers various inputs including: future prices, time value, volatility factors, counterparty credit risk and current market and contractual prices for the underlying instruments. The values calculated are then compared to the values given by counterparties for reasonableness. Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and unobservable (or less observable) from objective sources (supported by little or no market activity). The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis. Fair Value Measurement at September 30, 2019 Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs Total (Level 1) (Level 2) (Level 3) Value Financial Assets (Liabilities): Derivative Contracts - Swaps $ - $ 1,892,954 $ - $ 1,892,954 Derivative Contracts - Collars $ - $ 601,190 $ - $ 601,190 Fair Value Measurement at September 30, 2018 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 $ - $ (2,317,069 ) $ - $ (2,317,069 ) Derivative Contracts - Collars $ - $ (1,096,947 ) $ - $ (1,096,947 ) 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. Year Ended September 30, 2019 2018 2017 Fair Value Impairment Fair Value Impairment Fair Value Impairment Producing Properties (a) $ 9,101,032 $ 76,824,337 $ - $ - $ 567,077 $ 662,990 (a) At the end of each quarter, the Company assessed the carrying value of its producing properties for impairment. This assessment utilized estimates of future cash flows or fair value (selling price) less cost to sell if the property is held for sale. Significant judgments and assumptions in these assessments include estimates of future oil, NGL and natural gas prices using a forward NYMEX curve adjusted for projected inflation, locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values. At September 30, 2019, and September 30, 2018, the carrying values of cash and cash equivalents, receivables, and payables are considered to be representative of their respective fair values due to the short-term maturities of those instruments.
Depreciation, Depletion and Amortization	Depreciation, Depletion and Amortization 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 $9,673,787 and $8,025,015 at September 30, 2019 and 2018, respectively, consisting of perpetual ownership of mineral interests in several states, with 91% of the acreage in Oklahoma, North Dakota, Texas, Arkansas and New Mexico. As mentioned, these mineral rights are perpetual and have been accumulated over the 93-year life of the Company. There are approximately 197,468 net acres of non-producing minerals in more than 6,688 tracts owned by the Company. An average tract contains approximately 30 acres, and the average cost per acre is $73. 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 on these mineral interests each year. 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 Company’s mineral ownership consists 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 (by mineral deed). When a new well is drilled on our mineral acreage, all of the non-producing mineral costs for the associated mineral deed are transferred to producing minerals and are amortized straight-line over a 20-year period (insignificant fields are amortized over 10-year period). Management has historically chosen to move non-producing mineral costs in this manner, as it is very difficult for the Company, as a non-operator, to predict well spacing and timing of drilling on all of the minerals that we have purchased over the long life of the Company. Given that we are moving all of the costs to the first new well drilled on each mineral deed, we believe that a straight-line amortization over a 20-year period is appropriate as these wells and future development will deplete these assets over a fairly long period.
Impairment	Impairment 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 At the end of 2019, impairment of $76,560,376 was recorded on our Eagle Ford assets. The remaining $263,961 of impairment was taken on other assets. The impairment on the Eagle Ford assets was caused by the Company making the strategic decision to cease participating with a working interest on its mineral and leasehold acreage going forward and therefore removing all working interest PUDs from the Company’s reserve reports. The removal of the PUDs caused the Eagle Ford assets to fail the step one test for impairment, as its undiscounted cash flows were not high enough to cover the book basis of the assets. These assets were written down to their fair market value as required by GAAP. The Company determined the fair value based on discounted cash flows of the properties as well as active market bids received from interested potential buyers. The discounted cash flows of the properties were prepared using NYMEX strip pricing as of year-end, using a discount rate of 10% for proved developed and assigning no value to undeveloped locations. Market bids received from interested potential buyers corroborated the fair value of the discounted cash flows as of year-end. The fair value was determined to be $9.1 million based on the discounted cash flows and market quotes. The Company decided not to sell the assets after the marketing process was complete, as we believed that the market conditions were not ideal for selling at that time and that the highest and best use of the assets was to continue to own and produce out the Eagle Ford properties. 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.
Divestitures	Divestitures During the 2019 fiscal year, the Company sold 112 non-core wells and 890 net mineral and non-participating royalty interest acres for $19,515,735 and recorded a net gain on sales of $18,730,197. The total net book value that was removed from the Balance Sheets due to these sales was approximately $786,000. On the Statements of Operations, the net gain is reflected in the Gain on asset sales line item with a balance of $18,973,426 with an offset to the Loss on asset sales line item in the amount of $243,228. During the 2018 fiscal year, the Company sold 324 non-core marginal wells for $1,085,137 and recorded a net loss on the sales of $660,597. The total net book value that was removed from the Balance Sheets due to these sales was approximately $1.7 million. The loss on sales was included in the Loss on asset sales and other line of the Statements of Operations.
Acquisitions	Acquisitions During the 2019 fiscal year, the Company acquired mineral acreage in the cores of the Bakken in North Dakota and the STACK and SCOOP plays in Oklahoma. The Company acquired a total of 790 net mineral acres for $5.7 million or an average of approximately $7,200 per net mineral acre. These mineral purchases were accounted for as asset acquisitions. During the 2018 fiscal year, the Company acquired mineral acreage in the cores of the Bakken in North Dakota and the STACK and SCOOP plays in Oklahoma. The Company acquired a total of 4,306 net mineral acres for $11.3 million or an average of approximately $2,600 per net mineral acre. These mineral purchases were accounted for as asset acquisitions.
Capitalized Interest	Capitalized Interest During 2019
Accrued Liabilities	Accrued Liabilities The following table shows the balances for the years ended September 30, 2019 and 2018, relating to the Company’s accrued liabilities: Year Ended September 30, 2019 2018 Accrued compensation $ 1,446,710 $ 905,445 Revenues payable 396,954 253,850 Accrued ad valorem 260,550 317,105 Other 329,252 315,550 Total accrued liabilities $ 2,433,466 $ 1,791,950 The increase in accrued compensation is primarily due to the one-time severance with the Company’s former CEO of approximately $670,000 upon his resignation towards the end of fiscal 2019. This increase was somewhat offset by a decrease in the overall bonus accrual for 2019 as compared to 2018. The increase in revenues payable was primarily due to oil, NGL and natural gas revenues received on properties sold during 2019 that related to production after the effective date of the sale.
Asset Retirement Obligations	Asset Retirement Obligations 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, 2019 and 2018, relating to the Company’s asset retirement obligations: 2019 2018 Asset retirement obligations as of beginning of the year $ 2,809,378 $ 3,196,889 Wells acquired or drilled 27,783 17,215 Wells sold or plugged (134,090 ) (542,892 ) Accretion of discount 132,710 138,166 Asset retirement obligations as of end of the year $ 2,835,781 $ 2,809,378 As a non-operator, we do not control the plugging of wells in which we have a working interest and are not involved in the negotiation of the terms of the plugging contracts. Our estimate relies on information that we can gather from outside sources as well as relevant information that we receive directly from operators.
Environmental Costs	Environmental Costs 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 (on working interest wells only). 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, 2019 and 2018, there were no such costs accrued.
Earnings (Loss) Per Share Of Common Stock	Earnings (Loss) Per Share of Common Stock 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.
Share-based Compensation	Share-based Compensation 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 only upon retirement, termination or death of the director or upon a change in control of the Company, the shares accrued under the Plan may 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 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.
Income Taxes	Income Taxes 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 Tax Cuts and Jobs Act was enacted on December 22, 2017. The Act reduced the U.S. federal corporate tax rate from 35% to 21%. As of September 30, 2018, we completed our estimates accounting for the tax effects of the Act. Based on these estimates, we recognized an amount which was included as a component of income tax expense (benefit) from continuing operations in 2018. We remeasured certain deferred tax assets and liabilities based on the rates at which they are expected to reverse in the future, which is generally 21%. The amount recorded related to the remeasurement of our deferred tax balance was $12,464,000 income tax benefit. The Company’s provision for income taxes differs from the statutory rate primarily due to estimated federal and state benefits generated from estimated excess federal and Oklahoma percentage depletion, which are permanent tax benefits. Excess percentage depletion, both federal and Oklahoma, can only be taken in the amount that it exceeds cost depletion which is calculated on a unit-of-production basis. Both excess federal percentage depletion, which is limited to certain production volumes and by certain income levels, and excess Oklahoma percentage depletion, which has no limitation on production volume, reduce estimated taxable income or add to estimated taxable loss projected for any year. Federal and Oklahoma excess percentage depletion, when a provision for income taxes is expected for the year, decreases the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is expected for the year. The benefits of federal and Oklahoma excess percentage depletion and excess tax benefits and deficiencies of stock-based compensation are not directly related to the amount of pre-tax income (loss) recorded in a period. Accordingly, in periods where a recorded pre-tax income or loss is relatively small, the proportional effect of these items on the effective tax rate may be significant. The effective tax rate for the year ended September 30, 2018, was a 672% benefit, as compared to a 25% benefit for the year ended September 30, 2019. 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 2016. 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, 2019, 2018 and 2017, the Company’s interest and penalties were not material. The Company does not believe it has any significant uncertain tax positions.
Adoption Of New Accounting Pronouncements	Adoption of New Accounting Pronouncements Revenue recognition and presentation – In May 2014, the FASB issued Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers (Topic 606) Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net).
New Accounting Pronouncements Yet To Be Adopted	New Accounting Pronouncements yet to be Adopted In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires lessees to recognize a lease liability and a right-of-use (ROU) asset on the balance sheet for all leases, including operating leases, with terms in excess of 12 months. This ASU modifies the definition of a lease and outlines the recognition, measurement, presentation and disclosure of leasing arrangements by both lessees and lessors. The standard will not apply to our leases of mineral rights to explore for or use oil and natural gas resources, including the intangible rights to explore for those natural resources and rights to use the land in which those natural resources are contained, as these are accounted for under ASC 932. The Company plans to make certain elections permitting us to not reassess whether any expired or existing contracts contained leases, permitting us to not reassess the lease classification for any expired or existing leases (all existing leases that were classified as operating leases in accordance with Topic 840 will be classified as operating leases) and permitting us to not reassess initial direct costs for any existing leases. The Company has completed the assessment of contracts potentially affected by the new standard and has completed the assessment of the accounting treatment for these leases. The adoption will primarily impact other assets and other liabilities and will also impact ongoing disclosures but will not have a material impact on our balance sheet, results of operations or cash flows. We plan to adopt the new standard on October 1, 2019, the effective date, and as permitted by ASU 2018-11 we will not adjust comparative-period financial statements and will continue to apply the guidance in ASC 840, including its disclosure requirements, in the comparative periods presented prior to adoption. In June 2016, the FASB issued ASU 2016-13, Financial Instruments Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments 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 the financial statements upon adoption.

Summary Of Significant Accoun_3

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Sep. 30, 2019
Accounting Policies [Abstract]
Summary Of Derivative Instruments Contracts	Derivative contracts in place as of September 30, 2019 Production volume Contract period covered per month Index Contract price Natural gas fixed price swaps July - December 2019 100,000 Mmbtu NYMEX Henry Hub $2.960 July - December 2019 100,000 Mmbtu NYMEX Henry Hub $2.950 July - December 2019 100,000 Mmbtu NYMEX Henry Hub $2.995 July 2019 - March 2020 100,000 Mmbtu NYMEX Henry Hub $2.982 August - December 2019 100,000 Mmbtu NYMEX Henry Hub $3.004 January - December 2020 80,000 Mmbtu NYMEX Henry Hub $2.750 Oil costless collars January - December 2019 1,000 Bbls NYMEX WTI $50.00 floor / $60.00 ceiling January - December 2019 2,000 Bbls NYMEX WTI $60.00 floor / $69.25 ceiling July - December 2019 3,000 Bbls NYMEX WTI $60.00 floor / $70.75 ceiling July 2019 - June 2020 2,000 Bbls NYMEX WTI $65.00 floor / $76.15 ceiling January - June 2020 2,000 Bbls NYMEX WTI $60.00 floor / $67.00 ceiling January - December 2020 2,000 Bbls NYMEX WTI $55.00 floor / $62.00 ceiling Oil fixed price swaps January - December 2019 1,000 Bbls NYMEX WTI $56.15 January - December 2019 2,000 Bbls NYMEX WTI $56.71 January - December 2019 1,000 Bbls NYMEX WTI $58.56 July - December 2019 2,000 Bbls NYMEX WTI $56.85 July - December 2019 5,000 Bbls NYMEX WTI $58.50 July - December 2019 1,000 Bbls NYMEX WTI $60.60 January - December 2020 2,000 Bbls NYMEX WTI $55.28 January - December 2020 2,000 Bbls NYMEX WTI $58.65 January - December 2020 2,000 Bbls NYMEX WTI $60.00
Summary Of Derivative Contracts	9/30/2019 9/30/2018 Fair Value Fair Value Commodity Contracts Commodity Contracts Current Non-Current Assets Current Current Liabilities Non-Current Liabilities Gross amounts recognized $ 2,256,639 $ 237,505 $ 42,150 $ 3,106,196 $ 349,970 Offsetting adjustments - - (42,150 ) (42,150 ) - Net presentation on Balance Sheets $ 2,256,639 $ 237,505 $ - $ 3,064,046 $ 349,970
Summary Of Fair Value Measurement Information For Financial Assets And Liabilities Measured At Fair Value On A Recurring Basis	The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis. Fair Value Measurement at September 30, 2019 Quoted Prices in Active Markets Significant Other Observable Inputs Significant Unobservable Inputs Total (Level 1) (Level 2) (Level 3) Value Financial Assets (Liabilities): Derivative Contracts - Swaps $ - $ 1,892,954 $ - $ 1,892,954 Derivative Contracts - Collars $ - $ 601,190 $ - $ 601,190 Fair Value Measurement at September 30, 2018 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 $ - $ (2,317,069 ) $ - $ (2,317,069 ) Derivative Contracts - Collars $ - $ (1,096,947 ) $ - $ (1,096,947 )
Summary Of Impairments Associated With Certain Assets Measured At Fair Value On A Nonrecurring Basis Within Level 3	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. Year Ended September 30, 2019 2018 2017 Fair Value Impairment Fair Value Impairment Fair Value Impairment Producing Properties (a) $ 9,101,032 $ 76,824,337 $ - $ - $ 567,077 $ 662,990 (a) At the end of each quarter, the Company assessed the carrying value of its producing properties for impairment. This assessment utilized estimates of future cash flows or fair value (selling price) less cost to sell if the property is held for sale. Significant judgments and assumptions in these assessments include estimates of future oil, NGL and natural gas prices using a forward NYMEX curve adjusted for projected inflation, locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values.
Summary Of Accrued Liabilities	The following table shows the balances for the years ended September 30, 2019 and 2018, relating to the Company’s accrued liabilities: Year Ended September 30, 2019 2018 Accrued compensation $ 1,446,710 $ 905,445 Revenues payable 396,954 253,850 Accrued ad valorem 260,550 317,105 Other 329,252 315,550 Total accrued liabilities $ 2,433,466 $ 1,791,950
Summary Of Asset Retirement Obligation	The following table shows the activity for the years ended September 30, 2019 and 2018, relating to the Company’s asset retirement obligations: 2019 2018 Asset retirement obligations as of beginning of the year $ 2,809,378 $ 3,196,889 Wells acquired or drilled 27,783 17,215 Wells sold or plugged (134,090 ) (542,892 ) Accretion of discount 132,710 138,166 Asset retirement obligations as of end of the year $ 2,835,781 $ 2,809,378

Revenues (Tables)

Revenues (Tables)	12 Months Ended
	Sep. 30, 2019
Revenue From Contract With Customer [Abstract]
Summary of Disaggregation of Oil, NGL and Natural Gas Revenues	The following table presents the disaggregation of the Company's oil, NGL and natural gas revenues for the year ended September 30, 2019. Year Ended September 30, 2019 Royalty Interest Working Interest Total Oil revenue $ 7,057,906 $ 11,072,081 $ 18,129,987 NGL revenue 1,148,033 2,549,920 3,697,953 Natural gas revenue 5,785,686 11,796,410 17,582,096 Oil, NGL and natural gas sales $ 13,991,625 $ 25,418,411 $ 39,410,036

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Sep. 30, 2019
Income Tax Disclosure [Abstract]
Summary Of Provision (Benefit) For Income Taxes	2019 2018 2017 Current: Federal $ (1,388,000 ) $ 204,000 $ 314,000 State 19,000 20,000 - (1,369,000 ) 224,000 314,000 Deferred: Federal (9,763,000 ) (13,240,000 ) 390,000 State (2,349,000 ) 277,000 (15,000 ) (12,112,000 ) (12,963,000 ) 375,000 $ (13,481,000 ) $ (12,739,000 ) $ 689,000
Summary Of Difference Between Provision (Benefit) For Income Taxes And Amount Which Would Result From Application Of Federal Statutory Rate	2019 2018 2017 Provision (benefit) for income taxes at statutory rate $ (11,387,447 ) $ 465,253 $ 1,477,327 Percentage depletion (431,340 ) (577,780 ) (570,801 ) State income taxes, net of federal provision (benefit) (1,986,850 ) 36,980 3,900 Effect of graduated rates - - 85,644 Restricted stock tax benefit 185,000 (69,000 ) (238,000 ) Deferred directors compensation benefit (38,000 ) (134,000 ) (79,000 ) Law change (a) - (12,464,000 ) - Other 177,637 3,547 9,930 $ (13,481,000 ) $ (12,739,000 ) $ 689,000 (a) This is the tax effect of the Tax Cuts and Jobs Act (enacted in December 2017) on our deferred tax liabilities. This Act reduced the U.S. federal corporate tax rate from 35% to 21%.
Summary Of Deferred Tax Assets And Liabilities	2019 2018 Deferred tax liabilities: Financial basis in excess of tax basis, principally intangible drilling costs capitalized for financial purposes and expensed for tax purposes $ 8,885,776 $ 23,885,522 Derivative contracts 619,392 - 9,505,168 23,885,522 Deferred tax assets: State net operating loss carry forwards 431,977 551,435 AMT credit carry forwards 1,387,042 2,936,457 Asset retirement obligations 459,810 420,761 Deferred directors' compensation 602,394 693,592 Restricted stock expense 119,697 238,477 Derivative contracts - 839,573 Business interest limitation 358,110 - Other 170,131 117,220 3,529,161 5,797,515 Net deferred tax liabilities $ 5,976,007 $ 18,088,007

Earnings (Loss) Per Share (Tabl

Earnings (Loss) Per Share (Tables)	12 Months Ended
	Sep. 30, 2019
Earnings Per Share [Abstract]
Summary Of Computation Of Earnings (Loss) Per Share	The following table sets forth the computation of earnings (loss) per share. Year Ended September 30, 2019 2018 2017 Numerator for basic and diluted earnings (loss) per share: Net income (loss) $ (40,744,938 ) $ 14,635,669 $ 3,531,933 Denominator for basic and diluted earnings per share: Weighted average shares (including for 2019, 2018 and 2017, unissued, vested directors' shares of 168,586, 205,736 and 253,603, respectively) 16,743,746 16,952,664 16,900,185

Employee Stock Ownership Plan (

Employee Stock Ownership Plan (Tables)	12 Months Ended
	Sep. 30, 2019
Share Based Arrangements To Obtain Goods And Services [Abstract]
Summary Of Plan Contributions	Year Shares Amount 2019 26,629 $ 372,274 2018 20,632 $ 382,174 2017 13,125 $ 312,380

Restricted Stock Plan (Tables)

Restricted Stock Plan (Tables)	12 Months Ended
	Sep. 30, 2019
Restricted Stock Plan [Abstract]
Summary Of Pre-Tax Compensation Expense	The following table summarizes the Company’s pre-tax compensation expense for the years ended September 30, 2019, 2018 and 2017, related to the Company’s performance based and non-performance based restricted stock. Year Ended September 30, 2019 2018 2017 Performance based, restricted stock $ 367,091 $ 276,272 $ 233,122 Non-performance based, restricted stock 404,706 379,142 364,818 Total compensation expense $ 771,797 $ 655,414 $ 597,940
Summary Of Unrecognized Compensation Cost	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. Unrecognized Compensation Cost Weighted Average (in years) Performance based, restricted stock $ 105,592 1.95 Non-performance based, restricted stock 166,100 1.36 Total $ 271,692
Summary Of Status And Changes In Unvested Shares Of Restricted Stock Awards	A summary of the status of, and changes in, unvested shares of restricted stock awards and changes is presented below: Performance Based Unvested Restricted Awards Weighted Average Grant-Date Fair Value Non- Performance Based Restricted Awards Weighted Average Grant-Date Fair Value Unvested shares as of September 30, 2016 114,417 $ 9.78 43,011 $ 16.25 Granted 20,531 14.27 16,426 24.41 Vested (34,672 ) 8.07 (28,449 ) 18.02 Forfeited (1,186 ) 8.07 (5,991 ) 17.04 Unvested shares as of September 30, 2017 99,090 $ 11.33 24,997 $ 19.41 Granted 29,099 11.34 19,918 20.77 Vested (35,485 ) 12.18 (16,248 ) 19.34 Forfeited - - - - Unvested shares as of September 30, 2018 92,704 $ 11.00 28,667 $ 20.40 Granted 43,287 8.24 27,978 15.61 Vested - - (24,785 ) 18.30 Forfeited (89,321 ) 10.08 (13,153 ) 18.23 Unvested shares as of September 30, 2019 46,670 $ 10.21 18,707 $ 17.54

Information On Oil And Natura_2

Information On Oil And Natural Gas Producing Activities (Tables)	12 Months Ended
	Sep. 30, 2019
Oil And Gas Exploration And Production Industries Disclosures [Abstract]
Summary Of Sales By Percentage Through Various Operators Or Purchasers	The following table shows sales, by percentage, through various operators/purchasers during 2019, 2018 and 2017. 2019 2018 2017 Company A 23 % 24 % 18 % Company B 8 % 16 % 3 % Company C 8 % 11 % 8 % Company D 5 % 7 % 13 %

Supplementary Information On _2

Supplementary Information On Oil, NGL And Natural Gas Reserves (Tables)	12 Months Ended
	Sep. 30, 2019
Extractive Industries [Abstract]
Summary Of Capitalized Costs Of Oil And Natural Gas Properties And Related Depreciation, Depletion And Amortization	2019 2018 Producing properties $ 354,718,398 $ 427,448,584 Non-producing minerals 14,413,899 12,378,395 Non-producing leasehold 185,124 185,124 Exploratory wells in progress - - 369,317,421 440,012,103 Accumulated depreciation, depletion and amortization (258,063,849 ) (242,169,604 ) Net capitalized costs $ 111,253,572 $ 197,842,499
Summary Of Costs Incurred In Oil And Natural Gas Producing Activities	2019 2018 2017 Property acquisition costs $ 6,235,905 $ 11,409,673 $ 20,190 Exploration costs - - - Development costs 3,012,095 10,291,476 25,382,377 $ 9,248,000 $ 21,701,149 $ 25,402,567
Summary Of Net Quantities Of Proved, Developed And Undeveloped Oil And Natural Gas Reserves	Proved Reserves Oil NGL Natural Gas Total (Barrels) (Barrels) (Mcf) Bcfe September 30, 2016 5,426,090 1,622,703 81,725,598 124.0 Revisions of previous estimates 253,481 407,250 13,651,501 17.6 Acquisitions (divestitures) (37,724 ) (12,953 ) (669,064 ) (1.0 ) Extensions, discoveries and other additions 178,497 541,557 34,681,614 39.0 Production (310,677 ) (173,858 ) (8,194,529 ) (11.1 ) September 30, 2017 5,509,667 2,384,699 121,195,120 168.6 Revisions of previous estimates (1,407,995 ) 303,728 (29,247 ) (6.7 ) Acquisitions (divestitures) 236,690 24,765 (1,782,949 ) (0.2 ) Extensions, discoveries and other additions 1,982,624 476,174 9,400,374 24.2 Production (336,564 ) (255,176 ) (8,721,262 ) (12.3 ) September 30, 2018 5,984,422 2,934,190 120,062,036 173.6 Revisions of previous estimates (3,266,351 ) (890,046 ) (35,644,135 ) (60.6 ) Acquisitions (divestitures) (322,023 ) (18,881 ) (948,496 ) (3.0 ) Extensions, discoveries and other additions 313,241 164,276 3,891,262 6.8 Production (329,199 ) (216,259 ) (7,086,761 ) (10.4 ) September 30, 2019 2,380,090 1,973,280 80,273,906 106.4
Summary Of Proved Developed And Undeveloped Reserves	Proved Developed Reserves Proved Undeveloped Reserves Oil NGL Natural Oil NGL Natural (Barrels) (Barrels) (Mcf) (Barrels) (Barrels) (Mcf) September 30, 2017 2,201,528 1,768,425 87,861,043 3,308,139 616,274 33,334,077 September 30, 2018 2,334,587 2,085,706 83,151,954 3,649,835 848,484 36,910,082 September 30, 2019 1,863,096 1,747,242 67,713,193 516,994 226,038 12,560,713
Summary Of Proved Undeveloped Reserves	Beginning proved undeveloped reserves 63,899,996 Proved undeveloped reserves transferred to proved developed (1,763,402 ) Revisions (48,404,716 ) Extensions and discoveries 4,679,986 Sales (1,648,780 ) Purchases 255,821 Ending proved undeveloped reserves 17,018,905
Summary Of Standardized Measure Of Discounted Future Net Cash Flows	2019 2018 2017 Future cash inflows $ 366,697,321 $ 759,899,074 $ 637,509,599 Future production costs (153,935,373 ) (259,413,766 ) (256,193,675 ) Future development and asset retirement costs (1,917,937 ) (89,518,449 ) (93,133,683 ) Future income tax expense (47,788,416 ) (95,872,182 ) (102,193,819 ) Future net cash flows 163,055,595 315,094,677 185,988,422 10% annual discount (77,494,066 ) (158,768,823 ) (105,155,847 ) Standardized measure of discounted future net cash flows $ 85,561,529 $ 156,325,854 $ 80,832,575
Summary Of Changes In Standardized Measure Of Discounted Future Net Cash Flows	2019 2018 2017 Beginning of year $ 156,325,854 $ 80,832,575 $ 29,770,119 Changes resulting from: Sales of oil, NGL and natural gas, net of production costs (25,072,122 ) (32,836,007 ) (25,783,055 ) Net change in sales prices and production costs (76,588,460 ) 47,533,281 37,186,619 Net change in future development and asset retirement costs 43,607,535 1,580,942 (7,939,156 ) Extensions and discoveries 7,074,245 34,667,557 38,582,908 Revisions of quantity estimates (60,308,497 ) (8,391,223 ) 15,282,587 Acquisitions (divestitures) of reserves-in-place (3,134,783 ) (307,472 ) (962,667 ) Accretion of discount 20,457,930 12,602,209 4,789,294 Net change in income taxes 23,413,194 (3,057,128 ) (27,070,430 ) Change in timing and other, net (213,367 ) 23,701,120 16,976,356 Net change (70,764,325 ) 75,493,279 51,062,456 End of year $ 85,561,529 $ 156,325,854 $ 80,832,575

Quarterly Results Of Operatio_2

Quarterly Results Of Operations (Unaudited) (Tables)	12 Months Ended
	Sep. 30, 2019
Quarterly Financial Information Disclosure [Abstract]
Summary Of The Company's Quarterly Results Of Operations	Fiscal 2019 Quarter Ended December March 31 June 30 September 30 Revenues $ 26,328,994 $ 7,636,213 $ 16,342,394 $ 15,728,084 Income (loss) before provision for income taxes $ 16,306,940 $ (2,061,334 ) $ 5,919,236 $ (74,390,780 ) Net income (loss) $ 12,735,940 $ (1,931,334 ) $ 4,604,236 $ (56,153,780 ) Earnings (loss) per share $ 0.75 $ (0.11 ) $ 0.28 $ (3.35 ) Fiscal 2018 Quarter Ended December 31 March 31 June 30 September 30 Revenues $ 12,490,526 $ 11,421,258 $ 9,557,937 $ 11,564,543 Income (loss) before provision for income taxes $ 1,074,939 $ 1,046,176 $ (984,093 ) $ 759,647 Net income (loss) $ 13,784,939 $ 1,070,176 $ (775,093 ) $ 555,647 Earnings (loss) per share $ 0.81 $ 0.06 $ (0.05 ) $ 0.04

Summary Of Significant Accoun_4

Summary Of Significant Accounting Policies (Narrative) (Details)	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2017	Sep. 30, 2018USD ($)$ / a	Sep. 30, 2019USD ($)aItem$ / a		Sep. 30, 2018USD ($)aItem$ / a	Sep. 30, 2017USD ($)
Summary Of Significant Accounting Policies [Line Items]
Number of Oil, NGL and Natural Gas Production Units | Item			6,496
Oil, NGL and natural gas revenues were derived from the sale of oil			46.00%
Oil, NGL and natural gas revenues were derived from the sale of NGL			9.00%
Oil, NGL and natural gas revenues were derived from the sale of natural gas			45.00%
Bad debt expense			$ 0		$ 0	$ 0
Fair value of derivative contracts, asset			2,494,144
Fair value of derivative contracts, liability		$ 3,414,016			3,414,016
Net cash paid on derivatives settled					1,001,893
Net cash received on derivatives settled			196,985			305,410
Book value of Non-producing oil and natural gas		$ 8,025,015	$ 9,673,787		8,025,015
Percentage of perpetual ownership of mineral interests in Oklahoma, North Dakota, Texas, Arkansas and New Mexico			91.00%
Accumulated period perpetual rights			93 years
Non Producing Minerals Area | a			197,468
Number of tracts owned | Item			6,688
Amount of acres average tract contains | a			30
Tracts Average Cost Per Acre | $ / a			73
Amortized Period of Non-producing Minerals			33 years
Straight-line amortized period of Producing Minerals			20 years
Straight-line amortized period of insignificant fields			10 years
Impairment			$ 76,824,337	[1]	$ 0	662,990	[1]
Percentage of discount rate for developed location			10.00%
Percentage of discount rate for undeveloped location			0.00%
Fair value of discounted cash flows and market quoted amount			$ 9,100,000
Number of non-core wells sold | Item			112		324
Mineral and non-participating royalty acreage sold | a			890
Proceeds from sales of assets			$ 19,515,735		$ 1,085,137	723,700
Net gain (loss) on sale of assets			18,730,197		(660,597)	(94,889)
Decrease in net book value			786,000		1,700,000
Gain on asset sales			18,973,426
Amount of Capitalized Interest Included in the Company's Capital Expenditures			38,606		89,023	168,351
Interest Expense			$ 1,995,789		1,748,101	$ 1,275,138
U.S. federal corporate tax rate	35.00%	21.00%	21.00%
Remeasurement of deferred income tax benefit, amount					$ 12,464,000
Effective tax rate			(25.00%)		(672.00%)
One-time Severance [Member]
Summary Of Significant Accounting Policies [Line Items]
Increase in accrued compensation			$ 670,000
Oklahoma and North Dakota [Member]
Summary Of Significant Accounting Policies [Line Items]
Mineral acreage acquired | a			790		4,306
Purchase price of mineral acreage acquired			$ 5,700,000		$ 11,300,000
Net mineral price per acre | $ / a		2,600	7,200		2,600
Gain (Loss) on Asset Sales [Member}
Summary Of Significant Accounting Policies [Line Items]
Loss on asset sales			$ (243,228)
Eagle Ford Asset [Member]
Summary Of Significant Accounting Policies [Line Items]
Impairment			76,560,376
Other Various Assets [Member]
Summary Of Significant Accounting Policies [Line Items]
Impairment			$ 263,961
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Useful life of furniture and fixtures			5 years
Restricted Stock Awards, vesting period			3 years
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Useful life of furniture and fixtures			8 years
Sales Revenue, Net [Member] | Product Concentration Risk [Member] | Natural Gas [Member]
Summary Of Significant Accounting Policies [Line Items]
Total sale volume from sale of Oil, NGL and Natural gas			68.00%
Sales Revenue, Net [Member] | Product Concentration Risk [Member] | Oil [Member]
Summary Of Significant Accounting Policies [Line Items]
Total sale volume from sale of Oil, NGL and Natural gas			19.00%
Sales Revenue, Net [Member] | Product Concentration Risk [Member] | NGL [Member]
Summary Of Significant Accounting Policies [Line Items]
Total sale volume from sale of Oil, NGL and Natural gas			13.00%
[1]	At the end of each quarter, the Company assessed the carrying value of its producing properties for impairment. This assessment utilized estimates of future cash flows or fair value (selling price) less cost to sell if the property is held for sale. Significant judgments and assumptions in these assessments include estimates of future oil, NGL and natural gas prices using a forward NYMEX curve adjusted for projected inflation, locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values.

Summary Of Significant Accoun_5

Summary Of Significant Accounting Policies (Summary Of Derivative Instruments Contracts) (Details)	Sep. 30, 2019MMBTU$ / MMBTU$ / bblbbl
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period One [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	100,000
Contract price | $ / MMBTU	2.960
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Two [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	100,000
Contract price | $ / MMBTU	2.950
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Three [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	100,000
Contract price | $ / MMBTU	2.995
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Four [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	100,000
Contract price | $ / MMBTU	2.982
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Five [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	100,000
Contract price | $ / MMBTU	3.004
Natural Gas Fixed Price Swaps [Member] | Derivative Contract Period Six [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas | MMBTU	80,000
Contract price | $ / MMBTU	2.750
Oil Costless Collars [Member] | Derivative Contract Period Seven [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	1,000
Oil Costless Collars [Member] | Derivative Contract Period Seven [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	50
Oil Costless Collars [Member] | Derivative Contract Period Seven [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	60
Oil Costless Collars [Member] | Derivative Contract Period Eight [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Eight [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	60
Oil Costless Collars [Member] | Derivative Contract Period Eight [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	69.25
Oil Costless Collars [Member] | Derivative Contract Period Nine [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	3,000
Oil Costless Collars [Member] | Derivative Contract Period Nine [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	60
Oil Costless Collars [Member] | Derivative Contract Period Nine [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	70.75
Oil Costless Collars [Member] | Derivative Contract Period Ten [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Ten [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	65
Oil Costless Collars [Member] | Derivative Contract Period Ten [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	76.15
Oil Costless Collars [Member] | Derivative Contract Period Eleven [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Eleven [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	60
Oil Costless Collars [Member] | Derivative Contract Period Eleven [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	67
Oil Costless Collars [Member] | Derivative Contract Period Twelve [Member]
Derivative [Line Items]
Production volume covered per month - Oil | bbl	2,000
Oil Costless Collars [Member] | Derivative Contract Period Twelve [Member] | Minimum [Member]
Derivative [Line Items]
Contract price	55
Oil Costless Collars [Member] | Derivative Contract Period Twelve [Member] | Maximum [Member]
Derivative [Line Items]
Contract price	62
Oil Fixed Price Swaps [Member] | Derivative Contract Period Thirteen [Member]
Derivative [Line Items]
Contract price	56.15
Production volume covered per month - Oil | bbl	1,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Fourteen [Member]
Derivative [Line Items]
Contract price	56.71
Production volume covered per month - Oil | bbl	2,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Fifteen [Member]
Derivative [Line Items]
Contract price	58.56
Production volume covered per month - Oil | bbl	1,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Sixteen [Member]
Derivative [Line Items]
Contract price	56.85
Production volume covered per month - Oil | bbl	2,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Seventeen [Member]
Derivative [Line Items]
Contract price	58.50
Production volume covered per month - Oil | bbl	5,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Eighteen [Member]
Derivative [Line Items]
Contract price	60.60
Production volume covered per month - Oil | bbl	1,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Nineteen [Member]
Derivative [Line Items]
Contract price	55.28
Production volume covered per month - Oil | bbl	2,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Twenty [Member]
Derivative [Line Items]
Contract price	58.65
Production volume covered per month - Oil | bbl	2,000
Oil Fixed Price Swaps [Member] | Derivative Contract Period Twenty One [Member]
Derivative [Line Items]
Contract price	60
Production volume covered per month - Oil | bbl	2,000

Summary Of Significant Accoun_6

Summary Of Significant Accounting Policies (Summary Of Derivative Contracts) (Details) - USD ($)	Sep. 30, 2019	Sep. 30, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Gross amounts recognized - Current Assets	$ 2,256,639	$ 42,150
Offsetting adjustments - Current Assets		(42,150)
Net presentation on Balance Sheets - Current Assets	2,256,639
Gross amounts recognized - Current Liabilities		3,106,196
Offsetting adjustments - Current Liabilities		(42,150)
Net presentation on Balance Sheets - Current Liabilities		3,064,046
Gross amounts recognized - Non-Current Assets	237,505
Net presentation on Balance Sheets - Non-Current Assets	$ 237,505
Gross amounts recognized - Non-Current Liabilities		349,970
Net presentation on Balance Sheets - Non-Current Liabilities		$ 349,970

Summary Of Significant Accoun_7

Summary Of Significant Accounting Policies (Summary Of Fair Value Measurement Information For Financial Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Details) - USD ($)	Sep. 30, 2019	Sep. 30, 2018
Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	$ 1,892,954	$ (2,317,069)
Swap [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	1,892,954	(2,317,069)
Collars [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	601,190	(1,096,947)
Collars [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis [Line Items]
Financial Assets (Liabilities)	$ 601,190	$ (1,096,947)

Summary Of Significant Accoun_8

Summary Of Significant Accounting Policies (Summary Of Impairments Associated With Certain Assets Measured At Fair Value On A Nonrecurring Basis Within Level 3) (Details) - USD ($)		12 Months Ended
		Sep. 30, 2019		Sep. 30, 2018	Sep. 30, 2017
Accounting Policies [Abstract]
Producing Properties, Fair Value	[1]	$ 9,101,032			$ 567,077
Provision for impairment		$ 76,824,337	[1]	$ 0	$ 662,990	[1]
[1]	At the end of each quarter, the Company assessed the carrying value of its producing properties for impairment. This assessment utilized estimates of future cash flows or fair value (selling price) less cost to sell if the property is held for sale. Significant judgments and assumptions in these assessments include estimates of future oil, NGL and natural gas prices using a forward NYMEX curve adjusted for projected inflation, locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values.

Summary Of Significant Accoun_9

Summary Of Significant Accounting Policies (Summary Of Accrued Liabilities) (Details) - USD ($)	Sep. 30, 2019	Sep. 30, 2018
Payables And Accruals [Abstract]
Accrued compensation	$ 1,446,710	$ 905,445
Revenues payable	396,954	253,850
Accrued ad valorem	260,550	317,105
Other	329,252	315,550
Total accrued liabilities	$ 2,433,466	$ 1,791,950

Summary Of Significant Accou_10

Summary Of Significant Accounting Policies (Summary Of Asset Retirement Obligation) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Accounting Policies [Abstract]
Asset retirement obligations as of beginning of the year	$ 2,809,378	$ 3,196,889
Wells acquired or drilled	27,783	17,215
Wells sold or plugged	(134,090)	(542,892)
Accretion of discount	132,710	138,166
Asset retirement obligations as of end of the year	$ 2,835,781	$ 2,809,378

Commitments (Details)

Commitments (Details) - USD ($)	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Commitments And Contingencies Disclosure [Abstract]
Future minimum rental payments under the terms of the lease due in 2020	$ 122,659
Future minimum rental payments under the terms of the lease due in 2021	0
Future minimum rental payments under the terms of the lease due in 2022	0
Rental Expenses	$ 218,899	$ 215,803	$ 206,366

Revenues (Narrative) (Details)

Revenues (Narrative) (Details) - USD ($)	Oct. 01, 2018	Sep. 30, 2019
Disaggregation Of Revenue [Line Items]
Revenue, practical expedient, financing component		true
Minimum [Member]
Disaggregation Of Revenue [Line Items]
New wells production statements period		30 days
Maximum [Member]
Disaggregation Of Revenue [Line Items]
New wells production statements period		90 days
Difference between Revenue Guidance in Effect before and after Topic 606 [Member] | ASU 2014-09, Revenue from Contracts with Customers [Member]
Disaggregation Of Revenue [Line Items]
Cumulative effect on retained earnings	$ 0

Revenues (Summary Of Disaggrega

Revenues (Summary Of Disaggregation Of Company's Oil, NGL And Natural Gas Revenues) (Details)	12 Months Ended
	Sep. 30, 2019USD ($)
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	$ 39,410,036
Royalty Interest [Member]
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	13,991,625
Working Interest [Member]
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	25,418,411
Oil [Member]
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	18,129,987
Oil [Member] | Royalty Interest [Member]
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	7,057,906
Oil [Member] | Working Interest [Member]
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	11,072,081
NGL [Member]
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	3,697,953
NGL [Member] | Royalty Interest [Member]
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	1,148,033
NGL [Member] | Working Interest [Member]
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	2,549,920
Natural Gas [Member]
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	17,582,096
Natural Gas [Member] | Royalty Interest [Member]
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	5,785,686
Natural Gas [Member] | Working Interest [Member]
Disaggregation Of Revenue [Line Items]
Oil, NGL and natural gas sales	$ 11,796,410

Income Taxes (Summary of Provis

Income Taxes (Summary of Provision (Benefit) for Income Taxes) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Federal	$ (1,388,000)	$ 204,000	$ 314,000
State	19,000	20,000
Current	(1,369,000)	224,000	314,000
Federal	(9,763,000)	(13,240,000)	390,000
State	(2,349,000)	277,000	(15,000)
Deferred	(12,112,000)	(12,963,000)	375,000
Provision (benefit) for income taxes	$ (13,481,000)	$ (12,739,000)	$ 689,000

Income Taxes (Summary of Differ

Income Taxes (Summary of Difference Between Provision (Benefit) for Income Taxes and Amount which Would Result from Application of Federal Statutory Rate) (Details) - USD ($)		12 Months Ended
		Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Provision (benefit) for income taxes at statutory rate		$ (11,387,447)	$ 465,253	$ 1,477,327
Percentage depletion		(431,340)	(577,780)	(570,801)
State income taxes, net of federal provision (benefit)		(1,986,850)	36,980	3,900
Effect of graduated rates				85,644
Restricted stock tax benefit		185,000	(69,000)	(238,000)
Deferred directors compensation benefit		(38,000)	(134,000)	(79,000)
Law change	[1]		(12,464,000)
Other		177,637	3,547	9,930
Provision (benefit) for income taxes		$ (13,481,000)	$ (12,739,000)	$ 689,000
[1]	This is the tax effect of the Tax Cuts and Jobs Act (enacted in December 2017) on our deferred tax liabilities. This Act reduced the U.S. federal corporate tax rate from 35% to 21%.

Income Taxes (Summary of Diff_2

Income Taxes (Summary of Difference Between Provision (Benefit) for Income Taxes and Amount which Would Result from Application of Federal Statutory Rate) (Parenthetical) (Details)	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2017	Sep. 30, 2018	Sep. 30, 2019
Income Tax Disclosure [Abstract]
U.S. federal corporate tax rate	35.00%	21.00%	21.00%

Income Taxes (Summary of Deferr

Income Taxes (Summary of Deferred Tax Assets and Liabilities) (Details) - USD ($)	Sep. 30, 2019	Sep. 30, 2018
Income Tax Disclosure [Abstract]
Financial basis in excess of tax basis, principally intangible drilling costs capitalized for financial purposes and expensed for tax purposes	$ 8,885,776	$ 23,885,522
Derivative contracts	619,392
Total deferred tax liabilities	9,505,168	23,885,522
State net operating loss carry forwards	431,977	551,435
AMT credit carry forwards	1,387,042	2,936,457
Asset retirement obligations	459,810	420,761
Deferred directors' compensation	602,394	693,592
Restricted stock expense	119,697	238,477
Derivative contracts		839,573
Business interest limitation	358,110
Other	170,131	117,220
Total Deferred tax assets	3,529,161	5,797,515
Net deferred tax liabilities	$ 5,976,007	$ 18,088,007

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Income Tax Contingency [Line Items]
State net operating loss carry forwards	$ 431,977	$ 551,435
Percentage of AMT credit refundable amount equal to excess of minimum tax credit	50.00%
Percentage of AMT credit refundable amount equal to excess of minimum tax credit in case of taxable years beginning in 2021	100.00%
AMT carryforward, description	The AMT carry forwards do not have an expiration date. The corporate alternative minimum tax was repealed by The Tax Cuts and Jobs Act (enacted on December 22, 2017). Taxpayers with AMT credit carryovers can use the credits to offset regular tax liability for any taxable year. In addition, the AMT credit is refundable in any taxable year beginning after 2017 and before 2022 in an amount equal to 50% (100% in the case of taxable years beginning in 2021) of the excess of the minimum tax credit for the taxable year over the amount of the credit allowable for the year against regular tax liability. Thus, the Company’s entire AMT credit carryforward amounts are fully refundable by 2023.
Deferred assets, business interest limitations	$ 358,110
Business Interest Limitations [Member]
Income Tax Contingency [Line Items]
Deferred tax assets, valuation allowance	$ 0
Earliest Tax Year [Member]
Income Tax Contingency [Line Items]
AMT credit refundable taxable year	2017
Latest Tax Year [Member]
Income Tax Contingency [Line Items]
AMT credit refundable taxable year	2022
Oklahoma [Member]
Income Tax Contingency [Line Items]
State net operating loss carry forwards	$ 381,906
Net operating loss carry forwards expiration period	2037
Operating loss carry forwards valuation allowance	$ 0

Long-Term Debt (Details)

Long-Term Debt (Details) - Revolving Credit Facility [Member] - USD ($)	12 Months Ended
	Sep. 30, 2019	Aug. 31, 2019
Line Of Credit Facility [Line Items]
Revolving loan credit facility	$ 200,000,000
Borrowing base of credit facility	$ 70,000,000	$ 70,000,000
Credit facility maturity	Nov. 30, 2022
Mortgaged properties net book value	$ 74,435,747
Effective Interest rate	4.34%
Funded debt to EBITDA ratio	400.00%
Availability under outstanding credit facility	$ 34,575,000
Minimum [Member]
Line Of Credit Facility [Line Items]
Current ratio	100.00%
Dividend payments and stock repurchases leverage ratio	275.00%
Minimum [Member] | Prime Rate [Member]
Line Of Credit Facility [Line Items]
Interest rate basis	0.50%
Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line Of Credit Facility [Line Items]
Interest rate basis	2.00%
Maximum [Member] | Prime Rate [Member]
Line Of Credit Facility [Line Items]
Interest rate basis	1.25%
Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line Of Credit Facility [Line Items]
Interest rate basis	2.75%

Stockholders' Equity (Details)

Stockholders' Equity (Details) - USD ($)	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017	May 31, 2018
Equity, Class of Treasury Stock [Line Items]
Purchase of additional common stock authorized				$ 1,500,000
Purchase of treasury stock	$ 7,454,000	$ 1,219,228	$ 601,853
Maximum [Member]
Equity, Class of Treasury Stock [Line Items]
Purchase of common stock, approval level				$ 1,500,000
2010 Restricted Stock Plan [Member]
Equity, Class of Treasury Stock [Line Items]
Purchase of treasury stock	$ 7,454,000
Purchase of treasury stock, shares	515,972

Earnings (Loss) Per Share (Deta

Earnings (Loss) Per Share (Details) - USD ($)	3 Months Ended								12 Months Ended
	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Earnings Per Share [Abstract]
Net income (loss)	$ (56,153,780)	$ 4,604,236	$ (1,931,334)	$ 12,735,940	$ 555,647	$ (775,093)	$ 1,070,176	$ 13,784,939	$ (40,744,938)	$ 14,635,669	$ 3,531,933
Denominator for basic and diluted earnings per share - Weighted average shares (including for 2019, 2018 and 2017, unissued, vested directors' shares of 168,586, 205,736 and 253,603, respectively)									16,743,746	16,952,664	16,900,185

Earnings (Loss) Per Share (Pare

Earnings (Loss) Per Share (Parenthetical) (Details) - shares	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Earnings Per Share [Abstract]
Vested directors' shares	168,586	205,736	253,603

Employee Stock Ownership Plan_2

Employee Stock Ownership Plan (Narrative) (Details)	12 Months Ended
	Sep. 30, 2019shares
Share Based Arrangements To Obtain Goods And Services [Abstract]
Percentage of Company Contributions Are Allocated To Employee Stock Ownership Plan Participants	100.00%
Eligibility of Receiving Full Contribution Of Employee Stock Ownership Plan	3 years
Number of Common Stock Share held for ESOP plan	182,337

Employee Stock Ownership Plan_3

Employee Stock Ownership Plan (Summary Of Plan Contributions) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Share Based Arrangements To Obtain Goods And Services [Abstract]
Shares Contributed to the ESOP	26,629	20,632	13,125
Amount Contributed to the ESOP	$ 372,274	$ 382,174	$ 312,380

Deferred Compensation Plan Fo_2

Deferred Compensation Plan For Directors (Details) - USD ($)	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Deferred Compensation Plan For Directors [Line Items]
Number of shares credited to directors deferred fee account	179,226	212,574
Outstanding deferred balance	$ 2,555,781	$ 2,950,405
Total expenses charged to the company's results of operations	$ 272,491	$ 301,715	$ 358,658
Maximum [Member]
Deferred Compensation Plan For Directors [Line Items]
Period outside directors may elect to receive shares	10 years

Restricted Stock Plan (Narrativ

Restricted Stock Plan (Narrative) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2019	Mar. 31, 2014	Mar. 31, 2010
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Intrinsic value of vested shares	$ 368,259
2010 Stock Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock authorized		500,000	200,000

Restricted Stock Plan (Summary

Restricted Stock Plan (Summary Of Pre-Tax Compensation Expense) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 771,797	$ 655,414	$ 597,940
Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	367,091	276,272	233,122
Non Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 404,706	$ 379,142	$ 364,818

Restricted Stock Plan (Summar_2

Restricted Stock Plan (Summary Of Unrecognized Compensation Cost) (Details)	12 Months Ended
	Sep. 30, 2019USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost	$ 271,692
Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost	$ 105,592
Weighted Average Period (in years)	1 year 11 months 12 days
Non Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized Compensation Cost	$ 166,100
Weighted Average Period (in years)	1 year 4 months 9 days

Restricted Stock Plan (Summar_3

Restricted Stock Plan (Summary Of Changes In Unvested Shares Of Restricted Stock Awards) (Details) - $ / shares	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Performance Based Restricted Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested shares, Beginning balance	92,704	99,090	114,417
Unvested Restricted Shares, Granted	43,287	29,099	20,531
Unvested Restricted Shares, Vested		(35,485)	(34,672)
Unvested Restricted Shares, Forfeited	(89,321)		(1,186)
Unvested shares, Ending balance	46,670	92,704	99,090
Weighted Average Grant Date Fair Value, Beginning balance	$ 11	$ 11.33	$ 9.78
Weighted Average Grant Date Fair Value, Granted	8.24	11.34	14.27
Weighted Average Grant Date Fair Value, Vested		12.18	8.07
Weighted Average Grant Date Fair Value, Forfeited	10.08		8.07
Weighted Average Grant Date Fair Value, Ending balance	$ 10.21	$ 11	$ 11.33
Non Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested shares, Beginning balance	28,667	24,997	43,011
Unvested Restricted Shares, Granted	27,978	19,918	16,426
Unvested Restricted Shares, Vested	(24,785)	(16,248)	(28,449)
Unvested Restricted Shares, Forfeited	(13,153)		(5,991)
Unvested shares, Ending balance	18,707	28,667	24,997
Weighted Average Grant Date Fair Value, Beginning balance	$ 20.40	$ 19.41	$ 16.25
Weighted Average Grant Date Fair Value, Granted	15.61	20.77	24.41
Weighted Average Grant Date Fair Value, Vested	18.30	19.34	18.02
Weighted Average Grant Date Fair Value, Forfeited	18.23		17.04
Weighted Average Grant Date Fair Value, Ending balance	$ 17.54	$ 20.40	$ 19.41

Information On Oil And Natura_3

Information On Oil And Natural Gas Producing Activities (Details)	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Company A [Member]
Results Of Operations For Oil And Gas Producing Activities, Purchasers By Significance [Line Items]
Percentage of revenue	23.00%	24.00%	18.00%
Company B [Member]
Results Of Operations For Oil And Gas Producing Activities, Purchasers By Significance [Line Items]
Percentage of revenue	8.00%	16.00%	3.00%
Company C [Member]
Results Of Operations For Oil And Gas Producing Activities, Purchasers By Significance [Line Items]
Percentage of revenue	8.00%	11.00%	8.00%
Company D [Member]
Results Of Operations For Oil And Gas Producing Activities, Purchasers By Significance [Line Items]
Percentage of revenue	5.00%	7.00%	13.00%

Subsequent Events (Narrative) (

Subsequent Events (Narrative) (Details)	Nov. 22, 2019USD ($)a	Nov. 14, 2019USD ($)a	Sep. 30, 2019USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)
Subsequent Event [Line Items]
Proceeds from sales of assets			$ 19,515,735	$ 1,085,137	$ 723,700
Subsequent Event [Member] | Eddy County, New Mexico [Member]
Subsequent Event [Line Items]
Mineral acreage sold | a		530
Proceeds from sales of assets		$ 3,400,000
Subsequent Event [Member] | Kingfisher, Canadian [Member]
Subsequent Event [Line Items]
Mineral acreage acquired | a	704
Purchase price of mineral acreage acquired	$ 9,650,000
Subsequent Event [Member] | Garvin Counties, Oklahoma [Member]
Subsequent Event [Line Items]
Mineral acreage acquired | a	704
Purchase price of mineral acreage acquired	$ 9,650,000

Supplementary Information On _3

Supplementary Information On Oil, NGL And Natural Gas Reserves (Summary of Capitalized Costs of Oil and Natural Gas Properties and Related Depreciation, Depletion and Amortization) (Details) - USD ($)	Sep. 30, 2019	Sep. 30, 2018
Extractive Industries [Abstract]
Producing properties	$ 354,718,398	$ 427,448,584
Non-producing minerals	14,413,899	12,378,395
Non-producing leasehold	185,124	185,124
Gross capitalized costs	369,317,421	440,012,103
Accumulated depreciation, depletion and amortization	(258,063,849)	(242,169,604)
Net capitalized costs	$ 111,253,572	$ 197,842,499

Supplementary Information On _4

Supplementary Information On Oil, NGL And Natural Gas Reserves (Summary of Costs Incurred in Oil and Natural Gas Producing Activities) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Extractive Industries [Abstract]
Property acquisition costs	$ 6,235,905	$ 11,409,673	$ 20,190
Development costs	3,012,095	10,291,476	25,382,377
Total cost incurred	$ 9,248,000	$ 21,701,149	$ 25,402,567

Supplementary Information On _5

Supplementary Information On Oil, NGL And Natural Gas Reserves (Summary of Net Quantities of Proved, Developed and Undeveloped Oil and Natural Gas Reserves) (Details)	12 Months Ended
	Sep. 30, 2019BcfebblMcf	Sep. 30, 2018BcfebblMcf	Sep. 30, 2017BcfebblMcf
Reserve Quantities [Line Items]
Proved Oil and Natural Gas Reserves, Beginning Balance | Bcfe	173.6	168.6	124
Revisions of previous estimates | Bcfe	(60.6)	(6.7)	17.6
Acquisitions (divestitures) | Bcfe	(3)	(0.2)	(1)
Extensions, discoveries and other additions | Bcfe	6.8	24.2	39
Production | Bcfe	(10.4)	(12.3)	(11.1)
Proved Oil and Natural Gas Reserves, Ending Balance | Bcfe	106.4	173.6	168.6
Oil [Member]
Reserve Quantities [Line Items]
Proved Oil and Natural Gas Reserves, Beginning Balance	5,984,422	5,509,667	5,426,090
Revisions of previous estimates	(3,266,351)	(1,407,995)	253,481
Acquisitions (divestitures)	(322,023)	236,690	(37,724)
Extensions, discoveries and other additions	313,241	1,982,624	178,497
Production	(329,199)	(336,564)	(310,677)
Proved Oil and Natural Gas Reserves, Ending Balance	2,380,090	5,984,422	5,509,667
NGL [Member]
Reserve Quantities [Line Items]
Proved Oil and Natural Gas Reserves, Beginning Balance	2,934,190	2,384,699	1,622,703
Revisions of previous estimates	(890,046)	303,728	407,250
Acquisitions (divestitures)	(18,881)	24,765	(12,953)
Extensions, discoveries and other additions	164,276	476,174	541,557
Production	(216,259)	(255,176)	(173,858)
Proved Oil and Natural Gas Reserves, Ending Balance	1,973,280	2,934,190	2,384,699
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Oil and Natural Gas Reserves, Beginning Balance | Mcf	120,062,036	121,195,120	81,725,598
Revisions of previous estimates | Mcf	(35,644,135)	(29,247)	13,651,501
Acquisitions (divestitures) | Mcf	(948,496)	(1,782,949)	(669,064)
Extensions, discoveries and other additions | Mcf	3,891,262	9,400,374	34,681,614
Production | Mcf	(7,086,761)	(8,721,262)	(8,194,529)
Proved Oil and Natural Gas Reserves, Ending Balance | Mcf	80,273,906	120,062,036	121,195,120

Supplementary Information On _6

Supplementary Information On Oil, NGL And Natural Gas Reserves (Narrative) (Details)	12 Months Ended
	Sep. 30, 2019BcfeMcfe$ / bbl$ / Mcf	Sep. 30, 2018BcfeMcfe$ / bbl$ / Mcf	Sep. 30, 2017Bcfe$ / bbl$ / Mcf
Supplementary Oil And Gas Disclosures [Line Items]
Negative pricing revisions	4,400,000
Negative revisions, developed	4,300,000
Negative revisions, undeveloped	100,000
Negative revisions	56,200,000
Proved developed reserve extensions, discoveries and other additions	2,100,000
Proved undeveloped reserves, additions	4,700,000
Production of oil and natural gas properties | Bcfe	10.4	12.3	11.1
Proved undeveloped Reserves	17,018,905	63,899,996
Proved undeveloped reserves transferred to proved developed	1,763,402
Percentage transferred to proved developed	3.00%
Revisions of proved undeveloped reserves	48,404,716
Revisions percentage of proved undeveloped reserves	76.00%
Arkoma Stack [Member]
Supplementary Oil And Gas Disclosures [Line Items]
Negative revisions, developed	8,000,000
Eagle Ford [Member]
Supplementary Oil And Gas Disclosures [Line Items]
Negative revisions, undeveloped	48,200,000
Bakken, North Dakota [Member]
Supplementary Oil And Gas Disclosures [Line Items]
Additional proved undeveloped acquisition	300,000
Texas and New Mexico [Member]
Supplementary Oil And Gas Disclosures [Line Items]
Divestiture of permain basin	3,800,000
Proved developed sale	2,200,000
Proved undeveloped sale	1,600,000
Additional proved undeveloped sale	1,600,000
Oil [Member]
Supplementary Oil And Gas Disclosures [Line Items]
Price used to calculate reserves and future cash flows from reserves | $ / bbl	54.40	62.86	46.31
NGL [Member]
Supplementary Oil And Gas Disclosures [Line Items]
Price used to calculate reserves and future cash flows from reserves | $ / bbl	19.30	26.13	17.55
Natural Gas [Member]
Supplementary Oil And Gas Disclosures [Line Items]
Price used to calculate reserves and future cash flows from reserves | $ / Mcf	2.48	2.56	2.81
Oil, NGL And Natural Gas [Member] | Bakken, North Dakota [Member]
Supplementary Oil And Gas Disclosures [Line Items]
Acquisition	800,000
Proved developed acquisition	500,000
Proved undeveloped acquisition	300,000

Supplementary Information On _7

Supplementary Information On Oil, NGL And Natural Gas Reserves (Summary of Proved Developed and Undeveloped Reserves) (Details)	Sep. 30, 2019bblMcf	Sep. 30, 2018bblMcf	Sep. 30, 2017bblMcf
Oil [Member]
Reserve Quantities [Line Items]
Proved Developed Reserves (Volume)	1,863,096	2,334,587	2,201,528
Proved Undeveloped Reserves (Volume)	516,994	3,649,835	3,308,139
NGL [Member]
Reserve Quantities [Line Items]
Proved Developed Reserves (Volume)	1,747,242	2,085,706	1,768,425
Proved Undeveloped Reserves (Volume)	226,038	848,484	616,274
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed Reserves (Volume) | Mcf	67,713,193	83,151,954	87,861,043
Proved Undeveloped Reserves (Volume) | Mcf	12,560,713	36,910,082	33,334,077

Supplementary Information On _8

Supplementary Information On Oil, NGL And Natural Gas Reserves (Summary of Proved Undeveloped Reserves) (Details)	12 Months Ended
	Sep. 30, 2019Mcfe
Extractive Industries [Abstract]
Beginning proved undeveloped reserves	63,899,996
Proved undeveloped reserves transferred to proved developed	(1,763,402)
Revisions	(48,404,716)
Extensions and discoveries	4,679,986
Sales	(1,648,780)
Purchases	255,821
Ending proved undeveloped reserves	17,018,905

Supplementary Information On _9

Supplementary Information On Oil, NGL And Natural Gas Reserves (Summary of Standardized Measure of Discounted Future Net Cash Flows) (Details) - USD ($)	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2016
Extractive Industries [Abstract]
Future cash inflows	$ 366,697,321	$ 759,899,074	$ 637,509,599
Future production costs	(153,935,373)	(259,413,766)	(256,193,675)
Future development and asset retirement costs	(1,917,937)	(89,518,449)	(93,133,683)
Future income tax expense	(47,788,416)	(95,872,182)	(102,193,819)
Future net cash flows	163,055,595	315,094,677	185,988,422
10% annual discount	(77,494,066)	(158,768,823)	(105,155,847)
Standardized measure of discounted future net cash flows	$ 85,561,529	$ 156,325,854	$ 80,832,575	$ 29,770,119

Supplementary Information On_10

Supplementary Information On Oil, NGL And Natural Gas Reserves (Summary of Changes in Standardized Measure of Discounted Future Net Cash Flows) (Details) - USD ($)	12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Extractive Industries [Abstract]
Beginning Balance	$ 156,325,854	$ 80,832,575	$ 29,770,119
Sales of oil, NGL and natural gas, net of production costs	(25,072,122)	(32,836,007)	(25,783,055)
Net change in sales prices and production costs	(76,588,460)	47,533,281	37,186,619
Net change in future development and asset retirement costs	43,607,535	1,580,942	(7,939,156)
Extensions and discoveries	7,074,245	34,667,557	38,582,908
Revisions of quantity estimates	(60,308,497)	(8,391,223)	15,282,587
Acquisitions (divestitures) of reserves-in-place	(3,134,783)	(307,472)	(962,667)
Accretion of discount	20,457,930	12,602,209	4,789,294
Net change in income taxes	23,413,194	(3,057,128)	(27,070,430)
Change in timing and other, net	(213,367)	23,701,120	16,976,356
Net change	(70,764,325)	75,493,279	51,062,456
Ending Balance	$ 85,561,529	$ 156,325,854	$ 80,832,575

Quarterly Results Of Operatio_3

Quarterly Results Of Operations (Details) - USD ($)	3 Months Ended								12 Months Ended
	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2017
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 15,728,084	$ 16,342,394	$ 7,636,213	$ 26,328,994	$ 11,564,543	$ 9,557,937	$ 11,421,258	$ 12,490,526	$ 66,035,685	$ 45,034,264	$ 46,361,154
Income (loss) before provision for income taxes	(74,390,780)	5,919,236	(2,061,334)	16,306,940	759,647	(984,093)	1,046,176	1,074,939
Net income (loss)	$ (56,153,780)	$ 4,604,236	$ (1,931,334)	$ 12,735,940	$ 555,647	$ (775,093)	$ 1,070,176	$ 13,784,939	$ (40,744,938)	$ 14,635,669	$ 3,531,933
Earnings (loss) per share	$ (3.35)	$ 0.28	$ (0.11)	$ 0.75	$ 0.04	$ (0.05)	$ 0.06	$ 0.81	$ (2.43)	$ 0.86	$ 0.21