10-K/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K/A

Amendment No. 1

ANNUALREPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FORTHE FISCAL YEAR ENDED SEPTEMBER 30, 2013

Commission  File  Number:001-31759

PANHANDLE OIL AND GAS INC.

(Exact name of registrant as specified in its charter)

OKLAHOMA	73-1055775
(State or other jurisdiction of incorporation	(I.R.S. Employer Identification No.)
or organization)
Grand Centre, Suite 300, 5400 N. Grand Blvd., Oklahoma City, OK   73112
(Address of principal executive offices)	(Zip code)
Registrant's telephone number:   (405) 948-1560
Securities registered under Section 12(b) of the Act:
CLASS A COMMON STOCK (VOTING)	NEW YORK STOCK EXCHANGE
(Title of Class)	(Name of each exchange on which registered)
Securities registered under Section 12(g) of the Act:
(Title of Class)
CLASS B COMMON STOCK (NON-VOTING)   $1.00 par value

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.Yes   X No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes   X No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.X Yes   No

(Facing Sheet Continued)

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during

the preceding 12 months (or for such shorter period) that the registrant was required to submit and post such files.

X  Yes   No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.__

Indicate by check mark whether the registrant is alarge accelerated filer, an accelerated filer, or a non-accelerated filer.See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer___Accelerated filer  XNon-accelerated filer___    Smaller reporting company ___

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).Yes   X No

The aggregate market value of the voting stock held by non-affiliates of the registrant, computed by using the $28.65 per share closing price of registrant's Common Stock, as reported by the New York Stock Exchange at March 31, 2013, was $201,942,992.As of December 1, 2013,  8,231,254  shares of Class A Common Stock were outstanding.

Documents Incorporated By Reference

The information required by Part III of this Report, to the extent not set forth herein, is incorporated by reference from the registrant’s Definitive Proxy Statement relating to the annual meeting of stockholders to be held on  March 5, 2014, which definitive proxy statement will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Report relates.

Explanatory Note

The sole purpose of this Amendment No. 1 to our Annual Report on Form 10-K for the fiscal year ended September 30, 2013, as filed with the Securities and Exchange Commission on December 11, 2013 (“Original Form 10-K”), is to amend the Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting and the Report of Independent Registered Public Accounting Firm to include the signatures of our registered independent registered public accounting firm.  These two reports shown on pages 44 and 45 of the Original Form 10-K were shown without the registered independent public accounting firm’s signatures.

Except as described above, this Amendment does not modify or update the disclosures presented in, or exhibits to, the Original Form 10-K in any way. Those sections of the Original Form 10-K that are unaffected by this Amendment are not included herein. This Amendment continues to speak as of the date of the Original Form 10-K. Other than the furnishing of these two reports from our Independent Registered Public Accounting Firm with its signatures as described above, this Amendment has no impact on the Company’s previously reported audited financial statements and notes thereto as of September 30, 2013. Furthermore, this Amendment does not reflect events occurring after the filing of the Original 10-K Filing. Accordingly, this Amendment should be read in conjunction with the Original Form 10-K, as well as the Company’s other filings made with the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act subsequent to the filing of the Original Form 10-K.

ITEM 8FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Management’s Annual Report on Internal Control Over Financial Reporting	2
Report of Registered Public Accounting Firm on Internal Control Over Financial Reporting	3
Report of Independent Registered Public Accounting Firm	4
Balance Sheets As of September 30, 2013 and 2012	5
Statements of Operations for the Years Ended September 30, 2013, 2012 and 2011	7
Statements of Stockholders’ Equity for the Years Ended September 30, 2013, 2012 and 2011	8
Statements of Cash Flows for the Years Ended September 30, 2013, 2012 and 2011	9
Notes to Financial Statements	11

(1)

Management’s Annual Report on Internal Control Over Financial Reporting

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

· Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company;

· Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and

· Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

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

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

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

(2)

Report of Independent Registered Public Accounting Firm

on Internal Control Over Financial Reporting

The Board of Directors and Stockholders of

Panhandle Oil and Gas Inc.

We have audited Panhandle Oil and Gas Inc.’s internal control over financial reporting as of September 30, 2013, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) (the COSO criteria). Panhandle Oil and Gas Inc.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

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

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

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Panhandle Oil and Gas Inc. maintained, in all material respects, effective internal control over financial reporting as of September 30, 2013, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the balance sheets of Panhandle Oil and Gas Inc. as of September 30, 2013 and 2012, and the related statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended September 30, 2013 and our report dated December 11, 2013 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Oklahoma City, Oklahoma

December 11, 2013

(3)

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of
Panhandle Oil and Gas Inc.

We have audited the accompanying balance sheets of Panhandle Oil and Gas Inc. (the Company) as of September 30, 2013 and 2012, and the related statements of operations, stockholders' equity, and cash flows for each of the three years in the period ended September 30, 2013. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Panhandle Oil and Gas Inc. at September 30, 2013 and 2012, and the results of its operations and its cash flows for each of the three years in the period ended September 30, 2013, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Panhandle Oil and Gas Inc.’s internal control over financial reporting as of September 30, 2013, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (1992 framework) and our report dated December 11, 2013, expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Oklahoma City, Oklahoma
December 11, 2013

(4)

Panhandle Oil and Gas Inc.

Balance Sheets

	September 30,
	2013		2012
Assets
Current Assets:
Cash and cash equivalents	$	2,867,171	$	1,984,099
Oil, NGL and natural gas sales receivables		13,720,761		8,349,865
Refundable income taxes		-		325,715
Refundable production taxes		662,051		585,454
Deferred income taxes		-		121,900
Derivative contracts		425,198		-
Other		129,998		255,812
Total current assets		17,805,179		11,622,845
Properties and equipment at cost, based on successful
efforts accounting:
Producing oil and natural gas properties		304,889,145		275,997,569
Non-producing oil and natural gas properties		8,932,905		10,150,561
Furniture and fixtures		737,368		668,004
		314,559,418		286,816,134
Less accumulated depreciation, depletion and
amortization		(186,641,291)		(165,199,079)
Net properties and equipment		127,918,127		121,617,055
Investments		1,574,642		1,034,870
Refundable production taxes		540,482		911,960
Total assets	$	147,838,430	$	135,186,730

(Continued on next page)

See accompanying notes.

(5)

Panhandle Oil and Gas Inc.

Balance Sheets

	September 30,
	2013		2012
Liabilities and Stockholders' Equity
Current Liabilities:
Accounts payable	$	8,409,634	$	6,447,692
Derivative contracts		-		172,271
Deferred income taxes		127,100		-
Income taxes payable		751,992		-
Accrued liabilities and other		1,011,865		1,007,779
Total current liabilities		10,300,591		7,627,742
Long-term debt		8,262,256		14,874,985
Deferred income taxes		31,226,907		26,708,907
Asset retirement obligations		2,393,190		2,122,950
Stockholders' equity:
Class A voting common stock, $.0166 par value;
24,000,000 shares authorized, 8,431,502 issued at
September 30, 2013 and 2012		140,524		140,524
Capital in excess of par value		2,587,838		2,020,229
Deferred directors' compensation		2,756,526		2,676,160
Retained earnings		96,454,449		84,821,395
		101,939,337		89,658,308
Treasury stock, at cost; 200,248 shares at
September 30, 2013, and 181,310 shares at
September 30, 2012		(6,283,851)		(5,806,162)
Total stockholders' equity		95,655,486		83,852,146
Total liabilities and stockholders' equity	$	147,838,430	$	135,186,730

See accompanying notes.

(6)

Panhandle Oil and Gas Inc.

Statements of Operations

	Year ended September 30,
	2013		2012		2011
Revenues:
Oil, NGL and natural gas sales	$	60,605,878	$	40,818,434	$	43,469,130
Lease bonuses and rentals		938,846		7,152,991		352,757
Gains (losses) on derivative contracts		611,024		73,822		734,299
Income from partnerships		733,372		487,070		420,465
		62,889,120		48,532,317		44,976,651
Costs and expenses:
Lease operating expenses		11,861,403		9,141,970		8,441,754
Production taxes		1,834,840		1,449,537		1,456,755
Exploration costs		9,795		979,718		1,025,542
Depreciation, depletion and amortization		21,945,768		19,061,239		14,712,188
Provision for impairment		530,670		826,508		1,728,162
Loss (gain) on asset sales, interest and other		(785,401)		39,493		(68,325)
General and administrative		6,801,996		6,388,856		5,994,663
		42,199,071		37,887,321		33,290,739
Income (loss) before provision (benefit)
for income taxes		20,690,049		10,644,996		11,685,912
Provision (benefit) for income taxes		6,730,000		3,274,000		3,192,000
Net income (loss)	$	13,960,049	$	7,370,996	$	8,493,912
Basic and diluted earnings per common share:
Net income (loss)	$	1.67	$	0.88	$	1.01

See accompanying notes.

(7)

Panhandle Oil and Gas Inc.

Statements of Stockholders’ Equity

	Class A voting			Capital in		Deferred
	Common Stock			Excess of		Directors'		Retained		Treasury	Treasury
	Shares	Amount		Par Value		Compensation		Earnings		Shares	Stock		Total
Balances at September 30, 2010	8,431,502	$	140,524	$	1,816,365	$	2,222,127	$	73,599,733	(120,560)	$	(4,196,753)	$	73,581,996
Purchase of treasury stock	-		-		-		-		-	(65,481)		(1,851,290)		(1,851,290)
Issuance of treasury shares to ESOP	-		-		(44,340)		-		-	10,710		348,183		303,843
Restricted stock awards	-		-		152,482		-		-	-		-		152,482
Common shares to be issued to
directors for services	-		-		-		443,456		-	-		-		443,456
Dividends declared ($.28 per share)	-		-		-		-		(2,322,082)	-		-		(2,322,082)
Net income	-		-		-		-		8,493,912	-		-		8,493,912
Balances at September 30, 2011	8,431,502	$	140,524	$	1,924,507	$	2,665,583	$	79,771,563	(175,331)	$	(5,699,860)	$	78,802,317
Purchase of treasury stock	-		-		-		-		-	(38,771)		(1,158,957)		(1,158,957)
Issuance of treasury shares to ESOP	-		-		(14,391)		-		-	10,660		341,333		326,942
Restricted stock awards	-		-		330,923		-		-	-		-		330,923
Distribution of deferred directors'
compensation	-		-		(220,810)		(406,770)		-	22,132		711,322		83,742
Common shares to be issued to
directors for services	-		-		-		417,347		-	-		-		417,347
Dividends declared ($.28 per share)	-		-		-		-		(2,321,164)	-		-		(2,321,164)
Net income	-		-		-		-		7,370,996	-		-		7,370,996
Balances at September 30, 2012	8,431,502	$	140,524	$	2,020,229	$	2,676,160	$	84,821,395	(181,310)	$	(5,806,162)	$	83,852,146
Purchase of treasury stock	-		-		-		-		-	(42,206)		(1,214,638)		(1,214,638)
Issuance of treasury shares to ESOP	-		-		(33,812)		-		-	10,907		342,262		308,450
Restricted stock awards	-		-		683,968		-		-	-		-		683,968
Distribution of deferred directors'
compensation	-		-		(82,547)		(297,154)		-	12,361		394,687		14,986
Common shares to be issued to
directors for services	-		-		-		377,520		-	-		-		377,520
Dividends declared ($.28 per share)	-		-		-		-		(2,326,995)	-		-		(2,326,995)
Net income	-		-		-		-		13,960,049	-		-		13,960,049
Balances at September 30, 2013	8,431,502	$	140,524	$	2,587,838	$	2,756,526	$	96,454,449	(200,248)	$	(6,283,851)	$	95,655,486

See accompanying notes.

(8)

Panhandle Oil and Gas Inc.

Statements of Cash Flows

	Year ended September 30,
	2013		2012		2011
Operating Activities
Net income (loss)	$	13,960,049	$	7,370,996	$	8,493,912
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
Depreciation, depletion and amortization		21,945,768		19,061,239		14,712,188
Impairment		530,670		826,508		1,728,162
Provision for deferred income taxes		4,767,000		1,802,000		1,878,000
Exploration costs		9,795		979,718		1,025,542
Gain from leasing fee mineral acreage		(936,701)		(7,146,299)		(352,642)
Net (gain) loss on sales of assets		(208,750)		(122,504)		2,112
Income from partnerships		(733,372)		(487,070)		(420,465)
Distributions received from partnerships		917,718		601,300		553,382
Common stock contributed to ESOP		308,450		326,942		303,843
Common stock (unissued) to Directors'
Deferred Compensation Plan		377,520		417,347		443,456
Restricted stock awards		683,968		330,923		152,482
Cash provided (used) by changes in assets
and liabilities:
Oil, NGL and natural gas sales receivables		(5,370,896)		461,539		251,598
Fair value of derivative contracts		(597,469)		388,211		1,404,386
Refundable income taxes		325,715		28,531		(354,246)
Refundable production taxes		294,881		85,926		(124,621)
Other current assets		73,508		(108,098)		317,370
Accounts payable		298,191		585,912		72,119
Other non-current assets		-		308		-
Income taxes payable		751,992		-		(922,136)
Accrued liabilities		4,072		(32,233)		119,487
Total adjustments		23,442,060		18,000,200		20,790,017
Net cash provided by operating activities		37,402,109		25,371,196		29,283,929

(Continued on next page)

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Panhandle Oil and Gas Inc.

Statements of Cash Flows (continued)

	Year ended September 30,
	2013		2012		2011
Investing Activities
Capital expenditures, including dry hole costs	$	(26,765,785)	$	(25,147,306)	$	(22,739,908)
Acquisition of working interest properties		-		(17,399,052)		(185,125)
Acquisition of minerals and overrides		(783,750)		(2,745,069)		(4,620,315)
Proceeds from leasing fee mineral acreage		1,023,368		7,265,808		389,807
Investments in partnerships		(724,118)		(481,904)		(46,213)
Proceeds from sales of assets		870,610		134,821		938
Excess tax benefit on stock-based compensation		15,000		83,742		-
Net cash used in investing activities		(26,364,675)		(38,288,960)		(27,200,816)
Financing Activities
Borrowings under debt agreement		11,569,652		43,475,443		-
Payments of loan principal		(18,182,381)		(28,600,458)		-
Purchases of treasury stock		(1,214,638)		(1,158,957)		(1,851,290)
Payments of dividends		(2,326,995)		(2,321,164)		(2,322,082)
Net cash provided by (used in) financing activities		(10,154,362)		11,394,864		(4,173,372)
Increase (decrease) in cash and cash equivalents		883,072		(1,522,900)		(2,090,259)
Cash and cash equivalents at beginning of year		1,984,099		3,506,999		5,597,258
Cash and cash equivalents at end of year	$	2,867,171	$	1,984,099	$	3,506,999
Supplemental Disclosures of Cash Flow
Information
Interest paid (net of capitalized interest)	$	157,558	$	127,970	$	-
Income taxes paid, net of refunds received	$	870,295	$	1,356,706	$	2,584,172
Supplemental schedule of noncash
investing and financing activities:
Additions and revisions, net, to asset
retirement obligations	$	161,065	$	279,075	$	113,506
Gross additions to properties and equipment	$	29,261,285	$	46,201,308	$	27,310,016
Net (increase) decrease in accounts payable for
properties and equipment additions		(1,711,750)		(909,881)		235,332
Capital expenditures, including dry hole costs	$	27,549,535	$	45,291,427	$	27,545,348

See accompanying notes.

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Panhandle Oil and Gas Inc.

Notes to Financial Statements

September 30, 2013,  2012and 2011

1.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Since its formation, the Company has been involved in the acquisition and management of fee mineral acreage and the exploration for, and development of, oil and natural gas properties, principally involving drilling wells located on the Company’s mineral acreage.Panhandle’s mineral properties and other oil and natural gas interests are all located in the United States, primarily in Arkansas, New Mexico, North Dakota, Oklahoma and Texas.The Company is not the operator of any wells.The Company’s oil, NGL and natural gas production is from interests in 6,105 wells located principally in Oklahoma and Arkansas.Approximately 60% of oil, NGL and natural gas revenues were derived from the sale of natural gas in 2013. Approximately 84% of the Company’s total sales volumes in 2013 were derived from natural gas.Substantially all the Company’s oil, NGL and natural gas production is sold through the operators of the wells.The Company from time to time disposes of 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 gasreserves to be the most significant.These estimates affect the unaudited standardized measure disclosures, as well as DD&A and impairment calculations.On an annual basis, with a semi-annual update, the Company’s Independent Consulting Petroleum Engineer, with assistance from the Company, prepares estimates of crude oil,  NGL and natural gasreserves 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, thereserveestimates  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 gasprices as estimated by management are used.Crude oil,NGL and natural gasprices are volatile and largely affected by worldwide production and consumption and are outside the control of management.Projected future crude oil, NGL and natural gas pricing assumptions are used by management to prepare estimates of crude oil, NGL and natural gas reserves 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) over a month later than the information is available to the operators of the wells.This being the case, on wells with greater significance to the Company, the most current available production data is gathered from the appropriate operators, and oil, NGL and natural gas index prices local to each well are used to estimate the accrual of revenue on these wells.Timely obtaining production data on all other wells from the operators is not feasible; therefore, the Company utilizes past production receipts and estimated sales price information to estimate its accrual of revenue on all other wells each quarter.The oil, NGL and natural gas sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for oil, NGL and natural gas.These variables could lead to an over or under accrual of oil, NGL and natural gas sales at the end of any particular quarter.Based on past history, the Company’s estimated accrual has been materially accurate.

Cash and Cash Equivalents

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 and Natural Gas Imbalances

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

The Company uses the sales method of accounting for natural gas imbalances in those circumstances where it has underproduced or overproduced its ownership percentage in a property.Under this method, a receivable or liability is recorded to the extent that an underproduced or overproduced position in a well cannot be recouped through the production of remaining reserves.At September 30, 2013 and 2012, the Company had no material natural gas imbalances.

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 we have an interest in may be similarly affected by changes in economic, industry or other conditions. During 2013 and 2012, we did not recognize a reserve for bad debt expense.

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 is determined to be nonproductive.Oil and natural gas mineral and leasehold costs are capitalized when incurred.

Non-producing oil and natural gas leases are assessed for impairment on a property-by-property basis for individually significant balances and on an aggregate basis for individually insignificant balances.If the assessment indicates an impairment, a loss is recognized by providing a valuation allowance at the level at which impairment was assessed.The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

terms and potential shifts in business strategy employed by management.In the case of individually insignificant balances, the amount of the impairment loss recognized is determined by amortizing the portion of these properties’ costs, which the Company believes will not be transferred to proved properties over the remaining lives of the leases.Impairment loss is charged to exploration costs when recognized.As of September 30, 2013, the remaining carrying cost of non-producing oil and natural gas leases was $285,752.

It is common business practice in the petroleum industry for drilling costs to be prepaid before spudding a well.The Company frequently fulfills these prepayment requirements with cash payments, but attimes will utilize letters of credit to meet these obligations.As of September 30, 2013, the Company had no outstanding letters of credit.

Leasing of Mineral Rights

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

The Company recognizes revenue from mineral lease bonus payments when it has received an executed lease agreement with the exploration company transferring the rights to explore for and produce any oil or natural gas theymay find within the term of the lease, the payment has been collected, and the Company has no obligation to refund the payment. The Company accounts for its lease bonuses in accordance with the guidance set forth in ASC 932, and it recognizes the lease bonus as a cost recovery with any excess above the mineral basis being treated as a gain. The excess of lease bonus above themineral 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, basis protection swaps 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 theindex 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.Basis protection swaps are derivatives that guarantee a price differential to NYMEX for natural gas from a specified delivery point (CEGT and PEPL historically).The Company receives a payment from the counterparty if the price differential is greater than the agreed terms of the contract and pays thecounterparty if the price differential is less than the agreed terms of the contract. These contracts cover only a portion of the Company’s oil and natural gas production and provide only partial price protection against declines in oil and natural gas prices. These derivative instruments expose the Company to risk of financial loss and may limit the benefit of future increases in prices. All of the Company’s derivative contracts are with Bank of Oklahoma and are

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

secured.The derivative instruments have settled or will settle based on the prices below, which are adjusted for location differentials and tied to certain pipelines.

Derivative contracts in place as of September 30, 2012

(prices below reflect the Company’s net price from the listed pipelines)

	Production volume	Indexed
Contract period	covered per month	Pipeline	Fixed price
Natural gas basis protection swaps
January - December 2012	50,000 Mmbtu	CEGT	NYMEX -$.29
January - December 2012	40,000 Mmbtu	CEGT	NYMEX -$.30
January - December 2012	50,000 Mmbtu	PEPL	NYMEX -$.29
January - December 2012	50,000 Mmbtu	PEPL	NYMEX -$.30
Natural gas costless collars
March - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50 floor/$3.25 ceiling
April - October 2012	120,000 Mmbtu	NYMEX Henry Hub	$2.50 floor/$3.10 ceiling
April - October 2012	60,000 Mmbtu	NYMEX Henry Hub	$2.50 floor/$3.20 ceiling
April - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50 floor/$3.20 ceiling
April - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50 floor/$3.45 ceiling
April - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50 floor/$3.30 ceiling
August - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50 floor/$3.30 ceiling
November 2012 - January 2013	150,000 Mmbtu	NYMEX Henry Hub	$3.00 floor/$3.70 ceiling
November 2012 - January 2013	150,000 Mmbtu	NYMEX Henry Hub	$3.00 floor/$3.70 ceiling
November 2012 - January 2013	50,000 Mmbtu	NYMEX Henry Hub	$3.00 floor/$3.65 ceiling
Oil costless collars
January - December 2012	2,000 Bbls	NYMEX WTI	$90 floor/$105 ceiling
February - December 2012	3,000 Bbls	NYMEX WTI	$90 floor/$110 ceiling
May - December 2012	2,000 Bbls	NYMEX WTI	$90 floor/$114 ceiling

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Derivative contracts in place as of September 30, 2013

(prices below reflect the Company’s net price from the listed pipelines)

	Production volume	Indexed
Contract period	covered per month	pipeline	Fixed price
Natural gas costless collars
February - December 2013	80,000 Mmbtu	NYMEX Henry Hub	$3.75 floor/$4.25 ceiling
February - December 2013	50,000 Mmbtu	NYMEX Henry Hub	$3.75 floor/$4.30 ceiling
February - December 2013	100,000 Mmbtu	NYMEX Henry Hub	$3.75 floor/$4.05 ceiling
November 2013 - April 2014	160,000 Mmbtu	NYMEX Henry Hub	$4.00 floor/$4.55 ceiling
Natural gas fixed price swaps
March - October 2013	100,000 Mmbtu	NYMEX Henry Hub	$3.505
March - October 2013	70,000 Mmbtu	NYMEX Henry Hub	$3.400
April - December 2013	40,000 Mmbtu	NYMEX Henry Hub	$3.655
May - November 2013	100,000 Mmbtu	NYMEX Henry Hub	$4.320
Oil costless collars
March - December 2013	3,000 Bbls	NYMEX WTI	$90.00 floor/$102.00 ceiling
March - December 2013	4,000 Bbls	NYMEX WTI	$90.00 floor/$101.50 ceiling
May - December 2013	2,000 Bbls	NYMEX WTI	$90.00 floor/$97.50 ceiling
January - June 2014	4,000 Bbls	NYMEX WTI	$90.00 floor/$101.50 ceiling
Oil fixed price swaps
September - December 2013	4,000 Bbls	NYMEX WTI	$105.250

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 $425,198as of September 30, 2013,and a net liabilityof $172,271 as of September 30, 2012.Realized and unrealized gains and (losses) are scheduled below:

Gains (losses) on natural gas	Fiscal year ended
derivative contracts	9/30/2013		9/30/2012		9/30/2011
Realized	$	13,555	$	462,033	$	2,138,685
Increase (decrease) in fair value		597,469		(388,211)		(1,404,386)
Total	$	611,024	$	73,822	$	734,299

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

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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 Condensed Balance Sheets. The Company has chosen to present the fair values of its derivative contracts under master netting agreements using a net fair value presentation. 

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 Condensed Balance Sheets at September 30, 2013, and September 30, 2012. The Company adopted the accounting guidance requiring additional disclosures for balance sheet offsetting of assets and liabilities effective January 1, 2013. The Company has offset all amounts subject to master netting agreements in the Company's Condensed Balance Sheets at September 30, 2013, and September 30, 2012.

	9/30/2013				9/30/2012
	Fair Value (a)				Fair Value (a)
	Commodity Contracts				Commodity Contracts
	Current Assets		Current Liabilities		Current Assets		Current Liabilities
Gross amounts recognized	$	665,099	$	239,901	$	51,530	$	223,801
Offsetting adjustments		(239,901)		(239,901)		(51,530)		(51,530)
Net presentation on Condensed Balance Sheets	$	425,198	$	-	$	-	$	172,271

(a)See Fair Value Measurements section for further disclosures regarding fair value of financial instruments.

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

Fair Value Measurements

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

(15)

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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, 2013
	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	$	-	$	182,296	$	-	$	182,296
Derivative Contracts - Collars	$	-	$	-	$	242,902	$	242,902

	Fair Value Measurement at September 30, 2012
	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	$	-	$	(75,334)	$	-	$	(75,334)
Derivative Contracts - Collars	$	-	$	-	$	(96,937)	$	(96,937)

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

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

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

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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

Instrument Type	Unobservable Input	Range	Weighted Average	Fair Value September 30, 2013
Oil Collars	Oil price volatility curve	0% - 17.56%	10.27%	$	(233,041)
Natural Gas Collars	Natural gas price volatility curve	0% - 19.67%	12.00%	$	475,943

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

	Derivatives
Balance of Level 3 as of October 1, 2012	$	(96,937)
Total gains or (losses) - realized and unrealized:
Included in earnings
Realized		242,435
Unrealized		97,404
Included in other comprehensive income (loss)		-
Purchases, issuances and settlements		-
Transfers in and out of Level 3		-
Balance of Level 3 as of September 30, 2013	$	242,902

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,
	2013				2012
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties	$	356,855	$	530,670	$	1,301,951	$	826,508	(a)

(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.Significant judgments and assumptions in these assessments include estimates of future oil, NGL and natural gas prices using a forward NYMEX curve adjusted for 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, 2013, and September 30, 2012, the fair value of financial instruments approximated their carrying amounts. Financial instruments include long-term debt, which the valuation is classified as Level 3 and is based on a valuation technique that requires inputs that are both unobservable and significant to the overall fair value measurement. The fair value measurement of our long-term debt is valued using a discounted cash flow model that calculates the present value of future

(17)

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

cash flows pursuant to the terms of the debt agreements and applies estimated current market interest rates. The estimated current market interest rates are based primarily on interest rates currently being offered on borrowings of similar amounts and terms. In addition, no valuation input adjustments were considered necessary relating to nonperformance risk for the debt agreements.

Depreciation, Depletion, Amortization and Impairment

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 $4,702,285and $5,374,868at September 30, 2013 and 2012, respectively, consisting of perpetual ownership of mineral interests in several states, with 91% of the acreage in Arkansas, New Mexico, North Dakota,Oklahoma and Texas.As mentioned, thesemineral rights are perpetual and have been accumulated over the 87-year life of the Company.There are approximately 196,768net acres of non-producing minerals in more than 6,818tracts owned by the Company.An average tract containsapproximately 29 acres, and the average cost per acre is $43.Since inception, the Company hascontinually 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 activity each year on these mineral interests.Non-producing minerals are being amortized straight-line over a 33-yearperiod.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, it was concluded that a long-term amortization was appropriate and that 33 years, based on past history and experience, was an appropriate period.Due to the fact that the minerals consist of a large number of properties, whose costs are not individually significant, and because virtually all are in the Company’s core operating areas, the minerals are being amortized on an aggregate basis.

The Company recognizes impairment losses for long-lived assets when indicators of impairment are present and the undiscounted cash flows are not sufficient to recover the assets’ carrying amount.The impairment loss is measured by comparing thefair value of the asset to its carrying amount.Fair values are based on discounted cash flowas estimated by the Company’s Independent Consulting Petroleum Engineer.The Company's estimate of fair value of its oil and natural gas properties at September 30, 2013, is based on the best information available as of that date, including estimates of forward oil, NGL and natural gas prices and costs.The Company’s oil and natural gas properties were reviewed for impairment on a field-by-field basis, resulting in the recognition of impairment provisions of $530,670,  $826,508 and$1,728,162,respectively, for 2013,  2012 and 2011.A  significant reduction in oil, NGL and natural gas prices or a decline in reserve volumes would likely lead to additional impairment in future periods that may be material to the Company.

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

Capitalized Interest

During 2013,  2012 and 2011, interest of $121,418,  $129,172 and$0, respectively, was included in the Company’s capital expenditures. Interest of $157,558,  $127,970 and$0, respectively, was charged to expense during those periods. Interest is capitalized using a weighted average interest rate based on the

Company’s outstanding borrowings.These capitalized costs are included with intangible drilling costs and amortized using unit-of-production method.

Investments

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

Asset Retirement Obligations

The Company owns interests in oil and natural gas properties, which may require expenditures to plug and abandon the wells when the oil, NGL and natural gas reserves in the wells are depleted.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.TheCompany does not have any assets restricted for the purpose of settling the asset retirement obligations.

The following table shows the activity for the yearsended September 30, 2013 and 2012,relating to the Company’s asset retirement obligations:

	2013		2012
Asset Retirement Obligations as of beginning of the year	$	2,122,950	$	1,843,875
Accretion of Discount		122,391		121,112
New Wells Placed on Production		167,609		184,027
Wells Sold or Plugged		(19,760)		(26,064)
Asset Retirement Obligations as of end of the year	$	2,393,190	$	2,122,950

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; however, to date the Company’s cost of compliance has been insignificant.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

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

compliance with environmental laws is controlled by others, with Panhandle being responsible forits proportionate share of the costs involved.Panhandle carries liability insurance and pollution control coverage.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.AtSeptember 30, 2013 and 2012, 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 added to each director’s account based on the  fair market value of the stock at the date earned.The Plan’s structure is that upon retirement,termination or death of the director or upon a change in control of the Company, the shares accrued under the Plan will be issued to the director.

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

Restricted stock awards to certain officers provide for cliff vesting at the end of three or five years from the date of the awards.The fair value of the awards 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 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

(20)

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

1.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)

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 2010.

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, 2013,  2012 and 2011, the Company recorded interest and penalties of $927,  $0and $21,000, respectively.The Company does not believe it has any significantuncertain tax positions.

New Accounting Standards

In December 2011, the Financial Accounting Standards Board issued "Balance Sheet: Disclosures about Offsetting Assets and Liabilities." The new standard requires entities to disclose information about financial instruments and derivative instruments that are either offset on the balance sheet or are subject to a master netting arrangement, including providing both gross information and net information for recognized assets and liabilities, the net amounts presented on an entity's balance sheet and a descriptionof the rights of offset associated with these assets and liabilities. The new standard is applicable for all entities that have financialinstruments and derivative instruments shown using a net presentation on an entity's balance sheet or are subject to a master nettingarrangement. The new standard is effective for interim and annual reporting periods for fiscal years beginning on or after January1, 2013, and should be applied retrospectively for all periods presented. The Company adopted this new standard effectiveJanuary 1, 2013.

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.

2. COMMITMENTS

The Company leases office space in Oklahoma City, Oklahoma, under the terms of an operating lease expiring in April 2015.Future minimum rental payments under the terms of the lease are $204,089 in 2014 and $119,052 in 2015.Total rent expense incurred by the Company was $200,782 in 2013,  $204,011 in 2012 and$204,089 in 2011.

3. INCOME TAXES

The Company’s provision (benefit) for income taxes is detailed as follows:

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

3. INCOME TAXES (CONTINUED)

	2013		2012		2011
Current:
Federal	$	1,813,000	$	1,452,000	$	1,266,000
State		150,000		20,000		48,000
		1,963,000		1,472,000		1,314,000
Deferred:
Federal		4,003,000		1,126,000		1,982,000
State		764,000		676,000		(104,000)
		4,767,000		1,802,000		1,878,000
	$	6,730,000	$	3,274,000	$	3,192,000

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:

	2013		2012		2011
Provision (benefit) for income taxes at statutory rate	$	7,241,517	$	3,725,749	$	4,090,069
Percentage depletion		(1,059,303)		(846,040)		(733,516)
State income taxes, net of federal provision (benefit)		572,650		464,677		(92,989)
State net operating loss valuation allowance (release)		-		(31,000)		31,000
Other		(24,864)		(39,386)		(102,564)
	$	6,730,000	$	3,274,000	$	3,192,000

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:

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

3. INCOME TAXES (CONTINUED)

	2013		2012
Deferred tax liabilities:
Financial basis in excess of tax basis, principally
intangible drilling costs capitalized for financial
purposes and expensed for tax purposes	$	33,557,515	$	30,320,765
Derivative contracts		165,402		-
		33,722,917		30,320,765
Deferred tax assets:
State net operating loss carry forwards, net of
valuation allowance of $0 in 2013 and 2012		782,785		1,008,271
AMT credit carry forwards		-		1,189,053
Deferred directors' compensation		1,021,717		990,455
Restricted stock expense		426,788		-
Statutory depletion carry forwards		-		415,958
Other		137,620		130,021
		2,368,910		3,733,758
Net deferred tax liabilities	$	31,354,007	$	26,587,007

At September 30, 2013, the Company had an income tax benefit of $782,785 related to Oklahoma state income tax net operating loss (OK NOL) carryforwards expiring from 2028to 2031.There is no valuation allowance for the OK NOL’s as management believes they will be utilized before they expire.

4. LONG-TERM DEBT

The Company has a credit facility with Bank of Oklahoma (BOK) consisting of a revolving loan in the amount of $80,000,000,  which is subject to a semi-annual borrowing base determination, wherein BOK applies their own current pricing forecast and an 8% discount rate to the Company’s proved reserves as calculated by the Company’s Independent Consulting Petroleum Engineering Firm. When applying the discount rate, BOK also applies an advance rate percentage to all proved non-producing and proved undeveloped reserves. The facility has a borrowing base of $35,000,000 and is secured by certain of the Company’s properties with a carrying value of $40,042,933 at September 30, 2013. The facility matures on November 30, 2017. The interest rate is based on BOKprime plus from 0.375% to 1.125%, or 30 day LIBOR plus from 1.875% to 2.625%. The election of BOKprime or LIBOR is at the Company’s discretion. The interest rate spread from LIBOR or the prime rate increases as a larger percent of the loan value of the Company’s oil and natural gas properties is advanced. The interest rate spread from BOKprime or LIBOR will be charged based on the percent of the value advanced of the calculated loan value of the Company’s oil and natural gas properties. At September 30, 2013, the effective interest rate was 2.36%.

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.

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

4. LONG-TERM DEBT (CONTINUED)

Since the bank charges a customary non-use fee of 0.25% annually of the unused portion of the borrowing base, the Company has not requested the bank to increase its borrowing base beyond $35,000,000. Determinations of the borrowing base are made semi-annually or whenever the bank, in its sole discretion, believes that there has been a material change in the value of the oil and natural gas properties. While the Company believes the availability could be increased (if needed) by placing more of the Company’s properties as security under the revolving credit facility, increases are at the discretion of the bank. The loan agreement contains customary covenants which, among other things, require periodic financial and reserve reporting and limit the Company’s incurrence of indebtedness, liens, dividends and acquisitions of treasury stock, and require the Company to maintain certain financial ratios. At September 30, 2013, the Company was in compliance with the covenants of the BOK agreement.

5. SHAREHOLDERS’ EQUITY

Upon approval by the shareholders of the Company’s 2010 Restricted Stock Plan on March 11, 2010, the Board approved purchase of up to $1.5 million of the Company’s Common Stock, from time to time, equal to the aggregate number of shares of Common Stock awarded pursuant to the Company’s 2010 Restricted Stock Plan, contributed by the Company to its ESOP and credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors.The Board’s approval included an initial authorization to purchase up to $1.5 million of Common Stock, with a provision for subsequent authorizations without specific action by the Board.As the amount of Common Stock purchased under any authorization reaches $1.5 million, another $1.5 million is automatically authorized for Common Stock purchases unless the Board determines otherwise.Pursuant to these resolutions adopted by theBoard, the purchase of additional $1.5 million increments of the Company’s Common Stock became authorized and approved effective March 29, 2011, March 14, 2012, and June 26, 2013.As of September 30, 2013,  $4,516,267 had been spent under the current program to purchase 158,784 shares.The shares are held in treasury and are accounted for using the cost method.OnSeptember 30 each year, treasury shares contributed to the Company’s ESOP on behalf of the ESOP participants were 10,907 in 2013,  10,660 in 2012 and 10,710 in 2011.

6. EARNINGS PER SHARE

The following table sets forth the computation of earnings per share. 

		Year ended September 30,
	2013		2012		2011
Numerator for basic and diluted earnings per share:
Net income (loss)	$	13,960,049	$	7,370,996	$	8,493,912
Denominator for basic and diluted earnings per share -
weighted average shares (including for 2013, 2012
and 2011, unissued, vested directors' shares
of 116,112, 114,596 and 122,728, respectively)		8,356,904		8,360,931		8,393,890

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

7. EMPLOYEE STOCK OWNERSHIP PLAN

The Company’s ESOP was established in 1984 and is a tax qualified, defined contribution plan thatserves as the Company’s sole retirement plan for all its employees.Company contributions are made at the discretion of the Board and, to date, all contributions have been made in shares of Company Common Stock.The Company contributions are allocated to all ESOP participants in proportion to their compensationfor 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 contributionsof Common Stock, the Company records as expense the fair market value of the stock at the time of contribution. The 259,060  shares of the Company’s Common Stock held by the plan, as of September 30, 2013, 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
2013	10,907	$	308,450
2012	10,660	$	326,942
2011	10,710	$	303,843

8. DEFERRED COMPENSATION PLAN FOR DIRECTORS

The Panhandle Oil and Gas Inc. Deferred Compensation Plan for Non-Employee Directors (the “Plan”) provides that each eligible director can individually elect to receive shares of Company Common Stock rather than cash forBoard and committee chair retainers, Board meeting fees and Board committee meeting fees.These shares are unissued and vest as earned.The shares are credited to each director’s deferred fee account at the closing market price of the stock on the date earned.As of September 30, 2013,  there were 122,219 shares (121,348 shares atSeptember 30, 2012) included in the Plan.The deferred balance outstanding at September 30, 2013, under the Plan was$2,756,526($2,676,160 at September 30, 2012).Expenses totaling $377,520,  $417,347 and$443,456were charged to the Company’s results of operations for the years ended September 30, 2013,  2012 and 2011, respectively, and are included in general and administrative expense in the accompanying Statement of Operations.

9. RESTRICTED STOCK PLAN

On March 11, 2010, shareholders approved the Panhandle Oil and Gas Inc. 2010 Restricted Stock Plan (2010 Stock Plan), which made available 100,000 shares of Common Stock to provide a long-term component to the Company’s total compensation package for its officers and to further align the interest of its officers with those of its shareholders. The 2010 Stock Plan is designed to provide as much flexibility as possible for future grants of restricted stock so the Company can respond as necessary to provide competitive compensation in order to retain, attract and motivate officers of the Company and to align their interests with those of the Company’s shareholders.

In June 2010, the Company began awarding shares of the Company’s Common Stock as restricted stock (non-performance based) to certain officers.The restricted stock vests at the end of the vestingperiod 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 dateand willbe

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

9. RESTRICTED STOCK PLAN (CONTINUED)

recognized as compensation expense ratably over the vesting period. Upon vesting, shares are expected to be issued out of shares held in treasury.

On December 21, 2010, the Company 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 Stockover 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. 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.

The following table summarizes the Company’s pre-tax compensation expense for the years ended September 30, 2013,2012 and 2011, related to the Company’s performance based and non-performance based restricted stock.

		Year Ended September 30,
	2013		2012		2011
Performance based, restricted stock	$	345,405	$	150,480	$	42,909
Non-performance based, restricted stock		338,563		180,443		109,573
Total compensation expense	$	683,968	$	330,923	$	152,482

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 Period (in years)
Performance based, restricted stock	$	282,726	1.41
Non-performance based, restricted stock		227,628	1.48
Total	$	510,354

Upon vesting, shares are expected to be issued out of shares held in treasury.

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

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

9. RESTRICTED STOCK PLAN (CONTINUED)

	Performance Based Unvested Restricted Shares	Weighted Average Grant-Date Fair Value		Non-Performance Based Unvested Restricted Shares	Weighted Average Grant-Date Fair Value
Unvested shares as of
September 30, 2010	-	$	-	8,500	$	28.30
Granted	8,782		19.54	8,780		28.00
Vested	-		-	-		-
Forfeited	-		-	-		-
Unvested shares as of
September 30, 2011	8,782	$	19.54	17,280	$	28.15
Granted	17,709		19.47	5,903		31.55
Vested	-		-	-		-
Forfeited	-		-	-		-
Unvested shares as of	26,491	$	19.49	23,183	$	29.01
September 30, 2012
Granted	20,104		15.18	6,701		29.19
Vested	-		-	-		-
Forfeited	-		-	-		-
Unvested shares as of	46,595	$	17.63	29,884	$	29.05
September 30, 2013

10.  INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES

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

The following table shows sales through various operators/purchasers during 2013,  2012 and2011.

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

10. INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (CONTINUED)

	2013	2012	2011
Southwestern Energy Company	20%	15%	9%
Chesapeake Operating, Inc.	10%	13%	15%
Devon Energy Corp.	7%	10%	9%
Apache Corporation	6%	4%	2%
Newfield Exploration	5%	7%	14%

11. SUPPLEMENTARY  INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES (UNAUDITED)

Aggregate Capitalized Costs

The aggregate amount of capitalized costs of oil and natural gas properties and related accumulated depreciation, depletion and amortization as of September 30 is as follows:

	2013		2012
Producing properties	$	304,889,145	$	275,997,569
Non-producing minerals		8,490,277		9,018,731
Non-producing leasehold		442,628		1,123,812
Exploratory wells in progress		-		8,018
		313,822,050		286,148,130
Accumulated depreciation, depletion and amortization		(186,042,746)		(164,652,199)
Net capitalized costs	$	127,779,304	$	121,495,931

Costs Incurred

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

	2013		2012		2011
Property acquisition costs	$	1,242,615	$	20,404,465	$	5,140,862
Exploration costs		-		1,210,417		4,837,451
Development costs		27,938,160		24,578,943		17,310,808
	$	29,180,775	$	46,193,825	$	27,289,121

In 2012, $17.4 million of the property acquisition costs related to the acquisition of certain assets in the Arkansas Fayetteville Shale.

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

11. SUPPLEMENTARY INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES (UNAUDITED) (CONTINUED)

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 isto be determined.The price shall bethe average price during the 12-month period prior to theending date of the period covered by the report,determined asan unweighted arithmetic average of the first-day-of-the-month price for each monthwithin such period, unless prices are defined by contractual arrangements, excluding escalations basedupon 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 reservoirconsidered as proved includes: (i) the area identified by drilling and limited by fluid contacts, ifany, 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 availablegeoscience 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 technologyestablishes 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 highercontact 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 ofthe 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 projector program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

The independent consulting petroleum engineering firm of DeGolyer and MacNaughton of Dallas, Texas, calculated the Company’s oil, NGL and natural gas reserves as of September 30, 2013,  2012 and 2011 (see Exhibits 23 and 99).

The Company’s net proved oil, NGL and natural gas reserves, all of which are located in the United States, as of September 30, 2013,  2012 and 2011, have been estimated by the Company’s Independent Consulting Petroleum Engineering Firm. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principals and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

11. SUPPLEMENTARY INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES (UNAUDITED) (CONTINUED)

methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history.

All of the reserve estimates are reviewed and approved by our Vice President and COO, who reports directly to our President and CEO.Mr. Blanchard, our COO, holds a Bachelor of Science Degree

in Petroleum Engineering from the University of Oklahoma.Before joining the Company, he was sole proprietor of a consulting petroleum engineering firm, spent 10 years as Vice President of the Mid-

Continent business unit of Range Resources Corporation and spent several years as an engineer with Enron Oil and Gas.He is an active member of the Society of Petroleum Engineers (SPE) with over 27 years of oil and gas industry experience, including engineering assignments in several field locations.

Our COO and internal staff work closely with our Independent Consulting Petroleum Engineers to ensure the integrity, accuracy and timeliness of data furnished to them for their reserves estimation process. We provide historical information to our Independent Consulting Petroleum

Engineers for all properties such as ownership interest, oil and gas production, well test data, commodity prices, operatingcosts and handling fees, and development costs.Throughout the year, our team meets regularly with representatives of our Independent Consulting Petroleum Engineers to review propertiesand 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:

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

11. SUPPLEMENTARY INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES (UNAUDITED) (CONTINUED)

	Proved Reserves
	Oil	NGL (1)	Natural Gas
	(Barrels)	(Barrels)	(Mcf)
September 30, 2010	925,009	-	98,170,455
Revisions of previous estimates	(59,360)	791,648	769,676
Divestitures	-	-	3,189,520
Extensions, discoveries and other additions	82,230	-	8,005,990
Production	(104,141)	-	(8,297,657)
September 30, 2011	843,738	791,648	101,837,984
Revisions of previous estimates	8,627	(76,794)	(27,389,752)
Acquisitions	-	-	19,075,529
Extensions, discoveries and other additions	373,097	172,602	29,062,593
Production	(153,143)	(98,714)	(9,072,298)
September 30, 2012	1,072,319	788,742	113,514,056
Revisions of previous estimates	(90,968)	141,081	(2,697,853)
Acquisitions	-	-	1,660,649
Extensions, discoveries and other additions	896,036	798,200	30,698,644
Production	(234,084)	(111,897)	(10,886,329)
September 30, 2013	1,643,303	1,616,126	132,289,167

(1) 2011 was the first year the Company had sufficient volumes of NGL to warrant reserve volumes disclosure.These NGL are associated with the rapid increase in drilling activity in western and southern Oklahoma and the Texas Panhandle, which includes many plays (horizontal Granite Wash, Hogshooter Wash, Cleveland, Marmaton, Anadarko Basin Woodford Shale and Ardmore Basin Woodford Shale) producing significant volumes of NGL.

The prices used to calculate reserves and future cash flows from reserves for oil, NGL and natural gas, respectively, were as follows: September 30, 2013 - $89.06/Bbl,  $27.28/Bbl,  $3.33/Mcf ; September 30, 2012–$89.41/Bbl,  $35.70/Bbl,  $2.51/Mcf;  September 30, 2011 - $90.28/Bbl,  $38.91/Bbl,  $3.81/Mcf.  

The revisions of previous estimates from 2012 to 2013were primarily the result of:

· Negative performance revisions of 5,844,070 Mcfe, of which 8,803,480 Mcfe were positive proved developed revisions principally due to better than projected well performance attributable to properties in Arkansas and Oklahoma. Theremaining 14,647,551 Mcfe were negative proved undeveloped revisions principally attributable to the removal of dry gas (31)

Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

11. SUPPLEMENTARY INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES (UNAUDITED) (CONTINUED)

reserves which are no longer projected to be developed within 5 years from the date they were added to the proved undeveloped reserves.

· Positive pricing revisions of 3,446,900 Mcfe due to proved developed wells (3,109,159 Mcfe) and proved undeveloped locations (337,741 Mcfe)reaching their economic limits later than previously projected, thus adding reserves, due to higher product prices.

Extensions, discoveries and other additions from 2012 to 2013 are principally attributable to:

· The Company’s participation in ongoing development of conventional oil, NGL and natural gas plays utilizing horizontal drilling, including the Cleveland and Granite Wash plays in western Oklahoma and the Texas Panhandle, as well as the Marmaton and Hogshooter Wash plays in western Oklahoma.

· The Company’s participation in ongoing development of unconventional natural gas plays utilizing horizontal drilling, including the Arkansas Fayetteville Shale and, to a much lesser extent, the Southeastern Oklahoma Woodford Shale.

· The Company’s participation in ongoing development of unconventional oil, NGL and natural gas plays utilizing horizontal drilling in the Anadarko Basin Woodford Shale and Ardmore Basin Woodford Shale in western and southern Oklahoma.

· PUD additions principally in the Fayetteville Shale play in Arkansas, the Anadarko Basin Woodford Shale and Ardmore Basin Woodford Shale in western and southern Oklahoma and the Cleveland and Granite Wash plays in western Oklahoma and the Texas Panhandle, as well as the Marmaton and Hogshooter Wash plays in western Oklahoma. These additions are the result of reservoir delineation proved by continuing drilling and well performance data in each of the referenced plays.

	Proved Developed Reserves			Proved Undeveloped Reserves
	Oil	NGL	Natural Gas	Oil	NGL	Natural Gas
	(Barrels)	(Barrels)	(Mcf)	(Barrels)	(Barrels)	(Mcf)
September 30, 2011	759,989	386,774	60,193,878	83,749	404,874	41,644,106
September 30, 2012	849,548	494,160	65,733,119	222,771	294,582	47,780,937
September 30, 2013	1,037,721	764,321	82,298,833	605,582	851,805	49,990,334

The following details the changes in proved undeveloped reserves for 2013 (Mcfe):

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

11. SUPPLEMENTARY INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES (UNAUDITED) (CONTINUED)

Beginning proved undeveloped reserves	50,885,055
Proved undeveloped reserves transferred to proved developed	(12,124,203)
Revisions	(14,309,809)
Extensions and discoveries	32,806,004
Purchases	1,477,609
Ending proved undeveloped reserves	58,734,656

The beginning PUD reserves were 50.9 Bcfe. A total of 12.1 Bcfe (24% of the beginning balance) were transferred to proved developed producing during 2013. The 14.3 Bcfe of negative revisions to PUD reserves consist of a positive pricing revision of 0.3 Bcfe offset by a 14.6 Bcfe (29% of the beginning balance) negative performance revision in 2013 as the result of removal of dry gas reserves which are no longer projected to be developed within 5 years from the date they were added. A total of 26.7 Bcfe (53% of the beginning balance) of PUD reserves were moved out of the category during 2013 as either the result of being transferred to proved developed or removed because they were no longer projected to be developed within 5 years from the date they were added to the proved undeveloped reserves. Only 21 PUD locations from 2009, representing 1% of total 2013 PUD reserves remain in the PUD category. We anticipate that all the Company’s PUD locations will be drilled and converted to PDP within five years of the date they were added. However, PUD locations and associated reserves which are no longer projected to be drilled within 5 years from the datethey were added to the proved undeveloped reserves will be removed as revisions at the time that determination is made andin 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.

Standardized Measure of Discounted Future Net Cash Flows

Accounting Standards prescribe guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves.The Company has followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying the trailing unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs to the estimated quantities of oil, natural gas and NGL to be produced. Actual future prices and costs may be materially higher or lower than the unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which theyare 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 carryforwards, 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 reflect the valuation process.

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

11. SUPPLEMENTARY INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES (UNAUDITED) (CONTINUED)

	2013		2012		2011
Future cash inflows	$	630,332,900	$	408,694,869	$	494,523,456
Future production costs		(216,584,982)		(135,516,703)		(146,168,829)
Future development and asset retirement costs		(50,572,218)		(35,290,260)		(45,269,686)
Future income tax expense		(131,397,192)		(83,543,516)		(107,111,317)
Future net cash flows		231,778,508		154,344,390		195,973,624
10% annual discount		(130,103,612)		(86,930,102)		(117,591,190)
Standardized measure of discounted
future net cash flows	$	101,674,896	$	67,414,288	$	78,382,434

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

	2013		2012		2011
Beginning of year	$	67,414,288	$	78,382,434	$	72,500,409
Changes resulting from:
Sales of oil, NGL and natural gas, net of production costs		(46,909,635)		(30,226,927)		(33,570,621)
Net change in sales prices and production costs		47,270,404		(45,178,377)		(2,697,833)
Net change in future development and asset retirement costs		(7,363,224)		4,483,543		4,126,812
Extensions and discoveries		54,101,830		34,216,533		11,938,029
Revisions of quantity estimates		(3,150,420)		(27,419,576)		7,046,873
Acquisitions (divestitures) of reserves-in-place		2,198,612		20,160,327		4,480,858
Accretion of discount		11,473,819		13,644,203		12,523,091
Net change in income taxes		(27,464,341)		10,735,694		(5,329,092)
Change in timing and other, net		4,103,563		8,616,434		7,363,908
Net change		34,260,608		(10,968,146)		5,882,025
End of year	$	101,674,896	$	67,414,288	$	78,382,434

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Panhandle Oil and Gas Inc.

Notes to Financial Statements (continued)

12. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)

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

	Fiscal 2013
	Quarter Ended
	December 31		March 31		June 30		September 30
Revenues	$	14,180,435	$	12,581,986	$	17,730,445	$	18,396,254
Income (loss) before provision
for income taxes	$	2,825,298	$	1,761,487	$	7,323,168	$	8,780,096
Net income (loss)	$	2,148,298	$	1,022,487	$	5,070,168	$	5,719,096
Earnings (loss) per share	$	0.26	$	0.12	$	0.61	$	0.68
	Fiscal 2012
	Quarter Ended
	December 31		March 31		June 30		September 30
Revenues	$	13,404,333	$	10,436,910	$	13,649,692	$	11,041,382
Income (loss) before provision
for income taxes	$	4,261,110	$	1,205,966	$	4,681,299	$	496,621
Net income (loss)	$	3,412,110	$	675,966	$	3,100,299	$	182,621
Earnings (loss) per share	$	0.41	$	0.08	$	0.37	$	0.02

(35)

PART IV

ITEM 15EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

FINANCIAL STATEMENT SCHEDULES

The Company has omitted all schedules because the conditions requiring their filing do not exist or because the required information appears in the Company’s Financial Statements, including the notes to those statements.

EXHIBITS

**(3)	Amended Certificate of Incorporation (incorporated by reference to Exhibit attached
	to Form 10 filed January 27, 1980, and to Forms 8-K dated June 1, 1982, December 3,
	1982, to Form 10-QSB dated March 31, 1999, and to Form 10-Q dated March 31, 2007)
	By-Laws as amended (incorporated by reference to Form 8-K dated October 31, 1994)
	By-Laws as amended (incorporated by reference to Form 8-K dated February 24, 2006)
	By-Laws as amended (incorporated by reference to Form 8-K dated October 29, 2008)
	By-Laws as amended (incorporated by reference to Form 8-K dated August 2, 2011)
**(4)	Instruments defining the rights of security holders (incorporated by reference to
	Certificate of Incorporation and By-Laws listed above)
*(10.1)	Agreement indemnifying directors and officers (incorporated by reference to
	Form 10-K dated September 30, 1989, and Form 8-K dated June 15, 2007)
*(10.2)	Agreements to provide certain severance payments and benefits to executive officers
	should a Change-in-Control occur as defined by the agreements (incorporated by reference
	to Form 8-K dated September 4, 2007)
**(23)	Consent of DeGolyer and MacNaughton, Independent Petroleum Engineering Consultants
***(31.1)	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
***(31.2)	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
***(32.1)	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
***(32.2)	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
**(99)	Report of DeGolyer and MacNaughton, Independent Petroleum Engineering Consultants
**(99.1)	Amended and Restated Credit Agreement dated November 25, 2013
(101.INS)	XBRL Instance Document
(101.SCH)	XBRL Taxonomy Extension Schema Document
(101.CAL)	XBRL Taxonomy Extension Calculation Linkbase Document
(101.LAB)	XBRL Taxonomy Extension Labels Linkbase Document
(101.PRE)	XBRL Taxonomy Extension Presentation Linkbase Document
(101.DEF)	XBRL Taxonomy Extension Definition Linkbase Document
*	Indicates management contract or compensatory plan or arrangement
**	Indicates previously filed exhibits
***	Indicates certificates filed herewith

REPORTS ON FORM 8-K

No Form 8-K’s were filed in the fourth quarter of 2013.

(36)

SIGNATURES

Pursuant to the requirements of Section 13 of the Securities Exchange Act of 1934, the registrant caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

PANHANDLE OIL AND GAS INC.

By: /s/ Michael C. Coffman

Michael C. Coffman

Chief Executive Officer

Date:  January 9, 2014

(37)

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Michael C. Coffman, certify that:

1.I have reviewed this annual report on Form 10-K of Panhandle Oil and Gas Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Michael C. Coffman

Michael C. Coffman

Chief Executive Officer

Date:January 9, 2014

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Lonnie J. Lowry, certify that:

1.I have reviewed this annual report on Form 10-K of Panhandle Oil and Gas Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

/s/ Lonnie J. Lowry

Lonnie J. Lowry

Chief Financial Officer

Date:January 9, 2014

EX-32.1

EXHIBIT 32.1

Panhandle Oil and Gas Inc.

5400 North Grand Blvd. Suite #300

Oklahoma City, OK  73112

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

REGARDING PERIODIC REPORT CONTAINING

FINANCIAL STATEMENTS

I, Michael C. Coffman,  President and Chief Executive Officer of Panhandle Oil and Gas Inc. (the “Company”), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify in connection with the Company’s Annual Report on Form 10-K for the period that ended September 30, 2013, as filed with the Securities and Exchange Commission (the “Report”) that:

(1) The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2) The information contained in this Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Michael C. Coffman

Michael C. Coffman

President &

Chief Executive Officer

January9, 2014

EX-32.2

EXHIBIT 32.2

Panhandle Oil and Gas Inc.

5400 North Grand Blvd. Suite #300

Oklahoma City, OK  73112

CERTIFICATION OF CHIEF FINANCIAL OFFICER

REGARDING PERIODIC REPORT CONTAINING

FINANCIAL STATEMENTS

I, Lonnie J. Lowry,  Vice President and Chief Financial Officer of Panhandle Oil and Gas Inc. (the “Company”), in compliance with 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, hereby certify in connection with the Company’s Annual Report on Form 10-K for the period that ended September 30, 2013, as filed with the Securities and Exchange Commission (the “Report”) that:

(1) The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

(2) The information contained in this Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Lonnie J. Lowry

Lonnie J. Lowry

Vice President &

Chief Financial Officer

January 9, 2014

XML

Information On Oil And Natural Gas Producing Activities

12 Months Ended

Sep. 30, 2013

Information On Oil And Natural Gas Producing Activities [Abstract]

Information On Oil And Natural Gas Producing Activities

10. INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES

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

The following table shows sales through various operators/purchasers during 2013,  2012 and 2011.

	2013	2012	2011
Southwestern Energy Company	20%	15%	9%
Chesapeake Operating, Inc.	10%	13%	15%
Devon Energy Corp.	7%	10%	9%
Apache Corporation	6%	4%	2%
Newfield Exploration	5%	7%	14%

XML

Information On Oil And Natural Gas Producing Activities (Details)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Southwestern Energy Company [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Percentage of revenue	20.00%	15.00%	9.00%
Chesapeake Operating Inc [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Percentage of revenue	10.00%	13.00%	15.00%
Devon Energy Corp [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Percentage of revenue	7.00%	10.00%	9.00%
Apache Corporation [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Percentage of revenue	6.00%	4.00%	2.00%
Newfield Exploration [Member]
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]
Percentage of revenue	5.00%	7.00%	14.00%

XML

Statements Of Operations (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Revenues:
Oil, NGL and natural gas sales	$ 60,605,878	$ 40,818,434	$ 43,469,130
Lease bonuses and rentals	938,846	7,152,991	352,757
Gains (losses) on derivative contracts	611,024	73,822	734,299
Income from partnerships	733,372	487,070	420,465
Total revenues	62,889,120	48,532,317	44,976,651
Costs and expenses:
Lease operating expenses	11,861,403	9,141,970	8,441,754
Production taxes	1,834,840	1,449,537	1,456,755
Exploration costs	9,795	979,718	1,025,542
Depreciation, depletion and amortization	21,945,768	19,061,239	14,712,188
Provision for impairment	530,670	826,508	1,728,162
Loss (gain) on asset sales, interest and other	(785,401)	39,493	(68,325)
General and administrative	6,801,996	6,388,856	5,994,663
Total costs and expenses	42,199,071	37,887,321	33,290,739
Income (loss) before provision (benefit) for income taxes	20,690,049	10,644,996	11,685,912
Provision (benefit) for income taxes	6,730,000	3,274,000	3,192,000
Net income (loss)	$ 13,960,049	$ 7,370,996	$ 8,493,912
Basic and diluted earnings per common share:
Net income (loss)	$ 1.67	$ 0.88	$ 1.01

XML

Income Taxes

12 Months Ended

Sep. 30, 2013

Income Taxes [Abstract]

Income Taxes

3. INCOME TAXES

The Company’s provision (benefit) for income taxes is detailed as follows:

	2013		2012		2011
Current:
Federal	$	1,813,000	$	1,452,000	$	1,266,000
State		150,000		20,000		48,000
		1,963,000		1,472,000		1,314,000
Deferred:
Federal		4,003,000		1,126,000		1,982,000
State		764,000		676,000		(104,000)
		4,767,000		1,802,000		1,878,000
	$	6,730,000	$	3,274,000	$	3,192,000

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:

	2013		2012		2011
Provision (benefit) for income taxes at statutory rate	$	7,241,517	$	3,725,749	$	4,090,069
Percentage depletion		(1,059,303)		(846,040)		(733,516)
State income taxes, net of federal provision (benefit)		572,650		464,677		(92,989)
State net operating loss valuation allowance (release)		-		(31,000)		31,000
Other		(24,864)		(39,386)		(102,564)
	$	6,730,000	$	3,274,000	$	3,192,000

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:

	2013		2012
Deferred tax liabilities:
Financial basis in excess of tax basis, principally
intangible drilling costs capitalized for financial
purposes and expensed for tax purposes	$	33,557,515	$	30,320,765
Derivative contracts		165,402		-
		33,722,917		30,320,765
Deferred tax assets:
State net operating loss carry forwards, net of
valuation allowance of $0 in 2013 and 2012		782,785		1,008,271
AMT credit carry forwards		-		1,189,053
Deferred directors' compensation		1,021,717		990,455
Restricted stock expense		426,788		-
Statutory depletion carry forwards		-		415,958
Other		137,620		130,021
		2,368,910		3,733,758
Net deferred tax liabilities	$	31,354,007	$	26,587,007

At September 30, 2013, the Company had an income tax benefit of $782,785 related to Oklahoma state income tax net operating loss (OK NOL) carry forwards expiring from 2028 to 2031. There is no valuation allowance for the OK NOL’s as management believes they will be utilized before they expire.

XML

Employee Stock Ownership Plan (Tables)

12 Months Ended

Sep. 30, 2013

Employee Stock Ownership Plan [Abstract]

Summary Of Plan Contributions

Year	Shares	Amount
2013	10,907	$	308,450
2012	10,660	$	326,942
2011	10,710	$	303,843

XML

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, 2013	Sep. 30, 2012	Sep. 30, 2011
Supplementary Information On Oil, Ngl And Natural Gas Reserves [Abstract]
Property acquisition costs	$ 1,242,615	$ 20,404,465	$ 5,140,862
Exploration costs		1,210,417	4,837,451
Development costs	27,938,160	24,578,943	17,310,808
Total cost incurred	$ 29,180,775	$ 46,193,825	$ 27,289,121

XML

Supplementary Information On Oil, Ngl And Natural Gas Reserves

12 Months Ended

Sep. 30, 2013

Supplementary Information On Oil, Ngl And Natural Gas Reserves [Abstract]

Supplementary Information On OIl, Ngl And Natrual Gas Reserves

11. SUPPLEMENTARY  INFORMATION ON OIL, NGL AND NATURAL GAS RESERVES (UNAUDITED)

Aggregate Capitalized Costs

The aggregate amount of capitalized costs of oil and natural gas properties and related accumulated depreciation, depletion and amortization as of September 30 is as follows:

	2013		2012
Producing properties	$	304,889,145	$	275,997,569
Non-producing minerals		8,490,277		9,018,731
Non-producing leasehold		442,628		1,123,812
Exploratory wells in progress		-		8,018
		313,822,050		286,148,130
Accumulated depreciation, depletion and amortization		(186,042,746)		(164,652,199)
Net capitalized costs	$	127,779,304	$	121,495,931

Costs Incurred

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

	2013		2012		2011
Property acquisition costs	$	1,242,615	$	20,404,465	$	5,140,862
Exploration costs		-		1,210,417		4,837,451
Development costs		27,938,160		24,578,943		17,310,808
	$	29,180,775	$	46,193,825	$	27,289,121

In 2012, $17.4 million of the property acquisition costs related to the acquisition of certain assets in the Arkansas Fayetteville Shale.

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 isto be determined.The price shall bethe average price during the 12-month period prior to theending date of the period covered by the report,determined asan unweighted arithmetic average of the first-day-of-the-month price for each monthwithin such period, unless prices are defined by contractual arrangements, excluding escalations basedupon 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 reservoirconsidered 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 availablegeoscience 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 technologyestablishes 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 highercontact 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 ofthe 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 projector program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

The independent consulting petroleum engineering firm of DeGolyer and MacNaughton of Dallas, Texas, calculated the Company’s oil, NGL and natural gas reserves as of September 30, 2013,  2012 and 2011 (see Exhibits 23 and 99).

The Company’s net proved oil, NGL and natural gas reserves, all of which are located in the United States, as of September 30, 2013,  2012 and 2011, have been estimated by the Company’s Independent Consulting Petroleum Engineering Firm. Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering and evaluation principals and techniques that are in accordance with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (Revision as of February 19, 2007).” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data and production history.

All of the reserve estimates are reviewed and approved by our Vice President and COO, who reports directly to our President and CEO.Mr. Blanchard, our COO, holds a Bachelor of Science Degree

in Petroleum Engineering from the University of Oklahoma.Before joining the Company, he was sole proprietor of a consulting petroleum engineering firm, spent 10 years as Vice President of the Mid-

Continent business unit of Range Resources Corporation and spent several years as an engineer with Enron Oil and Gas.He is an active member of the Society of Petroleum Engineers (SPE) with over 27 years of oil and gas industry experience, including engineering assignments in several field locations.

Our COO and internal staff work closely with our Independent Consulting Petroleum Engineers to ensure the integrity, accuracy and timeliness of data furnished to them for their reserves estimation process. We provide historical information to our Independent Consulting Petroleum

Engineers for all properties such as ownership interest, oil and gas production, well test data, commodity prices, operatingcosts and handling fees, and development costs.Throughout the year, our team meets regularly with representatives of our Independent Consulting Petroleum Engineers to review propertiesand 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 (1)	Natural Gas
	(Barrels)	(Barrels)	(Mcf)
September 30, 2010	925,009	-	98,170,455
Revisions of previous estimates	(59,360)	791,648	769,676
Divestitures	-	-	3,189,520
Extensions, discoveries and other additions	82,230	-	8,005,990
Production	(104,141)	-	(8,297,657)
September 30, 2011	843,738	791,648	101,837,984
Revisions of previous estimates	8,627	(76,794)	(27,389,752)
Acquisitions	-	-	19,075,529
Extensions, discoveries and other additions	373,097	172,602	29,062,593
Production	(153,143)	(98,714)	(9,072,298)
September 30, 2012	1,072,319	788,742	113,514,056
Revisions of previous estimates	(90,968)	141,081	(2,697,853)
Acquisitions	-	-	1,660,649
Extensions, discoveries and other additions	896,036	798,200	30,698,644
Production	(234,084)	(111,897)	(10,886,329)
September 30, 2013	1,643,303	1,616,126	132,289,167

(1) 2011 was the first year the Company had sufficient volumes of NGL to warrant reserve volumes disclosure.These NGL are associated with the rapid increase in drilling activity in western and southern Oklahoma and the Texas Panhandle, which includes many plays (horizontal Granite Wash, Hogshooter Wash, Cleveland, Marmaton, Anadarko Basin Woodford Shale and Ardmore Basin Woodford Shale) producing significant volumes of NGL.

The prices used to calculate reserves and future cash flows from reserves for oil, NGL and natural gas, respectively, were as follows: September 30, 2013 - $89.06/Bbl,  $27.28/Bbl,  $3.33/Mcf ; September 30, 2012  –$89.41/Bbl,  $35.70/Bbl,  $2.51/Mcf;  September 30, 2011 - $90.28/Bbl,  $38.91/Bbl,  $3.81/Mcf.  

The revisions of previous estimates from 2012 to 2013were primarily the result of:

· Negative performance revisions of 5,844,070 Mcfe, of which 8,803,480 Mcfe were positive proved developed revisions principally due to better than projected well performance attributable to properties in Arkansas and Oklahoma. Theremaining 14,647,551 Mcfe were negative proved undeveloped revisions principally attributable to the removal of dry gasreserves which are no longer projected to be developed within 5 years from the date they were added to the proved undeveloped reserves.

· Positive pricing revisions of 3,446,900 Mcfe due to proved developed wells (3,109,159 Mcfe) and proved undeveloped locations (337,741 Mcfe) reaching their economic limits later than previously projected, thus adding reserves, due to higher product prices.

Extensions, discoveries and other additions from 2012 to 2013 are principally attributable to:

· The Company’s participation in ongoing development of conventional oil, NGL and natural gas plays utilizing horizontal drilling, including the Cleveland and Granite Wash plays in western Oklahoma and the Texas Panhandle, as well as the Marmaton and Hogshooter Wash plays in western Oklahoma.

· The Company’s participation in ongoing development of unconventional natural gas plays utilizing horizontal drilling, including the Arkansas Fayetteville Shale and, to a much lesser extent, the Southeastern Oklahoma Woodford Shale.

· The Company’s participation in ongoing development of unconventional oil, NGL and natural gas plays utilizing horizontal drilling in the Anadarko Basin Woodford Shale and Ardmore Basin Woodford Shale in western and southern Oklahoma.

· PUD additions principally in the Fayetteville Shale play in Arkansas, the Anadarko Basin Woodford Shale and Ardmore Basin Woodford Shale in western and southern Oklahoma and the Cleveland and Granite Wash plays in western Oklahoma and the Texas Panhandle, as well as the Marmaton and Hogshooter Wash plays in western Oklahoma. These additions are the result of reservoir delineation proved by continuing drilling and well performance data in each of the referenced plays.

	Proved Developed Reserves			Proved Undeveloped Reserves
	Oil	NGL	Natural Gas	Oil	NGL	Natural Gas
	(Barrels)	(Barrels)	(Mcf)	(Barrels)	(Barrels)	(Mcf)
September 30, 2011	759,989	386,774	60,193,878	83,749	404,874	41,644,106
September 30, 2012	849,548	494,160	65,733,119	222,771	294,582	47,780,937
September 30, 2013	1,037,721	764,321	82,298,833	605,582	851,805	49,990,334

The following details the changes in proved undeveloped reserves for 2013 (Mcfe):

Beginning proved undeveloped reserves	50,885,055
Proved undeveloped reserves transferred to proved developed	(12,124,203)
Revisions	(14,309,809)
Extensions and discoveries	32,806,004
Purchases	1,477,609
Ending proved undeveloped reserves	58,734,656

The beginning PUD reserves were 50.9 Bcfe. A total of 12.1 Bcfe (24% of the beginning balance) were transferred to proved developed producing during 2013. The 14.3 Bcfe of negative revisions to PUD reserves consist of a positive pricing revision of 0.3 Bcfe offset by a 14.6 Bcfe (29% of the beginning balance) negative performance revision in 2013 as the result of removal of dry gas reserves which are no longer projected to be developed within 5 years from the date they were added. A total of 26.7 Bcfe (53% of the beginning balance) of PUD reserves were moved out of the category during 2013 as either the result of being transferred to proved developed or removed because they were no longer projected to be developed within 5 years from the date they were added to the proved undeveloped reserves. Only 21 PUD locations from 2009, representing 1% of total 2013 PUD reserves remain in the PUD category. We anticipate that all the Company’s PUD locations will be drilled and converted to PDP within five years of the date they were added. However, PUD locations and associated reserves which are no longer projected to be drilled within 5 years from the datethey were added to the proved undeveloped reserves will be removed as revisions at the time that determination is made and in the event that there are undrilled PUD locations at the end of the five-year period, it is our intent to remove the reserves associated with those locations from our proved reserves as revisions.

Standardized Measure of Discounted Future Net Cash Flows

Accounting Standards prescribe guidelines for computing a standardized measure of future net cash flows and changes therein relating to estimated proved reserves.The Company has followed these guidelines, which are briefly discussed below.

Future cash inflows and future production and development costs are determined by applying the trailing unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs to the estimated quantities of oil, natural gas and NGL to be produced. Actual future prices and costs may be materially higher or lower than the unweighted 12-month arithmetic average of the first-day-of-the-month individual product prices and year-end costs used. For each year, estimates are made of quantities of proved reserves and the future periods during which theyare 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 carryforwards, 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 reflect the valuation process.

	2013		2012		2011
Future cash inflows	$	630,332,900	$	408,694,869	$	494,523,456
Future production costs		(216,584,982)		(135,516,703)		(146,168,829)
Future development and asset retirement costs		(50,572,218)		(35,290,260)		(45,269,686)
Future income tax expense		(131,397,192)		(83,543,516)		(107,111,317)
Future net cash flows		231,778,508		154,344,390		195,973,624
10% annual discount		(130,103,612)		(86,930,102)		(117,591,190)
Standardized measure of discounted
future net cash flows	$	101,674,896	$	67,414,288	$	78,382,434

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

	2013		2012		2011
Beginning of year	$	67,414,288	$	78,382,434	$	72,500,409
Changes resulting from:
Sales of oil, NGL and natural gas, net of production costs		(46,909,635)		(30,226,927)		(33,570,621)
Net change in sales prices and production costs		47,270,404		(45,178,377)		(2,697,833)
Net change in future development and asset retirement costs		(7,363,224)		4,483,543		4,126,812
Extensions and discoveries		54,101,830		34,216,533		11,938,029
Revisions of quantity estimates		(3,150,420)		(27,419,576)		7,046,873
Acquisitions (divestitures) of reserves-in-place		2,198,612		20,160,327		4,480,858
Accretion of discount		11,473,819		13,644,203		12,523,091
Net change in income taxes		(27,464,341)		10,735,694		(5,329,092)
Change in timing and other, net		4,103,563		8,616,434		7,363,908
Net change		34,260,608		(10,968,146)		5,882,025
End of year	$	101,674,896	$	67,414,288	$	78,382,434

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Deferred Compensation Plan For Directors (Details) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Deferred Compensation Plan For Directors [Abstract]
Number of shares credited to directors deferred fee account	122,219	121,348
Outstanding deferred balance	$ 2,756,526	$ 2,676,160
Total expenses charged to the company's results of operations	$ 377,520	$ 417,347	$ 443,456

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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, 2013 bbl		Sep. 30, 2012 bbl		Sep. 30, 2011 bbl
Oil [Member]
Reserve Quantities [Line Items]
Proved Oil and Natural Gas Reserves, Beginning Balance	1,072,319		843,738		925,009
Revisions of previous estimates	(90,968)		8,627		(59,360)
Extensions and discoveries and other additions	896,036		373,097		82,230
Production	(234,084)		(153,143)		(104,141)
Proved Oil and Natural Gas Reserves, Ending Balance	1,643,303		1,072,319		843,738
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Proved Oil and Natural Gas Reserves, Beginning Balance	788,742	[1],[2]	791,648	[1],[2]
Revisions of previous estimates	141,081	[1],[2]	(76,794)	[1],[2]	791,648	[1],[2]
Extensions and discoveries and other additions	798,200	[1],[2]	172,602	[1],[2]
Production	(111,897)	[1],[2]	(98,714)	[1],[2]
Proved Oil and Natural Gas Reserves, Ending Balance	1,616,126	[1],[2]	788,742	[1],[2]	791,648	[1],[2]
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Oil and Natural Gas Reserves, Beginning Balance	113,514,056		101,837,984		98,170,455
Revisions of previous estimates	(2,697,853)		(27,389,752)		769,676
Divestitures					3,189,520
Acquisitions	1,660,649		19,075,529
Extensions and discoveries and other additions	30,698,644		29,062,593		8,005,990
Production	(10,886,329)		(9,072,298)		(8,297,657)
Proved Oil and Natural Gas Reserves, Ending Balance	132,289,167		113,514,056		101,837,984

[1] 2011 was the first year the Company had sufficient volumes of NGL to warrant reserve volumes disclosure.

[2] 2011 was the first year the Company had sufficient volumes of NGL to warrant reserve volumes disclosure. These NGL are associated with the rapid increase in drilling activity in western and southern Oklahoma and the Texas Panhandle, which includes many plays (horizontal Granite Wash, Hogshooter Wash, Cleveland, Marmaton, Anadarko Basin Woodford Shale and Ardmore Basin Woodford Shale) producing significant volumes of NGL.

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Commitments (Details) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Commitments [Abstract]
Future minimum rental payments under the terms of the lease due in 2014	$ 204,089
Future minimum rental payments under the terms of the lease due in 2015	119,052
Rental Expenses	$ 200,782	$ 204,011	$ 204,089

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Supplementary Information On Oil, Ngl And Natural Gas Reserves (Tables)

12 Months Ended

Sep. 30, 2013

Supplementary Information On Oil, Ngl And Natural Gas Reserves [Abstract]

Summary Of Capitalized Costs Of Oil And Natural Gas Properties And Related Depreciation, Depletion And Amortization

	2013		2012
Producing properties	$	304,889,145	$	275,997,569
Non-producing minerals		8,490,277		9,018,731
Non-producing leasehold		442,628		1,123,812
Exploratory wells in progress		-		8,018
		313,822,050		286,148,130
Accumulated depreciation, depletion and amortization		(186,042,746)		(164,652,199)
Net capitalized costs	$	127,779,304	$	121,495,931

Summary Of Costs Incurred In Oil And Natural Gas Producing Activities

	2013		2012		2011
Property acquisition costs	$	1,242,615	$	20,404,465	$	5,140,862
Exploration costs		-		1,210,417		4,837,451
Development costs		27,938,160		24,578,943		17,310,808
	$	29,180,775	$	46,193,825	$	27,289,121

Summary Of Net Quantities Of Proved, Developed And Undeveloped Oil And Natural Gas Reserves

	Proved Reserves
	Oil	NGL (1)	Natural Gas
	(Barrels)	(Barrels)	(Mcf)
September 30, 2010	925,009	-	98,170,455
Revisions of previous estimates	(59,360)	791,648	769,676
Divestitures	-	-	3,189,520
Extensions, discoveries and other additions	82,230	-	8,005,990
Production	(104,141)	-	(8,297,657)
September 30, 2011	843,738	791,648	101,837,984
Revisions of previous estimates	8,627	(76,794)	(27,389,752)
Acquisitions	-	-	19,075,529
Extensions, discoveries and other additions	373,097	172,602	29,062,593
Production	(153,143)	(98,714)	(9,072,298)
September 30, 2012	1,072,319	788,742	113,514,056
Revisions of previous estimates	(90,968)	141,081	(2,697,853)
Acquisitions	-	-	1,660,649
Extensions, discoveries and other additions	896,036	798,200	30,698,644
Production	(234,084)	(111,897)	(10,886,329)
September 30, 2013	1,643,303	1,616,126	132,289,167

2011 was the first year the Company had sufficient volumes of NGL to warrant reserve volumes disclosure.

Summary Of Proved Developed And Undeveloped Reserves

	Proved Developed Reserves			Proved Undeveloped Reserves
	Oil	NGL	Natural Gas	Oil	NGL	Natural Gas
	(Barrels)	(Barrels)	(Mcf)	(Barrels)	(Barrels)	(Mcf)
September 30, 2011	759,989	386,774	60,193,878	83,749	404,874	41,644,106
September 30, 2012	849,548	494,160	65,733,119	222,771	294,582	47,780,937
September 30, 2013	1,037,721	764,321	82,298,833	605,582	851,805	49,990,334

Summary Of Proved Undeveloped Reserves

Beginning proved undeveloped reserves	50,885,055
Proved undeveloped reserves transferred to proved developed	(12,124,203)
Revisions	(14,309,809)
Extensions and discoveries	32,806,004
Purchases	1,477,609
Ending proved undeveloped reserves	58,734,656

Summary Of Standardized Measure Of Discounted Future Net Cash Flows

	2013		2012		2011
Future cash inflows	$	630,332,900	$	408,694,869	$	494,523,456
Future production costs		(216,584,982)		(135,516,703)		(146,168,829)
Future development and asset retirement costs		(50,572,218)		(35,290,260)		(45,269,686)
Future income tax expense		(131,397,192)		(83,543,516)		(107,111,317)
Future net cash flows		231,778,508		154,344,390		195,973,624
10% annual discount		(130,103,612)		(86,930,102)		(117,591,190)
Standardized measure of discounted
future net cash flows	$	101,674,896	$	67,414,288	$	78,382,434

Summary Of Changes In Standardized Measure Of Discounted Future Net Cash Flows

	2013		2012		2011
Beginning of year	$	67,414,288	$	78,382,434	$	72,500,409
Changes resulting from:
Sales of oil, NGL and natural gas, net of production costs		(46,909,635)		(30,226,927)		(33,570,621)
Net change in sales prices and production costs		47,270,404		(45,178,377)		(2,697,833)
Net change in future development and asset retirement costs		(7,363,224)		4,483,543		4,126,812
Extensions and discoveries		54,101,830		34,216,533		11,938,029
Revisions of quantity estimates		(3,150,420)		(27,419,576)		7,046,873
Acquisitions (divestitures) of reserves-in-place		2,198,612		20,160,327		4,480,858
Accretion of discount		11,473,819		13,644,203		12,523,091
Net change in income taxes		(27,464,341)		10,735,694		(5,329,092)
Change in timing and other, net		4,103,563		8,616,434		7,363,908
Net change		34,260,608		(10,968,146)		5,882,025
End of year	$	101,674,896	$	67,414,288	$	78,382,434

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Information On Oil And Natural Gas Producing Activities (Tables)

12 Months Ended

Sep. 30, 2013

Information On Oil And Natural Gas Producing Activities [Abstract]

Summary Of Sales Through Various Operators Or Purchasers

	2013	2012	2011
Southwestern Energy Company	20%	15%	9%
Chesapeake Operating, Inc.	10%	13%	15%
Devon Energy Corp.	7%	10%	9%
Apache Corporation	6%	4%	2%
Newfield Exploration	5%	7%	14%

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Employee Stock Ownership Plan (Narrative) (Details)	12 Months Ended
	Sep. 30, 2013
Employee Stock Ownership Plan [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	259,060

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Summary Of Significant Accounting Policies (Summary Of Unobservable Inputs For Level 3 Fair Value Measurements) (Details) (USD $)	12 Months Ended
	Sep. 30, 2013
Oil costless collars [Member]
Derivative [Line Items]
Unobservable Input	Oil price volatility curve
Weighted Average	10.27%
Fair Value	$ (233,041)
Oil costless collars [Member] | Minimum [Member]
Derivative [Line Items]
Range	0.00%
Oil costless collars [Member] | Maximum [Member]
Derivative [Line Items]
Range	17.56%
Natural Gas Costless Collars [Member]
Derivative [Line Items]
Unobservable Input	Natural gas price volatility curve
Weighted Average	12.00%
Fair Value	$ 475,943
Natural Gas Costless Collars [Member] | Minimum [Member]
Derivative [Line Items]
Range	0.00%
Natural Gas Costless Collars [Member] | Maximum [Member]
Derivative [Line Items]
Range	19.67%

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Income Taxes (Summary of Provision (Benefit) for Income Taxes) (Details) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Income Taxes [Abstract]
Federal	$ 1,813,000	$ 1,452,000	$ 1,266,000
State	150,000	20,000	48,000
Current	1,963,000	1,472,000	1,314,000
Federal	4,003,000	1,126,000	1,982,000
State	764,000	676,000	(104,000)
Deferred	4,767,000	1,802,000	1,878,000
provision (benefit) for income taxes	$ 6,730,000	$ 3,274,000	$ 3,192,000

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Restricted Stock Plan (Narrative) (Details)	Sep. 30, 2013
Restricted Stock Plan [Abstract]
Common Stock Shares	100,000

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Summary Of Significant Accounting Policies (Summary Of Realized And Unrealized Gains And (Losses)) (Details) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Summary Of Significant Accounting Policies [Abstract]
Realized	$ 13,555	$ 462,033	$ 2,138,685
Increase (decrease) in fair value	597,469	(388,211)	(1,404,386)
Total	$ 611,024	$ 73,822	$ 734,299

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Long-Term Debt (Details) (USD $)	12 Months Ended
	Sep. 30, 2013
Line Of Credit Facility [Line Items]
Revolving loan credit facility	$ 80,000,000
Current pricing forecast and a discount rate	8.00%
Borrowing base of credit facility	35,000,000
Secured by carrying value	$ 40,042,933
Credit facility maturity	Nov. 30, 2017
Effective Interest rate	2.36%
Annual Non Use Fee Percentage	0.25%
Minimum [Member] | Prime Rate [Member]
Line Of Credit Facility [Line Items]
Interest rate basis	0.375%
Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line Of Credit Facility [Line Items]
Interest rate basis	1.875%
Maximum [Member] | Prime Rate [Member]
Line Of Credit Facility [Line Items]
Interest rate basis	1.125%
Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line Of Credit Facility [Line Items]
Interest rate basis	2.625%

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Restricted Stock Plan (Tables)

12 Months Ended

Sep. 30, 2013

Restricted Stock Plan [Abstract]

Summary Of Pre-Tax Compensation Expense

		Year Ended September 30,
	2013		2012		2011
Performance based, restricted stock	$	345,405	$	150,480	$	42,909
Non-performance based, restricted stock		338,563		180,443		109,573
Total compensation expense	$	683,968	$	330,923	$	152,482

Summary Of Unrecognized Compensation Cost

	Unrecognized Compensation Cost		Weighted Average Period (in years)
Performance based, restricted stock	$	282,726	1.41
Non-performance based, restricted stock		227,628	1.48
Total	$	510,354

Summary Of Status Of Unvested Shares Of Restricted Stock Awards

	Performance Based Unvested Restricted Shares	Weighted Average Grant-Date Fair Value		Non-Performance Based Unvested Restricted Shares	Weighted Average Grant-Date Fair Value
Unvested shares as of
September 30, 2010	-	$	-	8,500	$	28.30
Granted	8,782		19.54	8,780		28.00
Vested	-		-	-		-
Forfeited	-		-	-		-
Unvested shares as of
September 30, 2011	8,782	$	19.54	17,280	$	28.15
Granted	17,709		19.47	5,903		31.55
Vested	-		-	-		-
Forfeited	-		-	-		-
Unvested shares as of	26,491	$	19.49	23,183	$	29.01
September 30, 2012
Granted	20,104		15.18	6,701		29.19
Vested	-		-	-		-
Forfeited	-		-	-		-
Unvested shares as of	46,595	$	17.63	29,884	$	29.05
September 30, 2013

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Statements Of Stockholders' Equity (Parenthetical) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Statements Of Stockholders' Equity [Abstract]
Dividends per share	$ 0.28	$ 0.28	$ 0.28

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Summary Of Significant Accounting Policies

12 Months Ended

Sep. 30, 2013

Summary Of Significant Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Nature of Business

Since its formation, the Company has been involved in the acquisition and management of fee mineral acreage and the exploration for, and development of, oil and natural gas properties, principally involving drilling wells located on the Company’s mineral acreage. Panhandle’s mineral properties and other oil and natural gas interests are all located in the United States, primarily in Arkansas, New Mexico, North Dakota, Oklahoma and Texas. The Company is not the operator of any wells. The Company’s oil, NGL and natural gas production is from interests in 6,105 wells located principally in Oklahoma and Arkansas. Approximately 60% of oil, NGL and natural gas revenues were derived from the sale of natural gas in 2013. Approximately 84% of the Company’s total sales volumes in 2013 were derived from natural gas. Substantially all the Company’s oil, NGL and natural gas production is sold through the operators of the wells. The Company from time to time disposes of 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. On an annual basis, with a semi-annual update, the Company’s Independent Consulting Petroleum Engineer, with assistance from the Company, prepares estimates of crude oil, NGL and natural gas reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. For DD&A purposes, and as required by the guidelines and definitions established by the SEC, the reserve estimates were based on average individual product prices during the 12-month period prior to September 30 determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices were defined by contractual arrangements, excluding escalations based upon future conditions. For impairment purposes, projected future crude oil, NGL and natural gas prices as estimated by management are used. Crude oil, NGL and natural gas prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Projected future crude oil, NGL and natural gas pricing assumptions are used by management to prepare estimates of crude oil, NGL and natural gas reserves 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) over a month later than the information is available to the operators of the wells. This being the case, on wells with greater significance to the Company, the most current available production data is gathered from the appropriate operators, and oil, NGL and natural gas index prices local to each well are used to estimate the accrual of revenue on these wells. Timely obtaining production data on all other wells from the operators is not feasible; therefore, the Company utilizes past production receipts and estimated sales price information to estimate its accrual of revenue on all other wells each quarter. The oil, NGL and natural gas sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for oil, NGL and natural gas. These variables could lead to an over or under accrual of oil, NGL and natural gas sales at the end of any particular quarter. Based on past history, the Company’s estimated accrual has been materially accurate.

Cash and Cash Equivalents

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 and Natural Gas Imbalances

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

The Company uses the sales method of accounting for natural gas imbalances in those circumstances where it has underproduced or overproduced its ownership percentage in a property. Under this method, a receivable or liability is recorded to the extent that an underproduced or overproduced position in a well cannot be recouped through the production of remaining reserves. At September 30, 2013 and 2012, the Company had no material natural gas imbalances.

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 we have an interest in may be similarly affected by changes in economic, industry or other conditions. During 2013 and 2012, we did not recognize a reserve for bad debt expense.

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 is determined to be nonproductive. Oil and natural gas mineral and leasehold costs are capitalized when incurred.

Non-producing oil and natural gas leases are assessed for impairment on a property-by-property basis for individually significant balances and on an aggregate basis for individually insignificant balances. If the assessment indicates an impairment, a loss is recognized by providing a valuation allowance at the level at which impairment was assessed. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms and potential shifts in business strategy employed by management. In the case of individually insignificant balances, the amount of the impairment loss recognized is determined by amortizing the portion of these properties’ costs, which the Company believes will not be transferred to proved properties over the remaining lives of the leases. Impairment loss is charged to exploration costs when recognized. As of September 30, 2013, the remaining carrying cost of non-producing oil and natural gas leases was $285,752.

It is common business practice in the petroleum industry for drilling costs to be prepaid before spudding a well. The Company frequently fulfills these prepayment requirements with cash payments, but at times will utilize letters of credit to meet these obligations. As of September 30, 2013, the Company had no outstanding letters of credit.

Leasing of Mineral Rights

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

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

Derivatives

The Company has entered into fixed swap contracts, basis protection swaps 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. Basis protection swaps are derivatives that guarantee a price differential to NYMEX for natural gas from a specified delivery point (CEGT and PEPL historically). The Company receives a payment from the counterparty if the price differential is greater than the agreed terms of the contract and pays the counterparty if the price differential is less than the agreed terms of the contract. These contracts cover only a portion of the Company’s oil and natural gas production and provide only partial price protection against declines in oil and natural gas prices. These derivative instruments expose the Company to risk of financial loss and may limit the benefit of future increases in prices. All of the Company’s derivative contracts are with Bank of Oklahoma and are secured. The derivative instruments have settled or will settle based on the prices below, which are adjusted for location differentials and tied to certain pipelines.

Derivative contracts in place as of September 30, 2012

(prices below reflect the Company’s net price from the listed pipelines)

	Production volume	Indexed
Contract period	covered per month	Pipeline	Fixed price
Natural gas basis protection swaps
January - December 2012	50,000 Mmbtu	CEGT	NYMEX -$.29
January - December 2012	40,000 Mmbtu	CEGT	NYMEX -$.30
January - December 2012	50,000 Mmbtu	PEPL	NYMEX -$.29
January - December 2012	50,000 Mmbtu	PEPL	NYMEX -$.30
Natural gas costless collars
March - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50floor/$3.25 ceiling
April - October 2012	120,000 Mmbtu	NYMEX Henry Hub	$2.50floor/$3.10 ceiling
April - October 2012	60,000 Mmbtu	NYMEX Henry Hub	$2.50floor/$3.20 ceiling
April - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50floor/$3.20 ceiling
April - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50floor/$3.45 ceiling
April - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50floor/$3.30 ceiling
August - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50floor/$3.30 ceiling
November 2012 - January 2013	150,000 Mmbtu	NYMEX Henry Hub	$3.00floor/$3.70 ceiling
November 2012 - January 2013	150,000 Mmbtu	NYMEX Henry Hub	$3.00floor/$3.70 ceiling
November 2012 - January 2013	50,000 Mmbtu	NYMEX Henry Hub	$3.00floor/$3.65 ceiling
Oil costless collars
January - December 2012	2,000 Bbls	NYMEX WTI	$90floor/$105 ceiling
February - December 2012	3,000 Bbls	NYMEX WTI	$90floor/$110 ceiling
May - December 2012	2,000 Bbls	NYMEX WTI	$90floor/$114 ceiling

Derivative contracts in place as of September 30, 2013

(prices below reflect the Company’s net price from the listed pipelines)

	Production volume	Indexed
Contract period	covered per month	pipeline	Fixed price
Natural gas costless collars
February - December 2013	80,000 Mmbtu	NYMEX Henry Hub	$3.75floor/$4.25 ceiling
February - December 2013	50,000 Mmbtu	NYMEX Henry Hub	$3.75floor/$4.30 ceiling
February - December 2013	100,000 Mmbtu	NYMEX Henry Hub	$3.75floor/$4.05 ceiling
November 2013 - April 2014	160,000 Mmbtu	NYMEX Henry Hub	$4.00floor/$4.55 ceiling
Natural gas fixed price swaps
March - October 2013	100,000 Mmbtu	NYMEX Henry Hub	$3.505
March - October 2013	70,000 Mmbtu	NYMEX Henry Hub	$3.400
April - December 2013	40,000 Mmbtu	NYMEX Henry Hub	$3.655
May - November 2013	100,000 Mmbtu	NYMEX Henry Hub	$4.320
Oil costless collars
March - December 2013	3,000 Bbls	NYMEX WTI	$90.00floor/$102.00 ceiling
March - December 2013	4,000 Bbls	NYMEX WTI	$90.00floor/$101.50 ceiling
May - December 2013	2,000 Bbls	NYMEX WTI	$90.00floor/$97.50 ceiling
January - June 2014	4,000 Bbls	NYMEX WTI	$90.00floor/$101.50 ceiling
Oil fixed price swaps
September - December 2013	4,000 Bbls	NYMEX WTI	$105.250

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 $425,198 as of September 30, 2013, and a net liability of $172,271 as of September 30, 2012. Realized and unrealized gains and (losses) are scheduled below:

Gains (losses) on natural gas	Fiscal year ended
derivative contracts	9/30/2013		9/30/2012		9/30/2011
Realized	$	13,555	$	462,033	$	2,138,685
Increase (decrease) in fair value		597,469		(388,211)		(1,404,386)
Total	$	611,024	$	73,822	$	734,299

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 Condensed Balance Sheets. The Company has chosen to present the fair values of its derivative contracts under master netting agreements using a net fair value presentation. 

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 Condensed Balance Sheets at September 30, 2013, and September 30, 2012. The Company adopted the accounting guidance requiring additional disclosures for balance sheet offsetting of assets and liabilities effective January 1, 2013. The Company has offset all amounts subject to master netting agreements in the Company's Condensed Balance Sheets at September 30, 2013, and September 30, 2012.

	9/30/2013				9/30/2012
	Fair Value (a)				Fair Value (a)
	Commodity Contracts				Commodity Contracts
	Current Assets		Current Liabilities		Current Assets		Current Liabilities
Gross amounts recognized	$	665,099	$	239,901	$	51,530	$	223,801
Offsetting adjustments		(239,901)		(239,901)		(51,530)		(51,530)
Net presentation on Condensed Balance Sheets	$	425,198	$	-	$	-	$	172,271

(a)See Fair Value Measurements section for further disclosures regarding fair value of financial instruments.

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

Fair Value 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 inputs are unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs include the following: (i) quoted prices for similar assets or liabilities in active markets; (ii) quoted prices for identical or similar assets or liabilities in markets that are not active; (iii) inputs other than quoted prices that are observable for the asset or liability; or (iv) inputs that are derived principally from, or corroborated by, observable market data by correlation or other means. Level 3 inputs are unobservable inputs for the financial asset or liability.

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

	Fair Value Measurement at September 30, 2013
	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	$	-	$	182,296	$	-	$	182,296
Derivative Contracts - Collars	$	-	$	-	$	242,902	$	242,902

	Fair Value Measurement at September 30, 2012
	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	$	-	$	(75,334)	$	-	$	(75,334)
Derivative Contracts - Collars	$	-	$	-	$	(96,937)	$	(96,937)

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

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

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

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

Instrument Type	Unobservable Input	Range	Weighted Average	Fair Value September 30, 2013
Oil Collars	Oil price volatility curve	0% - 17.56%	10.27%	$	(233,041)
Natural Gas Collars	Natural gas price volatility curve	0% - 19.67%	12.00%	$	475,943

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

	Derivatives
Balance of Level 3 as of October 1, 2012	$	(96,937)
Total gains or (losses) - realized and unrealized:
Included in earnings
Realized		242,435
Unrealized		97,404
Included in other comprehensive income (loss)		-
Purchases, issuances and settlements		-
Transfers in and out of Level 3		-
Balance of Level 3 as of September 30, 2013	$	242,902

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,
	2013				2012
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties	$	356,855	$	530,670	$	1,301,951	$	826,508	(a)

(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. Significant judgments and assumptions in these assessments include estimates of future oil, NGL and natural gas prices using a forward NYMEX curve adjusted for 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, 2013, and September 30, 2012, the fair value of financial instruments approximated their carrying amounts. Financial instruments include long-term debt, which the valuation is classified as Level 3 and is based on a valuation technique that requires inputs that are both unobservable and significant to the overall fair value measurement. The fair value measurement of our long-term debt is valued using a discounted cash flow model that calculates the present value of future cash flows pursuant to the terms of the debt agreements and applies estimated current market interest rates. The estimated current market interest rates are based primarily on interest rates currently being offered on borrowings of similar amounts and terms. In addition, no valuation input adjustments were considered necessary relating to nonperformance risk for the debt agreements.

Depreciation, Depletion, Amortization and Impairment

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 $4,702,285 and $5,374,868 at September 30, 2013 and 2012, respectively, consisting of perpetual ownership of mineral interests in several states, with 91% of the acreage in Arkansas, New Mexico, North Dakota, Oklahoma and Texas. As mentioned, these mineral rights are perpetual and have been accumulated over the 87-year life of the Company. There are approximately 196,768 net acres of non-producing minerals in more than 6,818 tracts owned by the Company. An average tract contains approximately 29 acres, and the average cost per acre is $43. 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 activity each year on these mineral interests. Non-producing minerals are being amortized straight-line over a 33-year period. These assets are considered a long-term investment by the Company, as they do not expire (as do oil and natural gas leases). Given the above, it was concluded that a long-term amortization was appropriate and that 33 years, based on past history and experience, was an appropriate period. Due to the fact that the minerals consist of a large number of properties, whose costs are not individually significant, and because virtually all are in the Company’s core operating areas, the minerals are being amortized on an aggregate basis.

The Company recognizes impairment losses for long-lived assets when indicators of impairment are present and the undiscounted cash flows are not sufficient to recover the assets’ carrying amount. The impairment loss is measured by comparing thefair value of the asset to its carrying amount. Fair values are based on discounted cash flow as estimated by the Company’s Independent Consulting Petroleum Engineer. The Company's estimate of fair value of its oil and natural gas properties at September 30, 2013, is based on the best information available as of that date, including estimates of forward oil, NGL and natural gas prices and costs. The Company’s oil and natural gas properties were reviewed for impairment on a field-by-field basis, resulting in the recognition of impairment provisions of $530,670,  $826,508 and $1,728,162, respectively, for 2013,  2012 and 2011. A significant reduction in oil, NGL and natural gas prices or a decline in reserve volumes would likely lead to additional impairment in future periods that may be material to the Company.

Capitalized Interest

During 2013,  2012 and 2011, interest of $121,418,  $129,172 and $0, respectively, was included in the Company’s capital expenditures. Interest of $157,558,  $127,970 and $0, respectively, was charged to expense during those periods. Interest is capitalized using a weighted average interest rate based on the

Company’s outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using unit-of-production method.

Investments

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

Asset Retirement Obligations

The Company owns interests in oil and natural gas properties, which may require expenditures to plug and abandon the wells when the oil, NGL and natural gas reserves in the wells are depleted. 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, 2013 and 2012, relating to the Company’s asset retirement obligations:

	2013		2012
Asset Retirement Obligations as of beginning of the year	$	2,122,950	$	1,843,875
Accretion of Discount		122,391		121,112
New Wells Placed on Production		167,609		184,027
Wells Sold or Plugged		(19,760)		(26,064)
Asset Retirement Obligations as of end of the year	$	2,393,190	$	2,122,950

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; however, to date the Company’s cost of compliance has been insignificant. 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 others, with Panhandle being responsible for its proportionate share of the costs involved. Panhandle carries liability insurance and pollution control coverage. 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, 2013 and 2012, 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 added to each director’s account based on the fair market value of the stock at the date earned. The Plan’s structure is that upon retirement, termination or death of the director or upon a change in control of the Company, the shares accrued under the Plan will be issued to the director.

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

Restricted stock awards to certain officers provide for cliff vesting at the end of three or five years from the date of the awards. The fair value of the awards 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 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 2010.

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, 2013,  2012 and 2011, the Company recorded interest and penalties of $927,  $0 and $21,000, respectively. The Company does not believe it has any significant uncertain tax positions.

New Accounting Standards

In December 2011, the Financial Accounting Standards Board issued "Balance Sheet: Disclosures about Offsetting Assets and Liabilities." The new standard requires entities to disclose information about financial instruments and derivative instruments that are either offset on the balance sheet or are subject to a master netting arrangement, including providing both gross information and net information for recognized assets and liabilities, the net amounts presented on an entity's balance sheet and a description of the rights of offset associated with these assets and liabilities. The new standard is applicable for all entities that have financialinstruments and derivative instruments shown using a net presentation on an entity's balance sheet or are subject to a master nettingarrangement. The new standard is effective for interim and annual reporting periods for fiscal years beginning on or after January1, 2013, and should be applied retrospectively for all periods presented. The Company adopted this new standard effectiveJanuary 1, 2013.

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.

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Long-Term Debt

12 Months Ended

Sep. 30, 2013

Long-Term Debt [Abstract]

Long-Term Debt

4. LONG-TERM DEBT

The Company has a credit facility with Bank of Oklahoma (BOK) consisting of a revolving loan in the amount of $80,000,000,  which is subject to a semi-annual borrowing base determination, wherein BOK applies their own current pricing forecast and an 8% discount rate to the Company’s proved reserves as calculated by the Company’s Independent Consulting Petroleum Engineering Firm. When applying the discount rate, BOK also applies an advance rate percentage to all proved non-producing and proved undeveloped reserves. The facility has a borrowing base of $35,000,000 and is secured by certain of the Company’s properties with a carrying value of $40,042,933 at September 30, 2013. The facility matures on November 30, 2017. The interest rate is based on BOK prime plus from 0.375% to 1.125%, or 30 day LIBOR plus from 1.875% to 2.625%. The election of BOK prime or LIBOR is at the Company’s discretion. The interest rate spread from LIBOR or the prime rate increases as a larger percent of the loan value of the Company’s oil and natural gas properties is advanced. The interest rate spread from BOK prime or LIBOR will be charged based on the percent of the value advanced of the calculated loan value of the Company’s oil and natural gas properties. At September 30, 2013, the effective interest rate was 2.36%.

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.

Since the bank charges a customary non-use fee of 0.25% annually of the unused portion of the borrowing base, the Company has not requested the bank to increase its borrowing base beyond $35,000,000. Determinations of the borrowing base are made semi-annually or whenever the bank, in its sole discretion, believes that there has been a material change in the value of the oil and natural gas properties. While the Company believes the availability could be increased (if needed) by placing more of the Company’s properties as security under the revolving credit facility, increases are at the discretion of the bank. The loan agreement contains customary covenants which, among other things, require periodic financial and reserve reporting and limit the Company’s incurrence of indebtedness, liens, dividends and acquisitions of treasury stock, and require the Company to maintain certain financial ratios. At September 30, 2013, the Company was in compliance with the covenants of the BOK agreement.

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Commitments

12 Months Ended

Sep. 30, 2013

Commitments [Abstract]

Commitments

2. COMMITMENTS

The Company leases office space in Oklahoma City, Oklahoma, under the terms of an operating lease expiring in April 2015.Future minimum rental payments under the terms of the lease are $204,089 in 2014 and $119,052 in 2015.Total rent expense incurred by the Company was $200,782 in 2013,  $204,011 in 2012 and $204,089 in 2011.

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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, 2013	Sep. 30, 2012	Sep. 30, 2011
Income Taxes [Abstract]
Provision (benefit) for income taxes at statutory rate	$ 7,241,517	$ 3,725,749	$ 4,090,069
Percentage depletion	(1,059,303)	(846,040)	(733,516)
State income taxes, net of federal provision (benefit)	572,650	464,677	(92,989)
State net operating loss valuation allowance (release)		(31,000)	31,000
Other	(24,864)	(39,386)	(102,564)
provision (benefit) for income taxes	$ 6,730,000	$ 3,274,000	$ 3,192,000

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Quarterly Results Of Operations (Tables)

12 Months Ended

Sep. 30, 2013

Quarterly Results Of Operations [Abstract]

Summary Of The Company's Quarterly Results Of Operations

	Fiscal 2013
	Quarter Ended
	December 31		March 31		June 30		September 30
Revenues	$	14,180,435	$	12,581,986	$	17,730,445	$	18,396,254
Income (loss) before provision
for income taxes	$	2,825,298	$	1,761,487	$	7,323,168	$	8,780,096
Net income (loss)	$	2,148,298	$	1,022,487	$	5,070,168	$	5,719,096
Earnings (loss) per share	$	0.26	$	0.12	$	0.61	$	0.68
	Fiscal 2012
	Quarter Ended
	December 31		March 31		June 30		September 30
Revenues	$	13,404,333	$	10,436,910	$	13,649,692	$	11,041,382
Income (loss) before provision
for income taxes	$	4,261,110	$	1,205,966	$	4,681,299	$	496,621
Net income (loss)	$	3,412,110	$	675,966	$	3,100,299	$	182,621
Earnings (loss) per share	$	0.41	$	0.08	$	0.37	$	0.02

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Summary Of Significant Accounting Policies (Summary Of Derivative Contracts) (Details) (USD $)	Sep. 30, 2013	Sep. 30, 2012
Summary Of Significant Accounting Policies [Abstract]
Gross amounts recognized - Current Assets	$ 665,099	$ 51,530
Gross amounts recognized - Current Liabilities	239,901	223,801
Net presentation on Condensed Balance - Current Assets	425,198
Net presentation on Condensed Balance - Current Liabilities		$ 172,271

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Summary Of Significant Accounting Policies (Summary Of Asset Retirement Obligation) (Details) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Summary Of Significant Accounting Policies [Abstract]
Asset Retirement Obligations as of beginning of the year	$ 2,122,950	$ 1,843,875
Accretion of Discount	122,391	121,112
New Wells Placed on Production	167,609	184,027
Wells Sold or Plugged	(19,760)	(26,064)
Asset Retirement Obligations as of end of the year	$ 2,393,190	$ 2,122,950

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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, 2013	Sep. 30, 2012
Supplementary Information On Oil, Ngl And Natural Gas Reserves [Abstract]
Producing properties	$ 304,889,145	$ 275,997,569
Non-producing minerals	8,490,277	9,018,731
Non-producing leasehold	442,628	1,123,812
Exploratory wells in progress		8,018
Gross capitalized costs	313,822,050	286,148,130
Accumulated depreciation, depletion and amortization	(186,042,746)	(164,652,199)
Net capitalized costs	$ 127,779,304	$ 121,495,931

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Restricted Stock Plan (Summary Of Pre-Tax Compensation Expense) (Details) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted stock awards	$ 683,968	$ 330,923	$ 152,482
Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted stock awards	345,405	150,480	42,909
Non Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted stock awards	$ 338,563	$ 180,443	$ 109,573

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Earnings Per Share (Details) (USD $)	3 Months Ended								12 Months Ended
	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Earnings Per Share [Abstract]
Net income (loss)	$ 5,719,096	$ 5,070,168	$ 1,022,487	$ 2,148,298	$ 182,621	$ 3,100,299	$ 675,966	$ 3,412,110	$ 13,960,049	$ 7,370,996	$ 8,493,912
Denominator for basic and diluted earnings per share - weighted average shares (including for 2013, 2012 and 2011, unissued, vested directors' shares of 116,112, 114,596 and 122,728, respectively)									8,356,904	8,360,931	8,393,890
Vested directors' shares									116,112	114,596	122,728

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Balance Sheets (Parenthetical) (USD $)	Sep. 30, 2013	Sep. 30, 2012
Balance Sheets [Abstract]
Common stock, par value	$ 0.0166	$ 0.0166
Common stock, shares authorized	24,000,000	24,000,000
Common stock, shares issued	8,431,502	8,431,502
Treasury stock, shares	200,248	181,310

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Employee Stock Ownership Plan

12 Months Ended

Sep. 30, 2013

Employee Stock Ownership Plan [Abstract]

Employee Stock Ownership Plan

7. EMPLOYEE STOCK OWNERSHIP PLAN

The Company’s ESOP was established in 1984 and is a tax qualified, defined contribution plan that serves as the Company’s sole retirement plan for all its employees.Company contributions are made at the discretion of the Board and, to date, all contributions have been made in shares of Company Common Stock.The Company contributions are allocated to all ESOP participants in proportion to their compensation for the plan year, and 100% vesting occurs after three years of service. Any shares that do not vest are treated as forfeitures and are distributed among other vested employees. For contributions of Common Stock, the Company records as expense the fair market value of the stock at the time of contribution. The 259,060  shares of the Company’s Common Stock held by the plan, as of September 30, 2013, 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
2013	10,907	$	308,450
2012	10,660	$	326,942
2011	10,710	$	303,843

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Statements Of Stockholders' Equity (USD $)	Class A voting Common Stock [Member]	Capital in Excess of Par Value [Member]	Deferred Directors' Compensation [Member]	Retained Earnings [Member]	Treasury Stock [Member]	Total
Balances at Sep. 30, 2010	$ 140,524	$ 1,816,365	$ 2,222,127	$ 73,599,733	$ (4,196,753)	$ 73,581,996
Balances, Treasury shares at Sep. 30, 2010					(120,560)
Balances, shares at Sep. 30, 2010	8,431,502
Purchase of treasury stock					(1,851,290)	(1,851,290)
Purchase of treasury stock, shares					(65,481)
Issuance of treasury shares to ESOP		(44,340)			348,183	303,843
Issuance of treasury shares to ESOP, shares					10,710	10,710
Restricted stock awards		152,482				152,482
Common shares to be issued to directors for services			443,456			443,456
Dividends declared ($.28 per share)				(2,322,082)		(2,322,082)
Net income				8,493,912		8,493,912
Balances at Sep. 30, 2011	140,524	1,924,507	2,665,583	79,771,563	(5,699,860)	78,802,317
Balances, Treasury shares at Sep. 30, 2011					(175,331)
Balances, shares at Sep. 30, 2011	8,431,502
Purchase of treasury stock					(1,158,957)	(1,158,957)
Purchase of treasury stock, shares					(38,771)
Issuance of treasury shares to ESOP		(14,391)			341,333	326,942
Issuance of treasury shares to ESOP, shares					10,660	10,660
Restricted stock awards		330,923				330,923
Distribution of deferred directors' compensation		(220,810)	(406,770)		711,322	83,742
Distribution of deferred directors' compensation, shares					22,132
Common shares to be issued to directors for services			417,347			417,347
Dividends declared ($.28 per share)				(2,321,164)		(2,321,164)
Net income				7,370,996		7,370,996
Balances at Sep. 30, 2012	140,524	2,020,229	2,676,160	84,821,395	(5,806,162)	83,852,146
Balances, Treasury shares at Sep. 30, 2012					(181,310)	(181,310)
Balances, shares at Sep. 30, 2012	8,431,502
Purchase of treasury stock					(1,214,638)	(1,214,638)
Purchase of treasury stock, shares					(42,206)
Issuance of treasury shares to ESOP		(33,812)			342,262	308,450
Issuance of treasury shares to ESOP, shares					10,907	10,907
Restricted stock awards		683,968				683,968
Distribution of deferred directors' compensation		(82,547)	(297,154)		394,687	14,986
Distribution of deferred directors' compensation, shares					12,361
Common shares to be issued to directors for services			377,520			377,520
Dividends declared ($.28 per share)				(2,326,995)		(2,326,995)
Net income				13,960,049		13,960,049
Balances at Sep. 30, 2013	$ 140,524	$ 2,587,838	$ 2,756,526	$ 96,454,449	$ (6,283,851)	$ 95,655,486
Balances, Treasury shares at Sep. 30, 2013					(200,248)	(200,248)
Balances, shares at Sep. 30, 2013	8,431,502

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Supplementary Information On Oil, Ngl And Natural Gas Reserves (Summary of Proved Developed and Undeloped Reserves) (Details)	Sep. 30, 2013 bbl	Sep. 30, 2012 bbl	Sep. 30, 2011 bbl
Reserve Quantities [Line Items]
Proved Undeveloped Reserves	58,734,656	50,885,055
Oil [Member]
Reserve Quantities [Line Items]
Proved Developed Reserves (Volume)	1,037,721.00	849,548.00	759,989.00
Proved Undeveloped Reserves (Volume)	605,582.00	222,771.00	83,749.00
Natural Gas Liquids [Member]
Reserve Quantities [Line Items]
Proved Developed Reserves (Volume)	764,321.00	494,160.00	386,774.00
Proved Undeveloped Reserves (Volume)	851,805	294,582	404,874
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed Reserves (Volume)	82,298,833.00	65,733,119.00	60,193,878.00
Proved Undeveloped Reserves (Volume)	49,990,334	47,780,937	41,644,106

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Balance Sheets (USD $)	Sep. 30, 2013	Sep. 30, 2012
Current Assets:
Cash and cash equivalents	$ 2,867,171	$ 1,984,099
Oil, NGL and natural gas sales receivables	13,720,761	8,349,865
Refundable income taxes		325,715
Refundable production taxes	662,051	585,454
Deferred income taxes		121,900
Derivative contracts	425,198
Other	129,998	255,812
Total current assets	17,805,179	11,622,845
Properties and equipment at cost, based on successful efforts accounting:
Producing oil and natural gas properties	304,889,145	275,997,569
Non-producing oil and natural gas properties	8,932,905	10,150,561
Furniture and fixtures	737,368	668,004
Total properties and equipment, at cost, based on successful efforts accounting	314,559,418	286,816,134
Less accumulated depreciation, depletion and amortization	(186,641,291)	(165,199,079)
Net properties and equipment	127,918,127	121,617,055
Investments	1,574,642	1,034,870
Refundable production taxes	540,482	911,960
Total assets	147,838,430	135,186,730
Current Liabilities:
Accounts payable	8,409,634	6,447,692
Derivative contracts		172,271
Deferred income taxes	127,100
Income taxes payable	751,992
Accrued liabilities and other	1,011,865	1,007,779
Total current liabilities	10,300,591	7,627,742
Long-term debt	8,262,256	14,874,985
Deferred income taxes	31,226,907	26,708,907
Asset retirement obligations	2,393,190	2,122,950
Stockholders' equity:
Class A voting common stock, $.0166 par value; 24,000,000 shares authorized, 8,431,502 issued at September 30, 2012 and 2011	140,524	140,524
Capital in excess of par value	2,587,838	2,020,229
Deferred directors' compensation	2,756,526	2,676,160
Retained earnings	96,454,449	84,821,395
Total stockholders' equity	101,939,337	89,658,308
Treasury stock, at cost; 200,248 shares at September 30, 2013, and 181,310 shares at September 30, 2012	(6,283,851)	(5,806,162)
Total stockholders' equity	95,655,486	83,852,146
Total liabilities and stockholders' equity	$ 147,838,430	$ 135,186,730

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Restricted Stock Plan (Summary Of Unrecognized Compensation Cost) (Details) (USD $)	12 Months Ended
	Sep. 30, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	$ 510,354
Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	282,726
Weighted Average Period	1 year 4 months 28 days
Non Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	$ 227,628
Weighted Average Period	1 year 5 months 23 days

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Summary Of Significant Accounting Policies (Narrative) (Details) (USD $)	12 Months Ended
	Sep. 30, 2013 acre item	Sep. 30, 2012		Sep. 30, 2011
Property Plant And Equipment [Line Items]
Number of Oil and Natural Gas Production Units Located in Oklahoma	6,105
Oil, NGL and natural gas revenues were derived from the sale of natural gas		60.00%
Total sale volume from sale of natural Gas		84.00%
Amount of Natural Gas Imbalances	$ 0	$ 0
Carrying Cost of Non-Producing Oil and Natural Gas Leases	285,752
Outstanding letters of credit		0
Fair value of derivative contracts Asset , Liabilities	425,198
Net presentation on Condensed Balance - Current Liabilities		172,271
Book value of Non-producing oil and natural gas	4,702,285	5,374,868
Percentage of perpetual ownership of mineral interests in Arkansas ,New Mexico, North Dakota, Oklahoma and Texas	91.00%
Non Producing Minerals Area	196,768
Number of tracts owned	6,818
Average Tract Contains	29
Tracts Average Cost Per Acre	43
Amortized Period of Non-producing Minerals	33 years
Impairment	530,670	826,508	[1]	1,728,162
Amount of Capitalized Interest Included in the Company's Capital Expenditures	121,418	129,172		0
Interest On capitalized Expenses	157,558	127,970		0
Interest Held By Company	5.00%
Income Taxes interests and penalties	$ 927	$ 0		$ 21,000
Maximum [Member]
Property Plant And Equipment [Line Items]
Useful life of furniture and fixtures	8 years
Minimum [Member]
Property Plant And Equipment [Line Items]
Useful life of furniture and fixtures	5 years

[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. Significant judgments and assumptions in these assessments include estimates of future oil, NGL and natural gas prices using a forward NYMEX curve adjusted for 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.

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Earnings Per Share (Tables)

12 Months Ended

Sep. 30, 2013

Earnings Per Share [Abstract]

Summary Of Computation Of Earnings Per Share

		Year ended September 30,
	2013		2012		2011
Numerator for basic and diluted earnings per share:
Net income (loss)	$	13,960,049	$	7,370,996	$	8,493,912
Denominator for basic and diluted earnings per share -
weighted average shares (including for 2013, 2012
and 2011, unissued, vested directors' shares
of 116,112,  114,596 and 122,728, respectively)		8,356,904		8,360,931		8,393,890

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Shareholders' Equity (Details) (USD $)	0 Months Ended	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Equity, Class of Treasury Stock [Line Items]
Purchase of treasury stock	$ 4,516,267	$ 1,214,638	$ 1,158,957	$ 1,851,290
Purchase of treasury stock, shares	158,784
Number Of Treasury Stock contributed to the Companies ESOP		10,907	10,660	10,710
Maximum [Member]
Equity, Class of Treasury Stock [Line Items]
Purchase of Common Stock		$ 1,500,000

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Supplementary Information On Oil, Ngl And Natural Gas Reserves (Narrative) (Details) (USD $)	12 Months Ended										12 Months Ended
	Sep. 30, 2013 item Mcfe	Sep. 30, 2012 Mcfe	Sep. 30, 2011	Sep. 30, 2012 Arkansas Fayetteville Shale [Member]	Sep. 30, 2013 Oil [Member]	Sep. 30, 2012 Oil [Member]	Sep. 30, 2011 Oil [Member]	Sep. 30, 2013 Natural Gas Liquids [Member]	Sep. 30, 2012 Natural Gas Liquids [Member]	Sep. 30, 2011 Natural Gas Liquids [Member]	Sep. 30, 2013 Natural Gas [Member] Mcfe	Sep. 30, 2012 Natural Gas [Member]	Sep. 30, 2011 Natural Gas [Member]	Sep. 30, 2010 Natural Gas [Member]
Supplementary Oil And Gas Diclsoures [Line Items]
Positive pricing revisions	3,446,900										300,000
Positive pricing revisions, developed	3,109,159
Positive pricing revisions, undeveloped	337,741
Negative performance revisions	5,844,070										14,600,000
Negative performance revisions, developed	8,803,480
Negative performance revisions, undeveloped	14,647,551
Property acquisition costs	$ 1,242,615	$ 20,404,465	$ 5,140,862	$ 17,400,000
Price used to calculate reserves and future cash flows from reserves					89.06	89.41	90.28	27.28	35.70	38.91	3.33	2.51	3.81	3.81
Proved Undeveloped Reserves	58,734,656	50,885,055
Proved undeveloped reserves transferred to proved developed	(12,124,203)
Revisions	(14,309,809)
Percentage transferred to proved developed	(24.00%)
Performance revision percentage											(29.00%)
Total proved undeveloped reserves moved out	26,700,000
Percentage of proved undeveloped reserves moved out	(53.00%)
Period for converting PUD to PDP	5 years
Percentage of PUD reserves	1.00%
Number of PUD location	21

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Income Taxes (Narrative) (Details) (Oklahoma [Member], USD $)	Sep. 30, 2013
Oklahoma [Member]
Valuation Allowance [Line Items]
Income tax benefit	$ 782,785

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Summary Of Significant Accounting Policies (Summary Of Reconciliation Of Assets Classified As Level 3 Measurements) (Details) (USD $)	12 Months Ended
	Sep. 30, 2013
Summary Of Significant Accounting Policies [Abstract]
Balance of Level 3 as of October 1, 2012	$ (96,937)
Realized	242,435
Unrealized	97,404
Included in other comprehensive income (loss)
Purchases, issuances and settlements
Transfers in and out of Level 3
Balance of Level 3 as of September 30, 2013	$ 242,902

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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, 2013	Sep. 30, 2012		Sep. 30, 2011
Summary Of Significant Accounting Policies [Abstract]
Producing Properties, Fair Value	$ 356,855	$ 1,301,951
Producing Properties, Impairment	$ 530,670	$ 826,508	[1]	$ 1,728,162

[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. Significant judgments and assumptions in these assessments include estimates of future oil, NGL and natural gas prices using a forward NYMEX curve adjusted for 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.

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Earnings Per Share

12 Months Ended

Sep. 30, 2013

Earnings Per Share [Abstract]

Earnings Per Share

6. EARNINGS PER SHARE

The following table sets forth the computation of earnings per share. 

		Year ended September 30,
	2013		2012		2011
Numerator for basic and diluted earnings per share:
Net income (loss)	$	13,960,049	$	7,370,996	$	8,493,912
Denominator for basic and diluted earnings per share -
weighted average shares (including for 2013, 2012
and 2011, unissued, vested directors' shares
of 116,112,  114,596 and 122,728, respectively)		8,356,904		8,360,931		8,393,890

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Quarterly Results Of Operations (Details) (USD $)	3 Months Ended								12 Months Ended
	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Quarterly Results Of Operations [Abstract]
Revenues	$ 18,396,254	$ 17,730,445	$ 12,581,986	$ 14,180,435	$ 11,041,382	$ 13,649,692	$ 10,436,910	$ 13,404,333	$ 62,889,120	$ 48,532,317	$ 44,976,651
Income (loss) before provision for income taxes	8,780,096	7,323,168	1,761,487	2,825,298	496,621	4,681,299	1,205,966	4,261,110	20,690,049	10,644,996	11,685,912
Net income (loss)	$ 5,719,096	$ 5,070,168	$ 1,022,487	$ 2,148,298	$ 182,621	$ 3,100,299	$ 675,966	$ 3,412,110	$ 13,960,049	$ 7,370,996	$ 8,493,912
Earnings (loss) per share	$ 0.68	$ 0.61	$ 0.12	$ 0.26	$ 0.02	$ 0.37	$ 0.08	$ 0.41	$ 1.67	$ 0.88	$ 1.01

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Summary Of Significant Accounting Policies (Summary Of Derivative Instruments Contracts) (Details)	Sep. 30, 2013 Natural Gas Fixed Price Swaps [Member] Fixed Price Five [Member] MMBTU	Sep. 30, 2013 Natural Gas Fixed Price Swaps [Member] Fixed Price Six [Member] MMBTU	Sep. 30, 2013 Natural Gas Fixed Price Swaps [Member] Fixed Price Seven [Member] MMBTU	Sep. 30, 2013 Natural Gas Fixed Price Swaps [Member] Fixed Price Eight [Member] MMBTU	Sep. 30, 2012 Natural Gas Basis Protection Swaps [Member] Fixed Price One [Member] MMBTU	Sep. 30, 2012 Natural Gas Basis Protection Swaps [Member] Fixed Price Two [Member] MMBTU	Sep. 30, 2012 Natural Gas Basis Protection Swaps [Member] Fixed Price Three [Member] MMBTU	Sep. 30, 2012 Natural Gas Basis Protection Swaps [Member] Fixed Price Four [Member] MMBTU	Sep. 30, 2013 Natural Gas Costless Collars [Member] Fixed Price One [Member] MMBTU	Sep. 30, 2013 Natural Gas Costless Collars [Member] Fixed Price Two [Member] MMBTU	Sep. 30, 2013 Natural Gas Costless Collars [Member] Fixed Price Three [Member] MMBTU	Sep. 30, 2013 Natural Gas Costless Collars [Member] Fixed Price Four [Member] MMBTU	Sep. 30, 2012 Natural Gas Costless Collars [Member] Fixed Price Five [Member] MMBTU	Sep. 30, 2012 Natural Gas Costless Collars [Member] Fixed Price Six [Member] MMBTU	Sep. 30, 2012 Natural Gas Costless Collars [Member] Fixed Price Seven [Member] MMBTU	Sep. 30, 2012 Natural Gas Costless Collars [Member] Fixed Price Eight [Member] MMBTU	Sep. 30, 2012 Natural Gas Costless Collars [Member] Fixed Price Nine [Member] MMBTU	Sep. 30, 2012 Natural Gas Costless Collars [Member] Fixed Price Ten [Member] MMBTU	Sep. 30, 2012 Natural Gas Costless Collars [Member] Fixed Price Eleven [Member] MMBTU	Sep. 30, 2012 Natural Gas Costless Collars [Member] Fixed Price Twelve [Member] MMBTU	Sep. 30, 2012 Natural Gas Costless Collars [Member] Fixed Price Thirteen [Member] MMBTU	Sep. 30, 2012 Natural Gas Costless Collars [Member] Fixed Price Fourteen [Member] MMBTU	Sep. 30, 2013 Oil costless collars [Member] Fixed Price Nine [Member] bbl	Sep. 30, 2013 Oil costless collars [Member] Fixed Price Ten [Member] bbl	Sep. 30, 2013 Oil costless collars [Member] Fixed Price Eleven [Member] bbl	Sep. 30, 2013 Oil costless collars [Member] Fixed Price Twelve [Member] bbl	Sep. 30, 2012 Oil costless collars [Member] Fixed Price Fifteen [Member] bbl	Sep. 30, 2012 Oil costless collars [Member] Fixed Price Sixteen [Member] bbl	Sep. 30, 2012 Oil costless collars [Member] Fixed Price Seventeen [Member] bbl	Sep. 30, 2013 Oil Fixed Price Swaps [Member] Fixed Price Thirteen [Member] bbl	Sep. 30, 2013 Minimum [Member] Natural Gas Costless Collars [Member] Fixed Price One [Member]	Sep. 30, 2013 Minimum [Member] Natural Gas Costless Collars [Member] Fixed Price Two [Member]	Sep. 30, 2013 Minimum [Member] Natural Gas Costless Collars [Member] Fixed Price Three [Member]	Sep. 30, 2013 Minimum [Member] Natural Gas Costless Collars [Member] Fixed Price Four [Member]	Sep. 30, 2012 Minimum [Member] Natural Gas Costless Collars [Member] Fixed Price Five [Member]	Sep. 30, 2012 Minimum [Member] Natural Gas Costless Collars [Member] Fixed Price Six [Member]	Sep. 30, 2012 Minimum [Member] Natural Gas Costless Collars [Member] Fixed Price Seven [Member]	Sep. 30, 2012 Minimum [Member] Natural Gas Costless Collars [Member] Fixed Price Eight [Member]	Sep. 30, 2012 Minimum [Member] Natural Gas Costless Collars [Member] Fixed Price Nine [Member]	Sep. 30, 2012 Minimum [Member] Natural Gas Costless Collars [Member] Fixed Price Ten [Member]	Sep. 30, 2012 Minimum [Member] Natural Gas Costless Collars [Member] Fixed Price Eleven [Member]	Sep. 30, 2012 Minimum [Member] Natural Gas Costless Collars [Member] Fixed Price Twelve [Member]	Sep. 30, 2012 Minimum [Member] Natural Gas Costless Collars [Member] Fixed Price Thirteen [Member]	Sep. 30, 2012 Minimum [Member] Natural Gas Costless Collars [Member] Fixed Price Fourteen [Member]	Sep. 30, 2013 Minimum [Member] Oil costless collars [Member] Fixed Price Nine [Member]	Sep. 30, 2013 Minimum [Member] Oil costless collars [Member] Fixed Price Ten [Member]	Sep. 30, 2013 Minimum [Member] Oil costless collars [Member] Fixed Price Eleven [Member]	Sep. 30, 2013 Minimum [Member] Oil costless collars [Member] Fixed Price Twelve [Member]	Sep. 30, 2012 Minimum [Member] Oil costless collars [Member] Fixed Price Fifteen [Member]	Sep. 30, 2012 Minimum [Member] Oil costless collars [Member] Fixed Price Sixteen [Member]	Sep. 30, 2012 Minimum [Member] Oil costless collars [Member] Fixed Price Seventeen [Member]	Sep. 30, 2013 Maximum [Member] Natural Gas Costless Collars [Member] Fixed Price One [Member]	Sep. 30, 2013 Maximum [Member] Natural Gas Costless Collars [Member] Fixed Price Two [Member]	Sep. 30, 2013 Maximum [Member] Natural Gas Costless Collars [Member] Fixed Price Three [Member]	Sep. 30, 2013 Maximum [Member] Natural Gas Costless Collars [Member] Fixed Price Four [Member]	Sep. 30, 2012 Maximum [Member] Natural Gas Costless Collars [Member] Fixed Price Five [Member]	Sep. 30, 2012 Maximum [Member] Natural Gas Costless Collars [Member] Fixed Price Six [Member]	Sep. 30, 2012 Maximum [Member] Natural Gas Costless Collars [Member] Fixed Price Seven [Member]	Sep. 30, 2012 Maximum [Member] Natural Gas Costless Collars [Member] Fixed Price Eight [Member]	Sep. 30, 2012 Maximum [Member] Natural Gas Costless Collars [Member] Fixed Price Nine [Member]	Sep. 30, 2012 Maximum [Member] Natural Gas Costless Collars [Member] Fixed Price Ten [Member]	Sep. 30, 2012 Maximum [Member] Natural Gas Costless Collars [Member] Fixed Price Eleven [Member]	Sep. 30, 2012 Maximum [Member] Natural Gas Costless Collars [Member] Fixed Price Twelve [Member]	Sep. 30, 2012 Maximum [Member] Natural Gas Costless Collars [Member] Fixed Price Thirteen [Member]	Sep. 30, 2012 Maximum [Member] Natural Gas Costless Collars [Member] Fixed Price Fourteen [Member]	Sep. 30, 2013 Maximum [Member] Oil costless collars [Member] Fixed Price Nine [Member]	Sep. 30, 2013 Maximum [Member] Oil costless collars [Member] Fixed Price Ten [Member]	Sep. 30, 2013 Maximum [Member] Oil costless collars [Member] Fixed Price Eleven [Member]	Sep. 30, 2013 Maximum [Member] Oil costless collars [Member] Fixed Price Twelve [Member]	Sep. 30, 2012 Maximum [Member] Oil costless collars [Member] Fixed Price Fifteen [Member]	Sep. 30, 2012 Maximum [Member] Oil costless collars [Member] Fixed Price Sixteen [Member]	Sep. 30, 2012 Maximum [Member] Oil costless collars [Member] Fixed Price Seventeen [Member]
Derivative [Line Items]
Production volume covered per month	100,000	70,000	40,000	100,000	50,000	40,000	50,000	50,000	80,000	50,000	100,000	160,000	50,000	120,000	60,000	50,000	50,000	50,000	50,000	150,000	150,000	50,000
Production volume covered per month - Oil costless collars																							3,000	4,000	2,000	4,000	2,000	3,000	2,000	4,000
Fixed price	3.505	3.400	3.655	4.320	0.29	0.30	0.29	0.30																						105.250	3.75	3.75	3.75	4.00	2.50	2.50	2.50	2.50	2.50	2.50	2.50	3.00	3.00	3.00	90.00	90.00	90.00	90.00	90	90	90	4.25	4.30	4.05	4.55	3.25	3.10	3.20	3.20	3.45	3.30	3.30	3.70	3.70	3.65	102.00	101.50	97.50	101.50	105	110	114

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Income Taxes (Summary of Deferred Tax Assets and Liabilities) (Details) (USD $)	Sep. 30, 2013	Sep. 30, 2012
Income Taxes [Abstract]
Financial basis in excess of tax basis, principally intangible drilling costs capitalized for financial purposes and expensed for tax purposes	$ 33,557,515	$ 30,320,765
Derivative contracts	165,402
Total deferred tax liabilities	33,722,917	30,320,765
State net operating loss carry forwards, net of valuation allowance of $0 in 2013 and 2012	782,785	1,008,271
AMT credit carry forwards		1,189,053
Deferred directors' compensation	1,021,717	990,455
Restricted stock expense	426,788
Statutory depletion carry forwards		415,958
Other	137,620	130,021
Total Deferred tax assets	2,368,910	3,733,758
Net deferred tax liabilities	31,354,007	26,587,007
Operating loss carry forwards, net of valuation allowance	$ 0	$ 0

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Restricted Stock Plan

12 Months Ended

Sep. 30, 2013

Restricted Stock Plan [Abstract]

Restricted Stock Plan

9. RESTRICTED STOCK PLAN

On March 11, 2010, shareholders approved the Panhandle Oil and Gas Inc. 2010 Restricted Stock Plan (2010 Stock Plan), which made available 100,000 shares of Common Stock to provide a long-term component to the Company’s total compensation package for its officers and to further align the interest of its officers with those of its shareholders. The 2010 Stock Plan is designed to provide as much flexibility as possible for future grants of restricted stock so the Company can respond as necessary to provide competitive compensation in order to retain, attract and motivate officers of the Company and to align their interests with those of the Company’s shareholders.

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

On December 21, 2010, the Company 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 Stockover 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. 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.

The following table summarizes the Company’s pre-tax compensation expense for the years ended September 30, 2013,2012 and 2011, related to the Company’s performance based and non-performance based restricted stock.

		Year Ended September 30,
	2013		2012		2011
Performance based, restricted stock	$	345,405	$	150,480	$	42,909
Non-performance based, restricted stock		338,563		180,443		109,573
Total compensation expense	$	683,968	$	330,923	$	152,482

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 Period (in years)
Performance based, restricted stock	$	282,726	1.41
Non-performance based, restricted stock		227,628	1.48
Total	$	510,354

Upon vesting, shares are expected to be issued out of shares held in treasury.

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

	Performance Based Unvested Restricted Shares	Weighted Average Grant-Date Fair Value		Non-Performance Based Unvested Restricted Shares	Weighted Average Grant-Date Fair Value
Unvested shares as of
September 30, 2010	-	$	-	8,500	$	28.30
Granted	8,782		19.54	8,780		28.00
Vested	-		-	-		-
Forfeited	-		-	-		-
Unvested shares as of
September 30, 2011	8,782	$	19.54	17,280	$	28.15
Granted	17,709		19.47	5,903		31.55
Vested	-		-	-		-
Forfeited	-		-	-		-
Unvested shares as of	26,491	$	19.49	23,183	$	29.01
September 30, 2012
Granted	20,104		15.18	6,701		29.19
Vested	-		-	-		-
Forfeited	-		-	-		-
Unvested shares as of	46,595	$	17.63	29,884	$	29.05
September 30, 2013

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Shareholders' Equity

12 Months Ended

Sep. 30, 2013

Shareholders' Equity [Abstract]

Shareholders' Equity

5. SHAREHOLDERS’ EQUITY

Upon approval by the shareholders of the Company’s 2010 Restricted Stock Plan on March 11, 2010, the Board approved purchase of up to $1.5 million of the Company’s Common Stock, from time to time, equal to the aggregate number of shares of Common Stock awarded pursuant to the Company’s 2010 Restricted Stock Plan, contributed by the Company to its ESOP and credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors.The Board’s approval included an initial authorization to purchase up to $1.5 million of Common Stock, with a provision for subsequent authorizations without specific action by the Board.As the amount of Common Stock purchased under any authorization reaches $1.5 million, another $1.5 million is automatically authorized for Common Stock purchases unless the Board determines otherwise.Pursuant to these resolutions adopted by theBoard, the purchase of additional $1.5 million increments of the Company’s Common Stock became authorized and approved effective March 29, 2011, March 14, 2012, and June 26, 2013.As of September 30, 2013,  $4,516,267 had been spent under the current program to purchase 158,784 shares.The shares are held in treasury and are accounted for using the cost method. On September 30 each year, treasury shares contributed to the Company’s ESOP on behalf of the ESOP participants were 10,907 in 2013,  10,660 in 2012 and 10,710 in 2011.

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Statements Of Cash Flows (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012		Sep. 30, 2011
Operating Activities
Net income (loss)	$ 13,960,049	$ 7,370,996		$ 8,493,912
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	21,945,768	19,061,239		14,712,188
Impairment	530,670	826,508	[1]	1,728,162
Provision for deferred income taxes	4,767,000	1,802,000		1,878,000
Exploration costs	9,795	979,718		1,025,542
Gain from leasing fee mineral acreage	(936,701)	(7,146,299)		(352,642)
Net (gain) loss on sales of assets	(208,750)	(122,504)		2,112
Income from partnerships	(733,372)	(487,070)		(420,465)
Distributions received from partnerships	917,718	601,300		553,382
Common stock contributed to ESOP	308,450	326,942		303,843
Common stock (unissued) to Directors' Deferred Compensation Plan	377,520	417,347		443,456
Restricted stock awards	683,968	330,923		152,482
Cash provided (used) by changes in assets and liabilities:
Oil, NGL and natural gas sales receivables	(5,370,896)	461,539		251,598
Fair value of derivative contracts	(597,469)	388,211		1,404,386
Refundable income taxes	325,715	28,531		(354,246)
Refundable production taxes	294,881	85,926		(124,621)
Other current assets	73,508	(108,098)		317,370
Accounts payable	298,191	585,912		72,119
Other non-current asset		308
Income taxes payable	751,992			(922,136)
Accrued liabilities	4,072	(32,233)		119,487
Total adjustments	23,442,060	18,000,200		20,790,017
Net cash provided by operating activities	37,402,109	25,371,196		29,283,929
Investing Activities
Capital expenditures, including dry hole costs	(26,765,785)	(25,147,306)		(22,739,908)
Acquisition of working interest properties		(17,399,052)		(185,125)
Acquisition of minerals and overrides	(783,750)	(2,745,069)		(4,620,315)
Proceeds from leasing fee mineral acreage	1,023,368	7,265,808		389,807
Investments in partnerships	(724,118)	(481,904)		(46,213)
Proceeds from sales of assets	870,610	134,821		938
Excess tax benefit on stock-based compensation	15,000	83,742
Net cash used in investing activities	(26,364,675)	(38,288,960)		(27,200,816)
Financing Activities
Borrowings under debt agreement	11,569,652	43,475,443
Payments of loan principal	(18,182,381)	(28,600,458)
Purchases of treasury stock	(1,214,638)	(1,158,957)		(1,851,290)
Payments of dividends	(2,326,995)	(2,321,164)		(2,322,082)
Net cash provided by (used in) financing activities	(10,154,362)	11,394,864		(4,173,372)
Increase (decrease) in cash and cash equivalents	883,072	(1,522,900)		(2,090,259)
Cash and cash equivalents at beginning of year	1,984,099	3,506,999		5,597,258
Cash and cash equivalents at end of year	2,867,171	1,984,099		3,506,999
Supplemental Disclosures of Cash Flow Information
Interest paid (net of capitalized interest)	157,558	127,970
Income taxes paid, net of refunds received	870,295	1,356,706		2,584,172
Supplemental schedule of noncash investing and financing activities:
Additions and revisions, net, to asset retirement obligations	161,065	279,075		113,506
Gross additions to properties and equipment	29,261,285	46,201,308		27,310,016
Net (increase) decrease in accounts payable for properties and equipment additions	(1,711,750)	(909,881)		235,332
Capital expenditures, including dry hole costs	$ 27,549,535	$ 45,291,427		$ 27,545,348

[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. Significant judgments and assumptions in these assessments include estimates of future oil, NGL and natural gas prices using a forward NYMEX curve adjusted for 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.

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Restricted Stock Plan (Summary Of Unvested Shares Of Restricted Stock Awards) (Details) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested shares, Beginning balance	26,491	8,782
Weighted Average Grant Date Fair Value, Beginning balance	$ 19.49	$ 19.54
Unvested Restricted Shares, Granted	20,104	17,709	8,782
Weighted Average Grant Date Fair Value, Granted	$ 15.18	$ 19.47	$ 19.54
Unvested shares, Ending balance	46,595	26,491	8,782
Weighted Average Grant Date Fair Value, Ending balance	$ 17.63	$ 19.49	$ 19.54
Non Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unvested shares, Beginning balance	23,183	17,280	8,500
Weighted Average Grant Date Fair Value, Beginning balance	$ 29.01	$ 28.15	$ 28.30
Unvested Restricted Shares, Granted	6,701	5,903	8,780
Weighted Average Grant Date Fair Value, Granted	$ 29.19	$ 31.55	$ 28.00
Unvested shares, Ending balance	29,884	23,183	17,280
Weighted Average Grant Date Fair Value, Ending balance	$ 29.05	$ 29.01	$ 28.15

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Employee Stock Ownership Plan (Summary Of Plan Contributions) (Details) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Employee Stock Ownership Plan [Abstract]
Shares Contributed to the ESOP	10,907	10,660	10,710
Amount Contributed to the ESOP	$ 308,450	$ 326,942	$ 303,843

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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, 2013	Sep. 30, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Fair Value	$ 425,198
Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Fair Value	182,296	(75,334)
Collars [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Fair Value	242,902	(96,937)
Fair Value, Inputs, Level 2 [Member] | Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Fair Value	182,296	(75,334)
Fair Value, Inputs, Level 3 [Member] | Collars [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total Fair Value	$ 242,902	$ (96,937)

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Supplementary Information On Oil, Ngl And Natural Gas Reserves (Summary of Proved Undeveloped Reserves) (Details)	12 Months Ended
	Sep. 30, 2013 Mcfe
Supplementary Information On Oil, Ngl And Natural Gas Reserves [Abstract]
Beginning proved undeveloped reserves	50,885,055
Proved undeveloped reserves transferred to proved developed	(12,124,203)
Revisions	(14,309,809)
Extensions and discoveries	32,806,004
Purchases	1,477,609
Ending proved undeveloped reserves	58,734,656

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Quarterly Results Of Operations

12 Months Ended

Sep. 30, 2013

Quarterly Results Of Operations [Abstract]

Quarterly Results Of Operations

12. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)

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

	Fiscal 2013
	Quarter Ended
	December 31		March 31		June 30		September 30
Revenues	$	14,180,435	$	12,581,986	$	17,730,445	$	18,396,254
Income (loss) before provision
for income taxes	$	2,825,298	$	1,761,487	$	7,323,168	$	8,780,096
Net income (loss)	$	2,148,298	$	1,022,487	$	5,070,168	$	5,719,096
Earnings (loss) per share	$	0.26	$	0.12	$	0.61	$	0.68
	Fiscal 2012
	Quarter Ended
	December 31		March 31		June 30		September 30
Revenues	$	13,404,333	$	10,436,910	$	13,649,692	$	11,041,382
Income (loss) before provision
for income taxes	$	4,261,110	$	1,205,966	$	4,681,299	$	496,621
Net income (loss)	$	3,412,110	$	675,966	$	3,100,299	$	182,621
Earnings (loss) per share	$	0.41	$	0.08	$	0.37	$	0.02

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Deferred Compensation Plan For Directors

12 Months Ended

Sep. 30, 2013

Deferred Compensation Plan For Directors [Abstract]

DEFERRED COMPENSATION PLAN FOR DIRECTORS

8. DEFERRED COMPENSATION PLAN FOR DIRECTORS

The Panhandle Oil and Gas Inc. Deferred Compensation Plan for Non-Employee Directors (the “Plan”) provides that each eligible director can individually elect to receive shares of Company Common Stock rather than cash for Board and committee chair retainers, Board meeting fees and Board committee meeting fees. These shares are unissued and vest as earned. The shares are credited to each director’s deferred fee account at the closing market price of the stock on the date earned. As of September 30, 2013, there were 122,219 shares (121,348 shares at September 30, 2012) included in the Plan. The deferred balance outstanding at September 30, 2013, under the Plan was $2,756,526  ($2,676,160 at September 30, 2012). Expenses totaling $377,520,  $417,347 and $443,456 were charged to the Company’s results of operations for the years ended September 30, 2013,  2012 and 2011, respectively, and are included in general and administrative expense in the accompanying Statement of Operations.

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Income Taxes (Tables)

12 Months Ended

Sep. 30, 2013

Income Taxes [Abstract]

Summary Of Provision (Benefit) For Income Taxes

	2013		2012		2011
Current:
Federal	$	1,813,000	$	1,452,000	$	1,266,000
State		150,000		20,000		48,000
		1,963,000		1,472,000		1,314,000
Deferred:
Federal		4,003,000		1,126,000		1,982,000
State		764,000		676,000		(104,000)
		4,767,000		1,802,000		1,878,000
	$	6,730,000	$	3,274,000	$	3,192,000

Summary Of Difference Between Provision (Benefit) For Income Taxes And Amount Which Would Result From Application Of Federal Statutory Rate

	2013		2012		2011
Provision (benefit) for income taxes at statutory rate	$	7,241,517	$	3,725,749	$	4,090,069
Percentage depletion		(1,059,303)		(846,040)		(733,516)
State income taxes, net of federal provision (benefit)		572,650		464,677		(92,989)
State net operating loss valuation allowance (release)		-		(31,000)		31,000
Other		(24,864)		(39,386)		(102,564)
	$	6,730,000	$	3,274,000	$	3,192,000

Summary Of Deferred Tax Assets And Liabilities

	2013		2012
Deferred tax liabilities:
Financial basis in excess of tax basis, principally
intangible drilling costs capitalized for financial
purposes and expensed for tax purposes	$	33,557,515	$	30,320,765
Derivative contracts		165,402		-
		33,722,917		30,320,765
Deferred tax assets:
State net operating loss carry forwards, net of
valuation allowance of $0 in 2013 and 2012		782,785		1,008,271
AMT credit carry forwards		-		1,189,053
Deferred directors' compensation		1,021,717		990,455
Restricted stock expense		426,788		-
Statutory depletion carry forwards		-		415,958
Other		137,620		130,021
		2,368,910		3,733,758
Net deferred tax liabilities	$	31,354,007	$	26,587,007

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Summary Of Significant Accounting Policies (Policies)

12 Months Ended

Sep. 30, 2013

Summary Of Significant Accounting Policies [Abstract]

Nature Of Business

Nature of Business

Since its formation, the Company has been involved in the acquisition and management of fee mineral acreage and the exploration for, and development of, oil and natural gas properties, principally involving drilling wells located on the Company’s mineral acreage. Panhandle’s mineral properties and other oil and natural gas interests are all located in the United States, primarily in Arkansas, New Mexico, North Dakota, Oklahoma and Texas. The Company is not the operator of any wells. The Company’s oil, NGL and natural gas production is from interests in 6,105 wells located principally in Oklahoma and Arkansas. Approximately 60% of oil, NGL and natural gas revenues were derived from the sale of natural gas in 2013. Approximately 84% of the Company’s total sales volumes in 2013 were derived from natural gas. Substantially all the Company’s oil, NGL and natural gas production is sold through the operators of the wells. The Company from time to time disposes of 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. On an annual basis, with a semi-annual update, the Company’s Independent Consulting Petroleum Engineer, with assistance from the Company, prepares estimates of crude oil, NGL and natural gas reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. For DD&A purposes, and as required by the guidelines and definitions established by the SEC, the reserve estimates were based on average individual product prices during the 12-month period prior to September 30 determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices were defined by contractual arrangements, excluding escalations based upon future conditions. For impairment purposes, projected future crude oil, NGL and natural gas prices as estimated by management are used. Crude oil, NGL and natural gas prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Projected future crude oil, NGL and natural gas pricing assumptions are used by management to prepare estimates of crude oil, NGL and natural gas reserves 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) over a month later than the information is available to the operators of the wells. This being the case, on wells with greater significance to the Company, the most current available production data is gathered from the appropriate operators, and oil, NGL and natural gas index prices local to each well are used to estimate the accrual of revenue on these wells. Timely obtaining production data on all other wells from the operators is not feasible; therefore, the Company utilizes past production receipts and estimated sales price information to estimate its accrual of revenue on all other wells each quarter. The oil, NGL and natural gas sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for oil, NGL and natural gas. These variables could lead to an over or under accrual of oil, NGL and natural gas sales at the end of any particular quarter. Based on past history, the Company’s estimated accrual has been materially accurate.

Cash And Cash Equivalents

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 And Natural Gas Imbalances

Oil, NGL and Natural Gas Sales and Natural Gas Imbalances

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

The Company uses the sales method of accounting for natural gas imbalances in those circumstances where it has underproduced or overproduced its ownership percentage in a property. Under this method, a receivable or liability is recorded to the extent that an underproduced or overproduced position in a well cannot be recouped through the production of remaining reserves. At September 30, 2013 and 2012, the Company had no material natural gas imbalances.

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 we have an interest in may be similarly affected by changes in economic, industry or other conditions. During 2013 and 2012, we did not recognize a reserve for bad debt expense.

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 is determined to be nonproductive. Oil and natural gas mineral and leasehold costs are capitalized when incurred.

Non-producing oil and natural gas leases are assessed for impairment on a property-by-property basis for individually significant balances and on an aggregate basis for individually insignificant balances. If the assessment indicates an impairment, a loss is recognized by providing a valuation allowance at the level at which impairment was assessed. The impairment assessment is affected by economic factors such as the results of exploration activities, commodity price outlooks, remaining lease terms and potential shifts in business strategy employed by management. In the case of individually insignificant balances, the amount of the impairment loss recognized is determined by amortizing the portion of these properties’ costs, which the Company believes will not be transferred to proved properties over the remaining lives of the leases. Impairment loss is charged to exploration costs when recognized. As of September 30, 2013, the remaining carrying cost of non-producing oil and natural gas leases was $285,752.

It is common business practice in the petroleum industry for drilling costs to be prepaid before spudding a well. The Company frequently fulfills these prepayment requirements with cash payments, but at times will utilize letters of credit to meet these obligations. As of September 30, 2013, the Company had no outstanding letters of credit.

Lease Bonus

Leasing of Mineral Rights

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

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

Derivatives

Derivatives

The Company has entered into fixed swap contracts, basis protection swaps 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. Basis protection swaps are derivatives that guarantee a price differential to NYMEX for natural gas from a specified delivery point (CEGT and PEPL historically). The Company receives a payment from the counterparty if the price differential is greater than the agreed terms of the contract and pays the counterparty if the price differential is less than the agreed terms of the contract. These contracts cover only a portion of the Company’s oil and natural gas production and provide only partial price protection against declines in oil and natural gas prices. These derivative instruments expose the Company to risk of financial loss and may limit the benefit of future increases in prices. All of the Company’s derivative contracts are with Bank of Oklahoma and are secured. The derivative instruments have settled or will settle based on the prices below, which are adjusted for location differentials and tied to certain pipelines.

Derivative contracts in place as of September 30, 2012

(prices below reflect the Company’s net price from the listed pipelines)

	Production volume	Indexed
Contract period	covered per month	Pipeline	Fixed price
Natural gas basis protection swaps
January - December 2012	50,000 Mmbtu	CEGT	NYMEX -$.29
January - December 2012	40,000 Mmbtu	CEGT	NYMEX -$.30
January - December 2012	50,000 Mmbtu	PEPL	NYMEX -$.29
January - December 2012	50,000 Mmbtu	PEPL	NYMEX -$.30
Natural gas costless collars
March - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50floor/$3.25 ceiling
April - October 2012	120,000 Mmbtu	NYMEX Henry Hub	$2.50floor/$3.10 ceiling
April - October 2012	60,000 Mmbtu	NYMEX Henry Hub	$2.50floor/$3.20 ceiling
April - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50floor/$3.20 ceiling
April - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50floor/$3.45 ceiling
April - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50floor/$3.30 ceiling
August - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50floor/$3.30 ceiling
November 2012 - January 2013	150,000 Mmbtu	NYMEX Henry Hub	$3.00floor/$3.70 ceiling
November 2012 - January 2013	150,000 Mmbtu	NYMEX Henry Hub	$3.00floor/$3.70 ceiling
November 2012 - January 2013	50,000 Mmbtu	NYMEX Henry Hub	$3.00floor/$3.65 ceiling
Oil costless collars
January - December 2012	2,000 Bbls	NYMEX WTI	$90floor/$105 ceiling
February - December 2012	3,000 Bbls	NYMEX WTI	$90floor/$110 ceiling
May - December 2012	2,000 Bbls	NYMEX WTI	$90floor/$114 ceiling

Derivative contracts in place as of September 30, 2013

(prices below reflect the Company’s net price from the listed pipelines)

	Production volume	Indexed
Contract period	covered per month	pipeline	Fixed price
Natural gas costless collars
February - December 2013	80,000 Mmbtu	NYMEX Henry Hub	$3.75floor/$4.25 ceiling
February - December 2013	50,000 Mmbtu	NYMEX Henry Hub	$3.75floor/$4.30 ceiling
February - December 2013	100,000 Mmbtu	NYMEX Henry Hub	$3.75floor/$4.05 ceiling
November 2013 - April 2014	160,000 Mmbtu	NYMEX Henry Hub	$4.00floor/$4.55 ceiling
Natural gas fixed price swaps
March - October 2013	100,000 Mmbtu	NYMEX Henry Hub	$3.505
March - October 2013	70,000 Mmbtu	NYMEX Henry Hub	$3.400
April - December 2013	40,000 Mmbtu	NYMEX Henry Hub	$3.655
May - November 2013	100,000 Mmbtu	NYMEX Henry Hub	$4.320
Oil costless collars
March - December 2013	3,000 Bbls	NYMEX WTI	$90.00floor/$102.00 ceiling
March - December 2013	4,000 Bbls	NYMEX WTI	$90.00floor/$101.50 ceiling
May - December 2013	2,000 Bbls	NYMEX WTI	$90.00floor/$97.50 ceiling
January - June 2014	4,000 Bbls	NYMEX WTI	$90.00floor/$101.50 ceiling
Oil fixed price swaps
September - December 2013	4,000 Bbls	NYMEX WTI	$105.250

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 $425,198 as of September 30, 2013, and a net liability of $172,271 as of September 30, 2012. Realized and unrealized gains and (losses) are scheduled below:

Gains (losses) on natural gas	Fiscal year ended
derivative contracts	9/30/2013		9/30/2012		9/30/2011
Realized	$	13,555	$	462,033	$	2,138,685
Increase (decrease) in fair value		597,469		(388,211)		(1,404,386)
Total	$	611,024	$	73,822	$	734,299

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 Condensed Balance Sheets. The Company has chosen to present the fair values of its derivative contracts under master netting agreements using a net fair value presentation. 

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 Condensed Balance Sheets at September 30, 2013, and September 30, 2012. The Company adopted the accounting guidance requiring additional disclosures for balance sheet offsetting of assets and liabilities effective January 1, 2013. The Company has offset all amounts subject to master netting agreements in the Company's Condensed Balance Sheets at September 30, 2013, and September 30, 2012.

	9/30/2013				9/30/2012
	Fair Value (a)				Fair Value (a)
	Commodity Contracts				Commodity Contracts
	Current Assets		Current Liabilities		Current Assets		Current Liabilities
Gross amounts recognized	$	665,099	$	239,901	$	51,530	$	223,801
Offsetting adjustments		(239,901)		(239,901)		(51,530)		(51,530)
Net presentation on Condensed Balance Sheets	$	425,198	$	-	$	-	$	172,271

(a)See Fair Value Measurements section for further disclosures regarding fair value of financial instruments.

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

Fair Value 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 inputs are unadjusted quoted prices in active markets for identical assets and liabilities. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs include the following: (i) quoted prices for similar assets or liabilities in active markets; (ii) quoted prices for identical or similar assets or liabilities in markets that are not active; (iii) inputs other than quoted prices that are observable for the asset or liability; or (iv) inputs that are derived principally from, or corroborated by, observable market data by correlation or other means. Level 3 inputs are unobservable inputs for the financial asset or liability.

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

	Fair Value Measurement at September 30, 2013
	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	$	-	$	182,296	$	-	$	182,296
Derivative Contracts - Collars	$	-	$	-	$	242,902	$	242,902

	Fair Value Measurement at September 30, 2012
	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	$	-	$	(75,334)	$	-	$	(75,334)
Derivative Contracts - Collars	$	-	$	-	$	(96,937)	$	(96,937)

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

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

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

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

Instrument Type	Unobservable Input	Range	Weighted Average	Fair Value September 30, 2013
Oil Collars	Oil price volatility curve	0% - 17.56%	10.27%	$	(233,041)
Natural Gas Collars	Natural gas price volatility curve	0% - 19.67%	12.00%	$	475,943

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

	Derivatives
Balance of Level 3 as of October 1, 2012	$	(96,937)
Total gains or (losses) - realized and unrealized:
Included in earnings
Realized		242,435
Unrealized		97,404
Included in other comprehensive income (loss)		-
Purchases, issuances and settlements		-
Transfers in and out of Level 3		-
Balance of Level 3 as of September 30, 2013	$	242,902

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,
	2013				2012
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties	$	356,855	$	530,670	$	1,301,951	$	826,508	(a)

(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. Significant judgments and assumptions in these assessments include estimates of future oil, NGL and natural gas prices using a forward NYMEX curve adjusted for 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, 2013, and September 30, 2012, the fair value of financial instruments approximated their carrying amounts. Financial instruments include long-term debt, which the valuation is classified as Level 3 and is based on a valuation technique that requires inputs that are both unobservable and significant to the overall fair value measurement. The fair value measurement of our long-term debt is valued using a discounted cash flow model that calculates the present value of future cash flows pursuant to the terms of the debt agreements and applies estimated current market interest rates. The estimated current market interest rates are based primarily on interest rates currently being offered on borrowings of similar amounts and terms. In addition, no valuation input adjustments were considered necessary relating to nonperformance risk for the debt agreements.

Depreciation, Depletion, Amortization And Impairment

Depreciation, Depletion, Amortization and Impairment

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 $4,702,285 and $5,374,868 at September 30, 2013 and 2012, respectively, consisting of perpetual ownership of mineral interests in several states, with 91% of the acreage in Arkansas, New Mexico, North Dakota, Oklahoma and Texas. As mentioned, these mineral rights are perpetual and have been accumulated over the 87-year life of the Company. There are approximately 196,768 net acres of non-producing minerals in more than 6,818 tracts owned by the Company. An average tract contains approximately 29 acres, and the average cost per acre is $43. 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 activity each year on these mineral interests. Non-producing minerals are being amortized straight-line over a 33-year period. These assets are considered a long-term investment by the Company, as they do not expire (as do oil and natural gas leases). Given the above, it was concluded that a long-term amortization was appropriate and that 33 years, based on past history and experience, was an appropriate period. Due to the fact that the minerals consist of a large number of properties, whose costs are not individually significant, and because virtually all are in the Company’s core operating areas, the minerals are being amortized on an aggregate basis.

The Company recognizes impairment losses for long-lived assets when indicators of impairment are present and the undiscounted cash flows are not sufficient to recover the assets’ carrying amount. The impairment loss is measured by comparing thefair value of the asset to its carrying amount. Fair values are based on discounted cash flow as estimated by the Company’s Independent Consulting Petroleum Engineer. The Company's estimate of fair value of its oil and natural gas properties at September 30, 2013, is based on the best information available as of that date, including estimates of forward oil, NGL and natural gas prices and costs. The Company’s oil and natural gas properties were reviewed for impairment on a field-by-field basis, resulting in the recognition of impairment provisions of $530,670,  $826,508 and $1,728,162, respectively, for 2013,  2012 and 2011. A significant reduction in oil, NGL and natural gas prices or a decline in reserve volumes would likely lead to additional impairment in future periods that may be material to the Company.

Capitalized Interest

Capitalized Interest

During 2013,  2012 and 2011, interest of $121,418,  $129,172 and $0, respectively, was included in the Company’s capital expenditures. Interest of $157,558,  $127,970 and $0, respectively, was charged to expense during those periods. Interest is capitalized using a weighted average interest rate based on the

Company’s outstanding borrowings. These capitalized costs are included with intangible drilling costs and amortized using unit-of-production method.

Investments

Investments

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

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 when the oil, NGL and natural gas reserves in the wells are depleted. 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, 2013 and 2012, relating to the Company’s asset retirement obligations:

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; however, to date the Company’s cost of compliance has been insignificant. 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 others, with Panhandle being responsible for its proportionate share of the costs involved. Panhandle carries liability insurance and pollution control coverage. 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, 2013 and 2012, 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 added to each director’s account based on the fair market value of the stock at the date earned. The Plan’s structure is that upon retirement, termination or death of the director or upon a change in control of the Company, the shares accrued under the Plan will be issued to the director.

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

Restricted stock awards to certain officers provide for cliff vesting at the end of three or five years from the date of the awards. The fair value of the awards 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 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 2010.

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, 2013,  2012 and 2011, the Company recorded interest and penalties of $927,  $0 and $21,000, respectively. The Company does not believe it has any significant uncertain tax positions.

New Accounting Standards

New Accounting Standards

In December 2011, the Financial Accounting Standards Board issued "Balance Sheet: Disclosures about Offsetting Assets and Liabilities." The new standard requires entities to disclose information about financial instruments and derivative instruments that are either offset on the balance sheet or are subject to a master netting arrangement, including providing both gross information and net information for recognized assets and liabilities, the net amounts presented on an entity's balance sheet and a description of the rights of offset associated with these assets and liabilities. The new standard is applicable for all entities that have financialinstruments and derivative instruments shown using a net presentation on an entity's balance sheet or are subject to a master nettingarrangement. The new standard is effective for interim and annual reporting periods for fiscal years beginning on or after January1, 2013, and should be applied retrospectively for all periods presented. The Company adopted this new standard effectiveJanuary 1, 2013.

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.

XML

Document and Entity Information (USD $)	12 Months Ended
	Sep. 30, 2013	Dec. 01, 2013	Mar. 31, 2013
Document and Entity Information [Abstract]
Entity Registrant Name	PANHANDLE OIL & GAS INC
Entity Central Index Key	0000315131
Document Type	10-K/A
Document Period End Date	Sep. 30, 2013
Amendment Flag	true
Document Fiscal Year Focus	2013
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 Public Float			$ 201,942,992
Entity Common Stock, Shares Outstanding		8,231,254
Amendment Description	The sole purpose of this Amendment No. 1 to our Annual Report on Form 10-K for the fiscal year ended September 30, 2013, as filed with the Securities and Exchange Commission on December 11, 2013 ("Original Form 10-K"), is to amend the Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting and the Report of Independent Registered Public Accounting Firm to include the signatures of our registered independent registered public accounting firm. These two reports shown on pages 44 and 45 of the Original Form 10-K were shown without the registered independent public accounting firm's signatures. Except as described above, this Amendment does not modify or update the disclosures presented in, or exhibits to, the Original Form 10-K in any way. Those sections of the Original Form 10-K that are unaffected by this Amendment are not included herein. This Amendment continues to speak as of the date of the Original Form 10-K. Other than the furnishing of these two reports from our Independent Registered Public Accounting Firm with its signatures as described above, this Amendment has no impact on the Company's previously reported audited financial statements and notes thereto as of September 30, 2013. Furthermore, this Amendment does not reflect events occurring after the filing of the Original 10-K Filing. Accordingly, this Amendment should be read in conjunction with the Original Form 10-K, as well as the Company's other filings made with the SEC pursuant to Section 13(a) or 15(d) of the Exchange Act subsequent to the filing of the Original Form 10-K.

XML

Summary Of Significant Accounting Policies (Tables)

12 Months Ended

Sep. 30, 2013

Summary Of Significant Accounting Policies [Abstract]

Summary Of Derivative Instruments Contracts

Derivative contracts in place as of September 30, 2012

(prices below reflect the Company’s net price from the listed pipelines)

	Production volume	Indexed
Contract period	covered per month	Pipeline	Fixed price
Natural gas basis protection swaps
January - December 2012	50,000 Mmbtu	CEGT	NYMEX -$.29
January - December 2012	40,000 Mmbtu	CEGT	NYMEX -$.30
January - December 2012	50,000 Mmbtu	PEPL	NYMEX -$.29
January - December 2012	50,000 Mmbtu	PEPL	NYMEX -$.30
Natural gas costless collars
March - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50floor/$3.25 ceiling
April - October 2012	120,000 Mmbtu	NYMEX Henry Hub	$2.50floor/$3.10 ceiling
April - October 2012	60,000 Mmbtu	NYMEX Henry Hub	$2.50floor/$3.20 ceiling
April - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50floor/$3.20 ceiling
April - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50floor/$3.45 ceiling
April - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50floor/$3.30 ceiling
August - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50floor/$3.30 ceiling
November 2012 - January 2013	150,000 Mmbtu	NYMEX Henry Hub	$3.00floor/$3.70 ceiling
November 2012 - January 2013	150,000 Mmbtu	NYMEX Henry Hub	$3.00floor/$3.70 ceiling
November 2012 - January 2013	50,000 Mmbtu	NYMEX Henry Hub	$3.00floor/$3.65 ceiling
Oil costless collars
January - December 2012	2,000 Bbls	NYMEX WTI	$90floor/$105 ceiling
February - December 2012	3,000 Bbls	NYMEX WTI	$90floor/$110 ceiling
May - December 2012	2,000 Bbls	NYMEX WTI	$90floor/$114 ceiling

Derivative contracts in place as of September 30, 2013

(prices below reflect the Company’s net price from the listed pipelines)

	Production volume	Indexed
Contract period	covered per month	pipeline	Fixed price
Natural gas costless collars
February - December 2013	80,000 Mmbtu	NYMEX Henry Hub	$3.75floor/$4.25 ceiling
February - December 2013	50,000 Mmbtu	NYMEX Henry Hub	$3.75floor/$4.30 ceiling
February - December 2013	100,000 Mmbtu	NYMEX Henry Hub	$3.75floor/$4.05 ceiling
November 2013 - April 2014	160,000 Mmbtu	NYMEX Henry Hub	$4.00floor/$4.55 ceiling
Natural gas fixed price swaps
March - October 2013	100,000 Mmbtu	NYMEX Henry Hub	$3.505
March - October 2013	70,000 Mmbtu	NYMEX Henry Hub	$3.400
April - December 2013	40,000 Mmbtu	NYMEX Henry Hub	$3.655
May - November 2013	100,000 Mmbtu	NYMEX Henry Hub	$4.320
Oil costless collars
March - December 2013	3,000 Bbls	NYMEX WTI	$90.00floor/$102.00 ceiling
March - December 2013	4,000 Bbls	NYMEX WTI	$90.00floor/$101.50 ceiling
May - December 2013	2,000 Bbls	NYMEX WTI	$90.00floor/$97.50 ceiling
January - June 2014	4,000 Bbls	NYMEX WTI	$90.00floor/$101.50 ceiling
Oil fixed price swaps
September - December 2013	4,000 Bbls	NYMEX WTI	$105.250

Summary Of Realized And Unrealized Gains And (Losses)

Gains (losses) on natural gas	Fiscal year ended
derivative contracts	9/30/2013		9/30/2012		9/30/2011
Realized	$	13,555	$	462,033	$	2,138,685
Increase (decrease) in fair value		597,469		(388,211)		(1,404,386)
Total	$	611,024	$	73,822	$	734,299

Summary Of Derivative Contracts

	9/30/2013				9/30/2012
	Fair Value (a)				Fair Value (a)
	Commodity Contracts				Commodity Contracts
	Current Assets		Current Liabilities		Current Assets		Current Liabilities
Gross amounts recognized	$	665,099	$	239,901	$	51,530	$	223,801
Offsetting adjustments		(239,901)		(239,901)		(51,530)		(51,530)
Net presentation on Condensed Balance Sheets	$	425,198	$	-	$	-	$	172,271

(a)See Fair Value Measurements section for further disclosures regarding fair value of financial instruments.

Summary Of Fair Value Measurement Information For Financial Assets And Liabilities Measured At Fair Value On A Recurring Basis

	Fair Value Measurement at September 30, 2013
	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	$	-	$	182,296	$	-	$	182,296
Derivative Contracts - Collars	$	-	$	-	$	242,902	$	242,902

	Fair Value Measurement at September 30, 2012
	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	$	-	$	(75,334)	$	-	$	(75,334)
Derivative Contracts - Collars	$	-	$	-	$	(96,937)	$	(96,937)

Summary Of Unobservable Inputs For Level 3 Fair Value Measurements

Instrument Type	Unobservable Input	Range	Weighted Average	Fair Value September 30, 2013
Oil Collars	Oil price volatility curve	0% - 17.56%	10.27%	$	(233,041)
Natural Gas Collars	Natural gas price volatility curve	0% - 19.67%	12.00%	$	475,943

Summary Of Reconciliation Of Assets Classified As Level 3 Measurements

	Derivatives
Balance of Level 3 as of October 1, 2012	$	(96,937)
Total gains or (losses) - realized and unrealized:
Included in earnings
Realized		242,435
Unrealized		97,404
Included in other comprehensive income (loss)		-
Purchases, issuances and settlements		-
Transfers in and out of Level 3		-
Balance of Level 3 as of September 30, 2013	$	242,902

Summary Of Impairments Associated With Certain Assets Measured At Fair Value On A Nonrecurring Basis Within Level 3

	Year Ended September 30,
	2013				2012
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties	$	356,855	$	530,670	$	1,301,951	$	826,508	(a)

Summary Of Asset Retirement Obligation

	2013		2012
Asset Retirement Obligations as of beginning of the year	$	2,122,950	$	1,843,875
Accretion of Discount		122,391		121,112
New Wells Placed on Production		167,609		184,027
Wells Sold or Plugged		(19,760)		(26,064)
Asset Retirement Obligations as of end of the year	$	2,393,190	$	2,122,950

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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, 2013	Sep. 30, 2012	Sep. 30, 2011
Supplementary Information On Oil, Ngl And Natural Gas Reserves [Abstract]
Beginning Balance	$ 67,414,288	$ 78,382,434	$ 72,500,409
Sales of oil and natural gas, net of production costs	(46,909,635)	(30,226,927)	(33,570,621)
Net change in sales prices and production costs	47,270,404	(45,178,377)	(2,697,833)
Net change in future development costs	(7,363,224)	4,483,543	4,126,812
Extensions and discoveries	54,101,830	34,216,533	11,938,029
Revisions of quantity estimates	(3,150,420)	(27,419,576)	7,046,873
Acquisitions (divestitures) of reserves-in-place	2,198,612	20,160,327	4,480,858
Accretion of discount	11,473,819	13,644,203	12,523,091
Net change in income taxes	(27,464,341)	10,735,694	(5,329,092)
Change in timing and other, net	4,103,563	8,616,434	7,363,908
Net change	34,260,608	(10,968,146)	5,882,025
Ending Balance	$ 101,674,896	$ 67,414,288	$ 78,382,434

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Supplementary Information On Oil, Ngl And Natural Gas Reserves (Summary of Standardized Measure of Discounted Future Net Cash Flows) (Details) (USD $)	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2011
Supplementary Information On Oil, Ngl And Natural Gas Reserves [Abstract]
Future cash inflows	$ 630,332,900	$ 408,694,869	$ 494,523,456
Future production costs	(216,584,982)	(135,516,703)	(146,168,829)
Future development costs	(50,572,218)	(35,290,260)	(45,269,686)
Future income tax expense	(131,397,192)	(83,543,516)	(107,111,317)
Future net cash flows	231,778,508	154,344,390	195,973,624
10% annual discount	(130,103,612)	(86,930,102)	(117,591,190)
Standardized measure of discounted future net cash flows	$ 101,674,896	$ 67,414,288	$ 78,382,434