10-Q

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549
FORM 10-Q
☑	Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
	For the period ended		June  30, 2014
☐	Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
	For the transition period from			__________to__________
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						(I.R.S. Employer
incorporation or organization)						Identification No.)
Grand Centre Suite 300, 5400 N Grand Blvd., Oklahoma City, Oklahoma  73112
(Address of principal executive offices)
Registrant's telephone number including area code					(405) 948-1560
Indicate by check mark whether the registrant (1) has filed all reports required to be filedby 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 beensubject to such filing requirements for the past 90 days.
							Yes☑	No☐
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).
							Yes☑	No☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company.  See definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer☐    Accelerated filer☑Non-accelerated filer☐Smaller reporting company ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
							Yes☐	No☑
Outstanding shares of Class A Common stock (voting) at August7, 2014:								8,238,628

INDEX

Part I	Financial Information		Page
	Item 1	Condensed Financial Statements	1
		Condensed Balance Sheets – June  30, 2014 and September 30, 2013	1
		Condensed Statements of Operations – Three and nine months ended June  30, 2014 and 2013	2
		Statements of Stockholders’ Equity – Nine months ended June  30, 2014 and 2013	3
		Condensed Statements of Cash Flows – Nine months ended June  30, 2014 and 2013	4
		Notes to Condensed Financial Statements	5
	Item 2	Management's discussion and analysis of financial condition and results of operations	12
	Item 3	Quantitative and qualitative disclosures about market risk	17
	Item 4	Controls and procedures	18
Part II	Other Information		18
	Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	18
	Item 6	Exhibits and reports on Form 8-K	18
	Signatures		19

The following defined terms are used in this report:

“Bbl” means barrel.

“Board” means board of directors.

“BTU” means British Thermal Units.

“Company” refers to Panhandle Oil and Gas Inc.

“DD&A” means depreciation, depletion and amortization.

“ESOP” refers to the Panhandle Oil and Gas Inc. Employee Stock Ownership and 401(k) Plan, a tax qualified, defined contribution plan.

“FASB” means the Financial Accounting Standards Board.

“G&A” means general and administrative costs.

“Independent Consulting Petroleum Engineer(s)” or “Independent Consulting Petroleum Engineering Firm” refers to DeGolyer and MacNaughton of Dallas, Texas.

“LOE” means lease operating expense.

“Mcf” means thousand cubic feet.

“Mcfe” means natural gas stated on an Mcf basis and crude oil and natural gas liquids converted to a thousand cubic feet of natural gas equivalent by using the ratio of one Bbl of crude oil or natural gas liquids to six Mcf of natural gas.

“Mmbtu” means million BTU.

“minerals”,  “mineral acres” or “mineral interests” refers to fee mineral acreage owned in perpetuity by the Company.

“NGL” means natural gas liquids.

“NYMEX” refers to the New York Mercantile Exchange.

“Panhandle” refers to Panhandle Oil and Gas Inc.

“play” is a term applied to identified areas with potential oil and/or natural gas reserves.

“royalty interest” refers to well interests in which the Company does not pay a share of the costs to drill, complete and operate a well, but receives a much smaller proportionate share (as compared to a working interest) of production.

“SEC”refers to the United States Securities and Exchange Commission.

“working interest” refers to well interests in which the Company pays a share of the costs to drill, complete and operate a well and receives a proportionate share of production.

“WTI” refers to West Texas Intermediate.

Fiscal year references

All references to years in this report, unless otherwise noted, refer to the Company’s fiscal year end of September 30. For example, references to 2014 mean the fiscal year ended September 30, 2014.

References to oil and natural gas properties

References to oil and natural gas properties inherently include natural gas liquids associated with such properties.

PART 1   FINANCIAL INFORMATION

PANHANDLE OIL AND GAS INC.

CONDENSED BALANCE SHEETS

	June 30, 2014		September 30, 2013
Assets	(unaudited)
Current assets:
Cash and cash equivalents	$	1,511,057	$	2,867,171
Oil, NGL and natural gas sales receivables		15,070,653		13,720,761
Refundable income taxes		3,160,243		-
Refundable production taxes		760,947		662,051
Derivative contracts, net		-		425,198
Other		3,660,589		129,998
Total current assets		24,163,489		17,805,179
Properties and equipment at cost, based on successful efforts accounting:
Producing oil and natural gas properties		408,816,025		304,889,145
Non-producing oil and natural gas properties		9,544,840		8,932,905
Other		1,305,473		737,368
		419,666,338		314,559,418
Less accumulated depreciation, depletion and amortization		(198,439,791)		(186,641,291)
Net properties and equipment		221,226,547		127,918,127
Investments		1,653,406		1,574,642
Refundable production taxes		159,845		540,482
Total assets	$	247,203,287	$	147,838,430
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	8,031,138	$	8,409,634
Derivative contracts, net		1,944,091		-
Deferred income taxes		9,100		127,100
Income taxes payable		-		751,992
Accrued liabilities and other		1,111,910		1,011,865
Total current liabilities		11,096,239		10,300,591
Long-term debt		85,852,794		8,262,256
Deferred income taxes		37,308,907		31,226,907
Asset retirement obligations		2,855,520		2,393,190
Derivative contracts, net		62,138		-
Stockholders' equity:
Class A voting common stock, $.0166 par value;
24,000,000 shares authorized, 8,431,502 issued at
June 30, 2014, and September 30, 2013		140,524		140,524
Capital in excess of par value		2,767,615		2,587,838
Deferred directors' compensation		3,026,134		2,756,526
Retained earnings		110,162,113		96,454,449
		116,096,386		101,939,337
Less treasury stock, at cost; 192,874 shares at June 30,
2014, and 200,248 shares at September 30, 2013		(6,068,697)		(6,283,851)
Total stockholders' equity		110,027,689		95,655,486
Total liabilities and stockholders' equity	$	247,203,287	$	147,838,430

(See accompanying notes)

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PANHANDLE OIL AND GAS INC.

CONDENSED STATEMENTS OF OPERATIONS

	Three Months Ended June 30,				Nine Months Ended June 30,
	2014		2013		2014		2013
Revenues:	(unaudited)				(unaudited)
Oil, NGL and natural gas sales	$	19,534,545	$	15,827,137	$	59,115,928	$	42,686,935
Lease bonuses and rentals		137,476		24,146		353,422		539,479
Gains (losses) on derivative contracts		(1,427,165)		1,714,832		(3,511,095)		796,166
Income from partnerships		130,121		164,330		565,523		470,286
		18,374,977		17,730,445		56,523,778		44,492,866
Costs and expenses:
Lease operating expenses		2,961,750		3,105,709		9,930,147		9,040,613
Production taxes		593,941		460,902		1,871,538		1,177,341
Exploration costs		6,956		25,648		70,140		60,827
Depreciation, depletion and amortization		5,314,777		5,192,544		15,562,630		17,090,187
Provision for impairment		-		7,400		430,143		225,841
Loss (gain) on asset sales, interest and other		44,594		29,789		71,783		(138,921)
General and administrative		1,825,374		1,585,285		5,349,921		5,127,025
		10,747,392		10,407,277		33,286,302		32,582,913
Income before provision for income taxes		7,627,585		7,323,168		23,237,476		11,909,953
Provision for income taxes		2,505,000		2,253,000		7,534,000		3,669,000
Net income	$	5,122,585	$	5,070,168	$	15,703,476	$	8,240,953
Basic and diluted earnings per common share (Note 3)	$	0.61	$	0.61	$	1.88	$	0.99
Basic and diluted weighted average shares outstanding:
Common shares		8,237,020		8,163,520		8,235,186		8,247,642
Unissued, directors' deferred compensation shares		127,835		116,762		126,051		113,259
		8,364,855		8,280,282		8,361,237		8,360,901
Dividends declared per share of
common stock and paid in period	$	0.08	$	0.07	$	0.24	$	0.21

(See accompanying notes)

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PANHANDLE OIL AND GAS INC.

STATEMENTS OF STOCKHOLDERS’ EQUITY

Nine Months Ended June 30, 2014

	Class A voting			Capital in		Deferred
	Common Stock			Excess of		Directors'		Retained		Treasury	Treasury
	Shares	Amount		Par Value		Compensation		Earnings		Shares	Stock		Total
Balances at September 30, 2013	8,431,502	$	140,524	$	2,587,838	$	2,756,526	$	96,454,449	(200,248)	$	(6,283,851)	$	95,655,486
Purchase of treasury stock	-		-		-		-		-	(3,722)		(122,044)		(122,044)
Restricted stock awards	-		-		499,791		-		-	-		-		499,791
Net income	-		-		-		-		15,703,476	-		-		15,703,476
Dividends ($.24 per share)	-		-		-		-		(1,995,812)	-		-		(1,995,812)
Distribution of restricted stock
to officers and directors	-		-		(320,014)		-		-	11,096		337,198		17,184
Increase in deferred directors'
compensation charged to expense	-		-		-		269,608		-	-		-		269,608
Balances at June 30, 2014	8,431,502	$	140,524	$	2,767,615	$	3,026,134	$	110,162,113	(192,874)	$	(6,068,697)	$	110,027,689
(unaudited)

Nine Months Ended June 30, 2013

	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, 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)
Restricted stock awards	-		-		541,937		-		-	-		-		541,937
Net income	-		-		-		-		8,240,953	-		-		8,240,953
Dividends ($.21 per share)	-		-		-		-		(1,746,217)	-		-		(1,746,217)
Distribution of deferred directors'
compensation	-		-		(82,547)		(297,154)		-	12,361		394,687		14,986
Increase in deferred directors'
compensation charged to expense	-		-		-		288,759		-	-		-		288,759
Balances at June 30, 2013	8,431,502	$	140,524	$	2,479,619	$	2,667,765	$	91,316,131	(211,155)	$	(6,626,113)	$	89,977,926
(unaudited)

(See accompanying notes)

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PANHANDLE OIL AND GAS INC.

CONDENSED STATEMENTS OF CASH FLOWS

	Nine months ended June 30,
	2014		2013
Operating Activities	(unaudited)
Net income (loss)	$	15,703,476	$	8,240,953
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
Depreciation, depletion and amortization		15,562,630		17,090,187
Impairment		430,143		225,841
Provision for deferred income taxes		5,964,000		2,651,000
Exploration costs		70,140		60,827
Gain from leasing fee mineral acreage		(352,930)		(538,133)
Net (gain) loss on sales of assets		152,766		(208,750)
Income from partnerships		(565,523)		(470,286)
Distributions received from partnerships		734,825		603,249
Directors' deferred compensation expense		269,608		288,759
Restricted stock awards		499,791		541,937
Cash provided (used) by changes in assets and liabilities:
Oil, NGL and natural gas sales receivables		(1,349,892)		(3,885,005)
Fair value of derivative contracts		2,431,427		(987,249)
Refundable production taxes		281,741		253,048
Other current assets		(25,098)		78,889
Accounts payable		443,438		(48,038)
Income taxes receivable		(3,160,243)		325,715
Income taxes payable		(751,992)		50,854
Accrued liabilities		100,229		(80,584)
Total adjustments		20,735,060		15,952,261
Net cash provided by operating activities		36,438,536		24,193,214
Investing Activities
Capital expenditures, including dry hole costs		(26,693,851)		(20,576,359)
Acquisition of working interest properties		(86,759,445)		-
Acquisition of minerals and overrides		(56,250)		(783,750)
Proceeds from leasing fee mineral acreage		381,280		557,196
Investments in partnerships		(248,066)		(607,702)
Proceeds from sales of assets		92,000		870,610
Net cash used in investing activities		(113,284,332)		(20,540,005)
Financing Activities
Borrowings under debt agreement		95,112,044		9,353,651
Payments of loan principal		(17,521,506)		(10,663,399)
Purchases of treasury stock		(122,044)		(1,214,638)
Payments of dividends		(1,995,812)		(1,746,217)
Excess tax benefit on stock-based compensation		17,000		15,000
Net cash provided by (used in) financing activities		75,489,682		(4,255,603)
Increase (decrease) in cash and cash equivalents		(1,356,114)		(602,394)
Cash and cash equivalents at beginning of period		2,867,171		1,984,099
Cash and cash equivalents at end of period	$	1,511,057	$	1,381,705
Supplemental Schedule of Noncash Investing and Financing Activities:
Additions to asset retirement obligations	$	370,536	$	119,166
Gross additions to properties and equipment	$	109,182,119	$	21,660,852
Net (increase) decrease in accounts payable for
properties and equipment additions		4,327,427		(300,743)
Capital expenditures and acquisitions, including dry hole costs	$	113,509,546	$	21,360,109

(See accompanying notes)

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PANHANDLE OIL AND GAS INC.

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1:Accounting Principles and Basis of Presentation

The accompanying unaudited condensed financial statements of Panhandle Oil and Gas Inc. have been prepared in accordance with the instructions to Form 10-Q as prescribed by the SEC.Management of the Company believes that all adjustments necessary for a fair presentation of the financial position and results of operations and cash flows for the periods have been included.All such adjustments are of a normal recurring nature.The results are not necessarily indicative of those to be expected for the full year.The Company’s fiscal year runs from October 1 through September 30.

Certain amounts and disclosures have been condensed or omitted from these financial statements pursuant to the rules and regulations of the SEC.Therefore, these condensed financial statements should be read in conjunction with the financial statements and related notes thereto included in the Company’s 2013Annual Report on Form 10-K.

NOTE 2:Income Taxes

The Company’s provision for income taxes differs from the statutory rate primarily due to estimated federaland statebenefits generated from estimated excess federal and Oklahoma percentage depletion, which are permanent tax benefits.

Both excess  federal percentage depletion, which is limited to certain production volumes and by certain income levels, and excess Oklahoma percentage depletion, which hasno limitation on production volume, reduce estimated taxable income or add to estimated taxable loss projected for any year.The federal and Oklahoma excess percentage depletion estimates will be updated throughout the year until finalized with detailed well-by-well calculations at fiscal year-end.Federal and Oklahoma excess percentage depletion, when a provision for income taxes is recorded, decreases the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is recorded.The benefits of federal and Oklahoma excess percentage depletion are not directly related to the amount of pre-tax income recorded in a period.Accordingly, in periods where a recorded pre-tax income or loss is relatively small, the proportional effect of these items on the effective tax rate may be significant.The effective tax rate for the nine months ended June 30, 2014, was 32% as compared to 31% for the nine months ended June 30, 2013.  The effective tax rate for the quarter ended June 30, 2014, was 33% as compared to 31% for the quarter ended June 30, 2013.

NOTE 3:Basic and Diluted Earnings per Share

Basic and diluted earningsper share is calculated using net incomedivided by the weighted average number of voting common shares outstanding, including unissued,vested directors’ deferred compensation sharesduring the period.

NOTE 4:Long-term Debt

On June 17, 2014, the closing date of the Eagle Ford Shale asset acquisition, the Company increased its credit facility with a group of banks headed by Bank of Oklahoma (BOK) from $80,000,000 to $200,000,000, increased the borrowing base from $35,000,000 to $130,000,000 and extended the maturity date to November 30, 2018. The Company incurred $542,500 of debt issuance costs to increase its credit facility. These costs were capitalized and will be amortized over the term of the facility. The credit facility 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. The facility is secured by certain of the Company’s properties with a carrying value of $163,288,413 at June 30, 2014. The interest rate is based on BOK prime plus from 0.375% to 1.125%, or 30 day LIBOR plus from 1.875% to 2.625%. The election of BOK prime or LIBOR is at the Company’s discretion. The interest rate spread from BOK prime or LIBOR will be charged based on the ratio of the loan balance to the borrowing base. The interest rate spread from LIBOR or the prime rate increases as a larger percent of the borrowing base is advanced. At June 30, 2014, the effective interest rate was 2.58%.

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 $130,000,000. 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), 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 June 30, 2014, the Company

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was in compliance with the covenants of the BOK agreement.

NOTE 5:Deferred Compensation Plan for Directors

The Company has a deferred compensation plan for non-employee directors (the Plan).The Plan provides that each eligible director can individually elect to be credited with future unissued shares of Company stock rather than cash for Board and committee chair retainers, Board meeting fees and Board committee meeting fees.These unissued shares are credited to each director’s deferred fee account at the closing market price of the stock on the date earned.Upon retirement, termination or death of the director, or upon a change in control of the Company, the unissued shares credited under the Plan will be issued to the director.

NOTE 6: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. On March 5, 2014, shareholders approved an amendment to increase the number of shares of common stock reserved for issuance under the 2010 Stock Plan from 100,000 shares to 250,000 shares and to allow the grant of shares of restricted stock to our directors. The 2010 Stock Plan, as amended, is designed to provide as much flexibility as possible for future grants of restricted stock so that the Company can respond as necessary to provide competitive compensation in order to retain, attract and motivate directors and officers of the Company and to align their interests with those of the Company’s shareholders.

Effective May 14, 2014, the board of directors approved for management, at their discretion, to purchase the Company’s common stock, from time to time, up to an amount 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.

On December 21, 2013, the Company awarded 6,093 non-performance based shares and 18,279 performance based shares of the Company’s common stock as restricted stock to certain officers. The restricted stock vests at the end of three years and contains nonforfeitable rights to receive dividends and voting rights during the vesting period. The non-performance and performance based shares had a fair value on their award date of $199,788 and $294,889, respectively, and will be recognized as compensation expense ratably over the vesting period. The fair value of the performance based shares on their award date is calculated by simulating the Company’s stock price and stock price return utilizing a Monte Carlo model covering the period from the grant date through the end of the performance period (December 21, 2013, through December 21, 2016).

On May 29, 2014, the Company awarded 3,918 non-performance based shares of the Company’s common stock as restricted stock to its non-employee directors.  One-quarter of the restricted stock vested immediately on May 29, 2014, and an additional quarter vested on June 30, 2014. The remainder will vest over the next six months. The restricted stock contains nonforfeitable rights to receive dividends and voting rights during the vesting period. These non-performance based shares had a fair value on their award date of $210,120.

The following table summarizes the Company’s pre-tax compensation expense for the three and nine months ended June 30, 2014 and 2013, related to the Company’s performance based and non-performance based restricted stock.

	Three Months Ended				Nine Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
Performance based, restricted stock	$	76,520	$	81,822	$	226,800	$	263,583
Non-performance based, restricted stock		161,097		60,208		272,991		278,354
Total compensation expense	$	237,617	$	142,030	$	499,791	$	541,937

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.

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	As of June 30, 2014
	Unrecognized Compensation Cost		Weighted Average Period (in years)
Performance based, restricted stock	$	350,815	1.62
Non-performance based, restricted stock		364,545	1.26
Total	$	715,360

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

NOTE 7:Oil, NGL and Natural Gas Reserves

Management considers the estimation of the Company’s crude oil, NGL and natural gas reserves to be the most significant of its judgments and estimates. Changes in crude oil, NGL and natural gas reserve estimates affect the Company’s calculation of DD&A, provision for abandonment and assessment of the need for asset impairments. On an annual basis, with a semi-annual update, the Company’s Independent Consulting Petroleum Engineer, with assistance from Company staff, prepares estimates of crude oil, NGL and natural gas reserves based on available geological and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing appropriate prices for the current period. The estimated oil, NGL and natural gas reserves were computed using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month oil, NGL and natural gas price for each month within the 12-month period prior to the balance sheet date, held flat over the life of the properties. However, projected future crude oil, NGL and natural gas pricing assumptions are used by management to prepare estimates of crude oil, NGL and natural gas reserves and future net cash flows used in asset impairment assessments and in formulating management’s overall operating decisions. Crude oil, NGL and natural gas prices are volatile and affected by worldwide production and consumption and are outside the control of management.

NOTE 8:Impairment

All long-lived assets, principally oil and natural gas properties, are monitored for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its estimated future net cash flows. The evaluations involve significant judgment since the results are based on estimated future events, such as inflation rates, future sales prices for oil, NGL and natural gas, future production costs, estimates of future oil, NGL and natural gas reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. The need to test a property for impairment may result from significant declines in sales prices or unfavorable adjustments to oil, NGL and natural gas reserves. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing updated projected future price decks current with the period. For the three months ended June 30, 2014 and 2013, the assessment resulted in impairment provisions of $0 and $7,400, respectively.For the nine months ended June 30, 2014 and 2013, the assessment resulted in impairment provisions of $430,143 and $225,841, respectively. A reduction in oil, NGL or natural gas prices, or a decline in reserve volumes, could lead to additional impairment that may be material to the Company.

NOTE 9:Capitalized Costs

As ofJune 30, 2014 and 2013, non-producing oil and natural gas properties include costs of $888,505and $0, respectively, on exploratory wells which were drilling and/or testing.

NOTE 10:Derivatives

The Company has entered into fixed swap contracts and costless collar contracts.These instruments are intended to reduce the Company’s exposure to short-term fluctuations in the price of oil and natural gas.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.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.These contracts cover only a portion of the Company’s natural gas and oil production and provide only partial price protection against declines in natural gas and oil prices.These derivative instruments may expose the Company to risk of financial loss and 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.

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Derivative contracts in place as of June 30, 2014

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
July - December 2014	140,000 Mmbtu	NYMEX Henry Hub	$3.75 floor / $4.50 ceiling
Natural gas fixed price swaps
July - December 2014	140,000 Mmbtu	NYMEX Henry Hub	$4.11
April - September 2014	50,000 Mmbtu	NYMEX Henry Hub	$4.20
April - September 2014	50,000 Mmbtu	NYMEX Henry Hub	$4.18
April - September 2014	50,000 Mmbtu	NYMEX Henry Hub	$4.21
May - October 2014	30,000 Mmbtu	NYMEX Henry Hub	$4.30
October - December 2014	40,000 Mmbtu	NYMEX Henry Hub	$4.61
Oil costless collars
January - December 2014	4,000 Bbls	NYMEX WTI	$85.00 floor / $100.00 ceiling
July - December 2014	5,000 Bbls	NYMEX WTI	$90.00 floor / $97.00 ceiling
Oil fixed price swaps
January - December 2014	3,000 Bbls	NYMEX WTI	$94.50
July - December 2014	4,000 Bbls	NYMEX WTI	$95.25
July - December 2014	5,000 Bbls	NYMEX WTI	$94.20
January - March 2015	6,000 Bbls	NYMEX WTI	$92.85
June - December 2014	4,000 Bbls	NYMEX WTI	$99.40
January - June 2015	7,000 Bbls	NYMEX WTI	$96.80
January - June 2015	5,000 Bbls	NYMEX WTI	$97.40
April - December 2015	5,000 Bbls	NYMEX WTI	$94.56
July - December 2015	7,000 Bbls	NYMEX WTI	$93.91

Derivative contracts in place as of September 30, 2013

	Production volume
Contract period	covered per month	Index	Contract 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	$105.25

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The Company has elected not to complete all of 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 liabilityof $2,006,229 as of June 30, 2014, and a net asset of $425,198 as of September 30, 2013.

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 June 30, 2014, and September 30, 2013. 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 June 30, 2014, and September 30, 2013.

	6/30/2014						9/30/2013
	Fair Value (a)						Fair Value (a)
	Commodity Contracts						Commodity Contracts
	Current Assets		Current Liabilities			Non-Current Liabilities	Current Assets		Current Liabilities
Gross amounts recognized	$	15,871	$	1,959,962	$	62,138	$	665,099	$	239,901
Offsetting adjustments		(15,871)		(15,871)		-		(239,901)		(239,901)
Net presentation on Condensed Balance Sheets	$	-	$	1,944,091	$	62,138	$	425,198	$	-

(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.The impact of credit risk was immaterial for all periods presented.

NOTE 11: 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 as of June 30, 2014.

	Fair Value Measurement at June 30, 2014
	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	$	-	$	(1,483,216)	$	-	$	(1,483,216)
Derivative Contracts - Collars	$	-	$	-	$	(523,013)	$	(523,013)

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

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

The significant unobservable inputs for Level 3 derivative contracts include market volatility and credit risk of counterparties. Changes in these inputs will impact the fair value measurement of our derivative contracts. An increase (decrease) in the 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 June 30, 2014
Oil Collars	Oil price volatility curve	0% - 10.30%	6.30%	$	(386,098)
Natural Gas Collars	Natural gas price volatility curve	0% - 18.10%	11.40%	$	(136,915)

A reconciliation of the Company’s derivative contracts classified as Level 3 measurements is presented below. All gains and losses are presented on the Gains (losses) on derivative contracts line item on our Statement of Operations.

	Derivatives
Balance of Level 3 as of October 1, 2013	$	242,902
Total gains or (losses)
Included in earnings		(78,976)
Included in other comprehensive income (loss)		-
Purchases, issuances and settlements		(686,939)
Transfers in and out of Level 3		-
Balance of Level 3 as of June 30, 2014	$	(523,013)

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.

	Quarter Ended June 30,
	2014				2013
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	-	$	-	$	14,849	$	7,400
	Nine Months Ended June 30,
	2014				2013
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	628,097	$	430,143	$	356,855	$	225,841

(a) At the end of each quarter, the Company assesses the carrying value of its producing properties for impairment. This assessment utilizes estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of future oil 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 June 30, 2014, and September 30, 2013, the fair value of financial instruments approximated their carrying

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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.

NOTE 12: Acquisitions

On June 17, 2014,  the Company closed an acquisition of certain Eagle Ford Shale assets located in LaSalle and Frio Counties, Texas, in the core of the Eagle Ford Shale. The assets were purchased from private sellers and included a 16% non-operated working interest in 11,100 gross (1,775 net) acres. The acreage is largely contiguous, entirely held by production and contains 63 producing wells (57 Eagle Ford, 5 Pearsall and 1 Buda) and 109 undeveloped Eagle Ford locations. The adjusted purchase price at closing was  $81.7 million and was funded by utilizing the Company’s bank credit facility. The purchase price was allocated to the producing wells and undeveloped locations based on fair value determined by estimated reserves and adjusted for working capital. The purchase price allocation is preliminary, pending the finalization of working capital adjustments. Adjustments to the estimated fair values may be recorded during the allocation period, not to exceed one year from the date of acquisition.

Actual and Pro Forma Impact of Acquisitions (Unaudited)

Revenues attributable to this acquisition (June 17, 2014, through June 30, 2014)  included in the Company’s statement of operations for the quarter and nine months ended June 30, 2014, were $1,011,909. Net income attributable to the acquisition included in the statement of operations for the quarter and nine months ended June 30, 2014, was $388,128.

The following table presents the unaudited pro forma financial information assuming the Company had acquired this business on October 1, 2012:

	For the Nine Months Ended
	June 30,
	2014		2013
Revenue:
As reported	$	56,523,778	$	44,492,866
Pro forma revenue		16,811,606		14,862,947
Pro forma	$	73,335,384	$	59,355,813
Net Income:
As reported	$	15,703,476	$	8,240,953
Pro forma income		6,485,185		5,771,157
Pro forma	$	22,188,661	$	14,012,110

The unaudited pro forma financial information is for informational purposes only and does not purport to present what our results would actually have been had this transaction actually occurred on the date presented or to project our results of operations or financial position for any future period.

NOTE 13:Recently Adopted Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2014-09-Revenue from Contracts with Customers, which will supersede nearly all existing revenue recognition guidance under GAAP. The standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. We are evaluating our existing revenue recognition policies to determine whether any contracts in the scope of the guidance will be affected by the new requirements. The standard is effective for us on October 1, 2017. Early adoption is not permitted. The standard allows for either “full retrospective” adoption, meaning the standard is applied to all of the periods presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements. We are currently evaluating the transition method that will be elected.

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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ITEM 2 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

FORWARD-LOOKING STATEMENTS AND RISK FACTORS

Forward-Looking Statements for fiscal 2014 and later periods are made in this document. Such statements represent estimates by management based on the Company’s historical operating trends, its proved oil, NGL and natural gas reserves and other information currently available to management. The Company cautions that the Forward-Looking Statements provided herein are subject to all the risks and uncertainties incident to the acquisition, development and marketing of, and exploration for oil, NGL and natural gas reserves. Investors should also read the other information in this Form 10-Q and the Company’s 2013 Annual Report on Form 10-K where risk factors are presented and further discussed. For all the above reasons, actual results may vary materially from the Forward-Looking Statements and there is no assurance that the assumptions used are necessarily the most likely to occur.

LIQUIDITY AND CAPITAL RESOURCES

The Company had positive working capital of $13,067,250 at June 30, 2014,  compared to $7,504,588 at September 30, 2013.

Liquidity:

Cash and cash equivalents were $1,511,057 as of June 30, 2014, compared to $2,867,171 at September 30, 2013,  a decrease of $1,356,114. Cash flows for the nine months ended June 30 are summarized as follows:

Net cash provided (used) by:
	2014		2013		Change
Operating activities	$	36,438,536	$	24,193,214	$	12,245,322
Investing activities		(113,284,332)		(20,540,005)		(92,744,327)
Financing activities		75,489,682		(4,255,603)		79,745,285
Increase (decrease) in cash and cash equivalents	$	(1,356,114)	$	(602,394)	$	(753,720)

Operating activities:

Net cash provided by operating activities increased$12,245,322 during the2014 period, as compared to the2013 period, the result of the following:

· Receipts of oil, NGL and natural gas sales (net of production taxes and gathering, transportation and marketing costs) and otherincreased$18,488,063.

· Increased income tax payments of $4,863,337.

· Increased net payments on derivative contracts of $666,221.

· Increased payments for G&A expenses of $386,598.

· Increased payments for field operating expenses of $374,342.

Investing activities:

Net cash used in investing activities increased$92,744,327 during the 2014 period, as compared to the 2013 period, due to:

· An increase in cash used to acquire properties of $86,031,945.

· Higher drilling and completion activity during 2014increased capital expenditures by $6,117,492.

· Lower proceeds from mineral leasing and asset sales of $954,526.

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Financing activities:

Net cash provided by financing activities increased $79,745,285 during the 2014 period, as compared to the 2013 period, the result of the following:

· During the period ended June 30, 2014, net borrowings increased$77,590,538; during the period ended June 30, 2013, net borrowings decreased$1,309,748. Increased borrowings were used to finance the acquisition of properties.

Capital Resources:

On June 17, 2014, the Company closed on the purchase of a 16% non-operated working interest in 11,100 gross leasehold acres (1,775 net) located in the Eagle Ford Shale play in LaSalle and Frio Counties, Texas, at an adjusted purchase price at closing of $81,703,747, subject to further working capital adjustments. Cash used for investing activities relevant to the Eagle Ford Shale acquisition was $85,209,240. The $3,505,493 difference represents the net benefit (to be received in future periods) of accrued revenues less accrued expenses. The purchase was funded utilizing the Company’s bank credit facility (see further discussion in this section below regarding restructure of the bank credit facility). All of the acquired acreage is held by production and, at the time of closing, included 63 producing wells, 1 drilling well, 3 wells in the completion phase and 109 undeveloped locations. The acreage is largely contiguous and is wholly operated by privately held Cheyenne Petroleum Company (Oklahoma City, Oklahoma). The property is currently being developed utilizing one drilling rig full-time.

Capital expenditures to drill and complete wells increased$6,117,492(30%)fromthe 2013 to the 2014 period.  Primarily, this increase has been due to drilling activity in horizontal plays in western and southern Oklahoma (oil and NGL rich), the Texas Panhandle (oil and NGL rich), the Arkansas Fayetteville Shale (dry natural gas) and the newly acquired Eagle Ford Shale (oil). Less significant capital expenditures have also been made to fund horizontal drilling in the northern Oklahoma Mississippian (oil) and the North Dakota Bakken (oil) along with vertical drilling in the Permian Basin of West Texas and New Mexico (oil).

The oil and NGL rich plays in western and southern Oklahoma and the Texas Panhandle where drilling activity has been on mineral and leasehold acreage the Company owns are as follows:

· Horizontal Granite Wash and Hogshooter in western Oklahoma and the Texas Panhandle

· Horizontal Cleveland in the Texas Panhandle

· Horizontal Marmaton/Cleveland in western Oklahoma

· Horizontal Tonkawa in western Oklahoma

· Horizontal Anadarko Basin Woodford Shale in western Oklahoma

· Horizontal Ardmore Basin Woodford Shale in southern Oklahoma

Based on the current level of drilling proposals, including the recently acquired Eagle Ford Shale acreage, management expects capital expenditures for the drilling and completing of wells to approximate $47 million for fiscal 2014. Since the Company is not the operator of any of its oil and natural gas properties, it is difficult for us to predict the level of future well proposals, the Company’s percentage of participation in the drilling and completion of new wells and the amount of associated capital expenditures.

Production of oil, NGL and natural gas increased 9% on an Mcfe basis from the 2013 tothe 2014 period.  The production increase was largely the result of new production coming on line from drilling in late fiscal 2013 and early fiscal 2014, which exceeded the natural production decline of existing wells. Based on current levels of activity, which now includes drilling on the Eagle Ford Shale acreage, combined with the added production from Eagle Ford Shale wells that were producing at the time they were acquired, 2014 total Mcfe production is expected to exceed that of 2013 by approximately the same percentage as through the first nine months.

The shift, in recent years, of capital outlays more toward oil and NGL rich plays and less toward plays for dry natural gas, combined with oil production from the Eagle Ford Shale acreage, is expected to result in significantly increased oil and NGL production volumes in 2014 compared to 2013. Natural gas production for 2014 is expected to remain relatively level to 2013 as dry natural gas production coming on line as a result of continued drilling in the Arkansas Fayetteville Shale, combined with associated natural gas production from new wells coming on line in the oil and NGL rich areas noted above, are projected to offset the natural gas production decline of existing wells. As experienced previously, the timing of new wells coming on line may cause intermittent increases or decreases in oil, NGL and natural gas production from quarter to quarter.

Panhandle’s oil sales price averaged 96% of NYMEX oil price during the 2014 period. Based on this correlation and NYMEX oil futures prices, management expects the Company’s average oil sales price for 2014 to approximate $97.00 per barrel. For the 2014 period, NGL sales prices averaged 32% of NYMEX oil price; which correlates to an average NGL sales

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price for 2014 of approximately $33.00 per barrel, also in line with our expectations.

For the 2014 period, Panhandle’s natural gas sales price averaged 93% of NYMEX natural gas price. Based on NYMEX natural gas futures prices, management expects the Company’s average natural gas sales price for 2014 to approximate $4.00 per Mcf.

With continued oil and natural gas price volatility, management continues to evaluate opportunities for product price protection through additional hedging of the Company’s future oil and natural gas production. See NOTE  10  – “Derivatives” for a complete list of the Company’s outstanding derivative contracts.

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

	Nine months ended
	6/30/2014
Cash provided by operating activities	$	36,438,536
Cash provided (used) by:
Capital expenditures - acquisitions		(86,815,695)
Capital expenditures - drilling and completion of wells		(26,693,851)
Quarterly dividends of $.08 per share		(1,995,812)
Treasury stock purchases		(122,044)
Net borrowings on credit facility		77,590,538
Other investing and financing activities		242,214
Net cash used		(37,794,650)
Net increase (decrease) in cash	$	(1,356,114)

On June 17, 2014, the closing date of the Eagle Ford Shale asset acquisition, the Company increased its credit facility from $80 million to $200 million, increased the borrowing base from $35 million to $130 million and extended the maturity date to November 30, 2018. Outstanding borrowings on the credit facility at June 30, 2014, were $85,852,794.

Looking forward, the Company expects to fund overhead costs, capital additions related to the drilling and completion of wells, treasury stock purchases and dividend payments primarily from cash provided by operating activities and cash on hand. As management evaluates opportunities to acquire additional assets, additional borrowings utilizing our bank credit facility could be necessary. Also, during times of oil, NGL and natural gas price decreases, or increased capital expenditures, it may be necessary to utilize the credit facility further in order to fund these expenditures. The Company has availability ($44,147,206 at June 30, 2014) under its revolving credit facility and is in compliance with its debt covenants (current ratio, debt to EBITDA and dividends as a percent of operating cash flow). While the Company believes the availability could be increased (if needed), increases are at the discretion of the bank.

Based on expected capital expenditure levels and anticipated cash provided by operating activities for 2014, the Company has sufficient liquidity to fund its ongoing operations and, combined with availability under its credit facility, to fund acquisitions.

RESULTS OF OPERATIONS

THREE MONTHS ENDED JUNE 30, 2014 – COMPARED TO THREE MONTHS ENDED JUNE 30, 2013

Overview:

The Company recorded third quarter 2014 net income of $5,122,585, or $0.61per share, as compared to $5,070,168, or $0.61 per share, in the 2013 quarter. The increase in net income was principally the result of increased oil, NGL and natural gas sales; offset by losses on derivative contracts, increased G&A expenses and increased income taxes. These items are further discussed below.

Oil, NGL and Natural Gas Sales:

Oil, NGL and natural gas sales increased$3,707,408 or 23% for the 2014 quarter. Oil, NGL and natural gas sales were up due to increases in oil and NGL sales volumes of 27% and 146%, respectively, andincreases in oil, NGL and natural gas prices of 11%,  30% and 12%, respectively.  These increases were partially offset by a decrease in natural gas sales volumes of 9%. The following table outlines the Company’s production and average sales prices for oil, NGL and natural gas for the

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three month periods of fiscal 2014 and 2013:

	Oil Bbls	Average		Mcf	Average		NGL Bbls	Average		Mcfe	Average
	Sold	Price		Sold	Price		Sold	Price		Sold	Price
Three months ended
6/30/2014	70,479	$	97.90	2,508,346	$	4.20	63,029	$	33.51	3,309,394	$	5.90
6/30/2013	55,474	$	88.02	2,742,996	$	3.75	25,660	$	25.79	3,229,800	$	4.90

Oil production increases were principally the result of 14 days of production from the recent Eagle Ford Shale asset acquisition which closed on June 17, 2014, and to a lesser extent, drilling in the western Oklahoma horizontal Granite Wash and Marmaton oil plays. NGL production increases resulted from continued drilling in western Oklahoma and the Texas Panhandle horizontal oil plays, principally the Marmaton, Granite Wash and Cleveland. Natural gas production decreases were the result of natural decline from existing properties, principally in the Fayetteville Shale, exceeding production from new wells.

Oil production is anticipated to materially increase in the fourth quarter of 2014 and in 2015 due to existing production from our recently acquired Eagle Ford Shale properties in La Salle and Frio Counties, Texas. Projected ongoing development of this Eagle Ford Shale property, along with anticipated drilling in the Oklahoma and Texas Panhandle oil and NGL rich plays, are also expected to contribute to oil and NGL production increases in the fourth quarter of 2014 and in 2015. Natural gas production is expected to increase relative to the third quarter of 2014 primarily as the result of activity in the Fayetteville Shale where the Company has an interest in over 45 wells that are drilling or completing and are anticipated to begin production during the fourth quarter. For the full year, natural gas production is expected to remain relatively level in 2014 as compared to 2013.

Production for the last five quarters was as follows:

Quarter ended	Oil Bbls Sold	Mcf Sold	NGL Bbls Sold	Mcfe Sold
6/30/2014	70,479	2,508,346	63,029	3,309,394
3/31/2014	66,239	2,788,768	51,670	3,496,222
12/31/2013	83,413	2,785,952	37,140	3,509,270
9/30/2013	79,387	2,820,079	30,373	3,478,639
6/30/2013	55,474	2,742,996	25,660	3,229,800

Gains (Losses) on Derivative Contracts:

The fair value of derivative contracts was a net liability of $2,006,229 as of June 30, 2014, and a net asset of $814,978 as of June 30, 2013. We had a net loss on derivative contracts of $1,427,165 in the 2014 quarter as compared to a net gain of $1,714,832 recorded in the 2013 quarter. The change is principally due to the oil and natural gas collars and fixed price swaps decreasing in value as projected oil and natural gas prices at June 30, 2014, were above the ceiling prices of the collars and above the fixed price of the swaps.

Lease Operating Expenses (LOE):

LOE decreased $143,959 or 5% in the 2014 quarter. LOE per Mcfe decreased in the 2014 quarter to $0.89 compared to $0.96 in the 2013 quarter. LOE related to field operating costs increased $265,331 in the 2014 quarter compared to the 2013 quarter, a 22% increase. Field operating costs were $.45 per Mcfe in the 2014 quarter as compared to $.38 per Mcfe in the 2013 quarter. The increase in rate in the 2014 quarter is due to the large addition of oil and NGL rich wells, in recent years, which have higher lifting costs than the overall well population.

The increase in LOE related to field operating costs was offset by a decrease in handling fees (primarily gathering, transportation and marketing costs) of $409,290 in the 2014 quarter compared to the 2013 quarter. On a per Mcfe basis, these fees decreased $.14 due to significant increases in oil and NGL production, while natural gas production decreased. Natural gas sales bear the large majority of the handling fees while oil and NGL sales incur a much smaller amount. Handling fees are charged either as a percent of sales or based on production volumes.

Depreciation, Depletion and Amortization (DD&A):

DD&A increased $122,233 or 2% in the 2014 quarter. DD&A in the 2014 and 2013 quarters was $1.61 per Mcfe. The $122,233 increase was principally the result of production increasing 2% in the 2014 quarter compared to the 2013 quarter.

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General and Administrative Costs (G&A):

G&A costs increased$240,089 or 15% in the 2014 quarter. This increase is primarily related to increases in directors’ expense of $108,286 coupled with increased legal expenses of $58,506. Increase in directors’ expense was mainly due to restricted stock expense for shares awarded to directors in the 2014 quarter. The increase in legal expense was a result of additional fees for legal services associated with the Eagle Ford Shale asset acquisition.

Income Taxes:

Provision for income taxes increased in the 2014 quarter by $252,000, the result of a $304,417increase in income before provision for income taxes in the 2014 quarter compared to the 2013 quarter and an increase in the effective tax rate from 31% inthe 2013 quarter to33%  in the 2014 quarter.  Excess percentage depletion, which is a permanent tax benefit, reduced the effective tax rate below the statutory rate for both quarters.

NINE MONTHS ENDED JUNE 30, 2014 – COMPARED TO NINE MONTHS ENDED JUNE 30, 2013

Overview:

The Company recorded nine month net income of $15,703,476, or $1.88 per share, in the 2014 period, as compared to $8,240,953, or $0.99 per share, in the 2013 period. The increase in net income was principally the result of increased oil, NGL and natural gas sales; decreased DD&A expenses; partially offset by losses on derivative contracts; increased LOE, increased production taxes and increased income taxes. These items are further discussed below.

Oil, NGL and Natural Gas Sales:

Oil, NGL and natural gas sales increased$16,428,993 or 38% for the 2014period. Oil, NGL and natural gas sales were up due to increases in oil and NGL sales volumes of 42% and86%, respectively, and increases in oil, NGL and natural gas prices of 9%,  21% and 23%, respectively. The following table outlines the Company’s production and average sales prices for oil, NGL and natural gas for the nine month periods of fiscal 2014 and 2013:

	Oil Bbls	Average		Mcf	Average		NGL Bbls	Average		Mcfe	Average
	Sold	Price		Sold	Price		Sold	Price		Sold	Price
Nine months ended
6/30/2014	220,131	$	94.74	8,083,066	$	4.11	151,839	$	32.99	10,314,886	$	5.73
6/30/2013	154,697	$	86.73	8,066,250	$	3.35	81,524	$	27.22	9,483,576	$	4.50

Oil and NGL production increases resulted from continued drilling in the southern and western Oklahoma and Texas Panhandle horizontal oil plays, principally the Marmaton, Cleveland, Hogshooter, Granite Wash and the Woodford Shale in southern Oklahoma (Anadarko and Ardmore Basins). To a lesser extent, production from the recent Eagle Ford Shale asset acquisition which closed on June 17, 2014, in conjunction with horizontal oil drilling in the northern Oklahoma Mississippian, the Bakken in North Dakota and vertical oil drilling in the Permian Basin of West Texas and New Mexico contributed to the increases. Natural gas production remained relatively level for the period as new natural gas production from continued drilling in the southern and western Oklahoma and Texas Panhandle horizontal oil plays, principally the Marmaton, Cleveland, Hogshooter, Granite Wash and the Woodford Shale in southern Oklahoma (Anadarko and Ardmore Basins) offset natural decline from existing properties principally in the Fayetteville Shale.

Oil production is anticipated to materially increase in the fourth quarter of 2014 and in 2015 due to existing production from our recently acquired Eagle Ford Shale properties in La Salle and Frio Counties, Texas. Projected ongoing development of this Eagle Ford Shale property, along with anticipated drilling in the Oklahoma and Texas Panhandle oil and NGL rich plays, are also expected to contribute to oil and NGL production increases in the fourth quarter of 2014 and in 2015. Natural gas production is expected to increase relative to the third quarter of 2014 primarily as the result of activity in the Fayetteville Shale where the Company has an interest in over 45 wells that are drilling or completing and are anticipated to begin production during the fourth quarter. For the full year, natural gas production is expected to remain relatively level in 2014 as compared to 2013.

Gains (Losses) on Derivative Contracts:

The fair value of derivative contracts was a net liability of $2,006,229 as of June 30, 2014, and a net asset of $814,978 as of June 30, 2013. We had a net loss on derivative contracts of $3,511,095 in the 2014 period as compared to a net gain of $796,166 recorded in the 2013 period. The change is principally due to the oil and natural gas collars and fixed price swaps decreasing in value as projected oil and natural gas prices at June 30, 2014, were above the ceiling prices of the collars and above the fixed prices of the swaps.

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Lease Operating Expenses (LOE):

LOE increased$889,534 or 10% in the 2014period. LOE per Mcfe increased in the 2014period to $0.96 compared to $0.95 in the 2013period.  LOE related to field operating costs increased $671,330 in the 2014 period compared to the 2013 period, a 17% increase. Field operating costs were $.44 per Mcfe in the 2014 period as compared to $.41 per Mcfe in the 2013 period. This increase in rate is due to the large addition of oil and NGL rich wells which have higher lifting costs than the overall well population. The increase in amount in the 2014 period is the result of increased production.

The increase in LOE related to field operating costs was coupled with an increase in handling fees (primarily gathering, transportation and marketing costs) of $218,204 in the 2014 period compared to the 2013 period. This increase in the amount in the 2014 period is the result of increased production and sales. On a per Mcfe basis, these fees decreased $.02 due to significant increases in oil and NGL production, while gas production remained fairly flat. Natural gas sales bear the large majority of the handling fees while oil and NGL sales incur a much smaller amount. Handling fees are charged either as a percent of sales or based on production volumes.

Production Taxes:

Production taxes increased$694,197 or 59% in the 2014period as compared to the 2013period. Production taxes as a percentage of oil, NGL and natural gas sales increased from 2.8% in the 2013period to 3.2% in the 2014period.  The increase in amount is primarily the result of increased oil, NGL and natural gas sales of $16,428,993 during the 2014period. The increase in rate is due mainly to the Company receiving more ultra-deep well refunds and rate reducing corrections in the 2013 period. We do not accrue for ultra-deep well production tax exemptions (allowed by the state of Oklahoma) because we do not have sufficient information to calculate a reasonable estimate. The low overall production tax rate is due to a large proportion of the Company’s revenues coming from horizontally drilled wells, which are eligible for reduced Oklahoma and Arkansas production tax rates.

Depreciation, Depletion and Amortization (DD&A):

DD&A decreased$1,527,557 or 9% in the 2014 period. DD&A in the 2014 period was $1.51 per Mcfe as compared to $1.80 per Mcfe in the 2013 period. DD&A decreased $3,025,646 as a result of this $.29 decrease in the DD&A rate. An offsetting increase of $1,498,089 was the result of production increasing 9% in the 2014 period compared to the 2013 period. The rate decrease is mainly due to higher oil, NGL and natural gas prices utilized in the reserve calculations during the period ended June 30, 2014 (compared to June 30, 2013) increasing projected remaining reserves on a significant number of wells.

Income Taxes:

Provision for income taxes increased in the 2014period by $3,865,000, the result of an$11,327,523increase in pre-tax income in the 2014period compared to the 2013period. The effective tax rate for the 2014 and 2013periods was 32% and 31%, respectively. Excess percentage depletion, which is a permanent tax benefit, reduced the effective tax rate below the statutory rate for both periods.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Critical accounting policies are those the Company believes are most important to portraying its financial conditionsand results of operations and also require the greatest amount of subjective or complex judgments by management. Judgmentsand uncertainties regarding the application of these policies may result in materially different amounts being reported undervarious conditions or using different assumptions. There have been no material changes to the critical accounting policiespreviously disclosed in the Company’s Form 10-K for the fiscal year ended September 30, 2013.

ITEM 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk

Oil, NGL and natural gas prices historically have been volatile, and this volatility is expected to continue. Uncertainty continues to exist as to the direction of oil, NGL and natural gas price trends, and there remains a rather wide divergence in the opinions held by some in the industry. Being primarily a natural gas producer, the Company is more significantly impacted by changes in natural gas prices than by changes in oil or NGL prices.Longer term natural gas prices will be determined by the supply of and demand for natural gas as well as the prices of competing fuels, such as crude oil and coal. The market price of oil, NGL and natural gas in 2014 will impact the amount of cash generated from operating activities, which will in turn impact the level of the Company’s capital expenditures and production. Excluding the impact of the Company’s 2014 derivative contracts, based on the Company’s estimated natural gas volumes for 2014, the price sensitivity for each $0.10 per Mcf change in wellhead natural gas price is approximately $1,073,200 for operating revenue. Based on the Company’s estimated oil

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volumes for 2014, the price sensitivity in 2014 for each $1.00 per barrel change in wellhead oil price is approximately $357,000 for operating revenue.

Commodity Price Risk

The Company periodically utilizes derivative contracts to reduce its exposure to unfavorable changes in natural gas and oil prices. The Company does not enter into these derivatives for speculative or trading purposes. All of our outstanding derivative contracts are with one counterparty and are secured. These arrangements cover only a portion of the Company’s production and provide only partial price protection against declines in natural gas and oil prices. These derivative contracts expose the Company to risk of financial loss and may limit the benefit of future increases in prices. As of June 30, 2014, the Company has oil and natural gas fixed price swaps and oil and natural gas collars in place. For the Company’s oil fixed price swaps, a change of $1.00 in the NYMEX WTI forward strip prices would result in a change to pre-tax operating income of approximately $276,000. For the Company’s natural gas fixed price swaps, a change of $.10 in the NYMEX Henry Hub forward strip prices would result in a change to pre-tax operating income of approximately $153,000. For the Company’s natural gas collars, a change of $.10 in the NYMEX Henry Hub forward strip pricing would result in a change to pre-tax operating income of approximately $41,000. For the Company’s oil collars, a change of $1.00 in the NYMEX WTI forward strip prices would result in a change to pre-tax operating income of approximately $53,000.  

Financial Market Risk

Operating income could also be impacted, to a lesser extent, by changes in the market interest rates related to the Company’s credit facilities.The revolving loan bears interest at the BOK prime rate plus from 0.375% to 1.125%, or 30 day LIBOR plus from 1.875% to 2.625%.At June 30, 2014, the Company had $85,852,794outstanding under these facilities.At this point, the Company doesnot believe that its liquidity has been materially affected by the debt market uncertainties noted in the last few years and the Company does not believe that its liquidity will be impacted in the near future.

ITEM 4 CONTROLS AND PROCEDURES

The Company maintains “disclosure controls and procedures,” as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, that are designed to ensure that information required to be disclosed in reports the Company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is collected and communicated to management, including the Company’s President/Chief Executive Officer and Vice President/Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.In designing and evaluating its disclosure controls and procedures, management recognized that no matter how well conceived and operated, disclosure controls and procedures can provide only reasonable, not absolute, assurance that the objectives of the disclosure controls and procedures are met.The Company’s disclosure controls and procedures have been designed to meet, and management believes they do meet, reasonable assurance standards.Based on their evaluation as of the end of the fiscal period covered by this report, the Chief Executive Officer and Chief Financial Officer have concluded, subject to the limitations noted above, the Company’s disclosure controls and procedures were effective to ensure material information relating to the Company is made known to them.There were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting made during the fiscal quarter or subsequent to the date the assessment was completed.

PART II OTHER INFORMATION

ITEM 2UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

During the three months ended June 30, 2014, the Company did not repurchase shares of the Company’s common stock.

Upon approval by the shareholders of the Company’s 2010 Restricted Stock Plan on March 11, 2010, as amended March 5, 2014, the Board of Directors approved repurchase of up to $1.5 million of the Company’s common stock, from time to time, up to an amount 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.Pursuant to previously adopted board resolutions, the purchase of an additional $1.5 million of the Company’s common stock became authorized and approved effective June 26, 2013. The shares are held in treasury and are accounted for using the cost method. Effective May 14, 2014, the Board adopted resolutions to allow management to repurchase the Company’s common stock at their discretion.

ITEM 6 EXHIBITS

(a) EXHIBITS Exhibit 31.1 and 31.2 – Certification under Section 302 of the Sarbanes-Oxley Act of 2002

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		Exhibit 32.1 and 32.2 – Certification under Section 906 of the Sarbanes-Oxley Act of 2002
		Exhibit 101.INS – XBRL Instance Document
		Exhibit 101.SCH – XBRL Taxonomy Extension Schema Document
		Exhibit 101.CAL – XBRL Taxonomy Extension Calculation Linkbase Document
		Exhibit 101.LAB – XBRL Taxonomy Extension Labels Linkbase Document
		Exhibit 101.PRE – XBRL Taxonomy Extension Presentation Linkbase Document
		Exhibit 101.DEF – XBRL Taxonomy Extension Definition Linkbase Document
(b)	Form 8-K	Dated (5/16/14), item 1.01 – Enters Into a Material Definitive Agreement
	Form 8-K	Dated (6/19/14), item 1.01 – Enters Into a Material Definitive Agreement; item 2.01 Completion of Acquisition or Disposition of Assets

SIGNATURES

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

PANHANDLE OIL AND GAS INC.
	PANHANDLE OIL AND GAS INC.
August 7, 2014	/s/ Michael C. Coffman
Date	Michael C. Coffman, President and
	Chief Executive Officer
August 7, 2014	/s/ Lonnie J. Lowry
Date	Lonnie J. Lowry, Vice President
	and Chief Financial Officer
August 7, 2014	/s/ Robb P. Winfield
Date	Robb P. Winfield, Controller
	and Chief Accounting Officer

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EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Michael C. Coffman, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Panhandle Oil and Gas Inc. (the Company);

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(s) 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 (the registrant’s fourth fiscal quarter in the case of an annual report) 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(s) 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:August 7, 2014

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Lonnie J. Lowry, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Panhandle Oil and Gas Inc. (the Company);

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(s) 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 (the registrant’s fourth fiscal quarter in the case of an annual report) 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(s) 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:August 7, 2014

EX-32.1

EXHIBIT 32.1

Panhandle Oil and Gas Inc.

5400 North Grand Blvd. Suite #300

Oklahoma City, OK73112

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

REGARDING PERIODIC REPORT CONTAINING

FINANCIAL STATEMENTS

I, Michael C. Coffman, Chief Executive Officer of Panhandle Oil and Gas Inc., (the “Issuer”), 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 Issuer’s Quarterly Report on Form 10-Q for the period that ended June 30, 2014,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 Issuer.

/s/ Michael C. Coffman

Michael C. Coffman

President &

Chief Executive Officer

August 7, 2014

EX-32.2

EXHIBIT 32.2

Panhandle Oil and Gas Inc.

5400 North Grand Blvd. Suite #300

Oklahoma City, OK73112

CERTIFICATION OF CHIEF FINANCIAL OFFICER

REGARDING PERIODIC REPORT CONTAINING

FINANCIAL STATEMENTS

I, Lonnie J. Lowry, Chief Financial Officer of Panhandle Oil and Gas Inc., (the “Issuer”), 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 Issuer’s Quarterly Report on Form 10-Q for the period that ended June 30, 2014,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 Issuer.

/s/ Lonnie J. Lowry

Lonnie J. Lowry

Vice-President &

Chief Financial Officer

August 7, 2014

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Fair Value Measurements (Summary Of Impairments Associated With Certain Assets Measured At Fair Value On A Nonrecurring Basis Within Level 3) (Details) (USD $)	3 Months Ended			9 Months Ended
	Jun. 30, 2014	Jun. 30, 2013		Jun. 30, 2014		Jun. 30, 2013
Fair Value Measurements [Abstract]
Producing Properties, Fair Value		$ 14,849	[1]	$ 628,097	[1]	$ 356,855	[1]
Producing Properties, Impairment	$ 0	$ 7,400	[1]	$ 430,143	[1]	$ 225,841	[1]

[1] At the end of each quarter, the Company assesses the carrying value of its producing properties for impairment. This assessment utilizes estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of future oil 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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Derivatives (Narrative) (Details) (USD $)	Jun. 30, 2014		Sep. 30, 2013
Derivatives [Abstract]
Net liability	$ 2,006,229
Net asset		[1]	$ 425,198	[1]

[1] See Fair Value Measurements section for further disclosures regarding fair value of financial instruments.

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Income Taxes (Details)	3 Months Ended		9 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Income Taxes [Abstract]
Effective tax rate	33.00%	31.00%	32.00%	31.00%

XML

Fair Value Measurements (Summary Of Unobservable Inputs For Level 3 Fair Value Measurements) (Details) (USD $)	9 Months Ended
	Jun. 30, 2014
Oil Costless Collars [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Unobservable Input	Oil price volatility curve
Weighted Average	6.30%
Fair Value	$ (386,098)
Oil Costless Collars [Member] | Minimum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Range	0.00%
Oil Costless Collars [Member] | Maximum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Range	10.30%
Natural Gas Costless Collars [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Unobservable Input	Natural gas price volatility curve
Weighted Average	11.40%
Fair Value	$ (136,915)
Natural Gas Costless Collars [Member] | Minimum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Range	0.00%
Natural Gas Costless Collars [Member] | Maximum [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Range	18.10%

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Income Taxes

9 Months Ended

Jun. 30, 2014

Income Taxes [Abstract]

Income Taxes

NOTE 2: Income Taxes

The Company’s provision for income taxes differs from the statutory rate primarily due to estimated federaland statebenefits generated from estimated excess federal and Oklahoma percentage depletion, which are permanent tax benefits.

Both excess federal percentage depletion, which is limited to certain production volumes and by certain income levels, and excess Oklahoma percentage depletion, which hasno limitation on production volume, reduce estimated taxable income or add to estimated taxable loss projected for any year.The federal and Oklahoma excess percentage depletion estimates will be updated throughout the year until finalized with detailed well-by-well calculations at fiscal year-end.  Federal and Oklahoma excess percentage depletion, when a provision for income taxes is recorded, decreases the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is recorded.The benefits of federal and Oklahoma excess percentage depletion are not directly related to the amount of pre-tax income recorded in a period.Accordingly, in periods where a recorded pre-tax income or loss is relatively small, the proportional effect of these items on the effective tax rate may be significant. The effective tax rate for the nine months ended June 30, 2014, was 32% as compared to 31% for the nine months ended June 30, 2013.  The effective tax rate for the quarter ended June 30, 2014, was 33% as compared to 31% for the quarter ended June 30, 2013.

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Restricted Stock Plan (Summary Of Unrecognized Compensation Cost) (Details) (USD $)	9 Months Ended
	Jun. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	$ 715,360
Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	350,815
Weighted Average Period	1 year 7 months 13 days
Non Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	$ 364,545
Weighted Average Period	1 year 3 months 4 days

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Restricted Stock Plan (Summary Of Pre-Tax Compensation Expense) (Details) (USD $)	3 Months Ended		9 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 237,617	$ 142,030	$ 499,791	$ 541,937
Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	76,520	81,822	226,800	263,583
Non Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 161,097	$ 60,208	$ 272,991	$ 278,354

XML

Oil, NGL And Natural Gas Reserves (Details)	9 Months Ended
	Jun. 30, 2014
Oil, NGL And Natural Gas Reserves [Abstract]
Computation of Oil, Natural Gas and NGL Reserves	12 months

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Impairment (Details) (USD $)	3 Months Ended			9 Months Ended
	Jun. 30, 2014	Jun. 30, 2013		Jun. 30, 2014		Jun. 30, 2013
Impairment [Abstract]
Impairment	$ 0	$ 7,400	[1]	$ 430,143	[1]	$ 225,841	[1]

[1] At the end of each quarter, the Company assesses the carrying value of its producing properties for impairment. This assessment utilizes estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of future oil 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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Accounting Principles And Basis Of Presentation

9 Months Ended

Jun. 30, 2014

Accounting Principles And Basis Of Presentation [Abstract]

Accounting Principles And Basis Of Presentation

NOTE 1: Accounting Principles and Basis of Presentation

The accompanying unaudited condensed financial statements of Panhandle Oil and Gas Inc. have been prepared in accordance with the instructions to Form 10-Q as prescribed by the SEC. Management of the Company believes that all adjustments necessary for a fair presentation of the financial position and results of operations and cash flows for the periods have been included. All such adjustments are of a normal recurring nature. The results are not necessarily indicative of those to be expected for the full year. The Company’s fiscal year runs from October 1 through September 30.

Certain amounts and disclosures have been condensed or omitted from these financial statements pursuant to the rules and regulations of the SEC. Therefore, these condensed financial statements should be read in conjunction with the financial statements and related notes thereto included in the Company’s 2013 Annual Report on Form 10-K.

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Capitalized Costs (Details) (USD $)	Jun. 30, 2014	Jun. 30, 2013
Capitalized Costs [Abstract]
Cost of Non-Producing Oil and Natural Gas Properties	$ 888,505	$ 0

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Acquisitions (Narrative) (Details) (USD $)	3 Months Ended	9 Months Ended		0 Months Ended	9 Months Ended
	Jun. 30, 2014	Jun. 30, 2014	Jun. 17, 2014 item	Jun. 17, 2014 Eagle Ford Shale [Member] acre item	Jun. 30, 2014 Eagle Ford Shale [Member]	Jun. 17, 2014 Pearsall [Member] item	Jun. 17, 2014 Buda [Member] item
Acquisitions (Textual) [Abstract]
Date of business acquisition					Jun. 17, 2014
Acquired average working interest				16.00%
Number of gross acres				11,100
Number of net acres				1,775
Producing non-operated natural gas wells			63	57		5	1
Undeveloped locations				109
Purchase price business acquisition				$ 81,700,000
Revenues attributable	1,011,909	1,011,909
Net income attributable	$ 388,128	$ 388,128

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Condensed Balance Sheets (USD $)	Jun. 30, 2014		Sep. 30, 2013
Current Assets:
Cash and cash equivalents	$ 1,511,057		$ 2,867,171
Oil, NGL and natural gas sales receivables	15,070,653		13,720,761
Refundable income taxes	3,160,243
Refundable production taxes	760,947		662,051
Derivative contracts, net		[1]	425,198	[1]
Other	3,660,589		129,998
Total current assets	24,163,489		17,805,179
Properties and equipment at cost, based on successful efforts accounting:
Producing oil and natural gas properties	408,816,025		304,889,145
Non-producing oil and natural gas properties	9,544,840		8,932,905
Other	1,305,473		737,368
Total properties and equipment, at cost, based on successful efforts accounting	419,666,338		314,559,418
Less accumulated depreciation, depletion and amortization	(198,439,791)		(186,641,291)
Net properties and equipment	221,226,547		127,918,127
Investments	1,653,406		1,574,642
Refundable production taxes	159,845		540,482
Total assets	247,203,287		147,838,430
Current Liabilities:
Accounts payable	8,031,138		8,409,634
Derivative contracts, net	1,944,091	[1]		[1]
Deferred income taxes	9,100		127,100
Income taxes payable			751,992
Accrued liabilities and other	1,111,910		1,011,865
Total current liabilities	11,096,239		10,300,591
Long-term debt	85,852,794		8,262,256
Deferred income taxes	37,308,907		31,226,907
Asset retirement obligations	2,855,520		2,393,190
Derivative contracts, net	62,138	[1]
Stockholders' equity:
Class A voting common stock, $.0166 par value; 24,000,000 shares authorized, 8,431,502 issued at June 30, 2014, and September 30, 2013	140,524		140,524
Capital in excess of par value	2,767,615		2,587,838
Deferred directors' compensation	3,026,134		2,756,526
Retained earnings	110,162,113		96,454,449
Stockholders' Equity	116,096,386		101,939,337
Less treasury stock, at cost; 192,874 shares at June 30, 2014, and 200,248 shares at September 30, 2013	(6,068,697)		(6,283,851)
Total stockholders' equity	110,027,689		95,655,486
Total liabilities and stockholders' equity	$ 247,203,287		$ 147,838,430

[1] See Fair Value Measurements section for further disclosures regarding fair value of financial instruments.

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Statements Of Stockholders' Equity (Parenthetical) (Retained Earnings [Member], USD $)	9 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Retained Earnings [Member]
Dividends per share	$ 0.24	$ 0.21

XML

Derivatives (Summary Of Derivative Contracts) (Details) (USD $)	Jun. 30, 2014		Sep. 30, 2013
Derivatives [Abstract]
Gross amounts recognized - Current Assets	$ 15,871	[1]	$ 665,099	[1]
Gross amounts recognized - Current Liabilities	1,959,962	[1]	239,901	[1]
Gross amounts recognized - Non-Current Liabilities	62,138	[1]
Net presentation on Condensed Balance - Current Assets		[1]	425,198	[1]
Net presentation on Condensed Balance - Current Liabilities	1,944,091	[1]		[1]
Net presentation on Condensed Balance - Non-Current Liabilities	$ 62,138	[1]

[1] See Fair Value Measurements section for further disclosures regarding fair value of financial instruments.

XML

Derivatives (Tables)

9 Months Ended

Jun. 30, 2014

Derivatives [Abstract]

Summary Of Derivative Instruments Contracts

Derivative contracts in place as of June 30, 2014

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
July - December 2014	140,000 Mmbtu	NYMEX Henry Hub	$3.75 floor / $4.50 ceiling
Natural gas fixed price swaps
July - December 2014	140,000 Mmbtu	NYMEX Henry Hub	$4.11
April - September 2014	50,000 Mmbtu	NYMEX Henry Hub	$4.20
April - September 2014	50,000 Mmbtu	NYMEX Henry Hub	$4.18
April - September 2014	50,000 Mmbtu	NYMEX Henry Hub	$4.21
May - October 2014	30,000 Mmbtu	NYMEX Henry Hub	$4.30
October - December 2014	40,000 Mmbtu	NYMEX Henry Hub	$4.61
Oil costless collars
January - December 2014	4,000 Bbls	NYMEX WTI	$85.00 floor / $100.00 ceiling
July - December 2014	5,000 Bbls	NYMEX WTI	$90.00 floor / $97.00 ceiling
Oil fixed price swaps
January - December 2014	3,000 Bbls	NYMEX WTI	$94.50
July - December 2014	4,000 Bbls	NYMEX WTI	$95.25
July - December 2014	5,000 Bbls	NYMEX WTI	$94.20
January - March 2015	6,000 Bbls	NYMEX WTI	$92.85
June - December 2014	4,000 Bbls	NYMEX WTI	$99.40
January - June 2015	7,000 Bbls	NYMEX WTI	$96.80
January - June 2015	5,000 Bbls	NYMEX WTI	$97.40
April - December 2015	5,000 Bbls	NYMEX WTI	$94.56
July - December 2015	7,000 Bbls	NYMEX WTI	$93.91

Derivative contracts in place as of September 30, 2013

	Production volume
Contract period	covered per month	Index	Contract 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	$105.25

Summary Of Derivative Contracts

	6/30/2014						9/30/2013
	Fair Value (a)						Fair Value (a)
	Commodity Contracts						Commodity Contracts
	Current Assets		Current Liabilities			Non-Current Liabilities	Current Assets		Current Liabilities
Gross amounts recognized	$	15,871	$	1,959,962	$	62,138	$	665,099	$	239,901
Offsetting adjustments		(15,871)		(15,871)		-		(239,901)		(239,901)
Net presentation on Condensed Balance Sheets	$	-	$	1,944,091	$	62,138	$	425,198	$	-

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

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Fair Value Measurements (Summary Of Fair Value Measurement Information For Financial Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Details) (USD $)	Jun. 30, 2014
Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial Assets (Liabilities)	$ (1,483,216)
Collars [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial Assets (Liabilities)	(523,013)
Fair Value, Inputs, Level 1 [Member] | Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial Assets (Liabilities)
Fair Value, Inputs, Level 1 [Member] | Collars [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial Assets (Liabilities)
Fair Value, Inputs, Level 2 [Member] | Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial Assets (Liabilities)	(1,483,216)
Fair Value, Inputs, Level 3 [Member] | Collars [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial Assets (Liabilities)	$ (523,013)

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Acquisitions (Tables)

9 Months Ended

Jun. 30, 2014

Acquisitions [Abstract]

Summary Of Pro Forma Financial Information

	For the Nine Months Ended
	June 30,
	2014		2013
Revenue:
As reported	$	56,523,778	$	44,492,866
Pro forma revenue		16,811,606		14,862,947
Pro forma	$	73,335,384	$	59,355,813
Net Income:
As reported	$	15,703,476	$	8,240,953
Pro forma income		6,485,185		5,771,157
Pro forma	$	22,188,661	$	14,012,110

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Condensed Statements Of Cash Flows (USD $)	9 Months Ended
	Jun. 30, 2014		Jun. 30, 2013
Operating Activities
Net income (loss)	$ 15,703,476		$ 8,240,953
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	15,562,630		17,090,187
Impairment	430,143	[1]	225,841	[1]
Provision for deferred income taxes	5,964,000		2,651,000
Exploration costs	70,140		60,827
Gain from leasing fee mineral acreage	(352,930)		(538,133)
Net (gain) loss on sales of assets	152,766		(208,750)
Income from partnerships	(565,523)		(470,286)
Distributions received from partnerships	734,825		603,249
Directors' deferred compensation expense	269,608		288,759
Restricted stock awards	499,791		541,937
Cash provided (used) by changes in assets and liabilities:
Oil, NGL and natural gas sales receivables	(1,349,892)		(3,885,005)
Fair value of derivative contracts	2,431,427		(987,249)
Refundable production taxes	281,741		253,048
Other current assets	(25,098)		78,889
Accounts payable	443,438		(48,038)
Income taxes receivable	(3,160,243)		325,715
Income taxes payable	(751,992)		50,854
Accrued liabilities	100,229		(80,584)
Total adjustments	20,735,060		15,952,261
Net cash provided by operating activities	36,438,536		24,193,214
Investing Activities
Capital expenditures, including dry hole costs	(26,693,851)		(20,576,359)
Acquisition of working interest properties	(86,759,445)
Acquisition of minerals and overrides	(56,250)		(783,750)
Proceeds from leasing fee mineral acreage	381,280		557,196
Investments in partnerships	(248,066)		(607,702)
Proceeds from sales of assets	92,000		870,610
Net cash used in investing activities	(113,284,332)		(20,540,005)
Financing Activities
Borrowings under debt agreement	95,112,044		9,353,651
Payments of loan principal	(17,521,506)		(10,663,399)
Purchases of treasury stock	(122,044)		(1,214,638)
Payments of dividends	(1,995,812)		(1,746,217)
Excess tax benefit on stock-based compensation	17,000		15,000
Net cash provided by (used in) financing activities	75,489,682		(4,255,603)
Increase (decrease) in cash and cash equivalents	(1,356,114)		(602,394)
Cash and cash equivalents at beginning of period	2,867,171		1,984,099
Cash and cash equivalents at end of period	1,511,057		1,381,705
Supplemental Schedule of Noncash Investing and Financing Activities:
Additions to asset retirement obligations	370,536		119,166
Gross additions to properties and equipment	109,182,119		21,660,852
Net (increase) decrease in accounts payable for properties and equipment additions	4,327,427		(300,743)
Capital expenditures and acquisitions, including dry hole costs	$ 113,509,546		$ 21,360,109

[1] At the end of each quarter, the Company assesses the carrying value of its producing properties for impairment. This assessment utilizes estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of future oil 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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Condensed Balance Sheets (Parenthetical) (USD $)	Jun. 30, 2014	Sep. 30, 2013
Condensed 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	192,874	200,248

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Derivatives

9 Months Ended

Jun. 30, 2014

Derivatives [Abstract]

Derivatives

NOTE 10:Derivatives

The Company has entered into fixed swap contracts and costless collar contracts.  These instruments are intended to reduce the Company’s exposure to short-term fluctuations in the price of oil and natural gas.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.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. These contracts cover only a portion of the Company’s natural gas and oil production and provide only partial price protection against declines in natural gas and oil prices.These derivative instruments may expose the Company to risk of financial loss and 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.

Derivative contracts in place as of June 30, 2014

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
July - December 2014	140,000 Mmbtu	NYMEX Henry Hub	$3.75 floor / $4.50 ceiling
Natural gas fixed price swaps
July - December 2014	140,000 Mmbtu	NYMEX Henry Hub	$4.11
April - September 2014	50,000 Mmbtu	NYMEX Henry Hub	$4.20
April - September 2014	50,000 Mmbtu	NYMEX Henry Hub	$4.18
April - September 2014	50,000 Mmbtu	NYMEX Henry Hub	$4.21
May - October 2014	30,000 Mmbtu	NYMEX Henry Hub	$4.30
October - December 2014	40,000 Mmbtu	NYMEX Henry Hub	$4.61
Oil costless collars
January - December 2014	4,000 Bbls	NYMEX WTI	$85.00 floor / $100.00 ceiling
July - December 2014	5,000 Bbls	NYMEX WTI	$90.00 floor / $97.00 ceiling
Oil fixed price swaps
January - December 2014	3,000 Bbls	NYMEX WTI	$94.50
July - December 2014	4,000 Bbls	NYMEX WTI	$95.25
July - December 2014	5,000 Bbls	NYMEX WTI	$94.20
January - March 2015	6,000 Bbls	NYMEX WTI	$92.85
June - December 2014	4,000 Bbls	NYMEX WTI	$99.40
January - June 2015	7,000 Bbls	NYMEX WTI	$96.80
January - June 2015	5,000 Bbls	NYMEX WTI	$97.40
April - December 2015	5,000 Bbls	NYMEX WTI	$94.56
July - December 2015	7,000 Bbls	NYMEX WTI	$93.91

Derivative contracts in place as of September 30, 2013

	Production volume
Contract period	covered per month	Index	Contract 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	$105.25

The Company has elected not to complete all of the documentation requirements necessary to permit these derivative contracts to be accounted for as cash flow hedges. The Company’s fair value of derivative contracts was a net liability of $2,006,229 as of June 30, 2014, and a net asset of $425,198 as of September 30, 2013.

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 June 30, 2014, and September 30, 2013. 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 June 30, 2014, and September 30, 2013.

	6/30/2014						9/30/2013
	Fair Value (a)						Fair Value (a)
	Commodity Contracts						Commodity Contracts
	Current Assets		Current Liabilities			Non-Current Liabilities	Current Assets		Current Liabilities
Gross amounts recognized	$	15,871	$	1,959,962	$	62,138	$	665,099	$	239,901
Offsetting adjustments		(15,871)		(15,871)		-		(239,901)		(239,901)
Net presentation on Condensed Balance Sheets	$	-	$	1,944,091	$	62,138	$	425,198	$	-

(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. The impact of credit risk was immaterial for all periods presented.

XML

Document and Entity Information	9 Months Ended
	Jun. 30, 2014	Aug. 07, 2014
Document and Entity Information [Abstract]
Entity Registrant Name	PANHANDLE OIL & GAS INC
Entity Central Index Key	0000315131
Document Type	10-Q
Document Period End Date	Jun. 30, 2014
Amendment Flag	false
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--09-30
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		8,238,628

XML

Fair Value Measurements

9 Months Ended

Jun. 30, 2014

Fair Value Measurements [Abstract]

Fair Value Measurements

NOTE 11: 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 as of June 30, 2014.

	Fair Value Measurement at June 30, 2014
	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	$	-	$	(1,483,216)	$	-	$	(1,483,216)
Derivative Contracts - Collars	$	-	$	-	$	(523,013)	$	(523,013)

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

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

The significant unobservable inputs for Level 3 derivative contracts include market volatility and credit risk of counterparties. Changes in these inputs will impact the fair value measurement of our derivative contracts. An increase (decrease) in the 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 June 30, 2014
Oil Collars	Oil price volatility curve	0% - 10.30%	6.30%	$	(386,098)
Natural Gas Collars	Natural gas price volatility curve	0% - 18.10%	11.40%	$	(136,915)

A reconciliation of the Company’s derivative contracts classified as Level 3 measurements is presented below. All gains and losses are presented on the Gains (losses) on derivative contracts line item on our Statement of Operations.

	Derivatives
Balance of Level 3 as of October 1, 2013	$	242,902
Total gains or (losses)
Included in earnings		(78,976)
Included in other comprehensive income (loss)		-
Purchases, issuances and settlements		(686,939)
Transfers in and out of Level 3		-
Balance of Level 3 as of June 30, 2014	$	(523,013)

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.

	Quarter Ended June 30,
	2014				2013
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	-	$	-	$	14,849	$	7,400
	Nine Months Ended June 30,
	2014				2013
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	628,097	$	430,143	$	356,855	$	225,841

(a) At the end of each quarter, the Company assesses the carrying value of its producing properties for impairment. This assessment utilizes estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of future oil 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 June 30, 2014, and September 30, 2013, 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.

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Condensed Statements Of Operations (USD $)	3 Months Ended		9 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Revenues:
Oil, NGL and natural gas sales	$ 19,534,545	$ 15,827,137	$ 59,115,928	$ 42,686,935
Lease bonuses and rentals	137,476	24,146	353,422	539,479
Gains (losses) on derivative contracts	(1,427,165)	1,714,832	(3,511,095)	796,166
Income from partnerships	130,121	164,330	565,523	470,286
Total revenues	18,374,977	17,730,445	56,523,778	44,492,866
Costs and expenses:
Lease operating expenses	2,961,750	3,105,709	9,930,147	9,040,613
Production taxes	593,941	460,902	1,871,538	1,177,341
Exploration costs	6,956	25,648	70,140	60,827
Depreciation, depletion and amortization	5,314,777	5,192,544	15,562,630	17,090,187
Provision for impairment		7,400	430,143	225,841
Loss (gain) on asset sales, interest and other	44,594	29,789	71,783	(138,921)
General and administrative	1,825,374	1,585,285	5,349,921	5,127,025
Total costs and expenses	10,747,392	10,407,277	33,286,302	32,582,913
Income before provision for income taxes	7,627,585	7,323,168	23,237,476	11,909,953
Provision for income taxes	2,505,000	2,253,000	7,534,000	3,669,000
Net income	$ 5,122,585	$ 5,070,168	$ 15,703,476	$ 8,240,953
Basic and diluted earnings per common share (Note 3)	$ 0.61	$ 0.61	$ 1.88	$ 0.99
Basic and diluted weighted average shares outstanding:
Common shares	8,237,020	8,163,520	8,235,186	8,247,642
Unissued, directors' deferred compensation shares	127,835	116,762	126,051	113,259
Basic and diluted weighted average shares outstanding	8,364,855	8,280,282	8,361,237	8,360,901
Dividends declared per share of common stock and paid in period	$ 0.08	$ 0.07	$ 0.24	$ 0.21

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Deferred Compensation Plan For Directors

9 Months Ended

Jun. 30, 2014

Deferred Compensation Plan For Directors [Abstract]

Deferred Compensation Plan For Directors

NOTE 5: Deferred Compensation Plan for Directors

The Company has a deferred compensation plan for non-employee directors (the Plan). The Plan provides that each eligible director can individually elect to be credited with future unissued shares of Company stock rather than cash for Board and committee chair retainers, Board meeting fees and Board committee meeting fees. These unissued shares are credited to each director’s deferred fee account at the closing market price of the stock on the date earned. Upon retirement, termination or death of the director, or upon a change in control of the Company, the unissued shares credited under the Plan will be issued to the director.

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Long-Term Debt

9 Months Ended

Jun. 30, 2014

Long-Term Debt [Abstract]

Long-Term Debt

NOTE 4: Long-term Debt

On June 17, 2014, the closing date of the Eagle Ford Shale asset acquisition, the Company increased its credit facility with a group of banks headed by Bank of Oklahoma (BOK) from $80,000,000 to $200,000,000, increased the borrowing base from $35,000,000 to $130,000,000 and extended the maturity date to November 30, 2018. The Company incurred $542,500 of debt issuance costs to increase its credit facility. These costs were capitalized and will be amortized over the term of the facility. The credit facility 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. The facility is secured by certain of the Company’s properties with a carrying value of $163,288,413 at June 30, 2014. The interest rate is based on BOK prime plus from 0.375% to 1.125%, or 30 day LIBOR plus from 1.875% to 2.625%. The election of BOK prime or LIBOR is at the Company’s discretion. The interest rate spread from BOK prime or LIBOR will be charged based on the ratio of the loan balance to the borrowing base. The interest rate spread from LIBOR or the prime rate increases as a larger percent of the borrowing base is advanced. At June 30, 2014, the effective interest rate was 2.58%.

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 $130,000,000. 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), 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 June 30, 2014, the Company was in compliance with the covenants of the BOK agreement.

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Fair Value Measurements (Tables)

9 Months Ended

Jun. 30, 2014

Fair Value Measurements [Abstract]

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

	Fair Value Measurement at June 30, 2014
	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	$	-	$	(1,483,216)	$	-	$	(1,483,216)
Derivative Contracts - Collars	$	-	$	-	$	(523,013)	$	(523,013)

Summary Of Unobservable Inputs For Level 3 Fair Value Measurements

Instrument Type	Unobservable Input	Range	Weighted Average	Fair Value June 30, 2014
Oil Collars	Oil price volatility curve	0% - 10.30%	6.30%	$	(386,098)
Natural Gas Collars	Natural gas price volatility curve	0% - 18.10%	11.40%	$	(136,915)

Summary Of Reconciliation Of Assets Classified As Level 3 Measurements

	Derivatives
Balance of Level 3 as of October 1, 2013	$	242,902
Total gains or (losses)
Included in earnings		(78,976)
Included in other comprehensive income (loss)		-
Purchases, issuances and settlements		(686,939)
Transfers in and out of Level 3		-
Balance of Level 3 as of June 30, 2014	$	(523,013)

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

	Quarter Ended June 30,
	2014				2013
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	-	$	-	$	14,849	$	7,400
	Nine Months Ended June 30,
	2014				2013
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	628,097	$	430,143	$	356,855	$	225,841

(a) At the end of each quarter, the Company assesses the carrying value of its producing properties for impairment. This assessment utilizes estimates of future cash flows. Significant judgments and assumptions in these assessments include estimates of future oil 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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Acquisitions

9 Months Ended

Jun. 30, 2014

Acquisitions [Abstract]

Acquisitions

NOTE 12: Acquisitions

On June 17, 2014,  the Company closed an acquisition of certain Eagle Ford Shale assets located in LaSalle and Frio Counties, Texas, in the core of the Eagle Ford Shale. The assets were purchased from private sellers and included a 16% non-operated working interest in 11,100 gross (1,775 net) acres. The acreage is largely contiguous, entirely held by production and contains 63 producing wells (57 Eagle Ford, 5 Pearsall and 1 Buda) and 109 undeveloped Eagle Ford locations. The adjusted purchase price at closing was  $81.7 million and was funded by utilizing the Company’s bank credit facility. The purchase price was allocated to the producing wells and undeveloped locations based on fair value determined by estimated reserves and adjusted for working capital. The purchase price allocation is preliminary, pending the finalization of working capital adjustments. Adjustments to the estimated fair values may be recorded during the allocation period, not to exceed one year from the date of acquisition.

Actual and Pro Forma Impact of Acquisitions (Unaudited)

Revenues attributable to this acquisition (June 17, 2014, through June 30, 2014)  included in the Company’s statement of operations for the quarter and nine months ended June 30, 2014, were $1,011,909. Net income attributable to the acquisition included in the statement of operations for the quarter and nine months ended June 30, 2014, was $388,128.

The following table presents the unaudited pro forma financial information assuming the Company had acquired this business on October 1, 2012:

	For the Nine Months Ended
	June 30,
	2014		2013
Revenue:
As reported	$	56,523,778	$	44,492,866
Pro forma revenue		16,811,606		14,862,947
Pro forma	$	73,335,384	$	59,355,813
Net Income:
As reported	$	15,703,476	$	8,240,953
Pro forma income		6,485,185		5,771,157
Pro forma	$	22,188,661	$	14,012,110

The unaudited pro forma financial information is for informational purposes only and does not purport to present what our results would actually have been had this transaction actually occurred on the date presented or to project our results of operations or financial position for any future period.

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Impairment

9 Months Ended

Jun. 30, 2014

Impairment [Abstract]

Impairment

NOTE 8: Impairment

All long-lived assets, principally oil and natural gas properties, are monitored for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its estimated future net cash flows. The evaluations involve significant judgment since the results are based on estimated future events, such as inflation rates, future sales prices for oil, NGL and natural gas, future production costs, estimates of future oil, NGL and natural gas reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. The need to test a property for impairment may result from significant declines in sales prices or unfavorable adjustments to oil, NGL and natural gas reserves. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing updated projected future price decks current with the period. For the three months ended June 30, 2014 and 2013, the assessment resulted in impairment provisions of $0 and $7,400, respectively.For the nine months ended June 30, 2014 and 2013, the assessment resulted in impairment provisions of $430,143 and $225,841, respectively. A reduction in oil, NGL or natural gas prices, or a decline in reserve volumes, could lead to additional impairment that may be material to the Company.

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Restricted Stock Plan

9 Months Ended

Jun. 30, 2014

Restricted Stock Plan [Abstract]

Restricted Stock Plan

NOTE 6: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. On March 5, 2014, shareholders approved an amendment to increase the number of shares of common stock reserved for issuance under the 2010 Stock Plan from 100,000 shares to 250,000 shares and to allow the grant of shares of restricted stock to our directors. The 2010 Stock Plan, as amended, is designed to provide as much flexibility as possible for future grants of restricted stock so that the Company can respond as necessary to provide competitive compensation in order to retain, attract and motivate directors and officers of the Company and to align their interests with those of the Company’s shareholders.

Effective May 14, 2014, the board of directors approved for management, at their discretion, to purchase the Company’s common stock, from time to time, up to an amount 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.

On December 21, 2013, the Company awarded 6,093 non-performance based shares and 18,279 performance based shares of the Company’s common stock as restricted stock to certain officers. The restricted stock vests at the end of three years and contains nonforfeitable rights to receive dividends and voting rights during the vesting period. The non-performance and performance based shares had a fair value on their award date of $199,788 and $294,889, respectively, and will be recognized as compensation expense ratably over the vesting period. The fair value of the performance based shares on their award date is calculated by simulating the Company’s stock price and stock price return utilizing a Monte Carlo model covering the period from the grant date through the end of the performance period (December 21, 2013, through December 21, 2016).

On May 29, 2014, the Company awarded 3,918 non-performance based shares of the Company’s common stock as restricted stock to its non-employee directors.  One-quarter of the restricted stock vested immediately on May 29, 2014, and an additional quarter vested on June 30, 2014. The remainder will vest over the next six months. The restricted stock contains nonforfeitable rights to receive dividends and voting rights during the vesting period. These non-performance based shares had a fair value on their award date of $210,120.

The following table summarizes the Company’s pre-tax compensation expense for the three and nine months ended June 30, 2014 and 2013, related to the Company’s performance based and non-performance based restricted stock.

	Three Months Ended				Nine Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
Performance based, restricted stock	$	76,520	$	81,822	$	226,800	$	263,583
Non-performance based, restricted stock		161,097		60,208		272,991		278,354
Total compensation expense	$	237,617	$	142,030	$	499,791	$	541,937

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.

	As of June 30, 2014
	Unrecognized Compensation Cost		Weighted Average Period (in years)
Performance based, restricted stock	$	350,815	1.62
Non-performance based, restricted stock		364,545	1.26
Total	$	715,360

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

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Oil, NGL And Natural Gas Reserves

9 Months Ended

Jun. 30, 2014

Oil, NGL And Natural Gas Reserves [Abstract]

Oil, NGL And Natural Gas Reserves

NOTE 7: Oil, NGL and Natural Gas Reserves

Management considers the estimation of the Company’s crude oil, NGL and natural gas reserves to be the most significant of its judgments and estimates. Changes in crude oil, NGL and natural gas reserve estimates affect the Company’s calculation of DD&A, provision for abandonment and assessment of the need for asset impairments. On an annual basis, with a semi-annual update, the Company’s Independent Consulting Petroleum Engineer, with assistance from Company staff, prepares estimates of crude oil, NGL and natural gas reserves based on available geological and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing appropriate prices for the current period. The estimated oil, NGL and natural gas reserves were computed using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month oil, NGL and natural gas price for each month within the 12-month period prior to the balance sheet date, held flat over the life of the properties. However, projected future crude oil, NGL and natural gas pricing assumptions are used by management to prepare estimates of crude oil, NGL and natural gas reserves and future net cash flows used in asset impairment assessments and in formulating management’s overall operating decisions. Crude oil, NGL and natural gas prices are volatile and affected by worldwide production and consumption and are outside the control of management.

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Capitalized Costs

9 Months Ended

Jun. 30, 2014

Capitalized Costs [Abstract]

Capitalized Costs

NOTE 9: Capitalized Costs

As of June 30, 2014 and 2013, non-producing oil and natural gas properties include costs of $888,505 and $0, respectively, on exploratory wells which were drilling and/or testing.

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Derivatives (Summary Of Derivative Instruments Contracts) (Details)	Jun. 30, 2014 MMBTU	Sep. 30, 2013 MMBTU
Natural Gas Costless Collars [Member] | Fixed Price One [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas	140,000	80,000
Natural Gas Costless Collars [Member] | Fixed Price Two [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas		50,000
Natural Gas Costless Collars [Member] | Fixed Price Three [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas		100,000
Natural Gas Costless Collars [Member] | Fixed Price Four [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas		160,000
Natural Gas Fixed Price Swaps [Member] | Fixed Price Two [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas	140,000
Contract price	4.11
Natural Gas Fixed Price Swaps [Member] | Fixed Price Three [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas	50,000
Contract price	4.20
Natural Gas Fixed Price Swaps [Member] | Fixed Price Four [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas	50,000
Contract price	4.18
Natural Gas Fixed Price Swaps [Member] | Fixed Price Five [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas	50,000	100,000
Contract price	4.21	3.505
Natural Gas Fixed Price Swaps [Member] | Fixed Price Six [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas	30,000	70,000
Contract price	4.30	3.400
Natural Gas Fixed Price Swaps [Member] | Fixed Price Seven [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas	40,000	40,000
Contract price	4.61	3.655
Natural Gas Fixed Price Swaps [Member] | Fixed Price Eight [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas		100,000
Contract price		4.320
Oil Costless Collars [Member] | Fixed Price Eight [Member]
Derivative [Line Items]
Production volume covered per month - Oil	4,000
Oil Costless Collars [Member] | Fixed Price Nine [Member]
Derivative [Line Items]
Production volume covered per month - Oil	5,000	3,000
Oil Costless Collars [Member] | Fixed Price Ten [Member]
Derivative [Line Items]
Production volume covered per month - Oil		4,000
Oil Costless Collars [Member] | Fixed Price Eleven [Member]
Derivative [Line Items]
Production volume covered per month - Oil		2,000
Oil Costless Collars [Member] | Fixed Price Twelve [Member]
Derivative [Line Items]
Production volume covered per month - Oil		4,000
Oil Fixed Price Swaps [Member] | Fixed Price Ten [Member]
Derivative [Line Items]
Production volume covered per month - Oil	3,000
Contract price	94.50
Oil Fixed Price Swaps [Member] | Fixed Price Eleven [Member]
Derivative [Line Items]
Production volume covered per month - Oil	4,000
Contract price	95.25
Oil Fixed Price Swaps [Member] | Fixed Price Twelve [Member]
Derivative [Line Items]
Production volume covered per month - Oil	5,000
Contract price	94.20
Oil Fixed Price Swaps [Member] | Fixed Price Thirteen [Member]
Derivative [Line Items]
Production volume covered per month - Oil	6,000	4,000
Contract price	92.85	105.25
Oil Fixed Price Swaps [Member] | Fixed Price Fourteen [Member]
Derivative [Line Items]
Production volume covered per month - Oil	4,000
Contract price	99.40
Oil Fixed Price Swaps [Member] | Fixed Price Fifteen [Member]
Derivative [Line Items]
Production volume covered per month - Oil	7,000
Contract price	96.80
Oil Fixed Price Swaps [Member] | Fixed Price Sixteen [Member]
Derivative [Line Items]
Production volume covered per month - Oil	5,000
Contract price	97.40
Oil Fixed Price Swaps [Member] | Fixed Price Seventeen [Member]
Derivative [Line Items]
Production volume covered per month - Oil	5,000
Contract price	94.56
Oil Fixed Price Swaps [Member] | Fixed Price Eighteen [Member]
Derivative [Line Items]
Production volume covered per month - Oil	7,000
Contract price	93.91
Minimum [Member] | Natural Gas Costless Collars [Member] | Fixed Price One [Member]
Derivative [Line Items]
Contract price	3.75	3.75
Minimum [Member] | Natural Gas Costless Collars [Member] | Fixed Price Two [Member]
Derivative [Line Items]
Contract price		3.75
Minimum [Member] | Natural Gas Costless Collars [Member] | Fixed Price Three [Member]
Derivative [Line Items]
Contract price		3.75
Minimum [Member] | Natural Gas Costless Collars [Member] | Fixed Price Four [Member]
Derivative [Line Items]
Contract price		4.00
Minimum [Member] | Oil Costless Collars [Member] | Fixed Price Eight [Member]
Derivative [Line Items]
Contract price	85.00
Minimum [Member] | Oil Costless Collars [Member] | Fixed Price Nine [Member]
Derivative [Line Items]
Contract price	90.00	90.00
Minimum [Member] | Oil Costless Collars [Member] | Fixed Price Ten [Member]
Derivative [Line Items]
Contract price		90.00
Minimum [Member] | Oil Costless Collars [Member] | Fixed Price Eleven [Member]
Derivative [Line Items]
Contract price		90.00
Minimum [Member] | Oil Costless Collars [Member] | Fixed Price Twelve [Member]
Derivative [Line Items]
Contract price		90.00
Maximum [Member] | Natural Gas Costless Collars [Member] | Fixed Price One [Member]
Derivative [Line Items]
Contract price	4.50	4.25
Maximum [Member] | Natural Gas Costless Collars [Member] | Fixed Price Two [Member]
Derivative [Line Items]
Contract price		4.30
Maximum [Member] | Natural Gas Costless Collars [Member] | Fixed Price Three [Member]
Derivative [Line Items]
Contract price		4.05
Maximum [Member] | Natural Gas Costless Collars [Member] | Fixed Price Four [Member]
Derivative [Line Items]
Contract price		4.55
Maximum [Member] | Oil Costless Collars [Member] | Fixed Price Eight [Member]
Derivative [Line Items]
Contract price	100.00
Maximum [Member] | Oil Costless Collars [Member] | Fixed Price Nine [Member]
Derivative [Line Items]
Contract price	97.00	102.00
Maximum [Member] | Oil Costless Collars [Member] | Fixed Price Ten [Member]
Derivative [Line Items]
Contract price		101.50
Maximum [Member] | Oil Costless Collars [Member] | Fixed Price Eleven [Member]
Derivative [Line Items]
Contract price		97.50
Maximum [Member] | Oil Costless Collars [Member] | Fixed Price Twelve [Member]
Derivative [Line Items]
Contract price		101.50

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Restricted Stock Plan (Tables)

9 Months Ended

Jun. 30, 2014

Restricted Stock Plan [Abstract]

Summary Of Pre-Tax Compensation Expense

	Three Months Ended				Nine Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
Performance based, restricted stock	$	76,520	$	81,822	$	226,800	$	263,583
Non-performance based, restricted stock		161,097		60,208		272,991		278,354
Total compensation expense	$	237,617	$	142,030	$	499,791	$	541,937

Summary Of Unrecognized Compensation Cost

	As of June 30, 2014
	Unrecognized Compensation Cost		Weighted Average Period (in years)
Performance based, restricted stock	$	350,815	1.62
Non-performance based, restricted stock		364,545	1.26
Total	$	715,360

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Long-Term Debt (Details) (USD $)	0 Months Ended	9 Months Ended
	Jun. 17, 2014	Jun. 30, 2014	Jun. 16, 2014
Line Of Credit Facility [Line Items]
Credit facility maturity		Nov. 30, 2018
Revolving Credit Facility [Member]
Line Of Credit Facility [Line Items]
Revolving loan credit facility	$ 200,000,000		$ 80,000,000
Discount rate		8.00%
Borrowing base of credit facility	130,000,000		35,000,000
Properties carrying value		163,288,413
Debt issuance costs	$ 542,500
Effective Interest rate		2.58%
Annual Non Use Fee Percentage		0.25%
Revolving Credit Facility [Member] | Minimum [Member] | Prime Rate [Member]
Line Of Credit Facility [Line Items]
Interest rate basis		0.375%
Revolving Credit Facility [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line Of Credit Facility [Line Items]
Interest rate basis		1.875%
Revolving Credit Facility [Member] | Maximum [Member] | Prime Rate [Member]
Line Of Credit Facility [Line Items]
Interest rate basis		1.125%
Revolving Credit Facility [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Line Of Credit Facility [Line Items]
Interest rate basis		2.625%

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Acquisitions (Summary of Pro Forma Financial Information) (Details) (USD $)	3 Months Ended		9 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Revenue:
Revenue as reported	$ 18,374,977	$ 17,730,445	$ 56,523,778	$ 44,492,866
Pro forma revenue			16,811,606	14,862,947
Pro forma			73,335,384	59,355,813
Net Income:
Net income as reported	5,122,585	5,070,168	15,703,476	8,240,953
Pro forma income			6,485,185	5,771,157
Pro forma			$ 22,188,661	$ 14,012,110

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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, 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)
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)
Restricted stock awards		541,937				541,937
Net income				8,240,953		8,240,953
Dividends				(1,746,217)		(1,746,217)
Distribution of deferred directors' compensation		(82,547)	(297,154)		394,687	14,986
Distribution of deferred directors' compensation, shares					12,361
Increase in deferred directors' compensation charged to expense			288,759			288,759
Balances at Jun. 30, 2013	140,524	2,479,619	2,667,765	91,316,131	(6,626,113)	89,977,926
Balances, Treasury shares at Jun. 30, 2013					(211,155)
Balances, shares at Jun. 30, 2013	8,431,502
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
Purchase of treasury stock					(122,044)	(122,044)
Purchase of treasury stock, shares					(3,722)
Restricted stock awards		499,791				499,791
Net income				15,703,476		15,703,476
Dividends				(1,995,812)		(1,995,812)
Distribution of restricted stock to officers and directors		(320,014)			337,198	17,184
Distribution of restricted stock to officers and directors, shares					11,096
Increase in deferred directors' compensation charged to expense			269,608			269,608
Balances at Jun. 30, 2014	$ 140,524	$ 2,767,615	$ 3,026,134	$ 110,162,113	$ (6,068,697)	$ 110,027,689
Balances, Treasury shares at Jun. 30, 2014					(192,874)	(192,874)
Balances, shares at Jun. 30, 2014	8,431,502

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Basic And Diluted Earnings Per Share

9 Months Ended

Jun. 30, 2014

Basic And Diluted Earnings Per Share [Abstract]

Basic And Diluted Earnings Per Share

NOTE 3: Basic and Diluted Earnings per Share

Basic and diluted earningsper share is calculated using net incomedivided by the weighted average number of voting common shares outstanding, including unissued,vested directors’ deferred compensation sharesduring the period.

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Restricted Stock Plan (Narrative) (Details) (USD $)	0 Months Ended				0 Months Ended
	Dec. 21, 2013 Officer [Member]	Mar. 29, 2014 Non Employee Director [Member]	Mar. 05, 2014 2010 Stock Plan [Member]	Mar. 11, 2010 2010 Stock Plan [Member]	May 29, 2014 Non Performance Based Restricted Stock [Member]	Dec. 21, 2013 Non Performance Based Restricted Stock [Member]	Dec. 21, 2013 Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock authorized			250,000	100,000
Shares awarded					3,918	6,093	18,279
Restricted Stock vesting period	3 years	6 months
Fair value of shares awarded					$ 210,120	$ 199,788	$ 294,889

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Fair Value Measurements (Summary Of Reconciliation Of Assets Classified As Level 3 Measurements) (Details) (USD $)	9 Months Ended
	Jun. 30, 2014
Fair Value Measurements [Abstract]
Balance of Level 3 as of October 1, 2013	$ 242,902
Total gains or (losses) included in earnings	(78,976)
Total gains or (losses) included in other comprehensive income (loss)
Purchases, issuances and settlements	(686,939)
Transfers in and out of Level 3
Balance of Level 3 as of June 30, 2014	$ (523,013)

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Recently Adopted Accounting Pronouncements

9 Months Ended

Jun. 30, 2014

Recently Adopted Accounting Pronouncements [Abstract]

Recently Adopted Accounting Pronouncements

NOTE 13: Recently Adopted Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2014-09-Revenue from Contracts with Customers, which will supersede nearly all existing revenue recognition guidance under GAAP. The standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. We are evaluating our existing revenue recognition policies to determine whether any contracts in the scope of the guidance will be affected by the new requirements. The standard is effective for us on October 1, 2017. Early adoption is not permitted. The standard allows for either “full retrospective” adoption, meaning the standard is applied to all of the periods presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements. We are currently evaluating the transition method that will be elected.

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.