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		December  31, 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 February9, 2015:								16,507,446

INDEX

Part I	Financial Information		Page
	Item 1	Condensed Financial Statements	1
		Condensed Balance Sheets – December  31, 2014 and September 30, 2014	1
		Condensed Statements of Operations – Threemonths ended December  31, 2014 and 2013	2
		Statements of Stockholders’ Equity – Three months ended December  31, 2014 and 2013	3
		Condensed Statements of Cash Flows – Three months ended December  31, 2014 and 2013	4
		Notes to Condensed Financial Statements	5
	Item 2	Management's discussion and analysis of financial condition and results of operations	11
	Item 3	Quantitative and qualitative disclosures about market risk	15
	Item 4	Controls and procedures	16
Part II	Other Information
	Item 2	Unregistered Sales of Equity Securities and Use of Proceeds	16
	Item 6	Exhibits and reports on Form 8-K	17
	Signatures		17

The following defined terms are used in this report:

“Bbl” barrel.

“Board” board of directors.

“BTU” British Thermal Units.

“Company”Panhandle Oil and Gas Inc.

“completion”the process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil and/or natural gas.

“DD&A” depreciation, depletion and amortization.

“dry hole”exploratory or development well that does not produce crude oil and/or natural gas in economically producible quantities.

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

“exploratory well”awell drilled to find a new field or to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir.

“FASB” the Financial Accounting Standards Board.

“field”an  area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“G&A” general and administrative costs.

“gross acres” the total acres in which a working interest is owned.

“held by production”or “HBP”an oil and gas lease continued into effect into its secondary term for so long as a producing oil and/or gas well is located on any portion of the leased premises or lands pooled therewith.

“horizontal drilling”adrilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled horizontally within a specified interval.

“IDC”  intangible drilling costs.

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

“LOE” lease operating expense.

“Mcf” thousand cubic feet.

“Mcfe” 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” million BTU.

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

“net acres” the sum of the fractional working interests owned in gross acres.

“NGL” natural gas liquids.

“NYMEX” New York Mercantile Exchange.

“Panhandle”Panhandle Oil and Gas Inc.

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

“proved reserves”the quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain.

“royalty interest” 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” the United States Securities and Exchange Commission.

“undeveloped acreage”lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and/or natural gas.

“working interest” 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” 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 2015 mean the fiscal year ended September 30, 2015.

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

	December 31, 2014		September 30, 2014
Assets	(unaudited)
Current assets:
Cash and cash equivalents	$	519,605	$	509,755
Oil, NGL and natural gas sales receivables		13,555,350		16,227,469
Refundable production taxes		612,791		625,996
Derivative contracts, net		12,333,036		1,650,563
Other		255,743		354,828
Total current assets		27,276,525		19,368,611
Properties and equipment at cost, based on successful efforts accounting:
Producing oil and natural gas properties		430,310,159		418,237,512
Non-producing oil and natural gas properties		9,394,878		10,260,717
Other		1,372,943		1,317,725
		441,077,980		429,815,954
Less accumulated depreciation, depletion and amortization		(210,823,119)		(204,731,661)
Net properties and equipment		230,254,861		225,084,293
Investments		2,053,420		1,936,421
Derivative contracts, net		-		251,279
Total assets	$	259,584,806	$	246,640,604
Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	6,167,740	$	7,034,773
Deferred income taxes		765,100		600,100
Income taxes payable		3,415,443		523,843
Accrued liabilities and other		1,264,994		1,290,858
Total current liabilities		11,613,277		9,449,574
Long-term debt		78,715,107		78,000,000
Deferred income taxes		38,382,907		37,363,907
Asset retirement obligations		2,696,836		2,638,470
Stockholders' equity:
Class A voting common stock, $.0166 par value;
24,000,000 shares authorized, 16,863,004 issued at
December 31, 2014, and September 30, 2014		280,938		280,938
Capital in excess of par value		2,590,151		2,861,343
Deferred directors' compensation		3,211,940		3,110,351
Retained earnings		127,694,926		118,794,188
		133,777,955		125,046,820
Less treasury stock, at cost; 355,558 shares at December 31,
2014, and 372,364 shares at September 30, 2014		(5,601,276)		(5,858,167)
Total stockholders' equity		128,176,679		119,188,653
Total liabilities and stockholders' equity	$	259,584,806	$	246,640,604

All share and per share amounts were adjusted for the 2-for-1 stock split, effective on October 8, 2014.

(See accompanying notes)

(1)

PANHANDLE OIL AND GAS INC.

CONDENSED STATEMENTS OF OPERATIONS

	Three Months Ended December 31,
	2014		2013
Revenues:	(unaudited)
Oil, NGL and natural gas sales	$	19,519,700	$	18,473,082
Lease bonuses and rentals		29,291		196,229
Gains (losses) on derivative contracts		11,250,265		(496,901)
Income from partnerships		199,914		224,346
		30,999,170		18,396,756
Costs and expenses:
Lease operating expenses		4,785,350		3,315,397
Production taxes		622,512		571,564
Exploration costs		25,352		38,755
Depreciation, depletion and amortization		6,139,019		5,308,019
Provision for impairment		2,191,997		202,991
Loss (gain) on asset sales and other		(1,982)		(77,455)
Interest expense		402,733		-
General and administrative		1,958,428		1,873,167
		16,123,409		11,232,438
Income before provision for income taxes		14,875,761		7,164,318
Provision for income taxes		4,642,000		2,238,000
Net income	$	10,233,761	$	4,926,318
Basic and diluted earnings per common share (Note 3)	$	0.61	$	0.29
Basic and diluted weighted average shares outstanding:
Common shares		16,494,805		16,463,804
Unissued, directors' deferred compensation shares		262,121		246,122
		16,756,926		16,709,926
Dividends declared per share of
common stock and paid in period	$	0.04	$	0.04
Dividends declared per share of
common stock and to be paid in quarter ended March 31	$	0.04	$	0.04

All share and per share amounts were adjusted for the 2-for-1 stock split, effective on October 8, 2014.

(See accompanying notes)

(2)

PANHANDLE OIL AND GAS INC.

STATEMENTS OF STOCKHOLDERS’ EQUITY

Three Months Ended December 31, 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, 2014	16,863,004	$	280,938	$	2,861,343	$	3,110,351	$	118,794,188	(372,364)	$	(5,858,167)	$	119,188,653
Purchase of treasury stock	-		-		-		-		-	(7,177)		(120,611)		(120,611)
Restricted stock awards	-		-		165,111		-		-	-		-		165,111
Net income	-		-		-		-		10,233,761	-		-		10,233,761
Dividends ($.08 per share)	-		-		-		-		(1,333,023)	-		-		(1,333,023)
Distribution of restricted stock
to officers and directors	-		-		(436,303)		-		-	23,983		377,502		(58,801)
Increase in deferred directors'
compensation charged to expense	-		-		-		101,589		-	-		-		101,589
Balances at December 31, 2014	16,863,004	$	280,938	$	2,590,151	$	3,211,940	$	127,694,926	(355,558)	$	(5,601,276)	$	128,176,679
(unaudited)

Three Months Ended December 31, 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, 2013	16,863,004	$	280,938	$	2,447,424	$	2,756,526	$	96,454,449	(400,496)	$	(6,283,851)	$	95,655,486
Purchase of treasury stock	-		-		-		-		-	(7,444)		(122,044)		(122,044)
Restricted stock awards	-		-		127,976		-		-	-		-		127,976
Net income	-		-		-		-		4,926,318	-		-		4,926,318
Dividends ($.08 per share)	-		-		-		-		(1,328,272)	-		-		(1,328,272)
Distribution of restricted stock
to officers	-		-		(259,511)		-		-	18,280		275,662		16,151
Increase in deferred directors'
compensation charged to expense	-		-		-		114,069		-	-		-		114,069
Balances at December 31, 2013	16,863,004	$	280,938	$	2,315,889	$	2,870,595	$	100,052,495	(389,660)	$	(6,130,233)	$	99,389,684
(unaudited)

All share and per share amounts were adjusted for the 2-for-1 stock split, effective on October 8, 2014.

(See accompanying notes)

(3)

PANHANDLE OIL AND GAS INC.

CONDENSED STATEMENTS OF CASH FLOWS

	Three months ended December 31,
	2014		2013
Operating Activities	(unaudited)
Net income (loss)	$	10,233,761	$	4,926,318
Adjustments to reconcile net income (loss) to net cash provided
by operating activities:
Depreciation, depletion and amortization		6,139,019		5,308,019
Impairment		2,191,997		202,991
Provision for deferred income taxes		1,184,000		326,000
Exploration costs		25,352		38,755
Gain from leasing fee mineral acreage		(29,162)		(196,133)
Income from partnerships		(199,914)		(224,346)
Distributions received from partnerships		256,017		279,363
Directors' deferred compensation expense		101,589		114,069
Restricted stock awards		165,111		127,976
Cash provided (used) by changes in assets and liabilities:
Oil, NGL and natural gas sales receivables		2,672,119		(956,975)
Fair value of derivative contracts		(10,431,194)		891,970
Refundable production taxes		13,205		53,824
Other current assets		99,085		(35,813)
Accounts payable		565,409		414,267
Income taxes payable		2,891,600		1,088,350
Accrued liabilities		(692,505)		(472,288)
Total adjustments		4,951,728		6,960,029
Net cash provided by operating activities		15,185,489		11,886,347
Investing Activities
Capital expenditures, including dry hole costs		(14,901,631)		(9,892,262)
Acquisition of working interest properties		-		(1,550,205)
Acquisition of minerals and overrides		-		(56,250)
Proceeds from leasing fee mineral acreage		29,798		216,773
Investments in partnerships		(173,103)		(143,695)
Net cash used in investing activities		(15,044,936)		(11,425,639)
Financing Activities
Borrowings under debt agreement		12,335,774		2,280,280
Payments of loan principal		(11,620,667)		(4,542,536)
Purchases of treasury stock		(120,611)		(122,044)
Payments of dividends		(666,199)		(664,618)
Excess tax benefit on stock-based compensation		(59,000)		16,000
Net cash provided by (used in) financing activities		(130,703)		(3,032,918)
Increase (decrease) in cash and cash equivalents		9,850		(2,572,210)
Cash and cash equivalents at beginning of period		509,755		2,867,171
Cash and cash equivalents at end of period	$	519,605	$	294,961
Supplemental Schedule of Noncash Investing and Financing Activities:
Dividends declared and unpaid	$	666,824	$	663,654
Additions to asset retirement obligations	$	26,452	$	53,653
Gross additions to properties and equipment	$	13,469,206	$	9,843,214
Net (increase) decrease in accounts payable for
properties and equipment additions		1,432,425		1,655,503
Capital expenditures and acquisitions, including dry hole costs	$	14,901,631	$	11,498,717

(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 2014Annual Report on Form 10-K.

On September 11, 2014, the Company’s Board of Directors declared a 2-for-1 stock split of the outstanding Class A Common Stock. The Class A Common Stock split was effected in the form of a stock dividend and was distributed on October 8, 2014, to stockholders of record on September 24, 2014. All references to number of shares and per share information in the accompanying financial statements have been adjusted to reflect this stock split.

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 quarters ended December 31, 2014 and 2013, was 31%.

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

The Company has a $200,000,000 credit facility with a group of banks headed by Bank of Oklahoma (BOK)with aborrowing base of$130,000,000 and a maturity date of November 30, 2018.  The credit facility is subject to a semi-annual borrowing base determination, wherein BOK applies their 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 $176,724,836 at December 31, 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 December 31, 2014, the effective interest rate was 2.34%.

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

The borrowing base of$130,000,000 was reaffirmed by the banks in December 2014. Determinations of the borrowing base are made semi-annually or whenever the banks, in their discretion, believe that there has been a material change in the value of the oil and natural gas properties. 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 December 31, 2014, the Company was in compliance with the covenants of the loan agreement.

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NOTE 5:Deferred Compensation Plan for Directors

Annually, non-employee directors may elect to be included in the Directors’ Deferred Compensation Plan.  The Directors’ Deferred Compensation Plan provides that each outside director may individually elect to be credited with future unissued shares of Company Common Stock rather than cash for all or a portion of the annual retainers, Board meeting fees and committee meeting fees, and may elect to receive shares, when issued, over annual time periods up to ten years.  These unissued shares are recorded to each director’s deferred compensation account at the closing market price of the shares (i) on the dates of the Board and committee meetings, and (ii) on the payment dates of the annual retainers.  Only on a director’s retirement, termination, death, or a change-in-control of the Company will the shares recorded for such director under the Directors’ Deferred Compensation Plan be issued to the director.  The promise to issue such shares in the future is an unsecured obligation of the Company.

NOTE 6:Restricted  Stock  Plan

In March 2010, shareholders approved the Panhandle Oil and Gas Inc. 2010 Restricted Stock Plan (2010 Stock Plan), which made available 200,000 shares of common stock to provide a long-term component to the Company’s total compensation package for its officers and to further align the interest of its officers with those of its shareholders. In March 2014, shareholders approved an amendment to increase the number of shares of common stock reserved for issuance under the 2010 Stock Plan from 200,000 shares to 500,000 shares and to allow the grant of shares of restricted stock to our directors. The 2010 Stock Plan, 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 in May 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.

The following table summarizes the Company’s pre-tax compensation expense for the three months ended December 31, 2014 and 2013, related to the Company’s performance based and non-performance based restricted stock.

	Three Months Ended
	December 31,
	2014		2013
Performance based, restricted stock	$	64,174	$	72,695
Non-performance based, restricted stock		100,937		55,281
Total compensation expense	$	165,111	$	127,976

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 December 31, 2014
	Unrecognized Compensation Cost		Weighted Average Period (in years)
Performance based, restricted stock	$	205,374	1.41
Non-performance based, restricted stock		151,862	1.33
Total	$	357,236

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,

(6)

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 December 31, 2014 and 2013, the assessment resulted in impairment provisions of $2,191,997 and $202,991, 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 ofDecember 31, 2014 and 2013, non-producing oil and natural gas properties include costs of $908,872and $83,174, 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 under its credit facility with Bank of Oklahoma.The derivative instruments have settled or will settle based on the prices below.

(7)

Derivative contracts in place as of December 31, 2014

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
November 2014 - April 2015	100,000 Mmbtu	NYMEX Henry Hub	$3.75 floor / $4.25 ceiling
January - March 2015	100,000 Mmbtu	NYMEX Henry Hub	$4.00 floor / $5.00 ceiling
January - March 2015	30,000 Mmbtu	NYMEX Henry Hub	$4.00 floor / $4.60 ceiling
January - December 2015	100,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $4.10 ceiling
January - December 2015	70,000 Mmbtu	NYMEX Henry Hub	$3.25 floor / $4.00 ceiling
April - September 2015	70,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $4.05 ceiling
April - October 2015	50,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $4.00 ceiling
May - October 2015	70,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $3.95 ceiling
Oil costless collars
July - December 2015	10,000 Bbls	NYMEX WTI	$80.00 floor / $86.50 ceiling
Oil fixed price swaps
January - March 2015	6,000 Bbls	NYMEX WTI	$92.85
January - June 2015	7,000 Bbls	NYMEX WTI	$96.80
January - June 2015	5,000 Bbls	NYMEX WTI	$97.40
January - June 2015	4,000 Bbls	NYMEX WTI	$97.25
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, 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
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
June - December 2014	4,000 Bbls	NYMEX WTI	$99.40
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
January - June 2015	7,000 Bbls	NYMEX WTI	$96.80
January - June 2015	5,000 Bbls	NYMEX WTI	$97.40
January - June 2015	4,000 Bbls	NYMEX WTI	$97.25
April - December 2015	5,000 Bbls	NYMEX WTI	$94.56
July - December 2015	7,000 Bbls	NYMEX WTI	$93.91

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 asset of $12,333,036 as of December 31, 2014, and a net asset of $1,901,842 as of September 30, 2014.

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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 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 December 31, 2014, and September 30, 2014. 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 December 31, 2014, and September 30, 2014.

	12/31/2014		9/30/2014
	Fair Value (a)		Fair Value (a)
	Commodity Contracts		Commodity Contracts
	Current Assets		Current Assets			Current Liabilities	Non-Current Assets
Gross amounts recognized	$	12,333,036	$	1,658,785	$	8,222	$	251,279
Offsetting adjustments		-		(8,222)		(8,222)		-
Net presentation on Condensed Balance Sheets	$	12,333,036	$	1,650,563	$	-	$	251,279

(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 December 31, 2014.

	Fair Value Measurement at December 31, 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	$	-	$	8,386,282	$	-	$	8,386,282
Derivative Contracts - Collars	$	-	$	-	$	3,946,754	$	3,946,754

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.

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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 December 31, 2014
Oil Collars	Oil price volatility curve	0% - 38.56%	30.91%	$	1,557,327
Natural Gas Collars	Natural gas price volatility curve	0% - 33.11%	23.26%	$	2,389,427

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, 2014	$	30,044
Total gains or (losses)
Included in earnings		3,775,971
Included in other comprehensive income (loss)		-
Purchases, issuances and settlements		140,739
Transfers in and out of Level 3		-
Balance of Level 3 as of December 31, 2014	$	3,946,754

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 December 31,
	2014				2013
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	2,322,760	$	2,191,997	$	236,199	$	202,991

(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 December 31, 2014, and September 30, 2014, 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.

NOTE 12: Acquisitions

On June 17, 2014,  the Company closed an acquisition of certain Eagle Ford Shale assets located in LaSalle and Frio

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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, at the time of closing, contained63 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 acquisitionincluded in the Company’s statement of operations for the three months ended December 31, 2014, were $4,270,866. Net income attributable to the acquisition included in the statement of operations for the three months ended December 31, 2014, was $872,919.

The following table presents the unaudited pro forma financial information assuming the Company had acquired this business on October 1, 2013:

	For the Three Months Ended
	December 31,
	2014		2013
Revenue:
As reported	$	30,999,170	$	18,396,756
Pro forma revenue		-		5,869,980
Pro forma	$	30,999,170	$	24,266,736
Net Income:
As reported	$	10,233,761	$	4,926,318
Pro forma income		-		2,435,848
Pro forma	$	10,233,761	$	7,362,166

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.

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 2015 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 2014 Annual Report on Form 10-K where risk factors are presented and further discussed. For all the above

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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 $15,663,248 at December 31, 2014,  compared to $9,919,037 at September 30, 2014.

Liquidity:

Cash and cash equivalents were $519,605 as of December 31, 2014, compared to $509,755 at September 30, 2014,  an increase of $9,850. Cash flows for the three months ended December 31 are summarized as follows:

Net cash provided (used) by:
	2014		2013		Change
Operating activities	$	15,185,489	$	11,886,347	$	3,299,142
Investing activities		(15,044,936)		(11,425,639)		(3,619,297)
Financing activities		(130,703)		(3,032,918)		2,902,215
Increase (decrease) in cash and cash equivalents	$	9,850	$	(2,572,210)	$	2,582,060

Operating activities:

Net cash provided by operating activities increased$3,299,142 during the2015 period, as compared to the2014 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$4,729,382.

· Decreased income tax payments of $182,278.

· Increased net receipts on derivative contracts of $424,002.

· Increased interest payments of $393,779.

· Increased payments for G&A expenses of $95,598.

· Increased payments for field operating expenses of $1,603,315.

Investing activities:

Net cash used in investing activities increased$3,619,297 during the 2015 period, as compared to the 2014 period, due to:

· A decrease in cash used to acquire properties of $1,606,455.

· Higher drilling and completion activity during 2015increased capital expenditures by $5,009,369.

· Lower proceeds from mineral leasing of $186,975.

Financing activities:

Net cash used in financing activities decreased$2,902,215 during the 2015 period, as compared to the 2014 period, the result of the following:

· During the period ended December 31, 2014, net borrowings increased $715,107. During the period ended December 31, 2013, net borrowings decreased$2,262,256.

Capital Resources:

Capital expenditures to drill and complete wells increased$5,009,369(51%)fromthe 2014 to the 2015 period.  This

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increase was largely due to drilling activity in the Eagle Ford Shale oil play in South Texas. Less significant capital expenditures were also made to fund horizontal drilling in the Arkansas Fayetteville Shale (dry natural gas), western and southern Oklahoma (oil and NGL rich) and the North Dakota Bakken Shale (oil).

Oil, NGL and natural gas production volumes increased 7% on an Mcfe basis during the2015period, as compared to the2014 period.The production increase was the result of added production from the acquired properties in the Eagle Ford Shale and new production coming on line, which, combined, exceeded the natural production decline of existing wells. As the Company will be receiving oil production from the Eagle Ford properties for all of 2015 (as compared to three and one-half months of fiscal 2014), we expect 2015 oil production to increase over that of 2014. Natural gas and NGL production volumes are expected to be lower in 2015, as compared to 2014, as a result of anticipated lower 2015 capital expenditures which is discussed below.

The sharp drop in oil prices since September 2014, combined with lower natural gas prices within the last couple of months, has resulted in many of the operators in plays where we own an interest announcing that they are lowering their budgeted capital expenditures for calendar 2015. Particularly, on our Eagle Ford Shale properties and on five North Dakota Bakken Shale wells in which the Company owns an interest, the operators have recently ceased drilling and completion activities until the combination of oil prices and well service costs improve to a level which would yield a reasonable rate of return. As a result, Panhandle’s capital expenditures during 2015 are expected to be significantly less than in 2014. Reduced capital expenditures are anticipated to result in somewhat lower oil, NGL and natural gas production volumes in the remaining three quarters of 2015 compared to the first quarter, and combined with lower product prices, cash flow from operations will be reduced as long as product prices remain depressed. However, management does expect 2015 cash flow from operations to exceed capital expenditures, dividend payments and treasury stock purchases and plans to use excess cash flow to reduce bank debt.

Since the Company is not the operator of any of its oil and natural gas properties, it is extremely difficult for us to predict levels of future participation in the drilling and completion of new wells and their associated capital expenditures; thus, making 2015 capital expenditures for drilling and completion projects difficult to forecast.

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:

	Three months ended
	12/31/2014
Cash provided by operating activities	$	15,185,489
Cash provided (used) by:
Capital expenditures - drilling and completion of wells		(14,901,631)
Quarterly dividends of $.08 per share		(666,199)
Treasury stock purchases		(120,611)
Net borrowings on credit facility		715,107
Other investing and financing activities		(202,305)
Net cash used		(15,175,639)
Net increase (decrease) in cash	$	9,850

Outstanding borrowings on the credit facility at December 31, 2014, were$78,715,107.

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 ($51,284,893 at December 31, 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).

Based on expected capital expenditure levels and anticipated cash provided by operating activities for 2015, the Company has sufficient liquidity to fund its ongoing operations and, combined with availability under its credit facility, to fund acquisitions.

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RESULTS OF OPERATIONS

THREE MONTHS ENDED DECEMBER 31, 2014 – COMPARED TO THREE MONTHS ENDED DECEMBER 31, 2013

Overview:

The Company recorded first quarter 2015 net income of $10,233,761, or $0.61per share, as compared to $4,926,318, or $0.29 per share, in the 2014 quarter. The increase in net income was principally the result of gains on derivative contracts and increased oil and NGL sales; offset by increases in provision for impairment, LOE,  DD&A, interest expense and income taxes. These items are further discussed below.

Oil, NGL and Natural Gas Sales:

Oil, NGL and natural gas sales increased$1,046,618 or 6% for the 2015 quarter. Oil, NGL and natural gas sales were up due to increases in oil and NGL sales volumes of 40% and 96%, respectively. These increases were partially offset by a decrease in natural gas sales volumes of 7% and a decrease in oil and NGL prices of 24% and 16%, respectively.  The following table outlines the Company’s production and average sales prices for oil, NGL and natural gas for the three month periods of fiscal 2015 and 2014:

	Oil Bbls	Average		Mcf	Average		NGL Bbls	Average		Mcfe	Average
	Sold	Price		Sold	Price		Sold	Price		Sold	Price
Three months ended
12/31/2014	116,583	$	70.87	2,601,161	$	3.59	72,804	$	26.19	3,737,483	$	5.22
12/31/2013	83,413	$	93.66	2,785,952	$	3.41	37,140	$	31.35	3,509,270	$	5.26

Oil production increases were principally the result of a full quarter of production from the Eagle Ford Shale properties which were acquired in June 2014,offset by declining production from Texas Panhandle and western Oklahoma horizontal Cleveland, Marmaton and Granite Wash oil plays. Eagle Ford Shale production in the first quarter of 2015 was negatively impacted by the delay of completion of six wells that were drilled in the quarter. The operator has elected to defer the completions until oil prices recover from their current depressed levels and/or service costs decline materially. NGL production increases resulted from drilling in western Oklahoma horizontal plays that are rich in NGL, principally the Anadarko Woodford Shale, Granite Wash and Marmaton. A full quarter of production from the Eagle Ford Shale properties, which were acquired in 2014, also contributed to the NGL production increase. Natural gas production decreases were the result of natural decline from existing properties, principally in western Oklahoma, the Texas Panhandle, the southeastern Oklahoma Woodford Shale and the Fayetteville Shale, exceeding production from new wells in those areas. This decline was partially offset by growth in natural gas production in the Anadarko Woodford Shale and from a full quarter of natural gas production from the Eagle Ford Shale properties which were acquired in June 2014.

The Company anticipates a material decrease in oil and NGL related capital expenditures in the remainder of 2015 to continue as long as the price of those products remains at or near their current depressed levels. Therefore, oil and NGL production are anticipated to decrease, in the remaining three quarters compared to the first quarter, as the result of natural decline. The Company anticipates a decrease in natural gas related capital expenditures in the remainder of 2015 due to lower natural gas prices and an anticipated reduction in drilling in the Fayetteville Shale resulting from an announced decrease in the 2015 drilling budget by the primary operator in the play. Natural gas production is anticipated to decrease, in the remaining three quarters of 2015, as the result of natural decline in western Oklahoma, the Texas Panhandle, the southeastern Oklahoma Woodford Shale and the Fayetteville Shale, which will not be completely offset by new production.

Production for the last five quarters was as follows:

Quarter ended	Oil Bbls Sold	Mcf Sold	NGL Bbls Sold	Mcfe Sold
12/31/2014	116,583	2,601,161	72,804	3,737,483
9/30/2014	126,256	2,690,493	55,849	3,783,123
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

Gains (Losses) on Derivative Contracts:

The fair value of derivative contracts was a net asset of $12,333,036 as of December 31, 2014, and a net liability of $466,772 as of December 31, 2013. We had a net gain on derivative contracts of $11,250,265 in the 2015 quarter as compared

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to a net loss of $496,901 recorded in the 2014 quarter. The change is principally due to the oil andnatural gas collars and fixed price swaps increasing in value as projected oil and natural gas prices at December 31, 2014, were well below the floor prices of the collars and well below the fixed price of the swaps.

Lease Operating Expenses (LOE):

LOE increased$1,469,953 or 44% in the 2015 quarter. LOE per Mcfe increased in the 2015 quarter to $1.28 compared to $0.94 in the 2014 quarter. LOE related to field operating costs increased $1,486,415 in the 2015 quarter compared to the 2014 quarter, a 99% increase. Field operating costs were $.80 per Mcfe in the 2015 quarter as compared to $.43 per Mcfe in the 2014 quarter. This increase in rate in the 2015 quarter is principally the result of the properties added in the Eagle Ford Shale acquisition in the third quarter of 2014 and the significant number of oil and NGL rich wells drilled inrecent years. These wells have higher lifting costs than our overall well population, which are predominantly natural gas producers.  

The increase in LOE related to field operating costs was slightly offset by a decrease in handling fees (primarily gathering, transportation and marketing costs) of $16,462 in the 2015 quarter compared to the 2014 quarter. On a per Mcfe basis, these fees decreased $.04 due to increases in oil and NGL production, while natural gas production decreased. Natural gas sales bear the large majority of the handling. Handling fees are charged either as a percent of sales or based on production volumes.

Depreciation, Depletion and Amortization (DD&A):

DD&A increased $831,000or 16% in the 2015 quarter. DD&A in the 2015 quarter was $1.64 per Mcfeas compared to$1.51 per Mcfe in the 2014 quarter. DD&A increased $485,812 as a result of this $.13 increase in the DD&A rate. An additional increase of $345,188 was the result of production increasing 7% in the 2015 quarter compared to the 2014 quarter. The rate increase is mainly due to higher per Mcfe finding cost experienced in oil and liquids-rich areas where the Company has added production.

Provision for Impairment:

The provision for impairment increased$1,989,006 in the 2015 quarter compared to the 2014 quarter. During the 2015 quarter, impairment of $2,191,997 was recorded on eleven small fields. One oil field in Hemphill County, Texas accounted for $1,846,488 of the impairment due mainly to declining oil prices. During the 2014 quarter, impairment of $202,991 was recorded on three small fields. These fields have few wells and are more susceptible to impairment when a well in these fields experiences downward reserve revisions due to reserve pricing or well performance.

Interest Expense

Interest expense increased$402,733 in the 2015 quarter, as compared to the 2014 quarter. The increase was due to a larger outstanding debt balance that was used to purchase the Eagle Ford Shale properties in the third quarter of 2014.

Income Taxes:

Provision for income taxes increased in the 2015 quarter by $2,404,000, the result of a $7,711,443increase in income before provision for income taxes in the 2015 quarter compared to the 2014 quarter.The effective tax rate was31% inthe 2014 quarter and the 2015 quarter.  Excess percentage depletion, which is a permanent tax benefit, reduced the effective tax rate below the statutory rate for both quarters.

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, 2014.

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 in the industry. The Company can be significantly impacted by changes in oil and natural gas prices.The market

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price of oil, NGL and natural gas in 2015 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 2015 derivative contracts, the price sensitivity for each $0.10 per Mcf change in wellhead natural gas price is approximately $1,077,356 for operating revenuebased on the Company’s prior year natural gas volumes.  The price sensitivity in 2015 for each $1.00 per barrel change in wellhead oil price is approximately $346,387 for operating revenue  based on the Company’s prior year oil volumes.

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 Bank of Oklahoma and are secured. These arrangements cover only a portion of the Company’s production and provide only partial price protection against declines in natural gas and oil prices. These derivative contracts expose the Company to risk of financial loss and limit the benefit of future increases in prices. For the Company’s 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 $215,000. 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 $339,000. 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 $64,000.  

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 facility.The revolving loan bears interest at the BOK prime rate plus from 0.375% to 1.125%, or 30 day LIBOR plus from 1.875% to 2.625%.At December 31, 2014, the Company had $78,715,107outstanding under this facility. And the effective interest rate was 2.34%.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 December 31, 2014, the Company repurchased shares of the Company’s common stock as summarized in the table below.

(16)

Period	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Program	Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program
10/1 - 10/31/14	320	$	20.56	320	$	1,355,109
12/1 - 12/31/14	6,857	$	16.63	6,857	$	1,241,078
Total	7,177	$	16.81	7,177

Upon approval by the shareholders of the Company’s 2010 Restricted Stock Plan in March 2010, as amended in March 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
		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

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.
February9, 2015	/s/ Michael C. Coffman
Date	Michael C. Coffman, President and
	Chief Executive Officer
February 9, 2015	/s/ Lonnie J. Lowry
Date	Lonnie J. Lowry, Vice President
	and Chief Financial Officer
February 9, 2015	/s/ Robb P. Winfield
Date	Robb P. Winfield, Controller
	and Chief Accounting Officer

(17)

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:February 9, 2015

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:February 9, 2015

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 December 31, 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

February 9, 2015

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 December 31, 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

February 9, 2015

XML

Fair Value Measurements (Summary Of Reconciliation Of Assets Classified As Level 3 Measurements) (Details) (USD $)	3 Months Ended
	Dec. 31, 2014
Fair Value Measurements [Abstract]
Balance of Level 3 as of October 1, 2014	$ 30,044
Total gains or (losses) included in earnings	3,775,971
Total gains or (losses) included in other comprehensive income (loss)
Purchases, issuances and settlements	140,739
Transfers in and out of Level 3
Balance of Level 3 as of December 31, 2014	$ 3,946,754

XML

Capitalized Costs (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Capitalized Costs [Abstract]
Cost of Non-Producing Oil and Natural Gas Properties	$ 908,872	$ 83,174

XML

Accounting Principles And Basis Of Presentation (Details) (Common Class A [Member])	0 Months Ended
	Sep. 11, 2014
Common Class A [Member]
Class of Stock [Line Items]
Stock split	2

XML

Acquisitions (Summary of Pro Forma Financial Information) (Details) (USD $)	3 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Revenue:
Revenue as reported	$ 30,999,170	$ 18,396,756
Pro forma revenue		5,869,980
Pro forma	30,999,170	24,266,736
Net Income:
Net income as reported	10,233,761	4,926,318
Pro forma income		2,435,848
Pro forma	$ 10,233,761	$ 7,362,166

XML

Fair Value Measurements (Summary Of Fair Value Measurement Information For Financial Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Details) (USD $)	Dec. 31, 2014	Sep. 30, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial Assets (Liabilities)	$ 12,333,036	$ 1,901,842
Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial Assets (Liabilities)	8,386,282
Collars [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial Assets (Liabilities)	3,946,754
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)	8,386,282
Fair Value, Inputs, Level 3 [Member] | Collars [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial Assets (Liabilities)	$ 3,946,754

XML

Income Taxes

3 Months Ended

Dec. 31, 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 quarters ended December 31, 2014 and 2013, was 31%.

XML

Restricted Stock Plan (Summary Of Pre-Tax Compensation Expense) (Details) (USD $)	3 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 165,111	$ 127,976
Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	64,174	72,695
Non Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 100,937	$ 55,281

XML

Restricted Stock Plan (Narrative) (Details) (2010 Stock Plan [Member])	Mar. 05, 2014	Mar. 11, 2010
2010 Stock Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock authorized	500,000	200,000

XML

Restricted Stock Plan (Summary Of Unrecognized Compensation Cost) (Details) (USD $)	3 Months Ended
	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	$ 357,236
Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	205,374
Weighted Average Period	1 year 4 months 28 days
Non Performance Based Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	$ 151,862
Weighted Average Period	1 year 3 months 29 days

XML

Oil, NGL And Natural Gas Reserves (Details)	3 Months Ended
	Dec. 31, 2014
Oil, NGL And Natural Gas Reserves [Abstract]
Computation of Oil, Natural Gas and NGL Reserves	12 months

XML

Accounting Principles And Basis Of Presentation

3 Months Ended

Dec. 31, 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 2014 Annual Report on Form 10-K.

On September 11, 2014, the Company’s Board of Directors declared a 2-for-1 stock split of the outstanding Class A Common Stock. The Class A Common Stock split was effected in the form of a stock dividend and was distributed on October 8, 2014, to stockholders of record on September 24, 2014. All references to number of shares and per share information in the accompanying financial statements have been adjusted to reflect this stock split.

XML

Impairment (Details) (USD $)	3 Months Ended
	Dec. 31, 2014		Dec. 31, 2013
Impairment [Abstract]
Impairment	$ 2,191,997	[1]	$ 202,991	[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.

XML

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
	Dec. 31, 2014		Dec. 31, 2013
Fair Value Measurements [Abstract]
Producing Properties, Fair Value	$ 2,322,760	[1]	$ 236,199	[1]
Producing Properties, Impairment	$ 2,191,997	[1]	$ 202,991	[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.

XML

Condensed Balance Sheets (USD $)	Dec. 31, 2014		Sep. 30, 2014
Current Assets:
Cash and cash equivalents	$ 519,605		$ 509,755
Oil, NGL and natural gas sales receivables	13,555,350		16,227,469
Refundable production taxes	612,791		625,996
Derivative contracts, net	12,333,036	[1]	1,650,563	[1]
Other	255,743		354,828
Total current assets	27,276,525		19,368,611
Properties and equipment at cost, based on successful efforts accounting:
Producing oil and natural gas properties	430,310,159		418,237,512
Non-producing oil and natural gas properties	9,394,878		10,260,717
Other	1,372,943		1,317,725
Total properties and equipment, at cost, based on successful efforts accounting	441,077,980		429,815,954
Less accumulated depreciation, depletion and amortization	(210,823,119)		(204,731,661)
Net properties and equipment	230,254,861		225,084,293
Investments	2,053,420		1,936,421
Derivative contracts, net			251,279	[1]
Total assets	259,584,806		246,640,604
Current Liabilities:
Accounts payable	6,167,740		7,034,773
Deferred income taxes	765,100		600,100
Income taxes payable	3,415,443		523,843
Accrued liabilities and other	1,264,994		1,290,858
Total current liabilities	11,613,277		9,449,574
Long-term debt	78,715,107		78,000,000
Deferred income taxes	38,382,907		37,363,907
Asset retirement obligations	2,696,836		2,638,470
Stockholders' equity:
Class A voting common stock, $.0166 par value; 24,000,000 shares authorized, 16,863,004 issued at December 31, 2014, and September 30, 2014	280,938		280,938
Capital in excess of par value	2,590,151		2,861,343
Deferred directors' compensation	3,211,940		3,110,351
Retained earnings	127,694,926		118,794,188
Stockholders' Equity	133,777,955		125,046,820
Less treasury stock, at cost; 355,558 shares at December 31, 2014, and 372,364 shares at September 30, 2014	(5,601,276)		(5,858,167)
Total stockholders' equity	128,176,679		119,188,653
Total liabilities and stockholders' equity	$ 259,584,806		$ 246,640,604

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

XML

Statements Of Stockholders' Equity (Parenthetical) (Retained Earnings [Member], USD $)	3 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Retained Earnings [Member]
Dividends per share	$ 0.08	$ 0.08

XML

Derivatives (Summary Of Derivative Instruments Contracts) (Details)	Dec. 31, 2014 MMBTU	Sep. 30, 2014 MMBTU
Natural Gas Costless Collars [Member] | Fixed Price One [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas	100,000	140,000
Natural Gas Costless Collars [Member] | Fixed Price Two [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas	100,000
Natural Gas Costless Collars [Member] | Fixed Price Three [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas	30,000
Natural Gas Costless Collars [Member] | Fixed Price Four [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas	100,000
Natural Gas Costless Collars [Member] | Fixed Price Five [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas	70,000
Natural Gas Costless Collars [Member] | Fixed Price Six [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas	70,000
Natural Gas Costless Collars [Member] | Fixed Price Seven [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas	50,000
Natural Gas Costless Collars [Member] | Fixed Price Eight [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas	70,000
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		30,000
Contract price		4.30
Natural Gas Fixed Price Swaps [Member] | Fixed Price Four [Member]
Derivative [Line Items]
Production volume covered per month - Natural Gas		40,000
Contract price		4.61
Oil Costless Collars [Member] | Fixed Price Five [Member]
Derivative [Line Items]
Production volume covered per month - Oil		4,000
Oil Costless Collars [Member] | Fixed Price Six [Member]
Derivative [Line Items]
Production volume covered per month - Oil		5,000
Oil Costless Collars [Member] | Fixed Price Nine [Member]
Derivative [Line Items]
Production volume covered per month - Oil	10,000
Oil Fixed Price Swaps [Member] | Fixed Price Seven [Member]
Derivative [Line Items]
Production volume covered per month - Oil		3,000
Contract price		94.50
Oil Fixed Price Swaps [Member] | Fixed Price Eight [Member]
Derivative [Line Items]
Production volume covered per month - Oil		4,000
Contract price		99.40
Oil Fixed Price Swaps [Member] | Fixed Price Nine [Member]
Derivative [Line Items]
Production volume covered per month - Oil		4,000
Contract price		95.25
Oil Fixed Price Swaps [Member] | Fixed Price Ten [Member]
Derivative [Line Items]
Production volume covered per month - Oil	6,000	5,000
Contract price	92.85	94.20
Oil Fixed Price Swaps [Member] | Fixed Price Eleven [Member]
Derivative [Line Items]
Production volume covered per month - Oil	7,000	6,000
Contract price	96.80	92.85
Oil Fixed Price Swaps [Member] | Fixed Price Twelve [Member]
Derivative [Line Items]
Production volume covered per month - Oil	5,000	7,000
Contract price	97.40	96.80
Oil Fixed Price Swaps [Member] | Fixed Price Thirteen [Member]
Derivative [Line Items]
Production volume covered per month - Oil	4,000	5,000
Contract price	97.25	97.40
Oil Fixed Price Swaps [Member] | Fixed Price Fourteen [Member]
Derivative [Line Items]
Production volume covered per month - Oil	5,000	4,000
Contract price	94.56	97.25
Oil Fixed Price Swaps [Member] | Fixed Price Fifteen [Member]
Derivative [Line Items]
Production volume covered per month - Oil	7,000	5,000
Contract price	93.91	94.56
Oil Fixed Price Swaps [Member] | Fixed Price Sixteen [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	4.00
Minimum [Member] | Natural Gas Costless Collars [Member] | Fixed Price Three [Member]
Derivative [Line Items]
Contract price	4.00
Minimum [Member] | Natural Gas Costless Collars [Member] | Fixed Price Four [Member]
Derivative [Line Items]
Contract price	3.50
Minimum [Member] | Natural Gas Costless Collars [Member] | Fixed Price Five [Member]
Derivative [Line Items]
Contract price	3.25
Minimum [Member] | Natural Gas Costless Collars [Member] | Fixed Price Six [Member]
Derivative [Line Items]
Contract price	3.50
Minimum [Member] | Natural Gas Costless Collars [Member] | Fixed Price Seven [Member]
Derivative [Line Items]
Contract price	3.50
Minimum [Member] | Natural Gas Costless Collars [Member] | Fixed Price Eight [Member]
Derivative [Line Items]
Contract price	3.50
Minimum [Member] | Oil Costless Collars [Member] | Fixed Price Five [Member]
Derivative [Line Items]
Contract price		85.00
Minimum [Member] | Oil Costless Collars [Member] | Fixed Price Six [Member]
Derivative [Line Items]
Contract price		90.00
Minimum [Member] | Oil Costless Collars [Member] | Fixed Price Nine [Member]
Derivative [Line Items]
Contract price	80.00
Maximum [Member] | Natural Gas Costless Collars [Member] | Fixed Price One [Member]
Derivative [Line Items]
Contract price	4.25	4.50
Maximum [Member] | Natural Gas Costless Collars [Member] | Fixed Price Two [Member]
Derivative [Line Items]
Contract price	5.00
Maximum [Member] | Natural Gas Costless Collars [Member] | Fixed Price Three [Member]
Derivative [Line Items]
Contract price	4.60
Maximum [Member] | Natural Gas Costless Collars [Member] | Fixed Price Four [Member]
Derivative [Line Items]
Contract price	4.10
Maximum [Member] | Natural Gas Costless Collars [Member] | Fixed Price Five [Member]
Derivative [Line Items]
Contract price	4.00
Maximum [Member] | Natural Gas Costless Collars [Member] | Fixed Price Six [Member]
Derivative [Line Items]
Contract price	4.05
Maximum [Member] | Natural Gas Costless Collars [Member] | Fixed Price Seven [Member]
Derivative [Line Items]
Contract price	4.00
Maximum [Member] | Natural Gas Costless Collars [Member] | Fixed Price Eight [Member]
Derivative [Line Items]
Contract price	3.95
Maximum [Member] | Oil Costless Collars [Member] | Fixed Price Five [Member]
Derivative [Line Items]
Contract price		100.00
Maximum [Member] | Oil Costless Collars [Member] | Fixed Price Six [Member]
Derivative [Line Items]
Contract price		97.00
Maximum [Member] | Oil Costless Collars [Member] | Fixed Price Nine [Member]
Derivative [Line Items]
Contract price	86.50

XML

Derivatives (Tables)

3 Months Ended

Dec. 31, 2014

Derivatives [Abstract]

Summary Of Derivative Instruments Contracts

Derivative contracts in place as of December 31, 2014

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
November 2014 - April 2015	100,000 Mmbtu	NYMEX Henry Hub	$3.75 floor / $4.25 ceiling
January - March 2015	100,000 Mmbtu	NYMEX Henry Hub	$4.00 floor / $5.00 ceiling
January - March 2015	30,000 Mmbtu	NYMEX Henry Hub	$4.00 floor / $4.60 ceiling
January - December 2015	100,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $4.10 ceiling
January - December 2015	70,000 Mmbtu	NYMEX Henry Hub	$3.25 floor / $4.00 ceiling
April - September 2015	70,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $4.05 ceiling
April - October 2015	50,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $4.00 ceiling
May - October 2015	70,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $3.95 ceiling
Oil costless collars
July - December 2015	10,000 Bbls	NYMEX WTI	$80.00 floor / $86.50 ceiling
Oil fixed price swaps
January - March 2015	6,000 Bbls	NYMEX WTI	$92.85
January - June 2015	7,000 Bbls	NYMEX WTI	$96.80
January - June 2015	5,000 Bbls	NYMEX WTI	$97.40
January - June 2015	4,000 Bbls	NYMEX WTI	$97.25
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, 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
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
June - December 2014	4,000 Bbls	NYMEX WTI	$99.40
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
January - June 2015	7,000 Bbls	NYMEX WTI	$96.80
January - June 2015	5,000 Bbls	NYMEX WTI	$97.40
January - June 2015	4,000 Bbls	NYMEX WTI	$97.25
April - December 2015	5,000 Bbls	NYMEX WTI	$94.56
July - December 2015	7,000 Bbls	NYMEX WTI	$93.91

Summary Of Derivative Contracts

	12/31/2014		9/30/2014
	Fair Value (a)		Fair Value (a)
	Commodity Contracts		Commodity Contracts
	Current Assets		Current Assets			Current Liabilities	Non-Current Assets
Gross amounts recognized	$	12,333,036	$	1,658,785	$	8,222	$	251,279
Offsetting adjustments		-		(8,222)		(8,222)		-
Net presentation on Condensed Balance Sheets	$	12,333,036	$	1,650,563	$	-	$	251,279

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

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Derivatives (Summary Of Derivative Contracts) (Details) (USD $)	Dec. 31, 2014		Sep. 30, 2014
Derivatives [Abstract]
Gross amounts recognized - Current Assets	$ 12,333,036	[1]	$ 1,658,785	[1]
Offsetting adjustments - Current Assets		[1]	(8,222)	[1]
Net presentation on Condensed Balance - Current Assets	12,333,036	[1]	1,650,563	[1]
Gross amounts recognized - Current Liabilities			8,222	[1]
Offsetting adjustments - Current Liabilities			(8,222)	[1]
Net presentation on Condensed Balance - Current Liabilities				[1]
Gross amounts recognized - Non-Current Assets			251,279	[1]
Offsetting adjustments - Non-current Assets				[1]
Net presentation on Condensed Balance - Non-Current Assets			$ 251,279	[1]

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

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Acquisitions (Tables)

3 Months Ended

Dec. 31, 2014

Acquisitions [Abstract]

Summary Of Pro Forma Financial Information

	For the Three Months Ended
	December 31,
	2014		2013
Revenue:
As reported	$	30,999,170	$	18,396,756
Pro forma revenue		-		5,869,980
Pro forma	$	30,999,170	$	24,266,736
Net Income:
As reported	$	10,233,761	$	4,926,318
Pro forma income		-		2,435,848
Pro forma	$	10,233,761	$	7,362,166

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Condensed Statements Of Cash Flows (USD $)	3 Months Ended
	Dec. 31, 2014		Dec. 31, 2013
Operating Activities
Net income (loss)	$ 10,233,761		$ 4,926,318
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	6,139,019		5,308,019
Impairment	2,191,997	[1]	202,991	[1]
Provision for deferred income taxes	1,184,000		326,000
Exploration costs	25,352		38,755
Gain from leasing fee mineral acreage	(29,162)		(196,133)
Income from partnerships	(199,914)		(224,346)
Distributions received from partnerships	256,017		279,363
Directors' deferred compensation expense	101,589		114,069
Restricted stock awards	165,111		127,976
Cash provided (used) by changes in assets and liabilities:
Oil, NGL and natural gas sales receivables	2,672,119		(956,975)
Fair value of derivative contracts	(10,431,194)		891,970
Refundable production taxes	13,205		53,824
Other current assets	99,085		(35,813)
Accounts payable	565,409		414,267
Income taxes payable	2,891,600		1,088,350
Accrued liabilities	(692,505)		(472,288)
Total adjustments	4,951,728		6,960,029
Net cash provided by operating activities	15,185,489		11,886,347
Investing Activities
Capital expenditures, including dry hole costs	(14,901,631)		(9,892,262)
Acquisition of working interest properties			(1,550,205)
Acquisition of minerals and overrides			(56,250)
Proceeds from leasing fee mineral acreage	29,798		216,773
Investments in partnerships	(173,103)		(143,695)
Net cash used in investing activities	(15,044,936)		(11,425,639)
Financing Activities
Borrowings under debt agreement	12,335,774		2,280,280
Payments of loan principal	(11,620,667)		(4,542,536)
Purchases of treasury stock	(120,611)		(122,044)
Payments of dividends	(666,199)		(664,618)
Excess tax benefit on stock-based compensation	(59,000)		16,000
Net cash provided by (used in) financing activities	(130,703)		(3,032,918)
Increase (decrease) in cash and cash equivalents	9,850		(2,572,210)
Cash and cash equivalents at beginning of period	509,755		2,867,171
Cash and cash equivalents at end of period	519,605		294,961
Supplemental Schedule of Noncash Investing and Financing Activities:
Dividends declared and unpaid	666,824		663,654
Additions to asset retirement obligations	26,452		53,653
Gross additions to properties and equipment	13,469,206		9,843,214
Net (increase) decrease in accounts payable for properties and equipment additions	1,432,425		1,655,503
Capital expenditures and acquisitions, including dry hole costs	$ 14,901,631		$ 11,498,717

[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 $)	Dec. 31, 2014	Sep. 30, 2014
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	16,863,004	16,863,004
Treasury stock, shares	355,558	372,364

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Derivatives

3 Months Ended

Dec. 31, 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 under its credit facility with Bank of Oklahoma.The derivative instruments have settled or will settle based on the prices below.

Derivative contracts in place as of December 31, 2014

	Production volume
Contract period	covered per month	Index	Contract price
Natural gas costless collars
November 2014 - April 2015	100,000 Mmbtu	NYMEX Henry Hub	$3.75 floor / $4.25 ceiling
January - March 2015	100,000 Mmbtu	NYMEX Henry Hub	$4.00 floor / $5.00 ceiling
January - March 2015	30,000 Mmbtu	NYMEX Henry Hub	$4.00 floor / $4.60 ceiling
January - December 2015	100,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $4.10 ceiling
January - December 2015	70,000 Mmbtu	NYMEX Henry Hub	$3.25 floor / $4.00 ceiling
April - September 2015	70,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $4.05 ceiling
April - October 2015	50,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $4.00 ceiling
May - October 2015	70,000 Mmbtu	NYMEX Henry Hub	$3.50 floor / $3.95 ceiling
Oil costless collars
July - December 2015	10,000 Bbls	NYMEX WTI	$80.00 floor / $86.50 ceiling
Oil fixed price swaps
January - March 2015	6,000 Bbls	NYMEX WTI	$92.85
January - June 2015	7,000 Bbls	NYMEX WTI	$96.80
January - June 2015	5,000 Bbls	NYMEX WTI	$97.40
January - June 2015	4,000 Bbls	NYMEX WTI	$97.25
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, 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
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
June - December 2014	4,000 Bbls	NYMEX WTI	$99.40
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
January - June 2015	7,000 Bbls	NYMEX WTI	$96.80
January - June 2015	5,000 Bbls	NYMEX WTI	$97.40
January - June 2015	4,000 Bbls	NYMEX WTI	$97.25
April - December 2015	5,000 Bbls	NYMEX WTI	$94.56
July - December 2015	7,000 Bbls	NYMEX WTI	$93.91

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 asset of $12,333,036 as of December 31, 2014, and a net asset of $1,901,842 as of September 30, 2014.

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 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 December 31, 2014, and September 30, 2014. 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 December 31, 2014, and September 30, 2014.

	12/31/2014		9/30/2014
	Fair Value (a)		Fair Value (a)
	Commodity Contracts		Commodity Contracts
	Current Assets		Current Assets			Current Liabilities	Non-Current Assets
Gross amounts recognized	$	12,333,036	$	1,658,785	$	8,222	$	251,279
Offsetting adjustments		-		(8,222)		(8,222)		-
Net presentation on Condensed Balance Sheets	$	12,333,036	$	1,650,563	$	-	$	251,279

(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.

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Document and Entity Information	3 Months Ended
	Dec. 31, 2014	Feb. 09, 2015
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	Dec. 31, 2014
Amendment Flag	false
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--09-30
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		16,507,446

XML

Fair Value Measurements

3 Months Ended

Dec. 31, 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 December 31, 2014.

	Fair Value Measurement at December 31, 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	$	-	$	8,386,282	$	-	$	8,386,282
Derivative Contracts - Collars	$	-	$	-	$	3,946,754	$	3,946,754

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 December 31, 2014
Oil Collars	Oil price volatility curve	0% - 38.56%	30.91%	$	1,557,327
Natural Gas Collars	Natural gas price volatility curve	0% - 33.11%	23.26%	$	2,389,427

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, 2014	$	30,044
Total gains or (losses)
Included in earnings		3,775,971
Included in other comprehensive income (loss)		-
Purchases, issuances and settlements		140,739
Transfers in and out of Level 3		-
Balance of Level 3 as of December 31, 2014	$	3,946,754

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 December 31,
	2014				2013
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	2,322,760	$	2,191,997	$	236,199	$	202,991

(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 December 31, 2014, and September 30, 2014, 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
	Dec. 31, 2014	Dec. 31, 2013
Revenues:
Oil, NGL and natural gas sales	$ 19,519,700	$ 18,473,082
Lease bonuses and rentals	29,291	196,229
Gains (losses) on derivative contracts	11,250,265	(496,901)
Income from partnerships	199,914	224,346
Total revenues	30,999,170	18,396,756
Costs and expenses:
Lease operating expenses	4,785,350	3,315,397
Production taxes	622,512	571,564
Exploration costs	25,352	38,755
Depreciation, depletion and amortization	6,139,019	5,308,019
Provision for impairment	2,191,997	202,991
Loss (gain) on asset sales and other	(1,982)	(77,455)
Interest expense	402,733
General and administrative	1,958,428	1,873,167
Total costs and expenses	16,123,409	11,232,438
Income before provision for income taxes	14,875,761	7,164,318
Provision for income taxes	4,642,000	2,238,000
Net income	$ 10,233,761	$ 4,926,318
Basic and diluted earnings per common share (Note 3)	$ 0.61	$ 0.29
Basic and diluted weighted average shares outstanding:
Common shares	16,494,805	16,463,804
Unissued, directors' deferred compensation shares	262,121	246,122
Basic and diluted weighted average shares outstanding	16,756,926	16,709,926
Dividends declared per share of common stock and paid in period	$ 0.04	$ 0.04
Dividends declared per share of common stock and to be paid in quarter ended March 31	$ 0.04	$ 0.04

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Deferred Compensation Plan For Directors

3 Months Ended

Dec. 31, 2014

Deferred Compensation Plan For Directors [Abstract]

Deferred Compensation Plan For Directors

NOTE 5: Deferred Compensation Plan for Directors

Annually, non-employee directors may elect to be included in the Directors’ Deferred Compensation Plan.  The Directors’ Deferred Compensation Plan provides that each outside director may individually elect to be credited with future unissued shares of Company Common Stock rather than cash for all or a portion of the annual retainers, Board meeting fees and committee meeting fees, and may elect to receive shares, when issued, over annual time periods up to ten years.  These unissued shares are recorded to each director’s deferred compensation account at the closing market price of the shares (i) on the dates of the Board and committee meetings, and (ii) on the payment dates of the annual retainers.  Only on a director’s retirement, termination, death, or a change-in-control of the Company will the shares recorded for such director under the Directors’ Deferred Compensation Plan be issued to the director.  The promise to issue such shares in the future is an unsecured obligation of the Company.

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Long-Term Debt

3 Months Ended

Dec. 31, 2014

Long-Term Debt [Abstract]

Long-Term Debt

NOTE 4: Long-term Debt

The Company has a $200,000,000 credit facility with a group of banks headed by Bank of Oklahoma (BOK) with a borrowing base of $130,000,000 and a maturity date of November 30, 2018. The credit facility is subject to a semi-annual borrowing base determination, wherein BOK applies their 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 $176,724,836 at December 31, 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 December 31, 2014, the effective interest rate was 2.34%.

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

The borrowing base of $130,000,000 was reaffirmed by the banks in December 2014. Determinations of the borrowing base are made semi-annually or whenever the banks, in their discretion, believe that there has been a material change in the value of the oil and natural gas properties. 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 December 31, 2014, the Company was in compliance with the covenants of the loan agreement.

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Fair Value Measurements (Tables)

3 Months Ended

Dec. 31, 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 December 31, 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	$	-	$	8,386,282	$	-	$	8,386,282
Derivative Contracts - Collars	$	-	$	-	$	3,946,754	$	3,946,754

Summary Of Unobservable Inputs For Level 3 Fair Value Measurements

Instrument Type	Unobservable Input	Range	Weighted Average	Fair Value December 31, 2014
Oil Collars	Oil price volatility curve	0% - 38.56%	30.91%	$	1,557,327
Natural Gas Collars	Natural gas price volatility curve	0% - 33.11%	23.26%	$	2,389,427

Summary Of Reconciliation Of Assets Classified As Level 3 Measurements

	Derivatives
Balance of Level 3 as of October 1, 2014	$	30,044
Total gains or (losses)
Included in earnings		3,775,971
Included in other comprehensive income (loss)		-
Purchases, issuances and settlements		140,739
Transfers in and out of Level 3		-
Balance of Level 3 as of December 31, 2014	$	3,946,754

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

	Quarter Ended December 31,
	2014				2013
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties (a)	$	2,322,760	$	2,191,997	$	236,199	$	202,991

(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

3 Months Ended

Dec. 31, 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, at the time of closing, contained63 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 acquisitionincluded in the Company’s statement of operations for the three months ended December 31, 2014, were $4,270,866. Net income attributable to the acquisition included in the statement of operations for the three months ended December 31, 2014, was $872,919.

The following table presents the unaudited pro forma financial information assuming the Company had acquired this business on October 1, 2013:

	For the Three Months Ended
	December 31,
	2014		2013
Revenue:
As reported	$	30,999,170	$	18,396,756
Pro forma revenue		-		5,869,980
Pro forma	$	30,999,170	$	24,266,736
Net Income:
As reported	$	10,233,761	$	4,926,318
Pro forma income		-		2,435,848
Pro forma	$	10,233,761	$	7,362,166

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

3 Months Ended

Dec. 31, 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 December 31, 2014 and 2013, the assessment resulted in impairment provisions of $2,191,997 and $202,991, 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

3 Months Ended

Dec. 31, 2014

Restricted Stock Plan [Abstract]

Restricted Stock Plan

NOTE 6:Restricted  Stock  Plan

In March 2010, shareholders approved the Panhandle Oil and Gas Inc. 2010 Restricted Stock Plan (2010 Stock Plan), which made available 200,000 shares of common stock to provide a long-term component to the Company’s total compensation package for its officers and to further align the interest of its officers with those of its shareholders. In March 2014, shareholders approved an amendment to increase the number of shares of common stock reserved for issuance under the 2010 Stock Plan from 200,000 shares to 500,000 shares and to allow the grant of shares of restricted stock to our directors. The 2010 Stock Plan, 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 in May 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.

The following table summarizes the Company’s pre-tax compensation expense for the three months ended December 31, 2014 and 2013, related to the Company’s performance based and non-performance based restricted stock.

	Three Months Ended
	December 31,
	2014		2013
Performance based, restricted stock	$	64,174	$	72,695
Non-performance based, restricted stock		100,937		55,281
Total compensation expense	$	165,111	$	127,976

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 December 31, 2014
	Unrecognized Compensation Cost		Weighted Average Period (in years)
Performance based, restricted stock	$	205,374	1.41
Non-performance based, restricted stock		151,862	1.33
Total	$	357,236

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

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Oil, NGL And Natural Gas Reserves

3 Months Ended

Dec. 31, 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

3 Months Ended

Dec. 31, 2014

Capitalized Costs [Abstract]

Capitalized Costs

NOTE 9: Capitalized Costs

As of December 31, 2014 and 2013, non-producing oil and natural gas properties include costs of $908,872 and $83,174, respectively, on exploratory wells which were drilling and/or testing.

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Derivatives (Narrative) (Details) (USD $)	Dec. 31, 2014	Sep. 30, 2014
Derivatives [Abstract]
Fair value of derivative contracts, Asset	$ 12,333,036	$ 1,901,842

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Restricted Stock Plan (Tables)

3 Months Ended

Dec. 31, 2014

Restricted Stock Plan [Abstract]

Summary Of Pre-Tax Compensation Expense

	Three Months Ended
	December 31,
	2014		2013
Performance based, restricted stock	$	64,174	$	72,695
Non-performance based, restricted stock		100,937		55,281
Total compensation expense	$	165,111	$	127,976

Summary Of Unrecognized Compensation Cost

	As of December 31, 2014
	Unrecognized Compensation Cost		Weighted Average Period (in years)
Performance based, restricted stock	$	205,374	1.41
Non-performance based, restricted stock		151,862	1.33
Total	$	357,236

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Income Taxes (Details)	3 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Income Taxes [Abstract]
Effective tax rate	31.00%	31.00%

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Acquisitions (Narrative) (Details) (USD $)	0 Months Ended	3 Months Ended
	Jun. 17, 2014 item acre	Dec. 31, 2014
Acquisitions (Textual) [Abstract]
Producing non-operated natural gas wells	63
Revenues attributable		4,270,866
Net income attributable		872,919
Eagle Ford Shale [Member]
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	57
Undeveloped locations	109
Purchase price business acquisition	$ 81,700,000
Pearsall [Member]
Acquisitions (Textual) [Abstract]
Producing non-operated natural gas wells	5
Buda [Member]
Acquisitions (Textual) [Abstract]
Producing non-operated natural gas wells	1

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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, 2013	$ 280,938	$ 2,447,424	$ 2,756,526	$ 96,454,449	$ (6,283,851)	$ 95,655,486
Balances, Treasury shares at Sep. 30, 2013					(400,496)
Balances, shares at Sep. 30, 2013	16,863,004
Purchase of treasury stock					(122,044)	(122,044)
Purchase of treasury stock, shares					(7,444)
Restricted stock awards		127,976				127,976
Net income				4,926,318		4,926,318
Dividends				(1,328,272)		(1,328,272)
Distribution of restricted stock to officers and directors		(259,511)			275,662	16,151
Distribution of restricted stock to officers and directors, shares					18,280
Increase in deferred directors' compensation charged to expense			114,069			114,069
Balances at Dec. 31, 2013	280,938	2,315,889	2,870,595	100,052,495	(6,130,233)	99,389,684
Balances, Treasury shares at Dec. 31, 2013					(389,660)
Balances, shares at Dec. 31, 2013	16,863,004
Balances at Sep. 30, 2014	280,938	2,861,343	3,110,351	118,794,188	(5,858,167)	119,188,653
Balances, Treasury shares at Sep. 30, 2014					(372,364)	(372,364)
Balances, shares at Sep. 30, 2014	16,863,004
Purchase of treasury stock					(120,611)	(120,611)
Purchase of treasury stock, shares					(7,177)
Restricted stock awards		165,111				165,111
Net income				10,233,761		10,233,761
Dividends				(1,333,023)		(1,333,023)
Distribution of restricted stock to officers and directors		(436,303)			377,502	(58,801)
Distribution of restricted stock to officers and directors, shares					23,983
Increase in deferred directors' compensation charged to expense			101,589			101,589
Balances at Dec. 31, 2014	$ 280,938	$ 2,590,151	$ 3,211,940	$ 127,694,926	$ (5,601,276)	$ 128,176,679
Balances, Treasury shares at Dec. 31, 2014					(355,558)	(355,558)
Balances, shares at Dec. 31, 2014	16,863,004

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Basic And Diluted Earnings Per Share

3 Months Ended

Dec. 31, 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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Long-Term Debt (Details) (USD $)	3 Months Ended
	Dec. 31, 2014	Jun. 17, 2014
Line Of Credit Facility [Line Items]
Revolving loan credit facility		$ 200,000,000
Credit facility maturity	Nov. 30, 2018
Revolving Credit Facility [Member]
Line Of Credit Facility [Line Items]
Discount rate	8.00%
Borrowing base of credit facility		130,000,000
Properties carrying value	176,724,836
Effective Interest rate	2.34%
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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Fair Value Measurements (Summary Of Unobservable Inputs For Level 3 Fair Value Measurements) (Details) (USD $)	3 Months Ended
	Dec. 31, 2014
Oil Costless Collars [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Unobservable Input	Oil price volatility curve
Weighted Average	30.91%
Fair Value	$ 1,557,327
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	38.56%
Natural Gas Costless Collars [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Unobservable Input	Natural gas price volatility curve
Weighted Average	23.26%
Fair Value	$ 2,389,427
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	33.11%

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Recently Adopted Accounting Pronouncements

3 Months Ended

Dec. 31, 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.