PHX MINERALS INC. - Quarter Report: 2012 December (Form 10-Q)

phx_10q-123112.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

( X )

Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the period ended

December 31, 2012

( )

Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from

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 filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

X Yes No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

X Yes No

Indicate by check mark 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 X

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 X No

Outstanding shares of Class A Common stock (voting) at February 8, 2013: 8,258,355

INDEX

Part I	Financial Information

	Item 1 Condensed Financial Statements		Page

		Condensed Balance Sheets – December 31, 2012 and September 30, 2012	1

		Condensed Statements of Operations – Three months ended December 31, 2012 and 2011	2

		Statements of Stockholders’ Equity – Three months ended December 31, 2012 and 2011	3

		Condensed Statements of Cash Flows – Three months ended December 31, 2012 and 2011	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		16

	Item 6 Exhibits		16

	Signatures		17

The following defined terms are used in this report:

“Bbl” means barrel;

“Board” means board of directors;

“BTU” means British Thermal Units;

“CEGT” means Centerpoint Energy Gas Transmission’s East pipeline in Oklahoma;

“Company” refers to Panhandle Oil and Gas Inc.;

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

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

“FASB” means the Financial Accounting Standards Board;

“G&A” means general and administrative costs;

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

“LOE” means lease operating expense;

“Mcf” means thousand cubic feet;

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

“Mmbtu” means million BTU;

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

“NGL” means natural gas liquids;

“NYMEX” refers to the New York Mercantile Exchange;

“Panhandle” refers to Panhandle Oil and Gas Inc.;

“PEPL” means Panhandle Eastern Pipeline Company’s Texas/Oklahoma mainline;

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

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

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

PART 1 FINANCIAL INFORMATION

PANHANDLE OIL AND GAS INC.

CONDENSED BALANCE SHEETS

	December 31, 2012			September 30, 2012
Assets	(unaudited)
Current assets:
Cash and cash equivalents	$	986,363		$	1,984,099
Oil, NGL and natural gas sales receivables		8,234,220			8,349,865
Deferred income taxes		95,900			121,900
Refundable income taxes		5,980			325,715
Refundable production taxes		548,576			585,454
Derivative contracts		764,643			-
Other		155,978			255,812
Total current assets		10,791,660			11,622,845

Properties and equipment, at cost, based on successful efforts accounting:
Producing oil and natural gas properties		281,200,946			275,997,569
Non-producing oil and natural gas properties		9,962,008			10,150,561
Furniture and fixtures		703,457			668,004
		291,866,411			286,816,134
Less accumulated depreciation, depletion and amortization		(170,783,831	)		(165,199,079	)
Net properties and equipment		121,082,580			121,617,055

Investments		1,238,638			1,034,870
Refundable production taxes		736,004			911,960
Total assets	$	133,848,882		$	135,186,730

Liabilities and Stockholders' Equity
Current liabilities:
Accounts payable	$	4,057,404		$	6,447,692
Derivative contracts		-			172,271
Accrued liabilities and other		1,014,007			1,007,779
Total current liabilities		5,071,411			7,627,742

Long-term debt		14,454,757			14,874,985
Deferred income taxes		27,020,907			26,708,907
Asset retirement obligations		2,195,383			2,122,950

Stockholders' equity:
Class A voting common stock, $.0166 par value; 24,000,000 shares authorized, 8,431,502 issued at December 31, 2012, and September 30, 2012		140,524			140,524
Capital in excess of par value		2,195,559			2,020,229
Deferred directors' compensation		2,493,184			2,676,160
Retained earnings		85,805,264			84,821,395
		90,634,531			89,658,308
Less treasury stock, at cost; 173,147 shares at December 31, 2012, and 181,310 shares at September 30, 2012		(5,528,107	)		(5,806,162	)
Total stockholders' equity		85,106,424			83,852,146
Total liabilities and stockholders' equity	$	133,848,882		$	135,186,730

(See accompanying notes)

(1)

PANHANDLE OIL AND GAS INC.

CONDENSED STATEMENTS OF OPERATIONS

	Three Months Ended December 31,
	2012		2011
Revenues:	(unaudited)
Oil, NGL and natural gas sales	$	12,758,954	$	11,744,277
Lease bonuses and rentals		374,392		1,755,191
Gains (losses) on derivative contracts		892,693		(222,079	)
Income from partnerships		154,396		126,944
		14,180,435		13,404,333
Costs and expenses:
Lease operating expenses		3,296,562		2,264,912
Production taxes		303,553		438,499
Exploration costs		19,767		313,370
Depreciation, depletion and amortization		5,639,020		4,142,413
Provision for impairment		154,965		363,547
Loss (gain) on asset sales, interest and other		43,186		(77,041	)
General and administrative		1,898,084		1,697,523
		11,355,137		9,143,223
Income before provision for income taxes		2,825,298		4,261,110

Provision for income taxes		677,000		849,000

Net income	$	2,148,298	$	3,412,110





Basic and diluted earnings per common share (Note 3)	$	0.26	$	0.41

Basic and diluted weighted average shares outstanding:
Common shares		8,250,109		8,256,171
Unissued, directors' deferred compensation shares		122,285		130,654
		8,372,394		8,386,825

Dividends declared per share of common stock and paid in period	$	0.07	$	0.07

Dividends declared per share of common stock and to be paid in quarter ended March 31	$	0.07	$	0.07

(See accompanying notes)

(2)

PANHANDLE OIL AND GAS INC.

STATEMENTS OF STOCKHOLDERS’ EQUITY

Three Months Ended December 31, 2012

	Class A voting				Capital in			Deferred
	Common Stock				Excess of			Directors'			Retained			Treasury			Treasury
	Shares		Amount		Par Value			Compensation			Earnings			Shares			Stock			Total

Balances at September 30, 2012		8,431,502	$	140,524	$	2,020,229		$	2,676,160		$	84,821,395			(181,310	)	$	(5,806,162	)	$	83,852,146

Purchase of treasury stock		-		-		-			-			-			(4,198	)		(116,632	)		(116,632	)

Restricted stock awards		-		-		257,877			-			-			-			-			257,877

Net income		-		-		-			-			2,148,298			-			-			2,148,298

Dividends ($.14 per share)		-		-		-			-			(1,164,429	)		-			-			(1,164,429	)

Distribution of deferred directors' compensation		-		-		(82,547	)		(297,140	)		-			12,361			394,687			15,000

Increase in deferred directors' compensation charged to expense		-		-		-			114,164			-			-			-			114,164

Balances at December 31, 2012 (unaudited)		8,431,502	$	140,524	$	2,195,559		$	2,493,184		$	85,805,264			(173,147	)	$	(5,528,107	)	$	85,106,424

Three Months Ended December 31, 2011

	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, 2011		8,431,502	$	140,524	$	1,924,507	$	2,665,583	$	79,771,563			(175,331	)	$	(5,699,860	)	$	78,802,317

Restricted stock awards		-		-		57,729		-		-			-			-			57,729

Net income		-		-		-		-		3,412,110			-			-			3,412,110

Dividends ($.14 per share)		-		-		-		-		(1,161,075	)		-			-			(1,161,075	)

Increase in deferred directors' compensation charged to expense		-		-		-		119,876		-			-			-			119,876

Balances at December 31, 2011 (unaudited)		8,431,502	$	140,524	$	1,982,236	$	2,785,459	$	82,022,598			(175,331	)	$	(5,699,860	)	$	81,230,957

(See accompanying notes)

(3)

PANHANDLE OIL AND GAS INC.

CONDENSED STATEMENTS OF CASH FLOWS

	Three months ended December 31,
	2012			2011
Operating Activities	(unaudited)
Net income	$	2,148,298		$	3,412,110
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		5,639,020			4,142,413
Impairment		154,965			363,547
Provision for deferred income taxes		338,000			231,000
Exploration costs		19,767			313,370
Gain from leasing of fee mineral acreage		(373,440	)		(1,754,982	)
Net (gain) loss on sale of assets		-			(116,879	)
Income from partnerships		(154,396	)		(126,944	)
Distributions received from partnerships		194,147			150,404
Directors' deferred compensation expense		114,164			119,876
Restricted stock awards		257,877			57,729
Cash provided by changes in assets and liabilities:
Oil and natural gas sales receivables		115,645			338,124
Fair value of derivative contracts		(936,914	)		536,014
Refundable production taxes		212,834			65,919
Other current assets		47,528			(40,662	)
Accounts payable		(361,777	)		(95,148	)
Income taxes receivable		319,735			354,246
Other non-current assets		-			308
Income taxes payable		-			264,786
Accrued liabilities		(577,210	)		(469,579	)
Total adjustments		5,009,945			4,333,542
Net cash provided by operating activities		7,158,243			7,745,652

Investing Activities
Capital expenditures, including dry hole costs		(6,864,399	)		(6,344,006	)
Acquisition of working interest properties		-			(17,399,052	)
Acquisition of minerals and overrides		(330,000	)		(1,384,897	)
Proceeds from leasing of fee mineral acreage		384,790			1,802,892
Investments in partnerships		(243,519	)		(63,242	)
Proceeds from sales of assets		-			128,925
Excess tax benefit on stock-based compensation		15,000			-
Net cash used in investing activities		(7,038,128	)		(23,259,380	)

Financing Activities
Borrowings under debt agreement		4,171,662			25,726,136
Payments of loan principal		(4,591,890	)		(11,203,765	)
Purchase of treasury stock		(116,632	)		-
Payments of dividends		(580,991	)		(579,756	)
Net cash provided by (used in) financing activities		(1,117,851	)		13,942,615

Increase (decrease) in cash and cash equivalents		(997,736	)		(1,571,113	)
Cash and cash equivalents at beginning of period		1,984,099			3,506,999
Cash and cash equivalents at end of period	$	986,363		$	1,935,886

Supplemental Schedule of Noncash Investing and Financing Activities
Dividends declared and unpaid	$	583,438		$	581,319
Additions to asset retirement obligations	$	42,156		$	16,246

Gross additions to properties and equipment	$	5,218,194		$	23,483,505
Net (increase) decrease in accounts payable for properties and equipment additions		1,976,205			1,644,450
Capital expenditures and acquisitions, including dry hole costs	$	7,194,399		$	25,127,955

(See accompanying notes)

(4)

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 2012 Annual Report on Form 10-K.

Certain amounts (net gain on sales of assets in the Statements of Cash Flows) in the prior year have been reclassified to conform to the current year presentation.

NOTE 2: Income Taxes

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

Both excess federal percentage depletion, which is limited to certain production volumes and by certain income levels, and excess Oklahoma percentage depletion, which has no limitation on production volume, reduce estimated taxable income or add to estimated taxable loss projected for any year. The federal and Oklahoma excess percentage depletion estimates will be updated throughout the year until finalized with the detail well-by-well calculations at fiscal year-end. Federal and Oklahoma excess percentage depletion benefits, when a provision for income taxes is recorded, decrease 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 quarter ended December 31, 2012, was 24% as compared to 20% for the quarter ended December 31, 2011.

NOTE 3: Basic and Diluted Earnings per Share

Basic and diluted earnings per share is calculated using net income divided by the weighted average number of voting common shares outstanding, including unissued, vested directors’ deferred compensation shares during the period.

NOTE 4: Long-term Debt

The Company has a credit facility with Bank of Oklahoma (BOK) which consists of a revolving loan in the amount of $80,000,000 which is subject to a semi-annual borrowing base determination, wherein BOK applies their own current pricing forecast and an 8% discount rate to the Company’s proved reserves as calculated by the Company’s Independent Consulting Petroleum Engineering Firm. When applying the discount rate, BOK also applies an advance rate percentage to all proved non-producing and proved undeveloped reserves. The facility has a borrowing base of $35,000,000 and is secured by certain of the Company’s properties with a carrying value of $39,367,672 at December 31, 2012. The facility matures on November 30, 2014. The interest rate is based on national prime plus from .50% to 1.25%, or 30 day LIBOR plus from 2.00% to 2.75%. The election of national prime or LIBOR is at the Company’s discretion. The interest rate spread from LIBOR or the prime rate increases as a larger percent of the loan value of the Company’s oil and natural gas properties is advanced. The interest rate spread from national prime or LIBOR will be charged based on the percent of the value advanced of the calculated loan value of the Company’s oil and natural gas properties. At December 31, 2012 the effective interest rate was 2.31%.

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

Since the bank charges a customary non-use fee of .25% annually of the unused portion of the borrowing base, the Company has not requested the bank to increase its borrowing base beyond $35,000,000. Determinations of the borrowing base are made semi-annually or whenever the bank, in its sole discretion, believes that there has been a material change in the value of the oil and natural gas properties. 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, 2012, the Company was in compliance with the covenants of the BOK agreement.

(5)

NOTE 5: Deferred Compensation Plan for Directors

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

NOTE 6: Restricted Stock Plan

On March 11, 2010, shareholders approved the Panhandle Oil and Gas Inc. 2010 Restricted Stock Plan (2010 Stock Plan), which made available 100,000 shares of common stock to provide a long-term component to the Company’s total compensation package for its officers and to further align the interest of its officers with those of its shareholders. The 2010 Stock Plan 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 officers of the Company and to align their interests with those of the Company’s shareholders.

Effective March 2010, the board of directors approved the purchase of the Company’s common stock, from time to time, equal to the aggregate number of shares of common stock awarded pursuant to the Company’s 2010 Restricted Stock Plan, contributed by the Company to its ESOP and credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors.

On December 11, 2012, the Company awarded 6,701 non-performance based shares and 20,104 performance based shares of the Company’s common stock as restricted stock to certain officers. The restricted stock vests at the end of three years and contains nonforfeitable rights to receive dividends and voting rights during the vesting period. The non-performance and performance based shares had a fair value on their award date of $195,603 and $305,154, respectively, and will be recognized as compensation expense ratably over the vesting period. The fair value of the performance based shares on their award date is calculated by simulating the Company’s stock price and stock price return utilizing a Monte Carlo model covering the period from the grant date through the end of the performance period (December 11, 2012, through December 11, 2015).

The following table summarizes the Company’s pre-tax compensation expense for the three months ended December 31, 2012 and 2011, related to the Company’s performance based and non-performance based restricted stock.

	Three Months Ended
	December 31,
	2012		2011
Performance based, restricted stock	$	99,939	$	21,387
Non-performance based, restricted stock		157,938		36,342
Total compensation expense	$	257,877	$	57,729

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, 2012
	Unrecognized Compensation Cost		Weighted Average Period (in years)
Performance based, restricted stock	$	528,192		1.91
Non-performance based, restricted stock		408,252		1.99
Total	$	936,444

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

(6)

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 prices current with the 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. Crude oil, NGL and natural gas prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. 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.

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. The assessments at December 31, 2012 and 2011 resulted in $154,965 and $363,547 provision, respectively. A reduction in oil, NGL and 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

For the periods ending December 31, 2012 and 2011, non-producing oil and natural gas properties include costs of $0 and $1,378,864, respectively, on exploratory wells which were drilling and/or testing.

NOTE 10: Exploration Costs

In the quarter ended December 31, 2012, lease expirations and leasehold impairments of $13,222 were charged to exploration costs. Leasehold impairments are recorded for individually insignificant non-producing leases which the Company believes will not be transferred to proved properties over the remaining lives of the leases. In the quarter ended December 31, 2012, the Company also had additional costs of $6,545 related to exploratory dry hole adjustments. In the quarter ended December 31, 2011, lease expirations and impairments of $311,817 were charged to exploration costs as well as additional costs of $1,553 related to exploratory dry holes.

NOTE 11: Derivatives

The Company has entered into basis protection swaps and costless collar contracts. These instruments are intended to reduce the Company’s exposure to short-term fluctuations in the price of oil and natural gas. Basis protection swaps are derivatives that guarantee a price differential to NYMEX for natural gas from a specified delivery point (CEGT and PEPL historically). The Company receives a payment from the counterparty if the price differential is greater than the agreed terms of the contract and pays the counterparty if the price differential is less than the agreed terms of the contract. Collar contracts set a fixed floor price and a fixed ceiling price and provide for payments to the Company if the basis adjusted price falls below the floor or require payments by the Company if the basis adjusted 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 unsecured. The derivative instruments have settled or will settle based on the prices below which are adjusted for location differentials and tied to certain pipelines.

(7)

Derivative contracts in place as of December 31, 2012

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

	Production volume	Indexed
Contract period	covered per month	pipeline	Fixed price
Natural gas costless collars
November 2012 - January 2013	150,000 Mmbtu	NYMEX Henry Hub	$3.00 floor/$3.70 ceiling
November 2012 - January 2013	150,000 Mmbtu	NYMEX Henry Hub	$3.00 floor/$3.70 ceiling
November 2012 - January 2013	50,000 Mmbtu	NYMEX Henry Hub	$3.00 floor/$3.65 ceiling
February 2013 - December 2013	80,000 Mmbtu	NYMEX Henry Hub	$3.75 floor/$4.25 ceiling
February 2013 - December 2013	50,000 Mmbtu	NYMEX Henry Hub	$3.75 floor/$4.30 ceiling
February 2013 - December 2013	100,000 Mmbtu	NYMEX Henry Hub	$3.75 floor/$4.05 ceiling

Derivative contracts in place as of September 30, 2012

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

	Production volume	Indexed (1)
Contract period	covered per month	pipeline	Fixed price
Natural gas basis protection swaps
January - December 2012	50,000 Mmbtu	CEGT	NYMEX -$.29
January - December 2012	40,000 Mmbtu	CEGT	NYMEX -$.30
January - December 2012	50,000 Mmbtu	PEPL	NYMEX -$.29
January - December 2012	50,000 Mmbtu	PEPL	NYMEX -$.30

Natural gas costless collars
March - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50 floor/$3.25 ceiling
April - October 2012	120,000 Mmbtu	NYMEX Henry Hub	$2.50 floor/$3.10 ceiling
April - October 2012	60,000 Mmbtu	NYMEX Henry Hub	$2.50 floor/$3.20 ceiling
April - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50 floor/$3.20 ceiling
April - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50 floor/$3.45 ceiling
April - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50 floor/$3.30 ceiling
August - October 2012	50,000 Mmbtu	NYMEX Henry Hub	$2.50 floor/$3.30 ceiling
November 2012 - January 2013	150,000 Mmbtu	NYMEX Henry Hub	$3.00 floor/$3.70 ceiling
November 2012 - January 2013	150,000 Mmbtu	NYMEX Henry Hub	$3.00 floor/$3.70 ceiling
November 2012 - January 2013	50,000 Mmbtu	NYMEX Henry Hub	$3.00 floor/$3.65 ceiling

Oil costless collars
January - December 2012	2,000 Bbls	NYMEX WTI	$90 floor/$105 ceiling
February - December 2012	3,000 Bbls	NYMEX WTI	$90 floor/$110 ceiling
May - December 2012	2,000 Bbls	NYMEX WTI	$90 floor/$114 ceiling

(1) CEGT - Centerpoint Energy Gas Transmission's East pipeline in Oklahoma
PEPL - Panhandle Eastern Pipeline Company's Texas/Oklahoma mainline

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 an asset of $764,643 as of December 31, 2012, and a liability of $172,271 as of September 30, 2012. Realized and unrealized gains and (losses) for the periods ended December 31, 2012, and December 31, 2011, are scheduled below:

Gains (losses) on natural gas	Three months ended
derivative contracts	12/31/2012			12/31/2011
Realized	$	(44,221	)	$	313,935
Increase (decrease) in fair value		936,914			(536,014	)
Total	$	892,693		$	(222,079	)

(8)

To the extent that a legal right of offset exists, the Company nets the fair value of its derivative contracts with the same counterparty in the accompanying balance sheets. The following table summarizes the Company’s derivative contracts as of December 31, 2012, and September 30, 2012:

		Balance Sheet	12/31/2012		9/30/2012
		Location	Fair Value		Fair Value
Asset Derivatives:
Derivatives not designated as Hedging Instruments:
Commodity contracts		Short-term derivative contracts	$	764,643	$	-
Commodity contracts		Long-term derivative contracts		-		-
	Total Asset Derivatives (a)		$	764,643	$	-

Liability Derivatives:
Derivatives not designated as Hedging Instruments:
Commodity contracts		Short-term derivative contracts	$	-	$	172,271
Commodity contracts		Long-term derivative contracts		-		-
	Total Liability Derivatives (a)		$	-	$	172,271

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

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

NOTE 12: 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, 2012.

	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total Fair Value
Financial Assets (Liabilities):
Derivative Contracts - Collars	$	-	$	-	$	764,643	$	764,643

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, among other things, future prices, volatility and time to maturity. These values are then compared to the values given by our counterparties for reasonableness.

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

(9)

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, 2012

Oil Collars	Oil price volatility curve		0%	-	0%		0	%	$	14,980
Natural Gas Collars	Natural gas price volatility curve		0%	-	29.39%		20.14	%	$	749,663

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

	Derivatives
Balance of Level 3 as of October 1, 2012	$	(96,937	)
Total gains or (losses) - realized and unrealized:
Included in earnings
Realized		23,579
Unrealized		838,001
Included in other comprehensive income (loss)
Purchases, issuances and settlements
Transfers in and out of Level 3

Balance of Level 3 as of December 31, 2012	$	764,643

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,
	2012				2011
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties	$	332,220	$	154,965	$	419,122	$	363,547	(a)

(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.

The carrying amounts reported in the balance sheets for cash and cash equivalents, receivables, refundable income taxes, accounts payable and accrued liabilities approximate their fair values due to the short maturity of these instruments. The fair value of Company’s debt approximates its carrying amount due to the interest rates on the Company’s revolving line of credit being rates which are approximately equivalent to market rates for similar type debt based on the Company’s credit worthiness, which represents level 3 of the fair value hierarchy.

NOTE 13: Recently Adopted Accounting Pronouncements

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

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.

(10)

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 2013 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 2012 Annual Report on Form 10-K where risk factors are presented and further discussed. For all the above reasons, actual results may vary materially from the Forward-Looking Statements and there is no assurance that the assumptions used are necessarily the most likely to occur.

LIQUIDITY AND CAPITAL RESOURCES

The Company had positive working capital of $5,720,249 at December 31, 2012, compared to $3,995,103 at September 30, 2012.

Liquidity:

Cash and cash equivalents were $986,363 as of December 31, 2012, compared to $1,984,099 at September 30, 2012, a decrease of $997,736. Cash flows for the three months ended December 31 are summarized as follows:

Net cash provided (used) by:
	2012			2011			Change

Operating activities	$	7,158,243		$	7,745,652		$	(587,409	)

Investing activities	$	(7,038,128	)	$	(23,259,380	)	$	16,221,252

Financing activities	$	(1,117,851	)	$	13,942,615		$	(15,060,466	)

Increase (decrease) in cash and cash equivalents	$	(997,736	)	$	(1,571,113	)	$	573,377

Operating activities:

The decrease of $587,409 in net cash provided by operating activities is primarily the effect of the following:

Realized gains on derivative contracts decreased $358,156 in the 2013 period, as compared to the 2012 period.

Payments for field related lease operating expenses were $244,235 higher in the 2013 period than in the 2012 period. The increase was due to new well additions and increases in ad valorem expenses.

Investing activities:

Net cash used in investing activities decreased $16,221,252 in the 2013 first quarter, the result of the following:

Capital expenditures increased approximately $500,000 in the 2013 period due to increased drilling and completion activity on the Company’s mineral and leasehold acreage during the first quarter of 2013, as compared to the first quarter of 2012.

Cash used to acquire properties decreased from $18,783,949 in the 2012 first quarter to $330,000 in the 2013 first quarter, or $18,453,949. In the 2012 first quarter the Company acquired producing properties, leasehold and mineral acreage in Arkansas totaling approximately $18.8 million.

Receipts of lease bonus payments during the 2013 period were approximately $1.4 million lower than those received during the 2012 period. Lease bonuses received during the 2013 period totaled $384,790, as compared to $1,802,892 in the 2012 period. In December 2011, the Company leased 2,431 net mineral acres in the horizontal Mississippi Limestone play in northern Oklahoma and received lease bonus payments of approximately $1.7 million.

(11)

The 2013 first quarter investments in partnerships increase of approximately $180,000, as compared to the 2012 first quarter, is the result of increased working interest participation in drilling activity on mineral acreage owned by Whiterock Royalty Partnership, in which the Company owns an 11.7% interest.

Financing activities:

Net cash of $1,117,851 was used in financing activities during the 2013 period, as compared to net cash provided by financing activities of $13,942,615 during the 2012 period. The change of $15,060,466 of net cash provided is the result of the following:

The Company financed the acquisition of producing properties and leasehold in Arkansas discussed above utilizing its credit facility with Bank of Oklahoma and cash. During the quarters ended December 31, 2012 and 2011, net borrowings were ($420,228) and $14,522,371, respectively.

The Company paid $580,991 and $579,756 in dividends during the 2013 and 2012 periods, respectively.

Stock repurchases in the amount of $116,632 were made in the 2013 period. No stock repurchases were made in the 2012 period.

Capital Resources:

Increased drilling activity, primarily in the Fayetteville Shale, western Oklahoma and the Texas Panhandle, during the 2013 first quarter, as compared to the 2012 first quarter, resulted in increased capital expenditures for drilling and completion of $520,393 (8%) from 2012 to 2013. The acreage acquired in the Fayetteville Shale during the 2012 first quarter continues to generate additional drilling opportunities for the Company. In western Oklahoma, the Texas Panhandle and other areas, drilling continues to be very active where the Company owns substantial mineral and leasehold acreage, which include the following oily and NGL rich horizontal and vertical plays:

Horizontal Granite Wash in western Oklahoma and the Texas Panhandle

Horizontal Cleveland in western Oklahoma and the Texas Panhandle

Horizontal Marmaton in western Oklahoma

Horizontal Tonkawa in western Oklahoma

Vertical Mississippian in northern Oklahoma

Vertical Spraberry in West Texas

Vertical Yeso in southeastern New Mexico

Horizontal Anadarko Basin Woodford Shale in western Oklahoma

Horizontal Ardmore Basin Woodford Shale in southern Oklahoma

Capital expenditures for drilling and completion projects for the 2013 period were $6,864,399. In addition, unleased mineral acreage in the Fayetteville Shale was acquired for $330,000. Capital expenditures for drilling and completion projects in 2013 are expected to be approximately $27 million. Although there may be decreases in oil, NGL and natural gas production from quarter to quarter (depending on the timing of new wells coming on line), we expect these capital outlays, as well as production volumes from new wells in which the Company owns a non-cost-bearing royalty interest, to result in an overall continued trend of production increases for 2013. Management will also continue to evaluate opportunities to acquire additional production or acreage.

Please note, 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 drilling and completing new wells and associated capital expenditures.

Production of oil, NGL and natural gas increased 18% on an Mcfe basis during the 2013 period, as compared to the 2012 period. Production increased in the 2013 period as a result of new production exceeding the natural production decline of existing wells. We expect production for fiscal 2013 to exceed fiscal 2012 as production continues to come on line throughout fiscal 2013.

(12)

Oil and NGL prices per barrel received by the Company for the first quarter of 2013 averaged $83.86 and $30.31, respectively. Panhandle’s oil price received has averaged 94% of NYMEX price over the last 12 months. Based on this correlation, and NYMEX oil futures prices, we expect the Company’s average oil price to be received for fiscal year 2013 to approximate $88.00 per barrel. For the last 12 months, NGL prices received averaged 36% of NYMEX oil price; this would correlate to an average NGL price for 2013 of approximately $33.00 per barrel, which is in line with management’s expectations. Natural gas prices received by the Company averaged $3.11 per Mcf for the first quarter of 2013. Based on NYMEX natural gas futures prices (the Company receives on average approximately 93% of NYMEX price for its natural gas sales), the price per Mcf to be received by the Company for fiscal year 2013 would be in the $3.20 to $3.30 range. Management expects the average natural gas price for fiscal year 2013 to be approximately the same as the fiscal 2013 first quarter. As of December 31, 2012, the Company had costless collar contracts covering 350,000 Mmbtu per month of natural gas production through January 2013 (floor and ceiling per Mmbtu of $3.00 and $3.65-$3.70, respectively) and 230,000 Mmbtu per month of natural gas production from February 2013 through December 2013 (floor and ceiling per Mmbtu of $3.75 and $4.05-$4.30, respectively). With continued oil and natural gas price volatility, management continues to evaluate opportunities for product price protection by hedging a portion of the Company’s future oil and natural gas production.

Cash provided by operating activities during the 2013 first quarter of $7,158,243 funded capital expenditures of $6,864,399 for the drilling and completion of wells. After payment of our regular $.07 per share quarterly dividend totaling $580,991, treasury stock purchases of $116,632, net principal payments under the Company’s revolving credit facility of $420,228 and other miscellaneous investing activities, cash was reduced during the first quarter of 2013 by $997,736. Net outstanding borrowings on the credit facility at December 31, 2012, were $14,454,757.

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 flow 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 ($20,545,243 at December 31, 2012) under its revolving credit facility and is in compliance with its debt covenants (current ratio, debt to EBITDA, tangible net worth and dividends as a percent of operating cash flow). While the Company believes the availability could be increased (if needed) by placing more of the Company’s properties as security under the revolving credit facility, increases are at the discretion of the bank.

Based on expected capital expenditure levels and anticipated cash flows for 2013, the Company has sufficient liquidity to fund its ongoing operations and, combined with availability under its credit facility, to fund additional acquisitions.

RESULTS OF OPERATIONS

THREE MONTHS ENDED DECEMBER 31, 2012 – COMPARED TO THREE MONTHS ENDED DECEMBER 31, 2011

Overview:

The Company recorded first quarter 2013 net income of $2,148,298, or $.26 per share, as compared to $3,412,110, or $.41 per share, in the 2012 quarter. The decrease in net income was principally due to decreased lease bonuses; lower oil, NGL and natural gas prices; increased LOE and DD&A; partially offset by higher oil, NGL and natural gas sales volumes; increased gains on derivative contracts; and decreased exploration costs and impairment expenses. These items are further discussed below.

Oil, NGL and Natural Gas Sales:

Oil, NGL and natural gas sales increased $1,014,677 or 9% for the 2013 quarter. Oil, NGL and natural gas sales were up due to increases in oil, NGL and natural gas sales volumes of 23%, 109% and 13%, respectively, partially offset by decreases in oil, NGL and natural gas prices of 6%, 24% and 10%, 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 2013 and 2012:

	Oil Bbls		Average		Mcf		Average		NGL Bbls		Average		Mcfe		Average
	Sold		Price		Sold		Price		Sold		Price		Sold		Price
Three months ended
12/31/2012		46,656	$	83.86		2,544,385	$	3.11		30,674	$	30.31		3,008,365	$	4.24
12/31/2011		38,040	$	89.39		2,243,312	$	3.46		14,662	$	40.05		2,559,524	$	4.59

This quarter’s oil production increase is due to oil drilling in the Permian Basin and in western Oklahoma oil producing plays, principally the horizontal Marmaton, Cleveland and Tonkawa. The NGL production increase is primarily the result of drilling activity in the Oklahoma oil and NGL rich plays. The natural gas production increase is largely attributable to continued drilling in the Fayetteville Shale in Arkansas. Panhandle owns substantial acreage positions in each of the previously mentioned plays, as well as in the horizontal Granite Wash and Hogshooter plays in western Oklahoma, and expects continued drilling on its acreage in all of these plays. This expected drilling activity in fiscal 2013 will provide the Company with opportunities to further increase its oil, NGL and natural gas production.

(13)

Production for the last five quarters was as follows:

Quarter ended	Oil Bbls Sold		Mcf Sold		NGL Bbls Sold		Mcfe Sold
12/31/2012		46,656		2,544,385		30,674		3,008,365
9/30/2012		45,552		2,251,540		32,538		2,720,080
6/30/2012		38,937		2,273,649		23,680		2,649,351
3/31/2012		30,614		2,303,797		27,834		2,654,485
12/31/2011		38,040		2,243,312		14,662		2,559,524

Lease Bonuses and Rentals:

Lease bonuses and rentals decreased $1,380,799 in the 2013 quarter compared to the 2012 quarter. The decrease was due to the Company leasing 2,431 net acres in the horizontal Mississippi Limestone play in northern Oklahoma for $1.7 million during the 2012 quarter.

Gains (Losses) on Derivative Contracts:

The fair value of derivative contracts was an asset of $764,643 as of December 31, 2012, and a liability of $320,074 as of December 31, 2011. We had a net gain on derivative contracts of $892,693 in the 2013 quarter as compared to a net loss of ($222,079) recorded in the 2012 quarter. The change is principally due to the natural gas collars, which were entered in the 2013 quarter, increasing in value as projected natural gas prices are below the floor prices of the collar at December 31, 2012.

Lease Operating Expenses (LOE):

LOE increased $1,031,650 or 46% in the 2013 quarter as compared to the 2012 quarter and LOE per Mcfe increased in the 2013 quarter to $1.10 per Mcfe from $.88 per Mcfe in the 2012 quarter. LOE related to field operating costs increased $239,377 in the 2013 quarter compared to the 2012 quarter, a 19% increase. This increase is principally a result of production increasing 18%. In the 2013 quarter, field operating costs were $.50 per Mcfe compared to $.49 per Mcfe in the 2012 quarter.

The increase in LOE related to field operating costs was coupled with an increase in handling fees (primarily gathering, transportation and marketing costs) on natural gas of $792,273 in the 2013 quarter compared to the 2012 quarter. On a per Mcfe basis, these fees increased $.20 due to the significant addition of new natural gas wells in the Fayetteville Shale play in Arkansas, which have higher handling fees. Handling fees are mainly charged as a percent of natural gas sales but can also be charged based on natural gas production volumes.

Production Taxes:

Production taxes decreased $134,946 or 31% in the 2013 quarter as compared to the 2012 quarter. Production taxes as a percentage of oil, NGL and natural gas sales decreased from 3.7% in the 2012 quarter to 2.4% in the 2013 quarter. The decrease in amount and rate is due mainly to the Company receiving ultra-deep well refunds and rate corrections of approximately $85,000 in the 2013 quarter. We do not accrue for ultra-deep well production tax exemptions (allowed by the state of Oklahoma) because we do not have sufficient information to calculate a reasonable estimate. The Company also had a large increase in natural gas revenues from new horizontally drilled wells in Arkansas coming on line in the 2013 quarter. These wells are eligible for reduced production tax rates (1.5%) for the first few years of production. The low overall production tax rate is due to a large proportion of the Company’s natural gas revenues coming from horizontally drilled wells, which are eligible for reduced Oklahoma and Arkansas production tax rates.

Exploration Costs:

Exploration costs decreased $293,603 in the 2013 quarter as compared to the 2012 quarter. During the 2013 quarter, leasehold impairment and expired leasehold totaled $13,222 compared to $311,817 during the 2012 quarter, a $298,595 decrease. The decrease was due primarily to one leasehold prospect which was significantly impaired in the 2012 quarter. Charges on exploratory dry holes totaled $6,545 during the 2013 quarter as compared to $1,533 in the 2012 quarter.

Depreciation, Depletion and Amortization (DD&A):

DD&A increased $1,496,607 or 36% in the 2013 quarter. DD&A in the 2013 quarter was $1.87 per Mcfe as compared to $1.62 per Mcfe in the 2012 quarter. DD&A increased $726,418 due to production on an Mcfe basis increasing 18% in the 2013 quarter compared to the 2012 quarter. The remaining increase of $770,189 was caused by a $.25 increase in the DD&A rate. This rate increase is mainly due to lower reserve prices at December 31, 2012 (compared to December 31, 2011) reducing ultimate reserves on a significant number of wells, as well as higher per Mcfe finding cost experienced in oil and liquids-rich areas where the Company is drilling and continues to have new wells come on line.

(14)

Provision for Impairment:

The provision for impairment decreased $208,582 in the 2013 quarter compared to the 2012 quarter. During the 2012 quarter, impairment of $363,547 was recorded on five smaller fields. During the 2013 quarter, impairment of $154,965 was recorded on two smaller fields. These fields have few wells and are more susceptible to impairment when a well in the field experiences downward reserve revisions.

General and Administrative Costs (G&A):

G&A costs increased $200,561 or 12% in the 2013 period. This increase is primarily related to increases in personnel expenses of $235,862 offset by decreased legal expenses of $36,791. Increases in personnel expenses are mainly due to restricted stock expense. The decrease in legal expense is a result of less acquisition activity.

Income Taxes:

Provision for income taxes decreased in the 2013 quarter by $172,000, the result of a $1,435,812 decrease in income before income taxes in the 2013 quarter compared to the 2012 quarter. The effective tax rate for the 2013 and 2012 quarters was 24% and 20%, respectively. 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 conditions and results of operations and also require the greatest amount of subjective or complex judgments by management. Judgments and uncertainties regarding the application of these policies may result in materially different amounts being reported under various conditions or using different assumptions. There have been no material changes to the critical accounting policies previously disclosed in the Company’s Form 10-K for the fiscal year ended September 30, 2012.

ITEM 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk

Oil, NGL and natural gas prices historically have been volatile, and this volatility is expected to continue. Uncertainty continues to exist as to the direction of oil, NGL and natural gas price trends, and there remains a rather wide divergence in the opinions held by some in the industry. Being primarily a natural gas producer, the Company is more significantly impacted by changes in natural gas prices than by changes in oil or NGL prices. Longer term natural gas prices will be determined by the supply of and demand for natural gas as well as the prices of competing fuels, such as crude oil and coal. The market price of oil, NGL and natural gas in 2013 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 2013 derivative contracts, based on the Company’s estimated natural gas volumes for 2013, the price sensitivity for each $0.10 per Mcf change in wellhead natural gas price is approximately $1,050,000 for operating revenue. Based on the Company’s estimated oil volumes for 2013, the price sensitivity in 2013 for each $1.00 per barrel change in wellhead oil price is approximately $155,000 for operating revenue.

Commodity Price Risk

The Company periodically utilizes derivative contracts to reduce its exposure to unfavorable changes in natural gas and oil prices. The Company does not enter into these derivatives for speculative or trading purposes. All of our outstanding derivative contracts are with one counterparty and are unsecured. 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 may expose the Company to risk of financial loss and limit the benefit of future increases in prices. As of December 31, 2012, the Company has natural gas collars in place. For the Company’s natural gas collars, a change of $.10 in the basis differential from NYMEX and the indexed pipelines would result in a change to pre-tax operating income of approximately $210,000.

Financial Market Risk

Operating income could also be impacted, to a lesser extent, by changes in the market interest rates related to the Company’s credit facilities. The revolving loan bears interest at the national prime rate plus from .50% to 1.25%, or 30 day LIBOR plus from 2.00% to 2.75%. At December 31, 2012, the Company had $14,454,757 outstanding under these facilities. At this point, the Company does not 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.

(15)

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 2 UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

During the three months ended December 31, 2012, the Company repurchased shares of the Company’s common stock as summarized in the table below.

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
12/1 - 12/31/12		4,198	$	27.78		4,198	$	1,082,000

Total		4,198	$	27.78		4,198

Upon approval by the shareholders of the Company’s 2010 Restricted Stock Plan on March 11, 2010, the Board of Directors approved repurchase of up to $1.5 million of the Company’s common stock, from time to time, equal to the aggregate number of shares of common stock awarded pursuant to the Company’s 2010 Restricted Stock Plan, contributed by the Company to its ESOP and credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors. 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 March 14, 2012. The shares are held in treasury and are accounted for using the cost method.

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

(b) Form 8-K – Dated (1/2/13), item 5.02 – Departure of Directors or Certain Officers; Election of Directors; Appointment of Certain Officers

(16)

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.



February 7, 2013		/s/ Michael C. Coffman
Date		Michael C. Coffman, President and
		Chief Executive Officer

February 7, 2013		/s/ Lonnie J. Lowry
Date		Lonnie J. Lowry, Vice President
		and Chief Financial Officer

February 7, 2013		/s/ Robb P. Winfield
Date		Robb P. Winfield, Controller
		and Chief Accounting Officer

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