Edgar Filing: PANHANDLE OIL & GAS INC

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Form 10-Q

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, 2011

( )	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)

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, 2012: 8,256,171

INDEX


			Page
Part I	Financial Information

	Item 1	Condensed Financial Statements

		Condensed Balance Sheets – December 31, 2011 and September 30, 2011	1

		Condensed Statements of Operations – Three months ended December 31, 2011 and 2010	2

		Statements of Stockholders’ Equity – Three months ended December 31, 2011 and 2010	3

		Condensed Statements of Cash Flows – Three months ended December 31, 2011 and 2010	4

		Notes to Condensed Financial Statements	5

	Item 2	Management’s discussion and analysis of financial condition and results of operations	12

	Item 3	Quantitative and qualitative disclosures about market risk	16

	Item 4	Controls and procedures	16

Part II	Other Information		17

	Item 6	Exhibits	17

	Signatures		17

The following defined terms are used in this report:

“Bbl” means barrel;

“Board” means board of directors;

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

“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(s)” 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;

“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;

“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” means 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.

References to natural gas

Excluding 2012 amounts, all references to natural gas reserves, production, sales and prices include associated natural gas liquids.

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, 2011		September 30, 2011
Assets		(unaudited)
Current assets:
Cash and cash equivalents	$	1,935,886	$	3,506,999
Oil and natural gas sales receivables		8,473,280		8,811,404
Deferred income taxes		70,900		-
Refundable income taxes		-		354,246
Refundable production taxes		366,413		223,672
Derivative contracts		-		269,329
Other		523,296		95,408

Total current assets		11,369,775		13,261,058

Properties and equipment, at cost, based on successful efforts accounting:
Producing oil and natural gas properties		253,421,239		230,554,198
Non-producing oil and natural gas properties		11,151,778		11,100,350
Furniture and fixtures		646,221		628,929

		265,219,238		242,283,477
Less accumulated depreciation, depletion and amortization		150,435,510		146,147,514

Net properties and equipment		114,783,728		96,135,963

Investments		706,978		667,504
Refundable production taxes		1,151,008		1,359,668

Total assets	$	128,011,489	$	111,424,193


Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	3,249,441	$	4,899,593
Deferred income taxes		-		7,100
Derivative contracts		320,074		-
Income taxes payable		264,786		-
Accrued liabilities and other		1,449,789		1,040,269

Total current liabilities		5,284,090		5,946,962

Long-term debt		14,522,371		-
Deferred income taxes		25,086,650		24,777,650
Asset retirement obligations		1,887,421		1,843,875
Derivative contracts		-		53,389

Stockholders’ equity:
Class A voting common stock, $.0166 par value; 24,000,000 shares authorized, 8,431,502 issued at December 31, 2011 and September 30, 2011		140,524		140,524
Capital in excess of par value		1,982,236		1,924,507
Deferred directors’ compensation		2,785,459		2,665,583
Retained earnings		82,022,598		79,771,563

		86,930,817		84,502,177
Less treasury stock, at cost; 175,331 shares at December 31, 2011 and at September 30, 2011		(5,699,860)		(5,699,860)

Total stockholders’ equity		81,230,957		78,802,317

Total liabilities and stockholders’ equity	$	128,011,489	$	111,424,193

(See accompanying notes)

(1)

PANHANDLE OIL AND GAS INC.

CONDENSED STATEMENTS OF OPERATIONS


	Three Months Ended December 31,
	2011		2010
Revenues:		(unaudited)
Oil and natural gas (and associated natural gas liquids) sales	$	11,744,277	$	9,731,574
Lease bonuses and rentals		1,755,191		113,365
Gains (losses) on derivative contracts		(222,079)		(21,439)
Income from partnerships		126,944		78,048

		13,404,333		9,901,548
Costs and expenses:
Lease operating expenses		2,264,912		2,197,870
Production taxes		438,499		344,644
Exploration costs		313,370		287,104
Depreciation, depletion and amortization		4,142,413		3,434,811
Provision for impairment		363,547		-
Loss (gain) on asset sales, interest and other		(77,041)		(5,727)
General and administrative		1,697,523		1,639,997

		9,143,223		7,898,699

Income before provision for income taxes		4,261,110		2,002,849

Provision for income taxes		849,000		576,000


Net income	$	3,412,110	$	1,426,849


Basic and diluted earnings per common share (Note 3)	$	0.41	$	0.17


Basic and diluted weighted average shares outstanding:
Common shares		8,256,171		8,301,811
Unissued, directors’ deferred compensation shares		130,654		115,483

		8,386,825		8,417,294


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, 2011


	Class A voting Common Stock				Capital in Excess of		Deferred 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		8,431,502	$	140,524	$	1,982,236	$	2,785,459	$	82,022,598		(175,331)	$	(5,699,860)	$	81,230,957

(unaudited)

Three Months Ended December 31, 2010


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


Balances at September 30, 2010		8,431,502	$	140,524	$	1,816,365	$	2,222,127	$	73,599,733			(120,560	)	$	(4,196,753	)	$	73,581,996

Purchase of treasury stock		-		-		-		-		-			(21,852	)		(576,813	)		(576,813	)

Restricted stock awards		-		-		12,028		-		-			-			-			12,028

Net income		-		-		-		-		1,426,849			-			-			1,426,849

Dividends ($.14 per share)		-		-		-		-		(1,163,329	)		-			-			(1,163,329	)

Increase in deferred directors’ compensation charged to expense		-		-		-		141,313		-			-			-			141,313


Balances at December 31, 2010		8,431,502	$	140,524	$	1,828,393	$	2,363,440	$	73,863,253			(142,412)		$	(4,773,566)		$	73,422,044

(unaudited)

(See accompanying notes)

(3)

PANHANDLE OIL AND GAS INC.

CONDENSED STATEMENTS OF CASH FLOWS


	Three months ended December 31,
	2011		2010
Operating Activities		(unaudited)
Net income	$	3,412,110	$	1,426,849
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization		4,142,413		3,434,811
Impairment		363,547		-
Provision for deferred income taxes		231,000		339,000
Exploration costs		313,370		287,104
Net (gain) loss on sale of assets		(1,871,861)		(111,478)
Income from partnerships		(126,944)		(78,048)
Distributions received from partnerships		150,404		110,743
Directors’ deferred compensation expense		119,876		141,313
Restricted stock awards		57,729		12,028
Cash provided by changes in assets and liabilities:
Oil and natural gas sales receivables		338,124		2,138,525
Fair value of derivative contracts		536,014		1,597,939
Refundable production taxes		65,919		159,708
Other current assets		(40,662)		240,951
Accounts payable		(95,148)		83,242
Income taxes receivable		354,246		-
Other non-current assets		308		-
Income taxes payable		264,786		(725,070)
Accrued liabilities		(469,579)		(477,953)

Total adjustments		4,333,542		7,152,815

Net cash provided by operating activities		7,745,652		8,579,664

Investing Activities
Capital expenditures, including dry hole costs		(6,344,006)		(6,570,808)
Acquisition of working interest properties		(17,399,052)		-
Acquisition of minerals and overrides		(1,384,897)		-
Proceeds from leasing of fee mineral acreage		1,802,892		122,678
Investments in partnerships		(63,242)		50,936
Proceeds from sales of assets		128,925		938

Net cash used in investing activities		(23,259,380)		(6,396,256)

Financing Activities
Borrowings under debt agreement		25,726,136		-
Payments of loan principal		(11,203,765)		-
Purchase of treasury stock		-		(576,813)
Payments of dividends		(579,756)		(581,675)

Net cash provided by (used in) financing activities		13,942,615		(1,158,488)


Increase (decrease) in cash and cash equivalents		(1,571,113)		1,024,920
Cash and cash equivalents at beginning of period		3,506,999		5,597,258

Cash and cash equivalents at end of period	$	1,935,886	$	6,622,178


Supplemental Schedule of Noncash Investing and Financing Activities
Dividends declared and unpaid	$	581,319	$	581,654

Additions to asset retirement obligations	$	16,246	$	3,436


Gross additions to properties and equipment	$	23,483,505	$	5,092,496
Net (increase) decrease in accounts payable for properties and equipment additions		1,644,450		1,478,312

Capital expenditures and acquisitions, including dry hole costs	$	25,127,955	$	6,570,808

(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. (the Company) have been prepared in accordance with the instructions to Form 10-Q as prescribed by the Securities and Exchange Commission (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 2011 Annual Report on Form 10-K.

NOTE 2: Income Taxes

The Company’s provision for income taxes differs from the statutory rate primarily due to estimated 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 or income, 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 (as is the case as of December 31, 2011 and 2010), 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.

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. The Company’s restricted stock awards are not included in the diluted earnings per share calculation because the effect would be anti-dilutive.

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 a 9% 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 $26,347,556 at December 31, 2011. 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, 2011 the effective interest rate was 2.63%.

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 million. 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, 2011, 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 receive shares of Company stock rather than cash for Board and committee chair retainers, Board meeting fees and Board committee meeting fees. These shares are unissued and 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 shares accrued 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.

In June 2010, the Company awarded 8,500 shares of the Company’s common stock as restricted stock to certain officers. The restricted stock vests at the end of five years and contains nonforfeitable rights to receive dividends and voting rights during the vesting period. The fair value of the shares at the time of their award, based on the closing price of the shares on their award date, was $240,550 and will be recognized as compensation expense ratably over the vesting period.

On December 21, 2010, the Company awarded 8,780 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 fair value of the shares at the time of their award, based on the closing price of the shares on their award date, was $245,840 and will be recognized as compensation expense ratably over the vesting period.

On December 8, 2011, the Company awarded 5,903 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 fair value of the shares at the time of their award, based on the closing price of the shares on their award date, was $186,240 and will be recognized as compensation expense ratably over the vesting period.

The impact of these awards on G&A expense in the quarters ended December 31, 2011 and 2010 was $36,342 and $12,028, respectively. As of December 31, 2011, there was $514,688 of total unrecognized compensation cost related to these awards. The cost is to be recognized over a weighted average period of 2.78 years. Upon vesting, shares are expected to be issued out of shares held in treasury.

A summary of the status of unvested shares of restricted stock awards and changes during 2012 is presented below:


	Unvested Restricted Shares		Weighted Average Grant- Date Fair Value
Unvested shares as of September 30, 2011		17,280	$	28.15
Granted		5,903	$	31.55
Vested		-		-
Forfeited		-		-


Unvested shares as of December 31, 2011		23,183	$	29.01

On December 21, 2010, the Company also awarded 8,782 shares of the Company’s common stock, subject to certain share price performance standards, as restricted stock to certain officers. On December 8, 2011, the Company also awarded 17,709 shares of the Company’s common stock, subject to certain share price performance standards, as restricted stock to certain officers. Vesting of these shares is based on the performance of the market price of the common stock over the vesting period (three years). The fair value of the performance shares was estimated on the grant date using a Monte Carlo valuation model that factors in information, including the expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance shares. Compensation expense for the performance shares is a fixed amount determined at the grant date and is recognized over the vesting period (three years) regardless of whether performance shares are awarded at the end of the vesting period.

The impact of these awards on G&A expense in the quarters ended December 31, 2011 and 2010 was $21,387 and $0, respectively. As of December 31, 2011, there was $452,070 of total unrecognized compensation cost related to this performance-based, restricted stock. The cost is to be recognized over a weighted average period of 2.61 years.

(6)

NOTE 7: Oil and Natural Gas Reserves

Management considers the estimation of the Company’s crude oil, natural gas and NGL reserves to be the most significant of its judgments and estimates. Changes in crude oil, natural gas and NGL 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, natural gas and NGL 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, natural gas and NGL reserves were computed using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month oil, natural gas and NGL 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, natural gas and NGL prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. However, projected future crude oil, natural gas and NGL pricing assumptions are used by management to prepare estimates of crude oil, natural gas and NGL 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, natural gas and NGL, future production costs, estimates of future oil, natural gas and NGL 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, natural gas and NGL 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, 2011 and 2010 resulted in $363,547 and $0 provision, respectively. A reduction in oil 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, 2011 and 2010, non-producing oil and natural gas properties include costs of $1,378,864 and $1,175,752, respectively, on exploratory wells which were drilling and/or testing. On those wells drilling and/or testing as of December 31, 2011, the Company is expecting to have evaluation results within the next six months.

NOTE 10: Derivatives

The Company has entered into fixed swap contracts, basis protection swaps and costless collar contracts. These instruments are intended to reduce the Company’s exposure to short-term fluctuations in the price of oil and natural gas. Fixed swap contracts set a fixed price and provide payments to the Company if the index price is below the fixed price, or require payments by the Company if the index price is above the fixed price. Basis protection swaps are derivatives that guarantee a price differential to NYMEX for natural gas from a specified delivery point (CEGT and PEPL currently). 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 in Oklahoma.

(7)

Derivative contracts in place as of December 31, 2011

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


Contract period	Production volume covered per month	Indexed (1) 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

Oil costless collars
January - December 2012	2,000 Bbls	NYMEX WTI	$90 floor/$105 ceiling

(1)

CEGT - Centerpoint Energy Gas Transmission’s East pipeline in Oklahoma

PEPL - Panhandle Eastern Pipeline Company’s Texas/Oklahoma mainline

Derivative contracts in place as of September 30, 2011

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


Contract period	Production volume covered per month	Indexed (1) pipeline	Fixed price
Natural gas fixed price swaps
April - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.65
April - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.65
April - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.70
April - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.75
May - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.50
May - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.60
June - October 2011	50,000 Mmbtu	NYMEX Henry Hub	$4.63

Natural gas basis protection swaps
January - December 2011	50,000 Mmbtu	CEGT	NYMEX -$.27
January - December 2011	50,000 Mmbtu	CEGT	NYMEX -$.27
January - December 2011	50,000 Mmbtu	PEPL	NYMEX -$.26
January - December 2011	50,000 Mmbtu	PEPL	NYMEX -$.27
January - December 2011	70,000 Mmbtu	PEPL	NYMEX -$.36
January - December 2012	50,000 Mmbtu	CEGT	NYMEX -$.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

Oil costless collars
April - December 2011	5,000 Bbls	NYMEX WTI	$100 floor/$112 ceiling

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CEGT - Centerpoint Energy Gas Transmission’s East pipeline in Oklahoma

PEPL - Panhandle Eastern Pipeline Company’s Texas/Oklahoma mainline

While the Company believes that its derivative contracts are effective in achieving the risk management objective for which they were intended, 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 liability of $320,074 as of December 31, 2011, and a net asset of $215,940 as of September 30, 2011. Realized and unrealized gains and (losses) for the periods ended December 31, 2011, and December 31, 2010, are scheduled below:


Gains (losses) on natural gas		Three months ended
derivative contracts		12/31/2011		12/31/2010
Realized	$	313,935	$	1,576,500
Increase (decrease) in fair value		(536,014)		(1,597,939)

Total	$	(222,079)	$	(21,439)

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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, 2011, and September 30, 2011:


	Balance Sheet Location	12/31/2011 Fair Value		9/30/2011 Fair Value
Asset Derivatives:
Derivatives not designated as Hedging Instruments:
Commodity contracts	Short-term derivative contracts	$	-	$	269,329
Commodity contracts	Long-term derivative contracts		-		-

Total Asset Derivatives (a)		$	-	$	269,329


Liability Derivatives:
Derivatives not designated as Hedging Instruments:
Commodity contracts	Short-term derivative contracts	$	320,074	$	-
Commodity contracts	Long-term derivative contracts		-		53,389

Total Liability Derivatives (a)		$	320,074	$	53,389

(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: Exploration Costs

In the quarter ended December 31, 2011, lease expirations and leasehold impairments of $311,817 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, 2011, the Company also had additional costs of $1,553 related to exploratory dry hole adjustments. In the quarter ended December 31, 2010, lease expirations and impairments of $73,084 were charged to exploration costs as well as additional costs of $214,020 related to exploratory dry holes.

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, 2011.


	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 - Swaps	$	-	$	(295,062)	$	-	$	(295,062)
Derivative Contracts - Collars	$	-	$	-	$	(25,012)	$	(25,012)

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

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


	Derivatives
Balance of Level 3 as of October 1, 2011	$	293,847
Total gains or (losses) - realized and unrealized:
Included in earnings		(318,859	)
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, 2011	$	(25,012	)

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,
	2011				2010
	Fair Value		Impairment		Fair Value		Impairment
Producing Properties	$	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.

NOTE 13: Fair Values of Financial Instruments

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.

NOTE 14: Acquisitions

On October 25, 2011, the Company closed an acquisition of certain Fayetteville Shale assets located in Van Buren, Conway and Cleburne Counties, Arkansas, in the core of the Fayetteville Shale. The Company acquired an average working interest of 2.3% in 193 producing non-operated natural gas wells and 1,531 acres of leasehold from a private seller. There are approximately 240 future infill drilling locations identified on the leasehold. The purchase price was $17.4 million and was funded by utilizing cash on hand and $13.3 million from the Company’s bank credit facility. The purchase price was allocated to the producing wells based on fair value determined by estimated reserves. The purchase price allocation is preliminary, pending the finalization of asset valuations and working capital adjustments. Adjustments to the estimated fair values may be recorded during the allocation period, not to exceed one year from the date of acquisition.

Actual and Pro Forma Impact of Acquisitions (Unaudited)

Revenues attributable to this acquisition included in the Company’s statement of operations for the quarter ended December 31, 2011, were $1,039,414. Net income attributable to the acquisition included in the statement of operations for the same period was $265,134.

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The following table presents the unaudited pro forma financial information assuming the Company had acquired this business on October 1, 2010:


	For the Quarter Ended December 31
	2011		2010
Revenue:
As reported	$	13,404,333	$	9,901,548
Pro forma revenue		409,988		1,066,932

Pro forma	$	13,814,321	$	10,968,480

Net Income:
As reported	$	3,412,110	$	1,426,849
Pro forma income		136,315		214,322

Pro forma	$	3,548,425	$	1,641,171

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 15: 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.

In May 2011, the FASB issued Accounting Standards Update 2011-04, Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS. This update does not require additional fair value measurements and is not intended to establish valuation standards or affect valuation practices outside of financial reporting. This update may require certain additional disclosures related to fair value measurements. This update is required to be adopted in our second quarter ended March 31, 2012. We do not expect the adoption of this update will materially impact our financial statement disclosures.

Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date are not expected to have a material impact on the financial statements upon adoption.

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ITEM 2

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FORWARD-LOOKING STATEMENTS AND RISK FACTORS

Forward-Looking Statements for fiscal 2012 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 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 and natural gas reserves. Investors should also read the other information in this Form 10-Q and the Company’s 2011 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 $6,085,685 at December 31, 2011, compared to $7,314,096 at September 30, 2011.

Liquidity:

Cash and cash equivalents were $1,935,886 as of December 31, 2011, compared to $3,506,999 at September 30, 2011, a decrease of approximately $1.6 million. Cash flows for the three months ended December 31 are summarized as follows:

Net cash provided (used) by:


	2012			2011			Change

Operating activities	$	7,745,652		$	8,579,664		$	(834,012	)

Investing activities	$	(23,259,380	)	$	(6,396,256	)	$	(16,863,124	)

Financing activities	$	13,942,615		$	(1,158,488	)	$	15,101,103


Increase (decrease) in cash and cash equivalents	$	(1,571,113	)	$	1,024,920		$	(2,596,033	)

Operating activities:

The decrease of $834,012 in net cash provided by operating activities is primarily the effect of the following:

Realized gains on derivative contracts decreased $1,262,565 in the 2012 period, as compared to the 2011 period.

Net decrease in collections of oil and natural gas sales and other receivables for the 2012 period compared to the 2011 period resulted in less cash provided by operating activities of approximately $180,000.

In the fiscal 2012 first quarter, payments for field related lease operating expenses (LOE) were $80,063 higher than in the fiscal 2011 first quarter.

Expenditures for G&A, interest and other expenses during the 2012 first quarter increased approximately $151,310, as compared to the 2011 first quarter. These expenditures were the result of higher personnel, technical consulting, auditing and tax preparation and legal costs.

The Company had lower income tax payments during the 2012 period compared to the 2011 period of $957,760.

Investing activities:

Net cash used in investing activities increased $16,863,124 in the 2012 first quarter, the result of the following:

In the 2012 period the Company acquired producing properties, leasehold and mineral acreage in Arkansas totaling approximately $18.8 million which is discussed below under Capital Resources.

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Lease bonus payments increased during the 2012 period approximately $1.6 million, as compared to the 2011 period. In December 2012, the Company leased 2,431 net mineral acres in the horizontal Mississippi Limestone play in northern Oklahoma and received approximately $1.7 million in lease bonus payments.

Proceeds from sales of assets were higher by $127,987 in the 2012 period, as compared to the 2011 period. In December 2012 the Company sold 1,719 mineral acres in Florida for $128,925.

Financing activities:

Net cash of $13,942,615 was provided by financing activities in the 2012 period, as compared to net cash used in financing activities in the 2011 period, the change of $15,101,103 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. As of December 31, 2011 and 2010, net borrowings were $14,522,371 and $0, respectively.

The Company paid $579,756 and $581,675 in dividends during the 2012 and 2011 periods, respectively.

No stock repurchases were made in the 2012 period. Stock repurchases in the amount of $576,813 were made in the 2011 period.

Capital Resources:

Capital expenditures in 2012 of $6,344,006 were slightly lower than the $6,570,808 of capital expenditures in 2011. Although there was a small decrease, it is not indicative of a noticeable change in drilling activity. Asset acquisitions were made in the 2012 first quarter totaling $18,783,949. No asset acquisitions were made in the 2011 first quarter. All of the acquired assets were located in the Fayetteville Shale and consisted of producing properties including 1,531 net leasehold acres, associated overriding royalty interests and 353 net producing mineral acres. The larger purchase totaling $17,399,052 closed on October 25, 2011, and included small working interests in 193 producing wells and 240 future drilling locations located on 1,531 net leasehold acres. The Company utilized cash and borrowings to make these purchases resulting in a long term debt balance of $14,522,371 as of December 31, 2011.

Drilling activity through the first quarter of fiscal 2012 continued at a relatively steady pace in the Arkansas Fayetteville Shale area and in western Oklahoma where we own substantial mineral and leasehold acreage in oil and natural gas liquids-rich areas including the Anadarko (Cana) Woodford Shale, Horizontal Granite Wash, Hogshooter Wash, Cleveland, Tonkawa and Marmaton. Drilling in the western Oklahoma oily and NGL plays is expected to continue at a rapid pace throughout fiscal 2012 giving the Company the opportunity to continue increasing its oil production. Further, drilling for natural gas in the Fayetteville Shale play, both on legacy acreage and the recently acquired acreage, remains brisk and is expected to increase the Company’s gas production in fiscal 2012. Drilling in the Anadarko (Cana) Woodford Shale play has begun to slow significantly. Capital expenditures (including asset acquisitions) of approximately $40 million are currently expected for fiscal 2012. We will continue to search for opportunities to acquire additional acreage which will yield favorable returns on investment in areas that are complementary to our existing acreage holdings.

Production of oil, natural gas and NGL increased 16% on an Mcfe basis from the 2011 period to the 2012 period. The Company reported NGL production for the first time in the first quarter of 2012. Increased drilling activity over the last 12–18 months in several western Oklahoma plays which produce significant NGL has resulted in meaningful NGL production and reserves for the Company, necessitating the inclusion of NGL production beginning with the first quarter of fiscal 2012. The inclusion of NGL in the reserve calculation began with the fiscal 2011 year-end reserve report. In previous quarters, all NGL sales revenues were included with natural gas sales revenues. Excluding the effect of the inclusion of NGL production for the first time in the 2012 period, production volumes increased 12% on an Mcfe basis. This increase was due to added production from the newly acquired wells and from wells that have recently come on line, which has exceeded the natural decline of pre-existing wells. Looking forward, we expect production from these newly acquired wells, wells that have recently come on line and wells that will come on line later in fiscal 2012 to result in a production increase for fiscal 2012, as compared to fiscal 2011.

Due to the Company not being the operator of any of its oil and natural gas properties, it is extremely difficult for us to predict levels of participation in drilling and completing new wells and our associated capital expenditures with certainty.

The continued decline in natural gas prices and the high levels of natural gas in storage has resulted in announced cutbacks in domestic drilling activity and restricted gas production on existing wells by some operators. These factors point

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toward continued low natural gas price levels through the remainder of fiscal 2012. As of December 31, 2011, we had costless collar contracts covering 2,000 barrels per month of the Company’s oil production from January 2012 through December 2012 and natural gas basis protection swap contracts covering 190,000 Mmbtu per month which will expire in December 2012 (see NOTE 10 – Derivatives). We also have executed costless collar contracts in January 2012 covering another 3,000 barrels of oil per month from February through December 2012. During this highly volatile period for oil and natural gas prices, management continues to evaluate opportunities for product price protection by hedging a portion of the Company’s future oil and natural gas production.

For the first quarter of fiscal 2012 cash provided by operating activities of $7,745,652 more than funded capital expenditures for drilling and equipping wells of $6,344,006. After payment of our regular $.07 per share quarterly dividend totaling $579,756 and other miscellaneous investing activities, cash was reduced during 2012 by $1,571,113 and the Company borrowed $14,522,371 utilizing its credit facility. Looking forward, the Company expects to fund overhead costs, capital additions related to the drilling and equipping of wells, stock repurchases and dividend payments primarily from cash flow and cash on hand. During the first quarter of 2012, the Company utilized excess cash and the bank credit facility to finance the $18.8 million purchase of Fayetteville Shale assets discussed above. As management evaluates opportunities to acquire additional assets, additional borrowings utilizing our bank credit facility could be necessary. Also, during times of oil and natural gas price decreases, or increased expenditures for drilling, it may be necessary for us to utilize the credit facility further in order to fund these expenditures. The Company has availability (approximately $20.5 million at December 31, 2011) 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 2012, 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, 2011 – COMPARED TO THREE MONTHS ENDED DECEMBER 31, 2010

Overview:

The Company recorded first quarter 2012 net income of $3,412,110, or $.41 per share, as compared to $1,426,849, or $.17 per share, in the 2011 quarter. Major contributing factors were higher oil and natural gas sales volumes and increased lease bonuses, partially offset by increased losses on natural gas derivative contracts and increased DD&A and impairment costs.

Oil and Natural Gas (and associated natural gas liquids) Sales:

Oil and natural gas sales increased $2,012,703 or 21% for the 2012 quarter. Oil and natural gas sales were up due to increases in oil and natural gas sales volumes of 52% and 9%, respectively, coupled with an increase in oil prices of 12% and partially offset by a decrease in natural gas prices of 8%. The following table outlines the Company’s production and average sales prices for oil, natural gas and NGL for the three month periods of fiscal 2012 and 2011:


	Oil Bbls Sold	Average Price	Mcf Sold	Average Price	NGL Bbls Sold	Average Price	Mcfe Sold	Average Price
Three months ended
12/31/2011	38,040	$89.39	2,243,312	$3.46	14,662	$40.05	2,559,524	$4.59
12/31/2010	24,965	$79.77	2,058,428	$3.76	*	*	2,208,218	$4.41

The oil production increase is due to continued drilling in western Oklahoma oily plays such as the horizontal Granite Wash, Hogshooter Wash, Cleveland, Tonkawa and Marmaton. The natural gas production increase is mainly due to production attributable to the acquisition in the Fayetteville Shale in Arkansas that the Company completed effective October 25, 2011. The Company owns a substantial acreage position in western Oklahoma and drilling in these plays is expected to continue at a rapid pace throughout fiscal 2012 giving the Company opportunity to continue to increase its oil production. Further, drilling for natural gas in the Fayetteville Shale play both on legacy acreage and the recently acquired acreage remains brisk. Increases in gas production from this play are expected in fiscal 2012.

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Production for the last five quarters was as follows:


Quarter ended	Oil Bbls Sold	Mcf Sold	NGL Bbls Sold	Mcfe Sold
12/31/11	38,040	2,243,312	14,662	2,559,524
9/30/11	27,418	2,268,606	*	2,433,114
6/30/11	25,382	1,976,868	*	2,129,160
3/31/11	26,376	1,993,755	*	2,152,011
12/31/10	24,965	2,058,428	*	2,208,218

* The Company reported NGL reserves for the first time in its 2011 year-end reserve report. Increased drilling activity over the last 12-18 months in several western Oklahoma plays which produce significant NGL has resulted in meaningful NGL reserves and production for the Company. These reserve and production increases necessitated inclusion of NGL in the 2011 year-end reserve calculation and first quarter 2012 production volumes. In previous quarters, all NGL sales revenues were included with natural gas sales revenues.

Lease Bonuses and Rentals:

Lease bonuses and rentals increased $1,641,826 in the 2012 quarter compared to the 2011 quarter. The increase was due to the Company leasing 2,431 net acres in the horizontal Mississippi Limestone play, in northern Oklahoma, for $1.7 million.

Gains (Losses) on Derivative Contracts:

At December 31, 2011, the Company’s fair value of derivative contracts was a liability of $320,074; whereas at December 31, 2010, the Company’s fair value of derivative contracts was an asset of $22,387. The Company had a net loss on derivative contracts of $222,079 in the 2012 quarter, as compared to a net loss of $21,439 recorded in the 2011 quarter.

Lease Operating Expenses (LOE):

LOE increased $67,042 or 3% in the 2012 quarter as compared to the 2011 quarter and LOE per Mcfe decreased in the 2012 quarter to $.88 per Mcfe from $1.00 per Mcfe in the 2011 quarter. LOE related to field operating costs increased approximately $186,000 in the 2012 quarter compared to the 2011 quarter, a 17% increase. This increase is principally a result of production increasing 16%. In the 2012 quarter, field operating costs were $.49 per Mcfe compared to $.48 per Mcfe in the 2011 quarter.

The increase in LOE related to field operating costs was partially offset by a decrease in value based fees (primarily gathering, transportation and marketing costs) of approximately $119,000 in the 2012 quarter compared to the 2011 quarter. On a per Mcfe basis, these fees were down $.12 due to the addition of significant oil production and new natural gas wells producing in areas with lower value based fees. Value based fees are charged as a percent of natural gas sales.

Production Taxes:

Production taxes increased $93,855 or 27% in the 2012 quarter as compared to the 2011 quarter. Production taxes as a percentage of oil and natural gas sales increased slightly from 3.5% in the 2011 quarter to 3.7% in the 2012 quarter. 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.

Depreciation, Depletion and Amortization (DD&A):

DD&A increased $707,602 or 21% in the 2012 quarter. DD&A in the 2012 quarter was $1.62 per Mcfe as compared to $1.56 per Mcfe in the 2011 quarter. DD&A increased $546,445 due to oil and natural gas production increasing 16% in the 2012 quarter compared to the 2011 quarter. The remaining increase of $161,157 was caused by a $.06 increase in the DD&A rate. This rate increase is due to higher finding cost experienced in oil and liquids rich areas where the Company has new wells that have come on line.

Income Taxes:

Provision for income taxes increased in the 2012 quarter by $273,000, the result of a $2,258,261 increase in income before income taxes in the 2012 quarter compared to the 2011 quarter. The effective tax rate for the 2012 and 2011 quarters was 20% and 29%, respectively. Excess percentage depletion, which is a permanent tax benefit, reduced the effective tax rate below the statutory rate for both quarters.

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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, 2011.

ITEM 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk

Oil and natural gas prices historically have been volatile, and this volatility is expected to continue. Uncertainty continues to exist as to the direction of natural gas and oil 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 natural gas liquids 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 natural gas, oil and natural gas liquids in 2012 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 2012 derivative contracts, based on the Company’s estimated natural gas volumes for 2012, the price sensitivity for each $0.10 per Mcf change in wellhead natural gas price is approximately $1,005,000 for operating revenue. Based on the Company’s estimated oil volumes for 2012, the price sensitivity in 2012 for each $1.00 per barrel change in wellhead oil price is approximately $112,000 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. As of December 31, 2011, the Company has basis protection swaps and oil collars in place. 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. For the Company’s basis protection swaps, 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 $224,000. For the Company’s oil collars, a change of $1.00 in the forward strip prices would result in a change to pre-tax operating income of approximately $22,000.

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, 2011, the Company had $14,522,371 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.

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 that 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 that, subject to the limitations noted above, the Company’s disclosure controls and procedures were effective to ensure that 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.

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PART II OTHER INFORMATION

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.

February 8, 2012		/s/ Michael C. Coffman
Date		Michael C. Coffman, President and Chief Executive Officer

February 8, 2012		/s/ Lonnie J. Lowry
Date		Lonnie J. Lowry, Vice President and Chief Financial Officer

February 8, 2012		/s/ Robb P. Winfield
Date		Robb P. Winfield, Controller and Chief Accounting Officer

(17)

(State or other jurisdiction of

incorporation or organization)

(I.R.S. Employer

Identification No.)