e10vq

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q


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

For the period ended December 31, 2010


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

For the transition period from to

Commission File Number 001-31759

PANHANDLE OIL AND GAS INC.

(Exact name of registrant as specified in its charter)


OKLAHOMA		73-1055775
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer 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.

þ Yes o 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).

o Yes o 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 o		Accelerated filer þ		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

o Yes þ No

Outstanding shares of Class A Common stock (voting) at February 8, 2011: 8,289,090

The following defined terms are used in this report:

“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;

“Independent Consulting Petroleum Engineer(s)” or “Independent Consulting Petroleum Engineering Firm(s)” refers to DeGolyer and MacNaughton of Dallas, Texas, for proved reserves calculated as of September 30, 2010, or to Pinnacle Energy Services, L.L.C. of Oklahoma City, Oklahoma, for proved reserves calculated as of September 30, 2009;

“LOE” means lease operating expense;

“Mcf” means thousand cubic feet;

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

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

“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
All references to natural gas reserves, sales and prices include associated natural gas liquids.

PART 1 FINANCIAL INFORMATION
PANHANDLE OIL AND GAS INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Information at December 31, 2010 is unaudited)


	December 31, 2010			September 30, 2010
Assets
Current assets:
Cash and cash equivalents	$	6,622,178		$	5,597,258
Oil and natural gas sales receivables, net of allowance for uncollectible accounts		6,924,477			9,063,002
Refundable production taxes		435,073			804,120
Derivative contracts		—			1,481,527
Other		171,827			412,778

Total current assets		14,153,555			17,358,685

Properties and equipment, at cost, based on successful efforts accounting:
Producing oil and natural gas properties		211,911,838			207,928,578
Non-producing oil and natural gas properties		10,309,142			9,616,330
Furniture and fixtures		664,135			656,889

		222,885,115			218,201,797
Less accumulated depreciation, depletion and amortization		135,304,688			131,983,249

Net properties and equipment		87,580,427			86,218,548

Investments		670,577			754,208
Derivative contracts		53,334			138,799
Refundable production taxes		863,938			654,599

Total assets	$	103,321,831		$	105,124,839


Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	3,667,736		$	5,062,806
Deferred income taxes		250,100			354,100
Derivative contracts		30,947			—
Accrued income taxes and other liabilities		1,221,549			1,842,918

Total current liabilities		5,170,332			7,259,824

Deferred income taxes		22,995,650			22,552,650
Asset retirement obligations		1,733,805			1,730,369

Stockholders’ equity:
Class A voting common stock, $.0166 par value; 24,000,000 shares authorized, 8,431,502 issued at December 31, 2010 and September 30, 2010		140,524			140,524
Capital in excess of par value		1,828,393			1,816,365
Deferred directors’ compensation		2,363,440			2,222,127
Retained earnings		73,863,253			73,599,733

		78,195,610			77,778,749
Less treasury stock, at cost; 142,412 shares at December 31, 2010 and 120,560 at September 30, 2010		(4,773,566	)		(4,196,753	)

Total stockholders’ equity		73,422,044			73,581,996

Total liabilities and stockholders’ equity	$	103,321,831		$	105,124,839

(See accompanying notes)

(1)

PANHANDLE OIL AND GAS INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)


	Three Months Ended December 31,
	2010			2009
Revenues:
Oil and natural gas (and associated natural gas liquids) sales	$	9,731,574		$	10,810,432
Lease bonuses and rentals		113,365			30,828
Gains (losses) on derivative contracts		(21,439	)		1,403,340
Income from partnerships		78,048			76,752

		9,901,548			12,321,352

Costs and expenses:
Lease operating expenses		2,197,870			2,306,544
Production taxes		344,644			355,042
Exploration costs		287,104			576,261
Depreciation, depletion and amortization		3,434,811			5,292,695
Loss (gain) on asset sales, interest and other		(5,727	)		(37,366	)
General and administrative		1,639,997			1,416,798

		7,898,699			9,909,974

Income before provision for income taxes		2,002,849			2,411,378

Provision for income taxes		576,000			703,000


Net income	$	1,426,849		$	1,708,378




Basic and diluted earnings per common share (Note 3)	$	0.17		$	0.20


Basic and diluted weighted average shares outstanding:
Common shares		8,301,811			8,311,636
Unissued, directors’ deferred compensation shares		115,483			100,553

		8,417,294			8,412,189


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		$	—

(See accompanying notes)

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PANHANDLE OIL AND GAS INC.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(Information at and for the three months ended December 31, 2010 is unaudited)

Three Months Ended December 31, 2010


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

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

Purchase of treasury stock		—		—		—		—		—			(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

Three Months Ended December 31, 2009


	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, 2009		8,431,502	$	140,524	$	1,922,053	$	1,862,499	$	64,507,547			(119,866	)	$	(4,310,280	)	$	64,122,343

Net income		—		—		—		—		1,708,378			—			—			1,708,378

Dividends ($.07 per share)		—		—		—		—		(581,815	)		—			—			(581,815	)

Increase in deferred directors’ compensation charged to expense		—		—		—		49,031		—			—			—			49,031


Balances at December 31, 2009		8,431,502	$	140,524	$	1,922,053	$	1,911,530	$	65,634,110			(119,866	)	$	(4,310,280	)	$	65,297,937

(See accompanying notes)

(3)

PANHANDLE OIL AND GAS INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


	Three months ended December 31,
	2010			2009
Operating Activities
Net income	$	1,426,849		$	1,708,378
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and impairment		3,434,811			5,292,695
Provision for deferred income taxes		339,000			383,000
Exploration costs		287,104			576,161
Net (gain) loss on sale of assets		(111,478	)		(133,192	)
Income from partnerships		(78,048	)		(76,752	)
Distributions received from partnerships		110,743			104,391
Directors’ deferred compensation expense		141,313			49,031
Restricted stock awards		12,028			—
Cash provided by changes in assets and liabilities:
Oil and natural gas sales receivables		2,138,525			(1,253,808	)
Fair value of derivative contracts		1,597,939			(1,648,940	)
Refundable production taxes		159,708			295,244
Other current assets		240,951			(96,725	)
Accounts payable		83,242			(102,443	)
Income taxes payable		(725,070	)		(51,770	)
Accrued liabilities		(477,953	)		(222,373	)

Total adjustments		7,152,815			3,114,519

Net cash provided by operating activities		8,579,664			4,822,897

Investing Activities
Capital expenditures, including dry hole costs		(6,570,808	)		(2,658,662	)
Proceeds from leasing of fee mineral acreage		122,678			56,004
Investments in partnerships		50,936			(1,971	)
Proceeds from sales of assets		938			102,881

Net cash used in investing activities		(6,396,256	)		(2,501,748	)

Financing Activities
Borrowings under debt agreement		—			5,000,388
Payments of loan principal		—			(6,862,879	)
Purchase of treasury stock		(576,813	)		—
Payments of dividends		(581,675	)		(581,815	)

Net cash provided by (used in) financing activities		(1,158,488	)		(2,444,306	)


Increase (decrease) in cash and cash equivalents		1,024,920			(123,157	)
Cash and cash equivalents at beginning of period		5,597,258			639,908

Cash and cash equivalents at end of period	$	6,622,178		$	516,751


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

Additions to asset retirement obligations	$	3,436		$	9,693


Gross additions to properties and equipment	$	5,092,496		$	1,736,461
Net (increase) decrease in accounts payable for properties and equipment additions		1,478,312			922,201

Capital expenditures, including dry hole costs	$	6,570,808		$	2,658,662

(See accompanying notes)

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PANHANDLE OIL AND GAS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

NOTE 1: Accounting Principles and Basis of Presentation

The accompanying unaudited condensed consolidated 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), and include the Company’s wholly-owned subsidiary, Wood Oil Company (Wood). Management of the Company believes that all adjustments necessary for a fair presentation of the consolidated 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 consolidated 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 consolidated financial statements pursuant to the rules and regulations of the SEC. Therefore, these condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and related notes thereto included in the Company’s 2010 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, 2010 and 2009), 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 directors’ deferred compensation shares during the period. The unvested restricted stock discussed in NOTE 7 is not included in diluted earnings per share because the effect is antidilutive.

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 risk 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 $29,802,940 at December 31, 2010. 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 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.

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, 2010, the Company was in compliance with the covenants of the BOK agreement.

NOTE 5: Dividends

On October 27, 2010, the Company’s Board of Directors declared a $.07 per share dividend that was paid on December 10, 2010 to shareholders of record on November 22, 2010. On December 8, 2010, the Company’s Board of Directors approved payment of a $.07 per share dividend to be paid on March 10, 2011 to shareholders of record on February 24, 2011.

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NOTE 6: 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 7: 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.

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.

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. Dividends expected to be paid are $.07 per share each quarter. 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.

The compensation expense recognized as a part of G&A expense in the 2011 quarter was $12,028 (none in the 2010 quarter).

A summary of the status of unvested shares of restricted stock awards and changes during 2011 is presented below:


			Weighted Average
	Unvested Restricted		Grant-Date Fair
	Shares		Value

Unvested shares as of September 30, 2010		8,500	$	28.30
Granted		8,780	$	28.00
Vested		—	$	—
Forfeited		—	$	—


Unvested shares as of December 31, 2010		17,280	$	28.15

As of December 31, 2010, there was $462,335 of total unrecognized compensation cost related to unvested restricted stock. The cost is to be recognized over a weighted average period of 3.74 years. Upon vesting, shares are expected to be issued out of shares held in treasury.

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. Vesting of these shares is based on the performance of the market price of the common stock over the vesting period (three years). Shares not vested will be repurchased by the Company at par value. The impact of these awards on G&A expense in the 2011 quarter is not material.

NOTE 8: Oil and Natural Gas Reserves

Management considers the estimation of the Company’s crude oil and natural gas reserves to be the most significant of its judgments and estimates. Changes in crude oil 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

(6)

of crude oil and natural gas reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing prices current with the period. As of September 30, 2010, the Company adopted the SEC Rule, Modernization of Oil and Gas Reporting Requirements. Accordingly, the estimated oil and natural gas reserves at December 31, 2010, were computed using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month oil and natural gas price for each month within the 12-month period prior to December 31, 2010, held flat over the life of the properties. In accordance with SEC rules effective on December 31, 2009, current pricing of oil and natural gas on December 31, 2009, held flat over the life of the properties was used to estimate oil and natural gas reserves as of December 31, 2009. Crude oil 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 and natural gas pricing assumptions are used by management to prepare estimates of crude oil and natural gas reserves and future net cash flows used in asset impairment assessments and in formulating management’s overall operating decisions.

NOTE 9: 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 and natural gas, future production costs, estimates of future oil 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 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, 2010 and 2009 resulted in no impairment provision. 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.

The first well in our internally generated Joiner City prospect, a horizontal Woodford Shale prospect in the oil and natural gas liquids-rich Marietta Basin in southern Oklahoma, has been drilled during the first quarter of 2011. The well is currently in the testing stage and the flow back results are being evaluated. As of the date of this filing, approximately $1.1 million has been capitalized on this well that may be subject to future impairment pending the evaluation results.

NOTE 10: Capitalized Costs

Oil and natural gas properties include costs of $1,175,752 on exploratory wells which were drilling and/or testing at December 31, 2010. The Company is expecting to have evaluation results on these wells within the next six months.

NOTE 11: Derivatives

The Company has entered into fixed swap contracts and basis protection swaps. These instruments are intended to reduce the Company’s exposure to short-term fluctuations in the price of 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. These contracts cover only a portion of the Company’s natural gas production and provide only partial price protection against declines in natural gas prices. 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. 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.

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Derivative contracts in place as of December 31, 2010
(prices below reflect the Company’s net price from the listed Oklahoma pipelines)

Production volume

Indexed (1)

Contract period

covered per month

Pipeline

Fixed price

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


(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, 2010
(prices below reflect the Company’s net price from the listed Oklahoma pipelines)

Production volume

Indexed (1)

Contract period

covered per month

Pipeline

Fixed price

Fixed price swaps

January — December, 2010

100,000 Mmbtu

CEGT

5.015

January — December, 2010

50,000 Mmbtu

CEGT

5.050

January — December, 2010

100,000 Mmbtu

PEPL

5.570

January — December, 2010

50,000 Mmbtu

PEPL

5.560

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, 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


(1)		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 an asset of $22,387 as of December 31, 2010 and an asset of $1,620,326 as of September 30, 2010. Realized and unrealized gains and (losses) for the periods ended December 31, 2010 and December 31, 2009 are scheduled below:


Gains (losses) on natural gas	Three months ended
derivative contracts	12/31/2010			12/31/2009
Realized	$	1,576,500		$	(245,600	)
Increase (decrease) in fair value		(1,597,939	)		1,648,940

Total	$	(21,439	)	$	1,403,340

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	Balance Sheet	12/31/2010		9/30/2010
	Location	Fair Value		Fair Value
Asset Derivatives:
Derivatives not designated as Hedging Instruments:
Commodity contracts	Short-term derivative contracts	$	—	$	1,481,527
Commodity contracts	Long-term derivative contracts		53,334		138,799

Total Asset Derivatives (a)		$	53,334	$	1,620,326


Liability Derivatives:
Derivatives not designated as Hedging Instruments:
Commodity contracts	Short-term derivative contracts	$	30,947	$	—
Commodity contracts	Long-term derivative contracts		—		—

Total Liability Derivatives (a)		$	30,947	$	—


(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: Exploration Costs

In the quarter ended December 31, 2010, lease expirations and leasehold impairments of $73,084 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, 2010, the Company also had additional costs of $214,020 related to exploratory dry hole adjustments. In the quarter ended December 31, 2009, lease expirations and impairments of $575,633 were charged to exploration costs as well as additional costs of $628 related to exploratory dry holes.

NOTE 13: 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, 2010.


	Quoted		Significant
	Prices in		Other		Significant
	Active		Observable		Unobservable
	Markets		Inputs		Inputs		Total Fair
	(Level 1)		(Level 2)		(Level 3)		Value
Financial Assets:
Derivative Contracts — Swaps	$	—	$	53,334	$	—	$	53,334

Financial Liabilities:
Derivative Contracts — Swaps	$	—	$	30,947	$	—	$	30,947

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

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prices and time to maturity. These values are then compared to the values given by our counterparties for reasonableness.

NOTE 14: 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 15: Recently Adopted Accounting Pronouncements

In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update 2010-03 (“ASU 2010-03”) to align the oil and natural gas reserve estimation and disclosure requirements of ASC Topic 932, Extractive Industries — Oil and Gas, with the requirements in the Securities and Exchange Commission’s final rule, Modernization of the Oil and Gas Reporting Requirements, which was issued on December 31, 2008 and was adopted on a prospective basis beginning in the fourth quarter of our fiscal year ended September 30, 2010. The Company implemented ASU 2010-03 prospectively as a change in accounting principle inseparable from a change in accounting estimate.

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 consolidated financial statements upon adoption.


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

FORWARD-LOOKING STATEMENTS AND RISK FACTORS

Forward-Looking Statements for fiscal 2011 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 2010 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 $8,983,223 at December 31, 2010 compared to $10,098,861 at September 30, 2010.

Liquidity:

Cash and cash equivalents were $6,622,178 as of December 31, 2010 compared to $5,597,258 at September 30, 2010, an increase of approximately $1 million. Cash flows for the three months ended December 31 are summarized s follows:

Net cash provided (used) by:


	2011			2010
Operating activities	$	8,579,664		$	4,822,897

Investing activities	$	(6,396,256	)	$	(2,501,748	)

Financing activities	$	(1,158,488	)	$	(2,444,306	)


Increase (decrease) in cash and cash equivalents	$	1,024,920		$	(123,157	)

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Operating activities:

The increase of approximately $3.8 million in cash provided by operating activities is the effect of the following:

The net increase in collections on oil and natural gas sales for the 2011 period compared the 2010 period resulting in additional cash provided by operating activities of approximately $2.5 million.

The net increase in realized gains on derivative contracts increased cash provided by operating activities by $1,822,100. The net realized gains on derivative contracts was $1,576,500 during the three months ended December 31, 2010, compared to realized losses of $245,600 during the three months ended December 31, 2009.

Investing activities:

Capital expenditures increased approximately $3.9 million, the result of increased drilling activity in areas where we own mineral and leasehold acreage (discussed in more detail below).

Financing activities:

The Company paid down its balance on the credit facility by $1,862,491 during the 2010 period. Having paid all of its previous borrowings under the credit facility in May 2010, no borrowings were made utilizing the Company’s credit facility during the three months ended December 31, 2010, thus maintaining an outstanding balance of zero. The Company paid approximately $582,000 in dividends during both the 2010 and 2011 periods. Stock repurchases in the amount of $576,813 were made in the 2011 period, while no stock repurchases were made in the 2010 period.

Additions to properties and equipment for oil and natural gas activities during the 2011 first quarter were $5,092,496 compared to $1,736,461 in the 2010 quarter. The increase in drilling activity where we own mineral and leasehold acreage in oil and natural gas liquids-rich areas such as the Anadarko (Cana) Woodford Shale, Horizontal Granite Wash, Cleveland, Tonkawa and other plays in western Oklahoma, combined with continued steady drilling activity in the Arkansas Fayetteville Shale area, has resulted in an increase of approximately $3.4 million in oil and natural gas property and equipment additions in the 2011 first quarter, compared to the 2010 first quarter.

Although production for the first quarter of 2011 decreased 3.1% compared to the first quarter of 2010, production from wells drilled in the abovementioned areas during 2011 is expected to result in production increases in the latter half of fiscal 2011 and continue into fiscal 2012.

Additions to properties and equipment for oil and natural gas activities during fiscal 2011 are projected by management to be approximately $25 million. It is important to note that, 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 associated capital expenditures, with certainty.

We are currently experiencing winter related increases in the price of natural gas; however, management expects natural gas prices to somewhat decrease during the spring and summer months. During the month of January 2011, we have executed fixed swap contracts covering 200,000 Mmbtu per month of our natural gas production from April 2011 through October 2011 at an average fixed price of $4.69.

During the 2011 first quarter, cash provided by operating activities exceeded capital expenditures by approximately $2 million. This excess allowed us to increase cash reserves by approximately $1 million while also paying our regular $.07 per share dividend and to make stock repurchases in the amount of $576,813. Looking forward, the Company expects to fund overhead costs, capital additions, stock repurchases and dividend payments primarily from cash flow. However, during past times of oil and natural gas price decreases, or increased expenditures for drilling, the Company has utilized its revolving line-of-credit facility to help fund these expenditures. The Company’s continued drilling activity, combined with normal delays in receiving first payments from new production, could result in future borrowings under the Company’s credit facility. The Company has availability ($35 million at December 31, 2010) under its revolving credit facility and is in compliance on 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.

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RESULTS OF OPERATIONS

THREE MONTHS ENDED DECEMBER 31, 2010 — COMPARED TO THREE MONTHS ENDED DECEMBER 31, 2009

Overview:

The Company recorded a first quarter 2011 net income of $1,426,849, or $.17 per share, as compared to $1,708,378, or $.20 per share, in the 2010 quarter. Major contributing factors were lower natural gas volumes and natural gas sales prices and decreased gain on natural gas derivative contracts, partially offset by reduced DD&A and exploration costs. These items are further discussed below.

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

Oil and natural gas sales decreased $1,078,858 or 10% for the 2011 quarter. Oil and natural gas sales were down due to 10% lower natural gas prices coupled with decreases in oil and natural gas sales volumes of 9% and 3%, respectively. The table below outlines the Company’s production and average sales prices for oil and natural gas for the three month periods of fiscal 2011 and 2010:


	Barrels		Average		Mcf		Average		Mcfe		Average
	Sold		Price		Sold		Price		Sold		Price
Three months ended 12/31/10		24,965	$	79.77		2,058,428	$	3.76		2,208,218	$	4.41
Three months ended 12/31/09		27,454	$	71.30		2,113,409	$	4.19		2,278,133	$	4.75

During the first quarter of 2011, the Company had several new wells that were completed and put on line; however, decreased drilling activity which began in 2009 continued through fiscal 2010 resulting in a slight decrease in production. The natural production decline of existing wells is currently exceeding production from newly completed wells.

For the past two years, depressed natural gas prices have slowed drilling activity and limited the Company’s opportunities to participate in drilling new wells, and, among these opportunities, the Company has been very selective. The Company owns working interests in newly completed wells which began producing during December 2010 and are expected to significantly contribute to the Company’s natural gas production. Management expects natural gas prices for 2011 to be in line with those of 2010; however, drilling activity is expected to increase over current levels based on the recent level of proposals. Drilling activity in horizontal plays in western Oklahoma where the Company owns mineral acreage such as the Anadarko (Cana) Woodford Shale, Granite Wash, Cleveland and Tonkawa is continuing to increase and should provide more opportunity for the Company.

Production for the last five quarters was as follows:


Quarter ended	Barrels Sold	Mcf Sold	Mcfe Sold
12/31/10	24,965	2,058,428	2,208,218
9/30/10	26,054	2,155,769	2,312,093
6/30/10	26,873	2,074,998	2,236,236
3/31/10	21,998	1,958,166	2,090,154
12/31/09	27,454	2,113,409	2,278,133

Gains (Losses) on Natural Gas Derivative Contracts:

At December 31, 2010, the Company’s fair value of derivative contracts was an asset of $22,387; whereas at December 31, 2009, the Company’s fair value of derivative contracts was a liability of $864,495. The decline in forward looking natural gas basis differentials since September 30, 2010 has resulted in a net loss on natural gas derivative contracts of $21,439 in the 2011 quarter as compared to a net gain of $1,403,340 recorded in the 2010 quarter. See the table under NOTE 11 for a breakdown of the realized and unrealized gains and losses on derivative contracts in place during the quarters ended December 31, 2010 and 2009.

Lease Operating Expenses (LOE):

LOE decreased $108,674 or 5% in the 2011 quarter as compared to the 2010 quarter, and LOE per Mcfe decreased in the 2011 quarter to $1.00 per Mcfe from $1.01 per Mcfe in the 2010 quarter. Value based fees (primarily gathering, transportation and marketing costs) decreased approximately $194,000 in the 2011 quarter compared to the 2010 quarter as a result of lower natural gas sales. On a per Mcfe basis, these fees were down $.07 due to lower natural gas prices creating lower value per Mcfe on which the fees are based. Value based fees are charged as a percent of natural gas sales.

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The decrease in value based fees is partially offset by an increase of approximately $85,000 in LOE related to field operating costs in the 2011 quarter compared to 2010 quarter, a 9% increase. In the 2011 quarter, field operating costs were $.48 per Mcfe compared to $.43 per Mcfe in the 2010 quarter. These increases are due to more new wells (with high initial LOE) coming on line in the 2011 quarter compared to the 2010 quarter when drilling activity on the Company’s acreage was less.

Production Taxes:

Production taxes decreased $10,398 or 3% in the 2011 quarter as compared to the 2010 quarter. Production taxes as a percentage of oil and natural gas sales increased from 3.3% in the 2010 quarter to 3.5% in the 2011 quarter. Although oil and natural gas sales decreased 10%, production taxes only declined 3% as the production tax rate increased slightly due to some wells no longer being eligible for production tax credits or reductions. As wells receiving these production tax benefits pay out, or reach four years of having received production tax benefits, the wells are no longer eligible to receive the production tax credits or reductions.

Exploration Costs:

Exploration costs decreased $289,157 in the 2011 quarter as compared to the 2010 quarter. During the 2011 quarter, leasehold impairment and expired leasehold totaled $73,084 compared to $575,633 during the 2010 quarter, a $502,549 decrease. Charges on two exploratory dry holes totaled $220,789 during the 2011 quarter; whereas, in the 2010 quarter no exploratory dry holes were drilled.

Depreciation, Depletion and Amortization (DD&A):

DD&A decreased $1,857,884 or 35% in the 2011 quarter. DD&A in the 2011 quarter was $1.56 per Mcfe as compared to $2.32 per Mcfe in the 2010 quarter. Oil and natural gas production decreased 3% in the 2011 quarter accounting for approximately $162,455 of the DD&A decrease. The remaining DD&A decrease of approximately $1,695,000 is attributable to the $.76 decline in the DD&A rate per Mcfe. This rate declined as a result of increased oil and natural gas reserves as of December 31, 2010, as compared to December 31, 2009.

General and Administrative Costs (G&A):

G&A increased $223,199 or 16% in the 2011 quarter, as compared to the 2010 quarter, due primarily to increases in Board of Directors’ fees of $92,281 and technical consulting expense of $79,410, largely related to compensation consultant fees.

Income Taxes:

Provision for income taxes decreased in the 2011 quarter by $127,000, the result of a $408,529 decrease in income before income taxes in the 2011 quarter, compared to the 2010 quarter. The effective tax rate for both the 2011 and 2010 quarters was 29%. Excess percentage depletion, which is a permanent tax benefit, reduced the effective tax rate below the statutory rate for both quarters. For further discussion regarding excess percentage depletion and its effect on the effective tax rate, see NOTE 2.

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, 2010.

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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 2011 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 2011 natural gas derivative contracts (see below), based on the Company’s estimated natural gas volumes for 2011, the price sensitivity for each $0.10 per Mcf change in wellhead natural gas price is approximately $855,000 of pre-tax operating income. Based on the Company’s estimated oil volumes for 2011, the price sensitivity in 2011 for each $1.00 per barrel change in wellhead oil price is approximately $123,000 of pre-tax operating income.

Commodity Price Risk

The Company periodically utilizes derivative contracts to reduce its exposure to unfavorable changes in natural gas prices. The Company does not enter into these derivatives for speculative or trading purposes. As of December 31, 2010, the Company has basis protection swaps (Refer to NOTE 11 for more detail) 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 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 as of December 31, 2010, the sensitivity of a $.10 per MCF change in differential between NYMEX and the indexed pipelines (CEGT and PEPL) futures prices is approximately $539,000 for pre-tax operating income.

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, 2010, the Company had $0 outstanding under these facilities. At this point, the Company doesn’t 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, including its consolidated subsidiary, 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 2 UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

During the three months ended December 31, 2010, the Company repurchased shares of the Company’s common stock as summarized in the table below.


							Approximate Dollar
					Total Number of		Value of Shares
					Shares Purchased as		that May Yet Be
	Total Number of		Average Price Paid		Part of Publicly		Purchased Under the
Period	Shares Purchased		per Share		Announced Program		Program
10/1 - 10/31/10		6,800	$	24.66		6,800	$	1,000,000
11/1 - 11/30/10		3,000	$	24.83		3,000	$	1,000,000
12/1 - 12/31/10		12,052	$	27.77		12,052	$	600,000


Total		21,852	$	26.40		21,852

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. 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

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, 2011				/s/ Michael C. Coffman
Date				Michael C. Coffman, President and
				Chief Executive Officer

February 8, 2011				/s/ Lonnie J. Lowry
Date				Lonnie J. Lowry, Vice President
				and Chief Financial Officer

February 8, 2011				/s/ Robb P. Winfield
Date				Robb P. Winfield, Controller
				and Chief Accounting Officer

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			Page
Part I Financial Information
Item 1 Condensed Consolidated Financial Statements Page
Condensed Consolidated Balance Sheets — December 31, 2010 and September 30, 2010			1
Condensed Consolidated Statements of Operations — Three months ended December 31, 2010 and 2009			2
Consolidated Statements of Stockholders’ Equity — Three months ended December 31, 2010 and 2009			3
Condensed Consolidated Statements of Cash Flows — Three months ended December 31, 2010 and 2009			4
Notes to Condensed Consolidated Financial Statements			5
Item 2 Management’s discussion and analysis of financial condition and results of operations			10
Item 3 Quantitative and qualitative disclosures about market risk			14
Item 4 Controls and procedures			14
Part II Other Information			15
Item 2 Unregistered Sales of Equity Securities and Use of Proceeds			15
Item 6 Exhibits			15
Signatures			15
EX-31.1
EX-31.2
EX-32.1
EX-32.2

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