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, 2008

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

For the transition period from                      to                     

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 is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions 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		Smaller reporting company o
				(Do not check if a smaller reporting company)

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 5, 2009: 8,300,128

 

 

INDEX

		Page
Part I Financial Information
Item 1 Condensed Consolidated Financial Statements
Condensed Consolidated Balance Sheets – December 31, 2008 and September 30, 2008		1
Condensed Consolidated Statements of Operations – Three months ended December 31, 2008 and 2007		2
Consolidated Statement of Stockholders’ Equity – Three months ended December 31, 2008		3
Condensed Consolidated Statements of Cash Flows – Three months ended December 31, 2008 and 2007		4
Notes to Condensed Consolidated Financial Statements		5-8
Item 2 Management’s discussion and analysis of financial condition and results of operations		8-12
Item 3 Quantitative and qualitative disclosures about market risk		12-13
Item 4 Controls and procedures		13
Part II Other Information		13
Item 6 Exhibits		13
Signatures		13
EX-31.1
EX-31.2
EX-32.1
EX-32.2

PART 1 FINANCIAL INFORMATION

PANHANDLE OIL AND GAS INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Information at December 31, 2008 is unaudited)

		December 31, 2008				September 30, 2008
Assets
Current assets:
Cash and cash equivalents		$	340,934			$	895,708
Oil and natural gas sales receivables (net)			10,655,050				17,183,128
Fair value of natural gas collar contracts			—				646,193
Refundable income taxes			2,548,817				2,162,305
Other			582,096				217,691
Total current assets			14,126,897				21,105,025
Properties and equipment, at cost, based on successful efforts accounting:
Producing oil and natural gas properties			185,500,036				175,727,196
Non-producing oil and natural gas properties			11,840,466				11,216,103
Other			504,111				491,321
			197,844,613				187,434,620
Less accumulated depreciation, depletion and amortization			94,599,231				87,661,433
Net properties and equipment			103,245,382				99,773,187
Investments			724,741				736,314
Other			194,549				392,657
Total assets		$	118,291,569			$	122,007,183
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable		$	10,342,331			$	15,897,565
Accrued liabilities			858,796				608,456
Total current liabilities			11,201,127				16,506,021
Long-term debt			12,996,339				9,704,100
Deferred income taxes			26,148,750				25,943,750
Asset retirement obligations			1,594,470				1,504,411
Stockholders’ equity:
Class A voting common stock, $.0166 par value; 24,000,000 shares authorized, 8,431,502 issued at December 31, 2008 and at September 30, 2008			140,524				140,524
Capital in excess of par value			2,090,070				2,090,070
Deferred directors’ compensation			1,644,440				1,605,811
Retained earnings			67,199,957				69,236,604
			71,074,991				73,073,009
Less treasury stock, at cost; 131,374 shares at December 31, 2008 and at September 30, 2008			(4,724,108	)			(4,724,108	)
Total stockholders’ equity			66,350,883				68,348,901
Total liabilities and stockholders’ equity		$	118,291,569			$	122,007,183

(See accompanying notes)

PANHANDLE OIL AND GAS INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

		Three Months Ended December 31,
		2008				2007
Revenues:
Oil and natural gas sales		$	10,616,664			$	13,226,094
Lease bonuses and rentals			113,380				10,446
Gains on natural gas collar contracts			393,007				263,786
Gain on asset sales, interest and other			58,060				52,394
Income of partnerships			138,591				151,083
			11,319,702				13,703,803
Costs and expenses:
Lease operating expenses			1,749,143				1,344,901
Production taxes			406,748				829,604
Exploration costs			172,265				209,981
Depreciation, depletion and amortization			6,950,092				4,256,610
Provision for impairment			1,875,920				122,009
General and administrative			1,219,163				1,597,045
Interest expense			—				44,346
			12,373,331				8,404,496
(Loss) income before (benefit) provision for income taxes			(1,053,629	)			5,299,307
(Benefit) provision for income taxes			(179,000	)			1,819,000
Net (loss) income		$	(874,629	)		$	3,480,307
(Loss) earnings per common share (Note 4)		$	(0.10	)		$	0.41
Weighted average shares outstanding:
Common shares			8,300,128				8,431,502
Unissued, vested directors’ shares			87,915				78,748
			8,388,043				8,510,250
Dividends declared per share of common stock and paid in period		$	0.07			$	0.07
Dividends declared per share of common stock for and to be paid in the quarter ended March 31 (Note 6)		$	0.07			$	0.07

(See accompanying notes)

PANHANDLE OIL AND GAS INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(Information at and for the three months ended December 31, 2008 is unaudited)

Three Months Ended December 31, 2008

		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, 2008			8,431,502			$	140,524			$	2,090,070			$	1,605,811			$	69,236,604				(131,374	)		$	(4,724,108	)		$	68,348,901
Net loss			—				—				—				—				(874,629	)			—				—				(874,629	)
Dividends ($.14 per share)			—				—				—				—				(1,162,018	)			—				—				(1,162,018	)
Increase in deferred directors’ compensation charged to expense			—				—				—				38,629				—				—				—				38,629
Balances at December 31, 2008			8,431,502			$	140,524			$	2,090,070			$	1,644,440			$	67,199,957				(131,374	)		$	(4,724,108	)		$	66,350,883

(See accompanying notes)

PANHANDLE OIL AND GAS INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

		Three months ended December 31,
		2008				2007
Operating Activities
Net (loss) income		$	(874,629	)		$	3,480,307
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Gain, net, on asset sales			(115,377	)			(16,942	)
Income of partnerships			(138,591	)			(151,083	)
Exploration costs			172,265				209,981
Depreciation, depletion and amortization			6,950,092				4,256,610
Provision for impairment			1,875,920				122,009
Deferred income taxes			205,000				1,431,000
Distributions received from partnerships			150,164				171,619
Directors’ deferred compensation expense			38,629				31,012
Cash provided by changes in assets and liabilities:
Oil and natural gas sales receivables			6,528,078				(2,161,389	)
Fair value of natural gas collar contracts			646,193				(202,386	)
Refundable income taxes			(386,512	)			—
Other current assets			(364,405	)			22,153
Other non-current assets			198,108				—
Accounts payable			501,227				150,657
Accrued liabilities			(330,669	)			375,323
Total adjustments			15,930,122				4,238,564
Net cash provided by operating activities			15,055,493				7,718,871
Investing Activities
Capital expenditures, including dry hole costs			(18,442,452	)			(7,579,345	)
Proceeds from leasing of fee mineral acreage			118,955				15,137
Proceeds from asset sales			2,000				6,270
Net cash used in investing activities			(18,321,497	)			(7,557,938	)
Financing Activities
Borrowings under credit facility			18,316,045				7,776,160
Payments on credit facility			(15,023,806	)			(7,584,911	)
Payments of dividends			(581,009	)			(590,205	)
Net cash provided by (used in) financing activities			2,711,230				(398,956	)
Decrease in cash and cash equivalents			(554,774	)			(238,023	)
Cash and cash equivalents at beginning of period			895,708				989,360
Cash and cash equivalents at end of period		$	340,934			$	751,337
Supplemental Schedule of Noncash Investing and Financing Activities
Dividends declared and unpaid		$	581,009			$	590,205
Additions to asset retirement obligations		$	90,059			$	—
Net decrease (increase) in accounts payable for properties and equipment additions		$	6,056,461			$	(1,145,044	)

(See accompanying notes)

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), formerly Panhandle Royalty 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 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 2008 Annual Report on Form 10-K.

NOTE 2: Income Taxes

     The Company’s provision for income taxes (both Federal and state) is reflective of excess percentage depletion, reducing the Company’s effective tax rate from the federal statutory rate.

     On October 1, 2007, the Company adopted the provisions of FIN No. 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109” (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes” (“SFAS 109”). FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The Company and its subsidiary file income tax returns in the U.S. federal jurisdiction and various state jurisdictions. Subject to statutory exceptions that allow for a possible extension of the assessment period, the Company is no longer subject to U.S. federal, state, and local income tax examinations for fiscal years prior to 2004.

NOTE 3: Stock Repurchase Program

     On May 28, 2008 and July 29, 2008, the Company announced that its Board of Directors had approved stock repurchase programs to purchase up to $2,000,000 and $3,000,000, respectively, of the Company’s common stock. The shares are held in treasury and are accounted for using the cost method. Total shares purchased under the two programs were 139,014, on September 30, 2008, 7,640 treasury shares were contributed to the Company’s ESOP on behalf of the ESOP participants, leaving 131,374 shares held in treasury as of December 31, 2008.

NOTE 4: (Loss) Earnings per Share

     (Loss) earnings per share is calculated using net (loss) income divided by the weighted average number of voting common shares outstanding, including unissued, vested directors’ shares during the period.

NOTE 5: Long-term Debt

     At December 31, 2008, the Company had a revolving credit facility with Bank of Oklahoma (BOK) which consisted of a revolving loan in the amount of $50,000,000 which was subject to a semi-annual borrowing base determination. At December 31, 2008, the borrowing base under the facility was $15,000,000. The revolving loan had a maturity date of October 31, 2010. Borrowings under the revolving loan were due at maturity. The revolving loan bore interest at the BOK national prime rate minus from 1.375% to .75%, or 30 day LIBOR plus from 1.375% to 2.0%. The interest rate charged was based on the percent of the value advanced of the calculated loan value of the Company’s oil and natural gas reserves. The interest rate spread from LIBOR or the prime rate increased as a larger percent of the loan value of the Company’s oil and natural gas properties was advanced.

     Effective February 3, 2009, the Company amended the revolving credit facility to increase the borrowing base to $25,000,000 (the revolving loan amount remains $50,000,000), restructure the interest rate, secure the loan by certain of the Company’s properties and change the maturity date to October 31, 2011. The restructured interest rate is based on national prime plus from .50% to 1.25%, or 30 day LIBOR plus from 2.00% to 2.75%, with an established interest rate floor of 4.50% annually. At the time of the amendment, the 4.50% interest rate floor was in effect. If the interest rate calculation utilizing the

national prime or LIBOR rate exceeds the interest rate floor, 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 reserves. 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.

NOTE 6: Dividends

     On October 29, 2008, the Company’s Board of Directors declared a $.07 per share dividend that was paid on December 10, 2008. On December 10, 2008, the Company’s Board of Directors approved payment of a $.07 per share dividend to be paid on March 6, 2009 to shareholders of record on February 23, 2009.

NOTE 7: 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 vest as earned. The shares are credited to each director’s deferred fee account at the closing market price of the stock on the date earned. Upon retirement, termination or death of the director or upon a change in control of the Company, the shares accrued under the Plan will be issued to the director.

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 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. Due to current significantly lower oil and natural gas prices, and their effect on future net cash flow of the Company’s oil and natural gas properties, the Company’s test for impairment resulted in the need to impair 16 fields a total of $1,875,920. Approximately 92% of the impairment related to 2 fields, one in Wheeler County, Texas consisting of one deep well (drilled in 2006 and had mechanical issues during completion which dramatically increased costs) and one mature field in Beckham County, Oklahoma principally consisting of wells drilled in 2006 and prior. A further 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

     Oil and natural gas properties include costs of $1,452,010 on exploratory wells which were drilling and/or testing at December 31, 2008. The Company is expecting to have evaluation results on these wells within the next six months.

NOTE 10: Derivatives

     The Company accounts for its derivative contracts under Financial Accounting Standards Board Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, (SFAS No. 133). Under the provision of SFAS No. 133, the Company is required to recognize all derivative instruments as either assets or liabilities in the consolidated balance sheet at fair value. The accounting for changes in the fair value of a derivative depends on the intended use of the derivative and resulting designation. For derivatives designated as cash flow hedges and meeting the effectiveness guidelines of SFAS No. 133, changes in fair value are recognized in other comprehensive income (loss) until the hedged item is recognized in earnings. Hedge effectiveness is required to be measured at least quarterly based on relative changes in fair value between the derivative contract and hedged item during the period of hedge designation. The ineffective portion of a derivative’s change in fair value is recognized in current earnings. For derivative instruments not designated as hedging instruments, the change in fair value is recognized in earnings during the period of change as a change in derivative fair value.

     The Company has entered in costless collar arrangements intended to reduce the Company’s exposure to short-term fluctuations in the price of natural gas. 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 arrangements cover only a portion of the Company’s production and provide only partial price protection against declines in natural gas prices. These economic hedging arrangements may expose the Company to risk of financial loss and limit the benefit of future increases in prices. No derivative contracts were in place as of December 31, 2008.

     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 under SFAS No. 133 to permit these derivative contracts to be accounted for as cash flow hedges. The Company’s fair value of derivative contracts was $-0- as of December 31, 2008 and an asset of $646,193 as of September 30, 2008. Realized and unrealized gains for the periods ended December 31, 2008 and December 31, 2007 are scheduled below:

Gains on natural gas		Three months ended
derivative contracts		12/31/08				12/31/07
Realized		$	1,039,200			$	61,400
(Decrease) increase in fair value			(646,193	)			202,386
Total		$	393,007			$	263,786

NOTE 11: Exploration Costs

     Certain non-producing leases which have expired or which have no future plans of development with an aggregate carrying value of $148,018 were fully impaired and charged to exploration costs in the first quarter of fiscal 2009, along with $24,247 related to an exploratory dry hole. In the fiscal 2008 quarter, $214,293 was charged to exploration costs for non-producing leases which had expired or which had no future plans of development, slightly offset by small credits on previously recorded exploratory dry holes.

NOTE 12: Fair Value Measurements

     Effective October 1, 2008, the Company adopted Statement of Financial Accounting Standards No. 157, Fair Value Measurements for its financial assets and liabilities measured on a recurring basis. This statement establishes a framework for measuring fair value of assets and liabilities and expands disclosures about fair value measurements. In February 2008, the FASB issued FSP 157-2, which delayed the effective date of SFAS No. 157 by one year for nonfinancial assets and liabilities. The Company has only partially applied SFAS No. 157 and will delay full application for nonfinancial assets and liabilities for one year (until the Company’s fiscal year beginning October 1, 2009) as permitted by FSP 157-2. The Company is currently assessing the impact that full application for nonfinancial assets and liabilities will have on its financial position, results of operations or cash flows.

     SFAS 157 defines fair value 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 and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the financial asset or liability and have the lowest priority. The Company uses appropriate valuation techniques based on available inputs, including counterparty quotes, to measure the fair values of its assets and liabilities. Counterparty quotes are generally assessed as a Level 3 input.

Level 3 Fair Value Measurements

     Derivatives. The fair values of the Company’s derivatives are based on estimates provided by its respective counterparty and reviewed internally using established index prices and other sources. These values are based upon, among other things, futures prices, volatility and time to maturity.

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

		Derivatives
Balance of Level 3 as of October 1, 2008		$	646,193
Total gains or losses (realized/unrealized):
Included in earnings			393,007
Included in other comprehensive income (loss)			—
Purchases, issuances and settlements			(1,039,200	)
Transfers in and out of Level 3			—
Balance of Level 3 as of December 31, 2008		$	—

NOTE 13: New Accounting Pronouncements

     In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities. This statement permits entities to choose to measure many financial instruments and certain other items at fair value. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. Since the Company has not elected to adopt the fair value option for eligible items, SFAS No. 159 has not had an impact on its financial position, results of operations or cash flows.

     In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133 . This statement changes the disclosure requirements for derivative instruments and hedging activities. The statement requires that objectives for using derivative instruments be disclosed in terms of underlying risk and accounting designation. This statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The Company is currently assessing the impact that adoption of this statement will have on its financial disclosures.

     In December 2008, the SEC released Final Rule, Modernization of Oil and Gas Reporting. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new requirements also will allow companies to disclose their probable and possible reserves to investors. In addition, the new disclosure requirements require companies to: (a) report the independence and qualifications of its reserves preparer or auditor; (b) file reports when a third party is relied upon to prepare reserves estimates or conducts a reserves audit; and (c) report oil and natural gas reserves using an average price based upon the prior 12-month period rather than year-end prices. The new disclosure requirements are effective for registration statements filed on or after January 1, 2010, and for annual reports on Forms 10-K and 20-F for fiscal years ending on or after December 31, 2009. The Company is currently assessing the impact that adoption of this rule will have on its financial 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 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 2009 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 2008 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

     At December 31, 2008, the Company had positive working capital of $2,925,770, as compared to positive working capital of $4,599,004 at September 30, 2008. Decreased working capital is the result of decreases in oil and natural gas sales receivables partially offset by decreases in accounts payable. Oil and natural gas sales receivables decreased as a result of decreased oil and natural gas sales resulting primarily from decreases in oil and natural gas sales prices. Accounts payable at December 31, 2008 compared to September 30, 2008 decreased as a result of decreased drilling activity.

     Operating cash flow in the fiscal 2009 quarter increased by 95% over the fiscal 2008 quarter due largely to a 44% increase in natural gas production which more than offset lower oil and natural gas prices and lower oil production. Additions to properties and equipment for oil and gas activities during the 2009 first quarter were $12,385,991 ($8,724,389 in the 2008 quarter). Due to the sharp decline in recent months of oil and natural gas prices, management expects operating cash flow and property and equipment additions for oil and natural gas activities to decline significantly from recent levels in the remaining quarters of fiscal 2009. Not being the operator of any of its oil and natural gas properties makes it extremely difficult for the Company to predict capital expenditures with certainty. However, based on management’s assessment of current conditions, fiscal 2009 additions to property and equipment for oil and gas activities are projected to be approximately $30,000,000; whereas fiscal 2008 property and equipment for oil and gas activities’ additions were approximately $53,000,000. Low oil and natural gas prices are also having a negative impact on drilling activity on the Company’s mineral and leasehold acreage. The Company’s drilling activity, to this point, in the Woodford Shale and Fayetteville Shale unconventional resource plays in southeast Oklahoma and Arkansas, respectively, and in the Dill City project has been relatively consistent with 2008; however,

significant decreases in drilling expenditures in all three of these areas are anticipated for the remainder of fiscal 2009. The Company is currently experiencing fewer wells being drilled on its acreage elsewhere in the mid-continent area.

     The industry-wide decline in drilling activity has also created downward pressure on the costs for drilling rigs, well equipment, and well services; which is expected to reduce the overall costs of drilling and completing wells. Nationwide, as lower prices continue to put downward pressure on drilling activity, and the resulting production declines occur, natural gas prices are expected to increase.

     The Company historically funded capital additions, overhead costs and dividend payments primarily from operating cash flow. However, due to the sharp decrease in oil and natural gas prices and the increased expenditures for drilling in the last two years, 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 and reduced product prices, could result in significantly increased borrowings under the Company’s credit facility. However, the Company currently has several wells that have been recently completed which will provide significant cash flow during both the second and third quarters of fiscal 2009 as the first payments (which will cover 4 to 6 months of production) on these wells are received. The Company has availability under its restructured revolving credit facility and also is well within compliance on its debt covenants (current ratio, debt to EBITDA, tangible net worth and dividends as a percent of operating cash flow). Therefore, 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.

RESULTS OF OPERATIONS

THREE MONTHS ENDED DECEMBER 31, 2008 — COMPARED TO THREE MONTHS ENDED DECEMBER 31, 2007

Overview:

     The Company recorded a first quarter 2009 net loss of $874,629, or $.10 per share, as compared to a net income of $3,480,307 or $.41 per share in the 2008 quarter.

Revenues:

     Total revenues were down $2,384,101 or 17% for the 2009 quarter, primarily the result of a $2,609,430 decline in oil and natural gas sales. This sales decline was due to decreases in natural gas and oil sales prices of 37% and 40%, respectively, and a decline in oil sales volume of 18% partially offset by a 44% increase in natural gas sales volume. Gains on natural gas collar contracts resulted in a revenue increase of $129,221 compared to the 2008 quarter. The table below outlines the Company’s production and average sales prices for oil and natural gas for the three month periods of fiscal 2009 and 2008:

		BARRELS				AVERAGE				MCF				AVERAGE				MCFE
		SOLD				PRICE				SOLD				PRICE				SOLD
Three months ended 12/31/08			30,260			$	51.80				2,313,739			$	3.91				2,495,299
Three months ended 12/31/07			36,721			$	86.40				1,610,880			$	6.24				1,831,206

     Increased natural gas production is the result of continued drilling success in the southeast Oklahoma Woodford Shale area, the Fayetteville Shale area in Arkansas and the western Oklahoma Dill City area. The decrease in oil production is the result of natural decline on older wells as the Company’s drilling focus is primarily for natural gas reserves. During the first quarter of fiscal 2009, the Company had several new wells that were completed and put on line, and had several more wells that were in the process of being completed. Expectations are that the production from these new wells will result in an increase in natural gas production for the second quarter of fiscal 2009 compared to the first quarter of 2009. As drilling is anticipated to continue, although at a significantly reduced rate compared to fiscal 2008, in the three core areas of the Woodford Shale, the Fayetteville Shale and the Dill City project, the Company expects additional new production to more than replace the decline in production of older wells.

     Production for the last five quarters was as follows:

Quarter ended		Barrels Sold				MCF Sold				MCFE
12/31/08			30,260				2,313,739				2,495,299
9/30/08			31,375				1,995,333				2,183,583
6/30/08			31,907				1,788,462				1,979,904
3/31/08			32,399				1,533,363				1,727,757
12/31/07			36,721				1,610,880				1,831,206

Gains on Natural Gas Collar Contracts:

     At December 31, 2008, the Company’s fair value of derivative contracts was $-0- (all of the Company’s derivative contracts in place expired as of December 31, 2008); whereas at September 30, 2008, the Company’s fair value of derivative contracts was an asset of $646,193. The Company recorded a gain during the fiscal 2009 first quarter of $393,007 as compared to a gain of $263,786 for the fiscal 2008 quarter. See the table under “NOTE 10: Derivatives” for a breakdown of the realized and unrealized gains and losses on derivative contracts in place during the quarters ended December 31, 2008 and 2007.

Lease Operating Expenses (LOE):

     LOE increased $404,242 or 30% in the 2009 quarter as compared to the 2008 quarter, while LOE per mcfe decreased in the 2009 quarter to $.70 per mcfe from $.73 per mcfe in the 2008 quarter. The total LOE increase is the result of new wells coming on line during the year. The decrease on a per mcfe basis is due to the decrease in natural gas sales prices resulting in lower “value based” fees (primarily gathering and marketing costs) which are charged as a percent of natural gas sales, combined with declining prices for field services and supplies.

Production Taxes:

     Production taxes decreased $422,856 or 51% in the 2009 quarter as compared to the 2008 quarter. The decline in production tax expense is the result of qualifying for production tax credits on horizontal wells drilled in the southeast Oklahoma Woodford Shale. The state of Oklahoma offers a refund on horizontally drilled wells of nearly all production taxes paid for the first four years of production or until well payout occurs, whichever comes first. The decrease also relates to the increasing number of Arkansas Fayetteville Shale wells coming on line as compared to a year ago. Such carry a production tax rate of $.012 per mcf produced. The combined result is a decrease in the severance tax rate as a percentage of oil and natural gas sales from 6.3% in the 2008 quarter to 3.9% in the 2009 quarter. As horizontally drilled wells coming on line in the Woodford Shale (all of which qualify for the production tax credits) have become a more significant part of the Company’s production, production tax expense as a percentage of oil and natural gas sales has continued to decline.

Exploration Costs:

     Exploration costs decreased $37,716 in the 2009 quarter as compared to the 2008 quarter. Leasehold expiration and abandonment costs were $148,018 for the 2009 quarter as compared to $214,293 for the 2008 quarter. One exploratory dry hole was drilled in the 2009 quarter at a cost of $24,247. No dry holes were drilled in the 2008 quarter; however, credits in the amount of $4,312 were recorded in the 2008 quarter on one previously drilled dry hole.

Depreciation, Depletion and Amortization (DD&A):

     DD&A increased $2,693,482 or 63% in the 2009 quarter. DD&A in the 2009 quarter was $2.79 per mcfe as compared to $2.32 per mcfe in the 2008 quarter. The overall increase is the result of increased production volumes in the 2009 quarter over the 2008 quarter. The increase in the DD&A rate per mcfe is due to increased costs of drilling and completing new wells during recent years.

Provision for Impairment:

     The provision for impairment increased $1,753,911 in the 2009 quarter as compared to the 2008 quarter. Driven by depressed oil and natural gas prices, impairment was recorded on 16 fields during the 2009 quarter in the amount of $1,875,920. Two of the fields accounted for $1,729,034 of the impairment, one field in Wheeler County, Texas consisting of one deep well (drilled in 2006 and had mechanical issues during completion which dramatically increased costs) was impaired $1,070,129 and one mature field in Beckham County, Oklahoma principally consisting of wells drilled in 2006 and prior was impaired $658,905. The Company did not incur any impairment in the three primary areas of operation (Woodford Shale area, Fayetteville Shale area and Dill City project). During the 2008 quarter, 4 fields were impaired a total of $122,009.

General and Administrative Costs (G&A):

     G&A decreased $377,882 or 24% in the 2009 quarter as compared to the 2008 quarter due to decreased personnel related costs of approximately $443,000, which included a decrease in employee bonus costs of approximately $500,000 in the 2009 quarter (the result of beginning to ratably accrue for estimated 2008 annual employee bonuses during the 2008 quarter due to specific bonus performance criteria being established plus recording the full 2007 annual bonuses approved and paid during the 2008 quarter), partially offset by overall increases in several other G&A categories.

Income Taxes:

     The provision for income taxes for the 2009 quarter decreased $1,998,000 due to a sharp decrease in income before provision for income taxes of $6,352,936 in the 2009 quarter as compared to the 2008 quarter. The resulting effective tax rate in the 2009 quarter was 17% as compared to an effective tax rate of 34% in the 2008 quarter. The Company’s utilization of excess percentage depletion (which is a permanent tax benefit) reduced taxable income a greater proportion during the 2009 quarter as compared to the 2008 quarter. This greater proportional effect in the 2009 quarter resulted in a significantly lower effective tax rate than in the 2008 quarter.

CRITICAL ACCOUNTING POLICIES

     Preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates, judgments and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. However, the accounting principles used by the Company generally do not change the Company’s reported cash flows or liquidity. Generally, accounting rules do not involve a selection among alternatives, but involve a selection of the appropriate policies for applying the basic principles. Interpretation of the existing rules must be done and judgments made on how the specifics of a given rule apply to the Company.

     The more significant reporting areas impacted by management’s judgments and estimates are crude oil and natural gas reserve estimation, impairment of assets, oil and natural gas sales revenue accruals and provision for income tax. Management’s judgments and estimates in these areas are based on information available from both internal and external sources, including engineers, geologists, consultants and historical experience in similar matters. Actual results could differ from the estimates as additional information becomes known. The oil and natural gas sales revenue accrual is particularly subject to estimates due to the Company’s status as a non-operator on all of its properties. Production information obtained from well operators is substantially delayed. This causes the estimation of recent production, used in the oil and natural gas revenue accrual, to be subject to some variations.

Oil and Natural Gas Reserves

     Management considers the estimation of crude oil and natural gas reserves to be the most significant of its judgments and estimates. These estimates affect the unaudited standardized measure disclosures, as well as DD&A and impairment calculations. Changes in crude oil and natural gas reserve estimates affect the Company’s calculation of depreciation, depletion and amortization, provision for abandonment and assessment of the need for asset impairments. On an annual basis, with a semi-annual update, the Company’s consulting engineer, with assistance from Company geologists, prepares estimates 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. However, when significant oil and natural gas price changes occur between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing a price deck current with the period (re-engineering is not performed, only the updated price deck is used to assess the economic lives of the wells). For instance, reserves for the quarter ended December 31, 2008 were updated due to significant changes in the prices of oil and natural gas since September 30, 2008. Both DD&A and impairment were calculated in the 2009 quarter based on these updated reserve calculations. As required by the guidelines and definitions established by the SEC, these estimates are based on current crude oil and natural gas pricing. Crude oil and natural gas prices are volatile and largely affected by worldwide production and consumption and are outside the control of management. Projected future crude oil and natural gas pricing assumptions are used by management to prepare estimates of crude oil and natural gas reserves used in formulating management’s overall operating decisions in the exploration and production segment. Based on the Company’s fiscal 2008 DD&A, a 10% change in the DD&A rate per mcfe would result in a corresponding $1,978,466 annual change in DD&A expense.

Successful Efforts Method of Accounting

     The Company has elected to utilize the successful efforts method of accounting for its oil and natural gas exploration and development activities. Exploration expenses, including geological and geophysical costs, rentals and exploratory dry holes, are charged against income as incurred. Costs of successful wells and related production equipment and developmental dry holes are capitalized and amortized by property using the unit-of-production method as oil and natural gas is produced. The Company’s exploratory wells are all on-shore and primarily located in the mid-continent area. Generally, expenditures on exploratory wells comprise less than 10% of the Company’s total expenditures for oil and natural gas properties. This accounting method may yield significantly different operating results than the full cost method.

Impairment of Assets

     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 Company estimates future net cash flows on its oil and natural gas properties utilizing differentially adjusted forward pricing curves for both oil and natural gas and a discount rate in line with the discount rate used by the Company’s bank to evaluate its properties. 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. A further reduction in oil and natural gas prices or a decline in reserve volumes (which are re-evaluated semi-anually) could lead to additional impairment that may be material to the Company. Any assets held for sale are reviewed for impairment when the Company approves the plan to sell. Estimates of anticipated sales prices are highly judgmental and subject to material revision in future periods. Because of the uncertainty inherent in these factors, the Company cannot predict when or if future impairment charges will be recorded.

Oil and Natural Gas Sales Revenue Accrual

     The Company does not operate any of its oil and natural gas properties. Drilling in the last two years has resulted in adding numerous wells with significantly larger interests, thus increasing the Company’s production and revenue. On many of these wells the most current available production data is gathered from the appropriate operators and oil and natural gas index prices local to each well are used to more accurately estimate the accrual of revenue on these wells. Timely obtaining production data on all other wells from the operators is not feasible; therefore, the Company utilizes past production receipts and estimated sales price information to estimate its accrual of revenue on all other wells each quarter. The oil and natural gas sales revenue accrual can be impacted by many variables including rapid production decline rates, production curtailments by operators, the shut-in of wells with mechanical problems and rapidly changing market prices for oil and natural gas. These variables could lead to an over or under accrual of oil and natural gas sales at the end of any particular quarter. Based on past history, the Company’s estimated accrual has been materially accurate.

Income Taxes

     The estimation of the amounts of income tax to be recorded by the Company involves interpretation of complex tax laws and regulations as well as the completion of complex calculations, including the determination of the Company’s percentage depletion deduction, if any. The excess percentage depletion calculation during interim periods represents a high-level estimate as the actual well-by-well calculation required cannot be performed until the end of the fiscal year. Although the Company’s management believes its tax accruals are adequate, differences may occur in the future depending on the resolution of pending and new tax matters.

     The above description of the Company’s critical accounting policies is not intended to be an all-inclusive discussion of the uncertainties considered and estimates made by management in applying accounting principles and policies. Results may vary significantly if different policies were used or required and if new or different information becomes known to management.

ITEM 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     The Company’s revenue can be significantly impacted by changes in market prices for oil and natural gas. Based on the Company’s fiscal 2008 production, a $.10 per mcf change in the price received for natural gas production would result in a corresponding $693,000 annual change in revenue. A $1.00 per barrel change in the price received for oil production would result in a corresponding $132,000 annual change in revenue. Cash flows could be impacted, to a lesser extent, by changes in the market interest rates related to the revolving credit facility which, as of December 31, 2008, bore interest at an annual variable interest rate equal to the national prime rate minus from 1.375% to .750% or 30 day LIBOR plus from 1.375% to 2.000%. At December 31, 2008, the Company had $12,996,339 outstanding under this facility. Based on total debt outstanding at December 31, 2008 a .5% change in interest rates would result in a $65,000 annual change in pre-tax operating cash flow.

     The Company periodically utilizes certain derivative contracts, costless collars, to reduce its exposure to unfavorable changes in natural gas prices. Volumes under such contracts do not exceed expected production. The Company’s collars contain a fixed floor price and a fixed ceiling price. If market prices exceed the ceiling price or fall below the floor, then the Company will receive the difference between the floor and market price or pay the difference between the ceiling and market price. If market prices are between the ceiling and the floor, then no payments or receipts related to the collars are required. These arrangements cover only a portion of the Company’s production and provide only partial price protection against declines in natural gas prices. These economic hedging arrangements may expose the Company to risk of financial loss and limit the benefit of future increases in prices. As of December 31, 2008, the Company had no collar contracts in place.

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.

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

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 5, 2009		/s/ Michael C. Coffman
Date		Michael C. Coffman, President and
		Chief Executive Officer
February 5, 2009		/s/ Lonnie J. Lowry
Date		Lonnie J. Lowry, Vice President
		and Chief Financial Officer