PHX Minerals (PHX) 10-Q 2008 Q1 Quarterly report

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, 2007

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 Number001-31759

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 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):

o Large accelerated filer þ Accelerated filer o  Non-accelerated filer o  Smaller reporting company

(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, 2008: 8,431,502

INDEX

Part I Financial Information
Item 1 Condensed Consolidated Financial Statements	Page
Condensed Consolidated Balance Sheets – December 31, 2007 and September 30, 2007	1
Condensed Consolidated Statements of Income – Three months ended December 31, 2007 and 2006	2
Consolidated Statement of Stockholders’ Equity – Three months ended December 31, 2007	3
Condensed Consolidated Statements of Cash Flows – Three months ended December 31, 2007 and 2006	4
Notes to Condensed Consolidated Financial Statements	5-7
Item 2 Management’s discussion and analysis of financial condition and results of operations	8-11
Item 3 Quantitative and qualitative disclosures about market risk	11-12
Item 4 Controls and procedures	12
Part II Other Information	12
Item 6 Exhibits and reports on Form 8-K	12
Signatures	12
Certification Under Section 302
Certification Under Section 302
Certification Under Section 906
Certification Under Section 906

PART 1 FINANCIAL INFORMATION

PANHANDLE OIL AND GAS INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Information at December 31, 2007 is unaudited)

	December 31, 2007		September 30, 2007
Assets
Current assets:
Cash and cash equivalents	$	751,337	$	989,360
Oil and gas sales receivables		10,264,639		8,103,250
Fair value of natural gas collar contracts		309,302		106,916
Other		90,729		112,882
Total current assets		11,416,007		9,312,408
Properties and equipment, at cost, based on successful efforts accounting:
Producing oil and gas properties		133,327,055		125,634,251
Non-producing oil and gas properties		11,369,135		10,697,854
Other		627,194		625,455
		145,323,384		136,957,560
Less accumulated depreciation, depletion and amortization		72,659,145		68,424,645
Net properties and equipment		72,664,239		68,532,915
Investments		669,475		690,011
Other		4,463		4,463
Total assets	$	84,754,184	$	78,539,797
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable	$	3,068,956	$	1,773,255
Accrued liabilities		1,313,570		348,042
Total current liabilities		4,382,526		2,121,297
Long-term debt		4,852,720		4,661,471
Deferred income taxes		18,258,750		16,827,750
Asset retirement obligations		1,247,908		1,247,908
Stockholders’ equity:
Class A voting common stock, $.0166 par value; 24,000,000 shares authorized, 8,431,502 issued and outstanding at December 31, 2007 and at September 30, 2007		140,524		140,524
Capital in excess of par value		2,146,071		2,146,071
Deferred directors’ compensation		1,389,790		1,358,778
Retained earnings		52,335,895		50,035,998
Total stockholders’ equity		56,012,280		53,681,371
Total liabilities and stockholders’ equity	$	84,754,184	$	78,539,797

(1)

PANHANDLE OIL AND GAS INC.

CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(unaudited)

	Three Months Ended December 31,
	2007		2006
Revenues:
Oil and gas sales	$	13,226,094	$	8,081,208
Lease bonuses and rentals		10,446		115,811
Realized gains on natural gas collar contracts		61,400		—
Unrealized gains on natural gas collar contracts		202,386		605,020
Gain on asset sales, interest and other		52,394		52,229
Income of partnerships		151,083		77,627
		13,703,803		8,931,895
Costs and expenses:
Lease operating expenses		1,344,901		899,968
Production taxes		829,604		500,728
Exploration costs		209,981		673,967
Depreciation, depletion, and amortization		4,256,610		2,693,468
Provision for impairment		122,009		52,567
Loss on asset sales		—		32,397
General and administrative		1,597,045		1,147,248
Interest expense		44,346		54,615
		8,404,496		6,054,958
Income before provision for income taxes		5,299,307		2,876,937
Provision for income taxes		1,819,000		893,444
Net income	$	3,480,307	$	1,983,493
Earnings per common share (Note 3)	$	0.41	$	0.23
Dividends declared per share of common stock and paid in period	$	0.07	$	0.04
Dividends declared per share of common stock for and to be paid in the quarter ended March 31 (Note 5)	$	0.07	$	0.07

(2)

PANHANDLE OIL AND GAS INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(Information at and for the three months ended December 31, 2007 is unaudited)
Three Months Ended December 31, 2007

	Class A voting				Capital in		Deferred
	Common Stock				Excess of		Directors’		Retained
	Shares		Amount		Par Value		Compensation		Earnings			Total
Balances at September 30, 2007		8,431,502	$	140,524	$	2,146,071	$	1,358,778	$	50,035,998		$	53,681,371
Net Income		—		—		—		—		3,480,307			3,480,307
Dividends ($.14 per share)		—		—		—		—		(1,180,410	)		(1,180,410	)
Increase in deferred directors’ compensation charged to expense		—		—		—		31,012		—			31,012
Balances at December 31, 2007		8,431,502	$	140,524	$	2,146,071	$	1,389,790	$	52,335,895		$	56,012,280

(3)

PANHANDLE OIL AND GAS INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(unaudited)

	Three months ended December 31,
	2007			2006
Operating Activities
Net income	$	3,480,307		$	1,983,493
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization		4,256,610			2,693,468
Provision for impairment		122,009			52,567
Deferred income taxes		1,431,000			1,027,500
Lease bonus income		—			(18,697	)
Exploration costs		209,981			673,967
Gain on sales of assets		(16,942	)		(80,651	)
Equity in earnings of partnerships		(151,083	)		(77,627	)
Distributions received from partnerships		171,619			98,163
Directors’ deferred compensation expense		31,012			30,085
Cash provided by changes in assets and liabilities:
Oil and gas sales receivables		(2,161,389	)		221,971
Fair value of derivative contracts		(202,386	)		(605,020	)
Refundable income taxes and other		22,153			(261,396	)
Accounts payable		150,657			1,214,221
Accrued liabilities		375,323			54,701
Total adjustments		4,238,564			5,023,252
Net cash provided by operating activities		7,718,871			7,006,745
Investing Activities
Capital expenditures, including dry hole costs		(7,579,345	)		(5,484,915	)
Proceeds from leasing of fee mineral acreage		15,137			107,265
Proceeds from sales of assets		6,270			190,814
Net cash used in investing activities		(7,557,938	)		(5,186,836	)
Financing Activities
Borrowings under credit facility		7,776,160			3,011,625
Payments on credit facility		(7,584,911	)		(3,928,278	)
Payments of dividends		(590,205	)		(336,901	)
Net cash used in financing activities		(398,956	)		(1,253,554	)
Increase (decrease) in cash and cash equivalents		(238,023	)		566,355
Cash and cash equivalents at beginning of period		989,360			434,353
Cash and cash equivalents at end of period	$	751,337		$	1,000,708
Supplemental Schedule of Noncash Investing and Financing Activities
Dividends declared and unpaid	$	590,205		$	589,577
Additions and revisions, net, to asset retirement obligations	$	—		$	197,697
Properties and equipment change included in accounts payable	$	1,145,044		$	156,884

(See accompanying notes)

(4)

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 have been prepared in accordance with the instructions to Form 10-Q as prescribed by the Securities and Exchange Commission, and include the Company’s wholly owned subsidiary, Wood Oil Company (Wood). Management of Panhandle Oil and Gas Inc. (formerly Panhandle Royalty Company) believes that all adjustments necessary for a fair presentation of the consolidated financial position and results of operations for the periods presented 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 2007 Annual Report on Form 10-K.

NOTE 2: Income Taxes

     The Company’s provision for income taxes 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.

     The Company has performed its evaluation of tax positions and has determined that the adoption of FIN 48 did not have a material impact on the Company’s financial condition, results of operations, or cash flows. This evaluation is a review of the appropriate recognition threshold for each tax position recognized in the Company’s financial statements. Based on this evaluation, the Company did not identify any tax positions that did not meet the “highly certain positions” threshold. As a result, no additional tax expense, interest, or penalties have been accrued as a result of the review.

     The Company includes interest assessed by the taxing authorities in “Interest expense” and penalties related to income taxes in “General and administrative expense” on its Consolidated Statements of Income. For the three months ended December 31, 2007 and 2006, the Company recorded no interest or penalties on uncertain tax positions.

NOTE 3: Earnings per Share

     Earnings per share is calculated using net income divided by the weighted average number of common shares outstanding (including unissued, vested directors’ shares of 78,748 and 71,108 for fiscal 2008 and 2007, respectively) during the period.

NOTE 4: Long-term Debt

     The Company has a credit facility with Bank of Oklahoma (BOK) which consists of a term loan in the amount of $2,500,000 and a revolving loan in the amount of $50,000,000 which is subject to a semi-annual borrowing base determination. The current borrowing base is $10,000,000. The term loan matured on September 1, 2007, and the revolving loan matures on October 31, 2010. Borrowings under the revolving loan are due at maturity. The revolving loan bears interest at the national prime rate minus from 1.375% to .75%, or 30 day LIBOR plus from 1.375% to 2.0%. The interest rate charged will be based on the percent of the value advanced of the calculated loan value of Panhandle’s oil and gas reserves. The interest rate spread from LIBOR or prime increases as a larger percent of the loan value of Panhandle’s oil and gas properties is advanced. At December 31, 2007 the interest rate for the revolving loan was 5.975%.

(5)

NOTE 5: Dividends

     On October 24, 2007, the Company’s Board of Directors declared a $.07 per share dividend that was paid on December 10, 2007. On December 11, 2007, the Company’s Board of Directors approved payment of a $.07 per share dividend to be paid on March 7, 2008 to shareholders of record on February 25, 2008.

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 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 7: Capitalized Costs

     Non-producing oil and gas properties include costs of $562,348 on exploratory wells which were drilling and/or testing at December 31, 2007.

NOTE 8: Derivatives

     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.

     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. Amounts recorded in unrealized gains (losses) on derivative activities do not represent cash gains or losses. Rather, these amounts are temporary valuation swings in contracts that are not entitled to receive hedge accounting treatment.

     Beginning in fiscal year 2007, 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 minimum price, or floor 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. The derivative instruments will settle based on the prices below which are tied to indexes for certain pipelines in Oklahoma.

(6)

     Effective January 1, 2007, the Company entered into the following three natural gas collar contracts.

First Contract:
Production volume covered	30,000 mmbtu/month
Period covered	January through December of 2007
Prices	Floor of $6.00 and a ceiling of $9.20
Second Contract:
Production volume covered	40,000 mmbtu/month
Period covered	January through December of 2007
Prices	Floor of $6.00 and a ceiling of $9.20
Third Contract:
Production volume covered	30,000 mmbtu/month
Period covered	January through December of 2007
Prices	Floor of $6.00 and a ceiling of $10.20

     In November 2007, the Company entered into the following natural gas collar contracts.

First Contract:
Production volume covered	40,000 mmbtu/month
January through March of 2008	Floor of $6.60 and a ceiling of $8.85
April through September of 2008	Floor of $6.20 and a ceiling of $8.15
October through December of 2008	Floor of $6.50 and a ceiling of $8.90
Second Contract:
Production volume covered	40,000 mmbtu/month
January through March of 2008	Floor of $6.60 and a ceiling of $9.10
April through September of 2008	Floor of $6.40 and a ceiling of $8.60
October through December of 2008	Floor of $6.90 and a ceiling of $9.15
Third Contract:
Production volume covered	40,000 mmbtu/month
January through March of 2008	Floor of $6.55 and a ceiling of $8.80
April through September of 2008	Floor of $6.15 and a ceiling of $8.05
October through December of 2008	Floor of $6.55 and a ceiling of $8.75

     Effective January 31, 2008, the Company entered into the following three natural gas collar contracts.

First Contract:
Production volume covered	30,000 mmbtu/month
Period covered	April through September of 2008
Prices	Floor of $6.65 and a ceiling of $7.50
Second Contract:
Production volume covered	30,000 mmbtu/month
Period covered	April through September of 2008
Prices	Floor of $6.85 and a ceiling of $7.80
Third Contract:
Production volume covered	30,000 mmbtu/month
Period covered	April through September of 2008
Prices	Floor of $6.60 and a ceiling of $7.50

     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 $309,302 as of December 31, 2007 and $106,916 as of September 30, 2007, resulting in net unrealized gains of $202,386 and realized gains of $61,400 in the three months ended December 31, 2007.

NOTE 9: Exploration Costs

     Certain non-producing leases which have expired or which have no future plan of development (aggregate carrying value of $214,293) were fully impaired and charged to exploration costs in the 2008 quarter, slightly offset by small credits on previously recorded dry holes. In the 2007 quarter $493,776 was charged to exploration costs on one exploratory dry hole, and $177,954 was also charged to exploration costs on non-producing leases which have expired or which have no future plan of development.

(7)

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 2008 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 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 gas reserves. These risks include, but are not limited to, oil and natural gas price risk, natural gas price hedging risk, drilling and equipment cost risk, field services cost risk, environmental risks, drilling risk, reserve quantity risk and operations and production risk. 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, 2007, the Company had positive working capital of $7,033,481, as compared to positive working capital of $7,191,111 at September 30, 2007. The decrease is the result of an increase in accounts payable, income taxes payable, other accrued liabilities and a decrease in cash, offset by increases in oil and gas sales receivable and fair value of derivative contracts. Oil and gas sales receivable increased due to an overall increase in oil and gas sales as a result of increased oil and gas production and sales price increases. Accounts payable increased as the Company continues capital spending for oil and gas activities at a high level.

     Operating cash flow remains strong. Additions to properties and equipment for oil and gas activities for the 2008 three-month period amounted to $8,724,389. Management currently expects capital commitments for oil and gas activities of up to $42,000,000 for fiscal 2008. Management’s strategy to participate in new wells with larger working interests combined with high drilling activity has resulted in continued increases in capital expenditures. Drilling in the Woodford Shale and Fayetteville Shale unconventional resource plays in southeast Oklahoma and Arkansas, respectively, and in the Dill City play in western Oklahoma are and will continue to be a large component of expected capital additions for the next several years. As drilling activity remains high, costs for drilling rigs, well equipment and services remain high, and are expected to remain so for the remainder of fiscal 2008. Any acquisitions of oil and gas properties would further increase the capital addition amount.

     The Company has historically funded capital additions, overhead costs and dividend payments from operating cash flow and has utilized, at times, its revolving line-of-credit facility to help fund these expenditures. With the uncertainty of natural gas prices, and their effect on cash flow, some amounts have been and will be in the next several quarters borrowed on a temporary basis under the Company’s credit facility. The Company has substantial availability under its bank debt facility and the availability could be increased, if needed. In addition, the Company has entered into natural gas collar contracts (discussed in Note 8 above) to help guard against potential negative price fluctuations which would reduce capital available for drilling new oil and gas wells.

RESULTS OF OPERATIONS

THREE MONTHS ENDED DECEMBER 31, 2007 – COMPARED TO THREE MONTHS ENDED DECEMBER 31, 2006

Overview:

     The Company recorded a first quarter 2008 net income of $3,480,307, or $.41 per share, as compared to a net income of $1,983,493 or $.23 per share in the 2007 quarter.

Revenues:

     Total revenues increased $4,771,908 or 53% for the 2008 quarter. The increase was primarily the result of a $5,144,886 increase in oil and gas sales resulting from a 34% increase in gas sales volumes and a 10% increase in gas sales price for the 2008 quarter. Oil sales volumes increased 63% in the 2008 quarter and oil prices increased 52%. Realized and unrealized gains on natural gas collar contracts resulted in a revenue decrease of $341,234. The table below outlines the Company’s production and average sales prices for oil and natural gas for the three month periods of fiscal 2008 and 2007:

(8)

	BARRELS		AVERAGE		MCF		AVERAGE		MCFE
	SOLD		PRICE		SOLD		PRICE		SOLD
Three months ended 12/31/07		36,721	$	86.40		1,610,880	$	6.24		1,831,206
Three months ended 12/31/06		22,567	$	56.94		1,198,955	$	5.67		1,334,357

     The Company’s applied strategy of increasing its working interests in new wells drilled and the associated increase in drilling expenditures continues to result in increased production volumes for both gas and oil, as compared to the fiscal 2007 quarter. Increased production is principally attributable to increased production from the Dill City, Oklahoma area (gas and oil), southeast Oklahoma Woodford Shale area (gas only) and the Yellowstone Southeast field (oil only) in Woods County, Oklahoma. The Company’s drilling continues to be concentrated on gas production, although the Dill City area and the Yellowstone Southeast field have yielded oil production that is significant to the Company. New wells coming on line are continuing to replace the decline in production of older wells, and the Company anticipates additional new production coming on line in future periods.

     Production by quarter for the last five quarters was as follows:

Quarter ended	Barrels Sold	MCF Sold	MCFE
12/31/07	36,721	1,610,880	1,831,206
9/30/07	31,677	1,529,924	1,719,986
6/30/07	31,223	1,244,685	1,432,023
3/31/07	21,877	1,173,779	1,305,041
12/31/06	22,567	1,198,955	1,334,357

     The Company is a non-operator and obtaining timely production data and sales price information from most operators is not possible. This causes the Company to utilize past production receipts and estimated sales price information to estimate its oil and gas sales revenue accrual at the end of each quarterly period. The oil and gas sales accrual estimates are impacted by many variables including the initial high production from and the possible rapid decline rates of certain new wells and rapidly changing market prices for natural gas. The Company records an accrual to actual adjustment in each succeeding quarter. In January 2008, the Company determined that its oil and gas revenue accrual estimate at September 30, 2007 was lower than actual production proceeds that have been received to date for the accrual period. The lower than actual oil and gas revenue accrual estimate was a result of the above variables. The effect of the accrual estimate change for the three months ended September 30, 2007 was that revenues and net income were approximately $618,000 and $345,000 lower, respectively, than actual results for those periods. Likewise, for the three months ended December 31, 2007, revenues and net income were higher by such amounts.

Realized and Unrealized Gains on Natural Gas Collar Contracts:

     The Company’s fair value of derivative contracts was $309,302 as of December 31, 2007 and $106,916 as of September 30, 2007, resulting in an unrealized gain of $202,386 in the three months ended December 31, 2007 compared to $605,020 for the three months ended December 31, 2006. The Company received cash payments of $61,400 (realized gains) in the three months ended December 31, 2007 (none for the three months ended December 31, 2006) under the contracts.

Gain on asset sales, interest, income of partnerships and other:

     These items increased $73,621 in the 2008 period. Income from partnerships increased $73,456 in the fiscal 2008 quarter as compared to the fiscal 2007 quarter due to increased natural gas production and higher oil prices.

Lease Operating Expenses (LOE):

     LOE increased $444,933 or 49% in the 2008 quarter while LOE per mcfe increased 9% from $.67 in the 2007 quarter to $.73 in the 2008 quarter. The overall increase is due to new wells that have been added since a year ago, major repairs made in the 2008 quarter on six wells and increased ad valorem taxes paid in the 2008 quarter. The major repairs and increased ad valorem taxes account for the increase in LOE per mcfe along with increased field service prices.

Production Taxes:

     Production taxes increased $328,876 or 66% in the 2008 quarter. This increase is in line with the 64% increase in oil and gas sales as production taxes are paid as a percentage of oil and gas sales.

(9)

Exploration Costs:

     These costs decreased $463,986 in the 2008 quarter. Certain non-producing leases which have expired or which are anticipated to have no future plan of development (aggregate carrying value of $214,293) were fully impaired and charged to exploration costs in the 2008 quarter, slightly offset by small credits on previously recorded dry holes. In the 2007 quarter $493,776 was charged to exploration costs on one exploratory dry hole, and $177,954 was also charged to exploration costs on non-producing leases which had expired or which had no anticipated future plan of development.

Depreciation, Depletion and Amortization (DD&A):

     DD&A increased $1,563,142 or 58% in the 2008 quarter to $2.32 per mcfe as compared to $2.02 per mcfe in the 2007 quarter. Well additions during the last year with higher ownership percentages, and consequently higher costs to the Company, account for most of the overall increase in DD&A. Increased drilling rig costs, equipment costs and service costs on new wells and reserve reductions since the 2007 quarter on approximately fifty of the Company’s working interest wells account for the remainder of the DD&A increase and is the reason the Company’s DD&A per mcfe increased by $.30.

Provision for Impairment:

     The provision for impairment increased $69,442 in the 2008 quarter. Four small fields were impaired in the 2008 quarter totaling $122,009 as compared to impairment of one small field and one of the Company’s other investments in the 2007 quarter totaling $52,567.

General and Administrative Costs (G&A):

     G&A costs increased $449,797 or 39% in the 2008 quarter principally due to increased personnel related costs. The increased personnel related costs are due to increased incentive bonuses paid, the addition of two employees since the fiscal 2007 quarter and salary increases awarded since a year ago.  These combined costs increased approximately $215,000 in the 2008 quarter as compared to the 2007 quarter.  Another portion of the increase is attributable to the accrual of anticipated incentive bonuses to be paid for fiscal 2008 of approximately $115,000.  Since the Company has adopted a formal incentive bonus plan, the accrual of incentive bonuses has been initiated in fiscal 2008.  Also, technical consulting and employee insurance expenses combined increased approximately $62,000.

Income Taxes:

     The 2008 quarter provision for income taxes increased due to higher income before provision for income taxes and an increase in the effective tax rate from 31% in the 2007 quarter to 34% for the 2008 quarter. The Company utilizes excess percentage depletion to reduce its effective tax rate from the federal statutory rate.

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 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 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 gas revenue accrual, to be subject to some variations.

Oil and Gas Reserves

     Of these judgments and estimates, management considers the estimation of crude oil and nature gas reserves to be the most significant. 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 (the Company employed a new consulting engineer beginning

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with the March 31, 2007 semi-annual update), 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. 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.

Successful Efforts Method of Accounting

     The Company has elected to utilize the successful efforts method of accounting for its oil and 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 gas is produced. This accounting method may yield significantly different operating results than the full cost method.

Impairment of Assets

     All long-lived assets, principally oil and 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 gas, future production costs, estimates of future oil and 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 gas reserves. 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 can not predict when or if future impairment charges will be recorded.

Oil and Gas Sales Revenue Accrual

     The Company does not operate any of its oil and gas properties, and it primarily holds small interests in several thousand wells. Thus, obtaining timely production data from the well operators is extremely difficult. This requires the Company to utilize past production receipts and estimated sales price information to estimate its oil and gas sales revenue accrual at the end of each quarterly period. The oil and gas accrual can be impacted by many variables, including initial high production rates of new wells and subsequent rapid decline rates of those wells and rapidly changing market prices for natural gas. This could lead to an over or under accrual of oil and gas sales at the end of any particular quarter. Based on past history, the 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. 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 results of operations and operating cash flows can be significantly impacted by changes in market prices for oil and gas. Based on the Company’s 2007 production, a $.10 per Mcf change in the price received for natural gas production would result in a corresponding $515,000 annual change in pre-tax operating cash flow. A $1.00 per barrel change in the price received for oil production would result in a corresponding $107,000 annual change in pre-tax operating cash flow. Cash flows could also be impacted, to a lesser extent, by changes in the market interest rates related to the revolving credit facility which bears interest at an annual variable interest rate equal to the national prime rate minus from 1.375% to .75% or 30 day LIBOR plus from 1.375% to 2.0%. At December 31, 2007 the Company had $4,852,720 outstanding under this facility. Based on total debt outstanding at December 31, 2007 a .5% change in interest rates would result in a $24,300 annual change in pre-tax operating cash flow.

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     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. The Company had not, through fiscal 2006, entered into derivative instruments to hedge the price risk on its oil or gas production. Beginning in fiscal year 2007, 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 minimum price, or floor 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.

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 AND REPORT ON FORM 8-K

(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 6, 2008Date	/s/ Michael C. CoffmanMichael C. Coffman, President and Chief Executive Officer
February 6, 2008Date	/s/ Lonnie J. LowryLonnie J. Lowry, Vice President and Chief Financial Officer

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