PHX MINERALS INC. - Quarter Report: 2009 December (Form 10-Q)

 

 

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

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

		For the transition period from _____________________ to _____________________

Commission File Number 001-31759

PANHANDLE OIL AND GAS INC.

(Exact name of registrant as specified in its charter)

OKLAHOMA		73-1055775
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

Grand Centre Suite 300, 5400 N Grand Blvd., Oklahoma City, Oklahoma 73112

(Address of principal executive offices)

Registrant’s telephone number including area code (405) 948-1560

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

þ Yes     o No

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

o Yes     o No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o

Accelerated filer þ

Non-accelerated filer o (Do not check if a smaller reporting company)

Smaller reporting company o

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

o Yes     þ No

Outstanding shares of Class A Common stock (voting) at February 8, 2010: 8,311,636

 

 

INDEX

						Page
Part I Financial Information
		Item 1		Condensed Consolidated Financial Statements
				Condensed Consolidated Balance Sheets — December 31, 2009 and September 30, 2009			1
				Condensed Consolidated Statements of Operations — Three months ended December 31, 2009 and 2008			2
				Consolidated Statement of Stockholders’ Equity — Three months ended December 31, 2009 and 2008			3
				Condensed Consolidated Statements of Cash Flows — Three months ended December 31, 2009 and 2008			4
				Notes to Condensed Consolidated Financial Statements			5-9
		Item 2		Management’s discussion and analysis of financial condition and results of operations			9-14
		Item 3		Quantitative and qualitative disclosures about market risk			14
		Item 4		Controls and procedures			14
Part II Other Information							15
		Item 6		Exhibits			15
		Signatures					15
EX-31.1
EX-31.2
EX-32.1
EX-32.2

PANHANDLE OIL AND GAS INC.
CONDENSED CONSOLIDATED BALANCE SHEETS
(Information at December 31, 2009 is unaudited)

		December 31, 2009				September 30, 2009
Assets
Current assets:
Cash and cash equivalents		$	516,751			$	639,908
Oil and natural gas sales receivables, net of allowance for uncollectible accounts			9,001,365				7,747,557
Deferred income taxes			1,622,900				1,934,900
Refundable production taxes			178,324				616,668
Other			165,542				68,817
Total current assets			11,484,882				11,007,850
Properties and equipment, at cost, based on successful efforts accounting:
Producing oil and natural gas properties			199,839,742				198,076,244
Non-producing oil and natural gas properties			10,248,480				10,332,537
Furniture and fixtures			584,060				578,460
			210,672,282				208,987,241
Less accumulated depreciation, depletion and amortization			118,733,463				112,900,027
Net properties and equipment			91,938,819				96,087,214
Investments			656,723				682,391
Refundable production taxes			915,277				772,177
Total assets		$	104,995,701			$	108,549,632
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable		$	3,786,043			$	4,810,687
Derivative contracts			864,495				1,726,901
Accrued liabilities			759,427				1,033,570
Total current liabilities			5,409,965				7,571,158
Long-term debt			8,522,231				10,384,722
Deferred income taxes			24,135,650				24,064,650
Asset retirement obligations			1,629,918				1,620,225
Derivative contracts			—				786,534
Stockholders’ equity:
Class A voting common stock, $.0166 par value; 24,000,000 shares authorized, 8,431,502 issued at December 31, 2009 and at September 30, 2009			140,524				140,524
Capital in excess of par value			1,922,053				1,922,053
Deferred directors’ compensation			1,911,530				1,862,499
Retained earnings			65,634,110				64,507,547
			69,608,217				68,432,623
Less treasury stock, at cost; 119,866 shares at December 31, 2009 and at September 30, 2009			(4,310,280	)			(4,310,280	)
Total stockholders’ equity			65,297,937				64,122,343
Total liabilities and stockholders’ equity		$	104,995,701			$	108,549,632

(See accompanying notes)

PANHANDLE OIL AND GAS INC.
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)

		Three Months Ended December 31,
		2009				2008
Revenues:
Oil and natural gas sales		$	10,810,432			$	10,616,664
Lease bonuses and rentals			30,828				113,380
Gains (losses) on natural gas derivative contracts			1,403,340				393,007
Gain on asset sales, interest and other			103,151				58,060
Income from partnerships			76,752				138,591
			12,424,503				11,319,702
Costs and expenses:
Lease operating expenses			2,306,544				1,749,143
Production taxes			355,042				406,748
Exploration costs			576,261				172,265
Depreciation, depletion and amortization			5,292,695				6,950,092
Provision for impairment			—				1,875,920
General and administrative			1,416,798				1,219,163
Interest expense			65,785				—
			10,013,125				12,373,331
Income (loss) before provision (benefit) for income taxes			2,411,378				(1,053,629	)
Provision (benefit) for income taxes			703,000				(179,000	)
Net income (loss)		$	1,708,378			$	(874,629	)
Basic earnings (loss) per common share (Note 3)		$	0.20			$	(0.10	)
Weighted average shares outstanding:
Common shares			8,311,636				8,300,128
Unissued, vested directors’ shares			100,553				87,915
			8,412,189				8,388,043
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		$	—			$	0.07

(See accompanying notes)

PANHANDLE OIL AND GAS INC.
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(Information at and for the three months ended December 31, 2009 is unaudited)
Three Months Ended December 31, 2009

		Class A voting								Capital in				Deferred
		Common Stock								Excess of				Directors’				Retained				Treasury				Treasury
		Shares				Amount				Par Value				Compensation				Earnings				Shares				Stock				Total
Balances at September 30, 2009			8,431,502			$	140,524			$	1,922,053			$	1,862,499			$	64,507,547				(119,866	)		$	(4,310,280	)		$	64,122,343
Net income			—				—				—				—				1,708,378				—				—				1,708,378
Dividends ($.07 per share)			—				—				—				—				(581,815	)			—				—				(581,815	)
Increase in deferred directors’ compensation charged to expense			—				—				—				49,031				—				—				—				49,031
Balances at December 31, 2009			8,431,502			$	140,524			$	1,922,053			$	1,911,530			$	65,634,110				(119,866	)		$	(4,310,280	)		$	65,297,937

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,
		2009				2008
Operating Activities
Net income (loss)		$	1,708,378			$	(874,629	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Unrealized gains (losses) on natural gas derivative contracts			(1,648,940	)			646,193
Depreciation, depletion, amortization and impairment			5,292,695				8,826,012
Provision for deferred income taxes			383,000				205,000
Exploration costs			576,161				172,265
Net (gain) loss on sale of assets			(133,192	)			(115,377	)
Income from partnerships			(76,752	)			(138,591	)
Distributions received from partnerships			102,420				150,164
Directors’ deferred compensation expense			49,031				38,629
Cash provided by changes in assets and liabilities:
Oil and natural gas sales receivables			(1,253,808	)			6,528,078
Refundable income taxes			—				(386,512	)
Refundable production taxes			295,244				(194,212	)
Other current assets			(96,725	)			27,915
Accounts payable			(102,443	)			501,227
Income taxes payable			(51,770	)			—
Accrued liabilities			(222,373	)			(330,669	)
Total adjustments			3,112,548				15,930,122
Net cash provided by operating activities			4,820,926				15,055,493
Investing Activities
Capital expenditures, including dry hole costs			(2,658,662	)			(18,442,452	)
Proceeds from leasing of fee mineral acreage			56,004				118,955
Proceeds from sales of assets			102,881				2,000
Net cash used in investing activities			(2,499,777	)			(18,321,497	)
Financing Activities
Borrowings under debt agreement			5,000,388				18,316,045
Payments of loan principal			(6,862,879	)			(15,023,806	)
Payments of dividends			(581,815	)			(581,009	)
Net cash provided by (used in) financing activities			(2,444,306	)			2,711,230
Decrease in cash and cash equivalents			(123,157	)			(554,774	)
Cash and cash equivalents at beginning of period			639,908				895,708
Cash and cash equivalents at end of period		$	516,751			$	340,934
Supplemental Schedule of Noncash Investing and Financing Activities
Dividends declared and unpaid		$	—			$	581,009
Additions to asset retirement obligations		$	9,693			$	90,059
Gross additions to properties and equipment		$	1,736,461			$	12,385,991
Net (increase) decrease in accounts payable for properties
and equipment additions			922,201				6,056,461
Capital expenditures, including dry hole costs		$	2,658,662			$	18,442,452

(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 2009 Annual Report on Form 10-K.

     Management has evaluated the impact of subsequent events for inclusion in the Company’s Consolidated Financial Statements occurring after December 31, 2009 through February 8, 2010, the date the Company’s financial statements were issued, and, in the opinion of management, the Company’s Condensed Consolidated Financial Statements and Notes contain all necessary adjustments and disclosures resulting from that evaluation.

NOTE 2: Income Taxes

     The Company’s provision or benefit for income taxes (both federal and state) differs from the statutory rate primarily due to estimated federal and state benefits generated from estimated excess federal percentage depletion, estimated excess Oklahoma percentage depletion and a valuation allowance in fiscal 2009 ($278,000) placed on certain state tax net operating loss carryforwards (NOLs) the Company no longer believes are more likely than not to be utilized in future periods prior to expiration.

     These estimated federal and state benefits are largely due to excess federal percentage depletion (limited to certain production volumes and by certain net income levels) and excess Oklahoma percentage depletion (with no limitation on production volume or net income) which reduces estimated taxable income or adds to estimated taxable loss projected for any year. The federal and Oklahoma excess percentage depletion allowance estimates will be updated throughout the year until finalized with the detail well-by-well calculations at fiscal year-end. The effect of the federal and Oklahoma excess percentage depletion when a provision for income taxes is recorded, is to decrease the effective tax rate (as is the case as of December 31, 2009), while the effect is to increase the effective tax rate when a benefit for income taxes is recorded. The benefit of federal and Oklahoma excess percentage depletion are not directly related to the amount of pre-tax loss or income recorded in a period. Accordingly, in periods where a recorded pre-tax income or loss is relatively small, the proportional effect of these items on the effective tax rate may be significant.

NOTE 3: Basic Earnings (Loss) per Share

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

NOTE 4: Long-term Debt

     The Company has a credit facility with Bank of Oklahoma (BOK) which consists of a revolving loan in the amount of $50,000,000 which is subject to a semi-annual borrowing base determination, wherein BOK applies their own current pricing forecast and a 9% discount rate to the Company’s proved reserves as calculated by the Company’s Consulting Petroleum Engineering Firm. When applying the discount rate, BOK also applies an advance rate percentage to risk all proved non-producing and proved undeveloped reserves. Effective February 3, 2009, the Company amended its revolving credit facility with BOK to increase the borrowing base from $15,000,000 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 (with a carrying value of $36,422,588)and change the maturity date to October 31, 2011. Effective May 20, 2009 the Company again increased the borrowing base from $25,000,000 to $35,000,000. On December 8, 2009, Panhandle’s banks reaffirmed the Company’s $35,000,000 borrowing base and extended the maturity date of the credit facility to October 31, 2012. 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. The 4.50% interest rate floor was in effect at December 31, 2009. 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. 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 properties.

     Determinations of the borrowing base are made semi-annually or whenever the bank, in its sole discretion, believes that there has been a material change in the value of the oil and natural gas properties. The loan agreement contains customary covenants which, among other things, require periodic financial and reserve reporting and limit the Company’s incurrence of indebtedness, liens, dividends and acquisitions of treasury stock, and require the Company to maintain certain financial ratios. At December 31, 2009, the Company was in compliance with the covenants of the BOK agreement.

NOTE 5: Dividends

     On October 28, 2009, the Company’s Board of Directors declared a $.07 per share dividend that was paid on December 10, 2009 to shareholders of record on November 24, 2009.

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: Oil and Natural Gas Reserves

     The estimation of crude oil and natural gas reserves affects depreciation, depletion and amortization (DD&A) and impairment calculations. On an annual basis, with a semi-annual update, the Company’s consulting engineer (Pinnacle Energy Services, LLC), with assistance from Company staff, 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. Separate reserve estimates are made using current and projected future prices of crude oil and natural gas. According to guidelines and definitions established by the SEC, DD&A must be calculated using non-escalated prices current with the period end for which estimates are being made, while reserve estimations used in assessments for asset impairments are calculated using projected future crude oil and natural gas prices. When significant crude oil and natural gas price changes occur between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing price decks current with the period. For DD&A calculation purposes, crude oil and natural gas reserves as of December 31, 2009 were updated, utilizing December 31, 2009 crude oil and natural gas prices ($74.99 per barrel of crude oil and $5.16 per Mcf of natural gas) held flat over the lives of the properties. The update of crude oil and natural gas reserves utilizing price decks as of December 31, 2009 positively impacted the reserves as the higher prices extended the economic lives of the Company’s properties resulting in higher overall reserve volumes. The higher prices resulted in upward revisions to crude oil and natural gas reserves of approximately 50,000 barrels and 13,731,000 Mcf, respectively. In comparison, prices used for the September 30, 2009 annual report were $66.96 per barrel of crude oil and $2.86 per Mcf of natural gas held flat over the lives of the properties. Crude oil and natural gas prices are volatile and largely affected by worldwide production and consumption and are outside the control of management.

     The Company will not adopt the SEC Modernization of Oil and Gas reporting requirements until September 30, 2010, as early adoption is not permitted.

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. When significant crude oil and natural gas price changes occur between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing updated projected future price decks current with the period. The assessment at December 31, 2009 resulted in no impairment provision. As of the quarter ended December 31, 2008, the Company’s test for impairment resulted in a charge to impairment of $1,875,920. The majority 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 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 $4,894 on exploratory wells which were drilling and/or testing at December 31, 2009.

NOTE 10: Derivatives

     In the past, the Company entered into costless collar contracts (all of which expired in the 2009 first quarter). Currently, the Company has entered into fixed swap contracts. Both of these instruments were intended to reduce the Company’s exposure to short-term fluctuations in the price of natural gas. Fixed swap contracts set a fixed price and provide payments to the Company if the index price is below the fixed price, or require payments by the Company if the index price is above the fixed price. These contracts cover only a portion of the Company’s natural gas production and provide only partial price protection against declines in natural gas prices. These derivative instruments may expose the Company to risk of financial loss and limit the benefit of future increases in prices. All of the Company’s derivative contracts are with Bank of Oklahoma and are unsecured. The derivative instruments have settled or will settle based on the prices below which are adjusted for location differentials and tied to certain pipelines in Oklahoma.

Derivative contracts in place as of December 31, 2009
(prices below reflect the Company’s net price from the listed Oklahoma pipelines)

Production volume

Indexed (1)

Contract period

covered per month

Pipeline

Fixed price

January — December, 2010

100,000 mmbtu

CEGT

$

5.015

January — December, 2010

50,000 mmbtu

CEGT

$

5.050

January — December, 2010

100,000 mmbtu

PEPL

$

5.57

January — December, 2010

50,000 mmbtu

PEPL

$

5.56

     While the Company believes that its derivative contracts are effective in achieving the risk management objective for which they were intended, the Company has elected not to complete all of the documentation requirements necessary to permit these derivative contracts to be accounted for as cash flow hedges. The Company’s fair value of derivative contracts was a liability of $864,495 as of December 31, 2009 and a liability of $2,513,435 as of September 30, 2009. Realized and unrealized gains and (losses) for the periods ended December 31, 2009 and December 31, 2008 are scheduled below:

		Three months ended
Gains (losses) on natural gas derivative contracts — current		12/31/2009				12/31/2008
Realized		$	(245,600	)		$	1,039,200
Increase (decrease) in fair value			1,648,940				(646,193	)
Total		$	1,403,340			$	393,007

     To the extent that a legal offset exists, the Company nets the fair value of its derivative contracts with the same counterparty in the accompanying balance sheets. The following table summarizes the Company’s derivative contracts as of December 31, 2009 and September 30, 2009:

		Balance Sheet				12/31/2009				9/30/2009
		Location				Fair Value				Fair Value
Liability Derivatives:
Derivatives not designated as Hedging Instruments:
Commodity contracts		Short-term derivative contracts				$	864,495			$	1,726,901
Commodity contracts		Long-term derivative contracts					—				786,534
Total Liability Derivatives (a)						$	864,495			$	2,513,435

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

NOTE 11: Exploration Costs

     In the quarter ended December 31, 2009, an impairment loss of $575,633 was charged to exploration costs for individually insignificant non-producing leases which the Company believes will not be transferred to proved properties over the remaining lives of the leases. The Company also had additional costs of $628 related to expired leases and dry hole adjustments. In the quarter ended December 31, 2008, an impairment loss of $129,828 was charged to exploration costs for non-producing leases as well as additional costs of $42,437 related to expired leases and two low cost dry holes.

NOTE 12: Fair Value Measurements

     Effective October 1, 2008, the Company adopted guidance which established a framework for measuring the fair value of assets and liabilities measured on a recurring basis and expanded disclosures about fair value measurements. In February 2008, the FASB delayed the effective date of this guidance by one year for nonfinancial assets and liabilities. Consequently, the Company only applied the fair value measurement statement to financial assets and liabilities and delayed application for nonfinancial assets and liabilities (including, but not limited to, its asset retirement obligations) until the Company’s fiscal year beginning October 1, 2009, as permitted. Upon adoption as of October 1, 2009, the impact of full application for nonfinancial assets and liabilities on its financial position, results of operations and cash flows was not material.

     This guidance 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. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs include the following: (i) quoted prices for similar assets or liabilities in active markets; (ii) quoted prices for identical or similar assets or liabilities in markets that are not active; (iii) inputs other than quoted prices that are observable for the asset or liability; or (iv) inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 inputs are unobservable inputs for the financial asset or liability. Counterparty quotes are generally assessed as a Level 3 input.

     The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2009.

Quoted

Significant

Prices in

Other

Significant

Active

Observable

Unobservable

Markets

Inputs

Inputs

Total Fair

(Level 1)

(Level 2)

(Level 3)

Value

Financial Assets (Liabilities):

Derivative Contracts — Swaps

$

—

$

(864,495

)

$

—

$

(864,495

)

NOTE 13: Fair Values of Financial Instruments

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

NOTE 14: New Accounting Pronouncements

     In June 2009, the FASB approved the FASB Accounting Standards Codification (ASC), which, as of July 1, 2009, became the single source of authoritative, nongovernmental U.S. Generally Accepted Accounting Principles (GAAP). The ASC was not intended to change U.S. GAAP. Rather, the ASC reorganizes all previous U.S. GAAP pronouncements into accounting topics, and displays all topics using a consistent structure. All existing standards that were used to create the ASC are now superseded, aside from those issued by the SEC, replacing the previous references to specific Statements of Financial Accounting Standards with numbers used in the ASC’s structural organization. All guidance in the Codification has an equal level of authority. The ASC is effective for financial statements that cover interim and annual periods ending after September 15, 2009. There was no impact on the Company’s financial position, results of operations or cash flows as a result of the Accounting Standards Codification.

     In December 2008, the SEC issued revised reporting requirements for oil and natural gas reserves that a company holds. Included in the new rule entitled Modernization of Oil and Gas Reporting Requirements, are the following changes: 1) permits use of new technologies to determine proved reserves, if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes; 2) enables companies to additionally disclose their probable and possible reserves to investors, in addition to their proved reserves; 3) allows previously excluded resources, such as oil sands, to be classified as oil and natural gas reserves rather than mining reserves; 4) requires companies to report the independence and qualifications of a preparer or auditor, based on current Society of Petroleum Engineers criteria; 5) requires the filing of reports for companies that rely on a third party to prepare reserve estimates or conduct a reserve audit; and 6) requires companies to report oil and natural gas reserves using an average sales price based upon the prior 12-month period, rather than period-end prices. The new requirements are effective for registration statements filed on or after January 1, 2010, and for annual reports on Form 10K for fiscal years ending on or after December 31, 2009. Early adoption is not permitted. The Company is currently assessing the impact that adoption of this rule will have on its financial disclosures.

     In January 2010, the FASB issued an Accounting Standards Update (ASU) entitled Oil and Gas Reserve Estimation and Disclosures. This ASU amends the FASB accounting standards to align the reserve calculation and disclosure requirements with the requirements in the new SEC Rule, Modernization of Oil and Gas Reporting Requirements. The ASU will be effective for annual reporting periods ending on or after December 31, 2009.

     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 2010 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 2009 Annual Report on Form 10-K where risk factors are presented and further discussed. For all the above reasons, actual results may vary materially from the Forward-Looking Statements and there is no assurance that the assumptions used are necessarily the most likely to occur.

LIQUIDITY AND CAPITAL RESOURCES

     The Company had positive working capital of $6,074,917 at December 31, 2009 compared to positive working capital of $3,436,692 at September 30, 2009 as detailed below:

ANALYSIS OF CHANGE IN WORKING CAPITAL

		As of				As of
		12/31/2009				9/30/2009				Change
CURRENT ASSETS:
Cash and cash equivalents		$	516,751			$	639,908			$	(123,157	)
Oil and natural gas sales receivables (net) (1)			9,001,365				7,747,557				1,253,808
Deferred income taxes			1,622,900				1,934,900				(312,000	)
Refundable production taxes (2)			178,324				616,668				(438,344	)
Other current assets			165,542				68,817				96,725
Total current assets			11,484,882				11,007,850				477,032
CURRENT LIABILITIES:
Accounts payable (3)			3,786,043				4,810,687				(1,024,644	)
Derivative contracts (4)			864,495				1,726,901				(862,406	)
Accrued liabilities (5)			759,427				1,033,570				(274,143	)
Total current liabilities			5,409,965				7,571,158				(2,161,193	)
WORKING CAPITAL		$	6,074,917			$	3,436,692			$	2,638,225

     Cash flow provided by operating activities decreased 68% to $4,820,926 in the 2010 quarter as compared to the 2009 quarter. The following schedule and footnotes explain major elements of the decrease:

ANALYSIS OF CHANGE IN CASH PROVIDED BY OPERATING ACTIVITIES

		As of				As of
		12/31/2009				12/31/2008				Change
Net income (loss)		$	1,708,378			$	(874,629	)		$	2,583,007
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Unrealized gains (losses) on natural gas derivative contracts (3)			(1,648,940	)			646,193				(2,295,133	)
Depreciation, depletion, amortization and impairment (1)			5,292,695				8,826,012				(3,533,317	)
Deferred income taxes (net)			383,000				205,000				178,000
Exploration costs			576,161				172,265				403,896
Net (gain) loss on sale of assets			(133,192	)			(115,377	)			(17,815	)
Income from partnerships			(76,752	)			(138,591	)			61,839
Distributions received from partnerships			102,420				150,164				(47,744	)
Directors deferred compensation			49,031				38,629				10,402
Cash provided by changes in assets and liabilities:
Oil and gas sales receivables (2)			(1,253,808	)			6,528,078				(7,781,886	)
Refundable income taxes			—				(386,512	)			386,512
Refundable production taxes			295,244				(194,212	)			489,456
Other current assets			(96,725	)			27,915				(124,640	)
Accounts payable			(102,443	)			501,227				(603,670	)
Income taxes payable			(51,770	)			—				(51,770	)
Accrued liabilities			(222,373	)			(330,669	)			108,296
Net cash provided by operating activities		$	4,820,926			$	15,055,493			$	(10,234,567	)

     Additions to properties and equipment for oil and natural gas activities during the 2010 first quarter were $1,736,461 ($12,385,991 in the 2009 quarter). Natural gas prices have increased during recent months and management expects natural gas prices for the remainder of fiscal 2010 to be higher than those experienced during the last three quarters of fiscal 2009. These natural gas prices are expected to increase drilling activity industry-wide which should provide more opportunities for the Company to participate as a working interest owner in the drilling and completion of new wells. In addition, two relatively new horizontal drilling plays have begun to develop in areas where the Company owns mineral interests and should provide the Company with working interest participation opportunities in the drilling and completion of new wells. These two plays are the Anadarko (Cana) Woodford Shale play and the Horizontal Granite Wash play, both of which are in western Oklahoma. The Company not being the operator of any of its oil and natural gas properties makes it extremely difficult for management to predict with certainty levels of participation in drilling and completing new wells and associated capital expenditures. However, based on management’s assessment of current conditions, fiscal 2010 additions to property and equipment for oil and natural gas activities are projected to be approximately $20 million; whereas additions to property and equipment for oil and natural gas activities in fiscal 2009 were $28,540,290.

     The Company has funded capital additions, overhead costs and dividend payments primarily from cash provided by operating activities. However, during times of oil and natural gas price decreases, or increased expenditures for drilling, the

Company has utilized its revolving line-of-credit facility to help fund these expenditures. The Company’s continued drilling activity, combined with normal delays in receiving first payments from new production, could result in increased borrowings under the Company’s credit facility. The Company has availability ($26,477,769 at December 31, 2009) 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). While the Company believes the availability could be increased, if needed, by placing more of the Company’s properties as security under the revolving credit facility, increases are at the discretion of the bank.

RESULTS OF OPERATIONS

THREE MONTHS ENDED DECEMBER 31, 2009 — COMPARED TO THREE MONTHS ENDED DECEMBER 31, 2008

Overview:

     The Company recorded a first quarter 2010 net income of $1,708,378, or $.20 per share, as compared to a net loss of $874,629 or $.10 per share in the 2009 quarter. Major contributing factors were decreased impairment and DD&A and increased gain on natural gas derivative contracts. These items are further discussed below.

Revenues:

     Total revenues were up $1,104,801 or 10% for the 2010 quarter, primarily the result of a $1,010,333 increase in gain on natural gas derivative contracts and a $193,768 increase in oil and natural gas sales. The decline in forward looking natural gas prices since September 30, 2009 has resulted in a net gain on natural gas derivative contracts of $1,403,340 in the 2010 quarter as compared to a net gain of $393,007 recorded in the 2009 quarter. The oil and natural gas sales increase was due to increases in average oil and natural gas prices of 38% and 7%, respectively, partially offset by decreases in oil and natural gas sales volumes of 9% each. The table below outlines the Company’s production and average sales prices for oil and natural gas for the three month periods of fiscal 2010 and 2009:

		Barrels				Average				Mcf				Average				Mcfe				Average
		Sold				Price				Sold				Price				Sold				Price
Three months ended 12/31/09			27,454			$	71.30				2,113,420			$	4.19				2,278,144			$	4.75
Three months ended 12/31/08			30,260			$	51.80				2,313,739			$	3.91				2,495,299			$	4.25

     During the first quarter of 2009, the Company had several new wells that were completed and put on line, whereas few wells were completed and put on line during the 2010 first quarter. Decreased drilling activity which began in 2009, and has continued through the first quarter of fiscal 2010 resulted in a slight decrease in production. The natural production decline of existing wells is currently exceeding production from newly completed wells.

     For the past year, depressed natural gas prices have limited the Company’s opportunities to participate in drilling new wells; and, among these opportunities, the Company has been very selective. The Company owns working interests in newly completed wells which began producing during December 2009 and are expected to significantly contribute to the Company’s natural gas production and help mitigate the current production decline. Management expects natural gas prices for 2010 to exceed those of 2009; and, therefore expects drilling activity to increase over current levels. Drilling activity in two major plays where the Company owns mineral acreage, the Anadarko (Cana) Woodford Shale and the horizontal Granite Wash, is continuing to increase and should provide more opportunity for the Company.

     Production for the last five quarters was as follows:

Quarter ended		Barrels Sold				Mcf Sold				Mcfe Sold
12/31/09			27,454				2,113,420				2,278,144
9/30/09			29,011				2,181,985				2,356,051
6/30/09			34,145				2,442,604				2,647,474
3/31/09			34,744				2,171,660				2,380,124
12/31/08			30,260				2,313,739				2,495,299

Gains on Natural Gas Derivative Contracts:

     At December 31, 2009, the Company’s fair value of derivative contracts was a liability of $864,495; whereas at December 31, 2008, the Company’s fair value of derivative contracts was $0. The Company recorded a gain during the fiscal 2010 first quarter of $1,403,340 as compared to a gain of $393,007 for the fiscal 2009 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, 2009 and 2008.

Lease Operating Expenses (LOE):

     LOE increased $557,401 or 32% in the 2010 quarter as compared to the 2009 quarter, and LOE per Mcfe increased in the 2010 quarter to $1.01 per Mcfe from $.70 per Mcfe in the 2009 quarter. Both the total LOE increase and the LOE per Mcfe increase are due to natural gas production from the Woodford Shale and Fayetteville Shale areas making up a greater proportion of total production. These two areas are where value based fees (primarily gathering and marketing costs), which are charged as a percent of natural gas sales, are significantly higher than like fees charged in other of the Company’s production areas. Total value based fees increased $661,575 in the 2010 quarter. Value based fees per Mcfe were $.58 in the 2010 quarter, as compared to $.26 in the 2009 quarter. The value based fees in the Woodford Shale and Fayetteville Shale areas typically are 12% to 19% of natural gas sales as compared to 6% on all other areas of natural gas production. LOE related to field operating costs in the 2010 quarter decreased $104,174 in total, as compared to the 2009 quarter, while field operating costs per Mcfe remained flat from the 2009 quarter to the 2010 quarter at $.37 per Mcfe.

Production Taxes:

     Production taxes decreased $51,706 or 13% in the 2010 quarter as compared to the 2009 quarter. Although oil and natural gas sales increased, production taxes decreased in the 2010 quarter as nearly all new wells coming on line during the past year have been horizontal Woodford Shale or Fayetteville Shale wells qualifying for production tax credits in Oklahoma or Arkansas. In the 2010 quarter, the Company also received production tax credit refunds on royalty interests which had not been previously accrued. Production taxes as a percentage of oil and natural gas sales decreased from 3.8% in the 2009 quarter to 3.3% in the 2010 quarter.

Exploration Costs:

     Exploration costs increased $403,996 in the 2010 quarter as compared to the 2009 quarter. Due to the shorter timeframe before expiration of certain of the Company’s non-producing leases, and the reassessment of risk of commercial production from such leases, non-producing leasehold was impaired $575,633 in the 2010 quarter, as compared to $129,828 in the 2009 quarter. Charges on two low cost exploratory dry holes totaled $24,247 during the 2009 quarter; whereas, in the 2010 quarter no exploratory dry holes were drilled.

Depreciation, Depletion and Amortization (DD&A):

     DD&A decreased $1,657,397 or 24% in the 2010 quarter. DD&A in the 2010 quarter was $2.32 per Mcfe as compared to $2.79 per Mcfe in the 2009 quarter. Oil and natural gas production decreased 9% in the 2010 quarter accounting for approximately $605,000 of the DD&A decrease. The remaining DD&A decrease of approximately $1,052,000 is attributable to the $.47 decline in the DD&A rate per Mcfe. This rate declined as a result of increased oil and natural gas reserves as of December 31, 2009, as compared to December 31, 2008, and a net reduction in asset basis subject to DD&A of approximately $3,091,000 during fiscal year 2009. This asset basis reduction occurred as DD&A and impairment, combined with the basis reduction associated with assets sold, exceeded new additions to properties and equipment for oil and natural gas activities during fiscal year 2009.

Provision for Impairment:

     Provision for impairment decreased $1,875,920 in the 2010 quarter as compared to the 2009 quarter. No impairment was recorded in the 2010 quarter. During the 2009 quarter, impairment of $1,875,920 was recorded on 16 fields. The majority 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 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.

General and Administrative Costs (G&A):

     G&A increased $197,635 or 16% in the 2010 quarter, as compared to the 2009 quarter, due primarily to increases in the following expense categories: personnel $113,306, legal $44,142, audit and tax preparation $27,711 and technical consulting $14,809.

Income Taxes:

     Provision for income taxes increased in the 2010 quarter by $882,000, the result of a $3,465,007 increase in income before income taxes in the 2010 quarter compared to a loss in the 2009 quarter. The effective tax rate for the 2010 and 2009 quarters were 29% and 17%, respectively. Excess percentage depletion (a permanent tax benefit) reduced the effective tax rate less in the 2010 quarter, as compared to the 2009 quarter, resulting in a higher effective tax rate for the 2010 quarter. For further discussion regarding excess percentage depletion and its effect on the effective tax rate, see NOTE 2: Income Taxes.

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

     Critical accounting policies are those the Company believes are most important to portraying its financial conditions and results of operations and also require the greatest amount of subjective or complex judgments by management. Judgments and uncertainties regarding the application of these policies may result in materially different amounts being reported under various conditions or using different assumptions. There have been no material changes to the critical accounting policies previously disclosed in the Company’s Form 10-K for the fiscal year ended September 30, 2009.

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 2009 production, a $.10 per Mcf change in the price received for natural gas production would result in a corresponding $911,000 annual change in revenue. A $1.00 per barrel change in the price received for oil production would result in a corresponding $128,000 annual change in revenue. Cash flows could also be impacted, to a lesser extent, by changes in the market interest rates related to the Company’s credit facilities. The revolving loan bears interest at the national prime rate plus from .50% to 1.25%, or 30 day LIBOR plus from 2.00% to 2.75%, with an established interest rate floor of 4.50% annually. The 4.5% interest rate floor was in effect at December 31, 2009. At December 31, 2009, the Company had $8,522,231 outstanding under these facilities. A change of .5% in the prime rate or on LIBOR would result in a change to interest expense of $42,611.

     The Company periodically utilizes derivative contracts to reduce its exposure to unfavorable changes in natural gas prices. Volumes under such contracts do not exceed expected production. These arrangements cover only a portion of the Company’s production and provide only partial price protection against declines in natural gas prices. These derivative contracts may expose the Company to risk of financial loss and limit the benefit of future increases in prices (Refer to NOTE 10). A change of 10% in the forward strip prices would result in a change to gain (loss) on derivative contracts of approximately $2 million.

     Changes in crude oil and natural gas reserve estimates affect the Company’s calculation of DD&A. Based on the Company’s 2009 DD&A, a 10% change in the DD&A rate per Mcfe would result in a corresponding annual change in DD&A expense of approximately $2.8 million. Crude oil and natural gas prices are volatile and largely affected by worldwide production and consumption and are outside the control of management.

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.