PHX MINERALS INC. - Quarter Report: 2006 December (Form 10-Q)

 

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

(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 Noo 

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

Large accelerated filer o     Accelerated filer þ     Non-accelerated filer o     

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ 

Outstanding shares of Class A Common stock (voting) at February 5, 2007: 8,422,529

 

 

INDEX

		Page
Part I Financial Information
Item 1 Condensed Consolidated Financial Statements
Condensed Consolidated Balance Sheets — December 31, 2006 and September 30, 2006			1
Condensed Consolidated Statements of Income — Three months ended December 31, 2006 and 2005			2
Consolidated Statement of Stockholders’ Equity — Three months ended December 31, 2006			3
Condensed Consolidated Statements of Cash Flows — Three months ended December 31, 2006 and 2005			4
Notes to Condensed Consolidated Financial Statements			5—7
Item 2 Management’s discussion and analysis of financial condition and results of operations			7—10
Item 3 Quantitative and qualitative disclosures about market risk			10
Item 4 Controls and procedures			10—11
Part II Other Information			11
Item 6 Exhibits and reports on Form 8-K			11
Signatures			11
Certification under Section 302
Certification under Section 302
Certification under Section 906
Certification under Section 906

PART 1 FINANCIAL INFORMATION

PANHANDLE ROYALTY COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Information at December 31, 2006 is unaudited)

		December 31, 2006				September 30, 2006
Assets
Current assets:
Cash and cash equivalents		$	1,000,708			$	434,353
Oil and gas sales receivables			6,249,652				6,471,623
Fair value of natural gas collar contracts			605,020				—
Income tax receivables and other			2,151,032				1,889,636
Total current assets			10,006,412				8,795,612
Properties and equipment, at cost, based on successful efforts accounting:
Producing oil and gas properties			108,906,175				103,129,158
Non-producing oil and gas properties			9,985,440				11,273,373
Other			562,590				562,047
			119,454,205				114,964,578
Less accumulated depreciation, depletion and amortization			56,223,362				53,654,385
Net properties and equipment			63,230,843				61,310,193
Investments			575,744				596,280
Other			214,805				247,157
Total assets		$	74,027,804			$	70,949,242
Liabilities and Stockholders’ Equity
Current liabilities:
Accounts payable		$	2,621,513			$	1,564,176
Accrued liabilities:
Interest			15,995				15,649
Other			862,001				218,069
Long-term debt due within one year			2,250,000				2,000,004
Total current liabilities			5,749,509				3,797,898
Long-term debt			—				1,166,649
Deferred income taxes			16,526,250				15,498,750
Asset retirement obligation and other non-current liabilities			1,599,248				1,420,248
Stockholders’ equity:
Class A voting common stock, $.0166 par value; 12,000,000, shares authorized, 8,422,529 issued and outstanding at December 31, 2006 and at September 30, 2006			140,375				140,375
Capital in excess of par value			1,924,587				1,924,587
Deferred directors’ compensation			1,232,654				1,202,569
Retained earnings			46,855,181				45,798,166
Total stockholders’ equity			50,152,797				49,065,697
Total liabilities and stockholders’ equity		$	74,027,804			$	70,949,242

PANHANDLE ROYALTY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

		Three Months Ended December 31,
		2006				2005
Revenues:
Oil and gas sales		$	8,081,208			$	11,704,964
Lease bonuses and rentals			115,811				93,476
Unrealized gains on natural gas collar contracts			605,020				—
Gain on sales, interest and other			52,229				263,983
Income from partnerships			77,627				145,256
			8,931,895				12,207,679
Costs and expenses:
Lease operating expenses			899,968				830,269
Production taxes			500,728				741,418
Exploration costs			673,967				32,544
Depreciation, depletion, and amortization			2,693,468				2,288,086
Provision for impairment			52,567				28,652
Loss on sale of assets			32,397				—
General and administrative			1,147,248				756,217
Interest expense			54,615				59,375
			6,054,958				4,736,561
Income before provision for income taxes			2,876,937				7,471,118
Provision for income taxes			893,444				2,577,000
Net income		$	1,983,493			$	4,894,118
Earnings per common share (Note 4)		$	0.23			$	0.58
Dividends declared per share of common stock and paid in period		$	0.04			$	0.025
Dividends declared per share of common stock for and to be paid in the quarter ended March 31(Note 6)		$	0.07			$	0.08

PANHANDLE ROYALTY COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(Unaudited)
Three Months Ended December 31, 2006

		Class A voting								Capital in				Deferred
		Common Stock								Excess of				Directors				Retained
		Shares				Amount				Par Value				Compensation				Earnings				Total
Balances at September 30, 2006			8,422,529			$	140,375			$	1,924,587			$	1,202,569			$	45,798,166			$	49,065,697
Net Income			—				—				—				—				1,983,493				1,983,493
Dividends declared ($.11 per share)			—				—				—				—				(926,478	)			(926,478	)
Increase in deferred directors compensation charged to expense			—				—				—				30,085				—				30,085
Balances at December 31, 2006			8,422,529			$	140,375			$	1,924,587			$	1,232,654			$	46,855,181			$	50,152,797

PANHANDLE ROYALTY COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

		Three months ended December 31,
		2006				2005
Cash flows from operating activities:
Net income		$	1,983,493			$	4,894,118
Adjustments to reconcile net income to net cash provided by operating activities:
Unrealized gains on natural gas collar contracts			(605,020	)			—
Depreciation, depletion, amortization			2,693,468				2,288,086
Provision for impairment			52,567				28,652
Deferred income taxes			1,027,500				352,000
Lease bonus income			(18,697	)			(31,034	)
Exploration costs			673,967				32,544
Gain on sale of assets			(80,651	)			(182,521	)
Equity in earnings of partnerships			(77,627	)			(145,256	)
Directors’ deferred compensation			30,085				15,622
Cash provided by changes in assets and liabilities:
Oil and gas sales receivables			221,971				(2,165,857	)
Income tax receivables and other			(261,396	)			(118,138	)
Accounts payable			(1,001,292	)			(496,864	)
Accrued directors’ deferred compensation			—				(281,897	)
Accrued interest payable			346				(1,275	)
Other accrued liabilities			54,355				46,718
Income taxes payable			—				1,502,489
Total adjustments			2,709,576				843,269
Net cash provided by operating activities			4,693,069				5,737,387
Cash flows from investing activities:
Capital expenditures, including dry hole costs			(3,269,402	)			(4,110,364	)
Proceeds from leasing of fee mineral acreage			107,265				176,066
Distributions received from partnerships			98,163				165,792
Proceeds from sale of assets			190,814				89,227
Net cash used in investing activities			(2,873,160	)			(3,679,279	)
Cash flows from financing activities:
Borrowings under debt agreement			3,011,625				—
Payments of loan principal			(3,928,278	)			(500,001	)
Payments of dividends			(336,901	)			(210,274	)
Net cash used in financing activities			(1,253,554	)			(710,275	)
Increase in cash and cash equivalents			566,355				1,347,833
Cash and cash equivalents at beginning of period			434,353				1,638,833
Cash and cash equivalents at end of period		$	1,000,708			$	2,986,666
Supplemental Schedule of Noncash Investing and Financing Activities:
Dividends declared and unpaid		$	589,577			$	672,871
Reclassification of deferred compensation as equity		$	—			$	1,053,408
Additions and revisions, net, to asset retirement obligations		$	197,697			$	—
Additions to properties and equipment included in accounts payable		$	2,058,629			$	1,204,592

(See accompanying notes)

PANHANDLE ROYALTY COMPANY
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 Royalty 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.

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.

NOTE 3: Stockholders’ Equity

     On December 13, 2005, the Company’s Board of Directors declared a 2-for-1 stock split of outstanding Class A common stock. The Class A common stock split was effected in the form of a stock dividend, distributed on January 9, 2006 to shareholders of record on December 29, 2005.

     All references to number of shares and per share information in the accompanying consolidated financial statements have been adjusted to reflect the stock split.

NOTE 4: Earnings per Share

     Earnings per share (EPS) is calculated using net income divided by the weighted average of common shares outstanding (including unissued, vested directors’ shares (71,108 and 62,978 for fiscal 2007 and 2006, respectively) after October 19, 2005 — see Note 7) during the period.

NOTE 5: Long-term Debt

     In October 2006, the Company refinanced its credit facility with BancFirst of Oklahoma City, Oklahoma with a credit facility from Bank of Oklahoma (BOK). The BOK Agreement consisted 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 under the BOK Agreement is $10,000,000. The term loan matures on September 1, 2007, and the revolving loan matures on October 31, 2009. Monthly payments, which began December 1, 2006, on the term loan are $250,000, plus accrued interest. Borrowings under the revolving loan are due at maturity. The term loan bears interest at 30 day LIBOR plus .75%. 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.

NOTE 6: Dividends

     On October 25, 2006, the Company’s Board of Directors declared a $.04 per share dividend that was paid on December 11, 2006. On December 12, 2006, the Company’s Board of Directors approved payment of a $.07 per share dividend to be paid on March 9, 2007 to shareholders of record on February 27, 2007.

NOTE 7: Deferred Compensation Plan for Directors

     No shares were issued under the Plan in the 2007 period. Effective October 19, 2005 the Plan was amended such that 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. This amendment removed the conversion to cash option available under the Plan, which eliminated the requirement to adjust the deferred compensation liability for changes in the market value of the Company’s common stock after October 19, 2005. The adjustment of the liability to market value of the shares at the closing price on October 19, 2005 resulted in a credit to general and administrative expense of approximately $288,000. This change will reduce volatility in the Company’s earnings resulting from the charges to expense caused by market value changes in the Company’s common stock. The deferred compensation obligation at the date of the Plan’s amendment was reclassified to stockholders’ equity.

NOTE 8: Capitalized Costs

     Oil and gas properties include costs of $175,870 on exploratory wells which were drilling and/or testing at December 31, 2006.

NOTE 9: Derivatives

     The Company periodically utilizes certain derivative contracts, including 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 currently in 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.

     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. The derivative instruments will settle based on the prices below which are tied to indexes for certain pipelines in Oklahoma.

     In December 2006, the Company entered into the following three natural gas collar contracts.

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

     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 $605,020 as of December 31, 2006 (none as of September 30, 2006) resulting in unrealized gains of $605,020 in the three months ended December 31, 2006.

NOTE 10: Exploration Costs

     Certain non-producing leases which will expire in March and April of 2007 were fully impaired in the 2007 period and charged to exploration costs. These leases had an aggregate carrying value of $177,954. In addition one exploratory dry hole ($493,776 in cost) was charged to exploration costs in the 2007 period.

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 2007 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, 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, 2006, the Company had positive working capital of $4,256,903, as compared to positive working capital of $4,997,714 at September 30, 2006. The decrease is a result of an increase in accounts payable, which relates to increased drilling costs, partially offset by increases in fair value of natural gas collar contracts, income tax receivable and cash. Capital additions to properties and equipment are increasing as the Company continues to implement its strategy of increasing the average working interest in new wells drilled and as costs for drilling rigs, field services and equipment remain high.

     Cash flow from operating activities decreased 18% over last year’s period. Additions to properties and equipment for oil and gas operations for the 2007 three-month period amounted to $5,328,031, as compared to $5,314,956 for the 2006 period. Management currently expects capital additions for oil and gas activities to be approximately $31,000,000 for fiscal 2007. The substantial increase in capital additions is a result of continued high drilling activity combined with the implementation of management’s strategy to participate in new wells with larger interests to increase the Company’s average overall working interest percentage. Drilling in the Woodford Shale unconventional resource play in southeast Oklahoma is 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 also remain high, and are expected to remain so for the remainder of fiscal 2007. 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, the 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 may be 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 9 above) to help guard against potential negative price fluctuations.

RESULTS OF OPERATIONS

THREE MONTHS ENDED DECEMBER 31, 2006 — COMPARED TO THREE MONTHS ENDED DECEMBER 31, 2005

Overview:

     The Company recorded a first quarter 2007 net income of $1,983,493, or $.23 per share, as compared to a net income of $4,894,118 or $.58 per share in the 2006 quarter.

Revenues:

     Total revenues decreased $3,275,784 or 27% for the 2007 quarter. The decrease was primarily the result of lower gas prices. Oil and gas sales revenues decreased $3,623,756 or 31% principally due to a $4.15 decrease in the average sales price for natural gas. Oil sales volumes decreased 10% while gas sales volumes increased 15%. The table below outlines the Company’s production and average sales prices for oil and natural gas for the three month periods of fiscal 2007 and 2006:

		BARRELS				AVERAGE				MCF				AVERAGE
		SOLD				PRICE				SOLD				PRICE
Three months ended 12/31/06			22,567			$	56.94				1,198,955			$	5.67
Three months ended 12/31/05			25,001			$	57.15				1,046,917			$	9.82

     The continuing increase in drilling activities and the Company’s stated goal of increasing its working interests in new wells drilled is expected to result in increased production volumes for gas in fiscal 2007 as compared to fiscal 2006. The Company’s drilling continues to be concentrated on gas production. During the last year, new wells coming on line have more than replaced the decline in production of older wells. The Company expects to continue to have additional production come on line in future periods of 2007.

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

12/31/05		1,196,923 mcfe
03/31/06		1,173,313 mcfe
06/30/06		1,134,814 mcfe
09/30/06		1,376,926 mcfe
12/31/06		1,334,357 mcfe

     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 2007, the Company determined that its oil and gas revenue accrual estimate at September 30, 2006 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, 2006 was that revenues and net income were approximately $320,000 and $74,000 lower, respectively, than actual results for those periods. Likewise, for the three months ended December 31, 2006, revenues and net income were higher by such amounts.

     The Company’s fair value of derivative contracts was $605,020 as of December 31, 2006 (none as of September 30, 2006) resulting in unrealized gains of $605,020 in the three months ended December 31, 2006.

Gain on sales, interest and other:

     These items decreased $211,754 in the 2007 period as compared to the 2006 period as certain fee mineral acreage was sold in the 2006 period resulting in a gain of approximately $80,000 and a class action lawsuit settlement of approximately $123,000 was also recorded in the 2006 period.

Lease Operating Expenses (LOE):

     LOE increased $69,699 or 8% in the 2007 quarter. The increase is the result of new larger ownership interest wells going on line in the last year, and the continuing increase in the number of wells in which the Company has a working interest.

Production Taxes:

     Production taxes decreased $240,690 or 32% in the 2007 quarter. The decrease is principally the result of lower oil and gas revenues in the 2007 quarter, as production taxes are paid as a percentage of these revenues. The Company continues to receive production tax credits on some properties.

Exploration Costs:

     These costs increased $641,423 in the 2007 period principally due to certain non-producing leases which will expire in March and April of 2007 which were fully impaired in the 2007 period and charged to exploration costs. These leases had an aggregate carrying value of $177,954. In addition one exploratory dry hole ($493,776 in cost) was charged to exploration costs in the 2007 period.

Depreciation, Depletion, Amortization (DD&A):

     DD&A increased $405,382 or 18% in the 2007 quarter. The increase is due primarily to increases during the last year in drilling activity and associated production, as well as general oilfield price increases.

General and Administrative Costs (G&A):

     G&A increased $391,031 in the 2007 period as compared to the 2006 period principally as a result of an amendment to the Directors’ Deferred Compensation Plan (the Plan). Effective October 19, 2005 the Plan was amended such that 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. This amendment removed the conversion to cash option available under the Plan, which eliminated the requirement to adjust the deferred compensation liability for changes in the market value of the Company’s common stock after October 19, 2005. The adjustment of the liability to market value of the shares at the closing price on October 19, 2005 resulted in a credit to G&A of approximately $288,000 in the 2006 period. The deferred compensation liability after the October 19, 2005 adjustment was reclassified to stockholders’ equity.

Income Taxes:

     The 2007 quarter provision for income taxes decreased due to lower income before provision for income taxes for the period and a lower estimate of income before provision for income taxes for fiscal 2007 as compared to fiscal 2006. The Company utilizes excess percentage depletion to reduce its effective tax rate from the federal statutory rate. The effective tax rate estimate was 31% for the 2007 period and 34% for the 2006 period.

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 limited scope semi-annual update, the Company’s consulting engineer, with assistance from Company geologists, prepares estimates of crude oil and natural gas reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. 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 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 cannot 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 2006 production, a $.10 per Mcf change in the price received for natural gas production would result in a corresponding $430,000 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 $97,100 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%. However, at December 31, 2006, the Company had no balance outstanding under this facility. The Company has a $2,500,000 term loan with an outstanding balance of $2,250,000 at December 31, 2006 maturing on September 1, 2007. The interest rate is 30 day LIBOR plus .75%.

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 Co-President/Chief Operating Officer and Co-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 Operating 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.

     In conjunction with the Company’s periodic utilization of derivative contracts as mentioned above in Footnote 9, the Company has implemented appropriate controls and procedures to properly account for derivative contracts. There were no additional 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 ROYALTY COMPANY
February 7, 2007		/s/ Michael C. Coffman
Date		Michael C. Coffman, Co-President,
		Chief Financial Officer and Treasurer
February 7, 2007		/s/ Ben D. Hare
Date		Ben D. Hare, Co-President
		and Chief Operating Officer
February 7, 2007		/s/ Lonnie J. Lowry
Date		Lonnie J. Lowry, Vice President
		and Chief Accounting Officer