PHX Minerals - 10-Q quarterly report FY

 

(Exact name of registrant as specified in its charter)

(Address of principal executive offices)

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):

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 May 4, 2008: 8,431,502

INDEX

PANHANDLE OIL AND GAS INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(Information at March 31, 2008 is unaudited)

PANHANDLE OIL AND GAS INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

PANHANDLE OIL AND GAS INC.

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(Information at and for the six months ended March 31, 2008 is unaudited)
Six Months Ended March 31, 2008

PANHANDLE OIL AND GAS INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(See accompanying notes)

PANHANDLE OIL AND GAS INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

     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 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. Certain reclassifications have been made to the 2007 amounts to conform with the 2008 presentation.

     The Company’s provision (benefit) 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 included 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 six months ended March 31, 2008 and 2007, the Company recorded no interest or penalties on uncertain tax positions.

     Earnings per share is calculated using net income (loss) divided by the weighted average number of common shares outstanding (including unissued, vested directors’ shares of 79,592 and 72,165 for fiscal 2008 and 2007, respectively during the period.

     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. The current borrowing base is $10,000,000. 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 March 31, 2008 the interest rate for the revolving loan was 4.078%.

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

     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.

     Oil and gas properties include costs of $130,302 on exploratory wells which were drilling and/or testing at March 31, 2008.

     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.

     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.

Derivative contracts in place as of 3/31/08
(prices below reflect the Company’s net price from Oklahoma pipelines)

     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 ($2,098,611) as of March 31, 2008 and $106,916 as of September 30, 2007. Realized and unrealized gains and losses for the periods ending March 31, 2008 and March 31, 2007 are scheduled below:

     Certain non-producing leases which have expired or which have no future plans of development (aggregate carrying value of $371,129) were fully impaired and charged to exploration costs in fiscal 2008, slightly offset by small credits on previously recorded exploratory dry holes. In fiscal 2007 $493,776 was charged to exploration costs on one exploratory dry hole and $223,851 was also charged to exploration costs on non-producing leases which had expired or which had no future plans of development.

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

     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.

     At March 31, 2008, the Company had positive working capital of $6,285,223, as compared to positive working capital of $7,191,111 at September 30, 2007. Decreased working capital is the result of increases in the accrued liability on the fair value of derivative contracts, accounts payable and income taxes payable partially offset by increases in oil and gas sales receivables and cash. Oil and gas sales receivables increased as a result of increased oil and gas sales resulting from increases in oil and gas production and prices. The increase in oil and gas prices, both current and future, has also caused the increase in the accrued liability on the fair value of derivative contracts. 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 six-month period amounted to $18,253,210. Management currently expects capital commitments for oil and gas activities of up to $42,000,000 for fiscal 2008. Management’s strategy to participate with larger working interests in new wells 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 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. As a result of the recent increases in both natural gas and oil prices, the Company’s dependence on temporarily borrowed funds for drilling purposes should somewhat decrease.

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

Overview:

     The Company recorded a second quarter 2008 net income of $2,831,281, or $.33 per share, as compared to a net loss of $218,745 or $.03 per share in the 2007 quarter. The 2007 quarter’s loss was principally the result of non-cash charges, including; impairment charges of approximately $1,100,000 on one field in western Oklahoma, additional DD&A charges totaling approximately $1,400,000 on approximately 50 working interest wells which incurred significant reductions in their reserve evaluations, and the recognition of a $627,011 loss on natural gas collar contracts in place.

     Revenues:

     Total revenues increased $4,603,489 or 57% for the 2008 quarter. The increase was the result of a $6,454,223 increase in oil and gas sales resulting from a 31% increase in gas sales volumes, a 25% increase in gas sales price, a 48% increase in oil sales volumes and a 71% increase in oil sales price. Losses on natural gas collar contracts resulted in a revenue decrease of $1,790,502. 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:

     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), the Fayetteville Shale area in Arkansas (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:

     The Company’s fair value of derivative contracts was ($2,098,611) as of March 31, 2008 and $309,302 as of December 31, 2007, resulting in a loss of $2,368,313 (net of $39,600 of realized gains) in the three months ended March 31, 2008 compared to a loss of $577,811 for the three months ended March 31, 2007. The Company received cash payments under the contracts of $39,600 and $49,200 (realized gains) for the three months ended March 31, 2008 and March 31, 2007, respectively.

     LOE increased $619,927 or 74% in the 2008 quarter to $.84 per mcfe, as compared to $.64 per mcfe in the 2007 quarter. The $.20 per mcfe increase is due to sharp increases in charges for transportation, compression, dehydration, gathering systems and fuel gas related to treating natural gas produced and delivering it to market. The Company is experiencing these higher operating costs on wells located particularly in the southeast Oklahoma Woodford Shale area. The recent sharp increase in overall fuel costs are closely related to each of the aforementioned operating expense items.

     Production taxes increased $384,846 or 71% in the 2008 quarter. The increase correlates closely to, and is the result of, a 76% increase in oil and gas sales in the 2008 quarter over the 2007 quarter, as production taxes are paid as a percentage of oil and gas sales.

     These costs increased $106,306 in the 2008 quarter. The increase is the result of higher leasehold expiration and abandonment costs of $110,940, offset by small credits received on previously drilled dry holes, in the 2008 quarter as compared to the 2007 quarter. There were no dry holes in either the 2008 or the 2007 quarter.

     DD&A increased $282,072 or 7% in the 2008 quarter. DD&A in the 2008 quarter was $2.57 per mcfe as compared to $3.19 per mcfe in the 2007 quarter. The overall increase is the result of increased production in the 2008 quarter over the 2007 quarter. The decrease in the DD&A per mcfe is due to higher than normal DD&A per mcfe in the 2007 quarter as a result of downward reserve revisions on approximately fifty of the Company’s working interest wells in the 2007 quarter, resulting in significant additional DD&A charges on those wells totaling approximately $1,400,000.

     The provision for impairment decreased $1,351,269 in the 2008 quarter. In the 2008 quarter three fields were impaired a total of $219,472 as compared to the 2007 quarter which incurred impairment on six fields totaling $1,557,978. In the 2007 quarter approximately $1,100,000 of the impairment provision related to one field in western Oklahoma which, due to declining production, incurred lower reserve estimates resulting in significant impairment of the field.

     G&A costs increased $234,312 or 24% in the 2008 quarter principally due to increased personnel related costs of approximately $147,000 and increased director retainer fees of $80,000.

     The provision for income taxes for the 2008 quarter increased $1,532,651 due to an increase in income before provision for income taxes of $4,582,677 in the 2008 quarter as compared to the 2007 quarter. The 2007 quarter incurred a loss before provision for income taxes of $271,396 resulting in an income tax benefit of $52,651. The effective tax rate in the 2008 quarter was 34%. The Company utilizes excess percentage depletion to reduce its effective tax rate from the federal statutory rate.

Overview:

     The Company recorded a six month period 2008 net income of $6,311,588, or $.74 per share, as compared to a net income of $1,764,748 or $.21 per share in the 2007 period.

     Total revenues increased $9,375,397 or 55% for the 2008 period. The increase was primarily the result of an $11,599,109 increase in oil and gas sales offset by a decrease in the value of natural gas collar contracts of $2,131,736. The oil and gas sales increase resulted from a 33% increase in gas sales volumes, an 18% increase in gas sales price, a 56% increase in oil sales volumes and a 61% increase in oil sales price for the 2008 quarter. The decrease in the value of natural gas collar contracts is the result of losses incurred during the 2008 period of $2,104,527 as compared to gains during the 2007 period of $27,209. The table below outlines the Company’s production and average sales prices for oil and natural gas for the six month periods of fiscal 2008 and 2007:

     As the Company continues increasing its drilling activities and increasing its working interests in new wells drilled, expectations are continued increases in production volumes of natural gas in fiscal 2008 as compared to fiscal 2007. New drilling continues to be concentrated on gas production; however, the drilling of wells with oil production has recently increased. 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 2008.

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

     The Company’s fair value of derivative contracts was ($2,098,611) as of March 31, 2008 and $106,916 as of September 30, 2007, resulting in a loss of $2,104,527 (net of $101,000 of realized gains) in the six months ended March 31, 2008 compared to a gain of $27,209 for the six months ended March 31, 2007. The Company received cash payments of $101,000 and $49,200 (realized gains) for the 2008 and 2007 periods, respectively.

     LOE increased $1,064,860 or 61% in the 2008 period to $.79 per mcfe, as compared to $.66 per mcfe in the 2007 period. The per mcfe increase is due to sharp increases in charges for transportation, compression, dehydration, gathering systems and fuel gas related to treating natural gas produced and delivering it to market. The Company is experiencing these higher operating costs on wells located particularly in the southeast Oklahoma Woodford Shale area. The recent sharp increase in overall fuel costs are closely related to each of the aforementioned operating expense items.

     Production taxes increased $713,722 or 68% in the 2008 period. The increase correlates closely to, and is the result of, a 70% increase in oil and gas sales in the 2008 quarter over the 2007 quarter, as production taxes are paid as a percentage of oil and gas sales.

     These costs decreased $357,680 in the 2008 period. This decrease is principally the result of one exploratory dry hole drilled in the 2007 period in the Mystic Bayou prospect in Louisiana. There were no dry holes in the 2008 period.

     DD&A increased $1,845,214 or 27% in the 2008 period. DD&A was $2.45 per mcfe in the 2008 period as compared to $2.60 per mcfe in the 2007 period. The overall increase is the result of increased production in the 2008 period over the 2007 period. The decrease in the DD&A per mcfe is due to higher than normal DD&A per mcfe in the 2007 period as a result of downward reserve revisions on approximately fifty of the Company’s working interest wells resulting in significant additional DD&A charges on those wells totaling approximately $1,400,000.

     The provision for impairment decreased $1,281,827 in the 2008 period. In the 2008 period six fields were impaired a total of $341,482 as compared to the 2007 period which incurred impairment on eight fields totaling $1,610,545. In the 2007 period approximately $1,100,000 of the impairment provision related to one field in western Oklahoma which, due to declining production, incurred lower reserve estimates resulting in significant impairment of the field.

     G&A costs increased $684,109 or 32% in the 2008 period. The increase is primarily due to increased personnel costs of approximately $483,000, increased director retainer fees of $80,000 and increased professional fees of approximately $51,000.

     The 2008 period provision for income taxes increased $2,458,207 due to increased income before provision for income taxes of $7,005,047. The effective tax rate was 34% for the 2008 period and 32% for the 2007 period. The Company utilizes excess percentage depletion to reduce its effective tax rate from the federal statutory rate.

     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.

     Management considers the estimation of crude oil and natural gas reserves to be the most significant of its judgments and estimates. These estimates affect the unaudited standardized measure disclosures, as well as DD&A and impairment calculations. Changes in crude oil and natural gas reserve estimates affect the Company’s calculation of depreciation, depletion and amortization, provision for abandonment and assessment of the need for asset impairments. On an annual basis, with a semi-annual update, the Company’s consulting engineer, with assistance from Company geologists, prepares estimates of crude oil and natural gas reserves based on available geologic and seismic data, reservoir pressure data, core analysis reports, well logs, analogous reservoir performance history, production data and other available sources of engineering, geological and geophysical information. 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.

     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.

     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 cannot predict when or if future impairment charges will be recorded.

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

     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.

     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 March 31, 2008 the Company had $5,119,382 outstanding under this facility. Based on total debt outstanding at March 31, 2008 a         .5% change in interest rates would result in a $25,600 annual change in pre-tax operating cash flow.

     The Company periodically utilizes certain derivative contracts, costless collars, to reduce its exposure to unfavorable changes in natural gas prices. Volumes under such contracts do not exceed expected production. The Company’s collars contain a fixed floor price and a fixed ceiling price. If market prices exceed the ceiling price or fall below the floor, then the Company will receive the difference between the floor and market price or pay the difference between the ceiling and market price. If market prices are between the ceiling and the floor, then no payments or receipts related to the collars are required. 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 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.

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.