PHX MINERALS INC. - Quarter Report: 2013 June (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the period ended             June 30, 2013                                                                       .                                                                            

(   )           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                                                                                                                                                                           

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.

                                                              X    Yes         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).

                                                              X     Yes         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):

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

                                                                   Yes    X    No

Outstanding shares of Class A Common stock (voting) at August 7, 2013: 8,220,347

INDEX

The following defined terms are used in this report:

“Bbl” means barrel;

“Board” means board of directors;

“BTU” means British Thermal Units;

“CEGT” means Centerpoint Energy Gas Transmission’s East pipeline in Oklahoma;

“Company” refers to Panhandle Oil and Gas Inc.;

“DD&A” means depreciation, depletion and amortization;

“ESOP” refers to the Panhandle Oil and Gas Inc. Employee Stock Ownership and 401(k) Plan, a tax qualified, defined contribution plan;

“FASB” means the Financial Accounting Standards Board;

“G&A” means general and administrative costs;

“Independent Consulting Petroleum Engineer(s)” or “Independent Consulting Petroleum Engineering Firm” refers to DeGolyer and MacNaughton of Dallas, Texas;

“LOE” means lease operating expense;

“Mcf” means thousand cubic feet;

“Mcfe” means natural gas stated on an Mcf basis and crude oil and natural gas liquids converted to a thousand cubic feet of natural gas equivalent by using the ratio of one Bbl of crude oil or natural gas liquids to six Mcf of natural gas;

“Mmbtu” means million BTU;

“minerals”, “mineral acres” or “mineral interests” refers to fee mineral acreage owned in perpetuity by the Company;

“NGL” means natural gas liquids;

“NYMEX” refers to the New York Mercantile Exchange;

“Panhandle” refers to Panhandle Oil and Gas Inc.;

“PEPL” means Panhandle Eastern Pipeline Company’s Texas/Oklahoma mainline;

“play” is a term applied to identified areas with potential oil and/or natural gas reserves;

“royalty interest” refers to well interests in which the Company does not pay a share of the costs to drill, complete and operate a well, but receives a much smaller proportionate share (as compared to a working interest) of production;

“SEC” refers to the United States Securities and Exchange Commission;

“working interest” refers to well interests in which the Company pays a share of the costs to drill, complete and operate a well and receives a proportionate share of production;

“WTI” refers to West Texas Intermediate.

Fiscal year references 

All references to years in this report, unless otherwise noted, refer to the Company’s fiscal year end of September 30. For example, references to 2013 mean the fiscal year ended September 30, 2013.

References to oil and natural gas properties

References to oil and natural gas properties inherently include natural gas liquids associated with such properties.

PART 1 FINANCIAL INFORMATION

PANHANDLE OIL AND GAS INC.

CONDENSED BALANCE SHEETS

(See accompanying notes)

PANHANDLE OIL AND GAS INC.

CONDENSED STATEMENTS OF OPERATIONS

(See accompanying notes)

PANHANDLE OIL AND GAS INC.

STATEMENTS OF STOCKHOLDERS’ EQUITY

Nine months Ended June 30, 2013

Nine Months Ended June 30, 2012

PANHANDLE OIL AND GAS INC.

CONDENSED STATEMENTS OF CASH FLOWS

(See accompanying notes)

PANHANDLE OIL AND GAS INC.

NOTES TO CONDENSED FINANCIAL STATEMENTS

(Unaudited)

NOTE 1: Accounting Principles and Basis of Presentation

The accompanying unaudited condensed financial statements of Panhandle Oil and Gas Inc. have been prepared in accordance with the instructions to Form 10-Q as prescribed by the SEC. Management of the Company believes that all adjustments necessary for a fair presentation of the financial position and results of operations and cash flows for the periods have been included. All such adjustments are of a normal recurring nature. The 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 financial statements pursuant to the rules and regulations of the SEC. Therefore, these condensed financial statements should be read in conjunction with the financial statements and related notes thereto included in the Company’s 2012 Annual Report on Form 10-K.

Certain amounts (net gain on sales of assets in the Statements of Cash Flows) in the prior year have been reclassified to conform to the current year presentation.

NOTE 2: Income Taxes

The Company’s provision for income taxes differs from the statutory rate primarily due to estimated federal and state benefits generated from estimated excess federal and Oklahoma percentage depletion, which are permanent tax benefits.

Both excess federal percentage depletion, which is limited to certain production volumes and by certain income levels, and excess Oklahoma percentage depletion, which has no limitation on production volume, reduce estimated taxable income or add to estimated taxable loss projected for any year. The federal and Oklahoma excess percentage depletion estimates will be updated throughout the year until finalized with the detail well-by-well calculations at fiscal year-end. Federal and Oklahoma excess percentage depletion benefits, when a provision for income taxes is recorded, decrease the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is recorded. The benefits of federal and Oklahoma excess percentage depletion are not directly related to the amount of pre-tax 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. The effective tax rate for the nine months ended June 30, 2013, was 31% as compared to 29% for the nine months ended June 30, 2012. Excess percentage depletion, which is a permanent tax benefit, reduced the effective tax rate below the statutory rate for the nine month periods ended June 30, 2013, and June 30, 2012. The effective tax rate for the quarter ended June 30, 2013, was 31% as compared to 34% for the quarter ended June 30, 2012. The decreased rate was the result of an increase in the estimated annual effective tax rate during the 2012 third quarter resulting from higher projected income before provision for income taxes (mostly related to higher lease bonus income) at June 30, 2012, as compared to the projections made as of March 31, 2012.

NOTE 3: Basic and Diluted Earnings per Share

Basic and diluted earnings per share is calculated using net income divided by the weighted average number of voting common shares outstanding, plus unissued, vested directors’ deferred compensation 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 $80,000,000 which is subject to a semi-annual borrowing base determination, wherein BOK applies their own current pricing forecast and an 8% discount rate to the Company’s proved reserves as calculated by the Company’s Independent Consulting Petroleum Engineering Firm. When applying the discount rate, BOK also applies an advance rate percentage to all proved non-producing and proved undeveloped reserves. The facility has a borrowing base of $35,000,000 and is secured by certain of the Company’s properties with a carrying value of $36,900,585 at June 30, 2013. The facility matures on November 30, 2014. The interest rate is based on national prime plus from .50% to 1.25%, or 30 day LIBOR plus from 2.00% to 2.75%. The election of national prime or LIBOR is at the Company’s discretion. 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. 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. At June 30, 2013, the effective interest rate was 2.43%.

The Company’s debt is recorded at the carrying amount on its balance sheet. The carrying amount of the Company’s revolving credit facility approximates fair value because the interest rates are reflective of market rates.

NOTE 5: 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 be credited with future unissued shares of Company stock rather than cash for Board and committee chair retainers, Board meeting fees and Board committee meeting fees. These unissued 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 unissued shares credited under the Plan will be issued to the director.

NOTE 6: Restricted Stock Plan

On March 11, 2010, shareholders approved the Panhandle Oil and Gas Inc. 2010 Restricted Stock Plan (2010 Stock Plan), which made available 100,000 shares of common stock to provide a long-term component to the Company’s total compensation package for its officers and to further align the interest of its officers with those of its shareholders. The 2010 Stock Plan is designed to provide as much flexibility as possible for future grants of restricted stock so that the Company can respond as necessary to provide competitive compensation in order to retain, attract and motivate officers of the Company and to align their interests with those of the Company’s shareholders.

Effective March 2010, the board of directors approved the purchase of the Company’s common stock, from time to time, equal to the aggregate number of shares of common stock awarded pursuant to the Company’s 2010 Restricted Stock Plan, contributed by the Company to its ESOP and credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors.

On December 11, 2012, the Company awarded 6,701 non-performance based shares and 20,104 performance based shares of the Company’s common stock as restricted stock to certain officers. The restricted stock vests at the end of three years and contains nonforfeitable rights to receive dividends and voting rights during the vesting period. The non-performance and performance based shares had a fair value on their award date of $195,603 and $305,154, respectively, and will be recognized as compensation expense ratably over the vesting period. The fair value of the performance based shares on their award date is calculated by simulating the Company’s stock price and stock price return utilizing a Monte Carlo model covering the period from the grant date through the end of the performance period (December 11, 2012, through December 11, 2015).

The following table summarizes the Company’s pre-tax compensation expense for the three and nine months ended June 30, 2013 and 2012, related to the Company’s performance based and non-performance based restricted stock.

A summary of the Company’s unrecognized compensation cost for its unvested performance based and non-performance based restricted stock and the weighted-average periods over which the compensation cost is expected to be recognized are shown in the following table.

Upon vesting, shares are expected to be issued out of shares held in treasury.

NOTE 7: Oil, NGL and Natural Gas Reserves

Management considers the estimation of the Company’s crude oil, NGL and natural gas reserves to be the most significant of its judgments and estimates. Changes in crude oil, NGL and natural gas reserve estimates affect the Company’s calculation of DD&A, provision for abandonment and assessment of the need for asset impairments. On an annual basis, with a semi-annual update, the Company’s Independent Consulting Petroleum Engineer, with assistance from Company staff, prepares estimates of crude oil, NGL and natural gas reserves based on available geological 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. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing appropriate prices for the current period. The estimated oil, NGL and natural gas reserves were computed using the 12-month average price calculated as the unweighted arithmetic average of the first-day-of-the-month oil, NGL and natural gas price for each month within the 12-month period prior to the balance sheet date, held flat over the life of the properties. However, projected future crude oil, NGL and natural gas pricing assumptions are used by management to prepare estimates of crude oil, NGL and natural gas reserves and future net cash flows used in asset impairment assessments and in formulating management’s overall operating decisions. Crude oil, NGL and natural gas prices are volatile and affected by worldwide production and consumption and are outside the control of management.

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, NGL and natural gas, future production costs, estimates of future oil, NGL 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, NGL and natural gas reserves. 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. For the three months ended June 30, 2013 and 2012, the assessment resulted in provisions of $7,400 and $205,915, respectively. For the nine months ended June 30, 2013 and 2012, the assessment resulted in provisions of $225,841 and $786,724, respectively. A reduction in oil, NGL or 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

As of June 30, 2013 and 2012, non-producing oil and natural gas properties include costs of $0 and $188,449, respectively, on exploratory wells which were drilling and/or testing.

NOTE 10: Exploration Costs

In the quarter and nine month period ended June 30, 2013, lease expirations and leasehold impairments of $25,345 and $53,961, respectively, were charged to exploration costs. Leasehold impairments are recorded for individually insignificant non-producing leases which the Company believes will not be transferred to proved properties over the remaining lives of the leases. In the quarter and nine month period ended June 30, 2013, the Company also had additional costs of $303 and $6,866, respectively, related to exploratory dry holes. In the quarter and nine month period ended June 30, 2012, lease expirations and impairments of $14,916 and $314,277, respectively, were charged to exploration costs as well as additional costs of $14,225 and $69,922, respectively, related to exploratory dry holes.

NOTE 11: Derivatives

The Company has entered into fixed swap contracts, basis protection swaps and costless collar contracts. These instruments are intended to reduce the Company’s exposure to short-term fluctuations in the price of oil and 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. Basis protection swaps are derivatives that guarantee a price differential to NYMEX for natural gas from a specified delivery point (CEGT and PEPL historically). The Company receives a payment from the counterparty if the price differential is greater than the agreed terms of the contract and pays the counterparty if the price differential is less than the agreed terms of the contract. Collar contracts set a fixed floor price and a fixed ceiling price and provide for payments to the Company if the basis adjusted price falls below the floor or require payments by the Company if the basis adjusted price rises above the ceiling. These contracts cover only a portion of the Company’s natural gas and oil production and provide only partial price protection against declines in natural gas and oil prices. These derivative instruments expose the Company to risk of financial loss and may limit the benefit of future increases in prices. All of the Company’s derivative contracts are with Bank of Oklahoma and are secured. The derivative instruments have settled or will settle based on the prices below which are adjusted for location differentials and tied to certain pipelines.

Derivative contracts in place as of June 30, 2013

(prices below reflect the Company’s net price from the listed pipelines)

Derivative contracts in place as of September 30, 2012

(prices below reflect the Company’s net price from the listed pipelines)

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 net asset of $814,978 as of June 30, 2013, and a net liability of $172,271 as of September 30, 2012. Realized and unrealized gains and losses for the periods ended June 30, 2013, and June 30, 2012, are scheduled below:

The fair value amounts recognized for the Company’s derivative contracts executed with the same counterparty under a master netting arrangement may be offset. The Company has the choice to offset or not, but that choice must be applied consistently. A master netting arrangement exists if the reporting entity has multiple contracts with a single counterparty that are subject to a contractual agreement that provides for the net settlement of all contracts through a single payment in a single currency in the event of default on or termination of any one contract. Offsetting the fair values recognized for the derivative contracts outstanding with a single counterparty results in the net fair value of the transactions being reported as an asset or a liability in the Condensed Balance Sheets. The Company has chosen to present the fair values of its derivative contracts under master netting agreements using a net fair value presentation.

                 The following table summarizes and reconciles the Company's derivative contracts’ fair values at a gross level back to net fair value presentation on the Company's Condensed Balance Sheets at June 30, 2013, and September 30, 2012. The Company adopted the accounting guidance requiring additional disclosures for balance sheet offsetting of assets and liabilities effective January 1, 2013. The Company has offset all amounts subject to master netting agreements in the Company's Condensed Balance Sheets at June 30, 2013, and September 30, 2012.

(a) See Fair Value Measurements section for further disclosures regarding fair value of financial instruments.

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 12: Fair Value Measurements

Fair value is defined 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.

The following table provides fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis as of June 30, 2013, and September 30, 2012.

Level 2 – Market Approach - The fair values of the Company’s natural gas swaps are based on a third-party pricing model which utilizes inputs that are either readily available in the public market, such as natural gas curves, or can be corroborated from active markets. These values are based upon future prices, time to maturity and other factors. These values are then compared to the values given by our counterparties for reasonableness.

Level 3 – The fair values of the Company’s costless collar contracts are based on a pricing model which utilizes inputs that are unobservable or not readily available in the public market. These values are based upon future prices, volatility, time to maturity and other factors. These values are then compared to the values given by our counterparties for reasonableness.

The significant unobservable inputs for Level 3 derivative contracts include unpublished forward prices of oil and natural gas, market volatility and credit risk of counterparties. Changes in these inputs will impact the fair value measurement of our derivative contracts. An increase (decrease) in the forward prices and volatility of oil and natural gas prices will decrease (increase) the fair value of oil and natural gas derivatives, and adverse changes to our counterparties’ creditworthiness will decrease the fair value of our derivatives.

The following table represents quantitative disclosures about unobservable inputs for Level 3 Fair Value Measurements.

A reconciliation of the Company’s derivative contracts classified as Level 3 measurements is presented below. All gains and losses are presented on the Gains (losses) on derivative contracts line item on our Statement of Operations.

The following table presents impairments associated with certain assets that have been measured at fair value on a nonrecurring basis within Level 3 of the fair value hierarchy.

(a) At the end of each quarter, the Company assesses the carrying value of its producing properties for impairment. This assessment utilizes estimates of future net cash flows. Significant judgments and assumptions in these assessments include estimates of future oil and natural gas prices using a forward NYMEX curve adjusted for locational basis differentials, drilling plans, expected capital costs and an applicable discount rate commensurate with risk of the underlying cash flow estimates. These assessments identified certain properties with carrying value in excess of their calculated fair values.

NOTE 13: Recently Adopted Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board issued "Balance Sheet: Disclosures about Offsetting Assets and Liabilities." The new standard requires entities to disclose information about financial instruments and derivative instruments that are either offset on the balance sheet or are subject to a master netting arrangement, including providing both gross information and net information for recognized assets and liabilities, the net amounts presented on an entity's balance sheet and a description of the rights of offset associated with these assets and liabilities. The new standard is applicable for all entities that have financial instruments and derivative instruments shown using a net presentation on an entity's balance sheet or are subject to a master netting arrangement. The new standard is effective for interim and annual reporting periods for fiscal years beginning on or after January 1, 2013, and should be applied retrospectively for all periods presented. The Company adopted this new standard effective January 1, 2013.

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 financial statements upon adoption.

NOTE 14: Subsequent Events

On July 26, 2013, the Company was notified and received a class action lawsuit settlement of approximately $604,000 related to the underpayment of royalty interest revenues. The settlement is a gain contingency and will be reflected in earnings in the fourth quarter of fiscal 2013.

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 2013 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, NGL 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, NGL and natural gas reserves. Investors should also read the other information in this Form 10-Q and the Company’s 2012 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 $7,606,506 at June 30, 2013, compared to $3,995,103 at September 30, 2012.

Liquidity:

Cash and cash equivalents were $1,381,705 as of June 30, 2013, compared to $1,984,099 at September 30, 2012, a decrease of $602,394. Cash flows for the nine months ended June 30 are summarized as follows:

Net cash provided (used) by:

Operating activities:

Net cash provided by operating activities increased $3,205,935 during the first nine months of 2013, the result of the following:

Higher receipts of oil, NGL and natural gas sales (net of production taxes and gathering, transportation and marketing costs) increased cash provided by operating activities from the 2012 period to the 2013 period by $4,593,241.

Cash flows from operating activities decreased $687,548 as net realized losses on derivative contracts were $191,083 in the 2013 period, compared to net realized gains on derivative contracts in the 2012 period of $496,465.

Field related LOE payments in the first nine months of 2013 exceeded payments during the same period in 2012 by $129,133, reducing cash provided by operating activities.

Payment of general and administrative expenses, debt interest and income taxes increased during 2013, compared to 2012, decreasing cash provided by operating activities by $354,590.

Investing activities:

Net cash used in investing activities decreased $8,658,465 during the first nine months of 2013, the result of the following:

Higher drilling and completion activity during the period ending June 30, 2013, as compared to the same period in 2012, increased capital expenditures by $4,549,943.

Cash used to acquire properties totaled $783,750 in the 2013 period and $20,024,621 in the 2012 period, a decrease of $19,240,871. In the 2012 first quarter the Company acquired producing properties, leasehold and mineral acreage in Arkansas totaling approximately $18.8 million.

Lease bonus payments received during the first nine months of 2013 were $557,196, compared to $7,042,364 during the first nine months of 2012, a decrease in cash provided by investing activities of $6,485,168. In the 2012 first quarter, the Company leased 2,431 net mineral acres in the horizontal Mississippi Limestone play in northern Oklahoma receiving lease bonus payments of approximately $1.7 million. In the third quarter of 2012, the Company received lease bonus payments of approximately $4.8 million, the result of leasing partial rights on 2,743 net mineral acres in Roger Mills County, Oklahoma.

Financing activities:

Net cash of $4,255,603 was used in financing activities in the first nine months of 2013, as compared to net cash provided by financing activities of $5,183,866 in the first nine months of 2012. The change of $9,439,469 of net cash provided is the result of the following:

The Company financed the first quarter 2012 acquisition of producing properties and leasehold in Arkansas discussed above utilizing its credit facility with Bank of Oklahoma and cash. As of June 30, 2012, cash provided by financing activities through net borrowings was $8,000,000. As of June 30, 2013, cash used in financing activities to reduce outstanding borrowings was $1,309,748. The combined effect is a decrease in cash provided by financing activities of $9,309,748.

Capital Resources:

Through the first nine months of 2013, as compared to the first nine months of 2012, capital expenditures to drill and complete wells increased $4,549,943 (28%). During the 2013 third quarter the Company experienced a significant increase in expenditures to drill and complete wells. Oil and NGL rich plays in western Oklahoma and the Texas Panhandle account for the majority of the drilling activity. Other active areas are the Arkansas Fayetteville Shale (dry natural gas), southern Oklahoma Woodford Shale (oil and NGL rich), Permian Basin of West Texas (oil and NGL rich) and Bakken Shale in North Dakota (oil).

Drilling continues to be active in the following oil and NGL rich plays where the Company owns mineral and leasehold acreage:

Capital expenditures for drilling and completion projects for the 2013 period were $20,576,359. In addition, mineral acreage in the Fayetteville Shale and the southeast Oklahoma Woodford Shale was acquired for $783,750. Panhandle has received a greater number of well proposals in recent months and has consequently increased the number of wells approved for participation with a working interest. We expect this increased activity to continue through the end of 2013, resulting in capital expenditures for drilling and completion projects of approximately $28 million. The shift of capital outlays more toward oil and NGL rich plays and less toward plays for dry natural gas, combined with production volumes from new wells in which the Company owns a non-cost-bearing royalty interest, is expected to result in continued increases in oil and NGL production volumes, with natural gas production leveling off in future quarters. As experienced previously, the timing of new wells coming on line may cause intermittent decreases in oil, NGL and natural gas production from quarter to quarter. Management continues to evaluate opportunities to acquire additional production or acreage.

Since the Company is not the operator of any of its oil and natural gas properties, it is extremely difficult for us to precisely predict levels of future participation in drilling and completing new wells and associated capital expenditures.

The following table compares the Company’s 2013 production to that of 2012:

These production increases are the result of new production coming on line which has exceeded the natural production decline of existing wells. We expect 2013 production to exceed that of 2012 as new production will continue to come on line through the remaining three months of 2013.

Product pricing for 2013 and 2012 is compared in the table below:

Panhandle’s oil sales price has averaged 93% of NYMEX oil price over the last 12 months. Based on this correlation, and NYMEX oil futures prices, we expect the Company’s average oil sales price for 2013 to approximate $90.00 per barrel. For the last 12 months, NGL sales prices averaged 30% of NYMEX oil price; this would correlate to an average NGL sales price for 2013 of approximately $28.00 per barrel, which is also in line with management’s expectations.

The extended winter experienced in many parts of the United States during March and April resulted in gas storage levels below the five-year average going into the natural gas storage injection season. Currently, gas storage levels have climbed to near the five-year average. As natural gas is used to generate electric power, abnormally hot or cool temperatures for the remainder of the injection season could affect natural gas prices going forward. For the previous 12 months, Panhandle’s natural gas sales price has averaged 93% of NYMEX natural gas price. Based on NYMEX natural gas futures prices, management expects the Company’s average natural gas sales price for 2013 to approximate $3.40 per Mcf.

As of June 30, 2013, the Company had the following derivative contracts in place:

Natural gas costless collar contracts

February 2013 – December 2013:

230,000 Mmbtu per month (floor and ceiling per Mmbtu of $3.75 and $4.05-$4.30, respectively)

November 2013 – April 2014:

160,000 Mmbtu per month (floor and ceiling per Mmbtu of $4.00 and $4.55, respectively)

Natural gas fixed price swaps

March 2013 – October 2013:

170,000 Mmbtu per month (fixed price of $3.40-$3.505 per Mmbtu)

April 2013 – December 2013:

40,000 Mmbtu per month (fixed price of $3.655 per Mmbtu)

May 2013 – November 2013:

100,000 Mmbtu per month (fixed price of $4.32 per Mmbtu)

Oil costless collar contracts

March 2013 – December 2013:

7,000 Bbls per month (floor and ceiling per Bbl of $90.00 and $101.50-$102.00, respectively)

May 2013 – December 2013:

2,000 Bbls per month (floor and ceiling per Bbl of $90.00 and $97.50, respectively)

With continued oil and natural gas price volatility, management continues to evaluate opportunities for product price protection through additional hedging of the Company’s future oil and natural gas production.

The use of the Company’s cash provided by operating activities and resultant change to cash is summarized in the table below:

Outstanding borrowings on the credit facility at March 31, 2013, were $13,565,237.

Looking forward, the Company expects to fund overhead costs, capital additions related to the drilling and completion of wells, treasury stock purchases and dividend payments primarily from cash provided by operating activities and cash on hand. As management evaluates opportunities to acquire additional assets, additional borrowings utilizing our bank credit facility could be necessary. Also, during times of oil, NGL and natural gas price decreases, or increased capital expenditures, it may be necessary to utilize the credit facility further in order to fund these expenditures. The Company has availability ($21,434,763 at June 30, 2013) under its revolving credit facility and is in compliance with 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.

Based on expected capital expenditure levels and anticipated cash provided by operating activities for 2013, the Company has sufficient liquidity to fund its ongoing operations and, combined with availability under its credit facility, to fund acquisitions.

RESULTS OF OPERATIONS

THREE MONTHS ENDED JUNE 30, 2013 – COMPARED TO THREE MONTHS ENDED JUNE 30, 2012

Overview:

The Company recorded third quarter 2013 net income of $5,070,168, or $.61 per share, compared to net income of $3,100,299, or $.37 per share, in the 2012 quarter. The increase in net income was principally the result of increased oil, NGL and natural gas sales; increased gains on derivative contracts; partially offset by decreased lease bonuses; and increased DD&A and lease operating expenses. These items are further discussed below.

Oil, NGL and Natural Gas Sales:

Oil, NGL and natural gas sales increased $7,388,428 or 88% for the 2013 quarter. Oil, NGL and natural gas sales were up due to increases in oil, NGL and natural gas sales volumes of 42%, 8% and 21%, respectively, and increases in NGL and natural gas sales prices of 11% and 92%, respectively. The following table outlines the Company’s production and average sales prices for oil, NGL and natural gas for the three month periods of 2013 and 2012:

Production for the last five quarters was as follows:

Lease Bonuses and Rentals:

Lease bonuses and rentals decreased $4,990,092 in the 2013 quarter as compared to the 2012 quarter. The decrease was mainly due to the Company leasing partial rights on 2,743 net mineral acres in Roger Mills County, Oklahoma, for $4.8 million in the 2012 quarter.

Gains (Losses) on Derivative Contracts:

At June 30, 2013, the Company’s fair value of derivative contracts was a net asset of $814,978; whereas at June 30, 2012, the Company’s fair value of derivative contracts was a net asset of $169,472. The Company had a net gain on derivative contracts of $1,714,832 in the 2013 quarter as compared to a net gain of $81,164 recorded in the 2012 quarter. The change was principally due to our natural gas fixed price swaps and collars increasing in value. Projected NYMEX natural gas prices are below both the fixed swap price and the floor of the collars at June 30, 2013.

Lease Operating Expenses (LOE):

LOE increased $851,166 or 38% in the 2013 quarter. LOE per Mcfe increased in the 2013 quarter to $.96 compared to $.85 in the 2012 quarter. LOE related to field operating costs increased $80,917 in the 2013 quarter compared to the 2012 quarter, a 7% increase. This increase was principally a result of production increasing 22%. Field operating costs were $.38 per Mcfe in the 2013 quarter as compared to $.43 per Mcfe in the 2012 quarter. The decrease in rate was due to fewer workovers in the 2013 quarter.

The increase in LOE related to field operating costs was coupled with an increase in handling fees (primarily gathering, transportation and marketing costs) on natural gas of $770,249 in the 2013 quarter compared to the 2012 quarter. On a per Mcfe basis, these fees increased $.16 due to higher natural gas sales and the significant addition of natural gas wells in the Fayetteville Shale play in Arkansas, which have higher handling fees. Handling fees are charged either as a percent of natural gas sales or based on natural gas production volumes.

Depreciation, Depletion and Amortization (DD&A):

DD&A increased $595,181 or 13% in the 2013 quarter. DD&A in the 2013 quarter was $1.61 per Mcfe as compared to $1.74 per Mcfe in the 2012 quarter. DD&A increased $1,007,241 due to production increasing 22% in the 2013 quarter compared to the 2012 quarter. The offsetting decrease of $412,060 was caused by a $.13 decrease in the DD&A rate. This rate decrease was mainly due to higher reserve prices at June 30, 2013, (compared to June 30, 2012) increasing ultimate reserves on a significant number of wells.

Provision for Impairment:

The provision for impairment decreased $198,515 in the 2013 quarter compared to the 2012 quarter. During the 2013 quarter, impairment of $7,400 was recorded on one small field. During the 2012 quarter, impairment of $205,915 was recorded on three small fields. These fields have few wells and are more susceptible to impairment when a well in these fields experiences downward reserve revisions due to reserve pricing or well performance.

Income Taxes:

The provision for income taxes was $672,000 higher in the 2013 quarter than the 2012 quarter. Income before provision for income taxes increased from $4,681,299 in the 2012 quarter to $7,323,168 in the 2013 quarter and the effective tax rate decreased to 31% in the 2013 quarter from 34% in the 2012 quarter. This decrease in the rate is the result of an increase in the estimated annual effective tax rate during the 2012 third quarter due to higher expected income before provision for income taxes (mostly related to higher lease bonus income) projected as of June 30, 2012, as compared to projections as of March 31, 2012.

NINE MONTHS ENDED JUNE 30, 2013 – COMPARED TO NINE MONTHS ENDED JUNE 30, 2012

Overview:

The Company recorded nine month 2013 net income of $8,240,953, or $.99 per share, as compared to net income of $7,188,375, or $.86 per share, in the 2012 period. Major contributing factors to the increase in net income were higher oil, NGL and natural gas sales; decreased provision for impairment; decreased exploration costs; and increased gains on derivative contracts; partially offset by decreased lease bonuses; increased DD&A expenses; increased LOE; and increased G&A. These items are further discussed below.

Oil, NGL and Natural Gas Sales:

Oil, NGL and natural gas sales increased $12,938,051 as a result of increased oil, NGL and natural gas sales volumes of 44%, 23% and 18%, respectively, and increased natural gas sales prices of 29%, partially offset by lower oil and NGL sales prices of 5% and 19%, respectively. The table below outlines the Company’s sales volumes and average sales prices for oil, NGL and natural gas for the nine month periods of 2013 and 2012:

Oil and NGL production increases resulted from continued drilling in the western Oklahoma and Texas Panhandle horizontal oil plays, principally the Marmaton, Cleveland, Tonkawa, Hogshooter, and Granite Wash and to a lesser extent horizontal oil drilling in the Bakken in North Dakota and the Woodford Shale in southern Oklahoma (Anadarko and Ardmore Basins). The natural gas production increase is largely attributable to continued drilling in the Fayetteville Shale in Arkansas and natural gas produced from new wells in western Oklahoma. Panhandle owns substantial acreage positions in each of the plays previously mentioned in Oklahoma and the Texas Panhandle as well as the Arkansas Fayetteville and expects continued drilling on its acreage in these plays. Expected drilling activity in the fourth quarter of 2013 will provide the Company opportunities to further increase its oil and NGL production for fiscal 2013. We are anticipating that natural gas production will level off in the coming quarters as new volumes associated with both dry gas drilling and our oil and liquids rich drilling are anticipated to approximately offset the natural decline of production from our existing properties.

Lease Bonuses and Rentals:

Lease bonuses and rentals decreased $6,396,677 in the 2013 period. The decrease was mainly due to the Company leasing partial rights on 2,743 net mineral acres in Roger Mills County, Oklahoma, for $4.8 million and leasing 2,431 net acres in the horizontal Mississippian play in northern Oklahoma for $1.7 million in the 2012 period.

Gains (Losses) on Derivative Contracts:

Lease Operating Expenses (LOE):

LOE increased $2,469,671 or 38% in the 2013 period. LOE per Mcfe increased in the 2013 period to $.95 compared to $.84 in the 2012 period. LOE related to field operating costs increased $539,306 in the 2013 period compared to the 2012 period, a 16% increase. This increase is principally a result of production increasing 21%. The field operating costs for the 2013 and 2012 periods were $.41 per Mcfe and $.42 per Mcfe, respectively.

The increase in LOE related to field operating costs was coupled with an increase in handling fees (primarily gathering, transportation and marketing costs) on natural gas of $1,930,365 in the 2013 period compared to the 2012 period. On a per Mcfe basis, these fees increased $.14 due to higher natural gas sales and the significant addition of new natural gas wells in the Fayetteville Shale play in Arkansas, which have higher handling fees. Handling fees are charged either as a percent of natural gas sales or based on natural gas production volumes.

Exploration Costs:

Exploration costs decreased $323,372 in the 2013 period as compared to the 2012 period. During the 2013 period, leasehold impairment and expired leasehold totaled $53,961 compared to $314,277 during the 2012 period, a $260,316 decrease. The decrease was due primarily to one leasehold prospect which was significantly impaired in the 2012 period. Charges on exploratory dry holes totaled $6,866 during the 2013 period as compared to $69,922 in the 2012 period.

Depreciation, Depletion and Amortization (DD&A):

Provision for Impairment:

The provision for impairment decreased $560,883 in the 2013 period compared to the 2012 period. During the 2012 period, impairment of $786,724 was recorded on ten small fields. During the 2013 period, impairment of $225,841 was recorded on four small fields. These fields have few wells and are more susceptible to impairment when a well in these fields experiences downward reserve revisions.

General and Administrative Costs (G&A):

G&A costs increased $324,906 or 7% in the 2013 period. This increase was primarily related to increases in personnel expenses of $338,778. Increases in personnel expenses were mainly due to restricted stock expense.

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, 2012.

ITEM 3  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Market Risk

Oil, NGL and natural gas prices historically have been volatile, and this volatility is expected to continue. Uncertainty continues to exist as to the direction of oil, NGL and natural gas price trends, and there remains a rather wide divergence in the opinions held by some in the industry. Being primarily a natural gas producer, the Company is more significantly impacted by changes in natural gas prices than by changes in oil or NGL prices. Longer term natural gas prices will be determined by the supply of and demand for natural gas as well as the prices of competing fuels, such as crude oil and coal. The market price of oil, NGL and natural gas in 2013 will impact the amount of cash generated from operating activities, which will in turn impact the level of the Company’s capital expenditures and production. Excluding the impact of the Company’s 2013 derivative contracts, based on the Company’s estimated natural gas volumes for 2013, the price sensitivity for each $0.10 per Mcf change in wellhead natural gas price is approximately $1,060,000 for operating revenue. Based on the Company’s estimated oil volumes for 2013, the price sensitivity in 2013 for each $1.00 per barrel change in wellhead oil price is approximately $213,000 for operating revenue. Based on the Company’s estimated NGL volumes for 2013, the price sensitivity in 2013 for each $1.00 per barrel change in NGL price is approximately $110,000 for operating revenue.

Commodity Price Risk

The Company periodically utilizes derivative contracts to reduce its exposure to unfavorable changes in natural gas and oil prices. The Company does not enter into these derivatives for speculative or trading purposes. All of our outstanding derivative contracts are with one counterparty and are secured. These arrangements cover only a portion of the Company’s production and provide only partial price protection against declines in natural gas and oil prices. These derivative contracts expose the Company to risk of financial loss and may limit the benefit of future increases in prices. As of June 30, 2013, the Company has natural gas fixed price swaps and oil and natural gas collars in place. For the Company’s fixed price swaps, a change of $.10 in the NYMEX Henry Hub forward strip prices would result in a change to pre-tax operating income of approximately $142,000. For the Company’s natural gas collars, a change of $.10 in the basis differential from NYMEX Henry Hub forward strip pricing would result in a change to pre-tax operating income of approximately $178,000. For the Company’s oil collars, a change of $1.00 in the basis differential from NYMEX WTI forward strip prices would result in a change to pre-tax operating income of approximately $30,000.

Financial Market Risk

Operating income 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%. At June 30, 2013, the Company had $13,565,237 outstanding under these facilities. At this point, the Company does not believe that its liquidity has been materially affected by the debt market uncertainties noted in the last few years and the Company does not believe that its liquidity will be impacted in the near future.

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 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, subject to the limitations noted above, the Company’s disclosure controls and procedures were effective to ensure material information relating to the Company 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 2 UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

During the three months ended June 30, 2013, the Company repurchased shares of the Company’s common stock as summarized in the table below.

Upon approval by the shareholders of the Company’s 2010 Restricted Stock Plan on March 11, 2010, the Board of Directors approved repurchase of up to $1.5 million of the Company’s common stock, from time to time, equal to the aggregate number of shares of common stock awarded pursuant to the Company’s 2010 Restricted Stock Plan, contributed by the Company to its ESOP and credited to the accounts of directors pursuant to the Deferred Compensation Plan for Non-Employee Directors. Pursuant to previously adopted board resolutions, the purchase of an additional $1.5 million of the Company’s common stock became authorized and approved effective June 26, 2013. The shares are held in treasury and are accounted for using the cost method.

ITEM 6 EXHIBITS AND REPORT ON FORM 8-K

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.

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