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INDEX

 

 

 

 

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The following defined terms are used in this report:

 

“Bbl” means barrel.

 

“Board” means board of directors.

 

“BTU” means British Thermal Units. 

 

“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.

 

“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 2014 mean the fiscal year ended September 30, 2014.

 

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)

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PANHANDLE OIL AND GAS INC.

CONDENSED STATEMENTS OF OPERATIONS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(See accompanying notes)

 

 

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PANHANDLE OIL AND GAS INC.

STATEMENTS OF STOCKHOLDERS’ EQUITY

 

Nine Months Ended June 30, 2014

 

 

 

 

Nine Months Ended June 30, 2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(See accompanying notes)

 

 

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PANHANDLE OIL AND GAS INC.

CONDENSED STATEMENTS OF CASH FLOWS

 

 

 

 

 

 

 (See accompanying notes)

 

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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 2013 Annual Report on Form 10-K. 

 

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 detailed well-by-well calculations at fiscal year-end. Federal and Oklahoma excess percentage depletion, when a provision for income taxes is recorded, decreases 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, 2014, was 32% as compared to 31% for the nine months ended June 30, 2013.  The effective tax rate for the quarter ended June 30, 2014, was 33% as compared to 31% for the quarter ended June 30, 2013. 

 

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, including unissued, vested directors’ deferred compensation shares during the period. 

 

NOTE 4: Long-term Debt

 

On June 17, 2014, the closing date of the Eagle Ford Shale asset acquisition, the Company increased its credit facility with a group of banks headed by Bank of Oklahoma (BOK) from $80,000,000 to $200,000,000, increased the borrowing base from $35,000,000 to $130,000,000 and extended the maturity date to November 30, 2018. The Company incurred $542,500 of debt issuance costs to increase its credit facility. These costs were capitalized and will be amortized over the term of the facility. The credit facility 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. The facility is secured by certain of the Company’s properties with a carrying value of $163,288,413 at June 30, 2014. The interest rate is based on BOK prime plus from 0.375% to 1.125%, or 30 day LIBOR plus from 1.875% to 2.625%. The election of BOK prime or LIBOR is at the Company’s discretion. The interest rate spread from BOK prime or LIBOR will be charged based on the ratio of the loan balance to the borrowing base. The interest rate spread from LIBOR or the prime rate increases as a larger percent of the borrowing base is advanced. At June 30, 2014, the effective interest rate was 2.58%.

 

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.

 

Since the bank charges a customary non-use fee of 0.25% annually of the unused portion of the borrowing base, the Company has not requested the bank to increase its borrowing base beyond $130,000,000. Determinations of the borrowing base are made semi-annually or whenever the bank, in its sole discretion, believes that there has been a material change in the value of the oil and natural gas properties. While the Company believes the availability could be increased (if needed), increases are at the discretion of the bank. The loan agreement contains customary covenants which, among other things, require periodic financial and reserve reporting and limit the Company’s incurrence of indebtedness, liens, dividends and acquisitions of treasury stock, and require the Company to maintain certain financial ratios. At June 30, 2014, the Company

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was in compliance with the covenants of the BOK agreement.

 

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. On March 5, 2014, shareholders approved an amendment to increase the number of shares of common stock reserved for issuance under the 2010 Stock Plan from 100,000 shares to 250,000 shares and to allow the grant of shares of restricted stock to our directors. The 2010 Stock Plan, as amended, 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 directors and officers of the Company and to align their interests with those of the Company’s shareholders.

 

Effective May 14, 2014, the board of directors approved for management, at their discretion, to purchase the Company’s common stock, from time to time, up to an amount 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 21, 2013, the Company awarded 6,093 non-performance based shares and 18,279 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 $199,788 and $294,889, 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 21, 2013, through December 21, 2016).

 

On May 29, 2014, the Company awarded 3,918 non-performance based shares of the Company’s common stock as restricted stock to its non-employee directors.  One-quarter of the restricted stock vested immediately on May 29, 2014, and an additional quarter vested on June 30, 2014. The remainder will vest over the next six months. The restricted stock contains nonforfeitable rights to receive dividends and voting rights during the vesting period. These non-performance based shares had a fair value on their award date of $210,120.

 

The following table summarizes the Company’s pre-tax compensation expense for the three and nine months ended June 30, 2014 and 2013, 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.

 

 

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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, 2014 and 2013, the assessment resulted in impairment provisions of $0 and $7,400, respectively. For the nine months ended June 30, 2014 and 2013, the assessment resulted in impairment provisions of $430,143 and $225,841, 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, 2014 and 2013, non-producing oil and natural gas properties include costs of $888,505 and $0, respectively, on exploratory wells which were drilling and/or testing. 

 

NOTE 10: Derivatives

 

The Company has entered into fixed swap contracts 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. Collar contracts set a fixed floor price and a fixed ceiling price and provide payments to the Company if the index price falls below the floor or require payments by the Company if the index 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 may expose the Company to risk of financial loss and limit the benefit of future increases in prices. All of the Company’s derivative contracts are with Bank of Oklahoma and are secured. The derivative instruments have settled or will settle based on the prices below.

 

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Derivative contracts in place as of June 30, 2014

 

 

 

 

 

Derivative contracts in place as of September 30, 2013

 

 

 

 

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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 liability of $2,006,229 as of June 30, 2014, and a net asset of $425,198 as of September 30, 2013.

 

 

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, 2014, and September 30, 2013. 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, 2014, and September 30, 2013.

 

 

 

(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 11: 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, 2014.

 

 

 

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Level 2 – Market Approach - The fair values of the Company’s 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 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 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 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.

 

At June 30, 2014, and September 30, 2013, the fair value of financial instruments approximated their carrying

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amounts. Financial instruments include long-term debt, which the valuation is classified as Level 3 and is based on a valuation technique that requires inputs that are both unobservable and significant to the overall fair value measurement. The fair value measurement of our long-term debt is valued using a discounted cash flow model that calculates the present value of future cash flows pursuant to the terms of the debt agreements and applies estimated current market interest rates. The estimated current market interest rates are based primarily on interest rates currently being offered on borrowings of similar amounts and terms. In addition, no valuation input adjustments were considered necessary relating to nonperformance risk for the debt agreements.

 

NOTE 12: Acquisitions

 

On June 17, 2014,  the Company closed an acquisition of certain Eagle Ford Shale assets located in LaSalle and Frio Counties, Texas, in the core of the Eagle Ford Shale. The assets were purchased from private sellers and included a 16% non-operated working interest in 11,100 gross (1,775 net) acres. The acreage is largely contiguous, entirely held by production and contains 63 producing wells (57 Eagle Ford, 5 Pearsall and 1 Buda) and 109 undeveloped Eagle Ford locations. The adjusted purchase price at closing was  $81.7 million and was funded by utilizing the Company’s bank credit facility. The purchase price was allocated to the producing wells and undeveloped locations based on fair value determined by estimated reserves and adjusted for working capital. The purchase price allocation is preliminary, pending the finalization of working capital adjustments. Adjustments to the estimated fair values may be recorded during the allocation period, not to exceed one year from the date of acquisition.

 

Actual and Pro Forma Impact of Acquisitions (Unaudited)

 

Revenues attributable to this acquisition (June 17, 2014, through June 30, 2014)  included in the Company’s statement of operations for the quarter and nine months ended June 30, 2014, were $1,011,909. Net income attributable to the acquisition included in the statement of operations for the quarter and nine months ended June 30, 2014, was $388,128.

 

The following table presents the unaudited pro forma financial information assuming the Company had acquired this business on October 1, 2012:

 

 

 

The unaudited pro forma financial information is for informational purposes only and does not purport to present what our results would actually have been had this transaction actually occurred on the date presented or to project our results of operations or financial position for any future period.

 

NOTE 13: Recently Adopted Accounting Pronouncements

 

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standard Update (“ASU”) 2014-09-Revenue from Contracts with Customers, which will supersede nearly all existing revenue recognition guidance under GAAP. The standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. We are evaluating our existing revenue recognition policies to determine whether any contracts in the scope of the guidance will be affected by the new requirements. The standard is effective for us on October 1, 2017. Early adoption is not permitted. The standard allows for either “full retrospective” adoption, meaning the standard is applied to all of the periods presented, or “modified retrospective” adoption, meaning the standard is applied only to the most current period presented in the financial statements. We are currently evaluating the transition method that will be elected.

 

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.

 

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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 2014 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 2013 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 $13,067,250 at June 30, 2014,  compared to $7,504,588 at September 30, 2013.

 

Liquidity:

 

Cash and cash equivalents were $1,511,057 as of June 30, 2014, compared to $2,867,171 at September 30, 2013,  a decrease of $1,356,114. Cash flows for the nine months ended June 30 are summarized as follows:

 

 

 

Operating activities:

 

Net cash provided by operating activities increased $12,245,322 during the 2014 period, as compared to the 2013 period, the result of the following:

 

 

 

 

 

 

Investing activities:

 

Net cash used in investing activities increased $92,744,327 during the 2014 period, as compared to the 2013 period, due to:

 

 

 

 

 

 

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Financing activities:

 

Net cash provided by financing activities increased $79,745,285 during the 2014 period, as compared to the 2013 period, the result of the following:

 

 

Capital Resources:

 

On June 17, 2014, the Company closed on the purchase of a 16% non-operated working interest in 11,100 gross leasehold acres (1,775 net) located in the Eagle Ford Shale play in LaSalle and Frio Counties, Texas, at an adjusted purchase price at closing of $81,703,747, subject to further working capital adjustments. Cash used for investing activities relevant to the Eagle Ford Shale acquisition was $85,209,240. The $3,505,493 difference represents the net benefit (to be received in future periods) of accrued revenues less accrued expenses. The purchase was funded utilizing the Company’s bank credit facility (see further discussion in this section below regarding restructure of the bank credit facility). All of the acquired acreage is held by production and, at the time of closing, included 63 producing wells, 1 drilling well, 3 wells in the completion phase and 109 undeveloped locations. The acreage is largely contiguous and is wholly operated by privately held Cheyenne Petroleum Company (Oklahoma City, Oklahoma). The property is currently being developed utilizing one drilling rig full-time.

 

Capital expenditures to drill and complete wells increased $6,117,492 (30%) from the 2013 to the 2014 period.  Primarily, this increase has been due to drilling activity in horizontal plays in western and southern Oklahoma (oil and NGL rich), the Texas Panhandle (oil and NGL rich), the Arkansas Fayetteville Shale (dry natural gas) and the newly acquired Eagle Ford Shale (oil). Less significant capital expenditures have also been made to fund horizontal drilling in the northern Oklahoma Mississippian (oil) and the North Dakota Bakken (oil) along with vertical drilling in the Permian Basin of West Texas and New Mexico (oil).

 

The oil and NGL rich plays in western and southern Oklahoma and the Texas Panhandle where drilling activity has been on mineral and leasehold acreage the Company owns are as follows:

 

 

Based on the current level of drilling proposals, including the recently acquired Eagle Ford Shale acreage, management expects capital expenditures for the drilling and completing of wells to approximate $47 million for fiscal 2014. Since the Company is not the operator of any of its oil and natural gas properties, it is difficult for us to predict the level of future well proposals, the Company’s percentage of participation in the drilling and completion of new wells and the amount of associated capital expenditures.

 

Production of oil, NGL and natural gas increased 9% on an Mcfe basis from the 2013 to the 2014 period.  The production increase was largely the result of new production coming on line from drilling in late fiscal 2013 and early fiscal 2014, which exceeded the natural production decline of existing wells. Based on current levels of activity, which now includes drilling on the Eagle Ford Shale acreage, combined with the added production from Eagle Ford Shale wells that were producing at the time they were acquired, 2014 total Mcfe production is expected to exceed that of 2013 by approximately the same percentage as through the first nine months.

 

The shift, in recent years, of capital outlays more toward oil and NGL rich plays and less toward plays for dry natural gas, combined with oil production from the Eagle Ford Shale acreage, is expected to result in significantly increased oil and NGL production volumes in 2014 compared to 2013. Natural gas production for 2014 is expected to remain relatively level to 2013 as dry natural gas production coming on line as a result of continued drilling in the Arkansas Fayetteville Shale, combined with associated natural gas production from new wells coming on line in the oil and NGL rich areas noted above, are projected to offset the natural gas production decline of existing wells. As experienced previously, the timing of new wells coming on line may cause intermittent increases or decreases in oil, NGL and natural gas production from quarter to quarter.

 

Panhandle’s oil sales price averaged 96% of NYMEX oil price during the 2014 period. Based on this correlation and NYMEX oil futures prices, management expects the Company’s average oil sales price for 2014 to approximate $97.00 per barrel. For the 2014 period, NGL sales prices averaged 32% of NYMEX oil price; which correlates to an average NGL sales

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price for 2014 of approximately $33.00 per barrel, also in line with our expectations.

 

For the 2014 period, Panhandle’s natural gas sales price 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 2014 to approximate $4.00 per Mcf.

 

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. See NOTE  10  – “Derivatives” for a complete list of the Company’s outstanding derivative contracts.

 

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

 

 

On June 17, 2014, the closing date of the Eagle Ford Shale asset acquisition, the Company increased its credit facility from $80 million to $200 million, increased the borrowing base from $35 million to $130 million and extended the maturity date to November 30, 2018. Outstanding borrowings on the credit facility at June 30, 2014, were $85,852,794.

 

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 ($44,147,206 at June 30, 2014) under its revolving credit facility and is in compliance with its debt covenants (current ratio, debt to EBITDA and dividends as a percent of operating cash flow). While the Company believes the availability could be increased (if needed), increases are at the discretion of the bank.

 

Based on expected capital expenditure levels and anticipated cash provided by operating activities for 2014, 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, 2014 – COMPARED TO THREE MONTHS ENDED JUNE 30, 2013

 

Overview:

 

The Company recorded third quarter 2014 net income of $5,122,585, or $0.61 per share, as compared to $5,070,168, or $0.61 per share, in the 2013 quarter. The increase in net income was principally the result of increased oil, NGL and natural gas sales; offset by losses on derivative contracts, increased G&A expenses and increased income taxes. These items are further discussed below. 

 

Oil, NGL and Natural Gas Sales:

 

Oil, NGL and natural gas sales increased $3,707,408 or 23% for the 2014 quarter. Oil, NGL and natural gas sales were up due to increases in oil and NGL sales volumes of 27% and 146%, respectively, and increases in oil, NGL and natural gas prices of 11%,  30% and 12%, respectively.  These increases were partially offset by a decrease in natural gas sales volumes of 9%. The following table outlines the Company’s production and average sales prices for oil, NGL and natural gas for the

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three month periods of fiscal 2014 and 2013:

 

 

 

Oil production increases were principally the result of 14 days of production from the recent Eagle Ford Shale asset acquisition which closed on June 17, 2014, and to a lesser extent, drilling in the western Oklahoma horizontal Granite Wash and Marmaton oil plays. NGL production increases resulted from continued drilling in western Oklahoma and the Texas Panhandle horizontal oil plays, principally the Marmaton, Granite Wash and Cleveland. Natural gas production decreases were the result of natural decline from existing properties, principally in the Fayetteville Shale, exceeding production from new wells.

 

Oil production is anticipated to materially increase in the fourth quarter of 2014 and in 2015 due to existing production from our recently acquired Eagle Ford Shale properties in La Salle and Frio Counties, Texas. Projected ongoing development of this Eagle Ford Shale property, along with anticipated drilling in the Oklahoma and Texas Panhandle oil and NGL rich plays, are also expected to contribute to oil and NGL production increases in the fourth quarter of 2014 and in 2015. Natural gas production is expected to increase relative to the third quarter of 2014 primarily as the result of activity in the Fayetteville Shale where the Company has an interest in over 45 wells that are drilling or completing and are anticipated to begin production during the fourth quarter. For the full year, natural gas production is expected to remain relatively level in 2014 as compared to 2013.

 

Production for the last five quarters was as follows:

 

 

 

Gains (Losses) on Derivative Contracts:

 

The fair value of derivative contracts was a net liability of $2,006,229 as of June 30, 2014, and a net asset of $814,978 as of June 30, 2013. We had a net loss on derivative contracts of $1,427,165 in the 2014 quarter as compared to a net gain of $1,714,832 recorded in the 2013 quarter. The change is principally due to the oil and natural gas collars and fixed price swaps decreasing in value as projected oil and natural gas prices at June 30, 2014, were above the ceiling prices of the collars and above the fixed price of the swaps.

 

Lease Operating Expenses (LOE):

 

LOE decreased $143,959 or 5% in the 2014 quarter. LOE per Mcfe decreased in the 2014 quarter to $0.89 compared to $0.96 in the 2013 quarter. LOE related to field operating costs increased $265,331 in the 2014 quarter compared to the 2013 quarter, a 22% increase. Field operating costs were $.45 per Mcfe in the 2014 quarter as compared to $.38 per Mcfe in the 2013 quarter. The increase in rate in the 2014 quarter is due to the large addition of oil and NGL rich wells, in recent years, which have higher lifting costs than the overall well population.

 

The increase in LOE related to field operating costs was offset by a decrease in handling fees (primarily gathering, transportation and marketing costs) of $409,290 in the 2014 quarter compared to the 2013 quarter. On a per Mcfe basis, these fees decreased $.14 due to significant increases in oil and NGL production, while natural gas production decreased. Natural gas sales bear the large majority of the handling fees while oil and NGL sales incur a much smaller amount. Handling fees are charged either as a percent of sales or based on production volumes.

 

Depreciation, Depletion and Amortization (DD&A):

 

DD&A increased $122,233 or 2% in the 2014 quarter. DD&A in the 2014 and 2013 quarters was $1.61 per Mcfe. The $122,233 increase was principally the result of production increasing 2% in the 2014 quarter compared to the 2013 quarter. 

 

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General and Administrative Costs (G&A):

 

G&A costs increased $240,089 or 15% in the 2014 quarter. This increase is primarily related to increases in directors’ expense of $108,286 coupled with increased legal expenses of $58,506. Increase in directors’ expense was mainly due to restricted stock expense for shares awarded to directors in the 2014 quarter. The increase in legal expense was a result of additional fees for legal services associated with the Eagle Ford Shale asset acquisition.

 

Income Taxes:

 

Provision for income taxes increased in the 2014 quarter by $252,000, the result of a $304,417 increase in income before provision for income taxes in the 2014 quarter compared to the 2013 quarter and an increase in the effective tax rate from 31% in the 2013 quarter to 33%  in the 2014 quarter.  Excess percentage depletion, which is a permanent tax benefit, reduced the effective tax rate below the statutory rate for both quarters.

 

NINE MONTHS ENDED JUNE 30, 2014 – COMPARED TO NINE MONTHS ENDED JUNE 30, 2013

 

Overview:

 

The Company recorded nine month net income of $15,703,476, or $1.88 per share, in the 2014 period, as compared to $8,240,953, or $0.99 per share, in the 2013 period. The increase in net income was principally the result of increased oil, NGL and natural gas sales; decreased DD&A expenses; partially offset by losses on derivative contracts; increased LOE, increased production taxes and increased income taxes. These items are further discussed below. 

 

Oil, NGL and Natural Gas Sales:

 

Oil, NGL and natural gas sales increased $16,428,993 or 38% for the 2014 period. Oil, NGL and natural gas sales were up due to increases in oil and NGL sales volumes of 42% and 86%, respectively, and increases in oil, NGL and natural gas prices of 9%,  21% and 23%, respectively. The following table outlines the Company’s production and average sales prices for oil, NGL and natural gas for the nine month periods of fiscal 2014 and 2013:

 

 

 

Oil and NGL production increases resulted from continued drilling in the southern and western Oklahoma and Texas Panhandle horizontal oil plays, principally the Marmaton, Cleveland, Hogshooter, Granite Wash and the Woodford Shale in southern Oklahoma (Anadarko and Ardmore Basins). To a lesser extent, production from the recent Eagle Ford Shale asset acquisition which closed on June 17, 2014, in conjunction with horizontal oil drilling in the northern Oklahoma Mississippian, the Bakken in North Dakota and vertical oil drilling in the Permian Basin of West Texas and New Mexico contributed to the increases. Natural gas production remained relatively level for the period as new natural gas production from continued drilling in the southern and western Oklahoma and Texas Panhandle horizontal oil plays, principally the Marmaton, Cleveland, Hogshooter, Granite Wash and the Woodford Shale in southern Oklahoma (Anadarko and Ardmore Basins) offset natural decline from existing properties principally in the Fayetteville Shale.

 

Oil production is anticipated to materially increase in the fourth quarter of 2014 and in 2015 due to existing production from our recently acquired Eagle Ford Shale properties in La Salle and Frio Counties, Texas. Projected ongoing development of this Eagle Ford Shale property, along with anticipated drilling in the Oklahoma and Texas Panhandle oil and NGL rich plays, are also expected to contribute to oil and NGL production increases in the fourth quarter of 2014 and in 2015. Natural gas production is expected to increase relative to the third quarter of 2014 primarily as the result of activity in the Fayetteville Shale where the Company has an interest in over 45 wells that are drilling or completing and are anticipated to begin production during the fourth quarter. For the full year, natural gas production is expected to remain relatively level in 2014 as compared to 2013.

 

Gains (Losses) on Derivative Contracts:

 

The fair value of derivative contracts was a net liability of $2,006,229 as of June 30, 2014, and a net asset of $814,978 as of June 30, 2013. We had a net loss on derivative contracts of $3,511,095 in the 2014 period as compared to a net gain of $796,166 recorded in the 2013 period. The change is principally due to the oil and natural gas collars and fixed price swaps decreasing in value as projected oil and natural gas prices at June 30, 2014, were above the ceiling prices of the collars and above the fixed prices of the swaps.

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Lease Operating Expenses (LOE):

 

LOE increased $889,534 or 10% in the 2014 period. LOE per Mcfe increased in the 2014 period to $0.96 compared to $0.95 in the 2013 period.  LOE related to field operating costs increased $671,330 in the 2014 period compared to the 2013 period, a 17% increase. Field operating costs were $.44 per Mcfe in the 2014 period as compared to $.41 per Mcfe in the 2013 period. This increase in rate is due to the large addition of oil and NGL rich wells which have higher lifting costs than the overall well population. The increase in amount in the 2014 period is the result of increased production.

 

The increase in LOE related to field operating costs was coupled with an increase in handling fees (primarily gathering, transportation and marketing costs) of $218,204 in the 2014 period compared to the 2013 period. This increase in the amount in the 2014 period is the result of increased production and sales. On a per Mcfe basis, these fees decreased $.02 due to significant increases in oil and NGL production, while gas production remained fairly flat. Natural gas sales bear the large majority of the handling fees while oil and NGL sales incur a much smaller amount. Handling fees are charged either as a percent of sales or based on production volumes.

 

Production Taxes:

 

Production taxes increased $694,197 or 59% in the 2014 period as compared to the 2013 period. Production taxes as a percentage of oil, NGL and natural gas sales increased from 2.8% in the 2013 period to 3.2% in the 2014 period.  The increase in amount is primarily the result of increased oil, NGL and natural gas sales of $16,428,993 during the 2014 period. The increase in rate is due mainly to the Company receiving more ultra-deep well refunds and rate reducing corrections in the 2013 period. We do not accrue for ultra-deep well production tax exemptions (allowed by the state of Oklahoma) because we do not have sufficient information to calculate a reasonable estimate. The low overall production tax rate is due to a large proportion of the Company’s revenues coming from horizontally drilled wells, which are eligible for reduced Oklahoma and Arkansas production tax rates.

 

Depreciation, Depletion and Amortization (DD&A):

 

DD&A decreased $1,527,557 or 9% in the 2014 period. DD&A in the 2014 period was $1.51 per Mcfe as compared to $1.80 per Mcfe in the 2013 period. DD&A decreased $3,025,646 as a result of this $.29 decrease in the DD&A rate. An offsetting increase of $1,498,089 was the result of production increasing 9% in the 2014 period compared to the 2013 period. The rate decrease is mainly due to higher oil, NGL and natural gas prices utilized in the reserve calculations during the period ended June 30, 2014 (compared to June 30, 2013) increasing projected remaining reserves on a significant number of wells.

 

Income Taxes:

 

Provision for income taxes increased in the 2014 period by $3,865,000, the result of an $11,327,523 increase in pre-tax income in the 2014 period compared to the 2013 period. The effective tax rate for the 2014 and 2013 periods was 32% and 31%, respectively. Excess percentage depletion, which is a permanent tax benefit, reduced the effective tax rate below the statutory rate for both periods.

 

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, 2013.

 

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 2014 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 2014 derivative contracts, based on the Company’s estimated natural gas volumes for 2014, the price sensitivity for each $0.10 per Mcf change in wellhead natural gas price is approximately $1,073,200 for operating revenue. Based on the Company’s estimated oil

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volumes for 2014, the price sensitivity in 2014 for each $1.00 per barrel change in wellhead oil price is approximately $357,000 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, 2014, the Company has oil and natural gas fixed price swaps and oil and natural gas collars in place. For the Company’s oil fixed price swaps, a change of $1.00 in the NYMEX WTI forward strip prices would result in a change to pre-tax operating income of approximately $276,000. For the Company’s natural gas 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 $153,000. For the Company’s natural gas collars, a change of $.10 in the NYMEX Henry Hub forward strip pricing would result in a change to pre-tax operating income of approximately $41,000. For the Company’s oil collars, a change of $1.00 in the NYMEX WTI forward strip prices would result in a change to pre-tax operating income of approximately $53,000.  

 

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 BOK prime rate plus from 0.375% to 1.125%, or 30 day LIBOR plus from 1.875% to 2.625%. At June 30, 2014, the Company had $85,852,794 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, 2014, the Company did not repurchase shares of the Company’s common stock.

 

 

Upon approval by the shareholders of the Company’s 2010 Restricted Stock Plan on March 11, 2010, as amended March 5, 2014, the Board of Directors approved repurchase of up to $1.5 million of the Company’s common stock, from time to time, up to an amount 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. Effective May 14, 2014, the Board adopted resolutions to allow management to repurchase the Company’s common stock at their discretion.

 

ITEM 6  EXHIBITS

 

 

 

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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