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INDEX

 

 

 

 

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The following defined terms are used in this report:

 

“Bbl” barrel.

“Board” board of directors.

“BTU” British Thermal Units. 

“Company” Panhandle Oil and Gas Inc.

“completion” the process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil and/or natural gas.

“DD&A” depreciation, depletion and amortization.

“dry hole” exploratory or development well that does not produce crude oil and/or natural gas in economically producible quantities.

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

“exploratory well” a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir.

“FASB” the Financial Accounting Standards Board.

“field” an  area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.

“G&A” general and administrative costs.

“gross acres” the total acres in which a working interest is owned.

“held by production” or “HBP” an oil and gas lease continued into effect into its secondary term for so long as a producing oil and/or gas well is located on any portion of the leased premises or lands pooled therewith.

“horizontal drilling” a drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled horizontally within a specified interval.

“IDC”  intangible drilling costs. 

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

“LOE” lease operating expense.

“Mcf” thousand cubic feet.

“Mcfe” 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” million BTU.

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

“net acres” the sum of the fractional working interests owned in gross acres.

“NGL” natural gas liquids.

“NYMEX” New York Mercantile Exchange.

“Panhandle” Panhandle Oil and Gas Inc.

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

“proved reserves” the quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain.

“royalty interest” 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” the United States Securities and Exchange Commission.

“undeveloped acreage” lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and/or natural gas.

“working interest” 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” 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 2015 mean the fiscal year ended September 30, 2015.

 

References to oil and natural gas properties

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

 

 

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PART 1   FINANCIAL INFORMATION

PANHANDLE OIL AND GAS INC.

CONDENSED BALANCE SHEETS

 

 

 

All share and per share amounts were adjusted for the 2-for-1 stock split, effective on October 8, 2014.

 

 

(See accompanying notes)

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PANHANDLE OIL AND GAS INC.

CONDENSED STATEMENTS OF OPERATIONS

 

 

 

 

 

All share and per share amounts were adjusted for the 2-for-1 stock split, effective on October 8, 2014.

 

 

 

 

 

 

 

 

 

 

 

 

(See accompanying notes)

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PANHANDLE OIL AND GAS INC.

STATEMENTS OF STOCKHOLDERS’ EQUITY

 

Three Months Ended December 31, 2014

 

 

 

 

Three Months Ended December 31, 2013

 

 

 

 

All share and per share amounts were adjusted for the 2-for-1 stock split, effective on October 8, 2014.

 

 

 

 

 

 

 

 

 

 

 

 

(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 2014 Annual Report on Form 10-K.

 

On September 11, 2014, the Company’s Board of Directors declared a 2-for-1 stock split of the outstanding Class A Common Stock. The Class A Common Stock split was effected in the form of a stock dividend and was distributed on October 8, 2014, to stockholders of record on September 24, 2014. All references to number of shares and per share information in the accompanying financial statements have been adjusted to reflect this stock split. 

 

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 quarters ended December 31, 2014 and 2013, was 31%. 

 

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

 

The Company has a $200,000,000 credit facility with a group of banks headed by Bank of Oklahoma (BOK) with a borrowing base of $130,000,000 and a maturity date of November 30, 2018.  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 $176,724,836 at December 31, 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 December 31, 2014, the effective interest rate was 2.34%.

 

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.

 

The borrowing base of $130,000,000 was reaffirmed by the banks in December 2014. Determinations of the borrowing base are made semi-annually or whenever the banks, in their discretion, believe that there has been a material change in the value of the oil and natural gas properties. The loan agreement contains customary covenants which, among other things, require periodic financial and reserve reporting and limit the Company’s incurrence of indebtedness, liens, dividends and acquisitions of treasury stock, and require the Company to maintain certain financial ratios. At December 31, 2014, the Company was in compliance with the covenants of the loan agreement.

 

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NOTE 5: Deferred Compensation Plan for Directors

 

Annually, non-employee directors may elect to be included in the Directors’ Deferred Compensation Plan.  The Directors’ Deferred Compensation Plan provides that each outside director may individually elect to be credited with future unissued shares of Company Common Stock rather than cash for all or a portion of the annual retainers, Board meeting fees and committee meeting fees, and may elect to receive shares, when issued, over annual time periods up to ten years.  These unissued shares are recorded to each director’s deferred compensation account at the closing market price of the shares (i) on the dates of the Board and committee meetings, and (ii) on the payment dates of the annual retainers.  Only on a director’s retirement, termination, death, or a change-in-control of the Company will the shares recorded for such director under the Directors’ Deferred Compensation Plan be issued to the director.  The promise to issue such shares in the future is an unsecured obligation of the Company.

 

NOTE 6: Restricted  Stock  Plan

 

In March 2010, shareholders approved the Panhandle Oil and Gas Inc. 2010 Restricted Stock Plan (2010 Stock Plan), which made available 200,000 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. In March 2014, shareholders approved an amendment to increase the number of shares of common stock reserved for issuance under the 2010 Stock Plan from 200,000 shares to 500,000 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 in May 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.

 

The following table summarizes the Company’s pre-tax compensation expense for the three months ended December 31, 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.

 

 

 

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,

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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 December 31, 2014 and 2013, the assessment resulted in impairment provisions of $2,191,997 and $202,991, 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 December 31, 2014 and 2013, non-producing oil and natural gas properties include costs of $908,872 and $83,174, 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 under its credit facility with Bank of Oklahoma. The derivative instruments have settled or will settle based on the prices below.

 

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Derivative contracts in place as of December 31, 2014

 

 

 

 

Derivative contracts in place as of September 30, 2014

 

 

 

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 $12,333,036 as of December 31, 2014, and a net asset of $1,901,842 as of September 30, 2014.

 

 

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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 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 December 31, 2014, and September 30, 2014. 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 December 31, 2014, and September 30, 2014.

 

 

 

(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 December 31, 2014.

 

 

 

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.

 

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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 December 31, 2014, and September 30, 2014, the fair value of financial instruments approximated their carrying 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

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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, at the time of closing, contained 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 included in the Company’s statement of operations for the three months ended December 31, 2014, were $4,270,866. Net income attributable to the acquisition included in the statement of operations for the three months ended December 31, 2014, was $872,919.

 

The following table presents the unaudited pro forma financial information assuming the Company had acquired this business on October 1, 2013:

 

 

 

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.

 

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 2015 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 2014 Annual Report on Form 10-K where risk factors are presented and further discussed. For all the above

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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 $15,663,248 at December 31, 2014,  compared to $9,919,037 at September 30, 2014.

 

Liquidity:

 

Cash and cash equivalents were $519,605 as of December 31, 2014, compared to $509,755 at September 30, 2014,  an increase of $9,850. Cash flows for the three months ended December 31 are summarized as follows:

 

 

 

Operating activities:

 

Net cash provided by operating activities increased $3,299,142 during the 2015 period, as compared to the 2014 period, the result of the following:

 

 

 

 

 

 

 

Investing activities:

 

Net cash used in investing activities increased $3,619,297 during the 2015 period, as compared to the 2014 period, due to:

 

 

 

 

Financing activities:

 

Net cash used in financing activities decreased $2,902,215 during the 2015 period, as compared to the 2014 period, the result of the following:

 

 

Capital Resources:

 

Capital expenditures to drill and complete wells increased $5,009,369 (51%) from the 2014 to the 2015 period.  This

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increase was largely due to drilling activity in the Eagle Ford Shale oil play in South Texas. Less significant capital expenditures were also made to fund horizontal drilling in the Arkansas Fayetteville Shale (dry natural gas), western and southern Oklahoma (oil and NGL rich) and the North Dakota Bakken Shale (oil).

 

Oil, NGL and natural gas production volumes increased 7% on an Mcfe basis during the 2015 period, as compared to the 2014 period. The production increase was the result of added production from the acquired properties in the Eagle Ford Shale and new production coming on line, which, combined, exceeded the natural production decline of existing wells. As the Company will be receiving oil production from the Eagle Ford properties for all of 2015 (as compared to three and one-half months of fiscal 2014), we expect 2015 oil production to increase over that of 2014. Natural gas and NGL production volumes are expected to be lower in 2015, as compared to 2014, as a result of anticipated lower 2015 capital expenditures which is discussed below.

 

The sharp drop in oil prices since September 2014, combined with lower natural gas prices within the last couple of months, has resulted in many of the operators in plays where we own an interest announcing that they are lowering their budgeted capital expenditures for calendar 2015. Particularly, on our Eagle Ford Shale properties and on five North Dakota Bakken Shale wells in which the Company owns an interest, the operators have recently ceased drilling and completion activities until the combination of oil prices and well service costs improve to a level which would yield a reasonable rate of return. As a result, Panhandle’s capital expenditures during 2015 are expected to be significantly less than in 2014. Reduced capital expenditures are anticipated to result in somewhat lower oil, NGL and natural gas production volumes in the remaining three quarters of 2015 compared to the first quarter, and combined with lower product prices, cash flow from operations will be reduced as long as product prices remain depressed. However, management does expect 2015 cash flow from operations to exceed capital expenditures, dividend payments and treasury stock purchases and plans to use excess cash flow to reduce bank debt.

 

Since the Company is not the operator of any of its oil and natural gas properties, it is extremely difficult for us to predict levels of future participation in the drilling and completion of new wells and their associated capital expenditures; thus, making 2015 capital expenditures for drilling and completion projects difficult to forecast.

 

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:

 

 

Outstanding borrowings on the credit facility at December 31, 2014, were $78,715,107.

 

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 ($51,284,893 at December 31, 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).

 

Based on expected capital expenditure levels and anticipated cash provided by operating activities for 2015, the Company has sufficient liquidity to fund its ongoing operations and, combined with availability under its credit facility, to fund acquisitions.

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RESULTS OF OPERATIONS

 

THREE MONTHS ENDED DECEMBER 31, 2014 – COMPARED TO THREE MONTHS ENDED DECEMBER 31, 2013

 

Overview:

 

The Company recorded first quarter 2015 net income of $10,233,761, or $0.61 per share, as compared to $4,926,318, or $0.29 per share, in the 2014 quarter. The increase in net income was principally the result of gains on derivative contracts and increased oil and NGL sales; offset by increases in provision for impairment, LOE,  DD&A, interest expense and income taxes. These items are further discussed below. 

 

Oil, NGL and Natural Gas Sales:

 

Oil, NGL and natural gas sales increased $1,046,618 or 6% for the 2015 quarter. Oil, NGL and natural gas sales were up due to increases in oil and NGL sales volumes of 40% and 96%, respectively. These increases were partially offset by a decrease in natural gas sales volumes of 7% and a decrease in oil and NGL prices of 24% and 16%, 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 fiscal 2015 and 2014:

 

 

 

Oil production increases were principally the result of a full quarter of production from the Eagle Ford Shale properties which were acquired in June 2014, offset by declining production from Texas Panhandle and western Oklahoma horizontal Cleveland, Marmaton and Granite Wash oil plays. Eagle Ford Shale production in the first quarter of 2015 was negatively impacted by the delay of completion of six wells that were drilled in the quarter. The operator has elected to defer the completions until oil prices recover from their current depressed levels and/or service costs decline materially. NGL production increases resulted from drilling in western Oklahoma horizontal plays that are rich in NGL, principally the Anadarko Woodford Shale, Granite Wash and Marmaton. A full quarter of production from the Eagle Ford Shale properties, which were acquired in 2014, also contributed to the NGL production increase. Natural gas production decreases were the result of natural decline from existing properties, principally in western Oklahoma, the Texas Panhandle, the southeastern Oklahoma Woodford Shale and the Fayetteville Shale, exceeding production from new wells in those areas. This decline was partially offset by growth in natural gas production in the Anadarko Woodford Shale and from a full quarter of natural gas production from the Eagle Ford Shale properties which were acquired in June 2014.

 

The Company anticipates a material decrease in oil and NGL related capital expenditures in the remainder of 2015 to continue as long as the price of those products remains at or near their current depressed levels. Therefore, oil and NGL production are anticipated to decrease, in the remaining three quarters compared to the first quarter, as the result of natural decline. The Company anticipates a decrease in natural gas related capital expenditures in the remainder of 2015 due to lower natural gas prices and an anticipated reduction in drilling in the Fayetteville Shale resulting from an announced decrease in the 2015 drilling budget by the primary operator in the play. Natural gas production is anticipated to decrease, in the remaining three quarters of 2015, as the result of natural decline in western Oklahoma, the Texas Panhandle, the southeastern Oklahoma Woodford Shale and the Fayetteville Shale, which will not be completely offset by new production.

 

Production for the last five quarters was as follows:

 

 

 

Gains (Losses) on Derivative Contracts:

 

The fair value of derivative contracts was a net asset of $12,333,036 as of December 31, 2014, and a net liability of $466,772 as of December 31, 2013. We had a net gain on derivative contracts of $11,250,265 in the 2015 quarter as compared

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to a net loss of $496,901 recorded in the 2014 quarter. The change is principally due to the oil and natural gas collars and fixed price swaps increasing in value as projected oil and natural gas prices at December 31, 2014, were well below the floor prices of the collars and well below the fixed price of the swaps.

 

Lease Operating Expenses (LOE):

 

LOE increased $1,469,953 or 44% in the 2015 quarter. LOE per Mcfe increased in the 2015 quarter to $1.28 compared to $0.94 in the 2014 quarter. LOE related to field operating costs increased $1,486,415 in the 2015 quarter compared to the 2014 quarter, a 99% increase. Field operating costs were $.80 per Mcfe in the 2015 quarter as compared to $.43 per Mcfe in the 2014 quarter. This increase in rate in the 2015 quarter is principally the result of the properties added in the Eagle Ford Shale acquisition in the third quarter of 2014 and the significant number of oil and NGL rich wells drilled in recent years. These wells have higher lifting costs than our overall well population, which are predominantly natural gas producers.  

 

The increase in LOE related to field operating costs was slightly offset by a decrease in handling fees (primarily gathering, transportation and marketing costs) of $16,462 in the 2015 quarter compared to the 2014 quarter. On a per Mcfe basis, these fees decreased $.04 due to increases in oil and NGL production, while natural gas production decreased. Natural gas sales bear the large majority of the handling. Handling fees are charged either as a percent of sales or based on production volumes.

 

Depreciation, Depletion and Amortization (DD&A):

 

DD&A increased $831,000 or 16% in the 2015 quarter. DD&A in the 2015 quarter was $1.64 per Mcfe as compared to $1.51 per Mcfe in the 2014 quarter. DD&A increased $485,812 as a result of this $.13 increase in the DD&A rate. An additional increase of $345,188 was the result of production increasing 7% in the 2015 quarter compared to the 2014 quarter. The rate increase is mainly due to higher per Mcfe finding cost experienced in oil and liquids-rich areas where the Company has added production. 

 

Provision for Impairment:

 

The provision for impairment increased $1,989,006 in the 2015 quarter compared to the 2014 quarter. During the 2015 quarter, impairment of $2,191,997 was recorded on eleven small fields. One oil field in Hemphill County, Texas accounted for $1,846,488 of the impairment due mainly to declining oil prices. During the 2014 quarter, impairment of $202,991 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.

 

Interest Expense

 

Interest expense increased $402,733 in the 2015 quarter, as compared to the 2014 quarter. The increase was due to a larger outstanding debt balance that was used to purchase the Eagle Ford Shale properties in the third quarter of 2014.

 

Income Taxes:

 

Provision for income taxes increased in the 2015 quarter by $2,404,000, the result of a $7,711,443 increase in income before provision for income taxes in the 2015 quarter compared to the 2014 quarter. The effective tax rate was 31% in the 2014 quarter and the 2015 quarter.  Excess percentage depletion, which is a permanent tax benefit, reduced the effective tax rate below the statutory rate for both quarters.

 

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, 2014.

 

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 in the industry. The Company can be significantly impacted by changes in oil and natural gas prices. The market

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price of oil, NGL and natural gas in 2015 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 2015 derivative contracts, the price sensitivity for each $0.10 per Mcf change in wellhead natural gas price is approximately $1,077,356 for operating revenue based on the Company’s prior year natural gas volumes.  The price sensitivity in 2015 for each $1.00 per barrel change in wellhead oil price is approximately $346,387 for operating revenue  based on the Company’s prior year oil volumes.

 

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 Bank of Oklahoma 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 limit the benefit of future increases in prices. 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 $215,000. 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 $339,000. 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 $64,000.  

 

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 facility. 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 December 31, 2014, the Company had $78,715,107 outstanding under this facility. And the effective interest rate was 2.34%. 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 December 31, 2014, the Company repurchased shares of the Company’s common stock as summarized in the table below.

 

 

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Upon approval by the shareholders of the Company’s 2010 Restricted Stock Plan in March 2010, as amended in March 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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