UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

For the period ended  March 31, 2018

For the transition period from                      to                        

Commission File Number 001-31759

PANHANDLE OIL AND GAS INC.

(Exact name of registrant as specified in its charter)

 

Grand Centre Suite 300, 5400 N Grand Blvd., Oklahoma City, Oklahoma  73112

(Address of principal executive offices)

Registrant's telephone number including area code (405) 948-1560

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes  ☑    No  ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).     Yes  ☑    No  ☐

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

 

Emerging growth company     ☐

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.     ☐

 

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

Outstanding shares of Class A Common stock (voting) at May 7, 2018: 16,775,953

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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 economic quantities.

“EBITDA” earnings before interest, taxes, depreciation and amortization (including impairment). This is a Non-GAAP measure.

“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 an 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 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 smaller proportionate share (as compared to a working interest) of production.

“SEC” the United States Securities and Exchange Commission.

“undeveloped acreage” 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 2018 mean the fiscal year ended September 30, 2018.

Fiscal quarter references

All references to quarters in this report, unless otherwise noted, refer to the Company’s fiscal quarter based on a fiscal year end of September 30. For example, references to first quarter mean the quarter of October 1 through December 31.

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

 

 

(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

Six Months Ended March 31, 2018

 

 

Six Months Ended March 31, 2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(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: Basis of Presentation and Accounting Principles

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 2017 Annual Report on Form 10-K.

New Accounting Pronouncements yet to be Adopted

In February 2016, the FASB issued its new lease accounting guidance in ASU 2016-02, Leases (Topic 842). Under the new guidance, lessees will be required to recognize the following for all leases (with the exception of short-term leases) at the commencement date: 1) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and 2) a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The new lease guidance simplified the accounting for sale and leaseback transactions primarily because lessees must recognize lease assets and lease liabilities. Lessees will no longer be provided with a source of off-balance sheet financing. The guidance is effective for us beginning October 1, 2019, including interim periods within the fiscal year. Early application is permitted for all public business entities upon issuance. Lessees (for capital and operating leases) and lessors (for sales-type, direct financing, and operating leases) must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The modified retrospective approach would not require any transition accounting for leases that expired before the earliest comparative period presented. Lessees and lessors may not apply a full retrospective transition approach. We are assessing the potential impact that this standard will have on our financial statements.

In January 2016, the FASB issued ASU 2016-01, Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities. The new guidance is intended to improve the recognition and measurement of financial instruments. The new guidance is effective for us beginning October 1, 2018, including interim periods within the fiscal year. We are assessing the potential impact that this standard will have on our financial statements.

In May 2014, the FASB issued 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 beginning October 1, 2018. 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 and utilizes a cumulative effect adjustment to retained earnings in the period of adoption to account for prior period effects rather than restating previously reported results. Panhandle intends to use the modified retrospective method upon adoption. We are currently evaluating the potential impact that this standard will have on our financial statements.

Other accounting standards that have been issued or proposed by the FASB, or other standards-setting bodies, that do not require adoption until a future date are not expected to have a material impact on the financial statements upon adoption.

NOTE 2: Income Taxes

The Tax Cuts and Jobs Act was enacted on December 22, 2017. The Act reduces the US federal corporate tax rate from 35% to 21%, requires companies to pay a one-time transition tax on earnings of certain foreign subsidiaries that were previously tax deferred and creates new taxes on certain foreign sourced earnings. As of March 31, 2018, we have not completed our accounting for the tax effects of enactment of the Act; however, in certain cases, as described below, we have made a reasonable estimate of the

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effects on our existing deferred tax balances. Based on these estimates, we recognized a provisional amount, which is included as a component of income tax expense (benefit) from continuing operations. In all cases, we will continue to make and refine our calculations as additional analysis is completed.

We remeasured certain deferred tax assets and liabilities based on the rates at which they are expected to reverse in the future, which is generally 21%. However, we are still analyzing certain aspects of the Act and refining our calculations, which could potentially affect the measurement of these balances or potentially give rise to new deferred tax amounts. The provisional amount recorded related to the remeasurement of our deferred tax balance was $12,825,000 income tax benefit.

The Company has a year end of September 30. Because this differs from a normal calendar year end, we have calculated the current year’s federal tax provision using a blended rate of 24.53% to adjust for one quarter of our fiscal year being under the old rate of 35% and the remaining three quarters being under the new rate of 21%. The impact of using a blended rate versus the old rate in the current quarter resulted in a federal tax benefit of $109,535.

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. Excess percentage depletion, both federal and Oklahoma, can only be taken in the amount that it exceeds cost depletion which is calculated on a unit-of-production basis. Excess tax benefits and deficiencies of stock based compensation will be recognized as income tax expense (benefit) in the statement of operations prospectively versus additional paid in capital in the equity section of the balance sheet as was previously required.

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 expected for the year, decreases the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is expected for the year. The benefits of federal and Oklahoma excess percentage depletion and excess tax benefits and deficiencies of stock based compensation are not directly related to the amount of pre-tax income (loss) 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 six months ended March 31, 2018, was a 600% benefit as compared to a 33% benefit for the six months ended March 31, 2017. The effective tax rate for the quarter ended March 31, 2018, was a 2% benefit as compared to a 19% provision for the quarter ended March 31, 2017.

NOTE 3: Basic and Diluted Earnings (Loss) per Share

Basic and diluted earnings (loss) per share is calculated using net income (loss) 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 current borrowing base of $80,000,000 and a maturity date of November 30, 2022. The credit facility is subject to a semi-annual borrowing base determination, wherein BOK applies their commodity pricing forecast to the Company’s reserve forecast and determines a borrowing base. The facility is secured by certain of the Company’s properties (well bore only) with a net book value of $141,464,533 at March 31, 2018. The interest rate is based on BOK prime plus from 0.375% to 1.250%, or 30 day LIBOR plus from 1.875% to 2.750%. 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 the ratio of loan balance to the borrowing base increases. At March 31, 2018, the effective interest rate was 3.84%.

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.

Determinations of the borrowing base are made semi-annually (usually June and December) 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. In October 2017, during the renegotiation of our credit facility, the borrowing base was redetermined by the banks and left unchanged at $80,000,000. The loan agreement contains customary covenants which, among other things, require periodic financial and reserve reporting and place certain limits on the Company’s incurrence of indebtedness, liens, payment of dividends and acquisitions of treasury stock. In addition, the Company is required to maintain certain financial ratios, a current ratio (as defined by the bank agreement – current assets includes availability under outstanding credit facility) of no less than 1.0 to 1.0 and a funded debt to EBITDA (trailing twelve months as

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defined by the bank agreement – traditional EBITDA with the unrealized gain or loss on derivative contracts also removed from earnings) of no more than 4.0 to 1.0. At March 31, 2018, the Company was in compliance with the covenants of the loan agreement and has $36,500,000 of availability under its outstanding credit facility.

NOTE 5: Deferred Compensation Plan for Non-Employee Directors

Annually, non-employee directors may elect to be included in the Deferred Compensation Plan for Non-Employee Directors. The Deferred Compensation Plan for Non-Employee Directors 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. 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 upon a director’s retirement, termination, death, or a change-in-control of the Company will the shares recorded for such director be issued under the Deferred Compensation Plan for Non-Employee Directors. Directors may elect to receive shares, when issued, over annual time periods up to ten years. If available, the shares are expected to be issued out of shares held in treasury. The promise to issue such shares in the future is an unsecured obligation of the Company. During 2018, deferred directors’ compensation on the Balance Sheets was reduced $811,219 for shares issued to retired directors. Of the shares issued, 31,838 shares were issued out of treasury and 32,599 shares were newly issued.

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 adopted resolutions to allow management, at their discretion, to purchase the Company’s common stock as treasury shares up to an amount equal to the aggregate number of shares of common stock awarded pursuant to the Company’s Amended 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 12, 2017, the Company awarded 9,700 non-performance based shares and 29,099 performance based shares of the Company’s common stock as restricted stock to certain officers. The restricted stock vests at the end of a three-year period and contains non-forfeitable 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 $203,700 and $330,043, respectively. The fair value for the non-performance and the performance based awards 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 prices as compared to the Dow Jones Select Oil Exploration and Production Index (DJSOEP) prices utilizing a Monte Carlo model covering the performance period (December 12, 2017, through December 12, 2020).

On December 31, 2017, the Company awarded 10,218 non-performance based shares of the Company’s common stock as restricted stock to its non-employee directors. The restricted stock vests quarterly over one year starting on March 31, 2018. The restricted stock contains non-forfeitable 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 $209,982.

The following table summarizes the Company’s pre-tax compensation expense for the three and six months ended March 31, 2018 and 2017, related to the Company’s performance based and non-performance based restricted stock.

 

 

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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.

 

 

NOTE 7: Properties and Equipment

Divestitures

During the first quarter of 2018, the Company sold 79 non-core marginal wells for $557,750 and recorded a loss on the sales of $272,236. The total net book value that was removed from the Balance Sheets due to these sales was approximately $0.8 million. All of the wells included in the Assets held for sale line item on the Balance Sheets at September 30, 2017, were sold during the first quarter of 2018.

During the second quarter of 2018, the Company sold 199 non-core marginal wells for $571,955 and recorded a loss on the sales of $193,893. The total net book value that was removed from the Balance Sheets due to these sales was approximately $0.8 million.

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 retirement of assets 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.

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 drilling and completion costs; 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 to reflect any material changes since the prior report was issued and then utilizes updated projected future price decks current with the period. For the three months ended March 31, 2018 and 2017, the assessment resulted in impairment provisions on producing properties of $0 and $10,788, respectively. For the six months ended March 31, 2018 and 2017, the assessment resulted in impairment provisions on producing properties of $0 and $10,788, respectively. A significant reduction in oil, NGL and natural gas prices or a decline in reserve volumes may lead to additional impairment in future periods that may be material to the Company.

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NOTE 8: Derivatives

The Company has entered into commodity price derivative agreements including 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.

Derivative contracts in place as of March 31, 2018

 

 

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 $1,970,359 as of March 31, 2018, and a net asset of $516,159 as of September 30, 2017. Net cash received related to derivative contracts settled during the six-month period ended March 31, 2018, was $648,690 compared to net cash paid of $345,916 in the same period in the prior year.

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.

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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 March 31, 2018, and September 30, 2017. The Company has offset all amounts subject to master netting agreements in the Company's Condensed Balance Sheets at March 31, 2018, and September 30, 2017.

 

 

(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 9: 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 March 31, 2018.

 

 

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 Condensed Statements of Operations.

 

 At March 31, 2018, and September 30, 2017, 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.

FORWARD-LOOKING STATEMENTS AND RISK FACTORS

Forward-Looking Statements for fiscal 2018 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 2017 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 $3,731,783 at March 31, 2018, compared to positive working capital of $6,451,356 at September 30, 2017. The change in working capital was mainly due to the net change in receivables (payables) for derivative contracts and decreased payables for drilling activity as of March 31, 2018.

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Liquidity:

Cash and cash equivalents were $168,562 as of March 31, 2018, compared to $557,791 at September 30, 2017, a decrease of $389,229. Cash flows for the six months ended March 31 are summarized as follows:

Net cash provided (used) by:

 

 

Operating activities:

Net cash provided by operating activities increased $6,011,417 during the 2018 period, as compared to the 2017 period, primarily the result of the following:

Investing activities:

Net cash used by investing activities decreased $1,612,491 during the 2018 period, as compared to the 2017 period, primarily due to lower payments of $1,176,773 for drilling and completion activity and higher proceeds from the sale of assets during 2018 of $411,005.

Financing activities:

Net cash used by financing activities increased $8,093,595 during the 2018 period, as compared to the 2017 period, primarily the result of higher net payments on long-term debt of $8,222,220.

Capital Resources:

Capital expenditures to drill and complete wells decreased $1,176,773 (15%) from the 2017 to the 2018 period. The Company completed the last of its significant drilling projects that were started in 2017 during the first quarter of 2018. The final four wells of the ten-well Eagle Ford Shale drilling program (from 2017) were completed and started producing in 2018. New drilling in the Eagle Ford is expected to begin in May 2018 as the operator has committed to a new six-well program that could be extended to a total of fourteen depending on market conditions. With current uncertain drilling expectations for the remainder of the year, management believes that 2018 capital expenditures may be lower than 2017 capital expenditures.

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 participation in and precise timing of the drilling and completion of new wells and their associated capital expenditures. This makes 2018 capital expenditures for drilling and completion projects difficult to forecast.

The Company received lease bonus payments during 2018 totaling $610,552. Looking forward, the cash flow benefit from bonus payments associated with the leasing of drilling rights on the Company’s mineral acreage is very difficult to project as the Company’s mineral acreage position is so diverse and spread across several states. However, management will continue to strategically evaluate the merit of leasing certain of the Company’s mineral acres.

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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 8– “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 March 31, 2018, were $43,500,000.

Looking forward, the Company expects to fund overhead costs, capital additions related to the drilling and completion of wells, treasury stock purchases, if any, and dividend payments from cash provided by operating activities, cash on hand and borrowings utilizing our bank credit facility. Any excess cash is intended to be used to reduce existing bank debt. The Company had availability ($36,500,000 at March 31, 2018) under its revolving credit facility and is in compliance with its debt covenants (current ratio, debt to trailing 12-month EBITDA, as defined by bank agreement, and dividends as a percent of operating cash flow). The debt covenants limit the maximum ratio of the Company’s debt to EBITDA to no more than 4:1.

The borrowing base under the credit facility was redetermined in October 2017 and left unchanged at $80 million, which is a level that is expected to provide ample liquidity for the Company to continue to employ its normal operating strategies. The next redetermination is scheduled for June 2018.

Based on expected capital expenditure levels, anticipated cash provided by operating activities for 2018 and availability under its credit facility, the Company has sufficient liquidity to fund its ongoing operations.

RESULTS OF OPERATIONS

THREE MONTHS ENDED MARCH 31, 2018 – COMPARED TO THREE MONTHS ENDED MARCH 31, 2017

Overview:

The Company recorded a second quarter 2018 net income of $1,070,176, or $0.06 per share, as compared to a net income of $3,470,433, or $0.21 per share, in the 2017 quarter. The change in net income (loss) was principally the result of decreased gains on derivative contracts and decreased lease bonuses; partially offset by increased oil, NGL and natural gas sales and changes in tax provision (benefit). These items are further discussed below.

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Oil, NGL and Natural Gas Sales:

Oil, NGL and natural gas sales increased $3,375,134 or 38% for the 2018 quarter. Oil, NGL and natural gas sales were up due to increases in oil and NGL prices of 32% and 23%, respectively, and increased oil, NGL and natural gas sales volumes of 24%, 68% and 21%, respectively, slightly offset by decreased natural gas prices of 6%. 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 2018 and 2017:

 

 

The oil production increase is a result of the ten-well drilling program in the Eagle Ford Shale and the six-well program in the Anadarko Basin Woodford Shale. New production from successful drilling in the STACK play in western Oklahoma adds to the increase. The increase was partially offset by the natural decline in oil production from the Bakken in North Dakota. The NGL production increase is attributed to the liquid-rich production from the six-well drilling program in the Anadarko Basin Woodford Shale. Increased gas production is realized from the eight-well drilling program in the southeastern Oklahoma Woodford Shale and the six-well program in the Anadarko Basin Woodford Shale. Smaller gains are seen in the STACK play in western Oklahoma. The gas production increase was partially offset by naturally declining production from the Fayetteville Shale and, to a much lesser extent, Northern Oklahoma Mississippian.

Production for the last five quarters was as follows:

 

 

Lease Bonuses and Rentals:

Lease bonuses and rentals decreased $1,835,005 in the 2018 quarter. The decrease was mainly due to the Company completing mineral lease packages in Lea and Eddy Counties in New Mexico and in Dewey County, Oklahoma, in the 2017 quarter. There were no significant lease packages in the 2018 quarter.

Gains (Losses) on Derivative Contracts:

The fair value of derivative contracts was a net liability of $1,970,359 as of March 31, 2018, and a net liability of $43,705 as of March 31, 2017. We had a net loss on derivative contracts of $1,343,976 in the 2018 quarter as compared to a net gain of $2,739,183 in the 2017 quarter. The change is principally due to the oil collars and fixed price swaps being less favorable in the 2018 quarter, as NYMEX oil futures experienced large increases in price in relation to the collars and the fixed prices of the swaps. During the 2017 quarter, the oil and natural gas collars and fixed price swaps experienced a very favorable change as the NYMEX futures prices (at that time) for both commodities significantly decreased from where they were at as of the end of the first quarter in 2017. The natural gas collars and fixed price swaps in place during the 2018 quarter were very beneficial and the largest part of the gain from these contracts (covering January through March 2018 production) cash settled during the quarter. The Company utilizes derivative contracts for the purpose of protecting its return on investments.

Lease Operating Expenses (LOE):

LOE increased $112,072 or 4% in the 2018 quarter driven mostly by increased production. LOE per Mcfe decreased in the 2018 quarter to $1.09 compared to $1.32 in the 2017 quarter. LOE related to field operating costs decreased $104,938 in the 2018 quarter compared to the 2017 quarter, a 6% decrease. Field operating costs were $.55 per Mcfe in the 2018 quarter as compared to $.74 per Mcfe in the 2017 quarter. The decrease in rate in the 2018 quarter is principally the result of significant new low-cost production coming on line late in fiscal 2017 and the first quarter of 2018 and the Company selling some marginal properties which had higher operating costs.

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The decrease in LOE related to field operating costs was offset with an increase in handling fees (primarily gathering, transportation and marketing costs) of $217,010 in the 2018 quarter compared to the 2017 quarter. On a per Mcfe basis, these handling fees were $0.54 in the 2018 quarter as compared to $0.58 in the 2017 quarter. The decrease in rate was due to significant new natural gas production coming on (since the 2017 quarter) with lower handling charges. Natural gas sales bear the large majority of the handling fees while oil 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 $135,423 or 3% in the 2018 quarter. DD&A in the 2018 quarter was $1.44 per Mcfe as compared to $1.75 per Mcfe in the 2017 quarter. DD&A increased $1,032,117 as a result of production increasing 25% in the 2018 quarter compared to the 2017 quarter. An offsetting decrease of $896,694 was the result of a $.31 decrease in the DD&A rate per Mcfe. The rate decrease is mainly due to higher oil, NGL and natural gas prices utilized in the reserve calculations during the 2018 quarter, as compared to the 2017 quarter, lengthening the economic life of wells thus resulting in higher projected remaining reserves on a significant number of wells. The Company had new high-volume wells with low finding costs begin producing in the latter half of 2017 and the first quarter of 2018, which also contributed to the rate decrease.

 

Interest Expense:

 

Interest expense increased $149,553 or 52% in the 2018 quarter. The increase was the result of higher average outstanding balances and a higher interest rate during the 2018 quarter as compared to the 2017 quarter.

Income Taxes:

Income taxes changed $827,000, from an $803,000 provision in the 2017 quarter to a $24,000 benefit in the 2018 quarter. This was mostly the result of the new Tax Cuts and Jobs Act enacted in December 2017 that reduces the US federal corporate tax rate from 35% to 21%. An estimate of the tax effects of this law change on our existing deferred tax liabilities of $173,000 was made in the 2018 quarter and is directly affecting the effective tax rate noted for this period. Additionally, due to the Company having a September 30 year end versus a calendar year end, we have calculated the current year’s federal tax provision using a blended rate of 24.53% to adjust for one quarter of our fiscal year being under the old rate of 35% and the remaining three quarters being under the new rate of 21%. The effective tax rate changed from a 19% provision in the 2017 quarter to a 2% benefit in the 2018 quarter.

When a provision for income taxes is expected for the year, federal and Oklahoma excess percentage depletion decreases the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is recorded.

 

SIX MONTHS ENDED MARCH 31, 2018– COMPARED TO SIX MONTHS ENDED MARCH 31, 2017

 

Overview:

 

The Company recorded a six month net income of $14,855,115, or $0.87 per share, in the 2018 period, as compared to net income of $1,232,041, or $0.07 per share, in the 2017 period. The change in net income (loss) was principally the result of increased tax benefits (due to new federal tax law), increases in oil, NGL and natural gas sales; partially offset by decreased lease bonuses and rentals, losses on derivative contracts and increased LOE, DD&A and interest expense. These items are further discussed below.

 

Oil, NGL and Natural Gas Sales:

 

Oil, NGL and natural gas sales increased $7,363,335 or 41% for the 2018 period. Oil, NGL and natural gas sales were up due to increases in oil and NGL prices of 24% and 32%, respectively, and increases oil, NGL and natural gas sales volumes of 22%, 86% and 26%, respectively, slightly offset by a decrease in natural gas sales prices of 4%. The following table outlines the Company’s production and average sales prices for oil, NGL and natural gas for the six-month periods of fiscal 2018 and 2017:

 

 

 

The oil production increase is primarily a result of the ten-well drilling program in the Eagle Ford Shale and the six-well program in the Anadarko Basin Woodford Shale. The increase was partially offset by the natural decline in oil production from the

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Bakken in North Dakota. The NGL production increase is attributed to the liquid-rich production from the six-well drilling program in the Anadarko Basin Woodford Shale. Increased gas production is realized from the eight-well drilling program in the southeastern Oklahoma Woodford Shale and the six-well program in the Anadarko Basin Woodford Shale. The gas production increase was partially offset by naturally declining production from the Fayetteville Shale and, to a much lesser extent, marginal property divestitures.

 

Lease Bonuses and Rentals:

Lease bonuses and rentals decreased $2,576,004 in the 2018 period. The decrease was mainly due to the Company completing mineral lease packages covering several counties in New Mexico and Oklahoma in the 2017 period. There were no significant lease packages in the 2018 period.

 

Gains (Losses) on Derivative Contracts:

 

The fair value of derivative contracts was a net liability of $1,970,359 as of March 31, 2018, and a net liability of $43,705 as of March 31, 2017. We had a net loss on derivative contracts of $1,837,828 in the 2018 period as compared to a net gain of $38,650 recorded in the 2017 period. The change is principally due to the oil collars and fixed price swaps being less favorable in the 2018 period, as NYMEX oil futures increased further above the ceiling of the collars and the fixed prices of the swaps. The natural gas collars and fixed price swaps in place during the 2018 period were very beneficial and the largest part of the gain from these contracts (covering January through March 2018 production) cash settled during the period. The Company utilizes derivative contracts for the purpose of protecting its return on investments.

 

Lease Operating Expenses (LOE):

 

LOE increased $689,366 or 11% in the 2018 period. LOE per Mcfe decreased in the 2018 period to $1.08 compared to $1.26 in the 2017 period. LOE related to field operating costs increased $46,730 in the 2018 period compared to the 2017 period, a 1% increase. Field operating costs were $.55 per Mcfe in the 2018 period as compared to $.71 per Mcfe in the 2017 period. The decrease in rate in the 2018 period is principally the result of significant new low-cost production coming on line late in fiscal 2017 and the first quarter of 2018 and the Company selling some marginal properties which had higher operating costs.

 

The increase in LOE related to field operating costs was coupled with an increase in handling fees (primarily gathering, transportation and marketing costs) of $642,636 in the 2018 period compared to the 2017 period. On a per Mcfe basis, these fees decreased $.03 due to significant new natural gas production coming on (since the 2017 period) with lower handling charges. Natural gas sales bear the large majority of the handling fees while oil 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 $576,984 or 6% in the 2018 period. DD&A in the 2018 period was $1.50 per Mcfe as compared to $1.84 per Mcfe in the 2017 period. DD&A increased $2,746,023 as a result of production increasing 31% in the 2018 period compared to the 2017 period. An offsetting decrease of $2,169,039 was the result of a $.34 decrease in the DD&A rate per Mcfe. The rate decrease is mainly due to higher oil, NGL and natural gas prices utilized in the reserve calculations during the 2018 period, as compared to 2017 period, lengthening the economic life of wells thus resulting in higher projected remaining reserves on a significant number of wells. The Company had new high-volume wells with low finding costs begin producing in the latter half of 2017 and the first quarter of 2018, which also contributed to the rate decrease.

 

Interest Expense:

 

Interest expense increased $288,763 or 50% in the 2018 period. The increase was the result of higher average outstanding balances and a higher interest rate during the 2018 period as compared to the 2017 period.

 

Income Taxes:

 

Income taxes changed $12,430,000, from a $304,000 benefit in the 2017 period to a $12,734,000 benefit in the 2018 period. This was mostly the result of the new Tax Cuts and Jobs Act enacted in December 2017 that reduces the US federal corporate tax rate from 35% to 21%. An estimate of the tax effects of this law change on our existing deferred tax liabilities of $12,825,000 was made in the 2018 period and is directly affecting the effective tax rate noted for this period. Additionally, due to the Company having a September 30 year end versus a calendar year end, we have calculated the current year’s federal tax provision using a blended rate of

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24.53% to adjust for one quarter of our fiscal year being under the old rate of 35% and the remaining three quarters being under the new rate of 21%. The effective tax rate changed from a 33% benefit in the 2017 period to a 600% benefit in the 2018 period.

 

When a provision for income taxes is expected for the year, federal and Oklahoma excess percentage depletion decreases the effective tax rate, while the effect is to increase the effective tax rate when a benefit for income taxes is recorded.

 

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, 2017.

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 price of oil, NGL and natural gas in 2018 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 2018 derivative contracts, the price sensitivity in 2018 for each $1.00 per barrel change in wellhead oil price is $310,677 for operating revenue based on the Company’s prior year oil volumes. The price sensitivity in 2018 for each $0.10 per Mcf change in wellhead natural gas price is $819,453 for operating revenue based on the Company’s prior year natural gas volumes.

Commodity Price Risk

The Company periodically utilizes derivative contracts to reduce its exposure to unfavorable changes in oil and natural gas 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 oil and natural gas 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 $220,000. 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 $97,000. For the Company’s natural gas fixed price swaps, a change of $.10 in the NYMEX Henry Hub forward strip pricing would result in a change to pre-tax operating income of approximately $201,000. 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 $73,000.

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 1.250%, or 30 day LIBOR plus from 1.875% to 2.750%. At March 31, 2018, the Company had $43,500,000 outstanding under this facility and the effective interest rate was 3.84%. At this point, the Company does not believe that its liquidity has been materially affected by the interest rate uncertainties noted in the last few years and the Company does not believe that its liquidity will be significantly impacted in the near future.

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 and Controller, 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

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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

During the three months ended March 31, 2018, the Company did not repurchased shares of the Company’s common stock.

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 up to an amount equal to the aggregate number of shares of common stock awarded pursuant to the Company’s Amended 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 becomes authorized and approved effective when the previous amount is utilized. 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.

 

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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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