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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

 

Nine Months Ended June 30, 2015

 

 

 

 

Nine Months Ended June 30, 2014

 

 

 

 

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 nine months ended June 30, 2015, was 32% as compared to 32% for the nine months ended June 30, 2014.  The effective tax rate for the quarter ended June 30, 2015, was -47% as compared to 33% for the quarter ended June 30, 2014. The higher estimated effective tax rate as of the end of the 2015 third quarter of 32%, as compared to 29% estimated at the end of the 2015 second quarter, resulted in a tax provision recorded during the 2015 third quarter. When a tax provision is recorded in a quarter with net loss (as opposed to a net income) before provision for income taxes, the result is a negative effective tax rate for the quarter, as was the case for the 2015 third quarter. 

 

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 borrowing base of  $120,000,000 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 $169,668,808 at June 30, 2015. The interest rate is based on BOK prime plus from 0.375% to 1.125%, or 30 day LIBOR plus from 1.875% to 2.625%. The election of BOK prime or LIBOR is at the Company’s discretion. The interest rate spread from BOK prime or LIBOR will be charged based on the ratio of the loan balance to the borrowing base. The interest rate spread from LIBOR or the prime rate increases as a larger percent of the borrowing base is advanced. At June 30, 2015, the effective interest rate was 2.31%.

 

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.

 

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On June 19, 2015, the borrowing base was adjusted by the banks from $130,000,000 to $120,000,000. 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 June 30, 2015, the Company was in compliance with the covenants of the loan agreement.

 

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, 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 upon a director’s retirement, termination, death, or a change-in-control of the Company will the shares recorded for such director under the Deferred Compensation Plan for Non-Employee Directors 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 adopted resolutions to allow 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 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 March 4, 2015, the Company awarded 11,828 non-performance based shares and 35,485 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 nonforfeitable rights to receive dividends and voting rights during the vesting period. The non-performance and performance based shares had a fair value on their award date of $213,969 and $432,207, respectively. The Company recognized $243,441 of compensation expense on the award date for performance based shares for officers that were eligible for retirement. The remaining fair value for the performance based awards as well as the entire fair value of the non-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 10, 2014, through December 10, 2017).

 

On March 4, 2015, the Company awarded 10,200 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, 2015. The restricted stock contains nonforfeitable rights to receive dividends and voting rights during the vesting period. These non-performance based shares had a fair value on their award date of $210,018.

 

The following table summarizes the Company’s pre-tax compensation expense for the three and nine months ended June 30, 2015 and 2014, 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-

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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 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.

 

NOTE 8: Impairment

 

All long-lived assets, principally oil and natural gas properties, are monitored for potential impairment when circumstances indicate that the carrying value of the asset may be greater than its estimated future net cash flows. The evaluations involve significant judgment since the results are based on estimated future events, such as inflation rates, future sales prices for oil, NGL and natural gas, future production costs, estimates of future oil, NGL and natural gas reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. The need to test a property for impairment may result from significant declines in sales prices or unfavorable adjustments to oil, NGL and natural gas reserves. Between periods in which reserves would normally be calculated, the Company updates the reserve calculations utilizing updated projected future price decks current with the period. For the three months ended June 30, 2015 and 2014, the assessment resulted in impairment provisions of $132,118 and $0, respectively. For the nine months ended June 30, 2015 and 2014, the assessment resulted in impairment provisions of $3,532,760 and $430,143, respectively. The impairment provisions for the three and nine months ended June 30, 2015, are principally the result of lower projected future prices for oil, NGL and natural gas. A reduction in oil, NGL or natural gas prices, or a decline in reserve volumes, could lead to additional impairment that may be material to the Company.

 

NOTE 9: Capitalized Costs

 

As of June 30, 2015 and 2014, non-producing oil and natural gas properties include costs of $355,567 and $888,505, 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

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settle based on the prices below.

 

Derivative contracts in place as of June 30, 2015

 

 

 

 

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 $5,402,106 as of June 30, 2015, and a net asset of $1,901,842 as of September 30, 2014.

 

 

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

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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 June 30, 2015, and September 30, 2014.  The Company has offset all amounts subject to master netting agreements in the Company's Condensed Balance Sheets at June 30, 2015, 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 June 30, 2015.

 

 

 

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

 

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

 

The significant unobservable inputs for Level 3 derivative contracts include market volatility and credit risk of counterparties. Changes in these inputs will impact the fair value measurement of our derivative contracts. An increase

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(decrease) in the volatility of oil and natural gas prices will decrease (increase) the fair value of oil and natural gas derivatives and adverse changes to our counterparties’ creditworthiness will decrease the fair value of our derivatives.

 

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

 

 

 

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

 

 

 

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

 

 

 

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

 

At June 30, 2015, 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 Counties, Texas, in the core of the Eagle Ford Shale. The assets were purchased from private sellers and included a 16% non-

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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  $81.5 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.

 

Actual and Pro Forma Impact of Acquisitions (Unaudited)

 

Revenues attributable to this acquisition included in the Company’s statement of operations for the quarter and nine months ended June 30, 2015, were $2,403,864 and $9,154,207, respectively. Net income (loss) attributable to the acquisition included in the statement of operations for the quarter and nine months ended June 30, 2015, was ($283,146) and $375,601, respectively. These amounts do not include gains on derivative contracts as noted on the Statement of Operations.

 

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, 2018. 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 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.

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LIQUIDITY AND CAPITAL RESOURCES

 

The Company had positive working capital of $7,812,814 at June 30, 2015,  compared to $9,919,037 at September 30, 2014.

 

Liquidity:

 

Cash and cash equivalents were $925,219 as of June 30, 2015, compared to $509,755 at September 30, 2014,  an increase of $415,464. Cash flows for the nine months ended June 30 are summarized as follows:

 

 

 

Operating activities:

 

Net cash provided by operating activities increased $909,266 during the 2015 period, as compared to the 2014 period, the result of the following:

 

 

 

 

 

 

 

Investing activities:

 

Net cash used in investing activities decreased $91,068,457 during the 2015  period, as compared to the 2014  period, due to:

 

 

 

 

Financing activities:

 

Net cash used in financing activities increased $90,206,145 during the 2015 period, as compared to the 2014 period, the result of the following:

 

 

Capital Resources:

 

Capital expenditures to drill and complete wells decreased $3,080,502 (12%) from the 2014 to the 2015 period. The decrease resulted primarily from the suspension of drilling activity in the Texas Eagle Ford Shale oil play late in the 2015 first

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quarter, combined with a significant decrease in well proposals to the Company in all of its other plays. Also, many of the well proposals we did receive did not meet our participation criteria. However, expenditures were made during the 2015 third quarter to complete five North Dakota Bakken Shale wells whose completion had previously been suspended awaiting higher oil prices and/or cost reductions. These wells began producing in late May. Other notable drilling and completion expenditures made during the 2015 third quarter related to activity on the Company’s mineral acreage in the SCOOP Woodford Shale and Springer plays in south central Oklahoma and the Arkansas Fayetteville Shale play.

 

Oil, NGL and natural gas production volumes increased 2% on an Mcfe basis during the 2015 period, as compared to the 2014 period. Oil production increased 55% principally due to production from the Eagle Ford Shale properties acquired in June 2014 and from drilling in the North Dakota Bakken Shale. These increases were partially offset by declining production from Texas Panhandle and western Oklahoma horizontal Cleveland, Marmaton and Granite Wash oil plays. During the second and third quarters of 2015, Eagle Ford Shale production was impacted by the delay of completion of six wells that were drilled in the first quarter of 2015. Five of the six wells are now scheduled to be completed beginning in August 2015 and production is expected to begin around October 1, 2015. Natural gas production decreased 7% as a result of declining production from the Arkansas Fayetteville Shale, declining associated natural gas production from western Oklahoma and Texas Panhandle horizontal Marmaton, Cleveland and Granite Wash oil plays and declines in the Northern Oklahoma Mississippian and Southeastern Oklahoma Woodford Shale. These decreases were partially offset by a production increase in the Anadarko Basin Woodford Shale in Oklahoma and the Eagle Ford Shale. NGL production increased 7% due to production from the Eagle Ford Shale and increased production from the Anadarko Basin Woodford Shale, partially offset by declining production from Texas Panhandle and western Oklahoma horizontal Cleveland, Marmaton and Granite Wash oil plays and in the Northern Oklahoma Mississippian and Southeastern Oklahoma Woodford Shale plays. Due to the Company receiving oil production from the Eagle Ford properties for all of 2015 (as compared to three and one-half months of fiscal 2014), combined with production from the five newly completed Bakken Shale wells, 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 discussed below. On an Mcfe basis, 2015 production volumes are expected to be slightly lower than that of 2014.

 

The Company expects the current reduced level of capital expenditures to continue during the 2015 fourth quarter as long as oil, NGL and natural gas prices remain at or near their current depressed levels. New oil production from the five newly completed Bakken Shale wells is expected to exceed the natural decline of existing wells, resulting in 2015 fourth quarter oil production exceeding that of the 2015 third quarter. Reduced capital expenditures are anticipated to result in marginally lower natural gas and NGL production volumes in the 2015 fourth quarter compared to the 2015 third quarter. Combined, lower product prices and production volumes, partially offset by realized gains on derivative contracts, are expected to result in cash provided by operating activities sufficient to fund capital expenditures, dividend payments and treasury stock purchases. Any excess cash is intended to be used 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. This makes 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:

 

 

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Outstanding borrowings on the credit facility at June 30, 2015, were $65,500,000.

 

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 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 ($54,500,000 at June 30, 2015) 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.

 

RESULTS OF OPERATIONS

 

THREE MONTHS ENDED JUNE 30, 2015 – COMPARED TO THREE MONTHS ENDED JUNE 30, 2014

 

Overview:

 

The Company recorded third quarter 2015 net loss of $728,946, or $0.04 per share, as compared to net income of $5,122,585, or $0.31 per share, in the 2014 quarter. The decrease in net income was principally the result of decreased oil, NGL and natural gas sales, increases in LOE, DD&A and interest expense; offset by increases in lease bonuses and rentals, decreased G&A, and decreased production and income taxes. These items are further discussed below.

 

Oil, NGL and Natural Gas Sales:

 

Oil, NGL and natural gas sales decreased $8,090,955 or 41% for the 2015 quarter. Oil, NGL and natural gas sales were down due to decreases in NGL and natural gas sales volumes of 34% and 4%, respectively, and decreases in oil, NGL and natural gas prices of 48%, 57% and 48%, respectively.  These decreases were partially offset by an increase in oil sales volumes of 56%.  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:

 

 

 

The oil production increase was principally the result of production from the Eagle Ford Shale properties which were acquired in June 2014 and, to a lesser extent, production from five North Dakota Bakken Shale wells that were completed and placed on production during the third quarter of 2015, offset by declining production from Texas Panhandle and western Oklahoma horizontal Cleveland, Marmaton and Granite Wash oil plays. The Eagle Ford Shale production in the second and third quarters of 2015 was impacted by the delay of completion of six wells that were drilled in the first quarter of 2015. Five of the six wells are now scheduled to be completed beginning in August 2015 and production is anticipated to begin around the first of October 2015. The decrease in natural gas production was the result of declining production from the Fayetteville Shale in Arkansas and declining associated natural gas production from the western Oklahoma horizontal Marmaton and Granite Wash oil plays partially offset by a production increase in the Anadarko Basin Woodford Shale in Oklahoma. The NGL production decrease resulted from declining production from Texas Panhandle and western Oklahoma horizontal Cleveland, Marmaton and Granite Wash oil plays, partially offset by production from the Eagle Ford Shale in Texas and increasing production due to drilling in the Anadarko Basin Woodford Shale in Oklahoma.

 

The Company anticipates that the current reduced level of capital expenditures will continue in the fourth quarter of 2015 as long as oil, NGL and natural gas prices remain at or near their current depressed levels. The Company anticipates that total equivalent production in 2015 will be slightly lower than that of 2014.

 

Production for the last five quarters was as follows:

 

 

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Lease Bonuses and Rentals:

 

Lease bonuses and rentals increased $1,525,926 in the 2015 quarter. The increase was mainly due to the Company leasing 2,407 net mineral acres in Andrews and Winkler Counties, Texas, for $1.2 million in the 2015 quarter.

 

Lease Operating Expenses (LOE):

 

LOE increased $1,109,884 or 37% in the 2015 quarter. LOE per Mcfe increased in the 2015 quarter to $1.23 compared to $0.89 in the 2014 quarter. LOE related to field operating costs increased $981,997 in the 2015 quarter compared to the 2014 quarter, a 66% increase. Field operating costs were $.75 per Mcfe in the 2015 quarter as compared to $.45 per Mcfe in the 2014 quarter. The increase in rate in the 2015 quarter is principally the result of the properties added in the Eagle Ford Shale acquisition on June 17, 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 coupled with an increase in handling fees (primarily gathering, transportation and marketing costs) of $127,887 in the 2015 quarter compared to the 2014 quarter. On a per Mcfe basis, these fees increased $.04 due mainly to prior period adjustments from operators. 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.

 

Production Taxes:

 

Production taxes decreased $231,393 or 39% in the 2015 quarter as compared to the 2014 quarter. This decrease in amount is primarily the result of decreased oil, NGL and natural gas sales of $8,090,955 during the 2015 quarter. Production taxes as a percentage of oil, NGL and natural gas sales increased from 3.0% in the 2014 quarter to 3.2% in the 2015 quarter.  

 

Depreciation, Depletion and Amortization (DD&A):

 

DD&A increased $414,683 or 8% in the 2015 quarter. DD&A in the 2015 quarter was $1.73 per Mcfe as compared to $1.61 per Mcfe in the 2014 quarter. DD&A increased $404,236 as a result of this $.12 increase in the DD&A rate per Mcfe. An additional increase of $10,447 was the result of production increasing .2% 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 in recent years.

 

Interest Expense

 

Interest expense increased $342,350 in the 2015 quarter, as compared to the 2014 quarter. The increase was due to a larger average outstanding debt balance in the 2015 quarter. The debt was used to purchase the Eagle Ford Shale properties on June 17, 2014.

 

General and Administrative Costs (G&A):

 

G&A costs decreased $259,799 or 14% in the 2015 quarter. This decrease is primarily related to decreases in personnel expenses of $252,281 due to lower anticipated discretionary compensation.

 

Income Taxes:

 

Provision for income taxes decreased in the 2015 quarter by $2,273,000, the result of an $8,124,531 decrease in income before provision for income taxes in the 2015 quarter compared to the 2014 quarter and a decrease in the effective tax rate from 33% in the 2014 quarter to -47% in the 2015 quarter. Excess percentage depletion, which is a permanent tax benefit, reduced the effective tax rate below the statutory rate for both quarters. The higher estimated effective tax rate as of the end of the 2015 third quarter of 32%, as compared to 29% estimated at the end of the 2015 second quarter, resulted in a tax provision recorded during the 2015 third quarter. When a tax provision is recorded in a quarter with net loss (as opposed to a net income) before provision for income taxes, the result is a negative effective tax rate for the quarter, as was the case for the 2015 third quarter.

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NINE MONTHS ENDED JUNE 30, 2015 – COMPARED TO NINE MONTHS ENDED JUNE 30, 2014

 

Overview:

 

The Company recorded nine month net income of $10,209,022, or $0.61 per share, in the 2015 period, as compared to $15,703,476, or $0.94 per share, in the 2014 period. The decrease in net income was principally the result of decreased oil, NGL and natural gas sales, and increases in provision for impairment, LOE, DD&A and interest expense; partially offset by gains on derivative contracts, increased lease bonuses and decreased production and income taxes. These items are further discussed below. 

 

Oil, NGL and Natural Gas Sales:

 

Oil, NGL and natural gas sales decreased $15,715,089 or 27% for the 2015 period. Oil, NGL and natural gas sales were down due to a decrease in natural gas sales volumes of 7% and decreases in oil, NGL and natural gas prices of 41%, 41% and 31%, respectively. These decreases were partially offset by increases in oil and NGL sales volumes of 55% and 7%, respectively. The following table outlines the Company’s production and average sales prices for oil, NGL and natural gas for the nine month periods of fiscal 2015 and 2014:

 

 

 

The oil production increase was principally the result of production from the Eagle Ford Shale properties in Texas which were acquired in June 2014 and from drilling in the North Dakota Bakken Shale, partially offset by declining production from Texas Panhandle and western Oklahoma horizontal Cleveland, Marmaton and Granite Wash oil plays. The Eagle Ford Shale production in the second and third quarters of 2015 was impacted by the delay of completion of six wells that were drilled in the first quarter of 2015. Five of the six wells are now scheduled to be completed beginning in August 2015 and production is anticipated to begin around the first of October 2015. The natural gas production decrease was the result of declining production in the Fayetteville Shale in Arkansas, declining associated natural gas production from western Oklahoma and Texas Panhandle horizontal oil plays, principally the Marmaton, Cleveland and Granite Wash, and from declines in the Northern Oklahoma Mississippian and the southeast Oklahoma Woodford Shale partially offset by increased production from the Anadarko Basin Woodford Shale in Oklahoma and from the Eagle Ford Shale in Texas. The NGL production increase was principally the result of increasing production due to drilling from the Anadarko Basin Woodford Shale and production from the Eagle Ford Shale, partially offset by declining production from Texas Panhandle and western Oklahoma horizontal Cleveland, Marmaton and Granite Wash oil plays and declining production in the Northern Oklahoma Mississippian and Southeastern Oklahoma Woodford Shale plays.

 

The Company anticipates that the current level of capital expenditures will continue in the fourth quarter of 2015 as long as oil, NGL and natural gas prices remain at or near their current depressed levels. The Company anticipates that total equivalent production in 2015 will be slightly lower than that of 2014.

 

Lease Bonuses and Rentals:

 

Lease bonuses and rentals increased $1,592,321 in the 2015 period. The increase was mainly due to the Company leasing 2,407 net mineral acres in Andrews and Winkler Counties, Texas, for $1.2 million in the 2015 period.

 

Gains (Losses) on Derivative Contracts:

 

The fair value of derivative contracts was a net asset of $5,402,106 as of June 30, 2015, and a net liability of $2,006,229 as of June 30, 2014. We had a net gain on derivative contracts of $11,706,955 in the 2015 period as compared to a net loss of $3,511,095 recorded in the 2014 period. 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 June  30, 2015, were well below the floor prices of the collars and well below the fixed price of the swaps.

 

Lease Operating Expenses (LOE):

 

LOE increased $3,303,833 or 33% in the 2015 period. LOE per Mcfe increased in the 2015 period to $1.26 compared to $0.96 in the 2014 period. LOE related to field operating costs increased $3,753,265 in the 2015 period compared to the 2014 period, a 83% increase. Field operating costs were $.79 per Mcfe in the 2015 period as compared to $.44 per Mcfe in the

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2014 period. The increase in rate in the 2015 period 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 offset by a decrease in handling fees (primarily gathering, transportation and marketing costs) of $449,432 in the 2015 period compared to the 2014 period. The decrease in the 2015 amount is the result of decreased gas production and sales. On a per Mcfe basis, these fees decreased $.05 due to significant increases in oil production, while gas production decreased. 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.

 

Production Taxes:

 

Production taxes decreased $487,321 or 26% in the 2015 period as compared to the 2014 period. The decrease in amount is primarily the result of decreased oil, NGL and natural gas sales of $15,715,089 during the 2015 period. Production taxes as a percentage of oil, NGL and natural gas sales was 3.2% for both the 2014 period and the 2015 period.  

 

Depreciation, Depletion and Amortization (DD&A):

 

DD&A increased $2,117,439 or 14% in the 2015 period. DD&A in the 2015 period was $1.68 per Mcfe as compared to $1.51 per Mcfe in the 2014 period. DD&A increased $1,825,101 as a result of this $.17 increase in the DD&A rate per Mcfe. An additional increase of $292,338 was the result of production increasing 2% in the 2015 period compared to the 2014 period. 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 $3,102,617 in the 2015 period compared to the 2014 period.  During the 2015 period, impairment of $3,532,760 was recorded on twenty 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 period, impairment of $430,143 was recorded on five 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 $1,154,359 in the 2015 period, as compared to the 2014 period. The increase was due to a larger average outstanding debt balance in the 2015 period. The debt was used to purchase the Eagle Ford Shale properties on June 17, 2014.

 

Income Taxes:

 

Provision for income taxes decreased in the 2015 period by $2,737,000, the result of an $8,231,454 decrease in pre-tax income in the 2015 period compared to the 2014 period. The effective tax rate for both the 2015 and 2014 periods was 32%. Excess percentage depletion, which is a permanent tax benefit, reduced the effective tax rate below the statutory rate for both periods.

 

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

 

Critical accounting policies are those the Company believes are most important to portraying its financial conditions and results of operations and also require the greatest amount of subjective or complex judgments by management. Judgments and uncertainties regarding the application of these policies may result in materially different amounts being reported under various conditions or using different assumptions. There have been no material changes to the critical accounting policies previously disclosed in the Company’s Form 10-K for the fiscal year ended September 30, 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 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 

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derivative contracts, the price sensitivity for each $0.10 per Mcf change in wellhead natural gas price is $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 $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 $93,000. 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 $152,000. 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 $58,000.  

 

Financial Market Risk

 

Operating income could also be impacted, to a lesser extent, by changes in the market interest rates related to the Company’s credit facilities. The revolving loan bears interest at the BOK prime rate plus from 0.375% to 1.125%, or 30 day LIBOR plus from 1.875% to 2.625%. At June 30, 2015, the Company had $65,500,000 outstanding under this facility. And the effective interest rate was 2.31%. At this point, the Company does not believe that its liquidity has been materially affected by the debt market uncertainties noted in the last few years and the Company does not believe that its liquidity will be impacted in the near future.

 

ITEM 4  CONTROLS AND PROCEDURES

 

The Company maintains “disclosure controls and procedures,” as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, that are designed to ensure that information required to be disclosed in reports the Company files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and that such information is collected and communicated to management, including the Company’s President/Chief Executive Officer and Vice President/Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating its disclosure controls and procedures, management recognized that no matter how well conceived and operated, disclosure controls and procedures can provide only reasonable, not absolute, assurance that the objectives of the disclosure controls and procedures are met. The Company’s disclosure controls and procedures have been designed to meet, and management believes they do meet, reasonable assurance standards. Based on their evaluation as of the end of the fiscal period covered by this report, the Chief Executive Officer and Chief Financial Officer have concluded, subject to the limitations noted above, the Company’s disclosure controls and procedures were effective to ensure material information relating to the Company is made known to them. There were no changes in the Company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting made during the fiscal quarter or subsequent to the date the assessment was completed.

 

PART II  OTHER INFORMATION

 

ITEM 2   UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS 

 

During the three months ended June 30, 2015, the Company repurchased shares of the Company’s common stock as summarized in the table below.

 

 

 

 

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

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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 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 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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