MEXCO ENERGY CORP - Quarter Report: 2017 December (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended December 31, 2017

OR

[  ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                   to

Commission File No. 1-31785

MEXCO ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

(432) 682-1119

(Registrant’s telephone number, including area code)

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 and (2) has been subject to such filing requirements for the past 90 days. YES [X] 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 (§ 229.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [X] No [  ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company as defined in Rule 12b-2 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 [X]

The number of shares outstanding of the registrant’s common stock, par value $.50 per share, as of February 12, 2018 was 2,037,266.

MEXCO ENERGY CORPORATION

Mexco Energy Corporation and Subsidiaries

CONSOLIDATED BALANCE SHEETS

(Unaudited)

The accompanying notes are an integral part of

the consolidated financial statements.

Mexco Energy Corporation and Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

The accompanying notes are an integral part of

the consolidated financial statements.

Mexco Energy Corporation and Subsidiaries

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

(Unaudited)

The accompanying notes are an integral part of

the consolidated financial statements.

Mexco Energy Corporation and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Nine Months Ended December 31,

(Unaudited)

The accompanying notes are an integral part of

the consolidated financial statements.

Mexco Energy Corporation and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Nature of Operations

Mexco Energy Corporation (a Colorado corporation) and its wholly owned subsidiaries, Forman Energy Corporation (a New York corporation), Southwest Texas Disposal Corporation (a Texas corporation) and TBO Oil & Gas, LLC (a Texas limited liability company) (collectively, the “Company”) are engaged in the exploration, development and production of natural gas, crude oil, condensate and natural gas liquids (“NGLs”). Most of the Company’s oil and gas interests are centered in West Texas; however, the Company owns producing properties and undeveloped acreage in thirteen states. Although the Company’s oil and gas interests predominately are operated by others, the Company operates five wells in which it owns an interest.

2. Basis of Presentation and Significant Accounting Policies

Principles of Consolidation. The consolidated financial statements include the accounts of Mexco Energy Corporation and its wholly owned subsidiaries. All significant intercompany balances and transactions associated with the consolidated operations have been eliminated.

Estimates and Assumptions. In preparing financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”), management is required to make informed judgments, estimates and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. In addition, significant estimates are used in determining proved oil and gas reserves. Although management believes its estimates and assumptions are reasonable, actual results may differ materially from those estimates. The estimate of the Company’s oil and natural gas reserves, which is used to compute depreciation, depletion, amortization and impairment of oil and gas properties, is the most significant of the estimates and assumptions that affect these reported results.

Interim Financial Statements. In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments (including normal recurring accruals) necessary to present fairly the financial position of the Company as of December 31, 2017, and the results of its operations and cash flows for the interim periods ended December 31, 2017 and 2016. The consolidated financial statements as of December 31, 2017 and for the three and nine month periods ended December 31, 2017 and 2016 are unaudited. The consolidated balance sheet as of March 31, 2017 was derived from the audited balance sheet filed in the Company’s 2017 annual report on Form 10-K filed with the Securities and Exchange Commission (“SEC”). The results of operations for the periods presented are not necessarily indicative of the results to be expected for a full year. The accounting policies followed by the Company are set forth in more detail in Note 2 of the “Notes to Consolidated Financial Statements” in the Form 10-K. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the SEC. However, the disclosures herein are adequate to make the information presented not misleading. It is suggested that these financial statements be read in conjunction with the financial statements and notes thereto included in the Form 10-K.

Reclassifications. Certain amounts in prior periods’ consolidated financial statements have been reclassified to conform with the current period’s presentation. These reclassifications had no effect on previously reported results of operations, retained earnings or net cash flows.

3. Property Sales

In December 2017, the Company received approximately $1.9 million in cash from a sale of joint venture leasehold marginal producing working interests in several thousand acres located in Ward and Midland Counties, Texas. Of these proceeds, approximately $1.518 million was applied to the Company’s bank debt and the balance to the Company’s working capital. Additionally, approximately $200,000 of the purchase price is being held in escrow pending payment of closing costs and resolution of title issues as to a small portion of the sale assets. This amount is reflected in accounts receivable escrow on our consolidated balance sheets.

During the first nine months of fiscal 2018, the Company sold for a total consideration of $460,461, leasehold interests in 137 net acres in the Scoop-Stack areas of Canadian and Grady Counties, Oklahoma. The first of these transactions in which the Company retained its interests in the existing producing wellbores on the acreage was in the amount of $336,730. The second transaction in the amount of $123,731 included the producing wellbores as well as the acreage. Of these proceeds, $410,000 was applied to reduce bank indebtedness and the balance of $50,461 was applied to working capital of the Company.

Subsequently, in January 2018, the Company sold additional leasehold interests in the Scoop-Stack area of Grady County, Oklahoma for $46,000 which the Company used to reduce bank indebtedness. The Company retained its interests in the existing producing wellbore on the acreage.

4. Asset Retirement Obligations

The Company’s asset retirement obligations (“ARO”) relate to the plugging of wells, the removal of facilities and equipment, and site restoration on oil and gas properties. The fair value of a liability for an ARO is recorded in the period in which it is incurred, discounted to its present value using the credit adjusted risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted each period, and the capitalized cost is depreciated as part of oil and gas properties, using the full cost method. The ARO is included in the Consolidated Balance Sheets with the current portion being included in the accounts payable and other accrued expenses.

The following table provides a rollforward of the AROs for the first nine months of fiscal 2018:

5. Credit Facility

The Company has a loan agreement with Bank of America, N.A. (the “Agreement”), which provided for a credit facility of $5,570,000 with no monthly commitment reductions and a borrowing base to be evaluated on July 30 and January 1 of each year or at any additional time in the bank’s discretion. The borrowing base was evaluated on January 26, 2018 and set at $950,000. The borrowing base also resets to the extent the Company sells or otherwise disposes of any of its oil and gas properties as the Company is required to pay 100% of such net proceeds to the lender resulting in a permanent reduction of the borrowing base unless prior approval by the bank states otherwise.

The Agreement was renewed eleven times with the eleventh amendment effective as of March 8, 2017 with a maturity date of November 30, 2020. Under such renewal agreement, interest on the facility accrues at an annual rate equal to the British Bankers Association London Interbank Offered Rate (“BBA LIBOR”) daily floating rate, plus 3.0 percentage points, which was 4.56% on December 31, 2017. Interest on the outstanding amount under the credit agreement is payable monthly. There was no availability of this line of credit at December 31, 2017. No principal payments are anticipated to be required through November 30, 2020. Amounts borrowed under the Agreement are collateralized by the common stock of the Company’s wholly owned subsidiaries and substantially all of the Company’s oil and gas properties.

The Agreement contains customary covenants for credit facilities of this type including limitations on change in control, disposition of assets, mergers and reorganizations. The Company is also obligated to meet certain financial covenants under the Agreement and requires minimum earnings before interest, taxes, depreciation and amortization (“EBITDA”) of $650,000 for each trailing four fiscal quarters and minimum interest coverage ratios (EBITDA/Interest Expense) of 2.00 to 1.00 for each quarter. The Company is in compliance with all covenants as of December 31, 2017 and believes it will remain in compliance for the next fiscal year.

In addition, this Agreement prohibits the Company from paying cash dividends on its common stock. The Agreement does grant the Company permission to enter into hedge agreements however, it is under no obligation to do so.

The Agreement allows for up to $500,000 of the facility to be used for outstanding letters of credit. As of December 31, 2017, one letter of credit for $50,000, in lieu of plugging bond with the Texas Railroad Commission (“TRRC”) covering the properties the Company operates is outstanding under the facility. This letter of credit renews annually. The Company will pay a fee in an amount equal to 1 percent (1.0%) per annum of the outstanding undrawn amount of each standby letter of credit, payable monthly in arrears, on the basis of the face amount outstanding on the day the fee is calculated.

The balance outstanding on the line of credit as of December 31, 2017 was $950,000. The following table is a summary of activity on the Bank of America, N.A. line of credit for the nine months ended December 31, 2017:

The balance outstanding on the line of credit as of February 12, 2018 was $900,000.

6. Income Taxes

On December 22, 2017, the tax legislation referred to as the “Tax Cuts and Jobs Act” (the 2017 Tax Reform Act) was enacted. The more significant changes that impact the Company are the reduction in the corporate federal income tax rate from 35% to 21%. Under GAAP, the tax effects of a change in tax law must be recognized in the period in which the law is enacted, or the quarter ending December 31, 2017 for the 2017 Tax Reform Act. GAAP also requires deferred income tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. The Company’s deferred income taxes were remeasured based upon the new tax rates which amounted to a $509,863 reduction in deferred tax asset and valuation amount.

A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, and we consider the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry.

Based on the material write-downs of the carrying value of our oil and natural gas properties during fiscal 2016, we are in a net deferred tax asset position as of December 31, 2017. Our deferred tax asset is $822,425 as of December 31, 2017 with a valuation amount of $822,425. We believe it is more likely than not that these deferred tax assets will not be realized. Management assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future taxable income are increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as future expected growth.

7. Loss Per Common Share

The Company’s basic net loss per share has been computed based on the weighted average number of common shares outstanding during the period. Diluted net loss per share assumes the exercise of all stock options having exercise prices less than the average market price of the common stock during the period using the treasury stock method and is computed by dividing net loss by the weighted average number of common shares and dilutive potential common shares (stock options) outstanding during the period. In periods where losses are reported, the weighted-average number of common shares outstanding excludes potential common shares, because their inclusion would be anti-dilutive.

The following is a reconciliation of the number of shares used in the calculation of basic net loss per share and diluted loss per share for the three and nine month periods ended December 31, 2017 and 2016:

Due to a net loss for the three and nine months ended December 31, 2017 and 2016, the weighted average number of common shares outstanding excludes common stock equivalents because their inclusion would be anti-dilutive.

8. Related Party Transactions

Related party transactions for the Company relate to shared office expenditures in addition to administrative and operating expenses paid on behalf of the principal stockholder. The total billed to and reimbursed by the stockholder for the three months ended December 31, 2017 and 2016 was $11,873 and $9,565, respectively. The total billed to and reimbursed by the stockholder for the nine months ended December 31, 2017 and 2016 was $30,355 and $22,061, respectively.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Unless the context otherwise requires, references to the “Company”, “Mexco”, “we”, “us” or “our” mean Mexco Energy Corporation and its consolidated subsidiaries.

Cautionary Statements Regarding Forward-Looking Statements. Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Forward-looking statements include statements regarding our plans, beliefs or current expectations and may be signified by the words “could”, “should”, “expect”, “project”, “estimate”, “believe”, “anticipate”, “intend”, “budget”, “plan”, “forecast”, “predict” and other similar expressions. Forward-looking statements appear throughout this Form 10-Q with respect to, among other things: profitability; planned capital expenditures; estimates of oil and gas production; future project dates; estimates of future oil and gas prices; estimates of oil and gas reserves; our future financial condition or results of operations; and our business strategy and other plans and objectives for future operations. Forward-looking statements involve known and unknown risks and uncertainties that could cause actual results to differ materially from those contained in any forward-looking statement.

While we have made assumptions that we believe are reasonable, the assumptions that support our forward-looking statements are based upon information that is currently available and is subject to change. All forward-looking statements in the Form 10-Q are qualified in their entirety by the cautionary statement contained in this section. We do not undertake to update, revise or correct any of the forward-looking information. It is suggested that these financial statements be read in conjunction with the financial statements and notes thereto included in the Form 10-K.

Liquidity and Capital Resources. Historically, we have funded our operations, acquisitions, exploration and development expenditures from cash generated by operating activities, bank borrowings, sales of non-core properties and issuance of common stock. Our primary financial resource is our base of oil and gas reserves. We pledge our producing oil and gas properties to secure our revolving line of credit. We do not have any delivery commitments to provide a fixed and determinable quantity of its oil and gas under any existing contract or agreement.

Due to depressed commodity price environment, we are applying financial discipline to all aspects of our business. In order to meet obligations, we may continue to sell non-core assets.

Our long term strategy is on increasing profit margins while concentrating on obtaining reserves with low cost operations by acquiring and developing oil and gas properties with potential for long-lived production. We focus our efforts on the acquisition of minerals, royalties and working interests and non-operated properties in areas with significant development potential.

For the first nine months of fiscal 2018, cash flow from operations was $153,136, a 4404% increase when compared to the corresponding period of fiscal 2017. Cash of $2,548,135 was received from the sale of oil and gas properties, cash of $74,744 was received for drilling refunds, cash of $1,950,000 was used to reduce the line of credit, and cash of $802,184 was used for additions to oil and gas properties. Accordingly, net cash increased $23,831.

At December 31, 2017, we had working capital of $534,037 compared to working capital of $367,675 at March 31, 2017, an increase of $166,362 for the reasons set forth below.

Oil and Natural Gas Properties

In addition to an indeterminate number of wells to be drilled by other operators on Mexco’s royalty interests, the Company currently expects to participate in the drilling and completion of approximately 30 horizontal wells at an estimated aggregate cost of approximately $1,200,000 for the fiscal year ending March 31, 2018. The operators of these wells include Concho Resources, Inc., Marathon Oil Permian LLC, McElvain Energy, Inc., Mewbourne Oil Company, XTO Energy, Inc. and others.

As of December 31, 2017, Mexco has expended approximately $700,000 for seventeen of these horizontal wells located in the Delaware Basin.

The first two of these wells began producing in September at an initial average rate of 288 barrels of oil; 1,308 barrels of water; and 332,000 cubic feet of gas per day, or 343 barrels of oil equivalent per day. The third well began producing in November at an initial rate of 245 barrels of oil; 1,053 barrels of water; and 247,000 cubic feet of gas per day, or 286 barrels of oil equivalent per day. These wells are in the Yeso/Paddock formations of the Dodd Federal Unit in the Grayburg San Andres Jackson Field of Eddy County, New Mexico and operated by Concho Resources, Inc. Mexco’s working interest in this unit is .1848%.

The next three of these wells were completed in December 2017 and tested at an average rate of 1,162 barrels of oil; 2,283 barrels of water; and 1,991,000 cubic feet of gas per day, or 1,494 barrels of oil equivalent per day, with an average flowing tubing pressure of 647 pounds per square inch. These wells are in the Lower Avalon formation located in Lea County, New Mexico. Mexco’s working interest in these wells is .6%.

The remaining eleven of these seventeen wells have been drilled and are in various stages of completion.

During the first nine months of fiscal 2018, the Company sold for a total consideration of $460,461, leasehold interests in 137 net acres in the Scoop-Stack areas of Canadian and Grady Counties, Oklahoma. The first of these transactions in which the Company retained its interests in the existing producing wellbores on the acreage was in the amount of $336,730. The second transaction in the amount of $123,731 included the producing wellbores as well as the acreage. Of these proceeds, $410,000 was applied to reduce bank indebtedness and the balance of $50,461 was applied to working capital of the Company.

Subsequently, in January 2018, the Company sold additional leasehold interests in the Scoop-Stack area of Grady County, Oklahoma for $46,000 which the Company used to reduce bank indebtedness. The Company retained its interests in the existing producing wellbore on the acreage.

In December 2017, the Company received approximately $1.9 million in cash from a sale of joint venture leasehold marginal producing working interests in several thousand acres located in Ward and Midland Counties, Texas. Of these proceeds, approximately $1.518 million was applied to the Company’s bank debt and the balance to the Company’s working capital. Additionally, approximately $200,000 of the purchase price is being held in escrow pending payment of closing costs and resolution of title issues as to a small portion of the sale assets. This amount is reflected in accounts receivable escrow on our consolidated balance sheets.

We are participating in other projects and are reviewing projects in which we may participate. The cost of such projects would be funded, to the extent possible, from existing cash balances, cash flow from operations and sales of non-core properties.

Crude oil and natural gas prices remained significantly depressed during the last year. Lower product prices reduce our cash flow from operations and diminish the present value of our oil and gas reserves. Lower product prices also offer us less incentive to assume the drilling risks that are inherent in our business. The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. For example in the last twelve months, the West Texas Intermediate (“WTI”) posted price for crude oil has ranged from a low of $39.00 per bbl in June 2017 to a high of $56.75 per bbl in December 2017. The Henry Hub Spot Market Price (“Henry Hub”) for natural gas has ranged from a low of $2.44 per MMBtu in February 2017 to a high of $3.71 per MMBtu in January 2017. On December 31, 2017 the WTI posted price for crude oil was $56.75 per bbl and the Henry Hub spot price for natural gas was $3.69 per MMBtu.

Contractual Obligations. We have no off-balance sheet debt or unrecorded obligations and have not guaranteed the debt of any other party. The following table summarizes our future payments we are obligated to make based on agreements in place as of December 31, 2017:

Results of Operations – Three Months Ended December 31, 2017 and 2016. For the quarter ended December 31, 2017, the net loss of $101,228 compared to a net loss of $159,741 for the quarter ended December 31, 2016 was a result of an increase in oil and gas revenues partially offset by an increase in total operating expenses as further explained below.

Oil and gas sales. Revenue from oil and gas sales was $641,468 for the third quarter of fiscal 2018, an 11% increase from $580,419 for the same period of fiscal 2017. This resulted from an increase in oil and gas prices partially offset by a decrease in oil and gas production. This decrease in production was primarily due to the sale of our operated oil and gas properties in Pecos County, Texas and to a lesser extent, the shut-in of current production in certain fields with drilling and completion activities. The following table sets forth our oil and gas revenues, production quantities and average prices received during the three months ended December 31, 2017 and 2016:

Production and exploration. Production costs were $248,865 for the third quarter of fiscal 2018, a 6% increase from $234,372 for the same period of fiscal 2017. This increase is primarily the result of an increase in lease operating expense for well repairs on non-operated properties and an increase in production taxes due to the increase in oil and gas sales.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense was $247,801 for the third quarter of fiscal 2018, a 10% decrease from $273,885 for the same period of fiscal 2017, primarily due to a decrease in oil and gas production and the full cost pool as a result of oil and gas property sales. And additionally due to an increase in oil and gas reserves partially offset by an increase in future development costs.

General and administrative expenses. General and administrative expenses were $225,528 for the third quarter of fiscal 2018, a 13% increase from $199,995 for the same period of fiscal 2017. This was primarily due to an increase in engineering services, accounting fees, and salaries partially offset by a decrease in stock option compensation expense and insurance expense.

Interest expense. Interest expense was $25,360 for the third quarter of fiscal 2018, a 22% decrease from $32,378 for the same period of fiscal 2017, due to a decrease in borrowings partially offset by an increase in interest rate.

Income taxes. There was no income tax for the quarter ended December 31, 2017 and the quarter ended December 31, 2016. The effective tax rate for the three months ended December 31, 2017 and December 31, 2016 was 0%. We are in a net deferred tax asset position and believe it is more likely than not that these deferred tax assets will not be realized.

Results of Operations – Nine Months Ended December 31, 2017 and 2016. For the nine months ended December 31, 2017, the net loss of $585,950 compared to a net loss of $691,099 for the nine months ended December 31, 2016 was a result of an increase in operating revenues partially offset by an increase in total operating expenses as further explained below.

Oil and gas sales. Revenue from oil and gas sales was $1,903,361 for the nine months ended December 31, 2017, a 14% increase from $1,662,985 for the same period of fiscal 2017. This resulted from an increase in oil and gas prices partially offset by a decrease in oil and gas production. This decrease in production was primarily due to the sale of our operated oil and gas properties in Pecos County, Texas and to a lesser extent, the shut-in of current production in certain fields with drilling and completion activities. The following table sets forth our oil and gas revenues, production quantities and average prices received during the nine months ended December 31, 2017 and 2016:

Other operating revenue. Other operating revenue was $38,342 for the nine months ended December 31, 2017 compared to $178,174 for the nine months ended December 31, 2016 due to the settlement of a lawsuit for underpayment of royalties from Chesapeake Energy Corporation and Total E & P USA in the amount of $148,614 during fiscal 2017.

Production and exploration. Production costs were $813,570 for the nine months ended December 31, 2017, a 13% increase from $721,864 for the nine months ended December 31, 2016. This was primarily the result of an increase in lease operating expenses and production taxes due to the increase in oil and gas revenue.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense was $844,566 for the nine months ended December 31, 2017, a 4% decrease from $879,637 for the nine months ended December 31, 2016, primarily due to a decrease in oil and gas production and the full cost pool as a result of oil and gas property sales. And additionally due to an increase in oil and gas reserves partially offset by an increase in future development costs.

General and administrative expenses. General and administrative expenses were $765,056 for the nine months ended December 31, 2017, a 2% decrease from $780,608 for the nine months ended December 31, 2016. This was primarily due to our efforts to apply financial discipline in all areas of our business resulting in a decrease in engineering services, insurance expense, legal fees and stock option compensation expense partially offset by an increase in accounting fees and salaries.

Interest expense. Interest expense was $79,310 for the nine months ended December 31, 2017, a 36% decrease from $123,385 for the nine months ended December 31, 2016 due to a decrease in borrowings partially offset by an increase in interest rate.

Income taxes. There was no income tax for the nine months ended December 31, 2017 and for the nine months ended December 31, 2016. The effective tax rate for the nine months ended December 31, 2017 and December 31, 2016 was 0%. We are in a net deferred tax asset position and believe it is more likely than not that these deferred tax assets will not be realized.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The primary sources of market risk for us include fluctuations in commodity prices and interest rates. All of our financial instruments are for purposes other than trading.

Interest Rate Risk. At December 31, 2017, we had an outstanding loan balance of $950,000 under our revolving credit agreement, which bears interest at an annual rate equal to the BBA LIBOR daily floating rate, plus 3.0 percentage points. If the interest rate on our bank debt increases or decreases by one percentage point, our annual pretax income would change by $9,500 based on the outstanding balance at December 31, 2017.

Credit Risk. Credit risk is the risk of loss as a result of nonperformance by other parties of their contractual obligations. At December 31, 2017, our largest credit risk was $200,000 or 32% of our total accounts receivables which related to escrow pending payment of closing costs on our property sale in Midland and Ward Counties, Texas. Our primary credit risk is related to oil and gas production sold to various purchasers and the receivables are generally not collateralized. At December 31, 2017, our largest credit risk associated with any single purchaser was $68,330 or 17% of our total oil and gas receivables. We are also exposed to credit risk in the event of nonperformance from any of our working interest co-owners. At December 31, 2017, our largest credit risk associated with any working interest partner was $8,718 or 29% of our total trade receivables. We have not experienced any significant credit losses.

Energy Price Risk. Our most significant market risk is the pricing for natural gas and crude oil. Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. Prices for oil and natural gas fluctuate widely. We cannot predict future oil and natural gas prices with any certainty. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile.

Factors that can cause price fluctuations include the level of global demand for petroleum products, foreign and domestic supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability of alternative fuels and overall political and economic conditions in oil producing countries.

Declines in oil and natural gas prices will materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Changes in oil and gas prices impact both estimated future net revenue and the estimated quantity of proved reserves. Any reduction in reserves, including reductions due to price fluctuations, can reduce the borrowing base under our revolving credit facility and adversely affect the amount of cash flow available for capital expenditures and our ability to obtain additional capital for our acquisition, exploration and development activities. In addition, a noncash write-down of our oil and gas properties could be required under full cost accounting rules if prices declined significantly, even if it is only for a short period of time. Lower prices may also reduce the amount of crude oil and natural gas that can be produced economically. Thus, we may experience material increases or decreases in reserve quantities solely as a result of price changes and not as a result of drilling or well performance.

Similarly, any improvements in oil and gas prices can have a favorable impact on our financial condition, results of operations and capital resources. Oil and natural gas prices do not necessarily fluctuate in direct relationship to each other. Our financial results are more sensitive to movements in oil prices than gas prices because most of our production is oil. If the average oil price had increased or decreased by ten dollars per barrel for the first nine months of fiscal 2018, pretax income or loss would have changed by $261,780. If the average gas price had increased or decreased by one dollar per mcf for the first nine months of fiscal 2018, pretax income or loss would have changed by $250,049.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures. We maintain disclosure controls and procedures to ensure that the information we must disclose in our filings with the SEC is recorded, processed, summarized and reported on a timely basis. At the end of the period covered by this report, our principal executive officer and principal financial officer reviewed and evaluated the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rules 13a-15(f). Based on such evaluation, such officers concluded that, as of December 31, 2017, our disclosure controls and procedures were effective.

Changes in Internal Control over Financial Reporting. No changes in our internal control over financial reporting occurred during the nine months ended December 31, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. We are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under various environmental protection statutes or other regulations to which we are subject.

Item 1A.Risk Factors

There have been no material changes to the information previously disclosed in Item 1A. “Risk Factors” in our 2017 Annual Report on Form 10-K.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None

Item 3. Defaults Upon Senior Securities

None

Item 4. Mine Safety Disclosures

None

Item 5. Other Information

None

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.