MEXCO ENERGY CORP - Quarter Report: 2016 December (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

For the quarterly period ended December 31, 2016

OR

For the transition period from ______________ to ______________

Commission File No. 0-6994

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 9, 2017 was 2,037,266.

MEXCO ENERGY CORPORATION

Table of Contents

PART I – FINANCIAL INFORMATION

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 predominately all of the Company’s oil and gas interests 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, 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 (consisting only of normal recurring accruals) necessary to present fairly the financial position of the Company as of December 31, 2016, and the results of its operations and cash flows for the interim periods ended December 31, 2016 and 2015. The financial statements as of December 31, 2016 and for the three and nine month periods ended December 31, 2016 and 2015 are unaudited. The consolidated balance sheet as of March 31, 2016 was derived from the audited balance sheet filed in the Company’s 2016 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.

Recent Accounting Pronouncements. In August 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2016-15, “Statement of Cash Flows (Topic 230)”, which is intended to reduce diversity in practice in how certain transactions are classified in the statement of cash flows. The guidance addresses eight specific cash flow issues for which current GAAP is either unclear or does not include specific guidance. The guidance is effective for annual periods beginning after December 15, 2017 and interim periods within those annual periods. Early adoption is permitted, provided that all of the amendments are adopted in the same period. This guidance must be adopted using a retrospective transition method. The Company is currently evaluating the effect that adopting this guidance will have on its cash flows.

In March 2016, the FASB issued ASU No. 2016-09, “Compensation – Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting”. The amendment is to simplify several aspects of the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The amendments in ASU No. 2016-09 are effective for interim and annual reporting periods beginning after December 15, 2016. The Company is currently assessing the impact of ASU No. 2016-09 on the consolidated financial statements.

In February 2016, the FASB issued ASU 2016-02, Topic 842 Leases, which requires companies to recognize a right of use asset and related liability on the balance sheet for the rights and obligations arising from leases with durations greater than 12 months. The standard is effective for fiscal years beginning after December 15, 2018, and interim periods thereafter. Early adoption is permitted. We are currently evaluating the effect the new guidance will have on our consolidated financial statements.

In January 2016, the FASB issued authoritative guidance that amends existing requirements on the classification and measurement of financial instruments. The standard principally affects accounting for equity investments and financial liabilities where the fair value option has been elected. The guidance is effective for fiscal periods after December 15, 2017, and interim periods thereafter. Early adoption of certain provisions is permitted. We are currently evaluating the effect the new guidance will have on our financial statements.

In November 2015, the FASB issued ASU No. 2015-17, Topic 740 Income Taxes: Balance Sheet Classification of Deferred Taxes which requires all deferred income tax liabilities and assets to be presented as noncurrent in a classified balance sheet. Currently, entities are required to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified balance sheet. The new standard will become effective for Mexco beginning on April 1, 2017, with the option to early adopt, and can be applied either prospectively or retrospectively. The adoption of this guidance will have no impact on our results of operations or cash flows. The reclassification of amounts from current to noncurrent could affect the presentation of our balance sheet.

In May 2014, the FASB issued ASU No. 2014-09, Topic 606: Revenue from Contracts with Customers. This ASU provides guidance concerning the recognition and measurement of revenue from contracts with customers. The effective date for ASU 2014-09 was delayed through the issuance of ASU 2015-14, Revenue from Contracts with Customers – Deferral of the Effective Date, to annual and interim periods beginning after December 15, 2017 and is required to be adopted using either the retrospective or cumulative effect transition method, with early adoption permitted in 2017. Additionally, in March 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus agent considerations (reporting revenue gross versus net), which clarifies the implementation guidance on principal versus agent considerations on such matters. In April 2016, the FASB issued ASU No. 2016-10, Revenue from Contracts with Customers (Topic 606): Identifying performance obligations and licensing, which clarifies guidance related to identifying performance obligations and licensing implementation guidance contained in the new revenue recognition standard. In May 2016, the FASB issued ASU No. 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-scope improvements and practical expedients, which addresses narrow-scope improvements to the guidance on collectibility, non-cash consideration, and completed contracts at transition. In December 2016, the FASB issued ASU No. 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. These amendments intended to improve and clarify the implementation guidance of Topic 606. Additionally, the amendments in this update provide a practical expedient for contract modifications at transition and an accounting policy election related to the presentation of sales taxes and other similar taxes collected from customers. Management is evaluating the effect, if any, this pronouncement will have on our consolidated financial statements.

3. 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 over the useful life of the related asset. 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 2017:

4. Stock-based Compensation

The Company recognized stock-based compensation expense of $10,738 and $23,873 in general and administrative expense in the Consolidated Statements of Operations for the three months ended December 31, 2016 and 2015, respectively. Compensation expense recognized for the nine months ended December 31, 2016 and 2015 was $42,424 and $95,770, respectively. The total cost related to non-vested awards not yet recognized at December 31, 2016 totals $35,860 which is expected to be recognized over a weighted average of 1.29 years.

The following table is a summary of activity of stock options for the nine months ended December 31, 2016:

There were no options granted during the nine months ended December 31, 2016 and 2015. During the nine months ended December 31, 2016, 3,000 vested and 1,000 unvested stock options were forfeited due to the resignation of an employee.

Outstanding options at December 31, 2016 expire between August 2020 and August 2024 and have exercise prices ranging from $5.98 to $7.00.

5. Fair Value of Financial Instruments

Fair value as defined by authoritative literature is the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories:

Level 1 – Quoted prices in active markets for identical assets and liabilities.

Level 2 – Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active and model-derived valuations whose inputs are observable or whose significant value drivers are observable.

Level 3 – Significant inputs to the valuation model are unobservable.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.

The carrying amount reported in the accompanying consolidated balance sheets for cash and cash equivalents, accounts receivable and accounts payable approximates fair value because of the immediate or short-term maturity of these financial instruments.

The fair value amount reported in the accompanying consolidated balance sheets for long term debt approximates fair value because the actual interest rates do not significantly differ from current rates offered for instruments with similar characteristics and is deemed to use Level 2 inputs. See the Company’s Note 6 on Credit Facility for further discussion.

6. 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 is reset to the extent the Company’s sells or otherwise disposes of any of its oil and gas properties. The Company is required to pay 100% of such net proceeds to the lender resulting in a permanent reduction of the borrowing base. 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 was renewed ten times with the tenth amendment effective as of March 31, 2016 with a maturity date of November 30, 2020. On January 30, 2017, the borrowing base was reevaluated and set at $3,120,000. 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 3.76% on December 31, 2016. Interest on the outstanding amount under the credit agreement is payable monthly. There was no availability of this line of credit at December 31, 2016. No principal payments are anticipated to be required through November 30, 2020.

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 $300,000 for the three fiscal quarters ending December 31, 2016, $500,000 for the four fiscal quarters ending March 31, 2017 and $650,000 for each trailing fiscal quarter period thereafter and minimum interest coverage ratios (EBITDA/Interest Expense) of 2.00 to 1.00 for each quarter thereafter. The Company is in compliance with all covenants as of December 31, 2016.

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, 2016, 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, 2016 was $3,070,000. 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, 2016:

7. Income Taxes

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 project being in a net deferred tax asset position at March 31, 2017. Our deferred tax asset is $1,094,421 as of December 31, 2016 with a valuation amount of $1,094,421. 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 reduced or 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.

The income tax provision consists of the following for the three and nine months ended December 31, 2016 and 2015:

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 majority stockholder. The total billed to and reimbursed by the stockholder for the three months ended December 31, 2016 and 2015 was $9,565 and $31,711, respectively. The total billed to and reimbursed by the stockholder for the nine months ended December 31, 2016 and 2015 was $22,061 and $81,412, respectively.

9. 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. 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, 2016 and 2015:

Due to a net loss for the three and nine months ended December 31, 2016 and 2015, the weighted average number of common shares outstanding excludes common stock equivalents because their inclusion would be anti-dilutive.

10. Impairments of Oil and Natural Gas Properties

Our oil and natural gas properties are subject to quarterly full cost ceiling tests. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. Estimated future net revenues for the quarterly ceiling limit are calculated using the average of commodity prices on the first day of the month over the trailing 12-month period. In the three and nine months ended December 31, 2015, capitalized costs of oil and natural gas properties exceeded the ceiling, resulting in an impairment in the carrying value of our oil and natural gas properties of approximately $2,150,621 and $2,984,410, respectively. We did not have an impairment in the carrying amount of our oil and natural gas properties for the nine months ended December 31, 2016.

11. Subsequent Events

In February 2017, the Company sold its fractional interest in two wells, a salt water disposal system and undeveloped acreage in Williams County, North Dakota for sales price of approximately $42,000 which was applied to the Company’s outstanding bank indebtedness.

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 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. Our ability to grow, make capital expenditures and service our debt depends primarily upon the prices we receive for the oil, natural gas and NGL we sell. Substantial expenditures are required to replace reserves, sustain production and fund our business plans. The substantial decline in oil and natural gas prices has negatively affected the amount of cash we have available for capital expenditures and debt service. In order to meet obligations, we may continue to sell non-core assets, if necessary.

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 royalties and working interests in non-operated properties in areas with significant development potential.

For the first nine months of fiscal 2017, cash flow from operations was $97,030, a 73% decrease when compared to the corresponding period of fiscal 2016. Cash of $75,808 was received for drilling refunds and net cash proceeds of $2,975,091 was received from the sale of assets. Cash of $517,454 was used for additions to oil and gas properties, cash of $93,630 was used to settle asset retirement obligations and cash of $2,510,000 was used to reduce the line of credit. Accordingly, net cash increased $26,845.

At December 31, 2016, we had working capital of $211,911 compared to working capital of $23,150 at March 31, 2016, an increase of $188,761 for the reasons set forth below.

Oil and Natural Gas Properties

Pioneer Natural Resources Company has drilled seven wells which are producing in Upton County, Texas, all being horizontal wells with 10,000 feet of laterals at no expense to Mexco. These wells are located in part on 411 acres in which Mexco has retained a 1% overriding royalty interest. On July 15, 2016, Pioneer exercised its option by paying to the Company $90,000 to extend for an additional two years on the undeveloped portion of Mexco’s leasehold interest in 60 net acres (200 gross acres) in Upton County, Texas.

During the first nine months of fiscal 2017, Mexco participated with various percentage interests in ten horizontal wells in the Delaware Basin located in the western portion of the Permian Basin in Eddy and Lea Counties, New Mexico with aggregate costs to date of $494,450.

The first of these wells we participated in was the drilling of a horizontal development well in the Cedar Canyon Bone Spring Wolfcamp formation of Eddy County, New Mexico. The lease, operated by BC Operating, Inc., contains approximately 320 acres with one producing well. Initial production results for the new well averaged 465 barrels of oil and 5,000,000 cubic feet of gas per day. Mexco’s working interest in this lease is .926% (.695% net revenue interest).

The next three wells were tested in October and November 2016 at an average rate of 1,015 barrels of oil; 1,705 barrels of water; and, 1,700,000 cubic feet of gas per day, or 1,298 barrels of oil equivalent per day, with an average flowing tubing pressures of 632 pounds per square inch, on 64/64 inch chokes. Mexco’s working interests in these wells range from .52% to .74%.

The fifth well was produced on January 24, 2017 flowing at a rate of 2,119 barrels of oil, 2,169 barrels of water and 2,441,000 cubic feet of gas per day, or 2,526 barrels of oil equivalent per day, with a flowing tubing pressure of 750 pounds per square inch, on a 51/64 inch choke. Mexco’s working interest in this well is .70%.

The sixth well was also produced on January 24, 2017 flowing at a rate of 1,411 barrels of oil, 2,660 barrels of water and 1,688,000 cubic feet of gas per day, or 1,692 barrels of oil equivalent per day, with a flowing tubing pressure of 975 pounds per square inch, on a 62/64 inch choke. Mexco’s working interest in this well is .34%.

The remaining four of these ten wells are in various stages of drilling, completion and production with possible further costs to be incurred by Mexco. The results of these tests are neither indicative of future sustained production rates nor of results to be expected in other wells.

During the first quarter of fiscal 2017, Mexco sold its interest in a non-core oil and gas property located in Martin County, Texas for $60,000 which was used to reduce the balance of Mexco’s line of credit.

In October 2016, Mexco received approximately $2.187 million in cash from a sale of working interests to Parsley Energy, Inc. covering 50 net acres located in Glasscock County, Texas in the horizontal Wolfcamp trend of the Permian Basin in West Texas. These proceeds are part of a sale by several co-owners of 11,672 gross (9,140 net) acres containing 67 gross (60 net) vertical wells with net production of 270 barrels of oil equivalent plus 5 disposal wells and existing infrastructure. Of these proceeds, approximately $1.887 million was applied to Mexco’s bank debt and the balance to the Company’s working capital.

Effective November 1, 2016, the Company sold its 100% working interest (76.7% average net revenue interest) in eight oil and gas wells and one disposal well of which Mexco is operator, located in the El Cinco and Tippett Fields of Pecos County, Texas. The Company received a cash purchase price of $405,000 which was applied to reduce bank indebtedness. These properties were determined by management to be non-core with limited potential for further development.

In connection with Barnett Shale Fort Worth Basin royalties owned by the Company, a settlement was reached with the defendants, Chesapeake Energy Corporation and Total E&P USA underpayment of royalties resulting in a payment of $154,289 of which $123,394 was paid in cash on August 19, 2016 and the balance of $30,894 in an interest free promissory note due in three years and payable by Chesapeake.

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 assets.

Crude oil and natural gas prices have fluctuated significantly in recent years. 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 $22.75 per bbl in February 2016 to a high of $50.75 per bbl in December 2016. The Henry Hub Spot Market Price (“Henry Hub”) for natural gas has ranged from a low of $1.49 per MMBtu in March 2016 to a high of $3.80 per MMBtu in December 2016. On December 31, 2016 the WTI posted price for crude oil was $50.25 per bbl and the Henry Hub spot price for natural gas was $3.71 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, 2016:

Results of Operations – Three Months Ended December 31, 2016 and 2015. For the quarter ended December 31, 2016, there was a net loss of $159,741 compared to a net loss of $2,445,536 for the quarter ended December 31, 2015. This was a result of an increase in operating revenues and a decrease in total operating expenses. As opposed to the prior year, there was no impairment during the three months ended December 31, 2016.

Oil and gas sales. Revenue from oil and gas sales was $580,419 for the third quarter of fiscal 2017, an 8% increase from $537,771 for the same period of fiscal 2016. This resulted from an increase in oil and gas prices partially offset by a decrease in oil and gas production, partially due to wells down for mechanical difficulties.

Production and exploration. Production costs were $234,372 for the third quarter of fiscal 2017, an 18% decrease from $286,519 for the same period of fiscal 2016. This was primarily the result of a decrease in lease operating expenses as a result of lowering service costs and the sale of our operated properties in Pecos County, Texas.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense was $273,885 for the third quarter of fiscal 2017, a 27% decrease from $375,987 for the same period of fiscal 2016, primarily due to a decrease to the full cost pool amortization base and a decrease in oil and gas production.

General and administrative expenses. General and administrative expenses were $199,995 for the third quarter of fiscal 2017, a 27% decrease from $272,936 for the same period of fiscal 2016. This was primarily due to a decrease in engineering services, stock option compensation expense, salaries and insurance expense.

Interest expense. Interest expense was $32,378 for the third quarter of fiscal 2017, a 25% decrease from $43,413 for the same period of fiscal 2016, 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, 2016 compared to an income tax benefit of $147,539 for the quarter ended December 31, 2015. The effective tax rate for the three months ended December 31, 2015 was 0% compared to (6%) for the three months ended December 31, 2015. The decrease in the effective income tax rate was primarily due to the tax benefit at expected rates being fully offset by a change in the valuation allowance.

Results of Operations – Nine Months Ended December 31, 2016 and 2015. For the nine months ended December 31, 2016, there was a net loss of $691,099 compared to a net loss of $3,546,209 for the nine months ended December 31, 2015. This was a result of a decrease in operating revenues partially offset by a decrease in total operating expenses. As opposed to the prior year, there was no impairment during the nine months ended December 31, 2016.

Oil and gas sales. Revenue from oil and gas sales was $1,662,985 for the nine months ended December 31, 2016, a 15% decrease from $1,951,228 for the same period of fiscal 2016. This resulted from a decrease in oil prices and a decrease in in oil and gas production.

Other operating revenue. Other operating revenue was $178,174 for the nine months ended December 31, 2016 compared to $25,080 for the nine months ended December 31, 2015 primarily 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.

Production and exploration. Production costs were $721,864 for the nine months ended December 31, 2016, a 17% decrease from $869,091 for the nine months ended December 31, 2015. This was primarily the result of a decrease in lease operating expenses as a result of lowering service costs and a decrease in production taxes due to the decrease in oil and gas revenue.

Depreciation, depletion and amortization. Depreciation, depletion and amortization expense was $879,637 for the nine months ended December 31, 2016, a 29% decrease from $1,244,617 for the nine months ended December 31, 2015, primarily due to a decrease in oil and gas production and a decrease in the full cost pool amortization base.

General and administrative expenses. General and administrative expenses were $780,608 for the nine months ended December 31, 2016, a 16% decrease from $931,545 for the nine months ended December 31, 2015. This was primarily due to a decrease in engineering services, stock option compensation expense, salaries and insurance expense.

Interest expense. Interest expense was $123,385 for the nine months ended December 31, 2016, a 3% decrease from $127,693 for the nine months ended December 31, 2015 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, 2016 compared to an income tax benefit of $660,870 for the nine months ended December 31, 2015. The effective tax rate for the nine months ended December 31, 2016 was 0% compared to (16%) for the nine months ended December 31, 2015. The decrease in our effective income tax rate was primarily due to the tax benefit at expected rates being fully offset by a change in our valuation allowance.

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, 2016, we had an outstanding loan balance of $3,070,000 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 $30,700 based on the outstanding balance at December 31, 2016.

Credit Risk. Credit risk is the risk of loss as a result of nonperformance by other parties of their contractual obligations. 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, 2016, our largest credit risk associated with any single purchaser was $75,650 or 23% 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 partners. At December 31, 2016, our largest credit risk associated with any working interest partner was $3,171 or 26% 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 natural gas prices than oil prices because most of our production and reserves are natural gas. If the average oil price had increased or decreased by ten dollars per barrel for the first nine months of fiscal 2017, our pretax income or loss would have changed by $264,340. If the average gas price had increased or decreased by one dollar per mcf for the first nine months of fiscal 2017, our pretax income or loss would have changed by $266,606.

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, 2016, 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, 2016 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 2016 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.