MEXCO ENERGY CORP 10-K

ITEM 9A. CONTROLS AND PROCEDURES Management’s Annual Report on Internal Control over Financial Reporting. The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Exchange Act Rule 13a-15(f) and 15d-15(f). The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements. Our internal control over financial reporting is supported by appropriate reviews by management, written policies and guidelines, careful selection and training of qualified personnel, and a written Code of Conduct adopted by our Board of Directors, applicable to all directors, officers and employees of Mexco. Our chief executive officer and chief financial officer assessed the effectiveness our internal control over financial reporting using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in the 2013 “Internal Control - Integrated Framework”. Based upon that evaluation, our chief executive officer and chief financial officer concluded that our internal control over financial reporting was effective as of March 31, 2021. 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 Rule 13a-15(e). Based on such evaluation, such officers concluded that, as of March 31, 2021, our disclosure controls and procedures were effective. Changes in Internal Control over Financial Reporting. No changes in the Company’s internal control over financial reporting occurred during the year ended March 31, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. ITEM 9B. OTHER INFORMATION None PART III ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE See “Mexco Energy Corporation Board of Directors”, “Named Executive Officers Who Are Not Directors”, “Section 16(a) Beneficial Ownership Reporting Compliance”, “Corporate Governance and Code of Business Conduct” and “Meetings and Committees of the Board of Directors” in the Proxy Statement of Mexco Energy Corporation for our Annual Meeting of Stockholders to be held September 9, 2021 (“Proxy Statement”) to be filed with the SEC within 120 days after the end of our fiscal year ended March 31, 2021, which is incorporated herein by reference. The information required by this item with respect to executive officers of the Company is also set forth in Part I of this report. ITEM 11. EXECUTIVE COMPENSATION The information required by this item will be contained in the Proxy Statement under the caption “Executive Compensation”, and is hereby incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS The information required by this item will be contained in the Proxy Statement under the captions “Security Ownership of Certain Beneficial Owners and Management” and “Employee Incentive Stock Option Plans”, and is hereby incorporated herein by reference. 30 ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE The information required by this item will be contained in the Proxy Statement under the captions “Certain Relationships and Related Transactions” and “Meetings and Committees of the Board of Directors”, and is hereby incorporated by reference herein. ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES The information required by this item will be contained in the Proxy Statement under the caption “Audit Fees and Services”, and is hereby incorporated by reference herein. PART IV ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES Consolidated Financial Statements. For a list of the consolidated financial statements filed as part of this Form 10-K, see the “Index to Consolidated Financial Statements” set forth on F-1 of this report. Financial Statement Schedules. All schedules have been omitted because they are not applicable, not required under the instructions or the information requested is set forth in the consolidated financial statements or related notes thereto. Exhibits. For a list of the exhibits required by this Item and accompanying this Form 10-K see the “Index to Exhibits” set forth on page F25 of this report. 31 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. MEXCO ENERGY CORPORATION By: /s/ Nicholas C. Taylor By: /s/ Tamala L. McComic Chairman of the Board and Chief Executive Officer President and Chief Financial Officer Dated: June 25, 2021 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below as of June 25, 2021, by the following persons on behalf of the Registrant and in the capacity indicated. /s/ Nicholas C. Taylor Nicholas C. Taylor Chief Executive Officer, Chairman of the Board of Directors /s/ Tamala L. McComic Tamala L. McComic Chief Financial Officer, President, Treasurer and Assistant Secretary /s/ Michael J. Banschbach Michael J. Banschbach Director /s/ Kenneth L. Clayton Kenneth L. Clayton Director /s/ Thomas R. Craddick Thomas R. Craddick Director /s/ Thomas H. Decker Thomas H. Decker Director /s/ Christopher M. Schroeder Christopher M. Schroeder Director 32 Glossary of Abbreviations and Terms The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report. Basin. A large natural depression on the earth’s surface in which sediments generally brought by water accumulate. Bbl . One stock tank barrel, or 42 U.S. gallons of liquid volume, used herein in reference to crude oil, condensate or natural gas liquids hydrocarbons. BOE. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil. BTU. British thermal unit. Completion . The installation of permanent equipment for the production of oil or natural gas. Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve. Credit Facility. A line of credit provided by a bank or group of banks, secured by oil and gas properties. DD&A. Refers to depreciation, depletion and amortization of the Company’s property and equipment. Developed acreage . The number of acres which are allocated or assignable to producing wells or wells capable of production. Development costs. Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves. Development well . A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive. Dry hole . A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes. Exploration. The search for natural accumulations of oil and natural gas by any geological, geophysical or other suitable means. Exploratory well . A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir. Extensions and discoveries . As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates. Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. Formation. A layer of rock which has distinct characteristics that differs from nearby rock. Gross acres or wells. Refers to the total acres or wells in which the Company owns any amount of working interest. Lease. An instrument which grants to another (the lessee) the exclusive right to enter and explore for, drill for, produce, store and remove oil and natural gas from the mineral interest, in consideration for which the lessor is entitled to certain rents and royalties payable under the terms of the lease. Typically, the duration of the lessee’s authorization is for a stated term of years and “for so long thereafter” as minerals are producing. Mcf . One thousand cubic feet of natural gas at standard atmospheric conditions. 33 MBOE . One thousand barrels of oil equivalent. MMBOE . One million barrels of oil equivalent. MMBtu . One million British thermal units of energy commonly used to measure heat value or energy content of natural gas. Natural gas liquids (“NGLs”) . Liquid hydrocarbons that have been extracted from natural gas, such as ethane, propane, butane and natural gasoline. Net acres or wells. Refers to gross acres or wells multiplied, in each case, by the percentage interest owned by the Company. Net production . Oil and gas production that is owned by the Company, less royalties and production due others. Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests. Oil . Crude oil or condensate. Operator . The individual or company responsible for the exploration, development and production of an oil or natural gas well or lease. Overriding royalty interest (“ORRI”). A royalty interest that is created out of the operating or working interest. Its term is coextensive with that of the operating interest from which it was created. Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells. Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed operating and production expenses and taxes. Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons. Proved developed nonproducing reserves (“PDNP”) . Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells. Proved developed producing reserves (“PDP”). Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods. Proved developed reserves. The combination of proved developed producing and proved developed nonproducing reserves. Proved reserves. The estimated quantities of oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions. Proved undeveloped reserves (“PUD”) . Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. 34 PV-10. When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses except for specific general and administrative expenses incurred to operate the properties, discounted to a present value using an annual discount rate of 10%. Recompletion. A process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production. Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs. Royalty . An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage, or of the proceeds of the sale thereof, but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. Shut in. A well suspended from production or injection but not abandoned. Spacing. The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 640-acre spacing) and is often established by regulatory agencies. Standardized measure of discounted future net cash flows . The discounted future net cash flows relating to proved reserves based on prices used in estimating the reserves, year-end costs, and statutory tax rates, and a 10% annual discount rate. The information for this calculation is included in the note regarding disclosures about oil and gas reserve data contained in the Notes to Consolidated Financial Statements included in this Form 10-K. Undeveloped acreage . Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. Unit. The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement. Wellbore. The hole drilled by the bit that is equipped for crude oil or natural gas production on a completed well. Also called well or borehole. Working interest . An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest is entitled will be smaller than the share of costs that the working interest owner is required to bear to the extent of any royalty burden. 35 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Report of Independent Registered Public Accounting Firm F-2 Consolidated Balance Sheets F-5 Consolidated Statements of Operations F-6 Consolidated Statements of Changes in Stockholders’ Equity F-7 Consolidated Statements of Cash Flows F-8 Notes to Consolidated Financial Statements F-9 F- 1 Report of Independent Registered Public Accounting Firm Board of Directors and Stockholders Mexco Energy Corporation Opinion on the Financial Statements We have audited the accompanying consolidated balance sheets of Mexco Energy Corporation (a Colorado corporation) and Subsidiaries (the Company) as of March 31, 2021 and 2020, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the two years in the period ended March 31, 2021, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of March 31, 2021 and 2020, and the results of its operations and its cash flows for each of the two years in the period ended March 31, 2021, in conformity with accounting principles generally accepted in the United States of America. Basis for Opinion These financial statements are the responsibility of the entity’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control over financial reporting. Accordingly, we express no such opinion. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. Critical Audit Matters The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved are especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. Estimation of proved reserves impacting the recognition and valuation of depletion expense and impairment of oil and gas properties F- 2 Critical Accounting Matter Description As described in Note 2 to the financial statements, the Company accounts for its oil and gas properties using the full cost method of accounting which requires management to make estimates of proved reserve volumes and future revenues and expenses to calculate depletion expense and measure its oil and gas properties for potential impairment. To estimate the volume of proved reserves and future revenues, management makes significant estimates and assumptions, including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions required in the estimation of depletion expense and potential impairment measurements. We identified the estimation of proved reserves of oil and gas properties, due to its impact on depletion expense and impairment evaluation, as a critical audit matter. The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain inputs and assumptions, which require a high degree of subjectivity necessary to estimate the volume and future revenues of the Company’s proved reserves could have a significant impact on the measurement of depletion expense or the impairment assessment. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment. How the Critical Audit Matter Was Addressed in the Audit We obtained an understanding of the design and implementation of management’s controls and our audit procedures related to the estimation of proved reserves included the following, among others. ● We evaluated the level of knowledge, skill, and ability of the Company’s reservoir engineering specialists and their relationship to the Company, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the reserve report prepared by the Company’s specialists. ● To the extent key, sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, such as commodity pricing, historical pricing differentials, operating costs, estimated capital costs and working and net revenue interests, we tested management’s process for determining the assumptions, including examining the underlying support, on a sample basis. Specifically, our audit procedures involved testing management’s assumptions as follows: - Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials; - Evaluated the models used to estimate the operating costs at year-end compared to historical operating costs; - Compared the models used to determine the future capital expenditures and compared estimated future capital expenditures used in the reserve report to amounts expended for recently drilled and completed wells with similar locations; - Evaluated the working and net revenue interests used in the reserve report by inspecting a sample of ownership interests, historical pricing differentials, and operating costs to underlying support from the Company’s accounting records. F- 3 - Evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s or the operator’s intent to develop the proved undeveloped properties; - Applied analytical procedures to the reserve report by comparing to historical actual results and to the prior year reserve report. /s/ WEAVER AND TIDWELL, L.L.P. We have served as the Company’s auditor since 2017. Midland, Texas June 25, 2021 F- 4 Mexco Energy Corporation and Subsidiaries CONSOLIDATED BALANCE SHEETS March 31, March 31, 2021 2020 ASSETS Current assets Cash and cash equivalents $ 57,813 $ 34,381 Accounts receivable: Oil and natural gas sales 621,384 271,315 Trade 30,402 13,382 Prepaid costs and expenses 47,895 50,188 Total current assets 757,494 369,266 Property and equipment, at cost Oil and gas properties, using the full cost method 38,664,347 37,465,172 Other 120,208 116,993 Accumulated depreciation, depletion and amortization (29,015,612 ) (28,109,252 ) Property and equipment, net 9,768,943 9,472,913 Investment in limited liability company at cost 200,000 150,000 Operating lease, right-of-use asset 20,861 76,130 Other noncurrent assets 83,389 2,200 Total assets $ 10,830,687 $ 10,070,509 LIABILITIES AND STOCKHOLDERS’ EQUITY Current liabilities Accounts payable and accrued expenses $ 116,569 $ 116,760 Operating lease liability, current 21,965 65,721 Total current liabilities 138,534 182,481 Long-term liabilities Long-term debt 1,154,949 757,423 Operating lease liability, long-term - 10,982 Asset retirement obligations 713,797 755,261 Total long-term liabilities 1,868,746 1,523,666 Total liabilities 2,007,280 1,706,147 Commitments and contingencies Stockholders’ equity Preferred stock - $1.00 par value; 10,000,000 shares authorized; none outstanding - - Common stock - $0.50 par value; 40,000,000 shares authorized; 2,143,666 and 2,107,166 shares issued; and, 2,076,666 and 2,040,166 shares outstanding as of March 31, 2021 and 2020 1,071,833 1,053,583 Additional paid-in capital 7,624,214 7,339,351 Retained earnings 473,361 317,429 Treasury stock, at cost (67,000 shares) (346,001 ) (346,001 ) Total stockholders’ equity 8,823,407 8,364,362 Total liabilities and stockholders’ equity $ 10,830,687 $ 10,070,509 The accompanying notes to the consolidated financial statements are an integral part of these statements. F- 5 Mexco Energy Corporation and Subsidiaries CONSOLIDATED STATEMENTS OF OPERATIONS Years ended March 31, 2021 2020 Operating revenues: Oil sales $ 2,028,792 $ 2,310,127 Natural gas sales 744,987 410,226 Other 25,225 18,187 Total operating revenues 2,799,004 2,738,540 Operating expenses: Production 871,963 914,649 Accretion of asset retirement obligation 28,548 27,235 Depreciation, depletion and amortization 906,361 853,801 General and administrative 833,431 1,006,531 Total operating expenses 2,640,303 2,802,216 Operating income (loss) 158,701 (63,676 ) Other income (expenses): Interest income 706 1,854 Interest expense (53,232 ) (37,656 ) PPP loan forgiveness 68,957 - Loss on derivative instruments (19,200 ) - Net other expense (2,769 ) (35,802 ) Income (loss) before provision for income taxes 155,932 (99,478 ) Income tax - - Net income (loss) $ 155,932 $ (99,478 ) Income (loss) per common share: Basic: $ 0.08 $ (0.05 ) Diluted: $ 0.08 $ (0.05 ) Weighted average common shares outstanding: Basic: 2,050,678 2,040,166 Diluted: 2,062,070 2,040,166 The accompanying notes to the consolidated financial statements are an integral part of these statements. F- 6 Mexco Energy Corporation and Subsidiaries CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY Years ended March 31, 2021 and 2020 Common Stock Par Value Additional Paid-In Capital Retained Earnings Treasury Stock Total Stockholders’ Equity Balance at April 1, 2019 $ 1,053,583 $ 7,305,048 $ 416,907 $ (346,001 ) $ 8,429,537 Net loss - - (99,478 ) - (99,478 ) Stock based compensation - 34,303 - - 34,303 Balance at March 31, 2020 $ 1,053,583 $ 7,339,351 $ 317,429 $ (346,001 ) $ 8,364,362 Net income - - 155,932 - 155,932 Issuance of stock through options exercised 18,250 229,185 - - 247,435 Stock based compensation - 55,678 - - 55,678 Balance at March 31, 2021 $ 1,071,833 $ 7,624,214 $ 473,361 $ (346,001 ) $ 8,823,407 SHARE ACTIVITY 2021 2020 Common stock shares, issued: At beginning of year 2,107,166 2,107,166 Issued 36,500 - At end of year 2,143,666 2,107,166 Common stock shares, held in treasury: At beginning of year (67,000 ) (67,000 ) Acquisitions - - At end of year (67,000 ) (67,000 ) Common stock shares, outstanding At end of year 2,076,666 2,040,166 The accompanying notes to the consolidated financial statements are an integral part of these statements. F- 7 Mexco Energy Corporation and Subsidiaries CONSOLIDATED STATEMENTS OF CASH FLOWS Years ended March 31, 2021 2020 Cash flows from operating activities: Net income (loss) $ 155,932 $ (99,478 ) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Stock-based compensation 55,678 34,303 Depreciation, depletion and amortization 906,361 853,801 Accretion of asset retirement obligations 28,548 27,235 PPP loan forgiveness (68,574 ) - Amortization of debt issuance costs 12,526 14,221 Changes in operating assets and liabilities: (Increase) decrease in accounts receivable (367,089 ) 64,903 Decrease in right-of-use asset 55,269 65,255 Decrease in prepaid expenses 2,292 3,547 Decrease in other assets - 30,421 Increase (decrease) in accounts payable and accrued expenses 3,223 (44,829 ) Decrease in operating lease liability (54,739 ) (64,682 ) Settlement of asset retirement obligations (19,380 ) (19,737 ) Net cash provided by operating activities 710,047 864,960 Cash flows from investing activities: Additions to oil and gas properties (1,592,023 ) (1,692,190 ) Additions to other property and equipment (3,215 ) (3,951 ) Drilling refund 136,236 - Investment in limited liability company at cost (50,000 ) (150,000 ) Proceeds from sale of oil and gas properties and equipment 121,378 104,576 Net cash used in investing activities (1,387,624 ) (1,741,565 ) Cash flows from financing activities: Proceeds from exercise of stock options 247,435 - Proceeds from long-term debt 935,000 1,285,000 Proceeds from PPP loan 68,574 - Debt issuance costs - (12,266 ) Reduction of long-term debt (550,000 ) (490,000 ) Net cash provided by financing activities 701,009 782,734 Net increase (decrease) in cash and cash equivalents 23,432 (93,871 ) Cash and cash equivalents at beginning of period 34,381 128,252 Cash and cash equivalents at end of period $ 57,813 $ 34,381 Supplemental disclosure of cash flow information: Cash paid for interest $ 39,269 $ 23,276 Accrued capital expenditures included in accounts payable $ 4,523 $ 15,437 Non-cash investing and financing activities: Asset retirement obligations $ 17,587 $ 19,512 Operating lease – right of use asset and associated liabilities $ 9,360 $ 141,385 The accompanying notes to the consolidated financial statements are an integral part of these statements. F- 8 MEXCO ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Years Ended March 31, 2021 and 2020 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 crude oil, natural gas, condensate and natural gas liquids (“NGLs”). Most of the Company’s oil and gas interests are centered in West Texas and Southeastern New Mexico; however, the Company owns producing properties and undeveloped acreage in fourteen states. All of the Company’s oil and gas interests are operated by others. 2. Summary of 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. Cash and Cash Equivalents . The Company considers all highly liquid debt instruments purchased with maturities of three months or less and money market funds to be cash equivalents. The Company maintains cash in bank deposit accounts that may, at times, exceed federally insured limits. At March 31, 2021, the Company had all of its cash and cash equivalents with one financial institution. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk. Accounts Receivable. Accounts receivable includes trade receivables from joint interest owners and oil and gas purchasers. Credit is extended based on an evaluation of a customer’s financial condition and, generally, is uncollateralized. Accounts receivable under joint operating agreements have a right of offset against future oil and gas revenues if a producing well is completed. The collectibility of receivables is assessed and an allowance is made for any doubtful accounts. The allowance for doubtful accounts is determined based on the Company’s previous loss history. The Company has not experienced any significant credit losses. For the years ended March 31, 2021 and 2020, no allowance has been made for doubtful accounts. Oil and Gas Properties . Oil and gas properties are accounted for using the full cost method of accounting. Under this method of accounting, the costs of unsuccessful, as well as successful, acquisition, exploration and development activities are capitalized as property and equipment. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation (“ARO”) when incurred. Generally, no gains or losses are recognized on the sale or disposition of oil and gas properties. F- 9 Excluded Costs . Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent investments in unproved properties and major development projects. These costs are excluded until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed at least quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the capitalized costs being amortized (the depreciation, depletion and amortization (“DD&A”) pool). Impairments transferred to the DD&A pool increase the DD&A rate. No costs were excluded for the years ended March 31, 2021 and 2020. Ceiling Test . Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is an impairment test to determine a limit, or ceiling, on the book value of oil and gas properties. That limit is the after-tax present value of the future net cash flows from proved crude oil and natural gas reserves and using an average price over the prior first day of the month 12-month period held flat for the life of production plus the lower of cost or fair market value of unproved properties. If net capitalized costs of crude oil and natural gas properties exceed the ceiling limit, the Company must charge the amount of the excess to earnings as an expense reflected in additional accumulated DD&A. This is called a “ceiling limitation write-down.” This impairment to our oil and gas properties does not impact cash flow from operating activities, but does reduce stockholders’ equity and reported earnings. Depreciation, Depletion and Amortization . The depreciable base for oil and gas properties includes the sum of capitalized costs, net of accumulated DD&A, estimated future development costs and asset retirement costs not accrued in oil and gas properties, less costs excluded from amortization and salvage. The depreciable base of oil and gas properties is amortized using the unit-of-production method. Asset Retirement Obligations . The Company has significant obligations to plug and abandon natural gas and crude oil wells and related equipment at the end of oil and gas production operations. The Company records the fair value of a liability for an ARO in the period in which it is incurred and a corresponding increase in the carrying amount of the related asset. Subsequently, the asset retirement costs included in the carrying amount of the related asset are allocated to expense using the units of production method. In addition, increases in the discounted ARO liability resulting from the passage of time are reflected as accretion expense in the Consolidated Statements of Operations. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. The Company uses the present value of estimated cash flows related to the ARO to determine the fair value. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the related asset. Income Taxes . The Company recognizes deferred tax assets and liabilities for future tax consequences of temporary differences between the carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates applicable to the years in which those differences are expected to be settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in net income in the period that includes the enactment date. Any interest and penalties are recorded as interest expense and general and administrative expense, respectively. Other Property and Equipment . Provisions for depreciation of office furniture and equipment are computed on the straight-line method based on estimated useful lives of three to ten years. Income (Loss) Per Common Share . Basic net income (loss) per share is computed by dividing net income (loss) by the weighted average number of common shares outstanding during the period. Diluted net income (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 income (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. F- 10 Revenue Recognition - Revenue from Contracts with Customers. Revenues from our royalty and non-operated working interest properties are recorded under the cash receipts approach as directly received from the remitters’ statement accompanying the revenue check. Since the revenue checks are generally received two to four months after the production month, the Company accrues for revenue earned but not received by estimating production volumes and product prices. Any identified differences between its revenue estimates and actual revenue received historically have not been significant. The Company records transportation and processing costs that are incurred after control of its product has transferred to the customer as a reduction of “Natural gas sales” on the Consolidated Statement of Operations. Gas Balancing . Gas imbalances are accounted for under the sales method whereby revenues are recognized based on production sold. A liability is recorded when excess takes of natural gas volumes exceed estimated remaining recoverable reserves (over produced). No receivables are recorded for those wells where the Company has taken less than its ownership share of gas production (under produced). The Company does not have any significant gas imbalances. Stock-based Compensation . The Company uses the Binomial option pricing model to estimate the fair value of stock-based compensation expenses at grant date. This expense is recognized as compensation expense in its consolidated financial statements over the vesting period. The Company recognizes the fair value of stock-based compensation awards as wages within general and administrative expense in the Consolidated Statements of Operations based on a graded-vesting schedule over the vesting period. Investments. The Company accounts for investments of less than 1% in limited liability companies at cost. The Company has no control of the limited liability companies. The cost of the investment is recorded as an asset on the consolidated balance sheets and when income from the investment is received, it is immediately recognized on the consolidated statements of operations. Derivative Financial Instruments. The Company’s derivative financial instruments are used to manage commodity price risk attributable to expected oil and gas production. While there is risk the financial benefit of rising oil and gas prices may not be captured, the Company believes the benefits of stable and predictable cash flows outweigh the potential risks. The Company accounts for derivative financial instruments using fair value accounting and recognizes gains and losses in earnings during the period in which they occur. Unsettled derivative instruments are recorded in the accompanying consolidated balance sheets as either a current or non-current asset or a liability measured at its fair value. The Company only offsets derivative assets and liabilities for arrangements with the same counterparty when right of offset exists. Derivative assets and liabilities with different counterparties are recorded gross in the consolidated balance sheets. Derivative contract settlements are reflected in operating activities in the accompanying consolidated statements of cash flows. The Company uses certain pricing models to determine the fair value of its derivative financial instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets. Recent Accounting Pronouncements. In December 2019, the FASB issued ASU No. 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes” (“ASU 2019-12”), which simplifies various aspects of the income tax accounting guidance in ASC 740, including requirements related to the following: (i) hybrid tax regimes; (ii) the tax basis step-up in goodwill obtained in a transaction that is not a business combination; (iii) separate financial statements of entities not subject to tax; (iv) the intraperiod tax allocation exception to the incremental approach; (v) ownership changes in investments - changes from a subsidiary to an equity method investment (and vice versa); (vi) interim-period accounting for enacted changes in tax laws; and (vii) the year-to-date loss limitation in interim-period tax accounting. ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years and early adoption is permitted. If an entity early adopts these amendments in an interim period, it should reflect any adjustments as of the beginning of the annual period that includes that interim period. In addition, an entity that elects to early adopt ASU 2019-12 is required to adopt all of the amendments in the same period. The Company adopted ASU 2019-12 on April 1, 2021 and it will not have a material impact on its financial position, results of operations and disclosures. F- 11 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 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 interest, non-operated properties in areas with significant development potential. 3. Fair Value of Financial Instruments The Company applies FASB ASC Topic 820, Fair Value Measurements and Disclosure (“ASC Topic 820”), which establishes a framework for measuring fair value based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs or unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following fair value input hierarchy: Level 1: Quoted prices for identical instruments in active markets at the measurement date. Level 2: Quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets at the measurement date and for the anticipated term of the instrument. Level 3: Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable inputs that reflect the reporting entity’s own assumptions about the assumptions market participants would use in pricing the asset or liability acquired, based on the best information available in the circumstances. 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. See the Company’s Note 5 on Long Term Debt for further discussion. Fair Value Measurements on a Recurring Basis A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. The Company’s commodity derivative instruments were carried at fair value on a recurring basis in the Company’s consolidated balance sheets. The Company uses certain pricing models to determine the fair value of its derivative financial instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets. Assumed credit risk adjustments, based on published credit ratings and public bond yield spreads are applied to the Company’s commodity derivatives. The Company’s derivative instruments are subject to netting arrangements and qualify for net presentation in the consolidated balance sheets in those instances where such arrangements exist with the respective counterparty. F- 12 To ensure these derivative instruments are recorded at fair value, valuation adjustments may be required to reflect the creditworthiness of either party as well as market constraints on liquidity. There was no adjustment as of March 31, 2021. Fair Value Measurements on a Nonrecurring Basis The asset retirement obligation estimates are derived from historical costs and management’s expectation of future cost environments and, therefore, the Company has designated these liabilities as Level 3 measurements. The significant inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, well life, inflation and credit-adjusted risk-free rate. See Note 6 for a reconciliation of the beginning and ending balances of the liability for the Company’s asset retirement obligations. 4. Derivative Financial Instruments It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive. The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk. Derivative contracts are utilized to economically hedge the Company’s exposure to price fluctuations and reduce the variability in the Company’s cash flows associated with anticipated sales of future oil and natural gas production. The Company follows FASB ASC Topic 815, Derivatives and Hedging (ASC Topic 815), to account for its derivative financial instruments. The Company’s crude oil derivative positions consisted of put options. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in net realized and unrealized gain (loss) on commodity price hedging contracts on the consolidated statements of operations. All derivative contracts are recorded at fair market value and included in the consolidated balance sheets as assets or liabilities. As of March 31, 2021 and 2020, the Company had no derivative contracts. The Company may have multiple hedge positions that span a several-month time period and result in fair value asset and liability positions. At the end of the reporting periods, those positions are offset to a single fair value asset or liability for each commodity and the netted balance is reflected in the consolidated balance sheets as an asset or liability. During the quarter ended June 30, 2020 the Company entered into a series of crude oil put option contracts. All of these such contracts expired in July and August 2020. The following tables summarizes the amounts of the Company’s realized and unrealized losses on derivative contracts listed as loss on derivative instruments in the Company’s consolidated statements of operations for the year ended March 31, 2021. Loss Recognized Realized loss on oil price hedging contracts $ (19,200 ) Unrealized gain (loss) on oil price hedging contracts - Net realized and unrealized loss on derivative contracts $ (19,200 ) 5. Long-Term Debt Long-term debt on the Consolidated Balance Sheets consisted of the following as of March 31: 2021 2020 Credit facility $ 1,180,000 $ 795,000 Unamortized debt issuance costs (25,051 ) (37,577 ) Total long-term debt $ 1,154,949 $ 757,423 F- 13 On December 28, 2018, the Company entered into a loan agreement (the “Agreement”) with West Texas National Bank (“WTNB”), which provided for a credit facility of $1,000,000 with a maturity date of December 28, 2021. The Agreement has no monthly commitment reduction and a borrowing base to be evaluated annually. On February 28, 2020, the Agreement was amended to increase the credit facility to $2,500,000, extend the maturity date to March 28, 2023 and increase the borrowing base to $1,500,000. Under the Agreement, interest on the facility accrues at a rate equal to the prime rate as quoted in the Wall Street Journal plus one-half of one percent (.5%) floating daily. Interest on the outstanding amount under the Agreement is payable monthly. In addition, the Company will pay an unused commitment fee in an amount equal to one-half of one percent (.5%) times the daily average of the unadvanced amount of the commitment. The unused commitment fee is payable quarterly in arrears on the last day of each calendar quarter. As of March 31, 2021, there was $320,000 available on the facility. No principal payments are anticipated to be required through the maturity date of the credit facility, March 28, 2023. Upon closing with WTNB on the original Agreement, the Company paid a .5% loan origination fee in the amount of $5,000 plus legal and recording expenses totaling $34,532, which were deferred over the life of the credit facility. Upon closing the amendment to the Agreement, the Company paid a .1% loan origination fee of $2,500 and an extension fee of $3,125 plus legal and recording expenses totaling $12,266, which were also deferred over the life of the credit facility. 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 senior debt to earnings before interest, taxes, depreciation and amortization (“EBITDA”) ratios (Senior Debt/EBITDA) less than or equal to 4.00 to 1.00 measured with respect to the four trailing fiscal quarters and minimum interest coverage ratios (EBITDA/Interest Expense) of 2.00 to 1.00 for each quarter. In addition, the Agreement prohibits the Company from paying cash dividends on its common stock without prior written permission of WTNB. The Agreement does not permit the Company to enter into hedge agreements covering crude oil and natural gas prices without prior WTNB approval. The Company obtained written permission from WTNB prior to entering into the current hedge agreement discussed in Note 4. The balance outstanding on the credit facility as of March 31, 2021 was $1,180,000. The following table is a summary of activity on the WTNB credit facility for the years ended March 31, 2021 and 2020: Principal Balance at April 1, 2019: $ - Borrowings 1,285,000 Repayments 490,000 Balance at March 31, 2020: $ 795,000 Borrowings 935,000 Repayments 550,000 Balance at March 31, 2021: $ 1,180,000 Subsequently, the Company has borrowed $100,000 and made payments totaling $480,000, leaving a balance of $800,000 as of June 21, 2021. The Company also maintained a Certificate of Deposit Account at WTNB to collateralize one outstanding letter of credit for $25,000 in lieu of a plugging bond with the Texas Railroad Commission covering the properties the Company operates. This operated property was sold effective December 1, 2019 and the letter of credit was cancelled. On April 10, 2020, the Certificate of Deposit Account was terminated and the funds deposited into the Company’s operating account. F- 14 6. Asset Retirement Obligations The Company’s asset retirement obligations 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 until the liability is settled or the well is sold, at which time the liability is removed. The related asset retirement cost is capitalized as part of the carrying amount of our oil and natural gas properties. The ARO is included on the consolidated balance sheets with the current portion being included in the accounts payable and accrued expenses. The following table provides a rollforward of the asset retirement obligations for fiscal years ended March 31: 2021 2020 Carrying amount of asset retirement obligations, beginning of year $ 762,761 $ 861,534 Liabilities incurred 17,587 19,512 Liabilities settled (80,099 ) (145,520 ) Accretion expense 28,548 27,235 Revisions - - Carrying amount of asset retirement obligations, end of year 728,797 762,761 Less: Current portion 15,000 7,500 Non-Current asset retirement obligation $ 713,797 $ 755,261 7. Income Taxes The Company files a consolidated federal income tax return and various state income tax returns. The amount of income taxes the Company records requires the interpretation of complex rules and regulations of federal and state taxing jurisdictions. With few exceptions, the earliest year open to examination by U.S. federal and state income tax jurisdictions is 2016. On December 22, 2017, the tax legislation referred to as the 2017 Tax Reform Act (“Tax Cuts and Jobs 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%. Effective April 1, 2018, our corporate federal statutory income tax rate is 21%. GAAP 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. Significant components of net deferred tax assets (liabilities) at March 31 are as follows: 2021 2020 Deferred tax assets: Percentage depletion carryforwards $ 1,132,352 $ 1,167,594 Deferred stock-based compensation 37,977 36,568 Asset retirement obligation 153,048 160,180 Net operating loss 1,411,017 1,248,528 Other 9,840 7,372 2,744,234 2,620,242 Deferred tax liabilities: Excess financial accounting bases over tax bases of property and equipment 1,485,833 1,313,271 Deferred tax asset, net $ 1,258,401 $ 1,306,971 Valuation allowance (1,258,401 ) (1,306,971 ) Net deferred tax $ - $ - As of March 31, 2021, the Company has a statutory depletion carryforward of approximately $5,400,000, which does not expire. At March 31, 2021, the Company had a net operating loss carryforward for regular income tax reporting purposes of approximately $6,700,000, which will begin expiring in 2029. The Company’s ability to use some of its net operating loss carryforwards and certain other tax attributes to reduce current and future U.S. federal taxable income is subject to limitations under the Internal Revenue Code. F- 15 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. A reconciliation of the provision for income taxes to income taxes computed using the federal statutory rate for years ended March 31 follows: 2021 2020 Tax expense at federal statutory rate (1) $ 32,746 $ (20,891 ) Statutory depletion carryforward 35,242 (31,384 ) Change in valuation allowance (48,570 ) 46,850 U. S. tax reform, corporate rate reduction - - Permanent differences (19,418 ) 5,427 Other - (2 ) Total income tax $ - $ - Effective income tax rate - - (1) The federal statutory rate was 21% for fiscal years ending March 31, 2021 and 2020. For the years ended March 31, 2021 and 2020, the Company did not have any uncertain tax positions. While the amount of unrecognized tax benefits may change in the next 12 months, the Company does not expect any change to have a significant impact on its results of operations. The recognition of the total amount of the unrecognized tax benefits would have an impact on the effective tax rate. If these unrecognized tax benefits are disallowed, the Company will be required to pay additional taxes. Based on the material write-downs of the carrying value of our oil and natural gas properties for the year ending March 31, 2016, we are in a net deferred tax asset position for years ending March 31, 2021 and 2020. Our deferred tax asset is $1,258,401 as of March 31, 2021 with a valuation amount of $1,258,401. 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 expected future growth. In December 2020, the President of the United States signed the Consolidated Appropriations Act, 2021 (“the Act”). The Act includes many tax provisions, including the extension of various expiring provisions, extensions and expansions of certain earlier pandemic tax relief provisions, among other things. The Act did not have a material impact on the Company’s current year tax provision or the Company’s consolidated financial statements. In March 2020, the President of the United States signed the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) to stabilize the economy during the coronavirus pandemic. The CARES Act temporarily suspends and modifies certain tax laws established by the 2017 Tax Cuts and Jobs Act, including, but not limited to, modifications to net operating loss limitations, business interest limitations and alternative minimum tax. The CARES Act did not have a material impact on the Company’s current year provision and the Company’s consolidated financial statements. F- 16 8. Major Customers Currently, the Company operates exclusively within the United States and its revenues and operating profit are derived from the oil and gas industry. Oil and gas production is sold to various purchasers and the receivables are unsecured. Historically, the Company has not experienced significant credit losses on its oil and gas accounts and management is of the opinion that significant credit risk does not exist. Management is of the opinion that the loss of any one purchaser would not have an adverse effect on the Company’s ability to sell its oil and gas production. In fiscal 2021, one customer accounted for 66% of the total oil and natural gas revenues and 71% of the total oil and natural gas accounts receivable. In fiscal 2020, one customer accounted for 52% of the total oil and natural gas revenues and 63% of the total oil and natural gas accounts receivable. 9. Oil and Natural Gas Costs The costs related to the Company’s oil and natural gas activities were incurred as follows for the years ended March 31: 2021 2020 Property acquisition costs: Proved $ - $ - Unproved - - Exploration - 168 Development 1,581,109 1,687,499 Capitalized asset retirement obligations 17,587 19,512 Total costs incurred for oil and gas properties $ 1,598,696 $ 1,707,179 The Company had the following aggregate capitalized costs relating to its oil and gas property activities at March 31: 2021 2020 Proved oil and gas properties $ 38,664,347 $ 37,465,172 Unproved oil and gas properties: subject to amortization - - not subject to amortization - - 38,664,347 37,465,172 Less accumulated DD&A 28,906,419 28,003,961 $ 9,757,928 $ 9,461,211 DD&A amounted to $8.68 and $9.15 per BOE of production for the years ended March 31, 2021 and 2020, respectively. 10. Income (Loss) Per Common Share The following is a reconciliation of the number of shares used in the calculation of basic income per share and diluted income per share for the years ended March 31: 2021 2020 Net income (loss) $ 155,932 $ (99,478 ) Shares outstanding: Weighted avg. common shares outstanding – basic 2,050,678 2,040,166 Effect of the assumed exercise of dilutive stock options 11,392 - Weighted avg. common shares outstanding – dilutive 2,062,070 2,040,166 Income (loss) per common share: Basic $ 0.08 $ (0.05 ) Diluted $ 0.08 $ (0.05 ) For the year ended March 31, 2021, no anti-dilutive shares relating to stock options were excluded from the computation of diluted net income. Due to a net loss for the year ended March 31, 2020, the weighted average number of common shares outstanding excludes common stock equivalents because their inclusion would be anti-dilutive. F- 17 11. Stockholders’ Equity In September 2020, the Board of Directors authorized the use of up to $250,000 to repurchase shares of the Company’s common stock for the treasury account. There were no shares of common stock repurchased for the treasury account during fiscal 2021 and 2020. 12. Stock-based Compensation In September 2019, the Company adopted the 2019 Employee Incentive Stock Plan (the “2019 Plan”). The 2019 Plan provides for the award of stock options up to 200,000 shares and includes option awards as well as stock awards. Option awards are granted with the restriction of requiring payment for the shares. Stock awards are granted without restrictions and without payment by the recipient. Neither option awards nor stock awards may exceed 25,000 shares granted to any one individual in any fiscal year. Stock options may be an incentive stock option or a nonqualified stock option. Options to purchase common stock under the plan are granted at the fair market value of the common stock at the date of grant, become exercisable to the extent of 25% of the shares optioned on each of four anniversaries of the date of grant, expire ten years from the date of grant and are subject to forfeiture if employment terminates. The 2019 Plan expires ten years from the date of adoption. According to the Company’s employee stock incentive plan, new shares will be issued upon the exercise of stock options and the Company can repurchase shares exercised under the plan. During the year ended March 31, 2021, there were no stock options issued. During the year ended March 31, 2020, the Compensation Committee of the Board of Directors approved and the Company issued options covering 42,000 shares of stock. The plan also provides for the granting of stock awards. No stock awards were granted during fiscal 2021 and 2020. The Company recognized compensation expense of $55,678 and $34,303 related to vesting stock options in general and administrative expense in the Consolidated Statements of Operations for fiscal 2021 and 2020, respectively. The total cost related to non-vested awards not yet recognized at March 31, 2021 totals $114,131, which is expected to be recognized over a weighted average of 2.35 years. The fair value of each stock option is estimated on the date of grant using the Binomial valuation model. Expected volatilities are based on historical volatility of the Company’s stock over the contractual term of 120 months and other factors. The Company uses historical data to estimate option exercise and employee termination within the valuation model. The expected term of options granted is derived from the output of the option valuation model and represents the period of time that options granted are expected to be outstanding. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant. As the Company has never declared dividends, no dividend yield is used in the calculation. Actual value realized, if any, is dependent on the future performance of the Company’s common stock and overall stock market conditions. There is no assurance the value realized by an optionee will be at or near the value estimated by the Binomial model. Included in the following table is a summary of the grant-date fair value of stock options granted and the related assumptions used in the Binomial models for stock options granted in fiscal 2021 and 2020. All such amounts represent the weighted average amounts for each period. For the year ended March 31, 2021 2020 Grant-date fair value - $ 2.24 Volatility factor - 60.12 % Dividend yield - - Risk-free interest rate - .85 % Expected term (in years) - 6.25 No forfeiture rate is assumed for stock options granted to directors or employees due to the forfeiture rate history for these types of awards. During the year ended March 31, 2021, 1,000 unvested stock options were forfeited due to the resignation of an employee and 34,200 vested stock options expired unexercised. During the year ended March 31, 2020, there were no stock options forfeited or expired. F- 18 The following table is a summary of activity of stock options for the years ended March 31, 2021 and 2020: Number of Shares Weighted Average Exercise Price Per Share Weighted Aggregate Average Remaining Contract Life in Years Intrinsic Value Outstanding at April 1, 2019 185,700 $ 6.18 4.68 $ - Granted 42,000 - Exercised - - Forfeited or Expired - - Outstanding at March 31, 2020 227,700 $ 5.65 4.83 $ - Granted - - Exercised (36,500 ) - Forfeited or Expired (35,200 ) - Outstanding at March 31, 2021 156,000 $ 5.28 5.53 $ 555,100 Vested at March 31, 2021 105,250 $ 5.92 4.17 $ 307,000 Exercisable at March 31, 2021 105,250 $ 5.92 4.17 $ 307,000 During the year ended March 31, 2021, stock options covering 36,500 shares were exercised with a total intrinsic value of $72,981. The Company received proceeds of $247,435 from these exercises. During the year ended March 31, 2020, no stock options were exercised. Other information pertaining to option activity was as follows during the year ended March 31: 2021 2020 Weighted average grant-date fair value of stock options granted (per share) $ - $ 2.24 Total fair value of options vested $ 55,460 $ 32,500 Total intrinsic value of options exercised $ 72,981 $ - The following table summarizes information about options outstanding at March 31, 2021: Range of Exercise Prices Number of Options Weighted Average Exercise Price Per Share Weighted Average Remaining Contract Life in Years Aggregate Intrinsic Value $ 3.34 – 4.83 41,000 $ 3.34 4.84 – 5.97 40,000 4.84 5.98 – 6.26 30,000 5.98 6.27 – 7.00 45,000 6.98 $ 3.34 – 7.00 156,000 $ 5.28 5.53 $ 555,100 Outstanding options at March 31, 2021 expire between November 2021 and March 2030 and have exercise prices ranging from $3.34 to $7.00. 13. Related Party Transactions Related party transactions for the Company primarily 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 years ended March 31, 2021 and 2020 were $39,067 and $44,724, respectively. The principal stockholder pays for his share of the lease amount for the shared office space directly to the lessor. Amounts paid by the principal stockholder directly to the lessor for the year ending March 31, 2021 and 2020 were $16,549 and $15,881, respectively. F- 19 In March 2020, the Company entered into an agreement with our principal shareholder, Nicholas C. Taylor for the sale of surface rights to an undivided interest of 1.98 acres in a 160-acre tract of rural land located in Brazoria County, Texas. Mr. Taylor paid the company approximately $18,000 in cash for these rights, such price being based on a November 22, 2019 appraisal by a firm of MAI appraisers at $9,000 per acre. 14. Leases The Company leases approximately 4,160 rentable square feet of office space from an unaffiliated third party for the corporate office located in Midland, Texas. This includes 1,021 square feet of office space shared with and reimbursed by the majority shareholder. The lease is a 36-month lease that expired in May 2021 and does not include an option to renew. In June 2020, in exchange for a reduction in rent for the months of June and July 2020, the Company agreed to a 2-month extension to its current lease agreement at the regular monthly rate extending its current lease expiration date to July 2021. The Company determines an arrangement is a lease at inception. Operating leases are recorded in operating lease right-of-use asset, operating lease liability, current, and operating lease liability, long-term on the consolidated balance sheets. Operating lease right-of-use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent its obligation to make lease payments arising from the lease. Operating lease assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. As the Company’s lease does not provide an implicit rate, the Company uses the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The incremental borrowing rate used at adoption was 6.0%. Significant judgement is required when determining the incremental borrowing rate. The Company chose not to discount because the difference is not significant. Rent expense for lease payments is recognized on a straight-line basis over the lease term. The balance sheets classification of lease assets and liabilities was as follows: March 31, 2021 Assets Operating lease right-of-use asset, beginning balance $ 76,130 Current period amortization (64,629 ) Lease amendment (1,622 ) Lease extension 10,982 Total operating lease right-of-use asset $ 20,861 Liabilities Operating lease liability, current $ 21,965 Operating lease liability, long term - Total lease liabilities $ 21,965 Future minimum lease payments as of March 31, 2021 under non-cancellable operating leases are as follows: Lease Obligation Fiscal Year Ended March 31, 2022 $ 21,965 Fiscal Year Ended March 31, 2023 - Total lease payments $ 21,965 Less: imputed interest - Operating lease liability 21,965 Less: operating lease liability, current (21,965 ) Operating lease liability, long term $ - Net cash paid for our operating lease for the year ended March 31, 2021 and 2020 was $48,360 and $46,447, respectively. Rent expense, less sublease income of $19,109 and $18,234, respectively, is included in general and administrative expenses. F- 20 Subsequently, in June 2021, the Company agreed to extend its current lease for its principal office space located at 415 West Wall Street, Suite 475, Midland, Texas 79701 for 36 months. The amended lease now expires on July 31, 2024. 15. Paycheck Protection Program (PPP) Loan. On March 27, 2020, the Coronavirus Aid, Relief, and Economic Security Act commonly referred to as the CARES Act became effective. One component of the CARES Act was the paycheck protection program (“PPP”) which provides small businesses with the resources needed to maintain their payroll and cover applicable overhead. The PPP is implemented by the United States Small Business Administration (“SBA”) with support from the Department of the Treasury. The PPP provides funds to pay up to 24 weeks of payroll costs including benefits. Funds can also be used to pay interest on mortgages, rent, and utilities. The Company applied for, and was accepted to participate in this program. On May 5, 2020, the Company received funding for approximately $68,600. The loan was a two-year loan with a maturity date of May 5, 2022 an annual interest rate of 1% payable monthly with the first six monthly payments deferred. The Company applied for and on November 25, 2020 was approved for loan forgiveness in the amount of $68,957 under the provisions of Section 1106 of the CARES Act. This was for the forgiveness of our PPP loan in the amount of $68,574 and $383 in accrued interest expense. The Company was eligible for loan forgiveness because the Company used all loan proceeds to partially subsidize direct payroll expenses. 16. Oil and Gas Reserve Data (Unaudited) The estimates of the Company’s proved oil and gas reserves, which are located entirely within the United States, were prepared in accordance with the generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. The estimates as of March 31, 2021 and 2020 were based on evaluations prepared by Russell K. Hall and Associates, Inc. The services provided by Russell K. Hall and Associates, Inc. are not audits of our reserves but instead consist of complete engineering evaluations of the respective properties. For more information about their evaluations performed, refer to the copy of their report filed as an exhibit to this Annual Report on Form 10-K. Management emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future. The following table summarizes the prices utilized in the reserve estimates for 2021 and 2020. Commodity prices utilized for the reserve estimates prior to adjustments for location, grade and quality are as follows: March 31, 2021 2020 Prices utilized in the reserve estimates before adjustments: Oil per Bbl $ 36.49 $ 52.23 Natural gas per MMBtu $ 2.16 $ 2.30 The Company’s total estimated proved reserves at March 31, 2021 were approximately 1.504 MBOE of which 49% was oil and natural gas liquids and 51% was natural gas. F- 21 Changes in Proved Reserves : Oil (Bbls) Natural Gas (Mcf) Proved Developed and Undeveloped Reserves: As of April 1, 2019 1,040,000 5,381,000 Revision of previous estimates (72,000 ) (384,000 ) Purchase of minerals in place - - Extensions and discoveries 90,000 175,000 Sales of minerals in place (6,000 ) (28,000 ) Production (44,000 ) (294,000 ) As of March 31, 2020 1,008,000 4,850,000 Revision of previous estimates (292,000 ) (200,000 ) Purchase of minerals in place - - Extensions and discoveries 92,000 283,000 Sales of minerals in place (20,000 ) (14,000 ) Production (50,000 ) (324,000 ) As of March 31, 2021 738,000 4,595,000 Proved developed reserves are those expected to be recovered through existing wells, equipment and operating methods. Proved undeveloped reserves (“PUD”) are proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion within five years of the date of their initial recognition. Moreover, the Company may be required to write down its proved undeveloped reserves if the operators do not drill on the reserves within the required five-year timeframe. Such downward revisions are primarily the result of reserves written off due to the five-year limitation. They are primarily working interests in a unit in the Wolfcamp B Zone in Upton and Reagan Counties, Texas which are on a lease held by production and still in place to be developed in the future. Summary of Proved Developed and Undeveloped Reserves as of March 31, 2021 and 2020 : Oil (Bbls) Natural Gas (Mcf) Proved Developed Reserves: As of April 1, 2019 376,600 3,823,440 As of March 31, 2020 358,230 3,344,210 As of March 31, 2021 413,050 3,639,330 Proved Undeveloped Reserves: As of April 1, 2019 663,860 1,557,250 As of March 31, 2020 649,570 1,506,160 As of March 31, 2021 325,020 956,050 At March 31, 2021, the Company reported estimated PUDs of 484 MBOE, which accounted for 32% of its total estimated proved oil and gas reserves. This figure primarily consists of a projected 121 new wells (263 MBOE) operated by others, 7 wells are currently being drilled with plans for 60 wells to follow in 2022, 48 wells in 2023 and 6 wells in 2024. The cost of these projects would be funded, to the extent possible, from existing cash balances, cash flow from operations and bank borrowings. The remainder may be funded through non-core asset sales and/or sales of our common stock. The following table discloses the Company’s progress toward the conversion of PUDs during fiscal 2021. Progress of Converting Proved Undeveloped Reserves : Oil & Natural Gas Future (BOE) Development Costs PUDs, beginning of year 900,592 $ 6,632,064 Revision of previous estimates (447,215 ) (3,765,188 ) Sales of reserves (14,394 ) - Conversions to PD reserves (83,202 ) (947,290 ) Additional PUDs added 128,581 1,095,588 PUDs, end of year 484,362 $ 3,015,174 Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using average prices for 2021 and 2020 along with estimates of the operating costs, production taxes and future development costs necessary to produce such reserves. No deduction has been made for depreciation, depletion or any indirect costs such as general corporate overhead or interest expense. F- 22 Operating costs and production taxes are estimated based on current costs with respect to producing oil and natural gas properties. Future development costs including abandonment costs are based on the best estimate of such costs assuming current economic and operating conditions. The future cash flows estimated to be spent to develop the Company’s share of proved undeveloped properties through March 31, 2024 are $3,015,174. Income tax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production and development costs over the current tax basis of the properties involved, less applicable carryforwards. The future net revenue information assumes no escalation of costs or prices, except for oil and natural gas sales made under terms of contracts which include fixed and determinable escalation. Future costs and prices could significantly vary from current amounts and, accordingly, revisions in the future could be significant. The current reporting rules require that year end reserve calculations and future cash inflows be based on the 12-month average market prices for sales of oil and gas on the first calendar day of each month during the fiscal year discounted at 10% per year and assuming continuation of existing economic conditions. The average prices used for fiscal 2021 were $37.42 per bbl of oil and $2.29 per mcf of natural gas. The average prices used for fiscal 2020 were $53.23 per bbl of oil and $1.66 per mcf of natural gas. The standardized measure of discounted future net cash flows is computed by applying the 12-month unweighted average of the first day of the month pricing for oil and natural gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and natural gas reserves, less estimated future expenditures (based on year end costs) to be incurred in developing and producing the proved reserves, discounted using a rate of 10% per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and natural gas properties plus available carryforwards and credits and applying the current tax rate to the difference. The basis for this table is the reserve studies prepared by an independent petroleum engineering consultant, which contain imprecise estimates of quantities and rates of production of reserves. Revisions of previous year estimates can have a significant impact on these results. Also, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates of proved reserves and their valuation. Therefore, the standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of proved oil and gas properties. The following information is based on the Company’s best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of March 31, 2021 and 2020 in accordance with ASC 932, “Extractive Activities – Oil and Gas” which requires the use of a 10% discount rate. This information is not the fair market value, nor does it represent the expected present value of future cash flows of the Company’s proved oil and gas reserves. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves: March 31 2021 2020 Future cash inflows $ 38,144,000 $ 61,676,000 Future production costs and taxes (11,248,000 ) (16,682,000 ) Future development costs (3,213,000 ) (6,984,000 ) Future income taxes (1,714,000 ) (4,675,000 ) Future net cash flows 21,969,000 33,335,000 Annual 10% discount for estimated timing of cash flows (9,206,000 ) (14,359,000 ) Standardized measure of discounted future net cash flows $ 12,763,000 $ 18,976,000 F- 23 Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves: March 31 2021 2020 Sales of oil and gas produced, net of production costs $ (1,902,000 ) $ (1,806,000 ) Net changes in price and production costs (5,680,000 ) (2,871,000 ) Changes in previously estimated development costs 2,623,000 865,000 Revisions of quantity estimates (5,954,000 ) (2,140,000 ) Net change due to purchases and sales of minerals in place (54,000 ) (335,000 ) Extensions and discoveries, less related costs 1,150,000 1,519,000 Net change in income taxes 2,070,000 404,000 Accretion of discount 1,376,000 2,164,000 Changes in timing of estimated cash flows and other 158,000 1,924,000 Changes in standardized measure (6,213,000 ) (276,000 ) Standardized measure, beginning of year 18,976,000 19,252,000 Standardized measure, end of year $ 12,763,000 $ 18,976,000 17. Subsequent Events During the first quarter of fiscal 2022, the Company borrowed $100,000 on the credit facility and made payments totaling $480,000 on the credit facility leaving a balance of $800,000. During the first quarter of fiscal 2022, the Company expended approximately $326,000 for participation in the drilling of eight wells and the completion of six wells in Lea County, New Mexico. In June 2021, the Company agreed to extend its current lease for its principal office space located at 415 West Wall Street, Suite 475, Midland, Texas 79701 for 36 months. The amended lease now expires on July 31, 2024. F- 24 INDEX TO EXHIBITS Exhibit Number 3.1 Restated Articles of Incorporation of Mexco Energy Corporation filed as Exhibit 3.1 to the Company’s Annual Report on Form 10-K dated June 24, 1998, and incorporated herein by reference. 3.2 Amended Bylaws of Mexco Energy Corporation as amended on September 13, 2011 filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K dated September 14, 2011, and incorporated herein by reference. 10.1 2009 Employee Incentive Stock Plan of Mexco Energy Corporation filed as Exhibit A to the Company’s Proxy Statement on Form 14C dated July 15, 2009, and incorporated herein by reference. 10.2 2019 Employee Incentive Stock Plan of Mexco Energy Corporation filed as Exhibit A to the Company’s Proxy Statement on Form 14C dated July 16, 2019, and incorporated herein by reference. 10.3 Loan Agreement dated December 28, 2018 between West Texas National Bank and Mexco Energy Corporation filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K dated December 31, 2018, and incorporated herein by reference. 10.4 First Amendment to Loan Agreement dated February 28, 2020 to the Loan Agreement between West Texas National Bank and Mexco Energy Corporation dated December 31, 2018, and incorporated herein by reference. 14.1 Code of Business Conduct and Ethics of Mexco Energy Corporation filed with the Company’s Quarterly Report on Form 10-Q filed on November 15, 2004, and incorporated herein by reference. 21.1 Subsidiaries of Mexco Energy Corporation 23.1 Consent of Weaver and Tidwell, L.L.P., Independent Registered Public Accounting Firm 23.2 Consent of Russell K. Hall & Associates, Inc., Independent Petroleum Engineers 31.1 Certification of the Chief Executive Officer of the Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification of the Chief Financial Officer of the Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32.1 Certification of the Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 99.1 Report of Russell K. Hall & Associates, Inc., Independent Petroleum Engineering Firm F- 25