UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

For the fiscal year ended March 31 2016, 2023

Commission File No. 0-66941-31785

MEXCO ENERGY CORPORATION

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code:(432) 682-1119

Securities registered pursuant to Section 12(b) of the Act:None

Securities registered pursuant to Section 12(g) of the Act:Common Stock, $0.50 par value per share

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [  ] ☐ No [X] ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes [  ] No [X]☐

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 twelve (12) months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past ninety (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 (§ 229.405232.405 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [  ]

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

Large Accelerated Filer [  ]☐ Accelerated Filer [  ] ☐ Non-Accelerated Filer [  ] ☒ Smaller Reporting Company [X]☒ Emerging Growth Company ☐

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

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.1D-1(b). ☐

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 aggregate market value of the voting stock held by non-affiliates of the Registrant as of September 30, 20152022 (the last business day of the Registrant’s most recently completed second quarter) was $2,228,639 based on Mexco Energy Corporation’s closing common stock price of $2.50 per share on that date$18,892,271 as computed by reference to the last reported by the NYSE MKT.sale.

There were 2,037,2662,136,500 shares of the registrant’s common stock outstanding as of June 23, 2016.26, 2023.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s Proxy Statement relating to the 20162023 Annual Meeting of Shareholders to be held on September 13, 2016,12, 2023, have been incorporated by reference in Part III of this Form 10-K. Such Proxy Statement will be filed with the Commission not later than 120 days after March 31, 2016,2023, the end of the fiscal year covered by this report.

TABLE OF CONTENTS

As used in this document, “the Company”, “Mexco”, “we”, “us” and “our” refer to Mexco Energy Corporation and its consolidated subsidiaries.

Abbreviations or definitions of certain terms commonly used in the oil and gas industry and in this Form 10-K can be found in the “Glossary of Abbreviations and Terms”.

PART I

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K 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”). These forward-looking statements are generally located in the material set forth under the headings “Risk Factors”, “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, “Business”, “Properties” but may be found in other locations as well, and are typically identified by the words “could”, “should”, “expect”, “project”, “estimate”, “believe”, “anticipate”, “intend”, “budget”, “plan”, “forecast”, “predict” and other similar expressions.

Forward-looking statements generally relate to our 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 and are based upon our management’s reasonable estimates of future results or trends. Actual results in future periods may differ materially from those expressed or implied by such forward-looking statements because of a number of risks and uncertainties affecting our business, including those discussed in “Risk Factors”. The factors that may affect our expectations regarding our operations include, among others, the following: our success in development, exploitation and exploration activities; our ability to make planned capital expenditures; declines in our production or prices of oil and gas; our ability to raise equity capital or incur additional indebtedness; our restrictive debt covenants; our acquisition and divestiture activities; weather conditions and events; the proximity, capacity, cost and availability of pipelines and other transportation facilities; increases in the cost of drilling, completion and gas gathering or other costs of production and operations; and other factors discussed elsewhere in this document.

We disclaim any intention or obligation to update or revise any forward-looking statements as a result of new information, future events or otherwise.

PART I

ITEM 1. BUSINESS

General

Mexco Energy Corporation, a Colorado corporation, is an independent oil and gas company engaged in the acquisition, exploration, development and production of crude oil and natural gas and crude oil properties located in the United States. Incorporated in April 1972 under the name Miller Oil Company, the Company changed its name to Mexco Energy Corporation effective April 30, 1980. At that time, the shareholders of the Company also approved amendments to the Articles of Incorporation resulting in a one-for-fifty reverse stock split of the Company’s common stock.

Our total estimated proved reserves at March 31, 20162023 were approximately 2.0511.552 million barrels of oil equivalent (“Boe”MMBOE”) of which 53%47% was oil and natural gas liquids and 47%53% was natural gas, and our estimated present value of proved reserves was approximately $16$39 million based on estimated future net revenues excluding taxes discounted at 10% per annum, pricing and other assumptions set forth in “Item 2 – Properties” below. During fiscal 2016, we added proved reserves of 590,000 Boe through extensions and discoveries, subtracted 4,500 Boe through sales of oil and gas properties and had downward revisions of previous estimates of 136,000 Boe. Such revisions are a result of Security Exchange Commission (“SEC”) rules which require such reserves to be developed within five years as well as decreased oil and natural gas prices.

Nicholas C. Taylor beneficially owns approximately 45%44% of the outstanding shares of our common stock. Mr. Taylor is also our Chairman of the Board and Chief Executive Officer. As a result, Mr. Taylor has significant influence in matters voted on by our shareholders, including the election of our Board members. Mr. Taylor participates in all facets of our business and has a significant impact on both our business strategy and daily operations.

Company Profile

Since our inception, we have been engaged in acquiring and developing oil and gas properties and the exploration for and production of natural gas, crude oil, condensate and natural gas liquids (“NGLs”) within the United States. We especially seek to acquire proved reserves that fit well with existing operations or in areas where Mexco has established production. Acquisitions preferably will contain most of their value in producing wells, behind pipe reserves and high quality proved undeveloped locations. Competition for the purchase of proved reserves is intense. Sellers often utilize a bid process to sell properties. This process usually intensifies the competition and makes it extremely difficult to acquire reserves without assuming significant price and production risks. We actively search for opportunities to acquire proved oil and gas properties. However, because the competition is intense, we cannot give any assurance that we will be successful in our efforts during fiscal 2017.2024.

While we own oil and gas properties in other states, the majority of our activities are centered in the Permian Basin of West Texas.Texas and Southeastern New Mexico. The Company also owns producing properties and undeveloped acreage in thirteenfourteen states. We acquire interests in producing and non-producing oil and gas leases from landowners and leaseholders in areas considered favorable for oil and gas exploration, development and production. In addition, we may acquire oil and gas interests by joining in oil and gas drilling prospects generated by third parties. We may also employ a combination of the above methods of obtaining producing acreage and prospects. In recent years, we have placed primary emphasis on the evaluation and purchase of producing oil and gas properties, bothincluding working, royalty and royaltymineral interests, and prospects that could have a potentially meaningful impact on our reserves. MostAll of the Company’s oil and gas interests are operated by others, however the Company operates several properties in which it owns an interest.others.

From 1983 to 2016,2023, Mexco Energy Corporation made approximately 80numerous acquisitions of producing oil and gas properties including royalties, overriding royalties, minerals and working interests both operatedin producing oil and non-operated plusgas properties including the following most significant and recent acquisitions:

Royalty interests, purchase price $500,000 covering 4 producing gas units in Freestone County, Texas containing 33 producing wells and 17 potential undeveloped locations in the Cotton Valley formation.

Royalty (mineral) acreage, purchase price $1,850,000 covering 122 mineral acres in the Newark East (Barnett Shale) Field of Tarrant County, Texas amounting to approximately 21.45% royalty interest.

Overriding royalty interests, purchase price $1,650,000 covering 5,120 gross acres over 8 sections in the Haynesville trend area of DeSoto Parish, Louisiana containing 6 horizontal producing wells, 2 wells drilling wells, and 57 additional potential drill sites. The Company paid $1.46 million in cash and the remainder was paid as 26,833 shares of its common stock issued from treasury shares.

Royalty interests, purchase price $580,000 covering 580 wells in 87 counties of eight8 states. Approximately 90% of the net revenue from these royalties is produced by 157 wells located in the Barnett Shale of the Fort Worth Basin of Texas. Also included are interests in 423 wells in 8 states.

Non-Operated working interests, purchase price $525,000 for 12.5% (approximately 10% net revenue interest). Eight wells now producing oil on 20-acre spacing at approximately 3,600 foot depth on the 190 acres in Pecos County, TX. The operator has agreed to pay all operating expenses of these interests. Mexco also receives 100% of the gross disposal fees paid by an adjacent operator for one disposal well located on these properties.

Royalty and mineral interests, purchase price $1,000,000 covering approximately 1,800 wells in 27 counties of Texas. Of these oil and gas reserves, approximately 80% is natural gas and 20% oil.

Non-Operated working interests, purchase price $840,000 in 70 Natural gas producing wells located in 5 counties of Oklahoma.

Non-Operated working interests, purchase price $200,000 covering 80 wells located in Hockley and Pecos Counties, Texas.

Non-Operated working interests, purchase price $450,000 covering 43 wells in Webster Parish, Louisiana; Eddy County, New Mexico; and, Nolan and Smith Counties, Texas.

Royalty interests, purchase price of $939,000 covering 22 producing wells and several additional potential locations for development in the Eagleford area of Dimmit County, Texas.

Royalty interest investment, $2,000,000 for an approximate 2% investment commitment in a limited liability company, capitalized at approximately $100 million to purchase royalty interests consisting of minerals located in the Marcellus and Utica areas of Ohio. As of the date of this report, $400,000 of the commitment has been expended.

Royalty interests, purchase price of $117,200 covering 28 producing wells in 6 counties in the Haynesville trend area of Louisiana and 5 counties in Texas.

Industry Environment and Outlook

CrudeThe outbreak of the novel coronavirus (“COVID-19”) resulted in a severe worldwide economic downturn, significantly disrupting the demand for oil throughout the world, and created significant volatility, uncertainty and turmoil in the oil and gas industry. The decrease in demand for oil, combined with excess supply of oil and related products, resulted in oil prices remaineddeclining significantly depressed in fiscal 2016late February 2020. Since mid-2020, oil prices have improved, with demand steadily increasing despite the uncertainties surrounding the COVID-19 variants, which have continued to inhibit a full global demand recovery. In addition, worldwide oil inventories, from a historical perspective, remain low and face continued downward pressureconcerns exist with the ability of Organization of Petroleum Exporting Countries (“OPEC”) and other oil producing nations to meet forecasted future oil demand growth in 2023 and 2024, with many OPEC countries not able to produce at their OPEC agreed upon quota levels due to domestictheir limited capital investments, and global supply and demand factors. The downward price pressure intensifiedincreases in late 2015 and early 2016, with crudecost over the last few years directed towards developing incremental oil prices dropping below $23 per barrel in February 2016, a level not seen since 2003. Natural gas prices faced similar downward pressure, dropping below $1.50 per mcf in March 2016.supplies.

In light of the challenges facing our industry and in response to these price declines, our primary business strategies for fiscal 2017 will include: (1) optimizing cash flows through operating efficiencies and cost reductions, (2) divesting of non-core assets, and (3) working to balance capital spending with cash flows to minimize new borrowings, reduce debt and maintain ample liquidity.

See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for discussion of our fiscal 20162023 operating results and potential impact on fiscal 20172024 operating results due to depressed commodity prices.price changes.

Oil and Gas Operations

As of March 31, 2016,2023, oil constituted approximately 53%70% of our oil and gas revenues and approximately 47% of our total proved reserves and approximately 67% of our revenuesvolumes for fiscal 2016.2023. Revenues from oil and gas royalty interests accounted for approximately 24%28% of our oil and gas revenues for fiscal 2016.2023.

Mexco believes there is potential for horizontal drilling, multi-stage fracturing and production of oil and gas in a substantial number of properties containing approximately 1,150 wells in which Mexco holds an interest. These wells are located in the core area of the horizontal Wolfcamp multi-zone formation in Reagan, Upton, Midland, Martin, Glasscock and Andrews Counties in the Midland Basin of West Texas. Such interests vary from .125% to 7.68% working interest (.094% to 6.24% net revenue interest, respectively).

In addition to these working interests, we also own various mineral and royalty interests in and around these core counties in the Midland Basin, a part of the Permian Basin of West Texas.

There are two primary areas in which the Company is focused, 1) the Midland Basin located in the Eastern portion of the Permian Basin including Reagan, Upton, Midland, Martin, Howard, Glasscock and Crockett Counties, Texas and 2) the Delaware Basin located in the Western portion of the Permian Basin including Lea and Eddy Counties, New Mexico and Reeves and Loving County,Counties, Texas and 2) the Midland Basin located in the Eastern portion of the Permian Basin including Reagan, Upton, Midland, Martin, Howard and Glasscock Counties, Texas. The Permian Basin in total accounts for 80% of our discounted future net cash flows from proved reserves and 79% of our gross revenues.

The MidlandPermian Basin is one of the oldest and most prolific producing basins in North America which has been a significant source of oil production since the 1920s. The Permian Basin is known to have a number of zones of oil and natural gas bearing rock throughout.

The Delaware Basin properties, encompassing 71,47730,007 gross acres, 285195 net acres, 534610 gross producing wells and 2.54 net wells account for approximately 42%58% of our discounted future net cash flows from proved reserves as of March 31, 2016.2023. For fiscal 2023, these properties accounted for 62% of our net revenues. Of these discounted future net cash flows from proved reserves, approximately 32%15% are attributable to proven undeveloped reserves which willwould be developed through new drilling. For fiscal 2016, these properties accounted for 19% of our gross revenues and 24% of our net revenues.

The DelawareMidland Basin properties, encompassing 29,63897,584 gross acres, 623256 net acres, 4581,016 gross producing wells and 5.22 net wells account for approximately 18% of our discounted future net cash flows from proved reserves as of March 31, 2016.2023. For fiscal 2023, these properties accounted for 14% of our net revenues. Of these discounted future net cash flows from proved reserves, approximately 2%8% are attributable to proven undeveloped reserves which willwould be developed through new drilling. For fiscal 2016, these properties accounted for 24% of our gross revenues and 29% of our net revenues.

Gomez Gas Field properties, encompassing 13,058 gross acres, 72 net acres, 26 gross wells and .13 net wells in Pecos County, Texas, account for approximately 3% of our discounted future net cash flows from proved reserves as of March 31, 2015. For fiscal 2016, these properties accounted for 3% of our gross revenues and 5% of our net revenues. All of these properties, except for one, are royalty interests. There is a potential for development of the horizontal Wolfcamp on these interests.

The Goldsmith North Field (San Andres formation) long-lived oil producing properties, encompassing 240 gross acres, 153 net acres, 3 gross wells in Ector County, Texas, account for 7.3% of our discounted future net cash flows from proved reserves as of March 31, 2016. Of these discounted future net cash flows from proved reserves, 7% are attributable to proven undeveloped reserves which will be developed through new drilling of 4 wells. For fiscal 2016, these properties consist of working interests and accounted for 3% of our gross revenues and .1% of our net revenues.

In August 2013, Mexco assigned Pioneer Natural Resources Company a three year term leasehold interest in 417.33 net acres (837.33 gross acres) of undeveloped acreage located above and below the Pembrook Unit of Upton County, Texas and retained a 1% royalty.

In November 2015, Mexco extended a six month option for which the Company received $112,000 for a three year assignment of a leasehold interest in 320 net acres (640 gross acres) in Upton County, Texas. The purchaser paid Mexco $2,000 per acre for a total of $640,000. Mexco also retained a 1% overriding royalty interest in this acreage. This acreage has the potential for horizontal development in multiple zones of the horizontal Wolfcamp formation centered in the southern Midland Basin. The purchaser advises that he has obtained rights to explore the balance of the undivided 640 acres from Apache Corporation and has been advised that Parsley Energy, Inc. plans to develop this property.

Mexco believes its most important properties for future development by horizontal drilling and hydraulic fracturing area are located in Lea and Eddy Counties, New Mexico of the Delaware Basin and the Midland Basin in Midland, Reagan and Upton Counties, Texas of the Midland Basin.Texas.

For more on these and other operations in this area see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources Commitments”.

We own interests in and operate 13 producing wells and 1 water injection well. We own partial interests in an additional 6,461approximately 6,400 producing wells all of which are located within the United States in the states of Texas, New Mexico, Oklahoma, Louisiana, Alabama, Mississippi, Arkansas, Wyoming, Kansas, Colorado, Montana, Virginia, North Dakota, and North Dakota.Ohio. Additional information concerning these properties and our oil and gas reserves is provided below.

The following table indicates our oil and gas production in each of the last five years:

Competition and Markets

The oil and gas industry is a highly competitive business. Competition for oil and gas reserve acquisitions is significant. We may compete with major oil and gas companies, other independent oil and gas companies and individual producers and operators, some of which have financial and personnel resources substantially in excess of those available to us. As a result, we may be placed at a competitive disadvantage. Competitive factors include price, contract terms and types and quality of service, including pipeline distribution. The price for oil and gas is widely followed and is generally subject to worldwide market factors. Our ability to acquire and develop additional properties in the future will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment in a timely manner.

In addition, the oil and gas industry as a whole also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. The price and availability of alternative energy sources could adversely affect our revenue.

Market factors affect the quantities of oil and natural gas production and the price we can obtain for the production from our oil and natural gas properties. Such factors include: the extent of domestic production; the level of imports of foreign oil and natural gas; the general level of market demand on a regional, national and worldwide basis; domestic and foreign economic conditions that determine levels of industrial production; political events in foreign oil-producing regions; and variations in governmental regulations including environmental, energy conservation and tax laws or the imposition of new regulatory requirements upon the oil and natural gas industry.

The market for our oil, gas and natural gas liquids production depends on factors beyond our control including: domestic and foreign political conditions; the overall level of supply of and demand for oil, gas and natural gas liquids; the price of imports of oil and gas; weather conditions; the price and availability of alternative fuels; the proximity and capacity of gas pipelines and other transportation facilities; and overall economic conditions.

Major Customers

We made sales to the following companies that amounted to 10% or more of oil and gas revenues as follows for the yearyears ended March 31:

Historically, the Company has not experienced significant credit losses on our oil and gas accounts and management is of the opinion that significant credit risk does not exist. Because a ready market exists for oil and gas production, we do not believe the loss of any individual customerpurchaser would have a material adverse effect on our financial position or results of operations.

Environmental Regulation

Our exploration, development, productionThe oil and marketing operations are subject to various types of extensive rules and regulations bygas industry is extensively regulated at the federal, state, and local authorities. Numerouslevels. Regulations affecting elements of the energy sector are under constant review for amendment or expansion and frequently more stringent requirements are imposed. Various federal and state and local departments and agencies, have issued rules and regulations binding onincluding the oil and gas industry, someTexas Railroad Commission, the Bureau of which carry substantial penalties for noncompliance. State statutes and regulations require permits and bonds for drilling operations and reports concerning operations. Most states and some counties and municipalities in which we operate regulateLand Management (the “BLM”), an agency of the locationU.S Department of wells; the method of drilling and casing wells;Interior (“DOI”), the rates of production or “allowables”; the surface use and restoration of properties upon which wells are drilled; the plugging and abandoning of wells; and notice to, and consultation with, surface owners and other third parties. The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects its profitability. Because these rules and regulations are frequently amended or reinterpreted, we are not able to predict the future cost or impact of complying with such laws.

The Federal Energy Regulatory Commission (“FERC”) regulates under, the Natural Gas ActU.S. Environmental Protection Agency (the “EPA”), the Department of 1938Transportation (“DOT”) and the Natural Gas Policy Act of 1978, interstate natural gas transportation ratesU.S. Occupational Safety and service conditions,Health Administration (“OSHA”), have legal and regulatory authority and oversight over the operations on the properties in which affect the marketing of natural gas we produce, as well as the revenues we receive for sales of such production. Since 1978, various laws have been enacted which have significantly altered the marketing and transportation of gas. These orders resulted in a fundamental restructuring of interstate pipeline sales and transportation services, including the unbundling by interstate pipelines of the sales, transportation, storage and other components of the city-gate sales, services such pipelines previously performed.Company owns an interest.

Commencing in 1985, the FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, unregulated, open access market for gas purchases and sales that permits all purchasers of gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated. Therefore, we cannot guarantee that the less stringent regulatory approach will continue indefinitely into the future, nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated market prices. Nevertheless, Congress could reenact price controls in the future. The price we receive from the sale of these products is affected by the cost of transporting the products to market. The FERC regulates interstate crude oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate crude oil pipeline rates must be cost-based, although many pipeline charges are today based on historical rates adjusted for inflation and other factors, and other charges may result from settlement rates agreed to by all shippers or market-based rates, which are permitted in certain circumstances. Intrastate crude oil pipeline transportation rates are subject to regulation by state regulatory commissions. Insofar as the interstate and intrastate transportation rates that we pay are generally applicable to all comparable shippers, we believe that the regulation of crude oil transportation rates will not affect our operations in a way that materially differs from the effect on the operations of our competitors who are similarly situated. Further, interstate and intrastate common carrier crude oil pipelines must provide service on an equitable basis.

Under this standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When crude oil pipelines operate at full capacity, access is governed by prorating provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to crude oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

The State of Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both.

States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill. The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

Environmental Matters

By nature of our oil and gas operations, we are subject to extensive federal, state and localcertain environmental laws and regulations, controlling the generation, use, storage and discharge of materials into the environment or otherwise relating to the protectionoperators of the environment. Numerous governmental departments issue rulesCompany properties could be subject to strict, joint and regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial penaltiesseveral liability for failure to comply. These laws and regulations may require the acquisitionremoval or remediation of property contamination, whether at a permit before drillingdrill site or production commences; restricta waste disposal facility, even when the types, quantities and concentration of various substances that can be released intooperators did not cause the environment in connection with drilling and production activities; limitcontamination or prohibit construction or drillingtheir activities on certain lands lying within protected areas; restrict the rate of oil and gas production; require remedial actions to prevent pollution from former operations; and impose substantial liabilities for pollution resulting from our operations. In addition, these laws and regulations may impose substantial liabilities and penalties for failure to comply with them or for any contamination resulting from our operations. We believe we arewere in compliance inwith all material respects, with applicable environmental requirements. We do not believe costs relating to these laws and regulations have had a material adverse effect on our operations or financial condition inat the past. Public interest intime the protection of the environment has increased dramatically in recent years.

The trend of applying more expansive and stricter environmental legislation and regulations to the natural gas and oil industry could continue, resulting in increased costs of doing business and consequently affecting our profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly waste handling, disposal and cleanup requirements, our business and prospects could be adversely affected.

The following are some of the existing laws, rules and regulations to which our business is subject:

actions were taken. The Comprehensive Environmental Response, Compensation and Liability Act(“CERCLA”), also known as the “Superfund”“superfund” law, for example, imposes liability, without regard toregardless of fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed tofor releases into the releaseenvironment of a “hazardous substance” into the environment. Thesesubstance.” Liable persons may include the current or previous owner orand operator of the disposal site or thea site where the release occurreda hazardous substance has been disposed and companies that disposed orpersons who arranged for the disposal of thea hazardous substances.substance at a site. Under CERCLA suchand similar statutes, government authorities or private parties may take actions in response to threats to the public health or the environment or sue responsible persons for the associated costs. In the course of operations, the working interest owner and/or the operator of the Company properties may have generated and may generate materials that could trigger cleanup liabilities. In addition, the Company properties have produced oil and/or natural gas for many years, and previous operators may have disposed or released hydrocarbons, wastes or hazardous substances at the Company properties. The operator of the Company properties or the working interest owners may be subject to joint and several liabilitiesresponsible for all or part of the costs to clean up any such contamination. Although the Company is not the operator of cleaning upsuch properties, its ownership of the hazardous substances thatproperties could cause it to be responsible for all or part of such costs to the extent CERCLA or any similar statute imposes responsibility on such parties as “owners.”

Various state governments and regional organizations comprising state governments already have been released intoenacted legislation and promulgated rules restricting greenhouse gases (“GHGs”) emissions or promoting the environment, for damages to natural resourcesuse of renewable energy, and for the costs of certain health studies. In addition,additional such measures are frequently under consideration. Although it is not uncommon for neighboring landownerspossible at this time to estimate how potential future requirements addressing GHG emissions would impact operations on the Company properties and other third partiesrevenue, either directly or indirectly, any future federal, state or local laws or implementing regulations that may be adopted to file claims for personal injury and property damage allegedly caused byaddress GHG emissions could require the hazardous substances released into the environment. We are able to control directly the operationoperators of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We do not believe that we will be requiredproperties to incur any material capital expendituresnew or increased costs to comply with existing environmental requirements.

The federalClean Air Act (“CAA”),obtain permits, operate and state air pollution laws and regulations provide a framework for national, state and local efforts to protect air quality. The operations of oil and gas properties utilize equipment that emits air pollutants which may be subject to federal and state air pollution control laws. These laws require utilization of air emissions abatement equipment to achieve prescribed emissions limitations and ambient air quality standards, as well as operating permits for existingmaintain equipment and construction permitsfacilities, install new emission controls, acquire allowances to authorize GHG emissions, pay taxes related to GHG emissions or administer a GHG emissions program. Regulation of GHGs could also result in a reduction in demand for new and modified equipment. Permits and related compliance obligations under the CAA, as well as changes to state implementation plans for controlling air emissions in regional non-attainment areas may require oil and natural gas exploration and production operators to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies.

In addition, some oil and natural gas facilities may be included within the categories of hazardous air pollutant sources, which are subject to increasing regulation under the CAA. Failure to comply with these requirements could subject a regulated entity to monetary penalties, injunctions, conditions or restrictions on operations and enforcement actions. On April 17, 2012, the EPA issued a final rule that established new source performance standards for volatile organic compounds, or VOCs, and sulfur dioxide, an air toxics standard for major sources of oil and natural gas production, and an air toxics standard for major sources of natural gas transmission and storage. These regulations apply to natural gas wells that are hydraulically fractured, or refractured, and to storage tanks and other equipment. Since January 1, 2015, all wells subjectgas. Additionally, to the rule have been required to use “green completion” technology to limit emissions during well completion operations.

Recent scientific studies have suggestedextent that emissions of certain gases, commonly referred to as greenhouse gases (“GHGs”) and including carbon dioxide and methane,unfavorable weather conditions are exacerbated by global climate change or otherwise, the Company properties may be contributingadversely affected to warming of the Earth’s atmosphere. These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. In September 2009, the EPA issued a GHG monitoring and reporting rule that requires certain parties, including participants in the oil and natural gas industry, to monitor and report their GHG emissions, including methane and carbon dioxide, to the EPA.greater degree than previously experienced.

The EPA’s finding, the GHG reporting rules, and the rules to regulate the emissions of GHGs may affect the outcome of other climate change lawsuits pending in U.S. federal courts in a manner unfavorable to our industry. In addition to the EPA’s actions to regulate GHGs, more than one-third of the states have begun taking action on their own to control and/or reduce emissions of GHGs. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility. Any of the climate change regulatory and legislative initiatives described above in areas in which we conduct business could result in increased compliance costs or additional operating restrictions which could have a material adverse effect on our business, financial condition, and results of operations.

The Federal Water Pollution Control Act (“Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including produced waters and other oil and gas wastes, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the applicable state agency. Although the costs to comply with such mandates under state or federal law may be significant, the entire industry will experience similar costs, and we do not believe that these costs will have a material adverse impact on our financial condition and operations.

The Resource Conservation and Recovery Act (“RCRA”) and analogous state laws govern the handling and disposal of hazardous and solid wastes. Wastes that are classified as hazardous under RCRA are subject to stringent handling, recordkeeping, disposal and reporting requirements. RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy.” However, these wastes may be regulated by the EPA or state agencies as solid waste. Moreover, many ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils, are regulated as hazardous wastes. Although the costs of managing hazardous waste may be significant, we do not expect to experience more burdensome costs than similarly situated companies.

The Safe Drinking Water Act (“SDWA”) and theUnderground Injection Control (“UIC”) program promulgated under the SDWA and state and local laws regulate the drilling and operation of salt water disposal (“SWD”) wells and the underground injection of waste substances produced from oil and gas operations. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and gas production. The EPA directly administers the UIC program in some states and in others it is delegated to the state for administering. Permits must be obtained before drilling SWD wells and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking saltwater into groundwater. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs. In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury. We currently operate one underground injection well and own interests in various underground injection wells operated by others and failure to abide by their permits could subject us and those operators to civil and/or criminal enforcement. We are, and believe the other operators are as well, in compliance in all material respects with the requirements of applicable state underground injection control programs and permits.

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly oil and natural gas, from tight formations, including shales. This technology involves the injection of fluids—usually consisting mostly of water but typically including small amounts of chemical additives—as well as sand into a well under high pressure in order to create fractures in the rock that allow oil or gas to flow more freely to the wellbore. Many newer wells would not be economical without the use of hydraulic fracturing to stimulate production from the well. We engage third parties to occasionally provide hydraulic fracturing or other well stimulation services to us in connection with many of the wells we operate. Hydraulic fracturing generally is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions.

For example, the Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission has adopted rules and regulations implementing this legislation that apply to all wells for which the Railroad Commission issues an initial drilling permit after February 1, 2012. This law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (OSHA) for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

We believe that we are in compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations, however we cannot assure you that the passage or application of more stringent laws or regulations in the future will not have an negative impact on our financial position or results of operation. We did not incur any material capital expenditures for remediation or pollution control activities for the year ended March 31, 2016.2023. Additionally, as of the date of this report, we are not aware of any environmental issues or claims that will require material capital expenditures during fiscal 2017.2024.

Various state and federal statutes prohibitOther Regulation

Other agencies with certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources. These statutesauthority over the Company’s business include theEndangered Species Act Internal Revenue Service (the “IRS”), the SEC and theMigratory Bird Treaty Act, as well as,NYSE. Ensuring compliance with the CWArules, regulations and CERCLA. The United States Fishorders promulgated by such entities requires extensive effort and Wildlife Service may designate critical habitatincremental costs to comply, which affects the Company’s profitability. Because public policy changes are commonplace, and suitable habitat areasexisting laws and regulations are frequently amended, the Company is unable to predict the future cost or impact of compliance. However, the Company does not expect that it believes are necessary for survivalany of threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land usethese laws and private land useregulations will affect its operations materially differently than they would affect other companies with similar operations, size and could delay or prohibit land access or development.financial strength.

Title to Properties

As is customary in the oil and gas industry, only a preliminary title examination is conducted at the time properties believed to be suitable for drilling operations are acquired by us. Prior to the commencement of drilling operations, a thorough title examination of the drill site tract is conducted and curative work is performed with respect to significant defects, if any, before proceeding with operations. A thorough title examination has been performed with respect to substantially all leasehold producing properties currently owned by us. We believe the title to our leasehold properties is good and defensible in accordance with standards generally acceptable in the oil and gas industry subject to such exceptions that, in the opinion of counsel employed in the various areas in which we have conducted exploration activities, are not so material as to detract substantially from the use of such properties.

The leasehold properties we own are subject to royalty, overriding royalty and other outstanding interests customary in the industry. The properties may be subject to burdens such as liens incident to operating agreements and current taxes, development obligations under oil and gas leases and other encumbrances, easements and restrictions. We do not believe any of these burdens will materially interfere with the use of these properties.

Prior to drilling of an oil and natural gas well, it is normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our operators’ failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest. We believe the title to our properties is good and defensible in accordance with standards generally acceptable in the oil and gas industry subject to such exceptions that, in the opinion of counsel employed in the various areas in which we have activities, are not so material as to detract substantially from the use of such properties.

Substantially all of our properties are currently mortgaged under a deed of trust to secure funding through a revolving line of credit.credit facility.

Insurance

Our operations are subject to all the risks inherent in the exploration for and development and production of oil and gas including blowouts, fires and other casualties. We maintain insurance coverage customary for operations of a similar nature, but losses could arise from uninsured risks or in amounts in excess of existing insurance coverage.

Executive Officers

The following table sets forth certain information concerning the executive officers of the Company as of March 31, 2016.2023.

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Set forth below is a description of the principal occupations during at least the past five years of each executive officer of the Company.

Nicholas C. Taylor was elected Chairman of the Board and Chief Executive Officer of the Company in September 2011 and continues to serve in such capacity on a part time basis, as required. He served as Chief Executive Officer, President and Director of the Company from 1983 to 2011. From July 1993 to the present, Mr. Taylor has been involved in the independent practice of law and other business activities. In November 2005 he was appointed by the Speaker of the House to the Texas Ethics Commission and served until February 2010.

Tamala L. McComic, a Certified Public Accountant and Chartered Global Management Accountant, became Controller for the Company in July 2001 and was elected President and Chief Financial Officer in September 2011. She served the Company as Executive Vice President and Chief Financial Officer from 2009 to 2011 and Vice President and Chief Financial Officer from 2003 to 2009. Prior thereto, Ms. McComic was appointedserved as Treasurer and Assistant Secretary of the Company.

Donna Gail Yanko was appointed to the position of Vice President of the Company in 1990. She has also served as Corporate Secretary sincefrom 1992 to 2021 and from 1986 to 1992 was Assistant Secretary. From 1986 to 2015, on a part-time basis, she has assisted the Chairman of the Board of the Company in his personal business activities. Ms. Yanko also served as a director of the Company from 1990 to 2008.

EmployeesStacy D. Hardin joined the Company in 2006 and was elected Corporate Secretary of the Company in September 2021. She has also served the Company as Assistant Treasurer of the Company since 2010 and from 2006 to 2021 was Assistant Secretary. Prior thereto, Ms. Hardin served as Assistant Controller.

Employees

As of March 31, 2015,2023, we had fourthree full-time and three part-time employees. We believe that relations with these employees are generally satisfactory. From time to time, we utilize the services of independent geological, land and engineering consultants on a limited basis and expect to continue to do so in the future. We also utilize the services of independent contractors to perform well drilling and production operations, including pumping, maintenance, inspection and testing.

Office Facilities

Our principal offices are located at 214415 W. Texas Avenue,Wall, Suite 1101,475, Midland, Texas 79701 and our telephone number is (432) 682-1119. On April 1, 2013, we agreed to a three year lease, with an option to renew for an additional two years, for our 3,199 square feet of office space which expired on April 1, 2016. On April 1, 2014, we agreed to a three year lease for an additional 340 square feet of office space which will expire on April 1, 2017. In February 2016, we exercised our option to renew the April 1, 2013 lease extending its expiration to April 1, 2018. We believe our facilities are adequate for our current operations and that we can obtain additional leased space if needed.future needs.

Access to Company Reports

Mexco Energy Corporation files annual, quarterly and current reports, proxy statements and other information with the SEC. Please call the SEC at 1-800-SEC-0330 for information on the public reference room. The SEC maintains an internet website (www.sec.gov) that contains annual, quarterly and current reports, proxy statements and other information that issuers, including Mexco, file electronically with the SEC.

We also maintain an internet website at www.mexcoenergy.com. In the Investor Relations section, our website contains our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and other reports and amendments to those reports as soon as reasonably practicable after such material is electronically filed with the SEC. Information on our website is not incorporated by reference into this Form 10-K and should not be considered part of this report or any other filing that we make with the SEC. Additionally, our Code of Business Conduct and Ethics and the charters of our Audit Committee, Compensation Committee and Nominating Committee are posted on our website. Any of these corporate documents as well as any of the SEC filed reports are available in print free of charge to any stockholder who requests them. Requests should be directed to our corporate Assistant Secretary by mail to P.O. Box 10502, Midland, Texas 79702 or by email to mexco@sbcglobal.net.

ITEM 1A. RISK FACTORS

There are many factors that affect our business and results of operations, some of which are beyond our control. The following is a description of some of the important factors that could have a material adverse effect on our business, financial position, liquidity and results of operations. Some of the following risks relate principally to the industry in which we operate and to our business. Other risks relate principally to the securities markets and ownership of our common stock.

RISKS RELATED TO OUR BUSINESS AND INDUSTRY

Volatility of oil and gas prices significantly affects our results and profitability.

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 supply and pricing of oil and gas; the abilityactions of the Organization of Petroleum Exporting Countries (“OPEC”)OPEC, its members and other state-controlled oil companies relating to set and maintain oil price and production controls; nature and extent of governmental regulation and taxation, including environmental regulations; level of domestic and international exploration, drilling and production activity; the cost of exploring for, producing and delivering oil and gas; speculative trading in crude oil and natural gas derivative contracts; availability, proximity and capacity of oil and gas pipelines and other transportation facilities; weather conditions; the price and availability of alternative fuels; technological advances affecting energy consumption; national and international pandemics; and, overall political and economic conditions in oil producing countries.

Increases and decreases in prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. The amount we can borrow from banks may be subject to redetermination based on changes in prices. In addition, we may have ceiling test writedowns when prices decline. 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.

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 exploration and development activities.

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 is natural gas. Lower prices or lack of storage may have an adverse affect on our financial condition due to reduction of our revenues, operating income and cash flows; curtailment or shut-in of our production due to lack of transportation or storage capacity; cause certain properties in our portfolio to become economically unviable; and, limit our financial condition, liquidity, and/or ability to finance planned capital expenditures and operations.

Our results of operations may be negatively impacted by current global events.

The economies in the United States and certain countries in Europe and Asia have been growing, with resulting improvements in industrial demand and consumer confidence. However, other economies, such as those of certain South American nations, continue to face economic struggles or slowing economic growth. If these conditions worsen, combined with a decline in economic growth in other parts of the world, there could be a significant adverse effect on global financial markets and commodity prices. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. Global or national health concerns may adversely affect the Company by (i) reducing demand for its oil, NGLs and gas because of reduced global or national economic activity, (ii) impairing its supply chain (for example, by limiting manufacturing of materials used in operations) and (iii) affecting the health of its workforce, rendering employees unable to work or travel. If the economic climate in the United States or abroad were to deteriorate, due to inflation, rising interest rates or otherwise, demand for petroleum products could diminish or stagnate, which could depress the prices at which the Company could sell its oil, NGLs and gas, affect the ability of the Company’s vendors, suppliers and customers to continue operations and ultimately decrease the Company’s cash flows and profitability. In addition, reduced worldwide demand for debt and equity securities issued by oil and gas companies may make it more difficult for the Company to raise capital to fund its operations or refinance its debt obligations.

Changes in environmental laws could increase our operators’ costs and adversely impact our business, financial condition and cash flows.

President Biden has indicated that he is supportive of, and has issued executive orders promoting various programs and initiatives designed to, among other things, curtail climate change, control the release of methane from new and existing oil and natural gas operations, and decarbonize electric generation and the transportation sector. In recent years the U.S. Congress has considered legislation to reduce emissions of GHGs, including methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas. For example, the Inflation Reduction Act of 2022 (the “IRA”), which appropriates significant federal funding for renewable energy initiatives and, for the first time ever, imposes a fee on GHG emissions from certain facilities, was signed into law in August 2022. The emissions fee and funding provisions of the law could increase operating costs within the oil and gas industry and accelerate the transition away from fossil fuels, which could in turn adversely affect our business and results of operations.

Governmental, scientific and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including climate change related pledges made by certain candidates elected to public office. President Biden has issued several executive orders focused on addressing climate change, including items that may impact costs to produce, or demand for, oil and gas.

Lower oil and gas prices and other factors may cause us to record ceiling test writedowns.

Lower oil and gas prices increase the risk of ceiling limitation write-downs. We use the full cost method to account for oil and gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop crude oil and natural gas properties.properties including the cost of abandoned properties, dry holes, geophysical costs and annual lease rentals. Sales or other dispositions of oil and natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded. Depletion of evaluated oil and natural gas properties is computed in the units of production method, whereby capitalized costs are amortized over total proved reserves. Under the full cost accounting rules, the net capitalized cost of crude oil and natural gas properties may not exceed a “ceiling limit” which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10% plus the lower of cost or fair market value of unproved properties. If net capitalized costs of oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess against earnings. This is called a “ceiling test writedown.” We use the unweighted arithmetic average first day of the month price for oil and natural gas for the 12-month period preceding the calculation date in estimating discounted future net reserves. Under the accounting rules, we are required to perform a ceiling test each quarter. A ceiling test writedown does not impact cash flow from operating activities, but does reduce stockholders’ equity and earnings. The risk that we will be required to write down the carrying value of oil and natural gas properties increases when oil and natural gas prices are low. We incurred impairment charges during fiscal 2016 and may incur additional impairment charges in the future, particularly if commodity prices remain at their currently low levels or decline, further, which could have a material adverse effect on our results of operations for the periods in which such charges are taken. There were no ceiling test impairments on our oil and gas properties during fiscal 20152023 and 2014.2022.

In the past we have entered into price swap derivatives and may in the future enter into additional price swap derivatives for a portion of our production, which may result in our making cash payments or prevent us from receiving the full benefit of increases in prices for oil.

We have used price swap derivatives to reduce price volatility associated with certain of our oil sales. Under these swap contracts, we receive a fixed price per barrel of oil and pay a floating market price per barrel of oil to the counterparty based on NYMEX WTI pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty. Such contracts and any future swap arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase. In addition, these arrangements may limit the benefit to us of increases in the price of oil.

We must replace reserves we produce.

Our future success depends upon our ability to find, develop or acquire additional, economically recoverable oil and gas reserves. Our proved reserves will generally decline as reserves are depleted, except to the extent that we can find, develop or acquire replacement reserves. One offset to the obvious benefits afforded by higher product prices especially for small to mid-cap companies in this industry, is that quality domestic oil and gas reserves are hard to find.

Approximately 47%26% and 39%37% of our total estimated net proved reserves at March 31, 20162023 and 2015,2022, respectively, were undeveloped, and those reserves may not ultimately be developed.

Recovery of undeveloped reserves requires significant capital expenditures and successful drilling. Our reserve data assumes that we can and will make these expenditures and conduct these operations successfully. These assumptions, however, may not prove correct. IfDelays in the development of our reserves, increases in costs to develop such reserves, or decreases in commodity prices will reduce the future net revenues or our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, if we or the outside operators of our properties choose not to spend the capital to develop these reserves, or if we are not able to successfully develop these reserves, we will be required to write-off these reserves. Any such write-offs of our reserves could reduce our ability to borrow money and could reduce the value of our common stock.

Information concerning our reserves and future net revenues estimates is inherently uncertain.

Estimates of oil and gas reserves, by necessity, are projections based on engineering data, and there are uncertainties inherent in the interpretation of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that are difficult to measure. Estimates of economically recoverable oil and gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, such as future production, oil and gas prices, operating costs, development costs and remedial costs, all of which may vary considerably from actual results. As a result, estimates of the economically recoverable quantities of oil and gas and of future net cash flows expected therefrom may vary substantially. As required by the SEC, the estimated discounted future net cash flows from proved reserves are based on a twelve month un-weighted first-day-of-the-month average oil and gas prices for the twelve months prior to the date of the report. Actual future prices and costs may be materially higher or lower.

An increase in the differential between NYMEX and the reference or regional index price used to price our oil and gas would reduce our cash flow from operations.

Our oil and gas is priced in the local markets where it is produced based on local or regional supply and demand factors. The prices we receive for our oil and gas are typically lower than the relevant benchmark prices, such as The New York Mercantile Exchange (“NYMEX”). The difference between the benchmark price and the price we receive is called a differential. Numerous factors may influence local pricing, such as refinery capacity, pipeline capacity and specifications, upsets in the midstream or downstream sectors of the industry, trade restrictions and governmental regulations. Additionally, insufficient pipeline capacity, lack of demand in any given operating area or other factors may cause the differential to increase in a particular area compared with other producing areas. During fiscal 2016,2023, differentials averaged $1.01$4.57 per Bbl of oil and $0.39($0.28) per Mcf of gas. Increases in the differential between the benchmark prices for oil and gas and the wellhead price we receive could significantly reduce our revenues and our cash flow from operations.

Our exploration and development drilling may not result in commercially productive reserves.

New wells that we drill may not be productive, or we may not recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that crude oil or natural gas is present or may be produced economically. Drilling for crude oil and natural gas often involves unprofitable efforts, not only from dry holes but also from wells that are productive but do not produce sufficient net reserves to return a profit at then realized prices after deducting drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project.

Drilling and operating activities are high risk activities that subject us to a variety of factors that we cannot control.

These factors include availability of workover and drilling rigs, well blowouts, cratering, explosions, fires, formations with abnormal pressures, pollution, releases of toxic gases and other environmental hazards and risks. Any of these operating hazards could result in substantial losses to us. In addition, we incur the risk that no commercially productive reservoirs will be encountered, and there is no assurance that we will recover all or any portion of our investment in wells drilled or re-entered.

Acquisitions are subject to the risks and uncertainties of evaluating reserves and potential liabilities and may be disruptive and difficult to integrate into our business.

We plan to continue growing our reserves through acquisitions. Acquired properties can be subject to significant unknown liabilities. Prior to completing an acquisition, it is generally not feasible to conduct a detailed review of each individual property to be acquired in an acquisition. Even a detailed review or inspection of each property may not reveal all existing or potential liabilities associated with owning or operating the property. Moreover, some potential liabilities, such as environmental liabilities related to groundwater contamination, may not be discovered even when a review or inspection is performed. Our initial reserve estimates for acquired properties may be inaccurate. Downward adjustments to our estimated proved reserves, including reserves added through acquisitions, could require us to write down the carrying value of our oil and gas properties, which would reduce our earnings and our stockholders’ equity. In addition, we may have to assume cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions. The scope and cost of these obligations may ultimately be materially greater than estimated at the time of the acquisition.

We may not be able to fund the capital expenditures that will be required for us to increase reserves and production.

We must make capital expenditures to develop our existing reserves and to discoveracquire new reserves. Historically, we have used our cash flow from operations and borrowings under our revolving credit facility to fund our capital expenditures, however, lower oil and gas prices may prevent these options. Volatility in oil and gas prices, the timing of our drilling programs and drilling results will affect our cash flow from operations. Lower prices and/or lower production will also decrease revenues and cash flow, thus reducing the amount of financial resources available to meet our capital requirements, including reducing the amount available to pursue our drilling opportunities. If our cash flow from operations does not increase as a result of planned capital expenditures, a greater percentage of our cash flow from operations will be required for debt service and operating expenses and our planned capital expenditures would, by necessity, be decreased.

The borrowing base under our credit facility will be determined from time to time by the lender. Reductions in estimates of oil and gas reserves could result in a reduction in the borrowing base, which would reduce the amount of financial resources available under the credit facility to meet our capital requirements. Such a reduction could be the result of lower commodity prices and/or production, inability to drill or unfavorable drilling results, changes in oil and gas reserve engineering, the lenders’lender’s inability to agree to an adequate borrowing base or adverse changes in the lenders’lender’s practices regarding estimation of reserves.

If cash flow from operations or our borrowing base decrease for any reason, our ability to undertake exploration and development activities could be adversely affected. As a result, our ability to replace production may be limited. In addition, if the borrowing base under the credit facility is reduced, we would be required to reduce our borrowings under the credit facility so that such borrowings do not exceed the borrowing base. This could further reduce the cash available to us for capital spending and, if we did not have sufficient capital to reduce our borrowing level, we may be in default under the credit facility.

Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management hasand outside operators have specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including crude oil and natural gas prices, the availability of capital, costs, drilling results, regulatory approvals and other factors. If future drilling results in these projects do not establish sufficient reserves to achieve an economic return, we may curtail drilling in these projects. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce crude oil or natural gas from these or any other potential drilling locations.

Failure to comply with covenants underOur business depends on oil and natural gas transportation facilities which are owned by others.

The marketability of our debt agreement could adversely impact our financial condition and results of operations.

Our revolving credit facility agreement requires us to comply with certain customary covenants including limitations on change of control, disposition of assets, mergers and reorganizations. We are also obligated to meet certain financial covenants. For example, our revolving credit facility requires, among other things, minimum earnings before interest, taxes, depreciation and amortization (“EBITDA”) of $100,000 for the two fiscal quarters ending September 30, 2016, $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 1.25 to 1 for the fiscal quarter ending June 30, 2016 and 2 to 1 for each quarter thereafter. If we fail to meet any of these loan covenants, the lender under the revolving credit facility could accelerate the indebtedness and seek to forecloseproduction depends in part on the pledged assets.availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities. Federal and state regulation of oil and gas production and transportation, tax and energy policies, changes in supply and demand and general economic conditions could all affect our ability to produce and market our oil and gas.

We have limited control over activities on properties we do not operate, which could reduce our production and revenues.

All of our business activities are conducted through joint operating or other agreements under which we own working and royalty interests in natural gas and oil properties in which we do not operate. As a result, we have a limited ability to exercise influence over normal operating procedures, expenditures or future development of underlying properties and their associated costs. The failure of an operator of our wells to adequately perform operations could reduce our revenues and production.

Acquiring reserves in the oil and gas industry is highly competitive.

Competition for oil and gas reserve acquisitions is significant. We may compete with major oil and gas companies, other independent oil and gas companies and individual producers and operators, some of which have financial and personnel resources substantially in excess of those available to us. As a result, we may be placed at a competitive disadvantage. Our ability to acquire and develop additional properties in the future will depend upon our ability to select and acquire suitable producing properties and prospects for future development activities. In addition, the oil and gas industry as a whole also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. The price and availability of alternative energy sources could adversely affect our revenue. The market for our oil, gas and natural gas liquids production depends on factors beyond our control, including domestic and foreign political conditions, the overall level of supply of and demand for oil, gas and natural gas liquids, the price of imports of oil and gas, weather conditions, the price and availability of alternative fuels, the proximity and capacity of gas pipelines and other transportation facilities and overall economic conditions.

We have limited control over activities on properties we do not operate, which could reduce our production and revenues.

A substantial amount of our business activities are conducted through joint operating or other agreements under which we own working and royalty interests in natural gas and oil properties in which we do not operate. As a result, we have a limited ability to exercise influence over normal operating procedures, expenditures or future development of underlying properties and their associated costs. The failure of an operator of our wells to adequately perform operations could reduce our revenues and production.

Our business depends on oil and natural gas transportation facilities which are owned by others.

The marketability of our production depends in part on the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities. Federal and state regulation of oil and gas production and transportation, tax and energy policies, changes in supply and demand and general economic conditions could all affect our ability to produce and market our oil and gas.

We may not be insured against all of the operating hazards to which our business is exposed.

Our operations are subject to all the risks inherent in the exploration for, and development and production of oil and gas including blowouts, fires and other casualties. We maintain insurance coverage customary for operations of a similar nature, but losses could arise from uninsured risks or in amounts in excess of existing insurance coverage.

Increases in taxes on energy sources may adversely affect the company’s operations.

Federal, state and local governments which have jurisdiction in areas where the company operates impose taxes on theCertain U.S. federal income tax deductions currently available with respect to crude oil and natural gas products sold. Historically, thereexploration and development may be eliminated as a result of proposed legislation.

Legislation previously has been an on-going consideration by federal, state and local officials concerning a variety of energy tax proposals. Such matters are beyond our ability to accurately predict or control.

Proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations and cash flows.

The U.S. President’s Fiscal Year 2016 Budget Proposal includes provisionsproposed that would, if enacted into law, make significant changes to U. S. federal income tax laws, including the elimination of certain key U.S. federal income tax deductionsincentives currently available to crude oil and natural gas exploration and production companies. OtherThese changes include, but are not limited to: (1) the repeal of the percentage depletion allowance for crude oil and natural gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for certain U.S. domestic production activities, and (4) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted orand, if enacted, how soon any such changes could become effective. The passage of this type of legislation or any other similar changes in the U. S.U.S. federal income tax laws could negativelyeliminate or postpone certain tax deductions that are currently available with respect to crude oil and natural gas exploration and development, and any such change could have an adverse effect on the value of an investment in our Common Stock as well as our financial position, results of operations and cash flows.

Our reliance on information technology, including those hosted by third parties, exposes us to cyber security risks that could affect our business, financial condition and results of operations.or reputation.

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, and processing activities, including digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering systems, conduct reservoir modeling and reserves estimation, and process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. The U.S. government has issued public warnings that indicate energy assets might be specific targets of cyber security threats. Our and our operators’ technologies, systems, networks, and those of vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of business activities. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Our systems for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents.

The loss of our chief executive officer or other key personnelpresident could adversely impact our ability to execute our business strategy.

We depend, and will continue to depend in the foreseeable future, upon the continued services of our Chief Executive Officer, Nicholas C. Taylor and our President and Chief Financial Officer, Tamala L. McComic, and other key personnel, who have extensive experience and expertise in evaluating and analyzing producing oil and gas properties and drilling prospects, maximizing production from oil and gas properties and developing and executing acquisitions and financing. WeAs of March 31, 2023, we do not have key-man insurance on the lives of Mr. Taylor and Ms. McComic. The unexpected loss of the services of one or more of these individuals could, therefore, significantly and adversely affect our operations. Competition for qualified individuals is intense and we may be unable to find or attract qualified replacements for our officers and key employees on acceptable terms.

We may be affected by one substantial shareholder.

Nicholas C. Taylor beneficially owns approximately 45%44% of the outstanding shares of our common stock. Mr. Taylor is also our Chairman of the Board and Chief Executive Officer. As a result, Mr. Taylor has significant influence in matters voted on by our shareholders, including the election of our Board members. Mr. Taylor participates in all facets of our business and has a significant impact on both our business strategy and daily operations. The retirement, incapacity or death of Mr. Taylor, or any change in the power to vote shares beneficially owned by Mr. Taylor, could result in negative market or industry perception and could have an adverse effect on our business.

RISKS RELATED TO OUR COMMON STOCK

We may issue additional shares of common stock in the future, which could cause dilution to all shareholders.

We may seek to raise additional equity capital in the future. Any issuance of additional shares of our common stock will dilute the percentage ownership interest of all shareholders and may dilute the book value per share of our common stock.

We have not and do not anticipate paying any cash dividends on our common stock in the foreseeable future.

We have paid no cash dividends on our common stock to date and it is not anticipated that any will be paid to holders of our common stock in the foreseeable future. The terms of our existing credit facility restricts the payment of dividends without the prior written consent of the lenders. We currently intend to retain all future earnings to fund the development and growth of our business. Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that our board of directors deems relevant. Stockholders must rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment.

Control by our executive officers and directors may limit your ability to influence the outcome of matters requiring stockholder approval and could discourage our potential acquisition by third parties.

As of March 31, 2016,2023, our executive officers and directors beneficially owned approximately 48%47% of our common stock. These stockholders, if acting together, would be able to influence significantly all matters requiring approval by our stockholders, including the election of our board of directors and the approval of mergers or other business combination transactions.

The price of our common stock has been volatile and could continue to fluctuate substantially.

Mexco common stock is traded on the New York Stock Exchange’s NYSE MKT.American. The market price of our common stock has and could continue to experience volatility due to reasons unrelated to our operating performance. These reasons include: supply and demand for oil and natural gas and oil;gas; political conditions in oil and natural gas and oil producing regions; demand for our common stock and limited trading volume; investor perception of our industry; fluctuations in commodity prices; variations in our results of operations; legislative or regulatory changes; general trends in the oil and natural gas industry; market conditions and analysts’ estimates; and, other events in the oil and gas industry.

Many of these factors are beyond our control, and we cannot predict their potential effects on the price of our common stock. We cannot assure you that the market price of our common stock will not fluctuate or decline significantly in the future. In addition, the stock markets in general can experience considerable price and volume fluctuations.

Failure of the Company’s internal control over financial reporting could harm its business and financial results.

The management of Mexco is responsible for establishing and maintaining effective internal control over financial reporting. Internal control over financial reporting is a process to provide reasonable assurance regarding the reliability of financial reporting for external purposes in accordance with accounting principles generally accepted in the United States. Internal control over financial reporting includes maintaining records that in reasonable detail accurately and fairly reflect Mexco’s transactions; providing reasonable assurance that transactions are recorded as necessary for preparation of the financial statements; providing reasonable assurance that receipts and expenditures are made in accordance with management authorization; and providing reasonable assurance that unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements would be prevented or detected on a timely basis.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Our properties consist primarily of oil and gas wells and our ownership in leasehold acreage, both developed and undeveloped. As of March 31, 2016,2023, we had interests in 6,461approximately 6,400 gross (34.3(18.5 net) producing oil and gas wells and owned leasehold mineral, royalty and royaltyother interests in approximately 580,978544,000 gross (5,152(2,768 net) acres.

Oil and Natural Gas Reserves

In accordance with current SEC rules, the average prices used in computing reserves at March 31, 20162023 were $41.76$92.02 per bbl of oil and $74.84compared to $74.52 in 2015, a decrease2022, an increase of 44%23%, and $1.998$5.68 per mcf of natural gas and $3.595compared to $4.60 in 2015, a decrease2022, an increase of 44%23%, such prices are based on the 12-month unweighted arithmetic average market prices for sales of oil and natural gas on the first calendar day of each month during fiscal 2016.2023. The benchmark price of $42.77$87.45 per bbl of oil at March 31, 20162023 versus $79.21$71.72 at March 31, 2015,2022, was adjusted by lease for gravity, transportation fees and regional pricemarket differentials and did not give effect to derivative transactions. The benchmark price of $2.39$5.96 per mcf of natural gas at March 31, 20162023 versus $3.88$4.09 at March 31, 2015,2022, was adjusted by lease for BTU content, transportation fees and regional pricemarket differentials. The average prices used in computing reserves at March 31, 2014 were $94.23 per bbl of oil and $3.67 per mcf of natural gas. The benchmark prices used in computing reserves at March 31, 2014 were $94.92 per bbl of oil and $3.99 per mcf of natural gas.

For information concerning our costs incurred for oil and gas operations, net revenues from oil and gas production, estimated future net revenues attributable to our oil and gas reserves, present value of future net revenues discounted at 10% and changes therein, see Notes to the Company’s consolidated financial statements.

The engineering report with respect to Mexco’s estimates of proved oil and gas reserves as of March 31, 2016, 2015 and 2014 is based on evaluations prepared by Joe C. Neal and Associates, Petroleum and Environmental Engineering Consultants, based in Midland, Texas (“Neal and Associates”), a summary of which is filed as Exhibit 99.1 to this annual report.

Management maintains internal controls designed to provide reasonable assurance that the estimates of proved reserves are computed and reported in accordance with rules and regulations provided by the SEC. As stated above, Mexco retained Joe C. Neal and Associates to prepare estimates of our oil and gas reserves. Management works closely with this firm, and is responsible for providing accurate operating and technical data to it. Our Chief Financial Officer who has over 20 years experience in the oil and gas industry reviews the final reserves estimate and consults with a degreed geological consultant with extensive geological experience and if necessary, discusses the process used and findings with Mr. Neal. Mr. Neal is responsible for overseeing the preparation of the reserve estimates and holds a bachelor’s degree in mechanical engineering (petroleum option), is a member of the Society of Petroleum Engineers and has over 50 years of experience in the oil and gas industry. Our Chairman and Chief Executive Officer who has over 40 years of experience in the oil and gas industry also reviews the final reserves estimate.

Proved reserves are estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production.

The engineering report with respect to Mexco’s estimates of proved oil and gas reserves as of March 31, 2023 and 2022 is based on evaluations prepared by Russell K. Hall and Associates, Inc. Environmental Engineering Consultants, based in Midland, Texas (“Hall and Associates”), a summary of which is filed as Exhibit 99.1 to this annual report.

Management maintains internal controls designed to provide reasonable assurance that the estimates of proved reserves are computed and reported in accordance with rules and regulations provided by the SEC. As stated above, Mexco retained Hall and Associates to prepare estimates of our oil and gas reserves. Management works closely with this firm, and is responsible for providing accurate operating and technical data to it. Our Chief Financial Officer who has over 25 years experience in the oil and gas industry reviews the final reserves estimate and consults with a degreed geological consultant with extensive geological experience and if necessary, discusses the process used and findings with Alan Neal, the technical person at Hall and Associates responsible for evaluating the proved reserves covered by this report. Mr. Neal is a member of the Society of Petroleum Engineers and has over 35 years of experience in the oil and gas industry. Our Chairman and Chief Executive Officer who has over 45 years of experience in the oil and gas industry also reviews the final reserves estimate.

Numerous uncertainties exist in estimating quantities of proved reserves. Reserve estimates are imprecise and subjective and may change at any time as additional information becomes available. Furthermore, estimates of oil and gas reserves are projections based on engineering data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.interpretation. Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from the assumptions and estimates. Any significant variance could materially affect the estimated quantities and value of our oil and gas reserves, which in turn may adversely affect our cash flow, results of operations and the availability of capital resources.

Per the current SEC rules, the prices used to calculate our proved reserves and the present value of proved reserves set forth herein are made using the 12-month unweighted arithmetic average of the first-day-of-the-month price. All prices are held constant throughout the life of the properties. Actual future prices and costs may be materially higher or lower than those as of the date of the estimate. The timing of both the production and the expenses with respect to the development and production of oil and gas properties will affect the timing of future net cash flows from proved reserves and their present value. Except to the extent that we acquire additional properties containing proved reserves or conduct successful exploration and development activities, or both, our proved reserves will decline as reserves are produced.

Our estimated proved oil and gas reserves and present value of estimated future net revenues from proved oil and gas reserves in the periods ended March 31 are summarized below.

PROVED RESERVES

We have not filed any other oil or gas reserve estimates or included any such estimates in reportsDuring fiscal 2023, we added proved reserves of 101 thousand BOE (“MBOE”) through extensions and discoveries, added 52 MBOE through acquisitions, subtracted 54 MBOE for downward revisions of previous estimates. Such downward revisions are primarily the result of reserves written off due to other federal or foreign governmental authority or agency during the year ended March 31, 2016,five-year limitation and no major discovery is believed to have caused a significantthe change in our estimatesthe timing of proved reserves since that date.new development. They are primarily royalty interests on leases in Loving, Pecos and Ward Counties, Texas which are held by production and still in place to be developed in the future.

During the fiscal year ending March 31, 2016, 4 wells in which2023, we ownhad a working or royalty interest were developedin the development of 59 wells converting reserves of approximately 66,000 mcfe186,000 BOE from proved undeveloped to proved developed - producing. We participated in the development of 20 wells converting reserves– producing with capital cost of approximately 190,000 mcfe from proved undeveloped to proved developed - producing. The capital cost was approximately $733,000 for the 20 wells in which we own a working interest.$3,612,000.

Oil and gas prices significantly impact the calculation of the PV-10 and the standardized measure of discounted future net cash flows. The present value of future net cash flows does not purport to be an estimate of the fair market value of the Company’s proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money and the risks inherent in producing oil and gas. Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The 10% discount factor used to calculate present value, which is required by Financial Accounting Standards Board (“FASB”) pronouncements,Accounting Standard Codification (“ASC”) 932, “Extractive Activities – Oil and Gas”, may not necessarily be the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

Productive Wells and Acreage

Productive wells consist of producing wells and wells capable of production, includingWe have not filed any other oil or gas wells awaiting pipeline connections. Wells that are completedreserve estimates or included any such estimates in more than one producing zone are counted as one well. The following table indicates our productive wells as ofreports to other federal or foreign governmental authority or agency during the year ended March 31, 2016:2023, and no major discovery is believed to have caused a significant change in our estimates of proved reserves since that date.

A gross acre is an acre in which an interest is owned. A net acre is deemed to exist when the sum of fractional ownership interests in gross acres equals one. The number of net acres is the sum of the fractional interests owned in gross acres.

The following table sets forth the approximate developed acreage in which we held a leasehold mineral or other interest as of March 31, 2016:

Drilling Activities

The following table sets forth our drilling activity in wells in which we own a working interest for the years ended March 31:

We have not participated in any exploratory wells during the years ended March 31, 2016, 2015 and 2014. The information contained in the foregoing table should not be considered indicative of future drilling performance, nor should it be assumed that there is any necessary correlation between the number of productive wells drilled and the amount of oil and gas that may ultimately be recovered by us.

In addition to the working interests mentioned above, other operators drilled 85 gross wells (.04 net wells) on company-owned minerals and royalties at no expense to the Company. We expect the production of our mineral interests will increase as operators continue to drill, complete and develop our acreage. We expect to capitalize on this development, which requires no capital expenditure funding from us, and believe the anticipated aggregate royalty receipts will enable us to grow our cash flows. A number of the horizontal wells in which the Company participates involve longer lateral which are more efficient and have greater estimated ultimate recovery.

Productive Wells and Acreage

Productive wells consist of producing wells and wells capable of production, including gas wells awaiting pipeline connections. Wells that are completed in more than one producing zone are counted as one well. As of March 31, 2023, we held an interest in approximately 6,400 gross (18.5 net) productive wells, including approximately 5,200 wells in which we held an overriding or royalty interest and 1,100 wells in which we held a working interest.

A gross acre is an acre in which an interest is owned. A net acre is deemed to exist when the sum of fractional ownership interests in gross acres equals one. The number of net acres is the sum of the fractional interests owned in gross acres. The following table sets forth the approximate developed acreage in which we held a leasehold mineral or other interest as of March 31, 2023:

Net Production, Unit Prices and Costs

The following table summarizes our net oil and natural gas production, the average sales price per barrel (“bbl”) of oil and per thousand cubic feet (“mcf”) of natural gas produced and the average production (lifting) cost per unit of production for the years ended March 31:

ITEM 3. 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 4. MINE SAFETY DISCLOSURES

Not applicable.

Not applicable.

PART II

ITEM 5.MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

In September 2003, our common stock began trading on the NYSE MKT,American, formerly the American Stock Exchange and more recently the NYSE MKT, under the symbol “MXC”. Prior to September 2003, the Company’s common stock was traded on the over-the-counter bulletin board market under the symbol “MEXC”. The registrar and transfer agent is Computershare Trust Company N.A., 250 Royall Street, Canton, Massachusetts, 02021Issuer Direct Corporation, 500 Perimeter Park Drive, Suite D, Morrisville, North Carolina, 27560 (Tel: 800-962-4284)877-481-4014). The following table sets forth certain information as to the high and low sales price quoted for Mexco’s common stock on the NYSE MKT.American.

On June 15, 2016,March 31, 2023, the closing sales price of our common stock on the NYSE MKTAmerican was $3.02$11.38 per share.

Stockholders

As of March 31, 2016,2023, we had approximately 2,104,2662,221,416 shares issued and 889849 shareholders of record which does not include shareholders for whom shares are held in a “nominee” or “street” name.

Dividends

We have never declared or paid any cash dividends on our common stock. We currently intend to retain future earnings and other cash resources, if any, for the operation and development of our business and do not anticipate paying any cash dividends on our common stock Of these issued shares, 85,416 are held in the foreseeable future.treasury.

Dividends

As of March 31, 2023, the Company had never paid a cash dividend to the Company’s shareholders. Payment of any future dividends will beare at the discretion of our Board of Directors after taking into account many factors, including our financial condition, operating results, current and anticipated cash needs and plans for expansion. In addition, our current bank loan prohibits us from paying cash dividends on our common stock. Anystock without written permission.

Subsequently, on April 10, 2023, the Company announced that its Board of Directors declared a special dividend of $0.10 per common share to its shareholders of record at the close of business on May 1, 2023. The special dividend was paid on May 15, 2023. The Company obtained written permission from WTNB prior to declaring the special dividend.

The Company can provide no assurance that dividends will be authorized or declared in the future or as to the amount or type of any future dividends. Our board of directors’ determination with respect to any such dividends, may also be restrictedincluding the record date, the payment date and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions imposed by any loan agreements which we may enter into fromapplicable law and other factors that the board deems relevant at the time to time.of such determination.

Securities Authorized for Issuance Under Compensation Plans

The following table includes certain information about our Employee Incentive Stock Plan as of March 31, 2016,2023, which has been approved by our stockholders.

Issuer Repurchases

In June 2015,September 2022, the Boardboard of Directorsdirectors authorized the use of up to $250,000 to repurchase shares of our common stock for the treasury account. This program does not have an expiration date.date and may be modified, suspended or terminated at any time by the board of directors. Under the repurchase program, shares of common stock may be purchased from time to time through open market purchases or other transactions. The amount and timing of repurchases will be subject to the availability of stock, prevailing market conditions, the trading price of the stock, our financial performance and other conditions. Repurchases may also be made from time-to-time in connection with the settlement of our share-based compensation awards. Repurchases will be funded from cash flow from operations.

The following table provides information related to repurchases of our common stock for the treasury account during the year ended March 31, 2023:

During the year ended March 31, 2023, the Company repurchased 18,416 shares for the treasury account at an aggregate cost of $244,494, an average price of $13.28 per share. There were no shares of our common stock repurchased for the treasury account during the fiscal year ended March 31, 2016. During2022.

Subsequently, in April 2023, the fiscal year ended March 31, 2015, we repurchased 1,000Company’s Board of Directors authorized the use of up to $1,000,000 to repurchase shares of the Company’s common stock, par value, $0.50, for the treasury at an aggregate cost of $5,009. There were no shares of ouraccount. This authorization replaced the previously authorized $250,000 common stock repurchasedrepurchase program which had $5,506 remaining at the time it was replaced.

On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (“IRA 2022”). The IRA 2022, among other tax provisions, establishes a 1% excise tax on stock repurchases made by publicly traded U.S. corporations, effective for stock repurchases after December 31, 2022. The IRA 2022 does provide for certain exceptions for repurchases of stock including an exception as long as the aggregate value of the repurchases for the treasury account during the fiscaltax year ended March 31, 2014.does not exceed $1,000,000.

ITEM6. RESERVED

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this Form 10-K.

Liquidity and Capital Resources and Commitments

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

Due to depressed commodity price environment, we are applying financial discipline to all aspects of our business. In order to meet obligations, we will continue to sell non-core assets, if necessary. This will enable us to participate in any Midland and Delaware Basin projects. 

Our long termlong-term strategy is on increasing profit margins while concentrating on obtaining reserves with low costlow-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,interests and non-operated properties in areas with significant development potential.

Cash Flows

Changes in the net funds provided by or (used in) each of our operating, investing and financing activities are set forth in the table below:

Cash Flow Provided by Operating Activities. Cash flow from operating activities is primarily derived from the production of our crude oil and natural gas reserves and changes in the balances of non-cash accounts, receivables, payables or other non-energy property asset account balances. Cash flow provided by our operating activities for the year ended March 31, 2023 was $6,515,895 in comparison to $3,744,407 for the year ended March 31, 2022. This increase of $2,771,488 in our cash flow operating activities consisted of an increase in our non-cash expenses of $565,838; a decrease in our accounts receivable of $594,673; a decrease of $128,615 in our accounts payable and accrued expenses; and, an increase in our net income of $1,807,636. Variations in cash flow from operating activities may impact our level of exploration and development expenditures.

Our expenditures in operating activities consist primarily of production expenses and engineering services. Our expenses also consist of employee compensation, accounting, insurance and other general and administrative expenses that we have incurred in order to address normal and necessary business activities of a public company in the crude oil and natural gas production industry.

Cash Flow Used in Investing Activities. Cash flow from investing activities is derived from changes in oil and gas property balances. For the year endingended March 31, 2016, cash flow from operations was $175,502, an 85% decrease when compared to the corresponding period of fiscal 2015. Net cash of $370,000 was used to reduce the line of credit and2023, we had net cash of $132,427 was provided by activity associated with$5,014,357 used for additions to oil and gas properties and other propertya $425,000 investment in two limited liability companies compared to $1,635,024 and equipment. $75,000, respectively, for the year ended March 31, 2022.

Cash Flow Used in Financing Activities. Cash flow from financing activities is derived from our changes in long-term debt and in equity account balances. Net cash flow used in our financing activities was $209,815 for the year ended March 31, 2023 compared to net cash flow used in our financing activities of $721,430 for the year ended March 31, 2022. During the year ended March 31, 2023, we received advances and made payments of $675,000 on our credit facility, received proceeds of $16,700 from the exercise of director stock options, received payment of $30,179 form a director for profits on purchase of stock within the six-month window of a previous stock sale, expended $244,494 for the purchase of 18,416 shares of our stock for the treasury and, expended $12,200 for the renewal of our credit facility. During the year ended March 31, 2022, we received advances of $275,000 and made payments of $1,455,000 on our credit facility and received proceeds of $458,570 for the exercise of employee and director stock options.

Accordingly, net cash decreased $62,071.increased $865,005, leaving cash and cash equivalents on hand of $2,235,771 as of March 31, 2023.

We had working capital of $23,150$3,475,776 as of March 31, 20162023 compared to working capital of $166,650$2,469,776 as of March 31, 2015, a decrease2022, an increase of $143,500$1,006,000 for the reasons set forth below.

Oil and Natural Gas Property TransactionsDevelopment.

During fiscal year 2016, MexcoNew Participations in Fiscal 2023. The Company participated in the lastdrilling and completion of 50 horizontal wells at a cost of approximately $4,200,000, of which $3,750,000 was expended during the fiscal year ending March 31, 2023. Eighteen of these wells have not been completed. Thirty-nine of these horizontal wells are in the Delaware Basin located in the western portion of the Permian Basin in Lea and Eddy Counties, New Mexico and twelve are in the Midland Basin located in the eastern portion of the Permian Basin in Reagan County, Texas.

In addition to the above working interests, there were 85 gross wells (.04 net wells) drilled by other operators on Mexco’s royalty interests and 50 gross wells (.29 net wells) obtained through acquisitions.

In April 2022, Mexco expended approximately $176,000 to participate in the drilling of four horizontal wells in the Wolfcamp Sand formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .52%. Subsequently, in May 2023, Mexco expended approximately $211,000 to complete these wells.

Mexco expended approximately $1,196,000 to participate in the drilling and completion of three horizontal wells in the Wolfcamp BSand formation of the Spraberry Field of Martin County, Texas. All three wells, operated by QEP Energy Company, are currently producing. Our shareMidland Basin located in the eastern portion of the costs to drill and complete these wells for our .2125% working interest (.159% net revenue interest) was approximately $76,000.

We participatedPermian Basin in the completion of three horizontal wells in the Penn Detrital formation of the F A Hogg Field of WinklerReagan County, Texas. All three wells in two units, operated by Apache Corporation, are currently producing on approximately 1,900 acres. Mexco’s working interest in these wells is .4167% (.3125% net revenue interest)3.2%. Our share of the costs to complete theseThese wells was approximately $54,000 in fiscal 2016.

A joint venture in which Mexco is a working interest owner participated in two wellswere completed in Wolfcamp AOctober 2022 with initial average production rates of 507 barrels of oil, 2,147 barrels of water and B formations using horizontal drilling and multi-stage fracture stimulation on a 1,125-acre tract in Reagan County, Texas. These wells, operated by Bold Energy III, LLC, are currently producing. Our share2,147,000 cubic feet of the costsgas per day, or, 560 barrels of oil equivalent per day.

Mexco expended approximately $681,000 to drill, fracture and complete these two wells for our approximately 3.13% working interest including a carried interest from and at the expense of Bold (2.48% net revenue interest) was approximately $411,000 to date ($224,000 of which was expended in fiscal 2016).

Mexco participatedparticipate in the drilling and completion of oneeight horizontal wellwells in the Wolfcamp Sand formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .52%. These wells were completed in February and March 2023 with initial average production rates of 1,011 barrels of oil, 4,581 barrels of water and 3,577,000 cubic feet of gas per day, or 1,607 barrels of oil equivalent per day.

Mexco expended approximately $607,000 to participate in the drilling and completion of anothera horizontal well in the ThirdWolfcamp Sand formation of the Midland Basin in Reagan County, Texas. Mexco’s working interest in this well is 5.1%. This well was completed in October 2022 with initial average production rates of 295 barrels of oil, 1,313 barrels of water and 237,000 cubic feet of gas per day, or, 335 barrels of oil equivalent per day.

Mexco expended approximately $649,000 to participate in the drilling and completion of four horizontal wells in the Bone Spring formation of the Delaware Basin in LeaEddy County, New Mexco. Both wells are operated by XTO Energy, Inc., a subsidiary of Exxon Mobil Corporation.Mexico. Mexco’s share of the costs during fiscal 2016 forworking interest in these wells wasis 2.1%. These wells began producing in October 2022 with initial average production rates of 1,154 barrels of oil, 2,887 barrels of water and 2,966,000 cubic feet of gas per day, or, 1,648 barrels of oil equivalent per day.

Mexco expended approximately $267,000 for our 2.78% working interest (1.95% net revenue interest).

Mexco participated$84,000 to participate in the drilling and completion of two horizontal wells and the completion of another horizontal well in the Lower AvalonPenn Shale formation locatedof the Delaware Basin in Lea County, New Mexico and operated by Concho Resources, Inc. All three wells are now producing. During fiscal 2016, Mexco has expended $96,000 for our approximate .60%Mexico. Mexco’s working interest (.45% net revenue interest)in these wells is .22%. These wells began producing in January 2023 with initial average production rates of 1,367 barrels of oil, 3,900 barrels of water and 1,786,000 cubic feet of gas per day, or, 1,665 barrels of oil equivalent per day.

Mexco participatedexpended approximately $30,000 to participate in the drilling and completion of one horizontal well and one salt water disposal well and the completion of two other horizontal wells in the Red Hills (Avalon) FieldBone Spring formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .1%. These wells operated by Concho Resources, Inc. are now all producing. Mexco’s sharebegan producing in February 2023 with initial average production rates of the costs through March 31, 2016 for these wells as well as purchase622 barrels of additional interests wasoil, 1,991 barrels of water and 262,000 cubic feet of gas per day, or, 666 barrels of oil equivalent per day.

Mexco expended approximately $131,000 for our approximately .49% working interest (.32% net revenue interest).

Mexco also participated$93,000 to participate in the drilling and completion of foureight horizontal wells and one vertical well in the Berry (Third Bone Spring) Field of Lea County, New Mexico. The wells, operated by Concho Resources, Inc. are now all producing. Mexco’s shareSpraberry trend of the costs through March 31, 2016 forMidland Basin in Reagan County, Texas. Mexco’s working interest in these wells wasis approximately $50,000 for our approximately .29% working interest (.18% net revenue interest).11%. These wells began producing in December 2022.

Mexco participatedexpended $16,000 to participate in the drilling and completion of three horizontal wells and one salt water disposal well and the completion of another horizontal well in the Avalon Shale portion of the Bone Spring formation of the Delaware Basin in Eddy County, New Mexico. Mexco’s working interest in these wells is .05%. These wells were subsequently completed in May 2023 with initial average production rates of 437 barrels of oil, 983 barrels of water and 603,000 cubic feet of gas per day, or, 538 barrels of oil equivalent per day.

In February 2023, Mexco expended approximately $31,000 to participate in the drilling and completion of seven horizontal wells in the Bone Spring formation of the Delaware Basin in Lea County, New Mexico. These wells, operated by Concho Resources, Inc. are now all producing. Mexco’s share of the costs through March 31, 2016 for these wells as well as purchase of additional interests was approximately $253,000. Mexco’s working interestsinterest in these wells now range from .74%is approximately .03%. These wells are currently being completed.

In January 2023, Mexco expended $180,000 to 1.07% (.44%participate in the drilling of four horizontal wells in the Wolfcamp Sand formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is approximately .52%. These wells are currently awaiting completion operations.

In March 2023, Mexco expended approximately $60,000 to .60% net revenue interest)participate in the drilling of two horizontal wells in the Penn Shale formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is approximately .285%. These wells began drilling in April 2023.

In November 2015, Mexco’s purchaser exercised a six month lease assignment extension option for whichOctober 2022, the Company received $112,000 formade an approximately 2% equity investment commitment in a three year assignmentlimited liability company amounting to $2,000,000 of a leasehold interest in 320 net acres (640 gross acres) in Upton County, Texas.which $400,000 has been funded to date. The purchaser paid Mexco $2,000 per acre for a total of $640,000. Mexco also retained a 1% overriding royalty interest in this acreage. This acreage has the potential for horizontal development in multiple zones of the horizontal Wolfcamp formation centeredlimited liability company is capitalized at approximately $100 million to purchase mineral interests in the southern Midland Basin.Utica and Marcellus areas in the state of Ohio.

Completion of Wells Drilled in Fiscal 2023. The purchaser advisesCompany expended approximately $329,000 for the completion costs of 8 horizontal wells located in Lea County, New Mexico that he has obtained rights to explore the balanceCompany participated in drilling during fiscal 2022. The first 4 of the undivided 640 acres from Apache Corporation and that Parsley Energy, Inc. plans to develop this property.

Two royalty interestthese wells drilled and recently began producing in UptonMay 2022 and the remaining 4 were completed in November 2022 with initial average production rates of 1,168 barrels of oil, 3,797 barrels of water and 2,621,000 cubic feet of gas per day, or, 1,605 barrels of oil equivalent per day.

Acquisitions in Fiscal 2023. The Company acquired various royalty (mineral) interests in 22 wells and several additional potential locations for development operated by Chesapeake Energy Corporation and located in the Eagleford area of Dimmit County, Texas by Pioneer Natural Resources Company, two more wells are currently undergoing completion procedures and 3 more wells are drilling, all being horizontal wells with 10,000 feetfor a purchase price of laterals at no expense to us. These wells are located in part on 411 acres in$939,000 which Mexco has retained a 1% overriding royalty interest.

In July 2015, Mexco began receiving royalties from three new horizontal wells operated by Pioneer in Reagan County, Texas at no expense to us.

At March 31, 2016, we reported estimated proved undeveloped reserves (“PUDs”) of 5.8 bcfe, which accounted for 47% of our total estimated proved oil and gas reserves. This figure primarily consists of a projected 67 new wells, four of which we plan to cause to be drilled in fiscal 2019 by an unrelated third party in addition to the three wells currently operated by Mexco on this property. Regarding the remaining 63 PUD locations operated by others, one well is currently being drilled with plans for 14 wells to follow in 2017, 14 wells in 2018, 16 wells in 2019 and 18 wells in 2020.

During fiscal 2016, butwas effective April 1, 2016, Mexco sold various interests in non-core oil and gas properties located in Howard, Johnson, Martin, Midland and Reagan Counties, Texas for $518,760 in aggregate. Of these received funds, $270,000 was used to reduce the balance of Mexco’s indebtedness.2022.

The Company also acquired, for a purchase price of $117,200, royalty interests covering 28 producing wells in 6 counties in the Haynesville trend area of Louisiana and 5 counties in Texas.

Subsequent Participations. In May 2023, Mexco expended approximately $133,000 to participate in the drilling of four horizontal wells in the Wolfcamp Sand formation of the Delaware Basin in Lea County, New Mexico.

Mexco expended approximately $68,000 to participate in the drilling of two horizontal wells in the Penn Shale formation of the Delaware Basin in Lea County, New Mexico.

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 and cash flow from operations. The remainder may be funded through borrowings on the credit facility and, if appropriate, sales of our commonstock. See Note 5 of Notes to Consolidated Financial Statements for a description of our revolving creditagreement with Bank of America, N.A.non-core properties.

Markets. Crude oil and natural gas prices generally remained significantly depressedvolatile during the last year. Lower product prices reduce our cash flow from operations and diminish the present value of our oil and gas reserves. Lower product prices also offer us less incentive to assume the drilling risks that are inherent in our business. The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. For example, in the last twelve months, the NYMEX West Texas Intermediate (“WTI”) posted price for crude oil has ranged from a low of $22.75$62.72 per bbl in February 2016March 2023 to a high of $58.00$118.09 per bbl in June 2015.2022. The Henry Hub Spot Market Price (“Henry Hub”) for natural gas has ranged from a low of $1.49$1.93 per MMBtu in March 20162023 to a high of $3.04$9.85 per MMBtu in May 2015. These are at a level not seen since 2003.August 2022.

On March 31, 20162023 the WTI posted price for crude oil was $34.75$71.65 per bbl and the Henry Hub spot price for natural gas was $1.98$2.10 per MMBtu. Management is of the opinion that cash flow from operations will be sufficient to provide adequate liquidity for the next fiscal year.

See Results of Operations below for realized prices.

Results of Operations

Fiscal 20162023 Compared to Fiscal 20152022

We had a net lossincome of $3,979,685$4,662,702 for the year ended March 31, 20162023 compared to a net loss of $340,986$2,855,066 for the year ended March 31, 2015.2022, a 63% increase as a result of an increase in operating revenues due to an increase in oil and natural gas prices and production partially offset by an increase in operating expenses that is further explained below.

Oil and natural gas sales.Revenue from oil and natural gas sales was $2,383,950$9,380,623 for the year ended March 31, 2016,2023, a 29% decrease44% increase from $3,336,826$6,525,264 for the year ended March 31, 2015.2022. This resulted from a decrease in oil and gas prices partially offset by an increase in oil and natural gas production.production volumes and an increase in oil and natural gas prices. The following table sets forth our oil and natural gas revenues, production quantities and average prices received during the fiscal years ended March 31:

Production and exploration.Production costs were $1,144,061$1,719,719 in fiscal 2016,2023, a 12% decrease34% increase from $1,300,820$1,281,112 in fiscal 2015.2022. This was primarily the result of a decreasean increase in production taxes and ad valorem taxes due to the decrease in salesmarketing charges as a result of the decreasedincrease in oil and gas prices. In addition, lease operating expenses decreased as a result of lowering service costs due to the depressed market.revenues.

Impairment of oil and gas properties.The impairment in the carrying value of our oil and natural gas properties was $2,984,410 for the year ended March 31, 2016. This was due to downward adjustments to the economically recoverable proved reserves associated with decreases in estimated realized oil and natural gas prices.

Depreciation, depletion and amortization.Depreciation, depletion and amortization (“DD&A”) expense was $1,572,738$1,854,047 in fiscal 2016,2023, a 15%38% increase from $1,362,862$1,345,435 in fiscal 2015.2022. This was primarily due to an increase in oil and gas production and an increase in the full cost pool amortization base prior to the impairmentand a decrease in the secondoil and third quarters of fiscal 2016.gas reserves.

General and administrative expenses. General and administrative expenses were $1,155,183$1,120,691 for the year ended March 31, 2016, a 7% decrease2023, an 18% increase from $1,239,750$949,079 for the year ended March 31, 2015.2022. This was primarily due to an increase in employee stock option compensation, salaries and contract services, legal and accounting fees.

Interest expense. Interest expense was $13,097 in fiscal 2023, a 51% decrease from $26,512 in fiscal 2022, due to a decrease in salary, insurance and subscriptions and dues expenses.borrowings.

Interest expense.Interest expense was $171,375 in fiscal 2016, a 73% increase from $99,240 in fiscal 2015, due to an increase in borrowings.

Income taxes. There was anno federal income tax benefit of $660,870 in fiscal 2016 compared to an income tax benefit of $197,499 in fiscal 2015. The effective tax rate for fiscal 2016 was (14%) compared to (37%) for2023 or fiscal 2015. This decrease in the effective income tax rate is primarily due to the tax benefit at expected rates being offset by an increase in our valuation allowance. Based on the material write-downs of the carrying value of our oil and natural gas properties for the year ending March 31, 2016, we2022. We are in a net deferred tax asset position at year end. Weand believe it is more likely than not that these deferred tax assets will not be realized. Management assessesState income tax was $164,510 in fiscal 2023, a 61% increase from $102,356 in fiscal 2022, due to the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. A significant piece of objective negative evidence evaluated was the cumulative loss incurred over the two-year period ending March 31, 2016. Such objective negative evidence limits the ability to consider other subjective positive evidence, such as our projections for future growth. 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 expected future growth.

Fiscal 2015 Compared to Fiscal 2014

We had a net loss of $340,986 for the year ended March 31, 2015 compared to net income of $301,113 for the year ended March 31, 2014.

Oil and gas sales.Revenue from oil and gas sales was $3,336,826 for the year ended March 31, 2015, a 16% decrease from $3,994,295 for the year ended March 31, 2014. This resulted from a decrease in oil and gas prices partially offset by an increase in oil and natural gas production. The following table sets forth our oil and gas revenues, production quantities and average prices received during the fiscal years ended March 31: