UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
 
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended March 31, 2015
 
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
Commission File No. 0-6694

MEXCO ENERGY CORPORATION
(Exact name of registrant as specified in its charter)

Colorado
84-0627918
(State or other jurisdiction of
(I.R.S. Employer
incorporation or organization)
Identification No.)

214 W. Texas Avenue, Suite 1101
79701
Midland, Texas
(Zip Code)
(Address of principal executive offices)
 

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 (§ 229.405 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. See definitions of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act:

Large Accelerated Filer [ ]  Accelerated Filer [ ]  Non-Accelerated Filer [ ]  Smaller Reporting Company [X]

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, 2014 (the last business day of the Registrant’s most recently completed second quarter) was $6,294,450 based on Mexco Energy Corporation’s closing common stock price of $6.92 per share on that date as reported by the NYSE MKT.

There were 2,037,266 shares of the registrant’s common stock outstanding as of June 23, 2015.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s Proxy Statement relating to the 2015 Annual Meeting of Shareholders to be held on September 15, 2015, 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, 2015, the end of the fiscal year covered by this report.

2

TABLE OF CONTENTS

 
PART I
 
     
Item 1.
Business
4
     
Item 1A.
Risk Factors
13
     
Item 1B.
Unresolved Staff Comments
20
     
Item 2.
Properties
20
     
Item 3.
Legal Proceedings
24
     
Item 4.
Mine Safety Disclosures
24
     
 
PART II
 
     
Item 5.
Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
25
     
Item 6.
Selected Consolidated Financial Data
26
     
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
26
     
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
32
     
Item 8.
Financial Statements and Supplementary Data
34
     
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosures
34
     
Item 9A.
Controls and Procedures
34
     
Item 9B.
Other Information
34
     
 
PART III
 
     
Item 10.
Directors, Executive Officers and Corporate Governance
35
     
Item 11.
Executive Compensation
35
     
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
35
     
Item 13.
Certain Relationships and Related Transactions, and Director Independence
35
     
Item 14.
Principal Accounting Fees and Services
35
     
 
PART IV
 
     
Item 15.
Exhibits and Financial Statement Schedules
35
     
 
Signatures
36
     
 
Glossary of Abbreviations and Terms
37

3

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.

ITEM 1. BUSINESS

General

Mexco Energy Corporation, a Colorado corporation, is an independent oil and gas company engaged in the exploration, development and production of 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, 2015 were approximately 6.289 billion cubic feet (“Bcf”) of natural gas and 659,700 barrels (“bbls”) of oil and natural gas liquids, and our estimated present value of proved reserves was approximately $24 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 2015, we added proved reserves of 1,679,000 thousand cubic feet equivalent (“Mcfe”) through extensions and discoveries, added 1,053,000 Mcfe through acquisitions and had downward revisions of previous estimates of 1,205,000 Mcfe. Such revisions are primarily as a result of Security Exchange Commission (“SEC”) rules which require such reserves to be developed within five years.

Nicholas C. Taylor beneficially owns approximately 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.

4

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 2016.

While we own oil and gas properties in other states, the majority of our activities are centered in West Texas. 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, both working and royalty interests, and prospects that could have a potentially meaningful impact on our reserves.

From 1983 to 2015, Mexco Energy Corporation made approximately 80 acquisitions of producing oil & gas properties including royalties, overriding royalties, minerals and working interests both operated and non-operated plus the following most significant and recent acquisitions:

1993-2010
Tabbs Bay Oil Company and Thompson Brothers Lumber Company, respectively dissolved in 1957 and 1947. Purchase covering thousands of acres located respectively in 19 counties of Texas, 3 parishes of Louisiana and one county in Arkansas and 8 counties of Texas, respectively consisting of various mineral, royalty and overriding royalty interests.

1997
Forman Energy Corporation, purchase price of $1,591,000 consisting of primarily working interests in approximately 634 wells located in 12 states.

2010
Southwest Texas Disposal Corporation, purchase price $478,000 consisting of royalty interests in over 300 wells located in 60 counties and parishes of 6 states.

2012
TBO Oil and Gas, LLC, purchase price of $1,150,000 consisting of working interests in approximately 280 wells located in 16 counties of 3 states.

2014
Royalty interests, purchase price of $200,000 covering 43 wells in 12 counties of eight states. Of these oil and gas reserves, approximately 54% are in TX and 10% in LA.

Royalty interests, purchase price $580,000 covering 580 wells in 87 counties of eight 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.

5

Oil and Gas Operations

As of March 31, 2015, natural gas constituted approximately 61% of our total proved reserves and approximately 38% of our revenues for fiscal 2015. Revenues from oil and gas royalty interests accounted for approximately 26% of our revenues for fiscal 2015.

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).

For example, we are in the process of investing approximately $650,000 for a 2.3% working interest in 5 wells located in Reagan County, Texas. The first 3 of these wells are now producing and the remaining 2 wells have been drilled and are currently being completed. These wells are each undergoing a 50 stage zipper fracture treatment through horizontals of approximately 7,000 feet per well at a vertical depth of approximately 8,000 feet.

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.

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”.

Newark East (Barnett Shale) Gas Field properties, encompassing 20,992 gross acres, 72 net acres, 279 gross producing wells and 1 net well in Denton, Johnson, Tarrant and Wise Counties, Texas, account for approximately 4% of our discounted future net cash flows from proved reserves as of March 31, 2015. For fiscal 2015, this field, consisting of royalty interests, accounted for 7% of our gross revenues, 9% of our net revenues.

El Cinco Gas Field properties, encompassing 1,166 gross acres, 886 net acres, 8 gross producing wells and 8 net wells in Pecos County, Texas, account for approximately 15% of our discounted future net cash flows from proved reserves as of March 31, 2015. This is a multi-pay area where most of the leases have potential reserves in two zones. Of these discounted future net cash flows from proved reserves, approximately 6% are attributable to proven undeveloped reserves which will be developed through re-entry of existing wells. For fiscal 2015, these properties accounted for 11% of our gross revenues and 8% 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 2015, these properties accounted for 4% 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, 5 gross wells and 3.5 net wells in Ector County, Texas, account for approximately 19% of our discounted future net cash flows from proved reserves as of March 31, 2015. Of these discounted future net cash flows from proved reserves, approximately 16% are attributable to proven undeveloped reserves which will be developed through new drilling of 6 wells. For fiscal 2015, these properties consist of working interests and accounted for 4% of our gross revenues and 3% of our net revenues.

The Haynesville area natural gas properties, encompassing 9,615 gross acres, 14 net acres, 15 gross producing wells and .02 net wells in DeSoto Parish, Louisiana, account for approximately 3% of our discounted future net cash flows from proved reserves as of March 31, 2015. Of these discounted future net cash flows from proved reserves, approximately 2% are attributable to proven undeveloped reserves. For fiscal 2015, these properties, consisting of royalty interests, accounted for 1% of our gross and net revenues. This acreage contains an additional 56 potential drill sites.

6

On August 13, 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. Mexco now owns approximately 320 net acres (640 gross acres) in this area which is held by production from wells in the Pembrook Unit. This acreage has the potential for development in the horizontal Wolfcamp formation centered in the southern Midland Basin.

We own interests in and operate 15 producing wells and 1 water injection well. We own partial interests in an additional 6,006 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 and North Dakota. 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:

Year
Oil(Bbls)
Gas (Mcf)
2015
29,557
369,034
2014
27,186
361,652
2013
23,260
401,077
2012
19,442
395,649
2011
17,040
459,446

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 revenues for the year ended March 31:

 
2015
2014
2013
Holly Frontier Refining & Marketing LLC
17%
22%
26%

7

Because a ready market exists for oil and gas production, we do not believe the loss of any individual customer would have a material adverse effect on our financial position or results of operations.

Regulation

Our exploration, development, production and marketing operations are subject to various types of extensive rules and regulations by federal, state and local authorities. Numerous federal, state and local departments and agencies have issued rules and regulations binding on the oil and gas industry, some 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 regulate the location of wells; the method of drilling and casing wells; 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 Act of 1938 and the Natural Gas Policy Act of 1978, interstate natural gas transportation rates and service conditions, 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.

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.

8

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 local environmental laws and regulations controlling the generation, use, storage and discharge of materials into the environment or otherwise relating to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial penalties for failure to comply. These laws and regulations may require the acquisition of a permit before drilling or production commences; restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities; limit or prohibit construction or drilling 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 are in compliance, in 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 in the past. Public interest in 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:

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, imposes liability, without regard to fault or the legality of the original conduct, on classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances. Under CERCLA, such persons may be subject to joint and several liabilities for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We are able to control directly the operation 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 required to incur any material capital expenditures to comply with existing environmental requirements.

The federal Clean Air Act (“CAA”), 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 existing equipment and construction permits 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.

9

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 August 16, 2012, the EPA approved final regulations under the CAA that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas drilling, completion, production and processing activities. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules will require a number of modifications to operations, including the installation of new equipment to control emissions from wells. We believe that we are currently in compliance in all material respects with the requirements of applicable federal and state air pollution control laws.
 
Recent scientific studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases (“GHGs”) and including carbon dioxide and methane, may be contributing 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.

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. The EPA has continued to adopt GHG regulations of other industries could set new source performance standards for new coal-fired and natural-gas fired power plants. 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 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 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 Safe Drinking Water Act (“SDWA”) and the Underground 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.

10

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 hydrocargons, 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. The new 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 substantial 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, 2015. 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 2016.

Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources. These statutes include the Endangered Species Act and the Migratory Bird Treaty Act , as well as, the CWA and CERCLA. The United States Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or development.

11

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.

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

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, 2015.

Name
Age
Position
Nicholas C. Taylor
77
Chairman and Chief Executive Officer
Tamala L. McComic
46
President, Chief Financial Officer, Treasurer, and Assistant Secretary
Donna Gail Yanko
70
Vice President and Secretary

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, 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 appointed 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 since 1992 and from 1986 to 1992 was Assistant Secretary. From 1986 to the present, 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.

12

Employees

As of March 31, 2015, we had two full-time and four 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 214 W. Texas Avenue, Suite 1101, 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 will expire 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. We believe our facilities are adequate for our current operations and that we can obtain additional leased space if needed.

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.  Mexco also employs the Public Register’s Annual Report Service which can provide you a copy of our annual report at www.prars.com , free of charge, as soon as practicable after providing such report to 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 ability of the Organization of Petroleum Exporting Countries (“OPEC”) 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; and, overall political and economic conditions in oil producing countries.

13

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 and reserves are natural gas. Lower natural gas prices or lack of natural gas 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 natural gas 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.

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.

In March 2013, we placed a commodity swap contract covering a total of 12,000 bbls of crude oil for the period from April 2013 to March 2015 at a fixed price of $90.00 per bbl. 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.

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. 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.” 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. For 2015, 2014 and 2013, there was no ceiling test impairment on our oil and gas properties.

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.

14

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 2015, differentials averaged $4.37 per Bbl of oil and $0.18 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.

Approximately 39% and 37% of our total estimated net proved reserves at March 31, 2015 and 2014, 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. 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.

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 can not 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.

15

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 discover new reserves. Historically, we have used our cash flow from operations and borrowings under our revolving credit facility to fund our capital expenditures and we expect to continue to do so in the future.
 
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’ inability to agree to an adequate borrowing base or adverse changes in the lenders’ 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 has 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.

16

Failure to comply with covenants under 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 disposition of assets, mergers and reorganizations. We are also obligated to meet certain financial covenants. For example, our revolving credit facility requires us to, among other things, maintain tangible net worth in accordance with computational guidelines contained in the related loan agreement. If we fail to meet any of these loan covenants, the lender under the revolving credit facility could accelerate the indebtedness and seek to foreclose on the pledged assets.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

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.

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 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.

17

Our business is subject to extensive environmental regulations, and to laws that can give rise to liabilities from environmental contamination.

Our operations are subject to extensive federal, state and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of hazardous materials and of solid and hazardous wastes, and impose obligations to investigate and remediate contamination in certain circumstances. Liabilities to investigate or remediate contamination, as well as other liabilities concerning hazardous materials or contamination such as claims for personal injury or property damage, may arise at many locations, including properties in which we have an ownership interest but no operational control, properties we formerly owned or operated and sites where our wastes have been treated or disposed of, as well as at properties that we currently own or operate. Such liabilities may arise even where the contamination does not result from any noncompliance with applicable environmental laws. Under a number of environmental laws, such liabilities may also be joint and several, meaning that we could be held responsible for more than our share of the liability involved, or even the entire share. Environmental requirements generally have become more stringent in recent years, and compliance with those requirements more expensive.

Increased regulation of hydraulic fracturing could result in reductions or delays in drilling and completing new oil and natural gas wells, which could adversely impact our revenues.

Legislation has been introduced in the U.S. Congress to amend the federal SDWA to subject hydraulic fracturing operations to regulation under the SDWA and to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate gas and oil production. We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with wells for which we are the operator. Several states, including Texas, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Railroad Commission has adopted rules and regulations requiring that well operators disclose the list of chemical ingredients subject to the requirements of 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 proposed legislation as well as laws being considered by certain states and other agencies requiring the reporting and public disclosure of chemicals used in the fracturing process, could 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 are impairing groundwater or causing other damage. Additional regulatory scrutiny could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

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 the oil and natural gas products sold. Historically, there 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 2015 Budget Proposal includes provisions that would, if enacted, make significant changes to U. S. federal income tax laws including the elimination of certain key U.S. federal income tax deductions currently available to oil and natural gas exploration and production companies. Other changes include, but are not limited to: (1) the repeal of the percentage depletion allowance for 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 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 or how soon any such changes could become effective. The passage of this legislation or any other similar changes in the U. S. federal income tax laws could negatively affect our financial condition and results of operations.

18

The loss of our chief executive officer or other key personnel 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, 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. 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 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 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.

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.

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, 2015, our executive officers and directors beneficially owned approximately 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 NYSE MKT. 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 natural gas and oil; political conditions in 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.

19

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, 2015, we had interests in 6,022 gross (37.8 net) oil and gas wells and owned leasehold mineral and royalty interests in approximately 790,134 gross (5,728 net) acres.

Oil and Natural Gas Reserves

In accordance with current SEC rules, the average prices used in computing reserves at March 31, 2015 were $74.84 per bbl of oil and $94.23 in 2014, a decrease of 21%, and $3.60 per mcf of natural gas and $3.67 in 2014, a decrease of 2%, 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 2015. The benchmark price of $79.21 per bbl of oil at March 31, 2015 versus $94.92 at March 31, 2014, was adjusted by lease for gravity, transportation fees and regional price differentials and did not give effect to derivative transactions. The benchmark price of $3.88 per mcf of natural gas at March 31, 2015 versus $3.99 at March 31, 2014, was adjusted by lease for BTU content, transportation fees and regional price differentials. The average prices used in computing reserves at March 31, 2013 were $85.53 per bbl of oil and $2.76 per mcf of natural gas. The benchmark prices used in computing reserves at March 31, 2013 were $89.17 per bbl of oil and $2.95 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, 2015, 2014 and 2013 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.

20

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 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 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.

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.

We have not filed any other oil or gas reserve estimates or included any such estimates in reports to other federal or foreign governmental authority or agency during the year ended March 31, 2015, and no major discovery is believed to have caused a significant change in our estimates of proved reserves since that date.

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.

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.

21

PROVED RESERVES

         
March 31,
       
   
2015
   
2014
   
2013
 
Oil (Bbls):
           
Proved developed – Producing
   
260,580
     
278,230
     
232,850
 
Proved developed – Non-producing
   
23,090
     
16,390
     
4,570
 
Proved undeveloped
   
376,070
     
206,930
     
128,290
 
   Total
   
659,730
     
501,550
     
365,710
 
                         
Natural gas (Mcf):
                       
Proved developed – Producing
   
3,470,970
     
2,982,480
     
3,727,710
 
Proved developed – Non-producing
   
1,113,820
     
1,098,990
     
1,079,310
 
Proved undeveloped
   
1,703,790
     
2,177,810
     
3,037,180
 
   Total
   
6,288,580
     
6,259,280
     
7,844,200
 
                         
Total net proved reserves (Mcfe)
   
10,246,960
     
9,268,580
     
10,038,460
 
                         
PV-10 Value (1)
 
$
23,700,470
   
$
24,745,250
   
$
17,788,790
 
Present value of future income tax discounted at 10%
   
(4,762,470
)
   
(5,416,250
)
   
(3,419,790
)
Standardized measure of discounted future net   cash flows (2)
 
$
18,938,000
   
$
19,329,000
   
$
14,369,000
 
                         
Prices used in Calculating Reserves: (3)
                       
Natural gas (per Mcf)
 
$
3.595
   
$
3.67
   
$
2.76
 
Oil (per Bbl)
 
$
74.84
   
$
94.23
   
$
85.53
 

 
(1)
The PV-10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10% per annum, which is the most directly comparable GAAP financial measure. PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. Our reconciliation of this non-GAAP financial measure is shown in the table as the PV-10, less future income taxes, discounted at 10% per annum, resulting in the standardized measure of discounted future net cash flows. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to our proved oil and natural gas reserves after income tax, discounted at 10%.

 
(2)
In accordance with SEC requirement, the standardized measure of discounted future net cash flows was computed by applying 12-month average prices for oil and gas during the fiscal year to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already legislated) to be incurred on pretax net cash flows less tax basis of the properties and available credits, and assuming continuation of existing economic conditions.

 
(3)
These prices reflect adjustment by lease for quality, transportation fees and regional price differentials and did not give effect to derivative transactions.

During the fiscal year ending March 31, 2015, 4 wells in which we own a royalty interest were developed converting reserves of approximately 7,000 mcfe from proved undeveloped to proved developed - producing. We participated in the development of 27 wells converting reserves of approximately 208,000 mcfe from proved undeveloped to proved developed - producing. The capital cost was approximately $643,000 for the 27 wells in which we own a working interest.

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, 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.

22

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. The following table indicates our productive wells as of March 31, 2015:

 
Gross
 
Net
Oil
3,198
 
22.8
Gas
2,824
 
15.0
   Total Productive Wells
   6,022
 
   37.8

The following table sets forth the approximate developed acreage in which we held a leasehold mineral or other interest as of March 31, 2015:

 
Developed Acres
 
Gross
 
Net
Texas
564,296
 
3,625
Oklahoma
97,390
 
1,450
New Mexico
29,519
 
514
Louisiana
43,027
 
47
North Dakota
30,174
 
46
Kansas
9,672
 
24
Montana
7,868
 
5
Wyoming
3,738
 
5
Arkansas
    960
 
     5
Alabama
640
 
2
Mississippi
1,600
 
3
Colorado
1,120
 
1
Virginia
130
 
1
   Total
 790,134
 
  5,728

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.

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:

     
Year Ended March 31,
     
2015
 
2014
 
2013
     
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Development Wells
                     
 
Productive
56
 
.41
 
34
 
.42
 
38
 
.52
 
Nonproductive
1
 
.09
 
1
 
.01
 
1
 
.01
   
Total
   57
 
.50
 
   35
 
.43
 
   39
 
.53

We have not participated in any exploratory wells during the years ended March 31, 2015, 2014 and 2013. 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.

23

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:

   
Year Ended March 31,
 
   
2015
   
2014
   
2013
 
Oil (a):
           
Production (Bbls)
   
29,557
     
27,186
     
23,260
 
Revenue
 
$
2,069,806
   
$
2,591,619
   
$
1,961,766
 
Average Bbls per day
   
81
     
74
     
64
 
Average sales price per Bbl (b)
 
$
70.03
   
$
95.33
   
$
84.34
 
Gas (c):
                       
Production (Mcf)
   
369,034
     
361,652
     
401,077
 
Revenue
 
$
1,267,020
   
$
1,402,676
   
$
1,101,941
 
Average Mcf per day
   
1,011
     
991
     
1,099
 
Average sales price per Mcf
 
$
3.43
   
$
3.88
   
$
2.75
 
Production cost:
                       
Production cost
 
$
1,024,130
   
$
943,730
   
$
843,277
 
Production and ad valorem taxes
 
$
276,690
   
$
288,084
   
$
238,766
 
Equivalent Mcf (d)
   
546,375
     
524,768
     
540,637
 
Production cost per equivalent Mcf
 
$
1.87
   
$
1.80
   
$
1.56
 
Production cost per sales dollar
 
$
0.31
   
$
0.24
   
$
0.28
 
 Total oil and gas revenue
 
$
3,336,826
   
$
3,994,295
   
$
3,063,707
 
 
 
(a)
Includes condensate.

 
(b)
After giving effect to our derivative instruments, the average sales price per Bbl of oil was $73.48 for year ended March 31, 2015. After giving effect to our derivative instruments, the average sales price per Bbl of oil was $93.33 for year ended March 31, 2014. We did not have a price swap agreement on our oil production for the years ended March 31, 2013.

 
(c)
Includes natural gas products.

 
(d)
Oil production is converted to equivalent mcf at the rate of 6 mcf per bbl, representing the estimated relative energy content of natural gas to oil.

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.

24

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, formerly the American Stock Exchange, 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, 02021 (Tel: 800-962-4284). 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.

   
High
   
Low
 
2015:
       
April - June 2014
 
$
10.05
   
$
6.44
 
July - September 2014
   
8.25
     
6.53
 
October - December 2014
   
7.02
     
5.43
 
January - March 2015
   
5.90
     
4.31
 
                 
2014:
               
April - June 2013
 
$
6.41
   
$
5.42
 
July - September 2013
   
8.10
     
5.30
 
October - December 2013
   
8.50
     
6.30
 
January - March 2014
   
10.10
     
6.61
 

On June 16, 2015, the closing sales price of our common stock on the NYSE MKT was $4.54 per share.

Stockholders

As of March 31, 2015, we had approximately 2,104,266 shares issued and 907 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 in the foreseeable future. Payment of any future dividends will be 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. Any future dividends may also be restricted by any loan agreements which we may enter into from time to time.

Securities Authorized for Issuance Under Compensation Plans

The following table includes certain information about our Employee Incentive Stock Plan as of March 31, 2015, which has been approved by our stockholders.

   
Number of Shares Authorized for Issuance under Plan
   
Number of Shares to be Issued upon Exercise of Outstanding Options
   
Weighted Average Exercise Price of Outstanding Options
   
Number of Shares Remaining Available for Future Issuance under Plan
 
2009 Plan
   
200,000
     
153,600
   
$
6.52
     
45,000
 
Total
   
200,000
     
153,600
   
$
6.52
     
45,000
 

25

Issuer Repurchases

In June 2014, the Board of Directors 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. 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, 2015:

Total Number
of Shares
Purchased
   
Average
Price Paid
per Share
   
Total Number of Shares Purchased as Part of Publicly Announced Program
   
Approximate Dollar Value of Shares that May Yet be Purchased Under the Program (1)
 
 
1,000
   
$
5.01
     
1,000
   
$
244,991
 

 
(1)
The program authorizing the use of up to $250,000 to repurchase shares of our common stock for the treasury account was approved by the board of directors on June 29, 2012 and does not have an expiration date. As of March 31, 2015, 1,000 shares of Mexco’s common stock have been purchased for a total of $5,009.

During the fiscal year ended March 31, 2015, we repurchased 1,000 shares for the treasury at an aggregate cost of $5,009. There were no shares of our common stock repurchased for the treasury account during fiscal 2014. During the fiscal year ended March 31, 2013, we repurchased 2,833 shares at an aggregate cost of $15,547.

ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA

Not applicable.

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 and issuance of common stock. Our primary financial resource is our base of oil and gas reserves. We pledge our producing oil and gas properties to secure our revolving line of credit. We do not have any delivery commitments to provide a fixed and determinable quantity of our oil and gas under any existing contract or agreement.

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

For the year ending March 31, 2015, cash flow from operations was $1,176,979, a 35% decrease when compared to the corresponding period of fiscal 2014. Net cash of $3,525,000 was provided by the line of credit; net cash of $4,774,705 was used for activity associated with oil and gas properties and other property and equipment; and cash of $57,089 was provided by settlement of derivatives. Accordingly, net cash decreased $59,998.
26

We had working capital of $166,650 as of March 31, 2015 compared to working capital of $522,216 as of March 31, 2014, a decrease of $355,566 for the reasons set forth below.

Acquisitions

Effective August 2014, Mexco purchased various royalty interests for $200,000 covering 43 wells in 12 counties of eight states. Of these oil and gas reserves, approximately 54% are in Texas and 10% in Lousiana where there is acreage available for further development by horizontal drilling and fracturing. These royalty interests are free of expenses to Mexco for drilling and operations.

Effective September 2014, Mexco purchased various royalty interests ranging from .0018% to 1.1% revenue interests at a price of $580,000 covering approximately 580 wells in 87 counties of eight states. Of this oil and gas production, virtually all is natural gas. Mexco believes that there is potential for further development of several of these royalties. These royalty interests are free of expenses to Mexco for drilling and operations. 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 Alabama, Arkansas, Kansas, Louisiana, Mississippi, North Dakota, Oklahoma and Texas.

Effective October 2014, Mexco purchased for $525,000 long lived non-operated working interests of 12.5% (approximately 10% net revenue interest). Six wells are producing oil from the Lower Tubb formation in Pecos County, Texas. These wells are on 20-acre spacing with four additional proven undeveloped locations at approximately 3,600 foot depth on the 190 acres. The operator has agreed to pay for the drilling and completion costs of one additional well and fracture treatment of one of the existing wells, as well as pay all operating expenses of all wells on these leases. In addition, Mexco will receive 100% of the gross disposal fees from one disposal well located on these properties paid by an adjacent operator. Mexco would be responsible for payment of the cost of drilling and completion on the balance of any development wells.

Effective October 2014, Mexco purchased various royalty interests at a price of $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. Mexco believes that there is potential for further development of a number of these royalties especially through horizontal drilling and fracturing. These royalty interests are free of expenses to Mexco for drilling and operations. Approximately 15% of the net revenue from these royalties comes from 237 wells located in Reagan County, Texas. Also included are interests in 21 wells in Glasscock County, Texas. Both of these counties are in the horizontal Spraberry Wolfcamp trend. The second largest source of net income is in Webb County, Texas from 202 wells producing 13.5 % of net income. Royalties in Karnes County, Texas amount to approximately 5% of net revenue from interests in 30 wells. Both Karnes and Webb counties are in the Eagle Ford trend.

Effective November 2014, Mexco purchased various long-lived non-operated working interests at a price of $840,000 covering 70 wells in 5 counties of Oklahoma.

During fiscal year 2015, total oil and gas drilling and development expenditures were approximately $1,750,000 of which 49% were in Texas and 51% were in New Mexico. We participated in 57 gross (.50 net) wells of which 17 gross (.20 net) wells were in Texas and 40 gross (.30 net) wells were in New Mexico. Of these wells all were development - 28 were horizontal and 29 vertical wells.

The Company currently expects to participate in the drilling and completion of 19 horizontal wells and 1 vertical disposal well at an estimated aggregate cost of approximately $954,000 for the fiscal year ended March 31, 2016. Of these estimated expenditures 23% have been paid to date. The operators of these wells include Apache Corporation, Bold Energy III, LLC, Concho Resources, Inc., Endurance Resources, LLC, QEP Resources, Inc., XTO Energy, Inc. and others. Approximately 74% of these expenditures are planned to be in Lea County, New Mexico. Mexco expects additional development in the Bone Springs-Wolfcamp area of Lea County because of greater pore space, permeability and consequent profitability compared to many other producing areas.

27

At March 31, 2015, we reported estimated proved undeveloped reserves (“PUDs”) of 3.96 bcfe, which accounted for 39% of our total estimated proved oil and gas reserves. This figure primarily consists of a projected 73 new wells, six (6) of which we operate, and one new zone behind pipe from a currently producing wellbore that we also operate. We project five (5) operated wells to be drilled in fiscal 2016 with the one remaining in fiscal 2017. Regarding the remaining 67 PUD locations operated by others, twelve (12) wells currently are being drilled and two (2) locations currently are being prepared to drill with plans for eighteen (18) wells to follow in 2016, 27 wells in 2017, seven (7) wells in 2018 and four (4) wells in 2019.

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 common stock. See Note 5 of Notes to Consolidated Financial Statements for a description of our revolving credit agreement with Bank of America, N.A.

Crude oil and natural gas prices have fluctuated significantly in recent years. Lower product prices reduce our cash flow from operations and diminish the present value of our oil and gas reserves. Lower product prices also offer us less incentive to assume the drilling risks that are inherent in our business. The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. For example in the last twelve months, the West Texas Intermediate (“WTI”) posted price for crude oil has ranged from a low of $44.00 per bbl in March 2015 to a high of $103.75 per bbl in June 2014. The Henry Hub Spot Market Price (“Henry Hub”) for natural gas has ranged from a low of $2.62 per MMBtu in February 2015 to a high of $4.81 per MMBtu in April 2014. On March 31, 2015 the WTI posted price for crude oil was $44.00 per bbl and the Henry Hub spot price for natural gas was $2.65 per MMBtu. Management is of the opinion that cash flow from operations and funds available from financing may be sufficient to provide adequate liquidity for the next fiscal year.

Results of Operations

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 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:

   
2015
   
2014
   
% Difference
 
Oil:
           
Revenue
 
$
2,069,806
   
$
2,591,619
     
(20.1%)
 
Volume (bbls)
   
29,557
     
27,186
     
8.7%
 
Average Price (per bbl) (a)
 
$
70.03
   
$
95.33
     
(26.5%)
 
                         
Gas:
                       
Revenue
 
$
1,267,020
   
$
1,402,676
     
(9.7%)
 
Volume (mcf)
   
369,034
     
361,652
     
2.0%
 
Average Price (per mcf)
 
$
3.43
   
$
3.88
     
(11.6%)
 

 
(a)
After giving effect to our derivative instruments, the average sales price per Bbl of oil was $73.48 for year ended March 31, 2015. After giving effect to our derivative instruments, the average sales price per Bbl of oil was $93.33 for year ended March 31, 2014.

Production and exploration. Production costs were $1,300,820 in fiscal 2015, a 6% increase from $1,231,814 in fiscal 2014. This was the result of an increase in lease operating expenses resulting from acquisitions of working interests of non-operated properties partially offset by a decrease in production taxes due to the decrease in oil and gas revenue.

28

Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expense was $1,362,862 in fiscal 2015, an 18% increase from $1,151,482 in fiscal 2014. This was due to an increase in oil and gas production and an increase in the full cost pool partially offset by an increase in oil and gas reserves.
General and administrative expenses. General and administrative expenses were $1,239,750 for the year ended March 31, 2015, a 9% increase from $1,136,939 for the year ended March 31, 2014. This was primarily due to an increase in accounting, salary and insurance expenses.

Interest expense. Interest expense was $99,240 in fiscal 2015, a 52% increase from $65,387 in fiscal 2014, due to an increase in borrowings.

Derivatives. Derivative realized gains of $102,069 were recorded during the year ended March 31, 2015 resulting from our oil swap agreement. This compared to derivative losses of $99,262 recorded during the year ended March 31, 2014 ($54,281 of realized losses and $44,981 of unrealized losses.)

Income taxes. There was an income tax benefit of $197,499 in fiscal 2015 compared to an income tax expense of $11,750 in fiscal 2014. The effective tax rate for fiscal 2015 was (37%) compared to 4% for fiscal 2014.
 
Fiscal 2014 Compared to Fiscal 2013

We had a net income of $301,113 for the year ended March 31, 2014 compared to a net loss of $176,374 for the year ended March 31, 2013.

Oil and gas sales. Revenue from oil and gas sales was $3,994,295 for the year ended March 31, 2014, a 30% increase from $3,063,707 for the year ended March 31, 2013. This resulted from an increase in oil production and an increase in oil and gas prices partially offset by a decrease in 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:

   
2014
   
2013
   
% Difference
 
Oil:
           
Revenue
 
$
2,591,619
   
$
1,961,766
     
32.1%
 
Volume (bbls)
   
27,186
     
23,260
     
16.9%
 
Average Price (per bbl) (a)
 
$
95.33
   
$
84.34
     
13.0%
 
                         
Gas:
                       
Revenue
 
$
1,402,676
   
$
1,101,941
     
27.3%
 
Volume (mcf)
   
361,652
     
401,077
     
(9.8%)
 
Average Price (per mcf)
 
$
3.88
   
$
2.75
     
41.1%
 

 
(a)
After giving effect to our derivative instruments, the average sales price per Bbl of oil was $93.33 for year ended March 31, 2014. We did not have a price swap agreement on our oil production for the year ended March 31, 2013.

Production and exploration. Production costs were $1,231,814 in fiscal 2014, a 14% increase from $1,082,043 in fiscal 2013. This was primarily the result of an increase in taxes related to an increase in sales, and fiscal 2014 includes twelve months of costs from the TBO wells compared to 3 months in fiscal 2013.

Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expense was $1,151,482 in fiscal 2014, a 5% increase from $1,100,425 in fiscal 2013. This was due to an increase in oil production and a decrease in gas reserves partially offset by a decrease in gas production and an increase in oil reserves.

General and administrative expenses. General and administrative expenses were $1,136,939 for the year ended March 31, 2014, an 11% increase from $1,028,846 for the year ended March 31, 2013. This was primarily due to an increase in engineering services, insurance, salaries and stock option compensation expense.

Interest expense. Interest expense was $65,387 in fiscal 2014, a 21% increase from $53,832 in fiscal 2013, due to an increase in borrowings.

29

Derivatives. Derivative losses of $99,262 were recorded during the year ended March 31, 2014. This amount reflects $54,281 of realized losses and $44,981 of unrealized losses resulting from our oil swap agreement.

Income taxes. There was an income tax expense of $11,750 in fiscal 2014 compared to an income tax benefit of $31,504 in fiscal 2013. The effective tax rate for fiscal 2014 was 4% compared to (15%) for fiscal 2013.

Contractual Obligations

We have no off-balance sheet debt or unrecorded obligations and have not guaranteed the debt of any other party. The following table summarizes future payments we are obligated to make based on agreements in place as of March 31, 2015:

   
Payments due in:
 
   
Total
   
less than 1 year
   
1 - 3 years
   
over 3 years
 
Contractual obligations:
               
Secured bank line of credit (1)
 
$
5,950,000
   
$
-
   
$
-
   
$
5,950,000
 
Leases (2)
 
$
27,860
   
$
23,440
   
$
4,420
   
$
-
 

 
(1)
These amounts represent the balances outstanding under the bank line of credit. These repayments assume that interest will be paid on a monthly basis, no additional funds will be drawn and does not include estimated interest of $159,326 less than 1 year, $477,978 1-3 years and $265,544 over 3 years.

 
(2)
The lease amount represents the monthly rent amount for our principal office space in Midland, Texas under one three year lease agreement effective April 1, 2013 and a second three year lease agreement effective April 1, 2014. The total obligation for the remainder of the leases is $37,100 which includes $9,240 billed to and reimbursed by our majority shareholder for his portion of the shared office space.

Alternative Capital Resources

Although we have primarily used cash from operating activities and funding from the line of credit as our primary capital resources, we have in the past, and could in the future, use alternative capital resources. These could include joint ventures, carried working interests and the sale of assets and/or issuances of common stock through a private placement or public offering of our common stock.

Other Matters

Critical Accounting Policies and Estimates

In preparing financial statements, management makes informed judgments, estimates and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews its estimates, including those related to litigation, environmental liabilities, income taxes, fair value and determination of proved reserves. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates.

The following represents those policies that management believes are particularly important to the financial statements and that require the use of estimates and assumptions to describe matters that are inherently uncertain.

Full Cost Method of Accounting for Crude Oil and Natural Gas Activities . SEC Regulation S-X defines the financial accounting and reporting standards for companies engaged in crude oil and natural gas activities. Two methods are prescribed: the successful efforts method and the full cost method. We have chosen to follow the full cost method under which all costs associated with property acquisition, exploration and development are capitalized. We also capitalize internal costs that can be directly identified with acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation ("ARO") when incurred.
30

Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and impairment of crude oil and natural gas properties are generally calculated on a well by well or lease or field basis versus the "full cost" pool basis. Additionally, gain or loss is generally recognized on all sales of crude oil and natural gas properties under the successful efforts method. As a result our financial statements will differ from companies that apply the successful efforts method since we will generally reflect a higher level of capitalized costs as well as a higher DD&A rate on our crude oil and natural gas properties.

At the time it was adopted, management believed that the full cost method would be preferable, as earnings tend to be less volatile than under the successful efforts method. However, the full cost method makes us more susceptible to significant non-cash charges during times of volatile commodity prices because the full cost pool may be impaired when prices are low. These charges are not recoverable when prices return to higher levels. Our crude oil and natural gas reserves have a relatively long life. However, temporary drops in commodity prices can have a material impact on our business including impact from the full cost method of accounting.

Ceiling Test . Companies that use the full cost method of accounting for oil and gas exploration and development activities are required to perform a ceiling test each quarter. The full cost ceiling test is an impairment test to determine a limit, or ceiling, on the book value of oil and gas properties. That limit is basically the after tax present value of the future net cash flows from proved crude oil and natural gas reserves plus the lower of cost or fair market value of unproved properties. If net capitalized costs of crude oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a "ceiling limitation write-down." This charge does not impact cash flow from operating activities, but does reduce our stockholders' equity and reported earnings.

The risk that we will be required to write down the carrying value of crude oil and natural gas properties increases when crude oil and natural gas prices are depressed or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or if purchasers cancel long-term contracts for natural gas production. An expense recorded in one period may not be reversed in a subsequent period even though higher crude oil and natural gas prices may have increased the ceiling applicable to the subsequent period.

Estimates of our proved reserves are based on the quantities of oil and gas that engineering and geological analysis demonstrates, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Our reserve estimates and the projected cash flows are derived from these reserve estimates, in accordance with SEC guidelines by an independent engineering firm based in part on data provided by us. The accuracy of a reserve estimate is a function of the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgment of the persons preparing the estimate. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.

It should not be assumed that the present value of future net cash flows is the current market value of our estimated proved reserves. In accordance with SEC requirements, the cost ceiling represents the present value (discounted at 10%) of net cash flows from sales of future production using the average price over the prior 12-month period.

The estimates of proved reserves materially impact DD&A expense. If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost projects.

31

Use of Estimates . In preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management is required to make informed judgments, estimates and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. In addition, significant estimates are used in determining year end proved oil and gas reserves. Although management believes its estimates and assumptions are reasonable, actual results may differ materially from those estimates. The estimate of our oil and natural gas reserves, which is used to compute DD&A and impairment of oil and gas properties, is the most significant of the estimates and assumptions that affect these reported results.

Excluded Costs . Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent investments in unproved properties and major development projects. These costs are excluded until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed at least quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the capitalized costs being amortized (the DD&A pool). Impairments transferred to the DD&A pool increase the DD&A rate.

Revenue Recognition . We recognize crude oil and natural gas revenue from our interest in producing wells as crude oil and natural gas are sold from those wells, net of royalties. We utilize the sales method to account for gas production volume imbalances. Under this method, income is recorded based on our net revenue interest in production taken for delivery.

Asset Retirement Obligations . The estimated costs of plugging, restoration and removal of facilities are accrued. The fair value of a liability for an asset's retirement obligation is recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated by the units of production method. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. For all periods presented, we have included estimated future costs of abandonment and dismantlement in the full cost amortization base and amortize these costs as a component of our depletion expense.

Derivatives. The Company uses price swap contracts to reduce price volatility associated with certain of its oil sales. All derivative financial instruments are recorded at fair value on the balance sheet as either assets or liabilities. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the realized and unrealized changes in fair value in the Consolidated Statements of Operations under the caption “Gain (loss) on derivative instruments.”

Gas Balancing . Gas imbalances are accounted for under the sales method whereby revenues are recognized based on production sold. A liability is recorded when our excess takes of natural gas volumes exceed our estimated remaining recoverable reserves (over produced). No receivables are recorded for those wells where Mexco has taken less than its ownership share of gas production (under produced).

Stock-based Compensation . We use the Binomial option pricing model to estimate the fair value of stock based compensation expenses at grant date. This expense is recognized as compensation expense in our financial statements over the vesting period. We recognize the fair value of stock based compensation awards as wages in the Consolidated Statements of Operations based on a graded-vesting schedule over the vesting period.

Accounts Receivable. Our accounts receivable include trade receivables from joint interest owners and oil and gas purchasers. Credit is extended based on an evaluation of a customer's financial condition and, generally, is uncollateralized. Accounts receivable under joint operating agreements have a right of offset against future oil and gas revenues if a producing well is completed. The collectability of receivables is assessed and an allowance is made for any doubtful accounts. The allowance for doubtful accounts is determined based on our previous loss history.

32

Income Taxes . The Company recognizes deferred tax assets and liabilities for future tax consequences of temporary differences between the carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates applicable to the years in which those differences are expected to be settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in net income in the period that includes the enactment date. Any interest and penalties are recorded as interest expense and general and administrative expense, respectively.

Other Property and Equipment . Provisions for depreciation of office furniture and equipment are computed on the straight-line method based on estimated useful lives of three to ten years.

Recent Accounting Pronouncements. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Topic 606: Revenue from Contracts with Customers. ASU No. 2014-09 is effective for Mexco as of April 1, 2017. Management is evaluating the effect, if any this pronouncement will have on our consolidated financial statements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

Interest Rate Risk. On March 31, 2015, we had an outstanding loan balance of $5,950,000 under our $6.3 million revolving credit agreement, which bears interest at an annual rate equal to the British Bankers Association London Interbank Offered Rate ("BBA LIBOR") daily floating rate, plus 2.5 percentage points. If the interest rate on our bank debt increases or decreases by one percentage point our annual pretax income would change by $59,500 based on borrowings at March 31, 2015.

Credit Risk. Credit risk is the risk of loss as a result of nonperformance by other parties of their contractual obligations. Our primary credit risk is related to oil and gas production sold to various purchasers and the receivables are generally not collateralized. At March 31, 2015, our largest credit risk associated with any single purchaser was $74,392 or 19% of our total oil and gas receivables. We are also exposed to credit risk in the event of nonperformance from any of our working interest co-owners. At March 31, 2015, our largest credit risk associated with any working interest co-owner was $14,485 or 22% of our total trade receivables. We have not experienced any significant credit losses.

Energy Price Risk . Our most significant market risk is the pricing for natural gas and crude oil. Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. Prices for oil and natural gas fluctuate widely. We cannot predict future oil and natural gas prices with any certainty. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile. Factors that can cause price fluctuations include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability of alternative fuels and overall political and economic conditions in oil producing countries.

Declines in oil and natural gas prices will materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Changes in oil and gas prices impact both estimated future net revenue and the estimated quantity of proved reserves. Any reduction in reserves, including reductions due to price fluctuations, can reduce the borrowing base under our revolving credit facility and adversely affect the amount of cash flow available for capital expenditures and our ability to obtain additional capital for our acquisition, exploration and development activities. In addition, a noncash write-down of our oil and gas properties could be required under full cost accounting rules if prices declined significantly, even if it is only for a short period of time. See Critical Accounting Policies and Estimates — Ceiling Test under Item 7 of this report on Form 10-K. 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.

33

Similarly, any improvements in oil and gas prices can have a favorable impact on our financial condition, results of operations and capital resources. Oil and natural gas prices do not necessarily fluctuate in direct relationship to each other. Our financial results are more sensitive to movements in natural gas prices than oil prices because most of our reserves are natural gas. If the average oil price had increased or decreased by five dollars per barrel for fiscal 2015, our oil and gas revenue would have changed by $147,785. If the average gas price had increased or decreased by one dollar per mcf for fiscal 2015, oil and gas revenue would have changed by $369,034.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required by this item appears on pages F1 through F20 hereof and are incorporated herein by reference.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES

None.

ITEM 9A. CONTROLS AND PROCEDURES

Management’s Annual Report on Internal Control over Financial Reporting. The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Exchange Act Rule 13a-15(f) and 15d-15(f). The Company's internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements. Our internal control over financial reporting is supported by appropriate reviews by management, written policies and guidelines, careful selection and training of qualified personnel, and a written Code of Conduct adopted by our Board of Directors, applicable to all directors, officers and employees of Mexco.

Our chief executive officer and chief financial officer assessed the effectiveness our internal control over financial reporting using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in the 2013 “Internal Control - Integrated Framework”.   Based upon that evaluation, our chief executive officer and chief financial officer concluded that our internal control over financial reporting was effective as of March 31, 2015.

Evaluation of Disclosure Controls and Procedures. We maintain disclosure controls and procedures to ensure that the information we must disclose in our filings with the SEC is recorded, processed, summarized and reported on a timely basis. At the end of the period covered by this report, our principal executive officer and principal financial officer reviewed and evaluated the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rule 13a-15(e). Based on such evaluation, such officers concluded that, as of March 31, 2015, our disclosure controls and procedures were effective.

Changes in Internal Control over Financial Reporting. No changes in the Company’s internal control over financial reporting occurred during the year ended March 31, 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None

34

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

See "Mexco Energy Corporation Board of Directors”, “Named Executive Officers Who Are Not Directors”, “Section 16(a) Beneficial Ownership Reporting Compliance”, “Corporate Governance and Code of Business Conduct” and “Meetings and Committees of the Board of Directors” in the Proxy Statement of Mexco Energy Corporation for our Annual Meeting of Stockholders to be held September 15, 2015 (“Proxy Statement”) to be filed with the SEC within 120 days after the end of our fiscal year ended March 31, 2015, which is incorporated herein by reference.

The information required by this item with respect to executive officers of the Company is also set forth in Part I of this report.

ITEM 11. EXECUTIVE COMPENSATION

The information required by this item will be contained in the Proxy Statement under the caption “Executive Compensation”, and is hereby incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by this item will be contained in the Proxy Statement under the captions “Security Ownership of Certain Beneficial Owners and Management” and “Employee Incentive Stock Option Plans”, and is hereby incorporated herein by reference.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by this item will be contained in the Proxy Statement under the captions “Certain Relationships and Related Transactions” and “Meetings and Committees of the Board of Directors”, and is hereby incorporated by reference herein.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The information required by this item will be contained in the Proxy Statement under the caption “Audit Fees and Services”, and is hereby incorporated by reference herein.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Consolidated Financial Statements. For a list of the consolidated financial statements filed as part of this Form 10-K, see the “Index to Consolidated Financial Statements” set forth on page F1 of this report.

Financial Statement Schedules. All schedules have been omitted because they are not applicable, not required under the instructions or the information requested is set forth in the consolidated financial statements or related notes thereto.

Exhibits. For a list of the exhibits required by this Item and accompanying this Form 10-K see the “Index to Exhibits” set forth on page F21 of this report.

35

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

MEXCO ENERGY CORPORATION

By:
/s/ Nicholas C. Taylor
By:
/s/ Tamala L. McComic
 
Chairman of the Board and Chief Executive Officer
 
President and Chief Financial Officer

Dated: June 25, 2015

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below as of June 25, 2015, by the following persons on behalf of the Registrant and in the capacity indicated.

/s/
Nicholas C. Taylor
 
 
Nicholas C. Taylor
 
 
Chief Executive Officer, Chairman of the Board of Directors
     
/s/
Tamala L. McComic
 
 
Tamala L. McComic
 
 
Chief Financial Officer, President, Treasurer and Assistant Secretary
     
/s/
Michael J. Banschbach
 
 
Michael J. Banschbach
 
 
Director
 
     
/s/
Kenneth L. Clayton
 
 
Kenneth L. Clayton
 
 
Director
 
     
/s/
Thomas R. Craddick
 
 
Thomas R. Craddick
 
 
Director
 
     
/s/
Paul G. Hines
 
 
Paul G. Hines
 
 
Director
 
     
/s/
Christopher M. Schroeder
 
 
Christopher M. Schroeder
 
 
Director
 
 
36

Glossary of Abbreviations and Terms

The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report.
 
BBA LIBOR. British Bankers Association London Interbank Offered Rate. BBA Libor is the most widely used rate for short term interest rates worldwide.

Bbl . One stock tank barrel, or 42 U.S. gallons of liquid volume, used herein in reference to crude oil, condensate or natural gas liquids hydrocarbons.
 
Bcf . One billion cubic feet of natural gas at standard atmospheric conditions.
 
BTU. British thermal unit.

Completion . The installation of permanent equipment for the production of oil or natural gas.

Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.
 
Credit Facility. A line of credit provided by a bank or group of banks, secured by oil and gas properties.
 
DD&A. Refers to depreciation, depletion and amortization of the Company’s property and equipment.
 
Developed acreage . The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development costs. Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.

Development well . A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
 
Dry hole . A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
 
Exploration. The search for natural accumulations of oil and natural gas by any geological, geophysical or other suitable means.

Exploratory well . A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.
 
Extensions and discoveries . As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
 
Formation. A layer of rock which has distinct characteristics that differs from nearby rock.

Gross acres or wells. Refers to the total acres or wells in which the Company owns any amount of working interest.

Lease. An instrument which grants to another (the lessee) the exclusive right to enter and explore for, drill for, produce, store and remove oil and natural gas from the mineral interest, in consideration for which the lessor is entitled to certain rents and royalties payable under the terms of the lease. Typically, the duration of the lessee’s authorization is for a stated term of years and “for so long thereafter” as minerals are producing.

37

Mcf . One thousand cubic feet of natural gas at standard atmospheric conditions.

Mcfe. One thousand cubic feet equivalent of natural gas, calculated by converting oil to equivalent Mcf at a ratio of 6 Mcf for each Bbl of oil.

MMBtu . One million British thermal units of energy commonly used to measure heat value or energy content of natural gas.

Natural gas liquids ("NGLs") . Liquid hydrocarbons that have been extracted from natural gas, such as ethane, propane, butane and natural gasoline.

Net acres or wells. Refers to gross acres or wells multiplied, in each case, by the percentage interest owned by the Company.

Net production . Oil and gas production that is owned by the Company, less royalties and production due others.
 
Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.

Oil . Crude oil or condensate.

Operator . The individual or company responsible for the exploration, development and production of an oil or natural gas well or lease.

Overriding royalty interest (“ORRI”). A royalty interest that is created out of the operating or working interest. Its term is coextensive with that of the operating interest from which it was created.
 
Pay zone.  A geological deposit in which oil and natural gas is found in commercial quantities.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed operating and production expenses and taxes.

Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed nonproducing reserves ("PDNP") . Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells.
 
Proved developed producing reserves ("PDP"). Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods.

Proved developed reserves. The combination of proved developed producing and proved developed nonproducing reserves.
 
Proved reserves. The estimated quantities of oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
 
Proved undeveloped reserves ("PUD") . Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.

38

PV-10. When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses except for specific general and administrative expenses incurred to operate the properties, discounted to a present value using an annual discount rate of 10%.

Recompletion. A process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

Re-entry. Entering an existing well bore to redrill or repair.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Royalty . An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage, or of the proceeds of the sale thereof, but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Shut in.  A well suspended from production or injection but not abandoned.

Spacing. The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 640-acre spacing) and is often established by regulatory agencies.

Standardized measure of discounted future net cash flows . The discounted future net cash flows relating to proved reserves based on prices used in estimating the reserves, year-end costs, and statutory tax rates, and a 10% annual discount rate. The information for this calculation is included in the note regarding disclosures about oil and gas reserve data contained in the Notes to Consolidated Financial Statements included in this Form 10-K.
 
Undeveloped acreage . Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
 
Unit. The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

Wellbore. The hole drilled by the bit that is equipped for crude oil or natural gas production on a completed well. Also called well or borehole.

Working interest . An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and natural gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest is entitled will be smaller than the share of costs that the working interest owner is required to bear to the extent of any royalty burden.
39

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Report of Independent Registered Public Accounting Firm
F-2
Consolidated Balance Sheets
F-3
Consolidated Statements of Operations
F-4
Consolidated Statements of Changes in Stockholders’ Equity
F-5
Consolidated Statements of Cash Flows
F-6
Notes to Consolidated Financial Statements
F-7
 
 

Report of Independent Registered Public Accounting Firm

Board of Directors and Shareholders
Mexco Energy Corporation

We have audited the accompanying consolidated balance sheets of Mexco Energy Corporation (a Colorado corporation) and Subsidiaries (the “Company”) as of March 31, 2015 and 2014 and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for each of the three years in the period ended March 31, 2015. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Mexco Energy Corporation and Subsidiaries as of March 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended March 31, 2015, in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Wichita, Kansas
June 25, 2015

F-2

Mexco Energy Corporation and Subsidiaries
 
CONSOLIDATED BALANCE SHEETS
 
         
   
March 31,
   
March 31,
 
   
2015
   
2014
 
ASSETS
       
Current assets
       
Cash and cash equivalents
 
$
96,084
   
$
156,082
 
Accounts receivable:
               
Oil and gas sales
   
384,485
     
628,098
 
Trade
   
64,584
     
18,144
 
Prepaid costs and expenses
   
44,618
     
28,804
 
Total current assets
   
589,771
     
831,128
 
                 
Property and equipment, at cost
               
Oil and gas properties, using the full cost method
   
40,563,443
     
35,460,741
 
Other
   
106,792
     
94,356
 
Accumulated depreciation, depletion and amortization
   
(19,838,036
)
   
(18,475,174
)
Property and equipment, net
   
20,832,199
     
17,079,923
 
                 
Other noncurrent assets
   
48,980
     
7,239
 
Total assets
 
$
21,470,950
   
$
17,918,290
 
                 
LIABILITIES AND STOCKHOLDERS' EQUITY
               
Current liabilities
               
Accounts payable and accrued expenses
 
$
423,121
   
$
257,431
 
Income tax payable
   
-
     
6,500
 
Derivative instruments
   
-
     
44,981
 
Total current liabilities
   
423,121
     
308,912
 
                 
Long-term debt
   
5,950,000
     
2,425,000
 
Asset retirement obligations
   
1,230,216
     
926,577
 
Deferred income tax liabilities
   
660,870
     
858,449
 
Total liabilities
   
8,264,207
     
4,518,938
 
                 
Commitments and contingencies
               
                 
Stockholders' equity
               
Preferred stock - $1.00 par value;
               
10,000,000 shares authorized; none outstanding
   
-
     
-
 
Common stock - $0.50 par value; 40,000,000 shares authorized;
               
2,104,266 shares issued; 2,037,266 and 2,038,266 shares
               
 outstanding as of March 31, 2015 and 2014, respectively
   
1,052,133
     
1,052,133
 
Additional paid-in capital
   
7,075,031
     
6,921,645
 
Retained earnings
   
5,425,580
     
5,766,566
 
Treasury stock, at cost (67,000 and 66,000 shares, respectively)
   
(346,001
)
   
(340,992
)
Total stockholders' equity
   
13,206,743
     
13,399,352
 
   
$
21,470,950
   
$
17,918,290
 

The accompanying notes to the consolidated financial statements
are an integral part of these statements.

F-3

Mexco Energy Corporation and Subsidiaries
 
CONSOLIDATED STATEMENTS OF OPERATIONS
 
Year ended March 31,
 
             
   
2015
   
2014
   
2013
 
Operating revenues:
           
Oil and gas
 
$
3,336,826
   
$
3,994,295
   
$
3,063,707
 
Other
   
53,179
     
47,646
     
32,708
 
Total operating revenues
   
3,390,005
     
4,041,941
     
3,096,415
 
                         
Operating expenses:
                       
Production
   
1,300,820
     
1,231,814
     
1,082,043
 
Accretion of asset retirement obligation
   
27,932
     
44,366
     
39,376
 
Depreciation, depletion and amortization
   
1,362,862
     
1,151,482
     
1,100,425
 
General and administrative
   
1,239,750
     
1,136,939
     
1,028,846
 
Total operating expenses
   
3,931,364
     
3,564,601
     
3,250,690
 
                         
Operating (loss) income
   
(541,359
)
   
477,340
     
(154,275
)
                         
Other income (expenses):
                       
Interest income
   
45
     
172
     
229
 
Interest expense
   
(99,240
)
   
(65,387
)
   
(53,832
)
Gain (loss) on derivative instruments
   
102,069
     
(99,262
)
   
-
 
Net other income (expense)
   
2,874
     
(164,477
)
   
(53,603
)
                         
(Loss) earnings before provision for income taxes
   
(538,485
)
   
312,863
     
(207,878
)
                         
Income tax (benefit) expense:
                       
Current
   
-
     
6,500
     
-
 
Deferred
   
(197,499
)
   
5,250
     
(31,504
)
     
(197,499
)
   
11,750
     
(31,504
)
                         
Net (loss) income
 
$
(340,986
)
 
$
301,113
   
$
(176,374
)
                         
                         
(Loss) income per common share:
                       
Basic:
 
$
(0.17
)
 
$
0.15
   
$
(0.09
)
Diluted:
 
$
(0.17
)
 
$
0.15
   
$
(0.09
)
                         
Weighted average common shares outstanding:
                       
Basic:
   
2,038,250
     
2,036,950
     
2,036,959
 
Diluted:
   
2,038,250
     
2,042,184
     
2,036,959
 

The accompanying notes to the consolidated financial statements
are an integral part of these statements.

F-4

Mexco Energy Corporation and Subsidiaries
 
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
 
Years ended March 31, 2015, 2014 and 2013
 
                     
    
Common Stock Par Value
   
Treasury
Stock
   
Additional
Paid-In
Capital
   
Retained
Earnings
   
Total Stockholders’ Equity
 
Balance at April 1, 2012
 
$
1,049,558
   
$
(325,445
)
 
$
6,608,350
   
$
5,641,827
   
$
12,974,290
 
Net loss
   
-
     
-
     
-
     
(176,374
)
   
(176,374
)
Purchase of stock
   
-
     
(15,547
)
   
-
     
-
     
(15,547
)
Issuance of stock through
                                       
options exercised
   
1,875
     
-
     
14,438
     
-
     
16,313
 
Stock based compensation
   
-
     
-
     
138,303
     
-
     
138,303
 
Balance at March 31, 2013
 
$
1,051,433
   
$
(340,992
)
 
$
6,761,091
   
$
5,465,453
   
$
12,936,985
 
Net income
   
-
     
-
     
-
     
301,113
     
301,113
 
Issuance of stock through
                                       
options exercised
   
700
     
-
     
8,106
     
-
     
8,806
 
Stock based compensation
   
-
     
-
     
152,448
     
-
     
152,448
 
Balance at March 31, 2014
 
$
1,052,133
   
$
(340,992
)
 
$
6,921,645
   
$
5,766,566
   
$
13,399,352
 
Net loss
   
-
     
-
     
-
     
(340,986
)
   
(340,986
)
Purchase of stock
   
-
     
(5,009
)
   
-
     
-
     
(5,009
)
Stock based compensation
   
-
     
-
     
153,386
     
-
     
153,386
 
Balance at March 31, 2015
 
$
1,052,133
   
$
(346,001
)
 
$
7,075,031
   
$
5,425,580
   
$
13,206,743
 
                                         
SHARE ACTIVITY
                                       
             
2015
     
2014
     
2013
         
Common stock shares, issued:
                                       
At beginning of year
           
2,104,266
     
2,102,866
     
2,099,116
         
Issued
           
-
     
1,400
     
3,750
         
At end of year
           
2,104,266
     
2,104,266
     
2,102,866
         
                                         
Common stock shares, held in treasury:
                                 
At beginning of year
           
(66,000
)
   
(66,000
)
   
(63,167
)
       
Acquisitions
           
(1,000
)
   
-
     
(2,833
)
       
At end of year
           
(67,000
)
   
(66,000
)
   
(66,000
)
       
                                         
Common stock shares, outstanding
                                 
At end of year
           
2,037,266
     
2,038,266
     
2,036,866
         
 
The accompanying notes to the consolidated financial statements
are an integral part of these statements.
F-5

Mexco Energy Corporation and Subsidiaries
 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
Year ended March 31,
 
             
   
2015
   
2014
   
2013
 
Cash flows from operating activities:
           
Net (loss) income
 
$
(340,986
)
 
$
301,113
   
$
(176,374
)
Adjustments to reconcile net (loss) income to net cash
                       
provided by operating activities:
                       
Deferred income tax (benefit) expense
   
(197,499
)
   
5,250
     
(31,504
)
Stock-based compensation
   
153,386
     
152,448
     
138,303
 
Depreciation, depletion and amortization
   
1,362,862
     
1,151,482
     
1,100,425
 
Accretion of asset retirement obligations
   
27,932
     
44,366
     
39,376
 
(Gain) loss on derivative instruments
   
(102,069
)
   
99,262
     
-
 
Changes in assets and liabilities, net of business combination:
                       
Decrease (increase) in accounts receivable
   
197,173
     
(90,901
)
   
(117,123
)
Increase in prepaid expenses
   
(15,814
)
   
(9,523
)
   
(2,499
)
Decrease (increase) in noncurrent assets
   
-
     
109,215
     
(116,454
)
(Decrease) increase in income tax payable
   
(6,500
)
   
6,500
     
-
 
Increase (decrease) in accounts payable and accrued expenses
   
98,494
     
43,289
     
(17,358
)
Net cash provided by operating activities
   
1,176,979
     
1,812,501
     
816,792
 
                         
Cash flows from investing activities:
                       
Additions to oil and gas properties
   
(4,777,979
)
   
(2,150,478
)
   
(1,300,151
)
Acquisition of business
   
-
     
-
     
(1,150,000
)
Additions to other property and equipment
   
(12,436
)
   
(2,030
)
   
(13,806
)
Settlement of asset retirement obligations
   
(39,352
)
   
(63,230
)
   
(4,918
)
Settlement of derivatives
   
57,089
     
(54,281
)
   
-
 
Proceeds from sale of oil and gas properties and equipment
   
15,710
     
963,388
     
69,042
 
Net cash used in investing activities
   
(4,756,968
)
   
(1,306,631
)
   
(2,399,833
)
                         
Cash flows from financing activities:
                       
Acquisition of treasury stock
   
(5,009
)
   
-
     
(15,547
)
Proceeds from exercise of stock options
   
-
     
8,806
     
16,313
 
Reduction of long-term debt
   
(150,000
)
   
(1,375,000
)
   
(350,000
)
Proceeds from long-term debt
   
3,675,000
     
850,000
     
1,600,000
 
Net cash provided by (used in) financing activities
   
3,519,991
     
(516,194
)
   
1,250,766
 
                         
Net decrease in cash and cash equivalents
   
(59,998
)
   
(10,324
)
   
(332,275
)
                         
Cash and cash equivalents at beginning of period
   
156,082
     
166,406
     
498,681
 
                         
Cash and cash equivalents at end of period
 
$
96,084
   
$
156,082
   
$
166,406
 
                         
Supplemental disclosure of cash flow information:
                       
Cash paid for interest
 
$
91,264
   
$
67,170
   
$
49,158
 
Income taxes paid
 
$
13,032
   
$
-
   
$
-
 
                         
Non-cash investing and financing activities:
                       
Asset retirement obligations
 
$
274,148
   
$
134,113
   
$
114,003
 
Acquisition of subsidiary resulting in the assumption of liabilities as follows:
                       
Fair value of assets
 
$
-
   
$
-
   
$
1,276,636
 
Cash paid
   
-
     
-
     
(1,150,000
)
Liabilities assumed
 
$
-
   
$
-
   
$
126,636
 

The accompanying notes to the consolidated financial statements
are an integral part of these statements.

F-6

MEXCO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended March 31, 2015, 2014 and 2013

1. Nature of Operations

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

2. Summary of Significant Accounting Policies

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

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

Cash and Cash Equivalents . The Company considers all highly liquid debt instruments purchased with maturities of three months or less and money market funds to be cash equivalents. The Company maintains cash in bank deposit accounts that may, at times, exceed federally insured limits. At March 31, 2015, the Company had the majority of its cash and cash equivalents with one financial institution. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk.

Accounts Receivable. Accounts receivable includes trade receivables from joint interest owners and oil and gas purchasers. Credit is extended based on an evaluation of a customer's financial condition and, generally, is uncollateralized. Accounts receivable under joint operating agreements have a right of offset against future oil and gas revenues if a producing well is completed. The collectability of receivables is assessed and an allowance is made for any doubtful accounts. The allowance for doubtful accounts is determined based on the Company’s previous loss history. The Company has not experienced any significant credit losses. For the years ending March 31, 2015, 2014 and 2013, no allowance has been made for doubtful accounts.

Oil and Gas Properties . Oil and gas properties are accounted for using the full cost method of accounting. Under this method of accounting, the costs of unsuccessful, as well as successful, acquisition, exploration and development activities are capitalized as property and equipment. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation (“ARO”) when incurred. Generally, no gains or losses are recognized on the sale or disposition of oil and gas properties.

Excluded Costs . Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent investments in unproved properties and major development projects. These costs are excluded until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed at least quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the capitalized costs being amortized (the depreciation, depletion and amortization (“DD&A”) pool). Impairments transferred to the DD&A pool increase the DD&A rate.
F-7

Ceiling Test . Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is an impairment test to determine a limit, or ceiling, on the book value of oil and gas properties. That limit is basically the after tax present value of the future net cash flows from proved crude oil and natural gas reserves and using an average price over the prior 12-month period held flat for the life of production plus the lower of cost or fair market value of unproved properties. If net capitalized costs of crude oil and natural gas properties exceed the ceiling limit, the Company must charge the amount of the excess to earnings as an expense reflected in additional accumulated DD&A. This is called a "ceiling limitation write-down." This charge does not impact cash flow from operating activities, but does reduce stockholders' equity and reported earnings.

Depreciation, Depletion and Amortization . The depreciable base for oil and gas properties includes the sum of capitalized costs, net of accumulated DD&A, estimated future development costs and asset retirement costs not accrued in oil and gas properties, less costs excluded from amortization and salvage. The depreciable base of oil and gas properties is amortized using the unit-of-production method.

Asset Retirement Obligations . The Company has significant obligations to plug and abandon natural gas and crude oil wells and related equipment at the end of oil and gas production operations. The Company records the fair value of a liability for an ARO in the period in which it is incurred and a corresponding increase in the carrying amount of the related asset. Subsequently, the asset retirement costs included in the carrying amount of the related asset are allocated to expense using the units of production method. In addition, increases in the discounted ARO liability resulting from the passage of time are reflected as accretion expense in the Consolidated Statement of Operations.

Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. The Company uses the present value of estimated cash flows related to the ARO to determine the fair value. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the related asset.

Income Taxes . The Company recognizes deferred tax assets and liabilities for future tax consequences of temporary differences between the carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates applicable to the years in which those differences are expected to be settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in net income in the period that includes the enactment date. Any interest and penalties are recorded as interest expense and general and administrative expense, respectively.

Other Property and Equipment . Provisions for depreciation of office furniture and equipment are computed on the straight-line method based on estimated useful lives of three to ten years.

Derivatives. The Company is required to recognize its derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the realized and unrealized change in fair value on derivative instruments in the consolidated statements of operations.

(Loss) Income Per Common Share . Basic net (loss) income per share is computed by dividing net (loss) income by the weighted average number of common shares outstanding during the period. Diluted net (loss) income per share assumes the exercise of all stock options having exercise prices less than the average market price of the common stock during the period using the treasury stock method and is computed by dividing net (loss) income by the weighted average number of common shares and dilutive potential common shares (stock options) outstanding during the period. In periods where losses are reported, the weighted-average number of common shares outstanding excludes potential common shares, because their inclusion would be anti-dilutive.
F-8

Revenue Recognition. Oil and gas sales and resulting receivables are recognized when the product is delivered to the purchaser and title has transferred. Sales are to credit-worthy energy purchasers with payments generally received within 60 days of transportation from the well site. The Company has historically had little, if any, uncollectible oil and gas receivables.

Gas Balancing . Gas imbalances are accounted for under the sales method whereby revenues are recognized based on production sold. A liability is recorded when excess takes of natural gas volumes exceed estimated remaining recoverable reserves (over produced). No receivables are recorded for those wells where the Company has taken less than its ownership share of gas production (under produced). The Company does not have any significant gas imbalances.

Stock-based Compensation . The Company uses the Binomial option pricing model to estimate the fair value of stock based compensation expenses at grant date. This expense is recognized as compensation expense in its financial statements over the vesting period. The Company recognizes the fair value of stock-based compensation awards as wages in the Consolidated Statements of Operations based on a graded-vesting schedule over the vesting period.

Recent Accounting Pronouncements. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Topic 606: Revenue from Contracts with Customers. ASU No. 2014-09 is effective for Mexco as of April 1, 2017. Management is evaluating the effect, if any this pronouncement will have on the Company’s consolidated financial statements.

3. Business Combinations

On December 31, 2012, the Company purchased all of the outstanding ownership interests of TBO Oil & Gas, LLC (“TBO”), a Texas limited liability company which owns non-operated working interests in approximately 280 wells producing primarily oil, expanding the Company’s revenues. The cash purchase price of $1,150,000 was funded from its $4.9 million bank credit facility.

The purchase price was allocated to the assets acquired and liabilities assumed at estimated fair values as follows:

Proved oil and gas properties
 
$
1,202,013
 
Accounts receivable
   
74,623
 
Total assets acquired
   
1,276,636
 
         
Accounts payable
   
(45,876
)
Asset retirement obligations assumed
   
(80,760
)
Net purchase price
 
$
1,150,000
 

The Company’s results of operations for fiscal year 2015 include approximately $366,000 in revenues and approximately $120,000 in earnings from TBO. The Company’s results of operations for fiscal year 2014 include approximately $705,000 in revenues and approximately $448,000 in earnings from TBO. The Company’s results of operations for fiscal year 2013 include approximately $119,800 in revenues and approximately $62,400 in earnings from TBO.

The Company has not disclosed the pro forma information for this acquisition because the revenue and expenses for this acquisition were immaterial to its consolidated financial statements.

4. Fair Value of Financial Instruments.

Fair value as defined by authoritative literature is the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. Fair value measurements are classified and disclosed in one of the following categories:
F-9

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

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

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

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

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

The fair value amount reported in the accompanying consolidated balance sheets for long term debt approximates fair value because the actual interest rates do not significantly differ from current rates offered for instruments with similar characteristics and is deemed to use Level 2 inputs. See the Company’s Note 5 on Credit Facility for further discussion.

The fair value of the Company’s crude oil swaps are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. The valuation of the Company’s derivative instrument is deemed to use Level 2 inputs. See the Company’s Note 8 on Derivatives for further discussion.

5. Credit Facility

The Company has a revolving credit agreement with Bank of America, N.A. (the “Agreement”), which provides for a credit facility of $6,300,000 with no monthly commitment reductions and a borrowing base evaluated annually, currently set at $6,300,000. Amounts borrowed under the Agreement are collateralized by the common stock of the Company’s wholly owned subsidiaries and substantially all of the Company’s oil and gas properties.

The Agreement was renewed nine times with the ninth amendment on February 13, 2015, which revised the maturity date to November 30, 2020. Under the original and renewed agreements, interest on the facility accrues at an annual rate equal to the British Bankers Association London Interbank Offered Rate ("BBA LIBOR") daily floating rate, plus 2.50 percentage points, which was 2.68% on March 31, 2015. Interest on the outstanding amount under the credit agreement is payable monthly. In addition, the Company will pay an unused commitment fee in an amount equal to ½ of 1 percent (.5%) times the daily average of the unadvanced amount of the commitment. The unused commitment fee is payable quarterly in arrears on the last day of each calendar quarter and is included in the consolidated statements of operations under the caption “General and administrative” expenses. Availability of this line of credit at March 31, 2015 was $300,000. No principal payments are anticipated to be required through November 30, 2020.

The Agreement contains customary covenants for credit facilities of this type including limitations on disposition of assets, mergers and reorganizations. The Company is also obligated to meet certain financial covenants under the Agreement. The Company is in compliance with all covenants as of March 31, 2015. In addition, this Agreement prohibits the Company from paying cash dividends on its common stock. The Agreement does grant the Company permission to enter into hedge agreements; however, it is under no obligation to do so.

The amended Agreement allows for up to $500,000 of the facility to be used for outstanding letters of credits. As of March 31, 2015, one letter of credit for $50,000, in lieu of a plugging bond with the Texas Railroad Commission (“TRRC”) covering the properties the Company operates is outstanding under the facility. This letter of credit renews annually. The Company will pay a fee in an amount equal to 1 percent (1.0%) per annum of the outstanding undrawn amount of each standby letter of credit, payable monthly in arrears, on the basis of the face amount outstanding on the day the fee is calculated.
F-10

The balance outstanding on the line of credit as of March 31, 2015 was $5,950,000 and as of June 23, 2015 was $6,100,000. The following table is a summary of activity on the Bank of America, N.A. line of credit for the year ended March 31, 2015:

   
Principal
 
Balance at April 1, 2014:
 
$
2,425,000
 
Borrowings
   
3,675,000
 
Repayments
   
(150,000
)
Balance at March 31, 2015:
 
$
5,950,000
 

6. Asset Retirement Obligations

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

The following table provides a rollforward of the asset retirement obligations for fiscal years ended March 31:

   
2015
   
2014
 
Carrying amount of asset retirement obligations as of April 1
 
$
961,577
   
$
813,412
 
Liabilities incurred
   
274,148
     
134,113
 
Liabilities settled
   
(23,441
)
   
(30,314
)
Accretion expense
   
27,932
     
44,366
 
Carrying amount of asset retirement obligations as of March 31
   
1,240,216
     
961,577
 
Less: Current portion
   
10,000
     
35,000
 
Non-Current asset retirement obligation
 
$
1,230,216
   
$
926,577
 

7. Income Taxes

The Company files a consolidated federal income tax return and various state income tax returns. The amount of income taxes we record requires the interpretation of complex rules and regulations of federal and state taxing jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal and state income tax examinations by tax authorities for years prior to 2012. In January 2014, the Company was notified by the Internal Revenue Service that it had been selected at random for a compliance research examination of fiscal year ending March 31, 2012. The Company has been informally advised by an employee of the Internal Revenue Service that the audit resulted in no change to the Company’s federal income tax return.

Significant components of net deferred tax assets (liabilities) at March 31 are as follows:

   
2015
   
2014
 
Deferred tax assets:
       
Percentage depletion carryforwards
 
$
1,535,126
   
$
1,463,834
 
Deferred stock-based compensation
   
36,958
     
29,475
 
Asset retirement obligation
   
384,467
     
298,089
 
Net operating loss
   
720,308
     
298,736
 
Derivative instruments
   
-
     
13,944
 
Other
   
11,111
     
9,673
 
     
2,687,970
     
2,113,751
 
Deferred tax liabilities:
               
Excess financial accounting bases over tax bases of    property and equipment
   
(3,348,840
)
   
(2,972,200
)
                 
Net deferred tax liabilities
 
$
(660,870
)
 
$
(858,449
)

F-11

As of March 31, 2015, the Company has a statutory depletion carryforward of approximately $4,950,000, which does not expire. At March 31, 2015, the Company had a net operating loss carryforward for regular income tax reporting purposes of approximately $4,500,000, which will begin expiring in 2029. The Company’s ability to use some of its net operating loss carryforwards and certain other tax attributes to reduce current and future U.S. federal taxable income is subject to limitations under the Internal Revenue Code.

The income tax provision consists of the following for years ended March 31, 2015, 2014 and 2013:

   
2015
   
2014
   
2013
 
Current income tax expense
 
$
-
   
$
6,500
   
$
-
 
Deferred income tax (benefit) expense
   
(197,499
 )    
5,250
     
(31,504
)
Total income tax provision:
 
$
(197,499
 )  
$
11,750
   
$
(31,504
)
                         
Effective tax rate
   
(37
%)
   
4
%
   
(15
%)

The current income tax expense for fiscal year 2014 is the Company’s anticipated alternative minimum tax that cannot offset with its alternative minimum tax net operating loss.

A reconciliation of the provision for income taxes to income taxes computed using the federal statutory rate for years ended March 31 follows:

   
2015
   
2014
   
2013
 
Tax expense at federal statutory rate (1)
 
$
(183,085
)
 
$
106,374
   
$
(70,678
)
Statutory depletion carryforward
   
(71,292
)
   
(127,204
)
   
-
 
Effect of graduated rates
   
12,221
     
(13,841
)
   
3,391
 
Permanent differences
   
       44,657
     
    46,421
     
 35,783
 
Total income tax (benefit) expense
 
$
(197,499
)
 
$
11,750
   
$
(31,504
)
                         
Effective income tax rate
   
(37
%)
   
4
%
   
(15
%)

 
(1)
The federal statutory rate was 34% for fiscal years ending March 31, 2015, 2014 and 2013.

For the years ended March 31, 2015, 2014 and 2013, the Company did not have any uncertain tax positions.

A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows:
 
   
2015
   
2014
   
2013
 
Unrecognized tax benefits at beginning of period
 
$
679,000
   
$
677,000
   
$
677,000
 
Additions based on tax positions related to the current year
   
-
     
2,000
     
-
 
Changes to tax positions of prior years
   
-
     
-
     
-
 
Settlements
   
-
     
-
     
-
 
Expirations
   
-
     
-
     
-
 
Unrecognized tax benefits at end of period
 
$
679,000
   
$
679,000
   
$
677,000
 

While the amount of unrecognized tax benefits may change in the next 12 months, the Company does not expect any change to have a significant impact on its results of operations. The recognition of the total amount of the unrecognized tax benefits would have an impact on the effective tax rate. If these unrecognized tax benefits are disallowed, the Company will be required to pay additional taxes.

8. Derivatives

All derivative financial instruments are recorded at fair value. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the realized and unrealized changes in fair value in the consolidated statements of operations under the caption “Gain (loss) on derivative instruments.”

F-12

The Company uses price swap contracts to reduce price volatility associated with certain of its oil sales. With respect to the Company’s fixed price swap contracts, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate (“NYMEX WTI”) pricing. The counterparty to the Company’s derivative contract is Merrill Lynch Commodities, Inc., which the Company believes is an acceptable credit risk.

The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity.

As of March 31, 2015 the Company does not have any open crude oil derivative positions with respect to future production.

The net fair value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows for the years ended March 31:

   
2015
   
2014
 
Current assets: Derivative instruments
 
$
-
   
$
-
 
Noncurrent assets: Derivative instruments
   
-
   
$
-
 
Total assets
 
$
-
   
$
-
 
                 
Current liabilities: Derivative instruments
 
$
-
   
$
44,981
 
Noncurrent liabilities: Derivative instruments
   
-
   
$
-
 
Total liabilities
 
$
-
   
$
44,981
 

None of the Company’s derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following summarizes the loss on derivative instruments included in the consolidated statements of operations for the year ended March 31, 2015 and 2014:

   
2015
   
2014
 
Unrealized loss on open non-hedge derivative instruments
 
$
-
   
$
(44,981
)
Gain (loss) on settlement of non-hedge derivative instruments
   
102,069
     
(54,281
)
Total gain (loss) on derivative instruments
 
$
102,069
   
$
(99,262
)

9. Major Customers

Currently, the Company operates exclusively within the United States and its revenues and operating profit are derived from the oil and gas industry. Oil and gas production is sold to various purchasers and the receivables are unsecured. Historically, the Company has not experienced significant credit losses on its oil and gas accounts and management is of the opinion that significant credit risk does not exist. Management is of the opinion that the loss of any one purchaser would not have an adverse effect on the Company’s ability to sell its oil and gas production.

In fiscal 2015, one customer accounted for 17% of the total oil and gas revenues and 19% of the total oil and gas accounts receivable. In fiscal 2014, one customer accounted for 22% of the total oil and gas revenues and 25% of the total oil and gas accounts receivable. In fiscal 2013, one customer accounted for 26% of the total oil and gas revenues and 24% of the total oil and gas accounts receivable.

F-13

10. Oil and Gas Costs

The costs related to the Company’s oil and gas activities were incurred as follows for the year ended March 31:

   
2015
   
2014
   
2013
 
Property acquisition costs:
           
Proved
 
$
3,108,040
   
$
785,144
   
$
20,542
 
Unproved
   
-
     
-
     
-
 
Exploration
   
15,472
     
9,641
     
15,715
 
Development
   
1,746,582
     
1,152,986
     
1,265,126
 
Capitalized asset retirement obligations
   
274,148
     
134,113
     
114,003
 
Total costs incurred for oil and gas properties
 
$
5,144,242
   
$
2,081,884
   
$
1,415,386
 

The Company had the following aggregate capitalized costs relating to its oil and gas property activities at March 31:

   
2015
   
2014
   
2013
 
Proved oil and gas properties
 
$
40,489,453
   
$
35,386,751
   
$
34,138,841
 
Unproved oil and gas properties:
                       
subject to amortization
   
73,990
     
73,990
     
170,487
 
not subject to amortization
   
-
     
-
     
-
 
     
40,563,443
     
35,460,741
     
34,309,328
 
Less accumulated DD&A
   
19,752,994
     
18,395,619
     
17,249,803
 
   
$
20,810,449
   
$
17,065,122
   
$
17,059,525
 

DD&A amounted to $2.48, $2.18 and $2.03 per mcfe of production for the years ended March 31, 2015, 2014 and 2013, respectively.

11. (Loss) Income Per Common Share

Due to a net loss for the year ended March 31, 2015, the weighted average number of common shares outstanding excludes common stock equivalents because their inclusion would be anti-dilutive. For the year ended March 31, 2014, 35,000 options were excluded from the diluted net income per share calculations because the options are anti-dilutive. Anti-dilutive stock options have a weighted average exercise price of $5.98 at March 31, 2014. Due to a net loss for the year ended March 31, 2013, the weighted average number of common shares outstanding excludes common stock equivalents because their inclusion would be anti-dilutive.

The following is a reconciliation of the number of shares used in the calculation of basic income per share and diluted income per share for the periods ended March 31:

   
2015
   
2014
   
2013
 
Net (loss) income
 
$
(340,986
)
 
$
301,113
   
$
(176,374
)
                         
Shares outstanding:
                       
Weighted avg. common shares outstanding – basic
   
2,038,250
     
2,036,950
     
2,036,959
 
Effect of the assumed exercise of dilutive stock options
   
-
     
5,234
     
-
 
Weighted avg. common shares outstanding – dilutive
   
2,038,250
     
2,042,184
     
2,036,959
 
                         
(Loss) income per common share:
                       
Basic
 
$
(0.17
)
 
$
0.15
   
$
(0.09
)
Diluted
 
$
(0.17
)
 
$
0.15
   
$
(0.09
)

F-14

12. Stockholders’ Equity

In June 2014, the Board of Directors authorized the use of up to $250,000 to repurchase shares of the Company’s common stock for the treasury account. During the fiscal year ended March 31, 2015, the Company repurchased 1,000 shares for the treasury at an aggregate cost of $5,009. There were no shares of common stock repurchased for the treasury account during fiscal 2014. During the fiscal year ended March 31, 2013, the Company repurchased 2,833 shares at an aggregate cost of $15,547.

13. Stock Options

In September 2009, the Company adopted the 2009 Employee Incentive Stock Plan (the “2009 Plan”). The 2009 Plan provides for the award of stock options up to 200,000 shares and includes option awards as well as stock awards. Option awards are granted with the restriction of requiring payment for the shares. Stock awards are granted without restrictions and without payment by the recipient. Neither option awards nor stock awards may exceed 25,000 shares granted to any one individual in any fiscal year. Stock options may be an incentive stock option or a nonqualified stock option. Options to purchase common stock under the plan are granted at the fair market value of the common stock at the date of grant, become exercisable to the extent of 25% of the shares optioned on each of four anniversaries of the date of grant, expire ten years from the date of grant and are subject to forfeiture if employment terminates. The 2009 Plan expires ten years from the date of adoption.

According to the Company’s employee stock incentive plan, new shares will be issued upon the exercise of stock options and the Company can repurchase shares exercised under the plan. The plan also provides for the granting of stock awards. No stock awards were granted during fiscal 2015, 2014 and 2013.

The Company recognized compensation expense of $153,386, $152,448 and $138,303 in general and administrative expense in the Consolidated Statements of Operations for fiscal 2015, 2014 and 2013, respectively. The total cost related to non-vested awards not yet recognized at March 31, 2015 totals $195,606, which is expected to be recognized over a weighted average of 2.6 years.

The fair value of each stock option is estimated on the date of grant using the Binomial valuation model. Expected volatilities are based on historical volatility of the Company’s stock over the contractual term of 120 months and other factors. The Company uses historical data to estimate option exercise and employee termination within the valuation model. The expected term of options granted is derived from the output of the option valuation model and represents the period of time that options granted are expected to be outstanding. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant. As the Company has never declared dividends, no dividend yield is used in the calculation. Actual value realized, if any, is dependent on the future performance of the Company’s common stock and overall stock market conditions. There is no assurance the value realized by an optionee will be at or near the value estimated by the Binomial model.

During the year ended March 31, 2015, the Compensation Committee of the Board of Directors approved and the Company granted 40,000 stock options to officers and employees of the Company exercisable at $7.00 per share. During the year ended March 31, 2014, the Compensation Committee of the Board of Directors approved and the Company granted 35,000 stock options to officers and employees of the Company exercisable at $5.98 per share. During the year ended March 31, 2013, no stock options were granted. These options are exercisable at a price not less than the fair market value of the stock at the date of grant, have an exercise period of ten years and generally vest over four years.

Included in the following table is a summary of the grant-date fair value of stock options granted and the related assumptions used in the Binomial models for stock options granted in fiscal 2015, 2014 and 2013. All such amounts represent the weighted average amounts for each period.

   
For the year ended March 31,
 
   
2015
   
2014
   
2013
 
Grant-date fair value
 
$
5.59
   
$
4.75
     
-
 
Volatility factor
   
76.23
%
   
77.01
%
   
-
 
Dividend yield
   
-
     
-
     
-
 
Risk-free interest rate
   
2.52
%
   
1.74
%
   
-
 
Expected term (in years)
   
10
     
7
     
-
 

F-15

No forfeiture rate is assumed for stock options granted to directors or employees due to the forfeiture rate history for these types of awards. There were no stock options forfeited or expired during the years ended March 31, 2015, 2014 and 2013.

The following table is a summary of activity of stock options for the year ended March 31, 2015, 2014 and 2013:

 
Number
of Shares
   
Weighted Average Exercise Price
Per Share
   
Weighted Aggregate Average Remaining Contract Life in Years
   
Intrinsic
Value
 
Outstanding at April 1, 2012
 
83,750
   
$
6.42
   
8.65
   
$
127,363
 
Granted
 
-
     
-
               
Exercised
 
(3,750
)
   
4.35
               
Forfeited or Expired
 
-
     
-
               
Outstanding at March 31, 2013
 
80,000
   
$
6.52
   
8.03
   
$
-
 
Granted
 
35,000
     
5.98
               
Exercised
 
(1,400
)
   
6.29
               
Forfeited or Expired
 
-
     
-
               
Outstanding at March 31, 2014
 
113,600
   
$
6.35
   
7.66
   
$
154,062
 
Granted
 
40,000
     
7.00
               
Exercised
 
-
     
-
               
Forfeited or Expired
 
-
     
-
               
Outstanding at March 31, 2015
 
153,600
   
$
6.52
   
7.36
   
$
-
 
                             
Vested at March 31, 2015
 
77,350
   
$
6.42
   
6.19
   
$
-
 
Exercisable at March 31, 2015
 
77,350
   
$
6.42
   
6.19
   
$
-
 

Other information pertaining to option activity was as follows during the year ended March 31:

   
2015
   
2014
   
2013
 
Weighted average grant-date fair value of stock options granted (per share)
 
$
5.59
   
$
4.75
   
$
-
 
Total fair value of options vested
 
$
150,063
   
$
108,500
   
$
108,500
 
Total intrinsic value of options exercised
 
$
-
   
$
6,244
   
$
3,138
 

The following table summarizes information about options outstanding at March 31, 2015:

Range of Exercise Prices
   
Number of
Options
   
Weighted Average Exercise Price
Per Share
 
Weighted Average
Remaining Contract
Life in Years
Aggregate
Intrinsic
Value
$
5.98 – 6.25
   
45,000
   
$
6.00
           
 
6.26 – 6.50
   
28,600
     
6.29
           
 
6.51 – 6.80
   
40,000
     
6.80
           
 
6.81 – 7.00
   
40,000
     
7.00
           
$
5.98 – 7.00
   
153,600
   
$
6.52
 
7.36
$
-

Outstanding options at March 31, 2015 expire between August 2020 and August 2024 and have exercise prices ranging from $5.98 to $7.00.

14. Related Party Transactions

Related party transactions for the fiscal year ended March 31, 2015 relate to shared office expenditures in addition to administrative and operating expenses paid on behalf of the majority stockholder. The total billed to and reimbursed by the stockholder for the years ended March 31, 2015, 2014 and 2013 were $125,209, $133,861 and $144,404, respectively.
F-16

15. Lease Commitments

The Company leases its principal office space. On April 1, 2013, the Company agreed to a three year lease, with an option to renew for an additional two years. On April 1, 2014, the Company agreed to a three year lease for an additional office space. The following table summarizes future payments we are obligated to make based on the lease commitments in place as of March 31, 2015:

   
Commitment Amount (1)
 
Fiscal Year 2016
 
$
23,440
 
Fiscal Year 2017
   
4,420
 

(1)
The total commitment for the remainder of the leases is $37,100 which includes $9,240 billed to and reimbursed by our majority shareholder for his portion of the shared office space.

16. Oil and Gas Reserve Data (Unaudited)

The estimates of the Company’s proved oil and gas reserves, which are located entirely within the United States, were prepared in accordance with the guidelines established by the SEC. The estimates as of March 31, 2015, 2014, and 2013 are based on evaluations prepared by Joe C. Neal and Associates, Petroleum Consultants. Management emphasizes that reserve estimates are inherently imprecise and are expected to change as new information becomes available and as economic conditions in the industry change.

Proved reserves are estimated quantities of oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

Changes in Proved Reserves :

 
Oil
(Bbls)
 
Natural Gas
(Mcf)
Proved Developed and Undeveloped Reserves:
     
As of April 1, 2012
346,000
 
8,445,000
 
Revision of previous estimates
(10,000)
 
(589,000)
 
Purchase of minerals in place
48,000
 
71,000
 
Extensions and discoveries
5,000
 
318,000
 
Sales of minerals in place
-
 
-
 
Production
(23,000)
 
(401,000)
As of March 31, 2013
366,000
 
7,844,000
 
Revision of previous estimates
12,000
 
(1,404,000)
 
Purchase of minerals in place
50,000
 
18,000
 
Extensions and discoveries
101,000
 
163,000
 
Sales of minerals in place
-
 
-
 
Production
(27,000)
 
(362,000)
As of March 31, 2014
502,000
 
6,259,000
 
Revision of previous estimates
(90,000)
 
(665,000)
 
Purchase of minerals in place
43,000
 
795,000
 
Extensions and discoveries
235,000
 
269,000
 
Sales of minerals in place
-
 
-
 
Production
(30,000)
 
(369,000)
As of March 31, 2015
660,000
 
6,289,000

Proved developed reserves are those expected to be recovered through existing wells, equipment and operating methods. Proved undeveloped reserves ("PUD") are proved reserves are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. The downward revision of oil and natural gas is primarily the result of SEC rules which require such reserves to be developed within five years and because of the participation in one unsuccessful well. Reserves written off due to the five year limitation are in the El Cinco field which are on leases held by production and are still in place to be developed in the future.

F-17

Summary of Proved Developed and Undeveloped Reserves as of March 31, 2015, 2014 and 2013 :

 
Oil
(Bbls)
 
Natural Gas
(Mcf)
Proved Developed Reserves:
     
As of April 1, 2012
194,620
 
5,359,670
As of March 31, 2013
237,420
 
4,807,020
As of March 31, 2014
294,620
 
4,081,470
As of March 31, 2015
283,670
 
4,584,790
       
Proved Undeveloped Reserves:
     
As of April 1, 2012
151,730
 
3,085,060
As of March 31, 2013
128,290
 
3,037,180
As of March 31, 2014
206,930
 
2,177,810
As of March 31, 2015
376,070
 
1,703,790

As of March 31, 2015, 2014 and 2013 reserves were computed using the 12-month unweighted average of the first-day-of-the-month prices, in accordance with current SEC rules.

At March 31, 2015, the Company reported estimated PUDs of 3.96 bcfe, which accounted for 39% of its total estimated proved oil and gas reserves. This figure primarily consists of a projected 73 new wells (2.7 bcfe), 6 of which we operate, and 1 new zone behind pipe from a currently producing wellbore (.4 bcfe) that the Company also operates. The Company’s timetable for this well is totally dependent on the life of the currently producing zone. After the current zone has depleted, the Company will open the new productive zone. Of the 6 wells the Company operates (1.6 bcfe), 4 wells will be drilled on existing acreage in the Goldsmith field where the Company currently operates 3 wells. The Company projects 5 operated wells will be drilled in fiscal 2016, with the 1 remaining well in fiscal 2017. Regarding the remaining 67 PUD locations operated by others (1.1 bcfe), 12 wells are currently being drilled and 2 locations are currently being prepared to drill with plans for 18 wells to follow in 2016, 27 wells in 2017, 7 wells in 2018 and 1 well in 2019.

The following table discloses the Company’s progress toward the conversion of PUDs during fiscal 2015.

Progress of Converting Proved Undeveloped Reserves :

   
Oil & Natural Gas
   
Future
 
   
(Mcfe)
   
Development Costs
 
PUDs, beginning of year
   
3,419,362
   
$
4,620,320
 
Revision of previous estimates
   
(943,113
)
   
(441,475
)
Conversions to PD reserves
   
(214,890
)
   
(643,429
)
Additional PUDs added
   
1,698,873
     
3,081,986
 
PUDs, end of year
   
3,960,232
   
$
6,617,402
 

Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using average prices for 2015, 2014 and 2013 along with estimates of the operating costs, production taxes and future development costs necessary to  produce such reserves. No deduction has been made for depreciation, depletion or any indirect costs such as general corporate overhead or interest expense.

Operating costs and production taxes are estimated based on current costs with respect to producing oil and natural gas properties. Future development costs including abandonment costs are based on the best estimate of such costs assuming current economic and operating conditions. The future cash flows estimated to be spent to develop the Company’s share of proved undeveloped properties through March 31, 2020 are $6,617,402.

Income tax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production and development costs over the current tax basis of the properties involved, less applicable carryforwards.

F-18

The future net revenue information assumes no escalation of costs or prices, except for oil and natural gas sales made under terms of contracts which include fixed and determinable escalation. Future costs and prices could significantly vary from current amounts and, accordingly, revisions in the future could be significant.

The current reporting rules require that year end reserve calculations and future cash inflows be based on the 12-month average market prices for sales of oil and gas on the first calendar day of each month during the fiscal year discounted at 10% per year and assuming continuation of existing economic conditions. The average prices used for fiscal 2015 were $74.84 per bbl of oil and $3.595 per mcf of natural gas. The average prices used for fiscal 2014 were $94.23 per bbl of oil and $3.67 per mcf of natural gas. The average prices used for fiscal 2013 were $85.53 per bbl of oil and $2.76 per mcf of natural gas.

The standardized measure of discounted future net cash flows were computed by applying 12-month average prices for oil and gas (with consideration of price changes only to the extent provided by contractual arrangements in existence at year end) to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on the year end statutory tax rates with consideration of future tax rates already legislated) to be incurred on pretax net cash flows less tax basis of the properties and available credits and assuming continuation of existing economic conditions. The estimated future net cash flows are then discounted using a rate of 10%.

The basis for this table is the reserve studies prepared by an independent petroleum engineering consultant, which contain imprecise estimates of quantities and rates of production of reserves. Revisions of previous year estimates can have a significant impact on these results. Also, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates of proved reserves and their valuation. Therefore, the standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of proved oil and gas properties.

The standardized measure of discounted future cash flows at March 31, 2015, 2014 and 2013, which represents the present value of estimated future cash flows using a discount rate of 10% a year, follows:

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves:

   
March 31
 
   
2015
   
2014
   
2013
 
Future cash inflows
 
$
72,238,000
   
$
70,252,000
   
$
52,900,000
 
Future production costs and taxes
   
(19,569,000
)
   
(20,647,000
)
   
(14,893,000
)
Future development costs
   
(6,617,000
)
   
(4,826,000
)
   
(4,850,000
)
Future income taxes
   
(9,254,000
)
   
(9,801,000
)
   
(6,374,000
)
Future net cash flows
   
36,798,000
     
34,978,000
     
26,783,000
 
Annual 10% discount for estimated timing of cash flows
   
(17,860,000
)
   
(15,649,000
)
   
(12,414,000
)
Standardized measure of discounted future net cash flows
 
$
18,938,000
   
$
19,329,000
   
$
14,369,000
 

F-19

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves:

   
March 31
 
   
2015
   
2014
   
2013
 
Sales of oil and gas produced, net of production costs
 
$
(2,036,000
)
 
$
(2,762,000
)
 
$
(1,982,000
)
Net changes in price and production costs
   
(4,066,000
)
   
2,464,000
     
(5,881,000
)
Changes in previously estimated development costs
   
2,627,000
     
270,000
     
1,150,000
 
Revisions of quantity estimates
   
(3,718,000
)
   
(657,000
)
   
(811,000
)
Net change due to purchases and sales of minerals in place
   
2,777,000
     
1,332,000
     
1,471,000
 
Extensions and discoveries, less related costs
   
4,607,000
     
3,802,000
     
321,000
 
Net change in income taxes
   
654,000
     
(1,997,000
)
   
2,178,000
 
Accretion of discount
   
2,474,000
     
1,779,000
     
2,495,000
 
Changes in timing of estimated cash flows and other
   
(3,710,000
)
   
729,000
     
(3,928,000
)
Changes in standardized measure
   
(391,000
)
   
4,960,000
     
(4,987,000
)
Standardized measure, beginning of year
   
19,329,000
     
14,369,000
     
19,356,000
 
Standardized measure, end of year
 
$
18,938,000
   
$
19,329,000
   
$
14,369,000
 

17. Selected Quarterly Financial Data (Unaudited)

   
FISCAL 2015
 
   
4 th QTR
   
3 rd QTR
   
2 nd QTR
   
1 st QTR
 
Oil and gas revenue
 
$
551,894
   
$
790,335
   
$
987,942
   
$
1,006,655
 
Operating (loss) profit
   
(412,332
)
   
(240,224
)
   
60,128
     
51,069
 
Net (loss) income
   
(270,975
)
   
(175,321
)
   
86,256
     
19,054
 
Net (loss) income per share – basic
   
(0.13
)
   
(0.09
)
   
0.04
     
0.01
 
Net (loss) income per share – diluted
   
(0.13
)
   
(0.09
)
   
0.04
     
0.01
 
 
   
FISCAL 2014
 
   
4 th QTR
   
3 rd QTR
   
2 nd QTR
   
1 st QTR
 
Oil and gas revenue
 
$
953,291
   
$
948,633
   
$
1,108,102
   
$
984,269
 
Operating profit
   
88,425
     
106,078
     
212,368
     
70,469
 
Net income
   
2,272
     
88,659
     
194,051
     
16,131
 
Net income per share – basic
   
0.00
     
0.04
     
0.10
     
0.01
 
Net income per share – diluted
   
0.00
     
0.04
     
0.10
     
0.01
 
F-20

INDEX TO EXHIBITS

Exhibit
Number

3.1
Restated Articles of Incorporation of Mexco Energy Corporation filed as Exhibit 3.1 to the Company’s Annual Report on Form 10-K dated June 24, 1998, and incorporated herein by reference.
   
3.2
Amended Bylaws of Mexco Energy Corporation as amended on September 13, 2011 filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K dated September 14, 2011, and incorporated herein by reference.
   
10.1
2009 Employee Incentive Stock Plan of Mexco Energy Corporation filed as Exhibit A to the Company’s Proxy Statement on Form 14C dated July 15, 2009, and incorporated herein by reference.
   
10.2
Loan Agreement between Bank of America, N.A. and Mexco Energy Corporation dated December 31, 2008
   
10.3
First Amendment to Loan Agreement dated December 28, 2009 to the Loan Agreement between Bank of America, N.A. and Mexco Energy Corporation dated December 31, 2008
   
10.4
Second Amendment to Loan Agreement dated March 1, 2010 to the Loan Agreement between Bank of America, N.A. and Mexco Energy Corporation dated December 31, 2008
   
10.5
Third Amendment to Loan Agreement dated September 30, 2010 to the Loan Agreement between Bank of America, N.A. and Mexco Energy Corporation dated December 31, 2008
   
10.6
Fourth Amendment to Loan Agreement dated October 22, 2010 to the Loan Agreement between Bank of America, N.A. and Mexco Energy Corporation dated December 31, 2008
   
10.7
Fifth Amendment to Loan Agreement dated December 28, 2011 to the Loan Agreement between Bank of America, N.A. and Mexco Energy Corporation dated December 31, 2008
   
10.8
Sixth Amendment to Loan Agreement dated October 22, 2012 to the Loan Agreement between Bank of America, N.A. and Mexco Energy Corporation dated December 31, 2008
   
10.9
Seventh Amendment to Loan Agreement dated October 25, 2013 to the Loan Agreement between Bank of America, N.A. and Mexco Energy Corporation dated December 31, 2008
   
10.10
Eighth Amendment to Loan Agreement dated September 10, 2014 to the Loan Agreement between Bank of America, N.A. and Mexco Energy Corporation dated December 31, 2008
   
10.11
Ninth Amendment to Loan Agreement dated February 13, 2015 to the Loan Agreement between Bank of America, N.A. and Mexco Energy Corporation dated December 31, 2008
 
F-21

14.1
Code of Business Conduct and Ethics of Mexco Energy Corporation filed with the Company’s Quarterly Report on Form 10-Q filed on November 15, 2004, and incorporated herein by reference.
   
21.1
Subsidiaries of Mexco Energy Corporation
   
23.1
Consent of Grant Thornton LLP, Independent Registered Public Accounting Firm
   
23.2
Consent of Joe C. Neal & Associates, Independent Petroleum Engineers
   
31.1
Certification of the Chief Executive Officer of the Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
   
31.2
Certification of the Chief Financial Officer of the Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
   
32.1
Certification of the Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
   
99.1
Report of Joe C. Neal & Associates, Independent Petroleum Engineer
___________________

 
F-22
 
EXHIBIT 10.2
 
LOAN AGREEMENT

This Agreement dated as of December 31, 2008, is between Bank of America, N.A. (the "Bank") and MEXCO ENERGY CORPORATION , a Colorado corporation ("Mexco") and FORMAN ENERGY CORPORATION , a New York corporation (“Forman,” and together with Mexco, “Borrowers” or individually, a “Borrower”).

1. FACILITY NO. 1: LINE OF CREDIT AMOUNT AND TERMS

1.1 Line of Credit Amount .

(a) During the availability period described below, the Bank will provide a line of credit to the Borrowers. The amount of the line of credit (the "Facility No. 1 Commitment") is the lesser of (i) FIVE MILLION AND NO/100 DOLLARS   ($5,000,000.00 ), or (ii) the Borrowing Base as determined by Bank from time to time in accordance with this Agreement.

(b) This is a revolving line of credit. Subject to the terms hereof, during the availability period, the Borrowers may repay principal amounts and reborrow them.

1.2 Availability Period .

The line of credit is available between the date of this Agreement and October 31, 2010, or such earlier date as the availability may terminate as provided in this Agreement (the "Facility No. 1 Expiration Date").

1.3 Borrowing Base .

The “Borrowing Base” is the amount of the loan value which Bank assigns, in the exercise of its sole discretion, to the collateral pledged by Borrowers to the Bank as security for Facility No. 1. The Borrowing Base is initially set at the amount of $4,900,000, but may be redetermined at least annually by Bank and at any time that it appears to the Bank, in its sole discretion, that there has been a material change in the value of the collateral securing Borrowers’ obligations to the Bank under this Agreement. In the event that the unpaid principal under this facility shall, at any time, be in excess of the Borrowing Base as a result of any Borrowing Base redetermination made by the Bank hereunder, Borrower shall, within fifteen (15) days thereafter (a) by instruments satisfactory in form and substance to the Bank, provide the Bank with additional collateral with value in an amount satisfactory to the Bank in order to increase the Borrowing Base by an amount at least equal to such excess, or (b) prepay the principal outstanding under this facility in an amount at least equal to such excess.

1.4 Repayment Terms .

(a) The Borrowers will pay interest on January 5, 2009, and then on the same day of each month thereafter until payment in full of any principal outstanding under this facility.

(b) The Borrowers will repay in full any principal, interest or other charges outstanding under this facility no later than the Facility No. 1 Expiration Date.

(c) The Borrowers may prepay the loan in full or in part at any time. The prepayment will be applied to the most remote payment of principal due under this Agreement.

1.5
Interest Rate .

(a) The interest rate is a rate per year equal to the lesser of (i) the BBA LIBOR Daily Floating Rate, plus 2.50 percentage points, or (ii) the maximum lawful rate of interest permitted under applicable usury laws, now or hereafter enacted (the "Maximum Rate").

 

(b) The BBA LIBOR Daily Floating Rate is a fluctuating rate of interest equal to the rate per annum equal to the British Bankers Association LIBOR Rate (“BBA LIBOR”), as published by Reuters (or other commercially available source providing quotations of BBA LIBOR as selected by the Bank from time to time) as determined for each banking day at approximately 11:00 a.m. London Time two (2) London Banking Days prior to the date in question, for U.S. Dollar deposits (for delivery on the first day of such interest period) with a one-month term, as adjusted from time to time in the Bank’s sole discretion for reserve requirements, deposit insurance assessment rates and regulatory costs. If such rate is not available at such time for any reason, then the rate for that interest period will be determined by such alternate method as reasonably selected by the Bank. A “London Banking Day” is a day on which banks in London are open for business and dealing in offshore dollars.

2. FEES AND EXPENSES

2.1 Unused Commitment Fee .

Borrowers shall pay to the Bank an unused commitment fee (the “Unused Commitment Fee”) in an amount equal to one half of one percent (.50%) times the daily average of the unadvanced amount of the Facility No. 1 Commitment. Such Unused Commitment Fee shall be calculated on the basis of a year consisting of 360 days. The Unused Commitment Fee shall be payable quarterly in arrears on the last day of each calendar quarter beginning March 31, 2009, with the first payment being for the period from the date of this Agreement through March 31, 2009, and with the final fee payment due on the Facility No. 1 Expiration Date for any period then ending for which the Unused Commitment Fee shall not have been theretofore paid. In the event the Facility No. 1 Expiration Date terminates on any date prior to the end of such quarterly period, Borrowers shall pay to the Bank on the date of such termination, the total Unused Commitment Fee due for the period in which such termination occurred.

2.2 Expenses .

The Borrowers agree to immediately repay the Bank for expenses that include, but are not limited to, filing, recording and search fees, appraisal fees, title report fees, and documentation fees.

2.3 Reimbursement Costs .

(a) The Borrowers agree to reimburse the Bank for any expenses it incurs in the preparation of this Agreement and any agreement or instrument required by this Agreement. Expenses include, but are not limited to, reasonable attorneys' fees, including any allocated costs of the Bank's in-house counsel to the extent permitted by applicable law.

(b) The Borrowers agree to reimburse the Bank for the cost of periodic field examinations of the Borrowers’ books, records and collateral, and appraisals of the collateral, at such intervals as the Bank may reasonably require. The actions described in this paragraph may be performed by employees of the Bank or by independent appraisers.

2.4 No Excess Fees .

Notwithstanding anything to the contrary in this Section 2, in no event shall any sum payable under this Section 2 (to the extent, if any, constituting interest under applicable laws), together with all other amounts constituting interest under applicable laws and payable in connection with the credit evidenced hereby, exceed the amount of interest computed at the Maximum Rate.

2

3. COLLATERAL

3.1 Real and Personal Property .

The Borrowers’ obligations to the Bank under this Agreement will be secured by liens covering Mexco’s interest in the oil and gas real and personal property collateral described in the Deed of Trust executed by Mexco and by liens covering Mexco’s interest in all of the issued and outstanding capital stock of Forman.
 
4. DISBURSEMENTS, PAYMENTS AND COSTS

4.1 Disbursements and Payments .

(a) Each payment by the Borrowers will be made in U.S. Dollars and immediately available funds by debit to a deposit account, as described in this Agreement or otherwise authorized by the Borrowers. For payments not made by direct debit, payments will be made by mail to the address shown on the Borrowers’ statement or at one of the Bank’s banking centers in the United States, or by such other method as may be permitted by the Bank.

(b) The Bank may honor instructions for advances or repayments given by the Borrowers (if an individual), or by any one of the individuals authorized to sign loan agreements on behalf of the Borrowers, or any other individual designated by any one of such authorized signers (each an “Authorized Individual”).

(c) For any payment under this Agreement made by debit to a deposit account, the Borrowers will maintain sufficient immediately available funds in the deposit account to cover each debit. If there are insufficient immediately available funds in the deposit account on the date the Bank enters any such debit authorized by this Agreement, the Bank may reverse the debit.

(d) Each disbursement by the Bank and each payment by the Borrowers will be evidenced by records kept by the Bank. In addition, the Bank may, at its discretion, require the Borrowers to sign one or more promissory notes.

(e) Prior to the date each payment of principal and interest and any fees from the Borrowers becomes due (the "Due Date"), the Bank will mail to the Borrowers a statement of the amounts that will be due on that Due Date (the "Billed Amount"). The calculations in the bill will be made on the assumption that no new extensions of credit or payments will be made between the date of the billing statement and the Due Date, and that there will be no changes in the applicable interest rate. If the Billed Amount differs from the actual amount due on the Due Date (the "Accrued Amount"), the discrepancy will be treated as follows:

(i) If the Billed Amount is less than the Accrued Amount, the Billed Amount for the following Due Date will be increased by the amount of the discrepancy. The Borrowers will not be in default by reason of any such discrepancy.

(ii) If the Billed Amount is more than the Accrued Amount, the Billed Amount for the following Due Date will be decreased by the amount of the discrepancy.

Regardless of any such discrepancy, interest will continue to accrue based on the actual amount of principal outstanding without compounding. The Bank will not pay the Borrowers’ interest on any overpayment.

3

4.2 Telephone and Telefax Authorization .

(a) The Bank may honor telephone or telefax instructions for advances or repayments given, or purported to be given, by any one of the Authorized Individuals.

(b) The Borrowers will indemnify and hold the Bank harmless from all liability, loss, and costs in connection with any act resulting from telephone or telefax instructions the Bank reasonably believes are made by any Authorized Individual. This paragraph will survive this Agreement's termination, and will benefit the Bank and its officers, employees, and agents.

4.3 Direct Debit .

The Borrowers agree that on the Due Date the Bank will debit the Billed Amount from deposit account number 0035xxxxxxxx owned by the Borrowers, or such other of the Borrowers’ accounts with the Bank as designated in writing by the Borrowers (the "Designated Account"). The Borrowers may terminate this Direct Debit arrangement at any time by sending written notice to the Bank at the address specified at the end of this Agreement.

4.4 Banking Days .

Unless otherwise provided in this Agreement, a banking day is a day other than a Saturday, Sunday or other day on which commercial banks are authorized to close, or are in fact closed, in the state where the Bank's lending office is located, and, if such day relates to amounts bearing interest at an offshore rate (if any), means any such day on which dealings in dollar deposits are conducted among banks in the offshore dollar interbank market. All payments and disbursements which would be due on a day which is not a banking day will be due on the next banking day. All payments received on a day which is not a banking day will be applied to the credit on the next banking day.

4.5 Interest Calculation .

Except as otherwise stated in this Agreement, all interest and fees, if any, will be computed on the basis of a 360-day year and the actual number of days elapsed. This results in more interest or a higher fee than if a 365-day year is used. Installments of principal which are not paid when due under this Agreement shall continue to bear interest until paid.

4.6 Default Rate .

Upon the occurrence of any default or after maturity or after judgment has been rendered on any obligation under this Agreement, all amounts outstanding under this Agreement, including any interest, fees, or costs which are not paid when due, will at the option of the Bank bear interest at a rate which is the lesser of (i) the Maximum Rate, or (ii) 4.0 percentage point(s) higher than the rate of interest otherwise provided under this Agreement. This may result in compounding of interest. This will not constitute a waiver of any default.

5. CONDITIONS

Before the Bank is required to extend any credit to the Borrowers under this Agreement, it must receive any documents and other items it may reasonably require, in form and content acceptable to the Bank, including any items specifically listed below.

4

5.1 Authorizations .

If the Borrowers or any guarantor is anything other than a natural person, evidence that the execution, delivery and performance by the Borrowers and/or such guarantor of this Agreement and any instrument or agreement required under this Agreement have been duly authorized.

5.2 Governing Documents .

If required by the Bank, a copy of the Borrowers' organizational documents.

5.3 Security Agreements .

Signed original security agreements covering the personal property collateral which the Bank requires.

5.4 Perfection and Evidence of Priority .

Evidence that the security interests and liens in favor of the Bank are valid, enforceable, properly perfected in a manner acceptable to the Bank and prior to all others' rights and interests, except those the Bank consents to in writing. All title documents for motor vehicles which are part of the collateral must show the Bank's interest.

5.5 Payment of Fees .

Payment of all fees and other amounts due and owing to the Bank, including without limitation payment of all accrued and unpaid expenses incurred by the Bank as required by the paragraph entitled "Reimbursement Costs."

5.6 Good Standing .

Certificates of good standing for the Borrowers from their states of formation and from any other state in which the Borrowers are required to qualify to conduct their business.

5.7 Insurance .

Evidence of insurance coverage, as required in the "Covenants" section of this Agreement.

5.8 Deed of Trust .

Signed and acknowledged original deed of trust, as required by the Bank, encumbering the real property collateral.

6. REPRESENTATIONS AND WARRANTIES

When the Borrowers sign this Agreement, and until the Bank is repaid in full, the Borrowers jointly and severally make the following representations and warranties. Each request for an extension of credit constitutes a renewal of these representations and warranties as of the date of the request:

6.1 Formation .

If a Borrower is anything other than a natural person, it is duly formed and existing under the laws of the state or other jurisdiction where organized.

5

6.2 Authorization .

This Agreement, and any instrument or agreement required hereunder, are within each Borrower's powers, have been duly authorized, and do not conflict with any of its organizational papers.

6.3 Enforceable Agreement .

This Agreement is a legal, valid and binding agreement of the Borrowers, enforceable against the Borrowers in accordance with its terms, and any instrument or agreement required hereunder, when executed and delivered, will be similarly legal, valid, binding and enforceable.

6.4 Good Standing .

In each state in which the Borrowers do business, each is properly licensed, in good standing, and, where required, in compliance with fictitious name statutes.

6.5 No Conflicts .

This Agreement does not conflict with any law, agreement, or obligation by which either Borrower is bound.

6.6 Financial Information .

All financial and other information that has been or will be supplied to the Bank is sufficiently complete to give the Bank accurate knowledge of the Borrowers' (and any guarantor's) financial condition, including all material contingent liabilities. Since the date of the most recent financial statement provided to the Bank, there has been no material adverse change in the business condition (financial or otherwise), operations, properties or prospects of either Borrower (or any guarantor).

6.7 Lawsuits .

There is no lawsuit, tax claim or other dispute pending or threatened against either Borrower which, if lost, would impair either Borrower's financial condition or ability to repay the loan, except as have been disclosed in writing to the Bank.

6.8 Collateral .

All collateral required in this Agreement is owned by the grantor of the security interest free of any title defects or any liens or interests of others, except those which have been approved by the Bank in writing.

6.9 Permits, Franchises .

The Borrowers possess all permits, memberships, franchises, contracts and licenses required and all trademark rights, trade name rights, patent rights, copyrights, and fictitious name rights necessary to enable them to conduct the businesses in which each is now engaged.

6.10 Other Obligations .

The Borrowers are not in default on any obligation for borrowed money, any purchase money obligation or any other material lease, commitment, contract, instrument or obligation, except as have been disclosed in writing to the Bank.

6

6.11 Tax Matters .

The Borrowers have no knowledge of any pending assessments or adjustments of their income tax for any year and all taxes due have been paid, except as have been disclosed in writing to the Bank.

6.12 No Event of Default .

There is no event which is, or with notice or lapse of time or both would be, a default under this Agreement.

6.13 Insurance .

The Borrowers have obtained, and maintained in effect, the insurance coverage required in the "Covenants" section of this Agreement.

6.14 Location of Borrowers .

The place of business of the Borrowers (or, if the Borrowers have more than one place of business, their chief executive office) is located at the address listed on the signature page of this Agreement.

7. COVENANTS

The Borrowers jointly and severally agree, so long as credit is available under this Agreement and until the Bank is repaid in full:

7.1 Use of Proceeds .

To use the proceeds of Facility No. 1 only for the working capital needs of Borrowers.

7.2 Financial Information .

To provide the following financial information and statements in form and content acceptable to the Bank, and such additional information as requested by the Bank from time to time. The Bank reserves the right, upon written notice to the Borrowers, to require the Borrowers to deliver financial information and statements to the Bank more frequently than otherwise provided below, and to use such additional information and statements to measure any applicable financial covenants in this Agreement.

(a) Within one hundred (100) days of each fiscal year end of Mexco,   the annual audited financial statements of Mexco. These financial statements must be audited (with an opinion satisfactory to the Bank) by a certified public accountant acceptable to the Bank. The statements shall be prepared on a consolidated basis.

(b) Within forty-five (45) days of the period's end (excluding the last period in each fiscal year), quarterly financial statements of Mexco, certified and dated by an authorized financial officer. These financial statements may be company-prepared. The statements shall be prepared on a consolidated basis.

(c) Promptly, upon sending or receipt, copies of any management letters and correspondence relating to management letters, sent or received by Mexco to or from Mexco’s auditor. If no management letter is prepared, the Bank may, in its discretion, request a letter from such auditor stating that no deficiencies were noted that would otherwise be addressed in a management letter.

7

(d) On or before June 1 of each calendar year an engineering report covering all of Borrowers’ material oil and gas properties dated effective as of March 31st of each such year, and at such other times as the Bank may request, an engineering report covering all of Borrowers’ material oil and gas properties dated effective not more than sixty (60) days prior to the delivery of the same to the Bank. Each such engineering report shall be prepared by an independent petroleum engineering firm acceptable to the Bank, utilizing economic pricing parameters used by the Bank as established from time to time, together with such other information, reports and data concerning the value of said oil and gas properties as the Bank shall deem necessary.

(e) Copies of the Form 10-K Annual Report, Form 10-Q Quarterly Report and Form 8-K Current Report for Mexco within thirty (30) days after the date of filing with the Securities and Exchange Commission.

(f) Within 100 days of the end of each fiscal year,   a compliance certificate of the Borrowers, signed by an authorized financial officer and setting forth (i) the information and computations (in sufficient detail) to establish compliance with all financial covenants at the end of the period covered by the financial statements then being furnished and (ii) whether there existed as of the date of such financial statements and whether there exists as of the date of the certificate, any default under this Agreement and, if any such default exists, specifying the nature thereof and the action the Borrowers are taking and propose to take with respect thereto.

(g) Within 45 days of the end of each fiscal quarter, a compliance certificate of the Borrowers, signed by an authorized financial officer and setting forth (i) the information and computations (in sufficient detail) to establish compliance with all financial covenants at the end of the period covered by the financial statements then being furnished and (ii) whether there existed as of the date of such financial statements and whether there exists as of the date of the certificate, any default under this Agreement and, if any such default exists, specifying the nature thereof and the action the Borrowers are taking and propose to take with respect thereto.

(h) Promptly upon the Bank's request, such other books, records, statements, lists of property and accounts, budgets, forecasts or reports as to the Borrowers and as to each guarantor of the Borrowers' obligations to the Bank as the Bank may request.

7.3
Tangible Net Worth .

To maintain on a consolidated basis, Tangible Net Worth equal to at least the sum of the following:

(a) Six Million Two Hundred Fifty-Seven Thousand Dollars ($6,257,000); plus

(b) The sum of 50% of net income after income taxes (without subtracting losses) earned in each quarterly accounting period commencing after June 30, 2008; plus

(c)
The net proceeds for from any equity securities issues after the date of this Agreement.

As used herein, “Tangible Net Worth” means the value of total assets (including leaseholds and leasehold improvements and reserves against assets but excluding goodwill, patents, trademarks, trade names, organization expense, unamortized debt discount and expense, capitalized or deferred research and development costs, deferred marketing expenses and other like intangibles, and monies due from affiliates, officers, directors, employees, shareholders, members or managers) less total liabilities, including but not limited to accrued and deferred income taxes, but excluding the non-current portion of Subordinated Liabilities. “Subordinated Liabilities” means liabilities subordinated to the Borrowers’ obligations to the Bank in a manner acceptable to the Bank in its sole discretion.

8

7.4 Dividends and Distributions .

Not to declare or pay any dividends (except dividends paid in capital stock), redemptions of stock, distributions and withdrawals (as applicable) to its owners.

7.5 Other Debts .

Not to have outstanding or incur any direct or contingent liabilities or lease obligations (other than those to the Bank), or become liable for the liabilities of others, without the Bank's written consent. This does not prohibit:

(a) Acquiring goods, supplies, or merchandise on normal trade credit.

(b) Endorsing negotiable instruments received in the usual course of business.

(c) Obtaining surety bonds in the usual course of business.

(d) Liabilities, lines of credit and leases in existence on the date of this Agreement disclosed in writing to the Bank in the Borrowers' most recent financial statement.

7.6 Other Liens .

Not to create, assume, or allow any security interest or lien (including judicial liens) on property the Borrowers now or later own, except:

(a) Liens and security interests in favor of the Bank.

(b) Liens for taxes not yet due.

(c) Liens outstanding on the date of this Agreement disclosed in writing to the Bank.

7.7 Investments .

Not to have any existing, or make any new, investments in any individual or entity, or make any capital contributions or other transfers of assets to any individual or entity, except for:

(a) Existing investments disclosed to the Bank in writing.

(b) Investments in the Borrowers’ current subsidiaries.

7.8 Loans .

Not to make any loans, advances or other extensions of credit to any individual or entity, except for:

(a) Existing extensions of credit disclosed to the Bank in writing.

(b) Extensions of credit in the nature of accounts receivable or notes receivable arising from the sale or lease of goods or services in the ordinary course of business to non-affiliated entities.

7.9 Loans to Officers or Affiliates .

Not to make any loans, advances or other extensions of credit (including extensions of credit in the nature of accounts receivable or notes receivable arising from the sale or lease of goods or services) to any of the Borrowers' executives, officers, directors or shareholders (or any relatives of any of the foregoing), or to any affiliated entities.

9

7.10 Change of Management .

Not to make any substantial change in the present executive or management personnel of the Borrowers.

7.11 Additional Negative Covenants .

Not to, without the Bank's written consent:

(a) Enter into any consolidation, merger, or other combination, or become a partner in a partnership, a member of a joint venture, or a member of a limited liability company.

(b) Acquire or purchase a business or its assets.

(c)
Engage in any business activities substantially different from the Borrowers' present businesses.

(d) Liquidate or dissolve either of the Borrower’s businesses.

(e) Sell, lease, assign or otherwise dispose of or transfer any assets, except in the normal course of business.

7.12
Notices to Bank.

To promptly notify the Bank in writing of:

(a) Any lawsuit against a Borrower or any Obligor.

(b) Any substantial dispute between any governmental authority and a Borrower or any Obligor.

(c) Any event of default under this Agreement, or any event which, with notice or lapse of time or both, would constitute an event of default.

(d) Any material adverse change in a Borrower's or any Obligor’s business condition (financial or otherwise), operations, properties or prospects, or ability to repay the credit.

(e) Any change in a Borrower's or any Obligor’s name, legal structure, principal residence (for an individual), state of registration (for a registered entity), place of business, or chief executive office if a Borrower or any Obligor has more than one place of business.

(f) Any actual contingent liabilities of a Borrower or any Obligor, and any such contingent liabilities which are reasonably foreseeable.

For purposes of this Agreement, “Obligor” shall mean any guarantor, any party pledging collateral to the Bank, or, if the Borrowers are comprised of the trustees of a trust, any trustor.

7.13 Insurance .

 (a) General Business Insurance . To maintain insurance satisfactory to the Bank as to amount, nature and carrier covering property damage (including loss of use and occupancy) to any of the Borrowers' properties, business interruption insurance, public liability insurance including coverage for contractual liability, product liability and workers' compensation, and any other insurance which is usual for the Borrowers' businesses. Each policy shall provide for at least thirty (30) days prior notice to the Bank of any cancellation thereof.

10

(b) Insurance Covering Collateral . To maintain all risk property damage insurance policies (including without limitation windstorm coverage, and hurricane coverage as applicable) covering the tangible property comprising the collateral. Each insurance policy must be in an amount acceptable to the Bank. The insurance must be issued by an insurance company acceptable to the Bank and must include a lender's loss payable endorsement in favor of the Bank in a form acceptable to the Bank.

(c) Evidence of Insurance . Upon the request of the Bank, to deliver to the Bank a copy of each insurance policy, or, if permitted by the Bank, a certificate of insurance listing all insurance in force.

7.14 Compliance with Laws.

To comply with the laws (including any fictitious or trade name statute), regulations, and orders of any government body with authority over the Borrowers' businesses. The Bank shall have no obligation to make any advance to the Borrowers except in compliance with all applicable laws and regulations and the Borrowers shall fully cooperate with the Bank in complying with all such applicable laws and regulations.

7.15 ERISA Plans .

Promptly during each year, to pay and cause any subsidiaries to pay contributions adequate to meet at least the minimum funding standards under ERISA with respect to each and every Plan; file each annual report required to be filed pursuant to ERISA in connection with each Plan for each year; and notify the Bank within ten (10) days of the occurrence of any Reportable Event that might constitute grounds for termination of any capital Plan by the Pension Benefit Guaranty Corporation or for the appointment by the appropriate United States District Court of a trustee to administer any Plan. "ERISA" means the Employee Retirement Income Security Act of 1974, as amended from time to time. Capitalized terms in this paragraph shall have the meanings defined within ERISA.

7.16 Books and Records .

To maintain adequate books and records.

7.17 Audits .

To allow the Bank and its agents to inspect the Borrowers' properties and examine, audit, and make copies of books and records at any reasonable time. If any of the Borrowers' properties, books or records are in the possession of a third party, the Borrowers authorize that third party to permit the Bank or its agents to have access to perform inspections or audits and to respond to the Bank's requests for information concerning such properties, books and records.

7.18 Perfection of Liens .

To help the Bank perfect and protect its security interests and liens, and reimburse it for related costs it incurs to protect its security interests and liens.

7.19
Bank as Principal Depository .

To maintain the Bank as its principal depository bank, including for the maintenance of business, cash management, operating and administrative deposit accounts.

7.20 Cooperation .

To take any action reasonably requested by the Bank to carry out the intent of this Agreement.

11

8. HAZARDOUS SUBSTANCES - REAL PROPERTY SECURITY

8.1 Indemnity Regarding Hazardous Substances .

The Borrowers agree to indemnify and hold the Bank harmless from and against all liabilities, claims, actions, foreseeable and unforeseeable consequential damages, costs and expenses (including sums paid in settlement of claims and all consultant, expert and legal fees and expenses of the Bank's counsel) or loss directly or indirectly arising out of or resulting from any of the following:

(a) Any hazardous substance being present at any time, whether before, during or after any construction, in or around any part of the real property collateral securing this Agreement (the "Real Property"), or in the soil, groundwater or soil vapor on or under the Real Property, including those incurred in connection with any investigation of site conditions or any clean-up, remedial, removal or restoration work, or any resulting damages or injuries to the person or property of any third parties or to any natural resources.

(b) Any use, generation, manufacture, production, storage, release, threatened release, discharge, disposal or presence of a hazardous substance. This indemnity will apply whether the hazardous substance is on, under or about any of the Borrowers' property or operations or property leased to the Borrowers, whether or not the property has been taken by the Bank as collateral.

Upon demand by the Bank, the Borrowers will defend any investigation, action or proceeding alleging the presence of any hazardous substance in any such location, which affects the Real Property or which is brought or commenced against the Bank, whether alone or together with the Borrowers or any other person, all at the Borrowers' own cost and by counsel to be approved by the Bank in the exercise of its reasonable judgment. In the alternative, the Bank may elect to conduct its own defense at the expense of the Borrowers. The Borrowers' obligations to the Bank under this Article, except the obligation to give notices to the Bank, shall survive termination of this Agreement, repayment of the Borrowers' obligations to the Bank under this Agreement, and foreclosure of the deed of trust or mortgage encumbering the Real Property or similar proceedings.

8.2 Representation and Warranty Regarding Hazardous Substances .

Before signing this Agreement, the Borrowers researched and inquired into the previous uses and ownership of the Real Property. Based on that due diligence, the Borrowers represent and warrant that to the best of their knowledge, no hazardous substance has been disposed of or released or otherwise exists in, on, under or onto the Real Property in violation of applicable Environmental Laws, except as the Borrower has disclosed to the Bank in writing.

8.3 Compliance Regarding Hazardous Substances .

The Borrowers have complied, and will comply and cause all occupants of the Real Property to comply, with all current and future laws, regulations and ordinances or other requirements of any governmental authority relating to or imposing liability or standards of conduct concerning protection of health or the environment or hazardous substances (“Environmental Laws”). The Borrowers shall promptly, at the Borrowers’ sole cost and expense, take all reasonable actions with respect to any hazardous substances or other environmental condition at, on, or under the Real Property necessary to (i) comply with all applicable Environmental Laws; (ii) allow continued use, occupation or operation of the Real Property; or (iii) maintain the fair market value of the Real Property. The Borrowers acknowledge that hazardous substances may permanently and materially impair the value and use of the Real Property.

12

8.4 Notices Regarding Hazardous Substances .

Until full repayment of the loan, the Borrowers will promptly notify the Bank in writing if it knows, suspects or believes there may be any hazardous substance in or around the Real Property, or in the soil, groundwater or soil vapor on or under the Real Property in violation of applicable Environmental Laws, or that the Borrower or the Real Property may be subject to any threatened or pending investigation by any governmental agency under any current or future law, regulation or ordinance pertaining to any hazardous substance.

8.5 Site Visits, Observations and Testing .

The Bank and its agents and representatives will have the right at any reasonable time, after giving reasonable notice to the Borrowers, to enter and visit the Real Property and any other locations where any personal property collateral securing this Agreement is located, for the purposes of observing the Real Property and the personal property collateral, taking and removing environmental samples, and conducting tests on any part of the Real Property. The Borrowers shall reimburse the Bank on demand for the costs of any such environmental investigation and testing. The Bank will make reasonable efforts during any site visit, observation or testing conducted pursuant this paragraph to avoid interfering with the Borrowers’ use of the Real Property and the personal property collateral. The Bank is under no duty, however, to visit or observe the Real Property or the personal property collateral or to conduct tests, and any such acts by the Bank will be solely for the purposes of protecting the Bank's security and preserving the Bank's rights under this Agreement. No site visit, observation or testing or any report or findings made as a result thereof (“Environmental Report”) (i) will result in a waiver of any default of the Borrowers; (ii) impose any liability on the Bank; or (iii) be a representation or warranty of any kind regarding the Real Property or the personal property collateral (including its condition or value or compliance with any laws) or the Environmental Report (including its accuracy or completeness). In the event the Bank has a duty or obligation under applicable laws, regulations or other requirements to disclose an Environmental Report to the Borrowers or any other party, the Borrowers authorize the Bank to make such a disclosure. The Bank may also disclose an Environmental Report to any regulatory authority, and to any other parties as necessary or appropriate in the Bank’s judgment. The Borrowers further understand and agree that any Environmental Report or other information regarding a site visit, observation or testing that is disclosed to the Borrowers by the Bank or its agents and representatives is to be evaluated (including any reporting or other disclosure obligations of the Borrowers) by the Borrowers without advice or assistance from the Bank.

8.6 Definition of Hazardous Substance .

"Hazardous substance" means any substance, material or waste that is or becomes designated or regulated as "toxic," "hazardous," "pollutant," or "contaminant" or a similar designation or regulation under any current or future federal, state or local law (whether under common law, statute, regulation or otherwise) or judicial or administrative interpretation of such, including without limitation petroleum or natural gas.

9. DEFAULT AND REMEDIES

If any of the following events of default occurs, the Bank may do one or more of the following: declare the Borrowers in default, stop making any additional credit available to the Borrowers, and require the Borrowers to repay their entire debt immediately and without prior notice. If an event which, with notice or the passage of time, will constitute an event of default has occurred and is continuing, the Bank has no obligation to make advances or extend additional credit under this Agreement. In addition, if any event of default occurs, the Bank shall have all rights, powers and remedies available under any instruments and agreements required by or executed in connection with this Agreement, as well as all rights and remedies available at law or in equity. If an event of default occurs under the paragraph entitled "Bankruptcy," below, with respect to the Borrowers, then the entire debt outstanding under this Agreement will automatically be due immediately.

13

9.1 Failure to Pay .

The Borrowers fail to make a payment under this Agreement when due.

9.2 Other Bank Agreements .

Any default occurs under any other agreement a Borrower (or any Obligor) or any of the Borrowers' related entities or affiliates has with the Bank or any affiliate of the Bank.

9.3 Cross-default .

Any default occurs under any agreement in connection with any credit a Borrower (or any Obligor) or any of the Borrowers' related entities or affiliates has obtained from anyone else or which a Borrower (or any Obligor) or any of the Borrowers' related entities or affiliates has guaranteed.

9.4 False Information .

A Borrower or any Obligor has given the Bank materially false or misleading information or representations.

9.5 Bankruptcy .

A Borrower, any Obligor, or any general partner of a Borrower or of any Obligor files a bankruptcy petition, a bankruptcy petition is filed against any of the foregoing parties, or a Borrower, any Obligor, or any general partner of a Borrower or of any Obligor makes a general assignment for the benefit of creditors.

9.6 Receivers .

A receiver or similar official is appointed for a substantial portion of a Borrower's or any Obligor's business, or the business is terminated, or, if any Obligor is anything other than a natural person, such Obligor is liquidated or dissolved.

9.7 Lien Priority .

The Bank fails to have an enforceable first lien (except for any prior liens to which the Bank has consented in writing) on or security interest in any property given as security for this Agreement (or any guaranty).

9.8 Judgments .

Any judgments or arbitration awards are entered against a Borrower or any Obligor, or a Borrower or any Obligor enters into any settlement agreements with respect to any litigation or arbitration.

9.9 Death .

If a Borrower or any Obligor is a natural person, a Borrower or such Obligor dies or becomes legally incompetent; if a Borrower or any Obligor is a trust, a trustor dies or becomes legally incompetent; if a Borrower or any Obligor is a partnership, any general partner dies or becomes legally incompetent.

14

9.10 Material Adverse Change .

A material adverse change occurs, or is reasonably likely to occur, in a Borrower's (or any Obligor's) business condition (financial or otherwise), operations, properties or prospects, or ability to repay the credit; or the Bank determines that it is insecure for any other reason.

9.11 Government Action .

Any government authority takes action that the Bank believes materially adversely affects a Borrower's or any Obligor's financial condition or ability to repay.

9.12 Default under Related Documents .

Any default occurs under any guaranty, subordination agreement, security agreement, deed of trust, mortgage, or other document required by or delivered in connection with this Agreement or any such document is no longer in effect, or any guarantor purports to revoke or disavow the guaranty.

9.13 ERISA Plans .

Any one or more of the following events occurs with respect to a Plan of a Borrower subject to Title IV of ERISA, provided such event or events could reasonably be expected, in the judgment of the Bank, to subject a Borrower to any tax, penalty or liability (or any combination of the foregoing) which, in the aggregate, could have a material adverse effect on the financial condition of a Borrower:

(a) A reportable event shall occur under Section 4043(c) of ERISA with respect to a Plan.

(b) Any Plan termination (or commencement of proceedings to terminate a Plan) or the full or partial withdrawal from a Plan by a Borrower or any ERISA Affiliate.

9.14 Other Breach Under Agreement .

A default occurs under any other term or condition of this Agreement not specifically referred to in this Article. This includes any failure or anticipated failure by a Borrower (or any other party named in the Covenants section) to comply with any financial covenants set forth in this Agreement, whether such failure is evidenced by financial statements delivered to the Bank or is otherwise known to a Borrower or the Bank.

10.
ENFORCING THIS AGREEMENT; MISCELLANEOUS

10.1
GAAP.

Except as otherwise stated in this Agreement, all financial information provided to the Bank and all financial covenants will be made under generally accepted accounting principles, consistently applied.

10.2 Governing Law .

This Agreement shall be governed and construed in accordance with the laws of Texas. To the extent that the Bank has greater rights or remedies under federal law, whether as a national bank or otherwise, this paragraph shall not be deemed to deprive the Bank of such rights and remedies as may be available under federal law. It is the intention of the parties to comply with applicable usury laws. The parties agree that the total amount of interest contracted for, charged, collected or received by the Bank under this Agreement shall not exceed the Maximum Rate. To the extent, if any, that Chapter 303 of the Texas Finance Code (the "Code") is relevant to the Bank for purposes of determining the Maximum Rate, the parties elect to determine the Maximum Rate under the Code pursuant to the “weekly ceiling” from time to time in effect, as referred to and defined in § 303.001-303.016 of the Code; subject, however, to any right the Bank subsequently may have under applicable law to change the method of determining the Maximum Rate. Notwithstanding any contrary provisions contained herein, (a) the Maximum Rate shall be calculated on the basis of the actual number of days elapsed over a year of 365 or 366 days, as the case may be; (b) in determining whether the interest hereunder exceeds interest at the Maximum Rate, the total amount of interest shall be spread throughout the entire term of this Agreement until its payment in full; (c) if at any time the interest rate chargeable under this Agreement would exceed the Maximum Rate, thereby causing the interest payable under this Agreement to be limited to the Maximum Rate, then any subsequent reductions in the interest rate(s) shall not reduce the rate of interest charged under this Agreement below the Maximum Rate until the total amount of interest accrued from and after the date of this Agreement equals the amount of interest which would have accrued if the interest rate(s) had at all times been in effect; (d) if the Bank ever charges or receives anything of value which is deemed to be interest under applicable Texas law, and if the occurrence of any event, including acceleration of maturity of obligations owing to the Bank, should cause such interest to exceed the maximum lawful amount, any amount which exceeds interest at the Maximum Rate shall be applied to the reduction of the unpaid principal balance under this Agreement or any other indebtedness owed to the Bank by the Borrowers, and if this Agreement and such other indebtedness are paid in full, any remaining excess shall be paid to the Borrowers; and (e) Chapter 346 of the Code shall not be applicable to this Agreement or the indebtedness outstanding hereunder.

15

10.3 Successors and Assigns .

This Agreement is binding on the Borrowers' and the Bank's successors and assignees. Each Borrower agrees that it may not assign this Agreement without the Bank's prior consent. The Bank may sell participations in or assign this loan, and may exchange information about the Borrowers (including, without limitation, any information regarding any hazardous substances) with actual or potential participants or assignees. If a participation is sold or the loan is assigned, the purchaser will have the right of set-off against the Borrowers.

10.4 Dispute Resolution Provision .

This paragraph, including the subparagraphs below, is referred to as the “Dispute Resolution Provision.” This Dispute Resolution Provision is a material inducement for the parties entering into this agreement.

(a) This Dispute Resolution Provision concerns the resolution of any controversies or claims between the parties, whether arising in contract, tort or by statute, including but not limited to controversies or claims that arise out of or relate to: (i) this agreement (including any renewals, extensions or modifications); or (ii) any document related to this agreement (collectively a "Claim"). For the purposes of this Dispute Resolution Provision only, the term “parties” shall include any parent corporation, subsidiary or affiliate of the Bank involved in the servicing, management or administration of any obligation described or evidenced by this agreement.

(b) At the request of any party to this agreement, any Claim shall be resolved by binding arbitration in accordance with the Federal Arbitration Act (Title 9, U.S. Code) (the "Act"). The Act will apply even though this agreement provides that it is governed by the law of a specified state.

(c) Arbitration proceedings will be determined in accordance with the Act, the then-current rules and procedures for the arbitration of financial services disputes of the American Arbitration Association or any successor thereof ("AAA"), and the terms of this Dispute Resolution Provision. In the event of any inconsistency, the terms of this Dispute Resolution Provision shall control. If AAA is unwilling or unable to (i) serve as the provider of arbitration or (ii) enforce any provision of this arbitration clause, the Bank may designate another arbitration organization with similar procedures to serve as the provider of arbitration.

16

(d) The arbitration shall be administered by AAA and conducted, unless otherwise required by law, in any U.S. state where real or tangible personal property collateral for this credit is located or if there is no such collateral, in the state specified in the governing law section of this agreement. All Claims shall be determined by one arbitrator; however, if Claims exceed Five Million Dollars ($5,000,000), upon the request of any party, the Claims shall be decided by three arbitrators. All arbitration hearings shall commence within ninety (90) days of the demand for arbitration and close within ninety (90) days of commencement and the award of the arbitrator(s) shall be issued within thirty (30) days of the close of the hearing. However, the arbitrator(s), upon a showing of good cause, may extend the commencement of the hearing for up to an additional sixty (60) days. The arbitrator(s) shall provide a concise written statement of reasons for the award. The arbitration award may be submitted to any court having jurisdiction to be confirmed and have judgment entered and enforced.

(e) The arbitrator(s) will give effect to statutes of limitation in determining any Claim and may dismiss the arbitration on the basis that the Claim is barred. For purposes of the application of any statutes of limitation, the service on AAA under applicable AAA rules of a notice of Claim is the equivalent of the filing of a lawsuit. Any dispute concerning this arbitration provision or whether a Claim is arbitratable shall be determined by the arbitrator(s), except as set forth at subparagraph (h) of this Dispute Resolution Provision. The arbitrator(s) shall have the power to award legal fees pursuant to the terms of this agreement.

(f) This paragraph does not limit the right of any party to: (i) exercise self-help remedies, such as but not limited to, setoff; (ii) initiate judicial or non-judicial foreclosure against any real or personal property collateral; (iii) exercise any judicial or power of sale rights, or (iv) act in a court of law to obtain an interim remedy, such as but not limited to, injunctive relief, writ of possession or appointment of a receiver, or additional or supplementary remedies.

(g) The filing of a court action is not intended to constitute a waiver of the right of any party, including the suing party, thereafter to require submittal of the Claim to arbitration.

(h) Any arbitration or trial by a judge of any Claim will take place on an individual basis without resort to any form of class or representative action (the “Class Action Waiver”). Regardless of anything else in this Dispute Resolution Provision, the validity and effect of the Class Action Waiver may be determined only by a court and not by an arbitrator. The parties to this Agreement acknowledge that the Class Action Waiver is material and essential to the arbitration of any disputes between the parties and is nonseverable from the agreement to arbitrate Claims. If the Class Action Waiver is limited, voided or found unenforceable, then the parties’ agreement to arbitrate shall be null and void with respect to such proceeding, subject to the right to appeal the limitation or invalidation of the Class Action Waiver. The Parties acknowledge and agree that under no circumstances will a class action be arbitrated.

(i) By agreeing to binding arbitration, the parties irrevocably and voluntarily waive any right they may have to a trial by jury in respect of any Claim. Furthermore, without intending in any way to limit this agreement to arbitrate, to the extent any Claim is not arbitrated, the parties irrevocably and voluntarily waive any right they may have to a trial by jury in respect of such Claim. This waiver of jury trial shall remain in effect even if the Class Action Waiver is limited, voided or found unenforceable. WHETHER THE CLAIM IS DECIDED BY ARBITRATION OR BY TRIAL BY A JUDGE, THE PARTIES AGREE AND UNDERSTAND THAT THE EFFECT OF THIS AGREEMENT IS THAT THEY ARE GIVING UP THE RIGHT TO TRIAL BY JURY TO THE EXTENT PERMITTED BY LAW.

17

10.5 Severability; Waivers .

If any part of this Agreement is not enforceable, the rest of the Agreement may be enforced. The Bank retains all rights, even if it makes a loan after default. If the Bank waives a default, it may enforce a later default. Any consent or waiver under this Agreement must be in writing.

10.6 Attorneys’ Fees .

The Borrowers shall reimburse the Bank for any reasonable costs and attorneys' fees incurred by the Bank in connection with the enforcement or preservation of any rights or remedies under this Agreement and any other documents executed in connection with this Agreement, and in connection with any amendment, waiver, "workout" or restructuring under this Agreement. In the event of a lawsuit or arbitration proceeding, the prevailing party is entitled to recover costs and reasonable attorneys' fees incurred in connection with the lawsuit or arbitration proceeding, as determined by the court or arbitrator. In the event that any case is commenced by or against a Borrower under the Bankruptcy Code (Title 11, United States Code) or any similar or successor statute, the Bank is entitled to recover costs and reasonable attorneys' fees incurred by the Bank related to the preservation, protection, or enforcement of any rights of the Bank in such a case. As used in this paragraph, "attorneys' fees" includes the allocated costs of the Bank's in-house counsel.

10.7 Joint and Several Liability .

(a) Each Borrower agrees that it is jointly and severally liable to the Bank for the payment of all obligations arising under this Agreement, and that such liability is independent of the obligations of the other Borrower(s). Each obligation, promise, covenant, representation and warranty in this Agreement shall be deemed to have been made by, and be binding upon, each Borrower, unless this Agreement expressly provides otherwise. The Bank may bring an action against any Borrower, whether an action is brought against the other Borrower(s).

(b) Each Borrower agrees that any release which may be given by the Bank to the other Borrower(s) or any guarantor will not release such Borrower from its obligations under this Agreement.

(c) Each Borrower waives any right to assert against the Bank any defense, setoff, counterclaim, or claims which such Borrower may have against the other Borrower(s) or any other party liable to the Bank for the obligations of the Borrower under this Agreement.

(d) Each Borrower waives any defense by reason of any other Borrower’s or any other person's defense, disability, or release from liability. The Bank can exercise its rights against each Borrower even if any other Borrower or any other person no longer is liable because of a statute of limitations or for other reasons.

(e) Each Borrower agrees that it is solely responsible for keeping itself informed as to the financial condition of the other Borrower(s) and of all circumstances which bear upon the risk of nonpayment. Each Borrower waives any right it may have to require the Bank to disclose to such Borrower any information which the Bank may now or hereafter acquire concerning the financial condition of the other Borrower(s).

(f) Each Borrower waives all rights to notices of default or nonperformance by any other Borrower under this Agreement. Each Borrower further waives all rights to notices of the existence or the creation of new indebtedness by any other Borrower and all rights to any other notices to any party liable on any of the credit extended under this Agreement.

(g) The Borrowers represent and warrant to the Bank that each will derive benefit, directly and indirectly, from the collective administration and availability of credit under this Agreement. The Borrowers agree that the Bank will not be required to inquire as to the disposition by any Borrower of funds disbursed in accordance with the terms of this Agreement.

18

(h) Until all obligations of the Borrowers to the Bank under this Agreement have been paid in full and any commitments of the Bank or facilities provided by the Bank under this Agreement have been terminated, each Borrower (a) waives any right of subrogation, reimbursement, indemnification and contribution (contractual, statutory or otherwise), including without limitation, any claim or right of subrogation under the Bankruptcy Code (Title 11, United States Code) or any successor statute, which such Borrower may now or hereafter have against any other Borrower with respect to the indebtedness incurred under this Agreement; (b) waives any right to enforce any remedy which the Bank now has or may hereafter have against any other Borrower, and waives any benefit of, and any right to participate in, any security now or hereafter held by the Bank.

(i) Each Borrower waives any right to require the Bank to proceed against any other Borrower or any other person; proceed against or exhaust any security; or pursue any other remedy. Further, each Borrower consents to the taking of, or failure to take, any action which might in any manner or to any extent vary the risks of the Borrowers under this Agreement or which, but for this provision, might operate as a discharge of a Borrower.

10.8 Individual Liability .

If a Borrower is a natural person, the Bank may proceed against such Borrower's business and non-business property in enforcing this and other agreements relating to this loan. If a Borrower is a partnership, the Bank may proceed against the business and non-business property of each general partner of such Borrower in enforcing this and other agreements relating to this loan.

10.9 Set-Off .

(a) In addition to any rights and remedies of the Bank provided by law, upon the occurrence and during the continuance of any event of default under this Agreement, the Bank is authorized, at any time, to set off and apply any and all Deposits of a Borrower or any Obligor held by the Bank against any and all Obligations owing to the Bank. The set-off may be made irrespective of whether or not the Bank shall have made demand under this Agreement or any guaranty, and although such Obligations may be contingent or unmatured or denominated in a currency different from that of the applicable Deposits.

(b) The set-off may be made without prior notice to the Borrowers or any other party, any such notice being waived by the Borrowers (on their own behalf and on behalf of each Obligor) to the fullest extent permitted by law. The Bank agrees promptly to notify the Borrowers after any such set-off and application; provided , however , that the failure to give such notice shall not affect the validity of such set-off and application.

(c) For the purposes of this paragraph, “Deposits” means any deposits (general or special, time or demand, provisional or final, individual or joint) and any instruments owned by a Borrower or any Obligor which come into the possession or custody or under the control of the Bank. “Obligations” means all obligations, now or hereafter existing, of a Borrower to the Bank under this Agreement and under any other agreement or instrument executed in connection with this Agreement, and the obligations to the Bank of any Obligor.

10.10 One Agreement .

This Agreement and any related security or other agreements required by this Agreement, collectively:

19

(a) represent the sum of the understandings and agreements between the Bank and the Borrowers concerning this credit;

(b) replace any prior oral or written agreements between the Bank and the Borrowers concerning this credit; and

(c) are intended by the Bank and the Borrowers as the final, complete and exclusive statement of the terms agreed to by them.

In the event of any conflict between this Agreement and any other agreements required by this Agreement, this Agreement will prevail. Any reference in any related document to a “promissory note” or a “note” executed by the Borrowers and dated as of the date of this Agreement shall be deemed to refer to this Agreement, as now in effect or as hereafter amended, renewed, or restated.

10.11 Indemnification .

The Borrowers will indemnify and hold the Bank harmless from any loss, liability, damages, judgments, and costs of any kind relating to or arising directly or indirectly out of (a) this Agreement or any document required hereunder, (b) any credit extended or committed by the Bank to the Borrowers hereunder, and (c) any litigation or proceeding related to or arising out of this Agreement, any such document, or any such credit. This indemnity includes but is not limited to attorneys' fees (including the allocated cost of in-house counsel). This indemnity extends to the Bank, its parent, subsidiaries and all of their directors, officers, employees, agents, successors, attorneys, and assigns. This indemnity will survive repayment of the Borrowers' obligations to the Bank. All sums due to the Bank hereunder shall be obligations of the Borrowers, due and payable immediately without demand.

10.12 Notices .

Unless otherwise provided in this Agreement or in another agreement between the Bank and the Borrowers, all notices required under this Agreement shall be personally delivered or sent by first class mail, postage prepaid, or by overnight courier, to the addresses on the signature page of this Agreement, or sent by facsimile to the fax numbers listed on the signature page, or to such other addresses as the Bank and the Borrowers may specify from time to time in writing. Notices and other communications shall be effective (i) if mailed, upon the earlier of receipt or five (5) days after deposit in the U.S. mail, first class, postage prepaid, (ii) if telecopied, when transmitted, or (iii) if hand-delivered, by courier or otherwise (including telegram, lettergram or mailgram), when delivered.

10.13 Headings .

Article and paragraph headings are for reference only and shall not affect the interpretation or meaning of any provisions of this Agreement.

10.14 Counterparts .

This Agreement may be executed in as many counterparts as necessary or convenient, and by the different parties on separate counterparts each of which, when so executed, shall be deemed an original but all such counterparts shall constitute but one and the same agreement.

10.15 Borrower Information; Reporting to Credit Bureaus .

The Borrowers authorize the Bank at any time to verify or check any information given by a Borrower to the Bank, check a Borrower’s credit references, verify employment, and obtain credit reports. Each Borrower agrees that the Bank shall have the right at all times to disclose and report to credit reporting agencies and credit rating agencies such information pertaining to the Borrowers and/or all guarantors as is consistent with the Bank's policies and practices from time to time in effect.

20

10.16 Prior Agreement Superseded .

This Agreement supersedes and restates the Loan Agreement entered into as of August 6, 2001, including all amendments thereto, between the Bank and the Borrowers, and any credit outstanding thereunder shall be deemed to be outstanding under this Agreement.

10.17 USA PATRIOT ACT NOTICE, AFFILIATE SHARING NOTICE and AFFILIATE MARKETING NOTICE .

A .              USA PATRIOT ACT NOTICE

Federal law requires all financial institutions to obtain, verify and record information that identifies each person who opens an account or obtains a loan. The Bank will ask for each Borrower’s legal name, address, tax ID number or social security number and other identifying information. The Bank may also ask for additional information or documentation or take other actions reasonably necessary to verify the identity of each Borrower, guarantors or other related persons.

B.              AFFILIATE SHARING NOTICE

From time to time the Bank may share information about each Borrower’s experience with Bank of America Corporation (or any successor company) and its subsidiaries and affiliated companies (the “Affiliates”), including, but not limited to, the Bank of America Companies listed in notice C. below. The Bank may also share with the Affiliates credit-related information contained in any applications, from credit reports and information it may obtain about each Borrower from outside sources.

If a Borrower is an individual, the Borrower may instruct the Bank not to share this information with the Affiliates. A Borrower can make this election by (1) calling the Bank at 1.888.341.5000, (2) visiting the Bank online at www.bankofamerica.com , selecting “Privacy & Security,” and then selecting “Set Your Privacy Preferences,” or (3) contacting the Borrower’s client manager or local banking center. To help the Bank complete the Borrower’s request, the Borrower should include the Borrower’s name, address, phone number, account numbers(s) and social security number.

If a Borrower makes this election, certain products or services may not be made available to the Borrower. This request will apply to information from applications, consumer reports and other outside sources only. Through the normal course of doing business, including servicing the Borrower’s accounts and better serving the Borrower’s financial needs, the Bank will continue to share transaction and account experience information, as well as other general information among the Affiliates.

C.              AFFILIATE MARKETING NOTICE – YOUR CHOICE TO LIMIT MARKETING

(i)              The Bank of America companies listed below are providing this notice C.

(ii)              Federal law gives you the right to limit some but not all marketing from all the Bank of America affiliated companies. Federal law also requires us to give you this notice to tell you about your choice to limit marketing from all the Bank of America affiliated companies.

(iii)              You may limit all the Bank of America affiliated companies, such as the banking, loan, credit card, insurance and securities companies, from marketing their products or services to you based upon your personal information that they receive from other Bank of America companies. This information includes your income, your account history, and your credit score.

21

(iv)              Your choice to limit marketing offers from all the Bank of America affiliated companies will apply for at least 5 years from when you tell us your choice. Before your choice to limit marketing expires, you will receive a renewal notice that will allow you to continue to limit marketing offers from all the Bank of America affiliated companies for at least another 5 years.

(v)              You may tell us your choice to limit marketing offers and you may tell us the choices for other customers who are joint account holders with you.

(vi)              This limitation will not apply in certain circumstances, such as when you have an account or service relationship with the Bank of America company that is marketing to you.

(vii)              For individuals with business purpose accounts, this limitation will only apply to marketing to individuals and not marketing to a business.

To limit marketing offers, contact us at 800.282.2884
 
Effective October 1, 2008
Bank of America Companies:
 
Banks and Trust Companies
Bank of America, N.A.
LaSalle Bank National Association
LaSalle Bank Midwest National Association
 
Credit Card
Bank of America Consumer Card Services, LLC
Bank of America
Fleet Credit Card Services, L.P.
Brokerage and Investments
BACAP Alternative Advisors, Inc.
Bank of America Capital Advisors LLC
Banc of America Investment Advisors, Inc.
Banc of America Investment Services, Inc.
Banc of America Securities LLC
LaSalle Financial Services, Inc.
U.S. Trust Hedge Fund Management, Inc.
UST Securities Corp.
 
Insurance and Annuities
BA Insurance Services, Inc.
Banc of America Agency of Texas, Inc.
Banc of America Insurance Services, Inc.,
   dba Banc of America Insurance Agency in New York State
General Fidelity Insurance Company
General Fidelity Life Insurance Company
LaSalle Financial Services, Inc.
Real Estate
Home Focus Services, LLC
 
Administrative Services
LaSalle Healthcare Administrative Services, LLC
 
Merchant Services
BA Merchant Services, LLC
LaSalle Merchant Services, LLC
 
10.18
Notice of Final Agreement.

THIS WRITTEN LOAN AGREEMENT AND THE LOAN DOCUMENTS EXECUTED IN CONNECTION HEREWITH REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES.

THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

22

This Agreement is executed as of the date stated at the top of the first page.
 
BORROWERS:
BANK:
           
MEXCO ENERGY CORPORATION
BANK OF AMERICA, N.A.
           
By:
/s/ Nicholas C. Taylor
 
By:
/s/ Kory Clark
 
 
Nicholas C. Taylor
 
Name:
Kory Clark
 
 
President
 
Title:
Senior Vice President
 

FORMAN ENERGY CORPORATION
     
By:
/s/ Nicholas C. Taylor
 
 
Nicholas C. Taylor
 
 
President
 
 
Address where notices to the Borrowers are to be sent:
 
214 West Texas Avenue, Suite 1101
Midland, Texas 79701
Telephone: (432) 682-1119
Facsimile: (432) 682-1123

Address where notices to the Bank are to be sent:
701 S. Taylor
Amarillo, Texas 79101
Attn: Kory Clark
Telephone: (806) 378-1743
Facsimile: (806) 374-0845


 
23
 
EXHIBIT 10.3

FIRST AMENDMENT TO LOAN AGREEMENT

This First Amendment to Loan Agreement (this "First Amendment") is entered into as of the 28 th day of October, 2009, by and among MEXCO ENERGY CORPORATION, a Colorado corporation, and FORMAN ENERGY CORPORATION, a New York corporation (collectively, "Borrowers") and BANK OF AMERICA, N.A., a national banking association ("Bank").

Recitals:

A.        Borrowers and Bank entered into that certain Loan Agreement dated December 31, 2008 (the "Loan Agreement").

B.        Pursuant to the terms of the Loan Agreement, Bank provided Borrowers a revolving line of credit loan in the amount of $5,000,000.00 (the "Facility No. 1 Loan").

C.        Borrowers and Bank desire to amend the Loan Agreement to reflect the extension of the Facility No. 1 Loan.

NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained and other good and valuable consideration, it is hereby agreed among Bank and Borrowers as follows:

Agreement

1.         Capitalized terms used but not defined herein shall have the respective meanings ascribed thereto in the Loan Agreement.

2.         Section 1.2 of the Loan Agreement is hereby amended in its entirety to read as follows:

1.2       Availability Period .

The line of credit is available between the date of this Agreement and January 31, 2011, or such earlier date as the availability may terminate as provided in this Agreement (the "Facility No. 1 Expiration Date").

3.         By their execution hereof, Borrowers hereby affirm and ratify the Loan Agreement as amended hereby, and all of the other loan documents executed in connection with the Loan Agreement.

4.         Neither the execution by Bank of this First Amendment nor anything contained herein shall in any way be construed or operate as a waiver by Bank of any event of default under the Loan Agreement or the other loan documents executed in connection therewith (whether now existing or that may occur hereafter) or any of Bank's rights under the Loan Agreement or any of such other loan documents.


5.         Except as provided herein, all terms and provisions of the Loan Agreement shall remain unchanged .

6.         As an inducement to Bank to enter into this First Amendment, Borrowers represent and warrant to Bank that (i) the representations and warranties contained in the Loan Agreement are true and correct as of the date hereof, (ii) Borrowers have not breached any of the covenants contained in the Loan Agreement or the other loan documents executed in connection therewith (except as may have been waived in writing by Bank), and (iii) no event of default now exists under the Loan Agreement, nor does there exist any condition or event which, with notice and/or lapse of time, would constitute such an event of default.

7.         THIS FIRST AMENDMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

EXECUTED effective as of the date first above written.

BORROWERS:
 
BANK:
 
           
MEXCO ENERGY CORPORATION
 
BANK OF AMERICA, N.A.
 
           
By:
/s/ Nicholas C. Taylor
 
By:
/s/ Mark A. Formky
 
 
Nicholas C. Taylor
   
Mark A. Formky
 
 
President
   
Assistant Vice President
 

FORMAN ENERGY CORPORATION

By:
/s/ Nicholas C. Taylor
 
 
Nicholas C. Taylor
 
 
President
 

 
EXHIBIT 10.4

SECOND AMENDMENT TO LOAN AGREEMENT

This Second Amendment to Loan Agreement (this "Second Amendment") is entered into as of the 1 st day of March, 2010, by and among MEXCO ENERGY CORPORATION, a Colorado corporation, and FORMAN ENERGY CORPORATION, a New York corporation (collectively, "Borrowers") and BANK OF AMERICA, N.A., a national banking association ("Bank").

Recitals:

A.       Borrowers and Bank entered into that certain Loan Agreement dated December 31, 2008, as amended by First Amendment to Loan Agreement dated December 28, 2009 (the "Loan Agreement").

B.       Pursuant to the terms of the Loan Agreement, Bank provided Borrowers a revolving line of credit loan in the amount of $5,000,000.00 (the "Facility No. 1 Loan").

C.       Borrowers and Bank desire to amend the Loan Agreement to reflect the extension of the Facility No. 1 Loan.

NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained and other good and valuable consideration, it is hereby agreed among Bank and Borrowers as follows:

Agreement

1.        Capitalized terms used but not defined herein shall have the respective meanings ascribed thereto in the Loan Agreement.

2.        Section 1.2 of the Loan Agreement is hereby amended in its entirety to read as follows:

1.2      Availability Period .

The line of credit is available between the date of this Agreement and April 30, 2011, or such earlier date as the availability may terminate as provided in this Agreement (the "Facility No. 1 Expiration Date").

3.        By their execution hereof, Borrowers hereby affirm and ratify the Loan Agreement as amended hereby, and all of the other loan documents executed in connection with the Loan Agreement.

4.        Neither the execution by Bank of this Second Amendment nor anything contained herein shall in any way be construed or operate as a waiver by Bank of any event of default under the Loan Agreement or the other loan documents executed in connection therewith (whether now existing or that may occur hereafter) or any of Bank's rights under the Loan Agreement or any of such other loan documents.


5.        Except as provided herein, all terms and provisions of the Loan Agreement shall remain  unchanged .

6.        As an inducement to Bank to enter into this Second Amendment, Borrowers represent and warrant to Bank that (i) the representations and warranties contained in the Loan Agreement are true and correct as of the date hereof, (ii) Borrowers have not breached any of the covenants contained in the Loan Agreement or the other loan documents executed in connection therewith (except as may have been waived in writing by Bank), and (iii) no event of default now exists under the Loan Agreement, nor does there exist any condition or event which, with notice and/or lapse of time, would constitute such an event of default.

7.        THIS SECOND AMENDMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES.  THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

EXECUTED effective as of the date first above written.

BORROWERS:
 
BANK:
 
           
MEXCO ENERGY CORPORATION
 
BANK OF AMERICA, N.A.
 
           
By:
/s/ Nicholas C. Taylor
 
By
: /s/ Jaime Pfeifer
 
 
Nicholas C. Taylor
   
Jaime Pfeifer
 
 
President
   
Assistant Vice President
 

FORMAN ENERGY CORPORATION

By:
/s/ Nicholas C. Taylor
 
 
Nicholas C. Taylor
 
 
President
 

 
EXHIBIT 10.5

THIRD AMENDMENT TO LOAN AGREEMENT

This Third Amendment to Loan Agreement (this "Fourth Amendment") is entered into as of the 30 th day of September , 2010, by and among MEXCO ENERGY CORPORATION, a Colorado corporation, and FORMAN ENERGY CORPORATION, a New York corporation (collectively, "Borrowers") and BANK OF AMERICA, N . A., a national banking association ("Bank") .

Recitals:

A.       Borrowers and Bank entered into that certain Loan Agreement dated December 31, 2008, as amended by First Amendment to Loan Agreement dated December 28, 2009 and by Second Amendment to Loan Agreement dated March 1, 2010 (the "Loan Agreement").

B.       Pursuant to the terms of the Loan Agreement, Bank provided Borrowers a revolving line of credit loan with a Facility No. I Commitment (as defined in the Loan Agreement) in the amount of $5,000,000.00 (the "Facility No. 1 Loan").

C.        Borrowers and Bank desire to amend the Loan Agreement to reflect the extension of the maturity date of the Facility No. 1 Loan.

NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained and other good and valuable consideration, it is hereby agreed among Bank and Borrowers as follows:

Agreement

1.        Capitalized terms used but not defined herein shall have the respective meanings ascribed thereto in the Loan Agreement.

2.        Section 1.2 of the Loan Agreement (Availability Period) is hereby amended in its entirety to read as follows:

1.2      Availability Period .

The line of credit is available between the date of this Agreement and November 30, 20 11, or such earlier date as the availability may terminate as provided in this Agreement (the "Facility No. 1 Expiration Date").

3.        By their execution hereof, Borrowers hereby affirm and ratify the Loan Agreement as amended hereby, and all of the other loan documents executed in connection with the Loan Agreement.

4.        Neither the execution by Bank of this Third Amendment nor anything contained herein shall in any way be construed or operate as a waiver by Bank of any event of default under the Loan Agreement or the other loan documents executed in connection therewith (whether now existing or that may occur hereafter) or any of Bank's rights under the Loan Agreement or any of such other loan documents.

5.        Except as provided herein, all terms and provisions of the Loan Agreement shall remain  unchanged .

6.        As an inducement to Bank to enter into this Third Amendment, Borrowers represent and warrant to Bank that (i) the representations and warranties contained in the Loan Agreement are true and correct as of the date hereof, (ii) Borrowers have not breached any of the covenants contained in the Loan Agreement or the other loan documents executed in connection therewith (except as may have been waived in writing by Bank), and (iii) no event of default now exists under the Loan Agreement, nor does there exist any condition or event which, with notice and/or lapse of time, would constitute such an event of default.

9.        THIS THIRD AMENDMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES.  THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES .

EXECUTED effective as of the date first above written.

BORROWERS:
BANK:
           
MEXCO ENERGY CORPORATION
BANK OF AMERICA, N.A.
 
           
By:
/s/ Nicholas C. Taylor
 
By:
/s/ Rose M. Storey
 
 
Nicholas C. Taylor
   
Rose M. Storey
 
 
President
   
Assistant Vice President
 

FORMAN ENERGY CORPORATION

By:
/s/ Nicholas C. Taylor
 
 
Nicholas C. Taylor
 
 
President
 

 
EXHIBIT 10.6

FOURTH AMENDMENT TO LOAN AGREEMENT

This Fourth Amendment to Loan Agreement (this "Fourth Amendment") is entered into as of the 22nd day of October, 2010, by and among MEXCO ENERGY CORPORATION, a Colorado corporation, and FORMAN ENERGY CORPORATION, a New York corporation (collectively, "Borrowers") and BANK OF AMERICA, N.A., a national banking association ("Bank").

Recitals:

A.       Borrowers and Bank entered into that certain Loan Agreement dated December 31, 2008, as amended by First Amendment to Loan Agreement dated December 28, 2009, by Second Amendment to Loan Agreement dated March 1, 2010, and by Third Amendment to Loan Agreement dated September 30, 2010 (the "Loan Agreement").

B.       Pursuant to the terms of the Loan Agreement, Bank provided Borrowers a revolving line of credit loan with a Facility No. I Commitment (as defined in the Loan Agreement) in the amount of $4,900,000.00 (the "Facility No. 1 Loan").

C.       Borrowers and Bank desire to amend the Loan Agreement to, among other matters, reflect the extension of the maturity date of the Facility No. 1 Loan.

NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained and other good and valuable consideration, it is hereby agreed among Bank and Borrowers as follows:

Agreement

1.        Capitalized terms used but not defined herein shall have the respective meanings ascribed thereto in the Loan Agreement.

2.        Section 1.2 of the Loan Agreement (Availability Period) is hereby amended in its entirety to read as follows:

1.2      Availability Period.

The line of credit is available between the date of this Agreement and November 30, 20 12, or such earlier date as the availability may terminate as provided in this Agreement (the "Facility No. 1 Expiration Date").

 

3.        Section 7.3 of the Loan Agreement (Tangible Net Worth) is hereby amended in its entirety to read as follows:

7.3      Tangible Net Worth.

To maintain on a consolidated basis, Tangible Net Worth equal to at least the sum of the following:

(a)       Ten Million Dollars ($10,000,000); plus

 
(b)
The sum of 50% of net income after income taxes (without subtracting losses) earned in each quarterly accounting period commencing after June 30, 2010; plus

(c)       The net proceeds for from any equity securities issues after the date of this Agreement.

As used herein, "Tangible Net Worth" means the value of total assets (including leaseholds and leasehold improvements and reserves against assets but excluding goodwill, patents, trademarks, trade names, organization expense, unamortized debt discount and expense, capitalized or deferred research and development costs, deferred marketing expenses and other like intangibles, and monies due from affiliates, officers, directors, employees, shareholders, members or managers) less total liabilities, including but not limited to accrued and deferred income taxes, but excluding the non-current portion of Subordinated Liabilities. "Subordinated Liabilities" means liabilities subordinated to the Borrowers' obligations to the Bank in a manner acceptable to the Bank in its sole discretion.

4.        The amount of the Borrowing Base and the Facility No. 1 Commitment under the Loan Agreement shall remain at $4,900,000 until redetermined by Bank in accordance with Section 1.3 of the Loan Agreement.

5.        By their execution hereof, Borrowers hereby affirm and ratify the Loan Agreement as amended hereby, and all of the other loan documents executed in connection with the Loan Agreement.

6.        Neither the execution by Bank of this Fourth Amendment nor anything contained herein shall in any way be construed or operate as a waiver by Bank of any event of default under the Loan Agreement or the other loan documents executed in connection therewith (whether now existing or that may occur hereafter) or any of Bank's rights under the Loan Agreement or any of such other loan documents.

7.        Except as provided herein, all terms and provisions of the Loan Agreement shall remain  unchanged .
-2-

8.        As an inducement to Bank to enter into this Fourth Amendment, Borrowers represent and warrant to Bank that (i) the representations and warranties contained in the Loan Agreement are true and correct as of the date hereof, (ii) Borrowers have not breached any of the covenants contained in the Loan Agreement or the other loan documents executed in connection therewith (except as may have been waived in writing by Bank), and (iii) no event of default now exists under the Loan Agreement, nor does there exist any condition or event which, with notice and/or lapse of time, would constitute such an event of default.

9.        THIS FOURTH AMENDMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT   ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES .

EXECUTED effective as of the date first above written.

BORROWERS:
BANK:
       
MEXCO ENERGY CORPORATION
BANK OF AMERICA, N.A.
       
By:
/s/ Nicholas C. Taylor
By:
/s/ Rose M. Storey
 
Nicholas C. Taylor
 
Rose M. Storey
 
President
 
Assistant Vice President

FORMAN ENERGY CORPORATION

By:
/s/ Nicholas C. Taylor
 
 
Nicholas C. Taylor
 
 
President
 

-3-
 
EXHIBIT 10.7

FIFTH AMENDMENT TO LOAN AGREEMENT

This Fifth Amendment to Loan Agreement (this "Fifth Amendment") is entered into as of the 28 th day of December, 2011, by and among MEXCO ENERGY CORPORATION, a Colorado corporation ("Mexco " ), FORMAN ENERGY CORPORATION, a New York corporation ("Forman") and SOUTHWEST TEXAS DISPOSAL CORPORATION, a Texas corporation ("Southwest'', and together with Mexco and Forman collectively "Borrowers" or individually a "Borrower") and BANK OF AMERICA, N.A., a national banking association ("Bank").

Recitals:

A.              Mexco, Forman and Bank entered into that certain Loan Agreement dated Dec ember 31, 2008, as amended by First Amendment to Loan Agreement dated December 28, 2009, by Second Amendment to Loan Agreement dated March 1 , 2010, by Third Amendment to Loan Agreement dated September 30, 2010 and by Fourth Amendment to Loan Agreement dated October 22, 2010 (the "Loan Agreement") .

B.              Pursuant to the terms of the Loan Agreement, Bank provided Mexco and Forman a revolving line of credit loan with a Facility No. 1 Commitment (as defined in the Loan Agreement) in the initial amount of $4 , 900 , 000.00 (the "Facility No. 1 Loan").

C.              Borrowers and Bank desire to amend the Loan Agreement to, among other matters (i) reflect the extension of the maturity date of the Facility No. 1 Loan, and (ii) make Southwest a Borrower under the Loan Agreement.

NOW , THEREFORE, in consideration of the premises and the mutual covenants herein contained and other good and valuable consideration , it is hereby agreed among Bank and Borrowers as follows:

Agreement

1.              Capitalized terms used but not defined herein shall have the respective meanings ascribed thereto in the Loan Agreement.

2.              The definitions of “Borrowers” and “Borrower” in the preamble and first paragraph of the Loan Agreement are hereby amended to include Southwest, such that Southwest shall be jointly and severally bound with Mexco and Forman with respect to all of the covenants, representations and obligations of Borrowers under the Loan Agreement, including, without limitations, the obligation to pay to Bank the Facility No. 1 Loan when due in accordance with the terms of the Loan Agreement.

3.              Section 1.2 of the Loan Agreement (Availability Period) is hereby amended in its entirety to read as follows:


1.2 Availability Period .

The line of credit is available between the date of this Agreement and November 30, 2013, or such earlier date as the availability may terminate as provided in this Agreement (the "Facility No. 1 Expiration Date").

4.              The amount of the Borrowing Base and the Facility No. 1 Commitment under the Loan Agreement shall remain at $4 , 900 , 000 until - redetermined by Bank in accordance with Section 1.3 of the Loan Agreement .

5.              By their execution hereof, Borrowers hereby affirm and ratify all of the terms and provisions of the Loan Agreement as amended hereby , and all of the terms and provisions of the other loan documents execut e d in connection with the Loan Agreement.

6.              Neither the execution by Bank of this Sixth Amendment nor anything contained herein shall in an y way be construed or operate as a waiver by Bank of any event of default under the Loan Agreement or the other loan documents e x ecuted in connection therewith (whether now e x i s ting or that ma y occur hereafter) or any of Bank's rights under the Loan Agreement or any of such other loan documents.

7.              Except as provided herein , all terms and provision s of the Loan Agreement shall remain unchanged.

8.              As an inducement to Bank to enter into this Fifth Amendment , Borrowers represent and warrant to Bank that (i) the representations and . warranties contained in the Loan Agreement are true and correct as of the date hereof , (ii) Borrowers have not breached any of the covenant s contained in the Loan Agreement or the other loan documents e xecuted in connection therewith (except as may have been waived in writing by Bank) , and (iii) no event of default now exists under the Loan Agreement , nor does there exist any condition or event which , with notice and/or lapse of time , would constitute such an event of default.

9.              THIS FIFTH AMENDMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR , CONTEMPORANEOUS , OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES . THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

[SIGNATURE PAGE TO FOLLOW]


EXECUTED effective as of the date first above written .

BORROWERS:
BANK:
           
MEXCO ENERGY CORPORATION
BANK OF AMERICA , N.A.
           
By:
/s/ Nicholas C. Taylor
 
By:
/s/ Rose M. Storey
 
 
Nicholas C. Taylor
   
Rose M. Storey
 
 
Chairman of the Board and
   
Assistant Vice President
 
 
Chief Executive Officer
       

FORMAN ENERGY CORPORATION
     
By:
/s/ Nicholas C. Taylor
 
 
Nicholas C. Taylor
 
 
Chairman of the Board and Chief Executive Officer
 
     
SOUTHWEST TEXAS DISPOSAL CORPORATION
     
By:
/s/ Nicholas C. Taylor
 
 
Nicholas C. Taylor
 
 
Chairman of the Board and Chief Executive Officer
 

 
EXHIBIT 10.8

SIXTH AMENDMENT TO LOAN AGREEMENT

This Sixth Amendment to Loan Agreement (this "Sixth Amendment") is entered into as of the 22nd day of October, 2012, by and among MEXCO ENERGY CORPORATION, a Colorado corporation ("Mexco"), FORMAN ENERGY CORPORATION, a New York corporation ("Forman") and SOUTHWEST TEXAS DISPOSAL CORPORATION, a Texas corporation ("Southwest'', and together with Mexco and Forman collectively "Borrowers" or individually a "Borrower") and BANK OF AMERICA, N.A., a national banking association ("Bank").

Recitals:

A.              Borrowers and Bank entered into that certain Loan Agreement dated December 31, 2008, as amended by First Amendment to Loan Agreement dated December 28, 2009, by Second Amendment to Loan Agreement dated March 1, 2010, by Third Amendment to Loan Agreement dated September 30, 2010, by Fourth Amendment to Loan Agreement dated October 22, 2010 and by Fifth Amendment to Loan Agreement dated December 28, 2011 (the "Loan Agreement") .

B.              Pursuant to the terms of the Loan Agreement, Bank provided Borrowers a revolving line of credit loan with a Facility No. 1 Commitment (as defined in the Loan Agreement) in the initial amount of $4,900,000.00 (the "Facility No. 1 Loan").

C.              Borrowers and Bank desire to amend the Loan Agreement to, among other matters, reflect the extension of the maturity date of the Facility No. 1 Loan.

NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained and other good and valuable consideration , it is hereby agreed among Bank and Borrowers as follows:

Agreement

1.              Capitalized terms used but not defined herein shall have the respective meanings ascribed thereto in the Loan Agreement.

2.              Section 1.2 of the Loan Agreement (Availability Period) is hereby amended in its entirety to read as follows:

1.2              Availability P eriod.

The line of credit is available between the date of this Agreement and November 30, 2014, or such earlier date as the availability may terminate as provided in this Agreement (the "Facility No. 1 Expiration Date").

3.              The amount of the Borrowing Base and the Facility No. 1 Commitment under the Loan Agreement shall remain at $4,900,000 until - redetermined by Bank in accordance with Section 1.3 of the Loan Agreement .

4.              By their execution hereof, Borrowers hereby affirm and ratify all of the terms and provisions of the Loan Agreement as amended hereby, and all of the terms and provisions of the other loan documents executed in connection with the Loan Agreement.

5.              Neither the execution by Bank of this Sixth Amendment nor anything contained herein shall in any way be construed or operate as a waiver by Bank of any event of default under the Loan Agreement or the other loan documents executed in connection therewith (whether now existing or that may occur hereafter) or any of Bank's rights under the Loan Agreement or any of such other loan documents.

6.              Except as provided herein, all terms and provisions of the Loan Agreement shall remain unchanged.

7.              As an inducement to Bank to enter into this Sixth Amendment , Borrowers represent and warrant to Bank that (i) the representations and .warranties contained in the Loan Agreement are true and correct as of the date hereof, (ii) Borrowers have not breached any of the covenants contained in the Loan Agreement or the other loan documents executed in connection therewith (except as may have been waived in writing by Bank), and (iii) no event of default now exists under the Loan Agreement, nor does there exist any condition or event which, with notice and/or lapse of time, would constitute such an event of default.

8.              THIS SIXTH AMENDMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES .

[SIGNATURE PAGE TO FOLLOW]

EXECUTED effective as of the date first above written.

BORROWERS:
BANK:
 
           
MEXCO ENERGY CORPORATION
BANK OF AMERICA , N.A.
 
           
By:
/s/ Nicholas C. Taylor
 
By:
/s/ Charles Dale
 
 
Nicholas C. Taylor
   
Charles Dale
 
 
Chairman of the Board and Chief Executive Officer
   
Senior Vice President
 

FORMAN ENERGY CORPORATION
     
By:
/s/ Nicholas C. Taylor
 
 
Nicholas C. Taylor
 
 
Chairman of the Board and Chief Executive Officer
 
     
SOUTHWEST TEXAS DISPOSAL CORPORATION
     
By:
/s/ Nicholas C. Taylor
 
 
Nicholas C. Taylor
 
 
Chairman of the Board and Chief Executive Officer
 
     
TBO OIL & GAS, LLC
     
By:
/s/ Nicholas C. Taylor
 
 
Nicholas C. Taylor
 
 
Chairman of the Board and Chief Executive Officer
 




 
EXHIBIT 10.9

SEVENTH AMENDMENT TO LOAN AGREEMENT

This Seventh Amendment to Loan Agreement (this "Seventh Amendment") is entered into as of the 25th day of October, 2013, by and among MEXCO ENERGY CORPORATION, a Colorado corporation (“Mexco”), FORMAN ENERGY CORPORATION, a New York corporation (“Forman”), SOUTHWEST TEXAS DISPOSAL CORPORATION , a Texas corporation (“Southwest”) and TBO OIL & GAS, LLC , a Texas limited liability company ("TBO", and together with Mexco, Forman and Southwest, collectively “Borrowers” or individually a “Borrower”) and BANK OF AMERICA, N.A. , a national banking association ("Bank").

Recitals:

A.              Borrowers and Bank entered into that certain Loan Agreement dated December 31, 2008, as amended by First Amendment to Loan Agreement dated December 28, 2009, by Second Amendment to Loan Agreement dated March 1, 2010, by Third Amendment to Loan Agreement dated September 30, 2010, by Fourth Amendment to Loan Agreement dated October 22, 2010, by Fifth Amendment to Loan Agreement dated December 28, 2011 and by Sixth Amendment to Loan Agreement dated October 22, 2012 (the "Loan Agreement").

B.              Pursuant to the terms of the Loan Agreement, Bank provided Borrowers a revolving line of credit loan with a Facility No. 1 Commitment (as defined in the Loan Agreement) in the initial amount of $4,900,000.00 (the “Facility No. 1 Loan”).

C.              Borrowers and Bank desire to amend the Loan Agreement to, among other matters (i) reflect the extension of the maturity date of the Facility No. 1 Loan, and (ii) make TBO a Borrower under the Loan Agreement.

NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained and other good and valuable consideration, it is hereby agreed among Bank and Borrowers as follows:

Agreement

1.              Capitalized terms used but not defined herein shall have the respective meanings ascribed thereto in the Loan Agreement.

2.              The definitions of "Borrowers" and "Borrower" in the preamble and first paragraph of the Loan Agreement are hereby amended to include TBO, such that TBO shall be jointly and severally bound with Mexco, Forman and Southwest with respect to all of the covenants, representations and obligations of Borrowers under the Loan Agreement, including, without limitation, the obligation to pay to Bank the Facility No. 1 Loan when due in accordance with the terms of the Loan Agreement.
 

3.              Section 1.2 of the Loan Agreement (Availability Period) is hereby amended in its entirety to read as follows:

"1.2              Availability Period .

The line of credit is available between the date of this Agreement and November 30, 2015, or such earlier date as the availability may terminate as provided in this Agreement (the "Facility No. 1 Expiration Date")."

4.              The Loan Agreement is hereby amended to include a new Section 1.6 (Letters of Credit) reading as follows:

"1.6              Letters of Credit .

(a) During the availability period, at the request of a Borrower, the Bank will issue standby letters of credit with a maximum maturity not to extend beyond the Facility No. 1 Expiration Date.

(b) The amount of the letters of credit outstanding at any one time (including the drawn and unreimbursed amounts of the letters of credit) may not exceed Five Hundred Thousand Dollars ($500,000.00).

(c) In calculating the principal amount outstanding under the Facility No. 1 Commitment, the calculation shall include the amount of any letters of credit outstanding, including amounts drawn on any letters of credit and not yet reimbursed.

(d) The following letter of credit is outstanding from the Bank for the account of a Borrower:

Letter of Credit Number
Amount
120995
$50,000.00

As of the date of this Agreement, this letter of credit shall be deemed to be outstanding under this Agreement, and shall be subject to all the terms and conditions stated in this Agreement.

(e) The Borrowers agree:

(i) Any sum drawn under a letter of credit may, at the option of the Bank, be added to the principal amount outstanding under this Agreement. The amount will bear interest and be due as described elsewhere in this Agreement.
-2-

(ii) If there is a default under this Agreement, to immediately prepay and make the Bank whole for any outstanding letters of credit.

(iii) The issuance of any letter of credit and any amendment to a letter of credit is subject to the Bank's written approval and must be in form and content satisfactory to the Bank and in favor of a beneficiary acceptable to the Bank.

(iv) To sign the Bank's form Application and Agreement for Standby Letter of Credit.

(v) To pay any issuance and/or other fees that the Bank notifies the Borrowers will be charged for issuing and processing letters of credit for a Borrower.

(vi) To allow the Bank to automatically charge its checking account for applicable fees, discounts, and other charges.

(vii) To pay the Bank a non-refundable fee equal to 1% per annum of the outstanding undrawn amount of each standby letter of credit, payable monthly in arrears, calculated on the basis of the face amount outstanding on the day the fee is calculated."

5.              The amount of the Borrowing Base and the Facility No. 1 Commitment under the Loan Agreement shall remain at $4,900,000 until redetermined by Bank in accordance with Section 1.3 of the Loan Agreement.

6.              By their execution hereof, Borrowers hereby affirm and ratify all of the terms and provisions of the Loan Agreement as amended hereby, and all of the terms and provisions of the other loan documents executed in connection with the Loan Agreement.

7.              Neither the execution by Bank of this Seventh Amendment nor anything contained herein shall in any way be construed or operate as a waiver by Bank of any event of default under the Loan Agreement or the other loan documents executed in connection therewith (whether now existing or that may occur hereafter) or any of Bank's rights under the Loan Agreement or any of such other loan documents.

8.              Except as provided herein, all terms and provisions of the Loan Agreement shall remain unchanged.

9.              As an inducement to Bank to enter into this Seventh Amendment, Borrowers represent and warrant to Bank that (i) the representations and warranties contained in the Loan Agreement are true and correct as of the date hereof, (ii) Borrowers have not breached any of the covenants contained in the Loan Agreement or the other loan documents executed in connection therewith (except as may have been waived in writing by Bank), and (iii) no event of default now exists under the Loan Agreement, nor does there exist any condition or event which, with notice and/or lapse of time, would constitute such an event of default.

-3-

10.              THIS SEVENTH AMENDMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

EXECUTED effective as of the date first above written.

BORROWERS:
BANK:
           
MEXCO ENERGY CORPORATION
BANK OF AMERICA, N.A.
           
By:
/s/ Donna Gail Yanko
 
By:
/s/ Ricky Temkin
 
 
Donna Gail Yanko
   
Ricky Temkin
 
 
Vice President and Secretary
   
Assistant Vice President
 

FORMAN ENERGY CORPORATION
     
By:
Donna Gail Yanko
 
 
Vice President and Secretary
 
     
SOUTHWEST TEXAS DISPOSAL CORPORATION
     
By:
Donna Gail Yanko
 
 
Vice President and Secretary
 
     
TBO OIL & GAS, LLC
     
By:
Donna Gail Yanko
 
 
Vice President and Secretary
 
 

 
-4-
 
EXHIBIT 10.10
 
EIGHTH AMENDMENT TO LOAN AGREEMENT

This Eighth Amendment to Loan Agreement (this “Eighth Amendment”) is entered into as of the 10th day of September, 2014, by and among MEXCO ENERGY CORPORATION, a Colorado corporation (“Mexco”), FORMAN ENERGY CORPORATION, a New York corporation (“Forman”), SOUTHWEST TEXAS DISPOSAL CORPORATION , a Texas corporation (“Southwest”) and TBO OIL & GAS, LLC , a Texas limited liability company (“TBO”, and together with Mexco, Forman and Southwest, collectively “Borrowers” or individually a “Borrower”) and BANK OF AMERICA, N.A. , a national banking association (“Bank”).

Recitals:

A.          Borrowers and Bank entered into that certain Loan Agreement dated December 31, 2008, as amended by First Amendment to Loan Agreement dated December 28, 2009, by Second Amendment to Loan Agreement dated March 1, 2010, by Third Amendment to Loan Agreement dated September 30, 2010, by Fourth Amendment to Loan Agreement dated October 22, 2010, by Fifth Amendment to Loan Agreement dated December 28, 2011, by Sixth Amendment to Loan Agreement dated October 22, 2012 and by Seventh Amendment to Loan Agreement dated October 25, 2013 (the “Loan Agreement”).

B.         P ursuant to the terms of the Loan Agreement, Bank provided Borrowers a revolving line of credit loan with a Facility No. 1 Commitment (as defined in the Loan Agreement) in the initial amount of $4,900,000.00 (the “Facility No. 1 Loan”).

C.          Borrowers and Bank desire to amend the Loan Agreement to, among other matters (i) reflect the extension of the maturity date of the Facility No. 1 Loan, and (ii) increase the amount of the Facility No. 1 Commitment.

NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained and other good and valuable consideration, it is hereby agreed among Bank and Borrowers as follows:

Agreement

1.           Capitalized terms used but not defined herein shall have the respective meanings ascribed thereto in the Loan Agreement.

2.           Section 1.1 of the Loan Agreement (Line of Credit Amount) is hereby amended in its entirety to read as follows:

“1.1 Line of Credit Amount .

(a) During the availability period described below, the Bank will provide a line of credit to the Borrowers. The amount of the line of credit (the “Facility No. 1 Commitment”) is the lesser of (i) SIX MILLION THREE HUNDRED THOUSAND AND NO/100 DOLLARS ($6,300,000.00 ), or (ii) the Borrowing

 

Base as determined by Bank from time to time in accordance with this Agreement.

(b) This is a revolving line of credit. Subject to the terms hereof, during the availability period, the Borrowers may repay principal amounts and reborrow them.”

3.           Section 1.2 of the Loan Agreement (Availability Period) is hereby amended in its entirety to read as follows:

“1.2 Availability Period .

The line of credit is available between the date of this Agreement and November 30, 2016, or such earlier date as the availability may terminate as provided in this Agreement (the “Facility No. 1 Expiration Date”).”

4.           Section 1.5 of the Loan Agreement (Interest Rate) is hereby amended in its entirety to read as follows:

“1.5 Interest Rate .

(a) The interest rate is a rate per year equal to the lesser of (i) the LIBOR Daily Floating Rate, plus 2.50 percentage points, or (ii) the maximum lawful rate of interest permitted under applicable usury laws, now or hereafter enacted (the “Maximum Rate”).

(b) The LIBOR Daily Floating Rate is a fluctuating rate of interest which can change on each banking day. The rate will be adjusted on each banking day to equal the London Interbank Offered Rate (or a comparable or successor rate which is approved by the Bank) for U.S. Dollar deposits for delivery on the date in question for a one month term beginning on that date. The Bank will use the London Interbank Offered Rate as published by Bloomberg (or other commercially available source providing quotations of such rate as selected by the Bank from time to time) as determined at approximately 11:00 a.m. London time two (2) London Banking Days prior to the date in question, as adjusted from time to time in the Bank’s sole discretion for reserve requirements, deposit insurance assessment rates and other regulatory costs. If such rate is not available at such time for any reason, then the rate will be determined by such alternate method as reasonably selected by the Bank. A “London Banking Day” is a day on which banks in London are open for business and dealing in offshore dollars.”

5.           Pursuant to Section 1.3 of the Loan Agreement the amount of the Borrowing Base under the Loan Agreement is hereby increased from $4,900,000 to $6,300,000 until redetermined by Bank in accordance with Section 1.3 of the Loan Agreement.

6.           As a condition to the effectiveness of this Eighth Amendment, Borrowers shall pay to Bank a facility fee in the amount of $7,000.00.

2

7.           By their execution hereof, Borrowers hereby affirm and ratify all of the terms and provisions of the Loan Agreement as amended hereby, and all of the terms and provisions of the other loan documents executed in connection with the Loan Agreement.

8.           Neither the execution by Bank of this Eighth Amendment nor anything contained herein shall in any way be construed or operate as a waiver by Bank of any event of default under the Loan Agreement or the other loan documents executed in connection therewith (whether now existing or that may occur hereafter) or any of Bank's rights under the Loan Agreement or any of such other loan documents.

9.           Except as provided herein, all terms and provisions of the Loan Agreement shall remain unchanged.

10.         As an inducement to Bank to enter into this Eighth Amendment, Borrowers represent and warrant to Bank that (i) the representations and warranties contained in the Loan Agreement are true and correct as of the date hereof, (ii) Borrowers have not breached any of the covenants contained in the Loan Agreement or the other loan documents executed in connection therewith (except as may have been waived in writing by Bank), and (iii) no event of default now exists under the Loan Agreement, nor does there exist any condition or event which, with notice and/or lapse of time, would constitute such an event of default.

11.         THIS EIGHTH AMENDMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

EXECUTED effective as of the date first above written.

BORROWERS:
BANK:
           
MEXCO ENERGY CORPORATION
BANK OF AMERICA, N.A.
           
By:
/s/ Nicholas C. Taylor
 
By:
/s/ Ricky Temkin
 
 
Nicholas C. Taylor
   
Ricky Temkin
 
 
Chairman of the Board and Chief Executive Officer
   
Assistant Vice President
 
 
3

FORMAN ENERGY CORPORATION
     
By:
/s/ Nicholas C. Taylor
 
 
Nicholas C. Taylor
 
 
Chairman of the Board and Chief Executive Officer
 
     
SOUTHWEST TEXAS DISPOSAL CORPORATION
     
By:
/s/ Nicholas C. Taylor
 
 
Nicholas C. Taylor
 
 
Chairman of the Board and Chief Executive Officer
 
     
TBO OIL & GAS, LLC
     
By:
/s/ Nicholas C. Taylor
 
 
Nicholas C. Taylor
 
 
Chairman of the Board and Chief Executive Officer
 

4
 
EXHIBIT 10.11
 
NINTH AMENDMENT TO LOAN AGREEMENT

This Ninth Amendment to Loan Agreement (this “Ninth Amendment”) is entered into as of February 13, 2015, by and among MEXCO ENERGY CORPORATION, a Colorado corporation (“Mexco”), FORMAN ENERGY CORPORATION, a New York corporation (“Forman”), SOUTHWEST TEXAS DISPOSAL CORPORATION , a Texas corporation (“Southwest”) and TBO OIL & GAS, LLC , a Texas limited liability company (“TBO”, and together with Mexco, Forman and Southwest, collectively “Borrowers” or individually a “Borrower”) and BANK OF AMERICA, N.A. , a national banking association (“Bank”).

Recitals:

A.           Borrowers and Bank entered into that certain Loan Agreement dated December 31, 2008, as amended by First Amendment to Loan Agreement dated December 28, 2009, by Second Amendment to Loan Agreement dated March 1, 2010, by Third Amendment to Loan Agreement dated September 30, 2010, by Fourth Amendment to Loan Agreement dated October 22, 2010, by Fifth Amendment to Loan Agreement dated December 28, 2011, by Sixth Amendment to Loan Agreement dated October 22, 2012, by Seventh Amendment to Loan Agreement dated October 25, 2013 and by Eighth Amendment to Loan Agreement dated September 10, 2014 (the “Loan Agreement”).

B.           Pursuant to the terms of the Loan Agreement, Bank provided Borrowers a revolving line of credit loan with a Facility No. 1 Commitment (as defined in the Loan Agreement) in the initial amount of $6,300,000.00 (the “Facility No. 1 Loan”).

C.           Borrowers and Bank desire to amend the Loan Agreement to, among other matters, reflect the extension of the maturity date of the Facility No. 1 Loan.

NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained and other good and valuable consideration, it is hereby agreed among Bank and Borrowers as follows:

Agreement

1.           Capitalized terms used but not defined herein shall have the respective meanings ascribed thereto in the Loan Agreement.

2.           Section 1.2 of the Loan Agreement (Availability Period) is hereby amended in its entirety to read as follows:

“1.2        Availability Period .

The line of credit is available between the date of this Agreement and November 30, 2020, or such earlier date as the availability may terminate as provided in this Agreement (the “Facility No. 1 Expiration Date”).”

3.           Section 1.5(b) of the  Loan Agreement (Interest  Rate) is  hereby amended to include the following sentence at the end thereof:

 

“The LIBOR Daily Floating Rate shall in no event be less than zero.”

4.           The amount of the Borrowing Base and the Facility No. 1 Commitment under the Loan Agreement shall remain at $6,300,000 until redetermined by Bank in accordance with Section 1.3 of the Loan Agreement.

5.           By their execution hereof, Borrowers hereby affirm and ratify all of the terms and provisions of the Loan Agreement as amended hereby, and all of the terms and provisions of the other loan documents executed in connection with the Loan Agreement.

6.           Neither the execution by Bank of this Ninth Amendment nor anything contained herein shall in any way be construed or operate as a waiver by Bank of any event of default under the Loan Agreement or the other loan documents executed in connection therewith (whether now existing or that may occur hereafter) or any of Bank's rights under the Loan Agreement or any of such other loan documents.

7.           Except as provided herein, all terms and provisions of the Loan Agreement shall remain unchanged.

8.           As an inducement to Bank to enter into this Ninth Amendment, Borrowers represent and warrant to Bank that (i) the representations and warranties contained in the Loan Agreement are true and correct as of the date hereof, (ii) Borrowers have not breached any of the covenants contained in the Loan Agreement or the other loan documents executed in connection therewith (except as may have been waived in writing by Bank), and (iii) no event of default now exists under the Loan Agreement, nor does there exist any condition or event which, with notice and/or lapse of time, would constitute such an event of default.

9.           THIS NINTH AMENDMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

EXECUTED effective as of the date first above written.

BORROWERS:
BANK:
           
MEXCO ENERGY CORPORATION
BANK OF AMERICA, N.A.
           
By:
/s/ Nicholas C. Taylor
 
By:
/s/ Ricky Temkin
 
 
Nicholas C. Taylor
   
Ricky Temkin
 
 
Chairman of the Board and Chief Executive Officer
   
Vice President
 
 
2

FORMAN ENERGY CORPORATION
     
By:
/s/ Nicholas C. Taylor
 
 
Nicholas C. Taylor
 
 
Chairman of the Board and Chief Executive Officer
 
     
SOUTHWEST TEXAS DISPOSAL CORPORATION
     
By:
/s/ Nicholas C. Taylor
 
 
Nicholas C. Taylor
 
 
Chairman of the Board and Chief Executive Officer
 
     
TBO OIL & GAS, LLC
     
By:
/s/ Nicholas C. Taylor
 
 
Nicholas C. Taylor
 
 
Chairman of the Board and Chief Executive Officer
 

3

EXHIBIT 21.1

SUBSIDIARIES OF MEXCO ENERGY CORPORATION

1. Forman Energy Corporation, a New York corporation

2. Southwest Texas Disposal Corporation, a Texas corporation

3. TBO Oil & Gas, LLC, a Texas limited liability company

 
EXHIBIT 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have issued our report dated June 24, 2015, with respect to the consolidated financial statements included in the Annual Report of Mexco Energy Corporation on Form 10-K for the year ended March 31, 2015. We hereby consent to the incorporation by reference of said report in the Registration Statement of Mexco Energy Corporation on Form S-8 (File No. 333-165296).

/s/ GRANT THORNTON LLP

Wichita, Kansas
June 24, 2015
 
EXHIBIT 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

As independent engineering consultants, Joe C. Neal & Associates, hereby consents to the use of the name Joe C. Neal & Associates and references to Joe C. Neal & Associates and to the inclusion of and references to our report, or information contained therein, entitled “Evaluation of Oil and Gas Reserves, Mexco Energy Corporation Annual Report Effective Date: March 31, 2015” prepared for Mexco Energy Corporation in the Annual Report on Form 10-K of Mexco Energy Corporation for the filing dated on or about June 24, 2015.

/s/ Joe C. Neal & Associates
JOE C. NEAL & ASSOCIATES,
PETROLEUM AND ENVIRONMENTAL ENGINEERING CONSULTANTS

Midland, Texas
June 24, 2015

 
Exhibit 31.1

CERTIFICATION OF THE CHIEF EXECUTIVE OFFICER
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Nicholas C. Taylor, certify that:

1. I have reviewed this annual report on Form 10-K of Mexco Energy Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
 
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

June 24, 2015
/s/ Nicholas C. Taylor
 
 
Nicholas C. Taylor
 
 
Chief Executive Officer
 

 
Exhibit 31.2

CERTIFICATION OF THE CHIEF FINANCIAL OFFICER
PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Tamala L. McComic, certify that:

1. I have reviewed this annual report on Form 10-K of Mexco Energy Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
 
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

June 24, 2015
/s/ Tamala L. McComic
 
 
Tamala L. McComic
 
 
Chief Financial Officer, President, Treasurer, and Assistant Secretary

 
Exhibit 32.1

CERTIFICATION OF CEO AND CFO PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
 
In connection with the Annual Report of Mexco Energy Corporation (the “Company”) on Form 10-K for the year ending March 31, 2015, as filed with the SEC on the date hereof (the “Report”), we, Nicholas C. Taylor, Chief Executive Officer and Tamala L. McComic, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to our knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Dated: June 24, 2015
/s/ Nicholas C. Taylor
 
 
Chairman of the Board and
 
 
Chief Executive Officer
 
     
Dated: June 24, 2015
/s/ Tamala L. McComic
 
 
Chief Financial Officer, President,
 
 
Treasurer and Assistant Secretary
 


 
Exhibit 99.1

JOE C. NEAL & ASSOCIATES
PETROLEUM ENGINEERING CONSULTANTS
214 W. TEXAS AVE, SUITE 600
MIDLAND, TX 79701
432-683-4371   FAX:432-683-9279
E-Mail:   info@joecneal.com

June 23, 2015

Mexco Energy Corporation
Tammy McComic, President
214 W Texas Ave, Suite 1101
Midland, Texas 79701

Re: Evaluation of Oil and Gas Reserves of Mexco Energy Corporation effective March 31, 2015

Mrs. McComic,

In accordance with your request, we have estimated the extent and value of domestic proved crude oil, condensate and gas reserves owned by Mexco Energy Corporation as of March 31, 2015. The properties to which proved reserves are attributable are located in the states of Louisiana, Montana, New Mexico, North Dakota, Oklahoma and Texas with the majority of the value in Texas. The estimated reserves are based on a detailed study of properties owned by Mexco Energy Corporation. During this study, we consulted freely with the officers and employees of Mexco Energy Corporation and were given access to such records, geological and engineering reports, and other data as were desired for examination. In preparation of this report, we have relied, without independent verification, upon information furnished by Mexco Energy Corporation with respect to property interest owned by it, production from such properties, current costs of operation, current prices for production agreements relating to current and future operation and various other information and data which were accepted as represented. The results of our third party study, completed on June 8, 2015, are presented herein. The properties reviewed by Joe C. Neal & Associates represent 98% of the total net proved reserves of Mexco Energy Corporation.

The summary below includes Mexco Energy Corporation, South West Texas Disposal Corporation and TBO Oil & Gas, LLC, which are wholly owned subsidiaries of Mexco Energy Corporation. Six (6) Minor Net Income Streams have been evaluated in this report by projecting an oil and gas stream and applying an oil and gas price. The Mexco Energy Corporation Royalty Income Stream has been limited to twenty five (25) years lifetime. The Mexco Energy Corporation Minor and Royalty Income Streams were declined at six percent (6%) per year. The Foreman Income Stream was declined at the rate of eight percent (8%) annually for a period of twenty-five (25) years. Twelve (12) joint ventures have been projected as income streams because it was not economical to project all the properties on an individual basis. The twenty-two (22) other minor income properties have also been projected as income streams. Income streams have been converted to barrels of oil and MCF’S of gas based on their ratio of income. Where multiple gas wells with small interest exist, production has been summarized to reduce the cost of the evaluation. It was not considered necessary to make a field examination of the physical condition and operation of the properties in which Mexco Energy Corporation owns an interest.


We estimate the Net Proved Reserves, Future Net Revenue, and the Present Value of Future Net Revenue from the properties of Mexco Energy Corporation as of March 31, 2015 to be as follows:

Classification of Reserves
Oil and Condensate
(MBBL)
 
Gas
(MMCF)
 
Future Net
Revenue (M$)
 
Present Value
Discounted at 10 % (M$)
Proved Developed:
       
   Producing
261
3,471
21,831
12,010
   Non-Producing
23
1,114
4,457
2,839
 
284
4,585
26,288
14,849
         
Proved Undeveloped
376
1,704
19,764
8,851
         
Total Proved
660
6,289
46,052
23,700

The following table sets forth the changes in total Proved Reserves owned by Mexco Energy Corporation as of March 31, 2015.

 
Net Liquid
(MBBL)
Net Gas
(MMCF)
Total Proved Reserves Developed and Undeveloped:
     
   Beginning of Period March 31, 2014
502
 
6,259
   Revisions of Previous Estimates
(115)
 
(687)
   Beginning of Period as Revised
387
 
5,572
       
   Additions from Drilling and Purchase
42
 
766
   Extensions
261
 
320
   Sales of Minerals-in-Place
0
 
0
   Production
(30)
 
(369)
   End of Period March 31, 2015
660
 
6,289
       
Proved Developed Reserves:
     
   Beginning of Period March 31, 2014
294
 
4,081
   End of Period March 31, 2015
284
 
4,585

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s (“SEC”) Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Definitions of Oil and Gas Reserves” is included as an attachment to this report. Reserves for the producing properties were determined by extrapolation of the production decline trends, where applicable, analogy with similar offset wells, by volumetric calculations using basic reservoir parameters such as porosity, water saturation, net pay thickness, and estimated areal extent of the reservoir, or by material balance calculations. Reserves for the Proved Developed Non-Producing and Proved Undeveloped properties were determined by volumetric calculations and/or by analogy with offset wells.

Exhibit 1 is a table showing the plugging and abandonment costs for the working interest properties owned by Mexco Energy Corporation.

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward. Moreover, estimates of reserves may increase or decrease as a result of future operations, effects of regulation by governmental agencies or geopolitical risks. As a result, the estimates of oil and gas reserves have an intrinsic uncertainty. The reserves included in this report are therefore estimates only and should not be construed as being exact quantities. They may or may not be actually recovered, and if recovered, the revenues therefrom and the actual costs related thereto could be more or less than the estimated amounts.

The estimates of reserves presented herein were based upon a detailed study of the properties in which Mexco owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liability to restore and clean up damages, if any, caused by past operating practices.

Where wells did not have significant income to Mexco during 2015, wells have been combined into an income stream in their respective Joint Venture and evaluated as a single projection. This eliminated a significant amount of paper in the Report without detracting from the accuracy of the numbers.

COG Operating drilled sixteen (16) Dodd Federal Unit wells during 2014. They plan to drill an additional eighteen (18) unit producers and four (4) Injection wells in 2015. In addition COG Operating plans to drill one (1) horizontal well in 2015.

The MHM acquisition should add considerable reserves to Mexco. The minor income stream on the MHM acquisition contains over 1,700 properties. The monthly income on each property is small and does not justify the expenses to evaluate them individually. The remaining properties have been evaluated individually.

The King/Barnett, Trinity Bay and Walker are acquisitions that were made in 2014. Also the Hybrid-Durrell properties were acquired in 2014. These properties had some special agreement which made them very attractive. Some of the operating expenses and capital drilling costs were suspended. This made the acquisition very attractive. Since the acquisition, three (3) wells have been drilled. The wells have not been fractured as of this report, but plans are in progress to treat them. Drilling continues on the Limpia Lease in Andrews County. The Forman project continues to drill wells in which Mexco has some interests.

To estimate economically recoverable oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be demonstrated to be economically producible based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined as of the effective date of the report. Mexco has informed us that they have furnished us all of the accounts, records, geological and engineering data, reports and other data required for this investigation. In preparing our forecast of future production and income, we have relied upon data furnished by Mexco with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, geological structural and isopach maps, well logs, core analyses, and pressure measurements. Joe C. Neal & Associates reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data supplied by Mexco.

The value estimated in this report is based on the assumptions that the properties are not negatively affected by the existence of hazardous substances or detrimental environmental conditions. We are experts in the identification of hazardous substances or detrimental environmental conditions, but have not been asked to perform an environmental study. It is possible that tests and inspections conducted by a qualified hazardous substance and environmental expert could reveal the existence of hazardous material and environmental conditions on or around the properties that would negatively affect the properties' values.


Property identification, expense and revenue interests, actual product prices, and operating expenses were provided by Mexco Energy Corporation. This data was not verified by inspection of internal records and files, nor was a physical inspection made of the properties. Information regarding prices and the particular pricing categories under current governmental regulations was supplied by Mexco Energy Corporation.

Net oil and gas reserves are estimated quantities of crude oil, natural gas, and natural gas liquids attributed to the revenue interests of Mexco Energy Corporation. Net income to the interests of Mexco Energy Corporation is the future net revenue after deduction of state and county taxes, operating expenses, and investments, if applicable. The resulting net income is before federal income tax and does not consider any encumbrances against the properties, if such exist. Minor variations in composite columns totals result from computer rounding. Values of the estimated net proved reserves are expressed in terms of future net revenue and present value of future net revenue. Future net revenues are calculated by deducting estimated operating expenses, capital costs, and severance and ad Valorem taxes from the future gross revenue.

Present value of future net revenue is calculated by discounting the future net revenue at the rate of ten percent (10%) per annum compounded monthly over the expected period of realization. The present value set forth in this report does not necessarily represent the fair market value of the evaluated interests.

A summary projection of the estimated future net revenue and present value of future net revenue as of March 31, 2015 is as follows:
 
Year
  
Proved Developed
Future Net Revenue $
  
Discounted at 10% $
         
2016
 
2,722,180
 
2,594,230
2017
 
2,983,670
 
2,591,040
2018
 
2,574,890
 
2,032,730
Remaining
 
18,006,910
 
7,631,470
         
Total
 
26,287,650
 
14,849,470

The future net revenue set forth above reflects estimated capital expenditures in the amount of $359,260.00 necessary to develop those reserves classified as Proved Developed Producing and Proved Developed Non-Producing. Proved Undeveloped net revenue reflects estimated capital costs of $6,258,140.00 to drill and complete those wells and install water floods.

Estimated reserves and future net income amounts presented in this report, as of March 31, 2015, are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the twelve (12) month period prior to the ending date of the period covered in this report (determined as unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements as required by the SEC regulations). The benchmark price of $79.21 per barrel has been adjusted by lease for gravity, transportation fees and regional price differentials to an average of $74.84. Gas prices per thousand cubic feet (MCF) are based on a benchmark price of $3.88 per MCF and have been adjusted by lease for BTU content, transportation fees and regional price differentials to an average of $3.595. The oil and gas prices were held constant for the economic life of the properties as specified by the SEC. Oil volumes shown herein are expressed in barrels, which are equivalent to forty-two (42) United States gallons. Gas volumes are expressed at standard conditions of sixty degrees (60°) Fahrenheit and at the standard pressure base of the respective area in which the reserves are located.


Operating expenses including direct and indirect overhead expenses were held constant for the life of the properties. Severance and ad valorem taxes were deducted in the lease reserves and economics projections at the standard state rates.

Joe C. Neal & Associates is an Independent Petroleum and Environmental Engineering Consulting Firm that has been providing Petroleum Consulting Services throughout the world for forty (40) years. Joe C. Neal & Associates does not have any financial interest, including stock ownership in Mexco. Our fees were not contingent on the results of our evaluation. Joe C. Neal & Associates has used all procedures and methods that it considered necessary to prepare this report. The technical persons responsible for preparing the reserve estimates presented herein meet the requirements regarding qualification, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

This report is solely for the information of and assistance to Mexco Energy Corporation for their use in SEC filings. It is not to be used, circulated, quoted, or otherwise referred to for any purpose without the express written consent of the undersigned except as required by law. Data utilized in this report will be maintained in our files and is available for your use.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the SEC Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion, the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

It has been our privilege to serve you by preparing this evaluation.

 
Yours very truly,
 
      
 
Joe C. Neal & Associates
 
Licensed Professional Engineer
 
Registration Number: 23238
 
Registered Professional Engineering Firm
 
Registration Number: F-001308
 

DEFINITIONS OF OIL AND GAS RESERVES
17 CFR § 210.4-10 Federal Register Dated December 31, 2008/Filed January 13, 2009

Developed oil and gas reserves

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Proved oil and gas reserves 1

Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.


(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including government entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-date-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

1 Joe C. Neal & Associates separates proved developed reserves into proved developed producing and proved developed nonproducing reserves. This is to identify proved developed producing reserves as those to be recovered from actively producing wells; proved developed nonproducing reserves as those to be recovered from wells or intervals within wells, which are completed but shut in waiting on equipment or pipeline connections, or wells where a relatively minor expenditure is required for recompletion to another zone.