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, 2019

 

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

 

Commission File No. 1-31785

 

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.)

 

415 W. Wall, Suite 475   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, 2018 (the last business day of the Registrant’s most recently completed second quarter) was $4,717,449 based on Mexco Energy Corporation’s closing common stock price of $5.60 per share on that date as reported by the NYSE American.

 

There were 2,040,166 shares of the registrant’s common stock outstanding as of June 21, 2019.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

Portions of the Registrant’s Proxy Statement relating to the 2019 Annual Meeting of Shareholders to be held on September 12, 2019, 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, 2019, the end of the fiscal year covered by this report.

 

 

 

 
 

 

TABLE OF CONTENTS

 

PART I  
     
Item 1. Business  3
     
Item 1A. Risk Factors 9
     
Item 1B. Unresolved Staff Comments 14
     
Item 2. Properties 14
     
Item 3. Legal Proceedings 18
     
Item 4. Mine Safety Disclosures 18
     
PART II  
     
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 18
     
Item 6. Selected Consolidated Financial Data 19
     
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 19
   
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 26
     
Item 8. Financial Statements and Supplementary Data 27
     
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures  27
   
Item 9A. Controls and Procedures 27
     
Item 9B. Other Information 27
     
PART III  
     
Item 10. Directors, Executive Officers and Corporate Governance 27
     
Item 11. Executive Compensation 28
     
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters  28
   
Item 13. Certain Relationships and Related Transactions, and Director Independence 28
     
Item 14. Principal Accounting Fees and Services 28
     
PART IV  
     
Item 15. Exhibits and Financial Statement Schedules  28
     
  Signatures 29
     
  Glossary of Abbreviations and Terms 30

 

2
 

 

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 crude oil and natural gas 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, 2019 were approximately 1.937 million barrels of oil equivalent (“MMBOE”) of which 54% was oil and natural gas liquids and 46% was natural gas, and our estimated present value of proved reserves was approximately $22 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 2019, we added proved reserves of 275 thousand BOE (“MBOE”) through extensions and discoveries and subtracted 365 MBOE through downward revisions of previous estimates. Such downward revisions are primarily the result of the restructuring of our plans for development of our operated property in Ector County, Texas due to market conditions partially offset by pricing and successful development in the Delaware and Midland Basins.

 

Nicholas C. Taylor beneficially owns approximately 47% 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.

 

3
 

 

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 2020.

 

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

 

From 1983 to 2019, Mexco Energy Corporation made approximately 80 acquisitions of producing oil and 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, primarily in Texas.

 

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). The purchase included eight wells producing oil on 20-acre spacing at approximately 3,600 foot depth on 190 acres in Pecos County, TX.

 

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.

 

4
 

 

Industry Environment and Outlook

 

The challenging commodity price environment continued in fiscal 2019. Commodity prices improved but continue to be volatile. In light of these challenges facing our industry and in response to the continued challenging environment, our primary business strategies for fiscal 2020 will continue to include: (1) optimizing cash flows through operating efficiencies and cost reductions, (2) divesting of non-core assets, and (3) working to balance capital spending with cash flows to minimize borrowings, reduce debt and maintain ample liquidity.

 

See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for discussion of our fiscal 2019 operating results and potential impact on fiscal 2020 operating results due to commodity price changes.

 

Oil and Gas Operations

 

As of March 31, 2019, oil constituted approximately 54% of our total proved reserves and approximately 72% of our revenues for fiscal 2019. Revenues from oil and gas royalty interests accounted for approximately 27% of our revenues for fiscal 2019.

 

There are two primary areas in which the Company is focused, 1) the Delaware Basin located in the Western portion of the Permian Basin including Lea and Eddy Counties, New Mexico and Loving County, Texas and 2) the Midland Basin located in the Eastern portion of the Permian Basin including Reagan, Upton, Midland, Martin, Howard and Glasscock Counties, Texas. The Permian Basin in total accounts for 70% of our discounted future net cash flows from proved reserves and 78% of our net revenues.

 

The Delaware Basin properties, encompassing 29,625 gross acres, 294 net acres, 488 gross producing wells and 5 net wells account for approximately 34% of our discounted future net cash flows from proved reserves as of March 31, 2019. Of these discounted future net cash flows from proved reserves, approximately 10% are attributable to proven undeveloped reserves which will be developed through new drilling. For fiscal 2019, these properties accounted for 45% of our gross revenues and 56% of our net revenues.

 

The Midland Basin properties, encompassing 99,183 gross acres, 298 net acres, 1,000 gross producing wells and 3 net wells account for approximately 36% of our discounted future net cash flows from proved reserves as of March 31, 2019. Of these discounted future net cash flows from proved reserves, approximately 29% are attributable to proven undeveloped reserves which will be developed through new drilling. For fiscal 2019, these properties accounted for 20% of our gross revenues and 25% of our net revenues.

 

Gomez Gas Field properties, encompassing 13,058 gross acres, 72 net acres, 27 gross wells and .13 net wells in Pecos County, Texas, account for approximately 10% of our discounted future net cash flows from proved reserves as of March 31, 2019. Of these discounted future net cash flows from proved reserves, approximately 9% are attributable to proven undeveloped reserves which will be developed through new drilling in the horizontal Wolfcamp. For fiscal 2019, these properties accounted for 2% of our gross revenues and 2% of our net revenues. All of these properties, except for one, are royalty interests.

 

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

 

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

 

We own partial interests in approximately 6,100 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. We own 100% working interests in and operate 3 producing wells in Ector County, Texas. Additional information concerning these properties and our oil and gas reserves is provided below.

 

5
 

 

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

 

Year   Oil(Bbls)     Gas (Mcf)  
2019     35,359       295,133  
2018     34,743       318,774  
2017     34,689       356,268  
2016     38,930       407,939  
2015     29,557       369,034  

 

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 that amounted to 10% or more of revenues as follows for the year ended March 31:

 

    2019     2018  
Company A     42 %     37 %

 

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

 

Environmental Regulation

 

General. Activities on the Company properties are subject to existing stringent and complex federal, state and local laws (including case law) and regulations governing health, safety, environmental quality and pollution control. Failure to comply with these laws, rules and regulations, however, may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all of the operations on the Company properties.

 

6
 

 

Cleanup. Under certain environmental laws and regulations, the operators of the Company properties could be subject to strict, joint and several liability for the removal or remediation of property contamination, whether at a drill site or a waste disposal facility, even when the operators did not cause the contamination or their activities were in compliance with all applicable laws at the time the actions were taken. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund” law, for example, imposes liability, regardless of fault or the legality of the original conduct, on certain classes of persons for releases into the environment of a “hazardous substance.” Liable persons may include the current or previous owner and operator of a site where a hazardous substance has been disposed and persons who arranged for the disposal of a hazardous substance at a site. Under CERCLA and similar statutes, government authorities or private parties may take actions in response to threats to the public health or the environment or sue responsible persons for the associated costs. In the course of operations, the working interest owner and/or the operator of the Company properties may have generated and may generate materials that could trigger cleanup liabilities. In addition, the Company properties have produced oil and/or natural gas for many years, and previous operators may have disposed or released hydrocarbons, wastes or hazardous substances at the Company properties. The operator of the Company properties or the working interest owners may be responsible for all or part of the costs to clean up any such contamination. Although the Company is not the operator of such properties, its ownership of the properties could cause it to be responsible for all or part of such costs to the extent CERCLA or any similar statute imposes responsibility on such parties as “owners.”

 

Climate Change. In December 2009, the EPA determined that emissions of carbon dioxide, methane and certain other greenhouse gases (“GHGs”) endanger public health and the environment because emissions of such gases are contributing to warming of the Earth’s atmosphere and other climatic changes. Based on those findings, the EPA adopted and implemented various regulations to restrict emissions of GHGs under existing provisions of the Clean Air Act (“CAA”). Among other things, these covered reductions in GHG emissions from motor vehicles, permits for certain large stationary sources of GHGs, monitoring and annual reporting of GHG emissions from specified GHG emission sources, including oil and natural gas exploration and production operations, and power plant performance standards that were intended to lead to the creation of additional state GHG control programs. On August 3, 2015, the EPA issued new regulations limiting GHG emissions. Under these regulations, nationwide carbon dioxide emissions would be reduced by approximately 30 percent from 2005 levels by 2030 with a flexible interim goal. Several industry groups and states challenged the rule. On February 9, 2016, the U.S. Supreme Court stayed the implementation of this rule pending judicial review. On March 28, 2017, President Trump signed an Executive Order directing the EPA to review the regulations, and on April 4, 2017, the EPA announced that it was reviewing the 2015 carbon dioxide regulations. On April 28, 2017, the U.S. Court of Appeals for the District of Columbia stayed the litigation pending the current administration’s review. That stay was extended for another 60 days on August 8, 2017. On October 10, 2017, the EPA initiated the formal rulemaking process to repeal the regulations. In August 2018, the EPA proposed the Affordable Clean Energy rule as a replacement to the 2015 regulations. The EPA’s proposals are subject to public comment and likely legal challenge, and as such, we cannot predict at this time what impact the rulemaking will have on the demand for oil and natural gas production and our operations.

 

Various state governments and regional organizations comprising state governments already have enacted legislation and promulgated rules restricting GHG emissions or promoting the use of renewable energy, and additional such measures are frequently under consideration. Although it is not possible at this time to estimate how potential future requirements addressing GHG emissions would impact operations on the Company properties and revenue, either directly or indirectly, any future federal, state or local laws or implementing regulations that may be adopted to address GHG emissions could require the operators of our properties to incur new or increased costs to obtain permits, operate and maintain equipment and facilities, install new emission controls, acquire allowances to authorize GHG emissions, pay taxes related to GHG emissions or administer a GHG emissions program. Regulation of GHGs could also result in a reduction in demand for and production of oil and natural gas. Additionally, to the extent that unfavorable weather conditions are exacerbated by global climate change or otherwise, the Company properties may be adversely affected to a greater degree than previously experienced.

 

We did not incur any material capital expenditures for remediation or pollution control activities for the year ended March 31, 2019. 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 2020.

 

7
 

 

Title to 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.

 

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.

 

Substantially all of our properties are currently mortgaged under a deed of trust to secure funding through a 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, 2019.

 

Name   Age   Position
Nicholas C. Taylor   81   Chairman and Chief Executive Officer
Tamala L. McComic   50   President, Chief Financial Officer, Treasurer, and Assistant Secretary
Donna Gail Yanko   74   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 served as Treasurer and Assistant Secretary of the Company.

 

Donna Gail Yanko was appointed to the position of Vice President of the Company in 1990. She has also served as Corporate Secretary since 1992 and from 1986 to 1992 was Assistant Secretary. From 1986 to 2015, on a part-time basis, she 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.

 

8
 

 

Employees

 

As of March 31, 2019, we had two full-time and three part-time employees. We believe that relations with these employees are generally satisfactory. From time to time, we utilize the services of independent geological, land and engineering consultants on a limited basis and expect to continue to do so in the future. We also utilize the services of independent contractors to perform well drilling and production operations, including pumping, maintenance, inspection and testing.

 

Office Facilities

 

At March 31, 2019, our principal offices are located at 415 W. Wall, Suite 475, Midland, Texas 79701 and our telephone number is (432) 682-1119. We believe our new facilities are adequate for our current operations and future needs.

 

Access to Company Reports

 

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

 

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

 

ITEM 1A. RISK FACTORS

 

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

 

RISKS RELATED TO OUR BUSINESS AND INDUSTRY

 

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

 

Prices for oil and natural gas fluctuate widely. We cannot predict future oil and natural gas prices with any certainty. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile. Factors that can cause price fluctuations include the level of global demand for petroleum products; foreign supply and pricing of oil and gas; the 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.

 

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 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.

 

9
 

 

Oil and natural gas prices do not necessarily fluctuate in direct relationship to each other. Lower prices or lack of storage may have an adverse affect on our financial condition due to reduction of our revenues, operating income and cash flows; curtailment or shut-in of our production due to lack of transportation or storage capacity; cause certain properties in our portfolio to become economically unviable; and, limit our financial condition, liquidity, and/or ability to finance planned capital expenditures and operations.

 

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. We incurred impairment charges during fiscal 2016 and may incur additional impairment charges in the future, particularly if commodity prices decline, which could have a material adverse effect on our results of operations for the periods in which such charges are taken. There were no ceiling test impairments on our oil and gas properties during fiscal 2019 and 2018.

 

We must replace reserves we produce.

 

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

 

Approximately 48% and 49% of our total estimated net proved reserves at March 31, 2019 and 2018, 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.

 

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.

 

10
 

 

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 2019, differentials averaged $5.81 per Bbl of oil and $0.30 per Mcf of gas. Increases in the differential between the benchmark prices for oil and gas and the wellhead price we receive could significantly reduce our revenues and our cash flow from operations.

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

We must make capital expenditures to develop our existing reserves and to discover new reserves. Historically, we have used our cash flow from operations and borrowings under our credit facility to fund our capital expenditures, however, lower oil and gas prices may prevent these options. Volatility in oil and gas prices, the timing of our drilling programs and drilling results will affect our cash flow from operations. Lower prices and/or lower production will also decrease revenues and cash flow, thus reducing the amount of financial resources available to meet our capital requirements, including reducing the amount available to pursue our drilling opportunities.

 

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.

 

11
 

 

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.

 

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

 

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

 

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

 

We 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.

 

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.

 

Certain U.S. federal income tax deductions currently available with respect to crude oil and natural gas exploration and development may be eliminated as a result of proposed legislation.

 

In December 2017, Congress enacted the budget reconciliation act commonly referred to as the Tax Cuts and Jobs Act (“TCJA”). The law made significant changes to U.S. federal income tax laws, including reducing the corporate income tax rate from 35 percent to 21 percent, repealing the corporate alternative minimum tax (“AMT”), partially limiting the deductibility of interest expense and net operating losses (“NOLs”), eliminating the deduction for certain U.S. production activities and allowing the immediate deduction of certain new investments in lieu of depreciation expense over time.

 

12
 

 

Legislation previously has been proposed that would, if enacted into law, make significant changes to U. S. federal income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to crude oil and natural gas exploration and production companies. These changes include, but are not limited to: (1) the repeal of the percentage depletion allowance for crude oil and natural gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for certain U.S. domestic production activities, and (4) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of this type of legislation or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to crude oil and natural gas exploration and development, and any such change could have an adverse effect on our financial position, results of operations and cash flows.

 

Additionally, future legislation could be enacted that increases the taxes or fees imposed on oil and natural gas extraction. Any such legislation could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our oil and natural gas.

 

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.

 

We may be affected by one substantial shareholder.

 

Nicholas C. Taylor beneficially owns approximately 47% of the outstanding shares of our common stock. Mr. Taylor is also our Chairman of the Board and Chief Executive Officer. As a result, Mr. Taylor has significant influence in matters voted on by our shareholders, including the election of our Board members. Mr. Taylor participates in all facets of our business and has a significant impact on both our business strategy and daily operations. The retirement, incapacity or death of Mr. Taylor, or any change in the power to vote shares beneficially owned by Mr. Taylor, could result in negative market or industry perception and could have an adverse effect on our business.

 

RISKS RELATED TO OUR COMMON STOCK

 

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

 

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

 

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

 

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

 

13
 

 

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, 2019, our executive officers and directors beneficially owned approximately 52% 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 American. The market price of our common stock has and could continue to experience volatility due to reasons unrelated to our operating performance. These reasons include: supply and demand for natural gas and oil; political conditions in oil and natural gas producing regions; demand for our common stock and limited trading volume; investor perception of our industry; fluctuations in commodity prices; variations in our results of operations; legislative or regulatory changes; general trends in the oil and natural gas industry; market conditions and analysts’ estimates; and, other events in the oil and gas industry.

 

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

 

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

 

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

 

ITEM 1B. UNRESOLVED STAFF COMMENTS

 

None.

 

ITEM 2. PROPERTIES

 

Our properties consist primarily of oil and gas wells and our ownership in leasehold acreage, both developed and undeveloped. As of March 31, 2019, we had interests in approximately 6,100 gross (24 net) oil and gas wells and owned leasehold mineral and royalty interests in approximately 553,000 gross (3,712 net) acres.

 

Oil and Natural Gas Reserves

 

In accordance with current SEC rules, the average prices used in computing reserves at March 31, 2019 were $53.71 per bbl of oil and $50.63 in 2018, an increase of 6%, and $2.77 per mcf of natural gas and $3.03 in 2018, a decrease of 9%, 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 2019. The benchmark price of $59.52 per bbl of oil at March 31, 2019 versus $49.94 at March 31, 2018, was adjusted by lease for gravity, transportation fees and regional price differentials and did not give effect to derivative transactions. The benchmark price of $3.07 per mcf of natural gas at March 31, 2019 versus $3.00 at March 31, 2018, was adjusted by lease for BTU content, transportation fees and regional price differentials.

 

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.

 

14
 

 

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

 

The engineering report with respect to Mexco’s estimates of proved oil and gas reserves as of March 31, 2019 and 2018 is based on evaluations prepared by Russell K. Hall and Associates, Inc. Environmental Engineering Consultants, based in Midland, Texas (“Hall and Associates”), a summary of which is filed as Exhibit 99.1 to this annual report.

 

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

 

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

 

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

 

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

 

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PROVED RESERVES

 

    March 31,  
    2019     2018  
Oil (Bbls):                
Proved developed – Producing     341,890       379,390  
Proved developed – Non-producing     34,710       11,350  
Proved undeveloped     663,860       805,980  
Total     1,040,460       1,196,720  
                 
Natural gas (Mcf):                
Proved developed – Producing     3,420,730       3,774,490  
Proved developed – Non-producing     402,710       328,900  
Proved undeveloped     1,557,250       1,383,120  
Total     5,380,690       5,486,510  
                 
Total net proved reserves (BOE)     1,937,240       2,111,140  
                 
PV-10 Value (1)   $ 22,317,300     $ 22,001,900  
Present value of future income tax discounted at 10%     (3,065,100 )     (3,125,900 )
Standardized measure of discounted future net cash flows (2)   $ 19,252,200     $ 18,876,000  
                 
Prices used in Calculating Reserves: (3)                
Natural gas (per Mcf)   $ 2.77     $ 3.03  
Oil (per Bbl)   $ 53.71     $ 50.63  

 

  (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 first day of the 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.

 

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, 2019, and no major discovery is believed to have caused a significant change in our estimates of proved reserves since that date.

 

During the fiscal year ending March 31, 2019, we participated in the development of 26 wells converting reserves of approximately 64,000 BOE from proved undeveloped to proved developed – producing with capital cost of approximately $828,000.

 

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

 

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,  
    2019     2018  
    Gross     Net     Gross     Net  
Exploratory Wells                                
Nonproductive – Vertical     1       .02       -       -  
Total     1       .02       -       -  
                                 
Development Wells                                
Productive - Horizontal     43       .12       23       .10  
Productive - Vertical     3       .01       2       .01  
Nonproductive - Vertical     1       -       -       -  
Total     47       .14       25       .11  

 

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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. The net numbers above represent Mexco’s working interest in the gross wells.

 

In addition to the working interests mentioned above, other operators drilled 113 gross wells (.08 net wells) on company-owned minerals and royalties at no expense to the Company.

 

Productive Wells and Acreage

 

Productive wells consist of producing wells and wells capable of production, including gas wells awaiting pipeline connections. Wells that are completed in more than one producing zone are counted as one well. As of March 31, 2019, we held an interest in approximately 6,100 gross (24 net) productive wells, including approximately 4,900 wells in which we held an overriding or royalty interest and 1,200 wells in which we held a working interest. Mexco operates 3 of its working interest producing wells.

 

A gross acre is an acre in which an interest is owned. A net acre is deemed to exist when the sum of fractional ownership interests in gross acres equals one. The number of net acres is the sum of the fractional interests owned in gross acres. The following table sets forth the approximate developed acreage in which we held a leasehold mineral or other interest as of March 31, 2019:

 

    Developed Acres  
    Gross     Net  
Texas     353,300       1,949  
Oklahoma     84,400       1,334  
New Mexico     30,000       280  
Louisiana     37,700       59  
North Dakota     22,500       29  
Kansas     10,600       41  
Montana     6,100       2  
Wyoming     3,800       5  
Arkansas     1,000       5  
Mississippi     1,600       3  
Alabama     700       3  
Colorado     1,100       1  
Virginia     100       1  
Total     552,900       3,712  

 

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,  
    2019     2018  
Oil (a):                
Production (Bbls)     35,359       34,743  
Revenue   $ 1,921,391     $ 1,789,736  
Average Bbls per day (d)     97       95  
Average sales price per Bbl   $ 54.34     $ 51.51  
Gas (b):                
Production (Mcf)     295,133       318,774  
Revenue   $ 726,486     $ 860,496  
Average Mcf per day (d)     809       873  
Average sales price per Mcf   $ 2.46     $ 2.70  
Production cost:                
Production cost   $ 748,038     $ 870,806  
Production and ad valorem taxes   $ 188,362     $ 199,641  
Total BOE (c)     84,548       87,872  
Production cost per BOE   $ 8.85     $ 9.91  
Production cost per sales dollar   $ 0.28     $ 0.33  
Total oil and gas revenue   $ 2,647,877     $ 2,650,232  

 

  (a) Includes condensate.
  (b) Includes natural gas products.
  (c) Natural gas production is converted to oil production using a ratio of six Mcf to one Bbl of oil.
  (d) Calculated on a 365 day year.

 

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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.

 

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

 

      High     Low  
2019:   April - June 2018   $ 6.94     $ 3.07  
    July - September 2018     14.49       4.85  
    October - December 2018     6.40       2.70  
    January - March 2019     5.36       2.85  
                     
2018:   April - June 2017   $ 4.95     $ 3.72  
    July - September 2017     5.85       4.40  
    October - December 2017     4.65       3.82  
    January - March 2018     5.04       3.06  

 

On June 18, 2019, the closing sales price of our common stock on the NYSE American was $3.44 per share.

 

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Stockholders

 

As of March 31, 2019, we had 2,107,166 shares issued and 868 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.

 

Securities Authorized for Issuance Under Compensation Plans

 

The following table includes certain information about our Employee Incentive Stock Plan as of March 31, 2019, 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       185,700     $ 6.18       10,000  
Total     200,000       185,700     $ 6.18       10,000  

 

Issuer Repurchases

 

In September 2018, 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.

 

There were no shares of our common stock repurchased for the treasury account during the fiscal years ended March 31, 2019 and 2018.

 

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, sales of non-core properties and issuance of common stock. Our primary financial resource is our base of oil and gas reserves. We have pledged 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.

 

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

 

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

 

For the year ended March 31, 2019, cash flow from operations was $1,012,328, a 130% increase when compared to the corresponding period of fiscal 2018. Net cash from investing activities of $655,395 was used for additions to oil and gas properties, cash of $700,000 was used to pay off the line of credit, cash of $39,532 was used for the issuance of our new loan agreement and cash of $18,241 was received from proceeds from the exercise of employee stock options. Accordingly, net cash decreased $364,358, leaving cash and cash equivalents on hand of $128,252 as of March 31, 2019.

 

We had working capital of $395,895 as of March 31, 2019 compared to working capital of $925,618 as of March 31, 2018, a decrease of $529,723 for the reasons set forth below.

 

Oil and Natural Gas Property Development

 

In addition to 113 gross wells (.08 net wells) drilled by other operators on Mexco’s royalty interests, the Company participated in the drilling and completion of 43 horizontal wells and 5 vertical wells at a cost of approximately $900,000 for the fiscal year ending March 31, 2019. Of these horizontal wells, 36 are in the Delaware Basin located in the western portion of the Permian Basin in Eddy and Lea Counties, New Mexico and 7 are located in Grady County, Oklahoma. The operators of these wells include Apache Corporation, Concho Resources, Inc., Marathon Oil Company, Mewbourne Oil Company, XTO Energy, Inc. and others.

 

Five of these wells were completed in September 2018 and tested at an average rate of 1,553 barrels of oil; 2,075 barrels of water; and 2,067,000 cubic feet of gas per day, or 1,899 barrels of oil equivalent per day. These wells are in the Upper Wolfcamp formation located in Lea County, New Mexico. Mexco’s working interest in these wells is .6%.

 

Two of these wells are in the Yeso/Paddock formations of the Dodd Federal Unit in the Grayburg San Andres Jackson Field of Eddy County, New Mexico and operated by Concho Resources, Inc. These wells began producing in December 2018 at an initial average rate of 337 barrels of oil; 1,914 barrels of water; and 160,000 cubic feet of gas per well per day, or 364 barrels of oil equivalent per day. Mexco’s working interest in this unit is .1848%.

 

Four of these wells began producing in February 2019 at an initial average rate of 1,445 barrels of oil; 3,994 barrels of water; and 4,500,000 cubic feet of gas per day, or 2,195 barrels of oil equivalent per day. These wells, operated by Marathon Oil Company, are in the Wolfcamp formation located in Lea County, New Mexico. Mexco’s working interest in these wells is .03%.

 

In addition, two wells were completed in March 2019 and tested at an average rate of 1,934 barrels of oil; 1,950 barrels of water; and 2,153,000 cubic feet of gas per day, or 2,259 barrels of oil equivalent per day. These wells are in the Bone Spring formation located in Lea County, New Mexico. Mexco’s working interest in these wells is .5%.

 

There were eleven additional wells that began producing throughout the fiscal year at an initial average rate of 470 barrels of oil; 2,148 barrels of water; and 1,431,000 cubic feet of gas per day, or 708 barrels of oil equivalent per day. Three wells, operated by XTO Energy, Inc., are in the Bone Spring formation located in Eddy County, New Mexico. And the other eight wells, operated by Marathon Oil Company and Mewbourne Oil Company, are in the Purple Sage formation located in Lea County, New Mexico. Mexco’s working interest in these various wells range from .008% to .031%.

 

The remaining 19 of the 48 wells have been drilled and are in various stages of completion and testing.

 

During fiscal 2019, the Company continued its policy of selling non-core assets in order to concentrate on the development of more profitable assets and to pay down debt. The Company received approximately $33,000 in cash from a sale of joint venture leasehold acreage and marginal producing working interest wells in North Dakota and Montana; approximately $72,000 in cash from a sale of joint venture leasehold marginal producing working interests in Ward and Winkler Counties in Texas; and, approximately $51,000 in cash from the sale of additional leasehold acreage in Eddy County, New Mexico.

 

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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 non-core properties.

 

Crude oil and natural gas prices generally remained volatile during the last year. The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. For example in the last twelve months, the NYMEX West Texas Intermediate (“WTI”) posted price for crude oil has ranged from a low of $39.25 per bbl in December 2018 to a high of $73.00 per bbl in October 2018. The Henry Hub Spot Market Price (“Henry Hub”) for natural gas has ranged from a low of $2.54 per MMBtu in February 2019 to a high of $4.70 per MMBtu in November 2018.

 

On March 31, 2019 the WTI posted price for crude oil was $56.50 per bbl and the Henry Hub spot price for natural gas was $2.73 per MMBtu. See Results of Operations below for realized prices.

 

Results of Operations

 

Fiscal 2019 Compared to Fiscal 2018

 

We had a net loss of $12,946 for the year ended March 31, 2019 compared to a net loss of $321,489 for the year ended March 31, 2018. This is primarily the result of a decrease in operating expenses and interest expense as further explained below.

 

Oil and gas sales. Revenue from oil and gas sales was $2,647,877 for the year ended March 31, 2019, a .1% decrease from $2,650,232 for the year ended March 31, 2018. This resulted from an increase in oil price and production partially offset by a decrease in gas price and production. The following table sets forth our oil and gas revenues, production quantities and average prices received during the fiscal years ended March 31:

 

    2019     2018     % Difference  
Oil:                        
Revenue   $ 1,921,391     $ 1,789,736       7.4 %
Volume (bbls)     35,357       34,743       1.8 %
Average Price (per bbl)   $ 54.34     $ 51.51       5.5 %
                         
Gas:                        
Revenue   $ 726,486     $ 860,496       (15.6 %)
Volume (mcf)     295,133       318,774       (7.4 %)
Average Price (per mcf)   $ 2.46     $ 2.70       (8.9 %)

 

Production and exploration. Production costs were $936,400 in fiscal 2019, a 13% decrease from $1,070,447 in fiscal 2018. This was primarily the result of a decrease in lease operating expenses due to the sale of our marginal operated properties in Loving County, Texas.

 

Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expense was $802,425 in fiscal 2019, a 9% decrease from $880,419 in fiscal 2018. This was primarily due to a decrease in gas production and a decrease in the full cost pool as a result of a decrease in future development costs partially offset by a decrease in oil and gas reserves.

 

General and administrative expenses. General and administrative expenses were $911,927 for the year ended March 31, 2019, a 5% decrease from $955,147 for the year ended March 31, 2018. This was primarily due to a decrease in accounting fees partially offset by an increase in rent, engineering services and legal fees.

 

Interest expense. Interest expense was $21,931 in fiscal 2019, a 76% decrease from $89,537 in fiscal 2018, due to a decrease in borrowings partially offset by an increase in interest rate.

 

Income taxes. There was no income tax for fiscal 2019 or fiscal 2018. The effective tax rate for fiscal 2019 and fiscal 2018 was 0%. We are in a net deferred tax asset position and believe it is more likely than not that these deferred tax assets will not be realized.

 

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Fiscal 2018 Compared to Fiscal 2017

 

We had a net loss of $321,489 for the year ended March 31, 2018 compared to a net loss of $694,553 for the year ended March 31, 2017. We achieved net income of $264,461 for the fiscal quarter ended March 31, 2018.

 

Oil and gas sales. Revenue from oil and gas sales was $2,650,232 for the year ended March 31, 2018, a 13% increase from $2,337,222 for the year ended March 31, 2017. This resulted from 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:

 

    2018     2017     % Difference  
Oil:                        
Revenue   $ 1,789,736     $ 1,517,606       17.9 %
Volume (bbls)     34,743       34,689       0.2 %
Average Price (per bbl)   $ 51.51     $ 43.75       17.7 %
                         
Gas:                        
Revenue   $ 860,496     $ 819,616       5.0 %
Volume (mcf)     318,774       356,268       (10.5 %)
Average Price (per mcf)   $ 2.70     $ 2.30       17.4 %

 

Other operating revenue. Other operating revenue was $55,003 for fiscal 2018 compared to $188,141 for fiscal 2017 primarily due to the settlement of a lawsuit for underpayment of royalties from Chesapeake Energy Corporation and Total E & P USA in the amount of $148,614 during fiscal 2017 partially offset by an increase in SWD income.

 

Production and exploration. Production costs were $1,070,447 in fiscal 2018, a 22% increase from $878,458 in fiscal 2017. This was primarily the result of an increase in lease operating expenses and production taxes due to the increase in oil and gas revenues and XTO Energy, Inc. incorrectly providing us a refund for marketing and transportation fees of approximately $67,000 which is being reversed via monthly netting.

 

Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expense was $880,419 in fiscal 2018, a 25% decrease from $1,177,422 in fiscal 2017. This was primarily due to a decrease in oil and gas production, a decrease in the full cost pool as a result of oil and gas property sales, and a decrease in oil and gas reserves.

 

General and administrative expenses. General and administrative expenses were $955,147 for the year ended March 31, 2018, a 2% decrease from $976,392 for the year ended March 31, 2017. This was primarily due to a decrease in engineering services, insurance expense and legal fees partially offset by an increase in accounting fees.

 

Interest expense. Interest expense was $89,537 in fiscal 2018, a 41% decrease from $152,126 in fiscal 2017, due to a decrease in borrowings partially offset by an increase in interest rate.

 

Income taxes. There was no income tax for fiscal 2018 or fiscal 2017. The effective tax rate for fiscal 2018 and fiscal 2017 was 0%. We are in a net deferred tax asset position and believe it is more likely than not that these deferred tax assets will not be realized.

 

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, 2019:

 

    Payments due in:  
    Total     less than 1 year     1 - 3 years     over 3 years  
Contractual obligations:                                
Leases (1)   $ 106,682     $ 48,810     $ 57,872     $ -  

 

(1) The lease amount represents the monthly rent amount for our principal office space in Midland, Texas under one three year lease agreement effective May 15, 2018. The total obligation for the remainder of the lease is $141,385 which includes $34,703 billed to and reimbursed by our majority shareholder for his portion of the shared office space.

 

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Alternative Capital Resources

 

Although we have primarily used cash from operating activities, the sales of assets 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 issuances of our common stock through a private placement or public offering.

 

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.

 

Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the sale 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 impairment to our oil and gas properties does not impact cash flow from operating activities, but does reduce our stockholders’ equity and reported earnings.

 

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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.

 

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 - Revenue from Contracts with Customers. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606). The amendments in this update are effective for fiscal years and interim periods within those years beginning after December 15, 2017 and supersedes any previous revenue recognition guidance. On April 1, 2018 we adopted ASU 2014-09 using the modified retrospective approach which only applies to contracts that were not completed as of the date of initial application. Recognition of revenue involves a five step approach including identifying the contract, identifying the separate performance obligations, determining the transaction price, allocating the price to the performance obligations and recognizing revenue as the obligations are satisfied.

 

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Adoption of this new standard did not have a material impact on the Company’s financial statements. When comparing the Company’s historical revenue recognition to the newly applied revenue recognition under Topic 606, there was no material change to the amount or timing of revenue recognized. Therefore, no quantitative adjustment was required to be made to the prior periods presented in the unaudited consolidated financial statements. Upon adoption the Company had not altered its existing information technology and internal controls outside of the contract review processes in order to identify impacts of future revenue contracts the Company may enter into.

 

Accounting Policy - Revenues from our royalty and non-operated working interest properties are recorded under the cash receipts approach as directly received from the remitters’ statement accompanying the revenue check. Since the revenue checks are generally received two to four months after the production month, the Company accrues for revenue earned but not received by estimating production volumes and product prices. Any identified differences between its revenue estimates and actual revenue received historically have not been significant.

 

The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption in accordance with ASC 606. The exemption, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

 

In accordance with ASC Topic 606, the Company now records transportation and processing costs that are incurred after control of its product has transferred to the customer as a reduction of “Natural gas sales” on the Consolidated Statement of Operations. Prior to the adoption of ASC Topic 606, these transportation and processing costs were recorded as an expense within “Production” expenses on the Consolidated Statements of Operations. There was no impact to net loss or retained earnings as a result of adopting ASC Topic 606.

 

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.

 

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.

 

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.

 

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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 February 2016, the FASB issued ASU 2016-02, Topic 842 Leases, which requires companies to include leases with a term greater than one year on their balance sheets, but recognize lease costs on the income statement in a manner similar to accounting for leases prior to ASU 2016-02. The standard is effective for fiscal years beginning after December 15, 2018, and interim periods thereafter. Early adoption is permitted. The Company has evaluated the provisions of this ASU and does not anticipate a significant impact on the consolidated financial statements from this amendment.

 

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, 2019, we did not have an outstanding loan balance on our credit agreement.

 

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, 2019, our largest credit risk associated with any single purchaser was $138,508 or 40% of our total oil and gas 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.

 

Prices for crude oil and natural gas have been adversely effected by temporary pipeline capacity constraints primarily in the Permian Basin. We are unable to predict exactly how long this limitation will continue.

 

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

 

Declines in oil and natural gas prices will materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Changes in oil and gas prices impact both estimated future net revenue and the estimated quantity of proved reserves. Any reduction in reserves, including reductions due to price fluctuations, can reduce the borrowing base under our 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.

 

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. If the average oil price had increased or decreased by five dollars per barrel for fiscal 2019, our oil and gas revenue would have changed by $176,785. If the average gas price had increased or decreased by one dollar per mcf for fiscal 2019, oil and gas revenue would have changed by $295,133.

 

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

The information required by this item appears on pages F1 through F19 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, 2019.

 

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, 2019, 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, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

ITEM 9B. OTHER INFORMATION

 

None

 

PART III

 

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

 

See “Mexco Energy Corporation Board of Directors”, “Named Executive Officers Who Are Not Directors”, “Section 16(a) Beneficial Ownership Reporting Compliance”, “Corporate Governance and Code of Business Conduct” and “Meetings and Committees of the Board of Directors” in the Proxy Statement of Mexco Energy Corporation for our Annual Meeting of Stockholders to be held September 12, 2019 (“Proxy Statement”) to be filed with the SEC within 120 days after the end of our fiscal year ended March 31, 2019, 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.

 

27
 

 

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 33 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 F20 of this report.

 

28
 

 

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 24, 2019      

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below as of June 24, 2019, 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  

 

29
 

 

Glossary of Abbreviations and Terms

 

The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report.

 

Basin. A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.

 

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.

 

BOE. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.

 

BTU. British thermal unit.

 

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

 

Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

 

Credit Facility. A line of credit provided by a bank or group of banks, secured by oil and gas properties.

 

DD&A. Refers to depreciation, depletion and amortization of the Company’s property and equipment.

 

Developed acreage . The number of acres which are allocated or assignable to producing wells or wells capable of production.

 

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

 

Development well . A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

 

Dry hole . A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

 

Exploration. The search for natural accumulations of oil and natural gas by any geological, geophysical or other suitable means.

 

Exploratory well . A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

 

Extensions and discoveries . As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates.

 

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

 

Formation. A layer of rock which has distinct characteristics that differs from nearby rock.

 

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

 

30
 

 

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

 

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

 

MBOE . One thousand barrels of oil equivalent.

 

MMBOE . One million barrels of oil equivalent.

 

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

 

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

 

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

 

Net production . Oil and gas production that is owned by the Company, less royalties and production due others.

 

Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.

 

Oil . Crude oil or condensate.

 

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

 

Overriding royalty interest (“ORRI”). A royalty interest that is created out of the operating or working interest. Its term is coextensive with that of the operating interest from which it was created.

 

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

 

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

 

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

 

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

 

Proved developed producing reserves (“PDP”). Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods.

 

Proved developed reserves. The combination of proved developed producing and proved developed nonproducing reserves.

 

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

 

31
 

 

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.

 

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

 

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

 

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

 

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

 

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

 

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

 

Standardized measure of discounted future net cash flows . The discounted future net cash flows relating to proved reserves based on prices used in estimating the reserves, year-end costs, and statutory tax rates, and a 10% annual discount rate. The information for this calculation is included in the note regarding disclosures about oil and gas reserve data contained in the Notes to Consolidated Financial Statements included in this Form 10-K.

 

Undeveloped acreage . Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

 

Unit. The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.

 

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

 

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

 

32
 

 

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

 

F- 1
 

 

Report of Independent Registered Public Accounting Firm

 

Board of Directors and Stockholders

Mexco Energy Corporation

Midland, Texas

 

Opinion on the Financial Statements

 

We have audited the accompanying consolidated balance sheets of Mexco Energy Corporation (a Colorado corporation) and Subsidiaries (the Company) as of March 31, 2019 and 2018, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the two years in the period ended March 31, 2019, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of March 31, 2019 and 2018, and the results of its operations and its cash flows for each of the two years in the period ended March 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

 

Basis for Opinion

 

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 are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

 

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

 

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

 

/s/ WEAVER AND TIDWELL, L.L.P.

 

Midland, Texas

June 24, 2019

 

We have served as the Company’s auditor since 2017.

 

F- 2
 

 

Mexco Energy Corporation and Subsidiaries

CONSOLIDATED BALANCE SHEETS

 

    March 31, 2019     March 31, 2018  
ASSETS                
Current assets                
Cash and cash equivalents   $ 128,252     $ 492,610  
Accounts receivable:                
Oil and natural gas sales     349,600       395,991  
Trade     -       436,249  
Note receivable     30,421       -  
Prepaid costs and expenses     53,735       47,583  
Total current assets     562,008       1,372,433  
                 
Property and equipment, at cost                
Oil and gas properties, using the full cost method     35,907,677       35,224,784  
Other     113,043       107,484  
Accumulated depreciation, depletion and amortization     (27,255,451 )     (26,453,025 )
Property and equipment, net     8,765,269       8,879,243  
                 
Other noncurrent assets     122,407       149,278  
Total assets   $ 9,449,684     $ 10,400,954  
                 
LIABILITIES AND STOCKHOLDERS’ EQUITY                
Current liabilities                
Accounts payable and accrued expenses   $ 166,113     $ 446,815  
Total current liabilities     166,113       446,815  
                 
Long-term debt     -       700,000  
Asset retirement obligations     854,034       852,553  
Total liabilities     1,020,147       1,999,368  
                 
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; 2,107,166 and 2,104,266 share issued; 2,040,166 and 2,037,266 outstanding As of March 31, 2019 and 2018, respectively     1,053,583       1,052,133  
Additional paid-in capital     7,305,048       7,265,601  
Retained earnings     416,907       429,853  
Treasury stock, at cost (67,000 shares)     (346,001 )     (346,001 )
Total stockholders’ equity     8,429,537       8,401,586  
Total liabilities and stockholders’ equity   $ 9,449,684     $ 10,400,954  

 

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

Years ended March 31,

 

    2019     2018  
Operating revenues:                
Oil sales   $ 1,921,391     $ 1,789,736  
Natural gas sales     726,486       860,496  
Other     38,996       55,003  
Total operating revenues     2,686,873       2,705,235  
                 
Operating expenses:                
Production     936,400       1,070,447  
Accretion of asset retirement obligation     27,775       31,460  
Depreciation, depletion and amortization     802,425       880,419  
General and administrative     911,927       955,147  
Total operating expenses     2,678,527       2,937,473  
                 
Operating income (loss)     8,346       (232,238 )
                 
Other income (expenses):                
Interest income     639       286  
Interest expense     (21,931 )     (89,537 )
Net other expense     (21,292 )     (89,251 )
                 
Loss before provision for income taxes     (12,946 )     (321,489 )
                 
Income tax     -       -  
                 
Net loss   $ (12,946 )   $ (321,489 )
                 
Loss per common share:                
Basic:   $ (0.01 )   $ (0.16 )
Diluted:   $ (0.01 )   $ (0.16 )
                 
Weighted average common shares outstanding:                
Basic:     2,039,412       2,037,266  
Diluted:     2,039,412       2,037,266  

 

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, 2019 and 2018

 

    Common Stock Par Value     Additional Paid-In Capital     Retained Earnings     Treasury Stock     Total
Stockholders’ Equity
 
Balance at April 1, 2017   $ 1,052,133     $ 7,244,848     $ 751,342     $ (346,001 )   $ 8,702,322  
Net loss     -       -       (321,489 )     -       (321,489 )
Stock based compensation     -       20,753       -       -       20,753  
Balance at March 31, 2018   $ 1,052,133     $ 7,265,601     $ 429,853     $ (346,001 )   $ 8,401,586  
Net loss     -       -       (12,946 )     -       (12,946 )
Issuance of stock through                                        
Options exercised     1,450       16,791       -       -       18,241  
Stock based compensation     -       22,656       -       -       22,656  
Balance at March 31, 2019   $ 1,053,583     $ 7,305,048     $ 416,907     $ (346,001 )   $ 8,429,537  
                                         
SHARE ACTIVITY                                        
              2019       2018                  
Common stock shares, issued:                                        
At beginning of year             2,104,266       2,104,266                  
Issued             2,900       -                  
At end of year             2,107,166       2,104,266                  
                                         
Common stock shares, held in treasury:                                        
At beginning of year             (67,000 )     (67,000 )                
Acquisitions             -       -                  
At end of year             (67,000 )     (67,000 )                
                                         
Common stock shares, outstanding                                        
At end of year             2,040,166       2,037,266                  

 

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

Years ended March 31,

 

    2019     2018  
Cash flows from operating activities:                
Net loss   $ (12,946 )   $ (321,489 )
Adjustments to reconcile net loss to net cash provided by operating activities:                        
Stock-based compensation     22,656       20,753  
Depreciation, depletion and amortization     802,425       880,419  
Accretion of asset retirement obligations     27,775       31,460  
Changes in operating assets and liabilities:                
Decrease (increase) in accounts receivable     482,640       (437,083 )
Increase in prepaid expenses     (6,152 )     (11,258 )
Increase in current assets     (5,202 )     -  
(Decrease) increase in accounts payable and accrued expenses     (284,219 )     303,831  
Settlement of asset retirement obligations     (14,649 )     (25,609 )
Net cash provided by operating activities     1,012,328       441,024  
                 
Cash flows from investing activities:                
Additions to oil and gas properties     (812,140 )     (1,092,657 )
Additions to other property and equipment     (5,559 )        
Drilling refunds     -       108,646  
Proceeds from sale of oil and gas properties and equipment     162,304       3,162,146  
Net cash (used in) provided by investing activities     (655,395 )     2,178,135  
                 
Cash flows from financing activities:                
Reduction of long-term debt     (700,000 )     (2,200,000 )
Debt issuance costs     (39,532 )     -  
Proceeds from exercise of stock options     18,241       -  
Net cash used in financing activities     (721,291 )     (2,200,000 )
                 
Net (decrease) increase in cash and cash equivalents     (364,358 )     419,159  
                 
Cash and cash equivalents at beginning of period     492,610       73,451  
                 
Cash and cash equivalents at end of period   $ 128,252     $ 492,610  
                 
Supplemental disclosure of cash flow information:                
Cash paid for interest   $ 21,120     $ 94,880  
                 
Non-cash investing and financing activities:                
Asset retirement obligations   $ 8,658     $ 6,689  

 

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, 2019 and 2018

 

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 and Southeastern New Mexico; however, the Company owns producing properties and undeveloped acreage in thirteen states. Although the Company’s oil and gas interests predominately are operated by others, the Company operates three wells on a lease in which it owns a 100% working 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 (“GAAP”), management is required to make informed judgments, estimates and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. In addition, significant estimates are used in determining proved oil and gas reserves. Although management believes its estimates and assumptions are reasonable, actual results may differ materially from those estimates. The estimate of the Company’s oil and natural gas reserves, which is used to compute depreciation, depletion, amortization and impairment of oil and gas properties, is the most significant of the estimates and assumptions that affect these reported results.

 

Cash and Cash Equivalents . The Company considers all highly liquid debt instruments purchased with maturities of three months or less and money market funds to be cash equivalents. The Company maintains cash in bank deposit accounts that may, at times, exceed federally insured limits. At March 31, 2019, 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 collectibility of receivables is assessed and an allowance is made for any doubtful accounts. The allowance for doubtful accounts is determined based on the Company’s previous loss history. The Company has not experienced any significant credit losses. For the years ended March 31, 2019 and 2018, 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. No costs were excluded for the years ended March 31, 2019 and 2018.

 

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 the after tax present value of the future net cash flows from proved crude oil and natural gas reserves and using an average price over the prior first day of the month 12-month period held flat for the life of production plus the lower of cost or fair market value of unproved properties. If net capitalized costs of crude oil and natural gas properties exceed the ceiling limit, the Company must charge the amount of the excess to earnings as an expense reflected in additional accumulated DD&A. This is called a “ceiling limitation write-down.” This impairment to our oil and gas properties does not impact cash flow from operating activities, but does reduce stockholders’ equity and reported earnings.

 

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

 

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

 

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

 

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

 

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

 

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

 

Revenue Recognition - Revenue from Contracts with Customers. On April 1, 2018, the Company adopted Accounting Standard Codification (“ASC”) Topic 606, Revenue from Contracts with Customers, using the modified retrospective approach. Results for reporting periods beginning April 1, 2018, are presented in accordance with ASC Topic 606, while prior period amounts are reported in accordance with ASC Topic 605, Revenue Recognition.

 

F- 8
 

 

In accordance with ASC Topic 606, the Company now records transportation and processing costs that are incurred after control of its product has transferred to the customer as a reduction of “Natural gas sales” on the Consolidated Statement of Operations. Prior to the adoption of ASC Topic 606, these transportation and processing costs were recorded as an expense within “Production” expenses on the Consolidated Statements of Operations. There was no impact to net loss or retained earnings as a result of adopting ASC Topic 606.

 

Recognition of revenue involves a five step approach including identifying the contract, identifying the separate performance obligations, determining the transaction price, allocating the price to the performance obligations and recognizing revenue as the obligations are satisfied.

 

Accounting Policy - Revenues from our royalty and non-operated working interest properties are recorded under the cash receipts approach as directly received from the remitters’ statement accompanying the revenue check. Since the revenue checks are generally received two to four months after the production month, the Company accrues for revenue earned but not received by estimating production volumes and product prices. Any identified differences between its revenue estimates and actual revenue received historically have not been significant.

 

The Company does not disclose the value of unsatisfied performance obligations under its contracts with customers as it applies the practical exemption in accordance with ASC 606. The exemption, as described in ASC 606-10-50-14(a), applies to variable consideration that is recognized as control of the product is transferred to the customer. Since each unit of product represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

 

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

 

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

 

Recent Accounting Pronouncements. In February 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-02, Topic 842 Leases, which requires companies to include leases with a term greater than one year on their balance sheets, but recognize lease costs on the income statement in a manner similar to accounting for leases prior to ASU 2016-02. The standard is effective for fiscal years beginning after December 15, 2018, and interim periods thereafter. Early adoption is permitted. The Company has evaluated the provisions of this ASU and does not expect it to have a material impact on its financial statements.

 

Liquidity and Capital Resources. Historically, we have funded our operations, acquisitions, exploration and development expenditures from cash generated by operating activities, bank borrowings, sales of non-core properties and issuance of common stock. Our long term strategy is on increasing profit margins while concentrating on obtaining reserves with low cost operations by acquiring and developing oil and gas properties with potential for long-lived production. We focus our efforts on the acquisition of royalties and working interest, non-operated properties in areas with significant development potential.

 

3. Fair Value of Financial Instruments

 

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

 

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

 

F- 9
 

 

4. Property Sales

 

During fiscal 2019, the Company continued its policy of selling non-core assets in order to concentrate on the development of more profitable assets and to pay down debt. The Company received approximately $33,000 in cash from a sale of joint venture leasehold acreage and marginal producing working interest wells in North Dakota and Montana; approximately $72,000 in cash from a sale of joint venture leasehold marginal producing working interests in Ward and Winkler Counties in Texas; and, approximately $51,000 in cash from the sale of additional leasehold acreage in Eddy County, New Mexico. Other immaterial dispositions and purchase price adjustments amounted to approximately $6,000.

 

During fiscal 2018, the Company sold non-core assets for a total of approximately $3.2 million.

 

5. Credit Facility

 

The Company has a loan agreement (the “Agreement”) with West Texas National Bank (“WTNB”), which provided for a credit facility of $1,000,000. The Agreement has no monthly commitment reduction and a borrowing base to be evaluated annually.

 

Under the Agreement, interest on the facility accrues at a rate equal to the prime rate as quoted in the Wall Street Journal plus one-half of one percent (.5%) floating daily. Interest on the outstanding amount under the Agreement is payable monthly. In addition, the Company will pay an unused commitment fee in an amount equal to one-half of one percent (.5%) times the daily average of the unadvanced amount of the commitment. The unused commitment fee is payable quarterly in arrears on the last day of each calendar quarter.

 

No principal payments are anticipated to be required through the maturity date of the credit facility, December 28, 2021. Upon closing with WTNB on the Agreement, the Company paid a .5% loan origination fee in the amount of $5,000 plus legal and recording expenses totaling $34,532, which were deferred over the life of the credit facility.

 

Amounts borrowed under the Agreement are collateralized by the common stock of the Company’s wholly owned subsidiaries and substantially all of the Company’s oil and gas properties.

 

The Agreement contains customary covenants for credit facilities of this type including limitations on change in control, disposition of assets, mergers and reorganizations. The Company is also obligated to meet certain financial covenants under the Agreement and requires senior debt to earnings before interest, taxes, depreciation and amortization (“EBITDA”) ratios (Senior Debt/EBITDA) less than or equal to 4.00 to 1.00 measured with respect to the four trailing fiscal quarters and minimum interest coverage ratios (EBITDA/Interest Expense) of 2.00 to 1.00 for each quarter. The Company is in compliance with all covenants as of March 31, 2019 and believes it will remain in compliance for the next fiscal year.

 

In addition, the Agreement prohibits the Company from paying cash dividends on its common stock without prior written permission of WTNB. The Agreement does not permit the Company to enter into hedge agreements covering crude oil and natural gas prices.

 

There is no balance outstanding on the WTNB credit facility as of March 31, 2019.

 

Prior thereto, the Company had a loan agreement with Bank of America, N.A. which provided for a credit facility of $5,570,000 with no monthly commitment reductions and a borrowing base to be evaluated on July 30 and January 1 of each year or at any additional time in the bank’s discretion. The borrowing base was evaluated on July 31, 2018 and set at $525,000. The Agreement was renewed eleven times with the eleventh amendment effective as of March 8, 2017 with a maturity date of November 30, 2020. Under such renewal agreement, interest on the facility accrued at an annual rate equal to the British Bankers Association London Interbank Offered Rate (“BBA LIBOR”) daily floating rate, plus 3.0 percentage points. Interest on the outstanding amount under the credit agreement was payable monthly. The Company was in compliance with the loan agreement as the date of repayment.

 

F- 10
 

 

On December 28, 2018, in connection with entering into the loan agreement with WTNB described above, the Company repaid in full and terminated its loan agreement with Bank of America, N.A. The $450,000 amount owed was repaid using Company funds and no early termination fees were incurred.

 

The following table is a summary of activity on the Bank of America, N.A. line of credit for the year ended March 31, 2019:

 

    Principal  
Balance at April 1, 2018:   $ 700,000  
Borrowings     -  
Repayments     700,000  
Balance at March 31, 2019:   $ -  

 

On December 26, 2018, the Company deposited $26,250 into a Cash Collateral Account at Bank of America, N.A. to collateralize one outstanding letter of credit for $25,000 in lieu of a plugging bond with the Texas Railroad Commission covering the properties the Company operates. This letter of credit renews annually.

 

6. Asset Retirement Obligations

 

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

 

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

 

    2019     2018  
Carrying amount of asset retirement obligations, beginning of year   $ 862,553     $ 978,484  
Liabilities incurred     8,658       6,689  
Liabilities settled     (27,452 )     (153,539 )
Accretion expense     27,775       31,460  
Revisions     (10,000 )     (541 )
Carrying amount of asset retirement obligations, end of year     861,534       862,553  
Less: Current portion     7,500       10,000  
Non-Current asset retirement obligation   $ 854,034     $ 852,553  

 

7. Income Taxes

 

The Company files a consolidated federal income tax return and various state income tax returns. The amount of income taxes the Company records requires the interpretation of complex rules and regulations of federal and state taxing jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal and state income tax examinations by tax authorities for years prior to 2016.

 

On December 22, 2017, the tax legislation referred to as the “Tax Cuts and Jobs Act” (the 2017 Tax Reform Act) was enacted. The more significant changes that impact the Company are the reduction in the corporate federal income tax rate from 35% to 21%. GAAP requires deferred income tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. The Company’s deferred income taxes were remeasured based upon the new tax rates which amounted to a $466,020 reduction in deferred tax asset and valuation amount.

 

The 2017 Tax Reform Act reduced the corporate federal statutory income tax rate from 35% to 21% generally effective for tax years beginning on or after January 1, 2018. However, companies with fiscal years that include January 1, 2018 must use a blended rate. As of April 1, 2018, our corporate federal statutory income tax rate is 21%.

 

F- 11
 

 

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

 

    2019     2018  
Deferred tax assets:                
Percentage depletion carryforwards   $ 1,136,210     $ 1,111,801  
Deferred stock-based compensation     34,771       33,581  
Asset retirement obligation     180,922       181,136  
Net operating loss     948,722       995,489  
Other     5,470       5,141  
      2,306,095       2,327,148  
Deferred tax liabilities:                
Excess financial accounting bases over tax bases of property and equipment     1,045,974       1,091,725  
Deferred tax asset, net   $ 1,260,121     $ 1,235,423  
Valuation allowance     (1,260,121 )     (1,235,423 )
Net deferred tax   $ -     $ -  

 

As of March 31, 2019, the Company has a statutory depletion carryforward of approximately $5,400,000, which does not expire. At March 31, 2019, 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.

 

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

 

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

 

    2019     2018  
Tax expense at federal statutory rate (1)   $ (2,719 )   $ (98,858 )
Statutory depletion carryforward     (24,409 )     (8,361 )
Change in valuation allowance     24,698       (362,908 )
U. S. tax reform, corporate rate reduction     -       466,020  
Permanent differences     3,812       3,506  
Other     (1,382 )     601  
Total income tax   $ -     $ -  
Effective income tax rate     -       -  

 

  (1) The federal statutory rate was 21% for fiscal year ending March 31, 2019 and 30.75% for fiscal year ending March 31, 2018.

 

For the years ended March 31, 2019 and 2018, the Company did not have any uncertain tax positions.

 

A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows for the years ended March 31, 2019 and 2018:

 

    2019     2018  
Unrecognized tax benefits at beginning of period   $ -     $ 745,000  
Change based on tax positions related to the current year     -       (745,000 )
Changes to tax positions of prior years     -       -  
Settlements     -       -  
Expirations     -       -  
Unrecognized tax benefits at end of period   $ -     $ -  

 

F- 12
 

 

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

 

Based on the material write-downs of the carrying value of our oil and natural gas properties for the year ending March 31, 2016, we are in a net deferred tax asset position for years ending March 31, 2019 and 2018. Our deferred tax asset is $1,260,121 as of March 31, 2019 with a valuation amount of $1,260,121. We believe it is more likely than not that these deferred tax assets will not be realized. Management assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future taxable income are increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as expected future growth.

 

8. Major Customers

 

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

 

In fiscal 2019, one customer accounted for 42% of the total oil and natural gas revenues and 40% of the total oil and natural gas accounts receivable and another customer accounted for 6% of the total oil and natural gas revenues and 9% of the total oil and natural gas accounts receivable. In fiscal 2018, one customer accounted for 37% of the total oil and natural gas revenues and 33% of the total oil and natural gas accounts receivable and another customer accounted for 8% of the total oil and natural gas revenues and 7% of the total oil and natural gas accounts receivable.

 

9. Oil and Natural Gas Costs

 

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

 

    2019     2018  
Property acquisition costs:                
Proved   $ -     $ -  
Unproved     -       -  
Exploration     14,555       -  
Development     803,602       1,099,051  
Capitalized asset retirement obligations     8,658       6,689  
Total costs incurred for oil and gas properties   $ 826,815     $ 1,105,740  

 

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

 

    2019     2018  
Proved oil and gas properties   $ 35,907,677     $ 35,224,784  
Unproved oil and gas properties:                
subject to amortization     -       -  
not subject to amortization     -       -  
      35,907,677       35,224,784  
Less accumulated DD&A     27,154,343       26,355,604  
    $ 8,753,334     $ 8,896,180  

 

DD&A amounted to $9.45 and $10.02 per BOE of production for the years ended March 31, 2019 and 2018, respectively.

 

F- 13
 

 

10. Loss Per Common Share

 

Due to a net loss for the years ended March 31, 2019 and 2018, 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 years ended March 31:

 

    2019     2018  
Net loss   $ (12,946 )   $ (321,489 )
                 
Shares outstanding:                
Weighted avg. common shares outstanding – basic     2,039,412       2,037,266  
Effect of the assumed exercise of dilutive stock options     -       -  
Weighted avg. common shares outstanding – dilutive     2,039,412       2,037,266  
                 
Loss per common share:                
Basic   $ (0.01 )   $ (0.16 )
Diluted   $ (0.01 )   $ (0.16 )

 

11. Stockholders’ Equity

 

In September 2018, the Board of Directors authorized the use of up to $250,000 to repurchase shares of the Company’s common stock for the treasury account. There were no shares of common stock repurchased for the treasury account during fiscal 2019 and 2018.

 

12. 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.

 

During the year ended March 31, 2019, the Compensation Committee of the Board of Directors approved and the Company issued 40,000 stock options. During the year ended March 31, 2018, no stock options were granted. The plan also provides for the granting of stock awards. No stock awards were granted during fiscal 2019 and 2018.

 

The Company recognized compensation expense of $22,656 and $20,753 related to vesting stock options in general and administrative expense in the Consolidated Statements of Operations for fiscal 2019 and 2018, respectively. The total cost related to non-vested awards not yet recognized at March 31, 2019 totals $112,011, which is expected to be recognized over a weighted average of 3.45 years.

 

F- 14
 

 

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

 

Included in the following table is a summary of the grant-date fair value of stock options granted and the related assumptions used in the Binomial models for stock options granted in fiscal 2019 and 2018. All such amounts represent the weighted average amounts for each period.

 

    For the year ended March 31,  
    2019     2018  
Grant-date fair value   $ 3.25       -  
Volatility factor     55.26 %     -  
Dividend yield     -       -  
Risk-free interest rate     2.91 %     -  
Expected term (in years)     6.25       -  

 

No forfeiture rate is assumed for stock options granted to directors or employees due to the forfeiture rate history for these types of awards. During the year ended March 31, 2019, there were no stock options forfeited or expired. During the year ended March 31, 2018, vested stock options covering 1,000 shares were forfeited due to the resignation of an employee.

 

The following table is a summary of activity of stock options for the years ended March 31, 2019 and 2018:

 

    Number of Shares    

Weighted Average

Exercise Price

Per Share

   

Weighted Aggregate Average Remaining Contract Life in

Years

 
Outstanding at April 1, 2017     149,600     $ 6.54       5.34  
Granted     -       -          
Exercised     -       -          
Forfeited or Expired     (1,000 )     5.98          
Outstanding at March 31, 2018     148,600     $ 4.84       4.34  
Granted     40,000       -          
Exercised     2,900       8.56          
Forfeited or Expired     -       -          
Outstanding at March 31, 2019     185,700     $ 6.18       4.68  
                         
Vested at March 31, 2019     145,700     $ 6.55       3.37  
Exercisable at March 31, 2019     145,700     $ 6.55       3.37  

 

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

 

    2019     2018  
Weighted average grant-date fair value of stock
options granted (per share)
  $ 3.25     $ -  
Total fair value of options vested   $ 55,900     $ 91,525  
Total intrinsic value of options exercised   $ 6,575     $ -  

 

F- 15
 

 

The following table summarizes information about options outstanding at March 31, 2019:

 

Range of Exercise Prices   Number of Options     Weighted Average Exercise Price Per Share     Weighted Average Remaining Contract Life in Years  
$ 4.84 – 5.97     40,000     $ 4.84          
5.98 – 6.26     40,000       6.00          
6.26 – 6.50     25,700       6.29          
6.51 – 6.80     40,000       6.80          
6.81 – 7.00     40,000       7.00          
$ 5.98 – 7.00     185,700     $ 6.18       4.68  

 

Outstanding options at March 31, 2019 expire between August 2020 and September 2028 and have exercise prices ranging from $4.84 to $7.00.

 

13. Related Party Transactions

 

Related party transactions for the Company relate to shared office expenditures in addition to administrative and operating expenses paid on behalf of the principal stockholder. The total billed to and reimbursed by the stockholder for the years ended March 31, 2019 and 2018 were $51,276 and $40,432, respectively.

 

14. Lease Commitments

 

The Company leases its principal office space. On May 15, 2018, the Company agreed to a three year lease. The following table summarizes, by fiscal year, future payments the Company is obligated to make based on the lease commitments in place as of March 31, 2019:

 

    Commitment Amount (1)  
Fiscal Year 2020   $ 48,810  
Fiscal Year 2021   $ 49,586  
Fiscal Year 2022   $ 8,286  

 

  (1) The total commitment for the remainder of the lease is $141,385 which includes $34,703 billed to and reimbursed by the Company’s principal shareholder for his portion of the shared office space.

 

Lease expense for the year ended March 31, 2019 was $44,028 and $23,440 for the year ended March 31, 2018.

 

15. Oil and Gas Reserve Data (Unaudited)

 

The estimates of the Company’s proved oil and gas reserves, which are located entirely within the United States, were prepared in accordance with the generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. The estimates as of March 31, 2019 and 2018 were based on evaluations prepared by Russell K. Hall and Associates, Inc. The services provided by Russell K. Hall and Associates, Inc. are not audits of our reserves but instead consist of complete engineering evaluations of the respective properties. For more information about their evaluations performed, refer to the copy of their report filed as an exhibit to this Annual Report on Form 10-K. Management emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

 

The following table summarizes the prices utilized in the reserve estimates for 2019 and 2018. Commodity prices utilized for the reserve estimates prior to adjustments for location, grade and quality are as follows:

 

    March 31,  
    2019     2018  
Prices utilized in the reserve estimates before adjustments:                
Oil per Bbl   $ 59.52     $ 49.94  
Natural gas per MMBtu   $ 3.07     $ 3.00  

 

F- 16
 

 

The Company’s total estimated proved reserves at March 31, 2019 were approximately 1.937 MBOE of which 54% was oil and natural gas liquids and 46% was natural gas.

 

Changes in Proved Reserves :

 

    Oil
(Bbls)
    Natural Gas
(Mcf)
 
Proved Developed and Undeveloped Reserves:                
As of April 1, 2017     2,124,000       6,681,000  
Revision of previous estimates     (850,000 )     (915,000 )
Purchase of minerals in place     -       -  
Extensions and discoveries     110,000       191,000  
Sales of minerals in place     (152,000 )     (151,000 )
Production     (35,000 )     (319,000 )
As of March 31, 2018     1,197,000       5,487,000  
Revision of previous estimates     (293,000 )     (430,000 )
Purchase of minerals in place     -       -  
Extensions and discoveries     171,000       619,000  
Sales of minerals in place     -       -  
Production     (35,000 )     (295,000 )
As of March 31, 2019     1,040,000       5,381,000  

 

Proved developed reserves are those expected to be recovered through existing wells, equipment and operating methods. Proved undeveloped reserves (“PUD”) are proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion within a five years of the date of their initial recognition. Moreover, the Company may be required to write down its proved undeveloped reserves if the operators do not drill on the reserves within the required five-year timeframe. The downward revision of oil and natural gas is primarily the result of restructuring the plans for development of an operated property in Ector County, Texas due to market conditions partially offset by pricing and successful development in the Delaware and Midland Basins. Reserves written off due to the five year limitation are primarily in the Bakken Field in Billings County, North Dakota which are on a lease held by production and are still in place to be developed in the future.

 

Summary of Proved Developed and Undeveloped Reserves as of March 31, 2019 and 2018 :

 

    Oil
(Bbls)
    Natural Gas
(Mcf)
 
Proved Developed Reserves:                
As of April 1, 2017     399,880       4,107,950  
As of March 31, 2018     390,740       4,103,390  
As of March 31, 2019     376,600       3,823,440  
                 
Proved Undeveloped Reserves:                
As of April 1, 2017     1,724,420       2,572,960  
As of March 31, 2018     805,980       1,383,120  
As of March 31, 2019     663,860       1,557,250  

 

At March 31, 2019, the Company reported estimated PUDs of 923 MBOE, which accounted for 48% of its total estimated proved oil and gas reserves. This figure primarily consists of a projected 152 new wells (679 MBOE) operated by others, 13 wells are currently being drilled with plans for 79 wells to follow in 2020, 46 wells in 2021 and 14 wells in 2022. The cost of these projects would be funded, to the extent possible, from existing cash balances, cash flow from operations and bank borrowings. The remainder may be funded through non-core asset sales and/or sales of our common stock.

 

The following table discloses the Company’s progress toward the conversion of PUDs during fiscal 2019.

 

F- 17
 

 

The following table discloses the Company’s progress toward the conversion of PUDs during fiscal 2019.

 

Progress of Converting Proved Undeveloped Reserves :

 

    Oil & Natural Gas     Future  
    (BOE)     Development Costs  
PUDs, beginning of year     1,036,503     $ 12,009,331  
Revision of previous estimates     (306,406 )     (3,246,620 )
Sales of reserves     -       -  
Conversions to PD reserves     (63,808 )     (828,262 )
Additional PUDs added     257,116       1,203,111  
PUDs, end of year     923,405     $ 9,137,560  

 

Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using average prices for 2019 and 2018 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, 2024 are $9,137,560.

 

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

 

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

 

The current reporting rules require that year end reserve calculations and future cash inflows be based on the 12-month average market prices for sales of oil and gas on the first calendar day of each month during the fiscal year discounted at 10% per year and assuming continuation of existing economic conditions. The average prices used for fiscal 2019 were $53.71 per bbl of oil and $2.77 per mcf of natural gas. The average prices used for fiscal 2018 were $50.63 per bbl of oil and $3.03 per mcf of natural gas.

 

The standardized measure of discounted future net cash flows is computed by applying the 12-month unweighted average of the first day of the month pricing for oil and natural gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and natural gas reserves, less estimated future expenditures (based on year end costs) to be incurred in developing and producing the proved reserves, discounted using a rate of 10% per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and natural gas properties plus available carryforwards and credits and applying the current tax rate to the difference.

 

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

 

The following information is based on the Company’s best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of March 31, 2019 and 2018 in accordance with ASC 932, “Extractive Activities – Oil and Gas” which requires the use of a 10% discount rate. This information is not the fair market value, nor does it represent the expected present value of future cash flows of the Company’s proved oil and gas reserves.

 

F- 18
 

 

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

 

    March 31  
    2019     2018  
Future cash inflows   $ 70,766,000     $ 77,221,000  
Future production costs and taxes     (19,355,000 )     (20,080,000 )
Future development costs     (9,424,000 )     (12,009,000 )
Future income taxes     (5,767,000 )     (6,413,000 )
Future net cash flows     36,220,000       38,719,000  
Annual 10% discount for estimated timing of cash flows     (16,968,000 )     (19,843,000 )
Standardized measure of discounted future net cash flows   $ 19,252,000