Attached files
| file | filename |
|---|---|
| EX-31.1 - MEXCO ENERGY CORP | ex31-1.htm |
| EX-99.1 - MEXCO ENERGY CORP | ex99-1.htm |
| EX-32.1 - MEXCO ENERGY CORP | ex32-1.htm |
| EX-31.2 - MEXCO ENERGY CORP | ex31-2.htm |
| EX-23.2 - MEXCO ENERGY CORP | ex23-2.htm |
| EX-23.1 - MEXCO ENERGY CORP | ex23-1.htm |
| EX-21.1 - MEXCO ENERGY CORP | ex21-1.htm |
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, 2021
| [ ] | 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. [ ]
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 (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [X] No [ ]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or and emerging growth company. See definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act:
Large Accelerated Filer [ ] Accelerated Filer [ ] Non-Accelerated Filer [ ] Smaller Reporting Company [X] Emerging Growth Company [ ]
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ]
Indicate by check mark whether the registrant 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, 2020 (the last business day of the Registrant’s most recently completed second quarter) was $4,724,764 based on Mexco Energy Corporation’s closing common stock price of $4.77 per share on that date as reported by the NYSE American.
There were 2,076,666 shares of the registrant’s common stock outstanding as of June 25, 2021.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s Proxy Statement relating to the 2021 Annual Meeting of Shareholders to be held on September 9, 2021, 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, 2021, the end of the fiscal year covered by this report.
TABLE OF CONTENTS
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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”.
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.
General
Mexco Energy Corporation, a Colorado corporation, is an independent oil and gas company engaged in the acquisition, exploration, development and production of crude oil and natural gas 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, 2021 were approximately 1.504 million barrels of oil equivalent (“MMBOE”) of which 49% was oil and natural gas liquids and 51% was natural gas, and our estimated present value of proved reserves was approximately $14 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.
Nicholas C. Taylor beneficially owns approximately 46% 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.
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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 2022.
While we own oil and gas properties in other states, the majority of our activities are centered in West Texas and Southeastern New Mexico. The Company also owns producing properties and undeveloped acreage in fourteen 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, including working, royalty and mineral interests, and prospects that could have a potentially meaningful impact on our reserves. All of the Company’s oil and gas interests are operated by others.
From 1983 to 2021, 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.
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| 2019 | In April 2019, the Company made a less than 1% investment commitment in a limited liability company amounting to $250,000 of which $200,000 has been funded through March 31, 2021. This amount is classified as an investment at cost on the Company’s consolidated balance sheets. The limited liability company is capitalized at approximately $50 million to purchase royalty interests consisting of minerals located in the state of Ohio. As of March 31, 2021 there are 225 gross wells (.85 net wells) of which 215 are Utica gas wells and 10 are Marcellus oil wells either producing, drilling or in process. |
Industry Environment and Outlook
The outbreak of the novel coronavirus (“COVID-19”) in the first calendar quarter of 2020 and its continued spread across the globe in the second, third and fourth calendar quarters of 2020 has resulted, and is likely to continue to result in, significant economic disruption and has, and is likely to continue to, adversely affect the operations of the Company’s business, as the significantly reduced global and national economic activity has resulted in reduced demand for oil and natural gas. Federal, state and local governments mobilized to implement containment mechanisms to minimize impacts to their populations and economies. Various containment measures, which include the quarantining of cities, regions and countries, while aiding in the prevention of further outbreak, have resulted in a severe drop in general economic activity and a resulting decrease in energy demand. In addition, the global economy has experienced a significant disruption to global supply chains. The direct impact to the Company’s operations began to take effect at the close of the fiscal year ended March 31, 2020, and continued through the close of the Company’s third quarter of this fiscal year.
The challenging commodity price environment continued in fiscal 2021 and in May 2020, commodity prices experienced extreme volatility resulting in historic lows. In light of these challenges facing our industry and in response to the continued challenging environment, our primary business strategies for fiscal 2022 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.
During the Company’s fourth quarter of fiscal 2021 and continuing through the first quarter of fiscal 2022, oil and natural gas prices recovered to pre-pandemic levels, due in part to the accessibility of vaccines, reopening of states after the lockdown and optimism about the economic recovery. However, the continued spread of the virus, including vaccine-resistant strains, could once again reduce the demand for oil and gas and deteriorate the oil and natural prices.
See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for discussion of our fiscal 2021 operating results and potential impact on fiscal 2022 operating results due to commodity price changes.
Oil and Gas Operations
As of March 31, 2021, oil constituted approximately 73% of our oil and gas revenues and approximately 49% of our total proved reserves for fiscal 2021. Revenues from oil and gas royalty interests accounted for approximately 22% of our oil and gas revenues for fiscal 2021.
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 80% of our discounted future net cash flows from proved reserves and 86% of our gross revenues.
The Delaware Basin properties, encompassing 31,224 gross acres, 210 net acres, 526 gross producing wells and 3 net wells account for approximately 52% of our discounted future net cash flows from proved reserves as of March 31, 2021. For fiscal 2021, these properties accounted for 66% of our gross revenues and 76% of our net revenues. Of these discounted future net cash flows from proved reserves, approximately 11% are attributable to proven undeveloped reserves which will be developed through new drilling.
The Midland Basin properties, encompassing 97,640 gross acres, 263 net acres, 981 gross producing wells and 3 net wells account for approximately 14% of our discounted future net cash flows from proved reserves as of March 31, 2021. For fiscal 2021, these properties accounted for 14% of our gross revenues and 13% of our net revenues. 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.
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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 13% of our discounted future net cash flows from proved reserves as of March 31, 2021. For fiscal 2021, these properties accounted for 3% of our gross revenues and 2% of our net revenues. All of these properties, except for one, are royalty interests. 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 in the horizontal Wolfcamp.
Mexco believes its most important properties for future development by horizontal drilling and hydraulic fracturing area are located in Lea and Eddy Counties, New Mexico of the Delaware Basin and the Midland Basin in Midland, Reagan and Upton Counties, Texas.
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 6,400 producing wells all of which are located within the United States in the states of Texas, New Mexico, Oklahoma, Louisiana, Alabama, Mississippi, Arkansas, Wyoming, Kansas, Colorado, Montana, Virginia, North Dakota, and Ohio. Additional information concerning these properties and our oil and gas reserves is provided below.
The following table indicates our oil and gas production in each of the last five years:
| Year | Oil(Bbls) | Gas (Mcf) | ||||||
| 2021 | 50,327 | 324,205 | ||||||
| 2020 | 44,301 | 294,007 | ||||||
| 2019 | 35,359 | 295,133 | ||||||
| 2018 | 34,743 | 318,774 | ||||||
| 2017 | 34,689 | 356,268 | ||||||
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 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 like the crude oil price disputes between Saudi Arabia and Russia; 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: national and international pandemics like the COVID-19; 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.
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Major Customers
We made sales that amounted to 10% or more of revenues as follows for the years ended March 31:
| 2021 | 2020 | |||||||
| Company A | 66 | % | 52 | % | ||||
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
The exploration and development of crude oil and natural gas 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 properties in which the Company owns an interest.
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.”
Various state governments and regional organizations comprising state governments already have enacted legislation and promulgated rules restricting greenhouse gases (“GHGs”) 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, 2021. 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 2022.
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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.
Prior to drilling of an oil and natural gas well, it is normal practice in our industry for the person or company acting as the operator of the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails expense. Our operators’ failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest. We believe the title to our properties is good and defensible in accordance with standards generally acceptable in the oil and gas industry subject to such exceptions that, in the opinion of counsel employed in the various areas in which we have activities, are not so material as to detract substantially from the use of such properties.
Substantially all of our properties are currently mortgaged under a deed of trust to secure funding through a credit facility.
Insurance
Our operations are subject to all the risks inherent in the exploration for and development and production of oil and gas including blowouts, fires and other casualties. We maintain insurance coverage customary for operations of a similar nature, but losses could arise from uninsured risks or in amounts in excess of existing insurance coverage.
Executive Officers
The following table sets forth certain information concerning the executive officers of the Company as of March 31, 2021.
| Name | Age | Position | ||
| Nicholas C. Taylor | 83 | Chairman and Chief Executive Officer | ||
| Tamala L. McComic | 52 | President, Chief Financial Officer, Treasurer, and Assistant Secretary | ||
| Donna Gail Yanko | 76 | 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 and Chartered Global Management Accountant, became Controller for the Company in July 2001 and was elected President and Chief Financial Officer in September 2011. She served the Company as Executive Vice President and Chief Financial Officer from 2009 to 2011 and Vice President and Chief Financial Officer from 2003 to 2009. Prior thereto, Ms. McComic 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.
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Employees
As of March 31, 2021, 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.
Office Facilities
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 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. 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 Secretary by mail to P.O. Box 10502, Midland, Texas 79702 or by email to mexco@sbcglobal.net.
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; national and international pandemics like the COVID-19; 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.
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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.
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.
Our results of operations may be negatively impacted by current global events such as the coronavirus outbreak.
In December 2019, a novel strain of the coronavirus (“COVID-19”) surfaced and spread around the world, including to the United States. In March 2020, the World Health Organization declared COVID-19 a pandemic, and the President of the United States declared the COVID-19 outbreak a national emergency. The COVID-19 pandemic has significantly affected the global economy, disrupted global supply chains and created significant volatility and disruption in the financial and commodity markets. In addition, the COVID-19 pandemic has resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities. As a result, there has been a significant reduction in demand for and prices of oil and natural gas. As of the first quarter of calendar year 2021, prices have recovered to pre-pandemic levels, due in part to the accessibility of vaccines, reopening of states after the lockdown, and optimism about the economic recovery. The continued spread of COVID-19, including vaccine-resistant strains, or repeated deterioration in oil and natural gas prices could result in additional adverse impacts on the Company’s results of operations, cash flows and financial position.
The ability or willingness of OPEC and other oil exporting nations to set and maintain production levels has a significant impact on oil and natural gas commodity prices.
OPEC is an intergovernmental organization that seeks to manage the price and supply of oil on the global energy market. OPEC and certain other oil exporting nations have previously agreed to take measures, including production cuts, to support crude oil prices. A dispute between OPEC and Russia over production cuts resulted in a decision by Saudi Arabia and other Persian Gulf members of OPEC to increase production. In April 2020, OPEC and Russia agreed to certain production cuts. If these cuts are effected, however, they may not offset near-term demand loss attributable to the COVID-19 pandemic and the related economic slowdown. In response to an oversupply of crude oil and corresponding low prices, there has been a significant decline in drilling by U.S. producers starting in mid-March 2020, but domestic supply has continued to exceed demand, which has led to significant operational stress with respect to capacity limitations associated with storage, pipeline and refining infrastructure. As storage capacity becomes fully subscribed, operators may be forced to curtail some portion or all production. Therefore, the impact cannot be reasonably estimated at this time. Volatility due to OPEC actions and other factors affecting the global supply and demand of oil and natural gas may continue.
Governmental actions and political instability may negatively affect drilling and production levels.
The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. The trend in oil and natural gas regulation has been to increase regulatory restrictions and limitations on such activities. Any changes in, or more stringent enforcement of, these laws and regulations may result in delays or restrictions in permitting or development of projects or more stringent or costly construction, drilling, water management or completion activities or waste handling, storage, transport, remediation, or disposal emission or discharge requirements which could have a material adverse effect on the Company.
For example, on January 20, 2021, the Biden Administration placed a 60-day moratorium on new oil and gas leasing and drilling permits on federal land, and on January 27, 2021, the Department of Interior acting pursuant to a Presidential Executive Order suspended the federal oil and gas leasing program indefinitely. However, earlier this month, a federal judge issued an order temporarily blocking the moratorium.
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The Biden Administration has also announced that it intends to review the Trump Administration’s 2017 repeal of the 2015 rule regulating hydraulic fracturing activities in federal land under the Presidential Executive Order on Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis.
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 2021 and 2020.
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 32% and 50% of our total estimated net proved reserves at March 31, 2021 and 2020, 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.
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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 2021, differentials averaged $0.93 per Bbl of oil and $0.13 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.
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 lender’s inability to agree to an adequate borrowing base or adverse changes in the lender’s practices regarding estimation of reserves.
If cash flow from operations or our borrowing base decrease for any reason, our ability to undertake exploration and development activities could be adversely affected. As a result, our ability to replace production may be limited.
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.
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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.
All of our business activities are conducted through joint operating or other agreements under which we own working and royalty interests in natural gas and oil properties in which we do not operate. As a result, we have a limited ability to exercise influence over normal operating procedures, expenditures or future development of underlying properties and their associated costs. The failure of an operator of our wells to adequately perform operations could reduce our revenues and production.
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.
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 the value of an investment in our Common Stock as well as our financial position, results of operations and cash flows.
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In March 2020, the President of the United States signed the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”), to stabilize the economy during the coronavirus pandemic. The CARES Act temporarily suspends and modifies certain tax laws established by the 2017 tax reform law known as the Tax Cuts and Jobs Act, including, but not limited to, modifications to net operating loss limitations, business interest limitations and alternative minimum tax. The CARES Act did not have a material impact on the Company’s current year provision and the Company’s consolidated financial statements.
A terrorist or cyber-attack or armed conflict could harm our business by decreasing our revenues and increasing our costs.
Terrorist activities, anti-terrorist efforts, cyber-attacks and other armed conflicts involving the United States may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur or escalate, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our production and causing a reduction in our revenue. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if significant infrastructure or facilities used for the production, transportation, processing or marketing of oil and natural gas production are destroyed or damaged.
Our reliance on information technology, including those hosted by third parties, exposes us to cyber security risks that could affect our business, financial condition or reputation and increase compliance challenges.
We rely on information technology systems, including internet sites, computer software, data hosting facilities and other hardware and platforms, some of which are hosted by third parties, to assist in conducting our business. Our information technology systems, as well as those of third parties we use in our operations, may be vulnerable to a variety of evolving cybersecurity risks, such as those involving unauthorized access or control, denial-of-service attacks, malicious software, data privacy breaches by employees, insiders or others with authorized access, cyber or phishing-attacks, ransomware, malware, social engineering, physical breaches or other actions. These cybersecurity threat actors, whether internal or external to us, are becoming more sophisticated and coordinated in their attempts to access the Company’s information technology systems and data, including the information technology systems of cloud providers and other third parties with whom the Company conducts business.
Although we have implemented information technology controls and systems that are designed to protect information and mitigate the risk of data loss and other cybersecurity risks, such measures cannot entirely eliminate cybersecurity threats, and the enhanced controls we have installed may be breached. If our information technology systems cease to function properly or our cybersecurity is breached, we could suffer disruptions to our normal operations. A cyber-attack involving our information systems and related infrastructure, or that of our business associates, could negatively impact our operations in a variety of ways, including, but not limited to, the following:
● Unauthorized access to seismic data, reserves information, strategic information, or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and natural gas resources;
● A cyber-attack on a vendor or service provider could result in supply chain disruptions which could delay or halt our major development projects;
● A cyber-attack on third-party gathering, pipeline, or rail transportation systems could delay or prevent our outside operators from transporting and marketing production, resulting in a loss of revenues;
● A cyber-attack which halts activities at a power generation facility or refinery using natural gas as feed stock could have a significant impact on the natural gas market, resulting in reduced demand for our production, lower natural gas prices, and reduced revenues;
● A deliberate corruption of our financial or operating data could result in events of non-compliance which could then lead to regulatory fines or penalties; and
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All of the above could negatively impact our operational and financial results. Additionally, certain cyber incidents, such as surveillance, may remain undetected for an extended period. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities. Additionally, the growth of cyber-attacks has resulted in evolving legal and compliance matters which impose significant costs that are likely to increase over time.
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. As of March 31, 2021, 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 46% of the outstanding shares of our common stock. Mr. Taylor is also our Chairman of the Board and Chief Executive Officer. As a result, Mr. Taylor has significant influence in matters voted on by our shareholders, including the election of our Board members. Mr. Taylor participates in all facets of our business and has a significant impact on both our business strategy and daily operations. The retirement, incapacity or death of Mr. Taylor, or any change in the power to vote shares beneficially owned by Mr. Taylor, could result in negative market or industry perception and could have an adverse effect on our business.
RISKS RELATED TO OUR COMMON STOCK
We may issue additional shares of common stock in the future, which could cause dilution to all shareholders.
We may seek to raise additional equity capital in the future. Any issuance of additional shares of our common stock will dilute the percentage ownership interest of all shareholders and may dilute the book value per share of our common stock.
We have not and do not anticipate paying any cash dividends on our common stock in the foreseeable future.
We have paid no cash dividends on our common stock to date and it is not anticipated that any will be paid to holders of our common stock in the foreseeable future. The terms of our existing credit facility restricts the payment of dividends without the prior written consent of the lenders. We currently intend to retain all future earnings to fund the development and growth of our business. Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that our board of directors deems relevant. Stockholders must rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment.
Control by our executive officers and directors may limit your ability to influence the outcome of matters requiring stockholder approval and could discourage our potential acquisition by third parties.
As of March 31, 2021, our executive officers and directors beneficially owned approximately 51% of our common stock. These stockholders, if acting together, would be able to influence significantly all matters requiring approval by our stockholders, including the election of our board of directors and the approval of mergers or other business combination transactions.
The price of our common stock has been volatile and could continue to fluctuate substantially.
Mexco common stock is traded on the New York Stock Exchange’s NYSE American. The market price of our common stock has and could continue to experience volatility due to reasons unrelated to our operating performance. These reasons include: supply and demand for oil and natural gas; 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.
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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.
Our properties consist primarily of oil and gas wells and our ownership in leasehold acreage, both developed and undeveloped. As of March 31, 2021, we had interests in approximately 6,400 gross (20 net) oil and gas wells and owned leasehold mineral, royalty and other interests in approximately 586,000 gross (3,169 net) acres.
Oil and Natural Gas Reserves
In accordance with current SEC rules, the average prices used in computing reserves at March 31, 2021 were $37.42 per bbl of oil compared to $53.23 in 2020, a decrease of 30%, and $2.29 per mcf of natural gas compared to $1.66 in 2020, an increase of 38%, 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 2021. The benchmark price of $36.49 per bbl of oil at March 31, 2021 versus $52.23 at March 31, 2020, was adjusted by lease for gravity, transportation fees and regional price differentials and did not give effect to derivative transactions. The benchmark price of $2.16 per mcf of natural gas at March 31, 2021 versus $2.30 at March 31, 2020, 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.
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, 2021 and 2020 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.
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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.
PROVED RESERVES
| March 31, | ||||||||
| 2021 | 2020 | |||||||
| Oil (Bbls): | ||||||||
| Proved developed – Producing | 344,610 | 314,460 | ||||||
| Proved developed – Non-producing | 68,440 | 43,770 | ||||||
| Proved undeveloped | 325,020 | 649,570 | ||||||
| Total | 738,070 | 1,007,800 | ||||||
| Natural gas (Mcf): | ||||||||
| Proved developed – Producing | 3,172,130 | 2,970,280 | ||||||
| Proved developed – Non-producing | 467,200 | 373,930 | ||||||
| Proved undeveloped | 956,050 | 1,506,160 | ||||||
| Total | 4,595,380 | 4,850,370 | ||||||
| Total net proved reserves (BOE) (1) | 1,503,970 | 1,816,195 | ||||||
| PV-10 Value (2) | $ | 13,758,300 | $ | 21,636,700 | ||||
| Present value of future income tax discounted at 10% | (995,300 | ) | (2,660,700 | ) | ||||
| Standardized measure of discounted future net cash flows (3) | $ | 12,763,000 | $ | 18,976,000 | ||||
| Prices used in Calculating Reserves: (4) | ||||||||
| Natural gas (per Mcf) | $ | 2.29 | $ | 1.66 | ||||
| Oil (per Bbl) | $ | 37.42 | $ | 53.23 | ||||
| (1) | These reserve estimates do not include the Company’s interest in the LLC referred to in Item 1. Business – Company Profile on page 4 hereto. |
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| (2) | 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%. | |
| (3) | 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. | |
| (4) | These prices reflect adjustment by lease for quality, transportation fees and regional price differentials and did not give effect to derivative transactions. |
During fiscal 2021, we added proved reserves of 139 thousand BOE (“MBOE”) through extensions and discoveries, subtracted 23 MBOE through sales of oil and gas properties and downward revisions of previous estimates of 324 MBOE. Such downward revisions are primarily the result of reserves written off due to the five-year limitation. They are primarily working interests in a unit in the Wolfcamp B Zone in Upton and Reagan Counties, Texas which are on a lease held by production and still in place to be developed in the future.
During the fiscal year ending March 31, 2021, we had a working or royalty interest in the development of 35 wells converting reserves of approximately 83,200 BOE from proved undeveloped to proved developed – producing with capital cost of approximately $947,000.
Oil and gas prices significantly impact the calculation of the PV-10 and the standardized measure of discounted future net cash flows. The present value of future net cash flows does not purport to be an estimate of the fair market value of the Company’s proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money and the risks inherent in producing oil and gas. Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The 10% discount factor used to calculate present value, which is required by Financial Accounting Standards Board (“FASB”) 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.
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, 2021, and no major discovery is believed to have caused a significant change in our estimates of proved reserves since that date.
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, | ||||||||||||||||
| 2021 | 2020 | |||||||||||||||
| Gross | Net | Gross | Net | |||||||||||||
| Exploratory Wells | ||||||||||||||||
| Productive | - | - | - | - | ||||||||||||
| Nonproductive | - | - | - | - | ||||||||||||
| Total | - | - | - | - | ||||||||||||
| Development Wells | ||||||||||||||||
| Productive - Horizontal | 22 | .12 | 50 | .16 | ||||||||||||
| Productive - Vertical | 3 | .01 | 8 | .02 | ||||||||||||
| Nonproductive - Vertical | - | - | - | - | ||||||||||||
| Total | 25 | .13 | 58 | .18 | ||||||||||||
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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 57 gross wells (.13 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, 2021, we held an interest in approximately 6,400 gross (20 net) productive wells, including approximately 5,100 wells in which we held an overriding or royalty interest and 1,100 wells in which we held a working interest.
A gross acre is an acre in which an interest is owned. A net acre is deemed to exist when the sum of fractional ownership interests in gross acres equals one. The number of net acres is the sum of the fractional interests owned in gross acres. The following table sets forth the approximate developed acreage in which we held a leasehold mineral or other interest as of March 31, 2021:
| Developed Acres | ||||||||
| Gross | Net | |||||||
| Texas | 379,600 | 1,797 | ||||||
| Oklahoma | 85,300 | 1,039 | ||||||
| New Mexico | 31,600 | 196 | ||||||
| Louisiana | 36,700 | 25 | ||||||
| North Dakota | 22,700 | 29 | ||||||
| Kansas | 9,700 | 41 | ||||||
| Montana | 5,000 | 1 | ||||||
| Ohio | 6,500 | 25 | ||||||
| Wyoming | 3,800 | 5 | ||||||
| Arkansas | 1,600 | 5 | ||||||
| Mississippi | 1,000 | 2 | ||||||
| Alabama | 1,000 | 2 | ||||||
| Colorado | 1,100 | 1 | ||||||
| Virginia | 100 | 1 | ||||||
| Total | 585,700 | 3,169 | ||||||
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:
| Years Ended March 31, | ||||||||
| 2021 | 2020 | |||||||
| Oil (a): | ||||||||
| Production (Bbls) | 50,327 | 44,301 | ||||||
| Revenue | $ | 2,028,792 | $ | 2,310,127 | ||||
| Average Bbls per day (d) | 137 | 121 | ||||||
| Average sales price per Bbl | $ | 40.31 | $ | 52.15 | ||||
| Gas (b): | ||||||||
| Production (Mcf) | 324,205 | 294,007 | ||||||
| Revenue | $ | 744,987 | $ | 410,226 | ||||
| Average Mcf per day (d) | 888 | 805 | ||||||
| Average sales price per Mcf | $ | 2.30 | $ | 1.40 | ||||
| Total BOE (c) | 104,361 | 93,302 | ||||||
| Production costs: | ||||||||
| Production expenses: | $ | 643,541 | $ | 700,739 | ||||
| Production expenses per BOE | $ | 6.17 | $ | 7.51 | ||||
| Production expenses per sales dollar | $ | 0.23 | $ | 0.26 | ||||
| Production and ad valorem taxes: | $ | 228,422 | $ | 213,910 | ||||
| Production and ad valorem taxes per BOE | $ | 2.19 | $ | 2.29 | ||||
| Production and ad valorem taxes per sales dollar | $ | 0.08 | $ | 0.08 | ||||
| Total oil and gas revenue | $ | 2,773,779 | $ | 2,720,353 | ||||
| (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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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.
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 | |||||||||
| 2021: | April - June 2020 | $ | 5.24 | $ | 2.00 | |||||
| July - September 2020 | 14.63 | 2.92 | ||||||||
| October - December 2020 | 8.79 | 4.60 | ||||||||
| January - March 2021 | 14.25 | 5.50 | ||||||||
| 2020: | April - June 2019 | $ | 6.10 | $ | 3.37 | |||||
| July - September 2019 | 5.70 | 3.70 | ||||||||
| October - December 2019 | 4.98 | 3.60 | ||||||||
| January - March 2020 | 4.25 | 1.75 | ||||||||
On June 14, 2021, the closing sales price of our common stock on the NYSE American was $8.85 per share.
Stockholders
As of March 31, 2021, we had 2,143,666 shares issued and 856 shareholders of record which does not include shareholders for whom shares are held in a “nominee” or “street” name.
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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 without written permission.
Securities Authorized for Issuance Under Compensation Plans
The following table includes certain information about our Employee Incentive Stock Plan as of March 31, 2021, 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 | 115,000 | $ | 5.38 | - | |||||||||||
| 2019 Plan | 200,000 | 41,000 | 3.34 | 159,000 | ||||||||||||
| Total | 400,000 | 156,000 | $ | 5.28 | 159,000 | |||||||||||
Issuer Repurchases
In September 2020, 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, 2021 and 2020.
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 credit facilty. 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 and to optimize allocation of resources, 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.
Cash Flows
Changes in the net funds provided by or (used in) each of our operating, investing and financing activities are set forth in the table below:
| For the Years Ended March 31, | ||||||||||||
| 2021 | 2020 | % Difference | ||||||||||
| Net cash provided by operating activities | 710,047 | 864,960 | (18 | )% | ||||||||
| Net cash used in investing activities | (1,387,624 | ) | (1,741,565 | ) | (20 | )% | ||||||
| Net cash provided by financing activities | 701,009 | 782,734 | (10 | )% | ||||||||
Cash Flow Provided by Operating Activities. Cash flow from operating activities is primarily derived from the production of our crude oil and natural gas reserves and changes in the balances of non-cash accounts, receivables, payables or other non-energy property asset account balances. Cash flow provided by our operating activities for the year ended March 31, 2021 was $710,047 in comparison to $864,960 for the year ended March 31, 2020. Changes in our cash flow operating activities for the year ended March 31, 2021 in comparison to the year ended March 31, 2020 were ($154,913) and consisted of an increase in our non-cash expenses of $4,979; an increase in our accounts receivable of $431,992; an increase of $48,052 in our accounts payable and accrued expenses; a decrease in other assets of $30.421; and, an increase in our net income for the current year compared to a net loss the prior year of $255,410. Variations in cash flow from operating activities may impact our level of exploration and development expenditures.
Our expenditures in operating activities consist primarily of drilling expenses, production expenses and engineering services. Our expenses also consist of employee compensation, accounting, insurance and other general and administrative expenses that we have incurred in order to address normal and necessary business activities of a public company in the crude oil and natural gas production industry.
Cash Flow Used in Investing Activities. Cash flow from investing activities is derived from changes in oil and gas property balances. For the year ended March 31, 2021, we had net cash of $1,337,624 used for additions to oil and gas properties and a $50,000 investment in a limited liability company compared to $1,591,565 and $150,000, respectively, for the year ended March 31, 2020.
Cash Flow Provided by Financing Activities. Cash flow from financing activities is derived from our changes in long-term debt and in equity account balances. Cash flow provided by our financing activities was $701,009 for the year ended March 31, 2021 compared to $782,734 for the year ended March 31, 2020. During the years ended March 31, 2021 and 2020, we received advances of $935,000 and $1,285,000, respectively, from our credit facility. For the year ended March 31, 2021 and March 31, 2020, we made payments of $550,000 and $490,000, respectively, on the credit facility. For the year ended March 31, 2021, we received proceeds of $247,435 for the exercise of employee and director stock options and $68,574 under the paycheck protection program (PPP).
Accordingly, net cash increased $23,432, leaving cash and cash equivalents on hand of $57,813 as of March 31, 2021.
We had working capital of $618,960 as of March 31, 2021 compared to working capital of $186,785 as of March 31, 2020, an increase of $409,849 for the reasons set forth below.
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Oil and Natural Gas Property Development
The Company participated in the drilling and completion of 22 horizontal wells at a cost of approximately $1,030,000 for the fiscal year ending March 31, 2021, of which 12 have not been completed. All of these horizontal wells are in the Delaware Basin located in the western portion of the Permian Basin in Lea and Eddy Counties, New Mexico.
In addition to the above working interests, there were 57 gross wells (.13 net wells) drilled by other operators on Mexco’s royalty interests,
Participations in Fiscal 2021. Mexco participated in the drilling and completion of two horizontal wells in the Wolfcamp formation of the Delaware Basin located in the western portion of the Permian Basin in Lea County, New Mexico with aggregate costs of approximately $233,000. These wells were completed in September 2020 with initial average production rates of 1,224 barrels of oil, 4,881 barrels of water and 3,422,000 cubic feet of gas per day, or 1,794 barrels of oil equivalent per day. Mexco’s working interest in these wells is 1.2%.
Mexco participated in the drilling and completion of four horizontal wells in the Wolfcamp formation of the Delaware Basin located in the western portion of the Permian Basin in Lea County, New Mexico with aggregate costs of approximately $370,000. Mexco’s working interest in these wells is 1.2%. These wells were completed in March and April 2021 with initial average production rates of 1,044 barrels of oil, 4,686 barrels of water and 2,898,000 cubic feet of gas per day, or 1,527 barrels of oil equivalent per day.
Mexco expended $271,000 to participate in the drilling and completion of five horizontal wells in the Upper Avalon formation of the Delaware Basin located in the western portion of the Permian Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .5%. These wells were completed in February 2021 with initial average production rates of 1,126 barrels of oil, 2,036 barrels of water and 2,108,000 cubic feet of gas per day, or 1,477 barrels of oil equivalent per day.
Mexco participated in the drilling of two horizontal wells in the Wolfcamp formation of the Delaware Basin located in the western portion of the Permian Basin in Lea County, New Mexico with aggregate costs of approximately $74,000. Mexco’s working interest in these wells is 1.2%. Subsequently, in April 2021, Mexco expended another $108,000 to complete these wells.
The Company expended $28,500 for its share to participate in the drilling and completion of two horizontal wells in the 3rd Bone Spring Sand formation of the Delaware Basin located in the western portion of the Permian Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .1%. Subsequently, these wells were completed in April 2021 with initial average production rates of 1,225 barrels of oil, 3,891 barrels of water and 2,905,000 cubic feet of gas per day, or 1,709 barrels of oil equivalent per day. Also in April 2021, the Company expended $11,400 to participate in the drilling of two additional wells on this acreage.
Mexco invested approximately $49,000 in the drilling of four horizontal wells in the Upper and Middle Wolfcamp formation of the Delaware Basin located in the western portion of the Permian Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .36%. These wells are planned to be drilled during fiscal 2022.
Mexco participated in the drilling of four horizontal wells in the Wolfcamp formation of the Delaware Basin located in the western portion of the Permian Basin in Lea County, New Mexico with aggregate costs of approximately $67,000. Mexco’s working interest in these wells is .56%. Subsequently, in May 2021, Mexco expended approximately $109,000 to complete these wells.
The Company also participated in the drilling and completion of three vertical wells in Winkler County, Texas at an aggregate cost of $12,400. Mexco’s working interest in these wells is .41%. These wells, operated by Blackbeard Operating, LLC are currently producing.
Completion of Wells Drilled in Fiscal 2020. The Company expended approximately $270,000 which was the balance of the completion costs of 22 horizontal wells located in Lea and Eddy Counties, New Mexico which were drilled during fiscal 2020. As of January 2021, all of these wells have been completed and are currently producing.
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Sales of Properties. Effective July 1, 2020, the Company sold its interest in the deep rights of a property in Martin County, Texas for a cash payment of $100,000.
Participations Subsequent to Fiscal 2021. In May 2021, Mexco expended approximately $28,000 to participate in the drilling of two horizontal wells in the Wolfcamp Sand formation of the Delaware Basin located in the western portion of the Permian Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .37%.
In May 2021, Mexco expended approximately $70,000 to participate in the drilling of four horizontal wells in the Lower Wolfcamp Shale of the Delaware Basin in Eddy County, New Mexico. Mexco’s working interest in these wells is .44%.
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.
Markets. 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 negative $41.25 per bbl in April 2020 to a high of $62.07 per bbl in March 2021. The Henry Hub Spot Market Price (“Henry Hub”) for natural gas has ranged from a low of $1.33 per MMBtu in September 2020 to a high of $23.86 per MMBtu in February 2021.
On March 31, 2021 the WTI posted price for crude oil was $55.14 per bbl and the Henry Hub spot price for natural gas was $2.52 per MMBtu. See Results of Operations below for realized prices.
Results of Operations
Fiscal 2021 Compared to Fiscal 2020
We had net income of $155,932 for the year ended March 31, 2021 compared to a net loss of $99,478 for the year ended March 31, 2020. This is primarily the result of an increase in natural gas sales and a decrease in operating expenses partially offset by a decrease in oil sales as further explained below.
Oil and natural gas sales. Revenue from oil and natural gas sales was $2,773,779 for the year ended March 31, 2021, a 2% increase from $2,720,353 for the year ended March 31, 2020. This resulted from an increase in oil and natural gas production and an increase in natural gas prices partially due to improved availability of pipeline capacities of natural gas. This increase was partially offset by a decrease in oil prices. The following table sets forth our oil and natural gas revenues, production quantities and average prices received during the fiscal years ended March 31:
| 2021 | 2020 | % Difference | ||||||||||
| Oil: | ||||||||||||
| Revenue | $ | 2,028,792 | $ | 2,310,127 | (12.1 | )% | ||||||
| Volume (bbls) | 50,327 | 44,301 | 13.6 | % | ||||||||
| Average Price (per bbl) | $ | 40.31 | $ | 52.15 | (22.7 | )% | ||||||
| Gas: | ||||||||||||
| Revenue | $ | 744,987 | $ | 410,226 | 81.6 | % | ||||||
| Volume (mcf) | 324,205 | 294,007 | 10.3 | % | ||||||||
| Average Price (per mcf) | $ | 2.30 | $ | 1.40 | 64.3 | % | ||||||
Production and exploration. Production costs were $871,963 in fiscal 2021, a 5% decrease from $914,649 in fiscal 2020. This was primarily the result of a decrease in lease operating expenses due to numerous wells being shut-in during the month of May 2020 as well as cost cutting measures being implemented by the operators because of the depressed oil prices.
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Depreciation, depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expense was $906,361 in fiscal 2021, a 6% increase from $853,801 in fiscal 2020. This was primarily due to an increase in oil and gas production and a decrease in oil and gas reserves partially offset by a decrease in the full cost pool amortization base.
General and administrative expenses. General and administrative expenses were $833,431 for the year ended March 31, 2021, a 17% decrease from $1,006,531 for the year ended March 31, 2020. This was primarily due to a decrease in salaries, contract services, engineering fees and accounting fees.
Interest expense. Interest expense was $53,232 in fiscal 2021, a 41% increase from $37,656 in fiscal 2020, due to an increase in borrowings partially offset by a decrease in interest rate.
PPP loan forgiveness. PPP loan forgiveness in the amount of $68,957 for the fiscal year ended March 31, 2021 was for the forgiveness of our PPP loan in the amount of $68,574 and $383 in accrued interest expense. The Company received the proceeds for this loan in May 2020 and applied for and received loan forgiveness in November 2020.
Income taxes. There was no federal income tax for fiscal 2021 or fiscal 2020. The effective tax rate for fiscal 2021 and fiscal 2020 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, 2021:
| Payments due in: | ||||||||||||||||
| Total | less than 1 year | 1 - 3 years | over 3 years | |||||||||||||
| Contractual obligations: | ||||||||||||||||
| Secured bank credit facility (1) | $ | 1,180,000 | $ | - | $ | 1,180,000 | $ | - | ||||||||
| Leases (2) | $ | 21,965 | $ | 21,965 | $ | - | $ | - | ||||||||
| (1) | These amounts represent the balances outstanding under the bank credit facility. This repayment assumes that interest will be paid on a monthly basis, no additional funds will be drawn and does not include estimated interest $44,250 less than 1 year, and $44,250 1-3 years. |
| (2) | The lease amount represents the monthly rent amount for our principal office space in Midland, Texas under one three-year lease agreement effective May 15, 2018. Of this total obligation for the remainder of the lease, our majority shareholder will pay $5,393 for his portion of the shared office space. |
Alternative Capital Resources
Although we have primarily used cash from operating activities, the sales of assets and funding from the credit facility 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.
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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.
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.
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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. Revenues from our royalty and non-operated working interest properties are recorded under the cash receipts approach as directly received from the remitters’ statement accompanying the revenue check. Since the revenue checks are generally received two to four months after the production month, the Company accrues for revenue earned but not received by estimating production volumes and product prices. Any identified differences between its revenue estimates and actual revenue received historically have not been significant.
The Company records transportation and processing costs that are incurred after control of its product has transferred to the customer as a reduction of “Natural gas sales” on the Consolidated Statement of Operations.
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.
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Accounts Receivable. Our accounts receivable includes trade receivables from joint interest owners and oil and gas purchasers. Credit is extended based on an evaluation of a customer’s financial condition and, generally, is uncollateralized. Accounts receivable under joint operating agreements have a right of offset against future oil and gas revenues if a producing well is completed. The collectability of receivables is assessed and an allowance is made for any doubtful accounts. The allowance for doubtful accounts is determined based on 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.
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.
Investments. The Company accounts for investments of less than 1% in limited liability companies using the cost method. The cost of the investment is recorded as an asset on the consolidated balance sheets and when income from the investment is received, it is immediately recognized on the consolidated statements of operations.
Leases. The Company determines an arrangement is a lease at inception. Operating leases are recorded in operating lease right-of-use asset, operating lease liability, current, and operating lease liability, long-term on the consolidated balance sheets.
Operating lease right-of-use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent its obligation to make lease payments arising from the lease. Operating lease assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. As the Company’s lease does not provide an implicit rate, the Company uses the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The incremental borrowing rate used at adoption was 6.0%. Significant judgement is required when determining the incremental borrowing rate. The Company chose not to discount because the difference is not significant. Rent expense for lease payments is recognized on a straight-line basis over the lease term.
Recent Accounting Pronouncements. In December 2019, the FASB issued ASU No. 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes” (“ASU 2019-12”), which simplifies various aspects of the income tax accounting guidance in ASC 740, including requirements related to the following: (i) hybrid tax regimes; (ii) the tax basis step-up in goodwill obtained in a transaction that is not a business combination; (iii) separate financial statements of entities not subject to tax; (iv) the intraperiod tax allocation exception to the incremental approach; (v) ownership changes in investments - changes from a subsidiary to an equity method investment (and vice versa); (vi) interim-period accounting for enacted changes in tax laws; and (vii) the year-to-date loss limitation in interim-period tax accounting. ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years and early adoption is permitted. If an entity early adopts these amendments in an interim period, it should reflect any adjustments as of the beginning of the annual period that includes that interim period. In addition, an entity that elects to early adopt ASU 2019-12 is required to adopt all of the amendments in the same period. The Company adopted ASU 2019-12 on April 1, 2021 and it will not have a material impact on its financial position, results of operations and disclosures.
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. At March 31, 2021, we had an outstanding loan balance of $1,180,000 under our credit agreement, which bears interest at a rate equal to the prime rate as quoted in the Wall Street Journal plus one-half of one percent (0.5%) floating daily. If the interest rate on our bank debt increases or decreases by one percentage point our annual pretax income would change by $11,800 based on the outstanding balance at March 31, 2021.
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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, 2021, our largest credit risk associated with any single purchaser was $440,715 or 71% 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 applicable to our natural gas and crude oil production. 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. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future.
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.
Oil prices dropped sharply in early March 2020, and then continued to decline reaching levels below zero dollars per barrel. This was a result of multiple factors affecting supply and demand in global oil and gas markets, including the announcement of price reductions and production increases by OPEC members and other oil exporting nations and the ongoing COVID-19 pandemic. Oil and natural gas prices are expected to continue to be volatile as a result of the changes in oil and natural gas production, inventories and demand, as well as national and international economic performance. We cannot predict when prices will stabilize.
For example, in the last twelve months, the NYMEX West Texas Intermediate (“WTI”) posted price for crude oil has ranged from a low of negative $41.25 per bbl in April 2020 to a high of $62.07 per bbl in March 2021. The Henry Hub Spot Market Price (“Henry Hub”) for natural gas has ranged from a low of $1.33 per MMBtu in September 2020 to a high of $23.86 per MMBtu in February 2021. On March 31, 2021 the WTI posted price for crude oil was $55.14 per bbl and the Henry Hub spot price for natural gas was $2.52 per MMBtu.
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 ten dollars per barrel for fiscal 2021, our oil revenue would have changed by $503,270. If the average gas price had increased or decreased by one dollar per mcf for fiscal 2021, natural gas revenue would have changed by $324,205.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by this item appears on pages F1 through F24 hereof and are incorporated herein by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
None.
| 29 |
ITEM 9A. CONTROLS AND PROCEDURES
Management’s Annual Report on Internal Control over Financial Reporting. The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Exchange Act Rule 13a-15(f) and 15d-15(f). The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements. Our internal control over financial reporting is supported by appropriate reviews by management, written policies and guidelines, careful selection and training of qualified personnel, and a written Code of Conduct adopted by our Board of Directors, applicable to all directors, officers and employees of Mexco.
Our chief executive officer and chief financial officer assessed the effectiveness our internal control over financial reporting using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in the 2013 “Internal Control - Integrated Framework”. Based upon that evaluation, our chief executive officer and chief financial officer concluded that our internal control over financial reporting was effective as of March 31, 2021.
Evaluation of Disclosure Controls and Procedures. We maintain disclosure controls and procedures to ensure that the information we must disclose in our filings with the SEC is recorded, processed, summarized and reported on a timely basis. At the end of the period covered by this report, our principal executive officer and principal financial officer reviewed and evaluated the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rule 13a-15(e). Based on such evaluation, such officers concluded that, as of March 31, 2021, our disclosure controls and procedures were effective.
Changes in Internal Control over Financial Reporting. No changes in the Company’s internal control over financial reporting occurred during the year ended March 31, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
See “Mexco Energy Corporation Board of Directors”, “Named Executive Officers Who Are Not Directors”, “Section 16(a) Beneficial Ownership Reporting Compliance”, “Corporate Governance and Code of Business Conduct” and “Meetings and Committees of the Board of Directors” in the Proxy Statement of Mexco Energy Corporation for our Annual Meeting of Stockholders to be held September 9, 2021 (“Proxy Statement”) to be filed with the SEC within 120 days after the end of our fiscal year ended March 31, 2021, which is incorporated herein by reference.
The information required by this item with respect to executive officers of the Company is also set forth in Part I of this report.
ITEM 11. EXECUTIVE COMPENSATION
The information required by this item will be contained in the Proxy Statement under the caption “Executive Compensation”, and is hereby incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required by this item will be contained in the Proxy Statement under the captions “Security Ownership of Certain Beneficial Owners and Management” and “Employee Incentive Stock Option Plans”, and is hereby incorporated herein by reference.
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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.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Consolidated Financial Statements. For a list of the consolidated financial statements filed as part of this Form 10-K, see the “Index to Consolidated Financial Statements” set forth on F-1 of this report.
Financial Statement Schedules. All schedules have been omitted because they are not applicable, not required under the instructions or the information requested is set forth in the consolidated financial statements or related notes thereto.
Exhibits. For a list of the exhibits required by this Item and accompanying this Form 10-K see the “Index to Exhibits” set forth on page F25 of this report.
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Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
MEXCO ENERGY CORPORATION
| By: | /s/ Nicholas C. Taylor | By: | /s/ Tamala L. McComic | |
| Chairman of the Board and Chief Executive Officer | President and Chief Financial Officer |
Dated: June 25, 2021
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below as of June 25, 2021, by the following persons on behalf of the Registrant and in the capacity indicated.
| /s/ Nicholas C. Taylor | |
| Nicholas C. Taylor | |
| Chief Executive Officer, Chairman of the Board of Directors |
| /s/ Tamala L. McComic | |
| Tamala L. McComic | |
| Chief Financial Officer, President, Treasurer and Assistant Secretary |
| /s/ Michael J. Banschbach | |
| Michael J. Banschbach | |
| Director |
| /s/ Kenneth L. Clayton | |
| Kenneth L. Clayton | |
| Director |
| /s/ Thomas R. Craddick | |
| Thomas R. Craddick | |
| Director |
| /s/ Thomas H. Decker | |
| Thomas H. Decker | |
| Director |
| /s/ Christopher M. Schroeder | |
| Christopher M. Schroeder | |
| Director |
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Glossary of Abbreviations and Terms
The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report.
Basin. A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
Bbl. One stock tank barrel, or 42 U.S. gallons of liquid volume, used herein in reference to crude oil, condensate or natural gas liquids hydrocarbons.
BOE. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
BTU. British thermal unit.
Completion. The installation of permanent equipment for the production of oil or natural gas.
Condensate. Liquid hydrocarbons associated with the production of a primarily natural gas reserve.
Credit Facility. A line of credit provided by a bank or group of banks, secured by oil and gas properties.
DD&A. Refers to depreciation, depletion and amortization of the Company’s property and equipment.
Developed acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.
Development costs. Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.
Development well. A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Exploration. The search for natural accumulations of oil and natural gas by any geological, geophysical or other suitable means.
Exploratory well. A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.
Extensions and discoveries. As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates.
Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.
Formation. A layer of rock which has distinct characteristics that differs from nearby rock.
Gross acres or wells. Refers to the total acres or wells in which the Company owns any amount of working interest.
Lease. An instrument which grants to another (the lessee) the exclusive right to enter and explore for, drill for, produce, store and remove oil and natural gas from the mineral interest, in consideration for which the lessor is entitled to certain rents and royalties payable under the terms of the lease. Typically, the duration of the lessee’s authorization is for a stated term of years and “for so long thereafter” as minerals are producing.
Mcf. One thousand cubic feet of natural gas at standard atmospheric conditions.
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MBOE. One thousand barrels of oil equivalent.
MMBOE. One million barrels of oil equivalent.
MMBtu. One million British thermal units of energy commonly used to measure heat value or energy content of natural gas.
Natural gas liquids (“NGLs”). Liquid hydrocarbons that have been extracted from natural gas, such as ethane, propane, butane and natural gasoline.
Net acres or wells. Refers to gross acres or wells multiplied, in each case, by the percentage interest owned by the Company.
Net production. Oil and gas production that is owned by the Company, less royalties and production due others.
Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.
Oil. Crude oil or condensate.
Operator. The individual or company responsible for the exploration, development and production of an oil or natural gas well or lease.
Overriding royalty interest (“ORRI”). A royalty interest that is created out of the operating or working interest. Its term is coextensive with that of the operating interest from which it was created.
Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed operating and production expenses and taxes.
Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved developed nonproducing reserves (“PDNP”). Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells.
Proved developed producing reserves (“PDP”). Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods.
Proved developed reserves. The combination of proved developed producing and proved developed nonproducing reserves.
Proved reserves. The estimated quantities of oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved undeveloped reserves (“PUD”). Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion.
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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.
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INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
| F-1 |
Report of Independent Registered Public Accounting Firm
Board of Directors and Stockholders
Mexco Energy Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Mexco Energy Corporation (a Colorado corporation) and Subsidiaries (the Company) as of March 31, 2021 and 2020, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the two years in the period ended March 31, 2021, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of March 31, 2021 and 2020, and the results of its operations and its cash flows for each of the two years in the period ended March 31, 2021, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the entity’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved are especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Estimation of proved reserves impacting the recognition and valuation of depletion expense and impairment of oil and gas properties
| F-2 |
Critical Accounting Matter Description
As described in Note 2 to the financial statements, the Company accounts for its oil and gas properties using the full cost method of accounting which requires management to make estimates of proved reserve volumes and future revenues and expenses to calculate depletion expense and measure its oil and gas properties for potential impairment. To estimate the volume of proved reserves and future revenues, management makes significant estimates and assumptions, including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected, with reasonable certainty, to be economical under the appropriate pricing assumptions required in the estimation of depletion expense and potential impairment measurements. We identified the estimation of proved reserves of oil and gas properties, due to its impact on depletion expense and impairment evaluation, as a critical audit matter.
The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain inputs and assumptions, which require a high degree of subjectivity necessary to estimate the volume and future revenues of the Company’s proved reserves could have a significant impact on the measurement of depletion expense or the impairment assessment. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.
How the Critical Audit Matter Was Addressed in the Audit
We obtained an understanding of the design and implementation of management’s controls and our audit procedures related to the estimation of proved reserves included the following, among others.
| ● | We evaluated the level of knowledge, skill, and ability of the Company’s reservoir engineering specialists and their relationship to the Company, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the reserve report prepared by the Company’s specialists. | |||
| ● | To the extent key, sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, such as commodity pricing, historical pricing differentials, operating costs, estimated capital costs and working and net revenue interests, we tested management’s process for determining the assumptions, including examining the underlying support, on a sample basis. Specifically, our audit procedures involved testing management’s assumptions as follows: | |||
| - | Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials; | |||
| - | Evaluated the models used to estimate the operating costs at year-end compared to historical operating costs; | |||
| - | Compared the models used to determine the future capital expenditures and compared estimated future capital expenditures used in the reserve report to amounts expended for recently drilled and completed wells with similar locations; | |||
| - | Evaluated the working and net revenue interests used in the reserve report by inspecting a sample of ownership interests, historical pricing differentials, and operating costs to underlying support from the Company’s accounting records. | |||
| F-3 |
| - | Evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s or the operator’s intent to develop the proved undeveloped properties; | |
| - | Applied analytical procedures to the reserve report by comparing to historical actual results and to the prior year reserve report. |
/s/ WEAVER AND TIDWELL, L.L.P.
We have served as the Company’s auditor since 2017.
Midland, Texas
June 25, 2021
| F-4 |
The accompanying notes to the consolidated financial statements are an integral part of these statements.
| F-5 |
The accompanying notes to the consolidated financial statements are an integral part of these statements.
| F-6 |
Mexco Energy Corporation and Subsidiaries
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
Years ended March 31, 2021 and 2020
| Common Stock Par Value | Additional Paid-In Capital | Retained Earnings | Treasury Stock | Total Stockholders’ Equity | ||||||||||||||||
| Balance at April 1, 2019 | $ | 1,053,583 | $ | 7,305,048 | $ | 416,907 | $ | (346,001 | ) | $ | 8,429,537 | |||||||||
| Net loss | - | - | (99,478 | ) | - | (99,478 | ) | |||||||||||||
| Stock based compensation | - | 34,303 | - | - | 34,303 | |||||||||||||||
| Balance at March 31, 2020 | $ | 1,053,583 | $ | 7,339,351 | $ | 317,429 | $ | (346,001 | ) | $ | 8,364,362 | |||||||||
| Net income | - | - | 155,932 | - | 155,932 | |||||||||||||||
| Issuance of stock through options exercised | 18,250 | 229,185 | - | - | 247,435 | |||||||||||||||
| Stock based compensation | - | 55,678 | - | - | 55,678 | |||||||||||||||
| Balance at March 31, 2021 | $ | 1,071,833 | $ | 7,624,214 | $ | 473,361 | $ | (346,001 | ) | $ | 8,823,407 | |||||||||
| SHARE ACTIVITY | ||||||||
| 2021 | 2020 | |||||||
| Common stock shares, issued: | ||||||||
| At beginning of year | 2,107,166 | 2,107,166 | ||||||
| Issued | 36,500 | - | ||||||
| At end of year | 2,143,666 | 2,107,166 | ||||||
| Common stock shares, held in treasury: | ||||||||
| At beginning of year | (67,000 | ) | (67,000 | ) | ||||
| Acquisitions | - | - | ||||||
| At end of year | (67,000 | ) | (67,000 | ) | ||||
| Common stock shares, outstanding | ||||||||
| At end of year | 2,076,666 | 2,040,166 | ||||||
The accompanying notes to the consolidated financial statements are an integral part of these statements.
| F-7 |
The accompanying notes to the consolidated financial statements are an integral part of these statements.
| F-8 |
MEXCO ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Years Ended March 31, 2021 and 2020
1. Nature of Operations
Mexco Energy Corporation (a Colorado corporation) and its wholly owned subsidiaries, Forman Energy Corporation (a New York corporation), Southwest Texas Disposal Corporation (a Texas corporation) and TBO Oil & Gas, LLC (a Texas limited liability company) (collectively, the “Company”) are engaged in the exploration, development and production of crude oil, natural gas, condensate and natural gas liquids (“NGLs”). Most of the Company’s oil and gas interests are centered in West Texas and Southeastern New Mexico; however, the Company owns producing properties and undeveloped acreage in fourteen states. All of the Company’s oil and gas interests are operated by others.
2. Summary of Significant Accounting Policies
Principles of Consolidation. The consolidated financial statements include the accounts of Mexco Energy Corporation and its wholly owned subsidiaries. All significant intercompany balances and transactions associated with the consolidated operations have been eliminated.
Estimates and Assumptions. In preparing financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”), management is required to make informed judgments, estimates and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. In addition, significant estimates are used in determining proved oil and gas reserves. Although management believes its estimates and assumptions are reasonable, actual results may differ materially from those estimates. The estimate of the Company’s oil and natural gas reserves, which is used to compute depreciation, depletion, amortization and impairment of oil and gas properties, is the most significant of the estimates and assumptions that affect these reported results.
Cash and Cash Equivalents. The Company considers all highly liquid debt instruments purchased with maturities of three months or less and money market funds to be cash equivalents. The Company maintains cash in bank deposit accounts that may, at times, exceed federally insured limits. At March 31, 2021, the Company had all of its cash and cash equivalents with one financial institution. The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk.
Accounts Receivable. Accounts receivable includes trade receivables from joint interest owners and oil and gas purchasers. Credit is extended based on an evaluation of a customer’s financial condition and, generally, is uncollateralized. Accounts receivable under joint operating agreements have a right of offset against future oil and gas revenues if a producing well is completed. The collectibility of receivables is assessed and an allowance is made for any doubtful accounts. The allowance for doubtful accounts is determined based on the Company’s previous loss history. The Company has not experienced any significant credit losses. For the years ended March 31, 2021 and 2020, no allowance has been made for doubtful accounts.
Oil and Gas Properties. Oil and gas properties are accounted for using the full cost method of accounting. Under this method of accounting, the costs of unsuccessful, as well as successful, acquisition, exploration and development activities are capitalized as property and equipment. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation (“ARO”) when incurred. Generally, no gains or losses are recognized on the sale or disposition of oil and gas properties.
| F-9 |
Excluded Costs. Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent investments in unproved properties and major development projects. These costs are excluded until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed at least quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the capitalized costs being amortized (the depreciation, depletion and amortization (“DD&A”) pool). Impairments transferred to the DD&A pool increase the DD&A rate. No costs were excluded for the years ended March 31, 2021 and 2020.
Ceiling Test. Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is an impairment test to determine a limit, or ceiling, on the book value of oil and gas properties. That limit is the after-tax present value of the future net cash flows from proved crude oil and natural gas reserves and using an average price over the prior first day of the month 12-month period held flat for the life of production plus the lower of cost or fair market value of unproved properties. If net capitalized costs of crude oil and natural gas properties exceed the ceiling limit, the Company must charge the amount of the excess to earnings as an expense reflected in additional accumulated DD&A. This is called a “ceiling limitation write-down.” This impairment to our oil and gas properties does not impact cash flow from operating activities, but does reduce stockholders’ equity and reported earnings.
Depreciation, Depletion and Amortization. The depreciable base for oil and gas properties includes the sum of capitalized costs, net of accumulated DD&A, estimated future development costs and asset retirement costs not accrued in oil and gas properties, less costs excluded from amortization and salvage. The depreciable base of oil and gas properties is amortized using the unit-of-production method.
Asset Retirement Obligations. The Company has significant obligations to plug and abandon natural gas and crude oil wells and related equipment at the end of oil and gas production operations. The Company records the fair value of a liability for an ARO in the period in which it is incurred and a corresponding increase in the carrying amount of the related asset. Subsequently, the asset retirement costs included in the carrying amount of the related asset are allocated to expense using the units of production method. In addition, increases in the discounted ARO liability resulting from the passage of time are reflected as accretion expense in the Consolidated Statements of Operations.
Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. The Company uses the present value of estimated cash flows related to the ARO to determine the fair value. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the related asset.
Income Taxes. The Company recognizes deferred tax assets and liabilities for future tax consequences of temporary differences between the carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates applicable to the years in which those differences are expected to be settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in net income in the period that includes the enactment date. Any interest and penalties are recorded as interest expense and general and administrative expense, respectively.
Other Property and Equipment. Provisions for depreciation of office furniture and equipment are computed on the straight-line method based on estimated useful lives of three to ten years.
Income (Loss) Per Common Share. Basic net income (loss) per share is computed by dividing net income (loss) by the weighted average number of common shares outstanding during the period. Diluted net income (loss) per share assumes the exercise of all stock options having exercise prices less than the average market price of the common stock during the period using the treasury stock method and is computed by dividing net income (loss) by the weighted average number of common shares and dilutive potential common shares (stock options) outstanding during the period. In periods where losses are reported, the weighted-average number of common shares outstanding excludes potential common shares, because their inclusion would be anti-dilutive.
| F-10 |
Revenue Recognition - Revenue from Contracts with Customers. Revenues from our royalty and non-operated working interest properties are recorded under the cash receipts approach as directly received from the remitters’ statement accompanying the revenue check. Since the revenue checks are generally received two to four months after the production month, the Company accrues for revenue earned but not received by estimating production volumes and product prices. Any identified differences between its revenue estimates and actual revenue received historically have not been significant.
The Company records transportation and processing costs that are incurred after control of its product has transferred to the customer as a reduction of “Natural gas sales” on the Consolidated Statement of Operations.
Gas Balancing. Gas imbalances are accounted for under the sales method whereby revenues are recognized based on production sold. A liability is recorded when excess takes of natural gas volumes exceed estimated remaining recoverable reserves (over produced). No receivables are recorded for those wells where the Company has taken less than its ownership share of gas production (under produced). The Company does not have any significant gas imbalances.
Stock-based Compensation. The Company uses the Binomial option pricing model to estimate the fair value of stock-based compensation expenses at grant date. This expense is recognized as compensation expense in its consolidated financial statements over the vesting period. The Company recognizes the fair value of stock-based compensation awards as wages within general and administrative expense in the Consolidated Statements of Operations based on a graded-vesting schedule over the vesting period.
Investments. The Company accounts for investments of less than 1% in limited liability companies at cost. The Company has no control of the limited liability companies. The cost of the investment is recorded as an asset on the consolidated balance sheets and when income from the investment is received, it is immediately recognized on the consolidated statements of operations.
Derivative Financial Instruments. The Company’s derivative financial instruments are used to manage commodity price risk attributable to expected oil and gas production. While there is risk the financial benefit of rising oil and gas prices may not be captured, the Company believes the benefits of stable and predictable cash flows outweigh the potential risks.
The Company accounts for derivative financial instruments using fair value accounting and recognizes gains and losses in earnings during the period in which they occur. Unsettled derivative instruments are recorded in the accompanying consolidated balance sheets as either a current or non-current asset or a liability measured at its fair value. The Company only offsets derivative assets and liabilities for arrangements with the same counterparty when right of offset exists. Derivative assets and liabilities with different counterparties are recorded gross in the consolidated balance sheets. Derivative contract settlements are reflected in operating activities in the accompanying consolidated statements of cash flows.
The Company uses certain pricing models to determine the fair value of its derivative financial instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties. Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets.
Recent Accounting Pronouncements. In December 2019, the FASB issued ASU No. 2019-12, “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes” (“ASU 2019-12”), which simplifies various aspects of the income tax accounting guidance in ASC 740, including requirements related to the following: (i) hybrid tax regimes; (ii) the tax basis step-up in goodwill obtained in a transaction that is not a business combination; (iii) separate financial statements of entities not subject to tax; (iv) the intraperiod tax allocation exception to the incremental approach; (v) ownership changes in investments - changes from a subsidiary to an equity method investment (and vice versa); (vi) interim-period accounting for enacted changes in tax laws; and (vii) the year-to-date loss limitation in interim-period tax accounting. ASU 2019-12 is effective for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years and early adoption is permitted. If an entity early adopts these amendments in an interim period, it should reflect any adjustments as of the beginning of the annual period that includes that interim period. In addition, an entity that elects to early adopt ASU 2019-12 is required to adopt all of the amendments in the same period. The Company adopted ASU 2019-12 on April 1, 2021 and it will not have a material impact on its financial position, results of operations and disclosures.
| F-11 |
Liquidity and Capital Resources. Historically, we have funded our operations, acquisitions, exploration and development expenditures from cash generated by operating activities, bank borrowings, sales of non-core properties and issuance of common stock. Our long-term strategy is on increasing profit margins while concentrating on obtaining reserves with low cost operations by acquiring and developing oil and gas properties with potential for long-lived production. We focus our efforts on the acquisition of royalties and working interest, non-operated properties in areas with significant development potential.
3. Fair Value of Financial Instruments
The Company applies FASB ASC Topic 820, Fair Value Measurements and Disclosure (“ASC Topic 820”), which establishes a framework for measuring fair value based upon inputs that market participants use in pricing an asset or liability, which are classified into two categories: observable inputs or unobservable inputs. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company’s own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. These two types of inputs are further prioritized into the following fair value input hierarchy:
Level 1: Quoted prices for identical instruments in active markets at the measurement date.
Level 2: Quoted prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets at the measurement date and for the anticipated term of the instrument.
Level 3: Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable inputs that reflect the reporting entity’s own assumptions about the assumptions market participants would use in pricing the asset or liability acquired, based on the best information available in the circumstances.
The carrying amount reported in the accompanying consolidated balance sheets for cash and cash equivalents, accounts receivable and accounts payable approximates fair value because of the immediate or short-term maturity of these financial instruments.
The fair value amount reported in the accompanying consolidated balance sheets for long-term debt approximates fair value because the actual interest rates do not significantly differ from current rates offered for instruments with similar characteristics. See the Company’s Note 5 on Long Term Debt for further discussion.
Fair Value Measurements on a Recurring Basis
A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.
The Company’s commodity derivative instruments were carried at fair value on a recurring basis in the Company’s consolidated balance sheets. The Company uses certain pricing models to determine the fair value of its derivative financial instruments. Inputs to the pricing models include publicly available prices and forward price curves generated from a compilation of data gathered from third parties.
Company management validates the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets. Assumed credit risk adjustments, based on published credit ratings and public bond yield spreads are applied to the Company’s commodity derivatives. The Company’s derivative instruments are subject to netting arrangements and qualify for net presentation in the consolidated balance sheets in those instances where such arrangements exist with the respective counterparty.
| F-12 |
To ensure these derivative instruments are recorded at fair value, valuation adjustments may be required to reflect the creditworthiness of either party as well as market constraints on liquidity. There was no adjustment as of March 31, 2021.
Fair Value Measurements on a Nonrecurring Basis
The asset retirement obligation estimates are derived from historical costs and management’s expectation of future cost environments and, therefore, the Company has designated these liabilities as Level 3 measurements. The significant inputs to this fair value measurement include estimates of plugging, abandonment and remediation costs, well life, inflation and credit-adjusted risk-free rate. See Note 6 for a reconciliation of the beginning and ending balances of the liability for the Company’s asset retirement obligations.
4. Derivative Financial Instruments
It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive.
The Company is exposed to certain risks relating to its ongoing business operations, such as commodity price risk. Derivative contracts are utilized to economically hedge the Company’s exposure to price fluctuations and reduce the variability in the Company’s cash flows associated with anticipated sales of future oil and natural gas production. The Company follows FASB ASC Topic 815, Derivatives and Hedging (ASC Topic 815), to account for its derivative financial instruments.
The Company’s crude oil derivative positions consisted of put options. The Company has elected not to designate any of its derivative contracts for hedge accounting. Accordingly, the Company records the net change in the mark-to-market valuation of these derivative contracts, as well as all payments and receipts on settled derivative contracts, in net realized and unrealized gain (loss) on commodity price hedging contracts on the consolidated statements of operations. All derivative contracts are recorded at fair market value and included in the consolidated balance sheets as assets or liabilities. As of March 31, 2021 and 2020, the Company had no derivative contracts.
The Company may have multiple hedge positions that span a several-month time period and result in fair value asset and liability positions. At the end of the reporting periods, those positions are offset to a single fair value asset or liability for each commodity and the netted balance is reflected in the consolidated balance sheets as an asset or liability.
During the quarter ended June 30, 2020 the Company entered into a series of crude oil put option contracts. All of these such contracts expired in July and August 2020.
The following tables summarizes the amounts of the Company’s realized and unrealized losses on derivative contracts listed as loss on derivative instruments in the Company’s consolidated statements of operations for the year ended March 31, 2021.
| Loss Recognized | ||||
| Realized loss on oil price hedging contracts | $ | (19,200 | ) | |
| Unrealized gain (loss) on oil price hedging contracts | - | |||
| Net realized and unrealized loss on derivative contracts | $ | (19,200 | ) | |
5. Long-Term Debt
Long-term debt on the Consolidated Balance Sheets consisted of the following as of March 31:
| 2021 | 2020 | |||||||
| Credit facility | $ | 1,180,000 | $ | 795,000 | ||||
| Unamortized debt issuance costs | (25,051 | ) | (37,577 | ) | ||||
| Total long-term debt | $ | 1,154,949 | $ | 757,423 | ||||
| F-13 |
On December 28, 2018, the Company entered into a loan agreement (the “Agreement”) with West Texas National Bank (“WTNB”), which provided for a credit facility of $1,000,000 with a maturity date of December 28, 2021. The Agreement has no monthly commitment reduction and a borrowing base to be evaluated annually.
On February 28, 2020, the Agreement was amended to increase the credit facility to $2,500,000, extend the maturity date to March 28, 2023 and increase the borrowing base to $1,500,000.
Under the Agreement, interest on the facility accrues at a rate equal to the prime rate as quoted in the Wall Street Journal plus one-half of one percent (.5%) floating daily. Interest on the outstanding amount under the Agreement is payable monthly. In addition, the Company will pay an unused commitment fee in an amount equal to one-half of one percent (.5%) times the daily average of the unadvanced amount of the commitment. The unused commitment fee is payable quarterly in arrears on the last day of each calendar quarter. As of March 31, 2021, there was $320,000 available on the facility.
No principal payments are anticipated to be required through the maturity date of the credit facility, March 28, 2023. Upon closing with WTNB on the original Agreement, the Company paid a .5% loan origination fee in the amount of $5,000 plus legal and recording expenses totaling $34,532, which were deferred over the life of the credit facility. Upon closing the amendment to the Agreement, the Company paid a .1% loan origination fee of $2,500 and an extension fee of $3,125 plus legal and recording expenses totaling $12,266, which were also deferred over the life of the credit facility.
Amounts borrowed under the Agreement are collateralized by the common stock of the Company’s wholly owned subsidiaries and substantially all of the Company’s oil and gas properties.
The Agreement contains customary covenants for credit facilities of this type including limitations on change in control, disposition of assets, mergers and reorganizations. The Company is also obligated to meet certain financial covenants under the Agreement and requires senior debt to earnings before interest, taxes, depreciation and amortization (“EBITDA”) ratios (Senior Debt/EBITDA) less than or equal to 4.00 to 1.00 measured with respect to the four trailing fiscal quarters and minimum interest coverage ratios (EBITDA/Interest Expense) of 2.00 to 1.00 for each quarter.
In addition, the Agreement prohibits the Company from paying cash dividends on its common stock without prior written permission of WTNB. The Agreement does not permit the Company to enter into hedge agreements covering crude oil and natural gas prices without prior WTNB approval. The Company obtained written permission from WTNB prior to entering into the current hedge agreement discussed in Note 4.
The balance outstanding on the credit facility as of March 31, 2021 was $1,180,000. The following table is a summary of activity on the WTNB credit facility for the years ended March 31, 2021 and 2020:
| Principal | ||||
| Balance at April 1, 2019: | $ | - | ||
| Borrowings | 1,285,000 | |||
| Repayments | 490,000 | |||
| Balance at March 31, 2020: | $ | 795,000 | ||
| Borrowings | 935,000 | |||
| Repayments | 550,000 | |||
| Balance at March 31, 2021: | $ | 1,180,000 | ||
Subsequently, the Company has borrowed $100,000 and made payments totaling $480,000, leaving a balance of $800,000 as of June 21, 2021.
The Company also maintained a Certificate of Deposit Account at WTNB to collateralize one outstanding letter of credit for $25,000 in lieu of a plugging bond with the Texas Railroad Commission covering the properties the Company operates. This operated property was sold effective December 1, 2019 and the letter of credit was cancelled. On April 10, 2020, the Certificate of Deposit Account was terminated and the funds deposited into the Company’s operating account.
| F-14 |
6. Asset Retirement Obligations
The Company’s asset retirement obligations relate to the plugging of wells, the removal of facilities and equipment, and site restoration on oil and gas properties. The fair value of a liability for an ARO is recorded in the period in which it is incurred, discounted to its present value using the credit adjusted risk-free interest rate, and a corresponding amount capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted each period until the liability is settled or the well is sold, at which time the liability is removed. The related asset retirement cost is capitalized as part of the carrying amount of our oil and natural gas properties. The ARO is included on the consolidated balance sheets with the current portion being included in the accounts payable and accrued expenses.
The following table provides a rollforward of the asset retirement obligations for fiscal years ended March 31:
| 2021 | 2020 | |||||||
| Carrying amount of asset retirement obligations, beginning of year | $ | 762,761 | $ | 861,534 | ||||
| Liabilities incurred | 17,587 | 19,512 | ||||||
| Liabilities settled | (80,099 | ) | (145,520 | ) | ||||
| Accretion expense | 28,548 | 27,235 | ||||||
| Revisions | - | - | ||||||
| Carrying amount of asset retirement obligations, end of year | 728,797 | 762,761 | ||||||
| Less: Current portion | 15,000 | 7,500 | ||||||
| Non-Current asset retirement obligation | $ | 713,797 | $ | 755,261 | ||||
7. Income Taxes
The Company files a consolidated federal income tax return and various state income tax returns. The amount of income taxes the Company records requires the interpretation of complex rules and regulations of federal and state taxing jurisdictions. With few exceptions, the earliest year open to examination by U.S. federal and state income tax jurisdictions is 2016.
On December 22, 2017, the tax legislation referred to as the 2017 Tax Reform Act (“Tax Cuts and Jobs Act”) was enacted. The more significant changes that impact the Company are the reduction in the corporate federal income tax rate from 35% to 21%. Effective April 1, 2018, our corporate federal statutory income tax rate is 21%. GAAP requires deferred income tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled.
Significant components of net deferred tax assets (liabilities) at March 31 are as follows:
| 2021 | 2020 | |||||||
| Deferred tax assets: | ||||||||
| Percentage depletion carryforwards | $ | 1,132,352 | $ | 1,167,594 | ||||
| Deferred stock-based compensation | 37,977 | 36,568 | ||||||
| Asset retirement obligation | 153,048 | 160,180 | ||||||
| Net operating loss | 1,411,017 | 1,248,528 | ||||||
| Other | 9,840 | 7,372 | ||||||
| 2,744,234 | 2,620,242 | |||||||
| Deferred tax liabilities: | ||||||||
| Excess financial accounting bases over tax bases of property and equipment | 1,485,833 | 1,313,271 | ||||||
| Deferred tax asset, net | $ | 1,258,401 | $ | 1,306,971 | ||||
| Valuation allowance | (1,258,401 | ) | (1,306,971 | ) | ||||
| Net deferred tax | $ | - | $ | - | ||||
As of March 31, 2021, the Company has a statutory depletion carryforward of approximately $5,400,000, which does not expire. At March 31, 2021, the Company had a net operating loss carryforward for regular income tax reporting purposes of approximately $6,700,000, which will begin expiring in 2029. The Company’s ability to use some of its net operating loss carryforwards and certain other tax attributes to reduce current and future U.S. federal taxable income is subject to limitations under the Internal Revenue Code.
| F-15 |
A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, and we consider the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry.
A reconciliation of the provision for income taxes to income taxes computed using the federal statutory rate for years ended March 31 follows:
| 2021 | 2020 | |||||||
| Tax expense at federal statutory rate (1) | $ | 32,746 | $ | (20,891 | ) | |||
| Statutory depletion carryforward | 35,242 | (31,384 | ) | |||||
| Change in valuation allowance | (48,570 | ) | 46,850 | |||||
| U. S. tax reform, corporate rate reduction | - | - | ||||||
| Permanent differences | (19,418 | ) | 5,427 | |||||
| Other | - | (2 | ) | |||||
| Total income tax | $ | - | $ | - | ||||
| Effective income tax rate | - | - | ||||||
| (1) | The federal statutory rate was 21% for fiscal years ending March 31, 2021 and 2020. |
For the years ended March 31, 2021 and 2020, the Company did not have any uncertain tax positions.
While the amount of unrecognized tax benefits may change in the next 12 months, the Company does not expect any change to have a significant impact on its results of operations. The recognition of the total amount of the unrecognized tax benefits would have an impact on the effective tax rate. If these unrecognized tax benefits are disallowed, the Company will be required to pay additional taxes.
Based on the material write-downs of the carrying value of our oil and natural gas properties for the year ending March 31, 2016, we are in a net deferred tax asset position for years ending March 31, 2021 and 2020. Our deferred tax asset is $1,258,401 as of March 31, 2021 with a valuation amount of $1,258,401. We believe it is more likely than not that these deferred tax assets will not be realized. Management assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future taxable income are increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as expected future growth.
In December 2020, the President of the United States signed the Consolidated Appropriations Act, 2021 (“the Act”). The Act includes many tax provisions, including the extension of various expiring provisions, extensions and expansions of certain earlier pandemic tax relief provisions, among other things. The Act did not have a material impact on the Company’s current year tax provision or the Company’s consolidated financial statements.
In March 2020, the President of the United States signed the Coronavirus Aid, Relief, and Economic Security Act (“CARES Act”) to stabilize the economy during the coronavirus pandemic. The CARES Act temporarily suspends and modifies certain tax laws established by the 2017 Tax Cuts and Jobs Act, including, but not limited to, modifications to net operating loss limitations, business interest limitations and alternative minimum tax. The CARES Act did not have a material impact on the Company’s current year provision and the Company’s consolidated financial statements.
| F-16 |
8. Major Customers
Currently, the Company operates exclusively within the United States and its revenues and operating profit are derived from the oil and gas industry. Oil and gas production is sold to various purchasers and the receivables are unsecured. Historically, the Company has not experienced significant credit losses on its oil and gas accounts and management is of the opinion that significant credit risk does not exist. Management is of the opinion that the loss of any one purchaser would not have an adverse effect on the Company’s ability to sell its oil and gas production.
In fiscal 2021, one customer accounted for 66% of the total oil and natural gas revenues and 71% of the total oil and natural gas accounts receivable. In fiscal 2020, one customer accounted for 52% of the total oil and natural gas revenues and 63% of the total oil and natural gas accounts receivable.
9. Oil and Natural Gas Costs
The costs related to the Company’s oil and natural gas activities were incurred as follows for the years ended March 31:
| 2021 | 2020 | |||||||
| Property acquisition costs: | ||||||||
| Proved | $ | - | $ | - | ||||
| Unproved | - | - | ||||||
| Exploration | - | 168 | ||||||
| Development | 1,581,109 | 1,687,499 | ||||||
| Capitalized asset retirement obligations | 17,587 | 19,512 | ||||||
| Total costs incurred for oil and gas properties | $ | 1,598,696 | $ | 1,707,179 | ||||
The Company had the following aggregate capitalized costs relating to its oil and gas property activities at March 31:
| 2021 | 2020 | |||||||
| Proved oil and gas properties | $ | 38,664,347 | $ | 37,465,172 | ||||
| Unproved oil and gas properties: | ||||||||
| subject to amortization | - | - | ||||||
| not subject to amortization | - | - | ||||||
| 38,664,347 | 37,465,172 | |||||||
| Less accumulated DD&A | 28,906,419 | 28,003,961 | ||||||
| $ | 9,757,928 | $ | 9,461,211 | |||||
DD&A amounted to $8.68 and $9.15 per BOE of production for the years ended March 31, 2021 and 2020, respectively.
10. Income (Loss) Per Common Share
The following is a reconciliation of the number of shares used in the calculation of basic income per share and diluted income per share for the years ended March 31:
| 2021 | 2020 | |||||||
| Net income (loss) | $ | 155,932 | $ | (99,478 | ) | |||
| Shares outstanding: | ||||||||
| Weighted avg. common shares outstanding – basic | 2,050,678 | 2,040,166 | ||||||
| Effect of the assumed exercise of dilutive stock options | 11,392 | - | ||||||
| Weighted avg. common shares outstanding – dilutive | 2,062,070 | 2,040,166 | ||||||
| Income (loss) per common share: | ||||||||
| Basic | $ | 0.08 | $ | (0.05 | ) | |||
| Diluted | $ | 0.08 | $ | (0.05 | ) | |||
For the year ended March 31, 2021, no anti-dilutive shares relating to stock options were excluded from the computation of diluted net income. Due to a net loss for the year ended March 31, 2020, the weighted average number of common shares outstanding excludes common stock equivalents because their inclusion would be anti-dilutive.
| F-17 |
11. Stockholders’ Equity
In September 2020, the Board of Directors authorized the use of up to $250,000 to repurchase shares of the Company’s common stock for the treasury account. There were no shares of common stock repurchased for the treasury account during fiscal 2021 and 2020.
12. Stock-based Compensation
In September 2019, the Company adopted the 2019 Employee Incentive Stock Plan (the “2019 Plan”). The 2019 Plan provides for the award of stock options up to 200,000 shares and includes option awards as well as stock awards. Option awards are granted with the restriction of requiring payment for the shares. Stock awards are granted without restrictions and without payment by the recipient. Neither option awards nor stock awards may exceed 25,000 shares granted to any one individual in any fiscal year. Stock options may be an incentive stock option or a nonqualified stock option. Options to purchase common stock under the plan are granted at the fair market value of the common stock at the date of grant, become exercisable to the extent of 25% of the shares optioned on each of four anniversaries of the date of grant, expire ten years from the date of grant and are subject to forfeiture if employment terminates. The 2019 Plan expires ten years from the date of adoption. According to the Company’s employee stock incentive plan, new shares will be issued upon the exercise of stock options and the Company can repurchase shares exercised under the plan.
During the year ended March 31, 2021, there were no stock options issued. During the year ended March 31, 2020, the Compensation Committee of the Board of Directors approved and the Company issued options covering 42,000 shares of stock. The plan also provides for the granting of stock awards. No stock awards were granted during fiscal 2021 and 2020.
The Company recognized compensation expense of $55,678 and $34,303 related to vesting stock options in general and administrative expense in the Consolidated Statements of Operations for fiscal 2021 and 2020, respectively. The total cost related to non-vested awards not yet recognized at March 31, 2021 totals $114,131, which is expected to be recognized over a weighted average of 2.35 years.
The fair value of each stock option is estimated on the date of grant using the Binomial valuation model. Expected volatilities are based on historical volatility of the Company’s stock over the contractual term of 120 months and other factors. The Company uses historical data to estimate option exercise and employee termination within the valuation model. The expected term of options granted is derived from the output of the option valuation model and represents the period of time that options granted are expected to be outstanding. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time of grant. As the Company has never declared dividends, no dividend yield is used in the calculation. Actual value realized, if any, is dependent on the future performance of the Company’s common stock and overall stock market conditions. There is no assurance the value realized by an optionee will be at or near the value estimated by the Binomial model.
Included in the following table is a summary of the grant-date fair value of stock options granted and the related assumptions used in the Binomial models for stock options granted in fiscal 2021 and 2020. All such amounts represent the weighted average amounts for each period.
| For the year ended March 31, | ||||||||
| 2021 | 2020 | |||||||
| Grant-date fair value | - | $ | 2.24 | |||||
| Volatility factor | - | 60.12 | % | |||||
| Dividend yield | - | - | ||||||
| Risk-free interest rate | - | .85 | % | |||||
| Expected term (in years) | - | 6.25 | ||||||
No forfeiture rate is assumed for stock options granted to directors or employees due to the forfeiture rate history for these types of awards. During the year ended March 31, 2021, 1,000 unvested stock options were forfeited due to the resignation of an employee and 34,200 vested stock options expired unexercised. During the year ended March 31, 2020, there were no stock options forfeited or expired.
| F-18 |
The following table is a summary of activity of stock options for the years ended March 31, 2021 and 2020:
Number of Shares | Weighted Average Exercise Price Per Share | Weighted Aggregate Average Remaining Contract Life in Years | Intrinsic Value | |||||||||||||
| Outstanding at April 1, 2019 | 185,700 | $ | 6.18 | 4.68 | $ | - | ||||||||||
| Granted | 42,000 | - | ||||||||||||||
| Exercised | - | - | ||||||||||||||
| Forfeited or Expired | - | - | ||||||||||||||
| Outstanding at March 31, 2020 | 227,700 | $ | 5.65 | 4.83 | $ | - | ||||||||||
| Granted | - | - | ||||||||||||||
| Exercised | (36,500 | ) | - | |||||||||||||
| Forfeited or Expired | (35,200 | ) | - | |||||||||||||
| Outstanding at March 31, 2021 | 156,000 | $ | 5.28 | 5.53 | $ | 555,100 | ||||||||||
| Vested at March 31, 2021 | 105,250 | $ | 5.92 | 4.17 | $ | 307,000 | ||||||||||
| Exercisable at March 31, 2021 | 105,250 | $ | 5.92 | 4.17 | $ | 307,000 | ||||||||||
During the year ended March 31, 2021, stock options covering 36,500 shares were exercised with a total intrinsic value of $72,981. The Company received proceeds of $247,435 from these exercises. During the year ended March 31, 2020, no stock options were exercised.
Other information pertaining to option activity was as follows during the year ended March 31:
| 2021 | 2020 | |||||||
| Weighted average grant-date fair value of stock options granted (per share) | $ | - | $ | 2.24 | ||||
| Total fair value of options vested | $ | 55,460 | $ | 32,500 | ||||
| Total intrinsic value of options exercised | $ | 72,981 | $ | - | ||||
The following table summarizes information about options outstanding at March 31, 2021:
| Range of Exercise Prices | Number of Options | Weighted Average Exercise Price Per Share | Weighted Average Remaining Contract Life in Years | Aggregate Intrinsic Value | ||||||||||||||
| $ | 3.34 – 4.83 | 41,000 | $ | 3.34 | ||||||||||||||
| 4.84 – 5.97 | 40,000 | 4.84 | ||||||||||||||||
| 5.98 – 6.26 | 30,000 | 5.98 | ||||||||||||||||
| 6.27 – 7.00 | 45,000 | 6.98 | ||||||||||||||||
| $ | 3.34 – 7.00 | 156,000 | $ | 5.28 | 5.53 | $ | 555,100 | |||||||||||
Outstanding options at March 31, 2021 expire between November 2021 and March 2030 and have exercise prices ranging from $3.34 to $7.00.
13. Related Party Transactions
Related party transactions for the Company primarily relate to shared office expenditures in addition to administrative and operating expenses paid on behalf of the principal stockholder. The total billed to and reimbursed by the stockholder for the years ended March 31, 2021 and 2020 were $39,067 and $44,724, respectively. The principal stockholder pays for his share of the lease amount for the shared office space directly to the lessor. Amounts paid by the principal stockholder directly to the lessor for the year ending March 31, 2021 and 2020 were $16,549 and $15,881, respectively.
| F-19 |
In March 2020, the Company entered into an agreement with our principal shareholder, Nicholas C. Taylor for the sale of surface rights to an undivided interest of 1.98 acres in a 160-acre tract of rural land located in Brazoria County, Texas. Mr. Taylor paid the company approximately $18,000 in cash for these rights, such price being based on a November 22, 2019 appraisal by a firm of MAI appraisers at $9,000 per acre.
14. Leases
The Company leases approximately 4,160 rentable square feet of office space from an unaffiliated third party for the corporate office located in Midland, Texas. This includes 1,021 square feet of office space shared with and reimbursed by the majority shareholder. The lease is a 36-month lease that expired in May 2021 and does not include an option to renew. In June 2020, in exchange for a reduction in rent for the months of June and July 2020, the Company agreed to a 2-month extension to its current lease agreement at the regular monthly rate extending its current lease expiration date to July 2021.
The Company determines an arrangement is a lease at inception. Operating leases are recorded in operating lease right-of-use asset, operating lease liability, current, and operating lease liability, long-term on the consolidated balance sheets.
Operating lease right-of-use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent its obligation to make lease payments arising from the lease. Operating lease assets and liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. As the Company’s lease does not provide an implicit rate, the Company uses the incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The incremental borrowing rate used at adoption was 6.0%. Significant judgement is required when determining the incremental borrowing rate. The Company chose not to discount because the difference is not significant. Rent expense for lease payments is recognized on a straight-line basis over the lease term.
The balance sheets classification of lease assets and liabilities was as follows:
| March 31, 2021 | ||||
| Assets | ||||
| Operating lease right-of-use asset, beginning balance | $ | 76,130 | ||
| Current period amortization | (64,629 | ) | ||
| Lease amendment | (1,622 | ) | ||
| Lease extension | 10,982 | |||
| Total operating lease right-of-use asset | $ | 20,861 | ||
| Liabilities | ||||
| Operating lease liability, current | $ | 21,965 | ||
| Operating lease liability, long term | - | |||
| Total lease liabilities | $ | 21,965 | ||
Future minimum lease payments as of March 31, 2021 under non-cancellable operating leases are as follows:
| Lease Obligation | ||||
| Fiscal Year Ended March 31, 2022 | $ | 21,965 | ||
| Fiscal Year Ended March 31, 2023 | - | |||
| Total lease payments | $ | 21,965 | ||
| Less: imputed interest | - | |||
| Operating lease liability | 21,965 | |||
| Less: operating lease liability, current | (21,965 | ) | ||
| Operating lease liability, long term | $ | - | ||
Net cash paid for our operating lease for the year ended March 31, 2021 and 2020 was $48,360 and $46,447, respectively. Rent expense, less sublease income of $19,109 and $18,234, respectively, is included in general and administrative expenses.
| F-20 |
Subsequently, in June 2021, the Company agreed to extend its current lease for its principal office space located at 415 West Wall Street, Suite 475, Midland, Texas 79701 for 36 months. The amended lease now expires on July 31, 2024.
15. Paycheck Protection Program (PPP) Loan.
On March 27, 2020, the Coronavirus Aid, Relief, and Economic Security Act commonly referred to as the CARES Act became effective. One component of the CARES Act was the paycheck protection program (“PPP”) which provides small businesses with the resources needed to maintain their payroll and cover applicable overhead. The PPP is implemented by the United States Small Business Administration (“SBA”) with support from the Department of the Treasury. The PPP provides funds to pay up to 24 weeks of payroll costs including benefits. Funds can also be used to pay interest on mortgages, rent, and utilities. The Company applied for, and was accepted to participate in this program. On May 5, 2020, the Company received funding for approximately $68,600.
The loan was a two-year loan with a maturity date of May 5, 2022 an annual interest rate of 1% payable monthly with the first six monthly payments deferred. The Company applied for and on November 25, 2020 was approved for loan forgiveness in the amount of $68,957 under the provisions of Section 1106 of the CARES Act. This was for the forgiveness of our PPP loan in the amount of $68,574 and $383 in accrued interest expense. The Company was eligible for loan forgiveness because the Company used all loan proceeds to partially subsidize direct payroll expenses.
16. Oil and Gas Reserve Data (Unaudited)
The estimates of the Company’s proved oil and gas reserves, which are located entirely within the United States, were prepared in accordance with the generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. The estimates as of March 31, 2021 and 2020 were based on evaluations prepared by Russell K. Hall and Associates, Inc. The services provided by Russell K. Hall and Associates, Inc. are not audits of our reserves but instead consist of complete engineering evaluations of the respective properties. For more information about their evaluations performed, refer to the copy of their report filed as an exhibit to this Annual Report on Form 10-K. Management emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.
The following table summarizes the prices utilized in the reserve estimates for 2021 and 2020. Commodity prices utilized for the reserve estimates prior to adjustments for location, grade and quality are as follows:
| March 31, | ||||||||
| 2021 | 2020 | |||||||
| Prices utilized in the reserve estimates before adjustments: | ||||||||
| Oil per Bbl | $ | 36.49 | $ | 52.23 | ||||
| Natural gas per MMBtu | $ | 2.16 | $ | 2.30 | ||||
The Company’s total estimated proved reserves at March 31, 2021 were approximately 1.504 MBOE of which 49% was oil and natural gas liquids and 51% was natural gas.
| F-21 |
Changes in Proved Reserves:
| Oil (Bbls) | Natural Gas (Mcf) | |||||||
| Proved Developed and Undeveloped Reserves: | ||||||||
| As of April 1, 2019 | 1,040,000 | 5,381,000 | ||||||
| Revision of previous estimates | (72,000 | ) | (384,000 | ) | ||||
| Purchase of minerals in place | - | - | ||||||
| Extensions and discoveries | 90,000 | 175,000 | ||||||
| Sales of minerals in place | (6,000 | ) | (28,000 | ) | ||||
| Production | (44,000 | ) | (294,000 | ) | ||||
| As of March 31, 2020 | 1,008,000 | 4,850,000 | ||||||
| Revision of previous estimates | (292,000 | ) | (200,000 | ) | ||||
| Purchase of minerals in place | - | - | ||||||
| Extensions and discoveries | 92,000 | 283,000 | ||||||
| Sales of minerals in place | (20,000 | ) | (14,000 | ) | ||||
| Production | (50,000 | ) | (324,000 | ) | ||||
| As of March 31, 2021 | 738,000 | 4,595,000 | ||||||
Proved developed reserves are those expected to be recovered through existing wells, equipment and operating methods. Proved undeveloped reserves (“PUD”) are proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion within five years of the date of their initial recognition. Moreover, the Company may be required to write down its proved undeveloped reserves if the operators do not drill on the reserves within the required five-year timeframe. Such downward revisions are primarily the result of reserves written off due to the five-year limitation. They are primarily working interests in a unit in the Wolfcamp B Zone in Upton and Reagan Counties, Texas which are on a lease held by production and still in place to be developed in the future.
Summary of Proved Developed and Undeveloped Reserves as of March 31, 2021 and 2020:
| Oil
(Bbls) | Natural
Gas (Mcf) | |||||||
| Proved Developed Reserves: | ||||||||
| As of April 1, 2019 | 376,600 | 3,823,440 | ||||||
| As of March 31, 2020 | 358,230 | 3,344,210 | ||||||
| As of March 31, 2021 | 413,050 | 3,639,330 | ||||||
| Proved Undeveloped Reserves: | ||||||||
| As of April 1, 2019 | 663,860 | 1,557,250 | ||||||
| As of March 31, 2020 | 649,570 | 1,506,160 | ||||||
| As of March 31, 2021 | 325,020 | 956,050 | ||||||
At March 31, 2021, the Company reported estimated PUDs of 484 MBOE, which accounted for 32% of its total estimated proved oil and gas reserves. This figure primarily consists of a projected 121 new wells (263 MBOE) operated by others, 7 wells are currently being drilled with plans for 60 wells to follow in 2022, 48 wells in 2023 and 6 wells in 2024. The cost of these projects would be funded, to the extent possible, from existing cash balances, cash flow from operations and bank borrowings. The remainder may be funded through non-core asset sales and/or sales of our common stock.
The following table discloses the Company’s progress toward the conversion of PUDs during fiscal 2021.
Progress of Converting Proved Undeveloped Reserves:
| Oil & Natural Gas | Future | |||||||
| (BOE) | Development Costs | |||||||
| PUDs, beginning of year | 900,592 | $ | 6,632,064 | |||||
| Revision of previous estimates | (447,215 | ) | (3,765,188 | ) | ||||
| Sales of reserves | (14,394 | ) | - | |||||
| Conversions to PD reserves | (83,202 | ) | (947,290 | ) | ||||
| Additional PUDs added | 128,581 | 1,095,588 | ||||||
| PUDs, end of year | 484,362 | $ | 3,015,174 | |||||
Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using average prices for 2021 and 2020 along with estimates of the operating costs, production taxes and future development costs necessary to produce such reserves. No deduction has been made for depreciation, depletion or any indirect costs such as general corporate overhead or interest expense.
| F-22 |
Operating costs and production taxes are estimated based on current costs with respect to producing oil and natural gas properties. Future development costs including abandonment costs are based on the best estimate of such costs assuming current economic and operating conditions. The future cash flows estimated to be spent to develop the Company’s share of proved undeveloped properties through March 31, 2024 are $3,015,174.
Income tax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production and development costs over the current tax basis of the properties involved, less applicable carryforwards.
The future net revenue information assumes no escalation of costs or prices, except for oil and natural gas sales made under terms of contracts which include fixed and determinable escalation. Future costs and prices could significantly vary from current amounts and, accordingly, revisions in the future could be significant.
The current reporting rules require that year end reserve calculations and future cash inflows be based on the 12-month average market prices for sales of oil and gas on the first calendar day of each month during the fiscal year discounted at 10% per year and assuming continuation of existing economic conditions. The average prices used for fiscal 2021 were $37.42 per bbl of oil and $2.29 per mcf of natural gas. The average prices used for fiscal 2020 were $53.23 per bbl of oil and $1.66 per mcf of natural gas.
The standardized measure of discounted future net cash flows is computed by applying the 12-month unweighted average of the first day of the month pricing for oil and natural gas (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved oil and natural gas reserves, less estimated future expenditures (based on year end costs) to be incurred in developing and producing the proved reserves, discounted using a rate of 10% per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and natural gas properties plus available carryforwards and credits and applying the current tax rate to the difference.
The basis for this table is the reserve studies prepared by an independent petroleum engineering consultant, which contain imprecise estimates of quantities and rates of production of reserves. Revisions of previous year estimates can have a significant impact on these results. Also, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates of proved reserves and their valuation. Therefore, the standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of proved oil and gas properties.
The following information is based on the Company’s best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of March 31, 2021 and 2020 in accordance with ASC 932, “Extractive Activities – Oil and Gas” which requires the use of a 10% discount rate. This information is not the fair market value, nor does it represent the expected present value of future cash flows of the Company’s proved oil and gas reserves.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves:
| March 31 | ||||||||
| 2021 | 2020 | |||||||
| Future cash inflows | $ | 38,144,000 | $ | 61,676,000 | ||||
| Future production costs and taxes | (11,248,000 | ) | (16,682,000 | ) | ||||
| Future development costs | (3,213,000 | ) | (6,984,000 | ) | ||||
| Future income taxes | (1,714,000 | ) | (4,675,000 | ) | ||||
| Future net cash flows | 21,969,000 | 33,335,000 | ||||||
| Annual 10% discount for estimated timing of cash flows | (9,206,000 | ) | (14,359,000 | ) | ||||
| Standardized measure of discounted future net cash flows | $ | 12,763,000 | $ | 18,976,000 | ||||
| F-23 |
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves:
| March 31 | ||||||||
| 2021 | 2020 | |||||||
| Sales of oil and gas produced, net of production costs | $ | (1,902,000 | ) | $ | (1,806,000 | ) | ||
| Net changes in price and production costs | (5,680,000 | ) | (2,871,000 | ) | ||||
| Changes in previously estimated development costs | 2,623,000 | 865,000 | ||||||
| Revisions of quantity estimates | (5,954,000 | ) | (2,140,000 | ) | ||||
| Net change due to purchases and sales of minerals in place | (54,000 | ) | (335,000 | ) | ||||
| Extensions and discoveries, less related costs | 1,150,000 | 1,519,000 | ||||||
| Net change in income taxes | 2,070,000 | 404,000 | ||||||
| Accretion of discount | 1,376,000 | 2,164,000 | ||||||
| Changes in timing of estimated cash flows and other | 158,000 | 1,924,000 | ||||||
| Changes in standardized measure | (6,213,000 | ) | (276,000 | ) | ||||
| Standardized measure, beginning of year | 18,976,000 | 19,252,000 | ||||||
| Standardized measure, end of year | $ | 12,763,000 | $ | 18,976,000 | ||||
17. Subsequent Events
During the first quarter of fiscal 2022, the Company borrowed $100,000 on the credit facility and made payments totaling $480,000 on the credit facility leaving a balance of $800,000.
During the first quarter of fiscal 2022, the Company expended approximately $326,000 for participation in the drilling of eight wells and the completion of six wells in Lea County, New Mexico.
In June 2021, the Company agreed to extend its current lease for its principal office space located at 415 West Wall Street, Suite 475, Midland, Texas 79701 for 36 months. The amended lease now expires on July 31, 2024.
| F-24 |
INDEX TO EXHIBITS
| F-25 |