PART
I
ITEM
1. BUSINESS
General
Mexco
Energy Corporation, a Colorado corporation, is an independent oil and gas company engaged in the acquisition, exploration, development
and production of crude oil and natural gas 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.
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.
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.
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.
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.
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.
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.
ITEM
1A. RISK FACTORS
There
are many factors that affect our business and results of operations, some of which are beyond our control. The following is a description
of some of the important factors that could have a material adverse effect on our business, financial position, liquidity and results
of operations. Some of the following risks relate principally to the industry in which we operate and to our business. Other risks relate
principally to the securities markets and ownership of our common stock.
RISKS
RELATED TO OUR BUSINESS AND INDUSTRY
Volatility
of oil and gas prices significantly affects our results and profitability.
Prices
for oil and natural gas fluctuate widely. We cannot predict future oil and natural gas prices with any certainty. Historically, the markets
for oil and gas have been volatile, and they are likely to continue to be volatile. Factors that can cause price fluctuations include
the level of global demand for petroleum products; foreign supply and pricing of oil and gas; the ability of the Organization of Petroleum
Exporting Countries (“OPEC”) to set and maintain oil price and production controls; nature and extent of governmental regulation
and taxation, including environmental regulations; level of domestic and international exploration, drilling and production activity;
the cost of exploring for, producing and delivering oil and gas; speculative trading in crude oil and natural gas derivative contracts;
availability, proximity and capacity of oil and gas pipelines and other transportation facilities; weather conditions; the price and
availability of alternative fuels; technological advances affecting energy consumption; 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.
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.
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.
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.
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.
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
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.
Many
of these factors are beyond our control, and we cannot predict their potential effects on the price of our common stock. We cannot assure
you that the market price of our common stock will not fluctuate or decline significantly in the future. In addition, the stock markets
in general can experience considerable price and volume fluctuations.
Failure
of the Company’s internal control over financial reporting could harm its business and financial results.
The
management of Mexco is responsible for establishing and maintaining effective internal control over financial reporting. Internal control
over financial reporting is a process to provide reasonable assurance regarding the reliability of financial reporting for external purposes
in accordance with accounting principles generally accepted in the United States. Internal control over financial reporting includes
maintaining records that in reasonable detail accurately and fairly reflect Mexco’s transactions; providing reasonable assurance
that transactions are recorded as necessary for preparation of the financial statements; providing reasonable assurance that receipts
and expenditures are made in accordance with management authorization; and providing reasonable assurance that unauthorized acquisition,
use or disposition of our assets that could have a material effect on the financial statements would be prevented or detected on a timely
basis.
ITEM
1B. UNRESOLVED STAFF COMMENTS
None.
ITEM
2. PROPERTIES
Our
properties consist primarily of oil and gas wells and our ownership in leasehold acreage, both developed and undeveloped. As of March
31, 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.
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.
|
|
(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
|
|
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.
|
ITEM
3. LEGAL PROCEEDINGS
We
may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. We are not
aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under various environmental protection
statutes or other regulations to which we are subject.
ITEM
4. MINE SAFETY DISCLOSURES
Not
applicable.
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
MEXCO
ENERGY CORPORATION
By:
|
/s/
Nicholas C. Taylor
|
|
By:
|
/s/
Tamala L. McComic
|
|
Chairman
of the Board and Chief Executive Officer
|
|
|
President
and Chief Financial Officer
|
Dated:
June 25, 2021
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been signed below as of June 25, 2021, by the following persons
on behalf of the Registrant and in the capacity indicated.
/s/
Nicholas C. Taylor
|
|
Nicholas
C. Taylor
|
|
Chief
Executive Officer, Chairman of the Board of Directors
|
|
/s/
Tamala L. McComic
|
|
Tamala
L. McComic
|
|
Chief
Financial Officer, President, Treasurer and Assistant Secretary
|
|
/s/
Michael J. Banschbach
|
|
Michael
J. Banschbach
|
|
Director
|
|
/s/
Kenneth L. Clayton
|
|
Kenneth
L. Clayton
|
|
Director
|
|
/s/
Thomas R. Craddick
|
|
Thomas
R. Craddick
|
|
Director
|
|
/s/
Thomas H. Decker
|
|
Thomas
H. Decker
|
|
Director
|
|
/s/
Christopher M. Schroeder
|
|
Christopher
M. Schroeder
|
|
Director
|
|
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.
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.
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.
INDEX
TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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.
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.
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.
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
|
|
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.
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.
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.
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.
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.
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.
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.
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.
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.
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
|
|
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.