PART
I
CAUTIONARY
NOTE REGARDING FORWARD-LOOKING STATEMENTS
This
Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933,
as amended, (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended, (the “Exchange
Act”). These forward-looking statements are generally located in the material set forth under the headings “Risk Factors”,
“Management’s Discussion and Analysis of Financial Condition and Results of Operations”, “Business”,
“Properties” but may be found in other locations as well, and are typically identified by the words “could”,
“should”, “expect”, “project”, “estimate”, “believe”, “anticipate”,
“intend”, “budget”, “plan”, “forecast”, “predict” and other similar
expressions.
Forward-looking
statements generally relate to our profitability; planned capital expenditures; estimates of oil and gas production; future project
dates; estimates of future oil and gas prices; estimates of oil and gas reserves; our future financial condition or results of
operations; and our business strategy and other plans and objectives for future operations and are based upon our management’s
reasonable estimates of future results or trends. Actual results in future periods may differ materially from those expressed
or implied by such forward-looking statements because of a number of risks and uncertainties affecting our business, including
those discussed in “Risk Factors”. The factors that may affect our expectations regarding our operations include,
among others, the following: our success in development, exploitation and exploration activities; our ability to make planned
capital expenditures; declines in our production or prices of oil and gas; our ability to raise equity capital or incur additional
indebtedness; our restrictive debt covenants; our acquisition and divestiture activities; weather conditions and events; the proximity,
capacity, cost and availability of pipelines and other transportation facilities; increases in the cost of drilling, completion
and gas gathering or other costs of production and operations; and other factors discussed elsewhere in this document. We
disclaim any intention or obligation to update or revise any forward-looking statements as a result of new information, future
events or otherwise.
ITEM
1. BUSINESS
General
Mexco
Energy Corporation, a Colorado corporation, is an independent oil and gas company engaged in the exploration, development and
production of crude oil and natural gas properties located in the United States. Incorporated in April 1972 under the name Miller
Oil Company, the Company changed its name to Mexco Energy Corporation effective April 30, 1980. At that time, the shareholders
of the Company also approved amendments to the Articles of Incorporation resulting in a one-for-fifty reverse stock split of the
Company’s common stock.
Our
total estimated proved reserves at March 31, 2020 were approximately 1.816 million barrels of oil equivalent (“MMBOE”)
of which 55% was oil and natural gas liquids and 45% was natural gas, and our estimated present value of proved reserves was approximately
$22 million based on estimated future net revenues excluding taxes discounted at 10% per annum, pricing and other assumptions
set forth in “Item 2 – Properties” below. During fiscal 2020, we added proved reserves of 119 thousand BOE (“MBOE”)
through extensions and discoveries and subtracted 136 MBOE through downward revisions of previous estimates. Such downward revisions
are primarily the result of reserves written off due to the five-year limitation. They are primarily royalty interests in the
Barnett Shale in Tarrant County, Texas and the Goldsmith field in Ector County, Texas, both of which are on a lease held by production
and still in place to be developed in the future. There were also reserves written off for a working interest in the Fuhrman Mascho
Field in Andrews County, Texas due to market conditions. These properties are also on a lease held by production and still in
place to be developed in the future.
Nicholas
C. Taylor beneficially owns approximately 47% of the outstanding shares of our common stock. Mr. Taylor is also our Chairman of
the Board and Chief Executive Officer. As a result, Mr. Taylor has significant influence in matters voted on by our shareholders,
including the election of our Board members. Mr. Taylor participates in all facets of our business and has a significant impact
on both our business strategy and daily operations.
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 2021.
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 2020, 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.
Industry
Environment and Outlook
The
challenging commodity price environment continued in fiscal 2020 and in March 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 2021 will continue to include: (1) optimizing cash flows through operating efficiencies
and cost reductions, (2) divesting of non-core assets, and (3) working to balance capital spending with cash flows to minimize
borrowings, reduce debt and maintain ample liquidity.
See
Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for discussion of
our fiscal 2020 operating results and potential impact on fiscal 2021 operating results due to commodity price changes.
Oil
and Gas Operations
As
of March 31, 2020, oil constituted approximately 55% of our total proved reserves and approximately 84% of our revenues for fiscal
2020. Revenues from oil and gas royalty interests accounted for approximately 27% of our revenues for fiscal 2020.
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 92% of our discounted future net cash flows from proved reserves and 78% of our gross revenues.
The
Delaware Basin properties, encompassing 31,165 gross acres, 213 net acres, 513 gross producing wells and 5 net wells account for
approximately 40% of our discounted future net cash flows from proved reserves as of March 31, 2020. For fiscal 2020, these properties
accounted for 54% of our gross revenues and 62% of our net revenues. Of these discounted future net cash flows from proved reserves,
approximately 13% are attributable to proven undeveloped reserves which will be developed through new drilling.
At
March 31, 2020, the Company has 13 drilled but uncompleted wells in the Delaware Basin at an approximate aggregate drilling cost
of $200,000. The Company anticipates aggregate completion costs of approximately $300,000 for these wells. Such completions will
be made as economic conditions are appropriate.
The
Midland Basin properties, encompassing 97,777 gross acres, 298 net acres, 1,031 gross producing wells and 3 net wells account
for approximately 41% of our discounted future net cash flows from proved reserves as of March 31, 2020. For fiscal 2020, these
properties accounted for 22% of our gross revenues and 22% of our net revenues. Of these discounted future net cash flows from
proved reserves, approximately 35% 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 10% of our discounted future net cash flows from proved reserves as of March 31, 2020. For fiscal 2020,
these properties accounted for 1% of our gross revenues and 1% 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 9% 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 6,300 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)
|
|
2020
|
|
|
44,301
|
|
|
|
294,007
|
|
2019
|
|
|
35,359
|
|
|
|
295,133
|
|
2018
|
|
|
34,743
|
|
|
|
318,774
|
|
2017
|
|
|
34,689
|
|
|
|
356,268
|
|
2016
|
|
|
38,930
|
|
|
|
407,939
|
|
Competition
and Markets
The
oil and gas industry is a highly competitive business. Competition for oil and gas reserve acquisitions is significant. We may
compete with major oil and gas companies, other independent oil and gas companies and individual producers and operators, some
of which have financial and personnel resources substantially in excess of those available to us. As a result, we may be placed
at a competitive disadvantage. Competitive factors include price, contract terms and types and quality of service, including pipeline
distribution. The price for oil and gas is widely followed and is generally subject to worldwide market factors. Our ability to
acquire and develop additional properties in the future will depend upon our ability to conduct operations, to evaluate and select
suitable properties and to consummate transactions in this highly competitive environment in a timely manner.
In
addition, the oil and gas industry as a whole also competes with other industries in supplying the energy and fuel requirements
of industrial, commercial and individual consumers. The price and availability of alternative energy sources could adversely affect
our revenue.
Market
factors affect the quantities of oil and natural gas production and the price we can obtain for the production from our oil and
natural gas properties. Such factors include: the extent of domestic production; the level of imports of foreign oil and natural
gas; the general level of market demand on a regional, national and worldwide basis; domestic and foreign economic conditions
that determine levels of industrial production; political events in foreign oil-producing regions 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:
|
|
2020
|
|
|
2019
|
|
Company A
|
|
|
52
|
%
|
|
|
42
|
%
|
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, 2020.
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 2021.
Title
to Properties
The
leasehold properties we own are subject to royalty, overriding royalty and other outstanding interests customary in the industry.
The properties may be subject to burdens such as liens incident to operating agreements and current taxes, development obligations
under oil and gas leases and other encumbrances, easements and restrictions. We do not believe any of these burdens will materially
interfere with the use of these properties.
As
is customary in the oil and gas industry, only a preliminary title examination is conducted at the time properties believed to
be suitable for drilling operations are acquired by us. Prior to the commencement of drilling operations, a thorough title examination
of the drill site tract is conducted and curative work is performed with respect to significant defects, if any, before proceeding
with operations. A thorough title examination has been performed with respect to substantially all leasehold producing properties
currently owned by us. We believe the title to our leasehold properties is good and defensible in accordance with standards generally
acceptable in the oil and gas industry subject to such exceptions that, in the opinion of counsel employed in the various areas
in which we have conducted exploration activities, are not so material as to detract substantially from the use of such properties.
Substantially
all of our properties are currently mortgaged under a deed of trust to secure funding through a line of credit.
Insurance
Our
operations are subject to all the risks inherent in the exploration for and development and production of oil and gas including
blowouts, fires and other casualties. We maintain insurance coverage customary for operations of a similar nature, but losses
could arise from uninsured risks or in amounts in excess of existing insurance coverage.
Executive
Officers
The
following table sets forth certain information concerning the executive officers of the Company as of March 31, 2020.
Name
|
|
Age
|
|
Position
|
Nicholas
C. Taylor
|
|
82
|
|
Chairman
and Chief Executive Officer
|
Tamala
L. McComic
|
|
51
|
|
President,
Chief Financial Officer, Treasurer, and Assistant Secretary
|
Donna
Gail Yanko
|
|
75
|
|
Vice
President and Secretary
|
Set
forth below is a description of the principal occupations during at least the past five years of each executive officer of the
Company.
Nicholas
C. Taylor was elected Chairman of the Board and Chief Executive Officer of the Company in September 2011 and continues to serve
in such capacity on a part time basis, as required. He served as Chief Executive Officer, President and Director of the Company
from 1983 to 2011. From July 1993 to the present, Mr. Taylor has been involved in the independent practice of law and other business
activities. In November 2005 he was appointed by the Speaker of the House to the Texas Ethics Commission and served until February
2010.
Tamala
L. McComic, a Certified Public Accountant, became Controller for the Company in July 2001 and was elected President and Chief
Financial Officer in September 2011. She served the Company as Executive Vice President and Chief Financial Officer from 2009
to 2011 and Vice President and Chief Financial Officer from 2003 to 2009. Prior thereto, Ms. McComic served as Treasurer and Assistant
Secretary of the Company.
Donna
Gail Yanko was appointed to the position of Vice President of the Company in 1990. She has also served as Corporate Secretary
since 1992 and from 1986 to 1992 was Assistant Secretary. From 1986 to 2015, on a part-time basis, she assisted the Chairman of
the Board of the Company in his personal business activities. Ms. Yanko also served as a director of the Company from 1990 to
2008.
Employees
As
of March 31, 2020, we had two full-time and four part-time employees. We believe that relations with these employees are generally
satisfactory. From time to time, we utilize the services of independent geological, land and engineering consultants on a limited
basis and expect to continue to do so in the future. We also utilize the services of independent contractors to perform well drilling
and production operations, including pumping, maintenance, inspection and testing.
Office
Facilities
Our
principal offices are located at 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. Please call
the SEC at 1-800-SEC-0330 for information on the public reference room. The SEC maintains an internet website (www.sec.gov) that
contains annual, quarterly and current reports, proxy statements and other information that issuers, including Mexco, file electronically
with the SEC.
We
also maintain an internet website at www.mexcoenergy.com. In the Investor Relations section, our website contains our Annual Reports
on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and other reports and amendments to those reports as
soon as reasonably practicable after such material is electronically filed with the SEC. Information on our website is not incorporated
by reference into this Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.
Additionally, our Code of Business Conduct and Ethics and the charters of our Audit Committee, Compensation Committee and Nominating
Committee are posted on our website. Any of these corporate documents as well as any of the SEC filed reports are available in
print free of charge to any stockholder who requests them. Requests should be directed to our corporate Assistant Secretary by
mail to P.O. Box 10502, Midland, Texas 79702 or by email to mexco@sbcglobal.net.
ITEM
1A. RISK FACTORS
There
are many factors that affect our business and results of operations, some of which are beyond our control. The following is a
description of some of the important factors that could have a material adverse effect on our business, financial position, liquidity
and results of operations. Some of the following risks relate principally to the industry in which we operate and to our business.
Other risks relate principally to the securities markets and ownership of our common stock.
RISKS
RELATED TO OUR BUSINESS AND INDUSTRY
Volatility
of oil and gas prices significantly affects our results and profitability.
Prices
for oil and natural gas fluctuate widely. We cannot predict future oil and natural gas prices with any certainty. Historically,
the markets for oil and gas have been volatile, and they are likely to continue to be volatile. Factors that can cause price fluctuations
include the level of global demand for petroleum products; foreign supply and pricing of oil and gas; the ability of the Organization
of Petroleum Exporting Countries (“OPEC”) to set and maintain oil price and production controls; nature and extent
of governmental regulation and taxation, including environmental regulations; level of domestic and international exploration,
drilling and production activity; the cost of exploring for, producing and delivering oil and gas; speculative trading in crude
oil and natural gas derivative contracts; availability, proximity and capacity of oil and gas pipelines and other transportation
facilities; weather conditions; the price and availability of alternative fuels; technological advances affecting energy consumption;
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. The extent of the impact of the COVID-19 pandemic on our operational and financial performance, including our ability to
execute our business strategies and initiatives in the expected time frame, is uncertain and depends on various factors, including
how the pandemic and measures taken in response to it impact demand for oil and natural gas, the availability of personnel, equipment
and services critical to the operations of our properties and the impact of potential governmental restrictions on travel, transports
and operations.
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, and so far,
the tentative agreement has not resulted in increased commodity prices. 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, while we expect these matters to negatively impact our short-term results, including
our revenues and operating costs, as well as operating cash flows, the degree of the adverse impact cannot be reasonably estimated
at this time.
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 2020 and 2019.
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
50% and 48% of our total estimated net proved reserves at March 31, 2020 and 2019, 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 2020, differentials averaged ($0.08) per Bbl of oil and ($0.90) per Mcf of gas. Increases
in the differential between the benchmark prices for oil and gas and the wellhead price we receive could significantly reduce
our revenues and our cash flow from operations.
Our
exploration and development drilling may not result in commercially productive reserves.
New
wells that we drill may not be productive, or we may not recover all or any portion of our investment in such wells. The seismic
data and other technologies we use do not allow us to know conclusively prior to drilling a well that crude oil or natural gas
is present or may be produced economically. Drilling for crude oil and natural gas often involves unprofitable efforts, not only
from dry holes but also from wells that are productive but do not produce sufficient net reserves to return a profit at then realized
prices after deducting drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain,
and cost factors can adversely affect the economics of a project.
Drilling
and operating activities are high risk activities that subject us to a variety of factors that we cannot control.
These
factors include availability of workover and drilling rigs, well blowouts, cratering, explosions, fires, formations with abnormal
pressures, pollution, releases of toxic gases and other environmental hazards and risks. Any of these operating hazards could
result in substantial losses to us. In addition, we incur the risk that no commercially productive reservoirs will be encountered,
and there is no assurance that we will recover all or any portion of our investment in wells drilled or re-entered.
Acquisitions
are subject to the risks and uncertainties of evaluating reserves and potential liabilities and may be disruptive and difficult
to integrate into our business.
We
plan to continue growing our reserves through acquisitions. Acquired properties can be subject to significant unknown liabilities.
Prior to completing an acquisition, it is generally not feasible to conduct a detailed review of each individual property to be
acquired in an acquisition. Even a detailed review or inspection of each property may not reveal all existing or potential liabilities
associated with owning or operating the property. Moreover, some potential liabilities, such as environmental liabilities related
to groundwater contamination, may not be discovered even when a review or inspection is performed. Our initial reserve estimates
for acquired properties may be inaccurate. Downward adjustments to our estimated proved reserves, including reserves added through
acquisitions, could require us to write down the carrying value of our oil and gas properties, which would reduce our earnings
and our stockholders’ equity. In addition, we may have to assume cleanup or reclamation obligations or other unanticipated
liabilities in connection with these acquisitions. The scope and cost of these obligations may ultimately be materially greater
than estimated at the time of the acquisition.
We
may not be able to fund the capital expenditures that will be required for us to increase reserves and production.
We
must make capital expenditures to develop our existing reserves and to discover new reserves. Historically, we have used our cash
flow from operations and borrowings under our credit facility to fund our capital expenditures, however, lower oil and gas prices
may prevent these options. Volatility in oil and gas prices, the timing of our drilling programs and drilling results will affect
our cash flow from operations. Lower prices and/or lower production will also decrease revenues and cash flow, thus reducing the
amount of financial resources available to meet our capital requirements, including reducing the amount available to pursue our
drilling opportunities.
The
borrowing base under our credit facility will be determined from time to time by the lender. Reductions in estimates of oil and
gas reserves could result in a reduction in the borrowing base, which would reduce the amount of financial resources available
under the credit facility to meet our capital requirements. Such a reduction could be the result of lower commodity prices and/or
production, inability to drill or unfavorable drilling results, changes in oil and gas reserve engineering, the 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. We do not have key-man insurance on the lives
of Mr. Taylor and Ms. McComic. The unexpected loss of the services of one or more of these individuals could, therefore, significantly
and adversely affect our operations.
We
may be affected by one substantial shareholder.
Nicholas
C. Taylor beneficially owns approximately 47% of the outstanding shares of our common stock. Mr. Taylor is also our Chairman of
the Board and Chief Executive Officer. As a result, Mr. Taylor has significant influence in matters voted on by our shareholders,
including the election of our Board members. Mr. Taylor participates in all facets of our business and has a significant impact
on both our business strategy and daily operations. The retirement, incapacity or death of Mr. Taylor, or any change in the power
to vote shares beneficially owned by Mr. Taylor, could result in negative market or industry perception and could have an adverse
effect on our business.
RISKS
RELATED TO OUR COMMON STOCK
We
may issue additional shares of common stock in the future, which could cause dilution to all shareholders.
We
may seek to raise additional equity capital in the future. Any issuance of additional shares of our common stock will dilute the
percentage ownership interest of all shareholders and may dilute the book value per share of our common stock.
We
have not and do not anticipate paying any cash dividends on our common stock in the foreseeable future.
We
have paid no cash dividends on our common stock to date and it is not anticipated that any will be paid to holders of our common
stock in the foreseeable future. The terms of our existing credit facility restricts the payment of dividends without the prior
written consent of the lenders. We currently intend to retain all future earnings to fund the development and growth of our business.
Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our
earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to
the payment of dividends and other considerations that our board of directors deems relevant. Stockholders must rely on sales
of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment.
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, 2020, our executive officers and directors beneficially owned approximately 64% of our common stock. These stockholders,
if acting together, would be able to influence significantly all matters requiring approval by our stockholders, including the
election of our board of directors and the approval of mergers or other business combination transactions.
The
price of our common stock has been volatile and could continue to fluctuate substantially.
Mexco
common stock is traded on the NYSE American. The market price of our common stock has and could continue to experience volatility
due to reasons unrelated to our operating performance. These reasons include: supply and demand for 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, 2020, we had interests in approximately 6,300 gross (22 net) oil and gas wells and owned leasehold mineral and royalty
interests in approximately 559,000 gross (3,402 net) acres.
Oil
and Natural Gas Reserves
In
accordance with current SEC rules, the average prices used in computing reserves at March 31, 2020 were $53.23 per bbl of oil
and $53.71 in 2019, a decrease of 1%, and $1.66 per mcf of natural gas and $2.77 in 2019, a decrease of 40%, 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 2020. The benchmark price of $52.23 per bbl of oil at March 31, 2020 versus $59.52 at March 31, 2019, was
adjusted by lease for gravity, transportation fees and regional price differentials and did not give effect to derivative transactions.
The benchmark price of $2.30 per mcf of natural gas at March 31, 2020 versus $3.07 at March 31, 2019, 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, 2020 and 2019 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,
|
|
|
|
2020
|
|
|
2019
|
|
Oil (Bbls):
|
|
|
|
|
|
|
|
|
Proved developed – Producing
|
|
|
314,460
|
|
|
|
341,890
|
|
Proved developed – Non-producing
|
|
|
43,770
|
|
|
|
34,710
|
|
Proved undeveloped
|
|
|
649,570
|
|
|
|
663,860
|
|
Total
|
|
|
1,007,800
|
|
|
|
1,040,460
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcf):
|
|
|
|
|
|
|
|
|
Proved developed – Producing
|
|
|
2,970,280
|
|
|
|
3,420,730
|
|
Proved developed – Non-producing
|
|
|
373,930
|
|
|
|
402,710
|
|
Proved undeveloped
|
|
|
1,506,160
|
|
|
|
1,557,250
|
|
Total
|
|
|
4,850,370
|
|
|
|
5,380,690
|
|
|
|
|
|
|
|
|
|
|
Total net proved reserves (BOE)
|
|
|
1,816,195
|
|
|
|
1,937,240
|
|
|
|
|
|
|
|
|
|
|
PV-10 Value (1)
|
|
$
|
21,636,700
|
|
|
$
|
22,317,300
|
|
Present value of future income tax discounted at 10%
|
|
|
(2,660,700
|
)
|
|
|
(3,065,100
|
)
|
Standardized measure of discounted future net cash flows (2)
|
|
$
|
18,976,000
|
|
|
$
|
19,252,200
|
|
|
|
|
|
|
|
|
|
|
Prices used in Calculating Reserves: (3)
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
1.66
|
|
|
$
|
2.77
|
|
Oil (per Bbl)
|
|
$
|
53.23
|
|
|
$
|
53.71
|
|
|
(1)
|
The
PV-10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income
tax, discounted at 10% per annum, which is the most directly comparable GAAP financial measure. PV-10 is relevant
and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved
reserves prior to taking into account future corporate income taxes. Further, investors may utilize the measure as a
basis for comparison of the relative size and value of our reserves to other companies. We use this measure when
assessing the potential return on investment related to our oil and natural gas properties. Our reconciliation
of this non-GAAP financial measure is shown in the table as the PV-10, less future income taxes, discounted at 10% per annum,
resulting in the standardized measure of discounted future net cash flows. The standardized measure of discounted future net
cash flows represents the present value of future cash flows attributable to our proved oil and natural gas reserves after
income tax, discounted at 10%.
|
|
(2)
|
In
accordance with SEC requirement, the standardized measure of discounted future net cash flows was computed by applying 12-month
first day of the month average prices for oil and gas during the fiscal year to the estimated future production of proved
oil and gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing
the proved reserves, less estimated future income tax expenses (based on year-end statutory tax rates, with consideration
of future tax rates already legislated) to be incurred on pretax net cash flows less tax basis of the properties and available
credits, and assuming continuation of existing economic conditions.
|
|
(3)
|
These
prices reflect adjustment by lease for quality, transportation fees and regional price differentials and did not give effect
to derivative transactions.
|
We
have not filed any other oil or gas reserve estimates or included any such estimates in reports to other federal or foreign governmental
authority or agency during the year ended March 31, 2020, and no major discovery is believed to have caused a significant change
in our estimates of proved reserves since that date.
During
the fiscal year ending March 31, 2020, we participated in the development of 57 wells converting reserves of approximately 96,000
BOE from proved undeveloped to proved developed – producing with capital cost of approximately $1,407,000.
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.
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,
|
|
|
|
2020
|
|
|
2019
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
Exploratory Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nonproductive – Vertical
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
|
|
.02
|
|
Total
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
|
|
.02
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive - Horizontal
|
|
|
50
|
|
|
|
.16
|
|
|
|
43
|
|
|
|
.12
|
|
Productive - Vertical
|
|
|
8
|
|
|
|
.02
|
|
|
|
3
|
|
|
|
.01
|
|
Nonproductive - Vertical
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
Total
|
|
|
58
|
|
|
|
.18
|
|
|
|
47
|
|
|
|
.14
|
|
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 86 gross wells (.09 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, 2020, we held an interest in approximately
6,300 gross (22 net) productive wells, including approximately 5,100 wells in which we held an overriding or royalty interest
and 1,200 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, 2020:
|
|
Developed Acres
|
|
|
|
Gross
|
|
|
Net
|
|
Texas
|
|
|
358,700
|
|
|
|
1,830
|
|
Oklahoma
|
|
|
80,000
|
|
|
|
1,204
|
|
New Mexico
|
|
|
31,900
|
|
|
|
201
|
|
Louisiana
|
|
|
36,800
|
|
|
|
59
|
|
North Dakota
|
|
|
22,500
|
|
|
|
29
|
|
Kansas
|
|
|
10,600
|
|
|
|
41
|
|
Montana
|
|
|
6,100
|
|
|
|
2
|
|
Ohio
|
|
|
4,700
|
|
|
|
18
|
|
Wyoming
|
|
|
3,800
|
|
|
|
5
|
|
Arkansas
|
|
|
1,000
|
|
|
|
5
|
|
Mississippi
|
|
|
1,000
|
|
|
|
3
|
|
Alabama
|
|
|
600
|
|
|
|
3
|
|
Colorado
|
|
|
1,100
|
|
|
|
1
|
|
Virginia
|
|
|
100
|
|
|
|
1
|
|
Total
|
|
|
558,900
|
|
|
|
3,402
|
|
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,
|
|
|
|
2020
|
|
|
2019
|
|
Oil (a):
|
|
|
|
|
|
|
|
|
Production (Bbls)
|
|
|
44,301
|
|
|
|
35,359
|
|
Revenue
|
|
$
|
2,310,127
|
|
|
$
|
1,921,391
|
|
Average Bbls per day (d)
|
|
|
121
|
|
|
|
97
|
|
Average sales price per Bbl
|
|
$
|
52.15
|
|
|
$
|
54.34
|
|
Gas (b):
|
|
|
|
|
|
|
|
|
Production (Mcf)
|
|
|
294,007
|
|
|
|
295,133
|
|
Revenue
|
|
$
|
410,226
|
|
|
$
|
726,486
|
|
Average Mcf per day (d)
|
|
|
805
|
|
|
|
809
|
|
Average sales price per Mcf
|
|
$
|
1.40
|
|
|
$
|
2.46
|
|
Production cost:
|
|
|
|
|
|
|
|
|
Production expenses
|
|
$
|
700,739
|
|
|
$
|
748,038
|
|
Production and ad valorem taxes
|
|
$
|
213,910
|
|
|
$
|
188,362
|
|
Total BOE (c)
|
|
|
93,302
|
|
|
|
84,548
|
|
Production cost per BOE
|
|
$
|
7.51
|
|
|
$
|
8.85
|
|
Production cost per sales dollar
|
|
$
|
0.26
|
|
|
$
|
0.28
|
|
Total oil and gas revenue
|
|
$
|
2,720,353
|
|
|
$
|
2,647,877
|
|
|
(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 26, 2020
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been signed below as of June 26, 2020, 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/
Paul G. Hines
Paul
G. Hines
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, 2020 and 2019
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, 2020, 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, 2020 and 2019, 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, 2020 and 2019.
Ceiling
Test. Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is an
impairment test to determine a limit, or ceiling, on the book value of oil and gas properties. That limit is the after tax present
value of the future net cash flows from proved crude oil and natural gas reserves and using an average price over the prior first
day of the month 12-month period held flat for the life of production plus the lower of cost or fair market value of unproved
properties. If net capitalized costs of crude oil and natural gas properties exceed the ceiling limit, the Company must charge
the amount of the excess to earnings as an expense reflected in additional accumulated DD&A. This is called a “ceiling
limitation write-down.” This impairment to our oil and gas properties does not impact cash flow from operating activities,
but does reduce stockholders’ equity and reported earnings.
Depreciation,
Depletion and Amortization. The depreciable base for oil and gas properties includes the sum of capitalized costs, net of
accumulated DD&A, estimated future development costs and asset retirement costs not accrued in oil and gas properties, less
costs excluded from amortization and salvage. The depreciable base of oil and gas properties is amortized using the unit-of-production
method.
Asset
Retirement Obligations. The Company has significant obligations to plug and abandon natural gas and crude oil wells and related
equipment at the end of oil and gas production operations. The Company records the fair value of a liability for an ARO in the
period in which it is incurred and a corresponding increase in the carrying amount of the related asset. Subsequently, the asset
retirement costs included in the carrying amount of the related asset are allocated to expense using the units of production method.
In addition, increases in the discounted ARO liability resulting from the passage of time are reflected as accretion expense in
the Consolidated Statements of Operations.
Estimating
the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what
constitutes adequate restoration. The Company uses the present value of estimated cash flows related to the ARO to determine the
fair value. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate costs, inflation
factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political
environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding
adjustment is made to the related asset.
Income
Taxes. The Company recognizes deferred tax assets and liabilities for future tax consequences of temporary differences between
the carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured
using enacted tax rates applicable to the years in which those differences are expected to be settled. The effect on deferred
tax assets and liabilities of a change in tax rates is recognized in net income in the period that includes the enactment date.
Any interest and penalties are recorded as interest expense and general and administrative expense, respectively.
Other
Property and Equipment. Provisions for depreciation of office furniture and equipment are computed on the straight-line method
based on estimated useful lives of three to ten years.
Loss
Per Common Share. Basic net loss per share is computed by dividing net loss by the weighted average number of common shares
outstanding during the period. Diluted net loss per share assumes the exercise of all stock options having exercise prices less
than the average market price of the common stock during the period using the treasury stock method and is computed by dividing
net loss by the weighted average number of common shares and dilutive potential common shares (stock options) outstanding during
the period. In periods where losses are reported, the weighted-average number of common shares outstanding excludes potential
common shares, because their inclusion would be anti-dilutive.
Revenue
Recognition - Revenue from Contracts with Customers. 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 using the cost method. The cost of the
investment is recorded as an asset on the consolidated balance sheets and when income from the investment is received, it is immediately
recognized on the consolidated statements of operations.
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 is currently
assessing the effect that ASU 2019-12 will have on its financial position, results of operations and disclosures.
In June 2016, the FASB issued ASU No. 2016-13,
“Financial Instruments–Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (“Topic
326”), which replaces the current “incurred loss” methodology for recognizing credit losses with an “expected
loss” methodology. This new methodology requires that a financial asset measured at amortized cost be presented at the net
amount expected to be collected. This standard is intended to provide more timely decision-useful information about the expected
credit losses on financial instruments. In November 2018, the FASB issued ASU No. 2018-19, “Codification Improvements to
Topic 326, Financial Instruments–Credit Losses,” which makes amendments to clarify the scope of the guidance, including
the amendment clarifying that receivables arising from operating leases are not within the scope of Topic 326. This guidance is
effective for fiscal years beginning after December 15, 2019. The Company is currently assessing the effect that ASU 2016-13 will
have 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
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.
4.
Property Sales
During
fiscal 2020, the Company continued its policy of selling non-core assets in order to concentrate on the development of more profitable
assets and to pay down debt. The Company received approximately $53,000 in cash from the sale of our remaining operated properties
in Ector County, Texas; approximately $17,500 in cash for the sale of an overriding royalty interest in Lea County, New Mexico;
approximately $4,300 in cash from the sale of joint venture leasehold acreage in which we retained the deep rights in Lea County,
New Mexico; and, approximately $4,600 in cash from sales of joint venture leasehold acreage and marginal producing working interest
wells in Howard and Ward Counties, Texas.
The Company also received approximately
$18,000 in cash from the sale of its surface rights on acreage in Brazoria County, Texas to a related party. The Company retained
its mineral rights in this property.
Other immaterial dispositions and purchase
price adjustments during fiscal 2020 amounted to approximately $7,200. During fiscal 2019, the Company sold non-core assets for
a total of approximately $162,000.
5.
Long-Term Debt
Long-term
debt on the Consolidated Balance Sheets consisted of the following as of March 31:
|
|
2020
|
|
|
2019
|
|
Credit facility
|
|
$
|
795,000
|
|
|
$
|
-
|
|
Unamortized debt issuance costs
|
|
|
(37,577
|
)
|
|
|
-
|
|
Total long-term debt
|
|
$
|
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, 2020, there was $705,000 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. The Company is in compliance with all covenants as
of March 31, 2020 and believes it will remain in compliance for the next fiscal year.
In
addition, the Agreement prohibits the Company from paying cash dividends on its common stock without prior written permission
of WTNB. The Agreement does not permit the Company to enter into hedge agreements covering crude oil and natural gas prices without
prior WTNB approval.
The
balance outstanding on the line of credit as of March 31, 2020 was $795,000. The following table is a summary of activity on the
WTNB line of credit for the year ended March 31, 2020:
|
|
Principal
|
|
Balance at April 1, 2019:
|
|
$
|
-
|
|
Borrowings
|
|
|
1,285,000
|
|
Repayments
|
|
|
490,000
|
|
Balance
at March 31, 2020:
|
|
$
|
795,000
|
|
Subsequently, on April 6, 2020, the Company
borrowed $25,000 on the line of credit; on April 17, 2020, made a payment of $100,000; on May 11, 2020, borrowed $160,000 on the
line of credit; and on June 10, 2020, borrowed $50,000 on the line of credit, leaving a balance of $930,000 as of June 26,
2020.
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. Subsequently, 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:
|
|
2020
|
|
|
2019
|
|
Carrying amount of asset retirement obligations, beginning of year
|
|
$
|
861,534
|
|
|
$
|
862,553
|
|
Liabilities incurred
|
|
|
19,512
|
|
|
|
8,658
|
|
Liabilities settled
|
|
|
(145,520
|
)
|
|
|
(27,452
|
)
|
Accretion expense
|
|
|
27,235
|
|
|
|
27,775
|
|
Revisions
|
|
|
-
|
|
|
|
(10,000
|
)
|
Carrying amount of asset retirement obligations, end of year
|
|
|
762,761
|
|
|
|
861,534
|
|
Less: Current portion
|
|
|
7,500
|
|
|
|
7,500
|
|
Non-Current asset retirement obligation
|
|
$
|
755,261
|
|
|
$
|
854,034
|
|
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 2015.
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:
|
|
2020
|
|
|
2019
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Percentage depletion carryforwards
|
|
$
|
1,167,594
|
|
|
$
|
1,136,210
|
|
Deferred stock-based compensation
|
|
|
36,568
|
|
|
|
34,771
|
|
Asset retirement obligation
|
|
|
160,180
|
|
|
|
180,922
|
|
Net operating loss
|
|
|
1,248,528
|
|
|
|
948,722
|
|
Other
|
|
|
7,372
|
|
|
|
5,470
|
|
|
|
|
2,620,242
|
|
|
|
2,306,095
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Excess financial accounting bases over tax bases of property and equipment
|
|
|
1,313,271
|
|
|
|
1,045,974
|
|
Deferred tax asset, net
|
|
$
|
1,306,971
|
|
|
$
|
1,260,121
|
|
Valuation allowance
|
|
|
(1,306,971
|
)
|
|
|
(1,260,121
|
)
|
Net deferred tax
|
|
$
|
-
|
|
|
$
|
-
|
|
As
of March 31, 2020, the Company has a statutory depletion carryforward of approximately $5,550,000, which does not expire.
At March 31, 2020, the Company had a net operating loss carryforward for regular income tax reporting purposes of approximately
$5,950,000, 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:
|
|
2020
|
|
|
2019
|
|
Tax expense at federal statutory rate (1)
|
|
$
|
(20,891
|
)
|
|
$
|
(2,719
|
)
|
Statutory depletion carryforward
|
|
|
(31,384
|
)
|
|
|
(24,409
|
)
|
Change in valuation allowance
|
|
|
46,850
|
|
|
|
24,698
|
|
U. S. tax reform, corporate rate reduction
|
|
|
-
|
|
|
|
-
|
|
Permanent differences
|
|
|
5,427
|
|
|
|
3,812
|
|
Other
|
|
|
(2
|
)
|
|
|
(1,382
|
)
|
Total income tax
|
|
$
|
-
|
|
|
$
|
-
|
|
Effective income tax rate
|
|
|
-
|
|
|
|
-
|
|
|
(1)
|
The
federal statutory rate was 21% for fiscal years ending March 31, 2020 and 2019.
|
For
the years ended March 31, 2020 and 2019, 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, 2020 and 2019. Our deferred tax asset is $1,306,971 as of March 31, 2020 with a valuation amount
of $1,306,971. 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
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 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. In fiscal 2019, one customer accounted for 42% of the total oil and natural gas revenues and 40% of the total
oil and natural gas accounts receivable and another customer accounted for 6% of the total oil and natural gas revenues and 9%
of the total oil and natural gas accounts receivable.
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:
|
|
2020
|
|
|
2019
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
-
|
|
|
$
|
-
|
|
Unproved
|
|
|
-
|
|
|
|
-
|
|
Exploration
|
|
|
168
|
|
|
|
14,555
|
|
Development
|
|
|
1,687,499
|
|
|
|
803,602
|
|
Capitalized asset retirement obligations
|
|
|
19,512
|
|
|
|
8,658
|
|
Total costs incurred for oil and gas properties
|
|
$
|
1,707,179
|
|
|
$
|
826,815
|
|
The
Company had the following aggregate capitalized costs relating to its oil and gas property activities at March 31:
|
|
2020
|
|
|
2019
|
|
Proved oil and gas properties
|
|
$
|
37,465,172
|
|
|
$
|
35,907,677
|
|
Unproved oil and gas properties:
|
|
|
|
|
|
|
|
|
subject to amortization
|
|
|
-
|
|
|
|
-
|
|
not subject to amortization
|
|
|
-
|
|
|
|
-
|
|
|
|
|
37,465,172
|
|
|
|
35,907,677
|
|
Less accumulated DD&A
|
|
|
28,003,961
|
|
|
|
27,154,343
|
|
|
|
$
|
9,461,211
|
|
|
$
|
8,753,334
|
|
DD&A
amounted to $9.57 and $9.45 per BOE of production for the years ended March 31, 2020 and 2019, respectively.
10.
Loss Per Common Share
Due
to a net loss for the years ended March 31, 2020 and 2019, the weighted average number of common shares outstanding excludes common
stock equivalents because their inclusion would be anti-dilutive.
The
following is a reconciliation of the number of shares used in the calculation of basic income per share and diluted income per
share for the years ended March 31:
|
|
2020
|
|
|
2019
|
|
Net loss
|
|
$
|
(99,478
|
)
|
|
$
|
(12,946
|
)
|
|
|
|
|
|
|
|
|
|
Shares outstanding:
|
|
|
|
|
|
|
|
|
Weighted avg. common shares outstanding – basic
|
|
|
2,040,166
|
|
|
|
2,039,412
|
|
Effect of the assumed exercise of dilutive stock options
|
|
|
-
|
|
|
|
-
|
|
Weighted avg. common shares outstanding – dilutive
|
|
|
2,040,166
|
|
|
|
2,039,412
|
|
|
|
|
|
|
|
|
|
|
Loss per common share:
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.05
|
)
|
|
$
|
(0.01
|
)
|
Diluted
|
|
$
|
(0.05
|
)
|
|
$
|
(0.01
|
)
|
11.
Stockholders’ Equity
In
September 2019, 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 2020 and
2019.
12.
Stock Options
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, 2020, the Compensation Committee of the Board of Directors approved and the Company issued options covering
42,000 shares of stock. During the year ended March 31, 2019, the Compensation Committee of the Board of Directors approved and
the Company issued options covering 40,000 shares of stock. The plan also provides for the granting of stock awards. No stock
awards were granted during fiscal 2019 and 2018.
The
Company recognized compensation expense of $34,303 and $22,656 related to vesting stock options in general and administrative
expense in the Consolidated Statements of Operations for fiscal 2020 and 2019, respectively. The total cost related to non-vested
awards not yet recognized at March 31, 2020 totals $171,788, which is expected to be recognized over a weighted average of 3.31
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 2020 and 2019. All such amounts represent the weighted average amounts
for each period.
|
|
For the year ended March 31,
|
|
|
|
2020
|
|
|
2019
|
|
Grant-date fair value
|
|
$
|
2.24
|
|
|
$
|
3.25
|
|
Volatility factor
|
|
|
60.12
|
%
|
|
|
55.26
|
%
|
Dividend yield
|
|
|
-
|
|
|
|
-
|
|
Risk-free interest rate
|
|
|
0.85
|
%
|
|
|
2.91
|
%
|
Expected term (in years)
|
|
|
6.25
|
|
|
|
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 years ended March 31, 2020 and 2019, 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, 2020 and 2019:
|
|
Number of Shares
|
|
|
Weighted Average Exercise Price Per Share
|
|
|
Weighted Aggregate Average Remaining Contract Life in Years
|
|
Outstanding at April 1, 2018
|
|
|
148,600
|
|
|
$
|
4.84
|
|
|
|
4.34
|
|
Granted
|
|
|
40,000
|
|
|
|
-
|
|
|
|
|
|
Exercised
|
|
|
2,900
|
|
|
|
8.56
|
|
|
|
|
|
Forfeited or Expired
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
Outstanding at March 31, 2019
|
|
|
185,700
|
|
|
$
|
6.18
|
|
|
|
4.68
|
|
Granted
|
|
|
42,000
|
|
|
|
-
|
|
|
|
|
|
Exercised
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
Forfeited or Expired
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
Outstanding at March 31, 2020
|
|
|
227,700
|
|
|
$
|
5.65
|
|
|
|
4.83
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested at March 31, 2020
|
|
|
155,700
|
|
|
$
|
6.44
|
|
|
|
2.76
|
|
Exercisable at March 31, 2020
|
|
|
155,700
|
|
|
$
|
6.44
|
|
|
|
2.76
|
|
During
the year ended March 31, 2020, no stock options were exercised. During the year ended March 31, 2019, stock options covering 2,900
shares were exercised with a total intrinsic value of $6,575. The Company received proceeds of $18,241 from these exercises.
Other
information pertaining to option activity was as follows during the year ended March 31:
|
|
2020
|
|
|
2019
|
|
Weighted average grant-date fair value of stock options granted (per share)
|
|
$
|
2.24
|
|
|
$
|
3.25
|
|
Total fair value of options vested
|
|
$
|
32,500
|
|
|
$
|
55,900
|
|
Total intrinsic value of options exercised
|
|
$
|
-
|
|
|
$
|
6,575
|
|
The
following table summarizes information about options outstanding at March 31, 2020:
Range of Exercise Prices
|
|
|
Number of Options
|
|
|
Weighted
Average
Exercise Price
Per Share
|
|
|
Weighted Average Remaining
Contract Life in Years
|
|
$ 3.34 – 4.83
|
|
|
|
42,000
|
|
|
$
|
3.34
|
|
|
|
|
4.84 – 5.97
|
|
|
|
40,000
|
|
|
|
4.84
|
|
|
|
|
5.98 – 6.26
|
|
|
|
40,000
|
|
|
|
6.00
|
|
|
|
|
6.26
– 6.50
|
|
|
|
25,700
|
|
|
|
6.29
|
|
|
|
|
6.51
– 7.00
|
|
|
|
80,000
|
|
|
|
6.90
|
|
|
|
|
$3.34
– 7.00
|
|
|
|
227,700
|
|
|
$
|
5.65
|
|
|
4.83
|
|
Outstanding
options at March 31, 2020 expire between August 2020 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, 2020 and 2019 were $44,724 and $51,276, 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, 2020 and 2019 were $15,881 and $13,291, 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 undiscounted by 10%.
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 expires in May 2021 and does not include an option to renew. Subsequently 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, 2020
|
|
Assets
|
|
|
|
|
Operating lease right-of-use asset, beginning balance
|
|
$
|
141,385
|
|
Current period amortization
|
|
|
(65,255
|
)
|
Total operating lease right-of-use asset
|
|
$
|
76,130
|
|
|
|
|
|
|
Liabilities
|
|
|
|
|
Operating lease liability, current
|
|
$
|
65,721
|
|
Operating lease liability, long term
|
|
|
10,982
|
|
Total lease liabilities
|
|
$
|
76,703
|
|
Future
minimum lease payments as of March 31, 2020 under non-cancellable operating leases are as follows:
|
|
Lease Obligation
|
|
Fiscal Year Ended March 31, 2021
|
|
|
65,721
|
|
Fiscal Year Ended March 31, 2022
|
|
|
10,982
|
|
Total lease payments
|
|
$
|
76,703
|
|
Less: imputed interest
|
|
|
-
|
|
Operating lease liability
|
|
|
76,703
|
|
Less: operating lease liability, current
|
|
|
(65,721
|
)
|
Operating lease liability, long term
|
|
$
|
10,982
|
|
Net
cash paid for our operating lease for the year ended March 31, 2020 and 2019 was $46,447 and $44,028, respectively. Rent expense,
less sublease income of $18,234 and $14,597, respectively, is included in general and administrative expenses.
15.
Oil and Gas Reserve Data (Unaudited)
The
estimates of the Company’s proved oil and gas reserves, which are located entirely within the United States, were prepared
in accordance with the generally accepted petroleum engineering and evaluation principles and definitions and guidelines established
by the SEC. The estimates as of March 31, 2020 and 2019 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 2020 and 2019. Commodity prices utilized for the reserve
estimates prior to adjustments for location, grade and quality are as follows:
|
|
March 31,
|
|
|
|
2020
|
|
|
2019
|
|
Prices utilized in the reserve estimates before adjustments:
|
|
|
|
|
|
|
|
|
Oil per Bbl
|
|
$
|
52.23
|
|
|
$
|
59.52
|
|
Natural gas per MMBtu
|
|
$
|
2.30
|
|
|
$
|
3.07
|
|
The
Company’s total estimated proved reserves at March 31, 2020 were approximately 1.816 MBOE of which 55% was oil and natural
gas liquids and 45% was natural gas.
Changes
in Proved Reserves:
|
|
Oil
(Bbls)
|
|
|
Natural Gas
(Mcf)
|
|
Proved Developed and Undeveloped Reserves:
|
|
|
|
|
|
|
|
|
As of April 1, 2018
|
|
|
1,197,000
|
|
|
|
5,487,000
|
|
Revision of previous estimates
|
|
|
(293,000
|
)
|
|
|
(430,000
|
)
|
Purchase of minerals in place
|
|
|
-
|
|
|
|
-
|
|
Extensions and discoveries
|
|
|
171,000
|
|
|
|
619,000
|
|
Sales of minerals in place
|
|
|
-
|
|
|
|
-
|
|
Production
|
|
|
(35,000
|
)
|
|
|
(295,000
|
)
|
As of March 31, 2019
|
|
|
1,040,000
|
|
|
|
5,381,000
|
|
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
|
|
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. The downward revision of oil and natural gas is primarily the result
of reserves written off due to the five-year limitation. They are primarily royalty interests in the Barnett Shale in Tarrant
County, Texas and the Goldsmith field in Ector County, Texas, both of which are on a lease held by production and still in place
to be developed in the future. There were also reserves written off due to the five-year limitation for a working interest in
the Fuhrman Mascho Field in Andrews County, Texas, also 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, 2020 and 2019:
|
|
Oil
(Bbls)
|
|
|
Natural Gas
(Mcf)
|
|
Proved Developed Reserves:
|
|
|
|
|
|
|
|
|
As of April 1, 2018
|
|
|
390,740
|
|
|
|
4,103,390
|
|
As of March 31, 2019
|
|
|
376,600
|
|
|
|
3,823,440
|
|
As of March 31, 2020
|
|
|
358,230
|
|
|
|
3,344,210
|
|
|
|
|
|
|
|
|
|
|
Proved Undeveloped Reserves:
|
|
|
|
|
|
|
|
|
As of April 1, 2018
|
|
|
805,980
|
|
|
|
1,383,120
|
|
As of March 31, 2019
|
|
|
663,860
|
|
|
|
1,557,250
|
|
As of March 31, 2020
|
|
|
649,570
|
|
|
|
1,506,160
|
|
At
March 31, 2020, the Company reported estimated PUDs of 901 MBOE, which accounted for 50% of its total estimated proved oil and
gas reserves. This figure primarily consists of a projected 142 new wells (662 MBOE) operated by others, 7 wells are currently
being drilled with plans for 59 wells to follow in 2021, 64 wells in 2022 and 12 wells in 2023. 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 2020.
Progress
of Converting Proved Undeveloped Reserves:
|
|
Oil & Natural Gas
|
|
|
Future
|
|
|
|
(BOE)
|
|
|
Development Costs
|
|
PUDs, beginning of year
|
|
|
923,405
|
|
|
$
|
9,137,560
|
|
Revision of previous estimates
|
|
|
(40,310
|
)
|
|
|
(2,215,976
|
)
|
Sales of reserves
|
|
|
-
|
|
|
|
-
|
|
Conversions to PD reserves
|
|
|
(96,443
|
)
|
|
|
(1,407,439
|
)
|
Additional PUDs added
|
|
|
113,940
|
|
|
|
1,117,919
|
|
PUDs, end of year
|
|
|
900,592
|
|
|
$
|
6,632,064
|
|
Estimated
future net cash flows represent an estimate of future net revenues from the production of proved reserves using average prices
for 2020 and 2019 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, 2023 are $6,632,064.
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 2020 were $53.23 per bbl of oil and
$1.655 per mcf of natural gas. The average prices used for fiscal 2019 were $53.71 per bbl of oil and $2.77 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, 2020 and 2019 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
|
|
|
|
2020
|
|
|
2019
|
|
Future cash inflows
|
|
$
|
61,676,000
|
|
|
$
|
70,766,000
|
|
Future production costs and taxes
|
|
|
(16,682,000
|
)
|
|
|
(19,355,000
|
)
|
Future development costs
|
|
|
(6,984,000
|
)
|
|
|
(9,424,000
|
)
|
Future income taxes
|
|
|
(4,675,000
|
)
|
|
|
(5,767,000
|
)
|
Future net cash flows
|
|
|
33,335,000
|
|
|
|
36,220,000
|
|
Annual 10% discount for estimated timing of cash flows
|
|
|
(14,359,000
|
)
|
|
|
(16,968,000
|
)
|
Standardized measure of discounted future net cash flows
|
|
$
|
18,976,000
|
|
|
$
|
19,252,000
|
|
Changes
in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves:
|
|
March 31
|
|
|
|
2020
|
|
|
2019
|
|
Sales of oil and gas produced, net of production costs
|
|
$
|
(1,806,000
|
)
|
|
$
|
(1,711,000
|
)
|
Net changes in price and production costs
|
|
|
(2,871,000
|
)
|
|
|
36,000
|
|
Changes in previously estimated development costs
|
|
|
865,000
|
|
|
|
1,923,000
|
|
Revisions of quantity estimates
|
|
|
(2,140,000
|
)
|
|
|
(6,901,000
|
)
|
Net change due to purchases and sales of minerals in place
|
|
|
(335,000
|
)
|
|
|
-
|
|
Extensions and discoveries, less related costs
|
|
|
1,519,000
|
|
|
|
4,333,000
|
|
Net change in income taxes
|
|
|
404,000
|
|
|
|
61,000
|
|
Accretion of discount
|
|
|
2,164,000
|
|
|
|
2,200,000
|
|
Changes in timing of estimated cash flows and other
|
|
|
1,924,000
|
|
|
|
435,000
|
|
Changes in standardized measure
|
|
|
(276,000
|
)
|
|
|
376,000
|
|
Standardized measure, beginning of year
|
|
|
19,252,000
|
|
|
|
18,876,000
|
|
Standardized measure, end of year
|
|
$
|
18,976,000
|
|
|
$
|
19,252,000
|
|
16.
Subsequent Events
During
the first quarter of fiscal 2021, the Company borrowed $235,000 on the line of credit and made a payment of $100,000 to reduce
the line of credit leaving a balance of $930,000.
During
the first quarter of fiscal 2021, the Company expended approximately $200,000 for participation in the drilling of four wells
in Lea County, New Mexico.
On
April 10, 2020, the Company’s Certificate of Deposit Account used to collateralize a plugging bond with the Texas Railroad
Commission in the amount of $25,000 was closed and the funds deposited into the Company’s operating account.
On
March 27, 2020, President Trump signed the Coronavirus Aid, Relief and Economic Security (the “CARES Act”), which,
among other things, outlines the provisions of the Paycheck Protection Program (the “PPP”). The Company determined
that it met the criteria to be eligible to obtain a loan under the PPP because, among other reasons, in light of the COVID-19
outbreak and the uncertainty of economic conditions related thereto, the loan was necessary to support the Company’s ongoing
operations. Under the PPP, the Company could obtain a U.S. Small Business Administration loan in an amount equal to the average
of the Company’s monthly payroll costs (as defined under the PPP) for calendar 2019 multiplied by 2.5 (approximately 10
weeks of payroll costs). Section 1106 of the CARES Act contains provisions for the forgiveness of all or a portion of a PPP loan,
subject to the satisfaction of certain requirements. The amount eligible for forgiveness is, subject to certain limitations, the
sum of the Company’s payroll costs, rent and utilities paid by the Company during the 24-week period beginning on the funding
date of the PPP loan. On May 5, 2020, the Company closed on a PPP loan in the amount of $68,574, which was funded on the date
thereof.
Beginning
in March 2020, significant price decline and price volatility for oil and gas products emerged in the market. The Company could
be directly impacted by these price changes if the decline in demand and price remain depressed for an extended period of time.
The financial statement impact, change in price and expected time for these changes is not estimable but will result in significant
decreases in oil and gas operations. Management has considered all available information and has concluded that volatility in
price and demand is difficult to estimate and the current outcome of future operations is unknown. The extent of the operational
and financial impact the COVID-19 pandemic may have on the Company has yet to be determined and is dependent on its duration and
spread, any related operational restrictions and the overall economy. The Company is unable to accurately predict how COVID-19
will affect the results of its operations because the virus’s severity and the duration of the pandemic are uncertain. For
example, the NYMEX West Texas Intermediate (“WTI”) posted price for crude oil on March 31, 2020 was $16.75 per bbl
and averaged $14.68 and $24.67 per bbl for the months of April and May 2020, respectively. The WTI posted price for crude oil
was $35.75 on June 19, 2020. The Henry Hub Spot Market Price (“Henry Hub”) posted price for natural gas on March 31,
2020 was $1.71 per MMBtu and averaged $1.74 and $1.75 per MMBtu for the months of April and May 2020, respectively. The Henry
Hub posted price for natural gas was $1.67 on June 19, 2020.
In
April 2020, the Company expended approximately $28,100 to purchase twelve 1,000 barrel contracts to hedge our oil production for
the months of April through August at a floor price of $25.00 per barrel. On May 4, 2020, the Company received a net settlement
of $8,200 for the first of these contracts.
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.