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, 2018 were approximately 2.111 million barrels of oil equivalent (“MMBOE”)
of which 57% was oil and natural gas liquids and 43% 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 2018, we added proved reserves of 142 thousand BOE (“MBOE”)
through extensions and discoveries, subtracted 178 MBOE through sales of oil and gas properties and downward revisions of previous
estimates of 1,003 MBOE. Such downward revisions are primarily the result of the restructuring of our plans for development of
a non-producing leasehold interest in Martin County, Texas located in the Eastern Permian Basin due to market conditions partially
offset by pricing and successful development in the Delaware and Midland Basins.
Nicholas
C. Taylor beneficially owns approximately 46% of the outstanding shares of our common stock. Mr. Taylor is also our Chairman of
the Board and Chief Executive Officer. As a result, Mr. Taylor has significant influence in matters voted on by our shareholders,
including the election of our Board members. Mr. Taylor participates in all facets of our business and has a significant impact
on both our business strategy and daily operations.
Company
Profile
Since
our inception, we have been engaged in acquiring and developing oil and gas properties and the exploration for and production
of natural gas, crude oil, condensate and natural gas liquids (“NGLs”) within the United States. We especially seek
to acquire proved reserves that fit well with existing operations or in areas where Mexco has established production. Acquisitions
preferably will contain most of their value in producing wells, behind pipe reserves and high quality proved undeveloped locations.
Competition for the purchase of proved reserves is intense. Sellers often utilize a bid process to sell properties. This process
usually intensifies the competition and makes it extremely difficult to acquire reserves without assuming significant price and
production risks. We actively search for opportunities to acquire proved oil and gas properties. However, because the competition
is intense, we cannot give any assurance that we will be successful in our efforts during fiscal 2019.
While
we own oil and gas properties in other states, the majority of our activities are centered in the Permian Basin of West Texas.
The Company also owns producing properties and undeveloped acreage in thirteen states. We acquire interests in producing and non-producing
oil and gas leases from landowners and leaseholders in areas considered favorable for oil and gas exploration, development and
production. In addition, we may acquire oil and gas interests by joining in oil and gas drilling prospects generated by third
parties. We may also employ a combination of the above methods of obtaining producing acreage and prospects. In recent years,
we have placed primary emphasis on the evaluation and purchase of producing oil and gas properties, both working and royalty interests,
and prospects that could have a potentially meaningful impact on our reserves. Most of the Company’s oil and gas interests
are operated by others, however the Company operates several properties in which it owns an interest.
From
1983 to 2018, 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. Of these oil and gas reserves, approximately
54% are in TX and 10% in LA.
|
|
|
|
Royalty
interests, purchase price $580,000 covering 580 wells in 87 counties of eight states. Approximately 90% of the net revenue
from these royalties is produced by 157 wells located in the Barnett Shale of the Fort Worth Basin of Texas. Also included
are interests in 423 wells in 8 states.
|
|
|
|
Non-Operated
working interests, purchase price $525,000 for 12.5% (approximately 10% net revenue interest). 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 2018. Commodity prices improved but continue to be volatile. In light
of these challenges facing our industry and in response to the continued challenging environment, our primary business strategies
for fiscal 2019 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 2018 operating results and potential impact on fiscal 2019 operating results due to commodity price changes.
Oil
and Gas Operations
As
of March 31, 2018, oil constituted approximately 57% of our total proved reserves and approximately 68% of our revenues for fiscal
2018. Revenues from oil and gas royalty interests accounted for approximately 21% of our revenues for fiscal 2018.
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 72% of our discounted future net cash flows from proved reserves and 64% of our net revenues.
The
Delaware Basin properties, encompassing 31,604 gross acres, 528 net acres, 473 gross producing wells and 5 net wells account for
approximately 37% of our discounted future net cash flows from proved reserves as of March 31, 2018. Of these discounted future
net cash flows from proved reserves, approximately 11% are attributable to proven undeveloped reserves which will be developed
through new drilling. For fiscal 2018, these properties accounted for 35% of our gross revenues and 44% of our net revenues.
The
Midland Basin properties, encompassing 90,148 gross acres, 268 net acres, 650 gross producing wells and 3 net wells account for
approximately 35% of our discounted future net cash flows from proved reserves as of March 31, 2018. Of these discounted future
net cash flows from proved reserves, approximately 29% are attributable to proven undeveloped reserves which will be developed
through new drilling. For fiscal 2018, these properties accounted for 18% of our gross revenues and 19% of our net revenues.
Gomez
Gas Field properties, encompassing 13,058 gross acres, 72 net acres, 26 gross wells and .13 net wells in Pecos County, Texas,
account for approximately 2% of our discounted future net cash flows from proved reserves as of March 31, 2018. For fiscal 2018,
these properties accounted for 2% of our gross revenues and 3% of our net revenues. All of these properties, except for one, are
royalty interests. There is a potential for development of the horizontal Wolfcamp on these interests.
The
Goldsmith North Field (San Andres formation) long-lived oil producing properties, encompassing 160 gross acres, 123 net acres,
3 gross wells in Ector County, Texas, account for 9% of our discounted future net cash flows from proved reserves as of March
31, 2018. Of these discounted future net cash flows from proved reserves, 8% are attributable to proven undeveloped reserves which
will be developed through new drilling of 4 wells. For fiscal 2018, these properties consist of working interests and accounted
for 4% of our gross revenues and 2.2% of our net revenues. There is potential for further development of this property by horizontal
drilling.
Mexco
believes its most important properties for future development by horizontal drilling and hydraulic fracturing area are located
in Midland, Reagan and Upton Counties, Texas of the Midland Basin and the Delaware Basin in Lea and Eddy Counties, New Mexico
and Loving County, Texas.
For
more on these and other operations in this area see “Item 7. Management’s Discussion and Analysis of Financial Condition
and Results of Operations – Liquidity and Capital Resources Commitments”.
We
own partial interests in approximately 6,000 producing wells all of which are located within the United States in the states of
Texas, New Mexico, Oklahoma, Louisiana, Alabama, Mississippi, Arkansas, Wyoming, Kansas, Colorado, Montana, Virginia and North
Dakota. We own interests in and operate 3 producing wells. We divested working interests in 2 producing wells located in Loving
County, Texas in January 2018 (see Oil and Natural Gas Property Transactions under Item 7 of this report for further details).
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)
|
|
2018
|
|
|
34,743
|
|
|
|
318,774
|
|
2017
|
|
|
34,689
|
|
|
|
356,268
|
|
2016
|
|
|
38,930
|
|
|
|
407,939
|
|
2015
|
|
|
29,557
|
|
|
|
369,034
|
|
2014
|
|
|
27,186
|
|
|
|
361,652
|
|
Competition
and Markets
The
oil and gas industry is a highly competitive business. Competition for oil and gas reserve acquisitions is significant. We may
compete with major oil and gas companies, other independent oil and gas companies and individual producers and operators, some
of which have financial and personnel resources substantially in excess of those available to us. As a result, we may be placed
at a competitive disadvantage. Competitive factors include price, contract terms and types and quality of service, including pipeline
distribution. The price for oil and gas is widely followed and is generally subject to worldwide market factors. Our ability to
acquire and develop additional properties in the future will depend upon our ability to conduct operations, to evaluate and select
suitable properties and to consummate transactions in this highly competitive environment in a timely manner.
In
addition, the oil and gas industry as a whole also competes with other industries in supplying the energy and fuel requirements
of industrial, commercial and individual consumers. The price and availability of alternative energy sources could adversely affect
our revenue.
Market
factors affect the quantities of oil and natural gas production and the price we can obtain for the production from our oil and
natural gas properties. Such factors include: the extent of domestic production; the level of imports of foreign oil and natural
gas; the general level of market demand on a regional, national and worldwide basis; domestic and foreign economic conditions
that determine levels of industrial production; political events in foreign oil-producing regions; and variations in governmental
regulations including environmental, energy conservation and tax laws or the imposition of new regulatory requirements upon the
oil and natural gas industry.
The
market for our oil, gas and natural gas liquids production depends on factors beyond our control including: domestic and foreign
political conditions; the overall level of supply of and demand for oil, gas and natural gas liquids; the price of imports of
oil and gas; weather conditions; the price and availability of alternative fuels; the proximity and capacity of gas pipelines
and other transportation facilities; and overall economic conditions.
Major
Customers
We
made sales that amounted to 10% or more of revenues as follows for the year ended March 31:
|
|
2018
|
|
|
2017
|
|
Company
A
|
|
|
37
|
%
|
|
|
31
|
%
|
Company
B
|
|
|
8
|
%
|
|
|
12
|
%
|
Historically,
the Company has not experienced significant credit losses on our oil and gas accounts and management is of the opinion that significant
credit risk does not exist. Because a ready market exists for oil and gas production, we do not believe the loss of any individual
customer would have a material adverse effect on our financial position or results of operations.
Environmental
Regulation
General.
Activities on the Company properties are subject to existing stringent and complex federal, state and local laws (including
case law) and regulations governing health, safety, environmental quality and pollution control. Failure to comply with these
laws, rules and regulations, however, may result in the assessment of administrative, civil or criminal penalties; the imposition
of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all of the operations
on the Company properties.
Cleanup.
Under certain environmental laws and regulations, the operators of the Company properties could be subject to strict, joint
and several liability for the removal or remediation of property contamination, whether at a drill site or a waste disposal facility,
even when the operators did not cause the contamination or their activities were in compliance with all applicable laws at the
time the actions were taken. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”),
also known as the “superfund” law, for example, imposes liability, regardless of fault or the legality of the original
conduct, on certain classes of persons for releases into the environment of a “hazardous substance.” Liable persons
may include the current or previous owner and operator of a site where a hazardous substance has been disposed and persons who
arranged for the disposal of a hazardous substance at a site. Under CERCLA and similar statutes, government authorities or private
parties may take actions in response to threats to the public health or the environment or sue responsible persons for the associated
costs. In the course of operations, the working interest owner and/or the operator of the Company properties may have generated
and may generate materials that could trigger cleanup liabilities. In addition, the Company properties have produced oil and/or
natural gas for many years, and previous operators may have disposed or released hydrocarbons, wastes or hazardous substances
at the Company properties. The operator of the Company properties or the working interest owners may be responsible for all or
part of the costs to clean up any such contamination. Although the Company is not the operator of such properties, its ownership
of the properties could cause it to be responsible for all or part of such costs to the extent CERCLA or any similar statute imposes
responsibility on such parties as “owners.”
Climate
Change.
In December 2009, the EPA determined that emissions of carbon dioxide, methane and certain other greenhouse gases
(“GHGs”) endanger public health and the environment because emissions of such gases are contributing to warming of
the Earth’s atmosphere and other climatic changes. Based on those findings, the EPA adopted and implemented various regulations
to restrict emissions of GHGs under existing provisions of the Clean Air Act (“CAA”). Among other things, these covered
reductions in GHG emissions from motor vehicles, permits for certain large stationary sources of GHGs, monitoring and annual reporting
of GHG emissions from specified GHG emission sources, including oil and natural gas exploration and production operations, and
power plant performance standards that were intended to lead to the creation of additional state GHG control programs. In June
2013, moreover, President Obama unveiled a Presidential climate action plan designed to reduce emissions in the US of methane,
carbon dioxide and other GHGs. In furtherance of that plan, the Obama Administration launched a number of initiatives, including
a Strategy to Reduce Methane Emissions from the oil and natural gas industry. The Obama Administration’s goal was to reduce
methane emissions from the oil and natural gas industry by 40-45% by 2025 as compared to 2012 levels. The EPA therefore issued
regulations in 2016 that set additional standards for methane and volatile organic compound emissions from oil and natural gas
production sources, including hydraulically fractured oil wells, and natural gas processing and transmission sources. As another
prong of President Obama’s methane strategy, the Bureau of Land Management promulgated standards for reducing venting and
flaring on public lands. The Trump Administration has tried to delay or revise a number of the Obama-era regulations; however,
proponents of climate change regulations have been challenging those efforts in various courts with some success to date. The
direction of future U.S. climate change regulation therefore is difficult to predict. Federal agencies may or may not continue
developing regulations to reduce GHG emissions from the oil and gas industry. Even if federal efforts in this area slow, states
may continue pursuing climate regulations.
Various
state governments and regional organizations comprising state governments already have enacted legislation and promulgated rules
restricting GHG emissions or promoting the use of renewable energy, and additional such measures are frequently under consideration.
Although it is not possible at this time to estimate how potential future requirements addressing GHG emissions would impact operations
on the Company properties and revenue, either directly or indirectly, any future federal, state or local laws or implementing
regulations that may be adopted to address GHG emissions could require the operators of our properties to incur new or increased
costs to obtain permits, operate and maintain equipment and facilities, install new emission controls, acquire allowances to authorize
GHG emissions, pay taxes related to GHG emissions or administer a GHG emissions program. Regulation of GHGs could also result
in a reduction in demand for and production of oil and natural gas. Additionally, to the extent that unfavorable weather conditions
are exacerbated by global climate change or otherwise, the Company properties may be adversely affected to a greater degree than
previously experienced.
We
did not incur any material capital expenditures for remediation or pollution control activities for the year ended March 31, 2018.
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 2019.
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, 2018.
Name
|
|
Age
|
|
Position
|
Nicholas
C. Taylor
|
|
80
|
|
Chairman
and Chief Executive Officer
|
Tamala
L. McComic
|
|
49
|
|
President,
Chief Financial Officer, Treasurer, and Assistant Secretary
|
Donna
Gail Yanko
|
|
73
|
|
Vice
President and Secretary
|
Set
forth below is a description of the principal occupations during at least the past five years of each executive officer of the
Company.
Nicholas
C. Taylor was elected Chairman of the Board and Chief Executive Officer of the Company in September 2011 and continues to serve
in such capacity on a part time basis, as required. He served as Chief Executive Officer, President and Director of the Company
from 1983 to 2011. From July 1993 to the present, Mr. Taylor has been involved in the independent practice of law and other business
activities. In November 2005 he was appointed by the Speaker of the House to the Texas Ethics Commission and served until February
2010.
Tamala
L. McComic, a Certified Public Accountant, became Controller for the Company in July 2001 and was elected President and Chief
Financial Officer in September 2011. She served the Company as Executive Vice President and Chief Financial Officer from 2009
to 2011 and Vice President and Chief Financial Officer from 2003 to 2009. Prior thereto, Ms. McComic was appointed Treasurer and
Assistant Secretary of the Company.
Donna
Gail Yanko was appointed to the position of Vice President of the Company in 1990. She has also served as Corporate Secretary
since 1992 and from 1986 to 1992 was Assistant Secretary. From 1986 to 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, 2018, we had three full-time and three part-time employees. We believe that relations with these employees are generally
satisfactory. From time to time, we utilize the services of independent geological, land and engineering consultants on a limited
basis and expect to continue to do so in the future. We also utilize the services of independent contractors to perform well drilling
and production operations, including pumping, maintenance, inspection and testing.
Office
Facilities
At
March 31, 2018, our principal offices were located at 214 W. Texas Avenue, Suite 1101, Midland, Texas 79701. All of our leases
for this location expired on April 1, 2018. As of May 15, 2018, our principal offices are located at 415 W. Wall, Suite 475, Midland,
Texas 79701 and our telephone number is (432) 682-1119. On May 7, 2018, we agreed to a three year lease for our 4,160 square feet
of office space. We believe our new facilities are adequate for our current operations and future needs.
Access
to Company Reports
Mexco
Energy Corporation files annual, quarterly and current reports, proxy statements and other information with the SEC. Please call
the SEC at 1-800-SEC-0330 for information on the public reference room. The SEC maintains an internet website (www.sec.gov) that
contains annual, quarterly and current reports, proxy statements and other information that issuers, including Mexco, file electronically
with the SEC.
We
also maintain an internet website at www.mexcoenergy.com. In the Investor Relations section, our website contains our Annual Reports
on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and other reports and amendments to those reports as
soon as reasonably practicable after such material is electronically filed with the SEC. Information on our website is not incorporated
by reference into this Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.
Additionally, our Code of Business Conduct and Ethics and the charters of our Audit Committee, Compensation Committee and Nominating
Committee are posted on our website. Any of these corporate documents as well as any of the SEC filed reports are available in
print free of charge to any stockholder who requests them. Requests should be directed to our corporate Assistant Secretary by
mail to P.O. Box 10502, Midland, Texas 79702 or by email to mexco@sbcglobal.net.
ITEM
1A. RISK FACTORS
There
are many factors that affect our business and results of operations, some of which are beyond our control. The following is a
description of some of the important factors that could have a material adverse effect on our business, financial position, liquidity
and results of operations. Some of the following risks relate principally to the industry in which we operate and to our business.
Other risks relate principally to the securities markets and ownership of our common stock.
RISKS
RELATED TO OUR BUSINESS AND INDUSTRY
Volatility
of oil and gas prices significantly affects our results and profitability.
Prices
for oil and natural gas fluctuate widely. We cannot predict future oil and natural gas prices with any certainty. Historically,
the markets for oil and gas have been volatile, and they are likely to continue to be volatile. Factors that can cause price fluctuations
include the level of global demand for petroleum products; foreign supply and pricing of oil and gas; the ability of the Organization
of Petroleum Exporting Countries (“OPEC”) to set and maintain oil price and production controls; nature and extent
of governmental regulation and taxation, including environmental regulations; level of domestic and international exploration,
drilling and production activity; the cost of exploring for, producing and delivering oil and gas; speculative trading in crude
oil and natural gas derivative contracts; availability, proximity and capacity of oil and gas pipelines and other transportation
facilities; weather conditions; the price and availability of alternative fuels; technological advances affecting energy consumption;
and, overall political and economic conditions in oil producing countries.
Increases
and decreases in prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money
or raise additional capital. The amount we can borrow from banks may be subject to redetermination based on changes in prices.
In addition, we may have ceiling test writedowns when prices decline. Lower prices may also reduce the amount of crude oil and
natural gas that can be produced economically. Thus, we may experience material increases or decreases in reserve quantities solely
as a result of price changes and not as a result of drilling or well performance.
Changes
in oil and gas prices impact both estimated future net revenue and the estimated quantity of proved reserves. Any reduction in
reserves, including reductions due to price fluctuations, can reduce the borrowing base under our credit facility and adversely
affect the amount of cash flow available for capital expenditures and our ability to obtain additional capital for our exploration
and development activities.
Oil
and natural gas prices do not necessarily fluctuate in direct relationship to each other. Lower prices or lack of storage may
have an adverse affect on our financial condition due to reduction of our revenues, operating income and cash flows; curtailment
or shut-in of our production due to lack of transportation or storage capacity; cause certain properties in our portfolio to become
economically unviable; and, limit our financial condition, liquidity, and/or ability to finance planned capital expenditures and
operations.
Lower
oil and gas prices and other factors may cause us to record ceiling test writedowns.
Lower
oil and gas prices increase the risk of ceiling limitation write-downs. We use the full cost method to account for oil and gas
operations. Accordingly, we capitalize the cost to acquire, explore for and develop crude oil and natural gas properties. Under
the full cost accounting rules, the net capitalized cost of crude oil and natural gas properties may not exceed a “ceiling
limit” which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10%
plus the lower of cost or fair market value of unproved properties. If net capitalized costs of oil and natural gas properties
exceed the ceiling limit, we must charge the amount of the excess against earnings. This is called a “ceiling test writedown.”
Under the accounting rules, we are required to perform a ceiling test each quarter. A ceiling test writedown does not impact cash
flow from operating activities, but does reduce stockholders’ equity and earnings. The risk that we will be required to
write down the carrying value of oil and natural gas properties increases when oil and natural gas prices are low. We incurred
impairment charges during fiscal 2016 and may incur additional impairment charges in the future, particularly if commodity prices
decline, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.
There were no ceiling test impairments on our oil and gas properties during fiscal 2018 and 2017.
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
49% and 67% of our total estimated net proved reserves at March 31, 2018 and 2017, 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 2018, differentials averaged $0.69 per Bbl of oil and $0.03 per Mcf of gas. Increases
in the differential between the benchmark prices for oil and gas and the wellhead price we receive could significantly reduce
our revenues and our cash flow from operations.
Our
exploration and development drilling may not result in commercially productive reserves.
New
wells that we drill may not be productive, or we may not recover all or any portion of our investment in such wells. The seismic
data and other technologies we use do not allow us to know conclusively prior to drilling a well that crude oil or natural gas
is present or may be produced economically. Drilling for crude oil and natural gas often involves unprofitable efforts, not only
from dry holes but also from wells that are productive but do not produce sufficient net reserves to return a profit at then realized
prices after deducting drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain,
and cost factors can adversely affect the economics of a project.
Drilling
and operating activities are high risk activities that subject us to a variety of factors that we cannot control.
These
factors include availability of workover and drilling rigs, well blowouts, cratering, explosions, fires, formations with abnormal
pressures, pollution, releases of toxic gases and other environmental hazards and risks. Any of these operating hazards could
result in substantial losses to us. In addition, we incur the risk that no commercially productive reservoirs will be encountered,
and there is no assurance that we will recover all or any portion of our investment in wells drilled or re-entered.
Acquisitions
are subject to the risks and uncertainties of evaluating reserves and potential liabilities and may be disruptive and difficult
to integrate into our business.
We
plan to continue growing our reserves through acquisitions. Acquired properties can be subject to significant unknown liabilities.
Prior to completing an acquisition, it is generally not feasible to conduct a detailed review of each individual property to be
acquired in an acquisition. Even a detailed review or inspection of each property may not reveal all existing or potential liabilities
associated with owning or operating the property. Moreover, some potential liabilities, such as environmental liabilities related
to groundwater contamination, may not be discovered even when a review or inspection is performed. Our initial reserve estimates
for acquired properties may be inaccurate. Downward adjustments to our estimated proved reserves, including reserves added through
acquisitions, could require us to write down the carrying value of our oil and gas properties, which would reduce our earnings
and our stockholders’ equity. In addition, we may have to assume cleanup or reclamation obligations or other unanticipated
liabilities in connection with these acquisitions. The scope and cost of these obligations may ultimately be materially greater
than estimated at the time of the acquisition.
We
may not be able to fund the capital expenditures that will be required for us to increase reserves and production.
We
must make capital expenditures to develop our existing reserves and to discover new reserves. Historically, we have used our cash
flow from operations and borrowings under our credit facility to fund our capital expenditures, however, lower oil and gas prices
may prevent these options. Volatility in oil and gas prices, the timing of our drilling programs and drilling results will affect
our cash flow from operations. Lower prices and/or lower production will also decrease revenues and cash flow, thus reducing the
amount of financial resources available to meet our capital requirements, including reducing the amount available to pursue our
drilling opportunities.
The
borrowing base under our credit facility will be determined from time to time by the lender. Reductions in estimates of oil and
gas reserves could result in a reduction in the borrowing base, which would reduce the amount of financial resources available
under the credit facility to meet our capital requirements. Such a reduction could be the result of lower commodity prices and/or
production, inability to drill or unfavorable drilling results, changes in oil and gas reserve engineering, the lenders’
inability to agree to an adequate borrowing base or adverse changes in the lenders’ practices regarding estimation of reserves.
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 has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities
on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability to drill and
develop these locations depends on a number of uncertainties, including crude oil and natural gas prices, the availability of
capital, costs, drilling results, regulatory approvals and other factors. If future drilling results in these projects do not
establish sufficient reserves to achieve an economic return, we may curtail drilling in these projects. Because of these uncertainties,
we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce
crude oil or natural gas from these or any other potential drilling locations.
Failure
to comply with covenants under our debt agreement could adversely impact our financial condition and results of operations.
Our
credit facility agreement requires us to comply with certain customary covenants including limitations on change of control, disposition
of assets, mergers and reorganizations. We are also obligated to meet certain financial covenants. For example, our credit facility
requires, among other things, minimum earnings before interest, taxes, depreciation and amortization (“EBITDA”) of
$650,000 for each trailing four fiscal quarters and minimum interest coverage ratios (EBITDA/Interest Expense) of 2.00 to 1.00
for each quarter. If we fail to meet any of these loan covenants, the lender under the credit facility could accelerate the indebtedness
and seek to foreclose on the pledged assets.
Our
business depends on oil and natural gas transportation facilities which are owned by others.
The
marketability of our production depends in part on the availability, proximity and capacity of natural gas gathering systems,
pipelines and processing facilities. Federal and state regulation of oil and gas production and transportation, tax and energy
policies, changes in supply and demand and general economic conditions could all affect our ability to produce and market our
oil and gas.
We
have limited control over activities on properties we do not operate, which could reduce our production and revenues.
A
substantial amount of our business activities are conducted through joint operating or other agreements under which we own working
and royalty interests in natural gas and oil properties in which we do not operate. As a result, we have a limited ability to
exercise influence over normal operating procedures, expenditures or future development of underlying properties and their associated
costs. The failure of an operator of our wells to adequately perform operations could reduce our revenues and production.
The
oil and gas industry is highly competitive.
Competition
for oil and gas reserve acquisitions is significant. We may compete with major oil and gas companies, other independent oil and
gas companies and individual producers and operators, some of which have financial and personnel resources substantially in excess
of those available to us. As a result, we may be placed at a competitive disadvantage. Our ability to acquire and develop additional
properties in the future will depend upon our ability to select and acquire suitable producing properties and prospects for future
development activities. In addition, the oil and gas industry as a whole also competes with other industries in supplying the
energy and fuel requirements of industrial, commercial and individual consumers. The price and availability of alternative energy
sources could adversely affect our revenue. The market for our oil, gas and natural gas liquids production depends on factors
beyond our control, including domestic and foreign political conditions, the overall level of supply of and demand for oil, gas
and natural gas liquids, the price of imports of oil and gas, weather conditions, the price and availability of alternative fuels,
the proximity and capacity of gas pipelines and other transportation facilities and overall economic conditions.
We
may not be insured against all of the operating hazards to which our business is exposed.
Our
operations are subject to all the risks inherent in the exploration for, and development and production of oil and gas including
blowouts, fires and other casualties. We maintain insurance coverage customary for operations of a similar nature, but losses
could arise from uninsured risks or in amounts in excess of existing insurance coverage.
Certain
U.S. federal income tax deductions currently available with respect to crude oil and natural gas exploration and development may
be eliminated as a result of proposed legislation.
Legislation
previously has been proposed that would, if enacted into law, make significant changes to U. S. federal income tax laws, including
the elimination of certain key U.S. federal income tax incentives currently available to crude oil and natural gas exploration
and production companies. These changes include, but are not limited to: (1) the repeal of the percentage depletion allowance
for crude oil and natural gas properties, (2) the elimination of current deductions for intangible drilling and development costs,
(3) the elimination of the deduction for certain U.S. domestic production activities, and (4) an extension of the amortization
period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted and, if enacted,
how soon any such changes could become effective. The passage of this type of legislation or any other similar changes in U.S.
federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to crude
oil and natural gas exploration and development, and any such change could have an adverse effect on our financial position, results
of operations and cash flows.
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 46% of the outstanding shares of our common stock. Mr. Taylor is also our Chairman of
the Board and Chief Executive Officer. As a result, Mr. Taylor has significant influence in matters voted on by our shareholders,
including the election of our Board members. Mr. Taylor participates in all facets of our business and has a significant impact
on both our business strategy and daily operations. The retirement, incapacity or death of Mr. Taylor, or any change in the power
to vote shares beneficially owned by Mr. Taylor, could result in negative market or industry perception and could have an adverse
effect on our business.
RISKS
RELATED TO OUR COMMON STOCK
We
may issue additional shares of common stock in the future, which could cause dilution to all shareholders.
We
may seek to raise additional equity capital in the future. Any issuance of additional shares of our common stock will dilute the
percentage ownership interest of all shareholders and may dilute the book value per share of our common stock.
We
have not and do not anticipate paying any cash dividends on our common stock in the foreseeable future.
We
have paid no cash dividends on our common stock to date and it is not anticipated that any will be paid to holders of our common
stock in the foreseeable future. The terms of our existing credit facility restricts the payment of dividends without the prior
written consent of the lenders. We currently intend to retain all future earnings to fund the development and growth of our business.
Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our
earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to
the payment of dividends and other considerations that our board of directors deems relevant. Stockholders must rely on sales
of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment.
Control
by our executive officers and directors may limit your ability to influence the outcome of matters requiring stockholder approval
and could discourage our potential acquisition by third parties.
As
of March 31, 2018, our executive officers and directors beneficially owned approximately 51% of our common stock. These stockholders,
if acting together, would be able to influence significantly all matters requiring approval by our stockholders, including the
election of our board of directors and the approval of mergers or other business combination transactions.
The
price of our common stock has been volatile and could continue to fluctuate substantially.
Mexco
common stock is traded on the NYSE American. The market price of our common stock has and could continue to experience volatility
due to reasons unrelated to our operating performance. These reasons include: supply and demand for natural gas and oil; political
conditions in oil and natural gas producing regions; demand for our common stock and limited trading volume; investor perception
of our industry; fluctuations in commodity prices; variations in our results of operations; legislative or regulatory changes;
general trends in the oil and natural gas industry; market conditions and analysts’ estimates; and, other events in the
oil and gas industry.
Many
of these factors are beyond our control, and we cannot predict their potential effects on the price of our common stock. We cannot
assure you that the market price of our common stock will not fluctuate or decline significantly in the future. In addition, the
stock markets in general can experience considerable price and volume fluctuations.
Failure
of the Company’s internal control over financial reporting could harm its business and financial results.
The
management of Mexco is responsible for establishing and maintaining effective internal control over financial reporting. Internal
control over financial reporting is a process to provide reasonable assurance regarding the reliability of financial reporting
for external purposes in accordance with accounting principles generally accepted in the United States. Internal control over
financial reporting includes maintaining records that in reasonable detail accurately and fairly reflect Mexco’s transactions;
providing reasonable assurance that transactions are recorded as necessary for preparation of the financial statements; providing
reasonable assurance that receipts and expenditures are made in accordance with management authorization; and providing reasonable
assurance that unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements
would be prevented or detected on a timely basis.
ITEM
1B. UNRESOLVED STAFF COMMENTS
None.
ITEM
2. PROPERTIES
Our
properties consist primarily of oil and gas wells and our ownership in leasehold acreage, both developed and undeveloped. As of
March 31, 2018, we had interests in approximately 6,000 gross (25 net) oil and gas wells and owned leasehold mineral and royalty
interests in approximately 564,000 gross (3,732 net) acres.
Oil
and Natural Gas Reserves
In
accordance with current SEC rules, the average prices used in computing reserves at March 31, 2018 were $50.63 per bbl of oil
and $43.88 in 2017, an increase of 15%, and $3.031 per mcf of natural gas and $2.561 in 2017, an increase of 18%, 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 2018. The benchmark price of $49.94 per bbl of oil at March 31, 2018 versus $44.10 at March 31, 2017,
was adjusted by lease for gravity, transportation fees and regional price differentials and did not give effect to derivative
transactions. The benchmark price of $3.00 per mcf of natural gas at March 31, 2018 versus $2.74 at March 31, 2017, 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, 2018 is based on evaluations
prepared by Russell K. Hall and Associates, Inc. Environmental Engineering Consultants, based in Midland, Texas (“Hall and
Associates”), a summary of which is filed as Exhibit 99.1 to this annual report. The engineering report with respect to
Mexco’s estimates of proved oil and gas reserves as of March 31, 2017 was based on evaluations prepared by Joe C. Neal and
Associates, Petroleum and Environmental Engineering Consultants, based in Midland, Texas.
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 20 years experience in the oil and gas industry reviews the final
reserves estimate and consults with a degreed geological consultant with extensive geological experience and if necessary, discusses
the process used and findings with 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 40 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,
|
|
|
|
2018
|
|
|
2017
|
|
Oil
(Bbls):
|
|
|
|
|
|
|
|
|
Proved
developed – Producing
|
|
|
379,390
|
|
|
|
371,860
|
|
Proved
developed – Non-producing
|
|
|
11,350
|
|
|
|
28,030
|
|
Proved
undeveloped
|
|
|
805,980
|
|
|
|
1,724,420
|
|
Total
|
|
|
1,196,720
|
|
|
|
2,124,310
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (Mcf):
|
|
|
|
|
|
|
|
|
Proved
developed – Producing
|
|
|
3,774,490
|
|
|
|
3,817,490
|
|
Proved
developed – Non-producing
|
|
|
328,900
|
|
|
|
290,460
|
|
Proved
undeveloped
|
|
|
1,383,120
|
|
|
|
2,572,960
|
|
Total
|
|
|
5,486,510
|
|
|
|
6,680,910
|
|
|
|
|
|
|
|
|
|
|
Total
net proved reserves (BOE)
|
|
|
2,111,140
|
|
|
|
3,237,795
|
|
|
|
|
|
|
|
|
|
|
PV-10 Value
(1)
|
|
$
|
22,001,900
|
|
|
$
|
25,265,700
|
|
Present
value of future income tax discounted at 10%
|
|
|
(3,125,900
|
)
|
|
|
(6,182,700
|
)
|
Standardized
measure of discounted future net cash flows (2)
|
|
$
|
18,876,000
|
|
|
$
|
19,083,000
|
|
|
|
|
|
|
|
|
|
|
Prices
used in Calculating Reserves: (3)
|
|
|
|
|
|
|
|
|
Natural
gas (per Mcf)
|
|
$
|
3.031
|
|
|
$
|
2.561
|
|
Oil (per Bbl)
|
|
$
|
50.63
|
|
|
$
|
43.88
|
|
|
(1)
|
The
PV-10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income
tax, discounted at 10% per annum, which is the most directly comparable GAAP financial measure. PV-10 is relevant and useful
to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior
to taking into account future corporate income taxes. Further, investors may utilize the measure as a basis for comparison
of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return
on investment related to our oil and natural gas properties. Our reconciliation of this non-GAAP financial measure is shown
in the table as the PV-10, less future income taxes, discounted at 10% per annum, resulting in the standardized measure of
discounted future net cash flows. The standardized measure of discounted future net cash flows represents the present value
of future cash flows attributable to our proved oil and natural gas reserves after income tax, discounted at 10%.
|
|
|
|
|
(2)
|
In
accordance with SEC requirement, the standardized measure of discounted future net cash flows was computed by applying 12-month
average prices for oil and gas during the fiscal year to the estimated future production of proved oil and gas reserves, less
estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less
estimated future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already
legislated) to be incurred on pretax net cash flows less tax basis of the properties and available credits, and assuming continuation
of existing economic conditions.
|
|
|
|
|
(3)
|
These
prices reflect adjustment by lease for quality, transportation fees and regional price differentials and did not give effect
to derivative transactions.
|
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, 2018, 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, 2018, we participated in the development of 16 wells converting reserves of approximately 70,500
BOE from proved undeveloped to proved developed – producing with capital cost of approximately $445,000.
Oil
and gas prices significantly impact the calculation of the PV-10 and the standardized measure of discounted future net cash flows.
The present value of future net cash flows does not purport to be an estimate of the fair market value of the Company’s
proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices
and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time
value of money and the risks inherent in producing oil and gas. Future prices received for production and costs may vary, perhaps
significantly, from the prices and costs assumed for purposes of these estimates. The 10% discount factor used to calculate present
value, which is required by Accounting Standard Codification (“ASC”) 932, “Extractive Activities - Oil and
Gas”, may not necessarily be the most appropriate discount rate. The present value, no matter what discount rate is
used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.
Drilling
Activities
The
following table sets forth our drilling activity in wells in which we own a working interest for the years ended March 31:
|
|
Year
Ended March 31,
|
|
|
|
2018
|
|
|
2017
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
Development
Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
- Horizontal
|
|
|
23
|
|
|
|
.10
|
|
|
|
17
|
|
|
|
.11
|
|
Productive
- Vertical
|
|
|
2
|
|
|
|
.01
|
|
|
|
4
|
|
|
|
.02
|
|
Nonproductive
- Vertical
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Total
|
|
|
25
|
|
|
|
.11
|
|
|
|
21
|
|
|
|
.13
|
|
We
have not participated in any exploratory wells during the years ended March 31, 2018 and 2017. 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.
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, 2018, we held an interest in approximately
6,000 gross (25 net) productive wells, including approximately 4,800 wells in which we held an overriding or royalty interest
and 1,200 wells in which we held a working interest. Mexco operates 3 of its working interest producing wells.
A
gross acre is an acre in which an interest is owned. A net acre is deemed to exist when the sum of fractional ownership interests
in gross acres equals one. The number of net acres is the sum of the fractional interests owned in gross acres. The following
table sets forth the approximate developed acreage in which we held a leasehold mineral or other interest as of March 31, 2018:
|
|
Developed
Acres
|
|
|
|
Gross
|
|
|
Net
|
|
Texas
|
|
|
345,700
|
|
|
|
1,727
|
|
Oklahoma
|
|
|
90,800
|
|
|
|
1,372
|
|
New
Mexico
|
|
|
32,900
|
|
|
|
511
|
|
Louisiana
|
|
|
37,900
|
|
|
|
34
|
|
North
Dakota
|
|
|
30,800
|
|
|
|
43
|
|
Kansas
|
|
|
9,700
|
|
|
|
24
|
|
Montana
|
|
|
7,800
|
|
|
|
5
|
|
Wyoming
|
|
|
3,800
|
|
|
|
5
|
|
Arkansas
|
|
|
1,000
|
|
|
|
5
|
|
Mississippi
|
|
|
1,600
|
|
|
|
3
|
|
Alabama
|
|
|
600
|
|
|
|
2
|
|
Colorado
|
|
|
1,100
|
|
|
|
.5
|
|
Virginia
|
|
|
100
|
|
|
|
.5
|
|
Total
|
|
|
563,800
|
|
|
|
3,734
|
|
Net
Production, Unit Prices and Costs
The
following table summarizes our net oil and natural gas production, the average sales price per barrel (“bbl”) of oil
and per thousand cubic feet (“mcf”) of natural gas produced and the average production (lifting) cost per unit of
production for the years ended March 31:
|
|
Year
Ended March 31,
|
|
|
|
2018
|
|
|
2017
|
|
Oil
(a):
|
|
|
|
|
|
|
|
|
Production
(Bbls)
|
|
|
34,743
|
|
|
|
34,689
|
|
Revenue
|
|
$
|
1,789,736
|
|
|
$
|
1,517,606
|
|
Average
Bbls per day (d)
|
|
|
95
|
|
|
|
95
|
|
Average
sales price per Bbl
|
|
$
|
51.51
|
|
|
$
|
43.75
|
|
Gas
(b):
|
|
|
|
|
|
|
|
|
Production
(Mcf)
|
|
|
318,774
|
|
|
|
356,268
|
|
Revenue
|
|
$
|
860,496
|
|
|
$
|
819,616
|
|
Average
Mcf per day (d)
|
|
|
873
|
|
|
|
976
|
|
Average
sales price per Mcf
|
|
$
|
2.70
|
|
|
$
|
2.30
|
|
Production
cost:
|
|
|
|
|
|
|
|
|
Production
cost
|
|
$
|
870,806
|
|
|
$
|
717,757
|
|
Production
and ad valorem taxes
|
|
$
|
199,641
|
|
|
$
|
160,701
|
|
Total
BOE (c)
|
|
|
87,872
|
|
|
|
94,067
|
|
Production
cost per BOE
|
|
$
|
9.91
|
|
|
$
|
7.63
|
|
Production
cost per sales dollar
|
|
$
|
0.33
|
|
|
$
|
0.31
|
|
Total
oil and gas revenue
|
|
$
|
2,650,232
|
|
|
$
|
2,337,222
|
|
|
(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, 2018
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been signed below as of June 26, 2018, by the following
persons on behalf of the Registrant and in the capacity indicated.
/s/
Nicholas C. Taylor
|
|
Nicholas
C. Taylor
|
|
Chief
Executive Officer, Chairman of the Board of Directors
|
|
|
|
/s/
Tamala L. McComic
|
|
Tamala
L. McComic
|
|
Chief
Financial Officer, President, Treasurer and Assistant Secretary
|
|
|
|
/s/
Michael J. Banschbach
|
|
Michael
J. Banschbach
|
|
Director
|
|
|
|
/s/
Kenneth L. Clayton
|
|
Kenneth
L. Clayton
|
|
Director
|
|
|
|
/s/
Thomas R. Craddick
|
|
Thomas
R. Craddick
|
|
Director
|
|
|
|
/s/
Paul G. Hines
|
|
Paul
G. Hines
|
|
Director
|
|
|
|
/s/
Christopher M. Schroeder
|
|
Christopher
M. Schroeder
|
|
Director
|
|
Glossary
of Abbreviations and Terms
The
following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report.
Basin.
A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
BBA
LIBOR.
British Bankers Association London Interbank Offered Rate. BBA Libor is the most widely used rate for short term interest
rates worldwide.
Bbl
.
One stock tank barrel, or 42 U.S. gallons of liquid volume, used herein in reference to crude oil, condensate or natural gas liquids
hydrocarbons.
BOE.
Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
BTU.
British thermal unit.
Completion
.
The installation of permanent equipment for the production of oil or natural gas.
Condensate.
Liquid hydrocarbons associated with the production of a primarily natural gas reserve.
Credit
Facility.
A line of credit provided by a bank or group of banks, secured by oil and gas properties.
DD&A.
Refers to depreciation, depletion and amortization of the Company’s property and equipment.
Developed
acreage
. The number of acres which are allocated or assignable to producing wells or wells capable of production.
Development
costs.
Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided
by proved reserve additions and revisions to proved reserves.
Development
well
. A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Dry
hole
. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of
such production exceed production expenses and taxes.
Exploration.
The search for natural accumulations of oil and natural gas by any geological, geophysical or other suitable means.
Exploratory
well
. A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in
a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.
Extensions
and discoveries
. As to any period, the increases to proved reserves from all sources other than the acquisition of proved
properties or revisions of previous estimates.
Field.
An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological
structural feature and/or stratigraphic condition.
Formation.
A layer of rock which has distinct characteristics that differs from nearby rock.
Gross
acres or wells.
Refers to the total acres or wells in which the Company owns any amount of working interest.
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, 2018 and 2017
1.
Nature of Operations
Mexco
Energy Corporation (a Colorado corporation) and its wholly owned subsidiaries, Forman Energy Corporation (a New York corporation),
Southwest Texas Disposal Corporation (a Texas corporation) and TBO Oil & Gas, LLC (a Texas limited liability company) (collectively,
the “Company”) are engaged in the exploration, development and production of natural gas, crude oil, condensate and
natural gas liquids (“NGLs”). Most of the Company’s oil and gas interests are centered in West Texas; however,
the Company owns producing properties and undeveloped acreage in thirteen states. Although the Company’s oil and gas interests
predominately are operated by others, the Company operates three wells in which it owns an interest.
2.
Summary of Significant Accounting Policies
Principles
of Consolidation
. The consolidated financial statements include the accounts of Mexco Energy Corporation and its wholly owned
subsidiaries. All significant intercompany balances and transactions associated with the consolidated operations have been eliminated.
Estimates
and Assumptions
. In preparing financial statements in conformity with accounting principles generally accepted in the United
States of America (“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, 2018, 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, 2018 and 2017, 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.
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.
Oil and gas sales and resulting receivables are recognized when the product is delivered to the purchaser and
title has transferred. Sales are to credit-worthy energy purchasers with payments generally received within 60 days of transportation
from the well site. The Company has historically had little, if any, uncollectible oil and gas receivables.
Gas
Balancing
. Gas imbalances are accounted for under the sales method whereby revenues are recognized based on production sold.
A liability is recorded when excess takes of natural gas volumes exceed estimated remaining recoverable reserves (over produced).
No receivables are recorded for those wells where the Company has taken less than its ownership share of gas production (under
produced). The Company does not have any significant gas imbalances.
Stock-based
Compensation
. The Company uses the Binomial option pricing model to estimate the fair value of stock based compensation expenses
at grant date. This expense is recognized as compensation expense in its 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.
Reclassifications.
Certain amounts in prior periods’ consolidated financial statements have been reclassified to conform with the current
period’s presentation. These reclassifications had no effect on previously reported results of operations, retained earnings
or net cash flows.
Recent
Accounting Pronouncements.
In February 2016, the FASB issued ASU 2016-02, Topic 842 Leases, which requires companies to include
leases with a term greater than one year on their balance sheets, but recognize lease costs on the income statement in a manner
similar to accounting for leases prior to ASU 2016-02. The standard is effective for fiscal years beginning after December 15,
2018, and interim periods thereafter. Early adoption is permitted. The Company is still determining the impact of this amendment.
In
May 2014, the FASB issued ASU updated No. 2014-09, Topic 606: Revenue from Contracts with Customers. Under the amendments in this
update, recognition of revenue occurs when a customer obtains control of promised goods or services in an amount that reflects
the consideration to which the entity expects to be entitled in exchange for those goods or services. In addition, the new standard
requires that reporting companies disclose the nature, amount, timing, and uncertainty of revenue and cash flows arising from
contracts with customers. The amendments in this update are effective for fiscal years and interim periods within those years
beginning after December 15, 2017. The new standard is required to be applied either retrospectively to each prior reporting period
presented, or retrospectively with the cumulative effect of applying the update recognized at the date of initial application.
The Company has determined that implementation of this amendment will not result in any change to its consolidated financial statements
other than mandatory disclosure items.
Liquidity
and Capital Resources.
Historically, we have funded our operations, acquisitions, exploration and development expenditures
from cash generated by operating activities, bank borrowings, sales of non-core properties and issuance of common stock. Our long
term strategy is on increasing profit margins while concentrating on obtaining reserves with low cost operations by acquiring
and developing oil and gas properties with potential for long-lived production. We focus our efforts on the acquisition of royalties
and working interest, non-operated properties in areas with significant development potential.
3.
Fair Value of Financial Instruments
The
carrying amount reported in the accompanying consolidated balance sheets for cash and cash equivalents, accounts receivable and
accounts payable approximates fair value because of the immediate or short-term maturity of these financial instruments.
The
fair value amount reported in the accompanying consolidated balance sheets for long term debt approximates fair value because
the actual interest rates do not significantly differ from current rates offered for instruments with similar characteristics.
See the Company’s Note 5 on Credit Facility for further discussion.
4
.
Property Sales
During
fiscal 2018, 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.
In
April 2017, the Company sold for a total consideration of $460,461, leasehold interests in 137 net acres in the Scoop-Stack areas
of Canadian and Grady Counties, Oklahoma. The first of these transactions in which the Company retained its interests in the existing
producing wellbores on the acreage was in the amount of $336,730. The second transaction in the amount of $123,731 included the
producing wellbores as well as the acreage. Of these proceeds, $410,000 was applied to reduce bank indebtedness and the balance
of $50,461 was applied to working capital of the Company.
In
June and November 2017, the Company received approximately $33,000 and $114,000, respectively, in cash from a sale of joint venture
leasehold acreage in Reeves and Ward County, TX. The Company retained its interests in the existing producing wellbores in both
counties.
In
July 2017, the Company received approximately $49,000 in cash from a sale of joint venture leasehold acreage and marginal producing
working interest wells in Ward County, TX.
In
December 2017, the Company received approximately $30,000 in cash from a sale of joint venture leasehold acreage and marginal
producing working interest wells in Midland County, TX.
In
December 2017, the Company received approximately $1.9 million in cash from a sale of joint venture leasehold marginal producing
working interests in several thousand acres located in Ward and Winkler Counties, Texas. Of these proceeds, approximately $1.518
million was applied to the Company’s bank debt and the balance to the Company’s working capital. Approximately $200,000
of the purchase price is being held in escrow pending payment of closing costs and resolution of title issues as to a small portion
of the sale assets. This amount is reflected in accounts receivable trade on our consolidated balance sheets.
In
January 2018, the Company sold additional leasehold interests in the Scoop-Stack area of Grady County, Oklahoma for $46,000 which
the Company used to reduce bank indebtedness. The Company retained its interests in the existing producing wellbore on the acreage.
In
January 2018, the Company received approximately $235,000 in cash from a sale of joint venture leasehold acreage and marginal
producing working interest wells in Winkler County, TX.
Also
in January 2018, the Company sold its working interests in two wells in Loving County, TX in which the Company was the operator.
The Company received approximately $204,000 in cash for its share of which $100,000 was applied to the Company’s bank debt.
In
March 2018, the Company sold its non-operated working interests in 6 producing oil wells and 1 salt water disposal well in Pecos
County, TX for a cash purchase price of $112,500 in which $100,000 was applied to the Company’s bank debt.
5
.
Credit Facility
The
Company has a loan agreement with Bank of America, N.A. (the “Agreement”), which provided for a credit facility of
$5,570,000 with no monthly commitment reductions and a borrowing base to be evaluated on July 30 and January 1 of each year or
at any additional time in the bank’s discretion. The borrowing base was evaluated on January 26, 2018 and set at $950,000.
The borrowing base also resets to the extent the Company sells or otherwise disposes of any of its oil and gas properties as the
Company is required to pay 100% of such net proceeds to the lender resulting in a permanent reduction of the borrowing base unless
prior approval by the bank states otherwise. As of March 31, 2018, the borrowing base was set at $700,000.
The
Agreement was renewed eleven times with the eleventh amendment effective as of March 8, 2017 with a maturity date of November
30, 2020. Under such renewal agreement, interest on the facility accrues at an annual rate equal to the British Bankers Association
London Interbank Offered Rate (“BBA LIBOR”) daily floating rate, plus 3.0 percentage points, which was 4.875% on March
31, 2018. Interest on the outstanding amount under the credit agreement is payable monthly. There was no availability of this
line of credit at March 31, 2018. No principal payments are anticipated to be required through November 30, 2020. 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 minimum earnings before interest, taxes, depreciation and amortization (“EBITDA”) of $650,000 for each
trailing four 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, 2018 and believes it will remain in compliance for the next fiscal
year.
In
addition, this Agreement prohibits the Company from paying cash dividends on its common stock. The Agreement does grant the Company
permission to enter into hedge agreements however, it is under no obligation to do so.
The
amended Agreement allows for up to $500,000 of the facility to be used for outstanding letters of credits. As of March 31, 2018,
one letter of credit for $50,000 is outstanding under the facility. This letter of credit is in lieu of a plugging bond with the
Texas Railroad Commission (“TRRC”) covering the properties the Company operates and renews annually. The Company will
pay a fee in an amount equal to 1 percent (1.0%) per annum of the outstanding undrawn amount of each standby letter of credit,
payable monthly in arrears, on the basis of the face amount outstanding on the day the fee is calculated.
The
balance outstanding on the line of credit as of March 31, 2018 was $700,000 and as of June 15, 2018 was $500,000. The following
table is a summary of activity on the Bank of America, N.A. line of credit for the year ended March 31, 2018:
|
|
Principal
|
|
Balance
at April 1, 2017:
|
|
$
|
2,900,000
|
|
Borrowings
|
|
|
-
|
|
Repayments
|
|
|
(2,200,000
|
)
|
Balance
at March 31, 2018:
|
|
$
|
700,000
|
|
6
.
Asset Retirement Obligations
The
Company’s asset retirement obligations relate to the plugging of wells, the removal of facilities and equipment, and site
restoration on oil and gas properties. The fair value of a liability for an ARO is recorded in the period in which it is incurred,
discounted to its present value using the credit adjusted risk-free interest rate, and a corresponding amount capitalized by increasing
the carrying amount of the related long-lived asset. The liability is accreted each period 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:
|
|
2018
|
|
|
2017
|
|
Carrying
amount of asset retirement obligations, beginning of year
|
|
$
|
978,484
|
|
|
$
|
1,221,077
|
|
Liabilities
incurred
|
|
|
6,689
|
|
|
|
8,753
|
|
Liabilities
settled
|
|
|
(153,539
|
)
|
|
|
(287,089
|
)
|
Accretion
expense
|
|
|
31,460
|
|
|
|
35,743
|
|
Revisions
|
|
|
(541
|
)
|
|
|
-
|
|
Carrying
amount of asset retirement obligations, end of year
|
|
|
862,553
|
|
|
|
978,484
|
|
Less:
Current portion
|
|
|
10,000
|
|
|
|
10,000
|
|
Non-Current
asset retirement obligation
|
|
$
|
852,553
|
|
|
$
|
968,484
|
|
7
.
Income Taxes
The
Company files a consolidated federal income tax return and various state income tax returns. The amount of income taxes the Company
records requires the interpretation of complex rules and regulations of federal and state taxing jurisdictions. With few exceptions,
the Company is no longer subject to U.S. federal and state income tax examinations by tax authorities for years prior to 2015.
On
December 22, 2017, the tax legislation referred to as the “Tax Cuts and Jobs Act” (the 2017 Tax Reform Act) was enacted.
The more significant changes that impact the Company are the reduction in the corporate federal income tax rate from 35% to 21%.
GAAP requires deferred income tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary
differences are to be realized or settled. The Company’s deferred income taxes were remeasured based upon the new tax rates
which amounted to a $466,020 reduction in deferred tax asset and valuation amount.
The
2017 Tax Reform Act reduced the corporate federal statutory income tax rate from 35% to 21% generally effective for tax years
beginning on or after January 1, 2018. However, companies with fiscal years that include January 1, 2018 must use a blended rate.
Our corporate federal statutory income tax rate will be 21% starting in fiscal 2019.
Significant
components of net deferred tax assets (liabilities) at March 31 are as follows:
|
|
2018
|
|
|
2017
|
|
Deferred
tax assets:
|
|
|
|
|
|
|
|
|
Percentage
depletion carryforwards
|
|
$
|
1,111,801
|
|
|
$
|
1,786,522
|
|
Deferred
stock-based compensation
|
|
|
33,581
|
|
|
|
52,654
|
|
Asset
retirement obligation
|
|
|
181,136
|
|
|
|
332,685
|
|
Net
operating loss
|
|
|
995,489
|
|
|
|
1,012,138
|
|
Other
|
|
|
5,141
|
|
|
|
7,170
|
|
|
|
|
2,327,148
|
|
|
|
3,191,169
|
|
Deferred
tax liabilities:
|
|
|
|
|
|
|
|
|
Excess
financial accounting bases over tax bases of property and equipment
|
|
|
1,091,725
|
|
|
|
2,052,749
|
|
Deferred
tax asset, net
|
|
$
|
1,235,423
|
|
|
$
|
1,138,420
|
|
Valuation
allowance
|
|
|
(1,235,423
|
)
|
|
|
(1,138,420
|
)
|
Net
deferred tax
|
|
$
|
-
|
|
|
$
|
-
|
|
As
of March 31, 2018, the Company has a statutory depletion carryforward of approximately $5,300,000, which does not expire. At March
31, 2018, the Company had a net operating loss carryforward for regular income tax reporting purposes of approximately $4,700,000,
which will begin expiring in 2029. The Company’s ability to use some of its net operating loss carryforwards and certain
other tax attributes to reduce current and future U.S. federal taxable income is subject to limitations under the Internal Revenue
Code.
A
valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that
some or all of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment
regarding our future taxable income, and we consider the tax consequences in the jurisdiction where such taxable income is generated,
to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results
of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as the
current and forecasted business economics of our industry.
A
reconciliation of the provision for income taxes to income taxes computed using the federal statutory rate for years ended March
31 follows:
|
|
2018
|
|
|
2017
|
|
Tax
expense at federal statutory rate (1)
|
|
$
|
(98,858
|
)
|
|
$
|
(236,148
|
)
|
Statutory
depletion carryforward
|
|
|
(8,361
|
)
|
|
|
(67,801
|
)
|
Change
in valuation allowance
|
|
|
(362,908
|
)
|
|
|
289,456
|
|
U.
S. tax reform, corporate rate reduction
|
|
|
466,020
|
|
|
|
-
|
|
Permanent
differences
|
|
|
3,506
|
|
|
|
14,497
|
|
Other
|
|
|
601
|
|
|
|
(4
|
)
|
Total
income tax
|
|
$
|
-
|
|
|
$
|
-
|
|
Effective
income tax rate
|
|
|
-
|
|
|
|
-
|
|
|
(1)
|
The
federal statutory rate was 30.75% for fiscal year ending March 31, 2018 and 34% for fiscal year ending March 31, 2017.
|
For
the years ended March 31, 2018 and 2017, the Company did not have any uncertain tax positions.
A
reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows:
|
|
2018
|
|
|
2017
|
|
Unrecognized
tax benefits at beginning of period
|
|
$
|
745,000
|
|
|
$
|
679,000
|
|
Change
based on tax positions related to the current year
|
|
|
(745,000
|
)
|
|
|
66,000
|
|
Changes
to tax positions of prior years
|
|
|
-
|
|
|
|
-
|
|
Settlements
|
|
|
-
|
|
|
|
-
|
|
Expirations
|
|
|
-
|
|
|
|
-
|
|
Unrecognized
tax benefits at end of period
|
|
$
|
-
|
|
|
$
|
745,000
|
|
While
the amount of unrecognized tax benefits may change in the next 12 months, the Company does not expect any change to have a significant
impact on its results of operations. The recognition of the total amount of the unrecognized tax benefits would have an impact
on the effective tax rate. If these unrecognized tax benefits are disallowed, the Company will be required to pay additional taxes.
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, 2018 and 2017. Our deferred tax asset is $1,235,423
as of March 31, 2018 with a valuation amount of $1,235,423. We believe it is more likely than not that these deferred tax
assets will not be realized. Management assesses the available positive and negative evidence to estimate whether sufficient future
taxable income will be generated to permit the use of deferred tax assets. The amount of the deferred tax asset considered realizable,
however, could be adjusted if estimates of future taxable income are increased or if objective negative evidence in the form of
cumulative losses is no longer present and additional weight is given to subjective evidence such as expected future growth.
8
.
Major Customers
Currently,
the Company operates exclusively within the United States and its revenues and operating profit are derived from the oil and gas
industry. Oil and gas production is sold to various purchasers and the receivables are unsecured. Historically, the Company has
not experienced significant credit losses on its oil and gas accounts and management is of the opinion that significant credit
risk does not exist. Management is of the opinion that the loss of any one purchaser would not have an adverse effect on the Company’s
ability to sell its oil and gas production.
In
fiscal 2018, one customer accounted for 37% of the total oil and gas revenues and 33% of the total oil and gas accounts receivable
and another customer accounted for 8% of the total oil and gas revenues and 7% of the total oil and gas accounts receivable. In
fiscal 2017, one customer accounted for 31% of the total oil and gas revenues and 32% of the total oil and gas accounts receivable
and another customer accounted for 12% of the total oil and gas revenues and 5% of the total oil and gas accounts receivable.
9
.
Oil and Gas Costs
The
costs related to the Company’s oil and gas activities were incurred as follows for the year ended March 31:
|
|
2018
|
|
|
2017
|
|
Property
acquisition costs:
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
-
|
|
|
$
|
-
|
|
Unproved
|
|
|
-
|
|
|
|
-
|
|
Exploration
|
|
|
-
|
|
|
|
-
|
|
Development
|
|
|
1,099,051
|
|
|
|
731,400
|
|
Capitalized
asset retirement obligations
|
|
|
6,689
|
|
|
|
8,753
|
|
Total
costs incurred for oil and gas properties
|
|
$
|
1,105,740
|
|
|
$
|
740,153
|
|
The
Company had the following aggregate capitalized costs relating to its oil and gas property activities at March 31:
|
|
2018
|
|
|
2017
|
|
Proved
oil and gas properties
|
|
$
|
35,224,784
|
|
|
$
|
37,640,096
|
|
Unproved
oil and gas properties:
|
|
|
|
|
|
|
|
|
subject
to amortization
|
|
|
-
|
|
|
|
-
|
|
not
subject to amortization
|
|
|
-
|
|
|
|
-
|
|
|
|
|
35,224,784
|
|
|
|
37,640,096
|
|
Less
accumulated DD&A
|
|
|
26,355,604
|
|
|
|
25,479,335
|
|
|
|
$
|
8,896,180
|
|
|
$
|
12,160,761
|
|
DD&A
amounted to $10.02 and $12.47 per BOE of production for the years ended March 31, 2018 and 2017, respectively.
10
.
Loss Per Common Share
Due
to a net loss for the years ended March 31, 2018 and 2017, 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:
|
|
2018
|
|
|
2017
|
|
Net
loss
|
|
$
|
(321,489
|
)
|
|
$
|
(694,553
|
)
|
|
|
|
|
|
|
|
|
|
Shares outstanding:
|
|
|
|
|
|
|
|
|
Weighted
avg. common shares outstanding – basic
|
|
|
2,037,266
|
|
|
|
2,037,266
|
|
Effect
of the assumed exercise of dilutive stock options
|
|
|
-
|
|
|
|
-
|
|
Weighted
avg. common shares outstanding – dilutive
|
|
|
2,037,266
|
|
|
|
2,037,266
|
|
|
|
|
|
|
|
|
|
|
Loss per common
share:
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.16
|
)
|
|
$
|
(0.34
|
)
|
Diluted
|
|
$
|
(0.16
|
)
|
|
$
|
(0.34
|
)
|
11
.
Stockholders’ Equity
In
September 2017, 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 2018 and
2017.
12
.
Stock Options
In
September 2009, the Company adopted the 2009 Employee Incentive Stock Plan (the “2009 Plan”). The 2009 Plan provides
for the award of stock options up to 200,000 shares and includes option awards as well as stock awards. Option awards are granted
with the restriction of requiring payment for the shares. Stock awards are granted without restrictions and without payment by
the recipient. Neither option awards nor stock awards may exceed 25,000 shares granted to any one individual in any fiscal year.
Stock options may be an incentive stock option or a nonqualified stock option. Options to purchase common stock under the plan
are granted at the fair market value of the common stock at the date of grant, become exercisable to the extent of 25% of the
shares optioned on each of four anniversaries of the date of grant, expire ten years from the date of grant and are subject to
forfeiture if employment terminates. The 2009 Plan expires ten years from the date of adoption.
According
to the Company’s employee stock incentive plan, new shares will be issued upon the exercise of stock options and the Company
can repurchase shares exercised under the plan. The plan also provides for the granting of stock awards. No stock awards were
granted during fiscal 2018 and 2017.
The
Company recognized compensation expense of $20,753 and $52,864 related to vesting stock options in general and administrative
expense in the Consolidated Statements of Operations for fiscal 2018 and 2017, respectively. The total cost related to non-vested
awards not yet recognized at March 31, 2018 totals $4,667, which is expected to be recognized over a weighted average of .42 years.
The
fair value of each stock option is estimated on the date of grant using the Binomial valuation model. Expected volatilities are
based on historical volatility of the Company’s stock over the contractual term of 120 months and other factors. The Company
uses historical data to estimate option exercise and employee termination within the valuation model. The expected term of options
granted is derived from the output of the option valuation model and represents the period of time that options granted are expected
to be outstanding. The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield
curve in effect at the time of grant. As the Company has never declared dividends, no dividend yield is used in the calculation.
Actual value realized, if any, is dependent on the future performance of the Company’s common stock and overall stock market
conditions. There is no assurance the value realized by an optionee will be at or near the value estimated by the Binomial model.
During
the years ended March 31, 2018 and 2017, no stock options were granted.
No
forfeiture rate is assumed for stock options granted to directors or employees due to the forfeiture rate history for these types
of awards. During the year ended March 31, 2018, vested stock options covering 1,000 shares were forfeited due to the resignation
of an employee. During the year ended March 31, 2017, 3,000 vested stock options expired because there were not exercised and
1,000 unvested stock options were forfeited due to the resignation of an employee.
The
following table is a summary of activity of stock options for the years ended March 31, 2018 and 2017:
|
|
Number
of
Shares
|
|
|
Weighted
Average
Exercise
Price
Per
Share
|
|
|
Weighted
Aggregate Average Remaining
Contract
Life in
Years
|
|
Outstanding
at April 1, 2016
|
|
|
153,600
|
|
|
$
|
6.52
|
|
|
|
6.36
|
|
Granted
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
Exercised
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
Forfeited
or Expired
|
|
|
(4,000
|
)
|
|
|
5.98
|
|
|
|
|
|
Outstanding
at March 31, 2017
|
|
|
149,600
|
|
|
$
|
6.54
|
|
|
|
5.34
|
|
Granted
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
Exercised
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
Forfeited
or Expired
|
|
|
(1,000
|
)
|
|
|
5.98
|
|
|
|
|
|
Outstanding
at March 31, 2018
|
|
|
148,600
|
|
|
$
|
6.54
|
|
|
|
4.34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested
at March 31, 2018
|
|
|
138,600
|
|
|
$
|
6.51
|
|
|
|
4.19
|
|
Exercisable
at March 31, 2018
|
|
|
138,600
|
|
|
$
|
6.51
|
|
|
|
4.19
|
|
Other
information pertaining to option activity was as follows during the year ended March 31:
|
|
2018
|
|
|
2017
|
|
Weighted average
grant-date fair value of stock options granted (per share)
|
|
$
|
-
|
|
|
$
|
-
|
|
Total
fair value of options vested
|
|
$
|
91,525
|
|
|
$
|
92,713
|
|
Total
intrinsic value of options exercised
|
|
$
|
-
|
|
|
$
|
-
|
|
The
following table summarizes information about options outstanding at March 31, 2018:
Range
of Exercise Prices
|
|
|
Number
of
Options
|
|
|
Weighted
Average
Exercise
Price
Per
Share
|
|
|
Weighted
Average Remaining
Contract
Life in
Years
|
|
|
$5.98
– 6.25
|
|
|
|
40,000
|
|
|
$
|
6.00
|
|
|
|
|
|
|
6.26
– 6.50
|
|
|
|
28,600
|
|
|
|
6.29
|
|
|
|
|
|
|
6.51
– 6.80
|
|
|
|
40,000
|
|
|
|
6.80
|
|
|
|
|
|
|
6.81
– 7.00
|
|
|
|
40,000
|
|
|
|
7.00
|
|
|
|
|
|
|
$
5.98
– 7.00
|
|
|
|
148,600
|
|
|
$
|
6.54
|
|
|
|
4.34
|
|
Outstanding
options at March 31, 2018 expire between August 2020 and August 2024 and have exercise prices ranging from $5.98 to $7.00.
13
.
Related Party Transactions
Related
party transactions for the Company relate to shared office expenditures in addition to administrative and operating expenses paid
on behalf of the principal stockholder. The total billed to and reimbursed by the stockholder for the years ended March 31, 2018
and 2017 were $40,432 and $35,263, respectively.
14.
Lease Commitments
The
Company leases its principal office space. On April 1, 2013, the Company agreed to a three year lease, with an option to renew
for an additional two years. In February 2016, the option to renew the lease for two years was exercised. The lease expired on
April 1, 2018. There is no further commitment under this lease.
Lease
expense was $23,440 for each of the fiscal years ended March 31, 2018 and 2017.
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, 2018 were based on evaluations prepared by Russell K. Hall and Associates, Inc. The
estimates as of March 31, 2017 were based on evaluations prepared by Joe C. Neal and Associates, Petroleum and Environmental Engineering
Consultants. 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 2018 and 2017. Commodity prices utilized for the reserve
estimates prior to adjustments for location, grade and quality are as follows:
|
|
March
31,
|
|
|
|
2018
|
|
|
2017
|
|
Prices
utilized in the reserve estimates before adjustments:
|
|
|
|
|
|
|
|
|
Oil
per Bbl
|
|
$
|
49.94
|
|
|
$
|
44.10
|
|
Natural
gas per MMBtu
|
|
$
|
3.00
|
|
|
$
|
2.74
|
|
The
Company’s total estimated proved reserves at March 31, 2018 were approximately 2.111 MBOE of which 57% was oil and natural
gas liquids and 43% was natural gas.
Changes
in Proved Reserves
:
|
|
Oil
(Bbls)
|
|
|
Natural
Gas
(Mcf)
|
|
Proved
Developed and Undeveloped Reserves:
|
|
|
|
|
|
|
|
|
As
of April 1, 2016
|
|
|
1,084,000
|
|
|
|
5,801,000
|
|
Revision
of previous estimates
|
|
|
205,000
|
|
|
|
946,000
|
|
Purchase
of minerals in place
|
|
|
-
|
|
|
|
-
|
|
Extensions
and discoveries
|
|
|
962,000
|
|
|
|
1,380,000
|
|
Sales
of minerals in place
|
|
|
(92,000
|
)
|
|
|
(1,090,000
|
)
|
Production
|
|
|
(35,000
|
)
|
|
|
(356,000
|
)
|
As
of March 31, 2017
|
|
|
2,124,000
|
|
|
|
6,681,000
|
|
Revision
of previous estimates
|
|
|
(850,000
|
)
|
|
|
(915,000
|
)
|
Purchase
of minerals in place
|
|
|
-
|
|
|
|
-
|
|
Extensions
and discoveries
|
|
|
110,000
|
|
|
|
191,000
|
|
Sales
of minerals in place
|
|
|
(152,000
|
)
|
|
|
(151,000
|
)
|
Production
|
|
|
(35,000
|
)
|
|
|
(319,000
|
)
|
As
of March 31, 2018
|
|
|
1,197,000
|
|
|
|
5,487,000
|
|
Proved
developed reserves are those expected to be recovered through existing wells, equipment and operating methods. Proved undeveloped
reserves (“PUD”) are proved reserves that are expected to be recovered from new wells on undrilled acreage or from
existing wells where a relatively major expenditure is required for recompletion within a five years of the date of their initial
recognition. Moreover, the Company may be required to write down its proved undeveloped reserves if the operators do not drill
on the reserves within the required five-year timeframe. The downward revision of oil and natural gas is primarily the result
of restructuring the plans for development of a non-producing leasehold interest in Martin County, Texas located in the Eastern
Permian Basin partially offset by pricing and successful development in the Delaware and Midland Basins. Reserves written off
due to the five year limitation are primarily in the Newark East field in Denton County, Texas which are on a lease held by production
and are still in place to be developed in the future.
Summary
of Proved Developed and Undeveloped Reserves as of March 31, 2018 and 2017
:
|
|
Oil
(Bbls)
|
|
|
Natural
Gas
(Mcf)
|
|
Proved Developed
Reserves:
|
|
|
|
|
|
|
As
of April 1, 2016
|
|
|
350,180
|
|
|
|
4,406,060
|
|
As
of March 31, 2017
|
|
|
399,880
|
|
|
|
4,107,950
|
|
As
of March 31, 2018
|
|
|
390,740
|
|
|
|
4,103,390
|
|
|
|
|
|
|
|
|
|
|
Proved
Undeveloped Reserves:
|
|
|
|
|
|
|
|
|
As
of April 1, 2016
|
|
|
734,170
|
|
|
|
1,395,220
|
|
As
of March 31, 2017
|
|
|
1,724,420
|
|
|
|
2,572,960
|
|
As
of March 31, 2018
|
|
|
805,980
|
|
|
|
1,383,120
|
|
At
March 31, 2018, the Company reported estimated PUDs of 1,037 MBOE, which accounted for 49% of its total estimated proved oil and
gas reserves. This figure primarily consists of a projected 102 new wells (937 MBOE), 4 of which the Company operates with reserves
of 205 MBOE, which will be drilled on existing acreage in the Goldsmith field where the Company currently operates 3 wells. The
Company projects these 4 operated wells will be drilled in fiscal 2019.
Regarding
the remaining 98 PUD locations operated by others (732 MBOE), 7 wells are currently being drilled with plans for 38 wells to follow
in 2019, 33 wells in 2020 and 24 wells in 2021. The cost of these projects would be funded, to the extent possible, from existing
cash balances and cash flow from operations. 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 2018.
Progress
of Converting Proved Undeveloped Reserves
:
|
|
Oil
& Natural Gas
|
|
|
Future
|
|
|
|
(BOE)
|
|
|
Development
Costs
|
|
PUDs,
beginning of year
|
|
|
2,153,248
|
|
|
$
|
28,809,230
|
|
Revision
of previous estimates
|
|
|
(998,890
|
)
|
|
|
(16,475,396
|
)
|
Sales
of reserves
|
|
|
(159,759
|
)
|
|
|
(2,043,502
|
)
|
Conversions
to PD reserves
|
|
|
(70,453
|
)
|
|
|
(445,406
|
)
|
Additional
PUDs added
|
|
|
112,357
|
|
|
|
2,164,405
|
|
PUDs,
end of year
|
|
|
1,036,503
|
|
|
$
|
12,009,331
|
|
Estimated
future net cash flows represent an estimate of future net revenues from the production of proved reserves using average prices
for 2018 and 2017 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 $12,009,331.
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 2018 were $50.63 per bbl of oil and
$3.031 per mcf of natural gas. The average prices used for fiscal 2017 were $43.88 per bbl of oil and $2.561 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, 2018 and 2017 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
|
|
|
|
2018
|
|
|
2017
|
|
Future
cash inflows
|
|
$
|
77,221,000
|
|
|
$
|
110,778,000
|
|
Future
production costs and taxes
|
|
|
(20,080,000
|
)
|
|
|
(27,267,000
|
)
|
Future
development costs
|
|
|
(12,009,000
|
)
|
|
|
(28,809,000
|
)
|
Future
income taxes
|
|
|
(6,413,000
|
)
|
|
|
(13,386,000
|
)
|
Future
net cash flows
|
|
|
38,719,000
|
|
|
|
41,316,000
|
|
Annual
10% discount for estimated timing of cash flows
|
|
|
(19,843,000
|
)
|
|
|
(22,233,000
|
)
|
Standardized
measure of discounted future net cash flows
|
|
$
|
18,876,000
|
|
|
$
|
19,083,000
|
|
Changes
in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves:
|
|
March
31
|
|
|
|
2018
|
|
|
2017
|
|
Sales
of oil and gas produced, net of production costs
|
|
$
|
(1,580,000
|
)
|
|
$
|
(1,459,000
|
)
|
Net
changes in price and production costs
|
|
|
6,967,000
|
|
|
|
1,849,000
|
|
Changes
in previously estimated development costs
|
|
|
16,196,000
|
|
|
|
970,000
|
|
Revisions
of quantity estimates
|
|
|
(23,969,000
|
)
|
|
|
(404,000
|
)
|
Net
change due to purchases and sales of minerals in place
|
|
|
(1,744,000
|
)
|
|
|
(2,380,000
|
)
|
Extensions
and discoveries, less related costs
|
|
|
1,240,000
|
|
|
|
6,994,000
|
|
Net
change in income taxes
|
|
|
3,057,000
|
|
|
|
(3,959,000
|
)
|
Accretion
of discount
|
|
|
2,527,000
|
|
|
|
1,612,000
|
|
Changes
in timing of estimated cash flows and other
|
|
|
(2,901,000
|
)
|
|
|
1,962,000
|
|
Changes
in standardized measure
|
|
|
(207,000
|
)
|
|
|
5,185,000
|
|
Standardized
measure, beginning of year
|
|
|
19,083,000
|
|
|
|
13,898,000
|
|
Standardized
measure, end of year
|
|
$
|
18,876,000
|
|
|
$
|
19,083,000
|
|
16
.
Subsequent Events
On
May 7, 2018, the Company agreed to a three year lease for its new principal office space located at 415 West Wall, Suite 475,
Midland, Texas 79701. The lease commences on May 15, 2018 and expires on May 31, 2021.