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 natural gas and crude oil 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, 2017 were approximately 3.238 million barrels of oil equivalent (“MMBOE”)
of which 66% was oil and natural gas liquids and 34% was natural gas, and our estimated present value of proved reserves was approximately
$25 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 2017, we added proved reserves of 1,192 thousand BOE
(“MBOE”) through extensions and discoveries, subtracted 274 MBOE through sales of oil and gas properties and had upward
revisions of previous estimates of 363 MBOE. Such revisions are the result of 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 2018.
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 2016, 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). Eight wells now producing oil on
20-acre spacing at approximately 3,600 foot depth on the 190 acres in Pecos County, TX. The operator has agreed to pay all operating
expenses of these interests. Mexco also receives 100% of the gross disposal fees paid by an adjacent operator for one disposal
well located on these properties
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 during fiscal 2016 continued in fiscal 2017. 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 2018 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 new 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 2017 operating results and potential impact on fiscal 2018 operating results due to depressed commodity prices.
Oil
and Gas Operations
As
of March 31, 2017, oil constituted approximately 66% of our total proved reserves and approximately 65% of our revenues for fiscal
2017. Revenues from oil and gas royalty interests accounted for approximately 27% of our revenues for fiscal 2017.
There
are two primary areas in which the Company is focused, 1) the Midland Basin located in the Eastern portion of the Permian Basin
including Reagan, Upton, Midland, Martin, Howard and Glasscock Counties, Texas and 2) the Delaware Basin located in the Western
portion of the Permian Basin including Lea and Eddy Counties, New Mexico and Loving County, Texas. The Permian Basin in total
accounts for 71% of our discounted future net cash flows from proved reserves and 55% of our net revenues.
The
Midland Basin properties, encompassing 83,074 gross acres, 283 net acres, 587 gross producing wells and 3 net wells account for
approximately 51% of our discounted future net cash flows from proved reserves as of March 31, 2017. Of these discounted future
net cash flows from proved reserves, approximately 44% are attributable to proven undeveloped reserves which will be developed
through new drilling. For fiscal 2017, these properties accounted for 23% of our gross revenues and 24% of our net revenues.
The
Delaware Basin properties, encompassing 31,718 gross acres, 624 net acres, 468 gross producing wells and 5 net wells account for
approximately 20% of our discounted future net cash flows from proved reserves as of March 31, 2017. Of these discounted future
net cash flows from proved reserves, approximately 5% are attributable to proven undeveloped reserves which will be developed
through new drilling. For fiscal 2017, these properties accounted for 28% of our gross revenues and 31% 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, 2017. For fiscal 2017,
these properties accounted for 3% of our gross revenues and 4% 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 6.4% of our discounted future net cash flows from proved reserves as of March
31, 2017. Of these discounted future net cash flows from proved reserves, 6% are attributable to proven undeveloped reserves which
will be developed through new drilling of 4 wells. For fiscal 2017, these properties consist of working interests and accounted
for 4% of our gross revenues and 2.6% 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 interests in and operate 5 producing wells. We divested 100% owned working interests in 8 producing wells and 1 injection
well located in Pecos County, Texas in November 2016 (see Oil and Natural Gas Property Transactions under Item 7 of this report
for further details). 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. 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)
|
|
2017
|
|
|
34,689
|
|
|
|
356,268
|
|
2016
|
|
|
38,930
|
|
|
|
407,939
|
|
2015
|
|
|
29,557
|
|
|
|
369,034
|
|
2014
|
|
|
27,186
|
|
|
|
361,652
|
|
2013
|
|
|
23,260
|
|
|
|
401,077
|
|
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 to the following companies that amounted to 10% or more of revenues for the year ended March 31:
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Enterprise
Crude Oil
|
|
|
19
|
%
|
|
|
1
|
%
|
|
|
0
|
%
|
Holly
Frontier Refining & Marketing LLC
|
|
|
12
|
%
|
|
|
14
|
%
|
|
|
17
|
%
|
Plains
Marketing LP
|
|
|
3
|
%
|
|
|
18
|
%
|
|
|
8
|
%
|
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.
Regulation
Our
exploration, development, production and marketing operations are subject to various types of extensive rules and regulations
by federal, state and local authorities. Numerous federal, state and local departments and agencies have issued rules and regulations
binding on the oil and gas industry, some of which carry substantial penalties for noncompliance. State statutes and regulations
require permits and bonds for drilling operations and reports concerning operations. Most states and some counties and municipalities
in which we operate regulate the location of wells; the method of drilling and casing wells; the rates of production or “allowables”;
the surface use and restoration of properties upon which wells are drilled; the plugging and abandoning of wells; and notice to,
and consultation with, surface owners and other third parties. The regulatory burden on the oil and gas industry increases its
cost of doing business and, consequently, affects its profitability. Because these rules and regulations are frequently amended
or reinterpreted, we are not able to predict the future cost or impact of complying with such laws.
The
Federal Energy Regulatory Commission (“FERC”) regulates under the Natural Gas Act of 1938 and the Natural Gas Policy
Act of 1978, interstate natural gas transportation rates and service conditions, which affect the marketing of natural gas we
produce, as well as the revenues we receive for sales of such production. Since 1978, various laws have been enacted which have
significantly altered the marketing and transportation of gas. These orders resulted in a fundamental restructuring of interstate
pipeline sales and transportation services, including the unbundling by interstate pipelines of the sales, transportation, storage
and other components of the city-gate sales, services such pipelines previously performed.
Commencing
in 1985, the FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the
business of transporting and marketing gas. Today, interstate pipeline companies are required to provide nondiscriminatory transportation
services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline
company. FERC’s initiatives have led to the development of a competitive, unregulated, open access market for gas purchases and
sales that permits all purchasers of gas to buy gas directly from third-party sellers other than pipelines. However, the natural
gas industry historically has been very heavily regulated. Therefore, we cannot guarantee that the less stringent regulatory approach
will continue indefinitely into the future, nor can we determine what effect, if any, future regulatory changes might have on
our natural gas related activities.
Sales
of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated market prices. Nevertheless,
Congress could reenact price controls in the future. The price we receive from the sale of these products is affected by the cost
of transporting the products to market. The FERC regulates interstate crude oil pipeline transportation rates under the Interstate
Commerce Act. In general, interstate crude oil pipeline rates must be cost-based, although many pipeline charges are today based
on historical rates adjusted for inflation and other factors, and other charges may result from settlement rates agreed to by
all shippers or market-based rates, which are permitted in certain circumstances. Intrastate crude oil pipeline transportation
rates are subject to regulation by state regulatory commissions. Insofar as the interstate and intrastate transportation rates
that we pay are generally applicable to all comparable shippers, we believe that the regulation of crude oil transportation rates
will not affect our operations in a way that materially differs from the effect on the operations of our competitors who are similarly
situated. Further, interstate and intrastate common carrier crude oil pipelines must provide service on an equitable basis. Under
this standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and
under the same rates. When crude oil pipelines operate at full capacity, access is governed by prorating provisions set forth
in the pipelines’ published tariffs. Accordingly, we believe that access to crude oil pipeline transportation services generally
will be available to us to the same extent as to our similarly situated competitors.
The
State of Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing
severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production
and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and
operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may
establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation,
or both.
States
do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will
not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced
from our wells and to limit the number of wells or locations we can drill. The petroleum industry is also subject to compliance
with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal
employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.
Environmental
Matters
By
nature of our oil and gas operations, we are subject to extensive federal, state and local environmental laws and regulations
controlling the generation, use, storage and discharge of materials into the environment or otherwise relating to the protection
of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws, which are
often difficult and costly to comply with and which carry substantial penalties for failure to comply. These laws and regulations
may require the acquisition of a permit before drilling or production commences; restrict the types, quantities and concentration
of various substances that can be released into the environment in connection with drilling and production activities; limit or
prohibit construction or drilling activities on certain lands lying within protected areas; restrict the rate of oil and gas production;
require remedial actions to prevent pollution from former operations; and impose substantial liabilities for pollution resulting
from our operations. In addition, these laws and regulations may impose substantial liabilities and penalties for failure to comply
with them or for any contamination resulting from our operations. We believe we are in compliance, in all material respects, with
applicable environmental requirements. We do not believe costs relating to these laws and regulations have had a material adverse
effect on our operations or financial condition in the past. Public interest in the protection of the environment has increased
dramatically in recent years.
The
trend of applying more expansive and stricter environmental legislation and regulations to the natural gas and oil industry could
continue, resulting in increased costs of doing business and consequently affecting our profitability. To the extent laws are
enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly waste handling, disposal
and cleanup requirements, our business and prospects could be adversely affected.
The
following are some of the existing laws, rules and regulations to which our business is subject:
The
Comprehensive Environmental Response, Compensation, and Liability Act
(“CERCLA”), also known as the “Superfund”
law, imposes liability, without regard to fault or the legality of the original conduct, on classes of persons that are considered
to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner
or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal
of the hazardous substances. Under CERCLA, such persons may be subject to joint and several liabilities for the costs of cleaning
up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of
certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for
personal injury and property damage allegedly caused by the hazardous substances released into the environment. We are able to
control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct
control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations
may, in certain circumstances, be attributed to us. We do not believe that we will be required to incur any material capital expenditures
to comply with existing environmental requirements.
The
federal
Clean Air Act
(“CAA”), and state air pollution laws and regulations provide a framework for national,
state and local efforts to protect air quality. The operations of oil and gas properties utilize equipment that emits air pollutants
which may be subject to federal and state air pollution control laws. These laws require utilization of air emissions abatement
equipment to achieve prescribed emissions limitations and ambient air quality standards, as well as operating permits for existing
equipment and construction permits for new and modified equipment. Permits and related compliance obligations under the CAA, as
well as changes to state implementation plans for controlling air emissions in regional non-attainment areas may require oil and
natural gas exploration and production operators to incur future capital expenditures in connection with the addition or modification
of existing air emission control equipment and strategies.
In
addition, some oil and natural gas facilities may be included within the categories of hazardous air pollutant sources, which
are subject to increasing regulation under the CAA. Failure to comply with these requirements could subject a regulated entity
to monetary penalties, injunctions, conditions or restrictions on operations and enforcement actions. On April 17, 2012, the EPA
issued a final rule that established new source performance standards for volatile organic compounds, or VOCs, and sulfur dioxide,
an air toxics standard for major sources of oil and natural gas production, and an air toxics standard for major sources of natural
gas transmission and storage. These regulations apply to natural gas wells that are hydraulically fractured, or refractured, and
to storage tanks and other equipment. Since January 1, 2015, all wells subject to the rule have been required to use “green
completion” technology to limit emissions during well completion operations.
Recent
scientific studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases (“GHGs”)
and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. These findings by the
EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under
existing provisions of the federal Clean Air Act. In September 2009, the EPA issued a GHG monitoring and reporting rule that requires
certain parties, including participants in the oil and natural gas industry, to monitor and report their GHG emissions, including
methane and carbon dioxide, to the EPA.
The
EPA’s finding, the GHG reporting rules, and the rules to regulate the emissions of GHGs may affect the outcome of other climate
change lawsuits pending in U.S. federal courts in a manner unfavorable to our industry. In addition to the EPA’s actions
to regulate GHGs, more than one-third of the states have begun taking action on their own to control and/or reduce emissions of
GHGs. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility.
Any of the climate change regulatory and legislative initiatives described above in areas in which we conduct business could result
in increased compliance costs or additional operating restrictions which could have a material adverse effect on our business,
financial condition, and results of operations.
The
Federal Water Pollution Control Act
(“Clean Water Act”) and analogous state laws impose restrictions and strict
controls with respect to the discharge of pollutants, including produced waters and other oil and gas wastes, into waters of the
United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit
issued by the EPA or the applicable state agency. Although the costs to comply with such mandates under state or federal law may
be significant, the entire industry will experience similar costs, and we do not believe that these costs will have a material
adverse impact on our financial condition and operations.
The
Resource Conservation and Recovery Act
(“RCRA”) and analogous state laws govern the handling and disposal of hazardous
and solid wastes. Wastes that are classified as hazardous under RCRA are subject to stringent handling, recordkeeping, disposal
and reporting requirements. RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced
waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy.”
However, these wastes may be regulated by the EPA or state agencies as solid waste. Moreover, many ordinary industrial wastes,
such as paint wastes, waste solvents, laboratory wastes and waste compressor oils, are regulated as hazardous wastes. Although
the costs of managing hazardous waste may be significant, we do not expect to experience more burdensome costs than similarly
situated companies.
The
Safe Drinking Water Act
(“SDWA”) and the
Underground Injection Control
(“UIC”) program promulgated
under the SDWA and state and local laws regulate the drilling and operation of salt water disposal (“SWD”) wells and
the underground injection of waste substances produced from oil and gas operations. Underground injection is the subsurface placement
of fluid through a well, such as the reinjection of brine produced and separated from oil and gas production. The EPA directly
administers the UIC program in some states and in others it is delegated to the state for administering. Permits must be obtained
before drilling SWD wells and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking saltwater
into groundwater. Contamination of groundwater by oil and natural gas drilling, production, and related operations may result
in fines, penalties, and remediation costs. In addition, third party claims may be filed by landowners and other parties claiming
damages for alternative water supplies, property damages, and bodily injury. We own partial interests in various underground injection
wells operated by others and failure to abide by their permits could subject us and those operators to civil and/or criminal enforcement
but we believe the other operators are in compliance in all material respects with the requirements of applicable state underground
injection control programs and permits.
Hydraulic
fracturing
is an important common practice that is used to stimulate production of hydrocarbons, particularly oil and natural
gas, from tight formations, including shales. This technology involves the injection of fluids—usually consisting mostly
of water but typically including small amounts of chemical additives—as well as sand into a well under high pressure in
order to create fractures in the rock that allow oil or gas to flow more freely to the wellbore. Many newer wells would not be
economical without the use of hydraulic fracturing to stimulate production from the well. We often participate as a non-operator
with operators who engage third parties to hydraulic fracturing or other well stimulation services. Hydraulic fracturing generally
is exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and
gas commissions.
For
example, the Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose the chemicals used
in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission has adopted rules and regulations
implementing this legislation that apply to all wells for which the Railroad Commission issues an initial drilling permit after
February 1, 2012. This law requires that the well operator disclose the list of chemical ingredients subject to the requirements
of the federal Occupational Safety and Health Act (OSHA) for disclosure on an internet website and also file the list of chemicals
with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a
well must also be disclosed to the public and filed with the Texas Railroad Commission.
There
has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on
drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally.
A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices.
If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult
or costly to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing
the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing
process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state
level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent
construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements
and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial
compliance costs, and compliance or the consequences of any failure to comply could have a material adverse effect on our financial
condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted
or potential federal or state legislation governing hydraulic fracturing.
We
believe that we are in compliance with all existing environmental laws and regulations applicable to our current operations and
that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and
results of operations, however we cannot assure you that the passage or application of more stringent laws or regulations in the
future will not have an negative impact on our financial position or results of operation. We did not incur any material capital
expenditures for remediation or pollution control activities for the year ended March 31, 2017. 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
2018.
Various
state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat,
migratory birds, wetlands, and natural resources. These statutes include the
Endangered Species Act
and the
Migratory
Bird Treaty Act
, as well as, the CWA and CERCLA. The United States Fish and Wildlife Service may designate critical habitat
and suitable habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat
or suitable habitat designation could result in further material restrictions to federal land use and private land use and could
delay or prohibit land access or development.
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, 2017.
Name
|
|
Age
|
|
Position
|
Nicholas
C. Taylor
|
|
79
|
|
Chairman
and Chief Executive Officer
|
Tamala
L. McComic
|
|
48
|
|
President,
Chief Financial Officer, Treasurer, and Assistant Secretary
|
Donna
Gail Yanko
|
|
72
|
|
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, 2017, 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
Our
principal offices are located at 214 W. Texas Avenue, Suite 1101, Midland, Texas 79701, and our telephone number is (432) 682-1119.
On April 1, 2013, we agreed to a three year lease, with an option to renew for an additional two years, for our 3,199 square feet
of office space which expired on April 1, 2016. On April 1, 2014, we agreed to a three year lease for an additional 340 square
feet of office space which expired on April 1, 2017. In February 2016, we exercised our option to renew the April 1, 2013 lease
extending its expiration to April 1, 2018. We believe our facilities are adequate for our current operations and that we can obtain
additional leased space if needed.
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
remain at their currently low levels or decline further, 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
2017 and 2015.
In
the past we have entered into price swap derivatives and may in the future enter into additional price swap derivatives for a
portion of our production, which may result in our making cash payments or prevent us from receiving the full benefit of increases
in prices for oil.
We
have used price swap derivatives to reduce price volatility associated with certain of our oil sales. Under these swap contracts,
we receive a fixed price per barrel of oil and pay a floating market price per barrel of oil to the counterparty based on NYMEX
WTI pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty.
Such contracts and any future swap arrangements may expose us to risk of financial loss in certain circumstances, including instances
where production is less than expected or oil prices increase. In addition, these arrangements may limit the benefit to us of
increases in the price of oil.
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
67% and 47% of our total estimated net proved reserves at March 31, 2017 and 2016, 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 2017, differentials averaged $0.22 per Bbl of oil and $0.18 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. If our cash flow from operations does not increase as a result of planned capital expenditures, a greater
percentage of our cash flow from operations will be required for debt service and operating expenses and our planned capital expenditures
would, by necessity, be decreased.
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. In addition, if the borrowing
base under the credit facility is reduced, we would be required to reduce our borrowings under the credit facility so that such
borrowings do not exceed the borrowing base. This could further reduce the cash available to us for capital spending and, if we
did not have sufficient capital to reduce our borrowing level, we may be in default under the credit facility.
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
$500,000 for the four fiscal quarters ending March 31, 2017 and $650,000 annually thereafter and minimum interest coverage ratios
(EBITDA/Interest Expense) of 2.00 to 1 for each quarter thereafter. 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.
Increases
in taxes on energy sources may adversely affect the company’s operations.
Federal,
state and local governments which have jurisdiction in areas where the company operates impose taxes on the oil and natural gas
products sold. Historically, there has been an on-going consideration by federal, state and local officials concerning a variety
of energy tax proposals. Such matters are beyond our ability to accurately predict or control.
Proposed
changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations
and cash flows.
In
past years, legislation 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 deductions currently available to oil and natural gas exploration
and production companies. Other changes include, but are not limited to: (1) the repeal of the percentage depletion allowance
for 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 domestic production activities, and (4) an extension of the amortization period for
certain geological and geophysical expenditures. The new President and certain members of Congress are calling for U.S. federal
tax reform, and Congress could consider, and could include, some or all of these proposals as part of tax reform legislation,
to accompany lower federal income tax rates. Moreover, other more general features of tax reform legislation, including changes
to cost recovery rules and to the deductibility of interest expense, may be developed that also would change the taxation of oil
and gas companies. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could
take effect. The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws
could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, or increase
costs, and any such changes 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. Competition for qualified individuals is intense and we may be unable to find or attract
qualified replacements for our officers and key employees on acceptable terms.
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, 2017, our executive officers and directors beneficially owned approximately 50% 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 MKT. 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 natural gas and oil 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, 2017, we had interests in approximately 6,000 gross (28 net) oil and gas wells and owned leasehold mineral and royalty
interests in approximately 573,000 gross (4,202 net) acres.
Oil
and Natural Gas Reserves
In
accordance with current SEC rules, the average prices used in computing reserves at March 31, 2017 were $43.88 per bbl of oil
and $41.76 in 2016, an increase of 5%, and $2.561 per mcf of natural gas and $1.998 in 2016, an increase of 28%, 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 2017. The benchmark price of $44.10 per bbl of oil at March 31, 2017 versus $42.77 at March 31, 2016,
was adjusted by lease for gravity, transportation fees and regional price differentials and did not give effect to derivative
transactions. The benchmark price of $2.74 per mcf of natural gas at March 31, 2017 versus $2.39 at March 31, 2016, was adjusted
by lease for BTU content, transportation fees and regional price differentials. The average prices used in computing reserves
at March 31, 2015 were $74.84 per bbl of oil and $3.595 per mcf of natural gas.
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, 2017, 2016 and 2015
is based on evaluations prepared by Joe C. Neal and Associates, Petroleum and Environmental Engineering Consultants, based in
Midland, Texas (“Neal and Associates”), a summary of which is filed as Exhibit 99.1 to this annual report.
Management
maintains internal controls designed to provide reasonable assurance that the estimates of proved reserves are computed and reported
in accordance with rules and regulations provided by the SEC. As stated above, Mexco retained Neal 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 Mr. Neal. Mr. Neal is responsible for overseeing the preparation of the reserve estimates and
holds a bachelor’s degree in mechanical engineering (petroleum option), is a member of the Society of Petroleum Engineers
and has over 50 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,
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Oil
(Bbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
developed – Producing
|
|
|
371,860
|
|
|
|
334,500
|
|
|
|
260,580
|
|
Proved
developed – Non-producing
|
|
|
28,030
|
|
|
|
15,680
|
|
|
|
23,080
|
|
Proved
undeveloped
|
|
|
1,724,420
|
|
|
|
734,170
|
|
|
|
376,070
|
|
Total
|
|
|
2,124,310
|
|
|
|
1,084,350
|
|
|
|
659,730
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (Mcf):
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
developed – Producing
|
|
|
3,817,490
|
|
|
|
3,356,660
|
|
|
|
3,470,970
|
|
Proved
developed – Non-producing
|
|
|
290,460
|
|
|
|
1,049,400
|
|
|
|
1,113,820
|
|
Proved
undeveloped
|
|
|
2,572,960
|
|
|
|
1,395,220
|
|
|
|
1,703,790
|
|
Total
|
|
|
6,680,910
|
|
|
|
5,801,280
|
|
|
|
6,288,580
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
net proved reserves (BOE)
|
|
|
3,237,795
|
|
|
|
2,051,230
|
|
|
|
1,707,827
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PV-10 Value
(1)
|
|
$
|
25,265,700
|
|
|
$
|
16,121,600
|
|
|
$
|
23,700,470
|
|
Present
value of future income tax discounted at 10%
|
|
|
(6,182,700
|
)
|
|
|
(2,223,600
|
)
|
|
|
(4,762,470
|
)
|
Standardized
measure of discounted future net cash flows (2)
|
|
$
|
19,083,000
|
|
|
$
|
13,898,000
|
|
|
$
|
18,938,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices
used in Calculating Reserves: (3)
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas (per Mcf)
|
|
$
|
2.561
|
|
|
$
|
1.998
|
|
|
$
|
3.595
|
|
Oil (per Bbl)
|
|
$
|
43.88
|
|
|
$
|
41.76
|
|
|
$
|
74.84
|
|
|
(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, 2017, 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, 2017, we participated in the development of 6 wells converting reserves of approximately 13,515
BOE from proved undeveloped to proved developed – producing with capital cost was approximately $284,000.
Oil
and gas prices significantly impact the calculation of the PV-10 and the standardized measure of discounted future net cash flows.
The present value of future net cash flows does not purport to be an estimate of the fair market value of the Company’s
proved reserves. An estimate of fair value would also take into account, among other things, anticipated changes in future prices
and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time
value of money and the risks inherent in producing oil and gas. Future prices received for production and costs may vary, perhaps
significantly, from the prices and costs assumed for purposes of these estimates. The 10% discount factor used to calculate present
value, which is required by Financial Accounting Standards Board (“FASB”) pronouncements, 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,
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
Development Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive - Horizontal
|
|
|
17
|
|
|
|
.11
|
|
|
|
14
|
|
|
|
.09
|
|
|
|
28
|
|
|
|
.21
|
|
Productive - Vertical
|
|
|
4
|
|
|
|
.02
|
|
|
|
1
|
|
|
|
-
|
|
|
|
28
|
|
|
|
.05
|
|
Nonproductive - Vertical
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
|
|
.17
|
|
Total
|
|
|
21
|
|
|
|
.13
|
|
|
|
15
|
|
|
|
.09
|
|
|
|
57
|
|
|
|
.43
|
|
We
have not participated in any exploratory wells during the years ended March 31, 2017, 2016 and 2015. 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, 2017, we held an interest in approximately
6,000 gross (28 net) productive wells, including approximately 4,700 wells in which we held an overriding or royalty interest
and 1,300 wells in which we held a working interest. Mexco operates 5 of its working interest productive 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, 2017:
|
|
Developed Acres
|
|
|
|
Gross
|
|
|
Net
|
|
Texas
|
|
|
344,200
|
|
|
|
2,106
|
|
Oklahoma
|
|
|
97,400
|
|
|
|
1,449
|
|
New Mexico
|
|
|
32,200
|
|
|
|
517
|
|
Louisiana
|
|
|
42,300
|
|
|
|
41
|
|
North Dakota
|
|
|
30,600
|
|
|
|
43
|
|
Kansas
|
|
|
9,700
|
|
|
|
24
|
|
Montana
|
|
|
7,800
|
|
|
|
5
|
|
Wyoming
|
|
|
3,900
|
|
|
|
5
|
|
Arkansas
|
|
|
1,000
|
|
|
|
5
|
|
Mississippi
|
|
|
1,600
|
|
|
|
3
|
|
Alabama
|
|
|
600
|
|
|
|
2
|
|
Colorado
|
|
|
1,100
|
|
|
|
1
|
|
Virginia
|
|
|
100
|
|
|
|
1
|
|
Total
|
|
|
572,500
|
|
|
|
4,202
|
|
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,
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Oil (a):
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (Bbls)
|
|
|
34,689
|
|
|
|
38,930
|
|
|
|
29,557
|
|
Revenue
|
|
$
|
1,517,606
|
|
|
$
|
1,598,725
|
|
|
$
|
2,069,806
|
|
Average Bbls per day (e)
|
|
|
95
|
|
|
|
107
|
|
|
|
81
|
|
Average sales price per Bbl (b)
|
|
$
|
43.75
|
|
|
$
|
41.07
|
|
|
$
|
70.03
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (c):
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (Mcf)
|
|
|
356,268
|
|
|
|
407,939
|
|
|
|
369,034
|
|
Revenue
|
|
$
|
819,616
|
|
|
$
|
785,225
|
|
|
$
|
1,267,020
|
|
Average Mcf per day (e)
|
|
|
976
|
|
|
|
1,118
|
|
|
|
1,011
|
|
Average sales price per Mcf
|
|
$
|
2.30
|
|
|
$
|
1.92
|
|
|
$
|
3.43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
Production cost
|
|
$
|
717,757
|
|
|
$
|
944,933
|
|
|
$
|
1,024,130
|
|
Production and ad valorem taxes
|
|
$
|
160,701
|
|
|
$
|
199,128
|
|
|
$
|
276,690
|
|
Total BOE (d)
|
|
|
94,067
|
|
|
|
106,920
|
|
|
|
91,063
|
|
Production cost per BOE
|
|
$
|
7.63
|
|
|
$
|
8.84
|
|
|
$
|
11.25
|
|
Production cost per sales dollar
|
|
$
|
0.31
|
|
|
$
|
0.40
|
|
|
$
|
0.31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas revenue
|
|
$
|
2,337,222
|
|
|
$
|
2,383,950
|
|
|
$
|
3,336,826
|
|
|
(a)
|
Includes
condensate.
|
|
(b)
|
We
did not have a price swap agreement on our oil production for the years ended March 31, 2017 and 2016.After giving
effect to our derivative instruments, the average sales price per Bbl of oil was $73.48 for year ended March 31, 2015.
|
|
(c)
|
Includes
natural gas products.
|
|
(d)
|
Natural
gas production is converted to oil production using a ratio of six Mcf to one Bbl of oil.
|
|
(e)
|
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 27, 2017
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been signed below as of June 27, 2017, 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.
Bcf
.
One billion cubic feet of natural gas at standard atmospheric conditions.
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.
Mcfe.
One thousand cubic feet equivalent of natural gas, calculated by converting oil to equivalent Mcf at a ratio of 6 Mcf for
each Bbl of oil.
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.
Pay
zone.
A geological deposit in which oil and natural gas is found in commercial quantities.
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.
Re-entry.
Entering an existing well bore to recomplete or repair.
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, 2017, 2016 and 2015
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 predominately all of the Company oil
and gas interests are operated by others, the Company operates five 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, management is required to make informed judgments, estimates and assumptions that affect the reported amounts
of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses
during the reporting period. In addition, significant estimates are used in determining year end proved oil and gas reserves.
Although management believes its estimates and assumptions are reasonable, actual results may differ materially from those estimates.
The estimate of 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, 2017, 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 collectability 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 ending March 31, 2017, 2016 and 2015, 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 basically 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 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.
Derivatives.
The Company is required to recognize its derivative instruments on the consolidated balance sheets as assets or liabilities
at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting
for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company
has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments
to fair value and recognizes the realized and unrealized change in fair value on derivative instruments in the Consolidated Statements
of Operations.
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 financial statements over the vesting period. The Company
recognizes the fair value of stock-based compensation awards as wages in the Consolidated Statements of Operations based on a
graded-vesting schedule over the vesting period.
Recent
Accounting Pronouncements.
In August 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting
Standards Update No. 2016-15, “Statement of Cash Flows (Topic 230)”, which is intended to reduce diversity in practice
in how certain transactions are classified in the statement of cash flows. The guidance addresses eight specific cash flow issues
for which current GAAP is either unclear or does not include specific guidance. The guidance is effective for annual periods beginning
after December 15, 2017 and interim periods within those annual periods. Early adoption is permitted, provided that all of the
amendments are adopted in the same period. This guidance must be adopted using a retrospective transition method. The Company
is currently evaluating the effect that adopting this guidance will have on its cash flows.
In
March 2016, the FASB issued ASU No. 2016-09, “Compensation – Stock Compensation (Topic 718): Improvements to Employee
Share-Based Payment Accounting”. The amendment is to simplify several aspects of the accounting for share-based payment
transactions including the income tax consequences, classification of awards as either equity or liabilities, and classification
on the statement of cash flows. The amendments in ASU No. 2016-09 are effective for interim and annual reporting periods beginning
after December 15, 2016. The Company is currently assessing the impact of ASU No. 2016-09 on the consolidated financial statements.
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. Our only lease agreement is for our office space so we believe this guidance will have just a minimum
impact to our consolidated balance sheet due to the recognition of lease-related assets and liabilities that were not previously
recognized.
In
January 2016, the FASB issued ASU 2016-01, “Financial Instruments – Overall”, an authoritative guidance that
amends existing requirements on the classification and measurement of financial instruments. The standard principally affects
accounting for equity investments and financial liabilities where the fair value option has been elected. The guidance is effective
for fiscal periods after December 15, 2017, and interim periods thereafter. Early adoption of certain provisions is permitted.
We are currently evaluating the effect the new guidance will have on our financial statements.
In
May 2014, the FASB issued ASU No. 2014-09, Topic 606: Revenue from Contracts with Customers. This ASU outlines a new, single comprehensive
model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue
recognition guidance, including industry-specific guidance. This new model provides a five-step analysis in determining when and
how revenue is recognized. The new model will require recognition to depict the transfer of promised goods or services to customers
in an amount that reflects the consideration a company expects to receive in exchange for those goods or services. In August 2015,
the effective date for ASU 2014-09 was delayed through the issuance of ASU 2015-14, Revenue from Contracts with Customers –
Deferral of the Effective Date, to annual and interim periods beginning after December 15, 2017. Management is currently reviewing
its primary oil and natural gas marketing agreements in order to assess the impact of adoption. At this time, adopting this standard
is not expected to have a material impact on our financial statements because recognition of revenue is not expected to materially
change under the new standard, since most of our revenue will continue to be recognized as production is delivered. However, management
is still evaluating the ultimate impact of this accounting standard on its consolidated results of operations, financial position,
cash flows and financial disclosures. This evaluation will continue throughout fiscal 2018, and we are currently planning to adopt
this new standard April 1, 2018. Entities have the option of using either a full retrospective or modified approach to adopt ASU
2014-09 and we have not yet determined which method of adoption we will apply for this new standard.
Liquidity
and Capital Resources.
Historically, we have funded our operations, acquisitions, exploration and development expenditures
from cash generated by operating activities, bank borrowings and issuance of common stock. Due to a depressed commodity
price environment, we are applying financial discipline to all aspects of our business. In order to meet obligations, we
will continue to sell non-core assets, if necessary. 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.
Fair
value as defined by authoritative literature is the price that would be received to sell an asset or paid to transfer a liability
(exit price) in an orderly transaction between market participants at the measurement date. Fair value measurements are classified
and disclosed in one of the following categories:
|
Level
1 – Quoted prices in active markets for identical assets and liabilities.
|
|
|
|
Level 2 –
Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in
markets that are not active and model-derived valuations whose inputs are observable or whose significant value drivers are
observable.
|
|
|
|
Level 3 –
Significant inputs to the valuation model are unobservable.
|
Financial
assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.
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
and is deemed to use Level 2 inputs. See the Company’s Note 4 on Credit Facility for further discussion.
4.
Credit Facility
The
Company has a loan agreement with Bank of America, NA (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 30, 2017 and set at $3,120,000. 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 Bank states otherwise. As of March 31, 2017, the borrowing base was set at $2,950,000.
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 3.983% on March
31, 2017. Interest on the outstanding amount under the credit agreement is payable monthly. There was no availability of this
line of credit at March 31, 2017. 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 $500,000 for the
four fiscal quarters ending March 31, 2017 and $650,000 for each trailing fiscal year period and minimum interest coverage
ratios (EBITDA/Interest Expense) of 2.00 to 1.00 for each quarter thereafter. The Company is in compliance with all covenants
as of March 31, 2017
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, 2017,
one letter of credit for $50,000, in lieu of a plugging bond with the Texas Railroad Commission (“TRRC”) covering
the properties the Company operates is outstanding under the facility. This letter of credit 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, 2017 was $2,900,000 and as of June 23, 2017 was $2,475,500. The following
table is a summary of activity on the Bank of America, N.A. line of credit for the year ended March 31, 2017:
|
|
Principal
|
|
Balance at April 1, 2016:
|
|
$
|
5,580,000
|
|
Borrowings
|
|
|
-
|
|
Repayments
|
|
|
(2,680,000
|
)
|
Balance at March 31, 2017:
|
|
$
|
2,900,000
|
|
5.
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:
|
|
2017
|
|
|
2016
|
|
Carrying amount of asset retirement obligations as of April 1
|
|
$
|
1,221,077
|
|
|
$
|
1,240,216
|
|
Liabilities incurred
|
|
|
8,753
|
|
|
|
5,844
|
|
Liabilities settled
|
|
|
(287,089
|
)
|
|
|
(60,138
|
)
|
Accretion expense
|
|
|
35,743
|
|
|
|
35,155
|
|
Carrying amount of asset retirement obligations as of March 31
|
|
|
978,484
|
|
|
|
1,221,077
|
|
Less: Current portion
|
|
|
10,000
|
|
|
|
10,000
|
|
Non-Current asset retirement obligation
|
|
$
|
968,484
|
|
|
$
|
1,211,077
|
|
6.
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 2014.
Significant
components of net deferred tax assets (liabilities) at March 31 are as follows:
|
|
2017
|
|
|
2016
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Percentage depletion carryforwards
|
|
$
|
1,786,522
|
|
|
$
|
1,718,721
|
|
Deferred stock-based compensation
|
|
|
52,654
|
|
|
|
49,090
|
|
Asset retirement obligation
|
|
|
332,685
|
|
|
|
415,166
|
|
Net operating loss
|
|
|
1,012,138
|
|
|
|
1,493,914
|
|
Other
|
|
|
7,170
|
|
|
|
6,413
|
|
|
|
|
3,191,169
|
|
|
|
3,683,304
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Excess financial accounting bases over tax bases of property and equipment
|
|
|
2,052,749
|
|
|
|
2,834,340
|
|
|
|
|
|
|
|
|
|
|
Deferred tax asset
|
|
$
|
1,138,420
|
|
|
$
|
848,964
|
|
|
|
|
|
|
|
|
|
|
Valuation allowance
|
|
|
(1,138,420
|
)
|
|
|
(848,964
|
)
|
Net deferred tax liability
|
|
$
|
-
|
|
|
$
|
-
|
|
As
of March 31, 2017, the Company has a statutory depletion carryforward of approximately $5,250,000, which does not expire. At March
31, 2017, the Company had a net operating loss carryforward for regular income tax reporting purposes of approximately $5,200,000,
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.
The
income tax provision consists of the following for years ended March 31, 2017, 2016 and 2015:
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Current income tax expense
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
Deferred income tax benefit
|
|
|
-
|
|
|
|
(660,870
|
)
|
|
|
(197,499
|
)
|
Total income tax provision:
|
|
$
|
-
|
|
|
$
|
(660,870
|
)
|
|
$
|
(197,499
|
)
|
Effective tax rate
|
|
|
-
|
|
|
|
(14
|
%)
|
|
|
(37
|
%)
|
A
reconciliation of the provision for income taxes to income taxes computed using the federal statutory rate for years ended March
31 follows:
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Tax expense at federal statutory rate (1)
|
|
$
|
(236,148
|
)
|
|
$
|
(1,577,789
|
)
|
|
$
|
(183,085
|
)
|
Statutory depletion carryforward
|
|
|
(67,801
|
)
|
|
|
(35,034
|
)
|
|
|
(71,292
|
)
|
Change in valuation allowance
|
|
|
289,456
|
|
|
|
848,964
|
|
|
|
-
|
|
Effect of rate change
|
|
|
-
|
|
|
|
64,585
|
|
|
|
12,221
|
|
Permanent differences
|
|
|
14,497
|
|
|
|
31,904
|
|
|
|
44,657
|
|
Other
|
|
|
(4)
|
|
|
|
6,500
|
|
|
|
-
|
|
Total income tax benefit
|
|
$
|
-
|
|
|
$
|
(660,870
|
)
|
|
$
|
(197,499
|
)
|
Effective income tax rate
|
|
|
-
|
|
|
|
(14
|
%)
|
|
|
(37
|
%)
|
|
(1)
|
The federal statutory rate was 34% for fiscal years
ending March 31, 2017, 2016 and 2015.
|
For
the years ended March 31, 2017, 2016 and 2015, the Company did not have any uncertain tax positions.
A
reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows:
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Unrecognized tax benefits at beginning of period
|
|
$
|
679,000
|
|
|
$
|
679,000
|
|
|
$
|
679,000
|
|
Additions based on tax positions related to the current year
|
|
|
66,000
|
|
|
|
-
|
|
|
|
-
|
|
Changes to tax positions of prior years
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Settlements
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Expirations
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Unrecognized tax benefits at end of period
|
|
$
|
745,000
|
|
|
$
|
679,000
|
|
|
$
|
679,000
|
|
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 at year end. 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. A significant piece of objective negative evidence evaluated
was the cumulative loss incurred over the three-year period ending March 31, 2017. Such objective negative evidence limits the
ability to consider other subjective positive evidence, such as our projections for future growth. The amount of the deferred
tax asset considered realizable, however, could be adjusted if estimates of future taxable income are reduced or 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.
7.
Derivatives
The
Company has used price swap contracts to reduce price volatility associated with certain of its oil sales. With respect to the
Company’s fixed price swap contracts, the counterparty is required to make a payment to the Company if the settlement price
for any settlement period is less than the swap price, and the Company is required to make a payment to the counterparty if the
settlement price for any settlement period is greater than the swap price. The Company’s derivative contracts are based
upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange
West Texas Intermediate (“NYMEX WTI”) pricing.
All
derivative financial instruments are recorded at fair value. The Company has not designated its derivative instruments as hedges
for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the realized and unrealized
changes in fair value in the consolidated statements of operations under the caption “Gain (loss) on derivative instruments.”
The following summarizes the gain on derivative instruments included in the consolidated statements of operations for the
years ended March 31, 2017, 2016 and 2015:
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Unrealized loss on open non-hedge derivative instruments
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
Gain on settlement of non-hedge derivative instruments
|
|
|
-
|
|
|
|
-
|
|
|
|
102,069
|
|
Total gain on derivative instruments
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
102,069
|
|
As
of March 31, 2017 the Company does not have any open crude oil derivative positions with respect to future production.
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 2017, one customer accounted for 19% of the total oil and gas revenues and 15% of the total oil and gas accounts receivable.
In fiscal 2016, one customer accounted for 18% of the total oil and gas revenues and 14% of the total oil and gas accounts receivable
and another customer accounted for 14% of the total oil and gas revenues and 18% of the total oil and gas accounts receivable.
In fiscal 2015, one customer accounted for 17% of the total oil and gas revenues and 19% 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:
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
3,108,040
|
|
Unproved
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Exploration
|
|
|
-
|
|
|
|
-
|
|
|
|
15,472
|
|
Development
|
|
|
731,400
|
|
|
|
1,112,733
|
|
|
|
1,746,582
|
|
Capitalized asset retirement obligations
|
|
|
8,753
|
|
|
|
5,844
|
|
|
|
274,148
|
|
Total costs incurred for oil and gas properties
|
|
$
|
740,153
|
|
|
$
|
1,118,577
|
|
|
$
|
5,144,242
|
|
The
Company had the following aggregate capitalized costs relating to its oil and gas property activities at March 31:
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Proved oil and gas properties
|
|
$
|
37,640,096
|
|
|
$
|
40,365,197
|
|
|
$
|
40,489,453
|
|
Unproved oil and gas properties:
|
|
|
|
|
|
|
|
|
|
|
|
|
subject to amortization
|
|
|
-
|
|
|
|
-
|
|
|
|
73,990
|
|
not subject to amortization
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
37,640,096
|
|
|
|
40,365,197
|
|
|
|
40,563,443
|
|
Less accumulated DD&A
|
|
|
25,479,335
|
|
|
|
24,306,770
|
|
|
|
19,752,994
|
|
|
|
$
|
12,160,761
|
|
|
$
|
16,058,427
|
|
|
$
|
20,810,449
|
|
DD&A
amounted to $12.47, $14.68 and $14.91 per BOE of production for the years ended March 31, 2017, 2016 and
2015, respectively.
10.
Loss Per Common Share
Due
to a net loss for the years ended March 31, 2017, 2016 and 2015, 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 periods ended March 31:
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Net loss
|
|
$
|
(694,553
|
)
|
|
$
|
(3,979,685
|
)
|
|
$
|
(340,986
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted avg. common shares outstanding – basic
|
|
|
2,037,266
|
|
|
|
2,037,266
|
|
|
|
2,038,250
|
|
Effect of the assumed exercise of dilutive stock options
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Weighted avg. common shares outstanding – dilutive
|
|
|
2,037,266
|
|
|
|
2,037,266
|
|
|
|
2,038,250
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(0.34
|
)
|
|
$
|
(1.95
|
)
|
|
$
|
(0.17
|
)
|
Diluted
|
|
$
|
(0.34
|
)
|
|
$
|
(1.95
|
)
|
|
$
|
(0.17
|
)
|
11.
Stockholders’ Equity
In
September 2016, 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 2017 and
2016. During the fiscal year ended March 31, 2015, the Company repurchased 1,000 shares for the treasury at an aggregate cost
of $5,009.
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 2017, 2016 and 2015.
The
Company recognized compensation expense of $52,864, $116,953 and $153,386 in general and administrative expense in the Consolidated
Statements of Operations for fiscal 2017, 2016 and 2015, respectively. The total cost related to non-vested awards not yet recognized
at March 31, 2017 totals $25,420, which is expected to be recognized over a weighted average of 1.04 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, 2017 and 2016, no stock options were granted. During the year ended March 31, 2015, the Compensation
Committee of the Board of Directors approved and the Company granted 40,000 stock options to officers and employees of the Company
exercisable at $7.00 per share. These options are exercisable at a price not less than the fair market value of the stock at the
date of grant, have an exercise period of ten years and generally vest over four years.
Included
in the following table is a summary of the grant-date fair value of stock options granted and the related assumptions used in
the Binomial models for stock options granted in fiscal 2017, 2016 and 2015. All such amounts represent the weighted average amounts
for each period.
|
|
For the year ended March 31,
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Grant-date fair value
|
|
|
-
|
|
|
|
-
|
|
|
$
|
5.59
|
|
Volatility factor
|
|
|
-
|
|
|
|
-
|
|
|
|
76.23
|
%
|
Dividend yield
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Risk-free interest rate
|
|
|
-
|
|
|
|
-
|
|
|
|
2.52
|
%
|
Expected term (in years)
|
|
|
-
|
|
|
|
-
|
|
|
|
10
|
|
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, 2017, 3,000 vested stock options expired because there were not exercised prior to
the end of their ten-year term and 1,000 unvested stock options were forfeited due to the resignation of an employee. There were
no stock options forfeited or expired during the years ended March 31, 2016 and 2015.
The
following table is a summary of activity of stock options for the year ended March 31, 2017, 2016 and 2015:
|
|
Number of Shares
|
|
|
Weighted Average Exercise Price Per Share
|
|
|
Weighted Aggregate Average Remaining Contract Life in Years
|
|
|
Intrinsic Value
|
|
Outstanding at April 1, 2014
|
|
|
113,600
|
|
|
$
|
6.35
|
|
|
|
7.66
|
|
|
$
|
154,062
|
|
Granted
|
|
|
40,000
|
|
|
|
7.00
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
Forfeited or Expired
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
Outstanding at March 31, 2015
|
|
|
153,600
|
|
|
$
|
6.52
|
|
|
|
7.36
|
|
|
$
|
-
|
|
Granted
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
Forfeited or Expired
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
Outstanding at March 31, 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
|
|
|
$
|
-
|
|
Vested at March 31, 2017
|
|
|
121,850
|
|
|
$
|
6.50
|
|
|
|
4.97
|
|
|
$
|
-
|
|
Exercisable at March 31, 2017
|
|
|
121,850
|
|
|
$
|
6.50
|
|
|
|
4.97
|
|
|
$
|
-
|
|
Other
information pertaining to option activity was as follows during the year ended March 31:
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Weighted average grant-date fair value of stock
options granted (per share)
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
5.59
|
|
Total fair value of options vested
|
|
$
|
92,713
|
|
|
$
|
154,338
|
|
|
$
|
150,063
|
|
Total intrinsic value of options exercised
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
-
|
|
The
following table summarizes information about options outstanding at March 31, 2017:
Range of Exercise Prices
|
|
Number of Options
|
|
|
Weighted Average Exercise Price Per Share
|
|
|
Weighted Average Remaining Contract Life in Years
|
|
|
Aggregate Intrinsic Value
|
|
$ 5.98 – 6.25
|
|
|
41,000
|
|
|
$
|
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
|
|
|
149,600
|
|
|
$
|
6.54
|
|
|
|
5.34
|
|
|
$
|
-
|
|
Outstanding
options at March 31, 2017 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 fiscal year ended March 31, 2017 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, 2017, 2016 and 2015 were $35,263, $92,723 and $125,209, 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. On April 1, 2014, the Company agreed to a three year lease for an additional office space. In February
2016, the Company exercised its option to renew the 2013 lease. The 2014 lease expired on April 1, 2017. The following table summarizes
future payments the Company is obligated to make based on the lease commitments in place as of March 31, 2017:
|
|
Commitment Amount (1)
|
|
Fiscal Year 2018
|
|
$
|
19,020
|
|
|
(1)
|
The
total commitment for the remainder of the leases is $28,260 which includes $9,240 billed to and reimbursed by the Company’s
principal shareholder for his portion of the shared office space.
|
Lease
expense for fiscal years ended March 31, 2017, 2016 and 2015 was $23,440, $23,438 and $23,442, respectively.
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 guidelines established by the SEC. The estimates as of March 31, 2017, 2016, and 2015 are based on evaluations
prepared by Joe C. Neal and Associates, Petroleum and Environmental Engineering Consultants. Management emphasizes that reserve
estimates are inherently imprecise and are expected to change as new information becomes available and as economic conditions
in the industry change.
Proved
reserves are 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.
The
Company’s total estimated proved reserves at March 31, 2017 were approximately 3.238 MBOE of which 66% was oil and natural
gas liquids and 34% was natural gas.
Changes
in Proved Reserves
:
|
|
Oil
(Bbls)
|
|
|
Natural Gas
(Mcf)
|
|
Proved Developed and Undeveloped Reserves:
|
|
|
|
|
|
|
|
|
As of April 1, 2014
|
|
|
502,000
|
|
|
|
6,259,000
|
|
Revision of previous estimates
|
|
|
(90,000
|
)
|
|
|
(665,000
|
)
|
Purchase of minerals in place
|
|
|
43,000
|
|
|
|
795,000
|
|
Extensions and discoveries
|
|
|
235,000
|
|
|
|
269,000
|
|
Sales of minerals in place
|
|
|
-
|
|
|
|
-
|
|
Production
|
|
|
(30,000
|
)
|
|
|
(369,000
|
)
|
As of March 31, 2015
|
|
|
660,000
|
|
|
|
6,289,000
|
|
Revision of previous estimates
|
|
|
(13,000
|
)
|
|
|
(736,000
|
)
|
Purchase of minerals in place
|
|
|
-
|
|
|
|
-
|
|
Extensions and discoveries
|
|
|
479,000
|
|
|
|
665,000
|
|
Sales of minerals in place
|
|
|
(3,000
|
)
|
|
|
(9,000
|
)
|
Production
|
|
|
(39,000
|
)
|
|
|
(408,000
|
)
|
As of March 31, 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
|
|
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. The upward revision of oil and natural gas is
primarily the result of pricing and successful development in the Delaware and Midland Basins. Reserves written off due to the
five year limitation are primarily in the Cotton Valley Sand field in Limestone and Freestone Counties, Texas which are on leases
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, 2017, 2016 and 2015
:
|
|
Oil
(Bbls)
|
|
|
Natural Gas
(Mcf)
|
|
Proved Developed Reserves:
|
|
|
|
|
|
|
|
|
As of April 1, 2014
|
|
|
294,620
|
|
|
|
4,081,470
|
|
As of March 31, 2015
|
|
|
283,670
|
|
|
|
4,584,790
|
|
As of March 31, 2016
|
|
|
350,180
|
|
|
|
4,406,060
|
|
As of March 31, 2017
|
|
|
399,880
|
|
|
|
4,107,950
|
|
|
|
|
|
|
|
|
|
|
Proved Undeveloped Reserves:
|
|
|
|
|
|
|
|
|
As of April 1, 2014
|
|
|
206,930
|
|
|
|
2,177,810
|
|
As of March 31, 2015
|
|
|
376,070
|
|
|
|
1,703,790
|
|
As of March 31, 2016
|
|
|
734,170
|
|
|
|
1,395,220
|
|
As of March 31, 2017
|
|
|
1,724,420
|
|
|
|
2,572,960
|
|
At
March 31, 2017, the Company reported estimated PUDs of 2,153 MBOE, which accounted for 67% of its total estimated proved oil and
gas reserves. This figure primarily consists of a projected 72 new wells (1,655 MBOE), 6 of which the Company operates with reserves
of 1,234 MBOE. Four of the wells the Company operates (202 MBOE), 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. The remaining
2 wells the Company operates are in the Midland Basin on acreage held by production. We project these 2 wells to be drilled in
2020.
Regarding
the remaining 66 PUD locations operated by others (421 BOE), 3 wells are currently being drilled with plans for 22 wells to follow
in 2018, 20 wells in 2019, 19 wells in 2020 and 2 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.
As
of March 31, 2017, 2016 and 2015 reserves were computed using the 12-month unweighted average of the first-day-of-the-month prices,
in accordance with current SEC rules.
The
following table discloses the Company’s progress toward the conversion of PUDs during fiscal 2017.
Progress
of Converting Proved Undeveloped Reserves
:
|
|
Oil & Natural Gas
|
|
|
Future
|
|
|
|
(BOE)
|
|
|
Development Costs
|
|
PUDs, beginning of year
|
|
|
966,707
|
|
|
$
|
9,617,160
|
|
Revision of previous estimates
|
|
|
122,762
|
|
|
|
1,467,427
|
|
Sales of reserves
|
|
|
(82,318
|
)
|
|
|
(228,586
|
)
|
Conversions to PD reserves
|
|
|
(13,515
|
)
|
|
|
(284,067
|
)
|
Additional PUDs added
|
|
|
1,159,612
|
|
|
|
18,237,296
|
|
PUDs, end of year
|
|
|
2,153,248
|
|
|
$
|
28,809,230
|
|
Estimated
future net cash flows represent an estimate of future net revenues from the production of proved reserves using average prices
for 2017, 2016 and 2015 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, 2022 are $28,809,230.
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 2017 were $43.88 per bbl of oil and
$2.561 per mcf of natural gas. The average prices used for fiscal 2016 were $41.76 per bbl of oil and $1.998 per mcf of natural
gas. The average prices used for fiscal 2015 were $74.84 per bbl of oil and $3.595 per mcf of natural gas.
The
standardized measure of discounted future net cash flows were computed by applying 12-month average prices for oil and gas (with
consideration of price changes only to the extent provided by contractual arrangements in existence at year end) 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 the 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. The estimated future net cash flows
are then discounted using a rate of 10%.
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
standardized measure of discounted future cash flows at March 31, 2017, 2016 and 2015, which represents the present value of estimated
future cash flows using a discount rate of 10% a year, follows:
Standardized
Measure of Discounted Future Net Cash Flows Relating to Proved Reserves:
|
|
March 31
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Future cash inflows
|
|
$
|
110,778,000
|
|
|
$
|
57,318,000
|
|
|
$
|
72,238,000
|
|
Future production costs and taxes
|
|
|
(27,267,000
|
)
|
|
|
(14,571,000
|
)
|
|
|
(19,569,000
|
)
|
Future development costs
|
|
|
(28,809,000
|
)
|
|
|
(9,617,000
|
)
|
|
|
(6,617,000
|
)
|
Future income taxes
|
|
|
(13,386,000
|
)
|
|
|
(4,569,000
|
)
|
|
|
(9,254,000
|
)
|
Future net cash flows
|
|
|
41,316,000
|
|
|
|
28,561,000
|
|
|
|
36,798,000
|
|
Annual 10% discount for estimated timing of cash flows
|
|
|
(22,233,000
|
)
|
|
|
(14,663,000
|
)
|
|
|
(17,860,000
|
)
|
Standardized measure of discounted future net cash flows
|
|
$
|
19,083,000
|
|
|
$
|
13,898,000
|
|
|
$
|
18,938,000
|
|
Changes
in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves:
|
|
March 31
|
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
Sales of oil and gas produced, net of production costs
|
|
$
|
(1,459,000
|
)
|
|
$
|
(1,240,000
|
)
|
|
$
|
(2,036,000
|
)
|
Net changes in price and production costs
|
|
|
1,849,000
|
|
|
|
(12,510,000
|
)
|
|
|
(4,066,000
|
)
|
Changes in previously estimated development costs
|
|
|
970,000
|
|
|
|
3,701,000
|
|
|
|
2,627,000
|
|
Revisions of quantity estimates
|
|
|
(404,000
|
)
|
|
|
(602,000
|
)
|
|
|
(3,718,000
|
)
|
Net change due to purchases and sales of minerals in place
|
|
|
(2,380,000
|
)
|
|
|
(105,000
|
)
|
|
|
2,777,000
|
|
Extensions and discoveries, less related costs
|
|
|
6,994,000
|
|
|
|
5,174,000
|
|
|
|
4,607,000
|
|
Net change in income taxes
|
|
|
(3,959,000
|
)
|
|
|
2,539,000
|
|
|
|
654,000
|
|
Accretion of discount
|
|
|
1,612,000
|
|
|
|
2,370,000
|
|
|
|
2,474,000
|
|
Changes in timing of estimated cash flows and other
|
|
|
1,962,000
|
|
|
|
(4,367,000
|
)
|
|
|
(3,710,000
|
)
|
Changes in standardized measure
|
|
|
5,185,000
|
|
|
|
(5,040,000
|
)
|
|
|
(391,000
|
)
|
Standardized measure, beginning of year
|
|
|
13,898,000
|
|
|
|
18,938,000
|
|
|
|
19,329,000
|
|
Standardized measure, end of year
|
|
$
|
19,083,000
|
|
|
$
|
13,898,000
|
|
|
$
|
18,938,000
|
|
16.
Selected Quarterly Financial Data (Unaudited)
|
|
FISCAL 2017
|
|
|
|
4
th
QTR
|
|
|
3
rd
QTR
|
|
|
2
nd
QTR
|
|
|
1
st
QTR
|
|
Operating revenue
|
|
$
|
684,204
|
|
|
$
|
590,134
|
|
|
$
|
580,842
|
|
|
$
|
670,183
|
|
Operating income (loss)
|
|
|
25,237
|
|
|
|
(127,366
|
)
|
|
|
(188,338
|
)
|
|
|
(252,185
|
)
|
Net loss
|
|
|
(3,454
|
)
|
|
|
(159,741
|
)
|
|
|
(237,902
|
)
|
|
|
(293,456
|
)
|
Net loss income per share – basic
|
|
|
-
|
|
|
|
(0.08
|
)
|
|
|
(0.12
|
)
|
|
|
(0.14
|
)
|
Net loss income per share – diluted
|
|
|
-
|
|
|
|
(0.08
|
)
|
|
|
(0.12
|
)
|
|
|
(0.14
|
)
|
|
|
FISCAL 2016
|
|
|
|
4
th
QTR
|
|
|
3
rd
QTR
|
|
|
2
nd
QTR
|
|
|
1
st
QTR
|
|
Operating revenue
|
|
$
|
445,484
|
|
|
$
|
544,870
|
|
|
$
|
728,829
|
|
|
$
|
702,609
|
|
Operating loss
|
|
|
(390,005
|
)
|
|
|
(2,549,990
|
)
|
|
|
(1,094,279
|
)
|
|
|
(435,481
|
)
|
Net loss
|
|
|
(433,476
|
)
|
|
|
(2,445,536
|
)
|
|
|
(776,307
|
)
|
|
|
(324,366
|
)
|
Net loss income per share – basic
|
|
|
(0.21
|
)
|
|
|
(1.20
|
)
|
|
|
(0.38
|
)
|
|
|
(0.16
|
)
|
Net loss income per share – diluted
|
|
|
(0.21
|
)
|
|
|
(1.20
|
)
|
|
|
(0.38
|
)
|
|
|
(0.16
|
)
|
17.
Subsequent Events
In
the first quarter of fiscal 2018, the Company sold for a total consideration of $460,461 leasehold interests in 137.01 net acres
in the Scoop-Stack areas of Canadian and Grady Counties, Oklahoma. Of the total proceeds, $410,000 was applied to reduce bank
indebtedness.
In
May 2017, we participated in the drilling of 2 horizontal wells in the Delaware Basin of Lea County, New Mexico at a cost of $165,600.
Mexco’s working interest in these wells is .6%.