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, 2016 were approximately 2.051 million barrels of oil equivalent (“Boe”)
of which 53% was oil and natural gas liquids and 47% was natural gas, and our estimated present value of proved reserves was approximately
$16 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 2016, we added proved reserves of 590,000 Boe through
extensions and discoveries, subtracted 4,500 Boe through sales of oil and gas properties and had downward revisions of previous
estimates of 136,000 Boe. Such revisions are a result of Security Exchange Commission (“SEC”) rules which require
such reserves to be developed within five years as well as decreased oil and natural gas prices.
Nicholas
C. Taylor beneficially owns approximately 45% 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 2017.
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
Crude
oil prices remained significantly depressed in fiscal 2016 and face continued downward pressure due to domestic and global supply
and demand factors. The downward price pressure intensified in late 2015 and early 2016, with crude oil prices dropping below
$23 per barrel in February 2016, a level not seen since 2003. Natural gas prices faced similar downward pressure, dropping below
$1.50 per mcf in March 2016.
In
light of the challenges facing our industry and in response to these price declines, our primary business strategies for fiscal
2017 will 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 2016 operating results and potential impact on fiscal 2017 operating results due to depressed commodity prices.
Oil
and Gas Operations
As
of March 31, 2016, oil constituted approximately 53% of our total proved reserves and approximately 67% of our revenues for fiscal
2016. Revenues from oil and gas royalty interests accounted for approximately 24% of our revenues for fiscal 2016.
Mexco
believes there is potential for horizontal drilling, multi-stage fracturing and production of oil and gas in a substantial number
of properties containing approximately 1,150 wells in which Mexco holds an interest. These wells are located in the core area
of the horizontal Wolfcamp multi-zone formation in Reagan, Upton, Midland, Martin, Glasscock and Andrews Counties in the Midland
Basin of West Texas. Such interests vary from .125% to 7.68% working interest (.094% to 6.24% net revenue interest, respectively).
In
addition to these working interests, we also own various mineral and royalty interests in and around these core counties in the
Midland Basin, a part of the Permian Basin of West Texas.
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, Glasscock and Crockett 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
Midland Basin properties, encompassing 71,477 gross acres, 285 net acres, 534 gross producing wells and 2.5 net wells account
for approximately 42% of our discounted future net cash flows from proved reserves as of March 31, 2016. Of these discounted future
net cash flows from proved reserves, approximately 32% are attributable to proven undeveloped reserves which will be developed
through new drilling. For fiscal 2016, these properties accounted for 19% of our gross revenues and 24% of our net revenues.
The
Delaware Basin properties, encompassing 29,638 gross acres, 623 net acres, 458 gross producing wells and 5.2 net wells account
for approximately 18% of our discounted future net cash flows from proved reserves as of March 31, 2016. Of these discounted future
net cash flows from proved reserves, approximately 2% are attributable to proven undeveloped reserves which will be developed
through new drilling. For fiscal 2016, these properties accounted for 24% of our gross revenues and 29% 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 3% of our discounted future net cash flows from proved reserves as of March 31, 2015. For fiscal 2016,
these properties accounted for 3% of our gross revenues and 5% 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 240 gross acres, 153 net acres,
3 gross wells in Ector County, Texas, account for 7.3% of our discounted future net cash flows from proved reserves as of March
31, 2016. Of these discounted future net cash flows from proved reserves, 7% are attributable to proven undeveloped reserves which
will be developed through new drilling of 4 wells. For fiscal 2016, these properties consist of working interests and accounted
for 3% of our gross revenues and .1% of our net revenues.
In
August 2013, Mexco assigned Pioneer Natural Resources Company a three year term leasehold interest in 417.33 net acres (837.33
gross acres) of undeveloped acreage located above and below the Pembrook Unit of Upton County, Texas and retained a 1% royalty.
In
November 2015, Mexco extended a six month option for which the Company received $112,000 for a three year assignment of a leasehold
interest in 320 net acres (640 gross acres) in Upton County, Texas. The purchaser paid Mexco $2,000 per acre for a total of $640,000.
Mexco also retained a 1% overriding royalty interest in this acreage. This acreage has the potential for horizontal development
in multiple zones of the horizontal Wolfcamp formation centered in the southern Midland Basin. The purchaser advises that he has
obtained rights to explore the balance of the undivided 640 acres from Apache Corporation and has been advised that Parsley Energy,
Inc. plans to develop this property.
Mexco
believes its most important properties for future development by horizontal drilling and hydraulic fracturing area located in
Midland, Reagan and Upton Counties, Texas of the Midland Basin.
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 13 producing wells and 1 water injection well. We own partial interests in an additional 6,461 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)
|
|
2016
|
|
|
38,930
|
|
|
|
407,939
|
|
2015
|
|
|
29,557
|
|
|
|
369,034
|
|
2014
|
|
|
27,186
|
|
|
|
361,652
|
|
2013
|
|
|
23,260
|
|
|
|
401,077
|
|
2012
|
|
|
19,442
|
|
|
|
395,649
|
|
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:
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Holly Frontier Refining & Marketing LLC
|
|
|
14
|
%
|
|
|
17
|
%
|
|
|
22
|
%
|
Plains Marketing LP
|
|
|
18
|
%
|
|
|
8
|
%
|
|
|
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 currently operate one underground injection well
and own 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. We are, and believe the other operators are as well, 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 engage third parties to occasionally
provide hydraulic fracturing or other well stimulation services to us in connection with many of the wells we operate. 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 for us 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 by us 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, 2016. 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
2017.
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
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.
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.
Substantially
all of our properties are currently mortgaged under a deed of trust to secure funding through a revolving 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, 2016.
Name
|
|
Age
|
|
Position
|
Nicholas
C. Taylor
|
|
78
|
|
Chairman
and Chief Executive Officer
|
Tamala
L. McComic
|
|
47
|
|
President,
Chief Financial Officer, Treasurer, and Assistant Secretary
|
Donna
Gail Yanko
|
|
71
|
|
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 has 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, 2015, we had four 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 will expire 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 revolving 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. Our financial results are more sensitive
to movements in natural gas prices than oil prices because most of our production is natural gas. 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
2015 and 2014.
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
47% and 39% of our total estimated net proved reserves at March 31, 2016 and 2015, 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 2016, differentials averaged $1.01 per Bbl of oil and $0.39 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 revolving 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
revolving 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 revolving credit facility requires, among other things, minimum earnings before interest, taxes, depreciation and amortization
(“EBITDA”) of $100,000 for the two fiscal quarters ending September 30, 2016, $300,000 for the three fiscal quarters
ending December 31, 2016, $500,000 for the four fiscal quarters ending March 31, 2017 and $650,000 for each trailing fiscal quarter
period thereafter and minimum interest coverage ratios (EBITDA/Interest Expense) of 1.25 to 1 for the fiscal quarter ending June
30, 2016 and 2 to 1 for each quarter thereafter. If we fail to meet any of these loan covenants, the lender under the revolving
credit facility could accelerate the indebtedness and seek to foreclose on the pledged assets.
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
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.
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
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.
The
U.S. President’s Fiscal Year 2016 Budget Proposal includes provisions that would, if enacted, 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. It is unclear whether any such changes will be
enacted or how soon any such changes could become effective. The passage of this legislation or any other similar changes in the
U. S. federal income tax laws could negatively affect our financial condition and results of operations.
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 45% 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, 2016, our executive officers and directors beneficially owned approximately 48% 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, 2016, we had interests in 6,461 gross (34.3 net) oil and gas wells and owned leasehold mineral and royalty interests
in approximately 580,978 gross (5,152 net) acres.
Oil
and Natural Gas Reserves
In
accordance with current SEC rules, the average prices used in computing reserves at March 31, 2016 were $41.76 per bbl of oil
and $74.84 in 2015, a decrease of 44%, and $1.998 per mcf of natural gas and $3.595 in 2015, a decrease of 44%, 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 2016. The benchmark price of $42.77 per bbl of oil at March 31, 2016 versus $79.21 at March 31, 2015,
was adjusted by lease for gravity, transportation fees and regional price differentials and did not give effect to derivative
transactions. The benchmark price of $2.39 per mcf of natural gas at March 31, 2016 versus $3.88 at March 31, 2015, was adjusted
by lease for BTU content, transportation fees and regional price differentials. The average prices used in computing reserves
at March 31, 2014 were $94.23 per bbl of oil and $3.67 per mcf of natural gas. The benchmark prices used in computing reserves
at March 31, 2014 were $94.92 per bbl of oil and $3.99 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.
The
engineering report with respect to Mexco’s estimates of proved oil and gas reserves as of March 31, 2016, 2015 and 2014
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 Joe C. 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.
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.
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 and judgment. 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,
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Oil (Bbls):
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed – Producing
|
|
|
334,500
|
|
|
|
260,580
|
|
|
|
278,230
|
|
Proved developed – Non-producing
|
|
|
15,680
|
|
|
|
23,090
|
|
|
|
16,390
|
|
Proved undeveloped
|
|
|
734,170
|
|
|
|
376,070
|
|
|
|
206,930
|
|
Total
|
|
|
1,084,350
|
|
|
|
659,730
|
|
|
|
501,550
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Mcf):
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed – Producing
|
|
|
3,356,660
|
|
|
|
3,470,970
|
|
|
|
2,982,480
|
|
Proved developed – Non-producing
|
|
|
1,049,400
|
|
|
|
1,113,820
|
|
|
|
1,098,990
|
|
Proved undeveloped
|
|
|
1,395,220
|
|
|
|
1,703,790
|
|
|
|
2,177,810
|
|
Total
|
|
|
5,801,280
|
|
|
|
6,288,580
|
|
|
|
6,259,280
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net proved reserves (Boe)
|
|
|
2,051,230
|
|
|
|
1,707,827
|
|
|
|
1,544,763
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PV-10 Value (1)
|
|
$
|
16,121,600
|
|
|
$
|
23,700,470
|
|
|
$
|
24,745,250
|
|
Present value of future income tax discounted at 10%
|
|
|
(2,223,600
|
)
|
|
|
(4,762,470
|
)
|
|
|
(5,416,250
|
)
|
Standardized measure of discounted future net cash flows (2)
|
|
$
|
13,898,000
|
|
|
$
|
18,938,000
|
|
|
$
|
19,329,000
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prices used in Calculating Reserves: (3)
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
1.998
|
|
|
$
|
3.595
|
|
|
$
|
3.67
|
|
Oil (per Bbl)
|
|
$
|
41.76
|
|
|
$
|
74.84
|
|
|
$
|
94.23
|
|
|
(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, 2016, 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, 2016, 4 wells in which we own a royalty interest were developed converting reserves of approximately
66,000 mcfe from proved undeveloped to proved developed - producing. We participated in the development of 20 wells converting
reserves of approximately 190,000 mcfe from proved undeveloped to proved developed - producing. The capital cost was approximately
$733,000 for the 20 wells in which we own a working interest.
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.
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. The following table indicates our productive wells as of
March 31, 2016:
|
|
Gross
|
|
|
Net
|
|
Oil
|
|
|
3,386
|
|
|
|
21.2
|
|
Gas
|
|
|
3,075
|
|
|
|
13.3
|
|
Total Productive Wells
|
|
|
6,461
|
|
|
|
34.5
|
|
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, 2016:
|
|
Developed Acres
|
|
|
|
Gross
|
|
|
Net
|
|
Texas
|
|
|
354,421
|
|
|
|
3,047
|
|
Oklahoma
|
|
|
97,430
|
|
|
|
1,450
|
|
New Mexico
|
|
|
30,039
|
|
|
|
517
|
|
Louisiana
|
|
|
43,027
|
|
|
|
46
|
|
North Dakota
|
|
|
30,174
|
|
|
|
46
|
|
Kansas
|
|
|
9,672
|
|
|
|
24
|
|
Montana
|
|
|
7,868
|
|
|
|
5
|
|
Wyoming
|
|
|
3,898
|
|
|
|
5
|
|
Arkansas
|
|
|
960
|
|
|
|
5
|
|
Alabama
|
|
|
640
|
|
|
|
2
|
|
Mississippi
|
|
|
1,600
|
|
|
|
3
|
|
Colorado
|
|
|
1,120
|
|
|
|
1
|
|
Virginia
|
|
|
129
|
|
|
|
1
|
|
Total
|
|
|
580,978
|
|
|
|
5,152
|
|
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,
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
Development Wells
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
15
|
|
|
|
.07
|
|
|
|
56
|
|
|
|
.41
|
|
|
|
34
|
|
|
|
.42
|
|
Nonproductive
|
|
|
-
|
|
|
|
-
|
|
|
|
1
|
|
|
|
.09
|
|
|
|
1
|
|
|
|
.01
|
|
Total
|
|
|
15
|
|
|
|
.07
|
|
|
|
57
|
|
|
|
.50
|
|
|
|
35
|
|
|
|
.43
|
|
We
have not participated in any exploratory wells during the years ended March 31, 2016, 2015 and 2014. 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.
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,
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Oil (a):
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (Bbls)
|
|
|
38,930
|
|
|
|
29,557
|
|
|
|
27,186
|
|
Revenue
|
|
$
|
1,598,725
|
|
|
$
|
2,069,806
|
|
|
$
|
2,591,619
|
|
Average Bbls per day (e)
|
|
|
107
|
|
|
|
81
|
|
|
|
74
|
|
Average sales price per Bbl (b)
|
|
$
|
41.07
|
|
|
$
|
70.03
|
|
|
$
|
95.33
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas (c):
|
|
|
|
|
|
|
|
|
|
|
|
|
Production (Mcf)
|
|
|
407,939
|
|
|
|
369,034
|
|
|
|
361,652
|
|
Revenue
|
|
$
|
785,225
|
|
|
$
|
1,267,020
|
|
|
$
|
1,402,676
|
|
Average Mcf per day (e)
|
|
|
1,118
|
|
|
|
1,011
|
|
|
|
991
|
|
Average sales price per Mcf
|
|
$
|
1.92
|
|
|
$
|
3.43
|
|
|
$
|
3.88
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
Production cost
|
|
$
|
944,933
|
|
|
$
|
1,024,130
|
|
|
$
|
943,730
|
|
Production and ad valorem taxes
|
|
$
|
199,128
|
|
|
$
|
276,690
|
|
|
$
|
288,084
|
|
Equivalent Mcf (d)
|
|
|
641,518
|
|
|
|
546,375
|
|
|
|
524,768
|
|
Production cost per equivalent Mcf
|
|
$
|
1.47
|
|
|
$
|
1.87
|
|
|
$
|
1.80
|
|
Production cost per sales dollar
|
|
$
|
0.40
|
|
|
$
|
0.31
|
|
|
$
|
0.24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total oil and gas revenue
|
|
$
|
2,383,950
|
|
|
$
|
3,336,826
|
|
|
$
|
3,994,295
|
|
|
(a)
|
Includes
condensate.
|
|
|
|
|
(b)
|
We
did not have a price swap agreement on our oil production for the year ended March 31, 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. After giving effect to our derivative
instruments, the average sales price per Bbl of oil was $93.33 for year ended March 31, 2014.
|
|
|
|
|
(c)
|
Includes
natural gas products.
|
|
|
|
|
(d)
|
Oil
production is converted to equivalent mcf at the rate of 6 mcf per bbl, representing the estimated relative energy content
of natural gas to 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 28, 2016
Pursuant to the requirements
of the Securities Exchange Act of 1934, this report has been signed below as of June 28, 2016, 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.
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 redrill 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, 2016, 2015 and 2014
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 most of the Company oil and gas interests are operated by others, the Company
operates several properties 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, 2016, the Company had the majority 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, 2016, 2015 and 2014, 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) Income Per Common Share
. Basic
net (loss) income per share is computed by dividing net (loss) income by the weighted average number of common shares outstanding
during the period. Diluted net (loss) income 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) income 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
March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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
and related disclosures.
In February 2016, the FASB issued ASU 2016-02,
Topic 842 Leases, which requires companies to recognize a right of use asset and related liability on the balance sheet for the
rights and obligations arising from leases with durations greater than 12 months. The standard is effective for fiscal years beginning
after December 15, 2018, and interim periods thereafter. Early adoption is permitted. We are currently evaluating the effect the
new guidance will have on our consolidated financial statements.
In January 2016, the FASB issued 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. The Company is currently evaluating the effect the new guidance will have on its financial statements.
In November 2015, the FASB issued ASU No.
2015-17, Topic 740 Income Taxes: Balance Sheet Classification of Deferred Taxes which requires all deferred income tax liabilities
and assets to be presented as noncurrent in a classified balance sheet. Currently, entities are required to separate deferred
income tax liabilities and assets into current and noncurrent amounts in a classified balance sheet. The new standard will become
effective for the Company beginning on April 1, 2017, with the option to early adopt, and can be applied either prospectively
or retrospectively. The adoption of this guidance will have no impact on the Company’s results of operations or cash flows.
The reclassification of amounts from current to noncurrent could affect the presentation of the Company’s balance sheet.
In February 2015, the FASB issued ASU No.
2015-02, Topic 810: Consolidation which amends the current consolidation guidance. ASU No. 2015-02 is effective for the Company
as of April 1, 2016. The Company is assessing the standard update and does not believe there will be a significant impact on its
consolidated financial statements.
In August 2014, the FASB issued ASU No. 2014-15,
Subtopic 205-40: Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern which provides guidance
on determining when and how reporting entities must disclose going-concern uncertainties in their financial statements. ASU No.
2014-15 is effective for the Company for the fiscal year ending March 31, 2017 and interim periods thereafter and early adoption
is permitted. The Company does not expect the adoption of this ASU to have a material impact on its consolidated financial statements.
In May 2014, the FASB issued
ASU No. 2014-09, Topic 606: Revenue from Contracts with Customers. This ASU provides guidance concerning the recognition and measurement
of revenue from contracts with customers. 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 in 2018
and is required to be adopted using either the retrospective or cumulative effect transition method, with early adoption permitted
in 2017. Management is evaluating the effect, if any this pronouncement will have on our consolidated financial statements.
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.
The fair value of the Company’s crude
oil swaps are measured internally using established commodity futures price strips for the underlying commodity provided by a
reputable third party, the contracted notional volumes, and time to maturity. The valuation of the Company’s derivative
instrument was deemed to use Level 2 inputs. See the Company’s Note 7 on Derivatives for further discussion.
4. Credit Facility
The Company has a loan agreement with Bank
of America, N.A. (the “Agreement”), which provided for a credit facility of $5,630,000 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 as of March 31, 2016. The borrowing base will be reset to the extent the Company sells or otherwise disposes of any
of its oil and gas properties. The Company is required to pay 100% of such net proceeds to the lender resulting in a permanent
reduction of the borrowing base. Subsequently, in April 2016, the Company sold some of its oil and gas properties for $60,000
and used these proceeds to pay on its line of credit, thus reducing its credit facility and borrowing base to $5,570,000. 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 was renewed ten times with the
tenth amendment effective as of March 31, 2016 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 an increased rate from 2.5 to 3.0 percentage points, which was 2.935% on March 31, 2016. Interest on
the outstanding amount under the credit agreement is payable monthly. In addition, the Company no longer will pay an unused commitment
fee in an amount equal to ½ to 1 percent (.5%) times the daily average of the unadvanced amount of the commitment. There
was no availability of this line of credit at March 31, 2016. No principal payments are anticipated to be required through November
30, 2020.
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 except that the tenth amendment replaces
the tangible net worth test and requires minimum earnings before interest, taxes, depreciation and amortization (“EBITDA”)
of $100,000 for the two fiscal quarters ending September 30, 2016, $300,000 for the three fiscal quarters ending December 31,
2016, $500,000 for the four fiscal quarters ending March 31, 2017 and $650,000 for each trailing fiscal quarter period thereafter
and minimum interest coverage ratios (EBITDA/Interest Expense) of 1.25 to 1 for the fiscal quarter ending June 30, 2016 and 2.00
to 1.00 for each quarter thereafter. The Company is in compliance with all covenants as of March 31, 2016.
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, 2016, one letter of credit for $50,000, in lieu
of 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, 2016 was $5,580,000 and as of June 15, 2016 was $5,520,000. The following table is a summary of activity on the
Bank of America, N.A. line of credit for the year ended March 31, 2016:
|
|
|
Principal
|
|
Balance
at April 1, 2015:
|
|
|
$
|
5,950,000
|
|
Borrowings
|
|
|
|
400,000
|
|
Repayments
|
|
|
|
(770,000
|
)
|
Balance
at March 31, 2016:
|
|
|
$
|
5,580,000
|
|
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:
|
|
2016
|
|
|
2015
|
|
Carrying amount of asset retirement obligations as of April 1
|
|
$
|
1,240,216
|
|
|
$
|
961,577
|
|
Liabilities incurred
|
|
|
5,844
|
|
|
|
274,148
|
|
Liabilities settled
|
|
|
(60,138
|
)
|
|
|
(23,441
|
)
|
Accretion expense
|
|
|
35,155
|
|
|
|
27,932
|
|
Carrying amount of asset retirement obligations as of March 31
|
|
|
1,221,077
|
|
|
|
1,240,216
|
|
Less: Current portion
|
|
|
10,000
|
|
|
|
10,000
|
|
Non-Current asset retirement obligation
|
|
$
|
1,211,077
|
|
|
$
|
1,230,216
|
|
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 2013.
Significant
components of net deferred tax assets (liabilities) at March 31 are as follows:
|
|
2016
|
|
|
2015
|
|
Deferred tax assets:
|
|
|
|
|
|
|
|
|
Percentage depletion carryforwards
|
|
$
|
1,718,721
|
|
|
$
|
1,535,126
|
|
Deferred stock-based compensation
|
|
|
49,090
|
|
|
|
36,958
|
|
Asset retirement obligation
|
|
|
415,166
|
|
|
|
384,467
|
|
Net operating loss
|
|
|
1,493,914
|
|
|
|
720,308
|
|
Other
|
|
|
6,413
|
|
|
|
11,111
|
|
|
|
|
3,683,304
|
|
|
|
2,687,970
|
|
Deferred tax liabilities:
|
|
|
|
|
|
|
|
|
Excess financial accounting bases over tax bases of
property and equipment
|
|
|
2,834,340
|
|
|
|
(3,348,840
|
)
|
|
|
|
|
|
|
|
|
|
Deferred tax asset (liability)
|
|
$
|
848,964
|
|
|
$
|
(660,870
|
)
|
|
|
|
|
|
|
|
|
|
Valuation allowance
|
|
|
(848,964
|
)
|
|
|
-
|
|
Net deferred tax asset (liability)
|
|
$
|
-
|
|
|
$
|
(660,870
|
)
|
As
of March 31, 2016, the Company has a statutory depletion carryforward of approximately $5,000,000, which does not expire. At March
31, 2016, the Company had a net operating loss carryforward for regular income tax reporting purposes of approximately $6,600,000,
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
is required when it is more-likely-than-not that some portion or all of the deferred tax assets will not be realized. The ultimate
realization of this deferred tax asset depends on the Company's ability to generate sufficient taxable income in the future. Management
believes it is more-likely-than- not that the net deferred tax asset will not be realized by future operating results.
The
income tax provision consists of the following for years ended March 31, 2016, 2015 and 2014:
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Current income tax expense
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
6,500
|
|
Deferred income tax (benefit) expense
|
|
|
(660,870
|
)
|
|
|
(197,499
|
)
|
|
|
5,250
|
|
Total income tax provision:
|
|
$
|
(660,870
|
)
|
|
$
|
(197,499
|
)
|
|
$
|
11,750
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective tax rate
|
|
|
(14
|
)%
|
|
|
(37
|
)%
|
|
|
4
|
%
|
The current income tax expense for fiscal
year 2014 is the Company’s alternative minimum tax that cannot offset with its alternative minimum tax net operating loss.
A
reconciliation of the provision for income taxes to income taxes computed using the federal statutory rate for years ended March
31 follows:
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Tax expense at federal statutory rate (1)
|
|
$
|
(1,577,789
|
)
|
|
$
|
(183,085
|
)
|
|
$
|
106,374
|
|
Statutory depletion carryforward
|
|
|
(35,034
|
)
|
|
|
(71,292
|
)
|
|
|
(127,204
|
)
|
Change in valuation allowance
|
|
|
848,964
|
|
|
|
-
|
|
|
|
-
|
|
Effect of graduated rates
|
|
|
64,585
|
|
|
|
12,221
|
|
|
|
(13,841
|
)
|
Permanent differences
|
|
|
31,904
|
|
|
|
44,657
|
|
|
|
46,421
|
|
Other
|
|
|
6,500
|
|
|
|
-
|
|
|
|
-
|
|
Total income tax (benefit) expense
|
|
$
|
(660,870
|
)
|
|
$
|
(197,499
|
)
|
|
$
|
11,750
|
|
Effective income tax rate
|
|
|
(14
|
)%
|
|
|
(37
|
)%
|
|
|
4
|
%
|
(1)
The federal statutory rate was 34% for fiscal years ending March 31, 2016, 2015 and 2014.
For
the years ended March 31, 2016, 2015 and 2014, the Company did not have any uncertain tax positions.
A
reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows:
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Unrecognized tax benefits at beginning of period
|
|
$
|
679,000
|
|
|
$
|
679,000
|
|
|
$
|
677,000
|
|
Additions based on tax positions related to the current year
|
|
|
-
|
|
|
|
-
|
|
|
|
2,000
|
|
Changes to tax positions of prior years
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Settlements
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Expirations
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Unrecognized tax benefits at end of period
|
|
$
|
679,000
|
|
|
$
|
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 two-year period ending March 31, 2016. 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 loss on derivative instruments included in the consolidated statements of operations for the years
ended March 31, 2016, 2015 and 2014:
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Unrealized loss on open non-hedge derivative instruments
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
(44,981
|
)
|
Gain (loss) on settlement of non-hedge derivative instruments
|
|
|
-
|
|
|
|
102,069
|
|
|
|
(54,281
|
)
|
Total gain (loss) on derivative instruments
|
|
$
|
-
|
|
|
$
|
102,069
|
|
|
$
|
(99,262
|
)
|
As
of March 31, 2016 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 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. In fiscal 2014, one customer accounted
for 22% of the total oil and gas revenues and 25% 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:
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Property acquisition costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$
|
-
|
|
|
$
|
3,108,040
|
|
|
$
|
785,144
|
|
Unproved
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Exploration
|
|
|
-
|
|
|
|
15,472
|
|
|
|
9,641
|
|
Development
|
|
|
1,112,733
|
|
|
|
1,746,582
|
|
|
|
1,152,986
|
|
Capitalized asset retirement obligations
|
|
|
5,844
|
|
|
|
274,148
|
|
|
|
134,113
|
|
Total costs incurred for oil and gas properties
|
|
$
|
1,118,577
|
|
|
$
|
5,144,242
|
|
|
$
|
2,081,884
|
|
The
Company had the following aggregate capitalized costs relating to its oil and gas property activities at March 31:
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Proved oil and gas properties
|
|
$
|
40,365,197
|
|
|
$
|
40,489,453
|
|
|
$
|
35,386,751
|
|
Unproved oil and gas properties:
|
|
|
|
|
|
|
|
|
|
|
|
|
subject to amortization
|
|
|
-
|
|
|
|
73,990
|
|
|
|
73,990
|
|
not subject to amortization
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
40,365,197
|
|
|
|
40,563,443
|
|
|
|
35,460,741
|
|
Less accumulated DD&A
|
|
|
24,306,770
|
|
|
|
19,752,994
|
|
|
|
18,395,619
|
|
|
|
$
|
16,058,427
|
|
|
$
|
20,810,449
|
|
|
$
|
17,065,122
|
|
DD&A
amounted to $2.45, $2.48 and $2.18 per mcfe of production for the years ended March 31, 2016, 2015 and 2014, respectively.
10.
(Loss) Income Per Common Share
Due
to a net loss for the year ended March 31, 2016 and 2015, the weighted average number of common shares outstanding excludes common
stock equivalents because their inclusion would be anti-dilutive. For the year ended March 31, 2014, 35,000 options were excluded
from the diluted net income per share calculations because the options are anti-dilutive. Anti-dilutive stock options have a weighted
average exercise price of $5.98 at March 31, 2014.
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:
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Net (loss) income
|
|
$
|
(3,979,685
|
)
|
|
$
|
(340,986
|
)
|
|
$
|
301,113
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted avg. common shares outstanding – basic
|
|
|
2,037,266
|
|
|
|
2,038,250
|
|
|
|
2,036,950
|
|
Effect of the assumed exercise of dilutive stock options
|
|
|
-
|
|
|
|
-
|
|
|
|
5,234
|
|
Weighted avg. common shares outstanding – dilutive
|
|
|
2,037,266
|
|
|
|
2,038,250
|
|
|
|
2,042,184
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss) income per common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
(1.95
|
)
|
|
$
|
(0.17
|
)
|
|
$
|
0.15
|
|
Diluted
|
|
$
|
(1.95
|
)
|
|
$
|
(0.17
|
)
|
|
$
|
0.15
|
|
11.
Stockholders’ Equity
In
June 2015, 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 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. There
were no shares of common stock repurchased for the treasury account during fiscal 2014.
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 2016, 2015 and 2014.
The
Company recognized compensation expense of $116,953, $153,386 and $152,448 in general and administrative expense in the Consolidated
Statements of Operations for fiscal 2016, 2015 and 2014, respectively. The total cost related to non-vested awards not yet recognized
at March 31, 2016 totals $78,653, which is expected to be recognized over a weighted average of 1.92 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 year ended March 31, 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. During the year ended March 31, 2014, the Compensation Committee of the Board of Directors approved and the
Company granted 35,000 stock options to officers and employees of the Company exercisable at $5.98 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 2016, 2015 and 2014. All such amounts represent the weighted average amounts
for each period.
|
|
For the year ended March 31,
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Grant-date fair value
|
|
|
-
|
|
|
$
|
5.59
|
|
|
$
|
4.75
|
|
Volatility factor
|
|
|
-
|
|
|
|
76.23
|
%
|
|
|
77.01
|
%
|
Dividend yield
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Risk-free interest rate
|
|
|
-
|
|
|
|
2.52
|
%
|
|
|
1.74
|
%
|
Expected term (in years)
|
|
|
-
|
|
|
|
10
|
|
|
|
7
|
|
No
forfeiture rate is assumed for stock options granted to directors or employees due to the forfeiture rate history for these types
of awards. There were no stock options forfeited or expired during the years ended March 31, 2016, 2015 and 2014.
The
following table is a summary of activity of stock options for the year ended March 31, 2016, 2015 and 2014:
|
|
Number of
Shares
|
|
|
Weighted
Average
Exercise Price
Per Share
|
|
|
Weighted Aggregate
Average Remaining
Contract Life in
Years
|
|
|
Intrinsic
Value
|
|
Outstanding at April 1, 2013
|
|
|
80,000
|
|
|
$
|
6.52
|
|
|
|
8.03
|
|
|
$
|
-
|
|
Granted
|
|
|
35,000
|
|
|
|
5.98
|
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
(1,400
|
)
|
|
|
6.29
|
|
|
|
|
|
|
|
|
|
Forfeited or Expired
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
Outstanding at March 31, 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
|
|
|
$
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Vested at March 31, 2016
|
|
|
106,100
|
|
|
$
|
6.48
|
|
|
|
5.68
|
|
|
$
|
-
|
|
Exercisable at March 31, 2016
|
|
|
106,100
|
|
|
$
|
6.48
|
|
|
|
5.68
|
|
|
$
|
-
|
|
Other
information pertaining to option activity was as follows during the year ended March 31:
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Weighted average grant-date fair value of stock options granted (per share)
|
|
$
|
-
|
|
|
$
|
5.59
|
|
|
$
|
4.75
|
|
Total fair value of options vested
|
|
$
|
154,338
|
|
|
$
|
150,063
|
|
|
$
|
108,500
|
|
Total intrinsic value of options exercised
|
|
$
|
-
|
|
|
$
|
-
|
|
|
$
|
6,244
|
|
The
following table summarizes information about options outstanding at March 31, 2016:
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
|
|
|
|
45,000
|
|
|
$
|
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
|
|
|
|
153,600
|
|
|
$
|
6.52
|
|
|
|
6.36
|
|
|
$
|
-
|
|
Outstanding
options at March 31, 2015 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, 2016 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, 2016, 2015 and 2014 were $92,723, $125,209 and $133,861, 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 following table summarizes future payments the Company is
obligated to make based on the lease commitments in place as of March 31, 2016:
|
|
Commitment Amount (1)
|
|
Fiscal Year 2017
|
|
$
|
23,440
|
|
Fiscal Year 2018
|
|
$
|
19,020
|
|
|
(1)
|
The
total commitment for the remainder of the leases is $60,939 which includes $18,479 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, 2016, 2015 and 2014 was $23,438, $23,442 and $19,020, 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, 2016, 2015, and 2014 are based on evaluations
prepared by Joe C. Neal and Associates, Petroleum 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, 2016 were approximately 2.051 million barrels of oil equivalent (“Boe”)
of which 53% was oil and natural gas liquids and 47% was natural gas.
Changes
in Proved Reserves
:
|
|
Oil
(Bbls)
|
|
|
Natural Gas (Mcf)
|
|
Proved Developed and Undeveloped Reserves:
|
|
|
|
|
|
|
|
|
As of April 1, 2013
|
|
|
366,000
|
|
|
|
7,844,000
|
|
Revision of previous estimates
|
|
|
12,000
|
|
|
|
(1,404,000
|
)
|
Purchase of minerals in place
|
|
|
50,000
|
|
|
|
18,000
|
|
Extensions and discoveries
|
|
|
101,000
|
|
|
|
163,000
|
|
Sales of minerals in place
|
|
|
-
|
|
|
|
-
|
|
Production
|
|
|
(27,000
|
)
|
|
|
(362,000
|
)
|
As of March 31, 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
|
|
Proved
developed reserves are those expected to be recovered through existing wells, equipment and operating methods. Proved undeveloped
reserves (“PUD”) are proved reserves 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 downward revision of oil and natural gas is primarily
the result of SEC rules which require such reserves to be developed within five years and because of the participation in one
unsuccessful well. Reserves written off due to the five year limitation are primarily in the Haynesville field in Louisiana 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, 2016, 2015 and 2014
:
|
|
Oil
(Bbls)
|
|
|
Natural Gas (Mcf)
|
|
Proved Developed Reserves:
|
|
|
|
|
|
|
|
|
As of April 1, 2013
|
|
|
237,420
|
|
|
|
4,807,020
|
|
As of March 31, 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
|
|
|
|
|
|
|
|
|
|
|
Proved Undeveloped Reserves:
|
|
|
|
|
|
|
|
|
As of April 1, 2013
|
|
|
128,290
|
|
|
|
3,037,180
|
|
As of March 31, 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
|
|
At
March 31, 2016, the Company reported estimated PUDs of 5.8 bcfe, which accounted for 47% of its total estimated proved oil and
gas reserves. This figure primarily consists of a projected 67 new wells (3.4 bcfe), 4 of which the Company operates. The 4 wells
the Company operates (1.2 bcfe), will be drilled on existing acreage in the Goldsmith field where the Company currently operates
3 wells. The Company projects 4 operated wells will be drilled in fiscal 2019. Regarding the remaining 63 PUD locations operated
by others (2.2 bcfe), 1 well is currently being drilled with plans for 14 wells to follow in 2017, 14 wells in 2018, 16 wells
in 2019 and 18 wells in 2020.
As
of March 31, 2016, 2015 and 2014 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 2016.
Progress
of Converting Proved Undeveloped Reserves
:
|
|
Oil & Natural Gas
|
|
|
Future
|
|
|
|
(Mcfe)
|
|
|
Development Costs
|
|
PUDs, beginning of year
|
|
|
3,960,232
|
|
|
$
|
6,617,402
|
|
Revision of previous estimates
|
|
|
(1,441,324
|
)
|
|
|
(2,778,279
|
)
|
Conversions to PD reserves
|
|
|
(256,618
|
)
|
|
|
(732,620
|
)
|
Additional PUDs added
|
|
|
3,537,952
|
|
|
|
6,510,657
|
|
PUDs, end of year
|
|
|
5,800,242
|
|
|
$
|
9,617,160
|
|
Estimated
future net cash flows represent an estimate of future net revenues from the production of proved reserves using average prices
for 2016, 2015 and 2014 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, 2021 are $9,617,160.
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 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 average prices used for fiscal 2014 were $94.23 per bbl of oil and $3.67 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, 2016, 2015 and 2014, 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
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Future cash inflows
|
|
$
|
57,318,000
|
|
|
$
|
72,238,000
|
|
|
$
|
70,252,000
|
|
Future production costs and taxes
|
|
|
(14,571,000
|
)
|
|
|
(19,569,000
|
)
|
|
|
(20,647,000
|
)
|
Future development costs
|
|
|
(9,617,000
|
)
|
|
|
(6,617,000
|
)
|
|
|
(4,826,000
|
)
|
Future income taxes
|
|
|
(4,569,000
|
)
|
|
|
(9,254,000
|
)
|
|
|
(9,801,000
|
)
|
Future net cash flows
|
|
|
28,561,000
|
|
|
|
36,798,000
|
|
|
|
34,978,000
|
|
Annual 10% discount for estimated timing of cash flows
|
|
|
(14,663,000
|
)
|
|
|
(17,860,000
|
)
|
|
|
(15,649,000
|
)
|
Standardized measure of discounted future net cash flows
|
|
$
|
13,898,000
|
|
|
$
|
18,938,000
|
|
|
$
|
19,329,000
|
|
Changes
in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves:
|
|
March 31
|
|
|
|
2016
|
|
|
2015
|
|
|
2014
|
|
Sales of oil and gas produced, net of production costs
|
|
$
|
(1,240,000
|
)
|
|
$
|
(2,036,000
|
)
|
|
$
|
(2,762,000
|
)
|
Net changes in price and production costs
|
|
|
(12,510,000
|
)
|
|
|
(4,066,000
|
)
|
|
|
2,464,000
|
|
Changes in previously estimated development costs
|
|
|
3,701,000
|
|
|
|
2,627,000
|
|
|
|
270,000
|
|
Revisions of quantity estimates
|
|
|
(602,000
|
)
|
|
|
(3,718,000
|
)
|
|
|
(657,000
|
)
|
Net change due to purchases and sales of minerals in place
|
|
|
(105,000
|
)
|
|
|
2,777,000
|
|
|
|
1,332,000
|
|
Extensions and discoveries, less related costs
|
|
|
5,174,000
|
|
|
|
4,607,000
|
|
|
|
3,802,000
|
|
Net change in income taxes
|
|
|
2,539,000
|
|
|
|
654,000
|
|
|
|
(1,997,000
|
)
|
Accretion of discount
|
|
|
2,370,000
|
|
|
|
2,474,000
|
|
|
|
1,779,000
|
|
Changes in timing of estimated cash flows and other
|
|
|
(4,367,000
|
)
|
|
|
(3,710,000
|
)
|
|
|
729,000
|
|
Changes in standardized measure
|
|
|
(5,040,000
|
)
|
|
|
(391,000
|
)
|
|
|
4,960,000
|
|
Standardized measure, beginning of year
|
|
|
18,938,000
|
|
|
|
19,329,000
|
|
|
|
14,369,000
|
|
Standardized measure, end of year
|
|
$
|
13,898,000
|
|
|
$
|
18,938,000
|
|
|
$
|
19,329,000
|
|
16.
Selected Quarterly Financial Data (Unaudited)
|
|
FISCAL 2016
|
|
|
|
4
th
QTR
|
|
|
3
rd
QTR
|
|
|
2
nd
QTR
|
|
|
1
st
QTR
|
|
Oil and gas revenue
|
|
$
|
432,723
|
|
|
$
|
537,771
|
|
|
$
|
720,874
|
|
|
$
|
692,582
|
|
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
|
)
|
|
|
FISCAL 2015
|
|
|
|
4
th
QTR
|
|
|
3
rd
QTR
|
|
|
2
nd
QTR
|
|
|
1
st
QTR
|
|
Oil and gas revenue
|
|
$
|
551,894
|
|
|
$
|
790,335
|
|
|
$
|
987,942
|
|
|
$
|
1,006,655
|
|
Operating (loss) profit
|
|
|
(412,332
|
)
|
|
|
(240,224
|
)
|
|
|
60,128
|
|
|
|
51,069
|
|
Net (loss) income
|
|
|
(270,975
|
)
|
|
|
(175,321
|
)
|
|
|
86,256
|
|
|
|
19,054
|
|
Net (loss) income per share – basic
|
|
|
(0.13
|
)
|
|
|
(0.09
|
)
|
|
|
0.04
|
|
|
|
0.01
|
|
Net (loss) income per share – diluted
|
|
|
(0.13
|
)
|
|
|
(0.09
|
)
|
|
|
0.04
|
|
|
|
0.01
|
|
17.
Subsequent Events
In
connection with Barnett Shale Fort Worth Basin royalties owned by the Company, the Company has been advised that settlement of
a lawsuit for underpayment of royalties has been reached with the defendants, Chesapeake Energy Corporation and Total E&P
USA resulting in an expected payment of $154,289 by September 1, 2016 of which $123,394 is payable in cash and a promissory note
in the principal amount of $30,894, interest free, due in three years and payable by Chesapeake.