The following discussion is intended to provide information relevant to an
understanding of our financial condition, changes in our financial condition and
our results of operations and cash flows and should be read in conjunction with
our consolidated financial statements and notes thereto included elsewhere
this Form 10-K.
Liquidity and Capital Resources and Commitments
Historically, we have funded our operations, acquisitions, exploration and
development expenditures from cash generated by operating activities, bank
borrowings, sales of non-core properties and issuance of common stock. Our
primary financial resource is our base of oil and gas reserves. We have pledged
our producing oil and gas properties to secure our revolving line of credit. We
do not have any delivery commitments to provide a fixed and determinable
quantity of our oil and gas under any existing contract or agreement.
Due to the current commodity price environment, we are applying financial
discipline to all aspects of our business. In order to meet obligations, we may
continue to sell non-core assets.
Our long term strategy is on increasing profit margins while concentrating on
obtaining reserves with low cost operations by acquiring and developing oil and
gas properties with potential for long-lived production. We focus our efforts on
the acquisition of royalties and working interests and non-operated properties
in areas with significant development potential.
For the year ended March 31, 2019, cash flow from operations was $1,012,328, a
130% increase when compared to the corresponding period of fiscal 2018. Net cash
from investing activities of $655,395 was used for additions to oil and gas
properties, cash of $700,000 was used to pay off the line of credit, cash of
$39,532 was used for the issuance of our new loan agreement and cash of $18,241
was received from proceeds from the exercise of employee stock options.
Accordingly, net cash decreased $364,358, leaving cash and cash equivalents on
hand of $128,252 as of March 31, 2019.
We had working capital of $395,895 as of March 31, 2019 compared to working
capital of $925,618 as of March 31, 2018, a decrease of $529,723 for the reasons
set forth below.
Oil and Natural Gas Property Development
In addition to 113 gross wells (.08 net wells) drilled by other operators on
Mexco's royalty interests, the Company participated in the drilling and
completion of 43 horizontal wells and 5 vertical wells at a cost of
approximately $900,000 for the fiscal year ending March 31, 2019. Of these
horizontal wells, 36 are in the Delaware Basin located in the western portion of
the Permian Basin in Eddy and Lea Counties, New Mexico and 7 are located in
Grady County, Oklahoma. The operators of these wells include Apache Corporation,
Concho Resources, Inc., Marathon Oil Company, Mewbourne Oil Company, XTO Energy,
Inc. and others.
Five of these wells were completed in September 2018 and tested at an average
rate of 1,553 barrels of oil; 2,075 barrels of water; and 2,067,000 cubic feet
of gas per day, or 1,899 barrels of oil equivalent per day. These wells are in
the Upper Wolfcamp formation located in Lea County, New Mexico. Mexco's working
interest in these wells is .6%.
Two of these wells are in the Yeso/Paddock formations of the Dodd Federal Unit
in the Grayburg San Andres Jackson Field of Eddy County, New Mexico and operated
by Concho Resources, Inc. These wells began producing in December 2018 at an
initial average rate of 337 barrels of oil; 1,914 barrels of water; and 160,000
cubic feet of gas per well per day, or 364 barrels of oil equivalent per day.
Mexco's working interest in this unit is .1848%.
Four of these wells began producing in February 2019 at an initial average rate
of 1,445 barrels of oil; 3,994 barrels of water; and 4,500,000 cubic feet of gas
per day, or 2,195 barrels of oil equivalent per day. These wells, operated by
Marathon Oil Company, are in the Wolfcamp formation located in Lea County, New
Mexico. Mexco's working interest in these wells is .03%.
In addition, two wells were completed in March 2019 and tested at an average
rate of 1,934 barrels of oil; 1,950 barrels of water; and 2,153,000 cubic feet
of gas per day, or 2,259 barrels of oil equivalent per day. These wells are in
the Bone Spring formation located in Lea County, New Mexico. Mexco's working
interest in these wells is .5%.
There were eleven additional wells that began producing throughout the fiscal
year at an initial average rate of 470 barrels of oil; 2,148 barrels of water;
and 1,431,000 cubic feet of gas per day, or 708 barrels of oil equivalent per
day. Three wells, operated by XTO Energy, Inc., are in the Bone Spring formation
located in Eddy County, New Mexico. And the other eight wells, operated by
Marathon Oil Company and Mewbourne Oil Company, are in the Purple Sage formation
located in Lea County, New Mexico. Mexco's working interest in these various
wells range from .008% to .031%.
The remaining 19 of the 48 wells have been drilled and are in various stages of
completion and testing.
During fiscal 2019, the Company continued its policy of selling non-core assets
in order to concentrate on the development of more profitable assets and to pay
down debt. The Company received approximately $33,000 in cash from a sale of
joint venture leasehold acreage and marginal producing working interest wells in
North Dakota and Montana; approximately $72,000 in cash from a sale of joint
venture leasehold marginal producing working interests in Ward and Winkler
Counties in Texas; and, approximately $51,000 in cash from the sale of
additional leasehold acreage in Eddy County, New Mexico.
We are participating in other projects and are reviewing projects in which we
may participate. The cost of such projects would be funded, to the extent
possible, from existing cash balances and cash flow from operations. The
remainder may be funded through borrowings on the credit facility and, if
appropriate, sales of non-core properties.
Crude oil and natural gas prices generally remained volatile during the last
year. The volatility of the energy markets makes it extremely difficult to
predict future oil and natural gas price movements with any certainty. For
example in the last twelve months, the NYMEX West Texas Intermediate ("WTI")
posted price for crude oil has ranged from a low of $39.25 per bbl in December
2018 to a high of $73.00 per bbl in October 2018. The Henry Hub Spot Market
Price ("Henry Hub") for natural gas has ranged from a low of $2.54 per MMBtu in
February 2019 to a high of $4.70 per MMBtu in November 2018.
On March 31, 2019 the WTI posted price for crude oil was $56.50 per bbl and the
Henry Hub spot price for natural gas was $2.73 per MMBtu. See Results of
Operations below for realized prices.
Results of Operations
Fiscal 2019 Compared to Fiscal 2018
We had a net loss of $12,946 for the year ended March 31, 2019 compared to a net
loss of $321,489 for the year ended March 31, 2018. This is primarily the result
of a decrease in operating expenses and interest expense as further explained
Oil and gas sales. Revenue from oil and gas sales was $2,647,877 for the year
ended March 31, 2019, a .1% decrease from $2,650,232 for the year ended March
31, 2018. This resulted from an increase in oil price and production partially
offset by a decrease in gas price and production. The following table sets forth
our oil and gas revenues, production quantities and average prices received
during the fiscal years ended March 31:
2019 2018 % Difference
Revenue $ 1,921,391$ 1,789,736 7.4 %
Volume (bbls) 35,357 34,743 1.8 %
Average Price (per bbl) $ 54.34$ 51.51 5.5 %
Revenue $ 726,486$ 860,496 (15.6 %)
Volume (mcf) 295,133 318,774
Average Price (per mcf) $ 2.46$ 2.70 (8.9 %)
Production and exploration. Production costs were $936,400 in fiscal 2019, a 13%
decrease from $1,070,447 in fiscal 2018. This was primarily the result of a
decrease in lease operating expenses due to the sale of our marginal operated
properties in Loving County, Texas.
Depreciation, depletion and amortization. Depreciation, depletion and
amortization ("DD&A") expense was $802,425 in fiscal 2019, a 9% decrease from
$880,419 in fiscal 2018. This was primarily due to a decrease in gas production
and a decrease in the full cost pool as a result of a decrease in future
development costs partially offset by a decrease in oil and gas reserves.
General and administrative expenses. General and administrative expenses were
$911,927 for the year ended March 31, 2019, a 5% decrease from $955,147 for the
year ended March 31, 2018. This was primarily due to a decrease in accounting
fees partially offset by an increase in rent, engineering services and legal
Interest expense. Interest expense was $21,931 in fiscal 2019, a 76% decrease
from $89,537 in fiscal 2018, due to a decrease in borrowings partially offset by
an increase in interest rate.
Income taxes. There was no income tax for fiscal 2019 or fiscal 2018. The
effective tax rate for fiscal 2019 and fiscal 2018 was 0%. We are in a net
deferred tax asset position and believe it is more likely than not that these
deferred tax assets will not be realized.
Fiscal 2018 Compared to Fiscal 2017
We had a net loss of $321,489 for the year ended March 31, 2018 compared to a
net loss of $694,553 for the year ended March 31, 2017. We achieved net income
of $264,461 for the fiscal quarter ended March 31, 2018.
Oil and gas sales. Revenue from oil and gas sales was $2,650,232 for the year
ended March 31, 2018, a 13% increase from $2,337,222 for the year ended March
31, 2017. This resulted from an increase in oil and gas prices partially offset
by a decrease in gas production. The following table sets forth our oil and gas
revenues, production quantities and average prices received during the fiscal
years ended March 31:
2018 2017 % Difference
Revenue $ 1,789,736$ 1,517,606 17.9 %
Volume (bbls) 34,743 34,689 0.2 %
Average Price (per bbl) $ 51.51$ 43.75 17.7 %
Revenue $ 860,496$ 819,616 5.0 %
Volume (mcf) 318,774 356,268
Average Price (per mcf) $ 2.70$ 2.30 17.4 %
Other operating revenue. Other operating revenue was $55,003 for fiscal 2018
compared to $188,141 for fiscal 2017 primarily due to the settlement of a
lawsuit for underpayment of royalties from Chesapeake Energy Corporation and
Total E & P USA in the amount of $148,614 during fiscal 2017 partially offset by
an increase in SWD income.
Production and exploration. Production costs were $1,070,447 in fiscal 2018, a
22% increase from $878,458 in fiscal 2017. This was primarily the result of an
increase in lease operating expenses and production taxes due to the increase in
oil and gas revenues and XTO Energy, Inc. incorrectly providing us a refund for
marketing and transportation fees of approximately $67,000 which is being
reversed via monthly netting.
Depreciation, depletion and amortization. Depreciation, depletion and
amortization ("DD&A") expense was $880,419 in fiscal 2018, a 25% decrease from
$1,177,422 in fiscal 2017. This was primarily due to a decrease in oil and gas
production, a decrease in the full cost pool as a result of oil and gas property
sales, and a decrease in oil and gas reserves.
General and administrative expenses. General and administrative expenses were
$955,147 for the year ended March 31, 2018, a 2% decrease from $976,392 for the
year ended March 31, 2017. This was primarily due to a decrease in engineering
services, insurance expense and legal fees partially offset by an increase
Interest expense. Interest expense was $89,537 in fiscal 2018, a 41% decrease
from $152,126 in fiscal 2017, due to a decrease in borrowings partially offset
by an increase in interest rate.
Income taxes. There was no income tax for fiscal 2018 or fiscal 2017. The
effective tax rate for fiscal 2018 and fiscal 2017 was 0%. We are in a net
deferred tax asset position and believe it is more likely than not that these
deferred tax assets will not be realized.
We have no off-balance sheet debt or unrecorded obligations and have not
guaranteed the debt of any other party. The following table summarizes future
payments we are obligated to make based on agreements in place as of March
Payments due in:
Total less than 1 year 1 - 3 years over 3 years
Leases (1) $ 106,682 $ 48,810 $ 57,872 $ -
(1) The lease amount represents the monthly rent amount for our principal office
space in Midland, Texas under one three year lease agreement effective May
15, 2018. The total obligation for the remainder of the lease is $141,385
which includes $34,703 billed to and reimbursed by our majority shareholder
for his portion of the shared office space.
Alternative Capital Resources
Although we have primarily used cash from operating activities, the sales of
assets and funding from the line of credit as our primary capital resources, we
have in the past, and could in the future, use alternative capital resources.
These could include joint ventures, carried working interests and issuances of
our common stock through a private placement or public offering.
Critical Accounting Policies and Estimates
In preparing financial statements, management makes 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. On an ongoing
basis, management reviews its estimates, including those related to litigation,
environmental liabilities, income taxes, fair value and determination of proved
reserves. Changes in facts and circumstances may result in revised estimates and
actual results may differ from these estimates.
The following represents those policies that management believes are
particularly important to the financial statements and that require the use of
estimates and assumptions to describe matters that are inherently uncertain.
Full Cost Method of Accounting for Crude Oil and Natural Gas Activities. SEC
Regulation S-X defines the financial accounting and reporting standards for
companies engaged in crude oil and natural gas activities. Two methods are
prescribed: the successful efforts method and the full cost method. We have
chosen to follow the full cost method under which all costs associated with
property acquisition, exploration and development are capitalized. We also
capitalize internal costs that can be directly identified with acquisition,
exploration and development activities and do 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")
Gain or loss on the sale or other disposition of oil and gas properties is not
recognized, unless the sale would significantly alter the relationship between
capitalized costs and proved reserves of oil and natural gas attributable to a
country. Under the successful efforts method, geological and geophysical costs
and costs of carrying and retaining undeveloped properties are charged to
expense as incurred. Costs of drilling exploratory wells that do not result in
proved reserves are charged to expense. Depreciation, depletion, amortization
and impairment of crude oil and natural gas properties are generally calculated
on a well by well or lease or field basis versus the "full cost" pool basis.
Additionally, gain or loss is generally recognized on all sales of crude oil and
natural gas properties under the successful efforts method. As a result our
financial statements will differ from companies that apply the successful
efforts method since we will generally reflect a higher level of capitalized
costs as well as a higher DD&A rate on our crude oil and natural gas properties.
At the time it was adopted, management believed that the full cost method would
be preferable, as earnings tend to be less volatile than under the successful
efforts method. However, the full cost method makes us more susceptible to
significant non-cash charges during times of volatile commodity prices because
the full cost pool may be impaired when prices are low. These charges are not
recoverable when prices return to higher levels. Our crude oil and natural gas
reserves have a relatively long life. However, temporary drops in commodity
prices can have a material impact on our business including impact from the
cost method of accounting.
Ceiling Test. Companies that use the full cost method of accounting for oil and
gas exploration and development activities are required to perform a ceiling
test 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 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, we must charge the amount of the excess to
earnings. 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 our stockholders' equity and reported earnings.
The risk that we will be required to write down the carrying value of crude oil
and natural gas properties increases when crude oil and natural gas prices are
depressed or volatile. In addition, write-downs may occur if we experience
substantial downward adjustments to our estimated proved reserves or if
purchasers cancel long-term contracts for natural gas production. An expense
recorded in one period may not be reversed in a subsequent period even though
higher crude oil and natural gas prices may have increased the ceiling
applicable to the subsequent period.
Estimates of our proved reserves are based on the quantities of oil and gas that
engineering and geological analysis demonstrates, with reasonable certainty, to
be recoverable from established reservoirs in the future under current operating
and economic parameters. Our reserve estimates and the projected cash flows are
derived from these reserve estimates, in accordance with SEC guidelines by an
independent engineering firm based in part on data provided by us. The accuracy
of a reserve estimate is a function of the quality and quantity of available
data, the interpretation of that data, the accuracy of various mandated economic
assumptions, and the judgment of the persons preparing the estimate. Estimates
prepared by other third parties may be higher or lower than those included
herein. Because these estimates depend on many assumptions, all of which may
substantially differ from future actual results, reserve estimates will be
different from the quantities of oil and gas that are ultimately recovered. In
addition, results of drilling, testing and production after the date of an
estimate may justify material revisions to the estimate.
It should not be assumed that the present value of future net cash flows is the
current market value of our estimated proved reserves. In accordance with SEC
requirements, the cost ceiling represents the present value (discounted at 10%)
of net cash flows from sales of future production using the average price over
the prior 12-month period.
The estimates of proved reserves materially impact DD&A expense. If the
estimates of proved reserves decline, the rate at which we record DD&A expense
will increase, reducing future net income. Such a decline may result from lower
market prices, which may make it uneconomic to drill for and produce higher
Use of Estimates. 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 our oil and natural gas
reserves, which is used to compute DD&A and impairment of oil and gas
properties, is the most significant of the estimates and assumptions that affect
these reported results.
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 DD&A pool). Impairments transferred to
the DD&A pool increase the DD&A rate.
Revenue Recognition - Revenue from Contracts with Customers. In May 2014, the
Financial Accounting Standards Board ("FASB") issued Accounting Standards Update
("ASU") No. 2014-09, Revenue from Contracts with Customers (Topic 606). The
amendments in this update are effective for fiscal years and interim periods
within those years beginning after December 15, 2017 and supersedes any previous
revenue recognition guidance. On April 1, 2018 we adopted ASU 2014-09 using the
modified retrospective approach which only applies to contracts that were not
completed as of the date of initial application. Recognition of revenue involves
a five step approach including identifying the contract, identifying the
separate performance obligations, determining the transaction price, allocating
the price to the performance obligations and recognizing revenue as the
obligations are satisfied.
Adoption of this new standard did not have a material impact on the Company's
financial statements. When comparing the Company's historical revenue
recognition to the newly applied revenue recognition under Topic 606, there was
no material change to the amount or timing of revenue recognized. Therefore, no
quantitative adjustment was required to be made to the prior periods presented
in the unaudited consolidated financial statements. Upon adoption the Company
had not altered its existing information technology and internal controls
outside of the contract review processes in order to identify impacts of future
revenue contracts the Company may enter into.
Accounting Policy - Revenues from our royalty and non-operated working interest
properties are recorded under the cash receipts approach as directly received
from the remitters' statement accompanying the revenue check. Since the revenue
checks are generally received two to four months after the production month, the
Company accrues for revenue earned but not received by estimating production
volumes and product prices. Any identified differences between its revenue
estimates and actual revenue received historically have not been significant.
The Company does not disclose the value of unsatisfied performance obligations
under its contracts with customers as it applies the practical exemption in
accordance with ASC 606. The exemption, as described in ASC 606-10-50-14(a),
applies to variable consideration that is recognized as control of the product
is transferred to the customer. Since each unit of product represents a separate
performance obligation, future volumes are wholly unsatisfied and disclosure of
the transaction price allocated to remaining performance obligations is not
In accordance with ASC Topic 606, the Company now records transportation and
processing costs that are incurred after control of its product has transferred
to the customer as a reduction of "Natural gas sales" on the Consolidated
Statement of Operations. Prior to the adoption of ASC Topic 606, these
transportation and processing costs were recorded as an expense within
"Production" expenses on the Consolidated Statements of Operations. There was no
impact to net loss or retained earnings as a result of adopting ASC Topic 606.
Asset Retirement Obligations. The estimated costs of plugging, restoration and
removal of facilities are accrued. The fair value of a liability for an asset's
retirement obligation is recorded in the period in which it is incurred and the
corresponding cost capitalized by increasing the carrying amount of the related
long-lived asset. The liability is accreted to its then present value each
period, and the capitalized cost is depreciated by the units of production
method. If the liability is settled for an amount other than the recorded
amount, a gain or loss is recognized. For all periods presented, we have
included estimated future costs of abandonment and dismantlement in the full
cost amortization base and amortize these costs as a component of our depletion
Gas Balancing. Gas imbalances are accounted for under the sales method whereby
revenues are recognized based on production sold. A liability is recorded when
our excess takes of natural gas volumes exceed our estimated remaining
recoverable reserves (over produced). No receivables are recorded for those
wells where Mexco has taken less than its ownership share of gas production
Stock-based Compensation. We use 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 our financial statements over the
vesting period. We recognize 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.
Accounts Receivable. Our accounts receivable include 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 our previous loss history.
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,
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.
Recent Accounting Pronouncements. In February 2016, the FASB issued ASU 2016-02,
Topic 842 Leases, which requires companies to include leases with a term greater
than one year on their balance sheets, but recognize lease costs on the income
statement in a manner similar to accounting for leases prior to ASU 2016-02. The
standard is effective for fiscal years beginning after December 15, 2018, and
interim periods thereafter. Early adoption is permitted. The Company has
evaluated the provisions of this ASU and does not anticipate a significant
impact on the consolidated financial statements from this amendment.
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