UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended March 31, 20012004 Commission File No. 0-6694
MEXCO ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
ColoradoCOLORADO 84-0627918
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
214 W. Texas Avenue, SuiteTEXAS AVENUE, SUITE 1101 79701
Midland, TexasMIDLAND, TEXAS (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code: (915)(432) 682-1119
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act:
Title of Each Class Name of Exchange on Which Registered
- ----------------------------- ------------------------------------
Common Stock, $0.50 par value NoneAmerican Stock Exchange
Indicate by check-mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding twelve (12) months (or for such shorter period that
the registrant was required to file such reports) and (2) has been subject to
such filing requirements for the past ninety (90) days. Yes X[X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K (ss.229.405 of this chapter) is not contained herein, and
will not be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part III of this
Form 10-K or an amendment to this Form 10-K. [ ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes [ ] No [X]
As of May 22, 2001,June 24, 2004, the aggregate market value of the registrant's common
stock held by non-affiliates (using the closing bidlast price of $4.00)at which a common equity was
sold ($6.80)) was approximately $1,924,540.$3,488,148.
The number of shares outstanding of the registrant's common stock as of
May
31, 2001June 24, 2004 was 1,610,133.1,736,041.
DOCUMENTS INCORPORATED BY REFERENCE
Part IIIPortions of this Report is incorporated by reference from the Registrant's InformationProxy Statement relating to itsthe 2004 Annual
Meeting of StockholdersShareholders to be held on September 27, 2001.14, 2004, have been incorporated
by reference in Part III of this Form 10-K. Such InformationProxy Statement will be filed
with the Commission not later than July 30, 2001.2004.
TABLE OF CONTENTS
PART 1
Item 1. Business ................................................................................................................. 3
Item 2. Properties...................................................... 6Properties......................................................... 7
Item 3. Legal Proceedings............................................... 8Proceedings.................................................. 10
Item 4. Submission of Matters to a Vote of Security Holders............. 8Holders................ 11
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters............................................. 9Matters................................................ 11
Item 6. Selected Financial Data......................................... 10Data............................................ 12
Item 7.6A. Selected Quarterly Financial Data............................... 10Data.................................. 13
Item 8.7. Management's Discussion and Analysis of Financial
Condition and Results of Operations............................. 10Operations................................ 13
Item 9.7A. Quantitative and Qualitative Disclosures About Market Risk...... 14Risk......... 19
Item 10.8. Financial Statements and Supplementary Data..................... 15Data........................ 20
Item 11.9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosures............................ 30Disclosures............................... 38
Item 9A. Controls and Procedures............................................ 38
PART III
Item 12.10. Directors and Executive Officers of the Registrant.............. 30Registrant................. 39
Item 13.11. Executive Compensation.......................................... 30Compensation............................................. 39
Item 14.12. Security Ownership of Certain Beneficial Owners and Management.. 30Management..... 39
Item 15.13. Certain Relationships and Related Transactions.................. 30Transactions..................... 39
Item 14. Principal Accountant Fees and Services............................. 39
PART IV
Item 16.15. Exhibits, Financial Statement Schedules and Reports on Form 8-K. 318-K.... 40
Signatures ............................................................... 3240
2
PART I
ITEM 1. BUSINESS
General
Mexco Energy Corporation, a Colorado corporation, (the "Company", which
reference shall include the Company's wholly-owned subsidiary) is an independent
oil and gas company engaged in the acquisition, exploration and development of
oil and gas properties located in the United States. Incorporated in April 1972
under the name Miller Oil Company, the Company changed its name to Mexco Energy
Corporation effective April 30, 1980. At that time, the shareholders of the
Company also approved amendments to the Articles of Incorporation resulting in a
one-for-fifty reverse stock split of the Company's common stock.
On February 25, 1997 Mexco Energy Corporation acquired all of the issued
and outstanding stock of Forman Energy Corporation, a New York corporation also
engaged in oil and gas exploration and development.
Since its inception, the Company has been engaged in acquiring and
developing oil and gas properties and the exploration for and production of oil
and gas within the United States. The Company continues to focusprimarily focuses on the
exploration for and development of natural gas and crude oil resources, as well as increased
profit margins through reductions in operating costs. The Company's long-term
strategy is to increase production and profits, while increasing its
concentration on gas reserves.
While the Company owns oil and gas properties in other states, the majority
of its activities are centered in West Texas. The Company acquires 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, the Company may acquire oil and gas interests by
joining in oil and gas drilling prospects generated by third parties. The
Company may employ a combination of the above methods of obtaining producing
acreage and prospects. In recent years, the Company has placed primary emphasis
on the evaluation and purchase of producing oil and gas properties, both working
and royalty interests, and re-entry prospects.
Oil and Gas Operationsprospects that could have a potentially
meaningful impact on Company reserves.
OIL AND GAS OPERATIONS
As of March 31, 2001,2004, gas reserves constituted approximately 82%91% of the
Company's total proved reserves and approximately 83%74% of the Company's revenues
for fiscal 2001.2004. Revenues from oil and gas royalty interests accounted for
approximately 16%17% of the Company's revenues for fiscal 2001.2004.
VIEJOS GAS FIELD properties, encompassing 2,583 gross acres, 156 net acres,
18 gross wells and 1.27 net wells in Pecos County, Texas, account for
approximately 20%6% of the Company's discounted future net cash flows from proved
reserves as of March 31, 2001,2004, and for fiscal 2001,2004, approximately 38%20% of
revenues and 29%10% of production costs.
GOMEZ GAS FIELD properties, encompassing 13,847 gross acres, 73 net acres,
24 gross wells and .11 net wells in Pecos County, Texas, account for
approximately 17%12% of the Company's discounted future net cash flows from proved
reserves as of March 31, 2001,2004, and for fiscal 2001,2004, approximately 14%12% of
revenues and 10%6% of production costs.
EL CINCO GAS FIELD properties, encompassing 1,713 gross acres, 1,237 net
acres, 9 gross producing wells and 6.6 net wells in Pecos County, Texas, account
for approximately 53% of the Company's discounted future net cash flows from
proved reserves as of March 31, 2004. This is a multi-pay area where most of the
leases have potential reserves in two zones. Of this amount approximately 36% of
the Company's discounted future net cash flows from proved reserves are
attributable to proven undeveloped reserves which will be developed through
re-entry of existing wells and new drilling. For fiscal 2004, these properties
accounted for approximately 18% of revenues and 24% of production costs.
3
The Company owns interests in and operates 1722 producing wells and two
shut-in wells. The Company owns partial interests in an additional 1,4611,704
producing wells located in the states of Texas, New Mexico, Oklahoma, Louisiana,
Arkansas, Wyoming, Kansas, Colorado, Alabama, Montana and North Dakota. Additional
information concerning these properties and the oil and gas reserves of the
Company is provided below.
The following table indicates the Company's oil and gas production in each
of the last five years, all of which is located within the United States:
Year Oil(Bbls) Gas(Mcf)Gas (Mcf)
---- --------- -----------------
2004...................................... 20,279 487,564
2003...................................... 23,391 538,787
2002...................................... 21,139 467,013
2001...................................... 18,545 503,773
2000...................................... 19,334 540,793
1999...................................... 49,573 482,948
1998...................................... 63,800 432,343
1997...................................... 39,363 236,034
CompetitionCOMPETITION
The oil and gas industry is a highly competitive business. Competition for
oil and gas reserve acquisitions is significant. The Company may compete with
major oil and gas companies, other independent oil and gas companies and
individual producers and operators with significantly largeroperators. Some of these competitors have financial and
other
resources.personnel resources substantially in excess of those available to the Company
and, therefore, the Company 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. Major CustomersThe Company's
ability to acquire and develop additional properties in the future will depend
upon its ability to conduct operations, to evaluate and select suitable
properties, and to consummate transactions in this highly competitive
environment in a timely manner.
MAJOR CUSTOMERS
The Company had sales to the following companiescompany that amounted to 10% or more
of revenues for the year ended March 31:
2001 2000 19992004 2003 2002
---- ---- ----
Sid Richardson Energy Services, Co.
(formerly Koch Midstream Services Company) 39% 35% 30%
Navajo Crude29% 28% 24%
Because a ready market exists for the Company's oil and gas production, the
Company does not believe the loss of any individual customer would have a
material adverse effect on its financial position or results of operations.
RISK FACTORS
There are many factors that affect the Company's business and results of
operations, some of which are beyond the Company's control. The following is a
description of some of the important factors that may cause results of
operations in future periods to differ materially from those currently expected
or desired.
4
Oil Marketingand gas prices are volatile and could adversely affect the Company's
revenues, cash flow, liquidity and reserve estimates. The Company - - 25%
Regulationcannot 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 changes in supply
and demand, weather conditions, the price and availability of alternative fuels,
political and economic conditions in oil producing countries, and other factors
that are beyond the Company's control. Natural gas prices affect the Company
more than oil prices because most of the Company's production and reserves are
natural gas.
Prices also affect the amount of cash flow available for capital
expenditures and the Company's ability to borrow money or raise additional
capital. Lower prices may also reduce the amount of crude oil and natural gas
that can be produced economically. Changes in oil and gas prices impact both
estimated future net revenue and the estimated quantity of proved reserves.
Price increases may permit additional quantities of reserves to be produced
economically, and price decreases may render uneconomic the production of
reserves previously classified as proved. Thus, the Company 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.
Lower oil and gas prices increase the risk of ceiling limitation
write-downs. The Company uses the full cost method to account for oil and gas
operations. Accordingly, the Company capitalizes 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,
the Company must charge the amount of the excess to earnings. This charge does
not impact cash flow from operating activities, but does reduce stockholders'
equity and earnings. The risk that the Company will be required to write down
the carrying value of oil and natural gas properties increases when oil and
natural gas prices are low.
Estimates of proved reserves and the estimated future net revenue from such
reserves are uncertain and inherently imprecise. The process of estimating oil
and gas reserves is complex and requires significant decisions and assumptions
in the evaluation of available geological, geophysical, engineering and economic
data for each reservoir. The interpretation of such data is a subjective process
dependent upon the quality of the data and the decision-making and judgment of
reservoir engineers.
Actual future production, oil and gas prices, revenues, taxes, development
expenditures, operating expenses and quantities of recoverable oil and gas
reserves most likely will vary from those estimated. Any significant variance
could materially affect the estimated quantities and present value of reserves,
which may in turn adversely affect the Company's cash flow, results of
operations and the availability of capital resources.
One should not assume that the present value of proved reserves is equal to
the current fair market value of the Company's estimated oil and gas reserves.
In accordance with the requirements of the Securities and Exchange Commission
("SEC"), the estimated discounted future net cash flows from proved reserves are
generally based on prices and costs as of the date of the estimate. 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.
5
REGULATION
The Company's exploration, development, production and marketing operations
are subject to 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 for drilling operations, bonds and reports concerning
operations. Most states also have statutes and regulations governing
conservation and safety matters, including the unitization and pooling of oil
and gas properties, the establishment of maximum rates of production from oil
and gas wells and the spacing of such wells. Such statutes and regulations may
limit the rate at which oil and gas otherwise could be produced from the
Company's properties. The regulatory burden on the oil and gas industry
increases its cost of doing business and, consequently, affects its
profitability. 4
Because these rules and regulations are frequently amended or
reinterpreted, the Company is not able to predict the future cost or impact of
complying with such laws.
Currently there are no laws that regulate the price for sales of production
by the Company. However, the rates charged and terms and conditions for the
movement of gas in interstate commerce through certain intrastate pipelines and
production area hubs are subject to regulation under the Natural Gas Policy Act
of 1978 ("NGPA"). The construction of pipelines and hubs are, to a limited
extent, also subject to regulation under the Natural Gas Act of 1938 ("NGA").
The NGA also establishes comprehensive controls over interstate pipelines,
including the transportation in interstate commerce. While these NGA controls do
not apply directly to the Company, their effect on natural gas markets can be
significant in terms of competition and cost of transportation services. The
Federal Energy Regulatory Commission ("FERC") administers the NGA and NGPA.
FERC has taken significant steps to increase competition in the sale,
purchase, storage and transportation of natural gas. FERC's regulatory programs
generally allow more accurate and timely price signals from the consumer to the
producer. Nonetheless, the ability to respond to market forces can and does add
to price volatility, inter-fuel competition and pressure on the value of
transportation and other services.
Additional proposals and proceedings that might affect the natural gas
industry are considered from time to time by Congress, FERC, state regulatory
bodies and the courts. Several proposals that might affect the natural gas
industry are pending before FERC. The Company cannot predict when or if any such
proposals will become effective and their effect, if any, on the Company's
operations. Historically, the natural gas industry has been heavily regulated
andregulated;
therefore, there is no assurance that the less stringent regulatory approach
recently pursued by FERC and Congress and the states will continue indefinitely into the
future.
Environmentalcontinue.
ENVIRONMENTAL
The Company, by nature of its oil and gas operations, is subject to
extensive federal, state and local environmental laws and regulations
governingcontrolling 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
6
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 the Company's operations.
In addition, these laws and regulations may impose substantial liabilities and
penalties for the Company's failure to comply with them or for any contamination
resulting from the Company's operations. The Company believes it is in
compliance, in all material respects, with applicable environmental
requirements. Although future
environmental obligations areThe Company does not expectedbelieve costs relating to these laws and
regulations have had a material impactadverse effect on the results ofCompany's operations or
financial condition ofin the Company,past. As these laws and regulations become more
stringent and complex, there can beis no assurance that future developments, such as increasingly stringent environmentalchanges in or additions to
laws or enforcement thereof,regulations regarding the protection of the environment will not causehave
such an impact in the Company to incur material
environmental liabilities or costs.
Insurancefuture.
INSURANCE
The Company is subject to all the risks inherent in the exploration for,
and development and production of oil and gas including blowouts, fires and
other casualties. The Company maintains 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.
EmployeesEMPLOYEES
As of March 31, 2001,2004, the Company had two full-time and three part-time
employees. The Company believes that relations with these employees are
generally satisfactory. The Company's employees are not covered by collective
bargaining arrangements. From time to time, the Company utilizes the services of
independent contractors to perform various field and other services. Experienced
personnel are available in all disciplines should the need to hire additional
staff arise.
Office FacilitiesOFFICE FACILITIES
The Company maintains its principal offices at 214 W. Texas, Suite 1101,
Midland, Texas pursuant to a month to month lease.
5
Title to Oil and Gas PropertiesTITLE TO OIL AND GAS PROPERTIES
The Company believes that its methods of investigating title to its
properties are consistent with practices customary in the oil and gas industry,
and that such practices are adequately designed to enable it to acquire good
title to such properties. The Company's properties may be subject to one or more
royalty, overriding royalty, carried and other similar non-cost bearing
interests and contractual arrangements customary in the industry. Substantially
all of the Company's properties are currently mortgaged under a deed of trust to
secure funding through a revolving line of credit.
ITEM 2. PROPERTIES
Oil and Natural Gas ReservesOIL AND NATURAL GAS RESERVES
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 and Financial Accounting Standards Board. The
estimates as of March 31, 2001, 20002004, 2003 and 19992002 are based on evaluations prepared
7
by Joe C. Neal and Associates, Petroleum Consultants. For information concerning
costs incurred by the Company for oil and gas operations, net revenues from oil
and gas production, estimated future net revenues attributable to the Company's
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 Company emphasizes that reserve estimates are inherently imprecise and
there can be no assurance that the reserves set forth below will be ultimately
realized. 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 Company oil and gas reserves, which in turn may adversely affect the
Company's cash flow, results of operations and the availability of capital
resources.
In estimatingaccordance with applicable financial accounting and reporting standards
of the SEC, the estimates of our proved reserves and the present value of proved
reserves set forth herein are made using oil and gas sales prices estimated to
be in affect as of March 31, 2001, averagethe date of such reserve estimates and are held constant
throughout the life of the properties. Actual future prices and costs may be
materially higher or lower than those as of $24.42 per
barrel forthe date of the estimate. The timing
of both the production and the expenses with respect to the development and
production of oil and $5.43 per mcf (thousand cubic feet) for gas were used, which
wereproperties will affect the average actual prices in effect for the Company's production.timing of future net cash
flows from proved reserves and their present value.
The Company has not filed any other oil or gas reserve estimates or
included any such estimates in reports to any other federal or foreign governmental
authority or agency within the pastlast twelve months.
The estimated proved oil and gas reserves and present value of estimated
future net revenues from proved oil and gas reserves for the Company in the
periods ended March 31 are summarized below.
PROVED RESERVES
March 31,
---------------------------------------
2001 2000 1999
----------- ----------- -----------
Oil (Bbls):
Proved developed - Producing 145,954 138,839 193,970
Proved developed - Non-producing 88,700 -- --
Proved undeveloped -- -- --
----------- ----------- -----------
Total 234,654 138,839 193,970
=========== =========== ===========
Natural gas (Mcf):
Proved developed - Producing 4,447,379 4,165,396 3,182,342
Proved developed - Non-producing 1,889,833 589,951 1,011,971
Proved undeveloped 8,234 -- --
----------- ----------- -----------
Total 6,345,446 4,755,347 4,194,313
=========== =========== ===========
Present value of estimated future
net revenues before income taxes $15,988,820 $ 6,144,644 $ 3,485,196
=========== =========== ===========
March 31,
-----------------------------------------------------
2004 2003 2002
-------------- -------------- -------------
Oil (Bbls):
Proved developed - Producing 75,455 93,199 143,003
Proved developed - Non-producing 1,386 1,386 1,404
Proved undeveloped 55,613 55,564 92,900
------------- ------------- -------------
Total 132,454 150,149 237,307
============= ============= =============
Natural gas (Mcf):
Proved developed - Producing 3,207,186 3,451,880 3,822,715
Proved developed - Non-producing 1,067,010 1,065,902 1,336,190
Proved undeveloped 3,643,116 3,413,846 5,023,328
------------- ------------- -------------
Total 7,917,312 7,931,628 10,182,233
============= ============= =============
Present value of estimated future
net revenues before income taxes $19,127,440 $20,772,830 $11,925,260
============= ============= =============
The preceding tables should be read in connection with the following
definitions:
6
Proved Reserves.PROVED RESERVES. Estimated quantities of oil and gas, based on geologic and
engineering data, appear with reasonable certainty to be economically
recoverable in future years from known reservoirs under existing economic
and operating conditions.
Proved Developed Reserves.8
PROVED DEVELOPED RESERVES. Proved oil and gas reserves expected to be
recovered through existing wells with existing equipment and operating
methods. Developed reserves include both producing and non-producing
reserves. Producing reserves are those reserves expected to be recovered
from existing completion intervals producing as of the date of the reserve
report. Non-producing reserves are currently shut-in awaiting a pipeline
connection or in reservoirs behind the casing or at minor depths above or
below the producing zone and are considered recoverable by production
either from wells in the field, by successful drill-stem tests, or by core
analysis. Non-producing reserves require only moderate expense for
recovery.
Proved Undeveloped Reserves.PROVED UNDEVELOPED RESERVES. Proved oil and gas reserves expected to be
recovered from additional wells yet to be drilled or from existing wells
where a relatively major expenditure is required for completion.
Productive wells and acreagePRODUCTIVE 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 the Company's productive wells as of March 31, 2001:2004:
Gross Net
----- ---
Oil........................................ 1,321 14
Gas........................................ 405 12
----- Oil ............................................ 1,259 12
Gas ............................................ 220 7
----- ---------
Total Productive Wells ..................... 1,479 19Wells................. 1,726 26
===== =========
Undeveloped acreage includes leased acres on which wells have not been
drilled or completed to a point that would permit the production of commercial
quantities of oil and gas, regardless of whether or not such acreage contains
proved reserves. 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. As of March 31, 2001 the only2004 material undeveloped acreage owned by
the Company owned was approximately 4,28311,350 gross and 5433,699 net acres which is in the state
of Texas.Texas
and North Dakota.
The following table sets forth the approximate developed acreage in which
the Company held a leasehold mineral or other interest at March 31, 2001.2004.
Developed Acres
----------------------------------------------
Gross Net
------- -------
Texas ............................ 84,691 2,465---------------------
Texas......................................... 122,178 4,831
New Mexico ....................... 16,554 145Mexico.................................... 18,034 150
North Dakota ..................... 23,999 18
Louisiana ........................ 21,961 28
Oklahoma ......................... 36,162 123
Montana .......................... 7,189 4
Kansas ...........................Dakota.................................. 26,159 24
Louisiana..................................... 25,879 31
Oklahoma...................................... 39,122 168
Montana....................................... 9,788 5
Kansas........................................ 7,240 21
Wyoming .......................... 1,798Wyoming....................................... 2,338 4
Colorado ......................... 1,040Colorado...................................... 1,200 1
Alabama ..........................Arkansas...................................... 320 1
Arkansas ......................... 320 ---
------- -------
Total ............................ 201,274 2,810-----
Total......................................... 252,258 5,235
======= =======
7=====
9
Drilling ActivitiesDRILLING ACTIVITIES
The following table sets forth the drilling activity of the Company for the
years ended March 31, 2001, 20002004, 2003 and 1999.2002.
Years ended March 31,
------------------------------------------
2001 2000 1999
------------ ------------ ---------------------------------------------------------------------
2004 2003 2002
--------------- --------------- ---------------
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ----- ----- --------
Exploratory Wells
Productive 1 .08 19 .03 2 .01 - -2 .01
Nonproductive 2 .48 - - - -
----- ----- ----- ----- ----- -----.30 1 .07 1 .09
--- ---- --- ---- --- ----
Total 11 .33 3 .56 1 .01 - -
===== ===== ===== ===== ===== =====.08 3 .10
=== ==== === ==== === ====
Development Wells
Productive 112 .02 1 .60 8 1.9010 .17 12 .13
Nonproductive - - - - - -
----- ----- ----- ----- ----- ------- -- -- -- -- --
--- ---- --- ---- --- ----
Total 112 .02 1 .60 8 1.90
===== ===== ===== ===== ===== =====
Net Production, Unit Prices10 .17 12 .13
=== ==== === ==== === ====
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
Coststhe amount of oil and gas that may ultimately be recovered by the company.
NET PRODUCTION, UNIT PRICES AND COSTS
The following table summarizes the net oil and natural gas production for
the Company, the average sales price per barrel of oil and per mcfthousand cubic
feet ("mcf") of natural gas produced and the average production (lifting) cost
per unit of production for the years ended March 31, 2001, 20002004, 2003 and 1999.
Year Ended March 31,
------------------------------------
2001 2000 1999
---------- ---------- ----------
Oil (a):
Production (Bbls) 18,545 19,334 49,573
Revenue $ 531,751 $ 416,405 $ 600,285
Average Bbls per day 51 53 136
Average sales price per Bbl $ 28.67 $ 21.54 $ 12.11
Gas (b):
Production (Mcf) 503,773 540,793 482,948
Revenue $2,560,459 $1,262,556 $ 903,338
Average Mcf per day 1,380 1,478 1,323
Average sales price per Mcf $ 5.08 $ 2.33 $ 1.87
Production cost:
Production cost $ 526,032 $ 542,789 $ 644,563
Equivalent Bbls (c) 102,507 109,466 130,064
Production cost per equivalent Bbl $ 5.13 $ 4.96 $ 4.96
Production cost per sales dollar $ 0.17 $ 0.32 $ 0.43
Total oil and gas revenues $3,092,210 $1,678,961 $1,503,6232002.
Year Ended March 31,
------------------------------------------
2004 2003 2002
------------- ------------ ------------
Oil (a):
Production (Bbls) 20,278 23,391 21,139
Revenue $ 588,089 $ 640,685 $ 456,108
Average Bbls per day 56 64 58
Average sales price per Bbl $ 29.00 $ 27.39 $ 21.58
Gas (b):
Production (Mcf) 487,564 538,787 467,013
Revenue $ 2,321,864 $ 2,041,074 $ 1,312,452
Average Mcf per day 1,336 1,476 1,279
Average sales price per Mcf $ 4.76 $ 3.79 $ 2.81
Production cost:
Production cost $ 942,093 $ 848,513 $ 648,820
Equivalent Mcf (c) 609,232 679,133 593,847
Production cost per equivalent Mcf $ 1.55 $ 1.25 $ 1.09
Production cost per sales dollar $ 0.32 $ 0.32 $ 0.37
Total oil and gas revenues $ 2,909,953 $ 2,681,759 $ 1,768,560
(a) Includes condensate.
(b) Includes natural gas products.
(c) GasOil production is converted to equivalent bblsmcf at the rate of 6 mcf per
bbl,barrel ("bbl"), representing the estimated relative energy content of
natural gas to oil.
ITEM 3. LEGAL PROCEEDINGS
The Company is a plaintiff in two class action lawsuits against gas
purchasersThere are no pending or threatened legal proceedings involving contract price disputes. The Company does not expect any
expenses of a material nature to arise from these class action claims. While
recoveries from these lawsuits could be substantial, the ultimate outcome is
uncertain.Company.
10
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during the
fourth quarter ended March 31, 2001.
8
Executive Officers of the Registrant2004.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table sets forth certain information concerning the executive
officers of the Company as of March 31, 2001.2004.
Name Age Position
- ------------------ ---------------------- ----- ---------------------------------------------
Nicholas C. Taylor 6366 President and Chief Executive Officer
Donna Gail Yanko 5759 Vice President and Corporate Secretary
Linda J. Crass 46Tamala L. McComic 35 Vice President, Treasurer, Controller and AssistantAsst Secretary
Set forth below is a description of the backgrounds of each executive
officer of the Company, including employment history for at least the last five
years.
Nicholas C. Taylor was elected President, Treasurer and Director of the
Company in April 1983 and continues to serve as President and Director on a part
time basis, as required. Mr. Taylor served as Treasurer until March 1999. From
July 1993 to the present, Mr. Taylor has been involved in the independent
practice of law and other business activities. For more than the prior 19 years,
he was a director and shareholder of the law firm of Stubbeman, McRae, Sealy,
Laughlin & Browder, Inc., Midland, Texas, and a partner of the predecessor firm.
In 1995 he was appointed by the Governor of Texas and served as Chairman ofto the
three member State Securities Board
through January 2001. In addition to serving as chairman for four years, he
continued to serve as a member until 2004.
Donna Gail Yanko worked as part-time administrative assistant to the Chief
Executive Officer and as Assistant Secretary of the Company until June 1992 when
she was appointed Corporate Secretary. Mrs. Yanko was appointed to the position
of Vice President and elected to the Boardboard of Directorsdirectors of the Company in 1990.
Linda J. Crass has beenTamala L. McComic became Controller for the Company sincein July 1998.2001. She was
appointed Assistant Secretary of the Company in August 19982001 and Treasurer in
March 1999.September 2001. From 19961994 to 1998 Ms. Crass2001 Mrs. McComic was employed by Titan Exploration,Regional Controller and
Credit Manager for Transit Mix Concrete & Materials Company, a subsidiary of
Trinity Industries, Inc. in various accounting positions. From 1989In May 2003, Mrs. McComic was appointed Vice President,
Chief Financial Officer and continues to 1996, Ms. Crass was Controller for
Midland Resources, Inc.serve as Treasurer and Assistant
Secretary.
PART II
-------
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
TheIn September 2003, the Company's common stock isbegan trading on the American
Stock Exchange under the symbol "MXC". Prior to September 2003, the Company's
common stock was traded on the over-the-counter market bulletin board under the
symbol MEXC."MEXC". The registrar and transfer agent is Computershare Investor Services,Trust Company,
Inc., P.O. Box 1596, Denver, Colorado, 80201 (Tel: 303-984-4100)303-262-0600). As of March
31, 20012004 the Company had 1,402approximately 1,400 shareholders of record and
1,610,1331,766,566 shares outstanding.issued.
11
PRICE RANGE OF COMMON STOCK
Bid Price
-------------------------
High Low
------- -------
2001:---- ---
2004:
April - June 2003 (1) $ 7.75 $ 4.00
July - September 5, 2003(1) 7.00 6.50
September 5 - 30, 2003 (2) 7.90 7.50
October - December 2003 (2) 8.50 7.85
January - March 2004 (2) 8.50 7.55
2003: (1)
April - June 2000 4 7/8 4 3/82002 6.00 3.80
July - September 2000 4 9/16 4 1/22002 6.00 2.50
October - December 2000 6 3/8 4 9/162002 3.00 2.25
January - March 2001 6 3/4 3 1/2
2000:(1)
April - June 1999 7 11/16 7 5/8
July - September 1999 7 1/2 5 1/2
October - December 1999 5 1/2 5
January - March 2000 5 4 7/82003 4.80 2.85
(1) Reflects high and low bid information received from Pink Sheets LLC,
formerly National Quotation Bureau, LLC.
(2) These bid quotations represent
prices between dealers, without retail markup, markdown or commissions, and
do not reflect actual transactions.
(3)(2) Reflects the high and low sales prices for the Company's Common Stock, as
reported on the American Stock Exchange.
On May 22, 2001,June 24, 2004, the bidclosing price was $4.00.
9
$6.80.
DIVIDENDS
On February 1, 2002 the Company's board of directors declared a stock dividend
consisting of shares of par value $0.50 common stock of the Company in the
amount of ten percent (10%) of the outstanding shares, or 1 share for each 10
shares held by all stockholders of record of the Company as of February 15,
2002, with any resulting fractional share dividends to be rounded up or down to
the nearest whole number of shares and issued the stock dividend accordingly.
The payable date for this dividend was February 28, 2002 and resulted in an
additional 160,566 shares of stock issued and outstanding.
The Company has notnever paid any cash dividends on its Common Stock, and the board
of directors does not currently anticipate paying any cash dividends to the
common stock, and it isstockholders in the present policyforeseeable future. In addition, under the terms of
the Company not to do so, but to retain its earnings for
future growth and business activities. Thecurrent loan agreement the Company is also subject to certain
loan covenants including restrictions on payment of dividends.dividends
payments.
ITEM 6. SELECTED FINANCIAL DATA
Years Ended March 31,
----------------------------------------------------------------------------------------------------------------------------------------------------
2004 2003 2002 2001 2000
1999 1998 1997
----------------------------------------------------------------------------------------------------------------------------------------------------
Statement of Operations:
Operating revenues $ 2,915,355 $ 2,949,113 $ 1,778,583 $ 3,099,966 $ 1,686,266
$ 1,510,005 $ 2,106,338 $ 1,458,741
Operating income (loss)785,739 926,277 252,101 1,881,776 498,384 (281,099) (1,558,335) 521,123
Other income (expense) (82,766) (95,357) (54,706) (92,160) (104,737)
(144,675) (134,891) (5,621)
Net income (loss)$ 429,846 $ 672,808 $ 189,291 $ 1,539,458 $ 393,647
$ (425,774) $(1,323,657) $ 377,867
Net income (loss) per share - basic (1)(2) $ 0.950.25 $ 0.240.39 $ (0.26)0.11 $ (0.83)0.86 $ 0.270.22
Net Income (loss)income per share - diluted $ 0.95(1)(2) $ 0.24 $ (0.26)0.39 $ (0.83)0.11 $ 0.270.86 $ 0.22
Weighted average shares
outstanding - basic 1,622,568 1,623,289 1,623,289 1,594,752 1,423,229(1) 1,736,047 1,741,462 1,768,314 1,784,825 1,785,618
Weighted average shares
outstanding - diluted 1,625,003 1,623,289 1,623,289 1,594,752 1,423,229(1) 1,802,300 1,746,831 1,768,579 1,787,503 1,785,618
Balance Sheet:
Property and equipment, net $ 7,647,284 $ 7,028,659 $ 5,895,429 $ 4,009,852 $ 3,459,522 $ 3,749,400 $ 4,078,053 $ 4,777,132
Total assets 8,172,464 7,688,638 6,347,965 4,961,360 3,853,319 4,043,015 4,542,486 5,109,199
Total debt 1,700,000 2,150,000 1,710,000 600,000 1,200,000 1,784,000 1,822,000 1,637,000
Stockholders' equity $ 5,435,219 $ 4,956,388 $ 4,276,042 $ 4,046,452 $ 2,567,228 $ 2,173,581 $ 2,599,355 $ 2,923,012
Cash Flow:
Cash provided by operations $ 1,903,3451,517,479 $ 722,0881,369,690 $ 532,171899,977 $ 1,118,5661,903,345 $ 866,931
EBITDA(1) $ 2,263,376 $ 927,326 $ 635,260 $ 1,252,539 $ 1,006,119
(1) EBITDA (as used herein) represents earnings before interest expense, income
taxes, depreciation, depletion and amortization. Management of the Company
believes that EBITDA may provide additional information about the Company's
ability to meet its future requirements for debt service, capital
expenditures and working capital. EBITDA is a financial measure commonly
used in the oil and gas industry and should not be considered in isolation
or as a substitute for net income, operating income, cash flows from
operating activities or any other measure of financial performance
presented in accordance with generally accepted accounting principles or as
a measure of the Company's profitability or liquidity.
722,088
12
(1) Amounts have been adjusted to reflect the 10% stock dividend effected on
February 1, 2002.
(2) Year 2004 includes a cumulative effect of change in accounting principle
(Cumulative Effect) loss of $0.06 related to the adoption of Statement of
Financial Accounting Standards (SFAS) No. 143, Asset Retirement
Obligations.
ITEM 7.6A. SELECTED QUARTERLY FINANCIAL DATA
FISCAL 2001
-----------------------------------------
4TH QTR 3RD QTR 2ND QTR 1ST QTR
-------- -------- -------- --------
Net sales $989,050 $798,110 $712,243 $592,807
Gross profit (loss) $839,481 $662,781 $562,402 $501,514
Net income (loss) $495,205 $408,516 $357,301 $278,436
Net income (loss) per share-basic $ 0.31 $ 0.25 $ 0.22 $ 0.17
Net income (loss) per share-diluted $ 0.31 $ 0.25 $ 0.22 $ 0.17
FISCAL 2000
-----------------------------------------
4TH QTR 3RD QTR 2ND QTR 1ST QTR
-------- -------- -------- --------
Net sales $513,576 $429,744 $403,139 $332,502
Gross profit (loss) $389,465 $314,517 $274,797 $157,393
Net income (loss) $191,010 $146,041 $ 92,519 $(35,923)
Net income (loss) per share-basic $ 0.11 $ 0.09 $ 0.06 $ (0.02)
Net income (loss) per share-diluted $ 0.11 $ 0.09 $ 0.06 $ (0.02)
FISCAL 2004
-------------------------------------------------------------------
4TH QTR 3RD QTR 2ND QTR 1ST QTR
---------------- --------------- ---------------- --------------
Net sales $ 723,258 $ 650,783 $ 768,852 $ 767,060
Gross profit $ 528,920 $ 412,888 $ 527,684 $ 498,368
Net income before cumulative effect $ 204,628 $ 57,255 $ 118,470 $ 151,760
Net income per share-basic (2) $ 0.12 $ 0.03 $ 0.07 $ 0.03
Net income per share-diluted (2) $ 0.12 $ 0.03 $ 0.06 $ 0.03
FISCAL 2003
-------------------------------------------------------------------
4TH QTR 3RD QTR 2ND QTR 1ST QTR
---------------- --------------- ---------------- --------------
Net sales $ 956,890 $ 668,039 $ 512,180 $ 544,650
Gross profit $ 730,662 $ 434,963 $ 279,575 $ 388,046
Net income $ 336,588 $ 238,718 $ 20,356 $ 77,146
Net income per share-basic(1) $ 0.19 $ 0.14 $ 0.01 $ 0.04
Net income per share-diluted(1) $ 0.19 $ 0.14 $ 0.01 $ 0.04
(1) Amounts have been adjusted to reflect the 10% stock dividend effected
on February 1, 2002.
(2) First quarter of fiscal 2004 includes a cumulative effect of change in
accounting principle (Cumulative Effect) loss of $0.06 related to the
adoption of Statement of Financial Accounting Standards (SFAS) No.
143, Asset Retirement Obligations.
ITEM 8.7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following information should be read in conjunction with the
information contained in the Consolidated Financial Statements and the notes
thereto included in Item 10 of this report.
10
Liquidity and Capital Resources and CommitmentsLIQUIDITY AND CAPITAL RESOURCES AND COMMITMENTS
Historically, the Company has funded its operations, acquisitions,
exploration and development expenditures from cash generated by operating
activities, bank borrowings and issuance of common stock.
In fiscal 2001,2004, the Company primarily used cash provided by operations
($1,903,345)1,517,479) and borrowings on the line of credit ($320,000) to fund oil and gas
property acquisitions and development ($936,293), repayments982,872). The Company had a working
capital deficit of bank debt ($600,000) and increased working capital.
Working capital$15,506 as of March 31, 2001 was $822,095.
In fiscal 2001, the board2004 due primarily to current portion
of directors authorized the purchase of up to
25,000 shares of the Company's common stock, and the Company repurchased 13,160
shares, at an aggregate cost of $84,934.long term debt.
For fiscal 2002, the board of directors
has authorized the use of up to
$250,000 to repurchase shares of the Company's common stock. No shares have been repurchased to date during fiscal 2002.
During fiscal 2000,year
2002, the Company repurchased 22,533 shares, at an aggregate cost of $91,231. Of
such shares, 18,400 shares were reissued in exchange for oil and gas lease
rights representing 368 net acres valued at approximately $83,000. The remaining
4,133 shares were cancelled. In fiscal 2003, the board of directors once again
authorized the use of up to $250,000 to repurchase shares of the Company's
common stock. During fiscal year 2003, the Company repurchased 30,244 shares, at
an aggregate cost of $127,536 for the treasury account. During fiscal 2004, the
Company repurchased 281 shares, at an aggregate cost of $1,389 for the treasury
account.
13
In December, 2002, the Company entered into a participation agreement with
Falcon Bay Exploration, LLC exercising its right to purchase at an aggregate
cash price of $597,301, the acreage and seismic data on the first of four such
prospects referred to in the exploration agreement relating to non-producing acreagebetween the Company and
Falcon Bay Exploration, LLC. This information is contained in PecosForm 8-K filed by
the Company on December 6, 2002.
During fiscal year 2004, the Company purchased a one-quarter interest in
leases and/or options on leases in Stark County, Texas. Approximately 3,795North Dakota covering 4920
gross acres for approximately $107,000. A director and 432 net acres have been leased andemployee of Mexco Energy
Corporation, will receive a 3-D seismic survey covering
23 square miles has been completed at a cost to the Company of approximately
$155,000. Two test1.5% ORRI on any wells were drilled on this acreage.
The first test well will
be completed as a producer at a cost toDuring fiscal year 2004, the Company ofpurchased partially developed royalty
interests in Jackson Parish, Louisiana for approximately $80,000. The second test well has been drilled, pluggedThese
properties, operated by Anadarko Petroleum Corporation in the Lower Cotton
Valley formation, currently contain 11 producing wells and abandoned at a cost toan additional 2
permitted and/or drilling wells.
In March 2004 the Company of approximately $44,000. Pending further evaluation of the information
gathered from these wells,purchased additional wells may be drilled on these prospects.
The Company owns approximate workingpartially developed royalty
interests in these prospects ranging from
10.41% to 15.51%Jackson Parish, Louisiana and a third party conducts operations.
Effective September 1, 2000, the Company acquired three producing
properties in Pecos County, Texas for $198,000 cash, adjusted for revenues and
expenses through September 28, 2000, the date of closing. The Company owns
working interests ranging from 97% to 99% and, as operator of the six producing
wells on these properties, is evaluating the workover, recompletion and re-entry
potential of these properties. Operating cash flow from these properties was
approximately $88,000 for the six months ended March 31, 2001. In January and
again in May 2001, workovers were performed on two of these producing wells,
increasing production at a total cost to the Company of approximately $60,000.
Effective September 1, 2000, the Company leased 159 gross non-producing
acres in Pecos County, Texas, in which it retained a 98% working interest, at a
cost of approximately $27,500. The Company plans to re-enter an abandoned well
on this acreage as soon as a rig becomes available at an estimated cost of
$60,000.
On September 5, 2000, the Company acquired a 50% working interest in
approximately 107 gross non-producing acres in Coke County, Texas for
approximately $10,000. The recompletion of the well on this acreage, which began
on January 31, 2001, was unsuccessful and the well has been abandoned, at a cost
to the Company to date of approximately $34,400.
On October 31, 2000, the Company acquired a 12.5% working interest in 400
gross non-producing acres in Nolan County, Texas for $11,750. An oil well was
completed on this acreage in May 2001 at a cost to the Company of approximately
$73,000. Drilling costs of $43,167 were prepaid in December 2000. An additional
well may be drilled on this acreage pending the results of the first well.
11
Effective December 1, 2000, the Company acquired a 1.345% royalty interest
in proved acreage in Limestone County, Texas
for cashapproximately $224,000. The properties in Limestone County, operated by XTO
Energy, Inc., are in the Cotton Valley formation and contain 23 producing wells
and an additional 6 permitted and/or drilling wells. This acreage contains
approximately 100 potential undrilled locations on 40 acre spacing. The property
in Louisiana, operated by Anadarko and producing from the Lower Cotton Valley
formation, contains 3 producing wells and an additional 5 permitted and/or
drilling wells. These royalty purchases advanced the Company's primary goal of
$33,000. A replacement
well was successfully completed on this acreage in February 2001.
Effective January 1, 2001,acquiring natural gas reserves.
In March 2004, the Company acquired royalty interests totaling
0.209%signed an agreement in producing acreageMoscow, Russia to begin a
preliminary feasibility study for exploration and development of natural gas
reserves in Ward County, Texas for $65,760. There are
presently two producingRussia. A team of U.S. and Russia experts commenced a feasibility
study of a number of undeveloped natural gas wells on this acreage.
On April 30, 2001, the Company acquired a 0.0164% royalty interest in a
producing gas unit containing 9,538 acres in Reagan and Upton Counties for
$12,500.
In April 2001, the Company acquired additional joint venture interests in
propertiesfields located in various countiesthe vicinity of
Gasprom pipelines which serve Russia. Mexco Energy Corporation has set up OBTX
LLC, a Delaware limited liability company, in which Mexco owns a 90% interest
with the remaining 10% interest split equally among three individuals, one of
which is Arden Grover, a director of Mexco Energy Corporation. OBTX, LLC, plans
to participate in any Russian ventures entered into and states for $174,000, adjusted for
revenues and expenses from January 1, 2001, the effective date, through April
29, 2001, date of closing.
In May 2001, the Company acquiredown a 12.5% working interest and 9.375% net
revenue interest in 8,934 acres in Edwards County, Texas for $125,000. The
initial test well to be drilled on this acreage will commence drilling as soon
as a rig is available. Estimated drilling costs to the Company of $85,667 were
prepaid in May 2001 and completion costs are estimated at $39,300.
In June 2001, the Company assumed operations and acquired an approximate
88.35% working interest and 62.7285% net revenue interest in a producing gas
well in Hutchinson County, Texas for $36,860, adjusted for revenues and expenses
from April 1, 2001, the effective date. The Company also acquired non-operated
working interests, ranging from .8512% to 3.75% with net revenue interests
ranging from .6816% to 3.267%, in 21 producing and 7 inactive wells in Limestone
and Freestone Counties, Texas for $200,000, adjusted for revenues and expenses
from April 1, 2001, the effective date.50% interest.
The Company is reviewing several other projects in which it 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 discussed below.
The Company hasfacility. See Note B of Notes to
Consolidated Financial Statements for a description of the Company's revolving
credit agreement with Bank of America, N.A.
("Bank"), which provides for a credit facility of $3,000,000, subject to a
borrowing base determination. Effective September 15, 2000, the borrowing base
was increased to $2,500,000, with scheduled monthly reductions of the available
borrowing base of $32,000 per month beginning October 5, 2000, and the maturity
date was extended to August 15, 2002. As of March 31, 2001, debt outstanding
under this agreement was $600,000 and the borrowing base was $2,308,000. No
required principal payments are anticipated for the next twelve months. A letter
of credit for $50,000, in lieu of a plugging bond with the Texas Railroad
Commission covering the properties the Company operates, is also outstanding
under the facility. The borrowing base is subject to redetermination on or about
August 1, of each year. Amounts borrowed under this agreement are collateralized
by the common stock of Forman and the Company's oil and gas properties. Interest
under this agreement is payable monthly at prime rate (9% and 8% at March 31,
2000 and 2001, respectively). This agreement generally restricts the Company's
ability to transfer assets or control of the Company, incur debt, extend credit,
change the nature of the Company's business, substantially change management
personnel or pay dividends.
12
Crude oil and natural gas prices have fluctuated significantly in recent
years as well as in recent months. Fluctuations in price have a significant
impact on the Company's financial condition and liquidity. A shortage of
available workover rigs in recent months has impeded the Company's ability to
increase or sustain production on a number of properties in a timely manner.
However, management
believes the Company can maintain adequate liquidity for the next fiscal year.
Results of Operations
Fiscal 2001 Compared to Fiscal 2000RESULTS OF OPERATIONS
FISCAL 2004 COMPARED TO FISCAL 2003
Oil and gas sales increased from $1,678,961$2,681,759 in 20002003 to $3,092,210$2,909,953 in 2001,2004,
an increase of $1,413,249$228,194 or 84%9%. This increase was primarily attributable to thean increase in
oil and gas prices during the year, offset in part by decreased
production.year. The average oil price increased from $21.54 in 2000 to $28.67$27.39
14
per bbl in 2001,2003 to $29.00 per bbl in 2004, an increase of $7.13$1.61 per bbl or 33%6%.
The average gas price increased from $2.33$3.79 in 20002003 to $5.08$4.76 per mcf in 2001,2004, an
increase of $2.75$.97 per mcf or 118%26%. Oil production decreased from 19,33423,391 bbls in
20002003 to 18,54520,279 bbls in 2001,2004, a decrease of 7893,112 bbls or 4%13%. Gas production
decreased from 540,793538,787 mcf in 20002003 to 503,773487,564 mcf in 2001,2004, a decrease of 37,02051,223
mcf or 7%10%. Production costsSuch decreases primarily were due to normal decline in production.
Other income decreased from $542,789$267,354 in 20002003 to $526,032$5,402 in 2001,2004, a decrease
of $16,757$261,952. This decrease is the result of the proceeds received ($254,862)
from the settlement of a class action lawsuit against a gas purchaser involving
contract price disputes in fiscal 2003.
Production costs increased from $848,513 in 2003 to $942,093 in 2004, an
increase of $93,580 or 3%11%. This is primarily attributable to an increased
number of repairs on operated properties during the year.
Depreciation, depletion and amortization decreased from $426,102$641,827 in 20002003 to
$377,761$633,443 in 2001,2004, a decrease of $48,341$8,384 or 11%1%, due primarily to increased
reserves attributable to higher gas prices and property acquisitions.a decrease in
production. There was no impairment of oil and gas properties in fiscal 20002003 or
2001.2004.
General and administrative expenses decreased from $532,496 in 2003 to
$529,834 in 2004, a decrease of $2,662 or 0.5%. This decrease was primarily
attributable to the decreased cost of consulting expenses during the year.
Interest expense decreased from $96,337 in 2003 to $83,530 in 2004, a
decrease of $12,807 or 13%. This decrease was attributable to decreased
borrowings during the current fiscal year.
FISCAL 2003 COMPARED TO FISCAL 2002
Oil and gas sales increased from $1,768,560 in 2002 to $2,681,759 in 2003,
an increase of $913,199 or 52%. This increase was attributable to both an
increase in production and an increase in oil and gas prices during the year.
The average oil price increased from $21.58 per bbl in 2002 to $27.39 per bbl in
2003, an increase of $5.81 per bbl or 27%. The average gas price increased from
$2.81 in 2002 to $3.79 per mcf in 2003, an increase of $.98 per mcf or 35%. Oil
production increased from 21,139 bbls in 2002 to 23,391 bbls in 2003, an
increase of 2,252 bbls or 11%. Gas production increased from 467,013 mcf in 2002
to 538,787 mcf in 2003, an increase of 71,774 mcf or 15%.
Other income increased from $10,023 in 2002 to $267,354 in 2003, an
increase of $257,331. This increase is the result of the proceeds received
($254,862) from the settlement of a class action lawsuit against a gas purchaser
involving contract price disputes.
Production costs increased from $648,820 in 2002 to $848,513 in 2003, an
increase of $199,633 or 31%. This is primarily attributable to an increased
number of repairs on operated properties during the year.
Depreciation, depletion and amortization increased from $448,422 in 2002 to
$641,827 in 2003, an increase of $193,405 or 43%, due primarily to the downward
revisions of proved undeveloped reserves in the El Cinco Field. There was no
impairment of oil and gas properties in fiscal 2002 or 2003.
General and administrative expenses increased from $218,991$429,240 in 20002002 to
$314,397$532,496 in 2001,2003, an increase of $95,406$103,256 or 44%24%. This increase was primarily
attributable to the increased salariescost of consulting expenses relating to the
settlement of the lawsuit which was settled during the fiscal year ($101,945)
and benefits ($40,700),an increase in compensation related to stock options granted to consultants
($24,700), engineering and geological
costs ($15,100), franchise taxes ($4,900) and a bad debt ($5,000)12,792).
15
Interest expense decreasedincreased from $107,577$57,161 in 20002002 to $95,999$96,337 in 2001,2003, an
increase of $11,578$39,176 or 11%. This decrease was primarily attributable to a
reduction in amounts borrowed during 2001.
Fiscal 2000 Compared to Fiscal 1999
Oil and gas sales increased from $1,503,623 in 1999 to $1,678,961 in 2000,
an increase of $175,338 or 12%69%. This increase was attributable to additional
borrowings during the current fiscal year.
ALTERNATIVE CAPITAL RESOURCES
Although the Company primarily due to increased oilhas used cash from operating activities and
gas prices and increased productionfunding from the acquisitionline of credit as its primary capital resources, the Company
has in the past, and development of
gas properties, offsetcould in part bythe future, use alternative capital resources.
These could include the sale of assets and/or issuances of common stock through
a public offering. The Company could also obtain funds through a private
placement.
CONTRACTUAL OBLIGATIONS
The Company has no off-balance sheet debt or unrecorded obligations and has
not guaranteed the Lazy JL propertiesdebt of any other party. The following table summarizes the
Company's future payments it is obligated to make based on agreements in place
as of March 31, 2004:
Payments Due In:
-------------------------------------------------------
Total one year 1-3 years 3 year
---------- -------- ---------- ------
Contractual obligations:
Secured bank line of credit $1,700,000 $443,378 $1,256,622 --
These amounts represent the balances outstanding under the bank line of
credit. These repayments assume that interest will be paid on a monthly basis
and normal
production declines. The sale of the Lazy JL properties accounted for a decrease
for fiscal 2000 as compared to fiscal 1999 of $335,532 in oil and gas sales,
26,673 bbls and 4,345 mcf. The average oil price increased from $12.11 in 1999
to $21.54 per bbl in 2000, an increase of $9.43 per bbl or 78%. The average gas
price increased from $1.87 in 1999 to $2.33 per mcf in 2000, an increase of
$0.46 per mcf or 25%. Oil production decreased from 49,573 bbls in 1999 to
19,334 bbls in 2000, a decrease of 30,239 bbls or 61%. Gas production increased
from 482,948 mcf in 1999 to 540,793 mcf in 2000, an increase of 57,845 mcf or
12%.
Production costs decreased from $644,563 in 1999 to $542,789 in 2000, a
decrease of $101,774 or 16%. The sale of the Lazy JL properties accounted for a
reduction in production costs for fiscal 2000 as compared to fiscal 1999 of
$238,072, while property acquisitions and development, and remedial repairs
increased production costs.
13
Depreciation, depletion and amortization decreased from $909,965 in 1999 to
$426,102 in 2000, a decrease of $483,863 or 53%, due primarily to an impairment
of oil and gas properties in the first quarter of fiscal 1999 of $288,393.
General and administrative expenses decreased from $236,576 in 1999 to
$218,991 in 2000, a decrease of $17,585 or 7%.
Interest expense decreased from $151,069 in 1999 to $107,577 in 2000, a
decrease of $43,492 or 29%. This decrease was primarily attributable to a
reduction in amounts borrowed during 2000.
Other Matters
Forward Looking Statementsthat no additional funds will be drawn.
OTHER MATTERS
FORWARD LOOKING STATEMENTS
Certain statements in this Form 10-K may be deemed to be "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"). All statements, other than statements
of historical facts, included in this Form 10-K that address activities, events
or developments that the Company expects, projects, believes or anticipates will
or may occur in the future, including such matters as oil and gas reserves,
future drilling and operations, future production of oil and gas, future net
cash flows, future capital expenditures and other such matters, are
forward-looking statements. These statements are based on certain assumptions
and analysis made by management of the Company in light of its experience and
its perception of historical trends, current conditions, expected future
developments and other factors it believes are appropriate in the circumstances.
Such statements are subject to a number of assumptions, risks and uncertainties,
including general economic and business conditions, prices of oil and gas, the
business opportunities (or lack thereof) that may be presented to and pursued by
the Company, changes in laws or regulations and other factors, many of which are
beyond the control of the Company.
CRITICAL ACCOUNTING POLICIES
The preparation of financial statements in conformity with generally
accepted accounting principles requires that management apply accounting
policies and make estimates and assumptions that affect results of operations
and the reported amounts of assets and liabilities in the financial statements.
16
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. The Company
has chosen to follow the full cost method under which all costs associated with
property acquisition, exploration and development are capitalized. The Company
also capitalizes 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. 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 the
Company's financial statements will differ from companies that apply the
successful efforts method since the Company will generally reflect a higher
level of capitalized costs as well as a higher depreciation, depletion and
amortization rate on Company 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 the Company
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. The Company's
crude oil and natural gas reserves have a relatively long life. However,
temporary drops in commodity prices can have a material impact on Company
business including impact from the full cost method of accounting.
Under 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 crude oil and natural gas properties
exceed the ceiling limit, the Company must charge the amount of the excess to
earnings. This is called a "ceiling limitation write-down." This charge does not
impact cash flow from operating activities, but does reduce the Company
stockholders' equity and reported earnings. The risk that the Company 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 the Company experiences
substantial downward adjustments to its 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.
17
Estimates of the Company's proved reserves included in this report are
prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve
estimate is a function of:
o the quality and quantity of available data;
o the interpretation of that data;
o the accuracy of various mandated economic assumptions;
o and the judgment of the persons preparing the estimate.
The Company's proved reserve information included in this Report was based
on evaluations prepared by independent petroleum engineers. 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 the Company's estimated proved reserves. In
accordance with SEC requirements, the Company based the estimated discounted
future net cash flows from proved reserves on prices and costs on the date of
the estimate. Actual future prices and costs may be materially higher or lower
than the prices and costs as of the date of the estimate.
The estimates of proved reserves materially impact DD&A expense. If the
estimates of proved reserves decline, the rate at which the Company records 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 cost fields.
Use of Estimates. The preparation of consolidated financial statements in
conformity with accounting principles generally accepted in the United States of
America requires management to make estimates and assumptions that affect the
reported amounts of assets and liabilities and disclosure of contingent assets
and liabilities at the date of the consolidated financial statements and the
reported amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates. Management believes that it is
reasonably possible that estimates of proved crude oil and natural gas revenues
could significantly change in the future.
Revenue Recognition. The Company recognizes crude oil and natural gas revenue
from its interest in producing wells as crude oil and natural gas is sold from
those wells, net of royalties. The Company utilizes the sales method to account
for gas production volume imbalances. Under this method, income is recorded
based on the Company's net revenue interest in production taken for delivery.
The Company had no material gas imbalances.
Asset Retirement Obligations. The estimated costs of 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.
18
If the liability is settled for an amount other than the recorded amount, a gain
or loss is recognized. For all periods presented, the Company has included
estimated future costs of abandonment and dismantlement in the full cost
amortization base and amortize these costs as a component of the Company's
depletion expense.
ITEM 9.7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Risk FactorsRISK FACTORS
All of the Company's financial instruments are for purposes other than
trading. Interest Rate Risk.At March 31, 2004, the Company had not entered into any hedge
arrangements, commodity swap agreements, commodity futures, options or other
similar agreements relating to crude oil and natural gas.
INTEREST RATE RISK. The following table summarizes maturities for the Company's variable rate bank debt which is tied to prime
rate. If the interest rate on the Company's bank debt increases or decreases by
one percentage point, the Company's annual pretax income would change by
$6,000.
Year ended March 31,
----------------------------------
2001 2002 2003
-------- -------- --------
Variable rate bank debt $ -- $ -- $600,000
Credit Risk.$17,000.
CREDIT RISK. Credit risk is the risk of loss as a result of nonperformance
by counter-parties of their contractual obligations. The Company's primary
credit risk is related to oil and gas production sold to various purchasers and
the receivables are generally not collateralized. At March 31, 2001,2004 the
Company's largest credit risk associated with any single purchaser was $95,110.$116,008.
The Company has not experienced any significant credit losses.
14
Volatility of Oil and Gas Prices.VOLATILITY OF OIL AND GAS PRICES. The Company's revenues, operating results
and future rate of growth are dependent upon the prices received for oil and
gas. These market prices tend to fluctuate significantly in response to factors
beyond the Company's control. The prices the Company receives for its crude oil
production are based on global market conditions. The continued terror threats
in the Middle East, the continuing political crisis in Venezuela (a major oil
exporter), and actions of OPEC and its maintenance of production constraints, as
well as other economic, political, and environment factors will continue to
affect world supply. Natural gas prices fluctuate significantly in response to
numerous factors including the U.S. economic environment, North American weather
patterns, other factors affecting demand such as substitute fuels, the impact of
drilling levels on natural gas supply, and the environmental and access issues
that limit future drilling activities for the industry. Historically, the
markets for oil and gas have been volatile and are likely to continue to be so
in the future. Various factors beyond the control of the Company affect the
price of oil and gas, including but not limited to worldwide and domestic
supplies of oil and gas, the ability of the members of the Organization of
Petroleum Exporting Countries to agree to and maintain oil price and production
controls, political instability or armed conflict in oil-producing regions, the
price and level of foreign imports, the level of consumer demand, the price and
availability of alternative fuels, the availability of pipeline capacity,
weather conditions, domestic and foreign governmental regulation and the overall
economic environment. Any significant decline in prices would adversely affect
the Company's revenues and operating income and may require a reduction in the
carrying value of the Company's oil and gas properties. If the average oil price
had increased or decreased by one cent per barrel for fiscal 2001,2004, the Company's
pretax income would have changed by $185.$203. If the average gas price had increased
or decreased by one cent per mcf for fiscal 2001,2004, the Company's pretax income
would have changed by $5,038.
Uncertainty of Reserve Information and Future Net Revenue Estimates.$4,876.
19
UNCERTAINTY OF RESERVE INFORMATION AND FUTURE NET REVENUE ESTIMATES.
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. Moreover, there can be no assurance that the Company's reserves
will ultimately be produced or that any undeveloped reserves will be developed.
Reserve Replacement Risk.As required by the SEC, the estimated discounted future net cash flows from
proved reserves are generally based on prices and costs as of the date of the
estimate, while actual future prices and costs may be materially higher or
lower.
RESERVE REPLACEMENT RISK. The Company's future success depends upon its
ability to find, develop or acquire additional, economically recoverable oil and
gas reserves. The proved reserves of the Company will generally decline as
reserves are depleted, except to the extent the Company can find, develop or
acquire replacement reserves. DrillingOne 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 Operating Risks.gas reserves are becoming harder to
find. Reserves to be produced from undiscovered reservoirs appear to be smaller,
and the risks to find these reserves are greater. Reports from the Energy
Information Administration indicate that on-shore domestic finding costs are on
the rise, and that the average reserves added per well are declining.
DRILLING AND OPERATING RISKS. Drilling and operating activities are subject
to many risks, including availability or lack thereof, 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, anyrisks.
Any of whichthese operating hazards could result in substantial losses to the
Company. In addition, the Company incurs the risk that no commercially
productive reservoirs will be encountered and there is no assurance that the
Company will recover all or any portion of its investment in wells drilled or
re-entered.
Marketability of Production.MARKETABILITY OF PRODUCTION. The marketability of the Company's 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 the Company's ability to produce and market its oil and gas.
ITEM 10.8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent CertifiedRegistered Public Accountants....................... 16Accounting Firm................ 21
Consolidated Balance Sheets.............................................. 17Sheets............................................ 22
Consolidated Statements of Operations.................................... 18Operations.................................. 23
Consolidated Statements of Changes in Stockholders' Equity.......................... 19Equity............. 24
Consolidated Statements of Cash Flows.................................... 20Flows.................................. 25
Notes to Consolidated Financial Statements............................... 21
15Statements............................. 26
20
Report of Independent Certified Public AccountantsREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
-------------------------------------------------------
Board of Directors and Shareholders
Mexco Energy Corporation
We have audited the accompanying consolidated balance sheets of Mexco Energy
Corporation and Subsidiary as of March 31, 20012004 and 2000,2003 and the related
consolidated statements of operations, stockholders' equity and cash flows for
each of the three years in the period ended March 31, 2001.2004. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditingthe standards generally accepted
inof the United States of America.Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the consolidated financial position of Mexco Energy
Corporation and Subsidiary as of March 31, 20012004 and 2000,2003, and the consolidated results of
their operations and their consolidated cash flows for each of the three years in the period
ended March 31, 20012004, in conformity with accounting principles generally
accepted in the United States of America.
As discussed in Note D to the financial statements, effective April 1, 2003, the
Company adopted Statement of Financial Accounting Standards No. 143, Accounting
for Asset Retirement Obligations, and changed its method of accounting for asset
retirement obligations.
GRANT THORNTON LLP
Oklahoma City, Oklahoma
May 11, 2001
1623, 2004
21
Mexco Energy Corporation and SubsidiaryMEXCO ENERGY CORPORATION AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
As of March 31,
2001 2000
------------ ------------
ASSETS
Current assets
Cash and cash equivalents $ 378,816 $ 97,712
Accounts receivable:
Oil and gas sales 489,217 255,121
Trade 1,074 2,070
Related parties 8,059 18,105
Other -- 5,000
Prepaid costs and expenses 74,342 15,789
------------ ------------
Total current assets 951,508 393,797
Property and equipment, at cost
Oil and gas properties, using
the full cost method 11,557,980 10,630,903
Other 23,600 22,586
------------ ------------
11,581,580 10,653,489
Less accumulated depreciation,
depletion, and amortization 7,571,728 7,193,967
------------ ------------
Property and equipment, net 4,009,852 3,459,522
------------ ------------
$ 4,961,360 $ 3,853,319
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable - trade $ 77,776 $ 86,091
Income taxes payable 51,637 --
------------ ------------
Total current liabilities 129,413 86,091
Long-term debt 600,000 1,200,000
Deferred income tax liability 185,495 --
Stockholders' equity
Preferred stock - $1.00 par value;
10,000,000 shares authorized -- --
Common stock - $0.50 par value;
40,000,000 shares authorized;
1,621,387 and 1,623,289 shares
issued at March 31, 2001 and
2000, respectively 810,693 811,644
Additional paid-in capital 2,900,097 2,875,399
Retained earnings (accumulated deficit) 407,254 (1,119,815)
Treasury stock, at cost (71,592) --
------------ ------------
Total stockholders' equity 4,046,452 2,567,228
------------ ------------
$ 4,961,360 $ 3,853,319
============ ============
ASSETS 2004 2003
---------- ----------
Current assets
Cash and cash equivalents $ 92,795 $ 68,547
Accounts receivable:
Oil and gas sales 396,902 560,297
Trade 3,101 17,617
Related parties -- 3,475
Prepaid costs and expenses 32,382 10,043
---------- ----------
Total current assets 525,180 659,979
Property and equipment, at cost
Oil and gas properties, using
the full cost method ($858,602 and $673,690
excluded from amortization in 2004 and 2003,
respectively) 16,959,560 15,656,928
Other 34,542 33,708
---------- ----------
16,994,102 15,690,636
Less accumulated depreciation,
depletion, and amortization 9,346,818 8,661,977
---------- ----------
Property and equipment, net 7,647,284 7,028,659
---------- ----------
$8,172,464 $7,688,638
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable - trade $ 97,308 $ 93,434
Lease obligation payable -- 61,086
Current portion of long-term debt 443,378 116,280
---------- ----------
Total current liabilities 540,686 270,800
Long-term debt 1,256,622 2,033,720
Asset retirement obligation 420,665 --
Deferred income tax liability 519,272 427,730
Commitments and contingencies (Notes B, E, G and H) -- --
Stockholders' equity
Preferred stock - $1.00 par value;
10,000,000 shares authorized;
none outstanding -- --
Common stock - $0.50 par value;
40,000,000 shares authorized;
1,766,566 shares issued 883,283 883,283
Additional paid-in capital 3,784,493 3,734,119
Retained earnings 896,368 466,522
Treasury stock, at cost (128,925) (127,536)
---------- ----------
Total stockholders' equity 5,435,219 4,956,388
---------- ----------
$8,172,464 $7,688,638
========== ==========
The accompanying notes to the consolidated financial statements
are an integral part of these statements.
1722
Mexco Energy Corporation and SubsidiaryMEXCO ENERGY CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF OPERATIONS
Year ended March 31,
2001 2000 1999
----------- ----------- ------------
Operating revenues:
Oil and gas $ 3,092,210 $ 1,678,961 $ 1,503,623
Other 7,756 7,305 6,382
----------- ----------- -----------
Total operating revenues 3,099,966 1,686,266 1,510,005
Operating expenses:
Production 526,032 542,789 644,563
Depreciation, depletion
and amortization 377,761 426,102 909,965
General and administrative 314,397 218,991 236,576
----------- ----------- -----------
Total operating expenses 1,218,190 1,187,882 1,791,104
----------- ----------- -----------
1,881,776 498,384 (281,099)
Other income (expense):
Interest income 3,839 2,840 6,394
Interest expense (95,999) (107,577) (151,069)
----------- ----------- -----------
Net other expense (92,160) (104,737) (144,675)
----------- ----------- -----------
Earnings (loss) before income taxes 1,789,616 393,647 (425,774)
Income tax expense:
Current 64,663 -- --
Deferred 185,495 -- --
----------- ----------- -----------
250,158 -- --
----------- ----------- -----------
Net earnings (loss) $ 1,539,458 $ 393,647 $ (425,774)
=========== =========== ===========
Net earnings (loss) per share:
Basic $ 0.95 $ 0.24 $ (0.26)
Diluted $ 0.95 $ 0.24 $ (0.26)
Weighted average outstanding shares:
Basic 1,622,568 1,623,289 1,623,289
Diluted 1,625,003 1,623,289 1,623,289
2004 2003 2002
----------- ----------- -----------
Operating revenues:
Oil and gas $ 2,909,953 $ 2,681,759 $ 1,768,560
Other 5,402 267,354 10,023
----------- ----------- -----------
Total operating revenues 2,915,355 2,949,113 1,778,583
Operating expenses:
Production 942,093 848,513 648,820
Accretion of asset retirement obligation 24,246 -- --
Depreciation, depletion,
and amortization 633,443 641,827 448,422
General and administrative 529,834 532,496 429,240
----------- ----------- -----------
Total operating expenses 2,129,616 2,022,836 1,526,482
----------- ----------- -----------
785,739 926,277 252,101
Other income (expense):
Interest income 764 981 2,455
Interest expense (83,530) (96,337) (57,161)
----------- ----------- -----------
Net other expense (82,766) (95,356) (54,706)
----------- ----------- -----------
Earnings before income taxes and
cumulative effect of accounting change 702,973 830,921 197,395
Income tax expense:
Current 33,371 (13,026) (62,992)
Deferred 137,489 171,139 71,096
----------- ----------- -----------
170,860 158,113 8,104
----------- ----------- -----------
Income before cumulative effect
of accounting change 532,113 672,808 189,291
Cumulative effect of accounting
change, net of tax (102,267) -- --
----------- ----------- -----------
Net income $ 429,846 $ 672,808 $ 189,291
=========== =========== ===========
Net income per common share:
Basic:
Income before cumulative effect
of accounting change $ 0.31 $ 0.39 $ 0.11
Cumulative effect, net of tax $ (0.06) $ -- $ --
Net income $ 0.25 $ 0.39 $ 0.11
Diluted:
Income before cumulative effect
of accounting change $ 0.30 $ 0.39 $ 0.11
Cumulative effect, net of tax $ (0.06) $ -- $ --
Net income $ 0.24 $ 0.39 $ 0.11
Pro forma amounts assuming, the new
method of accounting for asset retirement
obligations is applied retroactively:
Net income $ 532,113 $ 651,669 $ 170,780
Basic net income per share $ 0.31 $ 0.37 $ 0.10
Diluted net income per share $ 0.30 $ 0.37 $ 0.10
The accompanying notes to the consolidated financial statements
are an integral part of these statements.
1823
MEXCO ENERGY CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
Year ended March 31,
2001 2000 1999
----------- ----------- -----------
Common stock issued:
Balance at beginning of year $ 811,644 $ 811,644 $ 811,644
Issuance of 4 shares 2 -- --
Retirement of 1906 shares (953) -- --
----------- ----------- -----------
Balance at end of year:
1,623,289 shares at March 31, 1999
1,623,289 shares at March 31, 2000
1,621,387 shares at March 31, 2001 $ 810,693 $ 811,644 $ 811,644
Additional paid-in capital:
Balance at beginning of year $ 2,875,399 $ 2,875,399 $ 2,875,399
Stock-based compensation 24,700 -- --
Issuance of 4 shares (2) -- --
----------- ----------- -----------
Balance at end of year $ 2,900,097 $ 2,875,399 $ 2,875,399
Retained earnings (accumulated deficit):
Balance at beginning of year $(1,119,815) $(1,513,462) $(1,087,688)
Retirement of 1906 shares (12,389) -- --
Net earnings (loss) 1,539,458 393,647 (425,774)
----------- ----------- -----------
Balance at end of year $ 407,254 $(1,119,815) $(1,513,462)
Treasury stock:
Balance at beginning of year $ -- $ -- $ --
Purchases of 11,254 shares (71,592) -- --
----------- ----------- -----------
Balance at end of year:
11,254 shares at March 31, 2001 $ (71,592) $ -- $ --
----------- ----------- -----------
Total shareholders' equity $ 4,046,452 $ 2,567,228 $ 2,173,581
=========== =========== ===========
Retained
Common Stock Additional Earnings
Stockholders' Treasury Paid-In (Accumulated Total
Par Value Stock Capital Deficit) Equity
------------- -------- ---------- ------------ ----------
Balance, April 1, 2001 $ 810,693 $ (71,592) $2,900,097 $ 407,254 $4,046,452
Net earnings -- -- -- 189,291 189,291
10% stock dividend 80,283 -- 722,548 (802,831) --
Purchase of stock -- (91,231) -- -- (91,231)
Issuance of stock
for property -- 72,576 10,224 -- 82,800
Retirement of stock (7,693) 90,247 (82,554) -- --
Stock based
compensation -- -- 48,730 -- 48,730
------------- -------- ---------- ------------ ----------
Balance, March 31, 2002 883,283 -- 3,599,045 (206,286) 4,276,042
Net earnings -- -- -- 672,808 672,808
Purchase of stock -- (127,536) -- -- (127,536)
Issuance of warrants
for acreage -- -- 73,552 -- 73,552
Stock based
compensation -- -- 61,522 -- 61,522
------------- -------- ---------- ------------ ----------
Balance, March 31, 2003 883,283 (127,536) 3,734,119 466,522 4,956,388
Net earnings -- -- -- 429,846 429,846
Purchase of stock -- (1,389) -- -- (1,389)
Profits from sale of stock
by insider -- -- 2,950 -- 2,950
Stock based
compensation -- -- 47,424 -- 47,424
------------- -------- ---------- ------------ ----------
Balance, March 31, 2004 $ 883,283 $(128,925) $3,784,493 $ 896,368 $5,435,219
============= ========== ========== ============ ==========
Share Activity
2004 2003 2002
---------- ------------ ----------
Common stock issued
At beginning of year 1,766,566 1,766,566 1,621,387
Issued -- -- 160,566
Cancelled -- -- (15,387)
---------- ------------ ----------
At end of year 1,766,566 1,766,566 1,766,566
Held in treasury
At beginning of year (30,244) -- (11,254)
Acquisitions (281) (30,244) (22,533)
Issued for property -- -- 18,400
Cancellation, returned to
unissued -- -- 15,387
---------- ------------ ----------
At end of year (30,525) (30,244) --
---------- ------------ ----------
Common shares outstanding at end
of year 1,736,041 1,736,322 1,766,566
========== ============ ==========
The accompanying notes to the consolidated financial statements
are an integral part of these statements.
1924
MEXCO ENERGY CORPORATION AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended March 31,
2001 2000 1999
-----------2004 2003 2002
Cash flows from operating activities: ---------- ----------- -----------
Cash flows from operating activities:
Net earnings (loss) $ 1,539,458429,846 $ 393,647672,808 $ (425,774)189,291
Cumulative effect of accounting change 102,267 -- --
Adjustments to reconcile net earnings
(loss)income
to net cash provided by operating
activities:
DeferredIncrease in deferred income taxes 185,495 -- --137,489 171,139 71,096
Stock-based compensation 24,700 -- --47,424 61,522 48,730
Depreciation, depletion, and amortization 377,761 426,102 909,965633,443 641,827 448,422
Accretion of asset retirement obligations 24,246 -- --
(Increase) decrease in accounts receivable (218,054) (97,247) 24,851181,386 (193,089) 114,896
(Increase) decrease in prepaid expenses (22,340) 14,080 50,215
Decrease in income taxes payable -- -- (51,637)
Increase (decrease) in accounts payable
901 1,007 22,312
(Increase) decrease in prepaid assets (58,553) (1,421) 817
Increase in income taxes payable 51,637 -- --
----------- ----------- -----------and accrued expenses (16,282) 1,403 28,964
Net cash provided by operating activities 1,903,345 722,088 532,1711,517,479 1,369,690 899,977
Cash flows from investing activities:
Additions to oil and gas properties (936,293) (803,554) (643,377)
Proceeds from sale of assets -- 667,692 5,678(982,872) (1,628,695) (2,247,423)
Additions to other property and equipment (1,014) (712) (1,622)
----------- ----------- -----------(834) (4,927) (5,181)
Net cash used in investing activities (937,307) (136,574) (639,321)(983,706) (1,633,622) (2,252,604)
Cash flows from financing activities:
BorrowingsAcquisition of treasury stock (1,389) (127,536) (91,231)
Profits from sale of stock by insider 2,950 -- 248,174 --
Principal payments onReduction of capital lease obligations (61,086) (24,943) --
Reduction of long-term debt (600,000) (832,174) (38,000)
Purchases and retirements of common stock (84,934) -- --
----------- ----------- -----------(770,000) (470,000) (50,000)
Proceeds from long term debt 320,000 910,000 1,160,000
Net cash used in(used in) provided by
financing activities (684,934) (584,000) (38,000)
----------- ----------- -----------(509,525) 287,521 1,018,769
Net increase (decrease) in cash
and cash equivalents 281,104 1,514 (145,150)24,248 23,589 (333,858)
Cash and cash equivalents
at beginning of year 97,712 96,198 241,348
----------- ----------- -----------68,547 44,958 378,816
Cash and cash equivalents
at end of year $ 378,81692,795 $ 97,71268,547 $ 96,198
=========== =========== ===========44,958
Interest paid $ 99,04483,196 $ 109,25594,792 $ 138,58655,022
Income taxes paid (recovered) $ 50,000 $ (117,056) $ 92,675
Supplemental Disclosure of Non-cash investing
and financing activities:
Issuance of common stock in exchange
for oil and gas properties $ -- $ -- $ 82,800
Fair value of warrants issued for
oil and gas properties $ --
The accompanying notes to the consolidated financial statements
are an integral part$ 73,552 $ --
Acquisition of these statements.
equipment under capital leases $ -- $ 81,182 $ --
20The accompanying notes to the consolidated financial statements
are an integral part of these statements.
25
Mexco Energy Corporation and Subsidiary
Notes to Consolidated Financial Statements
NOTE A - NATURE OF OPERATIONS AND SIGNIFICANT ACCOUNTING POLICIES
NATURE OF OPERATIONS
Mexco Energy Corporation and its wholly-ownedwholly owned subsidiary, Forman Energy
Corporation (collectively, the "Company") are engaged in the acquisition,
exploration, development, and production of domestic oil and gas and owns
producing properties and undeveloped acreage in eleven11 states. The majority of the
Company's activities are centered in West Texas. Although most of the Company's
oil and gas interests are operated by others, the Company operates several
properties in which it owns an interest.
SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation. The consolidated financial statements include the
accounts of Mexco Energy Corporation and its wholly-ownedwholly owned subsidiary. All
significant inter-companyintercompany balances and transactions have been eliminated in
consolidation.
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 its cash in bank deposit
accounts and money market funds, some of which are not federally insured. The
Company has not experienced any losses in such accounts and believes it is not
exposed to any significant credit risk.
Oil and Gas Properties. Oil and gas properties are accounted for using the full
cost method of accounting. Under this method, all costs associated with the
acquisition, exploration, and development of properties (successful or not),
including leasehold acquisition costs, geological and geophysical costs, lease
rentals, exploratory and developmental drilling, and equipment costs, are
capitalized. CostsAll capitalized costs of oil and gas properties (excluding certain
unevaluated property costs), including the estimated future costs to develop
proved reserves, are amortized usingon the units-of-productionunit-of-production method based uponusing estimates
of proved oil and gas reserves. If unamortized costs, less related deferred income taxes,
exceed the sum of the present value, discounted at 10%, of estimated future net
revenues from proved reserves, less related income tax effects, the excess is
charged to expense. Generally, no gains or losses are recognized on the sale or
disposition of oil and gas properties.
Asset Retirement Obligations ("ARO"). 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 Statement 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 its ARO to determine the fair value. Inherent in the present value
26
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.
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 five to ten years.
21
Earnings (Loss)Income Per Common Share. Basic earnings (loss)income per share is computed by dividing net
earnings (loss)income by the weighted average number of shares outstanding during the period.
Diluted earnings (loss)income per share is computed by dividing net earnings (loss)income by the weighted
average number of common shares and dilutive potential common shares (stock
options)options and warrants) 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. The
following is a reconciliation of the number of shares used in the calculation of
basic earningsincome per share and diluted earningsincome per share for the periodperiods ended March
31, 2001.31:
2004 2003 2002
--------- --------- ---------
Weighted average number
of common shares
outstanding, 1,622,568basic 1,736,047 1,741,462 1,768,314
Incremental shares from
the assumed exercise of
dilutive stock options 2,43566,253 5,369 265
--------- --------- ---------
Dilutive potential common
shares 1,625,0031,802,300 1,746,831 1,768,579
========= ========= =========
Outstanding options and warrants to purchase 90,00010,000, 388,500 and 180,000200,000 shares
at March 31, 19992004, 2003, and 2000,2002, respectively, were not included in the
computation of diluted net earnings per share because the exercise price of the
options or warrants was greater than the average market price of the common
shares and, therefore, the effect would be anti-dilutive.
Stock Dividend. On February 1, 2002, the Company declared a 10% stock dividend
to shareholders of record on February 15, 2002. On February 28, 2002, the
Company issued 160,566 shares of common stock in conjunction with this dividend.
Accordingly, amounts equal to the fair market value of the additional shares
issued have been charged to retained earnings and credited to common stock and
additional paid-in capital. All references in the consolidated financial
statements to weighted average number of shares and earnings per common share
amounts have been adjusted to reflect the stock dividend on a retroactive basis.
Income Taxes. The Company recognizes deferred tax assets and liabilities for the
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.
27
Environmental. The Company is subject to extensive federal, state, and local
environmental laws and regulations. These laws, which are constantly changing,
regulate the discharge of materials into the environment and may require the
Company to remove or mitigate the environmental effects of the disposal or
release of petroleum or chemical substances at various sites. Environmental
expenditures are expensed or capitalized depending on their future economic
benefit. Liabilities for expenditures of a non-capital nature are recorded when
environmental assessment and/or remediation is probable and the costs can be
reasonably estimated. There were no significant environmental expenditures or
liabilities for the years ended March 31, 2001, 20002004, 2003, or 1999.2002.
Use of Estimates. In preparing financial statements in conformity with
accounting principles generally accepted accounting principles,in the United States of America,
management is required to make estimates and assumptions that affect the amounts
reported in the these financial statements. Although Managementmanagement believes its
estimates and assumptions are reasonable, actual results may differ materially
from those estimates. Significant estimates affecting these financial statements
include the estimated quantities of proved oil and gas reserves, and the related
present value of estimated future net cash flows.
22
flows and the future development,
dismantlement and abandonment costs.
Revenue Recognition and Gas Balancing. Oil and gas sales and resulting
receivables are recognized when the product is transporteddelivered 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; therefore, an allowance for uncollectible accounts is not required.
Gas imbalances are accounted for under the sales method whereby revenues are
recognized based on production sold. A liability is recorded when the Company's
excess takes of natural gas volumes exceed its 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 has no significant gas imbalances.
Stock Options.Options and Warrants. The Company accounts for employee stock option
grants in accordance with Accounting Principles Board ("APB") Opinion No. 25,
"Accounting for Stock Issued to Employees," as amended by the Financial Accounting
Standards Board ("FASB") Interpretation No. 44, "Accounting for Certain
Transactions involving Stock Compensation"Compensation," an interpretation of APB Opinion No.
25. The Company applies the intrinsic value method in accounting for its
employee stock options and records no compensation costs for its stock option
awards to employees. The Company recognizes compensation cost related to stock
options awarded to independent consultants based on fair value of the options at
date of grant.
If compensation cost for the Company's stock option plan had been determined
based on the fair value at the grant dates for all employee awards under the
plan, net income, basic income per common share, and diluted income per common
share would have been as follows:
2004 2003 2002
---- ---- ----
Net income, as reported $ 429,846 $ 672,808 $ 189,291
Deduct: Stock-based employee
compensation expense determined
under fair value based method
(SFAS 123), net of tax $ (86,070) $ (63,133) $ (50,066)
---------- ---------- -----------
Net income, pro forma $ 343,776 $ 609,675 $ 139,225
========== ========== ==========
Basic income per share:
As reported (1) $ 0.25 $ 0.39 $ 0.11
Pro forma (1) $ 0.20 $ 0.35 $ 0.08
Diluted income per share:
As reported (1) $ 0.24 $ 0.39 $ 0.11
Pro forma (1) $ 0.19 $ 0.35 $ 0.08
28
(1) Amounts have been adjusted to reflect the 10% stock dividend effected
on February 1, 2002.
Financial Instruments. Cash and money market funds, stated at cost, are
available upon demand and approximate fair value. Interest rates associated with
the Company's long-term debt are linked to current market rates. As a result,
management believes that the carrying amount approximates the fair value of the
Company's credit facilities. All financial instruments are held for purposes
other than trading.
NOTE B - DEBT
The Company has a revolving credit agreement with Bank of America, N.A.
("Bank"), which provides for a credit facility of $3,000,000,$5,000,000, subject to a
borrowing base determination. Effective SeptemberOn December 15, 2000,2003 the credit agreement was
amended with a maturity date of August 15, 2005. The borrowing base was
increased to $2,500,000,redetermined on this date and set at $1,938,372 with scheduled monthly commitment
reductions of the available borrowing base of $32,000 per month$45,450 beginning Octoberon January 5, 2000, and the maturity date was extended to August 15, 2002.2004. As of March 31, 2001, debt2004, the
balance outstanding under this agreement was $600,000 and
the borrowing base was $2,308,000. No required principal$1,700,000. Principal payments of
$443,378 are anticipated to be required for fiscal 2005 to comply with the
next twelve months.monthly commitment reductions. A letter of credit for $50,000, in lieu of a
plugging bond with the Texas Railroad Commission covering the properties the
Company operates, is also outstanding under the facility. The borrowing base is
subject to redetermination on or about August 1, of each year. Amounts borrowed
under this agreement are collateralized by the common stock of Forman and the
Company's oil and gas properties. Interest under this agreement is payable
monthly at prime rate (9%(4.00% and 8%4.25% at March 31, 20002004 and 2001,2003,
respectively). This agreement generally restricts the Company's ability to
transfer assets or control of the Company, incur debt, extend credit, change the
nature of the Company's business, substantially change management personnel, or
pay cash dividends.
23
NOTE C - OTHER INCOME
During the third quarter of fiscal 2003 the Company received proceeds of
$254,862, before expenses of $101,945, resulted from the settlement of a class
action lawsuit against a gas purchaser involving contract price disputes.
NOTE D - ASSET RETIREMENT OBLIGATIONS
The Company's asset retirement obligations relate to the plugging and
abandonment of oil and gas properties. The Company adopted SFAS No. 143 on April
1, 2003. SFAS No. 143 requires the fair value of a liability for an asset
retirement obligation to be recorded in the period in which it is incurred and a
corresponding increase in the carrying amount of the related long-lived asset.
The change resulted in a cumulative effect charge to net income of ($102,267)
net of tax, or ($0.06) per share. Additionally, the Company recorded an asset
retirement obligation liability of $358,419 and an increase to net properties
and equipment and other assets of $210,206 upon adoption of SFAS No. 143.
The asset retirement obligation, which is included on the Consolidated Balance
Sheet was $420,665 at March 31, 2004. Accretion expense for fiscal 2004 was
$24,246.
29
The asset retirement obligation was $358,419 and $336,543 for fiscal years
ending March 31, 2003 and 2002, assuming SFAS No. 143 had been adopted as of
April 1, 2001.
The following table provides a rollforward of the asset retirement obligation
for the fiscal year ended March 31, 2004.
Carrying amount of asset retirement obligations as of
April 1, 2003 $358,419
Liabilities incurred 48,321
Liabilities settled (10,321)
Accretion expense 24,246
Revisions in estimated cash flows 0
--------
Carrying amount of asset retirement obligations as of
March 31, 2004 $420,665
========
NOTE E - CAPITAL LEASE OBLIGATIONS
During fiscal 2003, the Company began leasing three gas compressors under
separate agreements that are classified as capital leases. The cost of the
equipment under the capital leases is included in the balance sheet as property
and equipment and was $81,182 on March 31, 2004 and 2003. The accumulated
amortization associated with these leases was $10,726 and $5,796 on March 31,
2004 and 2003, respectively. Amortization of assets under capital leases is
included in depreciation expense. The lease obligation associated with these
three compressors was $61,086 on March 31, 2003. As of March 31, 2004 the
Company has fulfilled its obligation of the lease agreements and received title
to the compressors.
NOTE F - INCOME TAXES
Deferred tax assets valuation allowance, and liabilities are the result of temporary differences
between the financial statement carrying values and the tax bases of assets and
liabilities. Significant components of net deferred tax assets (liabilities) at
March 31 are as follows:
2001 20002004 2003
----------- -----------
Deferred tax assets:---------
Percentage depletion carryforwards $ 258,661442,907 $ 213,365403,344
Vacation accrual 1,108 -2,636 1,334
Deferred compensation 56,536 41,835
Asset retirement obligation 130,406 --
Other 1,777 --
Net operating loss carryforwards - 224,713
Valuation allowance - (196,469)-- 43,927
----------- -----------
259,769 241,609---------
634,262 490,440
Deferred tax liabilities:
Excess financial accounting bases over
tax bases of property and equipment (445,264) (241,609)(1,153,534) (918,170)
----------- --------------------
Net deferred tax assets (liabilities)liabilities $ (185,495) $ -(519,272) $(427,730)
=========== ===========
Increase (decrease) in valuation
allowance for the year $ (196,469) $ (75,349)
=========== ====================
As of March 31, 2001,2004, the Company has statutory depletion carryforwards of
approximately $834,000,$1,428,000, which do not expire.
30
A reconciliation of the provision for income taxes to income taxes computed
using the federal statutory rate for years ended March 31 follows:
2001 2000 1999
--------- ---------2004 2003 2002
---------- ---------- ---------
Tax expense (benefit) at statutory rate $ 608,469239,011 $ 133,840 $(144,763)
Increase (decrease) in valuation allowance (196,469) (75,349) 135,928282,513 $ 67,114
Depletion in excess of basis (80,864) -- --(39,563) (86,170) (58,513)
Effect of graduated rates (53,688) (31,492) 34,062(21,089) (24,928) (5,922)
Revision of prior year estimates -- (13,026) 7,657
Other (27,290) (26,999) (25,227)
--------- ---------(7,499) (276) (2,232)
---------- ---------- ---------
$ 250,158170,860 $ --158,113 $ --
========= =========8,104
========== ========== =========
Effective tax rate 14% -- --
========= =========24% 19% 4%
========== ========== =========
NOTE DG - EXPLORATION AGREEMENT
On December 5, 2002, the Company entered into an exploration agreement with
Falcon Bay Operating, LLC. Pursuant to such agreement, the Company has obtained
the right to purchase and inventory seismic data and acreage in shallow water
areas of Texas and Louisiana. In consideration for the right to obtain four such
prospects, the Company has issued warrants to purchase 107,500 shares of common
stock at an exercise price of $5.00 per share. Such warrants are exercisable for
a period of two years from date of grant. Additional warrants, exercisable at
the same exercise price and exercisable for two years, would be issued covering
322,500 shares upon exercise of the Company's right to participate in a total of
four prospects.
NOTE H - FEASIBILITY STUDY
In March 2004, the Company signed an agreement in Moscow, Russia to begin a
preliminary feasibility study for exploration and development of natural gas
reserves in Russia. A team of U.S. and Russia experts commenced a feasibility
study of a number of undeveloped natural gas fields located in the vicinity of
Gasprom pipelines which serve Russia. The Company has formed OBTX LLC, a
Delaware limited liability company, in which it owns a 90% interest with the
remaining 10% interest split equally among three individuals, one of which is
Arden Grover, a director of the Company. OBTX, LLC, plans to participate in any
Russian ventures entered into and own a 50% interest. The Company's geological
and related costs associated with the feasibility study total $41,596 through
March 31, 2004, which has been capitalized.
NOTE I - MAJOR CUSTOMERS
TheCurrently, the Company operates exclusively within the United States and its
revenues and operating income are derived predominately 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 ability of the Company to sell its oil and gas production.
In fiscal 2001, 20002004, 2003, and 19992002, one purchaser accounted for 39%29%, 35%28%, and 30%24%,
respectively, of revenues. In fiscal 1999, anotherAt March 31, 2004, accounts receivable from the
purchaser accounted
for 25%was approximately 29% of revenues.
24accrued oil and gas sales.
31
NOTE EJ - OIL AND GAS COSTS
The costs related to the oil and gas activities of the Company were incurred as
follows:
Year ended March 31,
-----------------------------------------
2001 2000 1999
----------- ----------- ---------------------------------------------------
2004 2003 2002
---------- ---------- ----------
Property acquisition costs
Proved $ 470,223339,519 $ 334,61164,090 $ 207,325649,021
Unproved U.S. $ 184,912 $ 673,690 $ 280,745
Unproved Russia $ 41,596 $ -- $ --
Exploration costs $ 4,757 $ 55,543 $ 46,907
Development costs $ 466,070453,684 $ 468,943 $ 436,052990,106 $1,353,553
The Russian costs in 2004 were for the feasibility study referred to in Note H
to the Company's financial statements.
The Company had the following aggregate capitalized costs relating to the
Company's oil and gas property activities at March 31:
2001 2000 19992004 2003 2002
----------- ----------- -----------
Proved oil and gas properties $11,309,873 $10,531,259 $10,331,594$15,758,031 $14,596,072 $13,462,406
Unproved oil and gas properties 248,107 99,644 163,797properties:
subject to amortization 342,927 387,166 424,392
not subject to amortization-U.S. 817,006 673,690 --
not subject to amortization-Russia 41,596 -- --
----------- ----------- -----------
11,557,980 10,630,903 10,495,39116,959,560 15,656,928 13,886,798
Less accumulated depreciation,
depletion, and amortization 7,555,356 7,181,648 6,759,4169,320,174 8,637,902 7,999,539
----------- ----------- -----------
$ 4,002,6247,639,386 $ 3,449,2557,019,026 $ 3,735,9755,887,259
=========== =========== ===========
On April 21, 1999, the Company sold allThe cost of itscertain oil and gas interestsleases that the Company has acquired, but not
evaluated have been excluded in Lazy JL field properties located in Garza County, Texas for $600,000
cash, adjusted for revenues and expenses fromcomputing amortization of the effective date of
February 1, 1999 through the date of closing. The sales proceeds were used
to reduce the Company's outstanding debt under its line of credit with Bank
of America.
Depreciation, depletion, and amortization expense included a full cost ceiling write-down of $288,393pool.
The Company will begin to amortize these properties when the projects are
evaluated, which is currently estimated to be within the following year. Costs
excluded from amortization at March 31, 2004 total $858,602. No impairment
exists for the first quarter of fiscal 1999 due to
declines in oil and gas prices and the related downward adjustment of
estimated reserves.these properties at March 31, 2004 based on geological studies.
Depreciation, depletion, and amortization amounted to $3.65, $3.86$6.24, $5.64 and $6.97$4.49 per
equivalent barrel of production for the years ended March 31, 2001, 20002004, 2003, and
1999,2002, respectively.
NOTE FK - STOCKHOLDERS' EQUITY
In fiscal 2001, the board of directors authorized the purchase of up
to 25,000 shares of the Company's common stock. For fiscal 2002, the board of directors has authorized the use of up to $250,000 to
repurchase shares of the Company's common stock. During fiscal 2001,2002, the Company
repurchased 13,16022,533 shares, at an aggregate cost of $84,934.
25$91,231. Of such shares,
18,400 were reissued in exchange for oil and gas lease rights representing 368
net acres valued at $83,000. The remaining 4,133 shares along with the 11,254
shares of stock held in the treasury account from fiscal year ending March 31,
2001 were cancelled. On February 28, 2002, the Company distributed 160,566
shares of common stock in connection with a 10% stock dividend. As a result of
the stock dividend, par value of outstanding common stock was increased by
32
$80,283, additional paid-in capital was increased by $722,548, and retained
earnings was decreased by $802,831. In fiscal 2003, the board of directors
authorized the use of up to $250,000 to repurchase shares of the Company's
common stock. During fiscal 2003, the Company repurchased 30,244 shares at an
aggregate cost of $127,536 for the treasury account. For the fiscal 2004, the
board of directors repurchased 281 shares at an aggregate cost of $1,389 for the
treasury account.
During the last quarter of fiscal 2004, the Chairman of the board paid the
Company $2,950, representing profits on stock sold which he held less than six
months. Such payment was made in accordance with Section 16(b) of the Securities
Exchange Act of 1934.
NOTE GL - EMPLOYEE BENEFIT PLANSTOCK OPTIONS AND WARRANTS
The Company adopted an employee incentive stock plan effective September 15,
1997. Under the plan, 350,000 shares are available for distribution. Awards,
granted at the discretion of the compensation committee of the Boardboard of
Directors,directors, include stock options orof restricted stock. 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. Restricted stock awards may be granted with a condition to attain a
specified goal. The purchase price will be at least $5.00 per share of
restricted stock. The awards of restricted stock must be accepted within sixty60 days
and will vest as determined by agreement. Holders of restricted stock have all
rights of a shareholder of the Company.
During fiscal 2001,2004, options for 60,00049,000 shares were granted. Of these, 30,00010,000
options were granted to contract consultants. The exercise price of all options
granted equaled or exceeded the market price of the stock on the date of grant.
Additional information with respect to the Plan's stock option activity for
options issued to employees and directors is as follows:
Weighted
Number Average
of Shares Exercise Price
--------------------- --------------
Options outstanding, at April 1, 2001 170,000 $ 6.49
Granted 20,000 4.00
Exercised -- --
Forfeited (40,000) 6.81
--------- --------------
Options outstanding, at March 31, 1998 - $ -2002 150,000 6.07
Granted 100,000 7.6331,000 4.00
Exercised - --- --
Forfeited (10,000) 7.75
-------------- --
--------- --------------
Options outstanding, at March 31, 1999 90,000 7.612003 181,000 5.71
Granted 90,000 5.2539,000 6.00
Exercised - --- --
Forfeited - -
-------------- --
--------- --------------
Options outstanding, at March 31, 2000 180,000 6.43
Granted 60,000 6.75
Exercised - -
Forfeited - -
------------ --------------
Options outstanding, at March 31, 2001 240,0002004 220,000 $ 6.51
============5.76
========= ==============
Options exercisable at March 31, 1999 -2002 72,500 $ -6.57
Options exercisable at March 31, 2000 22,5002003 110,000 $ 7.616.40
Options exercisable at March 31, 2001 67,5002004 140,250 $ 6.82
266.11
33
Weighted average grant date fair value of stock options granted to employees and
directors during fiscal 2001 was $2.33. Weighted average grant date fair value of stock
options granted during fiscal 20002004, 2003, and 1999 was $2.652002 were $4.82, $3.72 and $4.04,$1.30,
respectively. The value for 2001 wasThese values were determined using a Binomial option-pricing
model. The model while amounts for 1999 and 2000 were determined using
the Black-Scholes option-pricing model. Both models valuevalues options based on the stock price at the grant date, the
expected life of the option, the estimated volatility of the stock, the expected
dividend payments, and the risk-free interest rate over the expected life of the
option. The Company considers the binomial model more accurate than the
Black-Scholes model, in that it recognizes the ability to exercise before
expiration once an option is vested, and began to the use the binomial model in fiscal 2001.vested. The assumptions used in the Black-Scholes and Binomial models
were as follows for stock options granted in fiscal 2001, 20002004, 2003 and 1999:
2001 2000 1999
-------- -------- --------2002:
2004 2003 2002
------- ------- -------
Expected volatility 29.86% 29.40% 27.89%67.46% 134.07% 27.24%
Expected dividend yield 0.00% 0.00% 0.00%
Risk-free rate of return 5.25% 6.43% 5.72%3.40% 5.40% 4.79%
Expected life of options 107 years 107 years 107 years
The option valuation models were developed for use in estimating the fair value
of traded options that have no vesting restrictions and are fully transferable.
In addition, option valuation models require the input of highly subjective
assumptions including expected stock price volatility.
Because the Company's employee stock options have characteristics
significantly different from those of traded options, and because changes
in the subjective input assumptions can materially affect the fair value
estimate, in management's opinion, the existing models do not necessarily
provide a reliable single measure of the fair value of its employee stock
options.
The following tables summarize information about employee and directors stock
options outstanding and exercisable at March 31, 2001:2004:
Stock Options Outstanding
Weighted Average
Number of Remaining Weighted
Range of Shares Contractual Average
Exercise Prices Outstanding Life in Years Exercise Price
--------------- ----------- ---------------- ------------- -----------------------------
$7.50-$7.75 90,000 7.56 $7.6150,000 4.55 $7.60
$6.00 39,000 9.27 $6.00
$6.75 60,000 9.8220,000 6.81 $6.75
$5.25 90,000 8.9760,000 5.97 $5.25
$4.00 51,000 7.87 $4.00
-----------
240,000220,000
Stock Options Exercisable
Number of Weighted
Range of Shares Average
Exercise Prices Exercisable Exercise Price
--------------- ----------------------------- --------------
$7.50-$7.75 45,000 $7.6150,000 $7.60
$6.75 15,000 $6.75
$5.25 22,50060,000 $5.25
27$4.00 15,250 $4.00
34
Since the Company applies the intrinsic value method in accounting for its
employee stock options, it generally records no compensation cost for its stock
option awards to employees. Effective July 1, 2000, theThe Company is required to recognize prospectively compensation costrecognizes expense related to stock
options awarded to independent consultants.consultants and contractors based on fair value
of the options at date of grant. Additional information with respect to stock
option and warrant activity for options and warrants granted to outside
consultants and contractors is as follows:
Weighted
Number Average
of Shares Exercise Price
--------- --------------
Options outstanding, at April 1, 2001 70,000 $ 6.57
Granted 10,000 4.00
Exercised -- --
Forfeited -- --
--------- --------------
Options outstanding, at March 31, 2002 80,000 6.25
Granted 127,500 4.84
Exercised -- --
Forfeited -- --
--------- --------------
Options outstanding, at March 31, 2003 207,500 5.39
Granted 10,000 7.00
Exercised -- --
Forfeited -- --
--------- --------------
Options outstanding, at March 31, 2004 217,500 $ 5.83
========= ==============
Options exercisable at March 31, 2002 32,500 $ 6.69
Options exercisable at March 31, 2003 160,000 $ 5.50
Options exercisable at March 31, 2004 180,000 $ 5.48
Weighted average grant date fair value of stock options and warrants granted to
outside consultants and contractors during fiscal 2004, 2003, and 2002 were
$5.46, $1.16 and $1.26, respectively. These values were determined using a
Binomial option-pricing model. The model values options based on the stock price
at the grant date, the expected life of the option, the estimated volatility of
the stock, the expected dividend payments, and the risk-free interest rate over
the expected life of the option. The assumptions used in the Binomial models
were as follows for stock options granted in fiscal 2004, 2003 and 2002:
2004 2003 2002
------- ------- -------
Expected volatility 62.52% 90.09% 27.23%
Expected dividend yield 0.00% 0.00% 0.00%
Risk-free rate of return 3.81% 2.39% 4.52%
Expected life of options 7 years 3 years 7 years
The option valuation models were developed for use in estimating the fair value
of traded options that have no vesting restrictions and are fully transferable.
In addition, option valuation models require the input of highly subjective
assumptions including expected stock price volatility.
The following tables summarize information about outside consultants and
contractors stock options and warrants outstanding and exercisable at March 31,
2004:
35
Stock Options/Warrants Outstanding
Weighted Average
Number of Remaining Weighted
Range of Shares Contractual Average
Exercise Prices Outstanding Life in Years Exercise Price
--------------- ----------- ---------------- --------------
$7.50-$7.75 20,000 4.46 $7.63
$7.00 10,000 9.64 $7.00
$6.75 30,000 6.81 $6.75
$5.25 20,000 5.97 $5.25
$5.00 107,500 0.68 $5.00
$4.00 30,000 7.96 $4.00
-----------
217,500
Stock Options/Warrants Exercisable
Number of Weighted
Range of Shares Average
Exercise Prices Exercisable Exercise Price
--------------- ----------- --------------
$7.50-$7.75 20,000 $7.63
$6.75 22,500 $6.75
$5.25 20,000 $5.25
$5.00 107,500 $5.00
$4.00 10,000 $4.00
The Company recognizes expense related to stock options awarded to independent
consultants based on fair value of the options at date of grant. Total compensation costexpense
related to these awards recognizedwas $47,424 and $61,522 for fiscal 2001 was $24,700. If compensation
cost for the Company's stock option plan had been determined based on the2004 and 2003,
respectively. The Company capitalizes fair value atof warrants as part of the
grant dates for all employee awards underleasehold cost of the plan, net
earnings (loss), basic earnings (loss) per common share and diluted
earnings (loss) per common share would have been as follows:
2001 2000 1999
---------- ----------- ----------
Net earnings (loss):
As reported $1,539,458 $ 393,647 $ (425,774)
Pro forma $1,424,064 $ 291,027 $ (477,189)
Basic earnings (loss) per share:
As reported $ 0.95 $ 0.24 $ (0.26)
Pro forma $ 0.88 $ 0.18 $ (0.29)
Diluted earnings (loss) per share:
As reported $ 0.95 $ 0.24 $ (0.26)
Pro forma $ 0.88 $ 0.18 $ (0.29)acreage acquired in connection with the issuance of the
warrants.
NOTE HM - RELATED PARTY TRANSACTIONS
The Company servesserved as operator of properties in which the majority stockholder
hashad interests and billsbilled the majority stockholder for lease operating expenses
and shared office expenditures on a monthly basis subject to usual trade terms.
The billings totaled $37,884, $56,775 and $21,981$43,827 for the year ended March 31, 2002. All of such
properties were sold in October 2001. The only related party transactions for
the years ended March 31, 2001, 20002004 and 1999,2003 relate to shared office expenditures.
The total billed for years ended March 31, 2004 and 2003 was $18,118 and
$10,016, respectively.
Effective January 1, 2000, the Company entered into an agreement with the
husband of an officer and director of the Company to provide geological
consulting services. Amounts paid under this contract were $25,787$8,094, $19,251 and
$8,386$23,627 for the years ended March 31, 20012004, 2003, and 2000,2002, respectively.
During the year ending March 31, 2004, a member of the board of directors, also
a Company employee, entered into an agreement with Deepwater Resources, L.P. and
Gary Martin, whereby he receives a 1.5% overriding royalty on certain leases
related to the Lodgepole Prospect in Stark County, North Dakota. In January
2004, the Company purchased a one-quarter interest in these leases and/or
options to lease.
During the year ending March 31, 2003, a member of the board of directors, also
a Company employee, entered into an agreement with Falcon Bay, LLC, whereby he
receives a commission from Falcon Bay Operating, LLC for any transactions
consummated between Falcon Bay Operating, LLC and the Company in the course of
the Exploration Agreement.
36
During the year ending March 31, 2002, the Company entered into two
transactions, respectively, with a Company director and employee and a trust
related to but not controlled by said director and employee. In the first
transaction, the Company purchased oil and gas lease rights representing 369 net
acres for cash consideration of $83,000. In the second transaction, the Company
exchanged 18,400 shares of its $.50 par value common stock for oil and gas lease
rights representing 368 net acres with a value of approximately $83,000. Such
acreage is available for exploration and production of oil and gas.
NOTE IM - 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 SecuritiesSEC and Exchange Commission and
Financial Accounting Standards Board.FASB. These guidelines require that
reserve estimates be prepared under existing economic and operating conditions
at year-end, with no provision for price and cost escalators, except by
contractual agreement. The estimates as of March 31, 2001, 20002004, 2003, and 19992002 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. The following estimates of proved reserves
quantities and related standardized measure of discounted net cash flow are
estimates only, and do not purport to reflect realizable values or fair market
values of the Company's reserves.
28
CHANGES IN PROVED RESERVE QUANTITIES (UNAUDITED):
2001 2000 1999
------------------ ------------------ ------------------
Bbls Mcf Bbls Mcf Bbls Mcf
------- --------- ------- --------- ------- ---------
Proved reserves,
beginning of year 139,000 4,755,000 194,000 4,194,000 246,000 3,197,000
Revision of previous
estimates (15,000) (10,000) 13,000 (471,000) (2,000) 348,000
Purchase of minerals
in place 108,000 1,706,000 3,000 1,403,000 -- 939,000
Extensions and
discoveries 21,000 398,000 1,000 174,000 -- 193,000
Production (18,000) (504,000) (19,000) (541,000) (50,000) (483,000)
Sales of minerals
in place -- -- (53,000) (4,000) -- --
------- --------- ------- --------- ------- ---------
Proved reserves,
end of year 235,000 6,345,000 139,000 4,755,000 194,000 4,194,000
======= ========= ======= ========= ======= =========
PROVED DEVELOPED RESERVES (UNAUDITED):
Beginning of year 139,000 4,755,000 194,000 4,194,000 219,000 2,941,000
End of year 235,000 6,337,000 139,000 4,755,000 194,000 4,194,000
2004 2003 2002
---------------------- ----------------------- -----------------------
Bbls Mcf Bbls Mcf Bbls Mcf
------- --------- ------- ---------- -------- ----------
Proved reserves,
beginning of year 150,000 7,931,000 237,000 10,182,000 235,000 6,345,000
Revision of previous
estimates 2,000 214,000 (66,000) (1,746,000) (70,000) (1,204,000)
Purchase of minerals
in place -- 260,000 -- 22,000 55,000 2,864,000
Extensions and
discoveries -- -- 2,000 12,000 38,000 2,644,000
Production (20,000) (488,000) (23,000) (539,000) (21,000) (467,000)
------- --------- ------- ---------- -------- ----------
Proved reserves,
end of year 132,000 7,917,000 150,000 7,931,000 237,000 10,182,000
======= ========= ======= ========== ======== ==========
PROVED DEVELOPED RESERVES (UNAUDITED):
Beginning of year 94,000 4,518,000 144,000 5,159,000 235,000 6,337,000
End of year 77,000 4,274,000 94,000 4,518,000 144,000 5,159,000
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED
RESERVES (UNAUDITED):
March 31,
--------------------------------------------
2001 2000 1999
March 31,
--------------------------------------------
2004 2003 2002
------------ ------------ ------------
Future cash inflows $ 46,230,000 $ 49,820,000 $ 36,005,000
Future production and
development costs (12,225,000) (13,284,000) (12,217,000)
Future income taxes (a) (7,761,000) (8,444,000) (5,228,000)
------------ ------------ ------------
Future cash inflows $ 40,179,000 $ 15,590,000 $ 8,994,000
Future production and
development costs (9,988,000) (4,414,000) (2,989,000)
Future income taxes (a) (7,182,000) (2,249,000) (715,000)
------------ ------------ ------------
Future net cash flows 23,009,000 8,927,000 5,290,000
Annual 10% discount for
estimated timing of cash flows (10,824,000) (4,019,000) (2,220,000)
------------ ------------ ------------
Standardized measure of
discounted future net cash flows $ 12,185,000 $ 4,908,000 $ 3,070,000
37
Future net cash flows 26,244,000 28,092,000 18,560,000
Annual 10% discount for
estimated timing of cash flows (11,482,000) (12,120,000) (9,256,000)
------------ ------------ ------------
Standardized measure of
discounted future net cash flows $ 14,762,000 $ 15,972,000 $ 9,304,000
============ ============ ============
(a) Future income taxes are computed using effective tax rates on future net
cash flows before income taxes less the tax bases of the oil and gas
properties and effects of statutory depletion.
CHANGES IN STANDARIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM
PROVED RESERVES (UNAUDITED):
Year ended March 31,
---------------------------------------
2001 2000 1999
----------- ----------- -----------
Sales of oil and gas produced,
net of production costs $(2,566,000) $(1,136,000) $ (859,000)
Net changes in price and production
costs 5,104,000 2,310,000 (1,255,000)
Changes in previously estimated
development costs (20,000) 22,000 296,000
Revisions of quantity estimates (148,000) (281,000) 389,000
Net change due to purchases and
sales of minerals in place 5,939,000 1,164,000 527,000
Extensions and discoveries,
less related costs 975,000 187,000 81,000
Net change in income taxes (2,567,000) (821,000) (18,000)
Accretion of discount 614,000 349,000 389,000
Changes in timing of estimated
cash flows and other (54,000) 44,000 25,000
----------- ----------- -----------
Changes in standardized measure 7,277,000 1,838,000 (425,000)
Standardized measure, beginning of year 4,908,000 3,070,000 3,495,000
----------- ----------- -----------
Standardized measure, end of year $12,185,000 $ 4,908,000 $ 3,070,000
=========== =========== ===========
29
Year ended March 31,
---------------------------------------------
2004 2003 2002
------------ ----------- ------------
Sales of oil and gas produced,
net of production costs (1,968,000) $(1,833,000) $ (1,120,000)
Net changes in price and production costs (1,697,000) 12,946,000 (7,145,000)
Changes in previously estimated
development costs -- 512,000 (59,000)
Revisions of quantity estimates 524,000 (5,103,000) (1,862,000)
Net change due to purchases and sales of
minerals in place 681,000 77,000 3,685,000
Extensions and discoveries,
less related costs -- 87,000 2,121,000
Net change in income taxes 436,000 (2,180,000) 1,183,000
Accretion of discount 2,077,000 1,193,000 1,599,000
Changes in timing of estimated cash
flows and other (1,263,000) 969,000 (1,283,000)
------------ ----------- ------------
Changes in standardized measure (1,210,000) 6,668,000 (2,881,000)
Standardized measure, beginning of year 15,972,000 9,304,000 12,185,000
------------ ----------- ------------
Standardized measure, end of year $14,762,000 $15,972,000 $ 9,304,000
============ =========== ============
ITEM 11.9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES
None.
ITEM 9A. CONTROLS AND PROCEDURES
We maintain disclosure controls and procedures designed to ensure that
information required to be disclosed in our filings under the Securities
Exchange Act of 1934 is recorded, processed, summarized and reported within the
time periods specified in the Securities and Exchange Commission's rules and
forms. Our principal executive and financial officers have evaluated our
disclosure controls and procedures and have determined that such disclosure
controls and procedures were effective as of the end of the period covered by
this Annual Report on Form 10-K.
38
PART III
--------
ITEM 12.10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTCOMPANY
The information required regarding Directors of the RegistrantCompany and compliance
with Section 16(a) of the Securities Exchange Act of 1934 is incorporated by
reference to the Company's InformationProxy Statement for its Annual Meeting of
Stockholders, which will be filed with the CommissionSEC not later than July 30, 2001.2004.
Pursuant to Item 401(b) of Regulation S-K, the information required by this
item with respect to executive officers of the Company is set forth in Part I of
this report.
ITEM 13.11. EXECUTIVE COMPENSATION
The information required in this item is incorporated by reference from the
Company's InformationProxy Statement for its Annual Meeting of Stockholders, which will be
filed with the CommissionSEC not later than July 30, 2001.2004.
ITEM 14.12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required in this item is incorporated by reference from the
Company's InformationProxy Statement for its Annual Meeting of Stockholders, which will be
filed with the CommissionSEC not later than July 30, 2001.2004.
ITEM 15.13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required in this item is incorporated by reference from the
Company's InformationProxy Statement for its Annual Meeting of Stockholders, which will be
filed with the CommissionSEC not later than July 30, 2001.2004.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required in this item is incorporated by reference from the
Company's Proxy Statement for its Annual Meeting of Stockholders, which will be
filed with the SEC not later than July 30, 2004.
39
PART IV
-------
ITEM 16.15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. and 2. Financial Statements and Schedules.
See "Index to Consolidated Financial Statements" set forth in Item 8
of this Form 10-K.
No schedules are required to be filed because of the absence of
conditions under which they would be required or because the required
information is set forth in the financial statements or notes thereto
referred to above.
(a) 3. Exhibits.
Exhibit
Number
- ------
3.1 Articles of Incorporation (incorporated by reference to the Company's
Annual Report on Form 10-K dated June 24, 1998).
3.2 Bylaws.Bylaws adopted December 5, 2002.
10.1 Stock Option Plan (incorporated by reference to the Amendment to Schedule
14C Information Statement filed on August 13, 1997).
10.2 Bank Line of Credit (incorporated by reference to the Company's Annual
Report on Form 10-K dated June 24, 1998).
10.3 Partial Assignment, Bill of Sale and Conveyance between Mexco Energy
Corporation and Shenandoah Petroleum Corporation dated April 21, 1999
(previously filed as exhibit 10.1 and incorporated by reference to
Form 8-K dated April 21, 1999). 21 Subsidiaries of the Company (incorporated by reference to the Company's
Annual Report on Form 10-K dated JunJune 24, 1998).
31.1 Certification by the President and Chief Executive Officer of the Company
pursuant to Rule 13a -- 14(a) of the Securities Exchange Act of 1934.
31.2 Certification of the Chief Financial Officer of the Company pursuant to
Rule 13a - 14(a) of the Securities Exchange Act of 1934.
32.1 Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
(b) Reports on Form 8-K.
A report on Form 8-K, dated January 12, 2001,March 24, 2004, was filed by the Company
duringfor the quarteryear ended March 31, 20012004 under Item 5. Other Events.
31
5 to provide public disclosure
of an agreement to begin a preliminary feasibility study for exploration
and development of natural gas reserves in Russia.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Company has duly caused this report to be signed on
behalf of the undersigned thereunto duly authorized.
MEXCO ENERGY CORPORATION
Registrant
By: /s/ Nicholas C. Taylor
----------------------------------------------------------------------------
Nicholas C. Taylor
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below as of June 14, 2001,29, 2004, by the following persons on
behalf of the Company and in the capacity indicated.
40
/s/ Nicholas C. Taylor
- --------------------------------------------------------------------------------
Nicholas C. Taylor
President, Chief Executive Officer
and Director
/s/ Donna Gail Yanko
- --------------------------------------------------------------------------------
Donna Gail Yanko
Vice President, Operations
and Director
Linda J. Crass/s/ Tamala L. McComic
- -----------------------------------
Linda J. Crass
Controller,---------------------------------------------
Tamala L. McComic
Vice President, Treasurer
and Assistant Secretary
/s/ Thomas Graham, Jr.
- --------------------------------------------------------------------------------
Thomas Graham, Jr.
Chairman of the Board of Directors
/s/ Thomas R. Craddick
- --------------------------------------------------------------------------------
Thomas R. Craddick
Director
/s/ William G. Duncan, Jr.
- --------------------------------------------------------------------------------
William G. Duncan, Jr.
Director
/s/ Arden Grover
- ---------------------------------------------
Arden Grover
Director
/s/ Jack D. Ladd
- --------------------------------------------------------------------------------
Jack D. Ladd
Director
3241
INDEX TO EXHIBITS
-----------------
Exhibit
Number Exhibit Page
- ------- --------------------------------------------------------------- --------------------------------------------------- ----
3.1* Articles of Incorporation.
3.23.2*** Bylaws. 34
10.1** Stock Option Plan.
10.2* Bank Line of Credit.
10.3*** Partial Assignment, Bill of Sale and Conveyance between
Mexco Energy Corporation and Shenandoah Petroleum
Corporation dated April 21, 1999.
21* Subsidiaries of the Company.
31.1 Certification by the President and Chief Executive Officer of the
Company pursuant to Rule 13a -- 14(a) of the Securities Exchange Act of
1934.
31.2 Certification of the Chief Financial Officer of the Company pursuant to
Rule 13a - 14(a) of the Securities Exchange Act of 1934.
32.1 Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002.
* Incorporated by reference to the Company's Annual Report on Form 10-K
dated June 24, 1998.
** Incorporated by reference to the Amendment to Schedule 14C Information
Statement filed on August 13, 1998.
*** Previously filed as exhibit 10.1 and incorporated by reference toFiled with the Company's Annual Report on Form 8-K10-K dated April 21, 1999.
33June 29, 2004.