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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, 2001 Commission File No. 0-6694
MEXCO ENERGY CORPORATION
(Exact name of registrant as specified in its charter)
Colorado 84-0627918
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
214 W. Texas Avenue, Suite 1101 79701
Midland, Texas (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code: (915) 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 None
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 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. [ ]
As of May 22, 2001, the aggregate market value of the registrant's common
stock held by non-affiliates (using the closing bid price of $4.00) was
approximately $1,924,540.
The number of shares outstanding of the registrant's common stock as of May
31, 2001 was 1,610,133.
DOCUMENTS INCORPORATED BY REFERENCE
Part III of this Report is incorporated by reference from the Registrant's
Information Statement relating to its Annual Meeting of Stockholders to be held
on September 27, 2001. Such Information Statement will be filed with the
Commission not later than July 30, 2001.
TABLE OF CONTENTS
PART 1
Item 1. Business ....................................................... 3
Item 2. Properties...................................................... 6
Item 3. Legal Proceedings............................................... 8
Item 4. Submission of Matters to a Vote of Security Holders............. 8
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters............................................. 9
Item 6. Selected Financial Data......................................... 10
Item 7. Selected Quarterly Financial Data............................... 10
Item 8. Management's Discussion and Analysis of Financial
Condition and Results of Operations............................. 10
Item 9. Quantitative and Qualitative Disclosures About Market Risk...... 14
Item 10. Financial Statements and Supplementary Data..................... 15
Item 11. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosures............................ 30
PART III
Item 12. Directors and Executive Officers of the Registrant.............. 30
Item 13. Executive Compensation.......................................... 30
Item 14. Security Ownership of Certain Beneficial Owners and Management.. 30
Item 15. Certain Relationships and Related Transactions.................. 30
PART IV
Item 16. Exhibits, Financial Statement Schedules and Reports on Form 8-K. 31
Signatures ............................................................... 32
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 focus 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 and re-entry
prospects.
Oil and Gas Operations
As of March 31, 2001, gas reserves constituted approximately 82% of the
Company's total proved reserves and approximately 83% of the Company's revenues
for fiscal 2001. Revenues from oil and gas royalty interests accounted for
approximately 16% of the Company's revenues for fiscal 2001.
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% of the Company's discounted future net cash flows from proved
reserves as of March 31, 2001, and for fiscal 2001, approximately 38% of
revenues and 29% 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% of the Company's discounted future net cash flows from proved
reserves as of March 31, 2001, and for fiscal 2001, approximately 14% of
revenues and 10% of production costs.
3
The Company owns interests in and operates 17 producing wells and two
shut-in wells. The Company owns partial interests in an additional 1,461
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)
---- --------- --------
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
Competition
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 larger financial and other
resources. 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 Customers
The Company had sales to the following companies that amounted to 10% or
more of revenues for the year ended March 31:
2001 2000 1999
---- ---- ----
Sid Richardson Energy Services, Co.
(formerly Koch Midstream Services Company) 39% 35% 30%
Navajo Crude Oil Marketing Company - - 25%
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
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
and there is no assurance that the less stringent regulatory approach recently
pursued by FERC, Congress and the states will continue indefinitely into the
future.
Environmental
The Company, by nature of its oil and gas operations, is subject extensive
federal, state and local environmental laws and regulations governing the
protection of the environment. The Company is in compliance, in all material
respects, with applicable environmental requirements. Although future
environmental obligations are not expected to have a material impact on the
results of operations or financial condition of the Company, there can be no
assurance that future developments, such as increasingly stringent environmental
laws or enforcement thereof, will not cause the Company to incur material
environmental liabilities or costs.
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.
Employees
As of March 31, 2001, 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 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 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 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 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, 2000 and 1999 are based on evaluations prepared
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.
In estimating reserves as of March 31, 2001, average prices of $24.42 per
barrel for oil and $5.43 per mcf (thousand cubic feet) for gas were used, which
were the average actual prices in effect for the Company's production.
The Company has not filed any oil or gas reserve estimates or included any
such estimates in reports to any other federal or foreign governmental authority
or agency within the past 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
=========== =========== ===========
The preceding tables should be read in connection with the following
definitions:
6
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. 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 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 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:
Gross Net
----- -----
Oil ............................................ 1,259 12
Gas ............................................ 220 7
----- -----
Total Productive Wells ..................... 1,479 19
===== =====
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 only material undeveloped acreage
the Company owned was approximately 4,283 gross and 543 net acres in the state
of Texas.
The following table sets forth the approximate developed acreage in which
the Company held a leasehold mineral or other interest at March 31, 2001.
Developed Acres
-------------------------
Gross Net
------- -------
Texas ............................ 84,691 2,465
New Mexico ....................... 16,554 145
North Dakota ..................... 23,999 18
Louisiana ........................ 21,961 28
Oklahoma ......................... 36,162 123
Montana .......................... 7,189 4
Kansas ........................... 7,240 21
Wyoming .......................... 1,798 4
Colorado ......................... 1,040 1
Alabama .......................... 320 1
Arkansas ......................... 320 --
------- -------
Total ............................ 201,274 2,810
======= =======
7
Drilling Activities
The following table sets forth the drilling activity of the Company for the
years ended March 31, 2001, 2000 and 1999.
Years ended March 31,
------------------------------------------
2001 2000 1999
------------ ------------ ------------
Gross Net Gross Net Gross Net
----- ----- ----- ----- ----- -----
Exploratory Wells
Productive 1 .08 1 .01 - -
Nonproductive 2 .48 - - - -
----- ----- ----- ----- ----- -----
Total 3 .56 1 .01 - -
===== ===== ===== ===== ===== =====
Development Wells
Productive 1 .02 1 .60 8 1.90
Nonproductive - - - - - -
----- ----- ----- ----- ----- -----
Total 1 .02 1 .60 8 1.90
===== ===== ===== ===== ===== =====
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 mcf of natural
gas produced and the average production (lifting) cost per unit of production
for the years ended March 31, 2001, 2000 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 $1,503,623
(a) Includes condensate.
(b) Includes natural gas products.
(c) Gas production is converted to equivalent bbls at the rate of 6 mcf per 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
purchasers 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.
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 Registrant
The following table sets forth certain information concerning the executive
officers of the Company as of March 31, 2001.
Name Age Position
- ------------------ --- ---------------------------------------------
Nicholas C. Taylor 63 President and Chief Executive Officer
Donna Gail Yanko 57 Vice President and Corporate Secretary
Linda J. Crass 46 Treasurer, Controller and Assistant 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 of the
three member State Securities Board through January 2001.
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 Board of Directors of the Company in 1990.
Linda J. Crass has been Controller for the Company since July 1998. She was
appointed Assistant Secretary of the Company in August 1998 and Treasurer in
March 1999. From 1996 to 1998 Ms. Crass was employed by Titan Exploration, Inc.
in various accounting positions. From 1989 to 1996, Ms. Crass was Controller for
Midland Resources, Inc.
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company's common stock is traded on the over-the-counter market
bulletin board under the symbol MEXC. The registrar and transfer agent is
Computershare Investor Services, Inc., P.O. Box 1596, Denver, Colorado, 80201
(Tel: 303-984-4100). As of March 31, 2001 the Company had 1,402 shareholders of
record and 1,610,133 shares outstanding.
PRICE RANGE OF COMMON STOCK
Bid Price
-------------------------
High Low
------- -------
2001:(1)
April - June 2000 4 7/8 4 3/8
July - September 2000 4 9/16 4 1/2
October - December 2000 6 3/8 4 9/16
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 7/8
(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) On May 22, 2001, the bid price was $4.00.
9
The Company has not paid any dividends on its common stock, and it is the
present policy of the Company not to do so, but to retain its earnings for
future growth and business activities. The Company is also subject to certain
loan covenants including restrictions on payment of dividends.
ITEM 6. SELECTED FINANCIAL DATA
Years Ended March 31,
-----------------------------------------------------------------------
2001 2000 1999 1998 1997
-----------------------------------------------------------------------
Statement of Operations:
Operating revenues $ 3,099,966 $ 1,686,266 $ 1,510,005 $ 2,106,338 $ 1,458,741
Operating income (loss) 1,881,776 498,384 (281,099) (1,558,335) 521,123
Other income (expense) (92,160) (104,737) (144,675) (134,891) (5,621)
Net income (loss) $ 1,539,458 $ 393,647 $ (425,774) $(1,323,657) $ 377,867
Net income (loss) per
share - basic $ 0.95 $ 0.24 $ (0.26) $ (0.83) $ 0.27
Net Income (loss) per
share - diluted $ 0.95 $ 0.24 $ (0.26) $ (0.83) $ 0.27
Weighted average shares
outstanding - basic 1,622,568 1,623,289 1,623,289 1,594,752 1,423,229
Weighted average shares
outstanding - diluted 1,625,003 1,623,289 1,623,289 1,594,752 1,423,229
Balance Sheet:
Property and equipment, net $ 4,009,852 $ 3,459,522 $ 3,749,400 $ 4,078,053 $ 4,777,132
Total assets 4,961,360 3,853,319 4,043,015 4,542,486 5,109,199
Total debt 600,000 1,200,000 1,784,000 1,822,000 1,637,000
Stockholders' equity $ 4,046,452 $ 2,567,228 $ 2,173,581 $ 2,599,355 $ 2,923,012
Cash Flow:
Cash provided by operations $ 1,903,345 $ 722,088 $ 532,171 $ 1,118,566 $ 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.
ITEM 7. 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)
ITEM 8. 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 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, the Company primarily used cash provided by operations
($1,903,345) to fund oil and gas property acquisitions and development
($936,293), repayments of bank debt ($600,000) and increased working capital.
Working capital as of March 31, 2001 was $822,095.
In fiscal 2001, the board 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. 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, the Company entered into an exploration agreement
relating to non-producing acreage in Pecos County, Texas. Approximately 3,795
gross acres and 432 net acres have been leased and a 3-D seismic survey covering
23 square miles has been completed at a cost to the Company of approximately
$155,000. Two test wells were drilled on this acreage. The first test well will
be completed as a producer at a cost to the Company of approximately $80,000.
The second test well has been drilled, plugged and abandoned at a cost to the
Company of approximately $44,000. Pending further evaluation of the information
gathered from these wells, additional wells may be drilled on these prospects.
The Company owns approximate working interests in these prospects ranging from
10.41% to 15.51% 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 cash of $33,000. A replacement
well was successfully completed on this acreage in February 2001.
Effective January 1, 2001, the Company acquired royalty interests totaling
0.209% in producing acreage in Ward County, Texas for $65,760. There are
presently two producing 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
properties located in various counties 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 acquired 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.
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 has a 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 2000
Oil and gas sales increased from $1,678,961 in 2000 to $3,092,210 in 2001,
an increase of $1,413,249 or 84%. This increase was primarily attributable to
the increase in oil and gas prices during the year, offset in part by decreased
production. The average oil price increased from $21.54 in 2000 to $28.67 per
bbl in 2001, an increase of $7.13 per bbl or 33%. The average gas price
increased from $2.33 in 2000 to $5.08 per mcf in 2001, an increase of $2.75 per
mcf or 118%. Oil production decreased from 19,334 bbls in 2000 to 18,545 bbls in
2001, a decrease of 789 bbls or 4%. Gas production decreased from 540,793 mcf in
2000 to 503,773 mcf in 2001, a decrease of 37,020 mcf or 7%.
Production costs decreased from $542,789 in 2000 to $526,032 in 2001, a
decrease of $16,757 or 3%.
Depreciation, depletion and amortization decreased from $426,102 in 2000 to
$377,761 in 2001, a decrease of $48,341 or 11%, due primarily to increased
reserves attributable to higher gas prices and property acquisitions. There was
no impairment of oil and gas properties in fiscal 2000 or 2001.
General and administrative expenses increased from $218,991 in 2000 to
$314,397 in 2001, an increase of $95,406 or 44%. This increase was primarily
attributable to increased salaries and benefits ($40,700), 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).
Interest expense decreased from $107,577 in 2000 to $95,999 in 2001, an
increase of $11,578 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%. This increase was primarily due to increased oil
and gas prices and increased production from the acquisition and development of
gas properties, offset in part by the sale of the Lazy JL properties 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 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.
ITEM 9. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Risk Factors
All of the Company's financial instruments are for purposes other than
trading.
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. 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, the
Company's largest credit risk associated with any single purchaser was $95,110.
The Company has not experienced any significant credit losses.
14
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. 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, the Company's pretax income would have changed
by $185. If the average gas price had increased or decreased by one cent per mcf
for fiscal 2001, the Company's pretax income would have changed by $5,038.
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. 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.
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, fires, releases of toxic gases and other
environmental hazards and risks, any of which 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. 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. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Report of Independent Certified Public Accountants....................... 16
Consolidated Balance Sheets.............................................. 17
Consolidated Statements of Operations.................................... 18
Consolidated Statements of Stockholders' Equity.......................... 19
Consolidated Statements of Cash Flows.................................... 20
Notes to Consolidated Financial Statements............................... 21
15
Report of Independent Certified Public Accountants
Board of Directors
Mexco Energy Corporation
We have audited the accompanying consolidated balance sheets of Mexco Energy
Corporation and Subsidiary, as of March 31, 2001 and 2000, 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. 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 auditing standards generally accepted
in the United States of America. 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 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, 2001 and 2000, and the consolidated
results of their operations and their consolidated cash flows for each of the
three years in the period ended March 31, 2001 in conformity with accounting
principles generally accepted in the United States of America.
GRANT THORNTON LLP
Oklahoma City, Oklahoma
May 11, 2001
16
Mexco 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
============ ============
The accompanying notes to the consolidated financial statements
are an integral part of these statements.
17
Mexco 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
The accompanying notes to the consolidated financial statements
are an integral part of these statements.
18
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
=========== =========== ===========
The accompanying notes to the consolidated financial statements
are an integral part of these statements.
19
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended March 31,
2001 2000 1999
----------- ----------- -----------
Cash flows from operating activities:
Net earnings (loss) $ 1,539,458 $ 393,647 $ (425,774)
Adjustments to reconcile net earnings
(loss) to net cash provided by
operating activities:
Deferred income taxes 185,495 -- --
Stock-based compensation 24,700 -- --
Depreciation, depletion and amortization 377,761 426,102 909,965
(Increase) decrease in accounts receivable (218,054) (97,247) 24,851
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 -- --
----------- ----------- -----------
Net cash provided by operating activities 1,903,345 722,088 532,171
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
Additions to other property and equipment (1,014) (712) (1,622)
----------- ----------- -----------
Net cash used in investing activities (937,307) (136,574) (639,321)
Cash flows from financing activities:
Borrowings -- 248,174 --
Principal payments on long-term debt (600,000) (832,174) (38,000)
Purchases and retirements of common stock (84,934) -- --
----------- ----------- -----------
Net cash used in financing activities (684,934) (584,000) (38,000)
----------- ----------- -----------
Net increase (decrease) in cash
and cash equivalents 281,104 1,514 (145,150)
Cash and cash equivalents
at beginning of year 97,712 96,198 241,348
----------- ----------- -----------
Cash and cash equivalents
at end of year $ 378,816 $ 97,712 $ 96,198
=========== =========== ===========
Interest paid $ 99,044 $ 109,255 $ 138,586
Income taxes paid $ -- $ -- $ --
The accompanying notes to the consolidated financial statements
are an integral part of these statements.
20
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-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 eleven 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-owned subsidiary.
All significant inter-company 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. Costs are amortized using the
units-of-production method based upon 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.
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) Per Common Share. Basic earnings (loss) per share is
computed by dividing net earnings (loss) by the weighted average number of
shares outstanding during the period. Diluted earnings (loss) per share is
computed by dividing net earnings (loss) by the weighted average number of
common shares and dilutive potential common shares (stock options)
outstanding during the period. In periods where losses are reported, the
weighted-average number of common shares outstanding excludes potential
common shares, because their inclusion would be anti-dilutive. The
following is a reconciliation of the number of shares used in the
calculation of basic earnings per share and diluted earnings per share for
the period ended March 31, 2001.
Weighted average number of
common shares outstanding 1,622,568
Incremental shares from the assumed
exercise of dilutive stock options 2,435
---------
Dilutive potential common shares 1,625,003
=========
Outstanding options to purchase 90,000 and 180,000 shares at March 31, 1999
and 2000, respectively, were not included in the computation of diluted net
earnings per share because the exercise price of the options was greater
than the average market price of the common shares and, therefore, the
effect would be anti-dilutive.
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.
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, 2000 or 1999.
Use of Estimates. In preparing financial statements in conformity with
generally accepted accounting principles, management is required to make
estimates and assumptions that affect the amounts reported in the these
financial statements. Although Management 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
Revenue Recognition and Gas Balancing. Oil and gas sales are recognized
when the product is transported from the well site. 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. 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" an interpretation of APB
Opinion No. 25.
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, 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.
23
NOTE C - INCOME TAXES
Deferred tax assets, valuation allowance, and liabilities at March 31 are
as follows:
2001 2000
----------- -----------
Deferred tax assets:
Percentage depletion carryforwards $ 258,661 $ 213,365
Vacation accrual 1,108 -
Net operating loss carryforwards - 224,713
Valuation allowance - (196,469)
----------- -----------
259,769 241,609
Deferred tax liabilities:
Excess financial accounting bases over
tax bases of property and equipment (445,264) (241,609)
----------- -----------
Net deferred tax assets (liabilities) $ (185,495) $ -
=========== ===========
Increase (decrease) in valuation
allowance for the year $ (196,469) $ (75,349)
=========== ===========
As of March 31, 2001, the Company has statutory depletion
carryforwards of approximately $834,000, which do not expire.
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
--------- --------- ---------
Tax expense (benefit) at statutory rate $ 608,469 $ 133,840 $(144,763)
Increase (decrease) in valuation allowance (196,469) (75,349) 135,928
Depletion in excess of basis (80,864) -- --
Effect of graduated rates (53,688) (31,492) 34,062
Other (27,290) (26,999) (25,227)
--------- --------- ---------
$ 250,158 $ -- $ --
========= ========= =========
Effective tax rate 14% -- --
========= ========= =========
NOTE D - MAJOR CUSTOMERS
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, 2000 and 1999 one purchaser accounted for 39%, 35% and
30%, respectively, of revenues. In fiscal 1999, another purchaser accounted
for 25% of revenues.
24
NOTE E - 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
----------- ----------- -----------
Property acquisition costs $ 470,223 $ 334,611 $ 207,325
Development costs $ 466,070 $ 468,943 $ 436,052
The Company had the following aggregate capitalized costs relating to
the Company's oil and gas property activities at March 31:
2001 2000 1999
----------- ----------- -----------
Proved oil and gas properties $11,309,873 $10,531,259 $10,331,594
Unproved oil and gas properties 248,107 99,644 163,797
----------- ----------- -----------
11,557,980 10,630,903 10,495,391
Less accumulated depreciation,
depletion, and amortization 7,555,356 7,181,648 6,759,416
----------- ----------- -----------
$ 4,002,624 $ 3,449,255 $ 3,735,975
=========== =========== ===========
On April 21, 1999, the Company sold all of its oil and gas interests
in Lazy JL field properties located in Garza County, Texas for $600,000
cash, adjusted for revenues and expenses from 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 $288,393 for the first quarter of fiscal 1999 due to
declines in oil and gas prices and the related downward adjustment of
estimated reserves. Depreciation, depletion, and amortization amounted to
$3.65, $3.86 and $6.97 per equivalent barrel of production for the years
ended March 31, 2001, 2000 and 1999, respectively.
NOTE F - 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, the Company repurchased
13,160 shares, at an aggregate cost of $84,934.
25
NOTE G - EMPLOYEE BENEFIT PLAN
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 Board of Directors, include stock options or 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 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 sixty days and will vest
as determined by agreement. Holders of restricted stock have all rights of
a shareholder of the Company.
During fiscal 2001, options for 60,000 shares were granted. Of these
30,000 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 is as follows:
Weighted
Number Average
of Shares Exercise Price
------------ --------------
Options outstanding, at March 31, 1998 - $ -
Granted 100,000 7.63
Exercised - -
Forfeited (10,000) 7.75
------------ --------------
Options outstanding, at March 31, 1999 90,000 7.61
Granted 90,000 5.25
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 240,000 $ 6.51
============ ==============
Options exercisable at March 31, 1999 - $ -
Options exercisable at March 31, 2000 22,500 $ 7.61
Options exercisable at March 31, 2001 67,500 $ 6.82
26
Weighted average grant date fair value of stock options granted during
fiscal 2001 was $2.33. Weighted average grant date fair value of stock
options granted during fiscal 2000 and 1999 was $2.65 and $4.04,
respectively. The value for 2001 was determined using a Binomial
option-pricing model, while amounts for 1999 and 2000 were determined using
the Black-Scholes option-pricing model. Both models value 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.
The assumptions used in the Black-Scholes and Binomial models were as
follows for stock options granted in fiscal 2001, 2000 and 1999:
2001 2000 1999
-------- -------- --------
Expected volatility 29.86% 29.40% 27.89%
Expected dividend yield 0.00% 0.00% 0.00%
Risk-free rate of return 5.25% 6.43% 5.72%
Expected life of options 10 years 10 years 10 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 stock options
outstanding and exercisable at March 31, 2001:
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 $7.61
$6.75 60,000 9.82 $6.75
$5.25 90,000 8.97 $5.25
-----------
240,000
Stock Options Exercisable
Number of Weighted
Range of Shares Average
Exercise Prices Exercisable Exercise Price
--------------- ------------------ --------------
$7.50-$7.75 45,000 $7.61
$5.25 22,500 $5.25
27
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, the Company
is required to recognize prospectively compensation cost related to stock
options awarded to independent consultants. Total compensation cost related
to these awards recognized for fiscal 2001 was $24,700. 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
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)
NOTE H - RELATED PARTY TRANSACTIONS
The Company serves as operator of properties in which the majority
stockholder has interests and bills the majority stockholder for lease
operating expenses on a monthly basis subject to usual trade terms. The
billings totaled $37,884, $56,775 and $21,981 for the years ended March 31,
2001, 2000 and 1999, 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 and
$8,386 for the years ended March 31, 2001 and 2000, respectively.
NOTE I - 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 Securities and Exchange Commission and
Financial Accounting Standards Board. These guidelines require that reserve
estimates be prepared under existing economic and operating conditions,
with no provision for price and cost escalators, except by contractual
agreement. The estimates as of March 31, 2001, 2000 and 1999 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
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED
RESERVES (UNAUDITED):
March 31,
--------------------------------------------
2001 2000 1999
------------ ------------ ------------
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
============ ============ ============
(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
ITEM 11. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES
None.
PART III
ITEM 12. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required regarding Directors of the Registrant and
compliance with Section 16(a) of the Securities Exchange Act of 1934 is
incorporated by reference to the Company's Information Statement for its Annual
Meeting of Stockholders, which will be filed with the Commission not later than
July 30, 2001.
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. EXECUTIVE COMPENSATION
The information required in this item is incorporated by reference from the
Company's Information Statement for its Annual Meeting of Stockholders, which
will be filed with the Commission not later than July 30, 2001.
ITEM 14. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required in this item is incorporated by reference from the
Company's Information Statement for its Annual Meeting of Stockholders, which
will be filed with the Commission not later than July 30, 2001.
ITEM 15. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required in this item is incorporated by reference from the
Company's Information Statement for its Annual Meeting of Stockholders, which
will be filed with the Commission not later than July 30, 2001.
30
PART IV
ITEM 16. 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.
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 Jun 24, 1998).
(b) Reports on Form 8-K.
A report on Form 8-K, dated January 12, 2001, was filed by the Company
during the quarter ended March 31, 2001 under Item 5. Other Events.
31
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
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, by the following persons on
behalf of the Company and in the capacity indicated.
Nicholas C. Taylor
- -----------------------------------
Nicholas C. Taylor
President, Chief Executive Officer
and Director
Donna Gail Yanko
- -----------------------------------
Donna Gail Yanko
Vice President, Operations
and Director
Linda J. Crass
- -----------------------------------
Linda J. Crass
Controller, Treasurer
and Assistant Secretary
Thomas Graham, Jr.
- -----------------------------------
Thomas Graham, Jr.
Chairman of the Board of Directors
Thomas R. Craddick
- -----------------------------------
Thomas R. Craddick
Director
William G. Duncan, Jr.
- -----------------------------------
William G. Duncan, Jr.
Director
Jack D. Ladd
- -----------------------------------
Jack D. Ladd
Director
32
INDEX TO EXHIBITS
Exhibit
Number Exhibit Page
- ------- --------------------------------------------------------- ----
3.1* Articles of Incorporation.
3.2 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.
* 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 to Form 8-K
dated April 21, 1999.
33