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.
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.
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.
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.
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:
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 ======= =======
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.
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.
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.
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.
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.
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.
ITEM 6. SELECTED FINANCIAL DATA
ITEM 7.
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.
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.
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.
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.
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.
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.
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.
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.
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
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
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.
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.
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.
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.
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.
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.
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.
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.
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
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
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.
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 =========== =========== ===========
ITEM 11.
ITEM 11. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES
None.
PART III
ITEM 12.
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.
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.
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.
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.
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.
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
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.