-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, B3UXnfqbNnbZ2TFZIp+JAPtO9DXgzRBK0WKxoyPZ5R0iyoFGL7NvNgF7qs7slN+w YWC+YgXcE5XWUSNbRW7N1w== 0001144204-06-026007.txt : 20060626 0001144204-06-026007.hdr.sgml : 20060626 20060623182515 ACCESSION NUMBER: 0001144204-06-026007 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 20060331 FILED AS OF DATE: 20060626 DATE AS OF CHANGE: 20060623 FILER: COMPANY DATA: COMPANY CONFORMED NAME: MEXCO ENERGY CORP CENTRAL INDEX KEY: 0000066418 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 840627918 STATE OF INCORPORATION: CO FISCAL YEAR END: 0331 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-31785 FILM NUMBER: 06923054 BUSINESS ADDRESS: STREET 1: 214 W TEXAS AVENUE STREET 2: SUITE 1101 CITY: MIDLAND STATE: TX ZIP: 79701 BUSINESS PHONE: 9156821119 MAIL ADDRESS: STREET 1: 214 W TEXAS AVENUE STREET 2: SUITE 1101 CITY: MIDLAND STATE: TX ZIP: 79701 FORMER COMPANY: FORMER CONFORMED NAME: MILLER OIL CO DATE OF NAME CHANGE: 19800702 10-K 1 v046146_10k.txt 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, 2006 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: (432) 682-1119 Securities registered pursuant to Section 12(b) of the Act: None Securities registered pursuant to Section 12(g) of the Act: Title of Each Class Name of Exchange on Which Registered - ----------------------------- ------------------------------------ Common Stock, $0.50 par value American Stock Exchange Indicate by check-mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve (12) months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past ninety (90) days. Yes |X| No |_| Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (ss.229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or an amendment to this Form 10-K. |_| Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes |_| No |X| The aggregate market value of the voting stock held by non-affiliates of the registrant as of September 30, 2005, the last business day of the registrant's most recently completed second quarter, was $6,019,618 (based on the closing price of such stock on the American Stock Exchange). The number of shares outstanding of the registrant's common stock, $.50 par value, as of June 21, 2006 was 1,743,041. DOCUMENTS INCORPORATED BY REFERENCE Portions of the Registrant's Proxy Statement relating to the 2006 Annual Meeting of Shareholders to be held on September 14, 2006, have been incorporated by reference in Part III of this Form 10-K. Such Proxy Statement will be filed with the Commission not later than July 28, 2006. TABLE OF CONTENTS
PART I Item 1. Business 3 Item 1A. Risk Factors 8 Item 1B. Unresolved Staff Comments 10 Item 2. Properties 10 Item 3. Legal Proceedings 13 Item 4. Submission of Matters to a Vote of Security Holders 13 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters 14 Item 6. Selected Financial Data 15 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations 16 Item 7A. Quantitative and Qualitative Disclosures About Market Risk 21 Item 8. Financial Statements and Supplementary Data 22 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures 22 Item 9A. Controls and Procedures 22 Item 9B. Other Information 22 PART III Item 10. Directors and Executive Officers of the Registrant 23 Item 11. Executive Compensation 23 Item 12. Security Ownership of Certain Beneficial Owners and Management 23 Item 13. Certain Relationships and Related Transactions 23 Item 14. Principal Accountant Fees and Services 23 PART IV Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K 24 Signatures 25
This Annual Report on Form 10-K contains forward-looking statements that are based on management's current expectations. Forward-looking statements include statements regarding our plans, beliefs or current expectations and may be signified by the words "could", "should", "expect", "project", "estimate", "believe", "anticipate", "intend", "budget", "plan", "forecast", "predict" and other similar expressions. Forward-looking statements appear throughout this Form 10-K with respect to, among other things: profitability; planned capital expenditures; estimates of oil and gas production; future project dates; estimates of future oil and gas prices; estimates of oil and gas reserves; our future financial condition or results of operations; and our business strategy and other plans and objectives for future operations. Actual results in future periods may differ materially from those expressed or implied by such forward-looking statements because of a number of risks and uncertainties affecting our business, including those discussed in "Item 1 - Business - Risk Factors" and elsewhere in this report. We disclaim any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Definitions of terms commonly used in the oil and gas industry and in this Form 10-K can be found in the Glossary of Terms. PART I ITEM 1. BUSINESS General Mexco Energy Corporation, a Colorado corporation, is an independent oil and gas company engaged in the acquisition, exploration and development of oil and gas properties located in the United States. Unless the context otherwise requires, references to the "Company", "Mexco", "we", "us" or "our" mean Mexco Energy Corporation and its consolidated subsidiaries. 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. In April 2004, Mexco Energy Corporation formed OBTX, LLC, a Delaware Limited Liability Company, in which Mexco owns 90% of the stock. The remaining 10% of the stock is split equally among three individuals, one of whom is Arden Grover, a director of Mexco Energy Corporation. Since its date of formation, OBTX, LLC has been included in the consolidated financial statements. OBTX, LLC, plans to participate in any Russian venture entered into and own a 50% interest. Through March 31, 2006, OBTX, LLC has had no operations other than evaluation activities on properties in Russia. Our total estimated proved reserves at March 31, 2006 were approximately 6.697 Bcf of natural gas and 183,000 barrels of oil and natural gas liquids, and our estimated present value of proved reserves was approximately $23 million based on estimated future net revenues discounted at 10% per annum, pricing and other assumptions set forth in "Item 2 - Properties" below. During fiscal 2006, we added proved reserves of 9,000 Mcfe through extensions and discoveries, acquired 36,000 Mcfe through acquisitions and had downward revisions of previous estimates of 10,000 Mcfe. Nicholas C. Taylor beneficially owns approximately 51% of the outstanding shares of our common stock. Mr. Taylor is also our President and Chief Executive Officer. As a result, Mr. Taylor has significant influence in matters voted on by our shareholders, including the election of our Board members. Mr. Taylor participates in all facets of our business and has a significant impact on both our business strategy and daily operations. 3 Company Profile Currently we conduct all of our drilling, exploration and production activities in the United States. All of our oil and gas assets, other than our investment in GazTex, LLC, are located in the United States, and all of our revenues are derived from sales to customers within the United States. GazTex, LLC is owned 50% by OBTX, LLC. Since our inception, we have been engaged in acquiring and developing oil and gas properties and the exploration for and production of oil and gas within the United States. We primarily focus on the exploration for and development of natural gas resources, as well as increased profit margins through reductions in operating costs. Our long-term strategy is to increase production and profits, while increasing concentration primarily on gas and secondarily on oil reserves. In addition to exploration, we are also engaged in the business of acquiring proved reserves. Competition for the purchase of proved reserves is intense. Sellers often utilize a bid process to sell properties. This process usually intensifies the competition and makes it extremely difficult for us to acquire reserves without assuming significant price and production risks. We are actively searching for opportunities to acquire proved oil and gas properties; however, because the competition is intense, we cannot give any assurance that we will be successful in our efforts during fiscal 2007. While we own oil and gas properties in other states, the majority of our activities are centered in West Texas. We acquire interests in producing and non-producing oil and gas leases from landowners and leaseholders in areas considered favorable for oil and gas exploration, development and production. In addition, we may acquire oil and gas interests by joining in oil and gas drilling prospects generated by third parties. We may also employ a combination of the above methods of obtaining producing acreage and prospects. In recent years, we have placed primary emphasis on the evaluation and purchase of producing oil and gas properties, both working and royalty interests, and re-entry prospects that could have a potentially meaningful impact on our reserves. From time to time, we decide to sell certain of our proved properties. In November 2005, we sold our interest in one outside operated well located in Reeves County, Texas. We received cash proceeds of approximately $48,000, subject to normal post-closing adjustments. Oil and Gas Operations As of March 31, 2006, gas reserves constituted approximately 86% of the Company's total proved reserves and approximately 75% of the Company's revenues for fiscal 2006. Revenues from oil and gas royalty interests accounted for approximately 26% of the Company's revenues for fiscal 2006. 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 3% of our discounted future net cash flows from proved reserves as of March 31, 2006, and for fiscal 2006, approximately 11% of revenues and 9% 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 10% of our discounted future net cash flows from proved reserves as of March 31, 2006, and for fiscal 2006, approximately 11% of revenues and 7% of production costs. El Cinco Gas Field properties, encompassing 1,006 gross acres, 766 net acres, 7 gross producing wells and 5.325 net wells in Pecos County, Texas, account for approximately 43% of our discounted future net cash flows from proved reserves as of March 31, 2006. This is a multi-pay area where most of the leases have potential reserves in two zones. Of this amount approximately 20% of our discounted future net cash flows from proved reserves are attributable to proven undeveloped reserves which will be developed through re-entry of existing wells and new drilling. For fiscal 2006, these properties accounted for approximately 15% of revenues and 27% of production costs. 4 We own interests in and operate 14 producing wells and one shut-in well. We own partial interests in an additional 2,026 producing wells located in the states of Texas, New Mexico, Oklahoma, Louisiana, Arkansas, Wyoming, Kansas, Colorado, Montana and North Dakota. Additional information concerning these properties and our oil and gas reserves is provided below. The following table indicates our oil and gas production in each of the last five years, all of which is located within the United States: Year Oil(Bbls) Gas (Mcf) - ---- --------- --------- 2006...................................... 17,118 370,069 2005...................................... 17,372 404,133 2004...................................... 20,279 487,564 2003...................................... 23,391 538,787 2002...................................... 21,139 467,013 Competition and Markets The oil and gas industry is a highly competitive business. Competition for oil and gas reserve acquisitions is significant. We may compete with major oil and gas companies, other independent oil and gas companies and individual producers and operators, some of which have financial and personnel resources substantially in excess of those available to us. As a result, we may be placed at a competitive disadvantage. Competitive factors include price, contract terms and types and quality of service, including pipeline distribution. The price for oil and gas is widely followed and is generally subject to worldwide market factors. Our ability to acquire and develop additional properties in the future will depend upon our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment in a timely manner. In addition, the oil and gas industry as a whole also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers. The price and availability of alternative energy sources could adversely affect our revenue. Market factors affect the quantities of oil and natural gas production and the price we can obtain for the production from our oil and natural gas properties. Such factors include: the extent of domestic production; the level of imports of foreign oil and natural gas; the general level of market demand on a regional, national and worldwide basis; domestic and foreign economic conditions that determine levels of industrial production; political events in foreign oil-producing regions; and variations in governmental regulations including environmental, energy conservation and tax laws or the imposition of new regulatory requirements upon the oil and natural gas industry. The market for our oil, gas and natural gas liquids production depends on factors beyond our control including: domestic and foreign political conditions; the overall level of supply of and demand for oil, gas and natural gas liquids; the price of imports of oil and gas; weather conditions; the price and availability of alternative fuels; the proximity and capacity of gas pipelines and other transportation facilities and overall economic conditions. Major Customers We had sales to the following company that amounted to 10% or more of revenues for the year ended March 31: 2006 2005 2004 ---- ---- ---- Sid Richardson Energy Services, Co. 16% 21% 29% Because a ready market exists for oil and gas production, we do not believe the loss of any individual customer would have a material adverse effect on our financial position or results of operations. 5 Regulation Our 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 our properties. These statutes, along with the regulations interpreting the statutes, generally are intended to prevent waste of oil and natural gas, and to protect correlative rights to produce oil and natural gas by assigning allowable rates of production to each well or proration unit. The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects its profitability. Because these rules and regulations are frequently amended or reinterpreted, we are not able to predict the future cost or impact of complying with such laws. The Federal Energy Regulatory Commission ("FERC") regulates interstate natural gas transportation rates and service conditions, which affect the marketing of gas we produce, as well as the revenues we receive for sales of such production. Since the mid-1980s, the FERC has issued various orders that have significantly altered the marketing and transportation of gas. These orders resulted in a fundamental restructuring of interstate pipeline sales and transportation services, including the unbundling by interstate pipelines of the sales, transportation, storage and other components of the city-gate sales services such pipelines previously performed. These FERC actions were designed to increase competition within all phases of the gas industry. The interstate regulatory framework may enhance our ability to market and transport our gas, although it may also subject us to greater competition and to the more restrictive pipeline imbalance tolerances and greater associated penalties for violation of such tolerances. Our sales of oil and natural gas liquids are not presently regulated and are made at market prices. The price we receive from the sale of those products is affected by the cost of transporting the products to market. The FERC has implemented regulations establishing an indexing system for transportation rates for oil pipelines, which, generally, would index such rate to inflation, subject to certain conditions and limitations. We are not able to predict with any certainty what effect, if any, these regulations will have on us. Other factors being equal, the regulations may, over time, tend to increase transportation costs which may have the effect of reducing wellhead prices for oil and natural gas liquids. Environmental Matters By nature of our oil and gas operations, we are subject to extensive federal, state and local environmental laws and regulations controlling the generation, use, storage and discharge of materials into the environment or otherwise relating to the protection of the environment. Numerous governmental departments issue rules and regulations to implement and enforce such laws, which are often difficult and costly to comply with and which carry substantial penalties for failure to comply. These laws and regulations may require the acquisition of a permit before drilling or production commences, restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within protected areas, restrict the rate of oil and gas production, require remedial actions to prevent pollution from former operations and impose substantial liabilities for pollution resulting from our operations. In addition, these laws and regulations may impose substantial liabilities and penalties for failure to comply with them or for any contamination resulting from our operations. We believe we are in compliance, in all material respects, with applicable environmental requirements. We do not believe costs relating to these laws and regulations have had a material adverse effect on our operations or financial condition in the past. Public interest in the protection of the environment has increased dramatically in recent years. The trend of applying more expansive and stricter environmental legislation and regulations to the natural gas and oil industry could continue, resulting in increased costs of doing business and consequently affecting our profitability. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly waste handling, disposal and cleanup requirements, our business and prospects could be adversely affected. 6 The United States Oil Pollution Act of 1990 ("OPA `90"), and similar legislation enacted in Texas, Louisiana and other coastal states, addresses oil spill prevention and control and significantly expands liability exposure across all segments of the oil and gas industry. OPA `90 and such similar legislation and related regulations impose on us a variety of obligations related to the prevention of oil spills and liability for damages resulting from such spills. OPA `90 imposes strict and, with limited exceptions, joint and several liabilities upon each responsible party for oil removal costs and a variety of public and private damages. The Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), also known as the "Superfund" law, imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We are able to control directly the operation of only those wells with respect to which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the failure of an operator other than us to comply with applicable environmental regulations may, in certain circumstances, be attributed to us. We do not believe that we will be required to incur any material capital expenditures to comply with existing environmental requirements. Our operations may be subject to the Clean Air Act ("CAA") and comparable state and local requirements. In 1990 Congress adopted amendments to the CAA containing provisions that have resulted in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and states have developed and continue to develop regulations to implement these requirements. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. However, we do not believe our operations will be materially adversely affected by any such requirements. The Resource Conservation and Recovery Act ("RCRA") and analogous state laws govern the handling and disposal of hazardous and solid wastes. Wastes that are classified as hazardous under RCRA are subject to stringent handling, recordkeeping, disposal and reporting requirements. RCRA specifically excludes from the definition of hazardous waste "drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy." However, these wastes may be regulated by the EPA or state agencies as solid waste. Moreover, many ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils, are regulated as hazardous wastes. Although the costs of managing hazardous waste may be significant, we do not expect to experience more burdensome costs than similarly situated companies. State water discharge regulations and federal waste discharge permitting requirements adopted pursuant to the Federal Water Pollution Control Act prohibit, or are expected in the future to prohibit, the discharge of produced water and sand and other substances related to the oil and gas industry into coastal waters. Although the costs to comply with such mandates under state or federal law may be significant, the entire industry will experience similar costs, and we do not believe that these costs will have a material adverse impact on our financial condition and operations. 7 Insurance Our operations are subject to all the risks inherent in the exploration for, and development and production of oil and gas including blowouts, fires and other casualties. We maintain insurance coverage customary for operations of a similar nature, but losses could arise from uninsured risks or in amounts in excess of existing insurance coverage. Employees As of March 31, 2006, we had two full-time and four part-time employees. We believe that relations with these employees are generally satisfactory. Our employees are not covered by collective bargaining arrangements. From time to time, we utilize 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 We maintain our principal offices at 214 W. Texas, Suite 1101, Midland, Texas pursuant to a month to month lease. Title to Properties As is customary in the oil and gas industry, only a preliminary title examination is conducted at the time properties believed to be suitable for drilling operations are acquired by us. Prior to the commencement of drilling operations, a thorough title examination of the drill site tract is conducted and curative work is performed with respect to significant defects, if any, before proceeding with operations. A thorough title examination has been performed with respect to substantially all leasehold producing properties currently owned by us. We believe the title to our leasehold properties is good and defensible in accordance with standards generally acceptable in the oil and gas industry subject to such exceptions that, in the opinion of counsel employed in the various areas in which we have conducted exploration activities, are not so material as to detract substantially from the use of such properties. The leasehold properties we own are subject to royalty, overriding royalty and other outstanding interests customary in the industry. The properties may be subject to burdens such as liens incident to operating agreements and current taxes, development obligations under oil and gas leases and other encumbrances, easements and restrictions. We do not believe any of these burdens will materially interfere with the use of these properties Substantially all of our properties are currently mortgaged under a deed of trust to secure funding through a revolving line of credit. Access to Company Reports Mexco Energy Corporation files quarterly, yearly and other reports with the SEC. You may obtain a copy of any materials filed by Mexco Energy Corporation with the SEC at 450 Fifth Street, N.W., Washington, D.C. 20549 or by calling 1-800-SEC-0330. The SEC also maintains an Internet site that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC at http://www.sec.gov. Mexco Energy Corporation also employs the Public Register's Annual Report Service which can provide you a copy of our annual report at http://www.prars.com, free of charge, as soon as practicable after providing such report to the SEC. We currently do not maintain an internet website. ITEM 1A. RISK FACTORS There are many factors that affect our business and results of operations, some of which are beyond our control. The following is a description of some of the important factors that may cause results of operations in future periods to differ materially from those currently expected or desired. 8 Oil and gas prices are volatile and could adversely affect our revenues, cash flow, liquidity and reserve estimates. We cannot predict future oil and natural gas prices with any certainty. Historically, the markets for oil and gas have been volatile, and they are likely to continue to be volatile. Factors that can cause price fluctuations include changes in supply and demand, weather conditions, the price and availability of alternative fuels, political and economic conditions in oil producing countries and other factors that are beyond our control. Natural gas prices affect us more than oil prices because most of our production and reserves are natural gas. Prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Lower prices may also reduce the amount of crude oil and natural gas that can be produced economically. Changes in oil and gas prices impact both estimated future net revenue and the estimated quantity of proved reserves. Price increases may permit additional quantities of reserves to be produced economically, and price decreases may render uneconomic the production of reserves previously classified as proved. Thus, we may experience material increases or decreases in reserve quantities solely as a result of price changes and not as a result of drilling or well performance. Lower oil and gas prices increase the risk of ceiling limitation write-downs. We use the full cost method to account for oil and gas operations. Accordingly, we capitalize the cost to acquire, explore for and develop crude oil and natural gas properties. Under the full cost accounting rules, the net capitalized cost of crude oil and natural gas properties may not exceed a "ceiling limit" which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10% plus the lower of cost or fair market value of unproved properties. If net capitalized costs of oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This charge does not impact cash flow from operating activities, but does reduce stockholders' equity and earnings. The risk that we will be required to write down the carrying value of oil and natural gas properties increases when oil and natural gas prices are low. 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 our reserves will ultimately be produced or that any undeveloped reserves will be developed. As required by the SEC, the estimated discounted future net cash flows from proved reserves are generally based on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Our future success depends upon our ability to find, develop or acquire additional, economically recoverable oil and gas reserves. Our proved reserves will generally decline as reserves are depleted, except to the extent that we can find, develop or acquire replacement reserves. One offset to the obvious benefits afforded by higher product prices especially for small to mid-cap companies in this industry, is that quality domestic oil and gas reserves are becoming harder to find. Reserves to be produced from undiscovered reservoirs appear to be smaller, and the risks to find these reserves are greater. Reports from the Energy Information Administration indicate that on-shore domestic finding costs are on the rise, and that the average reserves added per well are declining. Drilling and operating activities are subject to many risks, including availability of workover and drilling rigs, well blowouts, cratering, explosions, fires, formations with abnormal pressures, pollution, releases of toxic gases and other environmental hazards and risks. Any of these operating hazards could result in substantial losses to us. In addition, we incur the risk that no commercially productive reservoirs will be encountered and there is no assurance that we will recover all or any portion of its investment in wells drilled or re-entered. 9 The marketability of our production depends in part on the availability, proximity and capacity of natural gas gathering systems, pipelines and processing facilities. Federal and state regulation of oil and gas production and transportation, tax and energy policies, changes in supply and demand and general economic conditions could all affect our ability to produce and market our oil and gas. ITEM 1B. UNRESOLVED STAFF COMMENTS None. ITEM 2. PROPERTIES Oil and Natural Gas Reserves Estimates of our 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, 2006, 2005 and 2004 are based on evaluations prepared by Joe C. Neal and Associates, Petroleum Consultants. For information concerning our costs incurred for oil and gas operations, net revenues from oil and gas production, estimated future net revenues attributable to our oil and gas reserves, present value of future net revenues discounted at 10% and changes therein, see Notes to the Company's consolidated financial statements. We emphasize that reserve estimates are inherently imprecise and there can be no assurance that the reserves set forth below will be ultimately realized. Actual future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and gas reserves will most likely vary from the assumptions and estimates. Any significant variance could materially affect the estimated quantities and value of our oil and gas reserves, which in turn may adversely affect our cash flow, results of operations and the availability of capital resources. In accordance with applicable financial accounting and reporting standards of the SEC, the estimates of our proved reserves and the present value of proved reserves set forth herein are made using oil and gas sales prices estimated to be in effect as of the date of such reserve estimates and are held constant throughout the life of the properties. Actual future prices and costs may be materially higher or lower than those as of the date of the estimate. The timing of both the production and the expenses with respect to the development and production of oil and gas properties will affect the timing of future net cash flows from proved reserves and their present value. Except to the extent that we acquire additional properties containing proved reserves or conduct successful exploration and development activities, or both, our proved reserves will decline as reserves are produced. We have not filed any other oil or gas reserve estimates or included any such estimates in reports to other federal or foreign governmental authority or agency within the last twelve months. Our estimated proved oil and gas reserves and present value of estimated future net revenues from proved oil and gas reserves in the periods ended March 31 are summarized below. PROVED RESERVES March 31, ---------------------------------------- 2006 2005 2004 ------------ ------------ ------------ Oil (Bbls): Proved developed - Producing 85,091 106,495 75,455 Proved developed - Non-producing 1,432 1,388 1,386 Proved undeveloped 96,557 42,719 55,613 ------------ ------------ ------------ Total 183,080 150,602 132,454 ============ ============ ============ Natural gas (Mcf): Proved developed - Producing 2,816,566 3,535,316 3,207,186 Proved developed - Non-producing 1,074,550 1,061,190 1,067,010 Proved undeveloped 2,806,070 2,731,013 3,643,116 ------------ ------------ ------------ Total 6,697,186 7,327,519 7,917,312 ============ ============ ============ Present value of estimated future net revenues before income taxes $ 23,290,420 $ 20,946,720 $ 19,127,440 ============ ============ ============ 10 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 our productive wells as of March 31, 2006: Gross Net ------ ------ Oil ...................................................... 1,303 13 Gas ...................................................... 723 10 ------ ------ Total Productive Wells .............................. 2,026 23 ====== ====== 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, 2006, we own approximately 1,980 gross and 1,000 net acres of material undeveloped acreage located in Texas and North Dakota. The following table sets forth the approximate developed acreage in which we held a leasehold mineral or other interest as of March 31, 2006. Developed Acres -------------------------- Gross Net ----------- ----------- Texas........................................... 136,002 2,566 New Mexico...................................... 20,837 153 North Dakota.................................... 27,399 27 Louisiana....................................... 33,107 37 Oklahoma........................................ 42,482 192 Montana......................................... 9,788 5 Kansas.......................................... 8,040 21 Wyoming......................................... 3,438 4 Colorado........................................ 1,200 1 Arkansas........................................ 320 - ----------- ----------- Total........................................... 282,613 3,006 =========== =========== 11 Drilling Activities The following table sets forth our drilling activity in wells in which we own a working interest for the years ended March 31, 2006, 2005 and 2004: Year Ended March 31, ---------------------------------------------- 2006 2005 2004 -------------- -------------- -------------- Gross Net Gross Net Gross Net ------ ------ ------ ------ ------ ------ Exploratory Wells Productive 3 .03 2 .01 9 .03 Nonproductive -- -- -- -- 2 .30 ------ ------ ------ ------ ------ ------ Total 3 .03 2 .01 11 .33 ====== ====== ====== ====== ====== ====== Development Wells Productive 12 .05 10 .05 12 .02 Nonproductive -- -- -- -- -- -- ------ ------ ------ ------ ------ ------ Total 12 .05 10 .05 12 .02 ====== ====== ====== ====== ====== ====== The information contained in the foregoing table should not be considered indicative of future drilling performance, nor should it be assumed that there is any necessary correlation between the number of productive wells drilled and the amount of oil and gas that may ultimately be recovered by us. Net Production, Unit Prices and Costs The following table summarizes the net oil and natural gas production for the Company, the average sales price per barrel of oil and per thousand cubic feet ("mcf") of natural gas produced and the average production (lifting) cost per unit of production for the years ended March 31, 2006, 2005 and 2004.
Year Ended March 31, ---------------------------------------- 2006 2005 2004 ------------ ------------ ------------ Oil (a): Production (Bbls) 17,118 17,372 20,279 Revenue $ 938,681 $ 727,822 $ 588,089 Average Bbls per day 47 48 56 Average sales price per Bbl $ 54.84 $ 41.90 $ 29.00 Gas (b): Production (Mcf) 370,069 404,133 487,564 Revenue $ 2,777,883 $ 2,236,067 $ 2,321,864 Average Mcf per day 1,014 1,107 1,336 Average sales price per Mcf $ 7.51 $ 5.53 $ 4.76 Production cost: Production cost $ 843,927 $ 780,233 $ 942,093 Equivalent Mcf (c) 472,777 508,365 609,232 Production cost per equivalent Mcf $ 1.79 $ 1.53 $ 1.55 Production cost per sales dollar $ 0.23 $ 0.26 $ 0.32 Total oil and gas revenues $ 3,716,564 $ 2,963,889 $ 2,909,953
(a) Includes condensate. (b) Includes natural gas products. (c) Oil production is converted to equivalent mcf at the rate of 6 mcf per barrel ("bbl"), representing the estimated relative energy content of natural gas to oil. 12 ITEM 3. LEGAL PROCEEDINGS We were a defendant in a lawsuit that had arisen in the ordinary course of business related to the oil and gas leases on the Campbell 15-1 well in Hemphill County, Texas. We released the lease on the Campbell 15-1 well effective January 31, 2006 as part of a compromise settlement agreement in the lawsuit. We believe the settlement of the lawsuit and the release of the lease did not have a material effect on our consolidated financial condition or results of operations. Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any legal or governmental proceedings against us, or contemplated to be brought against us, under various environmental protection statutes or other regulations to which we are subject. ITEM 4. 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, 2006. Executive Officers of the Registrant The following table sets forth certain information concerning the executive officers of the Company as of March 31, 2006. Name Age Position - ------------------ --- --------------------------------------------- Nicholas C. Taylor 68 President and Chief Executive Officer Donna Gail Yanko 61 Vice President and Corporate Secretary Tamala L. McComic 37 Vice President, Treasurer, and Asst 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 to the State Securities Board through January 2001. In addition to serving as chairman for four years, he continued to serve as a member until 2004. In November 2005 he was appointed by the Speaker of the House to the Texas Ethics Commission for a term of five years. 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. Tamala L. McComic became Controller for the Company in July 2001. She was appointed Assistant Secretary of the Company in August 2001 and Treasurer in September 2001. From 1994 to 2001 Mrs. McComic was Regional Controller and Credit Manager for Transit Mix Concrete & Materials Company, a subsidiary of Trinity Industries, Inc. In May 2003, Mrs. McComic was appointed Vice President, Chief Financial Officer and continues to serve as Treasurer and Assistant Secretary. 13 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS In September 2003, our common stock began trading on the American Stock Exchange under the symbol "MXC". Prior to September 2003, the Company's common stock was traded on the over-the-counter market bulletin board under the symbol "MEXC". The registrar and transfer agent is Computershare Trust Company, Inc., P.O. Box 1596, Denver, Colorado, 80201 (Tel: 303-262-0600). As of March 31, 2006, the Company had approximately 1,357 shareholders of record and 1,776,566 shares issued. PRICE RANGE OF COMMON STOCK High Low -------- -------- 2006: April - June 2005 (1) $ 18.20 $ 6.10 July - September 2005(1) 13.38 9.50 October - December 2005 (1) 11.89 6.90 January - March 2006 (1) 12.95 7.01 2005: April - June 2004 (1) $ 7.85 $ 6.80 July - September 2004(1) 6.80 6.00 October - December 2004 (1) 6.15 5.55 January - March 2005 (1) 12.90 5.65 - ---------- (1) Reflects the high and low sales prices for the Company's Common Stock, as reported on the American Stock Exchange. On June 21, 2006, the closing price was $7.00. Dividends On February 1, 2002 our board of directors declared a stock dividend consisting of shares of par value $0.50 common stock of the Company in the amount of ten percent (10%) of the outstanding shares, or 1 share for each 10 shares held by all stockholders of record of Mexco Energy Corporation as of February 15, 2002, with any resulting fractional share dividends to be rounded up or down to the nearest whole number of shares and issued the stock dividend accordingly. The payable date for this dividend was February 28, 2002 and resulted in an additional 160,566 shares of stock issued and outstanding. We have never declared or paid any cash dividends on our common stock. We currently intend to retain future earnings and other cash resources, if any, for the operation and development of our business and do not anticipate paying any cash dividends on our common stock in the foreseeable future. Payment of any future dividends will be at the discretion of our board of directors after taking into account many factors, including our financial condition, operating results, current and anticipated cash needs and plans for expansion. In addition, our current bank loan prohibits us from paying cash dividends on our common stock. Any future dividends may also be restricted by any loan agreements which we may enter into from time to time. 14 ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
Year Ended March 31, ------------------------------------------------------------------------ 2006 2005 2004 2003 2002 ------------------------------------------------------------------------ Statement of Operations: Operating revenues $ 3,719,643 $ 2,969,826 $ 2,915,355 $ 2,949,113 $ 1,778,583 Operating income 1,114,966 924,230 785,739 926,277 252,101 Other income (expense) (95,820) (88,408) (82,766) (95,357) (54,706) Net income $ 788,805 $ 577,527 $ 429,846 $ 672,808 $ 189,291 Net income per share - basic (1)(2) $ 0.45 $ 0.33 $ 0.25 $ 0.39 $ 0.11 Net income per share - diluted (1)(2) $ 0.43 $ 0.32 $ 0.24 $ 0.39 $ 0.11 Weighted average shares outstanding - basic (1) 1,733,890 1,734,726 1,736,047 1,741,462 1,768,314 Weighted average shares outstanding - diluted (1) 1,827,026 1,801,167 1,802,300 1,746,831 1,768,579 Balance Sheet: Property and equipment, net $ 8,399,929 $ 8,484,743 $ 7,647,284 $ 7,028,659 $ 5,895,429 Total assets 8,978,324 9,303,149 8,172,464 7,688,638 6,347,965 Total debt 600,000 1,990,000 1,700,000 2,150,000 1,710,000 Stockholders' equity 6,898,996 6,038,195 5,435,219 4,956,388 4,276,042 Cash Flow: Cash provided by operations $ 1,900,665 $ 1,451,628 $ 1,517,479 $ 1,369,690 $ 899,977
(1) Amounts have been adjusted to reflect the 10% stock dividend effected on February 1, 2002. (2) Year 2004 includes a cumulative effect of change in accounting principle (Cumulative Effect) loss of $0.06 related to the adoption of Statement of Financial Accounting Standards (SFAS) No. 143, Asset Retirement Obligations. Selected Quarterly Financial Data (Unaudited)
FISCAL 2006 ----------------------------------------------- 4TH QTR 3RD QTR 2ND QTR 1ST QTR ---------- ---------- ---------- ---------- Oil and gas revenue $ 868,405 $1,111,524 $ 933,915 $ 802,720 Operating profit (loss) (93,373) 558,781 362,778 286,780 Net income (loss) (12,444) 354,608 285,723 160,918 Net income (loss) per share-basic (0.01) 0.20 0.16 0.09 Net income (loss) per share-diluted (0.01) 0.19 0.15 0.09
FISCAL 2005 ----------------------------------------------- 4TH QTR 3RD QTR 2ND QTR 1ST QTR ---------- ---------- ---------- ---------- Oil and gas revenue $ 791,476 $ 774,966 $ 722,452 $ 674,995 Operating profit 250,596 287,220 225,160 161,254 Net income 172,406 183,359 119,060 102,702 Net income per share-basic 0.09 0.11 0.07 0.06 Net income per share-diluted 0.09 0.10 0.07 0.06
During the fourth quarter of fiscal 2006 we had a net loss of $12,444. This was primarily the result of an impairment in our Russian venture. We expensed approximately $261,617, which represents the impairment of our investment in GazTex, LLC. Additionally, depreciation, depletion and amortization increased as a result of the leases on the East Umbrella Point prospect expiring during the fourth quarter. These leases were previously being excluded from the amortization base but were added when the leases expired. The increased depreciation, depletion and amortization expense is also a result of a decrease in reserves. 15 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion is intended to provide information relevant to an understanding of our financial condition, changes in our financial condition and our results of operations and cash flows and should be read in conjunction with our consolidated financial statements and notes thereto included elsewhere in this Form 10-K. Liquidity and Capital Resources and Commitments Historically, we have funded our operations, acquisitions, exploration and development expenditures from cash generated by operating activities, bank borrowings and issuance of common stock. Our primary financial resource is our base of oil and gas reserves. We pledge our producing oil and gas properties to secure our revolving line of credit. In fiscal 2006, we primarily used cash provided by operations ($1,900,665) to fund oil and gas property acquisitions and development ($676,633) and reduce our balance under our revolving line of credit ($1,390,000). We had working capital of $439,761 as of March 31, 2006 compared to working capital of $376,478 as of March 31, 2005, mainly as a result of an increase in prepaid accounts and a decrease in current income tax payable. In fiscal 2003, the board of directors authorized the use of up to $250,000 to repurchase shares of our common stock. As part of this ongoing repurchase plan, we repurchased 281 shares during fiscal 2004 at an aggregate cost of $1,389 and 3,000 shares during fiscal 2005 at an aggregate cost of $16,650 for the treasury account. No shares were repurchased in fiscal year 2006. In December 2002, we entered into a participation agreement with Falcon Bay Exploration, LLC exercising its right to purchase at an aggregate cash price of $597,301, the acreage and seismic data on the first of four such prospects referred to in the exploration agreement with Falcon Bay Exploration, LLC. This information is contained in the Form 8-K we filed on December 6, 2002. The warrants issued related to this transaction expired, unexercised, on December 5, 2004. The 1,280 undeveloped acres in the East Umbrella Point Prospect in Trinity Bay, Chambers County, Texas expired in February 2006. The costs related to these leases were added to the full cost amortization base during the fourth quarter of fiscal 2006. No further prospects will be generated under this exploration agreement. During fiscal year 2004, the Company purchased a one-quarter interest in leases and/or options on leases in Stark County, North Dakota covering 4,920 gross acres for approximately $107,000. Thomas Craddick, a director and employee of the Company, will receive a 1.5% ORRI on any wells drilled on this acreage. During fiscal year 2005, we elected to exercise options on approximately 320 acres in Stark County, North Dakota, therefore allowing the additional options to expire or be reassigned. In March 2004, we signed an agreement in Moscow, Russia to begin a preliminary geological and engineering study for exploration and development of natural gas reserves in Russia. A team of U.S. and Russia experts commenced a study of a number of undeveloped oil and gas properties. Mexco Energy Corporation set up OBTX, LLC, a Delaware limited liability company, in which Mexco owns a 90% interest with the remaining 10% interest split equally among three individuals, one of whom is Arden Grover, a director of Mexco Energy Corporation. OBTX, LLC plans to participate in any Russian ventures entered into and own a 50% interest. Through March 31, 2006, we have reviewed a number of possible projects in Russia. We established a long-term investment in GazTex, LLC for the capital costs of these projects of $282,126. Due to an impairment of the potential project comprising this capital cost, approximately $262,000 of the investment account has been expensed during fiscal 2006. Any assets associated with future projects will be expensed as incurred. In addition to the write-down of the asset account, we expensed approximately $185,000 related to Russia projects in fiscal 2006. 16 In fiscal 2006 we purchased a mineral interest in the East Ponder Unit located in Denton County, Texas for approximately $ 144,000. The East Ponder Unit is 360 acres of pooled leases which are currently being drilled on 40 acre spacing. The unit has 5 wells currently producing with plans to drill additional wells in 2006. We continue to focus our efforts on the acquisition of royalties in areas with significant development potential. We are reviewing several other projects in which we may participate. The cost of such projects would be funded, to the extent possible, from existing cash balances and cash flow from operations. The remainder may be funded through borrowings on the credit facility. See Note 3 of Notes to Consolidated Financial Statements for a description of our revolving credit agreement with Bank of America, N.A. 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 our financial condition and liquidity. However, management believes we can maintain adequate liquidity for the next fiscal year. Results of Operations Fiscal 2006 Compared to Fiscal 2005 Oil and gas sales increased from $2,963,889 in 2005 to $3,716,564 in 2006, an increase of $752,675 or 25%. This increase was attributable to an increase in oil and gas prices during the year. The average oil price increased from $41.90 per bbl in 2005 to $54.84 per bbl in 2006, an increase of $12.94 per bbl or 31%. The average gas price increased from $5.53 in 2005 to $7.51 per mcf in 2006, an increase of $1.98 per mcf or 36%. Oil production decreased from 17,372 bbls in 2005 to 17,118 bbls in 2006, a decrease of 254 bbls or 1%. Gas production decreased from 404,133 mcf in 2005 to 370,069 mcf in 2006, a decrease of 34,064 mcf or 8%. Such decreases primarily were due to normal decline in production. Production costs increased from $780,233 in 2005 to $843,927 in 2006, an increase of $63,694 or 8%. This is primarily a result of an increase in production taxes related to the increase in sales price. Depreciation, depletion and amortization increased from $582,268 in 2005 to $658,365 in 2006, an increase of $76,097 or 13%. This is partially the result of an increase to the full cost pool amortization base. The East Umbrella Point prospect, which was previously being excluded from the amortization base, was added to the base for fiscal 2006 when the leases expired. The increased expense is also a result of a decrease in reserves. General and administrative expenses increased from $658,360 in 2005 to $817,332 in 2006, an increase of $158,972 or 24%. This increase was partially attributable to costs associated with the Russian venture. Contract and consulting services that were directly related to Russian projects totaled approximately $185,000. There was also an increase of approximately $34,000 in directors fees for fiscal 2006 as a result of the increase in director fees from $100 per monthly meeting to $1,500 per quarter. Impairment of the long-term asset account increased $261,617 in fiscal 2006. This increase was a result of the impairment of the potential Russian project of our investment in GazTex, LLC. There were no impairments in fiscal 2005. Interest expense increased from $89,154 in 2005 to $98,657 in 2006, an increase of $9,503 or 11%. This increase was attributable to increased interest rates during the current fiscal year partially offset by decreased borrowings. Income tax expense decreased from $272,609 in 2005 to $272,140 in 2006, a decrease of $469. This decrease was attributable to the write-off of expired leases resulting in a tax net operating loss for fiscal 2006. 17 Fiscal 2005 Compared to Fiscal 2004 Oil and gas sales increased from $2,909,953 in 2004 to $2,963,889 in 2005, an increase of $53,936 or 2%. This increase was attributable to an increase in oil and gas prices during the year. The average oil price increased from $29.00 per bbl in 2004 to $41.90 per bbl in 2005, an increase of $12.90 per bbl or 44%. The average gas price increased from $4.76 in 2004 to $5.53 per mcf in 2005, an increase of $.77 per mcf or 16%. Oil production decreased from 20,279 bbls in 2004 to 17,372 bbls in 2005, a decrease of 2,907 bbls or 14%. Gas production decreased from 487,564 mcf in 2004 to 404,133 mcf in 2005, a decrease of 83,431 mcf or 17%. Such decreases primarily were due to normal decline in production. Production costs decreased from $942,093 in 2004 to $780,233 in 2005, a decrease of $161,860 or 17%. This is primarily attributable to a decreased number of repairs on operated properties during the year and a decrease in production units. Depreciation, depletion and amortization decreased from $633,443 in 2004 to $582,268 in 2005, a decrease of $51,175 or 8%, due primarily to a decrease in production. There was no impairment of oil and gas properties in fiscal 2004 or 2005. General and administrative expenses increased from $529,834 in 2004 to $658,360 in 2005, an increase of $128,526 or 24%. This increase was primarily attributable to costs associated with the Russian venture. Organization costs directly related to forming OBTX, LLC was $46,514. There was also an increase in contract and consulting services that were directly related to Russian projects that we decided to discontinue totaling approximately $83,000. Interest expense increased from $83,530 in 2004 to $89,154 in 2005, an increase of $5,624 or 7%. This increase was attributable to increased borrowings and increased interest rates during the current fiscal year. Income tax expense increased from $170,860 in 2004 to $272,609 in 2005, an increase of $101,749 or 60%. This increase was attributable to the generation of excess depletion in prior years. Alternative Capital Resources Although we have primarily used cash from operating activities and funding from the line of credit as our primary capital resources, we have in the past, and could in the future, use alternative capital resources. These could include the sale of assets and/or issuances of common stock through a private placement or public offering of our common stock. Contractual Obligations We have no off-balance sheet debt or unrecorded obligations and have not guaranteed the debt of any other party. The following table summarizes our future payments we are obligated to make based on agreements in place as of March 31, 2006: Payments Due In: ---------------------------------------------- Total 1 year 1-3 years 3 years ---------- ---------- ---------- ---------- Contractual obligations: Secured bank line of credit $ 600,000 $ -- $ 600,000 $ -- These amounts represent the balances outstanding under the bank line of credit. These repayments assume that interest will be paid on a monthly basis and that no additional funds will be drawn. 18 Other Matters Critical Accounting Policies and Estimates In preparing financial statements, management makes informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, management reviews its estimates, including those related to litigation, environmental liabilities, income taxes, fair value and determination of proved reserves. Changes in facts and circumstances may result in revised estimates and actual results may differ from these estimates. The following represents those policies that management believes are particularly important to the financial statements and that require the use of estimates and assumptions to describe matters that are inherently uncertain. Full Cost Method of Accounting for Crude Oil and Natural Gas Activities. SEC Regulation S-X defines the financial accounting and reporting standards for companies engaged in crude oil and natural gas activities. Two methods are prescribed: the successful efforts method and the full cost method. We have chosen to follow the full cost method under which all costs associated with property acquisition, exploration and development are capitalized. We also capitalize internal costs that can be directly identified with acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities. Effective with the adoption of SFAS No. 143 in 2003, the carrying amount of oil and gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and natural gas attributable to a country. Under the successful efforts method, geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and impairment of crude oil and natural gas properties are generally calculated on a well by well or lease or field basis versus the "full cost" pool basis. Additionally, gain or loss is generally recognized on all sales of crude oil and natural gas properties under the successful efforts method. As a result our financial statements will differ from companies that apply the successful efforts method since we will generally reflect a higher level of capitalized costs as well as a higher depreciation, depletion and amortization rate on our crude oil and natural gas properties. At the time it was adopted, management believed that the full cost method would be preferable, as earnings tend to be less volatile than under the successful efforts method. However, the full cost method makes us more susceptible to significant non-cash charges during times of volatile commodity prices because the full cost pool may be impaired when prices are low. These charges are not recoverable when prices return to higher levels. Our crude oil and natural gas reserves have a relatively long life. However, temporary drops in commodity prices can have a material impact on our business including impact from the full cost method of accounting. Ceiling Test. Companies that use the full cost method of accounting for oil and gas exploration and development activities are required to perform a ceiling test each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The test determines a limit, or ceiling, on the book value of oil and gas properties. That limit is basically the after tax present value of the future net cash flows from proved crude oil and natural gas reserves, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, plus the lower of cost or fair market value of unproved properties. If net capitalized costs of crude oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a "ceiling limitation write-down." This charge does not impact cash flow from operating activities, but does reduce our stockholders' equity and reported earnings. The risk that we will be required to write down the carrying value of crude oil and natural gas properties increases when crude oil and natural gas prices are depressed or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or if purchasers cancel long-term contracts for natural gas production. An expense recorded in one period may not be reversed in a subsequent period even though higher crude oil and natural gas prices may have increased the ceiling applicable to the subsequent period. 19 Estimates of our proved reserves included in this report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of: o the quality and quantity of available data; o the interpretation of that data; o the accuracy of various mandated economic assumptions; o and the judgment of the persons preparing the estimate. Our proved reserve information included in this report was based on evaluations prepared by independent petroleum engineers. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate. It should not be assumed that the present value of future net cash flows is the current market value of our estimated proved reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from proved reserves on prices and costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of the estimate. The estimates of proved reserves materially impact DD&A expense. If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields. Use of Estimates. In preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management is required to make informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. 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, the related present value of estimated future net cash flows and the future development, dismantlement and abandonment costs. Revenue Recognition. We recognize crude oil and natural gas revenue from our interest in producing wells as crude oil and natural gas is sold from those wells, net of royalties. We utilize the sales method to account for gas production volume imbalances. Under this method, income is recorded based on our net revenue interest in production taken for delivery. We had no material gas imbalances. Excluded Costs. Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent investments in unproved properties and major development projects. These costs are excluded until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed at least quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the capitalized costs being amortized (the DD&A pool) or a charge is made against earnings for those international operations where a reserve base has not yet been established. Impairments transferred to the DD&A pool increase the DD&A rate. Costs excluded for oil and gas properties are generally classified and evaluated as significant or individually insignificant properties. 20 Asset Retirement Obligations. The estimated costs of restoration and removal of facilities are accrued. The fair value of a liability for an asset's retirement obligation is recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and the capitalized cost is depreciated by the units of production method. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized. For all periods presented, we have included estimated future costs of abandonment and dismantlement in the full cost amortization base and amortize these costs as a component of our depletion expense. Long Term Investment in GazTex, LLC. The Company accounts for its investment in a limited liability company on the equity basis and adjusts the investment balance to agree with its equity in the underlying assets of the entity. Recent Accounting Pronouncements In December 2004, the Financial Accounting Standard Board (FASB) issued SFAS No. 123R, "Share-Based Payment," a revision to SFAS No. 123. SFAS No. 123R supersedes APB Opinion No. 25 and establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. This statement requires that the cost of all share-based payment transactions be recorded as an expense at their fair value determined by applying a fair value measurement method. The Company will adopt this standard in the first quarter of fiscal 2007 (the quarter ending June 2006), using the modified prospective method requiring the recognition of compensation expense for all awards granted after the date of adoption, and for the unvested portion of previously granted awards outstanding as of the date of adoption. The amount of expense to be recognized in future periods will depend on the levels of future grants, however, considering options outstanding at March 31, 2006, including employees, directors and consultants, the effect on March 31, 2007 net income would be approximately $41,000 net of tax. In March 2005, the FASB issued FASB Interpretation (FIN) No. 47, "Accounting for Conditional Asset Retirement Obligation." This Interpretation clarifies the definition and treatment of conditional asset retirement obligations as discussed in FASB Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations." A conditional asset retirement obligation is defined as an asset retirement activity in which the time and/or method of settlement are dependent on future events that may be outside the control of the Company. FIN 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. This Interpretation is intended to provide more information about long-lived assets, more information about future cash outflows for these obligations and more consistent recognition of these liabilities. FIN 47 is effective for fiscal years ending after December 15, 2005. The Company does not believe that its financial position, results of operations or cash flows were materially impacted by this Interpretation since the Company currently records all asset retirement obligations. In May 2005, the FASB issued FASB No. 154, "Accounting Changes and Error Corrections" (Statement 154). Statement 154 requires companies to recognize changes in accounting principle, including changes required by a new accounting pronouncement when the pronouncement does not include specific transition provisions, retrospectively to prior periods' financial statements. Statement 154 will become effective for the Company's fiscal year beginning April 1, 2006. The Company does not believe that the adoption of Statement 154 will have a material effect on its financial position or results of operations. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK Risk Factors All of the Company's financial instruments are for purposes other than trading. At March 31, 2006, the Company had not entered into any hedge arrangements, commodity swap agreements, commodity futures, options or other similar agreements relating to crude oil and natural gas. Interest Rate Risk. The Company's variable rate bank debt 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. 21 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, 2006, the Company's largest credit risk associated with any single purchaser was $57,602. The Company has not experienced any significant credit losses. Energy Price Risk. Our most significant market risk is the pricing for natural gas and crude oil. Our financial condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. These factors include the level of global demand for petroleum products, foreign supply of oil and gas, the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability of alternative fuels and overall economic conditions, both foreign and domestic. We cannot predict future oil and gas prices with any degree of certainty and expect energy prices to remain volatile and unpredictable. If energy prices decline significantly, revenues and cash flow would significantly decline. In addition, a noncash write-down of our oil and gas properties could be required under full cost accounting rules if prices declined significantly, even if it is only for a short period of time. See Critical Accounting Policies and Estimates -- Ceiling Test under Item 7 of this Form 10-K. Sustained weakness in oil and gas prices may also reduce the amount of net oil and gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can reduce the borrowing base under our revolving credit facility and adversely affect our liquidity and our ability to obtain capital for our exploration and development activities. Similarly, any improvements in oil and gas prices can have a favorable impact on our financial condition, results of operations and capital resources. If the average oil price had increased or decreased by one dollar per barrel for fiscal 2006, our pretax income would have changed by $17,118. If the average gas price had increased or decreased by one dollar per mcf for fiscal 2006, our pretax income would have changed by $370,069. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information required by this item appears on pages F1 through F19 hereof and are incorporated herein by reference. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES None. ITEM 9A. CONTROLS AND PROCEDURES We maintain disclosure controls and procedures to ensure that the information we must disclose in our filings with the SEC is recorded, processed, summarized and reported on a timely basis. Our principal executive officer and principal financial officer have reviewed and evaluated the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rules 13a-15(e) and 15d-15(e), as of March 31, 2006. Based on such evaluation, such officers have concluded that, as of March 31, 2006, our disclosure controls and procedures were effective in timely alerting them to material information relating to us (and our consolidated subsidiaries) required to be included in our periodic SEC filings. There has been no change in our internal control over financial reporting during the year ended March 31, 2006 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. ITEM 9B. OTHER INFORMATION None 22 PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required regarding Directors of the Company and compliance with Section 16(a) of the Securities Exchange Act of 1934 is incorporated by reference to the Company's Proxy Statement for its Annual Meeting of Stockholders, which will be filed with the SEC not later than July 28, 2006. 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 11. EXECUTIVE COMPENSATION The information required in this item is incorporated by reference from the Company's Proxy Statement for its Annual Meeting of Stockholders, which will be filed with the SEC not later than July 28, 2006. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required in this item is incorporated by reference from the Company's Proxy Statement for its Annual Meeting of Stockholders, which will be filed with the SEC not later than July 28, 2006. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information required in this item is incorporated by reference from the Company's Proxy Statement for its Annual Meeting of Stockholders, which will be filed with the SEC not later than July 28, 2006. ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES The information required in this item is incorporated by reference from the Company's Proxy Statement for its Annual Meeting of Stockholders, which will be filed with the SEC not later than July 28, 2006. 23 PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) 1. and 2. Financial Statements and Schedules. See "Index to Consolidated Financial Statements" set forth in Item 8 of this Form 10-K and appear on pages F1 through F19. 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. 3. Exhibits. The information required by this item 15 (a) (3) is set forth in the Index to Exhibits accompanying this Annual Report on Form 10-K. (b) Reports on Form 8-K. Current report on Form 8-K filed on February 14, 2006, pursuant to Item 2.02, announcing quarterly financial results. Current report on Form 8-K filed on November 14, 2005, pursuant to Item 2.02, announcing quarterly financial results. Current report on Form 8-K filed on August 12, 2005, pursuant to Item 2.02, announcing quarterly financial results. Current report on Form 8-K filed on July 1, 2005, pursuant to Item 2.02, announcing annual financial results. 24 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Company has duly caused this report to be signed on behalf of the undersigned thereunto duly authorized. MEXCO ENERGY CORPORATION Registrant By: /s/ Nicholas C. Taylor -------------------------------------- Nicholas C. Taylor President and Chief Executive Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below as of June 23, 2006, by the following persons on behalf of the Company and in the capacity indicated. /s/ Thomas R. Craddick - ------------------------------------------- Thomas R. Craddick Director /s/ Thomas Graham, Jr. - ------------------------------------------- Thomas Graham, Jr. Chairman of the Board of Directors /s/ Arden Grover - ------------------------------------------- Arden Grover Director /s/ Jack D. Ladd - ------------------------------------------- Jack D. Ladd Director /s/ Tamala L. McComic - ------------------------------------------- Tamala L. McComic Vice President, Treasurer and Assistant Secretary /s/ Jeffry A. Smith - ------------------------------------------- Jeffry A. Smith Director /s/ Nicholas C. Taylor - ------------------------------------------- Nicholas C. Taylor President, Chief Executive Officer and Director /s/ Donna Gail Yanko - ------------------------------------------- Donna Gail Yanko Vice President, Secretary and Director 25 Glossary of Terms The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this Form 10-K. Bbl. One barrel, or 42 U.S. gallons of liquid volume. Bcf. One billion cubic feet. Bcfe. One billion cubic feet of natural gas equivalents. Completion. The installation of permanent equipment for the production of oil or gas. Credit Facility. A line of credit provided by a group of banks, secured by oil and gas properties. DD&A. Refers to depreciation, depletion and amortization of the Company's property and equipment. Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. Dry hole. A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well. Exploratory well. A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new productive reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir. Extensions and discoveries. As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates. MBbls. One thousand barrels. Mcf. One thousand cubic feet. Mcfe. One thousand cubic feet of natural gas equivalents, based on a ratio of 6 Mcf for each barrel of oil, which reflects the relative energy content. MMbtu. One million British thermal units. One British thermal unit is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit. MMcf. One million cubic feet. MMcfe. One million cubic feet of natural gas equivalents. Natural gas liquids. Liquid hydrocarbons that have been extracted from natural gas, such as ethane, propane, butane and natural gasoline. Net production. Oil and gas production that is owned by the Company, less royalties and production due others. NYMEX. New York Mercantile Exchange, the exchange on which commodities, including crude oil and natural gas futures contracts, are traded. Oil. Crude oil or condensate. 26 Operator. The individual or company responsible for the exploration, development and production of an oil or gas well or lease. Present value of proved reserves. The present value of estimated future revenues to be generated from the production of proved reserves determined in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to nonproperty related expenses such as general and administrative expenses, debt service, future income tax expense, or depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. Proved developed nonproducing reserves. Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells. Proved developed producing reserves. Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods. Proved developed reserves. The combination of proved developed producing and proved developed nonproducing reserves. Proved reserves. The estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. Proved undeveloped reserves. Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Royalty. An interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner's royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. SEC. The United States Securities and Exchange Commission. Standardized measure of discounted future net cash flows. The after-tax present value of proved reserves determined in accordance with SEC guidelines. Undeveloped acreage. Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether such acreage contains proved reserves. Working interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest is entitled will be smaller than the share of costs that the working interest owner is required to bear to the extent of any royalty burden. Workover. Operations on a producing well to restore or increase production. 27 INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Report of Independent Registered Public Accounting Firm..................... F2 Consolidated Balance Sheets................................................. F3 Consolidated Statements of Operations....................................... F4 Consolidated Statements of Changes in Stockholders' Equity.................. F5 Consolidated Statements of Cash Flows....................................... F6 Notes to Consolidated Financial Statements.................................. F7 Report of Independent Registered Public Accounting Firm Board of Directors and Shareholders Mexco Energy Corporation We have audited the accompanying consolidated balance sheets of Mexco Energy Corporation and Subsidiaries as of March 31, 2006 and 2005 and the related consolidated statements of operations, changes in stockholders' equity and cash flows for each of the three years in the period ended March 31, 2006. 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 the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Mexco Energy Corporation and Subsidiaries as of March 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended March 31, 2006, in conformity with accounting principles generally accepted in the United States of America. As discussed in Note 4 to the financial statements, effective April 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations, and changed its method of accounting for asset retirement obligations. /s/ GRANT THORNTON LLP Oklahoma City, Oklahoma June 23, 2006 F2 Mexco Energy Corporation and Subsidiaries CONSOLIDATED BALANCE SHEETS As of March 31,
2006 2005 ------------ ------------ ASSETS Current assets Cash and cash equivalents $ 52,768 $ 85,209 Accounts receivable: Oil and gas sales 429,133 418,348 Trade 336 23,258 Related parties 73 2,103 Prepaid costs and expenses 75,576 7,362 ------------ ------------ Total current assets 557,886 536,280 Investment in GazTex, LLC 20,509 282,126 Property and equipment, at cost Oil and gas properties, using the full cost method ($121,418 and $921,719 excluded from amortization in 2006 and 2005, respectively) 18,947,532 18,376,974 Other 39,848 36,855 ------------ ------------ 18,987,380 18,413,829 Less accumulated depreciation, depletion, and amortization 10,587,451 9,929,086 ------------ ------------ Property and equipment, net 8,399,929 8,484,743 ------------ ------------ $ 8,978,324 $ 9,303,149 ============ ============ LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities Accounts payable - trade and accrued expenses $ 118,125 $ 111,675 Income tax payable -- 48,127 ------------ ------------ Total current liabilities 118,125 159,802 Long-term debt 600,000 1,990,000 Asset retirement obligation 352,416 374,506 Deferred income tax liability 1,006,736 715,284 Minority interest 2,051 25,362 Commitments and contingencies Stockholders' equity Preferred stock - $1.00 par value; 10,000,000 shares authorized; none outstanding -- -- Common stock - $0.50 par value; 40,000,000 shares authorized; 1,776,566 and 1,766,566 shares issued in 2006 and 2005, respectively 888,283 883,283 Additional paid-in capital 3,893,588 3,826,592 Retained earnings 2,262,700 1,473,895 Treasury stock, at cost (145,575) (145,575) ------------ ------------ Total stockholders' equity 6,898,996 6,038,195 ------------ ------------ $ 8,978,324 $ 9,303,149 ============ ============
The accompanying notes to the consolidated financial statements are an integral part of these statements. F3 Mexco Energy Corporation and Subsidiaries CONSOLIDATED STATEMENTS OF OPERATIONS Year ended March 31,
2006 2005 2004 ------------ ------------ ------------ Operating revenues: Oil and gas $ 3,716,564 $ 2,963,889 $ 2,909,953 Other 3,079 5,937 5,402 ------------ ------------ ------------ Total operating revenues 3,719,643 2,969,826 2,915,355 Operating expenses: Production 843,927 780,233 942,093 Accretion of asset retirement obligation 23,436 24,735 24,246 Depreciation, depletion, and amortization 658,365 582,268 633,443 General and administrative 817,332 658,360 529,834 Impairment of long-term asset 261,617 -- -- ------------ ------------ ------------ Total operating expenses 2,604,677 2,045,596 2,129,616 ------------ ------------ ------------ Operating profit 1,114,966 924,230 785,739 Other income (expense): Interest income 2,837 746 764 Interest expense (98,657) (89,154) (83,530) ------------ ------------ ------------ Net other expense (95,820) (88,408) (82,766) Minority interest in loss of subsidiary 41,799 14,314 -- ------------ ------------ ------------ Earnings before income taxes and cumulative effect of accounting change 1,060,945 850,136 702,973 Income tax expense (benefit): Current (19,312) 76,597 33,371 Deferred 291,452 196,012 137,489 ------------ ------------ ------------ 272,140 272,609 170,860 ------------ ------------ ------------ Income before cumulative effect of accounting change 788,805 577,527 532,113 Cumulative effect of accounting change, net of tax -- -- (102,267) ------------ ------------ ------------ Net income $ 788,805 $ 577,527 $ 429,846 ============ ============ ============ Net income per common share: Basic: Income before cumulative effect of accounting change $ 0.45 $ 0.33 $ 0.31 Cumulative effect, net of tax $ -- $ -- $ (0.06) ------------ ------------ ------------ Net income $ 0.45 $ 0.33 $ 0.25 Diluted: Income before cumulative effect of accounting change $ 0.43 $ 0.32 $ 0.30 Cumulative effect, net of tax $ -- $ -- $ (0.06) ------------ ------------ ------------ Net income $ 0.43 $ 0.32 $ 0.24 Pro forma amounts assuming, the new method of accounting for asset retirement obligations is applied retroactively: Net income $ 532,113 Basic net income per share $ 0.31 Diluted net income per share $ 0.30
The accompanying notes to the consolidated financial statements are an integral part of these statements. F4 Mexco Energy Corporation and Subsidiaries CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
Retained Additional Earnings Total Common Stock Treasury Paid-In (Accumulated) Stockholders' Par Value Stock Capital Deficit) Equity ------------- ------------- ------------- ------------- ------------- Balance, March 31, 2003 $ 883,283 $ (127,536) $ 3,734,119 $ 466,522 $ 4,956,388 Net earnings -- -- -- 429,846 429,846 Purchase of stock -- (1,389) -- -- (1,389) Profits from sale of stock by insider -- -- 2,950 -- 2,950 Stock based compensation -- -- 47,424 -- 47,424 ------------- ------------- ------------- ------------- ------------- Balance, March 31, 2004 883,283 (128,925) 3,784,493 896,368 5,435,219 Net earnings -- -- -- 577,527 577,527 Purchase of stock -- (16,650) -- -- (16,650) Stock based compensation -- -- 42,099 -- 42,099 ------------- ------------- ------------- ------------- ------------- Balance, March 31, 2005 883,283 (145,575) 3,826,592 1,473,895 6,038,195 Net earnings 788,805 788,805 Issuance of stock through options exercised 5,000 47,500 52,500 Stock based compensation 19,496 19,496 ------------- ------------- ------------- ------------- ------------- Balance, March 31, 2006 $ 888,283 $ (145,575) $ 3,893,588 $ 2,262,700 $ 6,898,996 ============= ============= ============= ============= =============
Share Activity 2006 2005 2004 ---------- ---------- ---------- Common stock issued At beginning of year 1,766,566 1,766,566 1,766,566 Issued 10,000 -- -- Cancelled -- -- -- ---------- ---------- ---------- At end of year 1,776,566 1,766,566 1,766,566 Held in treasury At beginning of year (33,525) (30,525) (30,244) Acquisitions -- (3,000) (281) ---------- ---------- ---------- At end of year (33,525) (33,525) (30,525) ---------- ---------- ---------- Common shares outstanding at end of year 1,743,041 1,733,041 1,736,041 ========== ========== ========== The accompanying notes to the consolidated financial statements are an integral part of these statements. F5 Mexco Energy Corporation and Subsidiaries CONSOLIDATED STATEMENTS OF CASH FLOWS Year ended March 31,
2006 2005 2004 ------------ ------------ ------------ Cash flows from operating activities: Net earnings $ 788,805 $ 577,527 $ 429,846 Cumulative effect of accounting change -- -- 102,267 Adjustments to reconcile net income to net cash provided by operating activities: Provision for deferred income taxes 291,452 196,012 137,489 Stock-based compensation 19,496 42,099 47,424 Depreciation, depletion, and amortization 658,365 582,268 633,443 Accretion of asset retirement obligations 23,436 24,735 24,246 Impairment of long-term asset 261,617 -- -- Minority interest in loss of GazTex, LLC (41,799) (14,314) -- (Increase) decrease in accounts receivable 14,167 (43,706) 181,386 (Increase) decrease in prepaid expenses (68,214) 25,020 (22,340) Increase (decrease) in income taxes payable (48,127) 48,127 -- Increase (decrease) in accounts payable and accrued expenses 1,467 13,860 (16,282) ------------ ------------ ------------ Net cash provided by operating activities 1,900,665 1,451,628 1,517,479 Cash flows from investing activities: Additions to oil and gas properties (676,633) (1,568,810) (982,872) Proceeds from sale of oil and gas properties and equipment 65,532 81,008 -- Additions to other property and equipment (2,993) (2,313) (834) Investment in GazTex, LLC -- (282,126) -- ------------ ------------ ------------ Net cash used in investing activities (614,094) (1,772,241) (983,706) Cash flows from financing activities: Issuance of common stock 52,500 -- -- Acquisition of treasury stock -- (16,650) (1,389) Profits from sale of stock by insider -- -- 2,950 Reduction of capital lease obligations -- -- (61,086) Reduction of long-term debt (1,390,000) (660,000) (770,000) Proceeds from long term debt -- 950,000 320,000 Minority interest contributions 18,488 39,677 -- ------------ ------------ ------------ Net cash (used in) provided by financing activities (1,319,012) 313,027 (509,525) ------------ ------------ ------------ Net increase (decrease) in cash and cash equivalents (32,441) (7,586) 24,248 Cash and cash equivalents at beginning of year 85,209 92,795 68,547 ------------ ------------ ------------ Cash and cash equivalents at end of year $ 52,768 $ 85,209 $ 92,795 ============ ============ ============ Interest paid $ 102,669 $ 84,662 $ 83,196 Income taxes paid $ 88,551 $ 12,269 $ 50,000
The accompanying notes to the consolidated financial statements are an integral part of these statements. F6 MEXCO ENERGY CORPORATION AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. Nature of Operations Mexco Energy Corporation (a Colorado Corporation), its wholly owned subsidiary, Forman Energy Corporation, and its 90% owned subsidiary, OBTX, LLC (a Delaware Limited Liability Company) (collectively, the "Company") are engaged in the exploration, development and production of natural gas, crude oil, condensate and natural gas liquids (NGLs). OBTX, LLC was formed on April 8, 2004, and is included in the consolidated financial statements since its date of formation. Although most of the Company's oil and gas interests are centered in West Texas, the Company owns producing properties and undeveloped acreage in ten states. 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. 2. Summary of Significant Accounting Policies Principles of Consolidation. The consolidated financial statements include the accounts of Mexco Energy Corporation and its wholly owned and majority owned subsidiaries. All significant intercompany balances and transactions associated with the consolidated operations have been eliminated. Estimates and Assumptions. In preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management is required to make informed judgments and estimates that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period. 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, the related present value of estimated future net cash flows and the future development, dismantlement and abandonment costs. 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 as defined by the Securities and Exchange Commission ("SEC"). Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as property and equipment. This includes any internal costs that are directly related to exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Effective with the adoption of SFAS No. 143 in fiscal 2004, the carrying amount of oil and gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation when incurred. Generally, no gains or losses are recognized on the sale or disposition of oil and gas properties. Excluded Costs. Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent investments in unproved properties and major development projects. These costs are excluded until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed at least quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the capitalized costs being amortized (the depreciation, depletion and amortization (DD&A) pool) or a charge is made against earnings for those international operations where a reserve base has not yet been established. Impairments transferred to the DD&A pool increase the DD&A rate. Depreciation, Depletion and Amortization. The depreciable base for oil and gas properties includes the sum of capitalized costs net of accumulated DD&A, estimated future development costs and asset retirement costs not accrued in oil and gas properties, less costs excluded from amortization and salvage. The depreciable base of oil and gas properties and mineral investments are amortized using the unit-of-production method. F7 Ceiling Test. Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test determines a limit, on a country-by-country basis, on the book value of oil and gas properties. The capitalized costs of proved oil and gas properties, net of accumulated DD&A and the related deferred income taxes, may not exceed the estimated future net cash flows from proved oil and gas reserves, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, generally using prices in effect at the end of the period held flat for the life of production and including the effect of derivative contracts that qualify as cash flow hedges, discounted at 10%, net of related tax effects, plus the cost of unevaluated properties and major development projects excluded from the costs being amortized. If capitalized costs exceed this limit, the excess is charged to expense and reflected as additional accumulated DD&A. Asset Retirement Obligations ("ARO"). The Company has significant obligations to plug and abandon natural gas and crude oil wells and related equipment at the end of oil and gas production operations. The Company records the fair value of a liability for an ARO in the period in which it is incurred and a corresponding increase in the carrying amount of the related asset. Subsequently, the asset retirement costs included in the carrying amount of the related asset are allocated to expense using the units of production method. In addition, increases in the discounted ARO liability resulting from the passage of time are reflected as accretion expense in the Consolidated Statement of Operations. Estimating the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes adequate restoration. The Company uses the present value of estimated cash flows related to its ARO to determine the fair value. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the related asset. Long Term Investment in GazTex, LLC. The Company accounts for its investment in a limited liability company on the equity basis and adjusts the investment balance to agree with its equity in the underlying assets of the entity. 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. Revenue Recognition and Gas Balancing. Oil and gas sales and resulting receivables are recognized when the product is delivered to the purchaser and title has transferred. Sales are to credit-worthy energy purchasers with payments generally received within 60 days of transportation from the well site. The Company has historically had little, if any, uncollectible oil and gas receivables; therefore, an allowance for uncollectible accounts is not required. Gas imbalances are accounted for under the sales method whereby revenues are recognized based on production sold. A liability is recorded when the Company's excess takes of natural gas volumes exceed its estimated remaining recoverable reserves (over produced). No receivables are recorded for those wells where the Company has taken less than its ownership share of gas production (under produced). The Company has no significant gas imbalances. Income Per Common Share. Basic income per share is computed by dividing net income by the weighted average number of shares outstanding during the period. Diluted income per share is computed by dividing net income by the weighted average number of common shares and dilutive potential common shares (stock options and warrants) outstanding during the period. In periods where losses are reported, the weighted-average number of common shares outstanding excludes potential common shares, because their inclusion would be anti-dilutive. The following is a reconciliation of the number of shares used in the calculation of basic income per share and diluted income per share for the periods ended March 31: 2006 2005 2004 --------- --------- --------- Weighted average number of common shares outstanding, basic 1,733,890 1,734,726 1,736,047 Incremental shares from the assumed exercise of dilutive stock options 93,136 66,441 66,253 --------- --------- --------- Dilutive potential common shares 1,827,026 1,801,167 1,802,300 ========= ========= ========= F8 Outstanding options and warrants to purchase 90,000 and 10,000 shares at March 31, 2005 and 2004, respectively, were not included in the computation of diluted net earnings per share because the exercise price of the options or warrants was greater than the average market price of the common shares and, therefore, the effect would be anti-dilutive. For the year ended March 31, 2006, no anti-dilutive shares relating to stock options were excluded from the calculation. 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. Stock Options and Warrants. The Company accounts for employee stock option grants in accordance with Accounting Principles Board ("APB") Opinion No. 25, "Accounting for Stock Issued to Employees," as amended by Financial Accounting Standards Board ("FASB") Interpretation No. 44, "Accounting for Certain Transactions involving Stock Compensation," an interpretation of APB Opinion No. 25. The Company applies the intrinsic-value method in accounting for its employee stock options and records no compensation costs for its stock option awards to employees. The Company recognizes compensation cost related to stock options awarded to independent consultants based on fair value of the options at date of grant. If compensation cost for the Company's stock option plan had been determined based on the fair value at the grant dates for all employee awards under the plan, net income, basic income per common share and diluted income per common share would have been as follows:
2006 2005 2004 ------------ ------------ ------------ Net income, as reported $ 788,805 $ 577,527 $ 429,846 Deduct: Stock-based employee compensation expense determined under fair value based method (SFAS 123), net of tax (72,078) (90,081) (86,070) ------------ ------------ ------------ Net income, pro forma $ 716,727 $ 487,446 $ 343,776 ============ ============ ============ Basic income per share: As reported $ 0.45 $ 0.33 $ 0.25 Pro forma $ 0.41 $ 0.28 $ 0.20 Diluted income per share: As reported $ 0.43 $ 0.32 $ 0.24 Pro forma $ 0.39 $ 0.27 $ 0.19
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. Recent Accounting Pronouncements. In December 2004, the Financial Accounting Standard Board (FASB) issued SFAS No. 123R, "Share-Based Payment," a revision to SFAS No. 123. SFAS No. 123R supersedes APB Opinion No. 25 and establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. This statement requires that the cost of all share-based payment transactions be recorded as an expense at their fair value determined by applying a fair value measurement method. The Company will adopt this standard in the first quarter of fiscal 2007 (the quarter ending June 2006), using the modified prospective method requiring the recognition of compensation expense for all awards granted after the date of adoption, and for the unvested portion of previously granted awards outstanding as of the date of adoption. The amount of expense to be recognized in future periods will depend on the levels of future grants, however, considering options outstanding at March 31, 2006, including employees, directors and consultants, the effect on March 31, 2007 net income would be approximately $41,000 net of tax. F9 In March 2005, the FASB issued FASB Interpretation (FIN) No. 47, "Accounting for Conditional Asset Retirement Obligation." This Interpretation clarifies the definition and treatment of conditional asset retirement obligations as discussed in FASB Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations." A conditional asset retirement obligation is defined as an asset retirement activity in which the time and/or method of settlement are dependent on future events that may be outside the control of the Company. FIN 47 states that a company must record a liability when incurred for conditional asset retirement obligations if the fair value of the obligation is reasonably estimable. This Interpretation is intended to provide more information about long-lived assets, more information about future cash outflows for these obligations and more consistent recognition of these liabilities. FIN 47 is effective for fiscal years ending after December 15, 2005. The Company does not believe that its financial position, results of operations or cash flows were materially impacted by this Interpretation since the Company currently records all asset retirement obligations. In May 2005, the FASB issued FASB No. 154, "Accounting Changes and Error Corrections" (Statement 154). Statement 154 requires companies to recognize changes in accounting principle, including changes required by a new accounting pronouncement when the pronouncement does not include specific transition provisions, retrospectively to prior periods' financial statements. Statement 154 will become effective for the Company's fiscal year beginning April 1, 2006. The Company does not believe that the adoption of Statement 154 will have a material effect on its financial position or results of operations. 3. Long-Term Debt The Company has a revolving credit agreement with Bank of America, N.A. ("Bank"), which provides for a credit facility of $5,000,000, subject to a borrowing base determination. Effective September 28, 2005, the credit agreement was amended with a maturity date of April 1, 2007 and the borrowing base was redetermined and increased to $3,250,000 with no monthly commitment reductions. As of March 31, 2006, the balance outstanding under this agreement was $600,000 compared to $1,990,000 at March 31, 2005. No principal payments are anticipated to be required through March 31, 2007 based on the revised borrowing base. 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 (7.75% and 5.75% at March 31, 2006 and 2005, respectively). This agreement generally restricts the Company's ability to transfer assets or control of the Company, incur debt, extend credit, change the nature of the Company's business, substantially change management personnel or pay cash dividends. 4. Asset Retirement Obligations The Company's asset retirement obligations relate to the plugging and abandonment of oil and gas properties. The Company adopted SFAS No. 143 on April 1, 2003. SFAS No. 143 requires the fair value of a liability for an asset retirement obligation to be recorded in the period in which it is incurred and a corresponding increase in the carrying amount of the related long-lived asset. The change resulted in a cumulative effect charge to net income of ($102,267) net of tax, or ($0.06) per share. Additionally, the Company recorded an asset retirement obligation liability of $358,419 and an increase to net properties and equipment and other assets of $210,206 upon adoption of SFAS No. 143. The asset retirement obligation, which is included on the consolidated balance sheet, was $372,956 at March 31, 2006. The current portion of the asset retirement obligation as of March 31, 2006, was $20,540 and is included on the consolidated balance sheet in accounts payable and other accrued expenses. Accretion expense for fiscal 2006 and 2005 was $23,436 and $24,735, respectively. F10 The following table provides a rollforward of the asset retirement obligation for the fiscal years ended March 31, 2006 and 2005:
2006 2005 ---------- ---------- Carrying amount of asset retirement obligations as of April 1 $ 395,046 $ 420,665 Liabilities incurred 2,851 4,831 Liabilities settled (48,377) (55,185) Accretion expense 23,436 24,735 ---------- ---------- Carrying amount of asset retirement obligations as of March 31 372,956 395,046 Less: Current portion 20,540 20,540 ---------- ---------- Non-Current asset retirement obligation $ 352,416 $ 374,506 ========== ==========
5. Income Taxes Deferred tax assets and liabilities are the result of temporary differences between the financial statement carrying values and the tax bases of assets and liabilities. Significant components of net deferred tax assets (liabilities) at March 31 are as follows:
2006 2005 ------------ ------------ Deferred tax assets: Percentage depletion carryforwards $ 449,500 $ 411,907 Vacation accrual 3,787 2,714 Deferred compensation 62,456 69,587 Asset retirement obligation 115,616 122,464 Net operating loss 52,041 -- ------------ ------------ 683,400 606,672 Deferred tax liabilities: Excess financial accounting bases over tax bases of property and equipment (1,690,136) (1,321,956) ------------ ------------ Net deferred tax liabilities $ (1,006,736) $ (715,284) ============ ============
As of March 31, 2006, the Company has statutory depletion carryforwards of approximately $1,450,000, 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: 2006 2005 2004 ------------ ------------ ------------ Tax expense at statutory rate $ 360,721 $ 284,180 $ 239,011 Depletion in excess of basis (10,806) -- (39,563) Effect of graduated rates (31,828) (25,075) (21,089) Revision of prior year estimates (46,099) 2,526 -- Other 152 10,978 (7,499) ------------ ------------ ------------ $ 272,140 $ 272,609 $ 170,860 ============ ============ ============ Effective tax rate 26% 33% 24% ============ ============ ============ 6. Exploration Agreement On December 5, 2002, the Company entered into an exploration agreement with Falcon Bay Operating, LLC. Pursuant to such agreement, the Company obtained the right to purchase and inventory seismic data and acreage in shallow water areas of Texas and Louisiana. In consideration for the right to obtain four such prospects, the Company issued warrants to purchase 107,500 shares of common stock at an exercise price of $5.00 per share. Such warrants were exercisable for a period of two years from date of grant and expired, unexercised on December 5, 2004. This agreement provided for the issuance of additional warrants, exercisable for two years at the same exercise price, covering 322,500 shares upon exercise of the Company's right to participate in a total of four prospects. In fiscal 2006 both parties elected not to participate in any additional prospects; therefore, no further warrants will be issued. F11 7. Investment in GazTex, LLC The Company's long-term assets consist of an investment in GazTex, LLC, a Russian company owned 50% by OBTX, LLC, accounted for by the equity method. OBTX, LLC is a Delaware limited liability company in which Mexco owns 90% of the interest, with the remaining 10% divided equally among three individuals, one of whom is Arden Grover, a director of Mexco Energy Corporation. All geological and geophysical costs associated with the evaluation of Russian properties have been paid 90% by Mexco Energy Corporation and 10% by the other three owners of OBTX, LLC. These amounts will not be reimbursed, but instead represent an investment in GazTex, LLC. GazTex, LLC was formed during fiscal 2005 and through March 31, 2006 has no operations other than the evaluation activity. The original capitalized amount associated with a certain Russian project in the amount of $261,617 was expensed during fiscal 2006 due to the termination of this project. The remaining balance of $20,509 represents the cash balance of our investment in GaxTex, LLC. The 10% interest in OBTX, LLC is included in the Company's financial statements as a minority interest. OBTX, LLC, plans to participate in any Russian venture entered into and own a 50% interest. Through March 31, 2006, in addition to the write-down of the long-term asset, the Company expensed approximately $185,000 in consulting costs for the evaluation of potential Russian projects. 8. Major Customers Currently, 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 2006, 2005, and 2004, one purchaser accounted for 16%, 21% and 29%, respectively, of revenues. At March 31, 2006, accounts receivable from the purchaser was approximately 13% of oil and gas accounts receivable. 9. Oil and Gas Costs The costs related to the oil and gas activities of the Company were incurred as follows: Year Ended March 31, ---------------------------------------- 2006 2005 2004 ---------- ---------- ---------- Property acquisition costs Proved $ 171,593 $1,203,768 $ 339,519 Unproved U.S. 29,592 104,713 184,912 Unproved Russia -- -- 41,596 Exploration costs 96,936 78,753 4,757 Development costs 335,122 193,446 453,684 The Russian costs included in 2004 have been contributed to GazTex, LLC and are included in the statement of operations as part of the impairment in the long-term investment in GazTex, LLC. F12 The Company had the following aggregate capitalized costs relating to the Company's oil and gas property activities at March 31:
2006 2005 2004 ------------- ------------- -------------- Proved oil and gas properties $ 18,655,627 $ 17,098,091 $ 15,758,031 Unproved oil and gas properties: subject to amortization 170,487 357,164 342,927 not subject to amortization-U.S. 121,418 921,719 817,006 not subject to amortization-Russia - - 41,596 ------------- ------------- -------------- 18,947,532 18,376,974 16,959,560 Less accumulated depreciation, depletion, and amortization 10,554,659 9,899,582 9,320,174 ------------- ------------- -------------- $ 8,392,873 $ 8,477,392 $ 7,639,386 ============= ============= =============
The cost of certain oil and gas leases that the Company has acquired, but not evaluated, have been excluded in computing amortization of the full cost pool. The Company will begin to amortize these properties when the projects are evaluated, which is currently estimated to be within the following year. Costs excluded from amortization at March 31, 2006 and 2005 total $121,418 and $921,719, respectively. The total of the East Umbrella Prospect which was previously excluded from amortization was added to the full cost amortization base for fiscal 2006. No impairment exists for the remaining property at March 31, 2006 based on geological studies. Depreciation, depletion, and amortization amounted to $8.35, $6.84 and $6.24 per equivalent barrel of production for the years ended March 31, 2006, 2005, and 2004, respectively. 10. Stockholders' Equity In fiscal 2003, the board of directors authorized the use of up to $250,000 to repurchase shares of the Company's common stock. During fiscal 2003, the Company repurchased 30,244 shares at an aggregate cost of $127, 536 for the treasury account. In fiscal 2004, the board of directors repurchased 281 shares at an aggregate cost of $1,389 for the treasury account. During fiscal 2005, the Company purchased 3,000 shares at an aggregate cost of $16,650 for the treasury account. During the last quarter of fiscal 2004, the Chairman of the board paid the Company $2,950, representing profits on stock sold which he held less than six months. Such payment was made in accordance with Section 16(b) of the Securities Exchange Act of 1934. 11. Stock Options and Warrants The Company adopted an employee incentive stock plan effective September 15, 1997. Under the plan, 350,000 shares are available for distribution. Awards, granted at the discretion of the compensation committee of the board of directors, include stock options of restricted stock. Stock options may be an incentive stock option or a nonqualified stock option. Options to purchase common stock under the plan are granted at the fair market value of the common stock at the date of grant, become exercisable to the extent of 25% of the shares optioned on each of four anniversaries of the date of grant, expire ten years from the date of grant and are subject to forfeiture if employment terminates. Restricted stock awards may be granted with a condition to attain a specified goal. The purchase price will be at least $5.00 per share of restricted stock. The awards of restricted stock must be accepted within 60 days and will vest as determined by agreement. Holders of restricted stock have all rights of a shareholder of the Company. In September 2004, the Board of Directors of the Company adopted the 2004 Incentive Stock Plan to replace, modify and extend the termination date of the September 15, 1997 stock plan to September 14, 2009. This new plan provides for the award of stock options up to 375,000 shares of which 125,000 may be the subject of stock grants without restrictions and without payment by the recipient and stock awards of up to 125,000 shares with restrictions including payment for the shares and employment of not less than three years from the date of the award. The terms of the stock options are similar to those of the existing stock option plan except that the term of the Plan is five years from the date of its adoption. F13 During fiscal 2006, no options were granted and 10,000 options were exercised. Additional information with respect to the Plan's stock option activity for options issued to employees and directors is as follows: Weighted Number Average of Shares Exercise Price -------------- -------------- Options outstanding, at March 31, 2003 181,000 $ 5.71 Granted 39,000 6.00 Exercised -- -- Forfeited -- -- -------------- -------------- Options outstanding, at March 31, 2004 220,000 5.76 Granted 30,000 6.52 Exercised -- -- Forfeited -- -- -------------- -------------- Options outstanding, at March 31, 2005 250,000 5.85 Granted -- -- Exercised 10,000 5.25 Forfeited -- -- -------------- -------------- Options outstanding, at March 31, 2006 240,000 $ 5.88 ============== ============== Options exercisable at March 31, 2004 142,750 $ 6.08 Options exercisable at March 31, 2005 170,250 $ 5.94 Options exercisable at March 31, 2006 190,250 $ 5.87 Weighted average grant date fair value of stock options granted to employees and directors during fiscal 2005 and 2004 were $3.98 and $4.82, respectively. These values were determined using a Binomial option-pricing model. The model values options based on the stock price at the grant date, the expected life of the option, the estimated volatility of the stock, the expected dividend payments and the risk-free interest rate over the expected life of the option. The 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. The assumptions used in the Binomial models were as follows for stock options granted in fiscal 2005 and 2004 (no options were granted during fiscal 2006): 2005 2004 ----------- --------- Expected volatility 62.99% 67.46% Expected dividend yield 0.00% 0.00% Risk-free rate of return 3.99% 3.40% Expected life of options 6.3 years 7 years The option valuation models were developed for use in estimating the fair value of traded options that have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions including expected stock price volatility. F14 The following tables summarize information about employee and directors stock options outstanding and exercisable at March 31, 2006: Stock Options Outstanding Weighted Average Number of Remaining Weighted Range of Options Contractual Average Exercise Prices Outstanding Life in Years Exercise Price - --------------- ----------- -------------------- -------------- $7.50-$7.75 50,000 2.56 $7.60 $6.70-$6.75 40,000 6.54 $6.73 $6.00-$6.17 49,000 6.50 $6.03 $5.25 50,000 3.98 $5.25 $4.00 51,000 5.88 $4.00 ----------- 240,000 Stock Options Exercisable Number of Weighted Range of Options Average Exercise Prices Exercisable Exercise Price --------------- ----------- -------------- $7.50-$7.75 50,000 $7.60 $6.70-$6.75 25,000 $6.74 $6.00-$6.17 22,000 $6.02 $5.25 50,000 $5.25 $4.00 43,250 $4.00 ----------- 190,250 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. The Company recognizes expense related to stock options awarded to independent consultants and contractors based on fair value of the options at date of grant. Additional information with respect to stock option and warrant activity for options and warrants granted to outside consultants and contractors is as follows: Number of Weighted Options/ Average Warrants Exercise Price -------------- -------------- Options outstanding, at March 31, 2003 207,500 $ 5.39 Granted 10,000 7.00 Exercised -- -- Forfeited -- -- -------------- -------------- Options outstanding, at March 31, 2004 217,500 5.83 Granted 10,000 5.65 Exercised -- -- Forfeited* 107,500 5.00 -------------- -------------- Options outstanding, at March 31, 2005 120,000 5.89 Granted -- -- Exercised -- -- Forfeited** 10,000 5.65 -------------- -------------- Options outstanding, at March 31, 2006 110,000 $ 5.91 ============== ============== Options exercisable at March 31, 2004 180,000 $ 5.48 Options exercisable at March 31, 2005 90,000 $ 5.75 Options exercisable at March 31, 2006 100,000 $ 5.95 F15 *Warrants issued December 5, 2002 to purchase 107,500 shares of common stock at an exercise price of $5.00 expired December 5, 2004. **Options granted March 3, 2005 to purchase 10,000 shares of common stock at an exercise price of $5.65 were forfeited by the consultant on July 1, 2005. Weighted average grant date fair value of stock options and warrants granted to outside consultants and contractors during fiscal 2005 and 2004 were $3.23 and $5.46, respectively. These values were determined using a Binomial option-pricing model. The assumptions used in the Binomial models were as follows for stock options granted in fiscal 2005 and 2004 (no options were granted in fiscal 2006): 2005 2004 ------- ------- Expected volatility 65.91% 62.52% Expected dividend yield 0.00% 0.00% Risk-free rate of return 4.01% 3.81% Expected life of options 5 years 7 years The following tables summarize information about outside consultants and contractors stock options outstanding and exercisable at March 31, 2006 (no warrants were outstanding): Stock Options Outstanding Weighted Average Number of Remaining Weighted Range of Options Contractual Average Exercise Prices Outstanding Life in Years Exercise Price - --------------- ----------- -------------------- -------------- $7.50-$7.75 20,000 2.47 $7.63 $7.00 10,000 7.65 $7.00 $6.75 30,000 4.82 $6.75 $5.25 20,000 3.98 $5.25 $4.00 30,000 5.97 $4.00 ----------- 110,000 Stock Options Exercisable Number of Weighted Range of Options Average Exercise Prices Exercisable Exercise Price --------------- ----------- -------------- $7.50-$7.75 20,000 $7.63 $7.00 5,000 $7.00 $6.75 30,000 $6.75 $5.25 20,000 $5.25 $4.00 25,000 $4.00 ---------- 100,000 The Company recognizes expense related to stock options awarded to independent consultants based on fair value of the options at date of grant. Total expense related to these awards was $ 19,496, 42,099 and $47,424 for fiscal 2006, 2005 and 2004, respectively. The Company capitalizes fair value of warrants as part of the leasehold cost of the acreage acquired in connection with the issuance of the warrants. 12. Related Party Transactions Related party transactions with the majority stockholder for the years ended March 31, 2006, 2005, and 2004 relate to shared office expenditures. The total billed to the stockholder for years ended March 31, 2006, 2005 and 2004 was $40,805, $6,612 and $18,118, respectively. F16 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 $5,234, $13,835 and $8,094 for the years ended March 31, 2006, 2005 and 2004, respectively. Arden Grover is a director of the Company and owns 3 1/3% of OBTX, LLC. Mr. Grover serves as a member of the board of directors of both OBTX, LLC and its 50% owned Russian subsidiary GazTex LLC. Since inception of this venture, Mr. Grover has invested $19,389 as his share of 3 1/3% ownership of OBTX, LLC. During the year ending March 31, 2004, Thomas Craddick, a member of the board of directors and Company employee, entered into an agreement with Deepwater Resources, L.P. and Gary Martin, whereby he receives a 1.5% overriding royalty on certain leases related to the Lodgepole Prospect in Stark County, North Dakota. In January 2004, the Company purchased a one-quarter interest in these leases and/or options to lease. As of March 31, 2006 these leases have not been developed; therefore, Mr. Craddick has received no revenue from this agreement. 13. Oil and Gas Reserve Data (Unaudited) The estimates of the Company's proved oil and gas reserves, which are located entirely within the United States, were prepared in accordance with the guidelines established by the SEC and FASB. These guidelines require that reserve estimates be prepared under existing economic and operating conditions at year-end, with no provision for price and cost escalators, except by contractual agreement. The estimates as of March 31, 2006, 2005, and 2004 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:
2006 2005 2004 ----------------------- ----------------------- ----------------------- Bbls Mcf Bbls Mcf Bbls Mcf ---------- ---------- ---------- ---------- ---------- ---------- Proved reserves, beginning of year 151,000 7,327,000 132,000 7,917,000 150,000 7,931,000 Revision of previous estimates 47,000 (292,000) 31,000 (660,000) 2,000 214,000 Purchase of minerals in place -- 36,000 3,000 482,000 -- 260,000 Extensions and discoveries 2,000 1,000 2,000 30,000 -- -- Sales of minerals in place -- (5,000) -- (38,000) -- -- Production (17,000) (370,000) (17,000) (404,000) (20,000) (488,000) ---------- ---------- ---------- ---------- ---------- ---------- Proved reserves, end of year 183,000 6,697,000 151,000 7,327,000 132,000 7,917,000 ========== ========== ========== ========== ========== ========== Proved Developed Reserves: Beginning of year 108,000 4,597,000 77,000 4,274,000 94,000 4,518,000 End of year 87,000 3,891,000 108,000 4,597,000 77,000 4,274,000
The following is a standardized measure of the discounted net future cash flows and changes applicable to proved oil and gas reserves required by Statement of Financial Accounting Standards No. 69, Disclosures about Oil and Gas Producing Activitites (SFAS No. 69). The future cash flows are based on estimated oil and gas reserves utilizing prices and costs in effect as of year end, discounted at 10% per year and assuming continuation of existing economic conditions. F17 During fiscal 2006, the average sales price received by the Company for its oil was approximately $54.84 per bbl, as compared to $41.90 and $29.00 in fiscal 2005 and 2004, respectively; while the average sales price for the Company's gas was approximately $7.51 per mcf in fiscal 2006, as compared to $5.53 and $4.76 in fiscal 2005 and 2004, respectively. The standardized measure of discounted future net cash flows, in management's opinion, should be examined with caution. The basis for this table is the reserve studies prepared by independent petroleum engineering consultants, which contain imprecise estimates of quantities and rates of production of reserves. Revisions of previous year estimates can have a significant impact on these results. Also, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates of proved reserves and their valuation. Therefore, the standardized measure of discounted future net cash flow is not necessarily indicative of the fair value of the Company's proved oil and gas properties. Future income tax expense was computed by applying statutory rates less the effects to tax credits for each period presented to the difference between pre-tax net cash flows relating to the Company's proved reserves and the basis of proved properties and available net operating loss and percentage depletion carryovers. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves:
March 31, ------------------------------------------ 2006 2005 2004 ------------ ------------ ------------ Future cash inflows $ 55,804,000 $49,785,000$ 46,230,000 Future production and development costs (13,939,000) (12,518,000) (12,225,000) Future income taxes (a) (9,646,000) (8,517,000) (7,761,000) ------------ ------------ ------------ Future net cash flows 32,219,000 28,750,000 26,244,000 Annual 10% discount for estimated timing of cash flows (14,295,000) (12,591,000) (11,482,000) ------------ ------------ ------------ Standardized measure of discounted future net cash flows $ 17,924,000 $ 16,159,000 $ 14,762,000 ============ ============ ============
(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 Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
Year Ended March 31, ---------------------------------------- 2006 2005 2004 ------------ ------------ ------------ Sales of oil and gas produced, net of production costs $ (2,873,000) $ (2,184,000) $ (1,968,000) Net changes in price and production costs 3,985,000 2,167,000 (1,697,000) Changes in previously estimated development costs 701,000 (539,000) -- Revisions of quantity estimates 428,000 (1,053,000) 524,000 Net change due to purchases and sales of minerals in place 74,000 1,305,000 681,000 Extensions and discoveries, less related costs 45,000 156,000 -- Net change in income taxes (579,000) (422,000) 436,000 Accretion of discount 2,095,000 1,912,000 2,077,000 Changes in timing of estimated cash flows and other (2,111,000) 55,000 (1,263,000) ------------ ------------ ------------ Changes in standardized measure 1,765,000 1,397,000 (1,210,000) Standardized measure, beginning of year 16,159,000 14,762,000 15,972,000 ------------ ------------ ------------ Standardized measure, end of year $ 17,924,000 $ 16,159,000 $ 14,762,000 ============ ============ ============
F18 14. Selected Quarterly Financial Data (Unaudited)
FISCAL 2006 ----------------------------------------------- 4TH QTR 3RD QTR 2ND QTR 1ST QTR ---------- ---------- ---------- ---------- Oil and gas revenue $ 868,405 $1,111,524 $ 933,915 $ 802,720 Operating profit (loss) (93,373) 558,781 362,778 286,780 Net income (loss) (12,444) 354,608 285,723 160,918 Net income (loss) per share-basic (0.01) 0.20 0.16 0.09 Net income (loss) per share-diluted (0.01) 0.19 0.15 0.09
FISCAL 2005 ----------------------------------------------- 4TH QTR 3RD QTR 2ND QTR 1ST QTR ---------- ---------- ---------- ---------- Oil and gas revenue $ 791,476 $ 774,966 $ 722,452 $ 674,995 Operating profit 250,596 287,220 225,160 161,254 Net income 172,406 183,359 119,060 102,702 Net income per share-basic 0.09 0.11 0.07 0.06 Net income per share-diluted 0.09 0.10 0.07 0.06
During the fourth quarter of fiscal 2006 we had a net loss of $12,444. This was primarily the result of an impairment in our Russian venture. We expensed approximately $261,617, which represents the impairment of our investment in GazTex, LLC. Additionally, depreciation, depletion and amortization increased as a result of the leases on the East Umbrella Point prospect expiring during the fourth quarter. These leases were previously being excluded from the amortization base but were added when the leases expired. The increased depreciation, depletion and amortization expense is also a result of a decrease in reserves. F19 INDEX TO EXHIBITS Exhibit Number - ---------- 3.1* Articles of Incorporation. 3.2*** Bylaws. 10.1** Stock Option Plan. 10.2* Bank Line of Credit. 10.3**** 2004 Incentive Stock Option. 14.1***** Code of Business Conduct and Ethics. 21* Subsidiaries of the Company. 31.1 Certification by the President and Chief Executive Officer of the Company pursuant to Rule 13a -- 14(a) of the Securities Exchange Act of 1934. 31.2 Certification of the Chief Financial Officer of the Company pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934. 32.1 Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2 Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. - ------------------- * Incorporated by reference to the Company's Annual Report on Form 10-K dated June 24, 1998. ** Incorporated by reference to the Amendment to Schedule 14C Information Statement filed on August 13, 1998. *** Filed with the Company's Annual Report on Form 10-K dated June 29, 2004. **** Filed with the Company's Proxy Statement filed July 9, 2004. ***** Filed with the Company's Quarterly Report on Form 10-Q filed on November 15, 2004. EX-31.1 2 v046146_ex31-1.txt Exhibit 31.1 I, Nicholas C. Taylor, certify that: 1. I have reviewed this annual report on Form 10-K of Mexco Energy Corporation; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have: a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c. evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d. disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. June 23, 2006 /s/Nicholas C. Taylor -------------------------------------------- Nicholas C. Taylor President EX-31.2 3 v046146_ex31-2.txt Exhibit 31.2 I, Tamala L. McComic, certify that: 1. I have reviewed this annual report on Form 10-K of Mexco Energy Corporation; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and we have: a. designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared; b. designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; c. evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d. disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a. all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and b. any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. June 23, 2006 /s/Tamala L. McComic ----------------------------------------------- Tamala L. McComic Vice President, Treasurer, and Assistant Secretary EX-32.1 4 v046146_ex32-1.txt Exhibit 32.1 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report of Mexco Energy Corporation (the "Company") on Form 10-K for the year ending March 31, 2005, as filed with the SEC on the date hereof (the "Report"), I, Nicholas C. Taylor, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Dated: June 23, 2006 /s/ Nicholas C. Taylor -------------------------------------- President and Chief Executive Officer EX-32.2 5 v046146_ex32-2.txt Exhibit 32.2 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Annual Report of Mexco Energy Corporation (the "Company") on Form 10-K for the year ending March 31, 2005, as filed with the SEC on the date hereof (the "Report"), I, Tamala L. McComic, Vice President, Treasurer and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that: (1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Dated: June 23, 2006 /s/ Tamala L. McComic ----------------------------------------------------- Vice President, Treasurer and Chief Financial Officer -----END PRIVACY-ENHANCED MESSAGE-----