UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-K

 

[X]	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended March 31, 2014
[  ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

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:  Common Stock, $0.50 par value per share

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes [  ]  No [X]

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes [  ]  No [X]

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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 229.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes [X]  No [  ]

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§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 any amendment to this Form 10-K. [  ]

 

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer", "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act:

Large Accelerated Filer [  ]   Accelerated Filer [  ]   Non-Accelerated Filer [  ]   Smaller Reporting Company [X]

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes [  ]  No [X]

The aggregate market value of the voting stock held by non-affiliates of the Registrant as of September 30, 2013 (the last business day of the Registrant’s most recently completed second quarter) was $5,966,732 based on Mexco Energy Corporation’s closing common stock price of $6.56 per share on that date as reported by the NYSE MKT.

There were 2,038,266 shares of the registrant’s common stock outstanding as of June 25, 2014.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s Proxy Statement relating to the 2014 Annual Meeting of Shareholders to be held on September 9, 2014, 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 120 days after March 31, 2014, the end of the fiscal year covered by this report.

TABLE OF CONTENTS

PART I
Item 1.	Business	4
Item 1A.	Risk Factors	13
Item 1B.	Unresolved Staff Comments	20
Item 2.	Properties	20
Item 3.	Legal Proceedings	25
Item 4.	Mine Safety Disclosures	25
PART II
Item 5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	25
Item 6.	Selected Consolidated Financial Data	26
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	34
Item 8.	Financial Statements and Supplementary Data	35
Item 9.	Changes in and Disagreements with Accountants on Accounting and  Financial Disclosures	35
Item 9A.	Controls and Procedures	35
Item 9B.	Other Information	36
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	36
Item 11.	Executive Compensation	36
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	36
Item 13.	Certain Relationships and Related Transactions, and Director Independence	36
Item 14.	Principal Accounting Fees and Services	36
PART IV
Item 15.	Exhibits and Financial Statement Schedules	37
	Signatures	38
	Glossary of Abbreviations and Terms	39

As used in this document, “the Company”, “Mexco”, “we”, “us” and “our” refer to Mexco Energy Corporation and its consolidated subsidiaries.

Abbreviations or definitions of certain terms commonly used in the oil and gas industry and in this Form 10-K can be found in the “Glossary of Abbreviations and Terms”.

 

PART I

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”).  These forward-looking statements are generally located in the material set forth under the headings “Risk Factors”, “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, “Business”, “Properties” but may be found in other locations as well, and are typically identified by the words “could”, “should”, “expect”, “project”, “estimate”, “believe”, “anticipate”, “intend”, “budget”, “plan”, “forecast”, “predict” and other similar expressions.

Forward-looking statements generally relate to our 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 and are based upon our management’s reasonable estimates of future results or trends.  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 “Risk Factors”.  The factors that may affect our expectations regarding our operations include, among others, the following: our success in development, exploitation and exploration activities; our ability to make planned capital expenditures; declines in our production or prices of oil and gas; our ability to raise equity capital or incur additional indebtedness; our restrictive debt covenants; our acquisition and divestiture activities; weather conditions and events; the proximity, capacity, cost and availability of pipelines and other transportation facilities; increases in the cost of drilling, completion and gas gathering or other costs of production and operations; and other factors discussed elsewhere in this document.

We disclaim any intention or obligation to update or revise any forward-looking statements as a result of new information, future events or otherwise.

 

ITEM 1.  BUSINESS

General

Mexco Energy Corporation, a Colorado corporation, is an independent oil and gas company engaged in the exploration, development and production of natural gas and crude oil properties located in the United States.  Incorporated in April 1972 under the name Miller Oil Company, the Company changed its name to Mexco Energy Corporation effective April 30, 1980.  At that time, the shareholders of the Company also approved amendments to the Articles of Incorporation resulting in a one-for-fifty reverse stock split of the Company's common stock.

On December 31, 2012, Mexco acquired all of the outstanding ownership interests of TBO Oil & Gas, LLC, a Texas limited liability company which owns non-operated working interests producing primarily oil.

In September 2010, Mexco acquired all of the issued and outstanding stock of Southwest Texas Disposal Corporation, a Texas corporation which owns royalties producing primarily natural gas.

On February 25, 1997, Mexco 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.

Nicholas C. Taylor beneficially owns approximately 44% of the outstanding shares of our common stock. Mr. Taylor is also our Chairman of the Board 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.

 

Company Profile

Since our inception, we have been engaged in acquiring and developing oil and gas properties and the exploration for and production of natural gas, crude oil, condensate and natural gas liquids (“NGLs”) within the United States.  We have focused primarily on acquiring natural gas reserves until 2011 when we changed our focus to oil.  We especially seek to acquire proved reserves that fit well with existing operations or in areas where Mexco has established production.  Acquisitions preferably will contain most of their value in producing wells, behind pipe reserves and high quality proved undeveloped locations.  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 to acquire reserves without assuming significant price and production risks.  We actively search 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 2015.

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 prospects that could have a potentially meaningful impact on our reserves.

Oil and Gas Operations

As of March 31, 2014, natural gas constituted approximately 68% of our total proved reserves and approximately 35% of our revenues for fiscal 2014.  Revenues from oil and gas royalty interests accounted for approximately 23% of our revenues for fiscal 2014.

Mexco believes there is potential for horizontal drilling, multi-stage fracturing and production of oil and gas in a substantial number of properties containing approximately 900 wells in which Mexco holds an interest.  These wells are located in the core area of the horizontal Wolfcamp multi-zone formation in Reagan, Upton, Midland, Martin, Glasscock and Andrews Counties in the Midland Basin of West Texas.  Such interests vary from .125% to 7.68% working interest (.094% to 6.24% net revenue interest).

For example, we are in the process of investing approximately $800,000 in 7 wells located in Reagan County, Texas.  The first 3 of these wells have been drilled and are currently being completed.  These wells are each undergoing a 50 stage zipper fracture treatment through horizontals of approximately 7,000 feet per well at a vertical depth of approximately 8,000 feet.

Also, we participated in a joint venture drilling 4 vertical development wells to a depth of 11,000 feet on 160 acre spacing in the Dean, Wolfcamp, Cline and Atoka formations on 640 acres in Reagan County, Texas.  Mexco’s working interest in this joint venture is .3% (.24% net revenue interest).  These wells will hold the rights for further development by horizontal drilling.  The Wolfcamp formation in this area is an approximately 1,700 feet thick section consisting of interbedded organic shales and carbonates and includes two reservoir units, the “A” and “B” benches that have both been successfully developed with horizontal wells.

 

 

In addition to these working interests we also own various mineral and royalty interests in and around these core counties in the Midland Basin, a part of the Permian Basin of West Texas.

For more details of these and other operations in this area see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources Commitments”.  See especially a description of the activities in which we are participating with operators including EOG Resources, Inc., Pioneer Natural Resources Company and several others on properties located in Reagan, Upton and Glasscock Counties, Texas on pages 27 and 28 below.  It is our plan to continue this pattern of development.

Newark East (Barnett Shale) Gas Field properties, encompassing 6,975 gross acres, 62 net acres, 155 gross producing wells and 1 net well in Denton, Johnson, Tarrant and Wise Counties, Texas, account for approximately 4% of our discounted future net cash flows from proved reserves as of March 31, 2014.  For fiscal 2014, this field, consisting of royalty interests, accounted for 7% of our gross revenues, 9% of our net revenues.

 

El Cinco Gas Field properties, encompassing 1,166 gross acres, 886 net acres, 8 gross producing wells and 6 net wells in Pecos County, Texas, account for approximately 24% of our discounted future net cash flows from proved reserves as of March 31, 2014.  This is a multi-pay area where most of the leases have potential reserves in two zones.  Of these discounted future net cash flows from proved reserves, approximately 11% are attributable to proven undeveloped reserves which will be developed through re-entry of existing wells and new drilling.  For fiscal 2014, these properties accounted for 13% of our gross revenues and 14% of our net revenues.

Gomez Gas Field properties, encompassing 13,058 gross acres, 72 net acres, 26 gross wells and .13 net wells in Pecos County, Texas, account for approximately 3% of our discounted future net cash flows from proved reserves as of March 31, 2014.  For fiscal 2014, these properties accounted for 4% of our gross revenues and 5% of our net revenues. All of these properties, except for one, are royalty interests.

The Haynesville area natural gas properties, encompassing 5,135 gross acres, 13 net acres, 8 gross producing wells and .02 net wells in DeSoto Parish, Louisiana, account for approximately 3% of our discounted future net cash flows from proved reserves as of March 31, 2014.  Of these discounted future net cash flows from proved reserves, approximately 2% are attributable to proven undeveloped reserves.  For fiscal 2014, these properties, consisting of royalty interests, accounted for 1% of our gross and net revenues.  This acreage contains an additional 56 potential drill sites.

The Fuhrman-Mascho field oil properties, encompassing 160 gross acres, 19 net acres, 10 gross producing wells and 1.17 net wells in Andrews County, Texas, account for approximately 5% of our discounted future net cash flows from proved reserves as of March 31, 2014.  For fiscal 2014, these properties accounted for 7% of our gross and net revenues. This acreage contains an additional 6 potential drill sites.

We own interests in and operate 16 producing wells and 1 water injection well.  We own partial interests in an additional 3,383 producing wells all of which are located within the United States in the states of Texas, New Mexico, Oklahoma, Louisiana, Alabama, Mississippi, 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:

Year	Oil(Bbls)	Gas (Mcf)
2014	27,186	361,652
2013	23,260	401,077
2012	19,442	395,649
2011	17,040	459,446
2010	18,036	545,991

 

 

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 made sales to the following companies that amounted to 10% or more of revenues for the year ended March 31:

	2014	2013	2012
Holly Refining	22%	26%	22%

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.

Regulation

Our exploration, development, production and marketing operations are subject to various types of 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 and bonds for drilling operations and reports concerning operations.  Most states and some counties and municipalities in which we operate regulate the location of wells; the method of drilling and casing wells; the rates of production or "allowables"; the surface use and restoration of properties upon which wells are drilled; the plugging and abandoning of wells; and notice to, and consultation with, surface owners and other third parties.  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 under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, interstate natural gas transportation rates and service conditions, which affect the marketing of natural gas we produce, as well as the revenues we receive for sales of such production.  Since 1978, various laws have been enacted which 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.

 

 

Commencing in 1985, the FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas.  Today, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company.  FERC's initiatives have led to the development of a competitive, unregulated, open access market for gas purchases and sales that permits all purchasers of gas to buy gas directly from third-party sellers other than pipelines.  However, the natural gas industry historically has been very heavily regulated.  Therefore, we cannot guarantee that the less stringent regulatory approach will continue indefinitely into the future, nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.

Sales of crude oil, condensate and natural gas liquids are not currently regulated and are made at negotiated market prices. Nevertheless, Congress could reenact price controls in the future.  The price we receive from the sale of these products is affected by the cost of transporting the products to market.  The FERC regulates interstate crude oil pipeline transportation rates under the Interstate Commerce Act.  In general, interstate crude oil pipeline rates must be cost-based, although many pipeline charges are today based on historical rates adjusted for inflation and other factors, and other charges may result from settlement rates agreed to by all shippers or market-based rates, which are permitted in certain circumstances.  Intrastate crude oil pipeline transportation rates are subject to regulation by state regulatory commissions.  Insofar as the interstate and intrastate transportation rates that we pay are generally applicable to all comparable shippers, we believe that the regulation of crude oil transportation rates will not affect our operations in a way that materially differs from the effect on the operations of our competitors who are similarly situated.  Further, interstate and intrastate common carrier crude oil pipelines must provide service on an equitable basis.  Under this standard, common carriers must offer service to all similarly situated shippers requesting service on the same terms and under the same rates.  When crude oil pipelines operate at full capacity, access is governed by prorating provisions set forth in the pipelines’ published tariffs.  Accordingly, we believe that access to crude oil pipeline transportation services generally will be available to us to the same extent as to our similarly situated competitors.

The State of Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production.  States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

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.

The following are some of the existing laws, rules and regulations to which our business is subject:

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 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.  Under CERCLA, such persons may be subject to joint and several liabilities for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies.  In addition, 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.

The federal Clean Air Act (“CAA”), and state air pollution laws and regulations provide a framework for national, state and local efforts to protect air quality.  The operations of oil and gas properties utilize equipment that emits air pollutants which may be subject to federal and state air pollution control laws. These laws require utilization of air emissions abatement equipment to achieve prescribed emissions limitations and ambient air quality standards, as well as operating permits for existing equipment and construction permits for new and modified equipment.  Permits and related compliance obligations under the CAA, as well as changes to state implementation plans for controlling air emissions in regional non-attainment areas may require oil and natural gas exploration and production operators to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies. In addition, some oil and natural gas facilities may be included within the categories of hazardous air pollutant sources, which are subject to increasing regulation under the CAA.  Failure to comply with these requirements could subject a regulated entity to monetary penalties, injunctions, conditions or restrictions on operations and enforcement actions.  On August 16, 2012, the EPA approved final regulations under the CAA that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, or VOCs, and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule seeks to achieve a 95% reduction in VOCs emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules will require a number of modifications to operations, including the installation of new equipment to control emissions from wells by January 1, 2015.  We believe that we are currently in compliance in all material respects with the requirements of applicable federal and state air pollution control laws.

 

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as greenhouse gases (“GHGs”) and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere.  These findings by the EPA allowed the agency to proceed with the adoption and implementation of regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. In September 2009, the EPA issued a GHG monitoring and reporting rule that requires certain parties, including participants in the oil and natural gas industry, to monitor and report their GHG emissions, including methane and carbon dioxide, to the EPA.

 

The EPA's finding, the GHG reporting rules, and the rules to regulate the emissions of GHGs may affect the outcome of other climate change lawsuits pending in U.S. federal courts in a manner unfavorable to our industry.  In addition to the EPA’s actions to regulate GHGs, more than one-third of the states have begun taking action on their own to control and/or reduce emissions of GHGs.  The EPA has continued to adopt GHG regulations of other industries, such as the September 2013 proposed GHG rule that, if finalized, would set new source performance standards for new coal-fired and natural-gas fired power plants. As a result of this continued regulatory focus, future GHG regulations of the oil and gas industry remain a possibility. Any of the climate change regulatory and legislative initiatives described above in areas in which we conduct business could result in increased compliance costs or additional operating restrictions which could have a material adverse effect on our business, financial condition, and results of operations.

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.

The Federal Water Pollution Control Act (“Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including produced waters and other oil and gas wastes, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the applicable state agency. 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.

The Safe Drinking Water Act (“SDWA”) and the Underground Injection Control (“UIC”) program promulgated under the SDWA and state and local laws regulate the drilling and operation of salt water disposal (“SWD”) wells and the underground injection of waste substances produced from oil and gas operations. Underground injection is the subsurface placement of fluid through a well, such as the reinjection of brine produced and separated from oil and gas production. The EPA directly administers the UIC program in some states and in others it is delegated to the state for administering.  Permits must be obtained before drilling SWD wells and casing integrity monitoring must be conducted periodically to ensure the casing is not leaking saltwater into groundwater.   Contamination of groundwater by oil and natural gas drilling, production, and related operations may result in fines, penalties, and remediation costs.  In addition, third party claims may be filed by landowners and other parties claiming damages for alternative water supplies, property damages, and bodily injury.  We currently operate one underground injection well and own interests in various underground injection wells operated by others and failure to abide by their permits could subject us and those operators to civil and/or criminal enforcement.  We are, and believe the other operators are as well, in compliance in all material respects with the requirements of applicable state underground injection control programs and permits.

Several states, including Texas, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission has adopted rules and regulations implementing this legislation that apply to all wells for which the Railroad Commission issues an initial drilling permit after February 1, 2012. The new law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (OSHA) for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources. These statutes include the Endangered Species Act and the Migratory Bird Treaty Act, as well as, the CWA and CERCLA.  The United States Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or development.  Where takings of or harm to species or damages to wetlands, habitat, or natural resources occur or may occur, government entities or at times private parties may act to prevent oil and gas exploration activities or seek damages for harm to species, habitat, or natural resources resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and may seek natural resources damages and in some cases, criminal penalties.

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.

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.

Executive Officers

The following table sets forth certain information concerning the executive officers of the Company as of March 31, 2014.

Name	Age	Position
Nicholas C. Taylor	76	Chairman and Chief Executive Officer
Tamala L. McComic	45	President, Chief Financial Officer, Treasurer, and Assistant Secretary
Donna Gail Yanko	69	Vice President and Secretary

Set forth below is a description of the principal occupations during at least the past five years of each executive officer of the Company.

Nicholas C. Taylor was elected Chairman of the Board and Chief Executive Officer of the Company in September 2011 and continues to serve in such capacity on a part time basis, as required.  He served as Chief Executive Officer, President and Director of the Company from 1983 to 2011.  From July 1993 to the present, Mr. Taylor has been involved in the independent practice of law and other business activities.  In November 2005 he was appointed by the Speaker of the House to the Texas Ethics Commission and served until February 2010.

Tamala L. McComic, a Certified Public Accountant, became Controller for the Company in July 2001 and was elected President and Chief Financial Officer in September 2011.  She served the Company as Executive Vice President and Chief Financial Officer from 2009 to 2011 and Vice President and Chief Financial Officer from 2003 to 2009.  Prior thereto, Ms. McComic was appointed Treasurer and Assistant Secretary of the Company.

Donna Gail Yanko was appointed to the position of Vice President of the Company in 1990.  She has also served as Corporate Secretary since 1992 and from 1986 to 1992 was Assistant Secretary.  From 1986 to the present, on a part-time basis, she has assisted the Chairman of the Board of the Company in his personal business activities.  Ms. Yanko also served as a director of the Company from 1990 to 2008.

Employees

As of March 31, 2014, we had three full-time and three part-time employees.  We believe that relations with these employees are generally satisfactory.  From time to time, we utilize the services of independent geological, land and engineering consultants on a limited basis and expect to continue to do so in the future.  We also utilize the services of independent contractors to perform well drilling and production operations, including pumping, maintenance, inspection and testing.

 

Office Facilities

Our principal offices are located at 214 W. Texas Avenue, Suite 1101, Midland, Texas 79701, and our telephone number is (432) 682-1119.  On April 1, 2013, we agreed to a three year lease, with an option to renew for an additional two year, for our 3,199 square feet of office space which will expire on April 1, 2016.  On April 1, 2014, we agreed to a three year lease for an additional 340 square feet of office space which will expire on April 1, 2017.  We believe our facilities are adequate for our current operations and that we can obtain additional leased space if needed.

Access to Company Reports

Mexco Energy Corporation files annual, quarterly and current reports, proxy statements and other information with the SEC.  Please call the SEC at 1-800-SEC-0330 for information on the public reference room.  The SEC maintains an internet website (www.sec.gov) that contains annual, quarterly and current reports, proxy statements and other information that issuers, including Mexco, file electronically with the SEC.

Mexco also employs the Public Register’s Annual Report Service which can provide you a copy of our annual report at www.prars.com, free of charge, as soon as practicable after providing such report to the SEC.

We also maintain an internet website at www.mexcoenergy.com.  In the Investor Relations section, our website contains our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and other reports and amendments to those reports as soon as reasonably practicable after such material is electronically filed with the SEC.  Information on our website is not incorporated by reference into this Form 10-K and should not be considered part of this report or any other filing that we make with the SEC.  Additionally, our Code of Business Conduct and Ethics and the charters of our Audit Committee, Compensation Committee and Nominating Committee are posted on our website.  Any of these corporate documents as well as any of the SEC filed reports are available in print free of charge to any stockholder who requests them.  Requests should be directed to our corporate Assistant Secretary by mail to P.O. Box 10502, Midland, Texas 79702 or by email to mexco@sbcglobal.net.

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 could have a material adverse effect on our business, financial position, liquidity and results of operations.  Some of the following risks relate principally to the industry in which we operate and to our business.  Other risks relate principally to the securities markets and ownership of our common stock.

RISKS RELATED TO OUR BUSINESS AND INDUSTRY

Volatility of oil and gas prices significantly affects our results and profitability.

Prices for oil and natural gas fluctuate widely.  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 the level of global demand for petroleum products; foreign supply and pricing of oil and gas; the ability of the Organization of Petroleum Exporting Countries (“OPEC”) to set and maintain oil price and production controls; nature and extent of governmental regulation and taxation, including environmental regulations; level of domestic and international exploration, drilling and production activity; the cost of exploring for, producing and delivering oil and gas; speculative trading in crude oil and natural gas derivative contracts; availability, proximity and capacity of oil and gas pipelines and other transportation facilities; weather conditions; the price and availability of alternative fuels; technological advances affecting energy consumption; and, overall political and economic conditions in oil producing countries.

Increases and decreases in prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital.  The amount we can borrow from banks may be subject to redetermination based on changes in prices.  In addition, we may have ceiling test writedowns when prices decline.  Lower prices may also reduce the amount of crude oil and natural gas that can be produced economically.  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.

Changes in oil and gas prices impact both estimated future net revenue and the estimated quantity of proved reserves.  Any reduction in reserves, including reductions due to price fluctuations, can reduce the borrowing base under our revolving credit facility and adversely affect the amount of cash flow available for capital expenditures and our ability to obtain additional capital for our exploration and development activities.

Oil and natural gas prices do not necessarily fluctuate in direct relationship to each other.  Our financial results are more sensitive to movements in natural gas prices than oil prices because most of our production and reserves are natural gas.  Lower natural gas prices or lack of natural gas storage may have an adverse affect on our financial condition due to reduction of our revenues, operating income and cash flows; curtailment or shut-in of our natural gas production due to lack of transportation or storage capacity;  cause certain properties in our portfolio to become economically unviable; and, limit our financial condition, liquidity, and/or ability to finance planned capital expenditures and operations.

We have entered into price swap derivatives and may in the future enter into additional price swap derivatives for a portion of our production, which may result in our making cash payments or prevent us from receiving the full benefit of increases in prices for oil.

We use price swap derivatives to reduce price volatility associated with certain of our oil sales.  Under these swap contracts, we receive a fixed price per barrel of oil and pay a floating market price per barrel of oil to the counterparty based on NYMEX WTI pricing. The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty.

In March 2013, we placed a commodity swap contract covering a total of 12,000 bbls of crude oil for the period from April 2013 to March 2015 at a fixed price of $90.00 per bbl.  Such contracts and any future swap arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase.  In addition, these arrangements may limit the benefit to us of increases in the price of oil.  Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments.

Our derivative transactions expose us to counterparty credit risk.

Our derivative transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract.  Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract.

Lower oil and gas prices and other factors may cause us to record ceiling test writedowns.

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 against earnings.  This is called a “ceiling test writedown.”  Under the accounting rules, we are required to perform a ceiling test each quarter.  A ceiling test writedown 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.  For 2014, 2013 and 2012, there was no ceiling test impairment on our oil and gas properties.

Information concerning our reserves and future net revenues estimates is inherently uncertain.

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.  As required by the SEC, the estimated discounted future net cash flows from proved reserves are based on a twelve month un-weighted first-day-of-the-month average oil and gas prices for the twelve months prior to the date of the report.  Actual future prices and costs may be materially higher or lower.

An increase in the differential between NYMEX and the reference or regional index price used to price our oil and gas would reduce our cash flow from operations.

 

Our oil and gas is priced in the local markets where it is produced based on local or regional supply and demand factors.  The prices we receive for our oil and gas are typically lower than the relevant benchmark prices, such as The New York Mercantile Exchange (“NYMEX”).  The difference between the benchmark price and the price we receive is called a differential.  Numerous factors may influence local pricing, such as refinery capacity, pipeline capacity and specifications, upsets in the midstream or downstream sectors of the industry, trade restrictions and governmental regulations.  Additionally, insufficient pipeline capacity, lack of demand in any given operating area or other factors may cause the differential to increase in a particular area compared with other producing areas.  During fiscal 2014, differentials averaged $.41 per Bbl of oil and $0.11 per Mcf of gas.  Increases in the differential between the benchmark prices for oil and gas and the wellhead price we receive could significantly reduce our revenues and our cash flow from operations.

We must replace reserves we produce.

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 hard to find.

Approximately 37% and 38% of our total estimated net proved reserves at March 31, 2014 and 2013, respectively, were undeveloped, and those reserves may not ultimately be developed.

 

Recovery of undeveloped reserves requires significant capital expenditures and successful drilling.  Our reserve data assumes that we can and will make these expenditures and conduct these operations successfully.  These assumptions, however, may not prove correct.  If we or the outside operators of our properties choose not to spend the capital to develop these reserves, or if we are not able to successfully develop these reserves, we will be required to write-off these reserves.  Any such write-offs of our reserves could reduce our ability to borrow money and could reduce the value of our common stock.

 

 

Our exploration and development drilling may not result in commercially productive reserves.

 

New wells that we drill may not be productive, or we may not recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that crude oil or natural gas is present or may be produced economically. Drilling for crude oil and natural gas often involves unprofitable efforts, not only from dry holes but also from wells that are productive but do not produce sufficient net reserves to return a profit at then realized prices after deducting drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project.

Acquisitions are subject to the risks and uncertainties of evaluating reserves and potential liabilities and may be disruptive and difficult to integrate into our business.

We plan to continue growing our reserves through acquisitions.  Acquired properties can be subject to significant unknown liabilities.  Prior to completing an acquisition, it is generally not feasible to conduct a detailed review of each individual property to be acquired in an acquisition.  Even a detailed review or inspection of each property may not reveal all existing or potential liabilities associated with owning or operating the property.  Moreover, some potential liabilities, such as environmental liabilities related to groundwater contamination, may not be discovered even when a review or inspection is performed.  Our initial reserve estimates for acquired properties may be inaccurate.  Downward adjustments to our estimated proved reserves, including reserves added through acquisitions, could require us to write down the carrying value of our oil and gas properties, which would reduce our earnings and our stockholders’ equity.  In addition, we may have to assume cleanup or reclamation obligations or other unanticipated liabilities in connection with these acquisitions.  The scope and cost of these obligations may ultimately be materially greater than estimated at the time of the acquisition.

We may not be able to fund the capital expenditures that will be required for us to increase reserves and production.

 

We must make capital expenditures to develop our existing reserves and to discover new reserves.  Historically, we have used our cash flow from operations and borrowings under our revolving credit facility to fund our capital expenditures and we expect to continue to do so in the future.

 

Volatility in oil and gas prices, the timing of our drilling programs and drilling results will affect our cash flow from operations.  Lower prices and/or lower production will also decrease revenues and cash flow, thus reducing the amount of financial resources available to meet our capital requirements, including reducing the amount available to pursue our drilling opportunities.  If our cash flow from operations does not increase as a result of planned capital expenditures, a greater percentage of our cash flow from operations will be required for debt service and operating expenses and our planned capital expenditures would, by necessity, be decreased.

 

The borrowing base under our credit facility will be determined from time to time by the lender.  Reductions in estimates of oil and gas reserves could result in a reduction in the borrowing base, which would reduce the amount of financial resources available under the credit facility to meet our capital requirements.  Such a reduction could be the result of lower commodity prices and/or production, inability to drill or unfavorable drilling results, changes in oil and gas reserve engineering, the lenders’ inability to agree to an adequate borrowing base or adverse changes in the lenders’ practices regarding estimation of reserves.

 

If cash flow from operations or our borrowing base decrease for any reason, our ability to undertake exploration and development activities could be adversely affected.  As a result, our ability to replace production may be limited.  In addition, if the borrowing base under the credit facility is reduced, we would be required to reduce our borrowings under the credit facility so that such borrowings do not exceed the borrowing base.  This could further reduce the cash available to us for capital spending and, if we did not have sufficient capital to reduce our borrowing level, we may be in default under the credit facility.

 

 

Failure to comply with covenants under our debt agreement could adversely impact our financial condition and results of operations.

Our revolving credit facility agreement requires us to comply with certain customary covenants including limitations on disposition of assets, mergers and reorganizations.  We are also obligated to meet certain financial covenants.  For example, our revolving credit facility requires us to, among other things, maintain tangible net worth in accordance with computational guidelines contained in the related loan agreement.  If we fail to meet any of these loan covenants, the lender under the revolving credit facility could accelerate the indebtedness and seek to foreclose on the pledged assets.

Drilling and operating activities are high risk activities that subject us to a variety of factors that we can not control.

These factors include 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.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.

Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.

Our identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage.  These drilling locations represent a significant part of our growth strategy.  Our ability to drill and develop these locations depends on a number of uncertainties, including crude oil and natural gas prices, the availability of capital, costs, drilling results, regulatory approvals and other factors. If future drilling results in these projects do not establish sufficient reserves to achieve an economic return, we may curtail drilling in these projects.  Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce crude oil or natural gas from these or any other potential drilling locations.

We have limited control over activities on properties we do not operate, which could reduce our production and revenues.

A substantial amount of our business activities are conducted through joint operating or other agreements under which we own working and royalty interests in natural gas and oil properties in which we do not operate.  As a result, we have a limited ability to exercise influence over normal operating procedures, expenditures or future development of underlying properties and their associated costs.  The failure of an operator of our wells to adequately perform operations could reduce our revenues and production.

Our business depends on oil and natural gas transportation facilities which are owned by others.

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.

The oil and gas industry is highly competitive.

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.  Our ability to acquire and develop additional properties in the future will depend upon our ability to select and acquire suitable producing properties and prospects for future development activities. 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.  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.

We may not be insured against all of the operating hazards to which our business is exposed.

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.

Our business is subject to extensive environmental regulations, and to laws that can give rise to liabilities from environmental contamination.

Our operations are subject to extensive federal, state and local environmental laws and regulations, which impose limitations on the discharge of pollutants into the environment, establish standards for the management, treatment, storage, transportation and disposal of hazardous materials and of solid and hazardous wastes, and impose obligations to investigate and remediate contamination in certain circumstances.  Liabilities to investigate or remediate contamination, as well as other liabilities concerning hazardous materials or contamination such as claims for personal injury or property damage, may arise at many locations, including properties in which we have an ownership interest but no operational control, properties we formerly owned or operated and sites where our wastes have been treated or disposed of, as well as at properties that we currently own or operate.  Such liabilities may arise even where the contamination does not result from any noncompliance with applicable environmental laws.  Under a number of environmental laws, such liabilities may also be joint and several, meaning that we could be held responsible for more than our share of the liability involved, or even the entire share.  Environmental requirements generally have become more stringent in recent years, and compliance with those requirements more expensive.

Increased regulation of hydraulic fracturing could result in reductions or delays in drilling and completing new oil and natural gas wells, which could adversely impact our revenues.

Legislation has been introduced in the U.S. Congress to amend the federal SDWA to subject hydraulic fracturing operations to regulation under the SDWA and to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process.  Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate gas and oil production. We engage third parties to provide hydraulic fracturing or other well stimulation services to us in connection with wells for which we are the operator.  Several states, including Texas, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Railroad Commission has adopted rules and regulations requiring that well operators disclose the list of chemical ingredients subject to the requirements of OSHA for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The proposed legislation as well as laws being considered by certain states and other agencies requiring the reporting and public disclosure of chemicals used in the fracturing process, could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process are impairing groundwater or causing other damage.  Additional regulatory scrutiny could make it difficult to perform hydraulic fracturing and increase our costs of compliance and doing business.

 

 

Increases in taxes on energy sources may adversely affect the company's operations.

 

Federal, state and local governments which have jurisdiction in areas where the company operates impose taxes on the oil and natural gas products sold.  Historically, there has been an on-going consideration by federal, state and local officials concerning a variety of energy tax proposals.  Such matters are beyond our ability to accurately predict or control.

Proposed changes to U.S. tax laws, if adopted, could have an adverse effect on our business, financial condition, results of operations and cash flows.

The U.S. President's Fiscal Year 2014 Budget Proposal includes provisions that would, if enacted, make significant changes to U. S. federal income tax laws including the elimination of certain key U.S. federal income tax deductions currently available to oil and natural gas exploration and production companies.  Other changes include, but are not limited to:  (1) the repeal of the percentage depletion allowance for oil and natural gas properties, (2) the elimination of current deductions for intangible drilling and development costs, (3) the elimination of the deduction for certain domestic production activities, and (4) an extension of the amortization period for certain geological and geophysical expenditures.  It is unclear whether any such changes will be enacted or how soon any such changes could become effective.  The passage of this legislation or any other similar changes in the U. S. federal income tax laws could negatively affect our financial condition and results of operations.

The loss of our chief executive officer or other key personnel could adversely impact our ability to execute our business strategy.

 

We depend, and will continue to depend in the foreseeable future, upon the continued services of our Chief Executive Officer, Nicholas C. Taylor, our President and Chief Financial Officer, Tamala L. McComic, and other key personnel, who have extensive experience and expertise in evaluating and analyzing producing oil and gas properties and drilling prospects, maximizing production from oil and gas properties and developing and executing acquisitions and financing.  We do not have key-man insurance on the lives of Mr. Taylor and Ms. McComic.  The unexpected loss of the services of one or more of these individuals could, therefore, significantly and adversely affect our operations.  Competition for qualified individuals is intense and we may be unable to find or attract qualified replacements for our officers and key employees on acceptable terms.

We may be affected by one substantial shareholder.

Nicholas C. Taylor beneficially owns approximately 44% of the outstanding shares of our common stock.  Mr. Taylor is also our Chairman of the Board 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.  The retirement, incapacity or death of Mr. Taylor, or any change in the power to vote shares beneficially owned by Mr. Taylor, could result in negative market or industry perception and could have an adverse effect on our business.

RISKS RELATED TO OUR COMMON STOCK

We have not and do not anticipate paying any cash dividends on our common stock in the foreseeable future.

 

We have paid no cash dividends on our common stock to date and it is not anticipated that any will be paid to holders of our common stock in the foreseeable future.  The terms of our existing credit facility restricts the payment of dividends without the prior written consent of the lenders.  We currently intend to retain all future earnings to fund the development and growth of our business. Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that our board of directors deems relevant. Stockholders must rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize a return on their investment.

We may seek to raise additional equity capital in the future.  Any issuance of additional shares of our common stock will dilute the percentage ownership interest of all shareholders and may dilute the book value per share of our common stock.

Control by our executive officers and directors may limit your ability to influence the outcome of matters requiring stockholder approval and could discourage our potential acquisition by third parties.

As of March 31, 2014, our executive officers and directors beneficially owned approximately 47% of our common stock.  These stockholders, if acting together, would be able to influence significantly all matters requiring approval by our stockholders, including the election of our board of directors and the approval of mergers or other business combination transactions.

The price of our common stock has been volatile and could continue to fluctuate substantially.

 

Mexco common stock is traded on the NYSE MKT.  The market price of our common stock has and could continue to experience volatility due to reasons unrelated to our operating performance.  These reasons include: supply and demand for natural gas and oil; political conditions in natural gas and oil producing regions; demand for our common stock and limited trading volume; investor perception of our industry; fluctuations in commodity prices; variations in our results of operations; legislative or regulatory changes; general trends in the oil and natural gas industry; market conditions and analysts’ estimates; and, other events in the oil and gas oil industry.  Many of these factors are beyond our control, and we cannot predict their potential effects on the price of our common stock.  We cannot assure you that the market price of our common stock will not fluctuate or decline significantly in the future.  In addition, the stock markets in general can experience considerable price and volume fluctuations.

Failure of the Company's internal control over financial reporting could harm its business and financial results.

The management of Mexco is responsible for establishing and maintaining effective internal control over financial reporting.  Internal control over financial reporting is a process to provide reasonable assurance regarding the reliability of financial reporting for external purposes in accordance with accounting principles generally accepted in the United States.  Internal control over financial reporting includes maintaining records that in reasonable detail accurately and fairly reflect Mexco's transactions; providing reasonable assurance that transactions are recorded as necessary for preparation of the financial statements; providing reasonable assurance that receipts and expenditures are made in accordance with management authorization; and providing reasonable assurance that unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements would be prevented or detected on a timely basis.

 

ITEM 1B.  UNRESOLVED STAFF COMMENTS

None.

 

ITEM 2.  PROPERTIES

Our properties consist primarily of oil and gas wells and our ownership in leasehold acreage, both developed and undeveloped.  As of March 31, 2014, we had interests in 3,400 gross (31.5 net) oil and gas wells and owned leasehold mineral and royalty interests in approximately 369,979 gross (4,457 net) acres.

 

Oil and Natural Gas Reserves

In accordance with current SEC rules, the average prices used in computing reserves at March 31, 2014 were $94.23 per bbl of oil and $85.53 in 2013, an increase of 10%, and $3.67 per mcf of natural gas and $2.76 in 2013, an increase of 33%, such prices are based on the 12-month unweighted arithmetic average market prices for sales of oil and natural gas on the first calendar day of each month during fiscal 2014.  The benchmark price of $94.92 per bbl of oil at March 31, 2014 versus $89.17 at March 31, 2013, was adjusted by lease for gravity, transportation fees and regional price differentials and did not give effect to derivative transactions.  The benchmark price of $3.99 per mcf of natural gas at March 31, 2014 versus $2.95 at March 31, 2013, was adjusted by lease for BTU content, transportation fees and regional price differentials.  The average prices used in computing reserves at March 31, 2012 were $93.75 per bbl of oil and $3.83 per mcf of natural gas. The benchmark prices used in computing reserves at March 31, 2012 were $94.65 per bbl of oil and $3.73 per mcf of natural gas.

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.

 

The engineering report with respect to Mexco’s estimates of proved oil and gas reserves as of March 31, 2014, 2013 and 2012 is based on evaluations prepared by Joe C. Neal and Associates, Petroleum and Environmental Engineering Consultants, based in Midland, Texas (“Neal and Associates”), a summary of which is filed as Exhibit 99.1 to this annual report.

Management maintains internal controls designed to provide reasonable assurance that the estimates of proved reserves are computed and reported in accordance with rules and regulations provided by the SEC.  As stated above, Mexco retained Neal and Associates to prepare estimates of our oil and gas reserves.  Management works closely with this firm, and is responsible for providing accurate operating and technical data to it.  Our Chief Financial Officer who has over 20 years experience in the oil and gas industry reviews the final reserves estimate and consults with a degreed geological consultant with extensive geological experience and if necessary, discusses the process used and findings with Mr. Neal.  Mr. Neal is responsible for overseeing the preparation of the reserve estimates and holds a bachelor’s degree in mechanical engineering (petroleum option), is a member of the Society of Petroleum Engineers and has over 50 years of experience in the oil and gas industry.  Our Chairman and Chief Executive Officer who has over 30 years experience in the oil and gas industry also reviews the final reserves estimate.

Numerous uncertainties exist in estimating quantities of proved reserves.  Reserve estimates are imprecise and subjective and may change at any time as additional information becomes available.  Furthermore, estimates of oil and gas reserves are projections based on engineering data.  There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production.  The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.

 

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.

Per the current SEC rules, the prices used to calculate our proved reserves and the present value of proved reserves set forth herein are made using the 12-month unweighted arithmetic average of the first-day-of-the-month price.  All prices 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 during the year ended March 31, 2014, and no major discovery is believed to have caused a significant change in our estimates of proved reserves since that date.

Proved reserves are estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions.  Proved developed reserves are those expected to be recovered through existing wells, equipment and operating methods.  Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which a relatively major expenditure is required to establish production.

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,
		2014				2013				2012
Oil (Bbls):
Proved developed – Producing			278,230				232,850				178,410
Proved developed – Non-producing			16,390				4,570				16,210
Proved undeveloped			206,930				128,290				151,730
Total			501,550				365,710				346,350
Natural gas (Mcf):
Proved developed – Producing			2,982,480				3,727,710				3,491,920
Proved developed – Non-producing			1,098,990				1,079,310				1,867,750
Proved undeveloped			2,177,810				3,037,180				3,085,060
Total			6,259,280				7,844,200				8,444,730
Total net proved reserves (Mcfe)			9,268,580				10,038,460				10,522,830
PV-10 Value (1)		$	24,745,250			$	17,788,790			$	24,953,450
Present value of future income tax discounted at 10%			5,416,250				(3,419,790	)			(5,597,450	)
Standardized measure of discounted future net cash flows (2)		$	19,329,000			$	14,369,000			$	19,356,000
Prices used in Calculating Reserves: (3)
Natural gas (per Mcf)		$	3.67			$	2.76			$	3. 83
Oil (per Bbl)		$	94.23			$	85.53			$	93.75

(1)

The PV-10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10% per annum, which is the most directly comparable GAAP financial measure.  PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes.  Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies.  We use this measure when assessing the potential return on investment related to our oil and natural gas properties.  Our reconciliation of this non-GAAP financial measure is shown in the table as the PV-10, less future income taxes, discounted at 10% per annum, resulting in the standardized measure of discounted future net cash flows. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to our proved oil and natural gas reserves after income tax, discounted at 10%.

(2)

In accordance with SEC requirement, the standardized measure of discounted future net cash flows was computed by applying 12-month average prices for oil and gas during the fiscal year to the estimated future production of proved oil and gas reserves, less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less estimated future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already legislated) to be incurred on pretax net cash flows less tax basis of the properties and available credits, and assuming continuation of existing economic conditions.

(3)	These prices reflect adjustment by lease for quality, transportation fees and regional price differentials and did not give effect to derivative transactions.

 

 

Oil and gas prices significantly impact the calculation of the PV-10 and the standardized measure of discounted future net cash flows.  The present value of future net cash flows does not purport to be an estimate of the fair market value of the Company's proved reserves.  An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money and the risks inherent in producing oil and gas.  Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates.  The 10% discount factor used to calculate present value, which is required by Financial Accounting Standards Board (“FASB”) pronouncements, may not necessarily be the most appropriate discount rate.  The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

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, 2014:

		Gross				Net
Oil			2,121				18.4
Gas			1,279				13.1
Total Productive Wells			3,400				31.5

The following table sets forth the approximate developed acreage in which we held a leasehold mineral or other interest as of March 31, 2014:

 

		Developed Acres
		Gross				Net
Texas			204,111				3,282
New Mexico			27,999				833
Oklahoma			50,007				214
Louisiana			36,442				46
North Dakota			28,734				44
Kansas			8,520				24
Montana			7,868				5
Wyoming			3,578				5
Alabama			640				2
Mississippi			640				1
Colorado			1,120				1
Arkansas			320				-
Total			369,979				4,457

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.  On August 13, 2013, Mexco assigned Pioneer Natural Resource Company a three year term leasehold interest in 417.33 net acres (837.33 gross acres) of  undeveloped acreage located above and below the Pembrook Unit of Upton County, Texas and retained a 1% royalty.  Mexco now owns approximately 320 net acres (640 gross acres) in this area which is held by production from approximately 200 wells in the Pembrook Unit.  This acreage has the potential for development in the horizontal Wolfcamp formation centered in the southern Midland Basin.

 

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:

		Year Ended March 31,
		2014								2013								2012
		Gross				Net				Gross				Net				Gross				Net
Development Wells
Productive			34				.42				38				.52				54				1.55
Nonproductive			1				.01				1				.01				-				-
Total			35				.43				39				.53				54				1.55

We have not participated in any exploratory wells during the years ended March 31, 2014, 2013 and 2012. 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 our net oil and natural gas production, the average sales price per barrel (“bbl”) 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:

		Year Ended March 31,
		2014				2013				2012
Oil (a):
Production (Bbls)			27,186				23,260				19,442
Revenue		$	2,591,619			$	1,961,766			$	1,810,459
Average Bbls per day			74				64				53
Average sales price per Bbl (b)		$	95.33			$	84.34			$	93.12
Gas (c):
Production (Mcf)			361,652				401,077				395,649
Revenue		$	1,402,676			$	1,101,941			$	1,413,200
Average Mcf per day			991				1,099				1,084
Average sales price per Mcf		$	3.88			$	2.75			$	3.57
Production cost:
Production cost		$	943,730			$	843,277			$	669,615
Production and ad valorem taxes		$	288,084			$	238,766			$	256,600
Equivalent Mcf (d)			524,768				540,637				512,301
Production cost per equivalent Mcf		$	1.80			$	1.56			$	1.31
Production cost per sales dollar		$	0.24			$	0.28			$	0.21
Total oil and gas revenue		$	3,994,295			$	3,063,707			$	3,223,659

 

(a)	Includes condensate.

(b)	After giving effect to our derivative instruments, the average sales price per Bbl of oil was $93.33 for year ended March 31, 2014.  We did not have a price swap agreement on our oil production for the years ended March 31, 2013 and 2012.

(c)	Includes natural gas products.

(d)	Oil production is converted to equivalent mcf at the rate of 6 mcf per bbl, representing the estimated relative energy content of natural gas to oil.

 

ITEM 3.

LEGAL PROCEEDINGS

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 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.

MINE SAFETY DISCLOSURES

Not applicable.

 

PART II

ITEM 5.

MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

In September 2003, our common stock began trading on the NYSE MKT, formerly the American Stock Exchange, under the symbol “MXC”.  Prior to September 2003, the Company’s common stock was traded on the over-the-counter bulletin board market under the symbol “MEXC”.  The registrar and transfer agent is Computershare Trust Company N.A., 250 Royall Street, Canton, Massachusetts, 02021 (Tel: 800-962-4284).  The following table sets forth certain information as to the high and low sales price quoted for Mexco’s common stock on the NYSE MKT.

			High				Low
2014:
	April - June 2013		$	6.41			$	5.42
	July - September 2013			8.10				5.30
	October - December 2013			8.50				6.30
	January - March 2014			10.10				6.61
2013:
	April - June 2012		$	8.25			$	5.45
	July - September 2012			7.14				5.68
	October - December 2012			6.90				5.13
	January - March 2013			7.20				5.16

On June 12, 2014, the closing sales price of our common stock on the NYSE MKT was $8.51 per share.

Stockholders

As of March 31, 2014, we had approximately 2,104,266 shares issued and 918 shareholders of record which does not include shareholders for whom shares are held in a “nominee” or “street” name.

Dividends

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.

Securities Authorized for Issuance Under Compensation Plans

The following table includes certain information about our Employee Incentive Stock Plan as of March 31, 2014, which has been approved by our stockholders.

		Number of Shares Authorized for Issuance under Plan				Number of Shares to be Issued upon Exercise of Outstanding Options				Weighted Average Exercise Price of Outstanding Options				Number of Shares Remaining Available for Future Issuance under Plan
2009 Plan			200,000				113,600			$	6.35				85,000
Total			200,000				113,600			$	6.35				85,000

Issuer Repurchases

In June 2013, the Board of Directors authorized the use of up to $250,000 to repurchase shares of our common stock for the treasury account.  This program does not have an expiration date.  Under the repurchase program, shares of common stock may be purchased from time to time through open market purchases or other transactions.  The amount and timing of repurchases will be subject to the availability of stock, prevailing market conditions, the trading price of the stock, our financial performance and other conditions.  Repurchases may also be made from time-to-time in connection with the settlement our share-based compensation awards.  Repurchases will be funded from cash flow from operations.

There were no shares of our common stock repurchased for the treasury account during fiscal 2014.  During the fiscal year ended March 31, 2013, we repurchased 2,833 shares for the treasury at an aggregate cost of $15,547.  During fiscal 2012, we repurchased 4,000 shares at an aggregate cost of $22,780.

ITEM 6.  SELECTED CONSOLIDATED FINANCIAL DATA

Not applicable.

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.  We do not have any delivery commitments to provide a fixed and determinable quantity of our oil and gas under any existing contract or agreement.

Our long term strategy is on increasing profit margins while concentrating on obtaining reserves with low cost operations by acquiring and developing oil and gas properties with potential for long-lived production.  We focus our efforts on the acquisition of royalties and working interest, non-operated properties in areas with significant development potential.

We had working capital of $522,216 as of March 31, 2014 compared to working capital of $309,180 as of March 31, 2013, an increase of $213,036 for the reasons set forth below.

For the year ending March 31, 2014, cash flow from operations was $1,812,501, a 122% increase when compared to the corresponding period of fiscal 2013.  Net cash of $1,187,090 was used for additions to oil and gas properties and equipment; net cash of $525,000 was used to reduce the balance on the line of credit; and cash of $54,281 was used for settlement of derivatives.  Accordingly, net cash decreased $10,324.

 

 

On March 31, 2014, Mexco acquired for $450,000, a package of non-operated producing properties primarily consisting of oil wells located in Webster Parish, Louisiana; Eddy County, New Mexico; Billings County, North Dakota; and Nolan and Smith Counties, Texas.  This purchase, effective March 1, 2014, includes working interests ranging from .13% to 27.5% (net revenue interests of .11% to 24.06%) adding estimated net proved reserves of approximately 35,000 barrels of oil equivalent at a cost of $12.68 per barrel.

 

Texas

 

 

New Mexico

 

Oklahoma

We participated in the drilling of three (3) horizontal wells in a 640 acre unit in the Cottage Grove formation of Ellis County, Oklahoma.  All three (3) of these wells, operated by Mewbourne Oil Company, have been completed and are currently producing.  Mexco’s working interest in this unit is 1.2% (.9878% net revenue interest).  Our share of the costs to drill and complete these wells through March 2014 was approximately $121,000.

 

 

North Dakota

We participated in the drilling of a horizontal infill well on a 1,280-acre unit in the Bakken and Three Forks formations of the Catwalk Creek Field of Williams County, North Dakota.  This well, operated by Continental Resources, Inc. has been completed and is currently producing.  Mexco’s working interest in this unit is .078% (.068% net revenue interest).  As of March 31, 2014, our share of the costs associated with this well was approximately $6,100.

We are participating in other projects and are reviewing projects in which we may participate.  The cost of such projects would be funded, to the extent possible, from existing cash balances and cash flow from operations. The remainder may be funded through borrowings on the credit facility and, if appropriate, sales of our common stock.  See Note 5 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. Lower product prices reduce our cash flow from operations and diminish the present value of our oil and gas reserves.  Lower product prices also offer us less incentive to assume the drilling risks that are inherent in our business. The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty.  For example in the last twelve months, the West Texas Intermediate (“WTI”) posted price for crude oil has ranged from a low of $83.25 per bbl in April 2013 to a high of $107.00 per bbl in September 2013.  The Henry Hub Spot Market Price (“Henry Hub”) for natural gas has ranged from a low of $3.27 per MMBtu in August 2013 to a high of $7.98 per MMBtu in March 2014.  On March 31, 2014 the WTI posted price for crude oil was $97.75 per bbl and the Henry Hub spot price for natural gas was $4.48 per MMBtu.  Management is of the opinion that cash flow from operations and funds available from financing will be sufficient to provide adequate liquidity for the next fiscal year.

Results of Operations

Fiscal 2014 Compared to Fiscal 2013

We had a net income of $301,113 for the year ended March 31, 2014 compared to a net loss of $176,374 for the year ended March 31, 2013.

		2014				2013				% Difference
Oil:
Revenue		$	2,591,619			$	1,961,766				32.1	%
Volume (bbls)			27,186				23,260				16.9	%
Average Price (per bbl) (a)		$	95.33			$	84.34				13.0	%
Gas:
Revenue		$	1,402,676			$	1,101,941				27.3
Volume (mcf)			361,652				401,077				(9.8	%)
Average Price (per mcf)		$	3.88			$	2.75				41.1	%

(a)	After giving effect to our derivative instruments, the average sales price per Bbl of oil was $93.33 for year ended March 31, 2014.  We did not have a price swap agreement on our oil production for the year ended March 31, 2013.

 

 

Depreciation, depletion and amortization.  Depreciation, depletion and amortization (“DD&A”) expense was $1,151,482 in fiscal 2014, a 5% increase from $1,100,425 in fiscal 2013.  This was due to an increase in oil production and a decrease in gas reserves partially offset by a decrease in gas production and an increase in oil reserves.

General and administrative expenses.  General and administrative expenses were $1,136,939 for the year ended March 31, 2014, an 11% increase from $1,028,846 for the year ended March 31, 2013.  This was primarily due to an increase in engineering services, insurance, salaries and stock option compensation expense.

Interest expense.  Interest expense was $65,387 in fiscal 2014, a 21% increase from $53,832 in fiscal 2013, due to an increase in borrowings.

Income taxes. There was an income tax expense of $11,750 in fiscal 2014 compared to an income tax benefit of $31,504 in fiscal 2013.  The effective tax rate for fiscal 2014 was 4% compared to (15%) for fiscal 2013.

Derivatives.  Derivative losses of $99,262 were recorded during the year ended March 31, 2014.  This amount reflects $54,281 of realized losses and $44,981 of unrealized losses resulting from our oil swap agreement.

Fiscal 2013 Compared to Fiscal 2012

There was a net loss of $176,374 for the year ended March 31, 2013 compared to net income of $329,993 for the year ended March 31, 2012.

		2013				2012				% Difference
Oil:
Revenue		$	1,961,766			$	1,810,459				8.4	%
Volume (bbls)			23,260				19,442				19.7	%
Average Price (per bbl)		$	84.34			$	93.12				(9.4	%)
Gas:
Revenue		$	1,101,941			$	1,413,200				(22.0	%)
Volume (mcf)			401,077				395,649				1.4	%
Average Price (per mcf)		$	2.75			$	3.57				(23.0	%)

Production and exploration.  Production costs were $1,082,043 in fiscal 2013, a 17% increase from $926,215 in fiscal 2012.  This was primarily the result of repairs on our El Cinco field operated wells in Pecos County, Texas during fiscal 2013.

Depreciation, depletion and amortization.  Depreciation, depletion and amortization (“DD&A”) expense was $1,100,425 in fiscal 2013, a 10% increase from $996,205 in fiscal 2012.  This was due to an increase in oil and gas production and an increase in the full cost pool amortization base partially offset by a decrease in oil and gas reserves.

General and administrative expenses.  General and administrative expenses were $1,028,846 for the year ended March 31, 2013, an 8% increase from $950,690 for the year ended March 31, 2012.  This was primarily due to an increase in insurance, salaries and stock option compensation expense.

Interest expense.  Interest expense was $53,832 in fiscal 2013, an 87% increase from $28,840 in fiscal 2012, due to an increase in borrowings.

Income taxes.  There was an income tax benefit of $31,504 in fiscal 2013 compared to $27,960 in fiscal 2012.  The effective tax rate for fiscal 2013 was (15%) compared to (9%) for fiscal 2012.

 

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, 2014:

		Payments due in:
		Total				less than 1 year				1 - 3 years				3 years
Contractual obligations:
Secured bank line of credit (1)		$	2,425,000			$	-			$	2,425,000			$	-
Leases (2)		$	38,040			$	19,020			$	19,020			$	-

(1)	These amounts represent the balances outstanding under the bank line of credit. These repayments assume that interest will be paid on a monthly basis, no additional funds will be drawn and does not include estimated interest of $64,335 less than 1 year and $42,890 1-3 years.

(2)	The total obligation for the remainder of the leases is $56,520 which includes $18,479 billed to and reimbursed by our majority shareholder for his portion of the shared office space.

 

Alternative Capital Resources

Although we have primarily used cash from operating activities and funding from the line of credit as our primary capital resources, we have in the past, and could in the future, use alternative capital resources.  These could include joint ventures, carried working interests and the sale of assets and/or issuances of common stock through a private placement or public offering of our common stock.

Other Matters

Critical Accounting Policies and Estimates

The following represents those policies that management believes are particularly important to the financial statements and that require the use of estimates and assumptions to describe matters that are inherently uncertain.

 

Full Cost Method of Accounting for Crude Oil and Natural Gas Activities.  SEC Regulation S-X defines the financial accounting and reporting standards for companies engaged in crude oil and natural gas activities.  Two methods are prescribed:  the successful efforts method and the full cost method.  We have chosen to follow the full cost method under which all costs associated with property acquisition, exploration and development are capitalized.  We also capitalize internal costs that can be directly identified with acquisition, exploration and development activities and do not include any costs related to production, general corporate overhead or similar activities.  The carrying amount of oil and gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation ("ARO") 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 DD&A rate on our crude oil and natural gas properties.

At the time it was adopted, management believed that the full cost method would be preferable, as earnings tend to be less volatile than under the successful efforts method.  However, the full cost method makes us more susceptible to significant non-cash charges during times of volatile commodity prices because the full cost pool may be impaired when prices are low.  These charges are not recoverable when prices return to higher levels. Our crude oil and natural gas reserves have a relatively long life.  However, temporary drops in commodity prices can have a material impact on our business including impact from the 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 to determine a limit, or ceiling, on the book value of oil and gas properties. That limit is basically the after tax present value of the future net cash flows from proved crude oil and natural gas reserves plus the lower of cost or fair market value of unproved properties. If net capitalized costs of crude oil and natural gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings.  This is called a "ceiling limitation write-down."  This 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.

Estimates of our proved reserves are based on the quantities of oil and gas that engineering and geological analysis demonstrates, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters.  Our reserve estimates and the projected cash flows are derived from these reserve estimates, in accordance with SEC guidelines by an independent engineering firm based in part on data provided by us.  The accuracy of a reserve estimate is a function of the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgment of the persons preparing the estimate.  Estimates prepared by other third parties may be higher or lower than those included herein.  Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities of oil and gas that are ultimately recovered.  In addition, results of drilling, testing and production after the date of an estimate may justify material revisions to the estimate.

It should not be assumed that the present value of future net cash flows is the current market value of our estimated proved reserves.  In accordance with SEC requirements, the cost ceiling represents the present value (discounted at 10%) of net cash flows from sales of future production using the average price over the prior 12-month period.

The estimates of proved reserves materially impact DD&A expense.  If the estimates of proved reserves decline, the rate at which we record DD&A expense will increase, reducing future net income.  Such a decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost projects.

 

Use of Estimates.  In preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management is required to make informed judgments, estimates and assumptions that affect the reported amounts of assets and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting period.  In addition, significant estimates are used in determining year end proved oil and gas reserves.  Although management believes its estimates and assumptions are reasonable, actual results may differ materially from those estimates.  The estimate of our oil and natural gas reserves, which is used to compute DD&A and impairment of oil and gas properties, is the most significant of the estimates and assumptions that affect these reported results.

Excluded Costs.  Oil and gas properties include costs that are excluded from capitalized costs being amortized.  These amounts represent investments in unproved properties and major development projects. These costs are excluded until proved reserves are found or until it is determined that the costs are impaired. All costs excluded are reviewed at least quarterly to determine if impairment has occurred.  The amount of any impairment is transferred to the capitalized costs being amortized (the DD&A pool).  Impairments transferred to the DD&A pool increase the DD&A rate.

Revenue Recognition.  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.

Asset Retirement Obligations.  The estimated costs of plugging, restoration and removal of facilities are accrued.  The fair value of a liability for an asset's retirement obligation is recorded in the period in which it is incurred and the corresponding cost capitalized by increasing the carrying amount of the related long-lived asset.  The liability is accreted to its then present value each period, and the capitalized cost is depreciated by the units of production method.  If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized.  For all periods presented, we have included estimated future costs of abandonment and dismantlement in the full cost amortization base and amortize these costs as a component of our depletion expense.

Derivatives.  The Company uses price swap contracts to reduce price volatility associated with certain of its oil sales.  All derivative financial instruments are recorded at fair value on the balance sheet as either assets or liabilities.  The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the realized and unrealized changes in fair value in the Consolidated Statements of Operations under the caption “Loss on derivative instruments.”

Gas Balancing.  Gas imbalances are accounted for under the sales method whereby revenues are recognized based on production sold.  A liability is recorded when our excess takes of natural gas volumes exceed our estimated remaining recoverable reserves (over produced).  No receivables are recorded for those wells where Mexco has taken less than its ownership share of gas production (under produced).

Stock-based Compensation.  We use the Binomial option pricing model to estimate the fair value of stock based compensation expenses at grant date.  This expense is recognized as compensation expense in our financial statements over the vesting period.  We recognize the fair value of stock based compensation awards as wages in the Consolidated Statements of Operations based on a graded-vesting schedule over the vesting period.

Accounts Receivable. Our accounts receivable include trade receivables from joint interest owners and oil and gas purchasers.  Credit is extended based on an evaluation of a customer's financial condition and, generally, is uncollateralized.  Accounts receivable under joint operating agreements have a right of offset against future oil and gas revenues if a producing well is completed.  The collectability of receivables is assessed and an allowance is made for any doubtful accounts.  The allowance for doubtful accounts is determined based on our previous loss history.

 

Income Taxes.  The Company recognizes deferred tax assets and liabilities for future tax consequences of temporary differences between the carrying amounts of assets and liabilities and their respective tax bases.  Deferred tax assets and liabilities are measured using enacted tax rates applicable to the years in which those differences are expected to be settled.  The effect on deferred tax assets and liabilities of a change in tax rates is recognized in net income in the period that includes the enactment date.  Any interest and penalties are recorded as interest expense and general and administrative expense, respectively.

Other Property and Equipment.  Provisions for depreciation of office furniture and equipment are computed on the straight-line method based on estimated useful lives of three to ten years.

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The primary source of market risk for us includes fluctuations in commodity prices and interest rates. All of our financial instruments are for purposes other than trading.

Commodity Risk.  We use price swap derivatives to reduce price volatility associated with certain of our oil sales.  Under these swap contracts, we receive a fixed price per barrel of oil and pay a floating market price per barrel of oil to the counterparty based on reported crude oil pricing on the New York Mercantile Exchange (“NYMEX”) West Texas Intermediate (“WTI”).  The fixed-price payment and the floating-price payment are offset, resulting in a net amount due to or from the counterparty.  Such contracts and any future swap arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or oil prices increase.  In addition, these arrangements may limit the benefit to us of increases in the price of oil.  As of April 1, 2013 and expiring on March 31, 2015, Mexco entered into a 24 month swap agreement with Merrill Lynch Commodities, Inc. for 500 bbls of crude oil per month at a fixed price of $90.00 per bbl.

At March 31, 2014, we had a net liability derivative position of $44,981 related to our price swap derivatives. Utilizing actual derivative contractual volumes as of March 31, 2014, a 10% increase or decrease in forward curves associated with the underlying commodity would have changed the net liability of these instruments by approximately $58,000.  However, any realized derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument.  If the settled oil price in any month during the agreement period is five dollars per barrel more or less than the fixed price of $90.00 per bbl the effect to the Company would be $2,500 for that month.

Interest Rate Risk.  On March 31, 2014, we had an outstanding loan balance of $2,425,000 under our $4.9 million revolving credit agreement, which bears interest at an annual rate equal to the British Bankers Association London Interbank Offered Rate ("BBA LIBOR") daily floating rate, plus 2.5 percentage points.  If the interest rate on our bank debt increases or decreases by one percentage point our annual pretax income would change by $24,250 based on borrowings at March 31, 2014.

Credit Risk.  Credit risk is the risk of loss as a result of nonperformance by other parties of their contractual obligations. Our primary credit risk is related to oil and gas production sold to various purchasers and the receivables are generally not collateralized.  At March 31, 2014, our largest credit risk associated with any single purchaser was $153,749 or 25% of our total oil and gas receivables.  We are also exposed to credit risk in the event of nonperformance from any of our working interest partners.  At March 31, 2014, our largest credit risk associated with any working interest partner was $2,591 or 14% of our total trade receivables. We have not experienced any significant credit losses.

Declines in oil and natural gas prices will materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results.  Changes in oil and gas prices impact both estimated future net revenue and the estimated quantity of proved reserves. Any reduction in reserves, including reductions due to price fluctuations, can reduce the borrowing base under our revolving credit facility and adversely affect the amount of cash flow available for capital expenditures and our ability to obtain additional capital for our acquisition, exploration and development activities. 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 report on Form 10-K.  Lower prices may also reduce the amount of crude oil and natural gas that can be produced economically.  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.

Similarly, any improvements in oil and gas prices can have a favorable impact on our financial condition, results of operations and capital resources.  Oil and natural gas prices do not necessarily fluctuate in direct relationship to each other.  Our financial results are more sensitive to movements in natural gas prices than oil prices because most of our production and reserves are natural gas. If the average oil price had increased or decreased by one dollar per barrel for fiscal 2014, our oil and gas revenue would have changed by $27,186.  If the average gas price had increased or decreased by one dollar per mcf for fiscal 2014, oil and gas revenue would have changed by $361,652.

 

ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required by this item appears on pages F1 through F20 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

 

Evaluation of Disclosure 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. At the end of the period covered by this report, our principal executive officer and principal financial officer reviewed and evaluated the effectiveness of our disclosure controls and procedures, as defined in Exchange Act Rule 13a-15(e). Based on such evaluation, such officers concluded that, as of March 31, 2014, our disclosure controls and procedures were effective.

 

Changes in Internal Control over Financial Reporting. No changes in the Company's internal control over financial reporting occurred during the year ended March 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B.  OTHER INFORMATION

None

 

PART III

ITEM 10.  DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

See "Mexco Energy Corporation Board of Directors”, “Named Executive Officers Who Are Not Directors”, “Section 16(a) Beneficial Ownership Reporting Compliance”, “Corporate Governance and Code of Business Conduct” and “Meetings and Committees of the Board of Directors” in the Proxy Statement of Mexco Energy Corporation for our Annual Meeting of Stockholders to be held September 9, 2014 (“Proxy Statement”) to be filed with the SEC within 120 days after the end of our fiscal year ended March 31, 2014, which is incorporated herein by reference.

The information required by this item with respect to executive officers of the Company is also set forth in Part I of this report.

ITEM 11.  EXECUTIVE COMPENSATION

The information required by this item will be contained in the Proxy Statement under the caption “Executive Compensation”, and is hereby incorporated herein by reference.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The information required by this item will be contained in the Proxy Statement under the captions “Security Ownership of Certain Beneficial Owners and Management” and “Employee Incentive Stock Option Plans”, and is hereby incorporated herein by reference.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

The information required by this item will be contained in the Proxy Statement under the captions “Certain Relationships and Related Transactions” and “Meetings and Committees of the Board of Directors”, and is hereby incorporated by reference herein.

 

 

PART IV

 

ITEM 15.  EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Consolidated Financial Statements.  For a list of the consolidated financial statements filed as part of this Form 10-K, see the “Index to Consolidated Financial Statements” set forth on page F1 of this report.

Financial Statement Schedules.  All schedules have been omitted because they are not applicable, not required under the instructions or the information requested is set forth in the consolidated financial statements or related notes thereto.

Exhibits.  For a list of the exhibits required by this Item and accompanying this Form 10-K see the “Index to Exhibits” set forth on page F21 of this report.

 

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

MEXCO ENERGY CORPORATION

By:	/s/ Nicholas C. Taylor		By:	/s/ Tamala L. McComic
	Chairman of the Board and Chief Executive Officer			President and Chief Financial Officer

Dated:  June 25, 2014

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below as of June 25, 2014, by the following persons on behalf of the Registrant and in the capacity indicated.

 

/s/	Nicholas C. Taylor
	Nicholas C. Taylor
	Chief Executive Officer, Chairman of the Board of Directors
/s/	Tamala L. McComic
	Tamala L. McComic
	Chief Financial Officer, President, Treasurer and Assistant Secretary
/s/	Kenneth L. Clayton
	Kenneth L. Clayton
	Director
/s/	Thomas R. Craddick
	Thomas R. Craddick
	Director
/s/	Paul G. Hines
	Paul G. Hines
	Director

Glossary of Abbreviations and Terms

The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report.

 

BBA LIBOR. British Bankers Association London Interbank Offered Rate.  BBA Libor is the most widely used rate for short term interest rates worldwide.

Bbl.  One stock tank barrel, or 42 U.S. gallons of liquid volume, used herein in reference to crude oil, condensate or natural gas liquids hydrocarbons.

 

Bcf.  One billion cubic feet of natural gas at standard atmospheric conditions.

 

BTU.  British thermal unit.

Completion.  The installation of permanent equipment for the production of oil or natural gas.

Condensate.  Liquid hydrocarbons associated with the production of a primarily natural gas reserve.

 

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.

Developed acreage.  The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development costs.  Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by proved reserve additions and revisions to proved reserves.

Development well.  A well drilled into a proved oil or natural 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 such that proceeds from the sale of such production exceed production expenses and taxes.

 

Exploitation.  The continuing development of a known producing formation in a previously discovered field.  To make complete or maximize the ultimate recovery of oil or natural gas from the field by work including development wells, secondary recovery equipment or other suitable processes and technology.

Exploration.  The search for natural accumulations of oil and natural gas by any geological, geophysical or other suitable means.

Exploratory well.  A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new 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.

Field.  An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

 

Formation.  A layer of rock which has distinct characteristics that differs from nearby rock.

Gross acres or wells.  Refers to the total acres or wells in which the Company owns any amount of working interest.

 

Lease.  An instrument which grants to another (the lessee) the exclusive right to enter and explore for, drill for, produce, store and remove oil and natural gas from the mineral interest, in consideration for which the lessor is entitled to certain rents and royalties payable under the terms of the lease.  Typically, the duration of the lessee’s authorization is for a stated term of years and “for so long thereafter” as minerals are producing.

Mcf.  One thousand cubic feet of natural gas at standard atmospheric conditions.

Mcfe.  One thousand cubic feet equivalent of natural gas, calculated by converting oil to equivalent Mcf at a ratio of 6 Mcf for each Bbl of oil.

MMBtu.  One million British thermal units of energy commonly used to measure heat value or energy content of natural gas.

Natural gas liquids ("NGLs").  Liquid hydrocarbons that have been extracted from natural gas, such as ethane, propane, butane and natural gasoline.

 

Net acres or wells.  Refers to gross acres or wells multiplied, in each case, by the percentage interest owned by the Company.

Net production.  Oil and gas production that is owned by the Company, less royalties and production due others.

 

Net revenue interest.  An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.

Oil.  Crude oil or condensate.

Operator.  The individual or company responsible for the exploration, development and production of an oil or natural gas well or lease.

Overriding royalty interest (“ORRI”).  A royalty interest that is created out of the operating or working interest. Its term is coextensive with that of the operating interest from which it was created.

 

Pay zone.    A geological deposit in which oil and natural gas is found in commercial quantities.

Plugging and abandonment.  Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface.  Regulations of all states require plugging of abandoned wells.

Productive well.  A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed operating and production expenses and taxes.

Prospect.  A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed nonproducing reserves ("PDNP").  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 ("PDP").  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 oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.

 

Proved undeveloped reserves ("PUD").  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.

PV-10.  When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses except for specific general and administrative expenses incurred to operate the properties, discounted to a present value using an annual discount rate of 10%.

Recompletion.  A process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

Re-entry.  Entering an existing well bore to redrill or repair.

Reservoir.  A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

Royalty.  An interest in an oil and natural 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.

Shut in.    A well suspended from production or injection but not abandoned.

Spacing.  The distance between wells producing from the same reservoir.  Spacing is often expressed in terms of acres (e.g., 640-acre spacing) and is often established by regulatory agencies.

Standardized measure of discounted future net cash flows.  The discounted future net cash flows relating to proved reserves based on prices used in estimating the reserves, year-end costs, and statutory tax rates, and a 10% annual discount rate.  The information for this calculation is included in the note regarding disclosures about oil and gas reserve data contained in the Notes to Consolidated Financial Statements included in this Form 10-K.

 

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 natural gas regardless of whether such acreage contains proved reserves.

 

Unit.  The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests.  Also, the area covered by a unitization agreement.

Wellbore.  The hole drilled by the bit that is equipped for crude oil or natural gas production on a completed well.  Also called well or borehole.

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 natural 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.

 

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

 

Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets	F-3
Consolidated Statements of Operations	F-4
Consolidated Statements of Changes in Stockholders’ Equity	F-5
Consolidated Statements of Cash Flows	F-6
Notes to Consolidated Financial Statements	F-7

Mexco Energy Corporation and Subsidiaries

CONSOLIDATED BALANCE SHEETS

 

The accompanying notes to the consolidated financial statements

are an integral part of these statements.

 

 

Mexco Energy Corporation and Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS

Year ended March 31,

 

The accompanying notes to the consolidated financial statements

are an integral part of these statements.

 

Mexco Energy Corporation and Subsidiaries
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
Years ended March 31, 2014, 2013 and 2012
		Common  Stock Par Value				Treasury Stock				Additional Paid-In Capital				Retained Earnings				Total Stockholders’ Equity
Balance at April 1, 2011		$	1,044,558			$	(302,665	)		$	6,453,226			$	5,311,834			$	12,506,953
Net income			-				-				-				329,993				329,993
Purchase of stock			-				(22,780	)			-				-				(22,780	)
Issuance of stock through
options exercised			5,000				-				35,000				-				40,000
Stock based compensation			-				-				120,124				-				120,124
Balance at March 31, 2012		$	1,049,558			$	(325,445	)		$	6,608,350			$	5,641,827			$	12,974,290
Net loss			-				-				-				(176,374	)			(176,374	)
Purchase of stock			-				(15,547	)			-				-				(15,547	)
Issuance of stock through
options exercised			1,875				-				14,438				-				16,313
Stock based compensation			-				-				138,303				-				138,303
Balance at March 31, 2013		$	1,051,433			$	(340,992	)		$	6,761,091			$	5,465,453			$	12,936,985
Net income			-				-				-				301,113				301,113
Issuance of stock through
options exercised			700				-				8,106				-				8,806
Stock based compensation			-				-				152,448				-				152,448
Balance at March 31, 2014		$	1,052,133			$	(340,992	)		$	6,921,645			$	5,766,566			$	13,399,352
SHARE ACTIVITY
							2014				2013				2012
Common stock shares, issued:
At beginning of year							2,102,866				2,099,116				2,089,116
Issued							1,400				3,750				10,000
At end of year							2,104,266				2,102,866				2,099,116
Common stock shares, held in treasury:
At beginning of year							(66,000	)			(63,167	)			(59,167	)
Acquisitions							-				(2,833	)			(4,000	)
At end of year							(66,000	)			(66,000	)			(63,167	)
Common stock shares, outstanding
At end of year							2,038,266				2,036,866				2,035,949

The accompanying notes to the consolidated financial statements

are an integral part of these statements.

 

 

Mexco Energy Corporation and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended March 31,
		2014				2013				2012
Cash flows from operating activities:
Net income (loss)		$	301,113			$	(176,374	)		$	329,993
Adjustments to reconcile net income (loss) to net cash
provided by operating activities:
Deferred income tax expense (benefit)			5,250				(31,504	)			(27,960	)
Stock-based compensation			152,448				138,303				120,124
Depreciation, depletion and amortization			1,151,482				1,100,425				996,205
Accretion of asset retirement obligations			44,366				39,376				36,251
Loss on derivative instruments			99,262				-				-
Changes in assets and liabilities, net of business combination:
(Increase) decrease in accounts receivable			(90,901	)			(117,123	)			63,052
(Increase) decrease in prepaid expenses			(9,523	)			(2,499	)			47,697
Decrease (increase) in noncurrent assets			109,215				(116,454	)			-
Increase in income tax payable			6,500				-				-
Increase (decrease) in accounts payable and accrued expenses			43,289				(17,358	)			10,257
Net cash provided by operating activities			1,812,501				816,792				1,575,619
Cash flows from investing activities:
Additions to oil and gas properties			(2,150,478	)			(1,300,151	)			(1,642,449	)
Acquisition of business			-				(1,150,000	)			-
Additions to other property and equipment			(2,030	)			(13,806	)			-
Settlement of asset retirement obligations			(63,230	)			(4,918)				(2,323)
Settlement of derivatives			(54,281	)			-				-
Proceeds from sale of oil and gas properties and equipment			963,388				69,042				471,543
Net cash used in investing activities			(1,306,631	)			(2,399,833	)			(1,173,229	)
Cash flows from financing activities:
Acquisition of treasury stock			-				(15,547	)			(22,780	)
Proceeds from exercise of stock options			8,806				16,313				40,000
Reduction of long-term debt			(1,375,000	)			(350,000	)			(1,200,000	)
Proceeds from long-term debt			850,000				1,600,000				1,100,000
Net cash (used in) provided by financing activities			(516,194	)			1,250,766				(82,780	)
Net (decrease) increase in cash and cash equivalents			(10,324	)			(332,275	)			319,610
Cash and cash equivalents at beginning of period			166,406				498,681				179,071
Cash and cash equivalents at end of period		$	156,082			$	166,406			$	498,681
Supplemental disclosure of cash flow information:
Cash paid for interest		$	67,170			$	49,158			$	27,920
Non-cash investing and financing activities:
Asset retirement obligations		$	134,113			$	114,003			$	53,468
Acquisition of subsidiary resulting in the assumption of liabilities as follows:
Fair value of assets		$	-			$	1,276,636			$	-
Cash paid			-				(1,150,000	)			-
Liabilities assumed		$	-			$	126,636			$	-

The accompanying notes to the consolidated financial statements

are an integral part of these statements.

 

MEXCO ENERGY CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Years Ended March 31, 2014, 2013 and 2012

 

 

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).  Impairments transferred to the DD&A pool increase the DD&A rate.

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 to determine a limit, or ceiling, on the book value of oil and gas properties.  That limit is basically the after tax present value of the future net cash flows from proved crude oil and natural gas reserves; and, using an average price over the prior 12-month period held flat for the life of production plus the lower of cost or fair market value of unproved properties.  If net capitalized costs of crude oil and natural gas properties exceed the ceiling limit, the Company must charge the amount of the excess to earnings as an expense reflected in additional accumulated DD&A.  This is called a "ceiling limitation write-down."  This charge does not impact cash flow from operating activities, but does reduce stockholders' equity and reported earnings.

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 is amortized using the unit-of-production method.

Income Taxes.  The Company recognizes deferred tax assets and liabilities for future tax consequences of temporary differences between the carrying amounts of assets and liabilities and their respective tax bases.  Deferred tax assets and liabilities are measured using enacted tax rates applicable to the years in which those differences are expected to be settled.  The effect on deferred tax assets and liabilities of a change in tax rates is recognized in net income in the period that includes the enactment date.  Any interest and penalties are recorded as interest expense and general and administrative expense, respectively.

Other Property and Equipment.  Provisions for depreciation of office furniture and equipment are computed on the straight-line method based on estimated useful lives of three to ten years.

Derivatives.  The Company is required to recognize its derivative instruments on the consolidated balance sheets as assets or liabilities at fair value with such amounts classified as current or long-term based on their anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the realized and unrealized change in fair value on derivative instruments in the consolidated statements of operations.

 

 

 

For the year ended March 31, 2014, 35,000 options were excluded from the diluted net income per share calculations because the options are anti-dilutive.  Anti-dilutive stock options have a weighted average exercise price of $5.98 at March 31, 2014.  Due to a net loss for the year ended March 31, 2013, the weighted average number of common shares outstanding excludes common stock equivalents because their inclusion would be anti-dilutive. For the year ended March 31, 2012, 40,000 options were excluded from the diluted net income per share calculations because the options are anti-dilutive.  Anti-dilutive stock options have a weighted average exercise price of $6.80 at March 31, 2012.

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:

		2014				2013				2012
Net income (loss)		$	301,113			$	(176,374	)		$	329,993
Shares outstanding:
Weighted avg. common shares outstanding – basic			2,036,950				2,036,959				2,028,014
Effect of the assumed exercise of dilutive stock options			5,234				-				8,227
Weighted avg. common shares outstanding – dilutive			2,042,184				2,036,959				2,036,241
Income (loss) per common share:
Basic		$	0.15			$	(0.09	)		$	0.16
Diluted		$	0.15			$	(0.09	)		$	0.16

Revenue Recognition. 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.

Gas Balancing. Gas imbalances are accounted for under the sales method whereby revenues are recognized based on production sold. A liability is recorded when excess takes of natural gas volumes exceed 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 does not have any significant gas imbalances.

Stock-based Compensation. The Company uses the Binomial option pricing model to estimate the fair value of stock based compensation expenses at grant date. This expense is recognized as compensation expense in its financial statements over the vesting period. The Company recognizes the fair value of stock-based compensation awards as wages in the Consolidated Statements of Operations based on a graded-vesting schedule over the vesting period.

Recent Accounting Pronouncements. In May 2014, the Financial Accounting Standards Boards ("FASB") issued Accounting Standards Update ("ASU") No. 2014-09, Topic 606: Revenue from Contracts with Customers. ASU No. 2014-09 is effective for Mexco as of April 1, 2017. Management is evaluating the effect, if any this pronouncement will have on the Company's consolidated financial statements.

 

3.  Business Combinations

On December 31, 2012, the Company purchased all of the outstanding ownership interests of TBO Oil & Gas, LLC ("TBO"), a Texas limited liability company which owns non-operated working interests in approximately 280 wells producing primarily oil, expanding the Company's revenues. The cash purchase price of $1,150,000 was funded from its $4.9 million bank credit facility.

 

The purchase price was allocated to the assets acquired and liabilities assumed at estimated fair values as follows:

Proved oil and gas properties		$	1,202,013
Accounts receivable			74,623
Total assets acquired			1,276,636
Accounts payable			(45,876	)
Asset retirement obligations assumed			(80,760	)
Net purchase price		$	1,150,000

The Company’s results of operations for fiscal year 2014 include approximately $705,000 in revenues and approximately $448,000 in earnings from TBO.  The Company’s results of operations for fiscal year 2013 include approximately $119,800 in revenues and approximately $62,400 in earnings from TBO.  The Company’s results of operations for fiscal year 2012 do not include any revenues or costs from TBO.

4.  Fair Value of Financial Instruments.

Fair value as defined by authoritative literature is the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date.  Fair value measurements are classified and disclosed in one of the following categories:

Level 1 – Quoted prices in active markets for identical assets and liabilities.

Level 2 – Quoted prices in active markets for similar assets and liabilities, quoted prices for identical or similar instruments in markets that are not active and model-derived valuations whose inputs are observable or whose significant value drivers are observable.

Level 3 – Significant inputs to the valuation model are unobservable.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.  In accordance with the reporting requirements of FASB ASC Topic 825, Financial Instruments, the Company calculates the fair value of its assets and liabilities which qualify as financial instruments.

The fair value of the Company’s crude oil swaps are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity.  The valuation of the Company’s derivative instrument is deemed to use Level 2 inputs.  See the Company’s Note 8 on Derivatives for further discussion.  The unrealized loss on derivatives for the year ended March 31, 2014 was approximately $45,000.

The initial measurement of asset retirement obligations’ fair value is calculated using discounted cash flow techniques and is based on internal estimates of future retirement costs associated with oil and gas properties. Given the unobservable nature of the inputs, including plugging costs and reserve lives, the initial measurement of the ARO liability is deemed to use Level 3 inputs.  See the Company’s note on AROs for further discussion.  AROs incurred during the year ended March 31, 2014 were approximately $134,000.

The carrying amount reported in the accompanying consolidated balance sheets for cash and cash equivalents, accounts receivable and accounts payable approximates fair value because of the immediate or short-term maturity of these financial instruments. The carrying amount reported in the accompanying consolidated balance sheets for long term debt approximates fair value because the actual interest rates do not significantly differ from current rates offered for instruments with similar characteristics.

 

5.  Credit Facility

Mexco has a revolving credit agreement with Bank of America, N.A. (the “Agreement”), which provides for a credit facility of $4,900,000 with no monthly commitment reductions and a borrowing base evaluated annually, currently set at $4,900,000.  Amounts borrowed under the Agreement are collateralized by the common stock of the Company’s wholly owned subsidiaries and substantially all of the Company’s oil and gas properties. Availability of this line of credit at March 31, 2014 was $2,319,333.  No principal payments are anticipated to be required through November 30, 2015.

The balance outstanding on the line of credit as of March 31, 2014 was $2,425,000 and as of June 25, 2014 was $2,300,000.  The following table is a summary of activity on the Bank of America, N.A. line of credit for the year ended March 31, 2014:

		Principal
Balance at April 1, 2013:		$	2,950,000
Borrowings			850,000
Repayments			(1,375,000	)
Balance at March 31, 2014:		$	2,425,000

6.  Asset Retirement Obligations

The following table provides a rollforward of the asset retirement obligations for fiscal years ended March 31:

		2014				2013
Carrying amount of asset retirement obligations as of April 1		$	813,412			$	663,279
Liabilities incurred			134,113				114,003
Liabilities settled			(30,314	)			(3,246	)
Accretion expense			44,366				39,376
Carrying amount of asset retirement obligations as of March 31			961,577				813,412
Less: Current portion			35,000				50,000
Non-Current asset retirement obligation		$	926,577			$	763,412

 

 

7.  Income Taxes

Significant components of net deferred tax assets (liabilities) at March 31 are as follows:

		2014				2013
Deferred tax assets:
Percentage depletion carryforwards		$	1,463,834			$	1,336,630
Deferred stock-based compensation			29,475				24,003
Asset retirement obligation			298,089				252,158
Net operating loss			298,736				503,659
Derivative instruments			13,944
Other			9,673				3,237
			2,113,751				2,119,687
Deferred tax liabilities:
Excess financial accounting bases over tax bases of property and equipment			(2,972,200	)			(2,972,886	)
Net deferred tax liabilities		$	(858,449	)		$	(853,199	)

The income tax provision consists of the following for years ended March 31, 2014, 2013 and 2012:

		2014				2013				2012
Current income tax expense		$	6,500			$	-			$	-
Deferred income tax expense (benefit)			5,250				(31,504	)			(27,960	)
Total income tax provision:		$	11,750			$	(31,504	)		$	(27,960	)
Effective tax rate			4	%			(15	%)			(9	%)

A reconciliation of the provision for income taxes to income taxes computed using the federal statutory rate for years ended March 31 follows:

		2014				2013				2012
Tax expense at federal statutory rate (1)		$	106,374			$	(70,678	)		$	102,691
Statutory depletion carryforward			(127,204	)			-				(155,734	)
Effect of graduated rates			(13,841	)			3,391				(16,940	)
Revision of prior year estimates			-				-				4,314
Permanent differences			46,421				35,783				30,210
Other			-				-				7,499
Total income tax expense (benefit)		$	11,750			$	(31,504	)		$	(27,960	)
Effective income tax rate			4	%			(15	%)			(9	%)

(1)	The federal statutory rate was 34% for fiscal years ending March 31, 2014, 2013 and 2012.

 

 

A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows:

 

		2014				2013				2012
Unrecognized tax benefits at beginning of period		$	677,000			$	677,000			$	670,000
Additions based on tax positions related to the current year			2,000				-				-
Changes to tax positions of prior years			-				-				7,000
Settlements			-				-				-
Expirations			-				-				-
Unrecognized tax benefits at end of period		$	679,000			$	677,000			$	677,000

While the amount of unrecognized tax benefits may change in the next 12 months, the Company does not expect any change to have a significant impact on its results of operations. The recognition of the total amount of the unrecognized tax benefits would have an impact on the effective tax rate. If these unrecognized tax benefits are disallowed, the Company will be required to pay additional taxes.

 

8. Derivatives

All derivative financial instruments are recorded at fair value. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the realized and unrealized changes in fair value in the consolidated statements of operations under the caption “Loss on derivative instruments.”

As of March 31, 2014 the Company had the following open crude oil derivative positions with respect to future production based on NYMEX WTI pricing:

		Volume (bbls)				Fixed Swap Price
Production Period
April 2014 – March 2015			6,000			$	90.00

The fair value of swaps is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity.

The net fair value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows for the years ended March 31:

		2014				2013
Current assets:  Derivative instruments		$	-			$	-
Noncurrent assets:  Derivative instruments			-			$	-
Total assets		$	-			$	-
Current liabilities:  Derivative instruments		$	44,981			$	-
Noncurrent liabilities: Derivative instruments			-			$	-
Total liabilities		$	44,981			$	-

None of the Company’s derivatives have been designated as hedges. As such, all changes in fair value are immediately recognized in earnings. The following summarizes the loss on derivative instruments included in the consolidated statements of operations for the year ended March 31, 2014 and 2013:

 

		2014				2013
Unrealized loss on open non-hedge derivative instruments		$	(44,981	)		$	-
Loss on settlement of non-hedge derivative instruments			(54,281	)		$	-
Total loss on derivative instruments		$	(99,262	)		$	-