NORTHERN MINERALS & EXPLORATION LTD. - Annual Report: 2018 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended July 31, 2018

Commission File Number 333-146934

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 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 90 days.

☐ YES ☒ 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 (§232.405 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 ☒ NO

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act ☐ YES ☒ NO

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. As of November 9, 2018, the issuer had 48,436,818 common shares issued and outstanding.

NORTHERN MINERALS & EXPLORATION LTD.

FORM 10-K

For the Year ended July 31, 2018

TABLE OF CONTENTS

PART I

ITEM 1. DESCRIPTION OF BUSINESS

Our Corporate History and Background

We were incorporated on December 11, 2006 under the laws of the State of Nevada.

We were originally a company involved in the placing of strength testing amusement gaming machines called Boxers in venues such as bars, pubs and nightclubs in the Seattle area, in the State of Washington. We acquired one Boxer that had been placed in Lynnwood, Washington. However, the machine was de-commissioned as it needed material repairs. We were not able to secure sufficient capital for these repairs and our management decided to change our business focus to on oil and gas and mineral exploration. On July 12, 2013, the stockholders approved an amendment to change the name of the Company from Punchline Resources Ltd. to Northern Mineral & Exploration Ltd. FINRA approved the name change on August 13, 2013.

Northern Minerals & Exploration Ltd. (the “Company”) is an emerging natural resource company operating in oil and gas production in central Texas and exploration for gold and silver in northern Nevada.

On November 22, 2017, the Company created a wholly owned subsidiary, Kathis Energy LLC (“Kathis”), a duly formed Limited Liability Company formed in the State of Texas, for the purpose of conducting oil and gas drilling programs in Texas.

On December 14, 2017, Kathis Energy, LLC and other Limited Partners, created Kathis Energy Fund 1, LP, a duly formed Limited Partnership formed in the State of Texas, created for the purpose of raising funds from investors for its drilling projects.

On May 7, 2018, the Company created a wholly owned subsidiary, ENMEX Operations LLC (“ENMEX”), a duly formed Limited Liability Company in the State of Quintana Roo, Mexico for the purpose of conducting business in Mexico in prospective real estate development projects. There has been no activity from inception to date.

Forward-Looking Statements

This report on Form 10-K contains certain forward-looking statements. All statements other than statements of historical fact are “forward-looking statements” for purposes of these provisions, including any projections of earnings, revenues, or other financial items; any statements of the plans, strategies, and objectives of management for future operation; any statements concerning proposed new products, services, or developments; any statements regarding future economic conditions or performance; statements of belief; and any statement of assumptions underlying any of the foregoing. Such forward-looking statements are subject to inherent risks and uncertainties, and actual results could differ materially from those anticipated by the forward-looking statements.

These forward-looking statements involve significant risks and uncertainties, including, but not limited to, the following: competition, promotional costs and the risk of declining revenues. Our actual results could differ materially from those anticipated in such forward-looking statements as a result of a number of factors. These forward-looking statements are made as of the date of this filing, and we assume no obligation to update such forward-looking statements. The following discusses our financial condition and results of operations based upon our unaudited financial statements which have been prepared in conformity with accounting principles generally accepted in the United States. It should be read in conjunction with our financial statements and the notes thereto included elsewhere herein.

Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, levels of activity, performance or achievements. Except as required by applicable law, including the securities laws of the United States, we do not intend to update any of the forward-looking statements to conform these statements to actual results.

Our financial statements are stated in United States Dollars (US$) and are prepared in accordance with United States Generally Accepted Accounting Principles.

In this annual report, unless otherwise specified, all dollar amounts are expressed in United States Dollars (US$) and all references to “common shares” refer to the common shares in our capital stock.

As used in this quarterly report, the terms “we”, “us”, “our” and “our company” mean Northern Minerals & Exploration Ltd. formerly known as Punchline Resources Ltd., unless otherwise indicated. 

Current Business

ENMEX Operations LLC – Wholly owned Subsidiary - Pemer Bacalar – Resort Development Project

During the quarter ended October 31, 2017, the Company entered into a Letter of Intent with Pemer Bacalar SAPI DE CV on September 22, 2017 to examine the opportunity of acquiring ownership in approximately 61 acres (“Property”) on a freshwater lagoon near the community of Bacalar, Mexico in the state of Quintana Roo for the purpose of entering into a joint venture for the potential development of the Property into a resort. On November 16, 2017, the Company entered into a Memorandum of Understanding (“MOU”) in order to further conduct due diligence toward this potential project. An amended MOU was entered into on April 13, 2018 setting forth the conditions for entering into a definitive agreement with Pemer Bacalar. As of July 31, 2018, the Company is still conducting its due diligence.

Coleman County, Texas – Three well rework/re-completion project

On October 14, 2014, we entered into an agreement to acquire the 206.5 acre J.E. Richey oil and gas lease. This lease area has six known productive formations. The existing three wells on the lease are fully equipped. Beginning in May 2015 we started conducting operations on the three wells to place them back into production. The rework/re-completion was completed on July 28, 2015 and production of oil and gas was established. Additional work was conducted on J. E. Richey lease during the fiscal year ended July 31, 2018. See Item 2 Properties for additional information

Coleman County, Texas – J. E. Richey #2A -Proposed New Well:

The Company has sold working interest in a 20 acre tract on the J.E. Richey Lease to drill a new well near the ARCO Richey #2 well. This well initially was completed in the Lower Ellenburger in 1982 coming in at 19 barrels per day. Following depletion of the Lower Ellenburger the well was re-completed in the Upper Ellenburger with an initial production rate of 2,535 MCF per day. Subsequently the well was re-completed in the Gray Sand, which came in at 45 barrels per day on a light acid job and no sand frac was conducted. The well only produced for a limited amount of time from the Gray Sand when a hole came in the casing above the cement at 1100 feet caused by a corrosive formation known as the Coleman Junction and the well was shut in. This well was plugged due to casing problems in the well on December 28, 2017. See Item 2 Properties for additional information 

Kathis Energy LLC – Wholly owned Subsidiary:

The Company created a wholly owned subsidiary, Kathis Energy LLC (“Kathis”), on November 22, 2017 for the purpose of conducting oil and gas drilling programs in Texas. The Company agreed to assign to Kathis the Olson and Guy Ranch leases in exchange for $126,500. Kathis is seeking to raise drilling funds to drill up to 8 wells. As of July 31, 2018, Kathis has raised $125,000 and is continuing to seek funding for its drilling program. As of the date of this report no wells have been drilled. Kathis has additional information regarding its drilling program on its website www.kathisenergy.com See Item 2 Properties for additional information

Jones County, Texas – Palo Pinto Reef project

During the fiscal year ended July 31, 2016 the Company acquired the Olson lease covering 160 acres in Jones County, Texas. This lease is 1.5 miles from the Strand Palo Pinto Reef Field which was discovered in 1940 and has produced 1,700,000 barrels of oil from 8 wells or 212,500 barrels of oil per well. The structure map on the Palo Pinto shows a large buildup in the Palo Pinto Reef across the southern portion of the lease. See Item 2 Properties for additional information

Shackelford County, Texas – Guy Ranch Project:

During the fiscal year ended July 31, 2016 the Company acquired 692-acres divided into two tracts Guy Ranch Lease in Shackelford County. The Guy Ranch lease is located in the southern part of Shackelford County. The Ranch has 32 wind turbines on it representing it is at a structurally higher elevation. The principal targets for this drilling prospect is the Patio (aka Palo Pinto Sand) and Morris Sands the area is also know to be productive from three other formations on the Guy Ranch acreage. See Item 2 Properties for additional information

Riverside Prospects, Runnels County, Texas

On October 20, 2017 the Company entered into an exclusive option agreement with Murphree Oil Company to acquire drilling prospects on four leases in Runnels County near the City of Ballinger, known as the Riverside Prospects. During the quarter ended April 30, 2018, the Company, through its wholly owned subsidiary, Kathis Energy LLC, (“Kathis”) paid the lease bonuses for extending the oil and gas lease period on 548.76 acres covering the Riverside Prospects. This acreage consists of 4 leases in a well established area where oil and gas production was discovered during 1978 – 1983. See Item 2 Properties for additional information

89 Guy #4 Well – Cased Hole:

On April 16, 2018, Kathis Energy acquired the 89 Guy Well #4 located on a 20-acre tract on the Guy Ranch property in Shackelford County, Texas. The well is an abandoned cased well that was drilled in October 2010 and completed in the Patio Sand at the interval of 3,144’ - 3,154’. The interval perforated (3,144 – 3,154’) is above the best productive part of the formation. See Item 2 Properties for additional information

McClure 2B Gas Well – Producing:

On February 6, 2018 the Company acquired the McClure # 2B producing gas well on a 40-acre oil & gas lease located in Palo Pinto County near the Community of Graford, Texas. The McClure 2B well is completed in the Strawn in the interval 2,882’ to 2,940’ and has produced in excess of 70 million cubic feet of natural gas. See Item 2 Properties for additional information

Carter & Foster Wells – Producing:

During the fiscal year ended July 31, 2018 the Company acquired the Carter and Foster wells located west of the Community of Atwell, Texas in Callahan County. The Carter lease consists of 40 acres and has one well. The Foster lease has 10 acres around each well of the three wells, all of which are fully equipped with surface and subsurface equipment. All four wells are completed in the Palo Pinto Limestone formation at approximately 1,900 feet. See Item 2 Properties for additional information

Reeves Lease – Acreage – Palo Pinto Reef Prospect:

In August 2018, subsequent to the end of the fiscal year ended July 31, 2018, the Company paid for the geological prospecting fees for a Palo Pinto Reef prospect in Jones County. The Reeves lease covers 160 acres and is located near Noodle, Texas in Jones County. The projected depth of the Palo Pinto Reef is 4,300’. See Item 2 Properties for additional information

Winnemucca Mountain Property

On September 14, 2012, our company entered into an option agreement (as amended and restated on November 15, 2012, February 1, 2013 and August 26, 2013) with AHL Holdings Ltd., a Nevada corporation, and Golden Sands Exploration Inc., a company incorporated under the laws of British Columbia, Canada, wherein we acquired an option to purchase a revised 80% interest in and to certain mining claims from AHL Holdings and Golden Sands, which claims form the Winnemucca Mountain Property in Humboldt County, Nevada. This Winnemucca Mountain property is currently comprised of 138 unpatented mining claims covering an area of approximately 2,700 acres.

On July 23, 2018, the Company entered into a New Option Agreement with AHL Holding Ltd & Golden Sands Exploration Inc. (“Optionors”). This agreement provided for the payment of $25,000 and the issuance of 3,000,000 shares of the Company’s common stock. The Company issued the shares and made the payment of $25,000 per the agreement on July 31, 2018. The second payment of $25,000 per the terms of the agreement was to be paid when it was due on August 31, 2018. The Company is in default of the terms of the July 23, 2018 agreement. The Company at the time of this filing is in discussions seek a mutual agreement and or settlement with the Optionors to proceed forward with the Winnemucca Property. Item 2 Properties for additional information

Mining Sector

Competition

We are a mineral resource exploration company. We compete with other mineral resource exploration companies for financing and for the acquisition of new mineral properties. Many of the mineral resource exploration companies with whom we compete have greater financial and technical resources than those available to us. Accordingly, these competitors may be able to spend greater amounts on acquisitions of mineral properties of merit, on exploration of their mineral properties and on development of their mineral properties. In addition, they may be able to afford more geological expertise in the targeting and exploration of mineral properties. This competition could result in competitors having mineral properties of greater quality and interest to prospective investors who may finance additional exploration. This competition could adversely impact on our ability to finance further exploration and to achieve the financing necessary for us to develop our mineral properties.

Compliance with Government Regulation

The operation of mines is governed by both federal and state laws. The Empress Property and the Winnemucca Property are administered by the United States Department of Interior, Bureau of Land Management (“BLM”) in Nevada. In general, the federal laws that govern mining claim location and maintenance and mining operations on Federal Lands, including the Empress Property and Winnemucca Property, are administered by the BLM. Additional federal laws, such as those governing the purchase, transport or storage of explosives, and those governing mine safety and health, also apply.

The State of Nevada likewise requires various permits and approvals before mining operations can begin, although the state and federal regulatory agencies usually cooperate to minimize duplication of permitting efforts. Among other things, a detailed reclamation plan must be prepared and approved, with bonding in the amount of projected reclamation costs. The bond is used to ensure that proper reclamation takes place, and the bond will not be released until that time. The Nevada Division of Environmental Protection (NDEP) is the state agency that administers the reclamation permits, mine permits and related closure plans on the project. Local jurisdictions may also impose permitting requirements, such as conditional use permits or zoning approvals.

Mining activities at the Properties are also subject to various environmental laws, both federal and state, including but not limited to the federal National Environmental Policy Act, CERCLA (as defined below), the Resource Recovery and Conservation Act, the Clean Water Act, the Clean Air Act and the Endangered Species Act, and certain Nevada state laws governing the discharge of pollutants and the use and discharge of water. Various permits from federal and state agencies are required under many of these laws. Local laws and ordinances may also apply to such activities as waste disposal, road use and noise levels.

We are committed to fulfilling our requirements under applicable environmental laws and regulations. These laws and regulations are continually changing and, as a general matter, are becoming more restrictive. Our policy is to conduct our business in a manner that safeguards public health and mitigates the environmental effects of our business activities. To comply with these laws and regulations, we have made, and in the future may be required to make, capital and operating expenditures.

The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), imposes strict, joint, and several liability on parties associated with releases or threats of releases of hazardous substances. Liable parties include, among others, the current owners and operators of facilities at which hazardous substances were disposed or released into the environment and past owners and operators of properties who owned such properties at the time of such disposal or release. This liability could include response costs for removing or remediating the release and damages to natural resources. We are unaware of any reason why our properties would currently give rise to any potential liability under CERCLA. We cannot predict the likelihood of future liability under CERCLA with respect to our properties or surrounding areas that have been affected by historic mining operations.

Under the Resource Conservation and Recovery Act (RCRA) and related state laws, mining companies may incur costs for generating, transporting, treating, storing, or disposing of hazardous or solid wastes associated with certain mining-related activities. RCRA costs may also include corrective action or clean up costs.

Mining operations may produce air emissions, including fugitive dust and other air pollutants, from stationary equipment, such as crushers and storage facilities, and from mobile sources such as trucks and heavy construction equipment. All of these sources are subject to review, monitoring, permitting, and/or control requirements under the federal Clean Air Act and related state air quality laws. Air quality permitting rules may impose limitations on our production levels or create additional capital expenditures in order to comply with the permitting conditions. Under the federal Clean Water Act and delegated state water-quality programs, point-source discharges into “Waters of the State” are regulated by the National Pollution Discharge Elimination System (NPDES) program. Section 404 of the Clean Water Act regulates the discharge of dredge and fill material into “Waters of the United States,” including wetlands. Stormwater discharges also are regulated and permitted under that statute. All of those programs may impose permitting and other requirements on our operations.

The National Environmental Policy Act (NEPA) requires an assessment of the environmental impacts of “major” federal actions. The “federal action” requirement can be satisfied if the project involves federal land or if the federal government provides financing or permitting approvals. NEPA does not establish any substantive standards. It merely requires the analysis of any potential impact. The scope of the assessment process depends on the size of the project. An “Environmental Assessment” (EA) may be adequate for smaller projects. An “Environmental Impact Statement” (EIS), which is much more detailed and broader in scope than an EA, is required for larger projects. NEPA compliance requirements for any of our proposed projects could result in additional costs or delays.

The Endangered Species Act (ESA) is administered by the U.S. Fish and Wildlife Service of the U.S. Department of Interior. The purpose of the ESA is to conserve and recover listed endangered and threatened species and their habitat. Under the ESA, “endangered” means that a species is in danger of extinction throughout all or a significant portion of its range. The term “threatened” under such statute means that a species is likely to become endangered within the foreseeable future. Under the ESA, it is unlawful to “take” a listed species, which can include harassing or harming members of such species or significantly modifying their habitat. We currently are unaware of any endangered species issues at our projects that would have a material adverse effect on our operations. Future identification of endangered species or habitat in our project areas may delay or adversely affect our operations.

U.S. federal and state reclamation requirements often mandate concurrent reclamation and require permitting in addition to the posting of reclamation bonds, letters of credit or other financial assurance sufficient to guarantee the cost of reclamation. If reclamation obligations are not met, the designated agency could draw on these bonds or letters of credit to fund expenditures for reclamation requirements. Reclamation requirements generally include stabilizing, contouring and re-vegetating disturbed lands, controlling drainage from portals and waste rock dumps, removing roads and structures, neutralizing or removing process solutions, monitoring groundwater at the mining site, and maintaining visual aesthetics. We are committed to maintaining all of our financial assurance and reclamation obligations.

We believe that we are currently in compliance with the statutory and regulatory provisions governing our operations. We hold or will hold all necessary permits and other authorizations to the extent that our current or future claims and the associated operations require them. During the initial phases of our exploration program there will not be any significant disturbances to the land or environment and hence, no government approval is required.

However, we may do business and own properties in a number of different geographical areas and are therefore subject to the jurisdictions of a large number of different authorities at different countries. We plan to comply with all statutory and regulatory provisions governing our current and future operations. However, these regulations may increase significant costs of compliance to us, and regulatory authorities also could impose administrative, civil and criminal penalties for non-compliance. At this time, it is not possible to accurately estimate how laws or regulations would impact our future business. We also can give no assurance that we will be able to comply with future changes in the statutes and regulations.

As we do not know the extent of the exploration program that we will be undertaking, we cannot estimate the cost of the remediation and reclamation that will be required. Hence, it is impossible at this time to assess the impact of any capital expenditures on earnings or our competitive position in the event that a potentially economic deposit is discovered.

If we are successful in identifying a commercially viable ore body and we are able to enter into commercial production, due to the increased environmental impact, the cost of complying with permit and environmental laws will be greater than in the previous phases.

Environmental Regulations

We are not aware of any material violations of environmental permits, licenses or approvals that have been issued with respect to our operations. We expect to comply with all applicable laws, rules and regulations relating to our business, and at this time, we do not anticipate incurring any material capital expenditures to comply with any environmental regulations or other requirements.

While our intended projects and business activities do not currently violate any laws, any regulatory changes that impose additional restrictions or requirements on us or on our potential customers could adversely affect us by increasing our operating costs or decreasing demand for our products or services, which could have a material adverse effect on our results of operations.

Oil & Gas Sector

Competition

The petroleum industry is highly competitive. Many of the oil and gas exploration companies with whom we compete have greater financial and technical resources than we do. Accordingly, these competitors may be able to spend greater amounts on acquisitions of properties of merit and on exploration. In addition, they may be able to afford greater geological expertise in the targeting and exploration of resource properties. This competition could result in our competitors having resource properties of greater quality and interest to prospective investors who may finance additional exploration, and to senior exploration companies that may purchase resource properties or enter into joint venture agreements with junior exploration companies. This competition could adversely impact our ability to finance property acquisitions and further exploration.

We compete with other exploration and early stage operating companies for financing from a limited number of investors prepared to make investments in junior companies exploring for conventional and unconventional oil and gas resources. The presence of competing oil and gas exploration companies, both major and independent, may impact our ability to raise additional capital in order to fund our exploration programs if investors are of the view that investments in competitors are more attractive based on the merit of the properties under investigation, and the price of the investment offered to investors.

Governmental Regulation

Our business is affected by numerous laws and regulations, including energy, environmental, conservation, tax and other laws and regulations relating to the oil and natural gas industry. We have developed internal procedures and policies to ensure that our operations are conducted in full and substantial environmental regulatory compliance. 

Failure to comply with any laws and regulations may result in the assessment of administrative, civil and/or criminal penalties, the imposition of injunctive relief or both. Moreover, changes in any of these laws and regulations could have a material adverse effect on business. In view of the many uncertainties with respect to current and future laws and regulations, including their applicability to us, we cannot predict the overall effect of such laws and regulations on our future operations.

We believe that our operations comply in all material respects with applicable laws and regulations and that the existence and enforcement of such laws and regulations have no more restrictive an effect on our operations than on other similar companies in the oil and natural gas industry.

Pricing and Marketing of Natural Gas

In the US, historically, the sale of natural gas in interstate commerce has been regulated pursuant to the Natural Gas Act of 1938, or the NGA, the Natural Gas Policy Act of 1978, or the NGPA, and regulations promulgated thereunder by the Federal Energy Regulatory Commission, or the FERC. In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, or the Decontrol Act. The Decontrol Act removed all NGA and NGPA price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993 and sales by producers of natural gas are uncontrolled and can be made at market prices. The natural gas industry historically has been heavily regulated and from time to time proposals are introduced by Congress and the FERC and judicial decisions are rendered that impact the conduct of business in the natural gas industry. We cannot assure you that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.

Pricing and Marketing of Oil

In the US, sales of crude oil, condensate and natural gas liquids are not regulated and are made at negotiated prices. Effective January 1,1995, the FERC implemented regulations establishing an indexing system for transportation rates for oil that allowed for an increase in the cost of transporting oil to the purchaser.

Royalties and Incentives

The royalty regime is a significant factor in the profitability of oil, natural gas and natural gas liquids production. In the US, all royalties are determined by negotiations between the mineral owner and the lessee.

Environmental

Like the oil and natural gas industry in general, our properties are subject to extensive and changing federal, state and local laws and regulations designed to protect and preserve natural resources and the environment. The recent trend in environmental legislation and regulation in the oil and natural gas industry is generally toward stricter standards, and this trend is likely to continue. These laws and regulations often require a permit or other authorization before construction or drilling commences and for certain other activities; limit or prohibit access, especially in wilderness areas with endangered or threatened plant or animal species; impose restrictions on construction, drilling and other exploration and production activities; regulate air emissions, wastewater and other production and waste streams from our operations; impose substantial liabilities for pollution that may result from our operations; and require the reclamation of certain lands.

The permits required for many of our operations are subject to revocation, modification and renewal by issuing authorities. Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines, compliance orders, and other enforcement actions. We are not aware of any material noncompliance with current applicable environmental laws and regulations, and we have no material commitments for capital expenditures to comply with existing environmental requirements, however, given the complex regulatory requirements applicable to our operations, and the rapidly changing nature of environmental laws in our industry, we cannot predict our future exposure concerning such matters, and our future costs to achieve compliance, or remedy potential violations, could be significant. Our operations require permits and are regulated under environmental laws, and current or future noncompliance with such laws, as well as changes to existing laws or interpretations thereof, could have a significant impact on us, as well as the oil and natural gas industry in general.

Waste Disposal and Contamination Issues

The federal Comprehensive Environmental Response, Compensation and Liability Act and comparable state laws may impose strict and joint and several liability on owners and operators of contaminated sites and on persons who disposed of or arranged for the disposal of hazardous substances found at such sites. Under these and other laws, the government, neighboring landowners and other third parties may recover the costs of responding to soil and groundwater contamination and threatened releases of hazardous substances, and seek recovery for related natural resources damages, personal injury and property damage. Some of our properties have been used for exploration and production activities for a number of years by third parties, and such properties could result in unknown cleanup liabilities for us.

The federal Resource Conservation and Recovery Act (the “RCRA”) and comparable state statutes govern the management, storage, treatment and disposal of solid waste and hazardous waste and authorize imposition of substantial fines and penalties for noncompliance. Although RCRA classifies certain oil field wastes as “non-hazardous” (for example, the waters produced from hydraulic fracturing operations), such wastes could be reclassified as hazardous wastes in the future, thereby making them subject to more stringent handling and disposal requirements which could have a material impact on us.

Water Regulation

The federal Clean Water Act (the “CWA”), the federal Safe Drinking Water Act (the “SWDA”) and analogous state laws restrict the discharge of wastewater and other pollutants into surface waters or underground wells and the construction of facilities in wetland areas without a permit. Federal regulations also require certain owners or operators of facilities that store or otherwise handle oil, such as us, to prepare and implement spill prevention, control countermeasure and response plans relating to the possible discharge of oil into surface waters. In addition, the Oil Pollution Act (the “OPA”) contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States. For onshore and offshore facilities that may affect waters of the United States, the OPA requires an operator to demonstrate financial responsibility. Regulations are currently being developed or considered under federal and state laws concerning oil pollution prevention and other matters that may impose additional regulatory burdens on us.

These and similar state laws also govern the management and disposal of produced waters from the extraction process. Currently, wastewater associated with oil and natural gas production is prohibited from being directly discharged to waterways and other waters of the U.S. While some of the wastewater is reused or re-injected, a significant amount still requires proper disposal. As a result, some wastewater is transported to third-party treatment plants. In October 2011, citing concerns that third-party treatment plants may not be properly equipped to handle wastewater from shale gas operations, the United States Environmental Protection Agency (the “EPA”) announced that it will consider federal pre-treatment standards for these wastewaters. We cannot predict the EPA’s future actions in this regard, but future regulation of our produced waters or other waste streams could have a material impact on us.

Air Emissions and Climate Change

The federal Clean Air Act (“CAA”) imposes permit requirements and operational restrictions on certain sources of emissions used in our operations. In July 2011, the EPA published proposed New Source Performance Standards (“NSPS”) and National Emissions Standards for Hazardous Air Pollutants (“NESHAPs”) that would, if adopted, amend existing NSPS and NESHAP standards for oil and natural gas facilities and create new NSPS standards for oil and natural gas production, transmission and distribution facilities. Importantly, these standards would include standards for hydraulically fractured wells. The standards would apply to newly drilled and fractured wells as well as existing wells that are refractured. A court has directed the EPA to issue final rules by April 1, 2012. In a report issued in late 2011, the Shale Gas Production Subcommittee of the Department of Energy (the “DOE Shale Gas Subcommittee”) called on the EPA to complete the rulemaking quickly and recommended expanding the shale gas emission sources to be covered by the new rules. The DOE Shale Gas Subcommittee also encouraged states to take similar action, and included several other recommendations for studying and reducing air emissions from shale gas production activities. Because the EPA’s regulations have not yet been finalized, we cannot at this time predict the impact they may have on our financial condition or results of operation.

The issue of climate change has received increasing regulatory attention in recent years. The EPA has issued regulations governing carbon dioxide, methane and other greenhouse gas (“GHG”) emissions citing its authority under the CAA Several of these regulations have been challenged in litigation that is currently pending before the federal D.C. Circuit Court of Appeals. In December 2011, the EPA issued amendments to a final rule issued in 2010 requiring reporting of GHG emissions from the oil and natural gas industry. Under this rule, we are obligated to report to the EPA certain GHG emissions from our operations. We do not expect that the costs of this new reporting will be material to us. In a late 2011 report, the DOE Shale Gas Subcommittee recommended that the EPA expand reporting requirements for GHG emissions from shale gas emission sources and include methane in reporting requirements. More generally, several proposals to regulate GHG emissions have been proposed in the U.S. Congress, and various states have taken steps to regulate GHG emissions. The adoption and implementation of regulations or legislation imposing restrictions or other regulatory obligations on emissions of GHGs from oil and natural gas operations could require us to obtain permits or allowances for our GHG emissions, install new pollution controls, increase our operational costs, limit our operations or adversely affect demand for the oil and natural gas produced from our lands.

Regulation of Hydraulic Fracturing

Our industry uses hydraulic fracturing to recover oil and natural gas in deep shale and other previously inaccessible subsurface geological formations. Hydraulic fracturing (or “fracking”) is a process to significantly increase production in drilled wells by creating or expanding cracks, or fractures, in underground formations by injecting water, sand and other additives into formations at high pressures. Like others in our industry, we may use this process as a means to increase the productivity of our wells. Although hydraulic fracturing has been an accepted practice in the oil and natural gas industry for many years, its use has dramatically increased in the last decade, and concerns over its potential environmental effects have received increasing attention from regulators and the public.

Under the Safe Drinking Water Act (“SDWA”), the EPA is prohibited from regulating the injection of fracking fluids through its underground injection control program, except in limited circumstances (for example, the EPA has asserted that it has authority to regulate when diesel is a component of the fluids). Waters produced from fracking operations must be disposed of in accordance with federal and state regulations. As discussed above, the EPA has announced an intention to propose pre-treatment standards for produced waters that are to be disposed of at third-party wastewater treatment plants. Separately, the EPA is studying the effects of fracking on drinking water as a result of Congressional and public concern over fracking’s potential to impact groundwater supplies, and the EPA has indicated that it expects to issue its findings later this year.

In that regard, the EPA recently issued a study indicating that contamination may have resulted from certain fracking operations in Wyoming. The operator of the wells has challenged the EPA’s findings, contending that other activities may be to blame for contaminated groundwater in the area, but the EPA’s findings can be expected to draw increased attention to potential groundwater impacts from fracking. In late 2011, the DOE Shale Gas Subcommittee recommended further study and coordination of federal, state and local efforts to determine and monitor potential groundwater impacts from fracking activities.

Other federal agencies, including the DOE, the Department of Interior, and the US Congress, are also investigating the potential impacts of fracking. In addition, bills have been introduced in the US. Congress to amend the SWDA to allow the EPA to regulate the injection of fracking fluids, which could require our and similar operations to meet federal permitting and financial assurance requirements, adhere to certain construction and testing specifications, fulfill monitoring, reporting, and recordkeeping obligations, and meet plugging and abandonment requirements. In addition, the federal Bureau of Land Management is developing draft regulations that would require companies drilling on federal land to disclose details of chemical additives, test the integrity of wells and report on water use and waste management. In November 2011, the EPA announced that it would solicit public input on possible reporting requirements for chemicals used in fracking under the authority of the federal Toxic Substances Control Act.

States, which traditionally have been the primary regulators of exploration and production wells, are also considering or have recently adopted, or may in the future adopt, additional regulations governing fracking activities. For example, North Dakota recently adopted regulations, effective April 1, 2012, to require disclosure of the chemical components of hydraulic fracturing fluids. We believe that compliance with any new reporting requirements will not have a material adverse impact on us. Nonetheless, these disclosures could make it easier for third parties who oppose fracking to initiate legal proceedings based on allegations that chemicals used in fracking could contaminate groundwater.

In addition, concerns have been raised about the potential for fracking to cause earthquakes through the disposal of produced waters into Class II underground injection control (“UIC”). The EPA’s current regulatory requirements for such wells do not require the consideration of seismic impacts when issuing permits. Some environmentalists have asked the EPA to consider reversing an exemption that excludes such wastewaters from hazardous waste rules, which would subject the wastes to more stringent management and disposal requirements. We cannot predict the EPA’s future actions in this regard. Certain states, such as Ohio, where earthquakes have been alleged to be linked to fracking activities, have proposed regulations that would require mandatory reviews of seismic data and related testing and monitoring as part of the future permitting process for UIC wells. In addition, certain other states, including New York, New Jersey and Vermont have sought to place moratoria on fracking or subject it to more stringent permitting and well construction and testing requirements. Additionally, several cities in the State of Colorado voted in November 2013 to ban or restrict fracking activities within their city limits.

Research and Development Expenditures

We have not incurred any research and development expenditures over the past two fiscal years.

Employees

As of July 31, 2018, we do not have any employees. Our four officers, Ivan Webb, Noel Schaefer, Victor Miranda and Roger Autrey act as consultants. Mr. Autrey was appointed Secretary on September 19, 2013. Mr. Schaefer was appointed as Chief Operating Officer on July 6, 2018. Mr. Miranda was appointed as Chief Financial Officer on July 6, 2018. Mr. Webb was appointed as Chief Executive Officer on July 6, 2018. Subsequent to the end of the fiscal year Mr. Autrey resigned as the Company secretary and Mr. Robert Campbell was appointed to fill the office as Secretary of the Company. There were no disagreements between the Company and Mr. Autrey.

We engage contractors from time to time to consult with us on specific corporate affairs or to perform specific tasks in connection with our exploration programs.

Subsidiaries

On November 22, 2017, the Company created a wholly owned subsidiary, Kathis Energy LLC (“Kathis”), a duly formed Limited Liability Company formed in the State of Texas, for the purpose of conducting oil and gas drilling programs in Texas.

On December 14, 2017, Kathis Energy, LLC and other Limited Partners, created Kathis Energy Fund 1, LP, a duly formed Limited Partnership formed in the State of Texas, created for the purpose of raising funds from investors for its drilling projects.

On May 7, 2018, the Company created a wholly owned subsidiary, ENMEX Operations LLC (“ENMEX”), a duly formed Limited Liability Company in the State of Quintana Roo, Mexico for the purpose of conducting business in Mexico in prospective real estate development projects.

Intellectual Property

We do not own, either legally or beneficially, any patent or trademark.

ITEM 1A. RISK FACTORS

Risks Related To Our Overall Business Operations

We have a limited operating history with significant losses and expect losses to continue for the foreseeable future.

We have yet to establish any history of profitable operations. As at July 31, 2018, we have an accumulated deficit of $2,392,496 and total stockholders’ deficit of $557,374. We began generating revenues in October 2015. We expect that our revenues will not be sufficient to sustain our operations for the foreseeable future. Our profitability will require our investments in oil and gas properties to become cash flow positive and/or the successful commercialization of our mining properties. We may not be able to successfully obtain a positive cash flow from our oil and gas investments or through commercializing our mining properties or ever become profitable. 

There is doubt about our ability to continue as a going concern due to recurring losses from operations, accumulated deficit and insufficient cash resources to meet our business objectives, all of which means that we may not be able to continue operations.

Our independent auditors have added an explanatory paragraph to their audit opinion issued in connection with the financial statements for the years ended July 31, 2018 and 2017, respectively, with respect to their doubt about our ability to continue as a going concern. As discussed in Note 3 to our financial statements for the year ended July 31, 2018, we have generated operating losses since inception, and our cash resources are insufficient to meet our planned business objectives, which together raises doubt about our ability to continue as a going concern.

We may not be able to conduct successful operations in the future.

The results of our operations will depend, among other things, upon our ability to develop and market our properties. Furthermore, our proposed operations may not generate income sufficient to meet operating expenses or will generate income and capital appreciation, if any, at rates lower than those anticipated or necessary to sustain ourselves. Our operations may be affected by many factors, some known by us, some unknown, and some which are beyond our control. Any of these problems, or a combination thereof, could have a materially adverse effect on our viability as an entity and might cause the investment of our shareholders to be impaired or lost.

To fully develop our business plan, we will need additional financing.

For the foreseeable future, we expect to rely principally upon external financing, although we have raised limited private placement and debt instrument funds during the past fiscal year and will be required to do so in the future. We cannot guarantee the success of this plan. We believe that from time to time, we may have to obtain additional financing in order to conduct our business in a manner consistent with our proposed operations. There can be no guaranty that additional funds will be available when, and if, needed. If we are unable to obtain financing, or if its terms are too costly, we may be forced to curtail proposed expansion of operations until such time as alternative financing may be arranged, which could have a materially adverse impact on our operations and our shareholders’ investment.

We lack working capital.

We currently lack the capital necessary to independently sustain our operations. Management is actively negotiating financing through accredited investors and other sources to meet its short term working capital needs and is negotiating long term capital options. There can be no guaranty that additional funds will be available. If we are unable to obtain financing, or if its terms are too costly, we may be forced to curtail proposed expansion of operations until such time as alternative financing may be arranged, which could have a materially adverse impact on our operations and our shareholders’ investment.

We have limited human resources necessary to expand operations.

We have a small staff of skilled developers and supplement our human resource needs through sub-contracting. We are planning to acquire additional resources internally thereby reducing the use of sub-contractors and increasing direct control over our operations. If we are unable to acquire additional resources internally we will be forced to use sub-contractors that may or may not be available to work when and where we need them thereby limiting our ability to expand operations as we intend.

Our ultimate success will be dependent upon management.

Our success is dependent upon the decision making of our directors and our executive officers, who are Noel Schaefer, Victor Miranda and Ivan Webb. These individuals intend to commit as much time as necessary to our business. The loss of any or all of these individuals could have a materially adverse impact on our operations. We currently do not have not key man life insurance on the lives of any of these officers and directors.

We may not be able to secure additional financing to meet our future capital needs due to changes in general economic conditions.

We anticipate needing significant capital to conduct further exploration and development needed to bring our existing oil and gas and mining properties into production and/or to continue to seek out appropriate joint venture partners or buyers for certain mining properties. We may use capital more rapidly than currently anticipated and incur higher operating expenses than currently expected, and we may be required to depend on external financing to satisfy our operating and capital needs. We may need new or additional financing in the future to conduct our operations or expand our business. Any sustained weakness in the general economic conditions and/or financial markets in the United States or globally could adversely affect our ability to raise capital on favorable terms or at all. From time to time we have relied, and may also rely in the future, on access to financial markets as a source of liquidity to satisfy working capital requirements and for general corporate purposes. We may be unable to secure debt or equity financing on terms acceptable to us, or at all, at the time when we need such funding. If we do raise funds by issuing additional equity or convertible debt securities, the ownership percentages of existing stockholders would be reduced, and the securities that we issue may have rights, preferences or privileges senior to those of the holders of our common stock or may be issued at a discount to the market price of our common stock which would result in dilution to our existing stockholders. If we raise additional funds by issuing debt, we may be subject to debt covenants, which could place limitations on our operations including our ability to declare and pay dividends. Our inability to raise additional funds on a timely basis would make it difficult for us to achieve our business objectives and would have a negative impact on our business, financial condition and results of operations.

Our properties are in the exploration stage. There is no assurance that we can establish the existence of any mineral resource on any of our properties in commercially exploitable quantities. Until we can do so, we can earn very little revenues from operations and if we do not do so we will lose all of the funds that we expend on exploration. If we do not discover any mineral resource in a commercially exploitable quantity, our business could fail.

Despite exploration work on our mineral properties, we have not established that our properties have sufficient mineral reserve to justify a mining operation, and there can be no assurance that we will be able to do so. If we do not, our business could fail.

A mineral reserve is defined by the Securities and Exchange Commission in its Industry Guide 7 (which can be viewed over the Internet at http://www.sec.gov/divisions/corpfin/forms/industry.htm#secguide7) as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. The probability of an individual prospect ever having a “reserve” that meets the requirements of the Securities and Exchange Commission’s Industry Guide 7 is extremely remote; in all probability our mineral resource properties do not contain any ‘reserve’ and any funds that we spend on exploration will probably be lost.

Even if we do eventually discover a mineral reserve on any of our properties, there can be no assurance that we will be able to develop any of our properties into a producing mine and extract those resources. Both mineral exploration and development involve a high degree of risk and few properties which are explored are ultimately developed into producing mines.

The commercial viability of an established mineral deposit will depend on a number of factors including, by way of example, the size, grade and other attributes of the mineral deposit, the proximity of the resource to infrastructure such as a smelter, roads and a point for shipping, government regulation and market prices. Most of these factors will be beyond our control, and any of them could increase costs and make extraction of any identified mineral resource unprofitable.

Mineral operations are subject to applicable law and government regulation. Even if we discover a mineral resource in a commercially exploitable quantity, these laws and regulations could restrict or prohibit the exploitation of that mineral resource. If we cannot exploit any mineral resource that we might discover on any of our properties, our business may fail.

Both mineral exploration and extraction require permits from various foreign, federal, state, provincial and local governmental authorities and are governed by laws and regulations, including those with respect to prospecting, mine development, mineral production, transport, export, taxation, labor standards, occupational health, waste disposal, toxic substances, land use, environmental protection, mine safety and other matters. There can be no assurance that we will be able to obtain or maintain any of the permits required for the continued exploration of our mineral properties or for the construction and operation of a mine on our properties at economically viable costs. If we cannot accomplish these objectives, our business could fail.

We believe that we are in compliance with all material laws and regulations that currently apply to our activities but there can be no assurance that we can continue to remain in compliance. Current laws and regulations could be amended and we might not be able to comply with them, as amended. Further, there can be no assurance that we will be able to obtain or maintain all permits necessary for our future operations, or that we will be able to obtain them on reasonable terms. To the extent such approvals are required and are not obtained, we may be delayed or prohibited from proceeding with planned exploration or development of our mineral properties.

If we establish the existence of a mineral resource on any of our properties in a commercially exploitable quantity, we will require additional capital in order to develop the property into a producing mine. If we cannot raise this additional capital, we will not be able to exploit the resource, and our business could fail.

If we do discover mineral resources in commercially exploitable quantities on any of our properties, we will be required to expend substantial sums of money to establish the extent of the resource, develop processes to extract it and develop extraction and processing facilities and infrastructure. Although we may derive substantial benefits from the discovery of a major deposit, there can be no assurance that any discovered resource will be large enough to justify commercial operations, nor can there be any assurance that we will be able to raise the funds required for development on a timely basis. If we cannot raise the necessary capital or complete the necessary facilities and infrastructure, our business may fail.

Mineral exploration and development is subject to extraordinary operating risks. We do not currently insure against these risks. In the event of a cave-in or similar occurrence, our liability may exceed our resources, which would have an adverse impact on our company.

Mineral exploration, development and production involve many risks which even a combination of experience, knowledge and careful evaluation may not be able to overcome. Our operations will be subject to all the hazards and risks inherent in the exploration for mineral resources and, if we discover a mineral resource in commercially exploitable quantity, our operations could be subject to all of the hazards and risks inherent in the development and production of resources, including liability for pollution, cave-ins or similar hazards against which we cannot insure or against which we may elect not to insure. Any such event could result in work stoppages and damage to property, including damage to the environment. We do not currently maintain any insurance coverage against these operating hazards. The payment of any liabilities that arise from any such occurrence would have a material adverse impact on our company.

Mineral prices are subject to dramatic and unpredictable fluctuations.

We expect to derive revenues, if any, either from the sale of our mineral resource properties or from the extraction and sale of ore. The price of those commodities has fluctuated widely in recent years, and is affected by numerous factors beyond our control, including international, economic and political trends, expectations of inflation, currency exchange fluctuations, interest rates, global or regional consumptive patterns, speculative activities and increased production due to new extraction developments and improved extraction and production methods. The effect of these factors on the price of base and precious metals, and therefore the economic viability of any of our exploration properties and projects, cannot accurately be predicted.

The mining industry is highly competitive and there is no assurance that we will continue to be successful in acquiring mineral claims. If we cannot continue to acquire properties to explore for mineral resources, we may be required to reduce or cease operations.

The mineral exploration, development, and production industry is largely un-integrated. We compete with other exploration companies looking for mineral resource properties. While we compete with other exploration companies in the effort to locate and acquire mineral resource properties, we will not compete with them for the removal or sales of mineral products from our properties if we should eventually discover the presence of them in quantities sufficient to make production economically feasible. Readily available markets exist worldwide for the sale of mineral products. Therefore, we will likely be able to sell any mineral products that we identify and produce.

In identifying and acquiring mineral resource properties, we compete with many companies possessing greater financial resources and technical facilities. This competition could adversely affect our ability to acquire suitable prospects for exploration in the future. Accordingly, there can be no assurance that we will acquire any interest in additional mineral resource properties that might yield reserves or result in commercial mining operations.

Risks Associated With Our Mining Industry

The development and operation of our mining projects involve numerous uncertainties.

Mine development projects, including our planned projects, typically require a number of years and significant expenditures during the development phase before production is possible.

Development projects are subject to the completion of successful feasibility studies, issuance of necessary governmental permits and receipt of adequate financing. The economic feasibility of development projects is based on many factors such as:

Our mine development projects may have limited relevant operating history upon which to base estimates of future operating costs and capital requirements. Estimates of proven and probable reserves and operating costs determined in feasibility studies are based on geologic and engineering analyses.

Any of the following events, among others, could affect the profitability or economic feasibility of a project:

Any of the above referenced events may necessitate significant capital outlays or delays, may materially and adversely affect the economics of a given property, or may cause material changes or delays in our intended exploration, development and production activities. Any of these results could force us to curtail or cease our business operations.

Mineral exploration is highly speculative, involves substantial expenditures, and is frequently non-productive.

Mineral exploration involves a high degree of risk and exploration projects are frequently unsuccessful. Few prospects that are explored end up being ultimately developed into producing mines. To the extent that we continue to be involved in mineral exploration, the long-term success of our operations will be related to the cost and success of our exploration programs. We cannot assure you that our mineral exploration efforts will be successful. The risks associated with mineral exploration include:

Substantial expenditures are required to determine if a project has economically mineable mineralization. It may take several years to establish proven and probable reserves and to develop and construct mining and processing facilities. Because of these uncertainties, our current and future exploration programs may not result in the discovery of reserves, the expansion of our existing reserves or the further development of our mines.

The price of gold and silver are highly volatile and a decrease in the price of gold or silver would have a material adverse effect on our business.

The profitability of mining operations is directly related to the market prices of metals. The market prices of metals fluctuate significantly and are affected by a number of factors beyond our control, including, but not limited to, the rate of inflation, the exchange rate of the dollar to other currencies, interest rates, and global economic and political conditions. Price fluctuations of metals from the time development of a mine is undertaken to the time production can commence can significantly affect the profitability of a mine. Accordingly, we may begin to develop one or more of our mining properties at a time when the price of metals makes such exploration economically feasible and, subsequently, incur losses because the price of metals decreases. Adverse fluctuations of the market prices of metals may force us to curtail or cease our business operations.

Mining risks and insurance could have an adverse effect on our profitability.

Our operations are subject to all of the operating hazards and risks normally incident to exploring for and developing mineral properties, such as unusual or unexpected geological formations, environmental pollution, personal injuries, flooding, cave-ins, changes in technology or mining techniques, periodic interruptions because of inclement weather and industrial accidents. Although maintenance of insurance to ameliorate some of these risks is part of our proposed exploration program associated with those mining properties we have an interest in, such insurance may not be available at economically feasible rates or in the future be adequate to cover the risks and potential liabilities associated with exploring, owning and operating our properties. Either of these events could cause us to curtail or cease our business operations.

We face significant competition in the mineral exploration industry.

We compete with other mining and exploration companies possessing greater financial resources and technical facilities than we do in connection with the acquisition of exploration properties and leases on prospects and properties and in connection with the recruitment and retention of qualified personnel. Such competition may result in our being unable to acquire interests in economically viable gold and silver exploration properties or qualified personnel.

Our applications for exploration permits may be delayed or may be denied in the future.

Exploration activities usually require the granting of permits from various governmental agencies. For exploration drilling on unpatented mineral claims, a drilling plan must be filed with the Bureau of Land Management or the United States Forest Service, which may then take several months or more to grant the requested permit. Depending on the size, location and scope of the exploration program, additional permits may also be required before exploration activities can be undertaken. Prehistoric or Indian grave yards, threatened or endangered species, archeological sites or the possibility thereof, difficult access, excessive dust and important nearby water resources may all result in the need for additional permits before exploration activities can commence. With all permitting processes, there is the risk that unexpected delays and excessive costs may be experienced in obtaining required permits or the refusal to grant required permits may not be granted at all, all of which may cause delays and unanticipated costs in conducting planned exploration activities. Any such delays or unexpected costs in the permitting process could result in serious adverse consequences to the price of our stock and to the value of your investment.

Risks Associated With Our Oil & Gas Industry

A substantial or extended decline in oil and natural gas prices or demand for oil and gas products may adversely affect our business, financial condition, cash flow, liquidity or results of operations and our ability to meet our capital expenditure obligations and financial commitments and to implement our business strategy.

The price we receive for our oil and natural gas production will heavily influence our revenue, profitability, access to capital, and future rate of growth. Recent extremely high prices have affected the demand for oil and gas products, and that demand has declined on a worldwide basis. If the decline in demand continues, the ability to command higher prices for oil and gas products will be endangered. Oil and natural gas are commodities, and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil and natural gas have been volatile. These markets will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, and the revenue we will receive, depend on numerous factors beyond our control. These factors include the following:

Lower oil and natural gas prices may not only decrease our revenues but may also reduce the amount of oil and natural gas that we can produce economically. A substantial or extended decline in oil or natural gas prices is likely to materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

We plan to conduct exploration, exploitation and production operations, which present additional unique operating risks.

There are additional risks associated with oil and gas investment which involve production and well operations and drilling. These risks include, among others, substantial cost overruns and/or unanticipated outcomes that may result in uneconomic projects or wells. Cost overruns could materially reduce the funds available to the Company, and cost overruns are common in the oil and gas industry. Moreover, drilling expense and the risk of mechanical failure can be significantly increased in wells drilled to greater depths and where one is more likely to encounter adverse conditions such as high temperature and pressure.

We may not be able to control operations of the wells we acquire.

We may not be able to acquire the operations for properties that we invest in. As a result, we may have limited ability to exercise influence over the operations for these properties or their associated costs. Our dependence on another operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could prevent the realization of our targeted returns on capital in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others depend upon a number of factors that will be largely outside of our control, including:

We may not be successful in identifying or developing recoverable reserves.

Our future success depends upon our ability to acquire and develop oil and gas reserves that are economically recoverable. Proved reserves will generally decline as reserves are depleted, except to the extent that we can replace those reserves by exploration and development activities or acquisition of properties contain exploration, drilling and recompletion programs or other replacement activities. Our current strategy includes increasing our reserve base through development, exploitation, exploration and acquisition. There can be no assurance that our planned development and exploration projects or acquisition activities will result in significant additional reserves or that we will have continuing success drilling productive wells at economical values in terms of their finding and development costs. Furthermore, while our revenues may increase if oil and gas prices increase significantly, finding costs for additional reserves have increased during the last few years. It is possible that product prices will decline while the Company is in the middle of executing its plans, while costs of drilling remain high. There can be no assurance that we will replace reserves or replace our reserves economically.

Our future oil & gas activities may not be successful.

Oil and gas activities are subject to many risks, including the risk that no commercially productive reservoirs will be encountered. There can be no assurance that new wells drilled by us will be productive or that we will recover all or any portion of our investment. Drilling for oil and gas may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. The cost of drilling, completing and operating wells is often uncertain, and the cost associated with these activities has risen significantly during the past year. Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, many of which are beyond our control, including economic conditions, mechanical problems, title problems, weather conditions, governmental requirements and shortages or delays in the delivery of equipment and services. Our future oil and gas activities may not be successful and, if unsuccessful, such failure may have a material adverse effect on our future results of operations and financial condition.

Our operations are subject to risks associated with drilling or producing and transporting oil and gas.

Our operations are subject to hazards and risks inherent in drilling or producing and transporting oil and gas, such as fires, natural disasters, explosions, encountering formations with abnormal pressures, blowouts, cratering, pipeline ruptures and spills, any of which can result in the loss of hydrocarbons, environmental pollution, personal injury claims and other damage to our properties.

The lack of availability or high cost of drilling rigs, fracture stimulation crews, equipment, supplies, insurance, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.

Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, fracture stimulation crews, equipment, supplies, key infrastructure, insurance or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified crews rise as the number of active rigs and completion fleets in service increases. If increasing levels of exploration and production result in response to strong prices of oil and natural gas, the demand for oilfield services will likely rise, and the costs of these services will likely increase, while the quality of these services may suffer. If the lack of availability or high cost of drilling rigs, equipment, supplies, insurance or qualified personnel were particularly severe in Texas, we could be materially and adversely affected because our operations and properties are concentrated in Texas at the present time.

Compliance with government regulations may require significant expenditures.

Our business is subject to federal, state and local laws and regulations relating to the exploration for, and the development, production and transportation of oil and gas, as well as safety matters. Although we will attempt to conduct due diligence concerning standard compliance issues, there is a heightened risk that our target properties are not in compliance because of lack of funding. We may be required to make significant expenditures to comply with governmental laws and regulations that may have a material adverse effect on our financial condition and results of operations. Even if the properties are in substantial compliance with all applicable laws and regulations, the requirements imposed by such laws and regulations are frequently changed and are subject to interpretation, and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations.

Environmental regulations and costs of remediation could have a material adverse effect on our operations.

Our operations are subject to complex and constantly changing environmental laws and regulations adopted by federal, state and local government authorities. The implementation of new, or the modification of existing, laws or regulations could have a material adverse effect on our operations. The discharge of oil, gas or other pollutants into the air, soil, or water may give rise to significant liabilities on our part to the government and third parties, and may require us to incur substantial costs of remediation. We will be required to consider and negotiate the responsibility of the Company for prior and ongoing environmental liabilities. We may be required to post or assume bonds or other financial guarantees with the parties from whom we purchase properties or with governments to provide financial assurance that we can meet potential remediation costs. There can be no assurance that existing environmental laws or regulations, as currently interpreted or reinterpreted in the future, or future laws or regulations will not materially adversely affect our results of operation and financial condition or that material indemnity claims will not arise against us with respect to properties acquired by us.

Certain United States federal income tax deductions currently available with respect to oil and natural gas exploration and production may be eliminated as a result of future legislation.

Recently, there has been significant discussion among members of Congress regarding potential legislation that, if enacted into law, would eliminate certain key United States federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, among other proposals:

It is unclear whether these or similar changes will be enacted. The passage of this legislation or any similar changes in federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to U.S. oil and natural gas exploration and development. Any such changes could have an adverse effect on our financial position, results of operations and cash flows.

We operate in a highly competitive environment.

We operate in the highly competitive areas of oil and gas exploration, development, acquisition and production with other companies. In seeking to acquire desirable producing properties or new leases for future exploration, and in marketing our oil and gas production, we face intense competition from both major and independent oil and gas companies. If any of these competitors have financial and other resources substantially in excess of those available to us. Our inability to effectively compete in this environment could materially and adversely affect our financial condition and results of operations.

The producing life of oil and gas wells is uncertain, and production will decline.

It is not possible to predict the life and production of any oil and gas wells with accuracy. The actual life could differ significantly from that anticipated. Sufficient oil or natural gas may not be produced for investors to receive a profit or even to recover their initial investments. In addition, production from the Company’s oil and natural gas wells, if any, will decline over time, and current production does not necessarily indicate any consistent level of future production. A production decline may be rapid and irregular when compared to a well’s initial production.

Our lack of diversification will increase the risk of an investment in us, as our financial condition may deteriorate if we fail to diversify.

Larger companies have the ability to manage their risk by diversification. However, we lack diversification, in terms of both the nature and geographic scope of our business. As a result, we will likely be impacted more acutely by factors affecting our industry or the regions in which we operate than we would if our business were more diversified, enhancing our risk profile. If we cannot diversify our operations, our financial condition and results of operations could deteriorate. The Company has a limited number of potential revenue generating properties. These properties historically had revenue derived from the sale of natural gas and oil. Therefore, the price we receive for our oil and natural gas production heavily influences our revenue, profitability, access to capital and future rate of growth.

Our business may suffer if we do not attract and retain talented personnel.

Our success will depend in large measure on the abilities, expertise, judgment, discretion, integrity and good faith of our management and other personnel in conducting our intended business. We presently have a small management team which we intend to expand in conjunction with our planned operations and growth. The loss of a key individual, or our inability to attract suitably qualified staff could materially adversely impact our business.

We may not be able to establish substantial oil operations or manage our growth effectively, which may harm our profitability.

Our strategy envisions establishing and expanding our oil business. If we fail to effectively establish sufficient oil operations and thereafter manage our growth, our financial results could be adversely affected. Growth may place a strain on our management systems and resources. We must continue to refine and expand our business development capabilities, our systems and processes, and our access to financing sources. As we grow, we must continue to hire, train, supervise and manage new employees. We cannot assure you that we will be able to:

If we are unable to manage our growth, our operations and our financial results could be adversely affected by inefficiency, which could diminish our profitability.

Relationships upon which we may rely are subject to change, which may diminish our ability to conduct our operations.

To develop our business, it will be necessary for us to establish business relationships, which may take the form of joint ventures with private parties and contractual arrangements with other unconventional oil companies, including those that supply equipment and other resources that we expect to use in our business. We may not be able to establish these relationships, or if established, we may not be able to maintain them. In addition, the dynamics of our relationships with strategic partners may require us to incur expenses or undertake activities we would not otherwise be inclined to in order to fulfill our obligations to these partners or maintain our relationships. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.

An increase in royalties payable may make our operations unprofitable.

Any development project of our resource assets will be directly affected by the royalty regime applicable. The economic benefit of future capital expenditures for the project is, in many cases, dependent on a satisfactory royalty regime. There can be no assurance that governments will not adopt a new royalty regime that will make capital expenditures uneconomic or that the royalty regime currently in place will remain unchanged.

Hydraulic fracturing, the process used for releasing oil and natural gas from shale rock, has recently come under increased scrutiny and could be the subject of further regulation that could impact the timing and cost of development.

Recently there has been increasing public and regulatory attention focused on the potential environmental impact of hydraulic fracturing (or “fracking”) operations. This process, which involves the injection of water, sand and certain additives deep underground to release natural gas, natural gas liquids and oil deposits, is part of our proposed future operations and future regulation of these activities could have a material adverse impact on our business, financial condition and results of operations.

Various government agencies, political representatives and public interest groups have raised concerns about the potential for fracking to lead to groundwater contamination, and various regulatory and legislative measures have been proposed or adopted at the federal, state and local level to study or monitor related concerns, to regulate well operations and related production and waste streams, or to ban fracking entirely. For example, various states and federal regulatory authorities require or are considering requiring public disclosure of the chemicals contained in fracking fluids, and testing and monitoring obligations relating to well integrity and operation. North Dakota, a state in which we conduct operations, recently amended its current regulations to require additional pollution control equipment at well sites and enhanced emergency response procedures in addition to other measures designed to reduce potential environmental impacts. In 2011, the EPA announced its intention to consider pre-treatment standards for produced waters that are sent to third party wastewater treatment plants.

In addition, bills have been proposed in the US. Congress to allow the EPA to regulate the injection of fracking fluids under the federal Safe Drinking Water Act, which could require hydraulic fracturing operations to meet federal permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting, and record keeping obligations, and meet plugging and abandonment requirements. The proposed legislation also would require the reporting and public disclosure of chemicals used in the fracturing process, which 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 could adversely affect groundwater. In addition, in light of concerns about seismic activity being triggered by the injection of produced waters into underground wells, certain regulators are considering additional requirements related to seismic safety. Other concerns have been raised regarding water usage, air emissions (including greenhouse gas emissions) and waste disposal, and certain jurisdictions have imposed moratoria on fracking operations while the potential impacts are studied. The EPA, Congress and other government representatives continue to investigate the impacts of fracking, and additional studies and regulatory or legislative initiatives are possible.

Depending on the legislation that may ultimately be enacted or the regulations that may be adopted at the federal, and/or state levels, exploration and production activities that entail hydraulic fracturing could be subject to additional regulation and permitting requirements. Individually or collectively, such new legislation or regulation could lead to operational delays or increased operating costs and could result in additional burdens that could increase the costs and delay or curtail the development of conventional and unconventional oil and natural gas resources including development of shale formations which are not commercial without the use of hydraulic fracturing. This could have an adverse effect on our business, financial condition and results of operations.

Exploration for petroleum and gas products is inherently speculative. There can be no assurance that we will ever establish commercial discoveries.

Exploration for economic reserves of oil and gas is subject to a number of risk factors. Few properties that are explored are ultimately developed into producing oil or gas wells. Some of our properties are in the exploration stage only and are without proven reserves of oil and gas. We may not establish commercial discoveries on any of our properties.

There are numerous uncertainties inherent in estimating quantities of conventional and unconventional oil and gas resources, including many factors beyond our control and no assurance can be given that expected levels of resources or recovery of oil and gas will be realized. In general, estimates of recoverable oil and gas resources are based upon a number of factors and assumptions made as of the date on which resource estimates are determined, such as geological and engineering estimates which have inherent uncertainties and the assumed effects of regulation by governmental agencies and estimates of future commodity prices and operating costs, all of which may vary considerably from actual results. All such estimates are, to some degree, uncertain, and classifications of resources are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the recoverable unconventional oil, the classification of such resources based on risk of recovery, prepared by different engineers or by the same engineers at different times, may vary substantially.

Prices and markets for oil and gas are unpredictable and tend to fluctuate significantly, which could reduce profitability, growth and the value of our proposed business.

Our revenues and earnings, if any, will be highly sensitive to the price of oil and gas. Prices for oil and gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty, and a variety of additional factors beyond our control. These factors include, without limitation, weather conditions, the condition of the Canadian, US. and global economies, the actions of the Organization of Petroleum Exporting Countries, governmental regulations, political stability in the Middle East and elsewhere, war, or the threat of war, in oil producing regions, the foreign supply of oil, the price of foreign imports, and the availability of alternate fuel sources. Significant changes in long-term price outlooks for crude oil and natural gas could have a material adverse effect on us. For example, market fluctuations of oil prices may render uneconomic the extraction of oil and gas.

All of these factors are beyond our control and can result in a high degree of price volatility not only in crude oil and natural gas prices, but also fluctuating price differentials between heavy and light grades of crude oil, which can impact prices for our crude oil. Oil and natural gas prices have fluctuated widely in recent years, and we expect continued volatility and uncertainty in crude oil and natural gas prices. A prolonged period of low crude oil and natural gas prices could affect the value of our crude oil and gas properties and the level of spending on growth projects, and could result in curtailment of production on some properties. Accordingly, low crude oil prices in particular could have an adverse impact on our financial condition and liquidity and results of operations.

Existing environmental regulations impose substantial operating costs which could adversely affect our business.

Environmental regulation affects nearly all aspects of our operations. These regulatory regimes are laws of general application that apply to us in the same manner as they apply to other companies and enterprises in the energy industry. Conventional and unconventional oil extraction operations present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of federal, state and county laws and regulations.

Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil operations. The legislation also requires that facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material.

We expect future changes to environmental legislation, including anticipated legislation for air pollution and greenhouse gases that will impose further requirements on companies operating in the energy industry. Changes in environmental regulation could have an adverse effect on us from the standpoint of product demand, product reformulation and quality, methods of production and distribution and costs, and financial results. For example, requirements for cleaner-burning fuels could cause additional costs to be incurred, which may or may not be recoverable in the marketplace. The complexity and breadth of these issues make it extremely difficult to predict their future impact on us. Management anticipates capital expenditures and operating expenses could increase in the future as a result of the implementation of new and increasingly stringent environmental regulations.

Abandonment and reclamation costs are unknown and may be substantial.

Certain environmental regulations govern the abandonment of project properties and reclamation of lands at the end of their economic life, the costs of which may be substantial. A breach of such regulations may result in the issuance of remedial orders, the suspension of approvals, or the imposition of fines and penalties, including an order for cessation of operations at the site until satisfactory remedies are made. It is not possible to estimate with certainty abandonment and reclamation costs since they will be a function of regulatory requirements at the time.

Changes in the granting of governmental approvals could raise our costs and adversely affect our business.

Permits, leases, licenses, and approvals are required from a variety of regulatory authorities at various stages of exploration and development. There can be no assurance that the various government permits, leases, licenses and approvals sought will be granted in respect of our activities or, if granted, will not be cancelled or will be renewed upon expiration. There is no assurance that such permits, leases, licenses, and approvals will not contain terms and provisions which may adversely affect our exploration and development activities.

Amendments to current laws and regulations governing our proposed operations could have a material adverse impact on our proposed business.

Our business will be subject to substantial regulation under state and federal laws relating to the exploration for, and the development, upgrading, marketing, pricing, taxation, and transportation of unconventional oil and related products and other matters. Amendments to current laws and regulations governing operations and activities of conventional and unconventional oil extraction operations could have a material adverse impact on our proposed business. In addition, there can be no assurance that income tax laws, royalty regulations and government incentive programs related to the unconventional oil industry generally will not be changed in a manner which may adversely affect us and cause delays, inability to complete or abandonment of properties.

Risks Related To The Market For Our Stock

Trading of our stock may be restricted by the SEC’s “Penny Stock” regulations, which may limit a stockholder’s ability to buy and sell our stock.

The U.S. Securities and Exchange Commission has adopted regulations which generally define “penny stock” to be any equity security that has a market price (as defined) less than $5.00 per share or an exercise price of less than $5.00 per share, subject to certain exceptions. Our securities are covered by the penny stock rules, which impose additional sales practice requirements on broker-dealers who sell to persons other than established customers and “accredited investors.” The term “accredited investor” refers generally to institutions with assets in excess of $5,000,000 or individuals with a net worth in excess of $1,000,000 or annual income exceeding $200,000 or $300,000 jointly with their spouse. The penny stock rules require a broker-dealer, prior to a transaction in a penny stock not otherwise exempt from the rules, to deliver a standardized risk disclosure document in a form prepared by the SEC, which provides information about penny stocks and the nature and level of risks in the penny stock market. The broker-dealer also must provide the customer with current bid and offer quotations for the penny stock, the compensation of the broker-dealer and its salesperson in the transaction and monthly account statements showing the market value of each penny stock held in the customer’s account. The bid and offer quotations, and the broker-dealer and salesperson compensation information, must be given to the customer orally or in writing prior to effecting the transaction and must be given to the customer in writing before or with the customer’s confirmation. In addition, the penny stock rules require that prior to a transaction in a penny stock not otherwise exempt from these rules, the broker-dealer must make a special written determination that the penny stock is a suitable investment for the purchaser and receive the purchaser’s written agreement to the transaction. These disclosure requirements may have the effect of reducing the level of trading activity in the secondary market for the stock that is subject to these penny stock rules. Consequently, these penny stock rules may affect the ability of broker-dealers to trade our securities. We believe that the penny stock rules discourage investor interest in and limit the marketability of, our common stock.

The Financial Industry Regulatory Authority, or FINRA, has adopted sales practice requirements which may also limit a stockholder’s ability to buy and sell our stock.

In addition to the “penny stock” rules described above, FINRA has adopted rules that require that in recommending an investment to a customer, a broker-dealer must have reasonable grounds for believing that the investment is suitable for that customer. Prior to recommending speculative low priced securities to their non-institutional customers, broker-dealers must make reasonable efforts to obtain information about the customer’s financial status, tax status, investment objectives and other information. Under interpretations of these rules, FINRA believes that there is a high probability that speculative low priced securities will not be suitable for at least some customers FINRA requirements make it more difficult for broker-dealers to recommend that their customers buy our common stock, which may limit our ability to buy and sell our stock and have an adverse effect on the market for our shares.

Trading in our common shares on the OTC is limited and sporadic making it difficult for our shareholders to sell their shares or liquidate their investments.

Our common shares are currently listed for public trading on the OTC under the stock symbol “NMEX”. The trading price of our common shares has been subject to wide fluctuations. Trading prices of our common shares may fluctuate in response to a number of factors, many of which will be beyond our control. The stock market has generally experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of companies with no current business operation. There can be no assurance that trading prices and price earnings ratios previously experienced by our common shares will be matched or maintained. These broad market and industry factors may adversely affect the market price of our common shares, regardless of our operating performance.

In the past, following periods of volatility in the market price of a company’s securities, securities class-action litigation has often been instituted. Such litigation, if instituted, could result in substantial costs for us and a diversion of management’s attention and resources.

We are not likely to pay cash dividends in the foreseeable future.

We intend to retain any future earnings for use in the operation and expansion of our business. We do not expect to pay any cash dividends in the foreseeable future but will review this policy as circumstances dictate. Should we decide in the future to do so, as a holding company, our ability to pay dividends and meet other obligations depends upon the receipt of dividends or other payments from our operating subsidiaries. In addition, our operating subsidiaries, from time to time, may be subject to restrictions on their ability to make distributions to us, including restrictions on the conversion of local currency into U.S. dollars or other hard currency and other regulatory restrictions.

Our stock price may be volatile, and you may not be able to resell your shares at or above your initial purchase price.

There has been, and continues to be, a limited public market for our common stock. Although our common stock trades on the NASD Bulletin Board, an active trading market for our shares has not developed and may never develop or be sustained. If you purchase shares of common stock, you may not be able to resell those shares at or above the initial price you paid. The market price of our common stock may fluctuate significantly in response to numerous factors, some of which are beyond our control.

Most of our common stock is currently restricted. As restrictions on resale end, the market price of our stock could drop significantly if the holders of restricted shares sell them or are perceived by the market as intending to sell them. This could cause the market price of our common stock to drop significantly, even if our business is doing well.

Our common stock has a limited public trading market.

While our common stock currently trades in the Over-the-Counter Bulletin Board market, our market is limited and sporadic. We cannot assure that such a market will improve in the future. We cannot assure that an investor will be able to liquidate the investor’s investment without considerable delay, if at all. If a more active market does develop, the price may be highly volatile. The factors which we have discussed in this document may have a significant impact on the market price of the common stock. The relatively low price of our common stock may keep many brokerage firms from engaging in transactions in our common stock.

The Over-The-Counter Market for our stock has had extreme price and volume fluctuations.

The securities of companies such as ours have historically experienced extreme price and volume fluctuations during certain periods. These broad market fluctuations and other factors, such as new product developments and trends in the our industry and in the investment markets generally, as well as economic conditions and annual variations in our operational results, may have a negative effect on the market price of our common stock.

Risk Related to Real Estate & Resort Development

We have no history of Development of Real Estate Property.

Because we are a company with a limited history, our operations are subject to numerous risks similar to that of a start-up company. We expect the real estate development business to be highly competitive because many developers have access to the same market. Substantially all of them have greater financial resources and longer operating histories than we have and can be expected to compete within the business in which we engage and intend to engage. We cannot assure that we will have the necessary resources to be competitive.

We may not be able to conduct successful operation in the future.

The results of our operations will depend, among other things, upon our ability to develop and market our properties. Furthermore, our proposed operations may not generate income sufficient to meet operating expenses or will generate income and capital appreciation, if any, at rates lower than those anticipated or necessary to sustain ourselves. Our operations may be affected by many factors, some known by us, some unknown, and some which are beyond our control. Any of these problems, or a combination thereof, could have a materially adverse effect on our viability as an entity and might cause the investment of our shareholders to be impaired or lost.

To fully develop our business plan, we will need additional financing.

For the foreseeable future, we expect to rely principally upon external financing, although we have raised limited private placement and debt instrument funds during the past fiscal year and will be required to do so in the future. We cannot guarantee the success of this plan. We believe that from time to time, we may have to obtain additional financing in order to conduct our business in a manner consistent with our proposed operations. There can be no guaranty that additional funds will be available when, and if, needed. If we are unable to obtain financing, or if its terms are too costly, we may be forced to curtail proposed expansion of operations until such time as alternative financing may be arranged, which could have a materially adverse impact on our operations and our shareholders’ investment.

We have limited human resources necessary to expand operations.

We have a small staff of skilled developers and supplement our human resource needs through sub-contracting. We are planning to acquire additional resources internally thereby reducing the use of sub-contractors and increasing direct control over our operations. If we are unable to acquire additional resources internally we will be forced to use sub-contractors that may or may not be available to work when and where we need them thereby limiting our ability to expand operations as we intend.

Our ultimate success will be dependent upon management.

Our success is dependent upon the decision making of our directors and our executive officers, who are Noel Schaefer, Victor Miranda, Howard Siegel and Ivan Webb. These individuals intend to commit as much time as necessary to our business. The loss of any or all of these individuals could have a materially adverse impact on our operations. We currently do not have not key man life insurance on the lives of any of these officers and directors.

We are subject to real estate development risks.

Our development projects are subject to significant risks relating to our ability to complete our projects on time and on budget. Factors that may result in a development project exceeding budget or being prevented from completion include:

If any of these occur, we may not achieve our projected returns on properties under development and we could lose some or all of our investments in those properties.

We are vulnerable to concentration risks because our operations are currently almost exclusive to the Yucatan Peninsula, Mexico area market.

Our real estate activities are currently entirely focused in the Bacalar area on the Yucatan Peninsula of Mexico. Because of our geographic concentration and limited number of projects, our operations are more vulnerable to local economic downturns and adverse project-specific risks than those of larger, more diversified companies. The performance tourism of the Mexico economy specifically as it relates to the Yucatan Peninsula could greatly affect our sales and, consequently the underlying values of our properties.

Our operations are subject to an intensive regulatory approval process.

Before we can develop a property, we must obtain a variety of approvals from local and state governments with respect to such matters as zoning, density, parking, sub-division, site planning and environmental issues. Certain of these approvals are discretionary by nature. Because certain government agencies and special interest groups are involved there is a high degree of uncertainty in obtaining these approvals.

Currency exchange rate fluctuations and higher inflation may adversely impact the Company’s future operating results and financial condition.

The exchange rate between the Mexican Peso and the U.S. dollar has changed substantially in the last two decades and could fluctuate substantially in the future. The Company’s market valuation could be materially adversely affected by any devaluation of the Mexican Peso if U.S. investors analyze the Company’s value and performance based on the U.S. dollar equivalent of the Company’s financial condition and operating results. The Company expects that a substantial portion of its expenses, including personnel costs, may be denominated in Mexican Pesos. As such, any appreciation of the Mexican Peso against the U.S. dollar would reduce the cost advantage derived from the Company’s Mexican Peso-denominated expenses and would likely adversely affect the Company’s financial condition and results of operations. In addition, an increase in inflation would adversely affect world economies generally, which would adversely affect the Company’s business.

ITEM 2. PROPERTIES

Our principal executive offices are located at 1889 FM 2088, Quitman, Texas 75783. Our mailing address is 1889 FM 2088, Quitman, Texas 75783.

As of July 31, 2018, we owned or had a lease on the following properties:

Coleman County, Texas – J. E. Richey Lease – Three Well Project

History & Background:

On October 14, 2014, the Company entered into an agreement to acquire the J. E. Richey lease located west of the Community of Novice in Coleman County, Texas. This lease area has six known productive formations. The existing three wells on the lease are fully equipped. There is spacing available for new drilling of two or more wells. In September 2014 the Company began selling working interest to raise working capital to rework two wells and re-complete one well on the J. E. Richey 206.5 acre. The Company sold 76% of the working interest to fund the rework/re-completion operations.

In May 2015 the Company started conducting operations on reworking the J. E. Richey #1 by conducting a xylene and acid wash to clean the perforations and well bore. The well responded by increasing the casing pressure from 25 pounds to 210 pounds with a strong oil flow. The same procedure was conducted on the J. E. Richey #3 well with the same results. Within a month the #1 well began to make less total fluid with very little oil and the #3 well had plenty of fluid but only a trace of oil. Both the #1 and #3 wells on the J. E. Richey lease were shut-in awaiting further evaluation.

In June the re-completion process began on the Concho Richey #1 also located on the J. E. Richey lease. The re-completion was to open the Gray formation in this well as it had never been tested in this well. Other formations had been tried with nominal success. The first stage of the re-completion process was to squeeze off the Tannehill formation at 1700’ before attempting to perforate the Gray. The squeeze was a success and the Gray formation was perforated yielding 3 barrels of oil on a swab naturally without any stimulation. This was followed by a 300 gallon 7.5% acid job that more than doubled the oil production to 6 barrels with no water. A 50 sack frac was performed yielding 65 barrels of oil and 100 MCF of natural gas per day. The rework/re-completion was completed on all three wells on July 28, 2015 and production of oil and gas was established.

In June 2016 a hole came in the casing on the Concho Richey #1 well. Production ceased until October 2016 when the hole in the casing was repaired. Production resumed at the rate of 8 barrels of oil and 40 MCF of natural gas per day. As of the date of this report the Concho Richey #1 well is averaging 4.5 barrels of oil and 34 MCF of natural gas per day with little to no formation water.

Two attempts were made to rework the J. E. Richey #1 well subsequent to the effort made in May 2015. During March and April of 2017 an effort to re-perforate the Gray formation with a TriStem Perforating Gun, a specialized tool, that perforate three holes in a wedge or pie shape in an effort to increase exposure to the well bore the flow into the well bore. After several attempts the TriStem tool would not go below 1100 feet deep. The area to be perforate is 3900 feet in the Gray. A temperature survey was ran and determined the well had a hole in the casing. This procedure was followed by conducting a multiple interval pressure pumping test from the top of the perforations in the Gray to the surface. The casing held pressure until we came up the hole to 970 feet and continued not to hold pressure in each pressure test to the surface. No further work was conducted until August 2017 providing time to meet with engineers to determine what procedure or method could be performed to salvage the well. After numerous meetings and discussions with local operators, petroleum engineers and service companies it was determined that the chances of success to save the well was very poor. A decision was made to plug the well. On January 3, 2018 the J. E. Richey #1 well was plugged.

Plans are to rework the J. E. Richey #3 well by placing a bridge plug over the Gray and produce the Morris for 60 – 90 days to see the daily average of total production of gas, oil and formation water. Depending on the amount of formation water a sand frac will be designed to stimulate the Morris in an effort to increase oil and gas production. The J. E. Richey #3 well was originally perforated in the Morris with an initial rate of 2,075 MCF per day and has produced more than 250 million cubic feet of natural gas. A previous operator attempted to produce the Gray by perforating it and letting it produce naturally. The xylene/acid wash conducted on this well in May 2015 is likely to have opened up the Gray and allowed it to produce most of the formation water as the Morris was not noted for making much formation water when it was produced independently. No date has been set for to conduct this rework procedure on the J. E. Richey #3 well.

The Company acquired a 206.5 acre lease (J. E. Richey) located in the northern part of Coleman County, Texas with four existing wells in September 2014. Three of the four wells were fully equipped with down hole pumps, rods, tubing, pump jacks, well head and surface equipment including tank battery, meter run and gas gathering pipelines.

The Concho Richey #1 became the primary producer on this lease following the re-completion in the Gray Formation (“Gray”). The Concho Richey #1 is located due west 660’ from the Olympia Hale #1 well that has produced more than 71,000 BBLS and over 190 MMCFG from the Gray since 1986 (approximately 30 years). In July 2015 the Company re-completed this well in the Gray Sand. The Gray Sand formation (3,860’) is a clean sand with section having 34% porosity with good permeability. This well came in with an initial production rate of 65 barrels of oil and 100 MCF of gas per day. It was averaging about 14 barrels of oil and 75 MCF of gas per day with about 10 barrels of saltwater before a hole came in the casing in June 2016. During the fiscal year we were able to successfully conduct a cement squeeze to seal off the casing leak. The well was brought back into production and is averaging 7 barrels of oil, 40 MCF of gas and ½ barrel of saltwater per day.

During March 2017 the Company attempted to bring the J.E. Richey #1 back into production. A hole was discovered in the casing around 600 feet. Additional work was performed on the well in August 2018. Pressure testing proved the casing from 900 feet to the surface was not repairable and was plugged on January 3, 2018.

Additional work is planned to be conducted on the J.E. Richey # 3 well with a view to produce the Morris for 60 – 90 days to determine if an additional stimulation is warranted to improve its production. No dates have been set at the time of this report to conduct this work program on the J.E. Richey #3 well.

Location and Access

The location of the 206.5 acre J.E Richey Lease is approximately 3.5 miles west of the community of Novice, Texas located in the central part of Coleman County which is south approximately 45 miles of the city of Abilene, Texas. Access to the lease is excellent with good access to county roads and lease roads. The terrain is rolling hills with no abnormal location or access problems.

Ownership Interest

The Company owns 11.5% of the working interest before payout and 24% working interest after payout in these three wells covering 60 acres and 87.5% working interest in rest of lease covering 146.5 acres.

History of Operations and Geology

The lease is located in a multiple pay area originally discovered by ARCO in the early 1980’s. This lease area has six known productive formations, which are stated below with their approximate depths:

The following is a summary of each of the three wells originally drilled by ARCO and the fourth well drilled by J.V. Rhyne, a local operator in the Abilene, Texas area:

J.E. Richey #1 Well – was completed in the Gray Sand in 1981 and came in with an initial production rate of 167 barrels and 118 MCF per day with no saltwater from the Gray Sand formation. The well is only open in the Gray and has the Upper Capps formation up the hole for future testing. As stated above the casing was not repairable and this well was plugged due to casing problems in the well on January 3, 2018.

J.E. Richey #2 Well – initially was completed in the Lower Ellenburger in 1982 coming in at 19 barrels per day. Following depletion of the Lower Ellenburger the well was re-completed in the Upper Ellenburger with an initial production rate of 2,535 MCF per day. Subsequently the well was re-completed in the Gray Sand, which came in at 45 barrels per day on a light acid job. The well only produced for a limited amount of time from the Gray Sand when a hole came in the casing above the cement at 1100 feet caused by a corrosive formation known as the Coleman Junction and the well was shut in. This well was plugged due to casing problems in the well on December 28, 2017.

J.E. Richey #3 Well – was completed in the Morris in 1982, which had an initial production rate of 2,075 MCF per day. This well has been shut in since 2010. The well is only open in the Morris with potential to open up the Gray Sand. The Upper Capps formation is also present up the hole to test. This well is currently shut in awaiting additional work to be performed.

Concho Richey #1 Well – was initially completed in the Ellenburger coming in at 1,200 MCF per day in 2005. The Ellenburger came in strong but quickly began to produce saltwater within a few months of production. In 2006 a re-completion attempt was made up the hole in the Tannehill formation (1700 Feet), where an oil show was recorded in the mud logs, in hopes of making a field discovery. Due to a poor cement bond the re-completion was not successful in the Tannehill. The well was shut in awaiting further reworking and/or re-completion in 2006. During the fiscal year ended July 31, 2015 the Company re-completed this well in the Gray formation and made a commercial producing well.

Coleman County, Texas – J. E. Richey #2A -Proposed New Well:

The Company has sold working interest in a 20 acre tract on the J.E. Richey Lease to drill a new well near the ARCO Richey #2 well. This well initially was completed in the Lower Ellenburger in 1982 coming in at 19 barrels per day. Following depletion of the Lower Ellenburger the well was re-completed in the Upper Ellenburger with an initial production rate of 2,535 MCF per day. Subsequently the well was re-completed in the Gray Sand, which came in at 45 barrels per day on a light acid job and no sand frac was conducted. The well only produced for a limited amount of time from the Gray Sand when a hole came in the casing above the cement at 1100 feet caused by a corrosive formation known as the Coleman Junction and the well was shut in. This well was plugged due to casing problems in the well on December 28, 2017.

A drilling location has been staked west of the J. E. Richey #2 well. Drilling funds have been received toward the drilling of the new proposed location for the J. E. Richey #2A well. At the time of this report no definitive schedule for drilling has been set. Additional drilling funds will be required to be able to drill this well to a projected total depth of 4,500’. All potential formations will be evaluated with particular attention being focused on the following formations:

Jones County, Texas – Palo Pinto Reef Project:

Location & Access:

The 160 acre lease known as the Olson is located approximately 6 miles southeast of the city of Stamford, Texas that basically sits on the county line of Jones and Haskell counties, on the north side of Jones County, Texas. Of particular importance is the location of the Olson Lease lies approximately 1.5 miles southeast of the Strand Oil Field, a Palo Pinto Reef Oil Field. Access to the lease is excellent with good access to county roads and lease roads. The terrain is rolling hills with no abnormal location or access problems.

The Olson Lease is in an area geographically known as the Eastern Shelf of the Permian Basin. It is influenced by the Bend Arch to the East and the South as it approaches the Llano Uplift. This area is best known for the several producing formations that are stratigraphically and structurally used as trapping oil and gas.

The principal target formation for the Olson Lease is the Palo Pinto Reef. The Palo Pinto Reef is a known productive formation with a high yield of cumulative oil production. The Strand Oil Field is a Palo Pinto Reef Oil Field, discovered in 1940, that consists of only 8 wells that has produced a total of 1,700,000 barrels of oil, an average of 212,500 barrels of oil per oil well.

Ownership Interest

During the fiscal year the Company acquired 100% of the working interest in the oil and gas lease known as the Olson covering approximately 160 acres for $30,000 including legal, landman, lease bonus, geological mapping etc. The Company has agreed to convey the Olson lease to Kathis, its wholly owned subsidiary, for its drilling program for $60,000. The term of the Olson lease expires on April 27, 2019

History of Operations and Geology

The Olson Lease is focused on the Palo Pinto formation as it is a primary target for drilling. The structure of the Palo Pinto shows a large buildup in the Palo Pinto Reef across the southern portion of the lease. The Guinn #1 Olson well is 90’ high to a well 1000’ to the southeast and 42’ high to a well 1,150’ to the northwest. The Guinn well had a show and a tremendous buildup in the Palo Pinto Reef (at approximately 3,350’). The structural buildup and reef buildup across the acreage and close similarities to the Strand Field make this a very good prospect.

The oil wells in the Strand Oil Field lie in a northwest to southeast direction which is the same layout of the contours mapped on top of the Palo Pinto Reef covering the Olson Lease. As previously stated the Strand Oil Field was discovered in 1940 making it not uncommon for a number of dry holes to be drilled looking for the structural development of the Palo Pinto Reef.

The following is a brief geological description of the Palo Pinto Reef:

The Palo Pinto Reef is a Limestone Formation that was formed during the Carboniferous period, which was during the end of the Paleozoic Era and at the beginning of the Devonian Era. Typical Palo Pinto Reef wells are known for their high rate of production and quick payout. A known Palo Pinto Reef Field in this area is the Strand Oil Field which has produced over 1.7 million barrels of oil from 8 wells and is located approximately 1.5 miles from the Olson lease. A new well is proposed to be drilled on the Olson lease to test the Palo Pinto Reef.

Shackelford County, Texas – Guy Ranch Project:

History & Background:

During the fiscal year ended July 31, 2016 the Company acquired a 100% working interest in a 692-acre Guy Ranch Lease divided into two tracts. Tract 1 covers 480 acres and Tract 2 covers 212 acres. The Ranch has 32 wind turbines on it representing it is at a structurally higher elevation. The principal targets for this drilling prospect is the Patio (aka Palo Pinto Sand) and Morris Sands the area is also know to be productive from three other formations on the Guy Ranch acreage.

The first project on the Guy Ranch was to re-complete a cased well in the Morris formation that was reportedly untested. The structure of the deal was for a third party to pay 100% of the costs re-complete the cased well in the Morris formation allocating 20 acres out of the 450 acres in order to earn a 75% working interest in the cased well. All records filed with the Texas Railroad Commission supported that no attempt to produce from the Morris had been performed. However, it was subsequently found out that in fact an attempt was made to re-complete in Morris formation and such attempt was unsuccessful due to an over stimulation of the Morris with a large frac at high pumping rate. The well produced mostly water. The 20 acres around the well was not assumed by the Company or its third-party investors. The unused funds provided by the third party will be allocated to a new well on the Guy Ranch Lease with the third party being responsible for providing the balance of the funds to drill and complete a new well in order to earn 75% of the working interest.

During the fiscal year ended July 31, 2018 the Company agreed to convey approximately 650 acres out of the Guy Ranch lease to Kathis Energy LLC, its wholly owned subsidiary, for its drilling program for the consideration of $66,500.

In March 2018 Kathis Energy staked two drilling locations on the Guy Ranch and prepared one drilling location. This drilling location is a direct offset to a Patio Sand well that came in at 140 barrels per day. The Patio Sand is one of the main producing formations in the area generally averages between 25,000 and 75,000 barrels oil per well. The Morris Sand a notable gas producer is known to produce up to 1.4 BCF gas from one well and the Gardner is noted in this area to produce between 50,000 and 110,000 barrels per well. The Net Revenue Interest for the Guy Ranch lease is 75%. Lease expires in December 16, 2018 unless well is commences drilling prior to that date or an extension can be obtained.

Ownership Interest:

During the fiscal year the Company acquired 100% of the working interest in the oil and gas lease known as the Guy Ranch covering approximately 692 acres for approximately $70,500 including legal, landman, lease bonus, geological mapping etc.

Location & Access:

The 692 acre Guy Ranch Lease is located approximately 15 miles northeast of the city of Abilene, Texas. Access to acreage is excellent with paved county roads and gravel lease roads to the well. The lease has access to gas lines and electric power.

History of Operations and Geology:

The Guy Ranch lease is in an area geographically known as the Eastern Shelf of the Permian Basin. It is influenced by the Bend Arch to the East and the South as it approaches the Llano Uplift. This area is best known for the several producing formations that are stratigraphically and structurally used as trapping oil and gas.

The Guy Ranch comprises a total of 5,120 acres of which the Company’s 692 acres is included. The Guy Ranch has had many wells drilled on it throughout the years. The Ranch has 32 wind turbines on it representing it is at a structurally higher elevation. Because of all the earlier drilled wells it is easy to see that most of the production is located on the many surface structural noses that occur on the ranch. The Patio/Morris prospect is located on such a structural nose.

There are five principal productive formation targets on the Guy Ranch Lease acreage. These formations are from shallow to deep as follows:

Flippen Sand: The first formation of interest is the Flippen Sand at 1600 feet. It is one of the most prolific producers in the immediate area. The Three Aces Field two miles south has produced 3,000,000 barrels of oil form approximately 30 wells. The Morrisett Field to the southwest has produced 750,000 barrels of oil from 10 wells. The A.V. Jones #1 Damewood well has the Flippen Sand present with approximately 6 feet of hydrocarbons present. Jim Webster, geologist believes that the structure is on the surface anomaly to the north-northwest of this well. The surface anomaly to the west would also be potential for a Flippen Sand field.

Cook Sand: The Cook Sand formation is at 1,750 feet and is believed to be underlying the surface anomaly to the east. Production from the Cook Sand is located on both the north and south ends of the feature. It is believed that the entire structure is carrying hydrocarbons and could be filled in with up to another 20 wells.

Patio Sand: The Patio Sand (also known as the Palo Pinto Sand) is at approximately 3100 feet. The Patio Sand is the main producer to the west (next section) and generally averages between 25,000 and 75,000 barrels oil per well. The A T & H Oil Company #2 Davis well (north offset) was perforated in the Patio Sand (3158-61’) and flowed 140 BOPD. This well produced 27,371 barrels oil and 60 MMCF gas before the Railroad Commission of Texas had it plugged for having to many violations. This well was still producing 12 barrels oil per day when plugged.

Morris Sand: The Morris is a Sandstone Formation of the Strawn Group of the Desmoinesian Series of the Pennsylvanian System. The Morris Formation in the 89Guy #1 well is more than 30-foot-thick having 15% porosity in the upper part of the formation with good permeability at 3,420’. The Morris Formation has similar characteristics to the Davis Estate #2 well which reported gas from the Morris when tested in July 1985. However, the operator elected to come up the hole to the Patio Sand where he made an oil well that came in with an initial potential of 140 barrels of oil and never produced the Morris.

The Morris Sand is gas in most wells and produces up to 1.4 BCF gas per well. The following are a few notable Morris Formation wells near the Guy Ranch Lease:

Gardner Sand: The Gardner Sand has not been drilled as much because of the success of the shallower production can make up to 200,000 barrels oil per well.

The A T & L Oil Company #2-A Davis well (south well 1,750’ from #2 Davis well) was perforated in the Gardner sand (3926-28’) and came in at 3.289 MMCFGPD and produced 125.473 MMCF gas from the Gardner sand.

Runnels County, Texas – Riverside Prospects – Multiple Pay Project

History & Background:

On October 20, 2017 the Company entered into an exclusive option agreement with Murphree Oil Company to acquire drilling prospects on four leases in Runnels County near the City of Ballinger, known as the Riverside Prospects. During the quarter ended April 30, 2018, the Company, through its wholly owned subsidiary, Kathis Energy LLC, (“Kathis”) paid the lease bonuses for extending the oil and gas lease period on 548.76 acres covering the Riverside Prospects. This acreage consists of 4 leases in a well established area where oil and gas production was discovered during 1978 – 1983.

Location & Access:

The location of the leases covering the Riverside Prospects is approximately 2 miles west of the City of Ballinger, Texas in Runnels County.

Ownership Interest:

Kathis has an option to acquire these leases in stages with the first stage to have proof of drilling funds to drill one well by December 31, 2018. The Net Revenue Interest on all of these leases is 75% and the expiration of these leases varies from April thru June 2019.

History of Operations & Geology:

Oil and gas field discoveries were made on the Riverside leases during the oil boom of 1978 thru 1983. The original discovery wells in these fields were drilled on 40 acre spacing and were never fully developed as crude oil prices fell sharply before the fields could be fully developed and remained undeveloped.

Significant discoveries were made in the Cross Cut formation with cumulative production in excess of 45,000 barrels. The Caddo formation had some wells with cumulative production of 56,000 barrels and the Gardner formation with some wells with 70,000 barrels of oil produced from single wells. Other notable formations in and on these leases include the Jennings and Fry.

89 Guy #4 Well – Cased Hole:

History & Background:

The 89 Guy Well #4 is located on the Guy Ranch property in Shackelford County. The well is an abandoned cased well that was drilled in October 2010 and completed in the Patio Sand at the interval of 3,144’ - 3,154’. This interval produced 2 barrels of oil and 20 thousand cubic feet of natural gas from a 100 sac gel frac. The interval perforated (3,144 – 3,154’) is above the best productive part of the formation. The cased well was purchased from the mineral owner through an independent geologist followed by an application to the Texas Railroad Commission to assume liability of the case well. The application is still pending approval.

Ownership Interest:

Kathis Energy owns 100% of the working interest with a 75% net revenue interest in the 20 acre lease with the cased well. Kathis has until April 17, 2019 to bring the well back into production. Kathis paid $22,500 for the cased well.

Location & Access:

The 20-acre tract on the Guy Ranch Lease is located approximately 15 miles northeast of the city of Abilene, Texas. Access to the 89 Guy Well #4 is excellent with paved county roads and gravel lease roads to the well. The lease has access to gas lines and electric power.

History of Operations & Geology:

The Guy Ranch lease is in an area geographically known as the Eastern Shelf of the Permian Basin. It is influenced by the Bend Arch to the East and the South as it approaches the Llano Uplift. This area is best known for the several producing formations that are stratigraphically and structurally used as trapping oil and gas.

The Guy Ranch comprises a total of 5,120 acres of which the Company’s 20 acre tract is included. The Guy Ranch has had many wells drilled on it throughout the years. The Ranch has 32 wind turbines on it representing it is at a structurally higher elevation. Because of all the earlier drilled wells it is easy to see that most of the production is located on the many surface structural noses that occur on the ranch.

Patio Sand: The Patio Sand (also known as the Palo Pinto Sand) is at approximately 3100 feet. The Patio Sand is the main producer to the west (next section) and generally averages between 25,000 and 75,000 barrels oil per well. The A T & H Oil Company #2 Davis well (north offset) was perforated in the Patio Sand (3158-61’) and flowed 140 BOPD. This well produced 27,371 barrels oil and 60 MMCF gas before the Railroad Commission of Texas had it plugged for having to many violations. This well was still producing 12 barrels oil per day when plugged.

McClure 2B Gas Well – Producing:

History & Background:

On February 6, 2018 the Company acquired the McClure # 2B producing gas well on a 40 -acre oil & gas lease located in Palo Pinto County near the Community of Graford, Texas. The McClure 2B well was drilled in 2006 to a total depth of 4,739’ and was re-completed in the Strawn formation in January 2011. The McClure 2B gas well is among a large number of gas wells that are producing in the area from the Strawn formation.

Location & Access:

The location of the McClure 2B gas well is 1 mile southwest of the Community of Graford, Texas in Palo Pinto County on a 40 acre tract. The lease is off a main county road and the lease road can have washouts depending on the amount of rain as the McClure 2B gas well is on top of a hill. There are two natural gas lines 1) high pressure and the 2) is low pressure.

Ownership Interest

The Company paid $25,000 for this gas well. The Net Revenue Interest for the McClure lease is 75% and the lease is held by existing production. The Company entered into an agreement with a third party to acquire and rework/re-complete the well in one or more of the other intervals in the Strawn formation in the well. As of the date of this report no work has been conducted toward the reworking/re-completing in this well. Upon the third party recovering its investment the Company will receive 40% of the Net Revenue Interest.

History of Operations & Geology:

The McClure 2B well was drilled to a total depth of 4,739’ in July 2006 into the Marble Falls formation. No production was made from this formation. In January 2011, the McClure 2B well was completed in the Strawn in the interval 2,882’ to 2,940’ and has produced in excess of 70 million cubic feet of natural gas. The McClure 2B well is a flowing gas well and is currently producing approximately 8 - 10MCF per day with little to no saltwater. The 2,882’ - 2,940’ interval was stimulated with 1,450 gallons of NEFE 10% acid and a 350 sac frac. The well responded with an initial production rate of 815 MCF per day on a 24/64ths choke with an Instant Shut In Pressure of 995 pounds.

The Strawn formation is more than 400 foot thick in the McClure 2B well and has 7 other intervals that can be perforated and stimulated to produce additional natural gas.

Carter & Foster Wells – Producing:

History and Background:

The wells on the Carter and Foster leases were drilled in1992-93. Most of the wells were treated with 5,000 gallons of 21% acid and yielded initial rates of production of 40 barrels of oil per day then gradually declined to 3 barrels per day by the end of the first year. The wells now are 25 plus years old and are producing 90% or better oil cut in the fluid being produced. the production is very nominal at the present time however no secondary acid stimulation has been conducted since they were originally brought into production in the early 1990’s. All four wells on the Carter and Foster leases are fully equipped and have their own production facilities and have electricity to each of the wells.

The Carter #1 well as of the date of this report has a down-hole pump problem and is awaiting to be pulled and replace the down-hole pump. The wells on the Foster lease are pumping. These wells are marginal producing oil wells producing approximately 20 barrels per month with little to no formation water. The objective is to conduct a large multiple stage acid job on three of the four wells to significantly enhance daily production rates.

Location & Access:

The Carter and Foster wells are located west of the Community of Atwell, Texas in Callahan County. The Carter lease consists of 40 acres and has one well. The Foster lease has 10 acres around each well of the three wells, all of which are fully equipped with surface and subsurface equipment. The Carter and Foster have good access to an all weather county road and the lease roads provide good access to each well.

Ownership Interest:

The Net Revenue Interest for the Carter lease is 75% and the lease is held by existing production. The Net Revenue Interest for the Foster lease is 60% and the lease is held by existing production. The Company entered into an agreement with a third party to acquire and rework Palo Pinto formation by conducting the multiple staged acid jobs on three wells. During the year the Company has placed new electric motors on all four wells, changed out the down hole pumps and placed the wells into production. As of the date of this report the Company has not conduced the multiple staged acid job on any of the three wells. Upon the third party recovering its investment the Company will receive 40% of the Net Revenue Interest. The Carter and Foster leases/wells were acquired from an Officer of the Company for total consideration of $1.00.

History of Operations & Geology:

All four wells are completed in the Palo Pinto Limestone formation at approximately 1,900 feet. The Palo Pinto formation is of the Pennsylvanian Period of the Paleozoic Era. The Palo Pinto is a well known limestone marker throughout several counties around Abilene, Texas. The Palo Pinto covering the Carter and Foster leases is saturated with oil with porosity of 3-6 percent with limited permeability. The Palo Pinto is a proven producer with the following characteristics:

The Palo Pinto formation covering the Carter and Foster leases is a clean section with low water saturation making it an excellent formation for acid stimulation.

Reeves Lease – Acreage – Palo Pinto Reef Prospect:

In August 2018, subsequent to the end of the fiscal year ended July 31, 2018, the Company paid for the geological prospecting fees for a Palo Pinto Reef prospect in Jones County. The Reeves lease covers 160 acres and is located near Noodle, Texas in Jones County. The projected depth of the Palo Pinto Reef is 4,300’. Excellent well control by 6 Strawn wells provides evidence of a Palo Pinto Reef showing a structure 48’ high to other wells. The nearest Palo Pinto Reef well to the Reeves Lease made more than 150,000 barrels from one well.

The lease bonus money of $28,000 was provided by a third party for a two year lease and the Company paid the geological prospect fee of $10,000. It was verbally understood between the Company and third party to promote this drilling prospect seeking to retain a carried interest plus recoup the lease and prospect monies.

The Net Revenue of the lease is 80%. The lease term is 2 years. Plans are to deliver a 75% net revenue lease to a drilling partner retaining an overriding royalty and a carried working interest in the drilling in the well.

Index of Oil & Gas Abbreviations

INDEX

Winnemucca Mountain Property:

On September 14, 2012, our company entered into an option agreement (as amended and restated on November 15, 2012, February 1, 2013, August 26, 2013 and July 30, 2014) with AHL Holdings Ltd., a Nevada corporation, and Golden Sands Exploration Inc., a company incorporated under the laws of British Columbia, Canada, wherein the company acquired an option to purchase a revised 80%, in and to certain mining claims from AHL Holdings and Golden Sands, which claims form the Winnemucca Mountain Properties in Humboldt County, Nevada. The Winnemucca Mountain Property is currently comprised of 138 unpatented mining claims covering an area of approximately 2,700 acres. As consideration our company is required to make cash and share payments and complete work expenditures. As part of the joint venture, we are solely responsible for financing and will act as the sole operator in consideration of a fee.

AHL Holdings and Golden Sands will also retain a 3% net smelter royalty in the event that we initiate mineral production on the Winnemucca Mountain Property.

Effective July 30, 2014, we entered into amended and restated option agreement with AHL Holdings and Golden Sands that materially modifies and replaces the terms of the original option agreement (as amended last on August 26, 2013).

Location and Access

The Winnemucca Mountain Property is located in north-western Nevada, approximately 4 miles northwest of the municipality of Winnemucca. The property is within the Winnemucca Mountain Mining District of Humboldt County. The claims are situated on the west flank of Winnemucca Mountain. A map showing the location of and access to the Winnemucca Mountain Property is attached below.

The Winnemucca Mountain Property is accessible from State Route 49, a graded gravel road from Winnemucca to Jungo. The claims that comprise the Winnemucca Mountain Property lie in an irregular, northerly trending block along the western flanks of Winnemucca Mountain. The mountain slopes are generally moderate along the west side of the claims, steepening on the east and in drainages. Pediment and alluvium cover is extensive, particularly in the western, or lower, part of the property where a classic bajada is developed. Within the claims, elevations range from approximately 4,700 feet in the southwest corner to nearly 6,600 feet in the east. The area is devoid of trees, and vegetation consists of sagebrush and sparse grass. The climate in southern Humboldt County is arid with annual rainfall averaging 8 inches and snowfall of 16 inches. The area is characterized by hot summers and short, cold winters.

Ownership Interest

On September 14, 2012, our company entered into an option agreement (as amended and restated on November 15, 2012, February 1, 2013 and August 26, 2013) with AHL Holdings Ltd., a Nevada corporation, and Golden Sands Exploration Inc., a company incorporated under the laws of British Columbia, Canada, wherein we acquired an option to purchase a revised 80% interest in and to certain mining claims from AHL Holdings and Golden Sands, which claims form the Winnemucca Mountain Property in Humboldt County, Nevada. This Winnemucca Mountain property is currently comprised of 138 unpatented mining claims covering an area of approximately 2,700 acres. As consideration to earn an 80% interest, the company is required to make cash and share payments and complete work expenditures.

If the option is exercised, the amended and restated option agreement provides that AHL Holdings and Golden Sands will enter into a joint venture agreement. Our company will solely be responsible for financing the joint venture and will act as sole operator in consideration of a fee.

AHL Holdings and Golden Sands will also retain a 3% net smelter royalty in the event that we begin mineral production on the Winnemucca Mountain Property. If we are unable to fulfill any of the commitments set out above, the option agreement will terminate and all property rights will revert back to AHL Holdings and Golden Sands.

The aggregate cash fee payable to exercise the option has been increased from $1,715,000 to $1,755,000 and the total number of common shares issuable to exercise the option has been increased from 100,000 to 2,100,000. Lastly, the amended and restated agreement provides that AHL Holdings may elect to receive shares of our common stock in lieu of any cash payments payable pursuant to the agreement at a 75% discount to the then current closing market price.

Effective July 30, 2014, we entered into amended and restated option agreement with AHL Holdings and Golden Sands that materially modifies and replaces the terms of the original option agreement (as amended last on August 26, 2013). Pursuant to this amended and restated agreement, our remaining outstanding obligations are as follows:

As of July 31, 2018 we have paid $142,500 in option payments, issued 1,350,000 common shares, paid an advance royalty payment of $20,000, and advanced $21,028 for exploration expenditures as required by the amended and restated agreement.

On May 30, 2017 the Company was given notice of default by the optionors whereby the Company lost the right to earn an interest in the Winnemucca Mountain property. We are currently in discussions with the optionors to potentially enter into a new agreement on the property. Although we are in such discussions, there are no assurances that acceptable terms can be reached with the optionors, AHL Holdings Ltd and Golden Sands Exploration Inc.

Due to the notice of default the Company determined this property to be fully impaired. As a result of writing off the asset and liability associated with this property the Company recognized a $345,157 loss on impairment.

As part of the Company’s outstanding obligations under the Option Agreement, the Company conducted a geophysical survey on the Winnemucca Property in January 2018 at a cost of $35,100.

On July 23, 2018, the Company entered into a New Option Agreement with AHL Holding Ltd & Golden Sands Exploration Inc. (“Optionors”). This agreement provided for the payment of $25,000 and the issuance of 3,000,000 shares of the Company’s common stock. The Company issued the shares and made the payment of $25,000 per the agreement on July 31, 2018. The second payment of $25,000 per the terms of the agreement was to be paid when it was due on August 31, 2018. The Company is in default of the terms of the July 23, 2018 agreement. The Company at the time of this filing is hopeful to seek a mutual agreement and or settlement with the Optionors to proceed forward with the Winnemucca Property.

History of Operations

The discovery of the Comstock Lode in western Nevada in 1859 spurred mineral exploration throughout Nevada. Gold and silver were first discovered in the Winnemucca Mining District in 1863 and, during the 1860’s, several smelters were constructed along the Humboldt River. The early productive lodes consisted of quartz veins containing small amounts of variably oxidized copper and lead.

The first significant gold discovery in Humboldt County was the Getchell gold deposit in 1933. The Getchell Mine began production in 1938 and has operated intermittently since. The current owners are Barrick and Newmont. The mine was reopened in 2002 with a resource of 7 million ounces of gold. Since discovery of the Getchell Deposit, Humboldt County has been the site of numerous other significant gold discoveries. Major gold deposits in the area include the Lone Tree, Marigold, Preble, Pinson, Turquoise Ridge, and Twin Creeks, all located east and northeast of Winnemucca, and the Hycroft (Crowfoot-Lewis), Sandman, Rosebud, and Sleeper deposits to the northwest.

On Winnemucca Mountain itself, the Adamson mine, located in the northeast portion of section 11, reported gold production from “rich ore” in 1911-1912 totaling $13,711 (approximately 20 kg of gold equivalent; Willden, 1964). The Pride of the Mountain mine, which reported gold and silver production during 1915, is situated just east of the Golden West claims in the northwestern portion of section 23. Both mines exploited gold-bearing quartz veins cutting metasedimentary rocks. Topographic maps indicate six ‘prospects’ and one old ‘mine’ within the boundaries of the Golden West 8 and 10 claims. These may be mercury workings referred to by Schnell & Hodges.

The upper slopes of Winnemucca Mountain contain dozens of prospects and several old mines. One of these, the Shively Mine on the north side of Winnemucca Mountain, exploited a west-northwest striking, moderate to steeply dipping quartz-calcite vein. In 1982, St. Joe conducted a drilling program directed at this structure. Results of their drilling included 90 feet of 0.34 g/t Au in DH1 and 30 feet of 0.69 g/t Au in DH2.

The earliest available record of exploration within the present Winnemucca Mountain property claim area is an undated map by St. Joe American Corporation that describes rock sampling over much of the claim block and soil sampling across the Golden West 6 to 13 claim area. This work was most likely done in conjunction with work in the Shively Mine area during 1982. The same map indicates that Cordilleran Exploration (Cordex) drilled seven drill holes, also on the Golden West 6 to 13 claims. However, an undated compilation map by Santa Fe places these Cordex drill holes (holes WV1 – 7, WV11 and WV16 – 18) over 4,900 feet to the east of the Golden West claims. The true location of these holes is therefore uncertain and should not be relied upon. Metzler reports that the Cordex holes were drilled in 1972; in addition, 700 feet of trenching was completed and over 3,300 feet of existing underground workings were mapped and sampled and the construction of drill access roads were completed. A map dated October 1982 indicates that induced polarization, magnetic, and VLF electromagnetic surveys were performed on the property. Details of work done by St. Joe and Cordex are not available.

The next record of exploration is by Arctic Precious Metals Inc. in 1985. Work over the next few years included rock sampling by Arctic and Tenneco Minerals in 1986, with geological mapping by Arctic in 1986 in the northern claim area. During 1987, Arctic drilled 1,916 feet in 5 reverse circulation drill holes. Results were encouraging with hole WM 5 intersecting a 5 feet interval of 1,050 ppb gold. The next year, Arctic conducted detailed rock sampling and VLF-EM and magnetic surveys over a breccia pipe target area, followed by 7 diamond drill holes for a total of 2,100 feet. Drill hole WM 7 intersected up to 1,950 ppb gold over 5 feet and WM 13 cut two large intervals (145 feet and 181 feet) of elevated gold in a breccia (164 ppb and 147 ppb respectively; SFPM data).

In late 1988, Santa Fe Pacific Mining, Inc. (now Newmont) entered into a joint venture with Arctic after recognizing the significance of anomalous gold in the breccia pipe identified by the Arctic drilling. Santa Fe became operator and, between 1988 and 1990, conducted geological mapping, rock sampling, trenching, CSAMT and induced polarization geophysical surveys, collected 286 auger hole bedrock samples, and completed a total of 52,470.8 feet in 73 reverse circulation drill holes. Three of these drill holes were re-entered with a diamond drill. The total diamond drill footage is uncertain but is in excess of 477 feet. Not all of Santa Fe’s drilling was within the boundaries of the current claim block. Santa Fe’s work outlined the Swordfish occurrence that extends approximately 2,200 feet along the western flank of Winnemucca Mountain within the current claim block.

In 1994, Anvil Resources of Vancouver, B.C., acquired the property and became the project operator. Anvil did a great deal of internal compilation work, prepared a topographic base map and collected surface samples to confirm previous gold tenors. They performed test assaying to determine optimum analytical procedures for coarse gold samples and milling tests on bulk samples to maximize gold liberation. An induced polarization (IP) survey conducted in 1996 confirmed that resistivity highs correlated well with known mineralized areas and delineated two new target zones.

In 2006-2007 Meridian Minerals Corp. acquired an option on the property from Evolving Gold Corp. Meridian conducted two separate drilling programs on the property. Twelve angled holes were drilled, totaling 7473 feet. In 2007 four additional angled holes were subsequently drilled totaling 2,659 feet. This drilling, targeted northwest and northeast striking veins to the northeast of the Swordfish Zone, and a further 3 holes targeted a vein system in the very north of the Property This drilling intersected lower grade mineralization than the moderate to high grade intercepts in the Swordfish Zone.

Santa Fe Pacific Gold Corp. utilized a computer program called Geostat to calculate a cross-sectional resource estimate for the Swordfish zone area. Santa Fe estimated that the Swordfish zone contained 4.15 million metric tons grading 0.82 g/t gold (4.58 million short tons grading 0.028 opt gold) at a 0.29 g/t cutoff (0.01 opt cutoff). All resource calculations were based on arithmetic averages. This estimated resource occurs in an area 2,200 feet long and 700 feet deep.

In March 2013 the Company contracted consultants to study the mineralization and known resources on the Winnemucca Mountain Property. Company consultants completed mapping and geochemical sampling of the 3000 feet long Swordfish zone on the Property. Using this surface work along with historical drill results, 3D modeling of the gold/silver mineralization was completed. Based on the results of the initial work, Company consultants have recommended further exploration on the property including geophysics, core and reverse circulation (RC) drilling.

Geology

Regional Geology – Nevada lies within the Basin and Range geological province. The geologic structure of this province is the result of repeated interactions between the North American Plate and oceanic plates to the west which are expressed as folds, thrust faults, strike slip faults, normal faults, igneous intrusions, volcanism, metamorphism and sedimentary basins. Every mountain range in the Basin and Range province is bounded on at least one side by a normal fault, many of which are still active. The area’s highly complex and active tectonic history has created a diversity of depositional environments, deep-seated structures, hydrothermal centers and numerous mineral deposits.

Humboldt County is underlain by rocks ranging in age from probable early Cambrian to late Miocene or early Pliocene. In general, the oldest rocks are in the southeastern portion of the county with younger rocks to the north and west, however, late Tertiary volcanic and sedimentary rocks are randomly distributed throughout the county. Five orogenic episodes have been recognized but structural and lithologic elements are not continuous between mountain ranges. The most important of the orogenic episodes in Nevada is the Antler Orogeny, the late Devonian collision of an arc terrane complex with the western margin of North America. The arc material (allochthon) was thrust over cratonic carbonates along the Roberts Mountain thrust fault. Mountain building accompanied the Antler Orogeny, resulting in a high mountain range to the west. In addition to the folding and low-angle faulting associated with orogenic compression and mountain building, high-angle reverse and strike-slip faulting were widespread, forming important wrench fault systems. These high-angle faults were crucial in localizing the fluid flow responsible for gold deposition.

Mineral deposits have been found in all rock units exposed in the county. At least three periods of epigenetic ore mineral deposition have been recognized. The oldest are the iron deposits in the Jackson Mountains. Contact metamorphic tungsten and vein deposits belong to the second period, developed in conjunction with the emplacement of Cretaceous and Tertiary intrusive rocks. The third, late Tertiary, depositional episode includes mercury, uranium and gold-silver deposits, including the Getchell and Sleeper gold deposits. Most Tertiary mineral deposits in northern Nevada are distributed linearly as a result of deep crustal controls including the Carlin and Battle Mountain trends.

Current gold producers in Humboldt County include the Getchell, Hycroft, Marigold, Lone Tree, and Twin Creeks mines.

Property Geology- The general geology of Winnemucca Mountain is shown on two publicly available maps. The oldest unit exposed on Winnemucca Mountain is the Upper Triassic Winnemucca Formation that underlies the upper elevations. These rocks are gray to brown calcareous shale; buff and gray, thin-bedded to massive carbonate rocks, buff to light brownish-gray calcareous sandstone, gray and brown shale and slate and some light brown feldspathic quartzite.

A younger, unnamed quartzite-mudstone formation is faulted against the Winnemucca Formation on the northwest side of Winnemucca Mountain by a normal fault of uncertain displacement. This unit consists of light brown or buff, thin to thick bedded, fine-grained, feldspathic quartzite which usually weathers dark brown; buff to light brown, medium bedded mudstone; and small amounts of light brown phyllitic shale.

The sedimentary rocks are cut by several small intrusive bodies. The largest is a Jurassic-Cretaceous stock which intrudes Winnemucca Formation rocks on the southern side of Winnemucca Mountain, measuring approximately 6,600 by 9,075 feet. The intrusive contains no quartz but, in general, contains more plagioclase than mafic minerals so is compositionally a diorite. A small body of Tertiary volcanic rocks has been identified on the west side of Winnemucca Mountain.

Tertiary basalt and andesite unconformably overlie the older units on the north side of the mountain. These also include more silicic volcanic and sedimentary rocks.

An east-northeast trending breccia body measuring 1,320 by 5,000 feet in Triassic sedimentary rocks was mapped on the west side of Winnemucca Mountain. The diatreme, containing gold mineralization now known as the Swordfish zone, is described by Metzler (1994) as an ellipsoid plug of brecciated, silicic dacite and rhyolite with sharp contacts. The breccia contains angular clasts of the older siltstone and granodiorite and is considered to be a Tertiary diatreme.

Three directions of major faulting are apparent, each of which appear confined to a particular area of Winnemucca Mountain. In the northern portion of the mountain are three parallel northeast trending faults, situated approximately 2,800 feet apart. Movement on these faults is primarily dip-slip although some minor strike-slip movement was also noted. On the southern flank of the mountain are two parallel north-northeast trending faults 5,000 feet apart. Northerly and northeasterly oriented faults dominate the central part of Winnemucca Mountain. Santa Fe geologists believed that the topography of Winnemucca Mountain was in part controlled by extensional range-front faults and the dominant structural trend, especially with respect to mineralizing events, is northeast.

Present Conditions and Plan of Exploration

Though there is a significant amount of historical exploration on the Winnemucca Mountain Property, none of the previous owners have established any substantial operations on the property. Further, the data set from past exploration is not complete. In March 2013 the Company contracted consultants to study the mineralization and known resources on the Winnemucca Mountain Property. Company consultants completed mapping and geochemical sampling of the 3,000 feet long Swordfish zone on the Property. Using this surface work along with available historical drill results data, 3D modeling of the gold/silver mineralization was completed. Based on the results of the initial work, Company consultants have recommended further exploration on the property including geophysics, core and reverse circulation (RC) drilling. Subject to available funds the Company plans further exploration of the property as recommended by the company consultants.

ITEM 3. LEGAL PROCEEDINGS

We know of no material, existing or pending legal proceedings against us, nor are we involved as a plaintiff in any material proceeding or pending litigation. There are no proceedings in which any of our directors, officers or affiliates, or any registered or beneficial shareholder, is an adverse party or has a material interest adverse to our company.

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

Our shares are quoted on the Over-the-Counter (“OTC”) under the symbol “NMEX”. The OTC is a regulated quotation service that displays real-time quotes, last sale prices and volume information in over-the counter securities. To be eligible for quotations on the OTC issuers must remain current in their filings with the SEC or applicable regulatory authority. Securities quoted on the OTC that become delinquent in their required filings will be removed following a grace period, if they do not make their required filing in that time. We cannot guarantee that we will continue to have the funds required to remain in compliance with our reporting obligations. There has been no active trading of our securities and therefore no high and low bid pricing.

The following table sets forth, for the quarterly periods indicated, the range of high and low bid prices of our common stock as reported on the OTC since our stock became actively traded. These quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not necessarily represent actual transactions.

DIVIDENDS

There are no restrictions in our articles of incorporation or bylaws that prevent us from declaring dividends. The Nevada Revised Statutes, however, do prohibit us from declaring dividends where, after giving effect to the distribution of the dividend:

On July 15, 2009, we effected a forward split of our common stock, by way of a dividend pursuant to which each shareholder of record on June 29, 2009 received ten shares of our post-split common stock in exchange for each share of pre-split common stock.

On August 13, 2013, we effected a reverse split of our common stock on a 10 old for 1 new basis, such that our issued and outstanding shares of common stock decreased from 50,444,842 shares of common stock (at July 12, 2013) to 5,044,484 shares of common stock with a par value of $0.001.

Any decisions regarding dividends will be made by our board of directors. We currently intend to retain and use any future earnings for the development and expansion of our business and do not anticipate paying any cash dividends in the foreseeable future. Our board of directors has complete discretion on whether to pay dividends, subject to the approval of our stockholders. Even if our board of directors decides to pay dividends, the form, frequency and amount will depend upon our future operations and earnings, capital requirements and surplus, general financial condition, contractual restrictions and other factors that the board of directors may deem relevant.

HOLDERS

As of November 12, 2018, there were approximately 60 shareholders of record of our common stock. This number does not include shares held by brokerage clearing houses depositories or others in unregistered form.

SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

As of November 12, 2018, we do not have in effect any compensation plans under which our equity securities are authorized for issuance and we do not have any outstanding stock options.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Private Placement of Units

On August 5, 2016, the Company issued 670,000 shares of common stock at $0.025 per share as a portion of the consideration to acquire an oil and gas lease known as the Guy Ranch (Note 4).

On January 24, 2017, the Company sold 300,000 shares of common stock along with warrants to purchase an additional 150,000 shares for total proceeds of $5,000. The warrants are exercisable at $0.10 and expire February 1, 2019.

On August 28, 2017, the Company sold 5,000,000 shares of common stock to an accredited investor for $50,000.

On August 29, 2017, the Company sold 5,000,000 shares of common stock to an accredited investor for $50,000.

On October 27, 2017, the Company sold 500,000 shares of common stock along with warrants to purchase an additional 250,000 shares for total proceeds of $25,000 to an accredited investor. The warrants are exercisable at $0.15 and expire December 1, 2019.

On November 14, 2017, the Company sold 800,000 shares of common stock along with warrants to purchase an additional 400,000 shares for total proceeds of $40,000 to an accredited investor. The warrants are exercisable at $0.15 and expire December 1, 2019.

On November 17, 2017, the Company sold 200,000 shares of common stock along with warrants to purchase an additional 100,000 shares for total proceeds of $10,000 to an accredited investor. The warrants are exercisable at $0.15 and expire December 1, 2019.

On November 27, 2017, the Company sold 1,800,000 shares of common stock to an accredited investor for $18,000.

On December 4, 2017, the Company sold 800,000 shares of common stock along with warrants to purchase an additional 400,000 shares for total proceeds of $40,000 to an accredited investor. The warrants are exercisable at $0.15 and expire December 1, 2019.

On December 30, 2017, the Company sold 600,000 shares of common stock to an accredited investor for $15,000.

On December 31, 2017, the Company sold 859,000 shares of common stock to an accredited investor for $21,475.

On February 14, 2018, the Company sold 130,000 shares of common stock along with warrants to purchase an additional 65,000 shares for total proceeds of $6,500 to an accredited investor. The warrants are exercisable at $0.15 and expire March 1, 2020.

On February 21, 2018, the Company sold 200,000 shares of common stock along with warrants to purchase an additional 100,000 shares for total proceeds of $10,000 to an accredited investor. The warrants are exercisable at $0.15 and expire May 1, 2020.

On April 19, 2018, the Company sold 300,000 shares of common stock along for total proceeds of $15,000 to an accredited investor.

On April 25, 2018, the Company sold 100,000 shares of common stock along with warrants to purchase an additional 50,000 shares for total proceeds of $5,000 to an accredited investor. The warrants are exercisable at $0.15 and expire May 1, 2020.

On July 31, 2018, the Company sold 1,000,000 shares of common stock along with warrants to purchase an additional 500,000 shares for total proceeds of $50,000 to an accredited investor. The warrants are exercisable at $0.15 and expire August 1, 2020. As of July 31, 2018, the stock has not yet been issued by the transfer agent.

Other than as disclosed above, we did not sell any equity securities which were not registered under the Securities Act during the year ended July 31, 2018 that were not otherwise disclosed on our quarterly reports on Form 10-Q or our current reports on Form 8-K filed during the year ended July 31, 2018.

ISSUER REPURCHASES OF EQUITY SECURITIES

None

STOCK OPTION GRANTS

To date, we have not granted any stock options.

REPORTS TO SECURITY HOLDERS

We intend to furnish our shareholders with annual reports containing financial statements audited by our independent auditors and to make available quarterly reports containing unaudited financial statements for each of the first three quarters of each year.

The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549.  The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.  The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC.  The address of that site is www.sec.gov.

ITEM 6. SELECTED FINANCIAL DATA

As a “smaller reporting company”, we are not required to provide the information required by this Item.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Results of Operations for the Years Ended July 31, 2018 and 2017

The following summary of our results of operations should be read in conjunction with our financial statements for the year ended July 31, 2018, which are included herein.

Revenue

Revenues of oil and gas for the years ended July 31, 2018 and 2017 were $59,444 and $53,685, respectively. Revenues are earned from the J.E. Richey Lease both in selling oil and gas and from funds received for reworking the Concho Richey #1. We began earning revenues in Q1 of 2015 from the J.E. Richey Lease. Revenues resumed from the sale of oil and gas during the second quarter of the 2016/17 fiscal year.

Distributions

During the year ended July 31, 2018, we had distribution expense of $60,390 compared to $47,294 for the year ended July 31, 2017. Distributions are paid or accrued in the quarter in which the revenue for those distributions is earned. Distributions are paid to the joint venture partners in the J.E. Richey Lease. We began paying distributions in Q1 of 2017 from the oil and gas revenues received from the J.E. Richey Lease.

Mineral property expenditures

Mineral property expenditures were $269,703 and $43,227 for the years ended July 31, 2018 and 2017, respectively. Expenditures include lease payments for the working interest in the mineral properties and rework expense.

Officer compensation

Officer compensation was $56,500 and $32,250 for the years ended July 31, 2018 and 2017, respectively, an increase of $24,250, or 75.1%. The increase is due to higher compensation for our CEO.

Director services

Director services was $0 and $2,000 for the years ended July 31, 2018 and 2017, respectively, a decrease of $2,000. Fees are paid to our directors but are billed as consulting fees.

Consulting expense

Consulting fees were $117,500, including $26,500 paid to our directors for consulting services, and $0 for the years ended July 31, 2018 and 2017, respectively, an increase of $117,500. Over the past fiscal year the Company has used its director to provide consulting services and hired other experts in the mining and gas industries to assist with its current projects.

Professional fees

Professional fees were $57,050 and $0 for the years ended July 31, 2018 and 2017, respectively, an increase of $57,050. Professional fees generally consist of legal, audit and accounting expense.

Advertising and promotion

Advertising and promotion expense were $123,352 and $0 for the years ended July 31, 2018 and 2017, respectively, an increase of $123,352. Advertising and promotion expense has increased with the increased availability of funds to use to promote the company’s current mining activities.

Property expenditures

Property expenditures were $289,969 and $43,227 for the years ended July 31, 2018 and 2017, respectively, an increase of $246,742. Property expenditures has increased as the Company has increased its efforts to get existing properties up and running and invest in new ones.

General and administrative

General and administrative expense was $105,415 and $57,338 for the year ended July 31, 2018 and 2017, respectively, an increase of $48,077, or 83.8%. The increase can be attributed to an increase in daily operating activities.

Other expense

During the year ended July 31, 2018 we had total other expense of $19,044 compared to $491,811 in the prior year. During the current year we incurred interest expense of $17,164, and a loss on conversion of debt $6,000, offset with a gain on forgiveness of debt of $4,120. In the year ended July 31, 2017, we incurred interest expense of $27,138, had a gain on forgiveness of debt of $2,796 and had a loss on impairment of mineral rights of $467,469. This loss is from the decision not to proceed with two projects, 1) Shallow Oil Project in Callahan County, Texas and 2) the Mississippi Reef Play also in Callahan County, Texas. See Note 4 to the financial statements.

Net Loss

For the year ended July 31, 2017, we had a net loss of $769,776 as compared to a net loss of $620,235 for year ended July 31, 2017. Our net loss was higher in the current period due to our increased operating expenses as discussed above.

Liquidity and Financial Condition

Operating Activities

Cash used by operating activities was $323,875 for the year ended July 31, 2018. Cash used for operating activities was $3,417 for the year ended July 31, 2017.

Investing Activities

We used $45,250 for investing activities for the year ended July 31, 2017 compared to net cash used of $6,000 used in year ended July 31, 2017.

Financing Activities

Cash provided by financing activities consisted of $355,975 from the sale of common stock and $65,000 from other cash advances for the year ended July 31, 2018 compared to $5,000 in the year ended July 31, 2017, from the sale of common stock.

We will require additional funds to fund our budgeted expenses over the next twelve months. These funds may be raised through equity financing, debt financing, or other sources, which may result in further dilution in the equity ownership of our shares. There is still no assurance that we will be able to maintain operations at a level sufficient for an investor to obtain a return on his investment in our common stock. Further, we may continue to be unprofitable. We need to raise additional funds in the immediate future in order to proceed with our budgeted expenses.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to stockholders.

Critical Accounting Policies

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.  Note 2 to the Financial Statements describes the significant accounting policies and methods used in the preparation of the Financial Statements. Estimates are used for, but not limited to, contingencies and taxes.  Actual results could differ materially from those estimates. The following critical accounting policies are impacted significantly by judgments, assumptions, and estimates used in the preparation of the Financial Statements.

We are subject to various loss contingencies arising in the ordinary course of business.  We consider the likelihood of loss or impairment of an asset or the incurrence of a liability, as well as our ability to reasonably estimate the amount of loss in determining loss contingencies.  An estimated loss contingency is accrued when management concludes that it is probable that an asset has been impaired, or a liability has been incurred and the amount of the loss can be reasonably estimated.  We regularly evaluate current information available to us to determine whether such accruals should be adjusted.

We recognize deferred tax assets (future tax benefits) and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities.  The deferred tax assets and liabilities represent the expected future tax return consequences of those differences, which are expected to be either deductible or taxable when the assets and liabilities are recovered or settled.  Future tax benefits have been fully offset by a 100% valuation allowance as management is unable to determine that it is more likely than not that this deferred tax asset will be realized.

The Company follows ASC 605-10-S99-1, Revenue Recognition, of the FASB Accounting Standards Codification for revenue recognition, which has four basic criteria that must be met before revenue is recognized: 1) existence of persuasive evidence that an arrangement exists; 2) delivery has occurred or services have been rendered; 3) the seller’s price to the buyer is fixed and determinable; and 4) collection is reasonably assured.

Property consists of mineral rights purchases as stipulated by underlying agreements and payments made for oil and gas exploration rights. Our company assesses the impairment of long-lived assets whenever events or changes in circumstances indicate that the carrying value may not be recoverable. When we determine that the carrying value of long-lived assets may not be recoverable based upon the existence of one or more indicators of impairment and the carrying value of the asset cannot be recovered from projected undiscounted cash flows, we record an impairment charge. Our company measures any impairment based on a projected discounted cash flow method using a discount rate determined by management to be commensurate with the risk inherent in the current business model. Significant management judgment is required in determining whether an indicator of impairment exists and in projecting cash flows.

Mineral property acquisition and exploration costs are expensed as incurred until such time as economic reserves are quantified. Cost of lease, exploration, carrying and retaining unproven mineral lease properties are expensed as incurred. We have chosen to expense all mineral exploration costs as incurred given that it is still in the exploration stage. Once our company has identified proven and probable reserves in its investigation of its properties and upon development of a plan for operating a mine, it would enter the development stage and capitalize future costs until production is established. When a property reaches the production stage, the related capitalized costs will be amortized over the estimated life of the probable-proven reserves. When our company has capitalized mineral properties, these properties will be periodically assessed for impairment of value and any diminution in value.

The Company applies the successful efforts method of accounting for oil and gas properties. The Company capitalizes asset acquisition costs of mineral rights and leases. Unproved oil and gas properties are periodically assessed to determine whether they have been impaired, and any impairment in value is charged to expense. The costs of proved properties will be depleted on an equivalent unit-of-production basis in which total proved reserves will be the base used to calculate depletion.

Recently Issued accounting pronouncements

Topic 606, Revenue from Contracts with Customers, of the Financial Accounting Standards Board’s (FASB) Accounting Standards Codification (ASC). The guidance in ASC 606 was originally issued by the FASB in May 2014 in Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606). Since then, the FASB has issued several ASUs that have revised or clarified the guidance in ASC 606.

On June 20, 2018, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2018-07, Compensation—Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting. ASU 2018-07 is intended to reduce cost and complexity and to improve financial reporting for share-based payments to nonemployees (for example, service providers, external legal counsel, suppliers, etc.). Under the new standard, companies will no longer be required to value non-employee awards differently from employee awards. Meaning that companies will value all equity classified awards at their grant-date under ASC718 and forgo revaluing the award after this date. The Company has chosen to early adopt this standard.

In January 2017, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) 2017-01, Business Combinations (Topic 805) Clarifying the Definition of a Business. The amendments in this update clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. The guidance is effective for interim and annual periods beginning after December 15, 2017 and should be applied prospectively on or after the effective date. The Company is in the process of evaluating the impact of this accounting standard update.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). ASU 2016-02 requires lessees to recognize lease assets and lease liabilities on the balance sheet and requires expanded disclosures about leasing arrangements. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and interim periods in fiscal years beginning after December 15, 2018, with early adoption permitted. The Company has evaluated the impact of this accounting standard update and noted that it has had no material impact.

The Company has implemented all new accounting pronouncements that are in effect. These pronouncements did not have any material impact on the financial statements unless otherwise disclosed, and the Company does not believe that there are any other new accounting pronouncements that have been issued that might have a material impact on its financial position or results of operations.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Smaller reporting companies are not required to provide the information required by this Item.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

NORTHERN MINERALS & EXPLORATION LTD.

CONSOLIDATED FINANCIAL STATEMENTS

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of Northern Minerals & Exploration Ltd.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Northern Minerals & Exploration Ltd. (“the Company”) as of July 31, 2018 and 2017, and the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for the years then ended, and the related notes (collectively referred to as the financial statements). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of July 31, 2018 and 2017, and the results of its operations and its cash flows for each of the years in the two-year period ended July 31, 2018, in conformity with accounting principles generally accepted in the United States of America.

Consideration of the Company’s Ability to Continue as a Going Concern

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 3 to the financial statements, the Company has an accumulated deficit and intends to fund operations through equity financing which may be insufficient to fund its capital expenditures. These factors raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 3. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

NORTHERN MINERALS & EXPLORATION LTD.

CONSOLIDATED BALANCE SHEETS

The accompanying notes are an integral part of these consolidated financial statements.

NORTHERN MINERALS & EXPLORATION LTD.

CONSOLIDATED STATEMENTS OF OPERATIONS

The accompanying notes are an integral part of these consolidated financial statements.

NORTHERN MINERALS & EXPLORATION LTD.

CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY

FOR THE YEAR ENDED JULY 31, 2018 AND 2017

The accompanying notes are an integral part of these consolidated financial statements.

NORTHERN MINERALS & EXPLORATION LTD.

CONSOLIDATED STATEMENTS OF CASH FLOWS

The accompanying notes are an integral part of these consolidated financial statements.

Northern Minerals & Exploration Ltd.

Notes to Consolidated Financial Statements

July 31, 2018

NOTE 1 - ORGANIZATION AND BUSINESS OPERATIONS

Northern Minerals & Exploration Ltd. (the “Company”) is an emerging natural resource company operating in oil and gas production in central Texas and exploration for gold and silver in northern Nevada.

The Company was incorporated in Nevada on December 11, 2006 under the name Punchline Entertainment, Inc. On August 22, 2012, the Company’s board of directors approved an agreement and plan of merger to effect a name change of the Company from Punchline Entertainment, Inc. to Punchline Resources Ltd. On July 12, 2013, the stockholders approved an amendment to change the name of the Company from Punchline Resources Ltd. to Northern Mineral & Exploration Ltd. FINRA approved the name change on August 13, 2013.

On November 22, 2017, the Company created a wholly owned subsidiary, Kathis Energy LLC (“Kathis”) for the purpose of conducting oil and gas drilling programs in Texas.

On December 14, 2017, Kathis Energy, LLC and other Limited Partners, created Kathis Energy Fund 1, LP, a limited partnership created for raising investor funds.

On May 7, 2018, the Company created ENMEX LLC, a wholly owned subsidiary in Mexico, for the purposes of managing and operating its investments in Mexico including but not limited to the Joint Venture opportunity being negotiated with Pemer Bacalar on the 61 acres on the Bacalar Lagoon on the Yucatan Peninsula. There was no activity from inception to date.

The Company is working on the following projects:

ENMEX Operations LLC – Wholly owned Subsidiary - Pemer Bacalar – Resort Development Project

During the quarter ended October 31, 2017, the Company entered into a Letter of Intent with Pemer Bacalar SAPI DE CV on September 22, 2017 to examine the opportunity of acquiring ownership in approximately 61 acres (“Property”) on a freshwater lagoon near the community of Bacalar, Mexico in the state of Quintana Roo for the purpose of entering into a joint venture for the potential development of the Property into a resort. On November 16, 2017, subsequent to the end of the quarter, the Company entered into a Memorandum of Understanding (“MOU”) in order to further conduct due diligence toward this potential project. An amended MOU was entered into on April 13, 2018 setting forth the conditions for entering into a definitive agreement with Pemer Bacalar.

Coleman County, Texas – Three well rework/re-completion project

On October 14, 2014, we entered into an agreement to acquire the 206.5 acre J.E. Richey oil and gas lease. This lease area has six known productive formations. The existing three wells on the lease are fully equipped. Beginning in May 2015 we started conducting operations on the three wells to place them back into production. The rework/re-completion was completed on July 28, 2015 and production of oil and gas was established. Additional work was conducted on J. E. Richey lease during the fiscal year ended July 31, 2018.

Coleman County, Texas – J. E. Richey #2A -Proposed New Well:

The Company has sold working interest in a 20 acre tract on the J.E. Richey Lease to drill a new well near the ARCO Richey #2 well. This well initially was completed in the Lower Ellenburger in 1982 coming in at 19 barrels per day. Following depletion of the Lower Ellenburger the well was re-completed in the Upper Ellenburger with an initial production rate of 2,535 MCF per day. Subsequently the well was re-completed in the Gray Sand, which came in at 45 barrels per day on a light acid job and no sand frac was conducted. The well only produced for a limited amount of time from the Gray Sand when a hole came in the casing above the cement at 1100 feet caused by a corrosive formation known as the Coleman Junction and the well was shut in. This well was plugged due to casing problems in the well on December 28, 2017. See Item 2 Properties for additional information.

Kathis Energy LLC – Wholly owned Subsidiary:

The Company created a wholly owned subsidiary, Kathis Energy LLC (“Kathis”), on November 22, 2017 for the purpose of conducting oil and gas drilling programs in Texas. The Company agreed to assign to Kathis the Olson and Guy Ranch leases in exchange for $126,500.

Jones County, Texas – Palo Pinto Reef project

During the fiscal year ended July 31, 2016 the Company acquired the Olson lease covering 160 acres in Jones County, Texas. This lease is 1.5 miles from the Strand Palo Pinto Reef Field which was discovered in 1940 and has produced 1,700,000 barrels of oil from 8 wells or 212,500 barrels of oil per well. The structure map on the Palo Pinto shows a large buildup in the Palo Pinto Reef across the southern portion of the lease.

Shackelford County, Texas – Guy Ranch Project:

During the fiscal year ended July 31, 2016 the Company acquired 692-acres divided into two tracts Guy Ranch Lease in Shackelford County. The Guy Ranch lease is located in the southern part of Shackelford County. The Ranch has 32 wind turbines on it representing it is at a structurally higher elevation. The principal targets for this drilling prospect is the Patio (aka Palo Pinto Sand) and Morris Sands the area is also know to be productive from three other formations on the Guy Ranch acreage.

Riverside Prospects, Runnels County, Texas

On October 20, 2017 the Company entered into an exclusive option agreement with Murphree Oil Company to acquire drilling prospects on four leases in Runnels County near the City of Ballinger, known as the Riverside Prospects. During the quarter ended April 30, 2018, the Company, through its wholly owned subsidiary, Kathis Energy LLC, (“Kathis”) paid the lease bonuses for extending the oil and gas lease period on 548.76 acres covering the Riverside Prospects. This acreage consists of 4 leases in a well established area where oil and gas production was discovered during 1978 – 1983.

89 Guy #4 Well – Cased Hole:

On April 16, 2018, Kathis Energy acquired the 89 Guy Well #4 located on a 20-acre tract on the Guy Ranch property in Shackelford County, Texas. The well is an abandoned cased well that was drilled in October 2010 and completed in the Patio Sand at the interval of 3,144’ - 3,154’. The interval perforated (3,144 – 3,154’) is above the best productive part of the formation.

McClure 2B Gas Well – Producing:

On February 6, 2018 the Company acquired the McClure # 2B producing gas well on a 40-acre oil & gas lease located in Palo Pinto County near the Community of Graford, Texas. The McClure 2B well is completed in the Strawn in the interval 2,882’ to 2,940’ and has produced in excess of 70 million cubic feet of natural gas. See Item 2 Properties for additional information

Carter & Foster Wells – Producing:

During the fiscal year ended July 31, 2018 the Company acquired the Carter and Foster wells located west of the Community of Atwell, Texas in Callahan County. The Carter lease consists of 40 acres and has one well. The Foster lease has 10 acres around each well of the three wells, all of which are fully equipped with surface and subsurface equipment. All four wells are completed in the Palo Pinto Limestone formation at approximately 1,900 feet.

Reeves Lease – Acreage – Palo Pinto Reef Prospect:

In August 2018, subsequent to the end of the fiscal year ended July 31, 2018, the Company paid for the geological prospecting fees for a Palo Pinto Reef prospect in Jones County. The Reeves lease covers 160 acres and is located near Noodle, Texas in Jones County. The projected depth of the Palo Pinto Reef is 4,300’.

Winnemucca Mountain Gold Property, Nevada

On September 14, 2012, the Company entered into an option agreement (as amended and restated on November 15, 2012, February 1, 2013 and August 26, 2013) with AHL Holdings Ltd., a Nevada corporation, and Golden Sands Exploration Inc., a company incorporated under the laws of British Columbia, Canada, wherein the Company acquired an option to purchase a revised 80% interest in and to certain mining claims from AHL Holdings and Golden Sands, which claims form the Swordfish Property (“Winnemucca Mountain Property”) in Humboldt County, Nevada. This Winnemucca Mountain property at September 14, 2012 consisted of 138 unpatented mining claims covering an area of approximately 2,700 acres.

Effective July 30, 2014, the Company entered into amended and restated option agreement with AHL Holdings and Golden Sands that materially modifies and replaces the terms of the original option agreement (as amended last on August 26, 2013). The amended and restated option agreement dated July 30, 2014 was further amended by letter agreement on February 11, 2016. The aggregate cash fee payable to exercise the option was increased from $1,715,000 to $1,740,000 and the total number of common shares issuable to exercise the option has been increased from 100,000 to 3,850,000. Lastly, the amended and restated agreement provides that AHL Holdings may elect to receive shares of the Company’s common stock in lieu of any cash payments payable pursuant to the agreement at a 75% discount to the then current closing market price.

In 2015 the Company failed to maintain in good standing all of the claims which form the Winnemucca Mountain Property whereby 70 unpatented mining claims were forfeited. The Company is obligated to pay the costs and cause to be re-acquired and recorded in the name of AHL Holdings the area of the property that was previously held by the 70 unpatented claims.

As part of the Company’s outstanding obligations under the Option Agreement the Company conducted a geophysical survey on the Winnemucca Property in January 2018 at a cost of $35,100.

On July 23, 2018, the Company entered into a New Option Agreement with AHL Holding Ltd & Golden Sands Exploration Inc. (“Optionors”). This agreement provided for the payment of $25,000 and the issuance of 3,000,000 shares of the Company’s common stock. The Company issued the shares and made the payment of $25,000 per the agreement on July 31, 2018. The second payment of $25,000 per the terms of the agreement was to be paid when it was due on August 31, 2018. The Company is in default of the terms of the July 23, 2018 agreement. The Company at the time of this filing is in discussions to seek a mutual agreement and or settlement with the Optionors to proceed forward with the Winnemucca Property.

NOTE 2 - SIGNIFICANT ACCOUNTING POLICIES

Basis of presentation

The accounting and reporting policies of the Company conform to U.S. generally accepted accounting principles (US GAAP).

Use of estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from those estimates.

Principles of Consolidation

The accompanying consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries, Kathis Energy LLC, Kathis Energy Fund 1, LLP and Enmex Operations LLC. All financial information has been prepared in conformity with accounting principles generally accepted in the United States of America. All significant intercompany transactions and balances have been eliminated.

Reclassifications

Certain reclassifications have been made to the prior year financial information to conform to the presentation used in the financial statements for the year ended July 31, 2018. There was no effect on net loss or earnings per share.

Revenue Recognition

Revenue is recognized when a customer obtains control of promised goods or services and is recognized in an amount that reflects the consideration that an entity expects to receive in exchange for those goods or services. In addition, the standard requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The amount of revenue that is recorded reflects the consideration that the Company expects to receive in exchange for those goods. The Company applies the following five-step model in order to determine this amount: (i) identification of the promised goods in the contract; (ii) determination of whether the promised goods are performance obligations, including whether they are distinct in the context of the contract; (iii) measurement of the transaction price, including the constraint on variable consideration; (iv) allocation of the transaction price to the performance obligations; and (v) recognition of revenue when (or as) the Company satisfies each performance obligation.

The Company only applies the five-step model to contracts when it is probable that the entity will collect the consideration it is entitled to in exchange for the goods or services it transfers to the customer. Once a contract is determined to be within the scope of ASC 606 at contract inception, the Company reviews the contract to determine which performance obligations the Company must deliver and which of these performance obligations are distinct. The Company recognizes as revenues the amount of the transaction price that is allocated to the respective performance obligation when the performance obligation is satisfied or as it is satisfied. Generally, the Company’s performance obligations are transferred to customers at a point in time, typically upon delivery.

Revenues are earned from the J.E. Richey Lease both in selling oil and gas and from funds received for reworking the Concho Richey #1. We began earning revenues in Q1 of 2015 from the J.E. Richey Lease. Revenues resumed from the sale of oil and gas during the second quarter of the 2016/17 fiscal year.

Long Lived Assets

Property consists of mineral rights purchases as stipulated by underlying agreements and payments made for oil and gas exploration rights. Our company assesses the impairment of long-lived assets whenever events or changes in circumstances indicate that the carrying value may not be recoverable. When we determine that the carrying value of long-lived assets may not be recoverable based upon the existence of one or more indicators of impairment and the carrying value of the asset cannot be recovered from projected undiscounted cash flows, we record an impairment charge. Our company measures any impairment based on a projected discounted cash flow method using a discount rate determined by management to be commensurate with the risk inherent in the current business model. Significant management judgment is required in determining whether an indicator of impairment exists and in projecting cash flows.

Mineral Property Acquisition and Exploration Costs

Mineral property acquisition and exploration costs are expensed as incurred until such time as economic reserves are quantified. Cost of lease, exploration, carrying and retaining unproven mineral lease properties are expensed as incurred. We have chosen to expense all mineral exploration costs as incurred given that it is still in the exploration stage. Once our company has identified proven and probable reserves in its investigation of its properties and upon development of a plan for operating a mine, it would enter the development stage and capitalize future costs until production is established. When a property reaches the production stage, the related capitalized costs will be amortized over the estimated life of the probable-proven reserves. When our company has capitalized mineral properties, these properties will be periodically assessed for impairment of value and any diminution in value.

Oil and Gas Properties

The Company applies the successful efforts method of accounting for oil and gas properties. The Company capitalizes asset acquisition costs of mineral rights and leases. Unproved oil and gas properties are periodically assessed to determine whether they have been impaired, and any impairment in value is charged to expense. The costs of proved properties will be depleted on an equivalent unit-of-production basis in which total proved reserves will be the base used to calculate depletion.

Basic and Diluted Earnings Per Share

Net income (loss) per common share is computed pursuant to ASC 260-10-45, Earnings per Share—Overall—Other Presentation Matters. Basic net income (loss) per common share is computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the period. Diluted net income (loss) per common share is computed by dividing net income (loss) by the weighted average number of shares of common stock and potentially outstanding shares of common stock during the period. The weighted average number of common shares outstanding and potentially outstanding common shares assumes that we incorporated as of the beginning of the first period presented.

As of July 31, 2018 and 2017, the Company had 6,566,815 and 3,744,255 potentially dilutive shares; however, the diluted loss per share is the same as the basic loss per share for the years ended July 31, 2018 and 2017, as the inclusion of any potential shares would have had an antidilutive effect due to our loss from operations.

Recently issued accounting pronouncements

Topic 606, Revenue from Contracts with Customers, of the Financial Accounting Standards Board’s (FASB) Accounting Standards Codification (ASC). The guidance in ASC 606 was originally issued by the FASB in May 2014 in Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606). Since then, the FASB has issued several ASUs that have revised or clarified the guidance in ASC 606.

 On June 20, 2018, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2018-07, Compensation—Stock Compensation (Topic 718): Improvements to Nonemployee Share-Based Payment Accounting. ASU 2018-07 is intended to reduce cost and complexity and to improve financial reporting for share-based payments to nonemployees (for example, service providers, external legal counsel, suppliers, etc.). Under the new standard, companies will no longer be required to value non-employee awards differently from employee awards. Meaning that companies will value all equity classified awards at their grant-date under ASC718 and forgo revaluing the award after this date. The Company has chosen to early adopt this standard.

In January 2017, the Financial Accounting Standards Board (“FASB”) issued an Accounting Standards Update (“ASU”) 2017-01, Business Combinations (Topic 805) Clarifying the Definition of a Business. The amendments in this update clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. The definition of a business affects many areas of accounting including acquisitions, disposals, goodwill, and consolidation. The guidance is effective for interim and annual periods beginning after December 15, 2017 and should be applied prospectively on or after the effective date. The Company is in the process of evaluating the impact of this accounting standard update.

In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). ASU 2016-02 requires lessees to recognize lease assets and lease liabilities on the balance sheet and requires expanded disclosures about leasing arrangements. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018 and interim periods in fiscal years beginning after December 15, 2018, with early adoption permitted. The Company has evaluated the impact of this accounting standard update and noted that it has had no material impact.

The Company has implemented all new accounting pronouncements that are in effect. These pronouncements did not have any material impact on the financial statements unless otherwise disclosed, and the Company does not believe that there are any other new accounting pronouncements that have been issued that might have a material impact on its financial position or results of operations.

NOTE 3 - GOING CONCERN

The accompanying financial statements are prepared and presented on a going concern basis, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. Accordingly, they do not include any adjustments relating to the realization of the carrying value of assets or the amounts and classification of liabilities that might be necessary should the Company be unable to continue as a going concern. Since inception to July 31, 2018, the Company has an accumulated deficit of $2,392,496. The Company intends to fund operations through equity financing arrangements, which may be insufficient to fund its capital expenditures, working capital and other cash requirements for the next twelve months. These factors, among others, raise substantial doubt about the Company’s ability to continue as a going concern. The accompanying financial statements do not include any adjustments that might result from the outcome of this uncertainty.

NOTE 4 - MINERAL RIGHTS AND PROPERTIES

Coleman County – J.E. Richey Lease

On October 14, 2014, the Company entered into a Terms of Farm-out Agreement with Copper Basin Oil & Gas Inc. to acquire a working interest in an oil and gas lease in the J.E. Richey lease, which has 3 fully equipped wells, production flow lines, injection flow line, Tank battery consisting of two 300 BBL tanks, one 210 BBL tank with two separators. The Company agreed to acquire a 75% working interest in the lease including the existing wells and equipment.

The total consideration that the Company must pay to acquire the 75% working interest is estimated at $336,000, which amount includes all work requirements, and common stock valued at $0.10 based upon our current share price of $0.11 as at October 14, 2014. The Net Revenue Interest is 56.25% and consists of approximately 206.5 acres, more or less, in Coleman County, Texas. This lease has no depth limit.

On March 20, 2015, the Company entered into a multi-well purchase and sale agreement with EF VC2, LLC to sell a 37.5% working interest (“WI”) in the 3 wells for total consideration of $180,000. Under the terms of the agreement both parties will receive a 50.0% of the WI revenue from these three wells until EF VC2 recaptures their investment of $180,000 (defined as “Payout”). After Payout EF VC2 will revert to a 37.5% of the WI revenue for the remaining life of the production from the three wells.

We were successful in the re-completion of the Concho Richey #1 well on the J.E. Richey Lease in the Gray formation in July 2015. The Concho Richey well came in with initial production rates of 65 barrels of oil per day and 100 MCF of gas per day. We hold a 25% working interest in one producing well (“Concho Richey #1”) on the lease and a 100% working interest in the remainder of the 206-acre J. E Richey Lease.

The Concho Richey well was shut in due to a hole coming in to the casing which was repaired in the quarter ended October 31, 2016. No revenues were received during the quarter from the Concho Richey well, subsequently repairs were made to the well. Repairs made to the well to squeeze off the holes in the casing were successful. Revenues from the sale of oil and gas resumed during the year ended July 31, 2017. The Concho Richey #1 well is currently producing 7 barrels of oil and 40 MCF of gas per day.

During August 2017 further work was conducted on the J.E. Richey #1 well during August 2017, which determined the casing in this well was beyond being repaired. A decision was made to plug this well. The Richey #1 well was plugged on January 3, 2018.

Further work is planned during the next fiscal year on the J. E. Richey lease on well #3 in an effort to improve its production.

Coleman County, Texas – J. E. Richey #2A -Proposed New Well:

The Company has sold working interest in a 20 acre tract on the J.E. Richey Lease to drill a new well near the ARCO Richey #2 well. This well initially was completed in the Lower Ellenburger in 1982 coming in at 19 barrels per day. Following depletion of the Lower Ellenburger the well was re-completed in the Upper Ellenburger with an initial production rate of 2,535 MCF per day. Subsequently the well was re-completed in the Gray Sand, which came in at 45 barrels per day on a light acid job and no sand frac was conducted. The well only produced for a limited amount of time from the Gray Sand when a hole came in the casing above the cement at 1100 feet caused by a corrosive formation known as the Coleman Junction and the well was shut in. This well was plugged due to casing problems in the well on December 28, 2017.

Callahan County Shallow Oil Play

On July 7, 2014, the Company entered into a Terms of Farm-out Agreement with Grasshoppers Unlimited Inc. to acquire a working interest in an oil and gas lease in the Callahan County Shallow Oil Play, which has 3 fully equipped wells, 1 injection well, production flow lines, injection flow line, Tank battery consisting of two 150 BBL tanks with separator, Injection system has a 150 BBL tank with Injection Pump, 8 un-drilled locations. The Company agreed to acquire a 75% working interest in the lease including the existing wells and equipment.

The total consideration that we must pay to acquire the 75% working interest is estimated at $275,000, which amount does not include all work requirement and drilling commitments. The common stock is valued at $0.05 per share based upon our current share price of $0.10 as at June 30, 2014. The Net Revenue Interest is 70% and consists of approximately 60 acres, more or less, in Callahan County, Texas. This lease has a depth limit to no more than 1,000 feet. The Company has elected not to proceed forward with earning an interest in this property. The property has expired without penalty to the Company. During the year ended July 31, 2017 management determined this property to be fully impaired. As a result of writing off the asset and liability associated with the property the Company recognized a $67,315 loss on impairment.

Callahan/Eastland Mississippi Reef Play

On July 7, 2014, under the same Terms of Farm-out Agreement with Grasshoppers Unlimited Inc., the Company acquired a working interest in a second oil and gas lease known as the Callahan/Eastland Mississippi Reef Play, which is located near the Callahan and Eastland County line in Central Texas.

The total consideration that we must pay to acquire the 60% working interest is approximately $65,000, which amount does not include the cost of drilling and completing a well on the acreage. The common stock is valued at $0.05 based upon our current share price of $0.10 as at June 30, 2014. The Net Revenue Interest is 75% and consists of approximately 220 acres, more or less, in Callahan County, Texas. This lease has no depth limit requirement. The Company has elected not to proceed forward with earning an interest in this property. The property has expired without penalty to the Company. During the year ended July 31, 2017, the Company determined this property to be fully impaired. As a result of writing off the asset and liability associated with this property the Company recognized a $58,000 loss on impairment.

Winnemucca Mountain Property

On September 14, 2012, the Company entered into an option agreement (as amended and restated on November 15, 2012, February 1, 2013 and August 26, 2013) with AHL Holdings Ltd., a Nevada corporation, and Golden Sands Exploration Inc., a company incorporated under the laws of British Columbia, Canada, wherein the Company acquired an option to purchase a revised 80% interest in and to certain mining claims from AHL Holdings and Golden Sands, which claims form the Swordfish Property (“Winnemucca Mountain Property”) in Humboldt County, Nevada. This Winnemucca Mountain property at September 14, 2012 consisted of 138 unpatented mining claims covering an area of approximately 2,700 acres.

Effective July 30, 2014, the Company entered into amended and restated option agreement with AHL Holdings and Golden Sands that materially modifies and replaces the terms of the original option agreement (as amended last on August 26, 2013). The amended and restated option agreement dated July 30, 2014 was further amended by letter agreement on February 11, 2016. The aggregate cash fee payable to exercise the option was increased from $1,715,000 to $1,740,000 and the total number of common shares issuable to exercise the option has been increased from 100,000 to 3,850,000. Lastly, the amended and restated agreement provides that AHL Holdings may elect to receive shares of the Company’s common stock in lieu of any cash payments payable pursuant to the agreement at a 75% discount to the then current closing market price.

In 2015 the Company failed to maintain in good standing all of the claims which form the Winnemucca Mountain Property whereby 70 unpatented mining claims were forfeited. The Company is obligated to pay the costs and cause to be re-acquired and recorded in the name of AHL Holdings the area of the property that was previously held by the 70 unpatented claims.  

As previously announced, on September 14, 2012, we entered into an option agreement (as last amended on February 11, 2016) with AHL Holdings Ltd., and Golden Sands Exploration Inc., wherein we acquired an option to purchase an 80% interest in and to certain mining claims, which claims form the Winnemucca Mountain Property in Humboldt County, Nevada. On May 30, 2017 the Company was given notice of default by the optionors whereby the Company lost the right to earn an interest in the property. At present the Company is in discussions with optionors to renegotiate the agreement. Although we are in such discussions, there are no assurances that acceptable terms can be reached with the optionors, AHL Holdings Ltd and Golden Sands Exploration Inc. Due to the notice of default the Company determined this property to be fully impaired. As a result of writing off the asset and liability associated with this property the Company recognized a $342,157 loss on impairment.

As part of the Company’s outstanding obligations under the Option Agreement, the Company conducted a geophysical survey on the Winnemucca Property in January 2018 at a cost of $35,100.

On July 23, 2018, the Company entered into a New Option Agreement with AHL Holding Ltd & Golden Sands Exploration Inc. (“Optionors”). This agreement provided for the payment of $25,000 and the issuance of 3,000,000 shares of the Company’s common stock. The Company issued the shares and made the payment of $25,000 per the agreement on July 31, 2018. The second payment of $25,000 per the terms of the agreement was to be paid when it was due on August 31, 2018. The Company is in default of the terms of the July 23, 2018 agreement. The Company at the time of this filing is hopeful to seek a mutual agreement and or settlement with the Optionors to proceed forward with the Winnemucca Property.

Olson Lease, Jones County, Texas:

We have a 100% interest in the 160-acre oil and gas Olsen lease located in the north central part of Jones County, Texas. The principal target formation is the Palo Pinto Reef. The Palo Pinto Reef is a known productive formation in the area with a high yield of cumulative oil production. An example in the area is the Strand Oil Field which is a Palo Pinto Reef Oil Field. The field discovered in 1940, consists of only 8 wells on approximately 160 acres produced a total of 1,700,000 barrels of oil, an average of 212,500 barrels of oil per oil well. The 160 Olson Lease lies approximately 1.5 miles southeast of the Strand Palo Pinto Reef Oil Field. We hold 100% of the working interest in this lease. The lease expires on April 27, 2019.

Subsequent to July 31, 2017, the Company agreed to assign its interest and rights to the 160-acre Olson Lease to Kathis Energy LLC, a wholly owned subsidiary of the Company in exchange for a $60,500 loan.

Guy Ranch Lease, Shackleford County, Texas

During the fiscal year ended July 31, 2016 the Company acquired a 100% working interest in a 692-acre Guy Ranch Lease divided into two tracts. Tract 1 covers 480 acres and Tract 2 covers 212 acres. The Ranch has 32 wind turbines on it representing it is at a structurally higher elevation. The principal targets for this drilling prospect is the Patio (aka Palo Pinto Sand) and Morris Sands the area is also know to be productive from three other formations on the Guy Ranch acreage.

The first project on the Guy Ranch was to re-complete a cased well in the Morris formation that was reportedly untested. The structure of the deal was for a third pary to pay 100% of the costs re-complete the cased well in the Morris formation allocating 20 acres out of the 450 acres in order to earn a 75% working interest in the cased well. All records filed with the Texas Railroad Commission supported that no attempt to produce from the Morris had been performed. However it was subsequently found out that in fact an attempt was made to re-complete in Morris formation and such attempt was unsuccessful due to an over stimulation of the Morris with a large frac at high pumping rate. The well produced mostly water. The 20 acres around the well was not assumed by the Company or its third party investors. The unused funds provided by the third party will be allocated to a new well on the Guy Ranch Lease with the third party being responsible for providing the balance of the funds to drill and complete a new well in order to earn 75% of the working interest.

During the fiscal year ended July 31, 2018 the Company agreed to convey approximately 650 acres out of the Guy Ranch lease to Kathis Energy LLC, its wholly owned subsidiary, for its drilling program for the consideration of $66,500.

In March 2018 Kathis Energy LLC, our wholly owned subsidiary, staked two drilling locations on the Guy Ranch and prepared one drilling location. This drilling location is a direct offset to a Patio Sand well that came in at 140 barrels per day. The Patio Sand is one of the main producing formations in the area generally averages between 25,000 and 75,000 barrels oil per well. The Morris Sand a notable gas producer is known to produce up to 1.4 BCF gas from one well and the Gardner is noted in this area to produce between 50,000 and 110,000 barrels per well. The Net Revenue Interest for the Guy Ranch lease is 75%. Lease expires in December 16, 2018 unless well is commences drilling prior to that date or an extension can be obtained.

89 Guy #4 Well – Cased Well:

The 89 Guy Well #4 is located on the Guy Ranch property in Shackelford County. The well is an abandoned cased well that was drilled in October 2010 and completed in the Patio Sand at the interval of 3,144’ - 3,154’. This interval produced 2 barrels of oil and 20 thousand cubic feet of natural gas from a 100 sac gel frac. The interval perforated (3,144 – 3,154’) is above the best productive part of the formation. The cased well was purchased from the mineral owner through an independent geologist followed by an application to the Texas Railroad Commission to assume liability of the case well. The application is still pending approval.

Kathis Energy has a 75% net revenue interest in the 20 acre lease with the cased well and owns 100% of the working interest. Kathis has until April 17, 2019 to bring the well back into production. Kathis paid $22,500 for the cased well.

McClure 2B – Gas Well – Palo Pinto County, Texas

On February 6, 2018 the Company acquired the McClure # 2B producing gas well on a 40 -acre oil & gas lease located in Palo Pinto County near the Community of Graford, Texas. The McClure 2B well was drilled in 2006 to a total depth of 4,739’ and was re-completed in the Strawn formation in January 2011. The McClure 2B gas well is among a large number of gas wells that are producing in the area from the Strawn formation.

The location of the McClure 2B gas well is 1 mile southwest of the Community of Graford, Texas in Palo Pinto County on a 40 acre tract. The lease is off a main county road and the lease road can have washouts depending on the amount of rain as the McClure 2B gas well is on top of a hill. There are two natural gas lines 1) high pressure and the 2) is low pressure.

The Company paid $25,000 for this gas well. The Net Revenue Interest for the McClure lease is 75% and the lease is held by existing production. The Company entered into an agreement with a third party to acquire and rework/re-complete the well in one or more of the other intervals in the Strawn formation in the well. As of the date of this report no work has been conducted toward the reworking/re-completing in this well. Upon the third party recovering its investment the Company will receive 40% of the Net Revenue Interest.

Carter & Foster Wells – Producing:

History and Background:

The wells on the Carter and Foster leases were drilled in1992-93. Most of the wells were treated with 5,000 gallons of 21% acid and yielded initial rates of production of 40 barrels of oil per day then gradually declined to 3 barrels per day by the end of the first year. The wells now are 25 plus years old and are producing 90% or better oil cut in the fluid being produced. the production is very nominal at the present time however no secondary acid stimulation has been conducted since they were originally brought into production in the early 1990’s. All four wells on the Carter and Foster leases are fully equipped and have their own production facilities and have electricity to each of the wells. These wells are marginal producing oil wells producing approximately 20 barrels per month with little to no formation water. The objective is to conduct a large multiple stage acid job on three of the four wells to significantly enhance daily production rates.

The Carter and Foster wells are located west of the Community of Atwell, Texas in Callahan County. The Carter lease consists of 40 acres and has one well. The Foster lease has 10 acres around each well of the three wells, all of which are fully equipped with surface and subsurface equipment. The Carter and Foster have good access to an all-weather county road and the lease roads provide good access to each well.

The Net Revenue Interest for the Carter lease is 75% and the lease is held by existing production. The Net Revenue Interest for the Foster lease is 60% and the lease is held by existing production. The Company entered into an agreement with a third party to acquire and rework Palo Pinto formation by conducting the multiple staged acid jobs on three wells. During the year the Company has placed new electric motors on all four wells, changed out the down hole pumps and placed the wells into production. As of the date of this report the Company has not conduced the multiple staged acid job on any of the three wells. Upon the third party recovering its investment the Company will receive 40% of the Net Revenue Interest. The Carter and Foster leases/wells were acquired from an Officer of the Company for total consideration of $1.00.

Reeves Lease – Palo Pinto Reef – Jones County, Texas

In August 2018, subsequent to the end of the fiscal year ended July 31, 2018, the Company paid for the geological prospecting fees for a Palo Pinto Reef prospect in Jones County. The Reeves lease covers 160 acres and is located near Noodle, Texas in Jones County. The projected depth of the Palo Pinto Reef is 4,300’. Excellent well control by 6 Strawn wells provides evidence of a Palo Pinto Reef showing a structure 48’ high to other wells. The nearest Palo Pinto Reef well to the Reeves Lease made more than 150,000 barrels from one well.

The lease bonus money of $28,000 was provided by a third party for a two year lease and the Company paid the geological prospect fee of $10,000. It was verbally understood between the Company and third party to promote this drilling prospect seeking to retain a carried interest plus recoup the lease and prospect monies.

The Net Revenue of the lease is 80%. The lease term is 2 years. Plans are to deliver a 75% net revenue lease to a drilling partner retaining an overriding royalty and a carried working interest in the drilling in the well. 

NOTE 5 - ACCRUED LIABILITIES

Accrued liabilities consist of $1,715 general accrual, $38,002 of accrued interest, $22,345 of accrued distribution and royalty payments and $170,518 of monies received in advance for well work to be performed and the acquisition of additional oil and gas properties and $95,000 of investment funds to be used for the development of future properties. The Company has partnered with others whereby they provide all or a portion of the working capital for either well to be completed on existing properties or towards the acquisition of new properties. As of July 31, 2018, the Company has unused funds it has received of $170,518.

NOTE 6 - CONVERTIBLE DEBT

On August 22, 2013 the Company entered into a $50,000 Convertible Loan Agreement with an un-related party. The Loan and interest are convertible into Units at $0.08 per Unit with each Unit consisting of one common share of the Company and ½ warrant with each full warrant exercisable for one year to purchase one common share at $0.30 per share. On July 10, 2014, a further $35,000 was received from the same unrelated party under the same terms. On July 31, 2018, this Note was amended whereby the principal and interest are now convertible into Units at $0.04 per Unit with each Unit consisting of one common share of the Company and ½ warrant with each full warrant exercisable for one year to purchase one common share at $0.08 per share. The Loan shall bear interest at the rate of Eight Percent (8%) per annum and matures on March 26, 2020. As of July 31, 2018, there is $85,000 and $36,382 of principal and accrued interest, respectively, due on this loan.

On April 16, 2017, the Company executed a promissory note for $15,000 with a third party. The note matures in two years and interest is set at $3,000 for the full two years. As of July 31, 2018, there is $15,000 and $375 of principal and accrued interest, respectively, due on this loan.

On October 20, 2017, the Company executed a convertible promissory note for $25,000 with a third party. The note accrues interest at 6%, matures in two years and is convertible into shares of common stock at maturity, at a minimum of $0.10 per share, at the option of the holder. As of July 31, 2018, there is $1,245 of accrued interest due on this loan.

NOTE 7 - COMMON STOCK

On August 5, 2016, the Company issued 670,000 shares of common stock at $0.025 per share as a portion of the consideration to acquire an oil and gas lease known as the Guy Ranch (Note 4).

On January 24, 2017, the Company sold 300,000 shares of common stock along with warrants to purchase an additional 150,000 shares for total proceeds of $5,000. The warrants are exercisable at $0.10 and expire February 1, 2019.

During the year ended July 31, 2018, the Company sold 16,559,000 shares of common stock for total cash proceeds of $219,475; $20,000 of which had not yet been received as of July 31, 2018. In addition, 1,000,000 shares of those sold were not issued as of July 31, 2018 and have therefore been credited to common stock to be issued.

During the year ended July 31, 2018, the Company sold 2,730,000 Units of its common stock for total cash proceeds of $136,500. Each Unit consists of one common share and one-half share purchase warrant exercisable for 1 years. Each whole share purchase warrant has an exercise price of $0.15 per common share.

During the year ended July 31, 2018, the Company issued 200,000 shares of common stock for conversion of a $4,000 loan payable. The shares were valued at $0.05, the closing stock price on the date of conversion for a loss on conversion of $6,000.

During the year ended July 31, 2018, the Company issued 3,000,000 shares of common stock for services. The shares were valued at $0.061, the closing stock price on the date of grant for total non-cash expense of $183.000.

NOTE 8 - WARRANTS

Warrants were issued during the year ended July 31, 2018 and 2017 in conjunction with common stock issuances. During the year ended July 31, 2018, the Company sold 2,730,000 Units of its common stock for total cash proceeds of $136,500. Each Unit consists of one common share and one-half share purchase warrant exercisable for 2 years. Each whole share purchase warrant has an exercise price of $0.15 per common share. The warrants were evaluated for purposes of classification between liability and equity. The warrants do not contain features that would require a liability classification and are therefore considered equity. The Black Scholes pricing model was used to estimate the fair value of $70,858 of the Warrants with the following inputs:

Using the fair value calculation, the relative fair value between the common stock and the warrants was calculated to determine the warrants recorded equity amount of $70,858, accounted for in additional paid in capital.

Activity for the year ended July 31, 2018 and 2017 is as follows: 

NOTE 9 - RELATED PARTY TRANSACTIONS

A former officer of the Company has advanced the Company $24,747 by making payments on behalf of the Company. The full balance of $24,747 was still owed as of July 31, 2016. The advance is unsecured, non-interest bearing and has no specific terms of repayment. During the year ended July 31, 2017, this debt was forgiven and credited to paid in capital.

For the year ended July 31, 2018 and 2017, total payments of $56,500 and $32,750, respectively were made to an officer of the Company for consulting services.

For the year ended July 31, 2018 and 2017, total payments of $26,500 and $0, respectively were made to directors of the Company for consulting services.

On July 31, 2018, Winona Webb, the wife of Ivan Webb, CEO, loaned the Company $25,000 for general operating expenses. This loan was repaid on August 2, 2018.

During the fiscal year ended July 31, 2018 the Company acquired from Ivan Webb, CEO of the Company, the oil and gas rights to two oil and gas leases located in Callahan County, Texas known as the Carter and Foster leases for total consideration of $1.00.

NOTE 10 - INCOME TAX

Deferred taxes are provided on a liability method whereby deferred tax assets are recognized for deductible temporary differences and operating loss and tax credit carry forwards and deferred tax liabilities are recognized for taxable temporary differences. Temporary differences are the differences between the reported amounts of assets and liabilities and their tax bases. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. The U.S. federal income tax rate of 21% is being used for 2017 due to the new tax law recently enacted.

The provision for Federal income tax consists of the following July 31:

The cumulative tax effect at the expected rate of 21% of significant items comprising our net deferred tax amount is as follows:

At July 31, 2018, the Company had net operating loss carry forwards of approximately $502,000 that maybe offset against future taxable income.  No tax benefit has been reported in the July 31, 2018 or 2017 financial statements since the potential tax benefit is offset by a valuation allowance of the same amount. The change in the valuation allowance for the year ended July 31, 2017 was an increase of $161,000.

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cut and Jobs Act (the “Tax Act”). The Tax Act establishes new tax laws that affects 2018 and future years, including a reduction in the U.S. federal corporate income tax rate to 21% effective January 1, 2018. For certain deferred tax assets and deferred tax liabilities.

Due to the change in ownership provisions of the Tax Reform Act of 1986, net operating loss carry forwards for Federal income tax reporting purposes are subject to annual limitations. Should a change in ownership occur, net operating loss carry forwards may be limited as to use in future years.

ASC Topic 740 provides guidance on the accounting for uncertainty in income taxes recognized in a company’s financial statements. Topic 740 requires a company to determine whether it is more likely than not that a tax position will be sustained upon examination based upon the technical merits of the position. If the more-likely-than-not threshold is met, a company must measure the tax position to determine the amount to recognize in the financial statements.

The Company includes interest and penalties arising from the underpayment of income taxes in the statements of operations in the provision for income taxes. As of July 31, 2018, the Company had no accrued interest or penalties related to uncertain tax positions.

NOTE 11 - SUBSEQUENT EVENTS

Management has evaluated subsequent events pursuant to the requirements of ASC Topic 855, from the balance sheet date through the date the financial statement were available to be issued, and has determined that no material subsequent events exist other then the following.

Subsequent to July 31, 2018, the Company gave 150,000 shares of common stock for consideration related to the Richey 2A project.

Subsequent to July 31, 2018, the Company sold 1,000,000 shares of common stock for total proceeds of $50,000. The shares have not yet been issued by the transfer agent.

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 conducted an evaluation of the effectiveness of our “disclosure controls and procedures” (“Disclosure Controls”), as defined by Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), as of July 31, 2018, the end of the period covered by this Annual Report on Form 10-K. The Disclosure Controls evaluation was done under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer.

Disclosure controls and procedures refer to controls and other procedures designed to ensure that information required to be disclosed in the reports we file or submit under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC and (ii) that such information is accumulated and communicated to our management, including our chief executive officer and chief financial officer, or persons performing similar functions, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management is required to apply its judgment in evaluating and implementing possible controls and procedures.

Our management does not expect that our disclosure controls and procedures will prevent all error and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the control system’s objectives will be met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. The design of any system of controls is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions.

With respect to the fiscal year ending July 31, 2018, our management, including our Chief Executive Officer and Chief Financial Officer, has concluded that our Disclosure Controls were not effective.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our management is also required to assess and report on the effectiveness of our internal control over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act of 2002 (“Section 404”). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes of accounting principles generally accepted in the United States.  Management assessed the effectiveness of our internal control over financial reporting as of July 31, 2018. In making this assessment, we used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework 2013 and determined that our internal controls over financial reporting are not effective.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.

Changes in Internal Controls

There have not been any changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal year ended July 31, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Subsequent to the end of the fiscal year ended July 31, 2018 the Company approved and implemented internal controls and procedures.

ITEM 9B. OTHER INFORMATION

None

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

All directors of our company hold office until the next annual meeting of the security holders or until their successors have been elected and qualified. The officers of our company are appointed by our board of directors and hold office until their death, resignation or removal from office. Our directors and executive officers, their ages, positions held, and duration as such, are as follows:

BUSINESS EXPERIENCE

The following is a brief account of the education and business experience during at least the past five years of each director, executive officer and key employee of our company, indicating the person’s principal occupation during that period, and the name and principal business of the organization in which such occupation and employment were carried out.

Howard Siegel, Director, was appointed to our Board of Directors on April 23, 2014 and appointed as our President, Chief Executive Officer, Chief Financial Officer and Treasurer on April 24, 2014. On July 6, 2018 he resigned as the Company’s Chief Executive Officer, Chief Financial Officer and Treasurer and remained as the Company’s President.

Howard Siegel is an attorney licensed to practice law in the State of Texas and has been a practicing attorney for over 40 years.  He holds a law degree from St. Mary’s University Law School.  Mr. Siegel’s law practice includes tax, real estate, and corporate law matters.  He previously worked for the Internal Revenue Service, Tenneco, Inc., The Superior Oil Company and Bracewell & Patterson.  He has served as a Director in public and private corporations, including Hondo Minerals, Inc., Australian Canadian Oil Royalties, Ltd., and Syndication, Inc.  Mr. Siegel resides in Houston, Texas.

Our company believes that Mr. Siegel’s professional background, management and corporate governance experience give him the qualifications and skills necessary to serve as principal officer and as a director of our company.

Noel Schaefer, Director & Chief Operations Officer, (“COO”) has served in a variety of executive and director positions in his 30 plus year career with both domestic and international companies. His emphasis has been with startups by setting up market profiles, developing strategic market placement and refining corporate objectives. Mr. Schaefer has successfully helped to raise funds from both the public and private sectors. He has worked extensively in Far East and Latin America with a particular focus on Mexico. He holds a Bachelor of Science degree from Brigham Young University with an emphasis in Marketing and Finance.

Victor Miranda, Director & Chief Financial Officer, (“CFO”), is a CEO of an insurance broker firm, passionate about ventures developing USA/MEXICO cross border opportunities. He has 15 years of hands on experience in the sales management for the financial sector, with particular focus on developing a savers culture through employee benefits, and 7 years developing successful real estate development projects in Quintana Roo. Quintana Roo is the State in Mexico where the Pemer Bacalar property is located.

Robert Campbell, Secretary, is Co-Founder and CEO of Crowdvac for the past six years which is a software engineering systems and product development company that also provides technical support. Mr. Campbell holds a MBA Degree in International Management from the Thunderbird School of Global Management and a BA Degree from the University of Utah in Economics.

Ivan Webb, Chief Executive Officer, is a seasoned and successful entrepreneur, with over 35 years of experience in the oil and gas industry internationally and in the United States. He is experienced with acquiring oil and gas concessions and leases, drilling of new wells and reworking/ re-completing existing wells, production management, working with service companies and regulatory compliance. Internationally, he has successfully leased more than 18,000,000 acres. Domestically he has been involved with the acquisition and or management of more than 250 wells in Kansas, Oklahoma and Texas.

Mr. Webb has also over 30 years of experience in managing or assisting public companies in both the US and Canada with regulatory compliance. His public company experience includes assisting companies with initial public offerings, reverse mergers, obtaining listings, and assisting with ongoing regulatory compliance.

Mr. Webb was appointed on July 6, 2018 to serve as the Company’s Chief Executive Officer.

Family Relationships

There are no family relationships among any of our officers or directors.

Involvement in Certain Legal Proceedings

To the best of our knowledge, none of our directors or executive officers has, during the past ten years:

Committees of the Board

All proceedings of our board of directors was conducted by resolutions consented to in writing by the directors and filed with the minutes of the proceedings of the directors. Such resolutions consented to in writing by the directors entitled to vote on that resolution at a meeting of the directors are, according to the corporate laws of the state of Nevada and the bylaws of our company, as valid and effective as if they had been passed at a meeting of the directors duly called and held.

Our company currently does not have nominating, compensation or audit committees or committees performing similar functions nor does our company have a written nominating, compensation or audit committee charter. Our board of directors does not believe that it is necessary to have such committees because it believes that the functions of such committees can be adequately performed by our directors.

Our company does not have any defined policy or procedure requirements for shareholders to submit recommendations or nominations for directors. The directors believe that, given the early stage of our business, a specific nominating policy would be premature and of little assistance until our business operations develop to a more advanced level. Our company does not currently have any specific or minimum criteria for the election of nominees to the board of directors and we do not have any specific process or procedure for evaluating such nominees. Our director assesses all candidates, whether submitted by management or shareholders, and makes recommendations for election or appointment.

A shareholder who wishes to communicate with our board of directors may do so by directing a written request addressed to our President, at the address appearing on the first page of this annual report.

Audit Committee and Audit Committee Financial Expert

Our board of directors has determined that our directors do not qualify as an “audit committee financial expert” as defined in Item 407(d)(5)(ii) of Regulation S-K and is “independent” as the term is used in Item 7(d)(3)(iv) of Schedule 14A under the Securities Exchange Act of 1934, as amended.

We believe that the board of directors is capable of analyzing and evaluating our financial statements and understanding internal controls and procedures for financial reporting. We believe that retaining an independent director who would qualify as an “audit committee financial expert” would be overly costly and burdensome and is not warranted in our circumstances given the early stages of our business and the fact that we have not generated any material revenues to date. In addition, we currently do not have nominating, compensation or audit committees or committees performing similar functions nor do we have a written nominating, compensation or audit committee charter. Our board of directors does not believe that it is necessary to have such committees because it believes the functions of such committees can be adequately performed by our directors.

Compliance with Section 16(a) of the Securities Exchange Act of 1934

Our common stock is not registered pursuant to Section 12 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).  Accordingly, our officers, directors, and principal stockholders are not subject to the beneficial ownership reporting requirements of Section 16(a) of the Exchange Act.

Code of Ethics

We have adopted a Code of Ethics applicable to our officers and directors which is a “code of ethics” as defined by applicable rules of the SEC. If we make any amendments to our Code of Ethics other than technical, administrative, or other non-substantive amendments, or grant any waivers, including implicit waivers, from a provision of our Code of Ethics to our Chief Executive Officer, Chief Financial Officer, or certain other finance executives, we will disclose the nature of the amendment or waiver, its effective date and to whom it applies in a current report on Form 8-K filed with the SEC.

Conflicts of Interest

Certain potential conflicts of interest are inherent in the relationships between our officers and directors, and us. 

From time to time, one or more of our affiliates may form or hold an ownership interest in and/or manage other businesses both related and unrelated to the type of business that we own and operate. These persons expect to continue to form, hold an ownership interest in and/or manage additional other businesses which may compete with ours with respect to operations, including financing and marketing, management time and services and potential customers. These activities may give rise to conflicts between or among the interests of us and other businesses with which our affiliates are associated. Our affiliates are in no way prohibited from undertaking such activities, and neither we nor our shareholders will have any right to require participation in such other activities.

Further, because we intend to transact business with some of our officers, directors and affiliates, as well as with firms in which some of our officers, directors or affiliates have a material interest, potential conflicts may arise between the respective interests of us and these related persons or entities. We believe that such transactions will be effected on terms at least as favorable to us as those available from unrelated third parties.

ITEM 11. EXECUTIVE COMPENSATION

The particulars of the compensation paid to the following persons:

Other than as set out below, there are no arrangements or plans in which we provide pension, retirement or similar benefits for directors or executive officers. Our directors and executive officers may receive share options at the discretion of our board of directors in the future. We do not have any material bonus or profit sharing plans pursuant to which cash or non-cash compensation is or may be paid to our directors or executive officers, except that share options may be granted at the discretion of our board of directors.

Stock Option Grants

We have not granted any stock options to the executive officers since our inception.

Outstanding Equity Awards at Fiscal Year End

For the year ended July 31, 2018, no director or executive officer has received compensation from us pursuant to any compensatory or benefit plan. There is no plan or understanding, express or implied, to pay any compensation to any director or executive officer pursuant to any compensatory or benefit plan.

Compensation of Directors

No member of our Board of Directors received any compensation for his services as a director during the year ended July 31, 2018.

Pension, Retirement or Similar Benefit Plans

There are no arrangements or plans in which we provide pension, retirement or similar benefits for directors or executive officers. We have no material bonus or profit sharing plans pursuant to which cash or non-cash compensation is or may be paid to our directors or executive officers, except that stock options may be granted at the discretion of the board of directors or a committee thereof.

Indebtedness of Directors, Senior Officers, Executive Officers and Other Management

None of our directors or executive officers or any associate or affiliate of our company during the last two fiscal years, is or has been indebted to our company by way of guarantee, support agreement, letter of credit or other similar agreement or understanding currently outstanding.

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

The following table sets forth, as of November 9, 2018, certain information with respect to the beneficial ownership of our common shares by each shareholder known by us to be the beneficial owner of more than 5% of our common shares, as well as by each of our current directors and executive officers as a group. Each person has sole voting and investment power with respect to the shares of common stock, except as otherwise indicated. Beneficial ownership consists of a direct interest in the shares of common stock, except as otherwise indicated.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE

Except as disclosed herein, no director, executive officer, shareholder holding at least 5% of shares of our common stock, or any family member thereof, had any material interest, direct or indirect, in any transaction, or proposed transaction since the year ended July 31, 2018, in which the amount involved in the transaction exceeded or exceeds the lesser of $120,000 or one percent of the average of our total assets at the year-end for the last three completed fiscal years.

A former officer of the Company has advanced the Company $24,747 by making payments on behalf of the Company. The full balance of $24,747 was still owed as of July 31, 2016. The advance is unsecured, non-interest bearing and has no specific terms of repayment. During the year ended July 31, 2017, this debt was forgiven and credited to paid in capital.

For the year ended July 31, 2018 and 2017, total payments of $56,500 and $32,750, respectively were made to an officer of the Company for consulting services.

For the year ended July 31, 2018 and 2017, total payments of $22,500 and $0, respectively were made to Noel Schaefer, a Director of the Company, for consulting services.

For the year ended July 31, 2018 and 2017, total payments of $4,000 and $0, respectively were made to Howard Siegel, a Director of the Company, for consulting services

On July 31, 2018, Winona Webb, the wife of Ivan Webb, CEO, loan the Company $25,000 for general operating expenses. This loan was repaid on August 2, 2018.

During the fiscal year ended July 31, 2018 the Company acquired from Ivan Webb, CEO of the Company, the oil and gas rights to two oil and gas leases located in Callahan County, Texas known as the Carter and Foster leases for total consideration of $1.00.

Promoters and Certain Control Persons

We did not have any promoters at any time during the past five fiscal years.

Director Independence

We currently act with three directors, Howard Siegel, Noel Schaefer and Victor Miranda. We have determined that we do not have an “independent director” as defined in NASDAQ Marketplace Rule 4200(a)(15).

We do not have a standing audit, compensation or nominating committee, but our sole director and officer acts in such capacities. We believe that our sole director is capable of analyzing and evaluating our financial statements and understanding internal controls and procedures for financial reporting. Our sole director does not believe that it is necessary to have an audit committee because we believe that the functions of an audit committee can be adequately performed by the sole director. In addition, we believe that retaining an independent director who would qualify as an “audit committee financial expert” would be overly costly and burdensome and is not warranted in our circumstances given the early stages of our development.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The aggregate fees billed for the most recently completed fiscal year ended July 31, 2018 and for the fiscal year ended July 31, 2017 for professional services rendered by the principal accountant for the audit of our annual financial statements and review of the financial statements included in our quarterly reports on Form 10-Q and services that are normally provided by the accountant in connection with statutory and regulatory filings or engagements for these fiscal periods were as follows:

Our board of directors pre-approves all services provided by our independent auditors. All of the above services and fees were reviewed and approved by the board of directors either before or after the respective services were rendered.

Our board of directors has considered the nature and amount of fees billed by our independent auditors and believes that the provision of services for activities unrelated to the audit is compatible with maintaining our independent auditors’ independence.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

SIGNATURES

Pursuant to the requirements 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.