MMEX Resources Corp - Annual Report: 2019 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-K

(Mark One)

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

For the fiscal year ended April 30, 2019

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

For the transition period from _______________ to _______________.

Commission file number 333-152608

MMEX RESOURCES CORPORATION

(Exact name of registrant as specified in charter)

Securities registered under Section 12(g) of the Exchange Act: Class A Common Stock, $0.001 par value

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the past 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 x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted 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 such files). Yes x No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and no disclosure will be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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 the 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. o

Indicate by check mark whether the issuer is a shell company (as defined in rule 12b-2 of the Exchange Act). Yes ¨ No x

The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price ($0.185 per share) at October 31, 2018 (the second quarter end date) was approximately $4,491,600.

As of July 26, 2019, there were 271,588,167 shares of the issuer’s Class A common stock outstanding.

A. DOCUMENTS INCORPORATED BY REFERENCE: None

MMEX RESOURCES CORPORATION

TABLE OF CONTENTS TO ANNUAL REPORT ON FORM 10-K

YEAR ENDED APRIL 30, 2019

PART 1

Special Note Regarding Forward-Looking Statements

This Annual Report contains certain forward-looking statements. When used in this Annual Report or in any other presentation, statements which are not historical in nature, including the words “anticipate,” “estimate,” “should,” “expect,” “believe,” “intend,” “may,” “project,” “plan” or “continue,” and similar expressions are intended to identify forward-looking statements. They also include statements containing a projection of revenues, earnings or losses, capital expenditures, dividends, capital structure or other financial terms.

The forward-looking statements in this Annual Report are based upon our management’s beliefs, assumptions and expectations of our future operations and economic performance, taking into account the information currently available to them. These statements are not statements of historical fact. Forward-looking statements involve risks and uncertainties, some of which are not currently known to us that may cause our actual results, performance or financial condition to be materially different from the expectations of future results, performance or financial condition we express or imply in any forward-looking statements. These forward-looking statements are based on our current plans and expectations and are subject to a number of uncertainties and risks that could significantly affect current plans and expectations and our future financial condition and results.

We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this Annual Report might not occur. We qualify any and all of our forward-looking statements entirely by these cautionary factors. As a consequence, current plans, anticipated actions and future financial conditions and results may differ from those expressed in any forward-looking statements made by or on our behalf. You are cautioned not to unduly rely on such forward-looking statements when evaluating the information presented herein.

Item 1: Business

Background of the Company

MMEX Resources Corporation was formed as a Nevada corporation in 2005. The current management team lead an acquisition of the Company (then named Management Energy, Inc.) through a reverse merger completed on September 23, 2010 and changed the Company’s name to MMEX Mining Corporation on February 11, 2011. As of April 12, 2016, the Company changed its name from MMEX Mining Corporation to MMEX Resources Corporation to reflect the change in its business plan to an energy focus in the Americas.

We are a development stage company engaged in the exploration, extraction, refining and distribution of oil, gas, petroleum products and electric power. We plan to focus on the acquisition, development and financing of oil, gas, refining and electric power projects in the Americas using the expertise of our principals to identify, finance and acquire these projects.

The most significant focus of our current business plan is to build crude oil distillation units and refining facilities in the Permian Basin in West Texas (hereinafter referred to as the “Projects”, or the “Distillation Unit” or the “CDU” or the “Refinery”). We intend to implement our current business plan now in several phases, First, through our subsidiary, Pecos Refining, we intend to build and commence operation of one 10,000 bpd crude oil Distillation Unit, now permitted by the TCEQ, that will produce a non-transportation grade diesel primarily for sale in the local market for drilling mud and frac fluids, along with naphtha and residual fuel oil to be sold to other refiners. In additional phases as separate projects we are contemplating building a second and possibly a third CDU with capacity of 10,000 bpd each. A later fourth phase may include the building and operation of the Large Refinery with up to 100,000 bpd capacity in West Texas. We contemplate that these projects will be built on land owned or land being negotiated for purchase by the Company.

INDUSTRY OVERVIEW

Background on Crude Distillation and Refining

Oil refining is the process of separating hydrocarbon molecules present in crude oil and converting them into marketable, finished petroleum products, such as gasoline, diesel fuel, jet fuel, lubricants and petrochemicals. The crude distillation unit is the first phase of the refining process as shown below.

A crude oil refinery is a group of industrial facilities that turns crude oil and other inputs into finished petroleum products. A refinery's capacity refers to the maximum amount of crude oil designed to flow into the distillation unit of a refinery, also known as the crude unit. The diagram above presents a stylized version of the distillation process. Crude oil is made up of a mixture of hydrocarbons, and the distillation process aims to separate this crude oil into broad categories of its component hydrocarbons, or "fractions." Crude oil is first heated and then put into a distillation column, also known as a still, where different products boil off and are recovered at different temperatures. Lighter products, such as butane and other liquid petroleum gases (LPG), gasoline blending components, and naphtha, are recovered at the lowest temperatures. Mid-range products include jet fuel, kerosene, and distillates(such as home heating oil and diesel fuel). The heaviest products such as residual fuel oil are recovered at temperatures sometimes over 1,000 degrees Fahrenheit.

The simplest refineries stop at this point. Although not shown in the simplified diagram above, most refineries in the United States reprocess the heavier fractions into lighter products to maximize the output of the most desirable products using more sophisticated refining equipment such as catalytic crackers, reformers, and cokers.

The Company CDU’s stop with the simple distillation components and will produce intermediate range products of Naphthas, Diesel and Residual Fuel Oil.

Industry Terminology

Crack Spreads

Crack spreads are a proxy for refining margins and refer to the margin that would be derived from the simultaneous purchase of crude oil and the sale of refined petroleum products, in each case at the then-prevailing price. The 2-1-1 crack spread assumes two barrels of crude oil will be converted, or “cracked,” into one barrel of gasoline and one barrel of heating oil or diesel fuel. Average 2-1-1 crack spreads vary from region to region throughout the United States, depending on the supply and demand balances of crude oils and refined products.

Actual refinery margins vary from benchmark crack spreads due to the actual crude oils used and products produced, transportation costs, regional differences and the timing of the purchase of the feedstock and sale of light products.

The Company CDU’s will have a crack spread margin that will be based most likely on the differential between the purchase of the crude oil in the area of operations based on a West Texas Intermediate (“WTI”) Midland posted price and sale price at the CDU plant site prior to sale. Transportation cost is then deducted depending on the contract term, but the crack spread for the Company CDU will be the margin between the purchase price and the sales price at the CDU plant shipping point.

Benchmark Crude Oils

Crude oil pricing is generally quoted in reference to the classification of the crude oil, which is based on certain physical characteristics, the source of its production and the major trading hub with which it is associated. Relevant classifications of crude oil include:

Operating Costs

Major operating costs for refineries include employee labor, maintenance and energy. Employee labor and maintenance are relatively fixed costs that generally increase in proportion to inflation. By far, the predominant variable cost is energy such as natural gas, electricity and refinery fuel gas.

CDUs Location

The CDUs will be located in the Permian Basin of Texas. According to the EIA, between January 2016 and March 2017, oil production in the Permian Basin increased in all but three months, even as domestic crude oil prices fell. As production in other regions fell throughout most of 2015 and 2016, the Permian Basin provided a growing share of U.S. crude oil production.

With rising oil prices over the past several years, the Permian Basin continues to be attractive to drillers, as reflected in rising rig counts. According to the EIA, as of April 21, 2017, the number of rigs in the Permian Basin reached 340, or 40% of the 857 total oil- and natural gas-directed rigs operating in the United States. The Permian Basin rig count reached as high as 568 in late 2014 before falling to a low of 134 in spring 2016 and increasing to 340 in April 2017. According to Baker Hughes, the Permian Basin Rig Count as of July 13, 2018 was 476 active rigs. According to the March 22, 2019 Houston Chronicle “West Texas' booming Permian Basin, which extends into New Mexico, counts 459 rigs all by itself. The Permian makes up 56 percent of all the oil-drilling rigs in the country.”

Recent geological surveys have further explored the resources contained in the Permian Basin. In November 2016, the U.S. Geological Survey (“USGS”) estimated that technically recoverable tight oil and shale gas resources in the Midland Basin portion of Texas’ Permian Basin (specifically the Wolfcamp shale formation) could exceed 20 billion barrels of oil, 16 trillion cubic feet of natural gas, and 1.6 billion barrels of hydrocarbon gas liquids. The technically recoverable resource estimate for tight oil in the Midland Basin portion of the Permian Basin is higher than any previous USGS assessment of tight oil resources in any domestic resource basin.

Source: U.S. Energy Information Administration, U.S. Geological Survey, University of Texas Bureau of Economic Geology, and Drillinginfo.

Oil production growth in the Permian Basin from 2009-2019 increased by 3,200,000 BPD and is projected to increase by another 2,700,000 BPD by 2024.

Source: RBN Energy LLC, Presentation June 6, 2019.

The production from these US shale basins, including the Permian Basin, is predominantly light, sweet crude oil, with gravity in excess of 35 degrees API. As a result, coincident with the growth in crude oil from these shale basins, U.S. imports of light crude oil began declining in 2010.

Outlook for Refining

Recent industry and financial research outline that refining industry fundamentals are more favorable than they have been in a number of years. Morgan Stanley in a recent research report states:

“A tectonic shift is underway on how new capital investments in refining are being thought about, as even good margins in past three years have not been able to attract major investments on concerns of competition from alternative fuels. We believe this divergence from earlier cycles primes up the refinery industry for the golden age. An overlay of new environmental norms, rising global miles driven (cars, airlines) and improving EM growth just makes margin on refining look stronger than ever.”

Morgan Stanley further comments “20 mega-refiners needed to fulfill demand in the time it takes to build one refinery: The global refining sector represents aboveUS$2 trillion in invested capital and ~US$150bn in planned new investments until 2027, on our estimates. It takes an average of 8-10 years to get a new refinery up and running from the drawing board (See Exhibit below). To put the time frame in context, we estimate we need about 20 new mega-refineries to fulfill the world's demand growth in that timeframe, but, based on the current pipeline, only five will be built. This lag creates cycles, and we see ourselves midway through an upcycle, due to the lack of investments in the past five years. While every cycle has its dynamics, what makes the current upcycle different is the lack of new investment committed despite the last three years of strong margins, due to concerns over the long-term shift in global energy demand from renewables and EVs.”

“In Transition to a Golden Age” Morgan Stanley Research May 16, 2018 at 6-7.

To compare the Company CDU project, we project a 3.5-year time from idea to production with the CDU at a cost of approximately $100 Million per CDU.

IMO 2020

The International Maritime Organization (IMO) will enforce a new 0.5% global sulphur cap on fuel content from 1 January 2020, lowering from the present 3.5% limit. The global fuel sulphur cap is part of the IMO's response to the heightening environmental concerns, contributed in part by harmful emissions from ships.

The impact of IMO 2020 will be enormous: industry reports suggest the new rule will require as much as 3 MMb/d of high-sulfur bunker fuel oil to be replaced by low-sulfur alternatives. According to the International Energy Agency's 2018 five-year oil market outlook, about 30% of the new demand for IMO 2020-compliant marine fuel will be met by marine gasoil, a middle distillate designed for ship engines, and another 30% will be met by new 0.5%-sulfur fuel oil blends created from existing 1%-or-less low-sulfur fuels and middle distillates such as ultra-low-sulfur diesel. The remaining 40% of the bunker market is expected to continue using existing high-sulfur fuel blends. Some vessels will use specially installed scrubbers that treat emissions to remove sulfur and other toxins from engine exhaust. A very small number of vessels will be fitted or built to use liquefied natural gas (LNG). Others will simply not comply with the new rule, at least initially, taking the risk that policing on the high seas will be difficult.

“Just Can't Get Enough - IMO 2020 And The Heavy-Sour Crude Shortage

 03/17/2019 Blog , RBN Energy, LLC.

Source: RBN Energy LLC, Presentation June 6, 2019.

The IMO 2020 sulfur regulations are a significant consideration in the Company’s business plan, as we will be producing 28% of the input crude oil as residual fuel oil that is below the 5% sulfur standard. Residual fuel oil has become a highly sought-after product and is the primary mover behind the development of the 2^nd CDU, principally at the recommendation of our proposed Off-taker for the residual. With the first and second unit combined we are planning to deliver by rail approximately 168,000 Bbls per month of IMO 2020 compliant residual fuel oil by 200 rail cars to the Texas Gulf Coast markets identified by our proposed Off-taker.

Current Business Operations and Strategy

The Company’s business plan has evolved into several additional potential components.

The most significant focus of our current business plan is to build crude oil distillation and refining facilities in the Permian Basin in West Texas. We intend to commence operations with a 10,000 bpd Distillation Unit that will produce a non-transportation grade diesel primarily for sale in the local market for drilling mud and frac fluids, along with naphtha and heavy fuel oil to be sold to other refiners.

Additional CDU Opportunities In additional phases as separate projects we are contemplating building a second and possibly a third CDU with capacity of 10,000 bpd each. A later fourth phase may include the building and operation of the Large Refinery with up to 100,000 bpd capacity in West Texas. We contemplate that these projects will be built on land owned or land being negotiated for purchase by the Company. The Company is focusing on the Distillation Unit first in an effort to build and commence operations, and ultimately generate cash flow, on an expedited basis. The permitting process is significantly shorter for construction of the Distillation Unit and the first one was received by the Company on August 30, 2017. We expect the permitting process to be similar for the additional Distillation Units. The permitting process for the Large Refinery, if pursued, is expected to be 12-18 months.

The Company currently estimates that construction costs for the Distillation Unit, inclusive of the potential Crude by Rail (see below), will be approximately $105 million. The second and third unit, if built, is estimated to cost in the range of $75 million each. According to a report the Company received from KP Engineering, the cost of a 50,000- bpd refinery is estimated to be approximately $500 million and the cost of a 100,000-bpd refinery is estimated to be approximately $850 million. These estimates are only preliminary estimates and are subject to substantial change when additional detailed engineering is completed.

These projects will be built on acreage located 20 miles northeast of Fort Stockton, Texas, near the Sulfur Junction spur of the Texas Pacifico Railroad. If successfully developed, the CDUs would connect to existing railways and pipelines to market diesel, gasoline, liquefied petroleum gas and other refined products within the U.S., with the potential to market these products and crude oil to western Mexico and South America. If completed, the Large Refinery will be one of the first full scale oil refineries built in the United States in more than 40 years.

Crude by Rail We are actively considering the inclusion in our Distillation Unit projects of a crude oil storage and dispatch facility (RSD). The RSD facilities will be constructed as part of the CDUs. We propose to charge a per barrel fee to receive, store and dispatch crude oil to the Texas Gulf Coast markets.

Hydrotreater We are also considering adding a distillate hydrotreater component to the two CDUs as a separate project. The distillate hydrotreater is a category of hydrotreaters that treats distillate streams from atmospheric distillation units to reduce their sulfur content and to improve their properties for blending into diesel. This would allow CDU’s to produce transportation grade diesel for the Permian Basin market. We have initiated a preliminary feasibility study. The separate Hydrotreater component, if built, is estimated to cost approximately $25 million

Constructing the CDUs and Hydrotreater will require a significant number of governmental permits and approvals. On August 30, 2017, we received approval from the TCEQ for the air quality permit for the 1^st Distillation Unit. We plan to file for additional permits with TCEQ as may be required. According to VFuels Oil & Gas Engineering, and Saulsbury Industries, our two EPC contractors, the construction for the 1^st Distillation Unit would take approximately 12 to 15 months from the date the Notice to Proceed is issued by the Company, which cannot be issued until the financing is completed. The 2^nd and 3^rd CDU’s will take approximately the same amount of time from the date of the Notice to Proceed, which will be dependent on receiving TCEQ permit approvals and the closing of financing. KP Engineering has estimated that the completion of the Large Refinery would take from 15 to 18 months following the receipt of the air quality permit.

Texas Gulf Coast Terminal and Storage Facilities Transportation and delivery of products by rail has opened up for the Company an opportunity to acquire potentially storage space in existing terminal facilities in the Texas Gulf Coast area with access to water for export of petroleum products including crude oil. We are in active negotiation with terminal owners and potential joint venture partners for the terminal site, the storage tanks and the financing. If built, the Company operated storage facilities on the Texas Gulf Coast will enhance the marketing activities of the Company.

Trading Company The Company is considering a potential joint venture with international partners to begin a physical trading operation of petroleum products into Mexico, Panama and potentially other Central and Latin America locations. If we are successful in implementing the trading opportunities this will add to the Company’s marketing expansion plans.

The cost of construction for all of these components is very significant and we intend to finance 100% of such costs through debt and equity offerings. See “Business—Proposed Organizational Structure.”

Marketing We plan on marketing and distributing refined products in the Texas Gulf Coast, and the Western areas of the United States and Mexico, and we may export product to Latin America. We have signed three off-take agreements with significant balance sheet purchasers. The diesel produced by the Distillation Unit will be marketed and sold locally, primarily for use in drilling mud and frac fluids, and likely transported by truck or by existing railroad systems. If the Hydrotreater is built, the diesel purchaser has indicated that it will purchase all of the transportation grade diesel produced by the 2 CDUs and the Hydrotreater. The ATBs and Naphthas produced by the CDU’s will be marketed and sold to a Super Major International Petroleum and Trading company under two separate signed agreements providing for the right to purchase all additional production. We will deliver these products by rail to the destination points the buyer designates on the Texas Gulf Coast. Our location with rail access from the Texas Pacifico Railroad with interconnections to the Burlington Northern Santa Fe RR, the Union Pacific RR, the Fort Worth and Western RR and the Kansas City Southern RR is a key component to our transportation and market access.

The Projects will be located on the Texas Pacifico Railroad rail route 20 miles Northeast of Fort Stockton, Texas, approximately 1.5 miles from the Sulphur Junction on the Texas Pacifico Railroad. Once needed repairs are finished to the tracks and railway, the Texas Pacifico Railroad will connect to the Ferromex RR in Ojinago, Mexico, giving us access to the western Mexico markets.

The Texas Department of Transportation owns the Texas Pacifico Railroad, which runs from the San Angelo Junction, near Coleman, Texas, to the Texas-Mexico border at Presidio. The Texas Pacifico Railroad entails approximately 371 miles of track and interchanges or has trackage rights with BNSF Railway the Union Pacific Railroad and Fort Worth and Western Railroad, which in turn have interchanges or trackage rights with the Kansas City Southern Railroad. The Texas Pacifico Railroad is operated by Texas Pacifico Transportation LTD, a subsidiary of Grupo Mexico. Our planned Project is located on the Texas Pacifico Railroad rail route approximately 20 miles northeast of Fort Stockton, Texas, approximately 1.5 miles from the Sulphur Junction on the Texas Pacifico Railroad. The Texas Pacifico Railroad will connect to the Ferromex Railroad at Ojinaga, Mexico.

Associated Gas and Liquids Treating Along with the crude oil production in the Permian Basin and the Eagle Ford, tremendous amounts of associated natural gas and natural gas liquids are being produced and without markets, is being flared into the atmosphere allowing producers to continue the crude oil production. It is estimated that 740 million cubic feet per day are being flared, which represents $1.8 million per day cost at current prices. That produces the equivalent green-house gas from 5 million cars driving per day according to the World Bank and the Environmental Protection Agency. The output of gas is projected to increase over 30% in the next five years according to the consultancy RBN Energy. Wall Street Journal July 18, 2019 (Rebecca Elliott)

The Company wants to be able to offer crude oil producers in the Permian Basin, particularly those near our location, a way to process their liquid-rich “associated” gas produced in tandem with the crude oil and the Company has commissioned an engineering consulting firm to present what technologies exist for small-scale, modular natural gas treating close to the wellhead and what the expected capital and operating expenses. We have also asked the consultancy to develop a capital and operating expense estimate to turn the produced gas into diesel fuels via a Fischer-Tropsch facility. Should these processes be economically viable and the Company able to finance and develop them, this may be another very strong business plan addition.

Solar Project We have also commenced initial discussions regarding a solar power project to be located on leased acreage near the Refinery. If successfully financed and completed, we would expect to utilize a portion of the generated power for the Refinery, with the balance to be sold into the Texas grid. There is no assurance that the solar power project will be financed or constructed.

Financing The Company is currently negotiating the financing for the Projects. There is no assurance that the required debt and equity financing for the Projects will be obtained.

Management Expertise in Oil, Gas, Refining and Electric Power Project Development and Project Finance Development

As of 2016, the Board of Directors has decided to focus the Company’s efforts in the oil, gas, refining and electric power business in the U.S. and in Latin America. The principal reasons behind this focus is to capitalize on the experience and expertise of the MMEX management team, its directors and principal stockholders. MMEX management has over 30 years of experience in natural resource project development and project financing in North and South America and the U.K. In addition, MMEX directors and principal stockholders with oil, gas, refining and electric power experience will bring this expertise into the Company.

MMEX principals formed Maple Resources Corporation (“Maple Resources”) in 1986 to engage in the evaluation, acquisition and development of oil & gas, refining, power generation, natural gas transmission and processing energy projects in the western United States and Latin America. Maple Resources and its principals have engaged in a number of oil and gas acquisitions and dispositions and ultimately acquired assets that included 10 gas processing plants and approximately 770 miles of natural gas gathering lines and transmission infrastructure. In 1992, Maple Resources sold substantially all of its existing US-based assets and began to pursue energy projects in Latin America, particularly in Peru through its affiliate The Maple Gas Corporation del Peru Ltd (“Maple Peru”). In 1993, Maple Peru began developing the Aguaytía Project, an integrated natural gas and electric power generation and transmission project. This US$273 million project involved the first commercial development of a natural gas field in Peru, as well as the construction and operation of approximately 175 miles of hydrocarbon pipelines, a gas processing plant, a fractionation facility, a 153 MW power plant and the related 392 km of electricity transmission lines. The Aguaytía Project began commercial operation in 1998. Maple Peru also acquired a 4,000-bpd refinery in Pucallpa along with 3 producing oil fields.

Jack Hanks, our President and CEO, is no longer engaged in the active business operations of Maple Peru and is able to devote substantially all of his business time to his duties on behalf of the Company. Further, we do not anticipate that Maple Resources will present any conflicts of interest for the MMEX principals in carrying out their responsibilities on behalf of the Company.

Proposed Organizational Structure

The Company expects to operate the Projects through its subsidiary, Pecos Refining, and to operate the Large Refinery through another subsidiary set up for such purpose. Currently, Pecos Refining is wholly-owned by the Company and the Company serves as its sole manager. However, the construction of the Distillation Units, Hydrotreater, Terminals, Trading and other components and the Large Refinery will require substantial equity and debt financing, far beyond the expected resources of the Company, and we anticipate that the Subsidiaries will obtain equity and debt financing to finance the cost of construction. To the extent these Subsidiaries raise money through the issuance of equity securities, our ownership in the Subsidiaries will be diluted and our economic ownership of such entities may be a minority interest. As such, we will be entitled to only a portion of any future distributions made by these Subsidiaries. In addition, while intend to retain managerial control of the Subsidiaries, it is possible that equity investors will require representation on the board of managers in connection with their equity investments.

We anticipate these Subsidiaries will be able to finance approximately 65 to 70% of the total costs of the Distillation Units and the Large Refinery through debt financing, and the remaining 35 to 30% of the total costs would be financed through equity investments. We intend to pursue the required debt financing from banks or other large institutional investors. Traditionally, such debt financing is in the form of project financing, which among other terms will require the Subsidiary borrow to restrict its activities to the operation of the project financed by the lender, to pledge all assets of the project to the lender and to be subject to restrictive financial covenants. Such lenders further typically require engineering, marketing and feasibility studies as a condition precedent to the financing. In order to attract the significant capital necessary to build the Refinery, the Company will have to fund the cost of these reports and studies, likely out of equity raises. We have estimated that such cost will aggregate approximately $500,000.

Location and Logistics

The Refinery will be located in the Permian Basin, which holds some of the largest tapped and untapped oil and gas reserves in the world. The Permian Basis is located principally in West Texas. While production in the Permian Basin in the past had been in decline, the development of hydraulic fracturing in shale zones reversed the trend, and the cost of developing oil and gas reserves from shale formations (the driver of recent US increases in production) is lower in the Permian Basin than in other areas of the US. For this reason, the activity in the Permian Basin has recently been expanding and drawing the interest of major oil and gas companies. We believe that the Permian Basin will be the major domestic producing region in the country for decades to come.

The Projects will be located 20 miles northeast of Fort Stockton, Texas, near the Sulfur Junction spur of the Texas Pacifico Railroad and in the Permian Basin. The currently owned site consists of 126 acres and another 119 acres is under contract and the rail line runs through a corner of the owned property.

There are six refineries in the Permian Basin located at El Paso, Texas; McKee, Texas; Borger, Texas; Big Spring, Texas; and Artesia, New Mexico. The total capacity of these refineries is 640,500 bpd. These refineries are older refineries designed to process historic production from the Permian Basin. As such, these refineries do not take high-API production or discount it significantly, such as the production being produced from the hydraulically-fractured shale zones in which the current increase in production is occurring in the Permian Basin. Moreover, the increasing amount of shale oil production has outpaced these refineries’ ability to process the new crude oil production. For these reasons, much of the new shale production is currently being exported out of the Permian Basin. Significant infrastructure improvements have been developed and announced to move Permian Basin production to the Texas Gulf Coast. According to the EIA, these infrastructure improvements have and will decrease the discount to WTI pricing that has often plagued the sale of Permian Basin shale crude in the recent past. The Company believes that while the construction of crude oil pipelines from the Permian Basin to the significant refining infrastructure in the Texas Gulf Coast will and have decreased discounts, trucking and pipeline companies will charge fees to transport the new shale production out of the Permian Basin, resulting, in effect, in a continued discount for such production, compared to the delivered price to our Projects.

The Projects will be located near the major producing shale areas of the Permian Basin in Reeves and Pecos counties. The estimates of crude production and potential production from “drilled uncompleted” wells in our area far exceed the 20,000 BPD capacity of the proposed two CDU’s (see below). The crude oil purchase offers are subject to substantial conditions and there is no assurance that the purchase arrangements can be successfully implemented. But the Company believes there are a number of alternative means of delivering the ever-increasing supply of oil shale production from the Permian Basin to the Refinery site, whether by truck, construction of gathering pipelines by another company or by rail. There are 4,002 Drilled Uncompleted ("DUCs") wells in the Permian Basin according to the EIA Drilling Productivity Report, DUC Wells by Region, July 15, 2019.

Source: Drilling Info and Energy Services Data Link

Transportation

We will likely be transporting refined products primarily by rail. Both the U.S. Department of Transportation and its agency, the Federal Railroad Administration, have issued regulations pertaining to the shipment of crude oil and refined products. In addition, TxDOT has its own set of regulations pertaining to these matters, and Mexico will have additional regulations governing the transport of refined products and crude oil. As part of the construction of the Refinery, we will develop procedures and policies in connection with our shipping partners and buyers to comply with all relevant regulations.

We intend to transport the diesel production from our Distillation Unit by truck or by existing railroad systems within the Permian Basin for use in drilling fracking markets. We intend to transport other of our refined products, principally ATBs and naphtha, to other refineries, primarily in the Port Arthur, Beaumont, Houston and Corpus Christi, Texas areas, by pipeline and existing railroad systems for further processing.

TxDOT owns the Texas Pacifico Railroad, which runs from the San Angelo Junction, near Coleman, Texas, to the Texas-Mexico border at Presidio. The Texas Pacifico Railroad entails approximately 371 miles of track and interchanges with BNSF Railway, the Union Pacific Railroad and Fort Worth and Western Railroad, which in turn connects into the Kansas City Southern Railroad. The Texas Pacifico Railroad is operated by Texas Pacifico Transportation LTD, a subsidiary of Grupo Mexico. Our planned Projects are located on the Texas Pacifico Railroad rail route approximately 20 miles northeast of Fort Stockton, Texas, approximately 1.5 miles from the Sulphur Junction on the Texas Pacifico Railroad. The Texas Pacifico Railroad will connect to the Ferromex Railroad at Ojinaga, Mexico.

We plan to transport refined product on the Texas Pacifico Railroad and significant investments are required to upgrade the railroad. TxDOT owns the Texas Pacifico Railroad, which runs from the San Angelo Junction, near Coleman, Texas, to the Texas-Mexico border at Presidio. There are two significant infrastructure improvement projects that TxDOT must be complete before we will be able to use the Texas Pacifico Railroad to transport our production to Mexico as we have planned.

The international railroad bridge, located at the southwestern end of the rail line connecting Presidio, TX to Ojinaga, Mexico burned on two separate occasions, February 29, 2008 and March 1, 2009. TxDOT and Texas Pacifico Transportation LTD, the company that operates the Texas Pacifico Railroad, has rebuilt the bridge allowing access to Mexico and increased business potential. On August 4, 2017, Tx DOT announced a $7 million federal grant from The U.S. Department of Transportation to strengthen existing rail infrastructure in Permian Basin. As announced on August 4, the funds were used to rebuild the Presidio-Ojinaga International Rail Bridge and 72 miles of track on the South Orient Rail Line that run from the Mexico border to near Coleman, Texas owned by the state of Texas but maintained and operated by Texas Pacifico Transportation, Ltd. under a lease with TxDOT.

In addition, the railroad track between Alpine and Presidio may be upgraded as traffic requires through the area. The upgrade capital improvements required on the Texas Pacifico Railroad to transport significant volumes of traffic are estimated by TxDOT to be in the range of $100 million to $150 million. Our ultimate business plan to market refined products into Western Mexico and to export refined products to Latin America will depend upon the capital investment on the Texas Pacifico Railroad. There is no assurance that these capital improvements will be made. If these capital improvements are not made, our business prospects for Mexico exports on the TXPF could be materially negatively impacted. The funding by TxDOT and Texas Pacifico/Ferromex for the completion of the international bridge at Presidio/Ojinaga, which has now occurred, is a very positive sign that upgrades to the Texas Pacifico line from Fort Stockton to Presidio are to follow the freight traffic commitments to and from Mexico-otherwise it becomes a “bridge to nowhere”.

The Company business plan may also include marketing diesel, gasoline and other refined products in the western areas of Mexico and to transport those products along Grupo Mexico’s/Ferromex rail lines to the Mexican port of Topolobampo located on the Gulf of Mexico for export to Latin America. This business plan depends on the completion of the track upgrades and the completion of the bridge at Presidio/Ojinaga. The Company believes that the market exists in Western Mexico and in Latin America for the refined products that it plans to ship, but it has no arrangements currently in place to market and sell its products in those areas.

With the proposed Company terminal and storage facilities and the trading company operations, the Company will have additional rail and ship/barge access to eastern Mexico areas and to other Latin America destinations from the Texas Gulf Coast. The Company believes that the market exists in Eastern Mexico and in Latin America for the refined products that it plans to ship, but it has no arrangements currently in place to market and sell its products in those areas.

Construction of the Projects

The Distillation Units would cover approximately 15 acres each of the 126 acres property which is owned. The Company is under contract to purchase an additional 119 acres. One or more of the CDU’s and the rail facilities are planned for both properties. The Large Refinery, if built, would cover approximately 250 acres which is not owned currently. Before construction of any of the Projects can commence, the Company must obtain all required permits. Constructing of the Projects will require a significant number of governmental permits and approvals. The principal permit for the construction of the Projects is the air quality permit issued by TCEQ and significant construction will not begin until we have received it. On August 30, 2017, we received approval from the TCEQ for the air quality permit for the 1^st Distillation Unit. Trinity Consultants, the Company’s air quality permit advisor, estimates it will take approximately 15 to 18 months to obtain the air quality permit for the Large Refinery, once filed. The other principal permits for the Projects that will be required are the following:

We have not yet filed for any of the foregoing permits.

The Company has hired VFuels Oil & Gas Engineering and Saulsbury Industries (the “EPCs”) with respect to the construction of the 1^st CDU. The total indicated cost estimate including continencies and owner costs plus or minus 10% is $105 Million for the 1^st CDU. Once we close on the financing and issue the notice to proceed, the completion and start-up date guaranteed by the EPCs is 15 months. We expect the 2^nd CDU to be less in cost than the 1^st CDU and the Hydrotreater capex to be in the range of $25,000,000. The total indicated cost of the 1^st CDU, the 2^nd CDU and the Hydrotreater is in the range of $200 million.

The Company has hired KP Engineering to advise it with respect to the construction of the Refinery. KP Engineering has prepared a preliminary report regarding the estimated cost and time-line for construction of the Refinery. KP Engineering has estimated the cost of a 50,000-bpd refinery to be approximately $500 million and the cost of a 100,000 bpd refinery to be approximately $850 million. These estimates are only preliminary estimates and are subject to substantial change when additional engineering is completed. KP Engineering has estimated that the completion of the Large Refinery would take from 15 to 18 months following the receipt of the air quality permit.

Building a complex refinery is a costly and time-consuming process. The preliminary report from KP Engineering must be followed by other detailed engineering reports. But these reports are all essential to the financing of the construction and development of the Refinery.

Employees

As of April 30, 2019, we had no employees and our executive officer, and our two directors had not received any compensation. We contract for all professional services when needed.

Legal Proceedings

There are no legal proceedings against the Company.

Environmental Regulations Pertaining to Refinery Operations.

The operations of the Refinery will be subject to complex and frequently-changing federal, state, and local laws and regulations relating to the protection of health and the environment, including laws and regulations that govern the handling and release of crude oil and other liquid hydrocarbon materials. As with the industry generally, compliance with existing and anticipated environmental laws and regulations increases our overall cost of business, including our capital costs to construct, maintain, operate, and upgrade equipment and facilities. While these laws and regulations affect our maintenance, capital expenditures and net income, we do not believe they affect our competitive position, as the operations of our competitors are similarly affected. Violations of environmental laws or regulations can result in the imposition of significant administrative, civil and criminal fines and penalties and, in some instances, injunctions banning or delaying certain activities. We will adopt policies and procedures to ensure compliance with applicable environmental laws and regulations. However, these laws and regulations are subject to frequent change at the federal, state and local levels, and the legislative and regulatory trend has been to place increasingly stringent limitations on activities that may affect the environment.

Clean Air Act.

The environmental laws and regulations applicable to the Refinery include permitting and monitoring activities relating to air emissions under the federal Clean Air Act, and its implementing regulations, as well as comparable state and local statutes and regulations. Failure to comply with these rules can result in severe penalties and potential shut down of facilities. We will be required to develop policies and procedures to comply with all these laws and regulations.

Greenhouse Gas Emissions.

Various legislative and regulatory measures to address greenhouse gas (“GHG”) emissions, including carbon dioxide and methane emissions, are in different phases of implementation and discussion. At the federal legislative level, both houses of Congress have considered legislation to reduce GHG emissions, including proposals to: (i) establish a cap-and-trade system, (ii) create a federal renewable or “clean” energy standard requiring electric utilities to provide a certain percentage of power from such sources, and (iii) create enhanced incentives for use of renewable energy and increased energy efficiency in energy supply and use. A number of states, both individually and on a regional basis, have adopted measures to reduce carbon dioxide and other GHG emissions, including statewide GHG inventories and regional GHG cap-and-trade initiatives. The EPA has also begun to regulate GHG emissions under the authority granted to it by the federal Clean Air Act. The EPA has adopted regulations limiting emissions of GHGs from motor vehicles, addressing the permitting of GHG emissions from stationary sources, and requiring the reporting of GHG emissions from specified large GHG emission sources, including petroleum refineries. The implementation of EPA regulations could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any GHG emissions program. Increased costs associated with compliance with any current or future legislation or regulation of GHG emissions, if it occurs, may have a material adverse effect on our financial condition, results of operations and cash flows. In addition, climate change legislation and regulations may result in increased costs not only for our business but also for our customers, thereby potentially decreasing demand for our products and services. Decreased demand for our products and services may have a material adverse effect on our financial condition, results of operations and cash flows.

Release of Hazardous Substances.

Environmental laws and regulations affecting our operations also relate to the release of hazardous substances or solid wastes into the soil, groundwater, and surface water, and include measures to control pollution of the environment. These laws generally regulate the generation, storage, treatment, transportation, and disposal of solid and hazardous waste. They also require corrective action, including investigation and remediation, at a facility where such waste may have been released or disposed. There are risks of accidental releases into the environment associated with our operations, such as releases of crude oil or hazardous substances from our pipelines or storage facilities. To the extent an event is not covered by our insurance policies, accidental releases could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage, and fines or penalties for any related violations of environmental laws or regulations.

CERCLA.

The Refinery property and any wastes disposed therefrom may be subject to the federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the federal Resource Conservation and Recovery Act, and comparable Texas state laws. CERCLA and comparable state laws may impose liability without regard to fault or the legality of the original conduct on certain classes of persons regarding the presence or release of a hazardous substance in (or into) the environment, which may include the disposal of wastes generated by the Refinery, even if the wastes are taken from the Refinery by others and disposed by them. We will develop procedures and policies to ensure compliance with these laws.

Our operations may potentially result in the discharge of regulated substances, including crude oil, refined products, or natural gas liquids. The federal Clean Air Act and comparable state laws impose restrictions and strict controls regarding the discharge of regulated substances into waters of the United States or state waters. We will develop policies and procedures to ensure compliance with these rules.

Renewable Identification Numbers.

In 2007, the EPA promulgated the Renewable Fuel Standard (“RFS”), which requires refiners to blend “renewable fuels” in with their transportation fuels or purchase renewable fuel credits, known as renewable identification numbers (“RINs”), in lieu of blending. Under the Clean Air Act the EPA is required to determine and publish the applicable annual renewable fuel percentage standards for each compliance year by November 30 of the prior year. However, the EPA has repeatedly missed that deadline. The percentage standards represent the ratio of renewable fuel volume to gasoline and diesel volume. For all domestically-sold gasoline and diesel fuels we produce at the Refinery, we will be required to blend renewable fuels into our gasoline and diesel fuel or purchase RINs in lieu of blending. The Refinery intends to purchase RINs on the open market or waiver credits from the EPA to comply with the RFS. While we cannot predict the future prices of RINs or waiver credits, the price of RINs can be extremely volatile. RINs will constitute a genuinely significant cost of operations for the Refinery relative to domestically-sold gasoline and diesel, which is why we intend to export gasoline and diesel to the fullest extent possible.

If the Refinery’s gasoline or diesel is sold domestically, we and other similarly-situated refiners may become more reliant on the purchase of RINs and waiver credits on the open market to comply with the RFS in the future. The cost of RINs is dependent upon a variety of factors, which include the volume mandates set by EPA, the availability of RINs for purchase, the price at which RINs can be purchased, transportation fuel production levels and the mix of our petroleum products, all of which can vary significantly from quarter to quarter. In addition, numerous instances of fraudulent RINs being made available on the market have led EPA to impose penalties on RIN purchasers, even those with no knowledge of the fraudulent nature of the RINs. If we purchase invalid RINs, or fail to properly keep records in accordance with EPA’s rules and regulations, we could be subject to fines and penalties.

Safety, Security and Insurance Concerns in Operating Refineries.

The Refinery will be subject to the Department of Homeland Security’s Chemical Facility Anti-Terrorism Standards, which are designed to regulate the security of high-risk chemical facilities, and to the Transportation Security Administration’s Pipeline Security Guidelines and Transportation Worker Identification Credential program. We will have to have an internal program of inspection designed to monitor and enforce compliance with all of these requirements, and we will need to develop a Facility Security Plan as required under the relevant law. We will also have to have in place procedures to monitor compliance with all applicable laws and regulations regarding the security of all our facilities.

The Refinery will also be subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens. We will also be subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. We will take measures to ensure that our operations are in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances.

Item 1A: Risk Factors

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

Item 1B: Unresolved Staff Comments.

None.

Item 2: Properties.

Our executive offices are located at 3616 Far West Blvd. #117-321, Austin, Texas 78731. We also maintain a satellite office in Fort Stockton, Texas near the site of our refinery project.

On July 28, 2017, we acquired the 126-acre parcel of the land, which is the site for our planned Distillation Unit, at a purchase price of $550 per acre, or $67,088. We continue to negotiate with the seller of the property to acquire an additional 119-acre parcel.

Item 3: Legal Proceedings.

None.

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

Since April 10, 2018, our Class A common stock has been listed on the OTC Pink under the symbol "MMEX". The OTC Market is a network of security dealers who buy and sell stock. The dealers are connected by a computer network that provides information on current “bids” and “asks”, as well as volume information. From November 2, 2017 through April 9, 2018, our Class A common stock was listed on the OTCQB and prior to November 2, 2017, our Class A common stock was quoted on the OTC Pink tier. The following table indicates the quarterly high and low bid price for our Class A common stock for the fiscal years ending April 30, 2019 and 2018. Such inter-dealer quotations do not necessarily represent actual transactions and do not reflect retail mark-ups, mark-downs or commissions. On September 14, 2018, the Company amended its articles of incorporation to provide for a 1 for 100 reverse stock split of our Class A and Class B common shares. The Company has given retroactive effect to the reverse stock split for all periods presented.

On July 24, 2019, the closing bid price of the Common Stock as reported on the OTC Pink was $.0011.

The number of holders of record of the Company's common stock as of April 30, 2019 was 157 as reported by our transfer agent. This number does not include an undetermined number of stockholders whose stock is held in "street" or "nominee" name.

We have not declared or paid any cash or other dividends on the Common Stock to date for the last two (2) fiscal years and have no intention of doing so in the foreseeable future.

We did not repurchase any of our equity securities during the fourth quarter of fiscal 2019.

Recent Sales of Unregistered Securities not previously reported in the Company's Form 10-Q

During the fourth quarter ended April 30, 2019, we issued a total of 15,680,450 unregistered shares of our Class A common stock: 273,552 shares for services valued at $11,121 and 15,406,898 shares for conversion of debt valued at $280,408.

Outstanding Equity Awards at Fiscal Year-End

(1) Consists of warrants to purchase 1,789,293 Class A common shares, options to purchase 1,000,000 Class A common shares and 1,000,000 Class B common shares.

Penny Stock

Our stock is considered to be a penny stock. The SEC has adopted rules that regulate broker-dealer practices in connection with transactions in penny stocks. Penny stocks are generally equity securities with a market price of less than $5.00, other than securities registered on certain national securities exchanges or quoted on the NASDAQ system, provided that current price and volume information with respect to transactions in such securities is provided by the exchange or system. The penny stock rules require a broker-dealer, prior to a transaction in a penny stock, to deliver a standardized risk disclosure document prepared by the SEC, that: (a) contains a description of the nature and level of risk in the market for penny stocks in both public offerings and secondary trading; (b) contains a description of the broker’s or dealer’s duties to the customer and of the rights and remedies available to the customer with respect to a violation of such duties or other requirements of the securities laws; (c) contains a brief, clear, narrative description of a dealer market, including bid and ask prices for penny stocks and the significance of the spread between the bid and ask price; (d) contains a toll-free telephone number for inquiries on disciplinary actions; (e) defines significant terms in the disclosure document or in the conduct of trading in penny stocks; and (f) contains such other information and is in such form, including language, type size and format, as the SEC shall require by rule or regulation.

The broker-dealer also must provide, prior to effecting any transaction in a penny stock, the customer with: (a) bid and offer quotations for the penny stock; (b) the compensation of the broker-dealer and its salesperson in the transaction; (c) the number of shares to which such bid and ask prices apply, or other comparable information relating to the depth and liquidity of the market for such stock; and (d) a monthly account statement showing the market value of each penny stock held in the customer’s account. In addition, the penny stock rules require that prior to a transaction in a penny stock not otherwise exempt from those 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 acknowledgment of the receipt of a risk disclosure statement, a written agreement as to transactions involving penny stocks, and a signed and dated copy of a written suitability statement.

These disclosure requirements may have the effect of reducing the trading activity for our common stock. Therefore, stockholders may have difficulty selling our securities.

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

Our discussion includes forward-looking statements based upon current expectations that involve risks and uncertainties, such as our plans, objectives, expectations and intentions. Actual results and the timing of events could differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including those set forth under Special Note Regarding Forward-Looking Statements and Business sections in this Annual Report. We use words such as “anticipate,” “estimate,” “plan,” “project,” “continuing,” “ongoing,” “expect,” “believe,” “intend,” “may,” “will,” “should,” “could,” and similar expressions to identify forward-looking statements.

The following discussion and analysis constitutes forward-looking statements for purposes of the Securities Act and the Exchange Act and as such involves known and unknown risks, uncertainties and other factors which may cause our actual results, performance or achievements to be materially different from future results, performance or achievements expressed or implied by such forward-looking statements. The words “expect”, “estimate”, “anticipate”, “predict”, “believes”, “plan”, “seek”, “objective” and similar expressions are intended to identify forward-looking statements or elsewhere in this report. Important factors that could cause our actual results, performance or achievement to differ materially from our expectations are discussed in detail in Item 1 above. All written or oral forward-looking statements attributable to us are expressly qualified in their entirety by such factors. We undertake no obligation to publicly release the result of any revisions to these forward-looking statements that may be made to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events. Notwithstanding the foregoing, we are not entitled to rely on the safe harbor for forward looking statements under 27A of the Securities Act or 21E of the Exchange Act as long as our stock is classified as a penny stock within the meaning of Rule 3a51-1 of the Exchange Act. A penny stock is generally defined to be any equity security that has a market price (as defined in Rule 3a51-1) of less than $5.00 per share, subject to certain exceptions.

The following discussion should be read in conjunction with the Consolidated Financial Statements, including the notes thereto.

Overview

Business Plan

MMEX Resources Corporation was formed as a Nevada corporation in 2005. The current management team lead an acquisition of the Company (then named Management Energy, Inc.) through a reverse merger completed on September 23, 2010 and changed the Company’s name to MMEX Mining Corporation on February 11, 2011. As of April 12, 2016, the Company changed its name from MMEX Mining Corporation to MMEX Resources Corporation to reflect the change in its business plan to an energy focus in the Americas.

We are a development stage company engaged in the exploration, extraction, refining and distribution of oil, gas, petroleum products and electric power. We plan to focus on the acquisition, development and financing of oil, gas, refining and electric power projects in the Americas using the expertise of our principals to identify, finance and acquire these projects.

The most significant focus of our current business plan is to build crude oil distillation and refining facilities in the Permian Basin in West Texas. We intend to implement our current business plan now in several phases, First, through our subsidiary, Pecos Refining, we intend to build and commence operation of one 10,000 bpd crude oil Distillation Unit, now permitted by the TCEQ, that will produce a non-transportation grade diesel primarily for sale in the local market for drilling mud and frac fluids, along with naphtha and residual fuel oil to be sold to other refiners. In additional phases as separate projects we are contemplating building a second and possibly a third CDU with capacity of 10,000 bpd each. A later fourth phase may include the building and operation of the Large Refinery with up to 100,000 bpd capacity in West Texas. We contemplate that these projects will be built on land owned or land being negotiated for purchase by the Company.

Initially, Pecos Refining, the owner of the 1^st Distillation Unit, and the other entities we may form to own and operate the 2^nd and 3^rd Distillation Units, the Hydrotreater and the Large Refinery will be wholly-owned subsidiaries of the Company. However, the construction of the Distillation Units, Hydrotreater and the Large Refinery will require substantial equity and debt financing, far beyond the expected resources of the Company, and we anticipate that these Subsidiaries will obtain equity and debt financing to finance the cost of construction. We anticipate these Subsidiaries will be able to finance approximately 65 to 70% of the total costs of the Distillation Units and the Large Refinery through debt financing, and the remaining 35 to 30% of the total costs would be financed through equity investments. To the extent these Subsidiaries raise money through the issuance of equity securities, our ownership will be diluted. We intend to retain managerial control of the Subsidiaries; however, our economic ownership of such entities may be a minority interest. As such, we will be entitled to only a portion of any future distributions made by these Subsidiaries.

We plan on marketing and distributing refined products in the Western areas of the United States and Mexico, and we may export product to Latin America. The Projects will be located on the Texas Pacifico Railroad rail route 20 miles Northeast of Fort Stockton, Texas, approximately 1.5 miles from the Sulphur Junction on the Texas Pacifico Railroad. Once needed repairs are finished to the tracks and railway, the Texas Pacifico Railroad will connect to the Ferromex RR in Ojinago, Mexico, giving us access to the western Mexico markets.

The Company has hired VFuels Oil & Gas Engineering and Saulsbury Industries (the “EPCs”) with respect to the construction of the 1^st CDU. The total indicated cost estimate including continencies and owner costs plus or minus 10% is $105 Million for the 1^st CDU. Once we close on the financing and issue the notice to proceed, the completion and start-up date guaranteed by the EPCs is 15 months. We expect the 2^nd CDU to be less in cost than the 1^st CDU and the Hydrotreater capex to be in the range of $25,000,000. The total indicated cost of the 1^st CDU, the 2^nd CDU and the Hydrotreater is in the range of $200 million.

According to a report the Company received from KP Engineering, the cost of a 50,000-bpd refinery is estimated to be approximately $500 million and the cost of a 100,000-bpd refinery is estimated to be approximately $850 million. These estimates are only preliminary estimates and are subject to substantial change when additional engineering is completed.

Constructing the Projects will require a significant number of governmental permits and approvals. The principal permit for the construction of any of the Projects is the Air Permit issued by TCEQ and significant construction will not begin until we have received the Air Permit. The Company has received the Air Permit for the 1^st Distillation Unit. Once the permit is filed for the, it may take approximately 18 months to obtain the Air Permit for the Large Refinery.

Through April 30, 2019, we have had no revenues and have reported continuing losses from operations.

Results of Operations

We recorded a net loss of $3,986,830 or $(0.13) per share, for the fiscal year ended April 30, 2019, compared to net income of $2,229,620, or $0.00 per share, for the fiscal year ended April 30, 2018. As discussed below, the net income or loss for any fiscal year fluctuates materially due to non-operating gains and losses.

Revenues

We have not yet begun to generate revenues.

General and Administrative Expenses

Our general and administrative expenses increased $214,698 to $1,331,096 for the year ended April 30, 2019 from $1,116,398 for the year ended April 30, 2018. The increase is due to additional professional fees, salaries, travel and other expenses associated with securing debt financing, administrative activities of our proposed refinery project.

Refinery Start-Up Costs

During the year ended April 30, 2019, the expenditures for the development of our proposed crude oil refinery in Pecos County, Texas decreased from the prior fiscal year due to financing constraints. We expense all costs incurred prior to opening the refinery, including acquisition of refinery rights, planning, design and permitting. Such costs totaled $531,983 and $828,609 for the years ended April 30, 2019 and 2018, respectively.

Depreciation and Amortization Expense

Our depreciation and amortization expenses increased to $30,914 for the year ended April 30, 2019 from $1,851 for the year ended April 30, 2018. The increase in the current year is due to depreciation of refinery land improvements and amortization of refinery land easements.

Other Income (Expense)

Our interest expense increased $48,327 to $1,976,307 for the year ended April 30, 2019 from $1,927,980 for the year ended April 30, 2018. The increase in interest expense is due to interest accrued on an increased level of convertible debt during the current fiscal year, including amortization of debt discount.

For the year ended April 30, 2019, we reported a loss on derivative liabilities of $128,860. For the year ended April 30, 2018, we reported a gain on derivative liabilities of $4,604,471. The gain on derivative liabilities in the prior fiscal year resulted primarily from the exercise of substantially all warrants.

In a series of subscription agreements, we have issued warrants that contain certain anti-dilution provisions that we have identified as derivatives. We also identified the variable conversion feature of certain convertible notes payable as derivatives. We estimate the fair value of the derivatives using multinomial lattice models that value the warrants based on a probability weighted cash flow model using projections of the various potential outcomes. These estimates are based on multiple inputs, including the market price of our stock, interest rates, our stock price volatility and management’s estimates of various potential equity financing transactions. These inputs are subject to significant changes from period to period and to management's judgment; therefore, the estimated fair value of the derivative liabilities will fluctuate from period to period, and the fluctuation may be material.

We reported a gain on extinguishment of debt of $14,239 for the year ended April 30, 2019 compared to a gain on extinguishment of debt of $409,716 for the year ended April 30, 2018. The gain on extinguishment of debt generally results from the settlement and extinguishment of convertible notes payable, preferred stock and certain accounts payable and accrued expenses. Where shares of our Class A common stock are issued in extinguishment of debt, we record the value of the shares issued at the current market price, which at times differs from the book value of the debt extinguished, resulting in a gain or loss on extinguishment of debt.

For the year ended April 30, 2019, we reported a loss on conversion of debt to common stock of $1,909. We had no gain or loss on conversion of debt for the year ended April 30, 2018.

We reported a gain on assignment and assumption agreement of $1,090,271 for the year ended April 30, 2018. On September 18, 2017, the Company, the members of LatAm and William B. Short (“Short”), an unrelated individual, entered into an Assignment and Assumption Agreement pursuant to which Short acquired the member interests in LatAm, thereby acquiring all the assets and assuming all the liabilities of MCCH, MCC and CC. Short agreed to assume all liabilities and hold the Company harmless from any and all liabilities (contingent or otherwise). In consideration therefor, we issued Short 10,000,000 shares of Class A common stock, valued at $110,000, or $0.011 per share, equal to the market value of the stock on the date of the agreement, which amount was recorded as a reduction of the gain on Assignment and Assumption Agreement. We did not have similar gain for the year ended April 30, 2019.

Net Income (Loss)

As a result of the above, we reported a net loss of $3,386,830 for the year ended April 30, 2019. For the year ended April 30, 2018, we reported net income of $2,229,620.

Non-Controlling Interest in (Income) Loss of Consolidated Subsidiaries

We had no non-controlling interest in net income or loss of consolidated subsidiaries for the year ended April 30, 2019 due to no activity in the consolidated subsidiaries. Non-controlling interest in income of consolidated subsidiaries was $388,314 for the year ended April 30, 2018 resulting primarily from elimination of the accounts of MCCH, MCC and CC pursuant to an Assignment and Assumption Agreement entered into on September 18, 2017.

Net Loss Attributable to the Company

Net loss attributable to the Company was the same as net loss of $3,986,830 for the year ended April 30, 2019. Net income attributable to the Company was $1,841,306 for the year ended April 30, 2018.

Liquidity and Capital Resources

Working Capital

As of April 30, 2019, we had current assets of $94,137, comprised of cash of $55,188 and prepaid expenses and other current assets of $38,949, and current liabilities of $3,813,739, resulting in a working capital deficit of $3,719,602. Included in our current liabilities as of April 30, 2019 are derivative liabilities of $1,825,596, which we do not anticipate will require the payment of cash.

Sources and Uses of Cash

Our sources and uses of cash for the years ended April 30, 2019 and 2018 were as follows:

We used net cash of $1,934,078 in operating activities for the year ended April 30, 2019 as a result of net loss attributable to the Company of $3,986,830, non-cash gain of $14,239, increase in prepaid expenses and other current assets of $33,949 and decrease in accounts payable of $1,880, partially offset by non-cash expenses totaling $1,948,042 and an increase in accrued expenses of $154,778.

In comparison, we used net cash of $1,563,091 in operating activities for the year ended April 30, 2018 as a result of net income attributable to the Company of $1,841,306, non-controlling interest in income of consolidated subsidiaries of $388,314, non-cash expenses totaling $2,070,953 and increases in accounts payable of $127,890 and accrued expenses of $118,804, offset by non-cash gains totaling $6,104,458 and increases in prepaid expenses and other current assets of $5,000 and deposits of $900.

Net cash used in investing activities was $260,812 and $303,120 for the years ended April 30, 2019 and 2018, respectively, comprised on the purchase of property and equipment.

Net cash provided by financing activities was $1,945,905 for the year ended April 30, 2019, comprised of net proceeds from convertible notes payable of $2,032,653 and proceeds from the issuance of common stock of $116,252, partially offset by repayments of convertible notes payable of $203,000.

By comparison, we had net cash provided by financing activities of $2,115,871 for the year ended April 30, 2018, comprised of net proceeds from convertible notes payable of $1,831,500 and proceeds from the issuance of common stock of $284,371.

Going Concern Uncertainty

Our financial statements are prepared using accounting principles generally accepted in the United States of America applicable to a going concern, which contemplate the realization of assets and liquidation of liabilities in the normal course of business. We have incurred continuous losses from operations, have an accumulated deficit of $39,064,118 and a total stockholders’ deficit of $3,363,675 at April 30, 2019, and have reported negative cash flows from operations since inception. In addition, we do not currently have the cash resources to meet our operating commitments for the next twelve months, and we expect to have ongoing requirements for capital investment to implement our business plan, including the construction of our proposed refinery project. Finally, our ability to continue as a going concern must be considered in light of the problems, expenses and complications frequently encountered by entrance into established markets and the competitive environment in which we operate.

Since inception, our operations have primarily been funded through private debt and equity financing, as well as capital contributions by our subsidiaries' partners, and we expect to continue to seek additional funding through private or public equity and debt financing.

Our ability to continue as a going concern is dependent on our ability to generate sufficient cash from operations to meet our cash needs and/or to raise funds to finance ongoing operations and repay debt. However, there can be no assurance that we will be successful in our efforts to raise additional debt or equity capital and/or that our cash generated by our operations will be adequate to meet our needs. These factors, among others, raise substantial doubt that we may be able to continue as a going concern for a reasonable period of time.

The financial statements do not include any adjustments that might result from the outcome of any uncertainty as to the Company's ability to continue as a going concern. The financial statements also do not include any adjustments relating to the recoverability and classification of recorded asset amounts or amounts and classifications of liabilities that might be necessary should the Company be unable to continue as a going concern.

Capital Resources

We have not generated any revenues or operating cash flows. As a result, we have significant short-term cash needs. Our principal source of operating capital has been provided from private sales of our common stock and warrants and convertible debt financing.

During the year ended April 30, 2019, we issued an aggregate of $2,302,600 principal amount of convertible notes resulting in net proceeds to us of $2,032,653. The notes are due and payable on various dates through October 16, 2020 and bear interest at rates ranging from 8% to 12%. The notes are convertible into shares of our Class A common stock at a discount from the lowest price during certain measurement periods prior to the date of conversion. In order to redeem the notes, we will be required to pay redemption premiums that range from 18% to 50% of the principal amounts of the notes, depending upon the date of redemption. The notes also contain penalty provisions in the event of our default in repayment of the notes (if not converted by the holder into shares of common stock) on the first anniversary after issuance. See Note 8 to our financial statements for a detail description of each note issued during the year ended April 30, 2019. During the year ended April 30, 2019, $1,210,304 total principal of convertible notes was converted into shares of our Class A common stock.

On June 12, 2017, the Company entered into an Equity Purchase Agreement with Crown Bridge Partners, LLC (“Crown Bridge”). The Equity Purchase Agreement allowed the Company to deliver a put notice to Crown Bridge stating the dollar amount of common stock that it intends to sell to Crown Bridge on the date specified in the put notice. The amount of each put notice is limited to a formula that is equal to the lesser of (i) $100,000 or (ii) 150% of the average dollar value of the trading volume of the Company’s stock, measured at the lowest price during the trading period, for the seven days prior to the purchase of shares by Crown Bridge. The purchase price of shares issued in respect of each put notice is 80% of the average of the three lowest trading prices in the seven trading days immediately preceding the date on which the Company exercises its put right. 

On February 14, 2018, March 19, 2018 and April 2, 2018, the Company delivered put notices to Crown Bridge pursuant to the Equity Purchase Agreement. A total of 1,300,960 Class A common shares were issued to Crown Bridge for total net cash proceeds of $284,371. A fourth put notice, dated April 6, 2018, was delivered to Crown Bridge for 989,473 Class A common shares, which shares were issued in July 2018. The fourth put notice was funded on September 4, 2018 in the amount of $116,252. The Company’s right to deliver further put notices under the Equity Purchase Agreement was terminated on April 10, 2018, when the listing of our Class A common stock was moved to the OTC Pink.

Effective May 7, 2019, the Company issued and delivered to Odyssey Capital Funding LLC (“Odyssey”) a 10% convertible note in the principal amount of $100,000. The Company received $95,000 after payment of $5,000 of fees and expenses of the lender and its counsel. Odyssey, at its option, may convert the unpaid principal balance of, and accrued interest on, the note into shares of common stock at a 40% discount from the lowest trading price during the 20 days prior to and including the conversion date (with a floor of $0.03 per share for the six months following the date of the note). The note matures on May 7, 2020. The Company may redeem the note at redemption prices ranging from 130% to 140% during the first 120 days after issuance. The Company may not redeem the note after the first 120 days after issuance.

Effective June 4, 2019, the Company issued and delivered to Geneva a 9% convertible note in the principal amount of $56,500. The note was issued at a discount and the Company received $50,000 after payment of $3,000 of fees and expenses of the lender and its counsel. Geneva, at its option, may convert the unpaid principal balance of, and accrued interest on, the note into shares of common stock at a 29% discount from the lowest trading price during the 20 days prior to conversion. The note matures on September 4, 2020. The Company may redeem the note at redemption prices ranging from 105% to 130% during the first 180 days after issuance. The Company may not redeem the note after the first 180 days after issuance.

Effective June 19, 2019, the Company issued and delivered to Odyssey a 10% convertible note in the principal amount of $250,000. Of the note proceeds, $144,296 was paid to One44 to redeem its February 27, 2019 convertible note and the Company received $80,704 after payment of $25,000 of legal and brokerage fees. Odyssey, at its option, may convert the unpaid principal balance of, and accrued interest on, the note into shares of common stock at a 40% discount from the lowest trading price during the 20 days prior to and including the date of conversion (with a floor of $0.03 per share for the six months following the date of the note). The note matures on June 19, 2020. The Company may redeem the note at redemption prices ranging from 130% to 140% during the first 120 days after issuance. The Company may not redeem the note after the first 120 days after issuance.

We do not expect to have the financial resources necessary to complete the proposed Refinery projects. The Company expects to operate the Distillation Unit through its subsidiary, Pecos Refining, and to operate the Large Refinery through another subsidiary set up for such purpose. The construction of the Distillation Unit and the Large Refinery will require substantial equity and debt financing, far beyond the expected resources of the Company. We anticipate that these Subsidiaries will obtain typical project development financing for the construction and development of the Distillation Unit and the Large Refinery and that such financings will be composed of both debt and equity financings. We anticipate these Subsidiaries will be able to finance approximately 80% of the total costs of the Distillation Unit and the Large Refinery through debt financing, and the remaining 20% of the total costs would be financed through equity investments. The Company has had only preliminary discussions with prospective equity sources regarding the financing of these projects and it is unclear at this time if we will be able to obtain such financing and, if so, how much equity in the Subsidiaries the equity investors will require in order to provide the financing. Any equity financing into which a Subsidiary enters will dilute the Company’s ownership of such Subsidiary. In addition, while the Company believes that the Refinery’s cost is financeable in large part through debt, it has not yet obtained a letter of intent or commitment for such financing.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements that have or are reasonably likely to have a material 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 are material to investors.

Critical Accounting Policies

Our results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. On an on-going basis, we evaluate our estimates, including those related to inventories, investments, intangible assets, income taxes, financing operations, and contingencies and litigation. We base our estimates on historical experience and on various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions. 

For further information on our significant accounting policies see the notes to our consolidated financial statements included in this Annual Report. There were no material changes to our significant accounting policies during the year ended April 30, 2019. The following is a description of those significant accounting policies that involve estimates and judgment by management.

Derivative liabilities

In a series of subscription agreements, the Company issued warrants in prior years that contain certain anti-dilution provisions that have been identified as derivatives. In addition, the Company identified the conversion feature of certain convertible notes payable and convertible preferred stock as derivatives. As of April 30, 2019, the number of warrants or common shares to be issued under these agreements is indeterminate; therefore, the Company concluded that the equity environment is tainted and all additional warrants, stock options and convertible debt are included in the value of the derivative. We estimate the fair value of the derivatives using multinomial lattice models that value the derivative liabilities based on a probability weighted cash flow model using projections of the various potential outcomes. These estimates are based on multiple inputs, including the market price of our stock, interest rates, our stock price volatility and management’s estimates of various potential equity financing transactions. These inputs are subject to significant changes from period to period and to management's judgment; therefore, the estimated fair value of the derivative liabilities will fluctuate from period to period, and the fluctuation may be material.

Fair value of financial instruments

Under Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 820, Fair Value Measurements and Disclosures, and ASC 825, Financial Instruments, the FASB establishes a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements. This Statement reaffirms that fair value is the relevant measurement attribute. The adoption of this standard did not have a material effect on the Company's financial statements as reflected herein. The carrying amounts of cash, accounts payable, accrued expenses and notes reported on the accompanying consolidated balance sheets are estimated by management to approximate fair value primarily due to the short-term nature of the instruments.

An entity is required to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value using a hierarchy based on the level of independent, objective evidence surrounding the inputs used to measure fair value. A financial instrument’s categorization within the fair value hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The hierarchy prioritized the inputs into three levels that may be used to measure fair value:

Level 1 applies to assets or liabilities for which there are quoted prices in active markets for identical assets or liabilities.

Level 2 applies to assets or liabilities for which there are inputs other than quoted prices that are observable for the asset or liability such as quoted prices for similar assets or liabilities in markets that are not active.

Level 3 applies to assets or liabilities for which there are unobservable inputs to the valuation methodology that are significant to the measurement of the fair value of the assets or liabilities.

Our derivative liabilities are measured at fair value on a recurring basis and estimated as follows:

Item 7A: Quantitative and Qualitative Disclosures About Market Risk

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

Item 8: Financial Statements and Supplementary Data

The following financial statements are being filed with this report and are located immediately following the signature page.

Index to Consolidated Financial Statements

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of April 30, 2019 and 2018

Consolidated Statements of Operations for the years ended April 30, 2019 and 2018

Consolidated Statements of Stockholders’ Deficit for the years ended April 30, 2019 and 2018

Consolidated Statements of Cash Flows for the years ended April 30, 2019 and 2018

Notes to Consolidated Financial Statements

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

There have been no changes in or disagreements with our accountants on accounting and financial disclosures.

Item 9A(T): Controls and Procedures

Evaluation of disclosure controls and procedures.

We carried out an evaluation, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)). Based upon that evaluation, our principal executive officer and principal financial officer concluded that, as of the end of the period covered in this report, our disclosure controls and procedures were not effective to ensure that information required to be disclosed in reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the required time periods and is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Our management, including our principal executive officer and principal financial officer, does not expect that our disclosure controls and procedures or our internal controls will prevent all error or fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are 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. Due to 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. To address the material weaknesses, we performed additional analysis and other post-closing procedures in an effort to ensure our consolidated financial statements included in this annual report have been prepared in accordance with generally accepted accounting principles. Accordingly, management believes that the financial statements included in this report fairly present in all material respects our financial condition, results of operations and cash flows for the periods presented.

Management's Annual Report on Internal Control over Financial Reporting.

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Securities Exchange Act, as amended. Our management assessed the effectiveness of our internal control over financial reporting as of April 30, 2019. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") in Internal Control-Integrated Framework. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company's annual or interim financial statements will not be prevented or detected on a timely basis. We have identified the following material weaknesses:

Because of these material weaknesses, management has concluded that the Company did not maintain effective internal control over financial reporting as of April 30, 2019, based on the criteria established in "Internal Control-Integrated Framework" issued by the COSO.

Changes in Internal Control Over Financial Reporting.

There have been no changes in the Company's internal control over financial reporting through the date of this report or during the quarter ended April 30, 2019, that materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

Independent Registered Accountant's Internal Control Attestation.

This annual report does not include an attestation report of the Company's registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by the Company's registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the Company to provide only management's report in this annual report.

Corrective Action. Management plans to address the structure of the Board of Directors and discuss adding an audit committee during fiscal year 2020.

Item 9B. Other Information

None.

Part III

Item 10. Directors, Executive Officers and Corporate Governance

Directors and Executive Officers

The Board of Directors currently consists of two persons. Directors serve until the next annual meeting and until their successors are elected and qualified. The following table sets forth information about our directors and executive officers:

Mr. Hanks has served as Director, Chief Executive Officer and President of the Company since the merger of Maple Carpenter Creek, LLC with the Company in September 2010. Mr. Hanks founded Maple Resources Corporation in 1986 and has been President or Chairman of the Board of Maple Resources since its inception. Mr. Hanks has also been the Executive Chairman of Maple Energy plc, a publicly-listed company on the London Stock Exchange AIM and the Lima Bolsa. Prior to founding Maple Resources Corporation, Mr. Hanks was a partner in the Washington D.C. office of the law firm of Akin Gump Strauss Hauer & Feld LLP. Mr. Hanks graduated from the University of Texas at Austin with a law degree in 1971 and a petroleum land management degree in 1968. We believe that Mr. Hanks’ business, finance and management experience qualifies him to serve as a member of our board of directors.

Mr. Lemons has been a practicing lawyer in the mineral area for over 25 years. He has been a private investor in oil and gas and coal projects in the last several years, including in Maple Carpenter Creek, LLC and Maple Energy, plc and predecessor entities. Since 2002, Mr. Lemons has served as a director of Ansen, an electronics manufacturing company based in upstate New York. Mr. Lemons was a partner in the law firms of Holme Roberts & Owen and in Holland & Hart. Mr. Lemons graduated law school from Brigham Young University in 1980, where he was a member of law review, and holds undergraduate degrees in Economics and Political Science from Utah State University. We believe that Mr. Lemons’ business, finance and management experience qualifies him to serve as a member of our board of directors.

We are not aware of any “family relationships” (as defined in Item 401(d) of Regulation S-K promulgated by the SEC) among directors, executive officers, or persons nominated or chosen by us to become directors or executive officers.

The Board of Directors has determined that neither director is “independent” as such term is defined by the listing standards of Nasdaq and the rules of the SEC. Mr. Lemons is not “independent” due to his significant beneficial ownership of our common stock. Mr. Hanks is not “independent” due to his significant beneficial ownership of our common stock and his role as an executive officer of the Company.

Audit, Nominating and Compensation Committees

Because we are not listed on a securities exchange, we are not required to establish audit, nominating or compensation committees of the Board of Directors and we have not done so. In the event we elect to seek listing on a securities exchange, we will meet the corporate governance requirements imposed by a national securities exchange, including the appointment of an audit committee, nominating committee and compensation committee, the adoption of charters for each such committee and the appointment of independent directors to such committees as required by the requirements of such securities exchange.

Compensation of Directors

We do not currently pay any compensation to our directors, but we pay their expenses to attend our board meetings. During the fiscal year ended April 30, 2019, no director expenses were incurred.

No option awards were granted to our non-executive directors during the year ended April 30, 3019. There were no stock option awards outstanding at April 30, 2019 to our non-executive directors:

Item 11. Executive Compensation

The following table sets forth the compensation paid or earned by our executive officers during the fiscal years ended April 30, 2019 and 2018.

Summary Compensation Table

(1) Mr. Hanks has served as Chief Executive Officer since September 21, 2010.

There are no employment agreements in place and no severance benefits are currently in place. During the years ended April 30, 2019 and 2018, we incurred consulting fees and expense reimbursement related to the development of the refinery project to Maple Resources Corporation (“Maple Resources”), a related party controlled by our President and CEO, totaling $350,931 and $123,986, respectively. Amounts included in accounts payable due to Maple Resources totaled $9,403 and $5,583 as of April 30, 2019 and 2018, respectively.

Outstanding Equity Awards at Fiscal Year-End

We have not granted any stock awards other than stock options. At April 30, 2019, we had no outstanding stock options or other equity awards.

As a condition for entering into an October 9, 2018 convertible debenture, the lender required affiliates of our directors (the “Affiliates”), to pledge their shares of Class B Common Stock (constituting 100% of the outstanding shares of Class B Common Stock) to the lender to secure the repayment of the debenture by the Company. As consideration to the Affiliates for entering into the GS pledge agreement, the Company granted a ten-year option, effective as of December 11, 2018, to the Affiliates to purchase 1,000,000 Class A Shares and 1,000,000 Class B Shares at $0.08 per share.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The following table sets forth as of July 12, 2019, the name and number of shares of the Company’s common stock beneficially owned by (i) each of the directors and named executive officers of the Company, (ii) beneficial owners of 5% or more of our common stock; and (iii) all the officers and directors as a group. Pursuant to the rules and regulations of the SEC, shares of common stock that an individual or group has a right to acquire within 60 days pursuant to the exercise of options or warrants are deemed to be outstanding for the purposes of computing the percentage ownership of such individual or group, but are not deemed to be outstanding for the purposes of computing the percentage ownership of any other person shown in the table.

SEC rules provide that, for purposes hereof, a person is considered the “beneficial owner” of shares with respect to which the person, directly or indirectly, has or shares the voting or investment power, irrespective of his/her/its economic interest in the shares. Unless otherwise noted, each person identified possesses sole voting and investment power over the shares listed, subject to community property laws.

The percentages in the table below are based on 271,588,167 shares of Class A common stock and 15,000,000 shares of Class B common stock outstanding on July 12, 2019. Shares of common stock subject to options and warrants that are exercisable within 60 days of July 12, 2019 are deemed beneficially owned by the person holding such options for the purposes of calculating the percentage of ownership of such person but are not treated as outstanding for the purpose of computing the percentage of any other person.

_______________

Item 13. Certain Relationships and Related Transactions and Director Independence

Unless otherwise indicated, the terms of the following transactions between related parties were not determined as a result of arm’s length negotiations.

Contractual Agreements

On March 4, 2017, the Company entered into an agreement with Maple Resources Corporation (“Maple Resources”), a related party owned by Mr. Jack W. Hanks, to acquire Maple Resources’ business plan to build a $450 million, 50,000 barrels per day capacity crude oil refinery in Pecos County, Texas in exchange for the issuance of 7 billion shares of common stock. The Company issued 15,000,000 shares of common stock on March 4, 2017. Subsequently, the Company amended and restated its articles of incorporation to authorize Class A and Class B common stock. Upon such amendment and restatement, Maple Resources agreed to waive its right to receive the remainder of the 7 billion shares of common stock and the 1.5 billion shares already issued were designated as Class B common stock. The Class B common stock is identical to the Class A common stock except that the Class A common stock has one vote per share and the Class B common stock has 10 votes per share. The 15,000,000 Class B common stock issued to Maple Resources was valued at $150,000 by an independent valuation firm, with the $150,000 expensed to refinery start-up costs.

Maple Resources subsequently granted BNL Family Trust (“BNL”), a related party to Mr. Lemons, an option to purchase 1,000,000 shares of Class B common stock from Maple Resources at a price of $0.20 per share. The option expires in March 2022. Beneficial ownership of Messrs. Hanks and. Lemons give effect to the exercise of such option.

As a condition for entering into an October 9, 2018 convertible debenture, the lender required Maple Resources and BNL, affiliates of Jack W. Hanks and Bruce Lemons, respectively, our directors (the “Affiliates”), to pledge their shares of Class B Common Stock (constituting 100% of the outstanding shares of Class B Common Stock) to the lender to secure the repayment of the debenture by the Company. As consideration to the Affiliates for entering into the pledge agreement, the Company granted a ten-year option, effective as of December 11, 2018, to the Affiliates to purchase 1,000,000 of Class A Shares and 1,000,000 of the Class B Shares at $0.08 per share. The options expire in December 2028. The value of the derivative associated with the option was estimated at $42,217, which amount was charged to expense.

Consulting Fees and Expense Reimbursement

During the years ended April 30, 2019 and 2018, we incurred consulting fees and expense reimbursement related to the development of the refinery project to Maple Resources, a related party controlled by our President and CEO, totaling $350,931 and $123,986, respectively. Amounts included in accounts payable due to Maple Resources totaled $9,403 and $5,583 as of April 30, 2019 and 2018, respectively.

Effective October 1, 2018, we entered into a consulting agreement with a related party to issue shares of our Class A common stock each month with a value of $2,500, with the number of shares issued based on the average closing price of the stock during the prior month. During the year ended April 30, 2019, we issued a total of 193,965 Class A common shares valued at $11,166 to the related party. A gain on extinguishment of debt of $3,835 related to this compensation arrangement was recorded as a contribution to capital in the year ended April 30, 2019.

Accrued Expenses

Accrued expenses, consisting of consulting fees, to related parties totaled $41,036 as of April 30, 2019 and 2018.

Item 14: Principal Accounting Fees and Services

Our independent auditors, M&K CPAs, PLLC ("M&K"), have no direct or indirect interest in the Company and have been the Company's Independent Registered Public Accounting Firm since 2009. The following table sets forth the fees billed and estimated fees for professional audit services provided by such firm for the fiscal years ended April 30, 2019 and 2018:

Our Board of Directors established a policy whereby the outside auditors are required to seek pre-approval on an annual basis of all audit, audit-related, tax and other services by providing a prior description of the services to be performed. For the year ended April 30, 2019, 100% of all audit-related services were pre-approved by the Board of Directors, which concluded that the provision of such services by M&K was compatible with the maintenance of that firm's independence in the conduct of its auditing functions. 

Item 15: Exhibits

(a) (3) Exhibits

SIGNATURES

In accordance with Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this annual report on Form 10-K to be signed on its behalf by the undersigned thereto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, this annual report on Form 10-K has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 

MMEX RESOURCES CORPORATION

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of MMEX Resources Corporation

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of MMEX Resources Corporation (the Company) as of April 30, 2019 and 2018, and the related consolidated statements of operations, stockholders’ deficit, and cash flows for each of the years in the two-year period ended April 30, 2019, and the related notes and schedules (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 April 30, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the two-year period ended April 30, 2019, in conformity with accounting principles generally accepted in the United States of America.

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.

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 suffered a net loss from operations and has a net capital deficiency, which raises substantial doubt about its ability to continue as a going concern. Management’s plans regarding those matters are described in Note 3. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ M&K CPAS, PLLC

We have served as the Company’s auditor since 2013.

Houston, TX

July 26, 2019

MMEX RESOURCES CORPORATION

Consolidated Balance Sheets

See accompanying notes to consolidated financial statements. 

MMEX RESOURCES CORPORATION

Consolidated Statements of Operations

See accompanying notes to consolidated financial statements.

MMEX RESOURCES CORPORATION

Consolidated Statement of Stockholders’ Deficit

Years Ended April 30, 2019 and 2018

See accompanying notes to consolidated financial statements.

MMEX RESOURCES CORPORATION

Consolidated Statement of Stockholders’ Deficit

Years Ended April 30, 2019 and 2018 (continued)

See accompanying notes to consolidated financial statements.

MMEX RESOURCES CORPORATION

Consolidated Statements of Cash Flows