As filed with the Securities and ExchangeExchange Commission on January 22 , 201 8

Registration No. 333-218958

6, 2022

Registration No. 333-

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

AMENDMENT NO. 3 TO

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

3616 Far West Blvd., #117-321

Austin, Texas 78731

(855) 880-0400

 (Address,(Address, including zip code, and telephone number, including

area code, of registrant’s principal executive offices)

Jack W. Hanks

President, Chief Executive Officer and Chief Financial Officer

3616 Far West Blvd., #117-321

Austin, Texas 78731

(855) 880-0400

 (Name,(Name, address, including zip code, and telephone number,

including area code, of agent for service)

Copies to:

Bruce H. Hallett

Hallett & Perrin, P.C.

1445 Ross Avenue, Suite 2400

Dallas, Texas 75202

Tel. No.: (214) 953-0053

Approximate date of commencement of proposed sale to the public:

As soon as practicable after the effective date of this registration statement

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. x☒

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨☐

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨☐

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Securities Exchange Act of 1934.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial account standards provided to Section 7(a)(2)(B) of the Securities Act. ¨☐

CALCULATION OF REGISTRATION FEE

Title of Each Class of Securities to be Registered		Amount to be Registered (1)				Proposed Maximum Offering Price Per Share (2)				Proposed Maximum Aggregate Offering Price				Amount of Registration Fee (3)
Class A Common Stock, par value $0.001 per share			1,009,690,382			$	.0066			$	6,663,957			$	829.67

__________ 

_____________ 

(1)	We are registering 300,000,00031,975,000 shares of our Class A common stock that we have the right to put to Crown Bridge Partners, L.LC. pursuant to the Equity Purchase Agreement we entered into on June 12, 2017 (as amended to date), 16,500,000 sharesare issuable upon conversion of shares of Series B Preferred Stock, Series B Warrants and Series C Warrants which were sold to an outstanding convertible note and 693,190,382institutional purchaser in a private transaction. We are also registering an additional 1,350,000 shares from other selling stockholders. Inof common stock issuable upon exercise of warrants granted to the eventplacement agent in such private transaction. Pursuant to Rule 416, the securities registered hereunder include such indeterminate number of shares being registered hereunder is insufficient to cover allwhich may become issuable as a result of stock splits, stock dividends and other adjustment provisions of the shares we put to Crown Bridge Partners, L.L.C., we will amend this registration statement Series B Preferred Stock, Series B Warrants, Series C Warrants and/or file a new registration statement to register those additional shares. Pursuant to Rule 416(a), this registration statement also cover any additional shares of our Class A common stock that will be issuable upon conversion of the outstanding convertible note by reason of any stock dividend, stock split, recapitalization or similar transaction.placement agent warrants.
(2)	The offering price has been estimated solely for the purpose of computing the amount of the registration fee in accordance with Rule 457(o) of the Securities Act on the basis of the closing bid price of the Class A common stock of the registrant as reported on the OTCQB tier of the OTC Markets Group, Inc. on January 18, 2018.Act.
(3)	$1, 421.38 previously paid

The registrant hereby amends this registration statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this registration statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the registration statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

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The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities, and it is not soliciting an offer to buy these securities, in any state where the offer or sale is not permitted.

PRELIMINARY PROSPECTUS

SUBJECT TO COMPLETION, DATED JANUARY 22 , 201 86, 2022

1,009,690,382 33,325,000 Shares of Class A Common Stock

MMEX RESOURCES CORPORATION

This prospectus relates to the offer and sale by the selling stockholders identified herein of up to 1,009,690,382 shares (the “Shares”) of Class A common stock, par value $0.001 per share (together with our Class B common stock, par value $0.001 per share, referred(referred to herein as the “common stock”) of MMEX Resources Corporation (referred to herein as “MMEX,” the “Company,” “we,” “our,” and “us”). TheseThe Shares are issuable upon the conversion of our outstanding shares consist of (i) 693,190,382Series B Convertible Preferred Stock (“Series B Preferred Stock”), the exercise of our outstanding Series B Warrants and Series C Warrants (the “Series B Warrants” and “Series C Warrants”, respectively) and the exercise of warrants issued to the placement agent (“Placement Agent Warrants”). We issued 1,500 shares of Series B Preferred Stock and Series D Warrants to purchase 15,000,000 shares of our Class A common stock that we issued to certain selling stockholders; (ii) 16,500,000 shares of our Class A common stock that are issuablestockholders pursuant to a holder of our convertible notes; and (iii) 300,000,000 shares of our Class A common stock issuable to Crown Bridge Partners, L.LC. (“Crown Bridge”) pursuant to the EquitySecurities Purchase Agreement that we entered into on June 12, 2017.December 22, 2021.  As part of that transaction, we issued to such holders Series B Warrants to purchase up to an aggregate of 14,399,500 shares at an exercise price of $0.0001 per share and Series C Warrants to purchase up to an aggregate of 2,575,500 shares at an exercise price of $0.10 per share.  We also issued the Placement Agent warrants to selling stockholders in connection with the foregoing transaction.

We are not offering any shares of common stock for sale under this prospectus and we will not receive any proceeds from the resale of the Shares. However, we will receive proceeds from the sale of securities to Crown Bridge pursuant to our exercise of a put right granted to us in the Equity Purchase Agreement. Crown Bridge is deemed an underwriter of our common stock.

The selling stockholders may offer all or portion of the Sharessecurities covered by this prospectus for resale from time to time through public or private transactions, at either prevailing market prices or at privately negotiated prices. We will bear all costs, expenses and fees in connection with the registration of the Shares,securities, including the cost of compliance with state securities or “blue sky” laws. The selling stockholders will bear all commissions, discounts and transfer taxes, if any, attributable to their sales of the Shares.securities. See “Plan of Distribution.”Distribution” beginning on page 28 of this prospectus.

Our Class A common stock is listed for quotation on the OTCQB tier (“OTCQB”) of the OTC Markets Group, Inc.Pink under the symbol “MMEX.” There is no established trading market for the Class B common stock. On January 19, 2018,____, 2022, the closing price of our Class A common stock was $0.0068. As of January 15, 2018, we had 1, 592,747,801 shares of Class A common stock and 1.5 billion shares of Class B common stock issued and outstanding.$_____.

We are a “smaller reporting company” as defined in Section 2(a) of the Securities Act of 1933, as amended (the “Securities Act”) and are subject to reduced public company reporting requirements. This prospectus complies with the requirements that apply to an issuer that is a smaller reporting company.

Investing in our Class A common stock involves a high degree of risk. See “Risk Factors” beginning on page 4 to read about factors you should consider before investing in shares of our Class A common stock.

NEITHER THE SECURITIES AND EXCHANGE COMMITTEE NOR ANY STATE SECURITIES COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR DETERMINED IF THIS PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.

The date of this prospectus is: January ____, 2018is _____________, 2022

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We have not authorized anyone to provide any information other than that contained or incorporated by reference in this prospectus, any prospectus supplement or in any free writing prospectus prepared by or on behalf of us or to which we have referred you. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. We and the selling stockholders have not authorized any other person to provide you with different information. If anyone provides you with different or inconsistent information, you should not rely on it. This prospectus does not constitute an offer to sell, or solicitation of an offer to buy, these securities in any jurisdiction where such offer, sale or solicitation is not permitted. You should assume that the information appearing in this prospectus is accurate only as of the date on the front cover of this prospectus. Our business, financial condition, results of operations and prospects may have changed since that date. This prospectus is an offer to sell only the shares offered hereby, but only under circumstances and in jurisdictions where it is lawful to do so.

For investors outside the United States: we have not done anything that would permit this offering or possession or distribution of this prospectus in any jurisdiction where action for that purpose is required, other than in the United States. Persons outside the United States who come into possession of this prospectus must inform themselves about, and observe any restrictions relating to, the offering of the shares of Class A common stock and the distribution of this prospectus outside the United States.

Unless otherwise indicated or the context otherwise requires, all financial data presented or incorporated by reference in this prospectus reflects the consolidated business and operations of MMEX and its consolidated subsidiaries, and has been prepared in accordance with generally accepted accounting principles in the United States of America.

Industry and Market Data

The market data and certain other statistical information used throughout this prospectus are based on independent industry publications, government publications or other published independent sources. Some data are also based on our good faith estimates. Although we believe the third-party sources are reliable as of their respective dates, neither we nor the selling stockholders have independently verified the accuracy or completeness of this information.

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PROSPECTUS SUMMARY

PROSPECTUS SUMMARY

This summary highlights selected information contained elsewhere in this prospectus. This summary does not contain all the information that you should consider before investing in our Class A common stock. You should carefully read the entire prospectus, including “Risk Factors,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements before making an investment decision.

Business Overview

We are a development stage company engaged inSince 2016, 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 Texas, Peru, and other countries in Latin America using the expertise of our principals to identify, finance and acquire these projects.

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. We previously unsuccessfully pursued mining and coal projects that have since been abandoned. We have never generated any revenues and have accumulated losses of $36,918,594 as of April 30, 2017.

The most significant focus of our current business plan ishas been to build crude oil distillation units and refining facilities (CDUs) in the Permian Basin in West Texas. ThroughWe revised our wholly-owned subsidiary, Pecos Refining & Transport, LLC (“Pecos Refining”), we intend initiallybusiness plan in 2021 to buildmove MMEX to clean energy use and commence operationproduction, leveraging our history, management and business relationships from the traditional energy sector. The focus of a 10,000 barrel-per-day (“bpd”) crude oil distillation unit (the “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. Through a separate subsidiary (together with Pecos Refining, the “Subsidiaries ”), we intend to build and commence operation of a crude oil refinery (the “Large Refinery”) with up to 100,000 bpd capacity at the same location in West Texas. In this prospectus, we often refer to the Distillation Unit and the Large Refinery collectively as the “Refinery.” These projects will be built on 476 acres located 20 miles northeast of Fort Stockton, Texas, near the Sulfur Junction spur of the South Orient Railroad (also known as the “Texas Pacifico Railroad”). The cost of the Distillation Unit with a 10,000 bpd capacityour business plan is estimated to be approximately $50 million. The cost of the Large Refinery with a 50,000 bpd capacity is estimated to be approximately $500 million and the cost of a 100,000 bpd refinery is estimated to be approximately $850 million. If successfully developed, the Refinery 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.to:

2021 Private Placement Financing

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, 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.

2017 Equity Purchase Agreement

On June 12, 2017, we entered into an Equity Purchase Agreement with Crown Bridge Partners, LLC pursuant to which Crown Bridge committed to purchase up to $3,000,000 of our common stock for a period of up to 24 months commencing upon the effectiveness of a registration statement covering the resale of shares issuable to Crown Bridge under the Equity Purchase Agreement. We amended the Equity Purchase Agreement on October 9, 2017, in contemplation of the listing of our Class A Common Stock for quotation on the OTCQB. Based upon the trading price of our Class A Common Stock as of January 15, 2018, we would have issued an aggregate of 410,958,904 shares of Class A Common Stock under the Equity Purchase Agreement if the entire $3,000,000 amount of potential shares issuable to Crown Bridge had been drawn. Such shares would represent approximately 26 % of the outstanding shares of Class A Common Stock as of January 15, 2018 , resulting in significant ownership dilution to our existing holders of Class A Common Stock. In connection with the Equity Purchase Agreement,December 22, 2021, we entered into a Registration RightsSecurities Purchase Agreement with Crown Bridge,an institutional investor, pursuant to which we agreed to register for resale by Crown Bridgeissue and sell in a private placement 1,500 shares of our Series B Preferred Stock and Series D Warrants to purchase up to an aggregate of 15,000,000 shares of our common stock. We received gross proceeds of $1.5 million. As part of that transaction, we issued to the investor Series B Warrants to purchase up to an aggregate of 14,399,500 shares at an exercise price of $0.0001 per share and Series C Warrants to purchase up to an aggregate of 2,575,500 shares at an exercise price of $0.10 per share.  We also issued the Placement Agent Warrants, covering 1,350,000 shares of common stock, purchased by them pursuant to affiliates of the Equityplacement agent as part of such private placement.  In connection with the Securities Purchase Agreement. PursuantAgreement, we entered in a registration rights agreement and agreed to such agreement, we filedfile within 15 days a resale registration statement with the SEC, on Form S-1 within 45 days of the date of the Registration Rights Agreement covering the resale of shares to be issued under such agreementwhich this prospectus statement is a part, and have agreed to use our reasonable best efforts to cause the resale registration statement to become effective as promptly as is practicable.

In connection with the Equity Purchase Agreement, we issued to Crown Bridge, as a commitment fee, an $80,000 convertible promissory note which matured on December 12, 2017. Pursuant to the terms of the note, Crown Bridge thereafter converted the principal balance of the note plus accrued interest at the rate of 8% per annum into 19,834,823 shares of our Class A common stock, representing a conversion price equal to the lesser of (i) the closing price of our Class A common stock on the issuance date of the note or (ii) 60% of the average of the three lowest trading prices during the 25-day period prior to the notice of conversion.

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within 75 days thereafter.

Acquisition of Land

We do not currently own all of the land on the site near Fort Stockton, Texas at which we intend to build the Refinery. On July 28, 2017, we acquired the 126 acre parcel of the land which is the site for the planned Distillation Unit at a purchase price of $550 per acre, or $69,249. At such time, we agreed with the seller of the property to acquire the remaining 350 acre parcel, which is the site for the planned Large Refinery, on or before January 31, 2018 at a price of $550 per acre, or $192,500.

TCEQ Permit

On July 31, 2017, we filed an application with the Texas Commission on Environmental Quality (“TCEQ”) to obtain an air quality permit and obtained permit approval from the TCEQ on August 30, 2017. Accordingly, we will begin construction on the Distillation Unit on 15 acres of our 126 acre tract as soon we receive adequate financing to do so, as to which there is no assurance.  

Where You Can Find Us

Our principal office is located at 3616 Far West Blvd, #117-321, Austin, Texas 78731, and our project office is located at 107 S. Main Street, Fort Stockton, Texas 79735. Our telephone number is (855) 880-0400. Our website is www.mmexresources.com. Information on our website or any other website is not incorporated by reference into, and does not constitute part of, this prospectus.

The Offering

Common stock offered by Selling Stockholders	785,611,588	33,325,000 shares of Class A common stock
Common stock outstanding before the offering	1,592 ,747,801 shares of Class A common stock	18,845,362 as of January 15, 2018 1,500,000,000 shares of Class B common stock as of January 15, 2018 December 31, 2021
Common stock outstanding after the offering	2,003,706,705 shares of Class A common stock, assuming the issuance of an additional 410,958,904 shares of Class A common stock pursuant to the Equity Purchase Agreement.	The number of outstanding shares of common stock will not otherwise be impacted by sales of the selling stockholders named herein.
Use of proceeds		We will not receive any proceeds from the sale of Class A common stocksecurities by the selling stockholders. However, we will receive proceeds from the sale of securities to Crown Bridge pursuant to our exercise of a put right granted to us in the Equity Purchase Agreement. Any such proceeds will be utilized first for the repayment of outstanding convertible notes and thereafter for general corporate purposes.
OTCQB Trading Symbol		MMEX
Risk Factors		The Class A common stock offered hereby involves a high degreeshares of risk and should not be purchased by investors who cannot afford the losscommon stock offered hereby involves a high degree of risk and should not be purchased by investors who cannot afford the loss of their entire investment. See “Risk Factors”.

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RISK FACTORS

RISK FACTORS

An investment in the Shares involves a high degree of risk. You should carefully consider the risks described below together with all of the other information included in this prospectus before making an investment decision with regard to our Shares. The statements contained in or incorporated into this prospectus that are not historic facts are forward-looking statements that are subject to risks and uncertainties that could cause actual results to differ materially from those set forth in or implied by forward-looking statements. If any of the following risks actually occurs, our business, financial condition or results of operations could be harmed. In that case, the trading price of our Class A common stock could decline, and you may lose all or part of your investment.

The risks included in this prospectus are not the only risks we face. We may experience additional risks and uncertainties not currently known to us, or as a result of developments occurring in the future. Conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flows and results of operations.

Risks Related to Ourour Business Plan

An investment in the Company is speculative.

Our business plans are highly speculative and no assurance can be given that we will operate profitably. Our lack of operating history makes it difficult for us to evaluate our future business prospects and make decisions based on those estimates of our future performance. Furthermore, the Company has pursued its proposed refineryhydrogen production business plan only for a short time, and thus our business carries both known and unknown risks. No assurance can be given that you will realize your investment objectives or realize a substantial return (if any) on your investment or that you will not lose your entire investment. An investment in the Class Aour common stock involves a high degree of risk.

The Company is a development stage company with a history of operating losses and expects to continue to realize losses in the near future.

The Company is a development stage company. We have incurred continuous losses from operations, had an accumulated deficit at April 30, 2017October 31, 2021 of almost $37more than $66 million and have reported negative cash flows from operations for more than the past five years.  The Company expectsWe expect to continue to incur net losses until such time as the Refinery enters into commercial production andwe have completed a project that generates sufficient revenues to fund continuing operations. The size of these losses will depend, in large part, on whether the Company is able to construct the Refineryfacilities, and commence operations and is thereafter able to operate the Refineryits facilities in a profitable manner. We recognize that if we are unable to generate significant revenues from our refining operations, we will not be able to earn profits or continue operations.  At this early stage of our operation, we also expect to face the risks, uncertainties, expenses, and difficulties frequently encountered by companies at the start-up stage of their business development. We cannot be sure that we will be successful in addressing these risks and uncertainties and our failure to do so could have a materially adverse effect on our financial condition.

We need to continue as a going concern if our business is to succeed.

Because of our recurring losses and negative cash flows from operations, the audit report of our independent registered public accountants on our consolidated financial statements for the year ended April 30, 20172020 contains an explanatory paragraph stating that there is substantial doubt about our ability to continue as a going concern. Factors identified in the report include our historical net losses and our net capital deficiency, which raises substantial doubt about our ability to continue as a going concern. If we are not able successfully to implement our business plan and attain profitability in the near future our financial condition could deteriorate further, which would have a material adverse impact on our business and prospects and result in a significant or complete loss of your investment. Further, we may be unable to pay our debt obligations as they become due. If we are unable to continue as a going concern, we might have to liquidate our assets and the values we receive for our assets in liquidation or dissolution could be significantly lower than the values reflected in our financial statements. In addition, the inclusion of an explanatory paragraph regarding substantial doubt about our ability to continue as a going concern and our lack of cash resources may materially adversely affect our share price and our ability to raise new capital or to enter into critical contractual relations with third parties.

The completion of our proposed business plan is subject to great uncertainty.

Our proposedThe pursuit of our business plan contemplates building one of the first refineries in the United States in the past 40 years. The successful completion of this plan depends, among other factors, upon the receipt of required governmental permits and substantial debt and equity financing. There is no assurance that this business plan can be successfully completed.

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We will require significant additional capital to fund our business plan.

substantial financial resources.  We do not currently generate any revenue and do not have the cash resources to meetimplement our operating commitments for the next twelve months. We have not yet commenced commercial production, as such, have not generated positive cash flows to date and have no reasonable prospects of doing so unless successful commercial production can be achieved at the Refinery. We expect to continue to incur negative investing and operating cash flows until such time as we enter into successful commercial production.

In addition, we will be required to make substantial capital expenditures and expend significant funds to construct and operate the Refinery. To the extent that the Refinery project proceeds, we anticipate that we will incur substantially increased expenses without realizing revenues from operations for a sustained period. We therefore expect to incur significant losses in the foreseeable future.business plan.  If we are unable to obtain additional financing from outside sources and eventually produce enough revenues, we may be forced to curtail or cease our planned operations. If this happens, you could lose all or part of your investment.

Our ability to obtain necessary funding for these purposes depends upon a number of factors, including the status of the national and worldwide economy and the pricehealth of crude oil and petroleum products.the energy sector. There is no assurance that any such financing sources will be available or sufficient to meet our requirements. There is no assurance that we will be able to continue to raise equity capital or to secure additional debt financing. We may not be successful in obtaining the required financing or, if we can obtain such financing, such financing may not be on terms that are favorable to us. Our inability to access sufficient capital for our operations could have a material adverse effect on our financial condition, results of operations, or prospects.

Even after the Refinery is operational, we will have working capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate.

The refining business is characterized by high fixed costs resulting from the significant capital outlays associated with the construction, operation and maintenance of the Refinery and related facilities. If the Refinery is completed, we will be dependent on the production and sale of quantities of refined products at refined product margins sufficient to cover operating costs, including any increases in costs resulting from future inflationary pressures or market conditions and increases in costs of fuel and power necessary in operating our planned facilities. After completion of the Refinery, our short-term working capital needs will be primarily crude oil purchase requirements that fluctuate with the pricing and sourcing of crude oil. We will also have significant long-term needs for cash, including those to support ongoing capital expenditures and other regulatory compliance. Furthermore, future regulatory requirements or competitive pressures could result in additional capital expenditures that may not produce a return on investment.

We expect to rely on borrowings to purchase crude oil. Changes in our credit profile could affect the way crude oil suppliers view our ability to make payments and induce them to shorten the payment terms of their invoices with us or require additional support such as letters of credit. Any imposition by our creditors of burdensome payment terms on us may have a material effect on our liquidity and our ability to make payments to our suppliers that could hinder our ability to purchase sufficient quantities of crude oil to operate the Refinery at planned rates. In addition, if the price of crude oil increases significantly, we may not have sufficient capacity under the credit agreements or sufficient cash on hand, to purchase enough crude oil to operate the Refinery at planned rates. A failure to operate the Refinery at planned rates could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Even if the Company begins to generate revenues from operations, the Company may not become profitable or be able to sustain profitability.

Refining is a competitive business and our profitability will be dependent upon our ability to source crude oil at competitive prices and to operate the Refinery efficiently in order to protect profit margins. Because the Company does not yet have a revenue stream resulting from sales or other operations, there can be no assurance that the Company will achieve material revenues in the future. Should the Company achieve a level of revenues that make it profitable, there is no assurance the Company can maintain or increase profitability levels in the future.

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The substantial amount of debt and equity financing we will need in order to construct the Refinery may dilute the Company’s ownership of the Refinery.

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 (collectively, the “Subsidiaries”). 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, and we anticipate that most of the equity and debt financing will be issued by these Subsidiaries. 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.

In addition, sales of substantial amounts of our securities may have a highly dilutive effect on our ownership or share structure. Sales of a significant number of shares of our common stock in the public markets, or the potential for such sales, could decrease the trading price of our common stock and could impair our ability to raise capital through future sales of common stock.

The insurance policies for our planned operations will not cover all losses, costs or liabilities that we may experience.

Our insurance coverage will not be expected to cover all potential losses, costs or liabilities. Our ability to obtain and maintain adequate insurance may be adversely affected by conditions in the insurance market over which we have no control. The occurrence of an event that is not fully covered by insurance or the loss of insurance coverage could have a material adverse effect on our planned business, financial condition, results of operations and cash flows.

Two of our stockholders collectively have the ability to determine any matter to be decided by the stockholders, which may prevent or delay a change in control of our company.

Jack W. Hanks, our CEO, and Bruce N. Lemons, one of the two members of our Board of Directors, currently beneficially own approximately 432,872,748 shares of our Class A common stock, which have one vote per share, and 1.5 billion shares of Class B common stock, which have ten votes per share. Through such beneficial ownership, at July 31, 2017, they controlled approximately 92. 8% of the voting power of the common stock on a combined basis. As a result, they can determine the outcome of any corporate matter submitted to our stockholders for approval, including the election of directors and any transaction that might cause a change in control, such as a merger or acquisition.

The loss of Mr. Hanks could adversely affect our business.

Since Mr. Hanks is our principal executive officer devoting substantially all of his business time to the activities of the Company, if he were to die, become disabled, or leave our company, we would be forced to retain individuals to replace him. There is no assurance that we can find suitable persons to replace him if that becomes necessary. We have no key man life insurance at this time.

If we are unable to recruit or retain qualified personnel, our business and operations could be harmed.

We must identify, recruit, hire, train, retain and motivate highly skilled technical, managerial, sales and marketing and administrative personnel. We may not be able to locate or employ such qualified personnel on acceptable terms, or at all. In addition, competition for these individuals is intense, and we may not be able to successfully recruit, assimilate or retain sufficiently qualified personnel. The failure to recruit and retain necessary technical, managerial, sales, marketing and administrative personnel could harm our business and our ability to construct and operate the Refinery.

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Our business plan to distribute refined products into Mexico and to export refined product to Latin America may be subject to adverse political, economic, regulatory or market conditions beyond our control.

We plan on marketing and distributing refined products in the Western area of Mexico and we may export product to Latin America. Many of the market conditions in Mexico are not entirely known at this time as a result of the recent deregulation of the fuel supply market in Mexico. Many factors such as the U.S. tax policy for exports, the U.S. policy toward immigration, and the economy of Mexico may all impact negatively our business plan of exporting refined products to Mexico. In addition, we do not have an off-take agreement with a buyer or distributor in Mexico and any failure to secure an off-take agreement for sale of refined product in Mexico may alter or adversely impact our business plan. Additionally, we currently do not have an off-take agreement with a buyer or distributor in Latin America and our failure to secure an off-take agreement for sale of refined product in Latin America may alter or adversely impact our business plan. Our proposed foreign sales could be adversely affected as a result of:

We may not be able to obtain or renew all required permits and licenses to place any of our properties into production.

Our current and future operations, including construction activities and commencement of production at the Refineryproposed projects will require permits from governmental authorities and such operations are, and will be governed by laws and regulations governing oil and gas development, construction and production as well as exports, taxes, labor standards, occupational health, waste disposal, toxic substances, land use, environmental protection, refineryemployee safety, and other matters.  We may experience increased costs, as well as delays in construction or operation as a result of the need to comply with applicable laws, regulations, and permits. We cannot predict if all permits that we may require for the construction and operation of the Refinery or the export of refined products and crude oil will be obtainable or renewable on reasonable terms, if at all. Costs related to applying for and obtaining permits and licenses may be prohibitive and could delay our planned construction and the operation of the Refinery.prohibitive.  Failure to comply with applicable laws, regulations, and permitting requirements may result in enforcement actions, including orders issued by regulatory or judicial authorities causing operations to cease or be curtailed, and may include corrective measures requiring capital expenditures, installation of additional equipment, or remedial actions.

Future indebtedness may limit our ability to obtain additional financing, and we also may face difficulties complying with the terms of any credit agreements.

As previously discussed, weWe anticipate we will use significant amounts of debt, if available, to fund theproject construction of the Refinery and its operations once construction is finished. Our level of future indebtedness will have a direct impact on our business. Among other things, it may:

We cannot assure you that we will generate sufficient cash flows or that we will be able to borrow funds under certain credit agreements in amounts sufficient to enable us to service our debt or meet our expected working capital and capital expenditure requirements.  Our ability to generate sufficient cash flows from our operating activities are expected to be primarily dependent on raising cash through issuances of equity, and, when the Refinery is constructed, on producing or purchasing and selling sufficient quantities of refined products at margins sufficient to cover fixed and variable expenses. If we are unable to raise sufficient cash through equity issuances, or, if after the Refinery isour planned projects are in operation and our marginscash flows were to deteriorate significantly, or if our earnings and cash flows when the Refinery is completed, were to suffer for any other reason,be adversely impacted, we may be unable to obtain the debt financing we expect to require for our expected working capital needs. To the extent that we are unable to generate sufficient cash flows from issuances of equity or operations, or if we are unable to obtain additional debt financing, we might be required to sell assets or reduce necessary capital expenditures. We cannot assure you that we would be able to refinance our debt, sell assets or obtain additional financing on terms acceptable to us, if at all.

Covenants and events of default in our future debt instruments could limit our ability to undertake certain types of transactions and adversely affect our liquidity.

We expect that any debt financing agreements that we may enter will contain covenants and events of default that may limit our financial flexibility and ability to undertake certain types of transactions. Typically, these covenants would restrict our business activities, including restrictions on:

	·	creating liens;
	·
	·	engaging in mergers, consolidations and sales of assets;
	·	incurring additional indebtedness;
	·	providing guarantees; incurring additional indebtedness;
	·	engaging in different businesses;
	·	making investments; providing guarantees;
	·
	·	engaging in different businesses;
	·	making investments;
	·	making certain dividend, debt and other restricted payments;
	·
	·	engaging in certain transactions with affiliates; and
	·
	·	entering into certain contractual obligations.

Our ability to comply with these expected covenants may depend on factors outside our control. We cannot assure you that we will be able to satisfy these covenants. If we fail to satisfy the covenants established in these facilities or an event of default occurs under the applicable debt agreement, the maturity of the debt instruments could be accelerated or we could be prohibited from future borrowing. If our obligations under the debt instruments are accelerated and we do not have sufficient cash on hand to pay all amounts due, we could be required to sell assets, to refinance all or a portion of our indebtedness or to obtain additional financing through equity or debt financings. Refinancing may not be possible and additional financing may not be available on commercially acceptable terms, or at all. If we cannot obtain such financing, we would need to curtail our planned operations.

Our business, financial condition, results of operations and cash flows may be materially adversely affected by an economic downturn.

The energy sector and the petroleum industry in particular, areis highly cyclical and have historically experienced severe downturns. We are currently in such a downturn, which was sudden when it started and has not shown signs of near term recovery. The dramatic decline in global oil prices which began in calendar year 2014 translated into an abrupt contraction in orders in the energy markets and is the most recent example of the cyclical nature of our markets. We believe that over the long-term, demand for petroleum products will expand, however, the current decline and volatility in oil prices confirms that cyclical downturns will occur periodically.  A sustained deterioration or economic downturn would materially harm our business and operating results. A cyclical downturn can occur suddenly and result in extremely different financial performance sequentially from quarter to quarter or on an annual comparative basis due to an inability to rapidly adjust costs.

In addition, the domestic economy, economic slowdowns and the scarcity of credit can lead to lack of consumer confidence, increased market volatility and widespread reduction of business activity generally in the United States and abroad. An economic downturn may adversely affect the liquidity, businesses and/or financial conditions of our future customers that may result in decreased demand for our products. Disruptions in the financial markets could also lead to a reduction in available trade credit due to counterparties’ liquidity concerns. If we are unable to obtain borrowings or letters of credit under our future credit agreements, our business, financial condition, results of operations and cash flows could be materially adversely affected.

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We must rely on third parties, including the Texas Department of Transportation, to make infrastructure improvements and repairs necessary for the implementation of our business plan.

Although we intend to ship through existing pipeline systems some of our refined product production to the Phoenix, Arizona market and ship some of our heavy oil (sometimes referred to as “atmospheric tower bottoms” or “ATBs”) and naphtha to refineries located in Corpus Christi, we plan to transport a significant portion of our high-value refined product on the Texas Pacifico Railroad. Significant investments are required to upgrade this railroad. The Texas Department of Transportation (“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 high-value products 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, plan to rebuild the bridge allowing access to Mexico and increased business potential. On August 4, 2017, TxDOT 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 are expected to help 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. A recent project schedule estimates the completion date to be in 2018.

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 business plan to market refined products into Western Mexico and to export refined products to Latin America will depend on the completion of the international bridge at Presidio/Ojinaga and the capital investment on the Texas Pacifico Railroad railroad. There is no assurance that these capital improvements will be made. If these capital improvements are not made, our business prospects and results of operations could be materially negatively impacted.

A material decrease in the supply of crude oil available to the Refinery could significantly reduce our future production levels.

We expect to contract with third-party crude oil suppliers to maintain a sufficient supply of crude oil for production at our planned Refinery. A material decrease in crude oil production from the fields that are expected to supply the Refinery as a result of economic, regulatory, or natural influences, availability of equipment, facilities, personnel or services, plant closures for scheduled maintenance, or transportation problems, or an increase in crude oil transport capacities, could result in a decline in the volume of crude oil available to the Refinery. If we are unable to secure sufficient crude oil supplies, we may not be able to take full advantage of current and future expansion of our production capacities. A decline in available crude oil or an inability to secure additional crude oil supplies to meet the needs of current or future refinery expansions could result in an overall decline in volumes of refined products produced by the Refinery and could have a material adverse effect on our business, financial condition, results of operations and cash flows.

The assets comprising the Refinery may experience physical damage as a result of an accident or natural disaster.

These hazards can also cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, and suspension of operations. We will have to have in place appropriate property, liability and business interruption policies, subject to the deductibles and limits under available policies. In addition, such insurance policies do not cover every potential risk associated with our operating facilities, and we cannot ensure that such insurance will be adequate to protect us from all material expenses related to potential future claims for personal and property damage, or that these levels of insurance will be available in the future at commercially reasonable prices.

We could incur substantial costs or disruptions in our business if we cannot obtain or maintain necessary permits and authorizations.

The construction of the Refinery and any subsequent planned operations will require numerous permits and authorizations under various laws and regulations, including environmental and health and safety laws. These authorizations and permits will be subject to revocation, renewal or modification and can require operational changes that may involve significant costs, to limit impacts or potential impacts on the environment, health and safety. A violation of these authorization or permit conditions or other legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions and/or refinery shutdowns.

We expect to face substantial competition from other refining companies.

The refining industry is highly competitive. Our expected competitors will include large, integrated, major or independent oil companies that, because of their more diverse geographic operations, larger refinery capacities or stronger capitalization, are likely to be better positioned than we are to withstand volatile industry conditions, including shortages or excesses of crude oil or refined products or intense price competition at the wholesale level. Some of our present and potential competitors may have substantially greater financial, marketing, technical or manufacturing resources. Our competitors may also be able to respond more quickly to new technologies or processes and changes in customer demands. Certain of our competitors may also have a cost advantage compared to us due to their geography or changes in relative currency values and may compete against us based on price. This may affect our ability to secure new business and maintain our level of profitability. If we are unable to compete effectively, we may lose customers or fail to acquire new customers. If we cannot compete successfully against current or future competitors, our business will be materially adversely affected.

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Risks Related to the Industry

The completion of our proposed Refinery project and ultimate operations of a petroleum refinery are subject to great uncertainty. Should we be successful in completing this project, our business would thereafter be subject to the following risks:

The price volatility of crude oil, other feedstocks, refined products and fuel and utility services will have a material adverse effect on our potential earnings and cash flows.

Our potential for earnings and cash flows from operations will depend on the margin above fixed and variable expenses (including the cost of refinery feedstocks such as crude oil) at which we are able to sell refined products. Refining margins historically have been volatile and are likely to continue to be volatile, as a result of a variety of factors, including fluctuations in the prices of crude oil, other feedstocks, refined products and fuel and utility services.

In recent years, the prices of crude oil, other feedstocks and refined products have fluctuated. It is possible that this volatility in crude oil pricing and crack spreads (the difference between the purchase price of crude oil and the selling price of the refined finished products, such as gasoline and distillate fuel) may continue for prolonged periods of time due to numerous factors beyond our control. Prolonged periods of low crude oil prices could impact production growth of inland crude oil, which could reduce the amount of advantaged crude oil available and/or the discount of such crude oil and thereby impacting the profitability of the Refinery. Prices of crude oil, other feedstocks and refined products depend on numerous factors beyond our control, including the supply of and demand for crude oil, other feedstocks, gasoline and other refined products. Such supply and demand are affected by, among other things:

	·	changes in global and local economic and political conditions;
	·	domestic and foreign demand for crude oil and refined products, especially in the U.S., China and India;
	·	worldwide political conditions, particularly in significant oil producing regions such as the Middle East, West Africa, Russia and Latin America;
	·	political and geopolitical instability or armed conflict in oil producing regions;
	·	the level of foreign and domestic production of crude oil and refined products and the level of crude oil, feedstocks and refined products imported into the U.S. that can be impacted by accidents, interruptions in transportation, inclement weather or other events affecting producers and suppliers;
	·	U.S. government regulations, including legislation affecting the exportation of domestic crude oil;
	·	utilization rates of U.S. refineries;
	·	changes in fuel specifications required by environmental and other laws;
	·	the ability of the members of the Organization of Petroleum Exporting Countries to influence oil price and production controls;
	·	commodities speculation;
	·	development and marketing of alternative and competing fuels;
	·	pricing and other actions taken by competitors that impact the market;
	·	accidents, interruptions in transportation and inclement weather; and
	·	federal and state government regulations and taxes.

Volatility may have a negative effect on our future results of operations to the extent that the margin between refined product prices and feedstock prices narrows.

The nature of the refining business will require us to maintain substantial quantities of crude oil and refined product inventories. Crude oil and refined products are commodities. As a result, we will have no control over the changing market value of these inventories. In addition, the volatility in costs of fuel, principally natural gas and other utility services, principally electricity, used by the Refinery will impact our planned operating costs. Fuel and utility prices will continue to be affected by factors outside our control, such as supply and demand for fuel and utility services in both local and regional markets. Natural gas prices have historically been volatile. Typically, electricity prices fluctuate with natural gas prices. Future increases in fuel and utility prices may have a material adverse effect on our planned business, financial condition, results of operations and cash flows.

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Our planned operations will be subject to significant hazards and risks inherent in refining operations and in transporting and storing crude oil, intermediate products and refined products.

Failure to identify and manage the hazards and risks inherent in refining operations could result in explosions, fires, refinery or pipeline releases of crude oil or refined products or other incidents resulting in personal injury, loss of life, environmental damage, property damage, legal liability, loss of revenue and substantial fines by government authorities. These hazards and risks include, but are not limited to, the following:

	·	natural disasters;
	·	weather-related disruptions;
	·	fires;
	·	explosions;
	·	pipeline ruptures and spills;
	·	third-party interference;
	·	disruption of natural gas deliveries;
	·	disruptions of electricity deliveries; and
	·	mechanical failure of equipment.

Any of the foregoing could result in production and distribution difficulties and disruptions, environmental pollution, personal injury or wrongful death claims and other damage to our properties and the properties of others. There is also risk of mechanical failure and equipment shutdowns both in general and following unforeseen events.

In addition, we expect to rely on a variety of logistics assets including but not limited to: rail, pipelines, product terminals, storage tanks and trucks to facilitate the movement of crude oil, feedstocks and refined products. We could experience an interruption of supply or an increased cost to deliver refined products to market if the ability to utilize these logistics assets is disrupted. Any sustained disruption is likely to have a material adverse effect on our business, financial condition, results of operations and cash flows.

Weather conditions and natural disasters could materially and adversely affect our business and operating results, including the supply of our feedstocks.

The effects of weather conditions and natural disasters can lead to volatility in the costs and availability of crude oil and other feedstocks and/or negatively impact our operations or those of our customers and suppliers, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. An interruption to our supply of feedstocks could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our planned operations involve environmental risks that could give rise to material liabilities.

Our planned operations could result in spills, discharges, or other releases of petroleum or hazardous substances into the environment. Such spills related to any of our planned operations may give rise to liability (including strict liability, or liability without fault, and clean-up responsibility) to governmental entities or private parties under federal, state, or local environmental laws, as well as under common law. In addition, we may face liability for alleged personal injury or property damage due to exposure to chemicals or other hazardous substances located at or released from our facilities or otherwise related to our planned operations. We may also face liability for personal injury, property damage, natural resource damage, or for clean-up costs for the alleged migration of contamination or other hazardous substances from our facilities to adjacent and other nearby properties.

We may incur significant costs to comply with environmental, health and safety laws and regulations.

Our planned operations are subject to extensive federal, state and local environmental, health and safety regulations governing, among other things, the generation, storage, handling, use and transportation of petroleum and hazardous substances, the emission and discharge of materials into the environment, waste management, characteristics and composition of gasoline, diesel and other fuels and the monitoring, reporting and control of greenhouse gas emissions. If we fail to comply with these regulations, we may be subject to administrative, civil and criminal proceedings by governmental authorities, as well as civil proceedings by environmental groups and other entities and individuals. A failure to comply, and any related proceedings, including lawsuits, could result in significant costs and liabilities, penalties, judgments against us or governmental or court orders that could alter, limit or stop our planned operations. In addition, new environmental laws and regulations, including new regulations relating to alternative energy sources and increased vehicle fuel economy, new state regulations relating to fuel quality, and the risk of global climate change regulation, as well as new interpretations of existing laws and regulations, increased governmental enforcement, or other developments could require us to make additional unforeseen expenditures. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. We are not able to predict the impact of new or changed laws or regulations or changes in the ways that such laws or regulations are administered, interpreted, or enforced. The requirements to be met, as well as the technology and length of time available to meet those requirements, continue to develop and change. To the extent that the costs associated with meeting any or all of these requirements are substantial and not adequately provided for, there could be a material adverse effect on our business, financial condition, results of operations and cash flows.

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The market for hydrogen is nascent and the market may not develop as quickly as the Company projects

The Environmental Protection Agency (the “EPA”) has issued rules pursuantWhile we plan to implement hydrogen off-take agreements with financially viable purchasers, the Water Pollution Control Acthydrogen market today is relatively limited as to purchasers and widespread penetration of 1972 (“Clean Water Act”) that require refiners to reduce the sulfur content of gasoline and dieselmarket as a transportation fuel and reduce the benzene content of gasoline by various specified dates. We may incur substantial costs to comply with the EPA’s low sulfur and low benzene rules. Failure to meet the EPA’s clean fuels mandates could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Various states have proposed and/or enacted low carbon fuel standards intended to reduce carbon intensity in transportation fuels. In addition, in 2010 the EPA issued social cost of carbon estimates used by the EPA and other federal agencies in regulatory cost-benefit analyses to take into account alleged broad economic consequences associated with emissions of greenhouse gases. These estimates were increased in 2013. While the impacts of low carbon fuel standards and higher social cost of carbon in future regulations is not knowndeveloped. In the event any such hydrogen off-take agreements are terminated before their terms, other alternative markets may not be available readily at this time, eithercomparable prices which could impact the Company’s potential results of these may result in increased costs to our planned operations.

Renewable fuels mandates may reduce demand for the petroleum fuels we intend to produce, which could haveCarbon capture technology and sequestration is not currently deployed on a material adverse effect on our business, financial condition, results of operations and cash flows.

Pursuant to the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007, the EPA has promulgated the Renewable Fuel Standard (“RFS”) implementing mandates to blend renewable fuels into petroleum fuels produced and sold in the United States. We are subject to the RFS, which requires obligated parties to blend renewable fuels, such as ethanol, into petroleum fuels sold in the United States. A Renewable Identification Number (a “RIN”) is generated for each gallon of renewable fuel produced under the RFS. At the end of each year, obligated parties must surrender sufficient RINs to meet their renewable fuel obligations under the RFS. The obligated volume increases annually over time until 2022. Uncertainty surrounding RFS requirements in recent years has resulted in increased volatility in RIN prices. We cannot predict the future prices of RINs or waiver credits for cellulosic biofuels from the EPA, but the costs to obtain the necessary number of RINs and waiver credits could be material.

In 2010 and 2011, the EPA issued partial waivers with conditions allowing a maximum of 15% ethanol to be used in certain vehicles. Future changes to existing laws and regulations could increase the minimum volumes of renewable fuels that must be blended with refined petroleum fuels. Because we do not plan to produce renewable fuels, increasing the volume of renewable fuels that must be blended into our products could displace an increasing volume of the Refinery’s product pool, potentially resulting in lower earnings and materially adversely affecting our business, financial condition and results of operations and cash flows.

During 2013, the price of RINs was very volatile as the EPA’s proposed renewable fuel volume mandates approached the “blend wall.” The blend wall refers to the point at which refiners are required to blend more ethanol into the transportation fuel supply than can be supported by the demand for E10 gasoline (gasoline containing 10 percent ethanol by volume). In November 2013, the EPA published the annual renewable fuel percentage standards for 2014, which acknowledged the blend wall and were generally lower than the volumes for 2013 and lower than statutory mandates. The price of RINs decreased significantly after the 2014 percentage standards were published; however, RIN prices remained volatile and increased subsequently in 2014. In November 2015, the EPA published final notice for RFS obligated volumes for 2014, 2015 and 2016 and Biomass-Based Diesel for 2017. The current standard may cause the blend wall to again become an issue affecting the overall supply of RINs.

We cannot predict the future prices of RINs or waiver credits. The cost of RINs is dependent upon a variety of factors, which include EPA regulations, the availability of RINs for purchase, the price at which RINs can be purchased, transportation fuel production levels, the mix of our petroleum products, as well as the fuel blending performed at the Refinery, all of which can vary significantly from quarter to quarter. Additionally, because we do not expect to produce renewable fuels, increasing the volume of renewable fuels that must be blended into our products could displace an increasing volume of the Refinery’s product pool, potentially resulting in lower earnings. If sufficient RINs are unavailable for purchase or if we have to pay a significantly higher price for RINs, or if we are otherwise unable to meet the EPA’s RFS mandates, our business, financial condition, results of operations and cash flows could be materially adversely affected.

To the extent that we export gasoline and diesel, the EPA’s RFS mandates do not apply, increasing the Company’s profitability dramatically. The Company cannot predict the amount of export volumes and how exports of gasoline and diesel may impact the earnings of the Company.

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We could incur significant costs to comply with greenhouse gas emissions regulation or legislation.

The EPA has adopted and implemented regulations to restrict emissions of greenhouse gases under certain provisions of the Clean Air Act. For example, the EPA requires, in certain circumstances, permitting of certain emissions of greenhouse gases from large stationary sources, such as refineries. The EPA has also adopted rules requiring refiners to report greenhouse gas emissions on an annualwide-spread basis, for emissions occurring after January 1, 2010.

To the extent that future legislation, rules and regulations are enacted, our operating costs, including capital expenditures, may increase and additional operating restrictions could be imposed on our business, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. Finally, some scientists have concluded that increasing concentrations of greenhouse gases in the earth’s atmosphere may produce climate changes that may have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events, which if any such event were to occur, it may have a material adverse effect on our business, financial condition, results of operations and cash flows.not developed.

Increased regulationCarbon capture and sequestration of hydraulic fracturing could resultthe CO2 is an emerging technology. While the technology to capture CO2 from refining is available, it is not in reductions or delayswide-spread use.  Sequestering the CO2 after it is captured in crude oil production in our existing areas of operation, which could impact our crude oil supplyunderground formations is a new technology and the regulations and legal framework is evolving.  Today the technical, legal and regulatory framework for injecting CO2 may change dramatically over time and may adversely impact our business.business model.

A significant percentageThe loss of the crude oil production in our existing areas of operation is being developed from unconventional sources, such as shale, using hydraulic fracturing. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate production. A number of federal agencies, including the EPA and the U.S. Department of Energy, are analyzing, or have been requested to review, a variety of environmental issues associated with shale development, including hydraulic fracturing. In addition, the EPA has asserted federal regulatory authority over hydraulic fracturing activities under the Safe Drinking Water Act’s Underground Injection Control Program and under the Toxic Substances Control Act of 1976 and in September 2015 issued proposed rules regulating methane emissions from oil and natural gas completion operations. The rules were finalized in June 2016 and became effective in August 2016. Further, some states and municipalities have adopted and other states and municipalities are considering adopting, regulations prohibiting hydraulic fracturing in certain areas or imposing more stringent disclosure. At the same time, certain environmental groups have suggested that additional laws may be needed to more closely and uniformly regulate the hydraulic fracturing process and legislation has been proposed by some members of Congress to provide for such regulation. We cannot predict whether any such legislation will ever be enacted and if so, what its provisions would be. If additional levels of regulation are imposed at the federal, state or local level, this could result in corresponding delays, increased operating costs and process prohibitions for crude oil producers and potentially negatively impact our crude oil supply, whichMr. Hanks could adversely affect our business, financial condition, results of operations and cash flows.business.

Since Mr. Hanks is our principal executive officer devoting substantially all of his business time to the activities of the Company, if he were to die, become disabled, or leave our company, we would be forced to retain individuals to replace him. There is no assurance that we can find suitable persons to replace him if that becomes necessary. We could experience business interruptions caused by pipeline shutdowns.have no key man life insurance at this time.

Assuming completionRisks Related to our Common Stock and the Offering

Two of our stockholders collectively have the ability to determine any matter to be decided by the stockholders, which may prevent or delay a change in control of our company.

Jack W. Hanks, our CEO, and Bruce N. Lemons, one of the Refinery, we may distribute its products by pipelinetwo members of our Board of Directors, beneficially owned approximately 2,731,676 shares of our common stock as wellof December 31, 2021, which constituted approximately 1.5% of our common stock outstanding as by rail. Certainof such date.  In addition, Mr. Hanks beneficially owns all of our outstanding Series A preferred stock, which represents the right to vote 50.1% of the pipelines we may utilize are subject tovotes presented for the vote of stockholders.  Through such beneficial ownership, Messrs. Hanks and Lemons control approximately 57.3% of the voting power of the common carrier regulatory obligations applicable to interstate oil pipelines that require that capacity must be prorated among shippers in an equitable manner in accordance with the tariff then in effect in the event there are nominations in excessstock on a combined basis as of capacity. Nominations by new shippers or increased nominations by existing shippers may reduce the capacity available to us. Any extended, non-excused downtime at the Refinery could, under certain circumstances, cause us to lose line space on the refined products pipelines used by the Refinery, if we cannot otherwise utilize our pipeline allocations.

December 31, 2021. As a result, we could experience an interruptionthey can determine the outcome of supplyany corporate matter submitted to our stockholders for approval, including the election of directors and any transaction that might cause a change in control, such as a merger or delivery, or an increased cost of receiving crude oil and delivering refined products to market, if the ability of these pipelines to transport crude oil, blended stocks or refined products is disrupted because of accidents, weather interruption, governmental regulation, terrorism, other third-party action, or any other events beyond our control. A prolonged inability to receive crude oil or transport refined products on pipelines that we currently utilize could have a material adverse effect on our business, financial condition, results of operations and cash flows.acquisition.

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The relative costs of oil, natural gas, nuclear power, hydropower and numerous forms of alternative energy production may have a material adverse impact on our business and operating results.

Global and regional energy supply comes from many sources, including oil, natural gas, coal, hydro, nuclear, solar, wind, geothermal and biomass, among others. A cost or supply shift among these sources could negatively impact our business opportunities going forward and the profitability of those opportunities. A demand shift, where technological advances favor the utilization of one or a few sources of energy may also impact the demand for our products. If demand shifts in a manner that increases energy utilization outside of our traditional customer base or expertise, our business and financial results could be materially adversely affected. In addition, governmental policy can affect the relative importance of various forms of energy sources. For example, non-fossil based sources may require and often receive government tax incentives to foster investment. If these incentives become more prominent, our business and results of operations could suffer.

Terrorist attacks, cyber-attacks, threats of war or actual war may negatively affect our future operations, financial condition, results of operations, cash flows and prospects.

Terrorist attacks in the U.S. as well as events occurring in response to or in connection with them, may adversely affect our planned operations, financial condition, results of operations, cash flows and prospects. Energy-related assets may be at greater risk of future terrorist attacks than other possible targets. A direct attack on assets to be used in our planned operations could have a material adverse effect on our operations, financial condition, results of operations, cash flows and prospects. In addition, any terrorist attack could have an adverse impact on energy prices, including prices for crude oil and refined products and an adverse impact on the margins from our future operations. In addition, disruption or significant increases in energy prices could result in government imposed price controls.

Any disruption of, or our inability to access, our information technology systems could adversely impact our business.

Our planned operations are likely to be dependent on technology infrastructure and to maintain and rely upon certain critical information systems. These information systems are expected to include data network and telecommunications, internet access and our websites and various computer hardware equipment and software applications. These information systems will be subject to damage or interruption from a number of potential sources including natural disasters, software viruses or other malware, power failures, cyber-attacks and other events. To the extent that these information systems are under our control, we expect to implement measures such as virus protection software and emergency recovery processes to address the outlined risks. However, security measures for information systems cannot be guaranteed. Breaches to our networks could lead to such information being accessed, publicly disclosed, lost or stolen, and could result in legal claims or proceedings, liability under laws that protect the privacy of customer information, disrupt the services we expect to provide and damage our reputation, any of which could have a material adverse effect on our planned business, financial condition, results of operations and cash flows. Any compromise of our data security or our inability to use or access these information systems at critical points in time could unfavorably impact the timely and efficient operation of our business and subject us to additional costs and liabilities.

Risks Related to Our Common Stock

We have conducted highly dilutive equity related offerings during 2017 and may conduct furtherAdditional stock offerings in the future may dilute then existing stockholders’ percentage ownership of our company.

Given our plans and expectations that we will need additional capital, we anticipate that we will need to issue additional shares of common stock or securities convertible or exercisable for shares of common stock, including convertible preferred stock, convertible notes, stock options or warrants. The issuance of additional securities in the future will dilute the shareholdingspercentage ownership of investors.

Since our inception, we have relied on sales of equity and equity related securities to fund our activities. During 2017, we have conducted convertible note offerings that are highly dilutive to ourthen existing stockholders and, due to the original issue discount of the notes and significant redemption premiums, have a high cost of capital. In addition, we entered into an Equity Purchase Agreement with Crown Bridge pursuant to which we have the right to put up to $3,000,000 of our Class A common stock to Crown Bridge. The purchase price of shares issued in connection with each put notice is 80% of the lowest traded price of our Class A common stock in the seven trading days immediately following the clearing date of the put shares for the respective put notice. We expect to conduct further equity offerings in the future to continue as a going concern. As additional equity securities are issued, investors’ percentage interests in our equity ownership will be diluted. The result of this could reduce the value of current investors’ stock. Further, if common stock is issued in return for additional funds, the price per share could be lower than that paid by our current stockholders.

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We are subject to penny stock regulations and restrictions and you may have difficulty selling shares of our Class A common stock.

Our Class A common stock is subject to the provisions of Section 15(g) and Rule 15g-9 of the Securities Exchange Act of 1934 (the “Exchange Act”), commonly referred to as the “penny stock rule.” Section 15(g) sets forth certain requirements for transactions in penny stock, and Rule 15g-9(d) incorporates the definition of “penny stock” that is found in Rule 3a51-1 of the Exchange Act. The Securities and Exchange Commission (the “SEC”) generally defines a penny stock to be any equity security that has a market price less than $5.00 per share, subject to certain exceptions. We are subject to the SEC’s penny stock rules.

Since our Class A common stock is deemed to be penny stock, trading in the shares of our Class A common stock is subject to additional sales practice requirements on broker-dealers who sell penny stock to persons other than established customers and accredited investors. “Accredited investors” are persons with assets in excess of $1,000,000 (excluding the value of such person’s primary residence) or annual income exceeding $200,000 or $300,000 together with their spouse. For transactions covered by these rules, broker-dealers must make a special suitability determination for the purchase of such security and must have the purchaser’s written consent to the transaction prior to the purchase. Additionally, for any transaction involving a penny stock, except in certain circumstances, the rules require the delivery, prior to the first transaction of a risk disclosure document, prepared by the SEC, relating to the penny stock market. A broker-dealer also must disclose the commissions payable to both the broker-dealer and the registered representative and current quotations for the securities. Finally, monthly statements must be sent disclosing recent price information for the penny stocks held in an account and information to the limited market in penny stocks. Consequently, these rules may restrict the ability of broker-dealer to trade and/or maintain a market in our Class A common stock and may affect the ability of the Company’s stockholders to sell their shares of Class A common stock.

There can be no assurance that our shares of Class A common stock will qualify for exemption from the “penny stock rule”. In any event, even if our Class A common stock was exempt from the “penny stock rule”, we would remain subject to Section 15(b)(6) of the Exchange Act, which gives the SEC the authority to restrict any person from participating in a distribution of penny stock if the SEC finds that such a restriction would be in the public interest.

We do not expect to pay dividends in the foreseeable future.

We do not intend to declare dividends for the foreseeable future, as we anticipate that we will reinvest any future earnings in the development and growth of our business. Therefore, our stockholders will not receive any funds unless they sell their Class A common stock, and stockholders may be unable to sell their shares on favorable terms or at all.

Our Class A common stock is subject to price volatility unrelated to our operations.

The market price of our Class A common stock could fluctuate substantially due to a variety of factors, including market perception of our ability to achieve our planned growth, quarterly operating results of other companies in the same industry, trading volume in our Class A common stock, changes in general conditions in the economy and the financial markets or other developments affecting the Company’s competitors or the Company itself. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to their operating performance and could have the same effect on our Class A common stock.

Trading inBecause our Class A common stock on the OTCQB is limited and sporadic making it difficult for our stockholders to sell their shares or liquidate theirinvestments.

Our Class A common stock is currently listed for public trading onsubject to the OTCQB tier of the OTC Markets Group, Inc. penny stock rules, it may be more difficult to sell our common stock.

The tradingSEC has adopted rules that regulate broker-dealer practices in connection with transactions in penny stocks. Penny stocks are generally equity securities with a price of our Class A common stock has been subject to wide fluctuations. Trading prices of our Class A common stock may fluctuate in response to a number of factors, many of which will be beyond our control. The stock market has generally experienced extremeless than $5.00 (other than securities registered on certain national securities exchanges or authorized for quotation on certain automated quotation systems, provided that current price and volume fluctuations that have often been unrelatedinformation with respect to transactions in such securities is provided by the exchange or disproportionate to the operating performance of companies with no current business operation. There can be no assurance that trading prices and price earnings ratios previously experienced by our Class A common stock will be matched or maintained. These broad market and industry factors may adversely affect the market price of our Class A common stock, regardless of our operating performance. In the past, following periods of volatility in the market price of a company’s securities, securities class-action litigation has often been instituted. Such litigation, if instituted, could result in substantial costs for us and a diversion of management’s attention and resources. Further, on January 8, 2018, we received a letter from OTC Markets that the bid price of our Class A common stock had closed below $0.01 for more than 30 consecutive calendar days and no longer meets the Standards for Continued Eligibility for OTCQB. Per Section 4.1 of the OTCQB Standards, we have been granted a cure period of 90 calendar days during which the minimum closing bid price for our Class A common stock must be $.01 or greater for ten consecutive trading days in order to continue trading on the OTCQB marketplace.system).  If this requirement is not met by April 8, 2018, the listing of our Class A common stock will be removed from the OTCQB marketplace.

Our Articles of Incorporation provide indemnification for officers, directors and employees.

Our governing instruments provide that officers, directors, employees and other agents and their affiliates shall only be liable to our Company for losses, judgments, liabilities and expenses that result from matters involving intentional misconduct, fraud or a knowing violation of law. Thus certain alleged errors or omissions might not be actionable by us. The governing instruments also provide that, under the broadest circumstances allowed under law, we must indemnify our officers, directors, employees and other agents and their affiliates for losses, judgments, liabilities, expenses and amounts paid in settlement of any claims sustained by them in connection with our Company, including liabilities under applicable securities laws.

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Crown Bridge will pay less than the then-prevailing market price for our Class A common stock.

The shares of Class A common stock to be issued to Crown Bridge pursuant to the Equity Purchase Agreement will be purchased at 80% of the lowest traded price of our Class A common stock in the seven trading days immediately following the clearing date of the put shares for the respective put notice. Because the put price and the conversion rate are lower than the prevailing market price of our Class A common stock, Crown Bridge has a financial incentive to sell our Class A common stock immediately upon receiving the shares to realize the profit equal to the difference between the discounted price and the market price. If Crown Bridge sells the shares, the price of our Class A common stock could decrease. If our stock price decreases, Crown Bridge may have a further incentive to sell its shares of the Class A common stock that it holds. These sales may have a further impact on our stock price.

The sale of a substantial number of shares of our common stock, or the perception that such sales could occur, could adversely affect prevailing market prices for our common stock.

The market price of our common stock could decline as a result of issuances and sales by us, including pursuant to the Equity Purchase Agreement, or sales by our existing shareholders, of common stock, or the perception that these issuances and sales could occur. Sales by our shareholders might also make it more difficult for us to issue and sell common stock at a time and price that we deem appropriate. It is likely that the sale of shares by Crown Bridge will depress the market price of our common stock.

The issue and sale of the shares under the Equity Purchase Agreement may also have an adverse effect on the market price of the common shares. Crown Bridge may resell some, if not all, of the shares that we issue to it under the Equity Purchase Agreement and such sales could cause the market price of the common stock to decline significantly. To the extent of any such decline, any subsequent puts would require us to issue and sell a greater number of shares to Crown Bridge in exchange for each dollar of the put amount. Under these circumstances, the existing shareholders of our company will experience greater dilution. The effect of this dilution may, in turn, cause the price of our common stock to decrease further, both because of the downward pressure on the stock price that would be caused by a large number of sales of our shares into the public market by Crown Bridge,remains less than $5.00 and because our existing stockholders may disagree with a decision to sell shares to Crown Bridge at a time when our stock price is low, and may in response decide to sell additional shares, further decreasing our stock price. If we draw down amounts under the Equity Purchase Agreement when our share price is decreasing, we will need to issue more shares to raise the same amount of funding.

Any shares of our common stock we issueis not listed on a national securities exchange such as OTCQB, our stock may be deemed a penny stock. The penny stock rules require a broker-dealer, at least two business days prior to a transaction in connection witha penny stock not otherwise exempt from those rules, to deliver to the put option undercustomer a standardized risk disclosure document containing specified information and to obtain from the Equity Purchase Agreement, orcustomer a signed and date acknowledgment of receipt of that document. In addition, the conversion option underpenny stock rules require that prior to effecting any transaction in a penny stock not otherwise exempt from those rules, a broker-dealer must make a special written determination that the penny stock is a suitable investment for the purchaser and receive: (i) the purchaser’s written acknowledgment of the receipt of a risk disclosure statement; (ii) a written agreement to transactions involving penny stocks; and (iii) a signed and dated copy of a written suitability statement. These disclosure requirements may have the effect of reducing the trading activity in the secondary market for our convertible notes, will cause your ownership interest to be diluted.common stock, and therefore stockholders may have difficulty selling their shares.

Crown Bridge has committed to purchase up to $3,000,000 worth of shares of our Class A common stock. From time to time during the term of the Equity Purchase Agreement, and at our sole discretion, we may present Crown Bridge with a put notice requiring Crown Bridge to purchase shares of our Class A common stock. The purchase price to be paid by Crown Bridge will be 80% of the lowest traded price of our Class A common stock in the seven trading days immediately following the clearing date of the put shares for the respective put notice. As a result, our existing shareholders will experience immediate dilution upon the purchase of any of the shares by Crown Bridge. In addition, because the shares that will be issued in connection with the exercise of our put right or upon the conversion of any of our convertible notes may be sold or converted at a price less than the prevailing market value, the value of your aggregate shareholdings in the Company will be diluted.

We may not have access to the full amount available under the Equity Purchase Agreement.

There is no guarantee that we will satisfy the conditions to the Equity Purchase Agreement. Although the Equity Purchase Agreement provides that we can require Crown Bridge to purchase, at our discretion, up to $3,000,000 worth of shares of our Class A common stock in the aggregate, there can be no assurances that we will be able to satisfy the closing conditions applicable for each put. For example, our ability to draw down funds and sell shares under the Equity Purchase Agreement requires that this resale registration statement be declared effective and continue to be effective. This registration statement registers the resale of 300,000,000 shares issuable under the Equity Purchase Agreement, and our ability to sell any remaining shares issuable under the Equity Purchase Agreement is subject to our ability to prepare and file one or more additional registration statements registering the resale of these shares. These registration statements may be subject to review and comment by the staff of the SEC, and will require the consent of our independent registered public accounting firm. Therefore, the timing of effectiveness of these registration statements cannot be assured and may affect our ability to put shares to Crown Bridge. If we fail to satisfy the applicable closing conditions, we will not be able to sell the put shares to Crown Bridge. There is no guarantee that we will be able to fully utilize the Equity Purchase Agreement. This description is qualified in its entirety by reference to the Equity Purchase Agreement, which is incorporated by reference as an exhibit to the Registration Statement of which this prospectus forms a part.

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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains certain forward-looking statements. When used in this prospectus 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 prospectus 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 prospectus 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.

USE OF PROCEEDS

We will not receive any proceeds from the sale of Shares by the selling stockholders. All proceeds from the sale of the Shares will be for the account of the selling security holder. However, we will receive proceeds from the sale of securities to Crown Bridge pursuant to our exercise of a put right granted to us in the Equity Purchase Agreement. Crown Bridge is deemed an underwriter of our common stock.stockholders.

Our business plan contemplates that we will draw upon the entire $3,000,000 worth of Class A Common Stock under the Equity Purchase Agreement. However, there is no guarantee that we will continue to satisfy all of the conditions precedent to each draw under the Equity Purchase Agreement. See “Risk Factors-- We may not have access to the full amount available under the Equity Purchase Agreement . ”

From April through December 2017, we issued an aggregate of approximately $1,382,000 principal amount of convertible notes resulting in net proceeds to us of approximately $990,000. As of January 15, 2018, the aggregate principal amount of these convertible notes, including accrued interest and net of conversions into our Class A common stock, was approximately $797,000. We incurred the indebtedness under the convertible notes in order to provide working capital for the Company since April 2017, given that we have yet to generate any revenues from operations. We intend to utilize the net proceeds from any puts tendered to Crown Bridge under the Equity Purchase Agreement for the repayment of our indebtedness under then outstanding convertible notes until we have retired all such notes. The table below sets forth the payee, principal balance, maturity dates, interest rates and maximum redemption premium for each of the convertible notes so issued that remained outstanding at January 15, 2018:

		Principal				Maturity		Maximum				Redemption
Payee		Balance				Date		Interest Rate				Price
GS Capital Partners		$	50,000			5/24/18			8	%			147	%
JSJ Investments		$	100,000			3/30/18			12	%			150	%
Auctus Fund		$	115,000			6/1/18			12	%			135	%
Power Up Lending		$	123,500			6/20/18			12	%			145	%
		$	111,773			11/14/18			12	%			133	%
Vista Capital		$	184,800			10/19/19			12	%			145	%
		$	112,000			12/14/19			12	%			145	%

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If planned draws under the Equity Purchase Agreement are not sufficient to retire the outstanding convertible notes, we will be required to obtain alternative sources of capital to refinance or retire the convertible notes when they mature, unless the holders thereof convert the outstanding balance into our Class A common stock pursuant to the terms of the convertible notes.

After the assumed repayment of our outstanding convertible notes, the amount of net proceeds received from any additional puts tendered to Crown Bridge under the Equity Purchase Agreement will be used for general corporate and working capital purposes and acquisitions or assets, businesses or operations or for other purposes that the Board of Directors, in its good faith deem to be in the best interest of the Company. The net proceeds of the Equity Purchase Agreement, even if fully drawn, are not sufficient to commence construction of the Company’s planned Refinery facilities. The Company will require substantial additional equity and debt financing to accomplish such objective. See “Business—Proposed Organizational Structure.”

DETERMINATION OF OFFERING PRICEDILUTION

The actual offering priceselling stockholders may offer all or portion of the selling stockholdersshares of the Sharescommon stock covered by this prospectus will be determined byfor resale from time to time through public or private transactions, at either prevailing market prices or at the time of sale, by private transactionsprivately negotiated by the selling stockholders or as otherwise describedprices. If you invest in the section entitled “Plan of Distribution.” The offering price of our common stock does not necessarily bear any relationshipin this offering at the closing price of $0.2350 per share in effect on December 31, 2021, your ownership interest will be diluted immediately to ourthe extent of the difference between such price per share and the net tangible book value assets, past operating results, financial condition or any other established criteriaper share of value. Our common stock may not trade at market prices in excessimmediately after this offering.

Our net tangible book value deficit is the amount of the offering priceour total tangible assets less our total liabilities. Our net tangible book value deficit as prices forof October 31, 2021 was $1,750,358, or $.0928 per share of common stock (based on shares outstanding at December 31, 2021). This represents an immediate dilution in any public market will be determinednet tangible book value of $0.1421 per share to new investors participating in the marketplace and may be influenced by many factors.this offering.

DILUTION

Under the Equity Purchase Agreement, the purchase price of the shares to be sold to Crown Bridge will be at a price equal to 80% of the lowest traded price of our Class A common stock in the seven trading days immediately following the clearing date of the put shares for the respective put notice. The table below illustrates an issuancenumber of shares of Class A common stock to Crown Bridge underthat will be outstanding after this offering is based on 18,845,362 shares of common stock outstanding as of December 31, 2021 and excludes 35,730,684 shares of common stock issuable upon the Equity Purchase Agreement for a hypothetical draw down amountexercise of $25,000 at an assumed trading priceoptions and warrants or the conversion of $0.01:shares of Series B Preferred Stock outstanding as of such date.

By comparison, if the trading price of our Class A common stock was $0.0075, the number of shares that we would be required to issue in order to have the same draw down amount of $25,000 would be greater, as shown by the following table:

Draw Down Amount				Price to be paid by Crown Bridge				Number of Shares to be Issued
$	25,000			$	0.006				4,166,667

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Accordingly, there would be dilution of an additional 1,041,667 shares issued due to the lower stock price of $0.0075 per share. In effect, if we are interested in receiving a fixed funding amount, a lower price per share of our common stock means a higher number of shares to be issued to Crown Bridge in order to receive that fixed funding amount, which equates to greater dilution of existing stockholders. The effect of this dilution may, in turn, cause the price of our Class A common stock to decrease further, both because of the downward pressure on the stock price that would be caused by a large number of sales of our shares into the public market by Crown Bridge, and because our existing stockholders may disagree with a decision to sell shares to Crown Bridge at a time when our stock price is low, and may in response decide to sell additional numbers of shares, further decreasing our stock price.

The actual number of shares that will be issued to Crown Bridge under the Equity Purchase Agreement will depend upon the market price of our common stock at the time of our puts to Crown Bridge and shortly thereafter.

MARKET PRICE OF AND DIVIDENDS ON OUR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

Public Market for Common Stock

Commencing on November 2, 2017,Since April 10, 2018, our Class A common stock has been listed on the OTCQBOTC Pink under the symbol “MMEX”"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. Prior toFrom November 2, 2017 through April 9, 2018, our common stock (then known as Class A common stockCommon Stock) was quotedlisted on the OTC Pink tier.OTCQB. The following table indicates the quarterly high and low bid price for our Class A common stock for the fiscal years ending April 30, 20162021 and April 30, 2017 and for the current fiscal year through January 19, 2018.2020. Such inter-dealer quotations do not necessarily represent actual transactions and do not reflect retail mark-ups, mark-downs or commissions. The Company amended its articles of incorporation to provide for a 1 for 10,000 reverse stock split of its common shares, which was effective as of July 1, 2021. The Company has given retroactive effect to the reverse stock split for all periods presented.

		High				Low
Fiscal year ended April 30, 2016
Quarter ended July 31, 2015		$	0.02			$	0.01
Quarter ended October 31, 2015		$	0.02			$	0.02
Quarter ended January 31, 2016		$	0.02			$	0.0041
Quarter ended April 30, 2016		$	0.0063			$	0.0041
Fiscal year ended April 30, 2017
Quarter ended July 31, 2016		$	0.0063			$	0.0049
Quarter ended October 31, 2016		$	0.0104			$	0.0049
Quarter ended January 31, 2017		$	0.0049			$	0.0001
Quarter ended April 30, 2017		$	0.0563			$	0.0001
Fiscal year ended April 30, 2018
Quarter ended July 31, 2017		$	0.0097			$	0.0066
Quarter ended October 31, 2017		$	0.0249			$	0.0076
Quarter ending January 31, 2018 (through January 19, 2018)		$	0.0182			$	0.0061

On January 19, 2018,4, 2022, the closing bid price of the Class Aour common stock as reported on the OTCQBOTC Pink was $0.0068. We have not repurchased any of our equity securities.$0.23 per share.

On January 8, 2018, we received a letter from OTC Markets thatThe number of holders of record of the bid price of our Class ACompany's common stock had closed below $0.01 for more than 30 consecutive calendar days and no longer meets the Standards for Continued Eligibility for OTCQB. Per Section 4.1as of the OTCQB Standards, we have been granted a cure period of 90 calendar days during which the minimum closing bid price for our Class A common stock must be $.01 or greater for ten consecutive trading days in order to continue trading on the OTCQB marketplace. If this requirement is not metDecember 31, 2021 was 148, as reported by April 8, 2018, the listing of our Class A common stock will be removed from the OTCQB marketplace.

We intend to maintain compliance with the OTCQB Standards. To the extent that market conditions do not otherwise result in our Class A common stock exceeding the minimum closing bid price requirements, we would expect to effect a reverse split of our Class A common stock in order to achieve compliance with the OTCQB Standards.

Holders

As of January 15, 2018 , 2017, we had 143 record holders of our Class A common stock and one record holder of our Class B common stock, according to the books of our transfer agent. TheThis number of our stockholders of record excludesdoes not include an undetermined number of stockholders whose shares arestock is held in “street”"street" or “nominee”"nominee" name.

Dividends

We have not declared or paid any cash or other dividends on theour common stock to date for the last two fiscal years and have no intention of doing so in the foreseeable future. See “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

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Equity Compensation Plans

As of April 30, 2017, the following securities were issuable under the Company’s equity compensation plans. As set forth in the table below, none of these transactions were approved by shareholders.

______________

Penny Stock

Our common 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.

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Dividends

We have not declared or paid any cash or other dividends on the common stock and have no intention of doing so in the foreseeable future. See “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Equity Compensation Plans

As of April 30, 2021, the following securities were issuable under the Company’s equity compensation plans:

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 the Risk Factors, Cautionary Notice Regarding Forward-Looking Statements and Business sections in this Prospectus. 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.

Overview

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 in 2010 and thereafter changed the Company’s name to MMEX Mining Corporation. In 2016, the Company changed its name to MMEX Resources Corporation to reflect the change in its business plan to an energy focus in the Americas.

Business Plan

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

Overview

Business Plan

We areCompany is a development stagedevelopment-stage company engaged in the exploration, extraction, refining and distribution of oil, gas, petroleum products and electric power. We plan to focusfocusing on the acquisition, development and financing of oil, gas, refining and electric powerinfrastructure projects in Texas Peru, and other countriesSouth America, recently announcing it intends to develop solar energy to power multiple planned projects producing hydrogen and ultra-low sulfur fuels combined with carbon dioxide (CO2) capture in Latin America using the expertise of our principals to identify, finance and acquire these projects.Texas.

The most significantSince 2016, the focus of our current business plan ishas been to build crude oil distillation units and refining facilities (CDUs) in the Permian Basin in West Texas. We intend to implementrevised our current business plan in two phases, First, through2021 to move MMEX to clean energy use and production, leveraging our subsidiary,history, management and business relationships from the traditional energy sector. The focus of our business plan is to

Our immediate plans are to pursue the following three projects powered by solar energy:

Project 1: A clean fuels 10,000 barrel per day facility at our Pecos Refining, we intendCounty site to buildproduce 87° gasoline, ultra-low sulphur diesel and commence operationlow-sulphur fuel oil, utilizing the Ultra Fuels Plus with carbon capture concept.

Project 2: We have teamed with Black Tree Group to develop a “blue hydrogen” facility in Pecos County to produce hydrogen with carbon capture and storage employing steam methane reformer technology with the abundant natural gas supplies in the immediate area as the feedstock.

Project 3: A parallel “green hydrogen” plant in Pecos County, which plans to utilize the proprietary electrolizer technology of a 10,000 bpd crude oil Distillation Unitmajor international technology partner.

We are in various stages of negotiations with major company off-takes that will produce a non-transportation grade diesel primarily for sale in the local market for drilling mudrange from specialty air and frac fluids, along with naphthagas companies to international trading companies. The proposed distribution network of liquid and heavy fuel oil to be sold to other refiners. Second, through a separate subsidiary, we intend to build and commence operation of the Large Refinery with up to 100,000 bpd capacity at the same location in West Texas. Thesegaseous hydrogen from our planned projects will be built on 476 acres located 20 miles northeast of Fort Stockton, Texas, near the Sulfur Junction spur of the Texas Pacifico Railroad. If successfully developed, the Refinery would connect to existing railwaysby truck 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.rail.

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 constructionResults of the Distillation Unit and we received the permit from TCEQ on August 30, 2017. The permitting process for the Large Refinery is expected to be 12-18 months. Additionally, the construction of the Distillation Unit will require significantly less capital than the construction of the Large Refinery. As a result, the less capital will be required to build and complete the project and generate revenue and profits.Operations

Initially, Pecos Refining, the owner of the Distillation Unit,Three and the entity we formSix Months Ended October 31, 2021 compared to own and operate the Large Refinery will be wholly-owned subsidiaries of the Company. However, 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, 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 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. 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.October 30, 2020

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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 Refinery 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. On August 4, 2017 the Texas Department of Transportation’s (TxDOT) announced receipt of 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 are expected to help 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.

According to a report the Company received from VFuels Oil & Gas Engineering, the cost of a Distillation Unit with a 10,000 bpd capacity would be approximately $50 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 Refinery will require a significant number of governmental permits and approvals. The principal permit for the construction of the Refinery is the air quality permit issued by TCEQ and it was received by the Company on August 30, 2017. Trinity Consultants, the Company’s air quality permit advisor, estimates it will take approximately 18 months once the permit is filed to obtain the air quality permit for the Large Refinery. According to VFuels Oil & Gas Engineering, construction for the Distillation Unit would take approximately 12 to 15 months . . 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.

We have no direct operations and no significant assets other than certain contractual rights relating to the ownership of certain real property and the development of the Refinery.

Results of Operations

Revenues

We have not yet begun to generate revenues.

General and Administrative Expenses

Our general and administrative expenses increased to $274,493 for the three months ended October 31, 2021 from $179,350 for the three months ended October 31, 2020 and increased to $717,000 for the six months ended October 31, 2021 from $362,675 for the six months ended October 31, 2020. The increase resulted from higher professional fee costs, which included increased costs for legal, public relations, and consulting services.

Project Costs

Our project costs increased to $1,006,666 for the three months ended October 31, 2021 from $51,985 for the three months ended October 31, 2020 and increased to $1,009,726 for the six months ended October 31, 2021 from $89,685 for the six months ended October 31, 2020. We expense the direct costs incurred on our projects, including acquisition of rights, planning, design and permitting. During the six months ended October 31, 2021 we entered into, and paid for, planning and design contracts for our project development. The levels of spending on our projects will vary from period to period based on availability of financing and will be expensed as project costs are incurred.

Depreciation and Amortization Expense

Our depreciation and amortization expense results from the depreciation of land improvements and amortization of land easements and totaled to $9,246 and $8,720 for the three months ended October 31, 2021 and 2020, respectively. The depreciation and amortization was $17,964 and $17,438 for the six months ended October 31, 2021 and 2020, respectively.

Other Income (Expense)

Our interest expense includes interest accrued on debt, amortization of debt discount and penalties assessed on debt. Interest expense totaled $57,645 and $171,054 for the three months ended October 31, 2021 and 2020, respectively, and totaled $262,255 and $725,143 for the six months ended October 31, 2021 and 2020, respectively. The decrease in interest expense is due to a lower levels of new non-related party convertible debt in the current period, resulting in less amortization of debt discount to interest expense, less loan penalties incurred in the period, and reduced debt balances as a result of debt being paid off or converted into shares common stock.

We reported gains on derivative liabilities of $0 and $102,341 for the three months ended October 31, 2021 and 2020, respectively and $3,010,042 and $1,289,693 for the six months ended October 31, 2021 and 2020, respectively. We had previously identified the variable conversion feature of certain convertible notes payable as derivatives. We estimated 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 were subject to significant changes from period to period and to management’s judgment; therefore, the estimated fair value of the derivative liabilities would fluctuate from period to period, and the fluctuation has been material. During the six months ended October 31, 2021 all derivative liabilities were written off the books, resulting in a larger gain in the current period than in the prior period.

We reported a net gain on extinguishment of liabilities of $196,166 and $136,310 for the three and six months ended October 31, 2021, respectively, which could be explained by the fact that our loan from the Small Business Administration was forgiven and we had other vendors forgive us for amounts owing. We reported no gain or loss on extinguishment of liabilities for the three or six months ended October 31, 2020.

Net Income (Loss)

As a result of the above, we reported net income (loss) of $(1,151,884) and $(308,768) for the three months ended October 31, 2021 and 2020, respectively, and $1,139,407 and $94,752 for the six months ended October 31, 2021 and 2020, respectively.

Non-Controlling Interest in Income of Consolidated Subsidiaries

Currently, we have no activity in our consolidated subsidiaries. Non-controlling interest in income of consolidated subsidiaries was $0 for all periods presented.

Net Income (Loss) Attributable to the Company

Because we had no non-controlling interest in income of consolidated subsidiaries, net income (loss) attributed to the Company was the same as net income (loss).

Fiscal Year ended April 30, 2021 Compared to Fiscal Year ended April 30, 2020

We recorded a net loss of $24,526,886 or $(14.23) per share, for fiscal year ended April 30, 2021, compared to a net loss of $4,393,689 or $(6.57) per share, for the fiscal year ended April 30, 2020. 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 decreased $20,132$36,835 to $211,160$867,471 for the year ended April 30, 20172021 from $231,292$904,306 for the year ended April 30, 2016.2020. The decrease is due to reduced payroll and operating expenses as we have focused on our new development strategy, offset by increased professional fees.

Our general and administrative expenses increased $29 ,930 to $132 ,581 for the three months ended October 31, 2017resulted from $102 ,651 for the three months ended October 31, 2016, and increased $ 3 44,470 to $ 4 70,711 for the six months ended October 31, 2017 from $ 126,241 for the six months ended October 31, 2017 . The increase s are due to additional professional fees,lower salaries, travel and other expenses associated with securing debt financing and administrative activities of our proposed refinery project and filingdevelopment activities due to limitations on funding during the current fiscal year.

Start-Up Costs

During the year ended April 30, 2021, the expenditures for the development of our S-1 registration statement.

Refinery Start-Up Costs

CDU project in Pecos County, Texas decreased from the prior fiscal year due to financing constraints. We expense the directhave expensed all costs incurred, prior to opening the Refinery, including acquisition of refinery rights, planning, design and permitting. Such costs totaled $372,560$179,133 and $214,439 for the yearyears ended April 30, 2017 . We did not incur any refinery start-up costs during the year ended April 30, 2016.2021 and 2020, respectively.

Depreciation and Amortization Expense

Our depreciation and amortization expenses are not currently material to our operationsremained constant, totaling $34,875 and our property and equipment was fully depreciated as of April 30, 2017. Depreciation and amortization expenses were $386 and $1,947$34,663 for the years ended April 30, 20172021 and 2016,2020, respectively. The expense results from the depreciation of land improvements and amortization of land easements.

Depreciation and amortization expenses were $417 and $62 for the three months ended October 31, 2017 and 2016, respectively, and $707 and $386 for the six months ended October 31, 2017 and 2016, respectively.

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Other Income (Expense)

Our interest expense decreased $246,213$703,108 to $283,261$1,143,495 for the year ended April 30, 20172021 from $529,474$1,846,603 for the year ended April 30, 2016 due2020. We entered into fewer convertible debt arrangements in the current fiscal year, resulting in less amortization of debt discount to a reduction in our interest-bearing indebtedness,interest expense, which was partially offset by the fees incurred on and debt discount amortization associated with new convertible notes issued in fiscal year 2017.

Our interest expense increased $351,093 to $431,793 for the three months ended October 31, 2017 from $80,700 for the three months ended October 31, 2016, and increased $609,462 to $726,401 for the six months ended October 31, 2017 from $116,939 for the six months ended October 31, 2016. The increase in interest expense is due to interest accrued on new convertible debt during the current fiscal year, including amortization of debt discount. loan penalties and default interest.

For the years ended April 30, 20172021 and 2016,2020, we reported a losslosses on derivative liabilities of $6,105,727$22,906,922 and $395,619, respectively . The increase in loss on derivative liabilities resulted primarily from the issuance of new warrants.

We reported a loss on derivative liabilities of $514,129 and $52,587 for the three months ended October 31, 2017 and 2016, respectively, and reported a gain on derivative liabilities of $3,952,554 and $33,108 for the six months ended October 31, 2017 and 2016,$1,402,233, respectively. The increase in gain on derivative liabilities in the first six months of the current fiscal year resulted primarily from the exercise of substantially all warrants.

In a series of subscription agreements, we issued warrants in prior years 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 these fluctuationsthe fluctuation may be material.

We reported a gain on assignment and assumption agreement of $1,090,271 for the three months and six months ended October 31, 2017. 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.

For the year ended April 30, 2017, we reported a gain on extinguishment of debt from the settlement of accrued salaries of $207,803. For the year ended April 30, 2016, we reported a loss on extinguishment of debt of $1,365,521 resulting primarily from the conversion of preferred stock and accrued dividends and convertible notes payable to shares of our common stock. We record the value of the shares issued at the current market price, which was significantly higher than the conversion price per share, resulting in a loss on conversion.

We reported a gain on extinguishment of debt of $475,587$605,010 for the six monthsyear ended October 31, 2017 resultingApril 30, 2021 compared to a gain on extinguishment of debt of $8,555 for the year ended April 30, 2020. The gain on extinguishment of debt generally results from the settlement and extinguishment of a convertible notenotes payable preferred stock and certain accounts payable and accrued expenses. Where sharesDuring the year ended April 30, 2021 we settled certain notes which resulted in principal and accrued interest being written off for a gain of our Class A common stock are issued in extinguishment$242,102. We also recorded a gain of debt, we record$194,008 for the valuewrite off of the shares issued atderivative liabilities associated with the current market price, which at times is significantly higher than the book valuesettlement of the debt, resulting innotes and we recorded a gain on extinguishment of debt. We had no gain or loss on extinguishment of debt for$167,900 when the three months ended October 31, 2017 and 2016 andUnited States Small Business Administration forgave our loan issued under the six months ended October 31, 2016.

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Paycheck Protection Program.

Net Income ( Loss)(Loss)

As a result of the above, our net loss increased to $6,765,291 for the year ended April 30, 2017 from $2,523,853 for the year ended April 30, 2016.

Wewe reported net losses of $154,069$24,526,886 and $236,000$4,393,689 for the three months ended October 31, 2017 and 2016, respectively, and a net loss of $210,458 for the six months ended October 31, 2016. Primarily as a result of the gain on derivative liabilities, gain on assignment and assumption agreement and gain on extinguishment of debt discussed above, we reported net income of $3,822,062 for the six months ended October 31, 2017.

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

Non-controlling interest in loss of consolidated subsidiaries remained constant and was $1,824 for the yearyears ended April 30, 2017 compared to $1,838 for the year ended April 30, 2016 .2021 and 2020, respectively.

Non-controlling interest in income of consolidated subsidiaries was $651,005 and $650,659 for the three months and six months ended October 31, 2017, respectively. Non-controlling interest in loss of consolidated subsidiaries was $453 and $915 for the three months and six months ended October 31, 2017 and 2016, respectively. The increase in non-controlling interest in income of consolidated subsidiaries in the current fiscal year resulted from elimination of the accounts of MCCH, MCC and CC pursuant to an Assignment and Assumption Agreement entered into on September 18, 2017. Prior to this agreement, we had little activity in these consolidated subsidiaries.

Net Income ( Loss)Attributable to the Company

Net loss attributable to the Company increased to $6,763,467 for the year ended April 30, 2017 from $2,522,015 for the year ended April 30, 2016.

Net loss attributable to the Company was $805,074 and $235,547 for the three months ended October 31, 2017 and 2016, respectively, and $209,543 for the six months ended October 31, 2016. Net income attributable to the Company was $3,171,403 for the six months ended October 31, 2017.

Liquidity and Capital Resources

Working Capital

As of October 31, 2017,2021, we had current assets of $50, 297,$309,119, comprised of cash and prepaid expenses, and current liabilities of $3,253,684,$2,770,086, resulting in a working capital deficit of $3,203,387. Included in our current liabilities as of October 31, 2017 are derivative liabilities of $1,789,047, which we do not anticipate will require the payment of cash.$2,460,967.

Our total current liabilities as of October 31, 2017 decreased $5,750,738 to $3,253,684 from $9,004,422 as of April 30, 2017. The decrease resulted primarily from the decrease in derivative liabilities and the decrease in currently liabilities resulting from assumption of liabilities pursuant to an Assignment and Assumption Agreement entered into on September 18, 2017, partially offset by increased borrowings of the Company.

Sources and Uses of Cash

Our sources and uses of cash for the yearsthree months ended April 30, 2017October 31, 2021 and 20162020 were as follows:

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We used net cash of $281,409 in operating activities for the year ended April 30, 2017 as a result of net loss attributable to the Company of $6,763,467, non-controlling interest in net loss of consolidated subsidiaries of $1,824 and non-cash gain of $207,803, partially offset by non-cash expenses totaling $6,499,532 and increases in accounts payable of $49,201 and accrued expenses of $142,952.

By comparison, we used net cash of $74,111 in operating activities for the year ended April 30, 2016 as a result of net loss attributable to the Company of $2,522,015, non-controlling interest in loss of consolidated subsidiaries of $1,838 and a decrease in accounts payable of $12,985, partially offset by non-cash expenses totaling $2,171,341 and an increase in accrued expenses of $291,386.

We had no net cash provided by or used in investing activities for the years ended April 30, 2017 and 2016.

We had net cash provided by financing activities of $334,892 for the year ended April 30, 2017, comprised of proceeds from common stock payable of $49,741, proceeds from issuance of common stock of $76,369 and net proceeds from convertible notes payable of $208,782.

Net cash provided by financing activities was $75,000 for the year ended April 30, 2016 from proceeds from common stock payable.

Our sources and uses of cash for the six months ended October 31, 2017 and 2016 were as follows:

		2017				2016
Cash, Beginning of Period		$	54,513			$	1,030
Net Cash Used in Operating Activities			(673,556	)			(33,205	)
Net Cash Used In Investing Activities			(101,910	)			-
Net Cash Provided by Financing Activities			771,250				32,384
Cash, End of Period		$	50,297			$	209

We used net cash of $673 ,556$2,275,278 in operating activities for the six months ended October 31, 20172021 as a result of our net income attributable to the Company of $3,171 ,403, non-controlling interest in income of consolidated subsidiaries of $650, 659,$1,139,407, non-cash expenses totaling $821 ,222$95,786, decreases in prepaid expenses of $2,460, and increases in accrued expenses of $19,089. This was offset by our non-cash gains of $3,146,352, a decrease in accounts payable of $ 135,039$171,857 and a decrease in accounts payable and accrued expenses – related party of $67,433, offset by non-cash gains totaling $5 ,518,412 and increase in deposits of $900.$213,811.

By comparison, weWe used net cash of $33 ,205$96,780 in operating activities for the six months ended October 31, 20162020 as a result of our net loss attributable to the Companyincome of $209 ,543, non-controlling interest in net loss of consolidated subsidiaries of $915 and$94,752, non-cash gain of $33,108, partially offset by non- cash expenses totaling $47,640$187,397, decrease in prepaid expenses and other current assets of $16,187, and increases in accounts payable of $90 ,766$140,431, accrued expenses of $524,196 and accounts payable and accrued expenses – related party of $71,955.$229,950, partially offset by non-cash gain of $1,289,693.

Net cash used in investing activities for the six months ended October 31, 20172021 was $101,910,$255,504, comprised of the purchase of propertyland and equipment.costs incurred for land improvements during the period. We had no net cash provided by or used in investing activities for the six months ended October 31, 2016.

We had net cash provided by financing activities of $771 ,250 for the six months ended October 31, 2017, comprised of proceeds from convertible notes payable.2020.

Net cash provided by financing activities was $32, 384 for the six months ended October 31, 2016 from2021 was $2,474,019, comprised of proceeds from common stock payable.

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Capital Resources

We have not generated any revenues or operating cash flows. As a result, we have significant short-term cash needs. Our principal sourcenotes payable of operating capital has been provided$200,000, proceeds from private salesconvertible notes payable of $78,500, and proceeds from the sale of our common stock of $3,000,000. This was offset by repayments of notes payable of $200,000, repayments of convertible notes payable of $255,331, and warrants and debt financing.offering costs incurred of $349,150.

DuringNet cash provided by financing activities for the six months ended October 31, 2017, we issued an aggregate2020 was $30,000, comprised of $1,148 ,470 principal amount ofproceeds from convertible notes resulting in netpayable - related party of $20,000 and proceeds to usfrom an SBA express bridge loan of $771,250. Included$10,000.

Going Concern Uncertainty

Our financial statements are prepared using accounting principles generally accepted in the new convertible notesUnited 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 $66,845,286 and a total stockholders’ deficit of $1,750,358 at October 31, 2021, and have reported negative cash flows from operations since inception. While we have received debt and equity funding during the period and have cash on hand of $273,686 at October 31, 2021, we still have a working capital deficit of $2,460,967. Therefore, there is a replacement note payable withquestion of whether or not we have the cash resources to meet our operating commitments for the next twelve months and have, or will obtain, sufficient capital investments to implement our business plan. Finally, our ability to continue as a principal amountgoing concern must be considered in light of $172,170, including $18,446 of capitalized interest expensethe problems, expenses and complications frequently encountered by entrance into established and emerging markets and the assumption of $145,000 principal and $8,724 from an April 17, 2017 promissory note. The notes are due and payable on various dates through October 2019 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,competitive environment in which 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.operate.

Subsequent to October 31, 2017, we issued an aggregate of $223,773 principle amount of convertible notes resulting in net proceeds to us of $197,000. The notes are dueSince inception, our operations have primarily been funded through private debt and payable on various dates through December 2019 and bear interest at 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 45% 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.

Subsequent to October 31, 2017, the Company issued a total of 118,484,723 shares of its Class A common stock in consideration for the conversion of note payable principal totaling $585,170 and accrued interest payable of $17,106.

On June 12, 2017, we entered into an equity purchase agreement with Crown Bridge for the purpose of commencing a redemption of our convertible note obligations and providing additional working capital for us to pursue our business strategy. Pursuant to the terms of this agreement, as amended, Crown Bridge has committed to purchase up to $3,000,000 of our common stock for a period of up to 24 months commencing upon the effectiveness of a registration statement covering the resale of shares issuable to Crown Bridge under this agreement. This facility allows us to deliver a put notice to Crown Bridge stating the dollar amount of common stock that we intend 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 our stock, the lowest price during the trading period, for the seven days prior to the purchase of shares by Crown Bridge. Accordingly, there is no assurance that we will be able to effectively utilize the equity financing, provided by this facility to fully redeem our outstanding convertible notes.

Even ifand we fully utilize the equity purchase facility from Crown Bridge, our available cash resources are expectedexpect to continue to be insufficientseek additional funding through private or public equity and debt financing. Our ability to satisfycontinue as a going concern is dependent on our anticipated costs over the next 12ability to 18 months. Until we can generate sufficient cash from operations in future periods to contributemeet our cash needs and/or to our capital requirements, we willraise funds to continue to rely on external financing activities, including the sale of our equity securities, to satisfy our capital requirements for the foreseeable future. Due, in part, to our lack of historical revenues or earnings, our prior success in attracting additional funding has been limited to transactions in which our equity is used as currency. Equity financings of the type we have been required to pursue are dilutive to our stockholdersfinance ongoing operations and may adversely impact the market price for our shares. Thererepay debt. However, there can be no assurance that we will be successful in consummating any such future financing transactions on terms satisfactoryour efforts to us,raise additional debt or at all.

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In addition, 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 anticipatecapital and/or 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 financingsour cash generated by our operations will be composed of both debt and equity financings. We anticipate these Subsidiaries will be ableadequate 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 ifmeet our needs. These factors, among others, raise substantial doubt that we will be able to obtain such financingcontinue 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 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 ownershipclassification of such Subsidiary. In addition, whilerecorded asset amounts or amounts and classifications of liabilities that might be necessary should the Company believes that the Refinery’s cost is financeable in large part through debt, it has not yet obtainedbe unable to continue as a letter of intent or commitment for such financing.going concern.

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 elsewhere in this filing. There were no changes to our significant accounting policies during the year ended April 30, 2017 or six months ended October 31, 2017. The following is a description of those significant accounting policies that involve estimates and judgment by management.prospectus.

Derivative Liabilities

In a series of subscription agreements, we issued warrants that contain certain anti-dilution provisions that we have identified as derivatives. We have also identified the conversion feature of certain convertible notes payable as a derivative. We estimate the fair value of the derivatives using multinomial lattice models that value the derivatives 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.

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Fair Value of Financial InstrumentsBUSINESS

Under Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 820, “Fair Value Measurements and Disclosures,” and ASC 825, “Financial Instruments,} FASB established a framework for measuring fair value in generally accepted accounting principles and expands disclosures about fair value measurements and 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- Level 1 applies to assets or liabilities for which there are quoted prices in active markets for identical assets or liabilities.
	·	Level 2- 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- 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 at October 31, 2017, April 30, 2017 and 2016:

October 31, 2017		Total				Level 1				Level 2				Level 3
Derivative liability		$	1,789,047			$	-			$	-			$	1,789,047

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INDUSTRY OVERVIEW

Background on 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. Refining is primarily a margin-based business where both the feedstock (primarily crude oil) and refined petroleum products are commodities with fluctuating prices. Refiners create profit by selling refined petroleum products at prices higher than the costs of acquiring crude oil and other feedstocks, and by managing operating costs. It is important for a refinery to maximize the yields of high value finished products and to minimize the costs of feedstock and operating expenses. Access to robust supply and distribution infrastructure such as pipelines or rail infrastructure that can deliver low-cost crude oil and provide for the delivery of refined products is also a key driver of profitability.

The United States has historically been the largest consumer of petroleum-based products in the world. According to the U.S. Energy Information Administration’s (the “EIA”) 2016 Refinery Capacity Report, there were 139 operating oil refineries in the United States in January 2015, with a total refining capacity of approximately 18.2 million bpd. High capital costs, historical excess capacity and environmental regulatory requirements have limited the construction of new refineries in the United States over the past 35 years and reduced the number of refineries from 254 in 1982 to 139 in 2016. Domestic operating refining capacity has increased at a compounded annual growth rate of 0.3% between January 1982 and January 2016, from 16.1 million bpd to 18.2 million bpd, according to the EIA. This net increase in capacity is the result of efficiency measures and expansions at various refineries, partially offset by the closure of more than 115 smaller and less efficient refineries. The Refinery, if built, will be the first fully-new large scale refinery built in the United States in the last 40 years.

Ownership of Refineries

Refineries are owned by either integrated oil companies or independent entities. Integrated oil companies have upstream operations, which are concerned with the exploration and production of crude oil, combined with downstream businesses such as refining, marketing, logistics and petrochemicals.

An independent refiner has no proprietary crude oil production, and it purchases its feedstocks on the open market under term or spot contracts. Refiners distribute their products through bulk, wholesale or retail channels under term and spot contracts. Many refiners, both integrated and independent, distribute part of their refined products through retail outlets.

Based on data from EIA, in recent years, many integrated oil companies have sought to lower their exposure to the refining sector. Because of this trend, the refining industry increasingly must rely on its own operations for its profitability. We believe this trend will continue.

Refining Basics

Refineries are uniquely designed to process specific types of crude oils into selected products. In general, each of a refinery’s different process units performs one of three functions:

	·	separate through distillation the many types of hydrocarbons present in crude oil into a number of different components, ranging from light to heavy;
	·	catalytically or thermally convert the separated hydrocarbons into more desirable products; and
	·	treat the products by removing unwanted elements and compounds.

Each function in the refining process is designed to maximize the value of the refined petroleum products produced. Below is a general description of refinery process units. Not all refineries possess each of these units.

Distillation

Typically crude oil is initially processed at a refinery in the atmospheric and vacuum distillation units. Crude oil is separated by boiling point in the distillation units under high heat and low pressure and recovered as hydrocarbon fractions. The lowest boiling fractions, including gasoline and LPG, vaporize and exit the top part of the atmospheric distillation unit. Medium boiling liquids, including jet fuel, kerosene and distillates such as gasoil, heating oil and diesel fuel, are drawn from the middle of the distillation unit. Higher boiling liquids, such as fuel oils and the highest boiling liquids, called residuum, are drawn together from the bottom of the atmospheric distillation unit and separated further in the vacuum distillation unit. Vacuum residues can be used for fuel oil or bitumen production. The various fractions are then pumped to the next appropriate unit in the refinery for further processing into higher value products or are sent to storage tanks for sale to customers.

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Conversion

The next step in the refining process is to convert the hydrocarbon fractions into distinct products. One of the ways of accomplishing this is through “cracking,” a process that breaks or cracks higher boiling fractions into more valuable products, such as gasoline, distillates and gasoil. The most important conversion units are the hydrocracker, the FCC unit and the coker. Thermal cracking is generally accomplished in the coker. The coker upgrades residuum into naphtha, distillate and gasoil and produces coke as a residual. Catalytic cracking is accomplished in the hydrocracker and/or FCC unit. Hydrocrackers receive feedstocks from cokers, FCCs and crude oil distillation units and convert lower value intermediate products into gasoline, naphtha, kerosene and distillates under very high pressure in the presence of hydrogen and a catalyst. The FCC unit converts gasoil and some residual from the crude oil distillation units into LPG, gasoline and distillates by applying heat in the presence of a catalyst. An FCC unit produces a higher percentage of gasoline, whereas a hydrocracker produces a higher percentage of diesel.

The reformer converts naphtha, or low-octane gasoline fractions, into higher octane gasoline blendstocks, which are used to increase the overall octane level of the gasoline pool. The alkylation unit reduces the vapor pressure and enhances the octane of gasoline blendstocks produced by the FCC and coker units through the conversion of light olefins to heavier, high-octane paraffins.

Removal of Impurities

Lastly, the intermediate products from the distillation and conversion processes are treated to remove impurities, such as sulfur, nitrogen and heavy metals and are processed to enhance octane, reduce vapor pressure and to meet other product specifications. Treatment for sulfur, nitrogen and metals is most-commonly accomplished in hydrotreating units by heating the intermediates under high pressure in the presence of hydrogen and catalysts.

Crude Oil Quality

The quality of crude oil dictates the level of processing and conversion necessary to achieve the optimal mix of finished products. In seeking to maximize their refining margins, refiners strive to process the optimal mix or slate of crude oils through their refineries, depending on their refinery’s conversion and treating equipment, the desired product output and the relative price of available crude oils. The terms light, medium and heavy when used in reference to crude oils refer to their density and the terms sweet and sour refer to their sulfur content. These terms are often used in conjunction with each other to describe the qualities of crude 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.

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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:

	·	West Texas Intermediate (“WTI”). WTI is a grade of crude oil that is described as light because of its relatively low density, and sweet because of its low sulfur content. Cushing, Oklahoma is a major trading hub for WTI and has been the delivery point for crude oil contracts, and therefore the price settlement point, on the NYMEX for over three decades.
	·	Louisiana Light Sweet (“LLS”). LLS is a major benchmark for light, sweet crude oil that is sourced from the Gulf Coast region. It has a slightly higher density and slightly lower sulfur content than WTI.
	·	Brent Crude Oil (“Brent”). Brent is a major trading classification of light, sweet crude oil comprised of Brent, Forties and Oseberg and Ekofisk, which are types of crude oil blends sourced from the North Sea. The Intercontinental Exchange is a major trading hub for Brent. Petroleum suppliers in Europe, Africa and the Middle East often set prices for Brent crude oil according to its value on the Intercontinental Exchange if it is being sold in the Western Hemisphere.

Light-Heavy Crude Oil Differential

The light-heavy crude oil differential is the price differential between heavy (high density), sour (high sulfur) and light (low density), sweet (low sulfur) crude oils.

Product Differentials

Because refineries produce many other products that are not reflected in crack spreads, product differentials relative to the products reflected in the crack spreads are calculated to analyze a given refinery’s product mix advantage. Refineries that have an economic advantage are those that produce relatively high volumes of premium products, such as premium and reformulated gasoline, low-sulfur diesel fuel and jet fuel and relatively low volumes of lesser valued products, such as LPG, residual fuel oil, petroleum coke and sulfur.

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.

Refinery Products

The main products produced by a refinery are as follows:

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Refinery Complexity

Refinery complexity refers to an oil refinery’s ability to process feedstocks, such as heavier and higher sulfur content crude oils, into value-added products. Refinery complexity is commonly measured by the Nelson Complexity Index. The Nelson Complexity Index assigns a complexity factor to each major piece of refinery equipment based on its complexity and cost in comparison to crude oil distillation, which is assigned a complexity factor of 1.0. The complexity of each piece of refinery equipment is then calculated by multiplying its complexity factor by its throughput ratio as a percentage of crude oil distillation capacity. Adding up the complexity values assigned to each piece of equipment, including crude oil distillation, determines a refinery’s complexity on the Nelson Complexity Index. A refinery with a complexity of 10.0 on the Nelson Complexity Index is considered ten times more complex than crude oil distillation for the same amount of throughput. The Nelson Complexity Index for the proposed Refinery is 6.0.

Refinery Location

The location of an oil refinery has an important impact on its refining margin since the location influences its ability to access feedstocks and distribute its products efficiently. The location also dictates whether the feedstocks and products can be transported via waterborne vessels, pipelines, rail or tank trucks. Refiners seek to maximize their profits by placing their products in the markets where they receive the highest margins. Historically, for example, refiners whose refineries and logistics systems are situated in areas of high petroleum consumption enjoy a competitive advantage over other suppliers in product distribution and in satisfying local demand. The map below shows the five regions in the United States (called Petroleum Administration for Defense Districts or “PADDs”), which have historically experienced varying levels of refining profitability due to regional market conditions.

Source: EIA

The Refinery will be located in PADD 3. PADD 3 has a refinery capacity that dwarfs the capacity of any of the other PADD regions. And, the PADD 3 region has produced more refined product than is used in the region due to its proximity to the Gulf of Mexico and the Texas and Louisiana Gulf Coast areas. Accordingly, the PADD 3 region has historically “exported” most of its refined product to the other PADD regions and internationally, whether by pipeline, ship or rail.

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The table below shows the export and import of gasoline from the PADD 3 region to other PADD regions and internationally.

Current Industry Trends Relevant to Our Business

The competitive landscape for U.S. refiners has been transformed by the growth of domestic crude oil. With the advent horizontal drilling and hydraulic fracturing, shale basins in the midcontinent of the U.S. began growing at accelerating rates in 2010 and 2011. This growth quickly overwhelmed a pipeline infrastructure that was ill-equipped to handle the volume of crude oil that needed to move from the interior of the United States to the coasts. As a result, the price of domestic crude oil, as represented by the WTI price marker, discounted relative to foreign crude oil, as represented by the Brent price marker. This discount has provided incentive for midstream logistics companies and refiners to build the infrastructure necessary to access this low-cost crude oil including crude-by-rail infrastructure that has been developed over the past several years. We believe that refiners with access to this lower-cost crude oil have benefitted from more attractive refining margins than those that lacked access. This margin environment has driven increased refinery utilization and increased exports of distillate while displacing significant volumes of imported of gasoline, transforming the United States into a net exporter of transportation fuels.

Growth in Domestic Crude Oil Supply, Particularly in the Permian Basin

In recent years the U.S. refining industry has benefitted from growth in U.S. crude oil production, especially production in the Bakken, Eagle Ford and Permian Basin shale basins. Due to advances in unconventional drilling technology and improved drilling economics, crude oil production in the United States increased from approximately 5.5 million bpd in 2009 to an average of nearly 8.9 million bpd in 2016. The aforementioned shale basins drove substantially all of this growth. The substantial decrease in the price of crude oil that began in early 2015 and persisted to the latter portion of 2016 caused a decrease in drilling and a resulting decrease in total crude oil production from these shale regions. Beginning in late 2016 and to the present, the price of crude oil stabilized at around $50 per barrel, drilling increased and shale production a whole increased, as shown in the following table.

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Source: EIA

The Refinery 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 year, 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.

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

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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.

Supply and Logistics Constraints Drive Discounts in Domestic Crude Oil Relative to Foreign Crude Oil

Historically, the United States has relied heavily on foreign crude oil imports which are received in waterborne vessels at coastal refineries and terminals. Given a concentration of U.S. refining capacity in the Gulf Coast, and significant refined product demand inland from the coast, much of the existing U.S. pipeline infrastructure was configured to move imported crude oil and domestic refined products from the Gulf Coast to other refining and population centers in the U.S. midcontinent and northern-tier states. With the growth of crude oil production in inland areas like the Bakken in North Dakota and both the Eagle Ford and Permian in the interior of Texas, new transportation infrastructure was needed to move crude oil generally in the opposite direction, to the coasts.

This mismatch between existing logistics capabilities and the growing need for inland U.S. crude oil producers to transport their crude oil to major refining centers drove a meaningful difference in the price of inland domestic crude oil and coastal crude oil. Inland domestic producers were forced to discount their crude oil in order to clear the market. As a measure of this discount, WTI on average traded at $10.04 per bbl less than Brent for the period from December 2009 to December 2014. This discount provided ample incentive for midstream logistics companies and others to invest in transportation infrastructure. However, the spread between WTI and Brent crude pricing has narrowed considerably, as more infrastructure to support transportation of inland crude oil to the US coasts has been developed.

During the last year, for example, the spread between WTI pricing and Brent pricing has been around $3 per barrel.

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Access to Domestic Crude Oil Provides Certain Refiners an Input Cost Advantage

Given the price differential between domestic and foreign crude oil over the past several years, refiners that have had access to low-cost domestic crude oil have demonstrated consistently higher margins relative to refiners that did not have access. Until the transportation infrastructure described above was built out, refineries in PADD II (Midwest), PADD III (Gulf Coast) and PADD IV (Rocky Mountain) have had access to these cheaper domestic crude oils via pipeline while refineries in PADD I (East Coast) and PADD V (West Coast) had to rely more heavily on waterborne imports or costly deliveries of domestic crude oil from the Gulf Coast via Jones Act compliant coastal barges and vessels.

This advantage is reflected in comparing the 2-1-1 crack spread using WTI crude oil as the input against the same crack spread using Brent crude oil as the input. According to information from the EIA, for the period from 2011 to mid-2013 the 2-1-1 WTI crack spread ranged from approximately $3 per barrel higher than the Brent crack spread to over $20 per barrel higher. From mid-2013 to 2015, the WTI crack spread over the Brent crack spread narrowed, ranging from a high of approximately $11 per barrel to a low of less than $1. After 2014, the WTI crack spread and Brent crack spread narrowed even further, with the Brent crack spread exceeding the WTI crack spread for brief periods. For the first few months of 2017, the WTI crack spread has exceeded the Brent-WTI crack spread by $2 or less per barrel

The United States is Becoming a Larger Exporter of Gasoline and Distillate, Including to Mexico

Coincident with accelerating crude oil production growth in the U.S. shale basins in 2010 and 2011, U.S. refining capacity utilization has increased significantly, as noted above. This has led to the U.S. becoming a net exporter of gasoline and distillate. One of the strongest export markets for US gasoline is Mexico, the market the Company intends to pursue.

The Mexican government is in the process of opening its gasoline and diesel markets to outside competition and replacing government-set prices with market-based prices. Last year, Mexico began allowing entities other than the state-owned company Petróleos Mexicanos (Pemex) to import gasoline and diesel and open retail stations. These changes followed previous energy sector reforms that ended Pemex’s upstream monopoly and opened the oil and natural gas sectors to foreign direct investment. According to the EIA, although Mexico is a large crude oil producer, it relies heavily on imports of gasoline from the United States to meet domestic demand. Based on reports from the EIA, the Company expects that these gasoline and diesel market reforms in Mexico will have significant implications for the sale of U.S.-produced gasoline.

The switch to market-based pricing in Mexico is being implemented in phases starting with a series of national price adjustments. The transition began at the start of this year. As reported by the EIA, January retail prices have averaged 14% and 20% higher than in December for regular gasoline and premium gasoline, respectively.

For the past several years, Pemex total gasoline sales, which can be used as an estimate for consumption, averaged around 800,000 bpd. However, gasoline sales increased 2.5% and averaged nearly 820,000 bpd in 2016 (through November). Mexican consumption of gasoline has been significantly greater than refinery production, with the difference increasing over the past three years.

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According to the EIA, Mexico’s refineries have historically been running at low utilization rates because they are challenged to produce clean gasoline and distillate fuels from the available marginal barrel of heavy sour crude oil. More recently, outages have hampered Mexico’s six refineries, which had a total output (including non-gasoline products) of 1.1 million bpd through November 2016, down from 1.3 million bpd over the same months in 2015. Mexican refinery output of gasoline fell steeply to 381,000 bpd in 2015 and then fell again to 333,000 bpd in 2016 (through November). Refinery utilization rates in Mexico declined in 2016 from 78% in January to 60% in November, creating a widening gap between domestic supply and demand.

To meet demand, Mexican imports of gasoline have climbed rapidly over the past two years. According to Pemex, Mexico’s motor gasoline imports were 122,000 bpd higher during the first 11 months of 2016 than during the comparable 2014 period. Since 2008, EIA data indicates that Mexico has imported significant quantities of U.S. gasoline. Based on U.S. and Mexican data sets, U.S. gasoline exports accounted for 80% of all Mexican gasoline imports and provided an average of 47% of Mexico’s gasoline consumption during the first 10 months of 2016.

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According to the EIA and Pemex, the volume of gasoline traded between Mexico and the United States is significant to U.S. refineries. Over the past five years, U.S. exports to Mexico accounted for between 44% (2014) and 54% (first 10 months of 2016) of total U.S. gasoline exports. On a year-over-year basis, U.S. gasoline exports to Mexico increased by 71,000 bpd in 2015, with additional average growth of 75,000 bpd over the first 10 months of 2016, when U.S. exports to Mexico averaged nearly 390,000 bpd.

While the effects of the ambitious reforms now underway in Mexico’s energy sector will only be realized over an extended period of time, the Company believes that the market will be very positive relative to the Company plans to market and sell its gasoline and diesel production in Western Mexico.

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BUSINESS

Background of the CompanyGeneral

MMEX Resources Corporation was formed as a Nevada corporation in 2005. The current management team leadled an acquisition of the Company (then named Management Energy, Inc.) through a reverse merger completed on September 23,in 2010 and changed the Company’s name to MMEX Mining Corporation on February 11, 2011. We previously unsuccessfully pursued miningin 2011 and coal projects that have since been abandoned. We have never generated any revenues and have accumulated losses of $36,918,594 as of April 30, 2017.

The Company was engaged in the exploration, extraction and distribution of coal from September 23, 2010 until April 12, 2016. As of April 12, 2016, the Company changed its business to the exploration, extraction, refining and distribution of oil, gas, petroleum products and electric power. Effective as of April 6, 2016, the Company changed its name from MMEX Mining Corporationthen to MMEX Resources Corporation to reflect the change in its business plan.2016. Our mailing address is 3616 Far West Blvd #117-321, Austin, Texas 78731. Our physical office address is 107-A S. Main Street, Fort Stockton, Texas 79735. The Company has adopted a fiscal year end of April 30.

We are a development stage company engaged inSince 2016, 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 Texas, Peru, and other countries in Latin America using the expertise of our principals to identify, finance and acquire these projects.

On March 31, 2017, the Company amended its articles of incorporation to increase the number of authorized shares of common stock from 3,000,000,000 to 5,000,000,000 and to provide for two classes of common stock: 3,000,000,000 shares of Class A common stock, having one vote per share, and 2,000,000,000 shares of Class B common stock, having 10 votes per share. Our board of directors has agreed to further amend the articles of incorporation to increase the number of authorized shares of Class A common stock from 3,000,000,000 to 10,000,000, 000, subject to the required approval of the stockholders.

Current Business Operations and Strategy

The most significant focus of our current business plan ishas been to build crude oil distillation units and refining facilities (CDUs) 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. We also anticipate constructing a crude oil refinery with up to a 100,000 bpd capacity at the same location in West Texas.

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 was received by the Company on August, 30, 2017. The permitting process for the Large Refinery is expected to be 12-18 months. Additionally, the construction of the Distillation Unit will require significantly less capital than the construction of the Large Refinery. As a result, less capital will be required to build and complete the project and generate revenue and profits.

On March 4, 2017, the Company entered into an agreement with Maple Resources, a related party, to acquire Maple Resources’revised our business plan for the Refinery, cash flow models, an agreementin 2021 to acquire the land for the Refinery site, potential refinery feed stock supplies,move MMEX to clean energy use and production, leveraging our history, management and business relationships for water resources, consulting services, refinery technology and potential railroad transportation agreements.from the traditional energy sector. The acquired assets did not include titlefocus of our business plan is to the site for the Refinery or any actual right to build the Refinery. The Company agreed to acquire all of these intangible assets in exchange for the issuance of 7,000,000,000 shares of Class B common stock. The shares were to be issued in two tranches, a first tranche of 1,500,000,000 shares issued on March 4, 2017 and a second tranche of 5,500,000,000 shares to be issued after the Company’s articles of incorporation were amended to increase the number of authorized shares of common stock. Following the issuance of the first tranche of 1,500,000 shares, Maple Resources agreed to forego the issuance of the second tranche of shares. Accordingly, no further shares will be issued to Maple Resources as part of this transaction.

These projects will be built on 476 acres located 20 miles northeast of Fort Stockton, Texas, near the Sulfur Junction spur of the Texas Pacifico Railroad. If successfully developed, the Refinery 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.

According to a report the Company received from VFuels Oil & Gas Engineering, the cost of a Distillation Unit with a 10,000 bpd capacity would be approximately $50 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.

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Constructing the Refinery will require a significant number of governmental permits and approvals. The principal permit for the construction of the Refinery 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 Distillation Unit. Trinity Consultants, the Company’s air quality permit advisor, estimates it will take approximately 18 months to obtain the air quality permit for the Large Refinery. According to VFuels Oil & Gas Engineering, construction for the Distillation Unit would take approximately 12 to 15 months . 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.

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

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 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. Any other refined products produced from the operation of the Distillation Unit (principally ATBs and naptha) would be shipped to other refineries, primarily in the Corpus Christi, Texas area, by pipeline and existing railroad systems for further processing.

The Refinery 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 with BNSF Railway and Fort Worth and Western Railroad. The Texas Pacifico Railroad is operated by Texas Pacifico Transportation LTD, a subsidiary of Grupo Mexico. Our planned Refinery 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.

The following chart indicates the principal project milestones and the Company’s currently estimated timetable for completing them. Completion of these milestones is dependent upon the consummation of required financing and the various risks described under “Risk Factors.” Further, completion of project milestones for the Large Refinery is dependent upon the commercial viability of the Distillation Unit. Accordingly, there is no assurance that this timetable or any individual project milestone will be achieved.

Project Milestones and Timeline

1^sthalf of 2018(Projected Costs: $ 33,500,000 )

Our immediate plans are to pursue the following three projects:

Project 1: Ultra Fuel clean refining.

We have teamed with Polaris Engineering to develop a clean refining, 10,000 barrel per day facility at our Pecos County site to produce 87° gasoline, ultra-low sulphur diesel and low-sulphur fuel oil, utilizing Polaris’ proprietary “UltraFuels® 2 Plus process,” to utilize the light crude oil and condensates from the Permian Basin to produce finished products of ultra-low sulfur diesel, gasoline, and IMO 2020 compliant marine fuel oil along with carbon capture from all major CO2 sources. The UltraFuels® 2 Plus concept features small size facilities to take advantage of proximity to smaller markets and/or locate directly near crude oil production areas. Because equipment is fabricated in modular units in the US A and shipped to site, this allows for 15 to 18 months’ project completion time and more rapid implementation than traditional facilities. The smaller size and footprint, as well as lower emissions, also allows for faster permitting.

Project 2: Blue Hydrogen

We have teamed with Black Tree Group to develop a facility in Pecos County to produce hydrogen with carbon capture and storage employing steam methane reformer technology with the abundant natural gas supplies in the immediate area as the feedstock. We have a 40% ownership in the WT Blue Fuels, LLC joint venture. The venture is contracting with Air Liquide to develop & implement the Air Liquide patented Steam Methane Reformer with Carbon Capture process to produce Blue H2. Air Liquide has built and operated liquid hydrogen plants since 1964 primarily for the space industry. WT Blue Fuels intends for the Pecos plan to have a 60 ton per day capacity.

Project 3: Green Hydrogen

MMEX has teamed up with Siemens Energy to develop and implement the Siemens patented process to produce Green Hydrogen by electrolysis of water with solar power. Siemens’ Silyzer 300 is the latest and most powerful product line in the Proton Exchange Membrane electrolysis portfolio. MMEX plans for Siemens to develop seven modular Silyzer 300 arrays to produce 50 tons per day at the planned project.

We are in various stages of negotiations with major company off-takes that range from specialty air and gas companies to international trading companies. We would expect the sales of hydrogen by these companies will be to their customer base, which are more traditional chemical end uses. The proposed distribution network of liquid hydrogen from our planned projects will be by truck and rail. Completion of off-take agreements is expected to a condition to obtaining any material funding for the planned projects.

We are also engaged in various stages of negotiations for supply arrangements to the planned projects. Our current plans include

Completion of these projects is dependent upon our obtaining the necessary capital for planning, construction and start-up costs. We are in consultation with the local and state tax authorities to file for tax abatement treatment generally applicable to projects such as our H2 projects. However, neither the receipt of adequate capital or tax abatement treatment can be assured. Financing depends upon the successful completion of front end engineering and design studies (FEED) for each planned project. MMEX believes that FEED studies for the ultra fuel and green hydrogen projects should be completed by the end of the first calendar quarter of 2022.

The costs to complete these projects is substantial and will require significant debt and equity funding MMEX estimates that the project capital budgets for the ultra fuels, blue hydrogen and green hydrogen projects are approximately $325 million, $300 million and $450 million.

There is no assurance that MMEX will be successful in obtaining financing or completing the milestones necessary to seek such financing.

The New Hydrogen Economy

The energy systems both in the United States and internationally are rapidly evolving. Major energy companies, regulatory agencies and all segments of society are working toward decarbonization and preservation of natural resources. In the interim, however, we need electric power and transportation energy. Hydrogen, as the most abundant fuel in the universe, is an energy carrier that cuts across sectors and has multiple benefits.

Hydrogen is the most abundant element in the universe; however, it is rarely found in its elemental form on earth. It must be produced from a hydrogen-containing feedstock (e.g., water, biomass, fossil fuels, or waste materials) using an energy source. Once hydrogen is produced, it can be used to store, move, and deliver low- or no-carbon energy to where it is needed. Hydrogen can be stored as a liquid, gas, or chemical compound, and is converted to energy via traditional combustion methods (in engines, furnaces, or gas turbines), through electrochemical processes (in fuel cells), and through hybrid approaches such as integrated combined cycle gasification and fuel cell systems. It is also used as a feedstock or fuel in a number of industries, including petroleum refining, ammonia production, food and pharmaceutical production, and metals manufacturing. Hydrogen can be produced in large centralized production facilities or in smaller distributed production facilities, and can be transported via truck, pipeline, tanker, or other means. Hydrogen, as a versatile energy carrier and chemical feedstock, offers advantages that unite all of our nation’s energy resources—renewables, nuclear, and fossil fuels—and enables innovations in energy production and end uses that can help decarbonize three of the most energy intensive sectors of our economy: transportation, electricity generation, and manufacturing.

Supplying hydrogen to industrial users is now a major business globally. Demand for hydrogen, which has grown more than threefold since 1975, continues to rise. Demand for hydrogen in its pure form is approximately 70 million tons per year. Governments are recognizing hydrogen’s role in energy security and its ability to decarbonize sectors that are otherwise extremely difficult to abate – such as logistics, industrial heating and industry feedstock. Meanwhile, industry leaders across the automotive, chemicals, oil and gas and heating sectors look to low-carbon and renewable hydrogen as a serious alternative to reach their increasingly robust sustainability objectives.

○

RAIL RATES FROM PROJECT TO MEXICO AND TEXAS GULF COAST DETERMINED

○

LARGE SCALE TCEQ PERMIT NOTICES AND PUBLIC HEARINGS HELD

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2^ndHalf of 2018(Projected Costs: $ 24,000,000 )

	○	CDU CONSTRUCTION COMPLETED
	○	CDU COMMERICAL OPERATIONS
	○	LARGE SCALE REFINERY FINANCING CIRCLED PENDING TCEQ PERMIT
	○	TEXAS PACIFICO BRIDGE AT PRESIDIO-OJINAGA COMPLETED.
	○	LARGE SCALE REFINERY CRUDE SUPPLY AND OFF-TAKE AGREEMENTS SIGNED.

2019 (Projected Costs: $ 275,000 )

	○	LARGE SCALE REFINERY TCEQ PERMIT ISSUED
	○	LARGE SCALE REFINERY FINANCING COMPLETED
	○	LARGE SCALE REFINERY CONSTRUCTION GROUND BREAKING

2020 (Projected Costs: $875,000,000)

○

LARGE SCALE REFINERY CONSTRUCTED COMPLETED

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 shift in 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 bpd4,000-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.

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Proposed Organizational Structure

The Company expects to operate the Distillation Unitits planned 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, thesubsidiaries. The construction of the Distillation Unit and the Large Refineryplanned projects will require substantial equity and debt financing, far beyond the expected resources of the Company, and we anticipate that the Subsidiariessubsidiaries will obtain equity and debt financing to finance the cost of construction. To the extent these Subsidiariessubsidiaries raise money through the issuance of equity securities, our ownership in the Subsidiariessubsidiaries 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.subsidiaries. In addition, while intend to retain managerial control of the Subsidiaries,subsidiaries, it is possiblelikely that equity investors will require representation on the board of managers in connection with their equity investments.

We anticipate these Subsidiariessubsidiaries will be able to finance approximately 80%a majority of the total costs of the Distillation Unit and the Large Refineryplanned projects through debt financing, and the remaining 20%portion 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 borrowproject subsidiary 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, theThe 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 $400,000.studies.

Location and LogisticsProperties

The Refinery will be locatedWe own a 126-acre and a 323.84-acre parcel of land in Pecos County, Texas that are the Permian Basin, which holds some ofsites for our planned clean fuels and hydrogen projects. We believe this site offers 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,following logistical advantages for 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.these projects:

The Refinery 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 Refinery site is 476 acres and the rail line runs through a corner of the property. We do not currently own all of the land on the site near Fort Stockton, Texas at which we intend to build the Refinery. On July 28, 2017, we acquired the 126 acre parcel of the land, which is the site for the planned Distillation Unit, at a purchase price of $550 per acre, or $69,249. At such time, we have agreed with the seller of the property to acquire the remaining 350 acre parcel, which is the site for the planned Large Refinery, on or before January 31, 2018 at a price of $550 per acre, or $192,500. To the extent that there are insufficient net proceeds from draws under our Equity Purchase Agreement, we will be required to obtain additional financing to complete this purchase. We have not yet received any financing commitment for such purchase.

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 might decrease discounts, pipeline companies will charge significant 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 the Refinery.

The Refinery will be located near the major producing shale areas of the Permian Basin in Reeves and Pecos counties. The Company has signed a letter of intent with a significant mid-stream crude oil and pipeline company to supply 50,000 bpd of crude oil production to the Refinery. The Company believes that this arrangement can be expanded to 100,000 bpd should the Company choose to build a 100,000 bpd facility. The arrangement is subject to substantial conditions and there is no assurance that the arrangement can be successfully implemented with this particular company. 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.

The Company’s business plan includes the export of gasoline, diesel and other products produced from the Refinery. The export of gasoline and diesel production is particularly attractive because, as noted above, exported gasoline and diesel does not bear any RIN costs, which is a significant cost of domestic refiners. The export of gasoline and diesel will therefore be a significant way to increase profits of the Refinery.

There are opportunities to sell refined products domestically, and there are significant refined product pipelines throughout the Permian Basin. Indeed, for some of the products produced by the Refinery, such as ATBs, the logical market is other domestic refineries that are designed to use these products as feedstock. The Company has had favorable preliminary discussions with product pipeline companies regarding the transport of the refined products from the Refinery, but there are no arrangements or contracts in place.

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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 naptha, to other refineries, primarily in the 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 and Fort Worth and Western Railroad. The Texas Pacifico Railroad is operated by Texas Pacifico Transportation LTD, a subsidiary of Grupo Mexico. Our planned Refinery 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.

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, plan to rebuild 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 are expected to help 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. A recent project schedule estimates the completion date to be in 2018.

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 business plan to market refined products into Western Mexico and to export refined products to Latin America will depend on the completion of the international bridge at Presidio/Ojinaga and the capital investment on the Texas Pacifico Railroad railroad . There is no assurance that these capital improvements will be made. If these capital improvements are not made, our business prospects and results of operations could be materially negatively impacted.

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 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 in place to market and sell its products in those areas.

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Construction of the Refinery

The Large Refinery would cover approximately 250 acres of the 476 acre property on which the Company holds an option. Before construction on the Refinery can commence, the Company must obtain all required permits. The Distillation Unit would cover approximately 15 acres of the property. Constructing the Refinery will require a significant number of governmental permits and approvals. The principal permit for the construction of the Refinery 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 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 that will be required are the following:

	·	Rail. The site provides access to all Class 1 carriers from direct location on the TXPF rail line, ability to go east or Rail west, and therefore potentially sell production to California and Western markets, the US Environmental Protection Agency (EPA)Gulf Coast or Mexico.
		– Air Permits, Risk Management Plan (RMP), Fuel Additives Registration, Facility Response Plan

	·	Middle Pecos Groundwater Conservation District·	Highway System. The site connects by a 15-mile hard top road to the transcontinental Interstate 10. This will provide the planned projects with the flexibility to receive crude and send refined products by trucks for products.
		– Water Use

	·	Pecos County·	Mexico. The site is 170 miles from Presidio Bridge, which has been recently rebuilt and allows for improved flow of goods by rail to western Mexico and to the ports of Mazatlán Mexico and Topolobampo.
		– Construction Permits

	·	Occupational Safety and Health Administration (OSHA)
		– Process Safety Management (PSM)

	·	Railroad Commission (RRC)Pipeline. The site in the middle of Texascrude oil and gas pipelines and adjacent gathering systems that could be connected to the planned projects.
		– Water discharge for oil & gas assets, LPG/LNG License & Notification

	·	US Army Corps of Engineers (USACOE)
		– Wetlands

	·	Texas Historical Commission (THC)
		– Cultural/Historical survey concurrence

	·	Texas Parks and Wildlife Department (TPWD)
		– Threatened/Endangered Species mitigation (if applicable)

	·	US Department of Transportation (USDOT)
		– HAZMAT shipping registration

	·	Texas Department of Licensing and Registration (TDLR)
		– Boiler registration

	·	Department of Homeland Security (DHS)
		– Chemical Facility Anti-Terrorism Standards (CFATS), Top-Screen Analysis

	·	Occupational Safety & Health Administration (OSHA)
		– OSHA 300 Logs, Reporting

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

The Company has hired VFuels Oil & Gas Engineering to advise it with respect to the construction of the Distillation Unit. Vfuels has prepared a preliminary report regarding the estimated cost and time-line for construction of the Distillation Unit. VFuels has estimated the cost of a 10,000 bpd facility to be approximately $50 million. This estimate is only a preliminary estimate and is subject to substantial change when additional engineering is completed. VFuels has estimated that the completion of the Refinery would take approximately 12 to 15 months following the receipt of the air quality permit from the TCEQ.

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Regulation

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 costAlthough we do not believe our planned blue hydrogen 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 refinery is a complicated, 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   October 31, 2017,green hydrogen projects will have any significant environmental or ecological impact, 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 localnumerous environmental 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.

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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 propertyWe expect to file with the Texas Commission on Environmental Quality (“TCEQ”) for construction and any wastes disposed therefrom may be subjectoperation permits. We expect to employ carbon capture with the federal Comprehensive Environmental Response, Compensationclean fuels and Liability Act (“CERCLA”),blue hydrogen facilities. We are studying the federal Resource Conservation and Recovery Act, and comparable Texas state laws. CERCLA and comparable state laws may impose liability without regard to faultoptions for sequestration for the CO2 in the various saline formations under our sites, which will require permits from the EPA or the legalityTexas Railroad Commission (which, we understand, is in the process 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.seeking primacy for sequestration permitting).

Our planned 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.

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Safety, Security and Insurance Concerns in Operating Refineries.

The Refinery willalso 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. WeIf applicable, 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 RefineryOur planned operations 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 willmay also bebecome 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.

Employees

We have no employees and our executive officer and our two directors currently do not receive compensation. We contract for all professional services when needed.

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.

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Audit, Nominating and Compensation Committees

Because we are not listed on 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, 2017,2021, no director expenses were incurred.

No option awards were granted to our non-executive directors during the year ended April 30, 2017. The following table reflects all option awards outstanding at April 30, 2017 to our non-executive directors:

These options were surrendered by Mr. Lemons effective June 1, 2017.

Executive Compensation

The following table sets forth the compensation paid or earned by our executive officers during the fiscal years ended April 30, 20172021 and 2016.2020:

Summary Compensation Table

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There are no employment agreements in place and no severance benefits are currently in place. During the period from May through December 2017,years ended April 30, 2021 and 2020, we paidincurred consulting fees and expense reimbursement related to business development, financing and other corporate activities to Maple Resources Corporation an affiliate(“Maple Resources”), a related party controlled by our President and CEO, totaling $218,970 and $275,713, respectively. Amounts included in accounts payable due to Maple Resources totaled $118,540 and $101,012 as of Mr. Hanks, a n aggregate of $37,052 for consulting services related to project developmentApril 30, 2021 and $9,354 in expense reimbursement for travel , office and other administrative support expenses on behalf of the Company.2020, respectively.

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Outstanding Equity Awards at Fiscal Year-End

We have not granted any stock awards other than stock options. The following table reflects all option awards outstanding atAt April 30, 20172021, we had no outstanding stock options or other equity awards issued to our executive officers: