S-1/A

As filed with the U.S. Securities and Exchange Commission on October 5, 2022.

Registration No. 333-266143

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Amendment No. 2

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

Next Bridge Hydrocarbons, Inc.

(Exact name of registrant as specified in its Charter)

Nevada	1311	87-2538731
(State or other jurisdiction of incorporation or organization)	(Primary Standard Industrial Classification Code Number)	(I.R.S. Employer Identification No.)

6300 Ridglea Place, Suite 950

Fort Worth, TX 76116

(817) 438-1937

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive office)

Corporate Secretary

Lucas T. Hawkins

6300 Ridglea Place, Suite 950

Fort Worth, TX 76116

(817) 438-1937

(Name, address, including zip code, and telephone number, including area code, of agent for service)

With copies to:

Mark Fitzgerald Wilson Sonsini Goodrich & Rosati 28 State Street, 37 Floor Boston, MA 02109 617-598-7800 Jack E. Jacobsen Jason A. Schumacher O’Melveny & Myers LLP 2501 N. Harwood Street, 17 Floor Dallas, TX 75201 214-647-9270

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.  ☐

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) 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(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 Exchange Act.

Large Accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☒	Smaller reporting company	☒
		Emerging Growth company	☒

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

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, as amended, or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. We may not issue 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 jurisdiction where the offer or sale is not permitted.

SUBJECT TO COMPLETION DATED OCTOBER 5, 2022

Prospectus

Next Bridge Hydrocarbons, Inc.

165,523,363 shares of Common Stock

(par value $0.0001)

This prospectus (“Prospectus”) is being furnished to you as a Series A Preferred stockholder of Meta Materials, Inc. (“Meta”) in connection with the planned distribution (the “Spin-Off” or the “Distribution”) by Meta to its Series A Preferred stockholders of all the shares of common stock, par value $0.0001 per share (the “Common Stock”), of Next Bridge Hydrocarbons, Inc. (the “Company,” “Next Bridge,” “we,” “us” or “our”) held by Meta immediately prior to the Spin-Off. As of immediately prior to the time of the Distribution, Meta holds 165,523,363 shares of Common Stock, which is 100% of the outstanding shares of capital stock of the Company.

At the time of the Spin-Off, Meta will distribute all the outstanding shares of Common Stock held by it on a pro rata basis to holders of Meta’s Series A Non-Voting Preferred Stock. Each one share of Meta’s Series A Non-Voting Preferred Stock outstanding as of             , New York City time, on                     , 2022, the record date for the Spin-Off (the “Record Date”), will entitle the holder thereof to receive one share of Common Stock. The Distribution will be made in book-entry form by a distribution agent. Fractional shares of Common Stock will not be distributed in the Spin-Off.

The Spin-Off will be effective as of             , New York City time, on                     , 2022. Immediately after the Spin-Off, the Company will be an independent public reporting company, provided, the Common Stock is not and will not be publicly traded and will not be eligible for electronic transfer through the Depository Trust Company book-entry system or any other established clearing corporation.

None of the Series A Preferred Stockholders are required to vote on or take any other action in connection with the Spin-Off. We are not asking you for a proxy, and we request that you do not send us a proxy. The Series A Preferred stockholders will not be required to pay any consideration for the Common Stock they receive in the Spin-Off; immediately after the Spin-Off, all shares of Series A Non-Voting Preferred Stock of Meta shall be cancelled.

Meta currently owns all the outstanding shares of Common Stock of the Company, and we have not sought to have the shares of Common Stock traded on any exchange. Accordingly, there is currently no public market for the Common Stock, and there is no current expectation for a public market to develop for the Common Stock.

In reviewing this Prospectus, you should carefully consider the matters described in the section titled “Risk Factors” beginning on page 7 of this Prospectus.

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

This Prospectus is not an offer to sell, or a solicitation of an offer to buy, any securities.

The date of this Prospectus is                     , 2022

Table of Contents

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS	i
DEFINITIONS	iii
PROSPECTUS SUMMARY	1
RISK FACTORS	7
THE SPIN-OFF	26
MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS	29
USE OF PROCEEDS	36
DETERMINATION OF OFFERING PRICE	36
CAPITALIZATION	36
BUSINESS	37
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	47
MANAGEMENT	58
EXECUTIVE COMPENSATION	65
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT	69
CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS	70
DESCRIPTION OF OUR CAPITAL STOCK	74
LEGAL MATTERS	78
EXPERTS	78
WHERE YOU CAN FIND MORE INFORMATION	79
INDEX TO FINANCIAL STATEMENTS	80

CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

This Prospectus contains certain forward-looking statements and information relating to our business that are based on the beliefs of our management as well as assumptions made by and information currently available to our management. When used in this communication, the words “may,” “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan,” “forecasts,” “projections,” and similar expressions are intended to identify such forward-looking statements. Forward-looking statements include, without limitation, the statements regarding our strategy, future plans for development and production and other strategic options, future expenses and costs and future liquidity and capital resources. Forward looking statements involve a number of risks, assumptions and uncertainties which may cause actual results to differ materially from those contained in this Prospectus. In light of these risks, uncertainties and assumptions, the future events and trends discussed in this Prospectus may not occur and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.

Such statements reflect our current views with respect to future events, the outcome of which is subject to certain risks, including, among others:

• general competitive conditions, including actions our competitors may take to grow their businesses;

• changes to payment terms, the discount or margin on products or other terms with our suppliers;

• risks associated with data privacy, information security and intellectual property;

• work stoppages or increases in labor costs;

• our ability to attract and retain employees;

• development costs of our current or future properties;

• timing and success of our drilling activities;

• amount and timing of future production of oil and natural gas;

• our ability to successfully implement our strategic initiatives, including amount, nature and timing of capital expenditures;

• the usual hazards associated with the oil and natural gas industry, including fires, well blowouts, pipe failure, spills, explosions and other unforeseen hazards;

• the numerous uncertainties inherent in estimating quantities of oil and natural gas reserves and actual future production rates and associated costs;

• operating costs including lease operating expenses, administrative costs and other expenses;

• the volatility of prices and supply of, and demand for, oil and natural gas;

• changes in regulatory requirements and legislation governing our business, including sustainability;

• the amount of our indebtedness and ability to comply with covenants applicable to any future debt financing;

• our ability to access the credit and capital markets to satisfy future capital and liquidity requirements on acceptable terms;

• if we are not able to successfully execute on our future operating plans, we may not be able to continue as a going concern;

• adverse results from litigation, governmental investigations or tax-related proceedings or audits;

• changes in accounting standards;

• impact and cost of energy conservation and other sustainability efforts;

• exploration and development risks, which could lead to environmental damage, injury and loss of life or the destruction of property;

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• proximity and capacity of oil, natural gas and other pipelines, transportation and support infrastructure to production facilities;

• availability of consumables and raw materials and drilling and processing equipment;

• adverse weather conditions, natural disasters or other events;

• the ability to successfully estimate the impact of litigation matters;

• our ability to initiate and maintain discussions with third parties regarding strategic options;

• the potential adverse impact on our business resulting from the Spin-Off; and

• the other risks and uncertainties detailed in the section titled “Risk Factors.”

Should one or more of these risks or uncertainties materialize, or should underlying assumptions prove incorrect, actual results or outcomes may vary materially from those described as anticipated, believed, estimated, expected, intended or planned. Subsequent written and oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by the cautionary statements in this paragraph. We undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise after the date of this Prospectus except to the extent required by law.

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DEFINITIONS

The following are abbreviations and definitions of terms commonly used in the oil and gas industry and in this prospectus. Natural gas equivalents and crude oil equivalents are determined using the ratio of six Mcf to one barrel. All references to “us”, “our”, “we”, or “Next Bridge” mean Next Bridge Hydrocarbons, Inc. and where applicable, its consolidated subsidiaries.

“Bbl” means a barrel of U.S. 42 gallons of oil.

“BOE” means one barrel of oil equivalent.

“Completion” means the installation of permanent equipment for the production of oil or gas.

“Condensate” means natural gas in liquid form produced in connection with natural gas wells.

“Exploratory well” means a well drilled to find a new field or to find a new productive reservoir in a field previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.

“Gross” when used with respect to acres or wells, production or reserves refers to the total acres or wells in which we or another specified person has a working interest.

“MBbls” means one thousand barrels of oil.

“Mcf” means one thousand cubic feet of natural gas.

“Net” when used with respect to acres or wells, refers to gross acres of wells multiplied, in each case, by the percentage working interest owned by us.

“NGL” refers to natural gas liquids, which is composed exclusively of carbon and hydrogen.

“Oil” means crude oil or condensate.

“Operator” means the individual or company responsible for the exploration, development, and production of an oil or gas well or lease.

“Proved developed reserves” means reserves that can be expected to be recovered through existing wells with existing equipment or operating methods.

“Proved developed non-producing” means reserves (i) expected to be recovered from zones capable of producing but which are shut-in because no market outlet exists at the present time or whose date of connection to a pipeline is uncertain or (ii) currently behind the pipe in existing wells, which are considered proved by virtue of successful testing or production of offsetting wells.

“Proved developed producing” means reserves expected to be recovered from currently producing zones under continuation of present operating methods. This category includes recently completed shut-in gas wells scheduled for connection to a pipeline in the near future.

“Proved reserves” means the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided by contractual arrangements.

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“Proved undeveloped reserves” means reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those drilling locations offsetting productive wells that are reasonably certain of production when drilled or where it can be demonstrated with certainty that there is continuity of production from the existing productive formation.

“Recompletion” means the completion for production of an existing well bore in another formation from which the well has been previously completed.

“Royalty” means an interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

“SEC” means the United States Securities and Exchange Commission.

“Working interest” means an interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production to which a working interest owner is entitled will always be smaller than the share of costs that the working interest owner is required to bear, with the balance of the production accruing to the owners of royalties. For example, the owner of a 100% working interest in a lease burdened only by a landowner’s royalty of 12.5% would be required to pay 100% of the costs of a well but would be entitled to retain 87.5% of the production.

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PROSPECTUS SUMMARY

This summary highlights certain information contained elsewhere in this Prospectus and may not contain all of the information that is important to you. To understand fully and for a more complete description of the terms and conditions of the Distribution, you should read this Prospectus in its entirety, including the information presented under the section titled “Risk Factors” and the consolidated financial statements and related notes, and the documents to which you are referred. See “Where You Can Find More Information.” Except where the context otherwise requires, or where otherwise indicated, references to the “Company,” “Next Bridge,” “we,” “us,” or “our” refer to Next Bridge Hydrocarbons, Inc. and its consolidated subsidiaries, including Torchlight Hazel, LLC, a Texas limited liability company, Hudspeth Oil Corporation, a Texas corporation, Hudspeth Operating, LLC, a Texas limited liability company, and Torchlight Energy, Inc., a Nevada corporation. “Meta” refers to Meta Materials, Inc. and its consolidated subsidiaries.

The Company

We were incorporated in Nevada on August 31, 2021, as OilCo Holdings, Inc. as a wholly owned subsidiary of Meta, and changed our name to Next Bridge Hydrocarbons, Inc. pursuant to our Amended and Restated Articles of Incorporation filed on June 30, 2022.

Background

On December 14, 2020, Meta (formerly known as Torchlight Energy Resources, Inc., “Torchlight”) and its subsidiaries, Metamaterial Exchangeco Inc. (formerly named 2798832 Ontario Inc., “Exchangeco”) and 2798831 Ontario Inc. (“Callco”), both Ontario corporations, entered into an Arrangement Agreement (the “Arrangement Agreement”) with Metamaterial Inc., an Ontario corporation headquartered in Nova Scotia, Canada, to acquire all of the outstanding common shares of Metamaterial, Inc. by way of a statutory plan of arrangement (the “Arrangement”) under the Business Corporations Act (Ontario), on and subject to the terms and conditions of the Arrangement Agreement, as amended. On June 28, 2021, following the satisfaction of the closing conditions set forth in the Arrangement Agreement, the Arrangement was completed.

In furtherance of the Arrangement, Torchlight (which subsequently changed its name to Meta Materials, Inc.) declared a dividend, on a one-for-one basis, of shares of Series A Non-Voting Preferred Stock of Meta (the “Series A Preferred Stock”) to holders of record of Torchlight’s common stock as of June 24, 2021. The holders of the Series A Preferred Stock are entitled to receive certain dividends based on the net proceeds of the sale of any assets that are used or held for use in Meta’s oil and natural gas exploration business and may also receive a pro rata dividend of equity in a spin-off entity to which Meta will transfer any remaining assets of such business. Meta has not sold to a third party any assets related to the historical oil and natural gas business and has transferred the subsidiary companies, the holders of the oil and natural gas assets, to us prior to the Spin-Off.

Business Overview

We are an energy company engaged in the acquisition, exploration, exploitation and/or development of oil and natural gas properties in the United States. Our primary focus has been the development of interests in an oil and gas project we hold in the Orogrande Basin in West Texas in Hudspeth County, Texas (the “Orogrande Project”). In addition, we have minor interests in the Eastern edge of the Midland Basin in Texas (the “Hazel Project”), and two minor well interests in Oklahoma.

We plan to operate our business through our wholly owned subsidiaries transferred to us from Meta, Torchlight Energy, Inc., a Nevada corporation, Hudspeth Oil Corporation, a Texas corporation, Torchlight Hazel, LLC, a

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Texas limited liability company, and Hudspeth Operating, LLC, a Texas limited liability company. In addition, we may consider strategic options, including partnering with, or the possible sale of any or all of our assets to, third parties. We currently have six full-time employees, and we employ consultants for various roles as needed.

As of December 31, 2021, we had interests in three oil and gas projects: the Orogrande Project in Hudspeth County, Texas, the Hazel Project in Sterling, Tom Green, and Irion Counties, Texas, and the Hunton wells in partnership with Kodiak in Central Oklahoma. (the “Oklahoma Properties”). See the description under “Current Projects” below under Note 4, “Oil & Natural Gas Properties,” of the financial statements included with this Prospectus for information and disclosure regarding these projects, which description is incorporated herein by reference.

Emerging Growth Company Status

We are an “emerging growth company,” as defined in Section 2(a) of the Securities Act of 1933, as amended (the “Securities Act”), as modified by the Jumpstart Our Business Startups Act of 2012 (“JOBS Act”). As an emerging growth company, we may take advantage of specified reduced disclosure and other requirements that are otherwise applicable, in general, to public reporting companies that are not emerging growth companies. These provisions include:

• Exemption from the auditor attestation requirement in the assessment of our internal control over financial reporting; and

• Reduced disclosure of certain financial information requirements related to executive compensation, including the requirements to hold a non-binding advisory vote on executive compensation and to provide information relating to the ratio of total compensation of its Chief Executive Officer to the median of the annual total compensation of all of our employees.

We may take advantage of these exemptions for up to five years or such earlier time that we are no longer an emerging growth company. We would cease to be an emerging growth company if we have more than $1.235 billion in annual revenues as of the end of a fiscal year, if we are deemed to be a large-accelerated filer under the rules of the SEC, or if we issue more than $1.235 billion of non-convertible debt over a three-year-period.

The JOBS Act permits emerging growth companies to take advantage of an extended transition period to comply with new or revised accounting standards applicable to public reporting companies. Following the consummation of the Spin-Off, we will elect to avail ourselves of the extended transition period. During the extended transition period, it may be difficult to compare our financial results with the financial results of a public reporting company that complies with accounting pronouncements when effective.

Smaller Reporting Company

We are a “smaller reporting company” as defined by Rule 12b-2 of the Securities Exchange Act of 1934 (the “Exchange Act”). As a “smaller reporting company,” the disclosure we will be required to provide in our SEC filings are less than it would be if we were not considered a “smaller reporting company.” Specifically, “smaller reporting companies” are able to provide simplified executive compensation disclosures in their filings; if annual revenue is less than $100 million, may be exempt from the provisions of Section 404(b) of the Sarbanes-Oxley Act of 2002 requiring that independent registered public accounting firms provide an attestation report on the effectiveness of internal control over financial reporting; and have certain other decreased disclosure obligations in their SEC filings, including, among other things, being permitted to provide two years of audited financial statements in annual reports rather than three years. Decreased disclosures in our SEC filings due to our status as a “smaller reporting company” may make it harder for investors to analyze our results of operations and financial prospects.

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Market Opportunity

The market for oil and natural gas that we will produce depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels, and the effects of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial, and individual consumers.

Our oil production is expected to be sold at prices tied to the spot oil markets. Our natural gas production is expected to be sold under short-term contracts and priced based on first of the month index prices or on daily spot market prices. We will rely on our operating partners to market and sell our production.

Regulatory Framework

Our oil and natural gas development operations are subject to stringent and complex federal, state, tribal, regional and local environmental, health and safety laws and regulations governing, among other factors, worker safety and health, the discharge and disposal of substances into the environment, and the protection of the environment and natural resources. Numerous governmental entities, including the Environmental Protection Agency (“EPA”) and analogous state and local agencies, (and, under certain laws, private individuals) have the power to enforce compliance with these laws and regulations and any permits issued under them. These laws and regulations may, among other things: (i) require permits to conduct exploration, drilling, water withdrawal, wastewater disposal and other production related activities; (ii) govern the types, quantities and concentrations of substances, including emissions of CO₂, methane and certain other greenhouse gases (“GHG”), that may be disposed or released into the environment or injected into formations in connection with drilling or production activities, and the manner of any such disposal, release, or injection; (iii) limit or prohibit construction or drilling activities or require formal mitigation measures in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; (iv) require investigatory and remedial actions to mitigate pollution conditions arising from the Company’s operations or attributable to former operations; (v) impose safety and health restrictions designed to protect employees and others from exposure to hazardous or dangerous substances; and (vi) impose obligations to reclaim and abandon well sites and pits.

Certain existing environmental and occupational safety and health laws and regulations to which our business operations are subject including, the Clean Air Act, as amended (the “CAA”), the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), the federal Resource Conservation and Recovery Act, Federal Water Pollution Control Act of 1972 as amended by the Oil Pollution Act of 1990, EPA rules to reduce methane emissions from new, modified or reconstructed sources in the oil and natural gas sector, including implementation of a leak detection and repair (“LDAR”) program under the CAA’s New Source Performance Standards in 40 C.F.R. Part 60, Subpart OOOOa (“Quad Oa”), the federal Occupational Safety and Health Act and other state equivalent laws and regulations. For further discussion of the risks to our results of operations arising out of our environmental regulatory compliance, see “Risks Related to Our Business”, including the following risk factors “—Our operations are heavily dependent on current environmental regulation, changes in which we cannot predict,” “—Government regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays,” and “—Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce”.

Corporate Information

Our executive office is located at 6300 Ridglea Place, Suite 950, Fort Worth, Texas 76116, and our telephone number is (817) 438-1937. We intend to have an internet website, nextbridgehydrocarbons.com. Information contained on or accessible through our website, when available, shall not be deemed a part of this prospectus and shall not be incorporated by reference herein.

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Summary of the Spin-Off

Distributing Company Meta Materials, Inc., a Nevada corporation, which holds all of our Common Stock issued and outstanding prior to the Distribution. After the Distribution, the holders of the Series A Preferred Stock will own all of our Common Stock and Meta Materials, Inc. will not own any shares of our Common Stock.

Distributed Company Next Bridge Hydrocarbons, Inc., a Nevada corporation, is a wholly owned subsidiary of Meta immediately prior to the Distribution. At the time of the Distribution, we will hold, directly or through our wholly owned subsidiaries, the assets and liabilities of the oil and natural gas business of Meta. After the Spin-Off, we will be an independent non-trading public reporting company.

Distributed Securities 165,523,363 shares of our Common Stock owned by Meta, which will be 100% of our Common Stock issued and outstanding immediately prior to the Distribution.

Each holder of Series A Preferred Stock will receive one share of our Common Stock for every one (1) share of Series A Preferred Stock held on the Record Date. The distribution agent will distribute only whole shares of our Common Stock in the Distribution. Shares of Common Stock that remain held by Meta following the Distribution, if any, shall be cancelled immediately after the Spin-Off.

Record Date The Record Date is the close of business on                     , 2022.

Distribution Date The Distribution Date is                     , 2022.

The Distribution On the Distribution Date, Meta will release the shares of our Common Stock to the distribution agent to distribute to Series A Preferred stockholders. The distribution agent will distribute our shares in book-entry form, and thus we will not issue any physical stock certificates, other than upon request. We expect that it will take the distribution agent up to two weeks to electronically issue shares of our Common Stock to you or your bank or brokerage firm on your behalf by way of direct registration in book-entry form. You will not be required to make any payment, surrender or exchange your shares of Series A Preferred Stock or take any other action to receive your shares of our Common Stock, although your shares of Series A Preferred Stock will be cancelled as of the Distribution Date.

Conditions to the Spin-Off The Spin-Off is subject to the satisfaction, or the Meta board of directors’ waiver, of the following conditions:

• the Meta board of directors shall have authorized and approved the Spin-Off and not withdrawn such authorization and approval, and shall have declared the dividend of our Common Stock to the holders of Meta’s Series A Preferred Stock;

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• the Distribution Agreement and the ancillary agreements contemplated by the Distribution Agreement shall have been executed by each party thereto;

• the SEC shall have declared effective our Registration Statement on Form S-1, of which this Prospectus is a part, under the Securities Act, and no stop order suspending the effectiveness of our Registration Statement shall be in effect and no proceedings for that purpose shall be pending before or threatened by the SEC;

• no order, injunction or decree issued by any governmental authority of competent jurisdiction or other legal restraint or prohibition preventing consummation of the Spin-Off shall be in effect, and no other event outside the control of Meta shall have occurred or failed to occur that prevents the consummation of the Spin-Off;

• all necessary actions and filings with regard to applicable state securities or “blue sky” laws shall have been taken; and

• any material third party consents necessary to consummate the Spin-Off shall have been obtained or waived.

The fulfillment of the foregoing conditions will not create any obligation on the part of Meta to effect the Spin-Off. We are not aware of any material federal, foreign or state regulatory requirements with which we must comply, other than SEC rules and regulations, state “blue sky” laws, or any material approvals that we must obtain, other than the SEC’s declaration of the effectiveness of the Registration Statement and applicable filings or notices required in compliance with applicable state securities or “blue sky” laws, in connection with the Spin-Off. Meta has the right not to complete the Spin-Off if, at any time, the Meta board or directors determines, in its sole and absolute discretion, that the Spin-Off is not in the best interests of Meta or its stockholders or is otherwise not advisable.

Trading Market All of our outstanding shares of Common Stock are currently beneficially owned by Meta and our Common Stock is currently not listed for trading on any stock exchange or market and we have not sought to be traded on any exchange or market. The shares of Common Stock will not be eligible for electronic transfer through the Depository Trust Company or any other established clearing corporation. Accordingly, there currently is no public trading market for the Common Stock and there is no current expectation for a public market to develop.

U.S. Federal Income Tax Consequences to Series A Preferred Stockholders U.S. federal income tax treatment of the issuance of our Common Stock to holders of the Series A Preferred Stock will not qualify for non-recognition of gain or loss for U.S. federal income tax purposes, and U.S. and non-U.S. holders could be subject to tax as a result of the Spin-Off and the cancellation all shares of the Series A Preferred Stock. Accordingly, holders of Series A Preferred Stock are

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encouraged to consult their own tax advisors as to the specific U.S. federal, state and local, and non-U.S. tax consequences of the Distribution to such stockholders.

Transfer Agent American Stock Transfer & Trust Company LLC.

Risk Factors Our business faces both general and specific risks and uncertainties. Our business also faces risks relating to the Spin-Off. Following the Spin-Off, we will also face risks associated with being an independent company. Accordingly, you should read carefully the information set forth under the heading “Risk Factors.”

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RISK FACTORS

You should carefully consider all of the information in this Prospectus and each of the risks described below, which we believe are the principal risks that we face. Some of the risks relate to our business, others to the Spin-Off and the ownership of our Common Stock. The risks and uncertainties described below are not the only ones faced by us. Additional risks and uncertainties not presently known or that are currently deemed immaterial also may impair our business operations. If any of the following risks occur, our business, financial condition, operating results and cash flows and the value of our Common Stock could be materially adversely affected.

Risks Relating to Our Business

We have a limited operating history relative to larger companies in our industry and may not be successful in developing profitable business operations.

We have a limited operating history relative to larger companies in our industry. Our business operations must be considered in light of the risks, expenses and difficulties frequently encountered in establishing a business in the oil and natural gas industry. As of the date of this Prospectus, we have generated limited revenues and have limited assets. We have an insufficient history at this time on which to base an assumption that our business operations will prove to be successful in the long-term. Our future operating results will depend on many factors, including:

• our ability to raise adequate working capital;

• the success of our development and exploration;

• the demand for oil and natural gas;

• the level of our competition;

• our ability to attract and maintain key management and employees; and

• our ability to efficiently explore, develop, produce or acquire sufficient quantities of marketable oil or natural gas in a highly competitive and speculative environment while maintaining quality and controlling costs.

To achieve profitable operations in the future, we must, alone or with others, successfully manage the factors stated above, as well as continue to develop ways to enhance our production efforts. Despite our best efforts, we may not be successful in our exploration or development efforts or obtain required regulatory approvals. There is a possibility that some, or all, of the wells in which we obtain interests may never produce oil or natural gas.

We have limited capital and will need to raise additional capital in the immediate future.

Following the Spin-Off, we will require additional capital to maintain operations and to expand our exploration and development programs. We may be unable to obtain additional capital when required or on favorable terms. Future acquisitions, exploration, development, production and marketing activities, as well as our administrative requirements (such as salaries, insurance expenses and general overhead expenses, as well as legal compliance costs and accounting expenses) will require a substantial amount of additional capital and cash flow.

We may pursue sources of additional capital through various financing transactions or arrangements, including joint venturing of projects, debt financing, equity financing, or other means. We may not be successful in identifying suitable financing transactions in the time period required or at all, and we may not obtain the capital we require by other means. If we do not succeed in raising additional capital, our resources may not be sufficient to fund our planned operations.

Our ability to obtain financing, if and when necessary, may be impaired by such factors as the capital markets (both generally and in the oil and natural gas industry in particular), our limited operating history, the location of

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our oil and natural gas properties and prices of oil and natural gas on the commodities markets (which will impact the amount of asset-based financing available to us, if any) and the departure of key employees. Further, if oil or natural gas prices on the commodities markets decline, our future revenues, if any, will likely decrease and such decreased revenues may increase our requirements for capital. If the amount of capital we are able to raise from financing activities, together with our revenues from operations, is not sufficient to satisfy our capital needs (even to the extent that we reduce our operations), third parties may be reluctant to provide the services we need in order to operate and we may be required to cease our operations, divest our assets at unattractive prices or obtain financing on unattractive terms.

Any additional capital raised through the sale of equity may dilute the ownership percentage of our stockholders. Raising any such capital could also result in a decrease in the fair market value of our equity securities because our assets would be owned by a larger pool of outstanding equity. The terms of securities we issue in future capital transactions may be more favorable to our new investors, and may include preferences, superior voting rights and the issuance of other derivative securities, and issuances of incentive awards under equity employee incentive plans, which may have a further dilutive effect.

We may incur substantial costs in pursuing future capital financing, including investment banking fees, legal fees, accounting fees, securities law compliance fees, printing and distribution expenses and other costs. We may also be required to recognize non-cash expenses in connection with certain securities we may issue, which may adversely impact our financial condition.

We may not achieve or maintain profitable operations, and therefore, may not be able to continue as a going concern.

The Company has a history of net losses from operations and negative cash flow from operating activities. We will need to raise additional working capital to continue our normal and planned operations. We will also need to generate and sustain significant revenue levels in future periods in order to become profitable, and, even if we do, we may not be able to maintain or increase our level of profitability. During the three and six months ended June 30, 2022, we incurred a net loss of $1,476,849 and $2,600,106, respectively, and used cash of $4,656,992 for operating activities for the six months ended June 30, 2022. At June 30, 2022, we had an accumulated deficit of $70,787,622 and had a working capital deficit of $17,082,726 compared with a working capital deficit of $13,307,453 as of December 31, 2021. These factors raise doubt regarding our ability to continue as a going concern. Because we have incurred significant net losses, our auditors have issued a “going concern” audit qualification. A “going concern” qualification indicates that the financial statements have been prepared assuming we will continue as a going concern and do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets, or the amounts and classification of liabilities that may result if we do not continue as a going concern. Therefore, you should not rely on our consolidated balance sheet as an indication of the amount of proceeds that would be available to satisfy claims of creditors, and potentially be available for distribution to stockholders, in the event of liquidation.

There can be no assurance that our financing strategy or strategic alternatives will result in a transaction satisfactory to holders of our Common Stock.

After the Spin-Off, we may consider various strategic alternatives, including partnering with third parties, a potential sale of some or all of our assets, a merger transaction, and potential financing alternatives. Even if a partnering transaction, sale, merger or financing transaction were to be consummated, it may not return any value to holders of our Common Stock. Regardless of whether we execute a partnership, sale, merger or financing transaction, the adverse pressures negatively impacting our business that we have been or are currently experiencing may continue or intensify, including the risk that we may not be able to continue as a going concern.

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We are mainly concentrated in one geographic area, which increases our exposure to many of the risks enumerated herein.

Operating in a concentrated area increases the potential impact that many of the risks stated herein may have upon our ability to perform. For example, we have greater exposure to regulatory actions impacting Texas, natural disasters in the geographic area, competition for equipment, services and materials available in the area and access to infrastructure and markets. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effect of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

Because of the speculative nature of oil and natural gas exploration, there is risk that we will not find commercially exploitable oil and natural gas and that our business will fail.

The search for commercial quantities of oil and natural gas as a business is extremely risky. We cannot provide investors with any assurance that any properties in which we obtain a mineral interest will contain commercially exploitable quantities of oil and/or natural gas. The exploration expenditures to be made by us may not result in the discovery of commercial quantities of oil and/or natural gas. Problems such as unusual or unexpected formations or pressures, premature declines of reservoirs, invasion of water into producing formations and other conditions involved in oil and natural gas exploration often result in unsuccessful exploration efforts. If we are unable to find commercially exploitable quantities of oil and natural gas, and/or we are unable to commercially extract such quantities, we may be forced to abandon or curtail our business plan, and as a result, any investment in us may become worthless.

Litigation may adversely affect our business, financial condition, and results of operations.

Certain of our subsidiaries are subject and from time to time in the normal course of our business operations, may become subject to litigation that may result in liability material to our financial statements as a whole or may negatively affect our operating results if changes to our business operations are required. The cost to defend such litigation may be significant and may require a diversion of our resources. There also may be adverse publicity associated with litigation that could negatively affect customer perception of our business, regardless of whether the allegations are valid or whether we are ultimately found liable. Insurance may not be available at all or in sufficient amounts to cover any liabilities with respect to these or other matters. A judgment or other liability in excess of our insurance coverage for any claims could adversely affect our business and the results of our operations. For additional discussion of pending litigation matters, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Legal Proceedings.”

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

Following the Spin-Off, our ability to successfully acquire oil and natural gas interests, to build our reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers will depend on developing and maintaining close working relationships with industry participants and our ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment. These realities are subject to change and our inability to maintain close working relationships with industry participants or continue to acquire suitable property may impair our ability to execute our business plan.

To continue to develop our business, we will endeavor to use the business relationships of our management to enter into strategic relationships, which may take the form of joint ventures with other private parties and contractual

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

Our acreage must be drilled before lease expiration in order to hold the acreage by production. In the highly competitive market for acreage, failure to drill sufficient wells in order to hold acreage will result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Our leases on oil and natural gas properties typically have a primary term of four to five years, after which they expire unless, prior to expiration, drilling obligations are fulfilled or production is established within the spacing units covering the undeveloped acres. As of June 30, 2022, we had leases representing approximately 134,066 net acres in the Orogrande Basin in West Texas expiring in 2022 if we fail to drill five wells as obligated. Unless we are able to negotiate an extension on these leases, these leases in the Orogrande Basin are also subject to expiration in 2023 in the event we fail to drill an additional five wells during the 2023 calendar year. We will require additional capital to drill these wells, and we may not be able to obtain additional capital when required in order to drill these wells, or on favorable terms. As of June 30, 2022, we have leases representing 645 net acres in the Eastern edge of the Midland Basin in West Texas, which are currently held by production by active wells. In the event that we fail to meet our drilling obligations in the Orogrande Basin, whether because we are unable to obtain additional capital when required or otherwise, or if production ceases in the Midland Basin, our leases will expire. If we have to renew such leases on new terms, we could incur significant cost increases, and we may not be able to renew such leases on commercially reasonable terms or at all. In addition, on certain portions of our acreage, third-party leases may become immediately effective if our leases expire. As such, our actual drilling activities may materially differ from our current expectations, which could adversely affect our business.

The price of oil and natural gas has historically been volatile. If it were to decrease substantially, our projections, budgets, and revenues would be adversely affected, potentially forcing us to make changes in our operations.

Following the Spin-Off, our future financial condition, results of operations and the carrying value of any oil and natural gas interests we acquire will depend primarily upon the prices paid for oil and natural gas production. Oil and natural gas prices historically have been volatile and likely will continue to be volatile in the future, especially given current world geopolitical conditions. Cash flows from operations are highly dependent on the prices that we receive for oil and natural gas. This price volatility could affect the amount of our cash flows available for capital expenditures and our ability to borrow money or raise additional capital. The prices for oil and natural gas are subject to a variety of additional factors that are beyond our control. These factors include:

• the level of consumer demand for oil and natural gas;

• the domestic and foreign supply of oil and natural gas;

• the ability of the members of the Organization of Petroleum Exporting Countries (“OPEC”) to agree to and maintain oil price and production controls;

• the price of foreign oil and natural gas;

• domestic governmental regulations and taxes;

• the price and availability of alternative fuel sources;

• weather conditions;

• market uncertainty due to political conditions in oil and natural gas producing regions, including the Middle East; and

• worldwide economic conditions.

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These factors as well as the volatility of the energy markets generally make it extremely difficult to predict future oil and natural gas price movements with any certainty. Declines in oil and natural gas prices affect our revenues and could reduce the amount of oil and natural gas that we can produce economically. Accordingly, such declines could have a material adverse effect on our financial condition, results of operations, oil and natural gas reserves and the carrying values of our oil and natural gas properties. If the oil and natural gas industry experiences significant price declines, we may be unable to make planned expenditures, among other things. If this were to happen, we may be forced to abandon or curtail our business operations, which would cause the value of an investment in us to decline or become worthless.

In early March 2020, the market experienced a precipitous decline in oil prices in response to concerns about oil demand due to the economic impact of COVID-19 and anticipated increases in supply from Russia and OPEC, particularly Saudi Arabia. Generally, demand for oil declined substantially following the initial onset of the COVID-19 pandemic, but has recovered over the past year. These trends materially, adversely affected our results of operations, cash flows and financial condition during the last two years.

If oil or natural gas prices reverse again and go on a downward trend or drilling efforts are unsuccessful, we could be required to record additional write-downs of our oil and natural gas properties. Write-downs may occur when oil and natural gas prices are low, or if we have downward adjustments to our estimated proved reserves, increases in our estimates of operating or development costs, deterioration in drilling results or mechanical problems with wells where the cost to redrill or repair is not supported by the expected economics.

Under the full cost method of accounting, capitalized oil and natural gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and natural gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are subject to amortization. Should capitalized costs exceed this ceiling, an impairment would be recognized.

The Company recognized an impairment charge of $2,108,301 in 2020 due to an adjustment required by this ceiling test.

Because of the inherent dangers involved in oil and natural gas operations, there is a risk that we may incur liability or damages as we conduct our business operations, which could force us to expend a substantial amount of money in connection with litigation and/or a settlement.

The oil and natural gas business involves a variety of operating hazards and risks such as well blowouts, pipe failures, casing collapse, explosions, uncontrollable flows of oil, natural gas or well fluids, fires, spills, pollution, releases of toxic gas and other environmental hazards and risks. These hazards and risks could result in substantial losses to us from, among other things, injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, cleanup responsibilities, regulatory investigation and penalties and suspension of operations. In addition, we may be liable for environmental damages caused by previous owners of property purchased and leased by us. In recent years, there has also been increased scrutiny on the environmental risk associated with hydraulic fracturing, such as underground migration and surface spillage or mishandling of fracturing fluids including chemical additives. This technology has evolved and continues to evolve and become more aggressive. We believe that recent designs have seen improvement in, among other things, proppant per foot, barrels of water per stage, fracturing stages, and clusters per fracturing stage. Nonetheless, substantial liabilities to third parties or governmental entities may be incurred, the payment of which could reduce or eliminate the funds available for exploration, development or acquisitions or result in the loss of our properties and/or force us to expend substantial monies in connection with cleanup, litigation or settlements. In addition, we will need to quickly adapt to the evolving technology, which could take time and divert our attention to other business matters. We currently have no insurance to cover such losses and liabilities, and even if insurance is obtained, it may not be adequate to cover any losses or liabilities. We cannot predict the

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availability of insurance or the availability of insurance at premium levels that justify our purchase. The occurrence of a significant event not fully insured or indemnified against could materially and adversely affect our financial condition and operations. We may elect to self-insure if management believes that the cost of insurance, although available, is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event not fully covered by insurance could have a material adverse effect on our financial condition and results of operations.

The market for oil and natural gas is intensely competitive, and competition pressures could force us to abandon or curtail our business plan.

The market for oil and natural gas exploration services is highly competitive, and we only expect competition to intensify in the future. Numerous well-established companies are focusing significant resources on exploration and are currently competing with us for oil and natural gas opportunities. Other oil and natural gas companies may seek to acquire oil and natural gas leases and properties that we have targeted. Additionally, other companies engaged in our line of business may compete with us from time to time in obtaining capital from investors. Competitors include larger companies which, in particular, may have access to greater resources, may be more successful in the recruitment and retention of qualified employees and may conduct their own refining and petroleum marketing operations, which may give them a competitive advantage. Actual or potential competitors may be strengthened through the acquisition of additional assets and interests. Additionally, there are numerous companies focusing their resources on creating fuels and/or materials which serve the same purpose as oil and natural gas but are manufactured from renewable resources.

As a result, we may not be able to compete successfully and competitive pressures may adversely affect our business, results of operations, and financial condition. If we are not able to successfully compete in the marketplace, we could be forced to curtail or even abandon our current business plan, which could cause any investment in us to become worthless.

Inflation may adversely affect us by increasing costs beyond what we can recover through price increases and limit our ability to enter into future traditional debt financing.

Inflation can adversely affect us by increasing costs of critical materials, equipment, labor, and other services. In addition, inflation is often accompanied by higher interest rates. Continued inflationary pressures could impact our profitability. Inflation may also affect our ability to enter into future traditional debt financing, as high inflation may result in an increase in cost.

We may not be able to successfully manage growth, which could lead to our inability to implement our business plan.

Any growth of the Company may place a significant strain on our managerial, operational and financial resources, especially considering that we currently only have a small number of executive officers, employees and advisors. Further, as we enter into additional contracts, we will be required to manage multiple relationships with various consultants, businesses and other third parties. These requirements will be exacerbated in the event of our further growth or in the event that the number of our drilling and/or extraction operations increases. Our systems, procedures and/or controls may not be adequate to support our operations or that our management will be able to achieve the rapid execution necessary to successfully implement our business plan. If we are unable to manage our growth effectively, our business, results of operations and financial condition will be adversely affected, which could lead to us being forced to abandon or curtail our business plan and operations.

Developing oil and natural gas wells and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect future production from our oil and natural gas properties. Any delays, reductions or cancellations in development and producing activities could materially, adversely impact the value of your shares of Common Stock.

Recovery of undeveloped reserves and the development of developed non-producing reserves requires substantial capital expenditures and successful drilling operations of our oil and natural gas properties. All of the recent

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development costs related to our Hazel Project were paid by Masterson Hazel Partners LP (“MHP”). We granted MHP the option to acquire the Hazel Project in exchange for it conducting, and paying for, development activity sufficient to maintain the Hazel mineral leases in good standing (the “Option Agreement”). The Option Agreement provided that if MHP declined to exercise the option to acquire the property, we would be obligated to reimburse them for their cost of the development activity to the extent that the wells produced revenues beyond the date of the option’s lapse until the total amount of development expenses are reimbursed. MHP declined to exercise the option effective September 30, 2021. The 2021 reserve data included in the reserve report of our independent petroleum engineer assumes a certain amount of capital expenditures will be made to develop such reserves, and the present value of such reserves was adjusted based on our obligation to assign revenue from the Hazel Project to MHP. Additionally, 33.5% of the development expenses for the Orogrande Project are borne by the non-operating working interest owners of such properties.

The development of such reserves may in the future take a long period of time and may require higher levels of capital expenditures than anticipated, which, for the Orogrande Project, are borne in part by the non-operating working interest owners of such properties. Delays in the development of the reserves, increases in drilling and development costs (including expenses related to secondary and tertiary recovery techniques) of such reserves or decreases or continued volatility in commodity prices will reduce the future net revenues of the estimated possible reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could force us to reclassify certain of the proved reserves as unproved reserves.

In addition, the process of developing oil and natural gas wells and producing oil and natural gas from our properties is subject to numerous risks beyond our control. The ability to carry out operations or to finance planned development expenses could be materially and adversely affected by any factor that may curtail, delay, reduce or cancel development and production, including:

• delays imposed by or resulting from compliance with environmental and other governmental or regulatory requirements, including permitting requirements, limitations on or resulting from wastewater discharge and disposal of exploration and production wastes, including, subsurface injections, as well as additional regulation with respect to GHG emissions;

• pressure or irregularities in geological formations;

• restricted access to land for drilling or to existing pipeline infrastructure;

• lack of available gathering, transportation and processing facilities, including availability on commercially reasonable terms, or delays in construction of gathering facilities;

• lack of available capacity on interconnecting transmission pipelines;

• equipment failures or accidents;

• failure of secondary recovery operations to perform as expected;

• unexpected operational events and drilling conditions;

• declines in oil or natural gas prices;

• limitations in the market for oil or natural gas;

• pipe or cement failures;

• casing collapses;

• shortages, unavailability or high cost of drilling rigs, tubular materials, equipment, supplies, personnel and services;

• lost or damaged drilling and service tools;

• loss of drilling fluid circulation;

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• uncontrollable flows of oil and natural gas, water or drilling fluids;

• blowouts, explosions fires and natural disasters;

• environmental hazards, such as oil and natural gas leaks, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

• adverse weather conditions, such as drought, floods, blizzards, tornados and ice storms; and

• title problems or legal disputes regarding leasehold rights.

Our operations are heavily dependent on current environmental regulation, changes in which we cannot predict.

Oil and natural gas activities that we will engage in, including production, processing, handling and disposal of hazardous materials, such as hydrocarbons and naturally occurring radioactive materials (if any), are subject to stringent regulation. We could incur significant costs, including cleanup costs resulting from a release of hazardous material, third-party claims for property damage and personal injuries fines and sanctions, as a result of any violations or liabilities under environmental or other laws. Changes in or more stringent enforcement of environmental laws could force us to expend additional operating costs and capital expenditures to stay in compliance.

Various federal, state and local laws regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment, directly impact oil and natural gas exploration, development and production operations, and consequently may impact our operations and costs. These regulations include, among others, (i) regulations by the Environmental Protection Agency and various state agencies regarding approved methods of disposal for certain hazardous and non-hazardous wastes; (ii) the Comprehensive Environmental Response, Compensation, and Liability Act and analogous state laws which regulate the removal or remediation of previously disposed wastes (including wastes disposed of or released by prior owners or operators), property contamination (including groundwater contamination), and remedial plugging operations to prevent future contamination; (iii) the Clean Air Act and comparable state and local requirements which regulate air emissions; (iv) the Oil Pollution Act of 1990 which contains numerous requirements relating to the prevention of and response to oil spills into waters of the United States; (v) the Resource Conservation and Recovery Act which is the principal federal statute governing the treatment, storage and disposal of hazardous wastes; (vi) the Federal Water Pollution Control Act and comparable state and local requirements which regulate discharges to federal and state waters; and (vii) state regulations and statutes governing the handling, treatment, storage and disposal of naturally occurring radioactive material.

We believe that we will be in substantial compliance with applicable environmental laws and regulations in reliance on our contractual relationship with Maverick Operating LLC, who operates our oil and natural gas properties and is primarily responsible for compliance with applicable environmental regulatory with respect to the operating activities of our oil and natural gas properties. We cover all costs associated with the related insurance coverage for such environmental regulatory compliance. To date, other than the cost of insurance, we have not expended any amounts to comply with such regulations, and we do not currently anticipate that future compliance will have a materially adverse effect on our consolidated financial position, results of operations or cash flows. However, if we are deemed to not be in compliance with applicable environmental laws, we could be forced to expend significant funds to be in compliance, which would have a materially adverse effect on our financial condition.

Government regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Several states, including Texas, and local jurisdictions, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating

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standards and/or require the disclosure of the composition of hydraulic fracturing fluids. The Texas Legislature adopted legislation, effective September 1, 2011, requiring oil and natural gas operators to publicly disclose the chemicals used in the hydraulic fracturing process. The Texas Railroad Commission adopted rules and regulations implementing this legislation that apply to all wells for which the Texas Railroad Commission issues an initial drilling permit after February 1, 2012. The law requires that the well operator disclose the list of chemical ingredients subject to the requirements of OSHA for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. Also, in May 2013, the Texas Railroad Commission adopted rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. The rules took effect in January 2014. Additionally, on October 28, 2014, the Texas Railroad Commission adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. The disposal well rule amendments, which became effective on November 17, 2014, also clarify the Texas Railroad Commission’s authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The Texas Railroad Commission has used this authority to deny permits and temporarily suspend operations for waste disposal wells and, in September 2021, the Texas Railroad Commission curtailed the amount of water companies were permitted to inject into some wells in the Permian Basin, and has since indefinitely suspended some permits there and expanded the restrictions to other areas. These restrictions on use of produced water and a moratorium on new produced water disposal wells could result in increased operating costs, requiring us or our service providers to truck produced water, recycle it or pump it through the pipeline network or other means, all of which could be costly. We or our service providers may also need to limit disposal well volumes, disposal rates and pressures or locations, or require us or our service providers to shut down or curtail the injection of produced water into disposal wells. These factors may make drilling and completion activity in the affected parts of the Permian Basin less economical and adversely impact our business, results of operations and financial condition.

Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce.

The EPA previously published its findings that emissions of GHGs present a danger to public health and the environment because such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted various rules to address GHG emissions under existing provisions of the CAA. For example, the EPA has adopted rules requiring the reporting of GHG emissions from various oil and natural gas operations on an annual basis, which includes certain of our operations. In addition, in June 2016, the EPA finalized rules to reduce methane emissions from new, modified or reconstructed sources in the oil and natural gas sector, including implementation of an LDAR program to minimize methane emissions, under the CAA’s New Source Performance Standards Quad Oa. However, the EPA has taken several steps to delay implementation of the Quad Oa standards. The agency proposed a rulemaking in June 2017 to stay the requirements for a period of two years and in October 2018, the EPA proposed revisions to Quad Oa, such as changes to the frequency for monitoring fugitive emissions at well sites and changes to requirements that a professional engineer certify when meeting certain Quad Oa requirements is technically infeasible. In September 2020, the EPA finalized amendments to Quad Oa that rescind requirements for the transmission and storage segment of the oil and natural gas industry and rescind methane-specific limits that apply to the industry’s production and processing segments, among other things. On June 30, 2021, Congress issued a joint resolution pursuant to the Congressional Review Act disapproving the September 2020 rule, and on November 15, 2021, EPA issued a proposed rule to revise the Quad Oa regulations that, if finalized, would require methane emissions reductions and implementation of a fugitive emissions monitoring and repair program. EPA has also announced its intention to issue a supplemental proposal in 2022 that may expand on or modify the 2021 proposal in response to public input. It is possible that these rules will continue to require oil and natural gas operators to expend material sums.

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In addition, in November 2016, the U.S. Department of the Interior Bureau of Land Management (“BLM”) issued final rules to reduce methane emissions from venting, flaring, and leaks during oil and natural gas operations on public lands that are substantially similar to the EPA Quad Oa requirements. However, on December 8, 2017, the BLM published a final rule to temporarily suspend or delay certain requirements contained in the November 2016 final rule until January 17, 2019, including those requirements relating to venting, flaring and leakage from oil and natural gas production activities. Further, in September 2018, the BLM published a final rule to revise or rescind certain provisions of the 2016 rule. On July 21, 2020, a Wyoming federal court vacated almost all of the 2016 rule, including all provisions relating to the loss of gas through venting, flaring, and leaks, and on July 15, 2020, a California federal court vacated the 2018 rule. While, as a result of these developments, future implementation of the EPA and BLM methane rules is uncertain, given the long-term trend towards increasing regulation, future federal GHG regulations of the oil and natural gas industry remain a possibility. We may be required to expend significant costs to obtain the necessary equipment (pollution control equipment and optical gas imaging equipment for LDAR inspections) and personnel trained to assist with inspection and reporting requirements to ensure we are in compliance with these rules.

We may incur increasing attention to environmental, social and governance (“ESG”) matters that may impact our business.

Businesses across all industries are facing increasing scrutiny from stakeholders related to their ESG practices. If we do not adapt to or comply with investor or stakeholder expectations and standards, which are evolving, or if we are perceived to have not responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, we may suffer from reputational damage and the business, financial condition and/or the value of our Common Stock could be materially and adversely affected. Increasing attention to climate change, increasing societal expectations on businesses to address climate change, and potential consumer use of substitutes to energy commodities may result in increased costs, reduced demand for our hydrocarbon products, reduced profits, increased investigations and litigation, and negative impacts on our ability to access capital markets.

In addition, organizations that provided information to investors on corporate governance and related matters have developed rating processes for evaluating business entities on their approach to ESG matters. Currently, there are no universal standards for such scores or ratings, but the importance of sustainability evaluations is becoming more broadly accepted by investors and shareholders. Such ratings are used by some investors to inform their investment and voting decisions. Additionally, certain investors use these scores to benchmark businesses against their peers. If we are perceived as lagging, our investors may engage with such third party organizations to require improved ESG disclosure or performance.

Our estimates of the volume of reserves could have flaws, or such reserves could turn out not to be commercially extractable. As a result, our future revenues and projections could be incorrect.

Estimates of reserves and of future net revenues prepared by different petroleum engineers may vary substantially depending, in part, on the assumptions made and may be subject to adjustment either up or down in the future. Our actual amounts of production, revenue, taxes, development expenditures, operating expenses, and quantities of recoverable oil and natural gas reserves may vary substantially from the estimates. Oil and natural gas reserve estimates are necessarily inexact and involve matters of subjective engineering judgment. In addition, any estimates of our future net revenues and the present value thereof are based on assumptions derived in part from historical price and cost information, which may not reflect current and future values, and/or other assumptions made by us that only represent our best estimates. If these estimates of quantities, prices and costs prove inaccurate, we may be unsuccessful in expanding our oil and natural gas reserves base with our acquisitions. Additionally, if declines in and instability of oil and natural gas prices occur, then write downs in the capitalized costs associated with any oil and natural gas assets we obtain may be required. Because of the nature of the estimates of our reserves and estimates in general, reductions to our estimated proved oil and natural gas reserves and estimated future net revenues may not be required in the future, and/or that our estimated

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reserves may not be present and/or commercially extractable. If our reserve estimates are incorrect, we may be forced to write down the capitalized costs of our oil and natural gas properties.

Decommissioning costs are unknown and may be substantial. Unplanned costs could divert resources from other projects.

We may become responsible for costs associated with abandoning and reclaiming wells, facilities and pipelines which we use for production of oil and natural gas reserves. Abandonment and reclamation of these facilities and the costs associated therewith is often referred to as “decommissioning.” We accrue a liability for decommissioning costs associated with our wells but have not established any cash reserve account for these potential costs in respect of any of our properties. If decommissioning is required before economic depletion of our properties or if our estimates of the costs of decommissioning exceed the value of the reserves remaining at any particular time to cover such decommissioning costs, we may have to draw on funds from other sources to satisfy such costs. The use of other funds to satisfy such decommissioning costs could impair our ability to focus capital investment in other areas of our business.

We may have difficulty distributing production, which could harm our financial condition.

In order to sell the oil and natural gas that we are able to produce, if any, the operators of the wells we obtain interests in may have to make arrangements for storage and distribution to the market. We will rely on local infrastructure and the availability of transportation for storage and shipment of our products, but infrastructure development and storage and transportation facilities may be insufficient for our needs at commercially acceptable terms in the localities in which we operate. This situation could be particularly problematic to the extent that our operations are conducted in remote areas that are difficult to access, such as areas that are distant from shipping and/or pipeline facilities. These factors may affect our and potential partners’ ability to explore and develop properties and to store and transport oil and natural gas production, increasing our expenses.

Furthermore, weather conditions or natural disasters, actions by companies doing business in one or more of the areas in which we will operate, or labor disputes may impair the distribution of oil and/or natural gas and in turn diminish our financial condition or ability to maintain our operations.

The marketability of any future production will be dependent upon transportation and other facilities, certain of which we do not control. When these facilities are unavailable, our operations can be interrupted and any revenues reduced.

The marketability of any future production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. The oil produced will be transported from the wellhead to our tank batteries by our gathering system. Our purchasers would then transport the oil by truck to a pipeline for transportation. Our natural gas production will generally be transported by our gathering lines from the wellhead to an interconnection point with the purchaser. We do not control these trucks and other third-party transportation facilities and our access to them may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of our or third-party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our production and thereby cause a significant interruption in our operations.

We may be required to flare a portion of our natural gas production for a number of reasons, including the fact that (i) our well is not yet tied into the third-party gathering system, (ii) the pressures on the third-party gathering system are too high to allow additional production from our well to be transported or (iii) our production is prorated due to high demand on the third-party gathering system. We may flare additional gas from time to time.

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Also, the transfer of our oil and natural gas through third-party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. Our access to transportation options, including trucks owned by third parties, can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production-related difficulties, we may be required to shut in or curtail production. Any such shut in or curtailment, or an inability to obtain favorable terms for delivery of our production, would adversely affect our financial condition and results of operations.

Our business will suffer if we cannot obtain or maintain necessary licenses.

Our operations will require licenses, permits and in some cases renewals of licenses and permits from various governmental authorities. Our ability to obtain, sustain or renew such licenses and permits on acceptable terms is subject to change in regulations and policies and to the discretion of the applicable governments, among other factors. Our inability to obtain, or our loss of or denial of extension of, any of these licenses or permits could hamper our ability to produce revenues from our operations.

Challenges to our properties may impact our financial condition.

Title to oil and natural gas interests is often not capable of conclusive determination without incurring substantial expense. While we have made and intend to make appropriate inquiries into the title of properties and other development rights we have acquired and intend to acquire, title defects may exist. In addition, we may be unable to obtain adequate insurance for title defects, on a commercially reasonable basis or at all. If title defects do exist, it is possible that we may lose all or a portion of our right, title and interests in and to the properties to which the title defects relate. If our property rights are reduced, our ability to conduct our exploration, development and production activities may be impaired. To mitigate title problems, common industry practice is to obtain a title opinion from a qualified oil and natural gas attorney prior to the drilling operations of a well.

We rely on technology to conduct our business, and our technology could become ineffective or obsolete.

We rely on technology, including geographic and seismic analysis techniques and economic models, to develop any reserve estimates and to guide our exploration, development and production activities. We and our operator partners will be required to continually enhance and update our technology to maintain its efficacy and to avoid obsolescence. The costs of doing so may be substantial and may be higher than the costs that we anticipate for technology maintenance and development. If we are unable to maintain the efficacy of our technology, our ability to manage our business and to compete may be impaired. Further, even if we are able to maintain technical effectiveness, our technology may not be the most efficient means of reaching our objectives, in which case we may incur higher operating costs than we would were our technology more efficient.

The loss of key personnel would directly affect our efficiency and profitability.

Our future success is dependent, in a large part, on retaining the services of our planned management team. Our executive officers possess a unique and comprehensive knowledge of our industry and related matters that are vital to our success within the industry. The knowledge, leadership and technical expertise of these individuals would be difficult to replace. The loss of one or more of our officers could have a material adverse effect on our operating and financial performance, including our ability to develop and execute our long-term business strategy. We do not maintain key-man life insurance with respect to any employees. We have entered into employment agreements with certain of our executive officers effective immediately following the Spin-Off. Three of our executives were party to prior employment agreements with one of our subsidiaries, which have been terminated and superseded by the agreements as described in more detail under the heading “Executive Compensation” elsewhere in this Prospectus.

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We have limited management and staff and are dependent upon partnering arrangements and third-party service providers.

After the Spin-Off we plan to have six full-time employees, including our Chief Executive Officer and Chief Financial Officer. The loss of these individuals would have an adverse effect on our business, as we have very limited personnel. We leverage the services of other independent consultants and contractors to perform various professional services, including engineering, oil and natural gas well planning and supervision, and land, legal, environmental and tax services. We also pursue alliances with partners in the areas of geological and geophysical services and prospect generation, evaluation and prospect leasing. Our dependence on third-party consultants and service providers create a number of risks, including but not limited to:

• the possibility that such third parties may not be available to us as and when needed; and

• the risk that we may not be able to properly control the timing and quality of work conducted with respect to our projects.

If we experience significant delays in obtaining the services of such third parties or they perform poorly, our results of operations and stock price could be materially adversely affected.

Certain of our directors and officers have significant duties with, and spend significant time serving, entities that may compete with us in seeking acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

Certain of our directors and officers, who are responsible for managing the direction of our operations and acquisition activities, hold positions of responsibility with other entities that are in the business of identifying and acquiring oil and natural gas properties. The existing positions held by these directors and officers may give rise to fiduciary or other duties that are in conflict with the duties they owe to us. These directors and officers may become aware of business opportunities that may be appropriate for presentation to us as well as to the other entities with which they are or may become affiliated. Due to these existing and potential future affiliations, they may present potential business opportunities to other entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that certain opportunities are more appropriate for other entities with which they are affiliated, and as a result, they may elect not to present those opportunities to us. These conflicts may not be resolved in our favor. For additional discussion of our management’s business affiliations and the potential conflicts of interest of which our stockholders should be aware, see “Certain Relationships and Related Party Transactions.”

Our business and operations may be adversely affected by the COVID-19 pandemic and may be adversely affected by other similar outbreaks.

As a result of the COVID-19 pandemic or other adverse public health developments, including voluntary and mandatory quarantines, travel restrictions, and other restrictions, we have experienced delays, disruptions and temporary suspensions of our operations. In addition, our financial condition and results of operations may be adversely affected by the COVID-19 pandemic in the future.

The timeline and potential magnitude of the COVID-19 outbreak continue to be unknown. The continuation or amplification of the COVID-19 pandemic could continue to more broadly affect the United States and global economy, including our business and operations, and the demand for oil and natural gas. Other contagious diseases in the human population could have similar adverse effects. The potential impact from COVID-19 is difficult to predict, therefore, the extent to which it will negatively affect our operating results, or the duration of any potential business disruption is uncertain. The magnitude and duration of any impact will depend on future developments and new information that may emerge regarding the duration of COVID-19 pandemic, the severity of any variants thereof, rate of vaccinations and other actions taken by authorities to contain its impact or otherwise treat the disease, all of which are beyond our control.

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Terrorist attacks or cyber-incidents could result in information theft, data corruption, operational disruption and/or financial loss.

Like most companies, we have become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications and services, to operate our businesses, to process and record financial and operating data, communicate with our business partners, analyze mine and mining information, estimate quantities of coal reserves, as well as other activities related to our businesses. Strategic targets, such as energy-related assets, may be at greater risk of future terrorist or cyber-attacks than other targets in the United States. Deliberate attacks on, or security breaches in, our systems or infrastructure, or the systems or infrastructure of third parties, or cloud-based applications could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery, difficulty in completing and settling transactions, challenges in maintaining our books and records, environmental damage, communication interruptions, other operational disruptions and third-party liability. Our insurance may not protect us against such occurrences. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition, results of operations and cash flows. Further, as cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. We plan to adopt plans and policies to address precautions with respect to data security and appropriate responses in case of a reported breach.

Risks Relating to the Spin-Off

The Spin-Off could result in significant tax liability to Meta and its stockholders.

The Spin-Off and cancellation of all shares of Meta’s Series A Preferred Stock together will not qualify for non-recognition of gain or loss for U.S. federal income tax purposes. Series A Preferred stockholders could be subject to tax as a result of the Spin-Off and such cancellation. The treatment of the Spin-Off and cancellation of all shares of the Series A Preferred Stock together for U.S. federal income tax purposes for a U.S. holder (as defined further below) will depend on whether the Spin-Off and such cancellation qualify as a sale or exchange of the Series A Preferred Stock under Section 302 of the Internal Revenue Code of 1986, as amended (the “Code”). If the Spin-Off and cancellation of all shares of the Series A Preferred Stock together qualify as a sale or exchange of the Series A Preferred Stock, the U.S. holder will be treated as recognizing capital gain or loss equal to the difference between the amount realized on the Spin-Off and such cancellation together, and such U.S. holder’s adjusted tax basis in the Series A Preferred Stock surrendered in the Spin-Off and such cancellation. The treatment of the Spin-Off and cancellation of all shares of the Series A Preferred Stock for U.S. federal income tax purposes for a non-U.S. holder (as defined further below) likewise will depend on whether the Spin-Off and such cancellation together qualify as a sale or exchange of the Series A Preferred Stock under Section 302 of the Code. If the Spin-Off and such cancellation together qualify as a sale or exchange of the Series A Preferred Stock, gain recognized from the Spin-Off by a non-U.S. holder generally will not be subject to U.S. federal income taxation. If the Spin-Off and such cancellation together do not qualify as a sale or exchange of Series A Preferred Stock, a non-U.S. holder will be treated as receiving a distribution from Meta, which distribution will be treated as a dividend to the extent the distribution is paid out of Meta’s current or accumulated earnings and profits (as determined under U.S. federal income tax principles) and will be subject to any applicable withholding. If a Series A Preferred stockholder is subject to withholding tax in connection with the Spin-Off (including nonresident withholding tax or backup withholding tax, each as described further under the heading “Material U.S. Federal Income Tax Considerations” below), Meta has the right to reduce the amount of Common Stock deliverable to such stockholder in the Spin-Off in order to pay such withholding tax.

Meta will generally recognize gain equal to the fair market value of our Common Stock in excess of Meta’s adjusted tax basis in such Common Stock at the time of the Spin-Off. To the extent such gain gives rise to unreimbursed federal, state or other tax liabilities, such liabilities could adversely affect Meta’s liquidity or capital reserves.

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See below under the headings “Notes to Unaudited Pro-Forma Condensed Combined Financial Statements” and “Material U.S. Federal Income Tax Considerations” for more information.

We may be unable to achieve some or all of the benefits that we expect to achieve from the Spin-Off.

We believe that, as an independent company, we will be able to, among other things, better focus our financial and operational resources on our specific business, implement and maintain a capital structure designed to meet our specific needs, design and implement corporate strategies and policies that are targeted to our business, more effectively respond to industry dynamics and create effective incentives for our management and employees that are more closely tied to our business performance. However, by separating from Meta, we may be more susceptible to market fluctuations and have less leverage with suppliers, and we may experience other adverse events. In addition, we may be unable to achieve some or all of the benefits that we expect to achieve as an independent company in the time we expect, if at all. The completion of the Spin-Off will also require significant amounts of our management’s time and effort, which may divert management’s attention from operating and growing our business.

We may be unable to make, on a timely or cost-effective basis, the changes necessary to operate as an independent company, and we may experience increased costs after the Spin-Off.

Meta has provided us with various corporate services. Following the Spin-Off, Meta will have no obligation to provide us with assistance other than as described under “Certain Relationships and Related Party Transactions—Agreements with Meta.” These arrangements do not account for every service that we have received from Meta in the past. Accordingly, following the Spin-Off, we will need to provide internally or obtain from unaffiliated third parties the services we currently receive from Meta. We may be unable to replace these services in a timely manner or on terms and conditions as favorable as those we receive from Meta. We may be unable to successfully establish the infrastructure or implement the changes necessary to operate independently or may incur additional costs. If we fail to obtain the services necessary to operate effectively or if we incur greater costs in obtaining these services, our business, financial condition and results of operations may be adversely affected.

We have limited operating history as an independent company, and our historical financial information is not necessarily representative of the results we would have achieved as an independent company and may not be a reliable indicator of our future results.

We derived the historical financial information included in this Prospectus from Meta’s consolidated financial statements, and this information does not necessarily reflect the results of operations and financial position we would have achieved as an independent company during the periods presented or those that we will achieve in the future. This is primarily because of the following factors:

• Prior to the Spin-Off, we operated as part of Meta’s broader corporate organization, and Meta performed various corporate functions for us. Our historical financial information reflects allocations of corporate expenses from Meta for these and similar functions. These allocations may not reflect the costs we will incur for similar services in the future as an independent company.

• We will enter into certain transactions with Meta that did not exist prior to the Spin-Off, such as the Tax Matters Agreement, which may cause us to incur new costs.

• Our historical financial information does not reflect changes that we expect to experience in the future as a result of our separation from Meta, including changes in our cost structure, personnel needs, tax structure, financing and business operations. As part of Meta, we enjoyed certain benefits from Meta’s operating diversity, size, purchasing power, borrowing leverage and available capital for investments, and we will lose these benefits after the Spin-Off. As an independent entity, we may be unable to purchase goods, services and technologies, such as insurance and health care benefits and computer software licenses or access capital markets on terms as favorable to us as those we obtained as part of Meta prior to the Spin-Off.

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Following the Spin-Off, we will also be responsible for the additional costs associated with being an independent company, including costs related to corporate governance, investor and public relations and public reporting. In addition, certain costs incurred by Meta, including executive oversight, accounting, treasury, tax, legal, human resources, occupancy, procurement, information technology and other shared services, have historically been allocated to us by Meta; but these allocations may not reflect the future level of these costs to us as we begin to provide these services ourselves. Therefore, our historical financial statements may not be indicative of our future performance as an independent company. We cannot assure you that our operating results will continue at a similar level when we are an independent company. For additional information about our past financial performance and the basis of presentation of our financial statements, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and the notes thereto included elsewhere in this Prospectus.

Our contracts may contain provisions requiring the consent of third parties in connection with the Spin-Off. If these consents are not obtained, we may be unable to enjoy the benefit of these contracts in the future.

Our contracts may contain provisions that require the consent of third parties to the Spin-Off. Failure to obtain such consents on commercially reasonable and satisfactory terms may impair our entitlement to the benefit of these contracts in the future.

The 2021 Note with Meta contains restrictive covenants that limit our operations.

In 2021, we borrowed $15 million pursuant to the terms of the 2021 Note (defined below). If we are not in compliance with the covenants of the 2021 Note, or if we are in default under the 2021 Note, it is unlikely that Meta will offer to extend any additional loans or debt financing under the 2021 Note or otherwise, which may affect our business as a going concern. The 2021 Note includes a restrictive covenant that, subject to certain exceptions and qualifications, restricts our ability to merge or consolidate with another person or entity, or sell or transfer all or substantially all of our assets, unless we are the surviving entity or the successor entity assumes all of obligations under the 2021 Note. This restriction may restrict our current and future operations, particularly our ability to respond to certain changes in our business or industry or take future actions. See the section titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for additional information.

The 2021 Note is secured by a security interest in shares of common stock of Meta and a 25% working interest in the Orogrande Prospect as defined in the Security Agreement (defined below), each held by the Pledgor (defined below) or the Pledgor’s affiliate. Any default that is not waived could permit Meta, as lender, to exercise rights and remedies with respect to all of the collateral that is securing the 2021 Note, and/or other rights and remedies under applicable law.

Our ability to meet these restrictive covenants or to avoid defaults can be impacted by events beyond our control. The 2021 Note provides that our breach or failure to satisfy certain covenants constitutes an event of default. Upon the occurrence of an event of default, Meta as our lender could elect to declare all amounts outstanding under the 2021 Note to be immediately due and payable. If the outstanding debt under the 2021 Note was to be accelerated, we may not have sufficient cash on hand to repay it, which would have an immediate adverse effect on our business and operating results. This could potentially cause us to cease operations and result in a complete loss of your investment in our Common Stock.

Our Loan Agreement with Meta contains restrictive covenants that limit our operations.

As of August 2022, we borrowed an aggregate principal amount of $5.0 million pursuant to the terms of the Loan Agreement (defined below), which is the maximum principal balance available under the Loan Agreement. The Loan Agreement contains various restrictive covenants and other restrictions, which include, among other things, restrictions on:

• our ability to transfer all or part of our business or property, except for inventory in the ordinary course of business, surplus or obsolete equipment, permitted liens, and transfers of cash permitted by the agreement;

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• our ability to liquidate or dissolve or merge or consolidate with another entity, or acquire another entity;

• our ability to incur additional debt beyond certain limits or encumber our assets; and

• our ability to pay dividends or make investments, other than permitted investments.

These restrictions may restrict our current and future operations, particularly our ability to respond to certain changes in our business or industry or take future actions. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” for additional information.

Our ability to meet these restrictive covenants can be impacted by events beyond our control. The Loan Agreement provides that our breach or failure to satisfy certain covenants constitutes an event of default. Upon the occurrence and during the continuance of an event of default, Meta as the lender could elect to (i) declare all outstanding principal and accrued and unpaid interest under the Loan Agreement immediately due and payable, (ii) terminate any remaining commitment to make loans under the Loan Agreement, and/or (iii) exercise certain other rights and remedies anticipated under the Loan Agreement. The events of default under the Loan Agreement include, among other things (subject to grace periods in certain instances), payment defaults, breaches of covenants or representations and warranties, a change in control or certain material adverse effects as defined in the Loan Agreement, material judgments and attachments, cross defaults with certain of our other material indebtedness, and bankruptcy and insolvency events with respect to us and our subsidiaries. If the outstanding debt under the Loan Agreement was to be accelerated, we may not have sufficient cash on hand to repay it, which would have an immediate adverse effect on our business and operating results. This could potentially cause us to cease operations and result in a complete loss of your investment in our Common Stock.

We may have been able to receive better terms from unaffiliated third parties than the terms we receive in our agreements with Meta.

We have negotiated agreements with Meta including the 2021 Note, Loan Agreement, Distribution Agreement and Tax Matters Agreement, while we are still part of Meta. Accordingly, these agreements may not reflect terms that would have resulted from arms-length negotiations between unaffiliated parties. The terms of the agreements being negotiated relate to, among other things, loans for working capital, allocations of assets, liabilities, rights, indemnifications and other obligations between Meta and us. We may have received better terms from third parties because third parties may have competed with each other to win our business. See “Certain Relationships and Related Party Transactions” for more information.

Risks Relating to our Common Stock

Our Common Stock is not eligible with the Depository Trust Company (“DTC”), which may result in brokerage firms being unwilling to hold or trade the stock.

A significant number of the holders of the Series A Preferred Stock hold such shares in “street name” brokerage accounts. Our shares of Common Stock will not become eligible with DTC to permit our shares of Common Stock to trade electronically. If an issuer is not “DTC-eligible,” then its capital stock cannot be electronically transferred between brokerage accounts, which means that brokerage firms may be unwilling to hold or trade our Common Stock, restricting all trades by holders of our Common Stock following the Spin-Off, and the brokerage firms may return all such shares from the brokerage accounts to the beneficial holders.

The price per share of Meta’s Series A Preferred Stock traded on the over-the-counter (“OTC”) market under the symbol MMTLP may not accurately reflect the value of a share of our Common Stock that you will receive in the Distribution.

Before the Distribution, Meta’s Series A Preferred Stock was traded on the OTC market under the trading symbol “MMTLP”, although such shares of MMTLP were not eligible for broker-dealer quotations. The OTC

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market does not constitute an established stock exchange, and as a result, the historical trading prices for the shares of MMTLP may not be a reliable benchmark on which to determine the value of the shares of our Common Stock you will receive in the Distribution.

Additionally, securities of certain companies have recently experienced significant and extreme volatility in stock price due to short sellers of shares of securities, known as a “short squeeze.” These short squeezes have caused extreme volatility in both the stock prices of those companies and in the market and have led those companies’ securities to trade at a significantly inflated price per share that is disconnected from the underlying value of the company. In particular, if any investors have sold shares of MMTLP short, then in connection with the Distribution such investors may feel compelled to buy shares of MMTLP to cover such sales before the Distribution. If this were to occur, given the potential high demand from buyers with a relatively low supply of MMTLP shares available for sale on the OTC market, the MMTLP price per share as shown on the OTC market may rise significantly but not be representative of the value of the underlying shares of our Common Stock that you will receive in the Distribution.

No trading market for our Common Stock is expected to develop.

There is presently no public market for our shares of Common Stock and our shares are not expected to become DTC eligible for electronic trading to third parties. There is no expectation that a trading market will develop or be sustained. Accordingly, you may have to hold the shares of Common Stock indefinitely.

We do not intend to pay any cash dividends in the foreseeable future and, therefore, any return on your investment in our Common Stock must come from increases in the fair market value of the Common Stock.

We do not intend to pay cash dividends on our Common Stock in the foreseeable future. We expect to retain future earnings, if any, for reinvestment in our business. Also, any credit agreements, which we may enter into, may restrict our ability to pay dividends. Whether we pay cash dividends in the future will be at the discretion of our board of directors (the “Board”) and will be dependent upon our financial condition, results of operations, cash requirements, future prospects and any other factors our Board deems relevant. Therefore, any return on your investment in our Common Stock must come from increases in the fair market value of the Common Stock.

Your percentage ownership in the Company may be diluted in the future, including in our plan to issue our Common Stock for the working interests in our Orogrande Project.

Your percentage ownership in the Company may be diluted in the future because of equity awards that we expect to grant to our directors, officers and other employees and current holders of working interests in our Orogrande Project. Prior to the Spin-Off, we approved an incentive plan that will provide for the grant of Common Stock-based equity awards to our directors, officers and other employees. In addition, we may issue equity as all or part of the consideration paid for acquisitions and strategic investments that we may make in the future or as necessary to finance our ongoing operations.

We may issue preferred stock with terms that could adversely affect the voting power or value of our Common Stock.

Our Board has the authority to cause us to issue, without any further vote or action by the stockholders, shares of preferred stock in one or more series, to designate the number of shares constituting any series, and to fix the rights, preferences, privileges and restrictions thereof, including dividend rights, voting rights and terms of redemption, redemption price or prices and liquidation preferences of such series. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our Common Stock. For example, we might afford holders of preferred stock the right to elect some number of our directors in all events or upon the occurrence of specified events or the right to vote on specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of our Common Stock.

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Risks Relating to Our Status as a Public Reporting Company

We are an emerging growth company and a smaller reporting company, subject to less stringent reporting and regulatory requirements of other publicly reporting companies and this status may have an adverse effect on our ability to attract interest in our Common Stock.

We are an emerging growth company as defined in the JOBS Act. As long as we remain an emerging growth company, we may take advantage of certain exemptions from various reporting and regulatory requirements that are applicable to other public reporting companies that are not emerging growth companies. We cannot predict if investors will find our Common Stock less attractive if we choose to rely on these exemptions.

Additionally, we are a “smaller reporting company” as defined under the Exchange Act. Smaller reporting companies may take advantage of certain reduced disclosure obligations, including, among other things, providing only two years of audited financial statements. We will remain a smaller reporting company provided: (1) the market value of our common stock held by non-affiliates is less than $250 million as of the end of the prior June 30th, or (2) our annual revenues are less than $100 million during such completed fiscal year and the market value of our Common Stock held by non-affiliates is less than $700 million as of the prior June 30th. To the extent we take advantage of such reduced disclosure obligations, it may also make comparison of our financial statements with other public reporting companies difficult or impossible.

We may be required to file reports with the SEC only for the fiscal year in which the registration statement for the Spin-Off becomes effective and may no longer be subject to the reporting obligations under the Exchange Act thereafter.

By registering the shares of Common Stock in connection with the Spin-Off, we become subject to the reporting obligations under the Exchange Act, which includes filings of Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K for reporting periods ending on or before December 31, 2022. We would be obligated to continue these reporting obligations for subsequent reporting periods if on the last day of our fiscal year in which the Registration Statement of which this prospectus forms a part becomes effective we have more than $10 million in assets and either 2,000 or more record holders or 500 or more record holders who are not “accredited investors.” It is unclear whether the number of our record holders following the Spin-Off will meet one or both of these thresholds, in which case, we may become exempt from such reporting requirements after the year ending December 31, 2022. If we were to decide not to continue reporting, you will not have access to updated information regarding our business, financial condition and results of operation. Although we may and intend to continue to file such reports with the SEC, such filings will be voluntary.

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THE SPIN-OFF

Background

In June 2020 the board of directors of Torchlight began to pursue strategic alternatives for Torchlight due to the permeating financial climate of the oil and gas industry in 2020. In July 2020 Torchlight engaged Roth Capital Partners, LLC as its financial advisor in connection with a strategic transaction. After discussions with various companies, Torchlight began discussions with Metamaterial, Inc. in September 2020 concerning a potential strategic transaction.

After several months of negotiations, in December 2020 Torchlight and Metamaterial, Inc. entered into the Arrangement Agreement. Within the Arrangement Agreement, the oil and gas properties of Torchlight (the “O&G Assets”) were effectively allocated to the legacy Torchlight stockholders, which became the Series A Preferred stockholders of Torchlight (which was subsequently renamed “Meta Materials, Inc.”). Concurrent with the negotiation and execution of the Arrangement Agreement was the Certificate of Designation of Preferences, Rights and Limitations of the Series A Preferred Stock. Pursuant to the Certificate of Designation, upon a sale of the O&G Assets, the proceeds from any such transaction are to be distributed to the Series A Preferred stockholders, or Meta was to pursue a spin-off. In lieu of a sale of the O&G Assets, the Meta board has now determined to pursue the Spin-Off.

Reasons for the Spin-Off

The Meta board of directors considered the Spin-Off to be strategic so that Meta can concentrate on its core business.

When and How You Will Receive Shares of Common Stock

Meta will distribute to the holders of its Series A Preferred Stock, as a pro rata dividend, one share of our Common Stock for every share of Series A Preferred Stock outstanding as of                     , 2022 (the “Record Date”).

Prior to the Spin-Off, Meta will deliver all of the issued and outstanding shares of our Common Stock to the distribution agent. American Stock Transfer & Trust Company LLC (the “Transfer Agent”) will serve as distribution agent in connection with the Distribution and as transfer agent and registrar for our Common Stock.

If you own Series A Preferred Stock of Meta as of the close of business on                     , 2022, the shares of our Common Stock that you are entitled to receive in the Distribution will be issued to your account as follows:

• Registered stockholders. If you own your shares of Series A Preferred Stock directly through Meta’s transfer agent, American Stock Transfer & Trust Company LLC, you are a registered stockholder. In this case, the distribution agent will credit the whole number of shares of our Common Stock you receive in the Distribution by way of direct registration in book-entry form to a new account with the Transfer Agent. Registration in book-entry form refers to a method of recording share ownership where no physical stock certificates are issued to stockholders, as is the case in the Distribution. You will be able to access information regarding your book-entry account holding our shares at the Transfer Agent.

Commencing on or shortly after the Distribution Date, the Transfer Agent will mail to you an account statement that indicates the number of whole shares of our Common Stock that have been registered in book-entry form in your name. We expect it will take the Transfer Agent up to two weeks after the Distribution Date to complete the distribution of the shares of our Common Stock and mail statements of holdings to all registered stockholders. You or your bank, broker or other nominee may request that the Transfer Agent issue to you a physical stock certificate representing your shares of Common Stock.

• “Street name” or beneficial stockholders. Most Meta stockholders own their shares of Series A Preferred Stock beneficially through a bank, broker or other nominee. In these cases, the bank, broker

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or other nominee holds the shares in “street name” and records your ownership on its books. If you own your shares of the Series A Preferred Stock through a bank, broker or other nominee, your bank, broker or other nominee will credit your account with the whole shares of our Common Stock that you receive in the Distribution on or shortly after the Distribution Date; however, our shares of Common Stock will not be eligible for electronic trading through DTC or any other established clearing corporation. Therefore, we encourage you to contact your bank, broker or other nominee to instruct such bank, broker or other nominee to transfer the shares of Series A Preferred Stock to our transfer agent on or prior to the Record Date such that each such holder of Series A Preferred Stock is the registered holder of the distributed shares of Common Stock in book-entry form in a new account with our Transfer Agent.

If you sell shares of Series A Preferred Stock on or before the Distribution Date, you will not be entitled to receive the shares of Common Stock in the Distribution in respect of such shares of Series A Preferred Stock sold. We expect all trading of the shares of Series A Preferred Stock to be suspended as of the Distribution Date.

We are not asking holders of Meta Series A Preferred Stock to take any action in connection with the Spin-Off. No approval of any holders of Meta’s capital stock is required for the Spin-Off. We are not asking you for a proxy and request that you not send us a proxy. We are also not asking you to make any payment or surrender or exchange any of your shares of Meta Series A Preferred Stock for shares of our Common Stock. As of the Distribution Date, all of the shares of Series A Preferred Stock will be automatically cancelled and the holders of such Series A Preferred Stock will cease to have any rights with respect to such shares.

Number of Shares You Will Receive

On the Distribution Date, you will receive one share of our Common Stock for every share of Meta Series A Preferred Stock you hold on the Record Date. No fractional shares of Common Stock will be issued.

Results of the Spin-Off

After the Spin-Off, we will be an independent company. Immediately following the Spin-Off, we expect to have approximately 64,000 holders of shares of our Common Stock. In computing the number of holders of record, all broker-dealers and clearing corporation holding shares on behalf of its customers, the holders of the Series A Preferred Stock, is counted as a single shareholder. A significant number of shares of our Common Stock are held in either nominee name or street name brokerage accounts, and consequently, we are unable to determine the exact number of beneficial owners of our Common Stock.

We have entered into a Distribution Agreement and certain other agreements with Meta related to the Spin-Off. These agreements will govern the relationship between us and Meta up to and after completion of the Spin-Off and allocate between us and Meta various assets, liabilities, rights and obligations, including employee benefits, intellectual property and tax-related assets and liabilities. We describe these arrangements in greater detail under “Certain Relationships and Related Party Transactions—Agreements with Meta.”

Conditions to the Spin-Off

We expect that the separation will be effective on the Distribution Date, provided that the following conditions shall have been satisfied or waived by Meta:

• the Meta board of directors shall have authorized and approved the Distribution and not withdrawn such authorization and approval, and shall have declared the dividend of our Common Stock to Meta stockholders;

• the Distribution Agreement and the ancillary agreements contemplated by the Distribution Agreement shall have been executed by each party to those agreements;

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• the SEC shall have declared effective our Registration Statement on Form S-1, of which this Prospectus is a part, under the Securities Act, and no stop order suspending the effectiveness of our Registration Statement shall be in effect and no proceedings for that purpose shall be pending before or threatened by the SEC;

• no order, injunction or decree issued by any governmental authority of competent jurisdiction or other legal restraint or prohibition preventing consummation of the Distribution shall be in effect, and no other event outside the control of Meta shall have occurred or failed to occur that prevents the consummation of the Distribution;

• all necessary actions and filings with regard to applicable state securities or “blue sky” laws shall have been taken; and

• any material third party consents necessary to consummate the Spin-Off shall have been obtained or waived.

Reasons for Furnishing this Prospectus

We are furnishing this Prospectus solely to provide information to Meta Series A Preferred Stockholders who will receive shares of our Common Stock in the Distribution. You should not construe this Prospectus as an inducement or encouragement to buy, hold or sell any of our securities or any securities of Meta. We believe that the information contained in this Prospectus is accurate as of the date set forth on the cover. Changes to the information contained in this Prospectus may occur after that date, and neither we nor Meta undertake any obligation to update the information except in the normal course of our and Meta’s public disclosure obligations and practices and except as required by applicable law.

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MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS

Certain U.S. Federal Income Tax Consequences of the Spin-Off

The following is a summary of the material U.S. federal income tax consequences of our separation from Meta, and in particular the distribution by Meta of our Common Stock to the holders of the shares of Series A Preferred Stock (the “Series A Preferred Stockholders”) and the cancellation of all shares of the Series A Preferred Stock. For purposes of this section under the heading “Certain U.S. Federal Income Tax Consequences of the Spin-Off”: (i) any references to the “Spin-Off” shall mean only the distribution of shares of our Common Stock by Meta to Series A Preferred Stockholders and the cancellation of all shares of the Series A Preferred Stock, taken together; (ii) references to “Company,” “we,” “our” and “us” mean only Next Bridge Hydrocarbons, Inc. and not its subsidiaries or other lower-tier entities, except as otherwise indicated; and (iii) references to Meta refer to Meta Materials, Inc. This summary is based upon the Internal Revenue Code of 1986, as amended (the “Code”), the regulations promulgated by the U.S. Treasury Department (“Treasury Regulations”), rulings and other administrative pronouncements issued by the Internal Revenue Service (“IRS”), and judicial decisions, all as currently in effect, and all of which are subject to differing interpretations or to change, possibly with retroactive effect. No assurance can be given that the IRS would not assert, or that a court would not sustain, a position contrary to any of the tax consequences described below. We have not sought and do not intend to seek an advance ruling from the IRS regarding any matter discussed herein. The summary is also based upon the assumption that Meta, the Company and their respective subsidiaries and affiliated entities will operate in accordance with their applicable organizational documents or partnership agreements and the agreements and other documents applicable to our separation from Meta. This summary is for general information purposes only, does not address all possible tax considerations that may be material to an investor and does not constitute legal or tax advice. Moreover, this summary does not purport to discuss all aspects of U.S. federal income taxation that may be important to a particular investor in light of its investment or tax circumstances, or to investors subject to special tax rules, such as:

• financial institutions;

• insurance companies;

• broker-dealers;

• regulated investment companies and real estate investment trusts;

• partnerships and trusts;

• persons who hold our stock on behalf of another person as a nominee;

• persons who receive our stock through the exercise of employee stock options or otherwise as compensation;

• persons holding our stock as part of a “straddle,” “hedge,” “conversion transaction,” “synthetic security” or other integrated investment;

• tax-exempt organizations;

and, except to the extent discussed below:

• foreign investors.

This summary assumes that investors hold their Series A Preferred Stock as a capital asset and will hold their Common Stock as a capital asset, which generally means as property held for investment.

For purposes of this discussion under the heading “Certain U.S. Federal Income Tax Consequences of the Spin-Off,” a U.S. holder is a Series A Preferred Stockholder that is for U.S. federal income tax purposes:

• a citizen or resident of the United States,

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• a corporation (including an entity treated as a corporation for U.S. federal income tax purposes) created or organized in or under the laws of the United States, any of its states, or the District of Columbia,

• an estate, whose income is subject to U.S. federal income taxation regardless of its source, or

• a trust if (1) a U.S. court is able to exercise primary supervision over the administration of such trust and one or more U.S. persons have the authority to control all substantial decisions of the trust or (2) it has a valid election to be treated as a U.S. person.

A “non-U.S. holder” is a Series A Preferred Stockholder that is not a U.S. holder and is not an entity treated as a partnership for U.S. federal income tax purposes. If a partnership, entity or arrangement treated as a partnership for U.S. federal income tax purposes holds Series A Preferred Stock, the U.S. federal income tax treatment of a partner in the partnership will generally depend upon the status of the partner and the activities of the partnership. An investor that is a partnership and the partners in such partnership should consult their tax advisors about the U.S. federal income tax consequences of the Spin-Off.

THE U.S. FEDERAL INCOME TAX TREATMENT OF THE SPIN-OFF TO STOCKHOLDERS OF META DEPENDS IN SOME INSTANCES ON DETERMINATIONS OF FACT AND INTERPRETATIONS OF COMPLEX PROVISIONS OF U.S. FEDERAL INCOME TAX LAW FOR WHICH NO CLEAR PRECEDENT OR AUTHORITY MAY BE AVAILABLE. IN ADDITION, THE TAX CONSEQUENCES OF THE SPIN-OFF TO ANY PARTICULAR STOCKHOLDER OF META WILL DEPEND ON THE STOCKHOLDER’S PARTICULAR TAX CIRCUMSTANCES. YOU ARE URGED TO CONSULT YOUR TAX ADVISOR REGARDING THE U.S. FEDERAL, STATE, LOCAL, AND FOREIGN INCOME AND OTHER TAX CONSEQUENCES TO YOU OF THE SPIN-OFF IN LIGHT OF YOUR PARTICULAR INVESTMENT OR TAX CIRCUMSTANCES.

Tax Classification of the Spin-Off in General

For U.S. federal income tax purposes, the Spin-Off will not be eligible for treatment as a tax-deferred distribution by Meta with respect to its stock. Accordingly, the Spin-Off will generally be treated as a fully taxable transaction. The discussion below describes the U.S. federal income tax consequences to a U.S. holder and a non-U.S. holder upon the receipt of our Common Stock in the Spin-Off.

Although Meta will ascribe a value to the Common Stock distributed in the Spin-Off, this valuation is not binding on the IRS or any other taxing authority. These taxing authorities could ascribe a higher valuation to the distributed Common Stock, particularly if, following the Spin-Off, those shares of Common Stock trade at prices significantly above the value ascribed to those shares by Meta. Such a higher valuation may affect the Spin-Off distribution amount and thus the U.S. federal income tax consequences of the Spin-Off to Meta’s Series A Preferred stockholders. Fractional shares of Common Stock will not be distributed.

Meta will be required to recognize any gain, but will not be permitted to recognize any loss, with respect to the Common Stock that it distributes in the Spin-Off equal to the fair market value of the Common Stock in excess of Meta’s adjusted tax basis in the Common Stock.

Tax Basis and Holding Period of Company Shares Received by Holders of Meta Stock

A Series A Preferred stockholder’s tax basis in shares of our Common Stock received in the Spin-Off generally will equal the fair market value of such shares on the date of the Spin-Off, and the holding period for such shares will begin the day after the date of the Spin-Off.

Tax Treatment of the Spin-Off to U.S. Holders

The following discussion describes the U.S. federal income tax consequences to a U.S. holder of Meta stock upon the receipt of our Common Stock in the Spin-Off.

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The treatment of the Spin-Off for U.S. federal income tax purposes for a U.S. holder will depend on whether the Spin-Off qualifies as a sale of the Series A Preferred Stock under Section 302 of the Code. If the Spin-Off qualifies as a sale of the Series A Preferred Stock, a U.S. holder will recognize gain or loss as described below under “—Gain or Loss on the Spin-Off Treated as a Sale or Exchange of Series A Preferred Stock” below. If the Spin-Off does not qualify as a sale of the Series A Preferred Stock, a U.S. holder will be treated as receiving a corporate distribution subject to tax as described below under “—Taxation of the Spin-Off Treated as a Distribution.” Whether a distribution qualifies for sale treatment will depend largely on the total number of shares of Meta stock treated as held by a U.S. holder (including any shares constructively owned by a U.S. holder) relative to all of the Meta stock outstanding both before and after the Spin-Off. The Spin-Off generally will be treated as a sale of Series A Preferred Stock (rather than as a corporate distribution) if the Spin-Off: (i) results in a “complete termination” of a U.S. holder’s interest in Meta, (ii) is “not essentially equivalent to a dividend” with respect to such U.S. holder or (iii) is a “substantially disproportionate redemption” with respect to such U.S. holder. These tests are explained more fully below.

In determining whether any of the foregoing tests are satisfied, a U.S. holder must take into account not only shares of Meta stock actually owned by such U.S. holder, but also shares of Meta stock that are constructively owned by such U.S. holder. A U.S. holder may constructively own, in addition to shares owned directly, shares owned by certain related individuals and entities in which such U.S. holder has an interest or that have an interest in such U.S. holder, as well as any shares such U.S. holder has a right to acquire by exercise of an option. There will be a complete termination of a U.S. holder’s interest if either (i) all of the shares of Meta stock actually and constructively owned by such U.S. holder are exchanged or (ii) all of the shares of Meta stock actually owned by such U.S. holder are exchanged and such U.S. holder is eligible to waive, and does waive, the attribution of shares owned by certain family members and such U.S. holder does not constructively own any other shares. The Spin-Off of Series A Preferred Stock will not be essentially equivalent to a dividend if the Spin-Off results in a “meaningful reduction” of a U.S. holder’s proportionate interest in Meta. Whether the Spin-Off will result in a meaningful reduction in a U.S. holder’s proportionate interest in Meta will depend on the particular facts and circumstances. However, the IRS has indicated in a published ruling that even a small reduction in the proportionate interest of a small minority stockholder in a publicly held corporation who exercises no control over its corporate affairs may constitute such a “meaningful reduction.” In order to meet the “substantially disproportionate” test, the percentage of outstanding shares of Meta voting stock actually and constructively owned by a U.S. holder immediately following the Spin-Off must, among other requirements, be less than 80% of the percentage of the outstanding shares of Meta voting stock actually and constructively owned by such U.S. holder immediately before the Spin-Off. Because the Class A Preferred Stock is not voting stock, it is not expected that the “substantially disproportionate” test will be satisfied in respect of the Spin-Off. U.S. holders are urged to consult with their tax advisors as to the tax consequences of the Spin-Off.

If none of the foregoing tests are satisfied, then the Spin-Off will be treated as a corporate distribution and the tax effects will be as described under “—Taxation of the Spin-Off Treated as a Distribution,” below.

Meta currently intends to report the Spin-Off as a corporate distribution (including a determination of the portion of the distribution pursuant to the Spin-Off constituting a taxable dividend, assuming that the Spin-Off is treated as a corporate distribution) on IRS Form 1099-DIV after its earnings and profits for the taxable year in which the distribution occurs are calculated. This information may not be available until after U.S. holders file their U.S. federal and state income tax returns for that taxable year, and such U.S. holders may need to file amended tax returns to reflect the amount of the taxable dividend as finally determined. Meta reporting the Spin-Off as a corporate distribution will not preclude a U.S. holder from treating the Spin-Off as a sale of Series A Preferred Stock, if one of the tests described above is satisfied.

Taxation of the Spin-Off Treated as a Distribution

If the Spin-Off of a U.S. holder’s Series A Preferred Stock does not qualify as a sale of Series A Preferred Stock, such U.S. holder will be treated as receiving a distribution from Meta. A U.S. holder generally will be required to

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include in gross income as dividends the amount received in connection with the Spin-Off to the extent the distribution is paid out of Meta’s current or accumulated earnings and profits (as determined under U.S. federal income tax principles). Distributions in excess of such current and accumulated earnings and profits generally will be treated as a return of capital that will be applied against and reduce a U.S. holder’s adjusted tax basis in such U.S. holder’s shares of Series A Preferred Stock (but not below zero), with any remaining excess treated as gain from the sale or exchange of such shares as described below under “—Gain or Loss on the Spin-Off Treated as a Sale or Exchange of Series A Preferred Stock.”

If a U.S. holder is a corporate U.S. holder, dividends paid by Meta to such U.S. holder generally will be eligible for the dividends-received deduction allowed to domestic corporations in respect of dividends received from other domestic corporations so long as such U.S. holder satisfies the holding period requirement for the dividends-received deduction.

If a U.S. holder is a non-corporate U.S. holder, under tax laws currently in effect, dividends generally will be taxed at the preferential applicable long-term capital gains rate so long as such U.S. holder satisfies the holding period requirement (i.e., more than sixty (60) days of ownership, without protection from the risk of loss, during the 121-day period that begins sixty (60) days before the ex-dividend date) and certain other requirements are met (see “—Gain or Loss on the Spin-Off Treated as a Sale or Exchange of Series A Preferred Stock” below).

Gain or Loss on the Spin-Off Treated as a Sale or Exchange of Series A Preferred Stock

If the Spin-Off qualifies as a sale of Series A Preferred Stock, such U.S. holder generally will recognize capital gain or loss in an amount equal to the difference between (i) the fair market value of our Common Stock received by such U.S. holder in the Spin-Off and (ii) such U.S. holder’s adjusted tax basis in the Series A Preferred Stock surrendered in the Spin-Off.

Any such capital gain or loss generally will be long-term capital gain or loss if a U.S. holder’s holding period for the Series A Preferred Stock so disposed of exceeds one (1) year. Long-term capital gains recognized by non-corporate U.S. holders generally will be eligible for taxation at reduced rates. The deductibility of capital losses is subject to limitations.

Tax Treatment of the Spin-Off to Non-U.S. Holders

For non-U.S. holders of Series A Preferred Stock, the characterization for U.S. federal income tax purposes of the Spin-Off of such non-U.S. holder’s Series A Preferred Stock generally will correspond to the U.S. federal income tax characterization of the Spin-Off of a U.S. holder’s Series A Preferred Stock, as described above under “Treatment of the Spin-Off for U.S. Holders” with respect to whether the Spin-Off is a sale or exchange of Series A Preferred Stock or is treated as a distribution.

Non-U.S. holders are urged to consult their own tax advisors as to whether the Spin-Off will be treated as a distribution, or as a sale or exchange, under the Code.

Taxation of the Spin-Off Treated as a Distribution

If the Spin-Off of a non-U.S. holder’s Series A Preferred Stock does not qualify as a sale or exchange of Series A Preferred Stock, such non-U.S. holder will be treated as receiving a distribution from Meta, which distribution will be treated as a dividend to the extent the distribution is paid out of Meta’s current or accumulated earnings and profits (as determined under U.S. federal income tax principles). The gross amount of such dividends will be subject to a withholding tax at a rate of 30% unless a non-U.S. holder is eligible for a reduced rate of withholding under an applicable income tax treaty and provides proper certification of such non-U.S. holder’s eligibility for such reduced rate. Dividends that are effectively connected with the conduct by a non-U.S. holder of a trade or

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business in the United States (and are attributable to a U.S. permanent establishment if an applicable treaty so requires) generally will be subject to U.S. federal income tax at the same regular U.S. federal income tax rates applicable to a comparable U.S. holder and, if such non-U.S. holder is a corporation for U.S. federal income tax purposes, may also be subject to an additional branch profits tax at a 30% rate or a lower rate under an applicable tax treaty.

Distributions in excess of current and accumulated earnings and profits generally will be treated as a return of capital that will be applied against and reduce a non-U.S. holder’s adjusted tax basis in such non-U.S. holder’s shares of Series A Preferred Stock (but not below zero), with any remaining excess treated as gain from the sale or exchange of such shares as described under “—Gain or Loss on the Spin-Off Treated as a Sale or Exchange of Series A Preferred Stock” below.

Gain or Loss on the Spin-Off Treated as a Sale or Exchange of Series A Preferred Stock

Subject to the discussions of backup withholding and FATCA withholding below, if the Spin-Off of a non-U.S. holder’s shares of Series A Preferred Stock qualifies as a sale or exchange of such shares, such non-U.S. holder generally will not be subject to U.S. federal income tax on any gain recognized on such Spin-Off unless:

• such gain is effectively connected with the conduct by such non-U.S. holder of a trade or business in the United States (and, if required by an applicable income tax treaty, is attributable to a permanent establishment or fixed base that such non-U.S. holder maintains in the United States), in which case such non-U.S. holder generally will be subject to U.S. federal income tax on such gain at the same regular U.S. federal income tax rates applicable to a comparable U.S. holder and, if such non-U.S. holder is a corporation for U.S. federal income tax purposes, also may be subject to an additional branch profits tax at a 30% rate or a lower rate provided by an applicable tax treaty;

• such non-U.S. holder is an individual who is present in the United States for 183 days or more in the taxable year of the disposition and certain other conditions are met, in which case such non-U.S. holder will be subject to a 30% tax on such non-U.S. holder’s net capital gain for the year (or lower rate provided by an applicable tax treaty); or

• Meta is or has been a “U.S. real property holding corporation” for U.S. federal income tax purposes at any time during the shorter of the five (5) year period ending on the date of the Spin-Off or the period during which such non-U.S. holder held Series A Preferred Stock, and, in the case where shares of the Series A Preferred Stock are traded on an established securities market, such non-U.S. holder has owned, directly or constructively, more than 5% of the Series A Preferred Stock at any time within the shorter of the five (5) year period or such non-U.S. holder’s holding period for the Series A Preferred Stock. Meta does not believe that it is or has been a U.S. real property holding corporation.

Because it may not be certain at the time a non-U.S. holder’s Series A Preferred Stock is exchanged whether the Spin-Off will be treated as a sale or exchange or as a distribution, and because such determination will depend in part on such non-U.S. holder’s particular circumstances, the applicable withholding agent may not be able to determine whether (or to what extent) such non-U.S. holder is treated as receiving a dividend for U.S. federal income tax purposes. Therefore, the applicable withholding agent may withhold tax at a rate of 30% (or such lower rate as may be specified by an applicable income tax treaty) on the gross amount of any consideration paid to a non-U.S. holder in exchange for such non-U.S. holder’s Series A Preferred Stock, unless (i) the applicable withholding agent has established special procedures allowing non-U.S. holders to certify that they are exempt from such withholding tax and (ii) such non-U.S. holder is able to certify that such non-U.S. holder meets the requirements of such exemption (e.g., because such non-U.S. holder is not treated as receiving a dividend under the Section 302 tests described above). However, there can be no assurance that any applicable withholding agent will establish such special certification procedures. Thus, the applicable withholding agent may withhold some portion of our Common Stock otherwise distributable to a non-U.S. holder to satisfy its obligation to withhold tax, except to the extent it estimates that the amount of the proceeds from the Spin-Off will exceed Meta’s

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current and accumulated earnings and profits. To the extent it is required to withhold tax, the applicable withholding agent may sell the portion of our Common Stock otherwise distributable to non-U.S. holders needed to pay that tax, together with associated expenses. If an applicable withholding agent withholds excess amounts from the amount payable to a non-U.S. holder, such non-U.S. holder generally may obtain a refund of any such excess amounts by timely filing an appropriate claim for refund with the IRS. Non-U.S. holders should consult their own tax advisors regarding the application of the foregoing rules in light of such non-U.S. holder’s particular facts and circumstances and any applicable procedures or certification requirements.

Tax Considerations to U.S. Holders in Respect of Ownership and Disposition of Our Common Stock

Dividends. Any dividends paid by the Company out of its current or accumulated earnings and profits (as determined for U.S. federal income tax purposes) generally will be taxable to a U.S. holder as ordinary dividend income. Corporate U.S. holders should generally be eligible for the dividends received deduction and non-corporate U.S. holders should generally qualify for reduced rates applicable to qualified dividend income, assuming, in each case, that a minimum holding period and certain other generally applicable requirements are satisfied. Dividends in excess of current and accumulated earnings and profits will be treated as a non-taxable return of capital to the extent of the U.S. holder’s basis in our Common Stock and thereafter as capital gain. U.S. holders should consult their own tax advisors with respect to the appropriate U.S. federal income tax treatment of any dividend received from the Company. Dividends received by a non-corporate U.S. holder may be subject to a 3.8% Medicare tax on net investment income.

Sales or Other Dispositions of Our Common Stock. A U.S. holder will recognize capital gain or loss on the sale or other disposition of our Common Stock in an amount equal to the difference between the U.S. holder’s adjusted tax basis in our Common Stock and the amount realized from the disposition. Any gain or loss on a sale or other disposition of our Common Stock generally will be long-term capital gain or loss if the holder has held our Common Stock for more than one year. Deductions for capital losses are subject to limitations. Any gain recognized by a non-corporate U.S. holder may be subject to a 3.8% Medicare tax on net investment income.

Tax Considerations to Non-U.S. Holders in Respect of Ownership and Disposition of Our Common Stock

Dividends. Any dividends paid on our Common Stock that are characterized as dividends paid to a non-U.S. holder generally will be subject to withholding of U.S. federal income tax at a 30% rate or such lower rate as may be provided by an applicable income tax treaty. To receive the benefit of a reduced treaty rate, a non-U.S. holder must furnish to the Company or its paying agent a valid IRS Form W-8 (or applicable successor form) certifying such holder’s qualification for the reduced rate. This certification must be provided to the Company or its paying agent prior to the payment of dividends and must be updated periodically. If a non-U.S. holder who qualifies for a reduced treaty rate but does not timely provide the Company or the payment agent with the required certification, such non-U.S. holder may be entitled to a credit against their U.S. federal income tax liability or a refund of the tax withheld, which the non-U.S. holder may claim by filing the appropriate claim for refund with the IRS.

Dividends that are treated as “effectively connected” with a trade or business conducted by a non-U.S. holder within the United States (and, if an applicable income tax treaty so provides, are also attributable to a U.S. permanent establishment of such non-U.S. holder) are not subject to withholding tax, provided the non-U.S. holder satisfies certain certification and disclosure requirements. Instead, such dividends, net of specified deductions and credits, are taxed at the same graduated U.S. federal income tax rates applicable to U.S. persons. To the extent a dividend is effectively connected with a U.S. trade or business, non-corporate non-U.S. holders may be eligible for taxation at reduced U.S. federal income tax rates applicable to qualified dividend income. Any such effectively connected dividends received by a non-U.S. holder that is a corporation may, under certain circumstances, be subject to an additional branch profits tax at a 30% rate or such lower rate as specified by an applicable income tax treaty.

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Sales or Other Dispositions of Our Common Stock. Subject to the discussions under “Information Reporting and Backup Withholding” and “FATCA,” below, a non-U.S. holder will generally not be subject to any U.S. federal income tax or withholding tax on any gain realized upon such holder’s sale or other disposition of our Common Stock. Gain on the sale of our Common Stock may be subject to U.S. net income tax (and in respect of corporate non-U.S. holders, branch profits tax) if the gain is effectively connected with a trade or business of the non-U.S. holder in the United States (and, if required by an applicable income tax treaty, is attributable to a permanent establishment or fixed base of the non-U.S. holder within the United States). Additionally, a non-U.S. holder that is an individual who is present in the United States for 183 days or more in the taxable year of the disposition and meets certain other requirements will be subject to a flat 30% tax on the amount of gain derived from the sale that, together with certain other U.S. source capital gains realized during such year exceed certain U.S. source capital losses realized during such year.

FATCA. Pursuant to the Foreign Account Tax Compliance Act, or FATCA, foreign financial institutions (which include most foreign hedge funds, private equity funds, mutual funds, securitization vehicles and any other investment vehicles) and certain other foreign entities must comply with registration and information reporting rules with respect to their U.S. account holders and investors or be subject to a withholding tax on U.S.-source payments made to them (whether received as a beneficial owner or as an intermediary for another party). A foreign financial institution or other foreign entity that does not comply with the FATCA registration and reporting requirements will generally be subject to a 30% withholding tax on “withholdable payments.” For this purpose, withholdable payments generally include U.S.-source payments (including U.S.-source dividends), and (subject to the proposed Treasury Regulations discussed below) the gross proceeds from a sale of equity or debt instruments of issuers who are considered U.S. issuers under the FATCA rules. The FATCA withholding tax applies even if the payment would otherwise not be subject to U.S. nonresident withholding tax (e.g., because it is capital gain). While withholding under FATCA would also have applied to payments of gross proceeds from the sale or other disposition of stock on or after January 1, 2019, proposed Treasury Regulations which, if finalized in their present form, would eliminate FATCA withholding on payments of gross proceeds of a disposition of Series A Preferred Stock or our Common Stock entirely. Taxpayers may generally rely on these proposed Treasury Regulations until final Treasury Regulations are issued. Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing FATCA may be subject to different rules. We will not pay additional amounts in respect of amounts withheld. Investors should consult their tax advisors regarding possible implications of FATCA.

Information Reporting and Backup Withholding. In general, information reporting requirements may apply to dividends, sales proceeds or other amounts paid to U.S. holders and non-U.S. holders, unless an exemption applies. Backup withholding tax may apply to amounts subject to reporting if the holder fails to provide an accurate taxpayer identification number or fails to report all interest and dividends required to be shown on its U.S. federal income tax returns. A U.S. holder or non-U.S. holder can claim a credit against its U.S. federal income tax liability for the amount of any backup withholding tax and a refund of any overpayment of taxes, provided that all required information is timely provided to the IRS. U.S. holders and non-U.S. holders should consult their tax advisors as to their qualification for exemption from backup withholding and the procedure for establishing an exemption.

THE DISCUSSION ABOVE IS A GENERAL SUMMARY. IT DOES NOT COVER ALL TAX MATTERS THAT MAY BE OF IMPORTANCE TO A PARTICULAR STOCKHOLDER. EACH STOCKHOLDER IS URGED TO CONSULT ITS OWN TAX ADVISOR ABOUT THE TAX CONSEQUENCES TO IT OF THE SPIN-OFF IN LIGHT OF THE STOCKHOLDER’S OWN CIRCUMSTANCES.

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USE OF PROCEEDS

We will not receive any proceeds from the Distribution of the Common Stock in the Spin-Off and any expenses incurred in connection with the Distribution shall be borne by us.

DETERMINATION OF OFFERING PRICE

Currently, there is no public trading market for our Common Stock and no consideration will be paid for the shares of Common Stock distributed in the Spin-Off.

CAPITALIZATION

The following table sets forth our cash and capitalization as of June 30, 2022 on (i) an actual basis; and (ii) on a pro forma basis to give effect to the Distribution. The following table should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our historical consolidated financial statements and the notes thereto included elsewhere in this Prospectus.

	June 30, 2022
	Actual As Reported			Pro Forma Adjustments for Distribution
Cash and cash equivalents	$	998,260		$	3,657,260
Short-term debt	$	18,137,111		$	21,942,471
Stockholders’ Equity
Common stock, $0.0001 par value; 500,000,000 shares authorized, 1 share issued and outstanding as reported; 165,523,363 shares issued and outstanding, pro forma as adjusted		16,552			16,552
Preferred stock, $0.0001 par value; 50,000,000 shares authorized, 0 shares issued and outstanding
Additional paid in capital		100,846,643			100,846,643
Accumulated deficit		(70,787,622	)		(73,065,395	)
Total stockholders’ equity		30,075,573			27,797,800
Total capitalization	$	48,212,684		$	49,740,271

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BUSINESS

General

We are an energy company engaged in the acquisition, exploration, exploitation and/or development of oil and natural gas properties in the United States. Our primary focus has been the development of interests in an oil and natural gas project we hold in the Orogrande Basin in West Texas. In addition, we may consider various strategic options, including partnering with, or the possible sale of any or all of our assets to, third parties. We operate our business through our wholly owned subsidiaries, Torchlight Energy, Inc., Hudspeth Oil Corporation, Torchlight Hazel, LLC, and Hudspeth Operating, LLC.

Presently, our primary interests include the oil and natural gas leases for properties of the Orogrande Basin in Hudspeth County, Texas (the “Orogrande Project”). In addition, we have minor interests in the Eastern edge of the Midland Basin in West Texas (the “Hazel Project”) and two minor well interests in Oklahoma (the “Oklahoma Properties”).

Rich Masterson, our consulting geologist, originated our Orogrande Project, as discussed below, based on his tenure as a geologist since 1974. He is credited with originating the Wolfbone shale play in the Southern Delaware Basin of West Texas and has prepared prospects totaling over 150,000 acres that have been leased, drilled and are currently being developed by Devon Energy Corp., Occidental Petroleum Corporation, Noble Energy, and Samson Oil & Gas Ltd., among others.

The Company has drilled 14 test wells in the Orogrande Project in the basin in order to stay in compliance with the continuous drilling clause under the University Lands D&D Unit Agreement, as well as, to test for potential shallow pay zones and deeper pay zones that may be present on structural plays. Development of the wells continued through the year ended December 31, 2021 to further capture and document the scientific base in support of demonstrating the production potential of the Orogrande Project properties. Two of the wells were successfully completed for hydrocarbons, while the remaining wells serve as fresh water supply wells, wells we maintain for salt water disposal or wells we expect to be plugged and abandoned.

We satisfied the 2021 drilling obligations in the Orogrande play and, in satisfying our 2021 drilling obligations, we identified new potential pay zones not yet discovered in the Orogrande play.

In addition to the Orogrande Project, we also have an interest in our Hazel Project in Tom Green County and Sterling County, Texas. In August 2020, our subsidiaries entered into the Option Agreement with MHP, under which, in exchange for satisfying certain drilling obligations, MHP had the option to purchase the entire Hazel Project. The option to purchase the entire acreage block was extended to September 30, 2021 and at such time MHP determined not to exercise the purchase option; however, MHP is entitled to receive, as its sole recourse for the recoupment of drilling costs, the revenue from production of the well attributable to our interest until such time as it has recovered its reasonable costs and expenses for drilling, completing and operating the well. Operations continue under the Option Agreement until such time as the revenue from the project equates to the dollars spent by, and shall be reimbursed to, MHP. At such time, any acreage held by production and all wells will revert back to our subsidiary, Torchlight Hazel, LLC.

Our principal executive offices are located at 6300 Ridglea Place, Suite 950, Fort Worth, Texas 76116. The telephone number of our principal executive offices is (817) 438-1937.

Key Business Attributes

Experienced People. Upon completion of the Distribution, we will have six full-time employees and we expect to engage consultants for various roles as needed including high quality exploration and technical partners. We will build on the expertise and experiences of our management team and seek guidance from outside advisors as well as our Board.

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Project Focus. We are focusing primarily on exploitation projects. We may pursue high risk exploration prospects which may appear less favored than low risk exploration. We will, however, consider these high risk-high reward exploration prospects in connection with exploitation opportunities in a project that would reduce the overall project economic risk. We will consider such high risk-high reward prospects on their individual merits.

Lower Cost Structure. We will attempt to maintain the lowest possible cost structure, enabling the greatest margins and providing opportunities for investment that would not be feasible for higher cost competitors.

Limit Capital Risks. Limited capital exposure is planned initially to add value to a project and determine its economic viability. Management has experience in successfully managing risks of projects, finance, and value.

Business Processes

We believe there are three principal business processes that we must follow to enable our operations to be profitable. Each major business process offers the opportunity for a distinct partner or alliance as we grow. These processes are:

• Investment Evaluation and Review;

• Operations and Field Activities; and

• Administrative and Finance Management.

Investment Evaluation and Review. This process is the key ingredient to our success. Recognition of quality investment opportunities is the fuel that drives our engine. Broadly, this process includes the following activities: prospect acquisition, regional and local geological and geophysical evaluations, data processing, economic analysis, lease acquisition and negotiations, permitting, and field supervision. We expect these evaluation processes to be managed by our management team. Expert or specific technical support will be outsourced as needed.

Operations and Field Activities. This process begins following management approval of an investment. Well site supervision, construction, drilling, logging, product marketing, and transportation are examples of some activities. We will prefer to be the operator where possible.

Administrative and Finance Management. This process coordinates our initial structuring and capitalization, general operations and accounting, reporting, audit, banking and cash management, regulatory agencies reporting and interaction, timely and accurate payment of royalties, taxes, leases rentals, vendor accounts and performance management that includes budgeting and maintenance of financial controls, and interface with legal counsel and tax and other financial and business advisors.

Current Projects

As of June 30, 2022, we had interests in three oil and natural gas projects: the Orogrande Project in Hudspeth County, Texas, the Hazel Project in Sterling, Tom Green, and Irion Counties, Texas and the Oklahoma Properties. See the description under “Current Projects” below under Note 4, “Oil & Natural Gas Properties,” of the financial statements included with this Prospectus for information and disclosure regarding these projects, which description is incorporated herein by reference.

Our Properties

Our principal executive office is located at 6300 Ridglea Place, Suite 950, Fort Worth, Texas 76116. We currently sublease this office space and believe that the condition and size of our offices are adequate for our current needs.

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The Orogrande Project consists of unevaluated and undeveloped properties in progress of development for future production.

	Total Acres				Developed Acres				Undeveloped Acres
	Gross		Net		Gross		Net		Gross		Net
Texas—
Orogrande Project		134,000		89,110		—		—		134,000		89,110
Hazel Project		645		516		645		516		—		—
Oklahoma—
Viking		640		192		640		192		—		—
Total		135,285		89,818		1,285		708		134,000		89,110

Investments to support our oil and natural gas properties during the years ended December 31, 2021 and 2020 were $14.7 million and $3.4 million, respectively.

	Fiscal Year Ended December 31,
	2021		2020
Property acquisition costs	$	—	$	—
Development costs		14,664,463		3,472,281
Exploratory costs		—		—
Totals	$	14,664,463	$	3,472,281

Property development costs presented above exclude interest capitalized into the full cost pool of $141,048 in 2021 and $2,353,700 in 2020.

The development costs for 2020 include work in the Orogrande and Hazel Projects in West Texas and for 2021 the development costs include work solely in the Orogrande Project. We made progress during 2021 to develop proved producing reserves in the Orogrande Project in the Permian Basin in West Texas, which has not yet resulted in hydrocarbon production. We incurred costs of $14.7 million in relation to certain drilling activity carried out to remain in compliance with all aspects of our lease obligations and to satisfy the continuous drilling clause under the agreement with University Lands, whereby we are obligated to satisfy certain minimum yearly requirements that may be exceeded if desired. No development costs were incurred in 2020 or 2021 for the Oklahoma Properties. During the fiscal years ended December 31, 2021 and 2020, and for the quarter ended June 30, 2022, we drilled development and exploratory wells as set forth in the table below.

Drilling Activity	June 30,				December 31,					December 31,
	2022				2021					2020
	Dry		Productive		Dry			Productive		Dry		Productive
Hazel Project (Texas)		0		0		2			0		1		0
Orogrande Project (Texas)		0		0		1	(1)		4		0		0

(1) Represents drilling re-entry to explore more of the formation.

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For the six months ended June 30, 2022 compared to the same period in 2021, investments were as follows:

	Six Months Ended June 30,
	2022		2021
Property acquisition costs	$	—	$	—
Development costs		1,491,766		1,713,604
Exploratory costs		—		—
Totals	$	1,491,766	$	1,713,604

During the six months ended June 30, 2022, a portion of the costs from development activities were cost carryover related to satisfaction of our drilling obligations for the fiscal year 2021 under the terms of the Purchase Agreement (defined below) at a cost of $1,084,285. Additionally, during the first six months of 2022, we completed some pre-drilling activity for our upcoming 2022 drilling program, including surveying, permitting, road and pad site work at an aggregate cost of $407,481. We have not yet conducted any drilling activities, but expect to commence drilling activities in October 2022 to satisfy our obligations for the 2022 fiscal year.

	June 30, 2022		December 31, 2021		December 31, 2020
Productive Wells
Oil		5		5		5
Gas		4		4		1
Test Wells
Salt Water Disposal		3		3		2
Fresh Water Supply		3		3		2
Plug & Abandon		5		5		4

With the principal goal of gathering scientific data from a strategy of drilling test wells, all wells were drilled with the intent of being completed and productive for hydrocarbons. We attempted completions on every well, however we were unable to effectuate a successful completion on all of the vertical wells due to various problems. This is not uncommon with early wells of frontier exploration projects. Two horizontal wells were successfully completed for hydrocarbons, however both wells are currently shut-in waiting for hook-up to a gas pipeline. The remaining wells serve as fresh water supply wells, wells we maintain for salt water disposal or wells we expect to be plugged and abandoned. Pipeline hook-ups will occur after we have achieved additional successful wells to justify the cost of tapping into the gas lines.

Oil and Natural Gas Reserves

No reserve report was prepared for 2020. Other than the Producing Hazel Wells (defined below), the only producing properties owned by us were the Oklahoma Properties, which were marginally producing and were uneconomic for reserve calculation purposes. At the end of 2021 and 2020, reserves did not include any value for proved undeveloped properties.

We currently have two producing wells located on the Hazel Project, the Flying B Ranch #3H well and the Flying B Ranch #4H well (the “Producing Hazel Wells”). Production is from the Wolfcamp formation. At December 31, 2021, there were no proved reserves or proved developed nonproducing reserves related to these properties after giving effect to the obligation to reimburse drilling costs incurred by MHP. The properties of the Hazel Project and Orogrande Project are operated by Maverick Operating LLC.

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The operating expenses reflect a substantial reduction from previous years as electric power is available and water is now disposed of on location after we drilled or converted a well to be used for saltwater disposal. Initial gross oil production from the Flying B Ranch #3H well reached 8,319 Bbl per month and 31,613 Bbl per month of water. It is anticipated that the well has a gross ultimate oil recovery of 154 MBbl. The Flying B Ranch #4H well had an initial monthly production rate of 4,200 Bbl of oil and has a gross ultimate oil recovery of 192 MBbl.

As of December 31, 2021 and 2020, our proved developed nonproducing reserves related to the Producing Hazel Wells totaled 0 and 0 BOE, respectively, and 0 BOE for the six months ended June 30, 2022 after giving effect to the obligation to reimburse drilling costs incurred by MHP.

Production, Price, and Production Cost History

Oklahoma Properties

During the year ended December 31, 2020, we produced and sold 278 barrels of oil net to our interest at an average sale price of $16.13 per Bbl. We produced and sold 2,012 Mcf of gas net to our interest at an average sales price of $1.20 per Mcf. Our average production cost including lease operating expenses and direct production taxes was $30.02 per BOE. Our depreciation, depletion, and amortization expense was $130.68 per BOE.

During the year ended December 31, 2021, we produced and sold 85 barrels of oil net to our interest at an average sale price of $55.00 per Bbl. We produced and sold 3,586 Mcf of gas net to our interest at an average sales price of $3.17 per Mcf. Our average production cost including lease operating expenses and direct production taxes was $18.54 per BOE. Our depreciation, depletion, and amortization expense was $0 per BOE.

During the six months ended June 30, 2021, we produced and sold 56.34 Bbls net to our interest at an average sale price of $50.72 per Bbl. We produced and sold 1922.87 Mcf of natural gas net to our interest at an average sale price of $1.62 per Mcf. Our average production cost including lease operating expenses and direct production taxes was $20.09 per BOE. Our depreciation, depletion, and amortization expense was $0 per BOE.

During the six months ended June 30, 2022, we produced and sold 96.83 Bbls net to our interest at an average sale price of $100.05 per Bbl. We produced and sold 1,267 Mcf of natural gas net to our interest at an average sales price of $6.09 per Mcf. Our average production cost including lease operating expenses and direct production taxes was $3.83 per BOE. Our depreciation, depletion, and amortization expense was $0 per BOE.

Hazel Project

During the year ended December 31, 2021, 23,422 barrels of oil net to our interest were sold at an average sale price of approximately $60.00 per Bbl, although we received none of this revenue because all of it, after deducting expenses to produce the oil, was either received by MHP directly during the time that the Option Agreement was in effect or credited towards the recoupment of drilling costs incurred by MHP. We produced and sold Nil Mcf of natural gas net to our interest.

	December 31, 2021 Reserves						December 31, 2021 Future Net Revenue (M$)
Category	Oil (Bbls)		Gas (Mcf)		Total (BOE)		Total		Present Value Discounted at 10%
Net Proved Producing		0		0		0	$	0	$	0
Net Proved Nonproducing		0		0		0	$	—	$	—
Total Net Proved		0		0		0	$	—	$	—
Standardized Measure of Future Net Cash Flows Related to Proved Oil and Gas Properties									$	—
Probable Undeveloped		0		0		0	$	—	$	—

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	December 31, 2020 Reserves						December 31, 2020 Future Net Revenue (M$)
Category	Oil (Bbls)		Gas (Mcf)		Total (BOE)		Total		Present Value Discounted at 10%
Net Proved Producing		0		0		0	$	—	$	—
Net Proved Nonproducing		0		0		0	$	—	$	—
Total Net Proved		0		0		0	$	—	$	—
Standardized Measure of Future Net Cash Flows Related to Proved Oil and Gas Properties									$	—
Probable Undeveloped							$	—	$	—

The net producing reserves from 2020 and 2021 were 0 BOE related to the Producing Hazel Wells due to the obligation to pass revenue through to MHP under the terms of the Option Agreement effective during both periods. There was no reserve value at December 31, 2020 and December 31, 2021, Standardized Measure is not presented.

During the six months ended June 30, 2022, 4,922 barrels of oil net to our interest were sold at an average sale price of approximately $99.99 per Bbl, although we received none of this revenue because all of it, after deducting expenses to produce the oil, was credited towards the recoupment of drilling costs incurred by MHP. We produced and sold Nil Mcf of gas net to our interest. During the six months ended June 30, 2021, Nil barrels of oil net to our interest were sold and we sold Nil Mcf of gas net to our interest.

Due to the inherent uncertainties and the limited nature of reservoir data, both proved and probable reserves are subject to change as additional information becomes available. The estimates of reserves, future cash flows, and present value are based on various assumptions, including those prescribed by the SEC, and are inherently imprecise.

Intent to Acquire Additional Interests

Following the Spin-Off, we intend to make offers and enter into agreements with one or more of the other current working interest owners in the Orogrande Project (each an “Orogrande Owner” and collectively, the “Orogrande Owners”). We anticipate offering the Orogrande Owners shares of Common Stock in exchange for their respective working interest in the Orogrande Project. We intend to offer the number of shares of Common Stock necessary such that each participating Orogrande Owner would own the percentage of Common Stock then outstanding in proportion to the percentage owned in the working interest of the Orogrande Project. For illustration purposes, if an Orogrande Owner owns ten percent (10%) of the working interest of the Orogrande Project, and such Orogrande Owner elects to participate and accept our offer of shares of Common Stock, then such Orogrande Owner will be offered ten percent (10%) of the aggregate amount of outstanding shares of Common Stock. Our decision to enter into these transactions will depend on us and each Orogrande Owner to negotiate and enter into definitive agreements related to such transaction and our Board receiving an industry-standard fairness opinion from an investment banking firm. One of the Orogrande Owners is Wolfbone Investments LLC, an entity controlled by Gregory McCabe, who will own, directly and indirectly through entities he owns or controls, over 11% of the Common Stock following the Spin-Off, which would increase if the proportionate exchange of working interest for shares of our Common Stock is consummated.

Industry and Business Environment

We are experiencing a time of fluctuating, but higher oil prices caused by higher demand, lower U.S. supply, turmoil on the world stage and OPEC’s policies on production. Unfortunately, this is the cyclical nature of the oil

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and natural gas industry. We experience highs and lows that seem to come in cycles. Fortunately, there exists plenty of demand for US onshore oil and natural gas. We believe advances in technology drive the US market and we feel this will drive the development costs down on our exploration and drilling programs while maintaining favorable economics.

Competition

The oil and natural gas industry is intensely competitive, and we will compete with numerous other companies engaged in the exploration and production of oil and natural gas. Some of these companies have substantially greater resources than we have. Not only do they explore for and produce oil and natural gas, but also many carry on midstream and refining operations and market petroleum and other products on a regional, national, or worldwide basis. The operations of other companies may be able to pay more for exploratory prospects and productive oil and natural gas properties. They may also have more resources to define, evaluate, bid for, and purchase a greater number of properties and prospects than our financial or human resources permit.

Our larger or integrated competitors may have the resources to be better able to absorb the burden of current and future federal, state, and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to locate reserves and acquire interests in properties in the future will be dependent upon our ability and resources to evaluate and select suitable properties and consummate transactions in this highly competitive environment. In addition, we may be at a disadvantage in producing oil and natural gas properties and bidding for exploratory prospects because we have fewer financial and human resources than other companies in our industry. Should a larger and better financed company decide to directly compete with us, and be successful in its efforts, our business could be adversely affected.

Marketing and Customers

The market for oil and natural gas that we will produce depends on factors beyond our control, including the extent of domestic production and imports of oil and natural gas, the proximity and capacity of natural gas pipelines and other transportation facilities, demand for oil and natural gas, the marketing of competitive fuels, and the effects of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial, and individual consumers.

Our oil production is expected to be sold at prices tied to the spot oil markets. Our natural gas production is expected to be sold under short-term contracts and priced based on first of the month index prices or on daily spot market prices. We will rely on our operating partners to market and sell our production.

Governmental Regulation and Environmental Matters

Our operations are subject to various rules, regulations, and limitations impacting the oil and natural gas exploration and production industry as a whole.

Regulation of Oil and Natural Gas Production

Our oil and natural gas exploration, production, and related operations, when developed, will be subject to extensive rules and regulations promulgated by federal, state, tribal, and local authorities and agencies. Certain states may also have statutes or regulations addressing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum rates of production from wells, and the regulation of spacing, plugging, and abandonment of such wells. We contract with Maverick Operating LLC who operates our oil and natural gas properties and is primarily responsible for compliance with applicable environmental regulatory with respect to the operating activities of our oil and natural gas properties. We cover all costs associated with the related insurance coverage for such environmental regulatory compliance. Failure to comply with any such rules and regulations can result in substantial penalties. The regulatory burden on the oil and natural gas industry will most likely increase our cost of doing business and may affect our

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profitability. Although we believe we are currently in substantial compliance with all applicable laws and regulations, because such rules and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws. Significant expenditures may be required to comply with governmental laws and regulations and may have a material adverse effect on our financial condition and results of operations.

Environmental Matters

Our operations and properties are and will be subject to extensive and changing federal, state, and local laws and regulations relating to environmental protection, including the generation, storage, handling, emission, transportation, and discharge of materials into the environment, and relating to safety and health. In the future, environmental legislation and regulation may trend toward stricter standards. These laws and regulations may, for example:

• require the acquisition of a permit or other authorization before construction or drilling commences and for certain other activities;

• limit or prohibit construction, drilling, and other activities on certain lands lying within wilderness and other protected areas;

• impose substantial liabilities for pollution resulting from operations; or

• restrict certain areas from fracking and other stimulation techniques.

The permits required for our operations may be subject to revocation, modification, and renewal by issuing authorities. Governmental authorities have the power to enforce their regulations, and violations are subject to fines or injunctions, or both. In the opinion of management, we are and will be in substantial compliance with current applicable environmental laws and regulations and have no material commitments for capital expenditures to comply with existing environmental requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have a significant impact on our company, as well as the oil and natural gas industry in general.

The Comprehensive Environmental, Response, Compensation, and Liability Act (“CERCLA”) and comparable state statutes impose strict, joint, and several liability on owners and operators of sites and on persons who disposed of or arranged for the disposal of “hazardous substances” found at such sites. It is not uncommon for the neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment. The Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the disposal of “solid waste” and “hazardous waste” and authorize the imposition of substantial fines and penalties for noncompliance. Although CERCLA currently excludes petroleum from its definition of “hazardous substance,” state laws affecting our operations may impose clean-up liability relating to petroleum and petroleum related products. In addition, although RCRA classifies certain oil field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous wastes thereby making such wastes subject to more stringent handling and disposal requirements.

The Endangered Species Act (“ESA”) seeks to ensure that activities do not jeopardize endangered or threatened animal, fish, and plant species, nor destroy or modify the critical habitat of such species. Under the ESA, exploration and production operations, as well as actions by federal agencies, may not significantly impair or jeopardize protected species or habitat. The ESA provides for criminal and civil penalties for violations. Other statutes that provide protection to animal and plant species and that may apply to our operations include, but are not necessarily limited to, the Fish and Wildlife Coordination Act, the Fishery Conservation and Management Act, the Migratory Bird Treaty Act and the National Historic Preservation Act. Although we believe that our operations are and will be in substantial compliance with such statutes, any change in these statutes or any reclassification of a species as endangered could subject us to significant expenses to modify our operations or could force us to discontinue certain operations altogether.

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Hydraulic fracturing is regulated by state and federal environmental and oil and gas regulatory authorities, including specifically the requirement to disclose certain information related to hydraulic fracturing operations. Operators must follow applicable legal requirements for groundwater protection and are subject to supervision by state and federal regulators (including the Bureau of Land Management on federal acreage). Furthermore, well construction practices require the installation of multiple layers of protective steel casing surrounded by cement that are specifically designed and installed to protect freshwater aquifers by preventing the migration of fracturing fluids into aquifers. Regulatory proposals in some states and local communities have been initiated to require or make more stringent the permitting and compliance requirements for hydraulic fracturing operations. Federal and state agencies have continued to assess the impacts of hydraulic fracturing, which could spur further action toward federal and/or state legislation and regulation of hydraulic fracturing activities. In addition, in light of concerns about seismic activity being triggered by the injection of produced waters into underground wells and hydraulic fracturing, certain regulators are also considering additional requirements related to seismic safety for hydraulic fracturing activities. Further restrictions on hydraulic fracturing could make it prohibitive to conduct our operations, and also reduce the amount of oil and natural gas that we or our operators are ultimately able to produce from our properties.

Climate Change

Significant studies and research have been devoted to climate change and global warming, and climate change has developed into a major political issue in the United States and globally. Certain research suggests that greenhouse gas emissions contribute to climate change and pose a threat to the environment. Recent scientific research and political debate has focused in part on carbon dioxide and methane incidental to oil and natural gas exploration and production. Many states and the federal government have enacted legislation directed at controlling greenhouse gas emissions, and future legislation and regulation could impose additional restrictions or requirements in connection with our drilling and production activities and favor use of alternative energy sources, which could affect operating costs and demand for oil products. As such, our business could be materially adversely affected by domestic and international legislation targeted at controlling climate change.

Legal Proceedings

On April 30, 2020, the Company’s wholly owned subsidiary, Hudspeth Oil Corporation (“Hudspeth”), filed suit against Datalog LWT, Inc. d/b/a Cordax Evaluation Technologies (“Cordax”). The suit, Hudspeth and Wolfbone Investments, LLC v. Datalog LWT, Inc. d/b/a Cordax Evaluation Technologies, was filed in the 189th Judicial District Court of Harris County, Texas. The suit seeks the recovery of approximately $1.4 million in costs incurred as a result of a tool failure during drilling activities on the University Founders A25 #2 well that is located in the Orogrande Field. Working interest owner Wolfbone Investments, LLC, a company owned by Meta’s former Chairman Gregory McCabe, is a co-plaintiff in that action. After the suit was filed, Cordax filed a mineral lien in the amount of $104,500 against the Orogrande Field and has sued the operator and counterclaimed against Hudspeth for breach of contract, seeking the same amount as the lien. Meta has added the manufacturer of one of the tool components that we contend was one of the causes of the tool failure. It was recently disclosed that Cordax is the subsidiary of a Canadian parent company, Cordax who has also been added to the case. Cordax’s current Chairman of the Board filed a special appearance after being served with a citation, alleging that he was a Canadian citizen with no meaningful ties to Texas. After discovery was conducted on this issue, a nonsuit without prejudice for this defendant was filed, dismissing him from the case. The remaining parties attended mediation on June 15, 2022, that was unsuccessful in resolving the case. The parties are now engaged in discovery and plan to take depositions of fact and expert witnesses, with counsel for the Company currently identifying and vetting potential expert witnesses. The case is set for trial in April 2023.

On March 18, 2021, Cordax filed a lawsuit in Hudspeth County, Texas seeking to foreclose its mineral lien against the Orogrande Field in the amount of $104,500.01 and recover related attorney’s fees. The foreclosure action, Datalog LWT Inc. d/b/a Cordax Evaluation Technologies v. Torchlight Energy Resources, Inc., was filed in the 205th Judicial District Court of Hudspeth County, Texas. We are contesting the lien in good faith and filed a Plea in Abatement on May 10, 2021, seeking a stay in the Hudspeth County lien foreclosure case pending final

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disposition of the related case currently pending in Harris County, Texas. We are required to indemnify Meta in connection with this matter pursuant to the terms of the Distribution Agreement.

On January 3, 2022, a putative securities class action lawsuit was filed in the U.S. District Court for the Eastern District of New York captioned Maltagliati v. Meta Materials Inc., et al., No. 1:21-cv-07203, against Meta, Meta’s former Chief Executive Officer, and Meta’s former Chief Financial Officer, Torchlight’s former Chairman of the Board of Directors, and Torchlight’s former Chief Executive Officer. On January 26, 2022, a similar putative securities class action lawsuit was filed in the U.S. District Court for the Eastern District of New York captioned McMillan v. Meta Materials Inc., et al., No. 1:22-cv-00463. The McMillan complaint names the same defendants and asserts the same claims on behalf of the same purported class as the Maltagliati complaint. The complaints, purportedly brought on behalf of all purchasers of our publicly traded securities from September 21, 2020 through and including December 14, 2021, assert claims under Sections 10(b) and 20(a) of the Exchange Act arising primarily from a short-seller report and statements related to our business combination with Torchlight. The complaints seek unspecified compensatory damages and reasonable costs and expenses, including attorneys’ fees. On April 11, 2022, the Court held a hearing on motions to consolidate the two actions and to appoint a lead plaintiff or lead plaintiffs, but has not yet ruled on the motions. In regards to any loss incurred by us in connection with this matter, we will be entitled to seek recovery from Meta pursuant to the indemnification provisions set forth under the Distribution Agreement.

On January 14, 2022, a shareholder derivative action was filed in the U.S. District Court for the Eastern District of New York captioned Hines v. Palikaras, et al., No. 1:22-cv-00248. The complaint names as defendants certain of Meta’s current officers and directors, certain former Torchlight officers and directors, and us (as nominal defendant). The complaint, purportedly brought on behalf of Meta, asserts claims under Section 14(a) of the Exchange Act, contribution claims under Sections 10(b) and 21D of the Exchange Act, and various state law claims such as breach of fiduciary duties and unjust enrichment. The complaint seeks, among other things, unspecified compensatory damages in favor of Meta, certain corporate governance related actions, and an award of costs and expenses to the derivative plaintiff, including attorneys’ fees. On March 9, 2022, the Court entered a stipulated order staying this action until there is a ruling on a motion to dismiss in the Securities Class Action. In regards to any loss incurred by us in connection with this matter, we will be entitled to seek recovery from Meta pursuant to the indemnification provisions set forth under the Distribution Agreement.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our audited and unaudited financial statements and related notes, respectively, beginning on page F-1 below of this Prospectus. Some of the information contained in this discussion and analysis constitutes forward-looking statements that involve risks and uncertainties. Actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to these differences include, but are not limited to, those discussed below and elsewhere in this Prospectus, particularly under the section titled “Cautionary Statement Concerning Forward-Looking Statements.”

Overview

Next Bridge Hydrocarbons, Inc. (formerly known as OilCo Holdings, Inc.) was incorporated in the State of

Nevada on August 31, 2021 and established a fiscal year end of December 31st.

In connection with the Arrangement, Torchlight (which subsequently changed its name to Meta Materials, Inc.) and Metamaterial, Inc. contemplated a sale of the O&G Assets or, alternatively, a complete legal and structural separation of the Company, holding the O&G Assets, from Meta following the Arrangement. Meta determined to pursue the structural separation and will distribute all of its equity interest in us, consisting of all of the outstanding shares of our Common Stock, to the Meta Series A Preferred Stockholders on a pro rata basis. Following the Spin-Off, Meta will not own any equity interest in us, and we will operate independently from Meta.

The Spin-Off is subject to the satisfaction, or the Meta board of directors’ waiver, of a number of conditions. In addition, subject to the terms of the Arrangement Agreement, Meta has the right not to complete the Spin-Off if, at any time, the Meta Board determines, in its sole and absolute discretion, that the Spin-Off is not in the best interests of Meta or its stockholders or is otherwise not advisable.

Our consolidated financial statements have been prepared on a stand-alone basis and are derived from the consolidated financial statements and accounting records of Meta. Our consolidated financial statements reflect our financial position, results of operations and cash flows as we were historically managed, in conformity with GAAP. Our financial statements include certain assets and liabilities that have historically been held at the Meta corporate level but are specifically identifiable or otherwise attributable to us.

All intercompany transactions between us and Meta have been included in our financial statements. The intercompany transactions are reflected in our consolidated statements of cash flow as a financing activity and in our consolidated balance sheets as “Notes Payable, Related Party.”

The historical costs and expenses reflected in our financial statements include an allocation for certain corporate shared service functions historically provided by Meta including executive oversight, accounting, treasury, tax, legal, human resources, occupancy, procurement, information technology and other shared services. These expenses have been allocated to us on the basis of direct usage when identifiable, with the remainder allocated on a pro rata basis based on sales, headcount, tangible assets or other measures considered to be a reasonable reflection of the historical utilization levels of these services.

Our management believes the assumptions underlying our financial statements, including the assumptions regarding the allocation of general corporate expenses from Meta are reasonable. Nevertheless, our financial statements may not include all of the actual expenses that would have been incurred had we operated as a stand- alone company during the periods presented and may not reflect what our actual results of operations, financial position and cash flows would have been if we had operated as a stand-alone company during the periods presented. Actual costs that would have been incurred if we had operated as a stand-alone company would depend on multiple factors, including organizational structure and strategic decisions made in various areas, including information technology and infrastructure. Following the Spin-Off, we will perform these functions using our own resources or purchased services.

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Income Taxes

Judgment is required in determining the provision for income taxes and related accruals, deferred tax assets and liabilities. In the ordinary course of business, tax issues may arise where the ultimate outcome is uncertain. Additionally, our tax returns are subject to audit by various tax authorities. Consequently, changes in our estimates for contingent tax liabilities may materially impact our results of operations or financial position.

RESULTS OF OPERATIONS

Historical Results for the Years Ended December 31, 2021 and 2020

For the year ended December 31, 2021, we had a net loss of $8,238,808 compared to a net loss of $5,749,006 for the year ended December 31, 2020. The difference is primarily due to an increased general and administrative expenses for the year ended December 31, 2021, offset by an impairment loss and a loss on sale of oil and gas property for the year ended December 31, 2020. At December 31, 2021, we had current assets of $2,229,762 and total assets of $47,918,232. As of December 31, 2021, we had current liabilities of $15,537,215. Stockholders’ equity was $32,359,080 at December 31, 2021.

Revenue and Gross Profit

	Year Ended December 31,
	2020			2021			Change			%
Product sales	$	6,906		$	15,904		$	8,998			130.3	%
Total Revenue		6,906			15,904			8,998			130.3	%
Cost of revenue		87,486			76,331			(11,155	)		(12.7	)%
Gross Profit (Loss)		(80,580	)		(60,427	)		(20,153	)		25.0	%
Gross Profit (Loss) percentage		(1,166.8	)%		(379.9	)%		223.97	%

Production Revenues and Cost of Revenue

For the year ended December 31, 2021, we had production revenue of $15,904 compared to $6,906 of production revenue for the year ended December 31, 2020. The change in revenue was primarily due to the increase in oil and natural gas production from 613 BOE for the 2020 period to 683 BOE for the 2021 period, from the Oklahoma Properties, an increase in the average price of oil from $34.48 in 2020 to $55.01 in 2021 and an increase in the average price of natural gas from $1.13 in 2020 to $3.13 in 2021, marginally offset by a decrease in production due to the sale of our Warwink Project in November 2020. Our cost of revenue, consisting of lease operating expenses and production taxes, was $76,331 for the year ended December 31, 2021 compared with $87,486 for the year ended December 31, 2020. Production and revenue are detailed as follows:

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Property	Quarter		Oil Production {BBLS}		Gas Production {MCF}		Oil Revenue			Gas Revenue			Total Revenue
Oklahoma		Q1 - 2021		28		711	$	1,166		$	1,305		$	2,471
Hazel (TX)		Q1 - 2021		0		0		—			—			—
Total Q1-2021				28		711	$	1,166		$	1,305		$	2,471
Oklahoma		Q2 - 2021		28		1,212	$	1,692		$	1,814		$	3,506
Hazel (TX)		Q2 - 2021		0		0		—			—		$	—
Total Q2-2021				28		1,212	$	1,692		$	1,814		$	3,506
Oklahoma		Q3 - 2021		29		441	$	1,818		$	1,146		$	2,964
Hazel (TX)		Q3 - 2021		0		0		—			—		$	—
Total Q3-2021				29		441	$	1,818		$	1,146		$	2,964
Oklahoma		Q4 - 2021		0		1,222	$	—		$	6,963		$	6,963
Hazel (TX)		Q4 - 2021		0		0	$	—		$	—		$	—
Total Q4-2021				0		1,222	$	—		$	6,963		$	6,963
Total 2021				85		3,586	$	4,676		$	11,228		$	15,904
Average Commodity Price							$	55.01		$	3.13
Oklahoma		Q1 - 2020		181		468	$	583		$	1,000		$	1,583
Hazel (TX)		Q1 - 2020		0		0	$	—		$	—		$	—
MECO (TX)		Q1 - 2020		1,863		1,559	$	81,530		$	1,507		$	83,037
Total Q1-2020				2,044		2,027	$	82,113		$	2,507		$	84,620
Oklahoma		Q2 - 2020		28		448	$	774		$	156		$	930
Hazel (TX)		Q2 - 2020		0		0	$	—		$	—		$	—
MECO (TX)		Q2 - 2020		1,389		747	$	44,223		$	324		$	44,547
Total Q2-2020				1,417		1,195	$	44,997		$	480		$	45,477
Oklahoma		Q3 - 2020		69		1,096	$	2,084		$	494		$	2,578
Hazel (TX)		Q3 - 2020		0		0	$	—		$	—		$	—
MECO (TX)		Q3 - 2020		1,480		680	$	57,774		$	1,370		$	59,144
Total Q3-2020				1,549		1,776	$	59,858		$	1,864		$	61,722
Oklahoma		Q4 - 2020		0		0	$	1,042		$	773		$	1,815
Hazel (TX)		Q4 - 2020		0		0	$	—		$	—		$	—
MECO (TX)		Q4 - 2020		435		0	$	9,837		$	5,519		$	15,356
MECO (Sold)		YTD ADJ		0		0	$	(10,092	)	$	(5,519	)	$	(15,611	)
Total Q4-2020				435		0	$	787		$	773		$	1,560
Sub Total 2020				5,445		4,998	$	187,755		$	5,624		$	193,379
Exclude MECO		Sold		-5,167		-2,986	$	(183,272	)	$	(3,201	)	$	(186,473	)
		11/20
Total 2020				278		2,012	$	4,483		$	2,423		$	6,906
Average Commodity Price							$	34.48		$	1.13

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Expenses for the Years Ended December 31, 2021 and 2022

We recorded depreciation, depletion and amortization expense of $4,642 for the year ended December 31, 2021 compared to $820,814 for the year ended December 31, 2020. Impairment expense recognized was $2,108,301 in 2020 with none for the year ended December 31, 2021.

Operating Expenses

	Year Ended December 31,
	2021		2020		Change		%
Operating Expenses
General & Administrative	$	8,050,443	$	2,557,975	$	5,472,468		214.7	%
Total operating expenses	$	8,050,443	$	2,557,975	$	2,557,975		214.7	%

General and Administrative Expenses

Our general and administrative expense for the year ended December 31, 2021 was $8,050,443 compared with $2,557,975 for the year ended December 31, 2020. Our general and administrative expenses consisted of consulting and compensation expense, substantially all of which were non-cash or deferred, accounting and administrative costs, professional consulting fees, and other general corporate expenses. The change in general and administrative expenses in 2021, compared to 2020, is primarily due to employee bonus compensation and expenses related to the Arrangement Agreement including consulting fees, filing fees, legal fees, director and officer liability insurance, and investor relations expenses.

Historical Results for the Three Months Ended June 30, 2022 and 2021

For the three months ended June 30, 2022, we had a net loss of $1,476,849 compared to a net loss of $4,126,667 for the three months ended June 30, 2021. The difference is primarily due to decreased general and administrative expenses for the three months ended June 30, 2022 offset with an increase in interest expense. At June 30, 2022, we had current assets of $1,224,145 and total assets of $48,404,381. As of June 30, 2022, we had current liabilities of $17,865,871. Stockholders’ equity was $30,516,573 at June 30, 2022.

	Three Months Ended June 30,
	2022			2021			Change			%
Product sales	$	17,404		$	3,502		$	13,902			397	%
Total Revenue		17,404			3,502			13,902			397	%
Cost of revenue		31,453			(71,192	)		102,645			144	%
Gross Profit (Loss)	$	(14,049	)	$	74,694		$	96,835			(118	)%
Gross Profit (Loss) percentage		(81	)%		2,133	%		631	%

For the three months ended June 30, 2022, we had production revenue of $17,404 compared to $3,502 of production revenue for the three months ended June 30, 2021. Our cost of revenue, consisting of lease operating expenses and production taxes, was $31,453 for the three months ended June 30, 2022 compared with $(71,192) for the three months ended June 30, 2021. The change in revenue was impacted by an increase in production

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from the Oklahoma Properties and commodity prices. The change in lease operating expenses is due to a vendor refund during the 2021 period. Production and revenue are detailed as follows:

Property	Quarter	Oil Production {BBLS}		Gas Production {MCF}		Oil Revenue		Gas Revenue		Total Revenue
Oklahoma	Q2 - 2022		97		1,267	$	9,688	$	7,716	$	17,404
Hazel (TX)	Q2 - 2022		0		0	$	—	$	—	$	—
Total Q2-2022			97		1,267	$	9,688	$	7,716	$	17,404
Average Commodity Price						$	99.88	$	6.09
Oklahoma	Q2 - 2021		28		1,212	$	1,692	$	1,814	$	3,506
Hazel (TX)	Q2 - 2021		0		0		—		—	$	—
Total Q2-2021			28		1,212	$	1,692	$	1,814	$	3,506
Average Commodity Price						$	60.43	$	1.50

Expenses for the three months ended June 30, 2022 and 2021

	Three Months Ended June 30,
	2022		2021		Change			%
Operating Expenses
General & Administrative	$	1,162,957	$	4,202,008	$	(3,039,051	)		(72.3	)%
Total operating expenses	$	1,162,957	$	4,202,008	$	(3,039,051	)		(72.3	)%

The change in general & administrative expenses during the three months ended June 30, 2022, compared to the same period in 2021 is related to reductions in directors fees, consulting services and investor relations expenses.

As described in “Our Properties—Intent to Acquired Additional Interests” one of the Orogrande Owners, an entity we intend to make an offer to acquire its working interest in the Orogrande Project, is Wolfbone Investments LLC, which is an affiliate of Gregory McCabe, who is also an affiliate of the Company.

Historical Results for the Six Months Ended June 30, 2022 and 2021

For the six months ended June 30, 2022, we had a net loss of $1,988,694 compared to a net loss of $5,236,601 for the six months ended June 30, 2021. The difference is primarily due to decreased general and administrative expenses for the six months ended June 30, 2022 offset with an increase in interest expense. At June 30, 2022, we had current assets of $1,224,145 and total assets of $48,404,381. As of June 30, 2022, we had current liabilities of $17,865,871. Stockholders’ equity was $30,516,573 at June 30, 2022.

	Six Months Ended June 30,
	2022			2021			Change			%
Product sales	$	17,404		$	5,973		$	11,431			191.4	%
Total Revenue		17,404			5,973			11,431			191.4	%
Cost of Revenue		42,074			38,735			3,339			8.6	%
Gross Profit (Loss)	$	(24,670	)	$	(32,762	)	$	8,092			24.7	%
Gross Profit (Loss) percentage		141.7	%		(548.5	)%		70.8	%

For the six months ended June 30, 2022, we had production revenue of $17,404 compared to $5,973 of production revenue for the six months ended June 30, 2021. Our cost of revenue, consisting of lease operating

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expenses and production taxes, was $42,074 for the six months ended June 30, 2022 compared with $38,735 for the six months ended June 30, 2021. The change in revenue was impacted by an increase in production from the Oklahoma Properties. Production and revenue are detailed as follows:

Property	Quarter		Oil Production {BBLS}		Gas Production {MCF}		Oil Revenue		Gas Revenue		Total Revenue
Oklahoma		Q1 - 2022		0		0	$	—	$	—	$	—
Hazel (TX)		Q1 - 2022		0		0	$	—	$	—	$	—
Total Q1-2022				0		0	$	—	$	—	$	—
Oklahoma		Q2 - 2022		97		1,267	$	9,688	$	7,716	$	17,404
Hazel (TX)		Q2 - 2022		0		0	$	—	$	—	$	—
Total Q2-2022				97		1,267	$	9,688	$	7,716	$	17,404
Six Months Ended June 2022				97		1,267	$	9,688	$	7,716	$	17,404
Average Commodity Price							$	99.88	$	6.09
Oklahoma		Q1 - 2021		28		711	$	1,166	$	1,305	$	2,471
Hazel (TX)		Q1 - 2021		0		0		—		—		—
Total Q1-2021				28		711	$	1,166	$	1,305	$	2,471
Oklahoma		Q2 - 2021		28		1,212	$	1,692	$	1,814	$	3,506
Hazel (TX)		Q2 - 2021		0		0		—		—	$	—
Total Q2-2021				28		1,212	$	1,692	$	1,814	$	3,506
Six Months Ended June 2021				56		1,923	$	2,858	$	3,119	$	5,977
Average Commodity Price							$	51.04	$	1.62

Expenses for the six months ended June 30, 2022 and 2021

	Six Months Ended June 30,
	2022		2021		Change			%
Operating Expenses
General & Administrative	$	1,988,694	$	5,236,601	$	(3,247,907	)		62.0	%
Total operating Expenses	$	1,988,694	$	5,236,601	$	(3,247,907	)		62.0	%

The change in general & administrative expenses during the six months ended June 30, 2022, compared to the same period in 2021 is related to reductions in directors fees, consulting services and investor relations expenses.

LIQUIDITY AND CAPITAL RESOURCES

Liquidity risk is the risk that we will not meet our financial obligations as they become due after use of currently available cash. We have a planning and budgeting process to monitor operating cash requirements, including amounts projected for capital expenditures, which are adjusted as input variables change. These variables include, but are not limited to, our ability to generate revenue from operations, general and administrative requirements and the availability of equity or debt capital. As these variables change, we may be required to issue equity or obtain debt financing.

At December 31, 2021, we had cash and cash equivalents of $1,989,419 compared to $130,504 as of December 31, 2020.

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Cash from operating activities for the for the year ended December 31, 2021, was $(7,050,541) compared to $(3,300,589) for the year ended December 31, 2020.

Cash used in operating activities for the year ended December 31, 2021 can be attributed principally to net loss from operations of $8,238,808 adjusted for $4,642 in depreciation, depletion and amortization expense, a decrease in accrued liabilities, and an increase in accounts payable.

Cash used in operating activities during 2020 can be attributed principally to net loss from operations of $5,749,006 adjusted for $820,814 in depreciation, depletion and amortization expense, and $2,108,301 in impairment expense.

Cash used in investing activities for the year ended December 31, 2021 and for year ended December 31, 2020 was $14,805,511 compared to $2,271,968. Cash used in investing activities consisted primarily of investments in oil and natural gas properties in 2021 offset by proceeds from the sale of property in 2020.

Cash from financing activities for the year ended December 31, 2021 and for year ended December 31, 2020 was $23,714,967 compared to $1,128,451 for the year ended December 31, 2020. Cash from financing activities consisted primarily of contributions from, and a note payable to, Meta.

At June 30, 2022, we had cash and cash equivalents of $998,260 compared to $1,989,419 as of December 31, 2021.

Cash flows from operating activities for the six months ended June 30, 2022 was $(4,656,992) compared to $(5,855,887) for the six months ended June 30, 2021, a decrease of $1,198,895. Cash flows from operating activities for the six months ended June 30, 2022 can be primarily attributed to net loss from operations and a decrease in accounts payable.

Cash flows from operating activities for the six months ended June 30, 2021 can be primarily attributed to net loss from operations of $5,193,214 and a decrease in accrued expenses.

Reference the Consolidated Statements of Cash Flows included in the financial statements for additional detail of the components that comprise the net use of cash in operations. We expect to continue to use cash flow in operating activities until such time as we achieve sufficient commercial oil and gas production to cover all of our operating costs.

Cash flows from investing activities for the six months ended June 30, 2022 was $(1,491,766) compared to $(1,713,604) for the six months ended June 30, 2021. Cash flows from investing activities principally consists of investment in oil and natural gas properties in Texas.

Cash flows from financing activities for the six months ended June 30, 2022 was $5,157,599 as compared to $11,398,151 for the six months ended June 30, 2021.

Cash flows from financing activities consists of intercompany loans from Meta for the six months ended June 30, 2022. For the six months ended June 30, 2021, cash flows from financing activities also consisted of intercompany loans from Meta. We expect to continue to have cash flow provided by financing activities as we seek new rounds of financing and continue to develop our oil and natural gas investments. We do not expect to pay cash dividends on our Common Stock in the foreseeable future.

On October 1, 2021, we issued a secured, revolving promissory note in an original principal amount of up to $15 million in favor of Meta (as amended to date, the “2021 Note”). The 2021 Note bears interest at 8% per annum, computed on the basis of a 360-day year, and matures March 31, 2023 (the “2021 Note Maturity Date”); provided, however, if we raise $30 million or more in capital through debt or equity or a combination thereof by

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the 2021 Note Maturity Date, the 2021 Note Maturity Date will be extended to September 30, 2023. If an event of default has occurred and is continuing, interest on the 2021 Note may accrue at the default rate of 12% per annum. The outstanding principal of the 2021 Note, together with all accrued interest thereon, becomes due on the 2021 Note Maturity Date. While the revolving commitment under the 2021 Note expires on 2021 Note Maturity Date, as of the date hereof, the full $15 million available under the 2021 Note has been fully drawn.

The 2021 Note is secured by a security interest in (a) pursuant to a Stock Pledge Agreement dated as of September 30, 2021 between Gregory McCabe (the “Pledgor”) and Meta (the “Stock Pledge Agreement”), 1,515,000 shares of common stock of Meta that are owned directly and beneficially by the Pledgor, and (b) pursuant to a Deed of Trust, Mortgage, Security Agreement, Fixture Filing, Financing Statement and Assignment of Production dated as of September 30, 2021 made by Wolfbone Investments, LLC (an affiliate of the Pledgor) for the benefit of Meta (the “Security Agreement”), a 25% working interest beneficially owned by the Pledgor in the Orogrande Prospect as defined in the Security Agreement.

The 2021 Note includes a restrictive covenant that, subject to certain exceptions and qualifications, restricts our ability to merge or consolidate with another person or entity, or sell or transfer all or substantially all of our assets, unless we are the surviving entity or the successor entity assumes all of obligations under the 2021 Note.

Upon the occurrence and during the continuance of an event of default under the 2021 Note, Meta as the lender may declare all outstanding principal and accrued and unpaid interest under the 2021 Note immediately due and payable, may terminate any remaining commitment to make advances under the 2021 Note, and may exercise the other rights and remedies provided for under the 2021 Note and related security documents. The events of default under the 2021 Note include among other things, subject to grace periods in certain instances, payment defaults, breaches of covenants, an event of default under the Stock Pledge Agreement or the Security Agreement, bankruptcy and insolvency events with respect us or our subsidiaries, cross defaults with certain of our other material indebtedness, and material judgments against us.

On June 28, 2022, we borrowed $1.9 million as an advance from Meta to be treated as an unsecured term loan, in addition to the $441,000 previously advanced, under a Loan Agreement with Meta as the lender (the “Loan Agreement”), the proceeds of which are available for our working capital and general corporate purposes. As of the date of this prospectus, we had an aggregate principal amount outstanding of $5.0 million, which is the maximum amount available under the Loan Agreement. The loans are due and payable on March 31, 2023 (the “Maturity Date”), unless extended as described below. Loans under the Loan Agreement bear interest at a fixed rate of 8% per annum if no event of default exists, and at a fixed rate of 12% per annum if an event of default exists. Under the Loan Agreement, if we raise $30 million or more in capital through debt or equity or a combination thereof by the Maturity Date, the Maturity Date will be extended to October 3, 2023 and the 2021 Note plus the loans under the Loan Agreement would be amortized in six equal monthly installments.

We have the right to prepay the loans under the Loan Agreement in whole or in part at any time without penalty. Amounts repaid or prepaid may not be reborrowed. We will be required to prepay the loans upon an asset disposition (other than permitted asset sales), certain equity issuances (other than permitted equity), debt issuances (other than permitted debt), and certain extraordinary receipts. We are required to prepay the loans from our annual excess cash flow, if any.

The Loan Agreement includes customary representations and covenants that, subject to certain exceptions and qualifications, restrict our ability to do certain things, such as: incur additional indebtedness; incur liens; engage in mergers, acquisitions, and asset sales; make loans and investments; declare dividends or redeem or repurchase equity interests; transact with affiliates on a non-arm’s length basis; and enter into certain restrictive agreements. In addition, the Loan Agreement contains customary affirmative covenants, including covenants regarding the payment of taxes and other obligations, maintenance of insurance, maintenance of our existence and material properties, customary visitation rights, reporting requirements, compliance with applicable laws and regulations, and formation or acquisition of new subsidiaries.

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Upon the occurrence and during the continuance of an event of default, Meta as the lender has the right to declare all outstanding principal and accrued and unpaid interest under the Loan Agreement immediately due and payable and exercise certain other rights and remedies. The events of default under the Loan Agreement include among other things, subject to grace periods in certain instances, payment defaults, breaches of covenants or representations and warranties, a change in control or a material adverse change defined in the Loan Agreement, material judgments and attachments, cross defaults with certain other material indebtedness, and bankruptcy and insolvency events with respect to the Company and our subsidiaries.

Contractual Obligations and Other Commitments

Our most significant contractual obligations relate to the Loan Agreement, the 2021 Note and drilling and development commitments and other lease operating expenses under certain leases for the Orogrande Project.

Our debt obligations include the $15 million principal balance outstanding under the 2021 Note with Meta, which incurs interest at 8% per annum and matures on March 31, 2023. For the six months ended June 30, 2022, we incurred an interest expense in respect of the 2021 Note of $587,222 that is paid in kind. On September 2, 2022, we entered into a Loan Agreement that governs the term loans advanced to us from Meta on April 14, 2022, May 4, 2022, May 12, 2022, May 26, 2022, June 1, 2022, June 13, 2022, June 28, 2022, August 11, 2022 and August 29, 2022, for an aggregate principal balance outstanding of $5 million, which is the maximum amount of Meta’s commitment under the Loan Agreement. The term loans incur interest at a per annum rate equal to 8% and mature on March 31, 2023. Under both the 2021 Note and the Loan Agreement, if we raise additional capital through debt or equity, or any combination thereof, of at least $30,000,000 before the respective maturity dates, we will be entitled to extend maturity to October 3, 2023 and repay the outstanding balances in six equal monthly installments beginning in April 2023 up to such extended maturity date. In addition, we may be obligated to pay Meta approximately $1 million for costs associated with the Spin-Off. See the discussion under the caption “Certain Relationships and Related Party Transactions—Agreements with Meta—Distribution Agreement—Settlement of Expenses.” As of the date of this Prospectus, we do not have any long-term debt obligations.

In addition to our debt commitments, the Orogrande Project leases representing approximately 134,066 net acres in the Orogrande Basin in West Texas are subject to expiration in 2022 if we fail to drill five wells as obligated by the end of the 2022 calendar year. Unless we are able to negotiate an extension on these leases, these leases in the Orogrande Basin are also subject to expiration in 2023 in the event we fail to drill an additional five wells during the 2023 calendar year. In order to fulfill our drilling commitments for 2022, we currently estimate that our capital expenditures needs may be up to $10 million, and to the extent Meta pays any of these capital expenditures on our behalf, our indebtedness to Meta will increase. As such, we will require additional capital, and may not be able to obtain such additional capital when or in the amount necessary to fulfill our commitments under, and maintain our interest in, the leases. We do not yet know what our capital expenditure needs will be to satisfy our drilling commitments for the calendar year 2023. For a discussion of the risks relating to our drilling obligations, see “Risk Factors—Risks Related to Our Business”, including the risk factor “—Our acreage must be drilled before lease expiration in order to hold the acreage by production. In the highly competitive market for acreage, failure to drill sufficient wells in order to hold acreage will result in a substantial lease renewal cost, or if renewal is not feasible, loss of our lease and prospective drilling opportunities”. See also Note 4 of the notes to our financial statements as of and for the years ended December 31, 2020 and 2021 included elsewhere in this Prospectus.

Management believes that currently available resources may not provide sufficient funds to enable us to meet our financing and drilling obligations for the remainder of the 2022 fiscal year and for the 2023 fiscal year. We anticipate that we will continue to incur operating losses and generate negative cash flows from operations for the foreseeable future. As a result, we will need additional capital resources to fund our operations both in the short term and in the long term, prior to achieving break even or positive operating cash flow. While we do not have any committed sources of capital, we expect to continue to opportunistically seek access to additional funds through public or private equity offerings or debt financings, through partnering or other strategic arrangements,

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including credit application arrangements with our third party servicers, or a combination of the foregoing. We may also seek additional credit support from Meta. Despite our efforts, we may face obstacles in continuing to attract new financing due to industry conditions and our history and current record of net losses. We can provide no assurance that we will be able to obtain the financing required to meet our stated objectives or even to continue as a going concern.

Critical Accounting Estimates

Oil and natural gas properties—The Company uses the full cost method of accounting for exploration and development activities as defined by the SEC. Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves.

Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Oil and natural gas property costs excluded represent investments in unevaluated properties and include non-producing leasehold, geological, and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. The Company allocates a portion of its acquisition costs to unevaluated properties based on relative value. Costs are transferred to the full cost pool as the properties are evaluated over the life of the reservoir. Unevaluated properties are reviewed for impairment at least annually and are determined through an evaluation considering, among other factors, seismic data, requirements to relinquish acreage, drilling results, remaining time in the commitment period, remaining capital plan, and political, economic, and market conditions.

Gains and losses on the sale of oil and natural gas properties are not generally reflected in income unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves. Sales of less than 100% of the Company’s interest in the oil and gas property are treated as a reduction of the capital cost of the field, with no gain or loss recognized, as long as doing so does not significantly affect the unit-of-production depletion rate. Costs of retired equipment, net of salvage value, are usually charged to accumulated depreciation.

Depreciation, depletion, and amortization—The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of accumulated depreciation, depletion, and amortization (“DD&A”), estimated future development costs and asset retirement costs not included in oil and natural gas properties, less costs excluded from amortization. The depreciable base of oil and natural gas properties is amortized on a unit-of-production method.

Ceiling test—Future production volumes from oil and gas properties are a significant factor in determining the full cost ceiling limitation of capitalized costs. Under the full cost method of accounting, the Company is required to periodically perform a “ceiling test” that determines a limit on the book value of oil and gas properties. If the net capitalized cost of proved oil and gas properties, net of related deferred income taxes, plus the cost of unproved oil and gas properties, exceeds the present value of estimated future net cash flows discounted at 10 percent, net of related tax affects, plus the cost of unproved oil and gas properties, the excess is charged to expense and reflected as additional accumulated DD&A. The ceiling test calculation uses a commodity price assumption which is based on the unweighted arithmetic average of the price on the first day of each month for each month within the prior 12-month period and excludes future cash outflows related to estimated abandonment costs.

The determination of oil and gas reserves is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of

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variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Subsequent re-evaluation of reserves and cost estimates related to future development of proved oil and gas reserves could result in significant revisions to proved reserves. Other issues, such as changes in regulatory requirements, technological advances, and other factors which are difficult to predict could also affect estimates of proved reserves in the future.

Asset retirement obligations—The fair value of a liability for an asset’s retirement obligation (“ARO”) is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, with the corresponding charge capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then-present value each subsequent period, and the capitalized cost is depleted over the useful life of the related asset. Abandonment costs incurred are recorded as a reduction of the ARO liability.

Inherent in the fair value calculation of an ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and gas property balance. Settlements greater than or less than amounts accrued as ARO are recorded as a gain or loss upon settlement.

Recent Accounting Pronouncements

Our audited financial statements and the accompanying notes thereto found elsewhere in this Prospectus contain a description of recent accounting pronouncements.

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MANAGEMENT

Executive Officers and Non-Employee Directors Following the Spin-Off

The following sets forth information regarding individuals who are currently expected to serve as executive officers and non-employee directors immediately after the Spin-Off, including their positions.

Name	Age		Position
Executive Officers
Clifton DuBose, Jr.		40	Chief Executive Officer, Chairman of the Board of Directors
Joseph DeWoody		40	President, Director
Lucas T. Hawkins		36	Chief Financial Officer
Delvina Oelkers		36	Chief Operating Officer
Key Employees
Kyle Bradford		42	Executive Vice President, Drilling & Construction
Daren Rader		38	Executive Vice President, Completions & Production
Non-Employee Directors
Robert Lance Cook		65	Director
Mia Pitts		38	Director
Kristin Whitley		38	Director

Executive Officers

Clifton DuBose, Jr. has successfully acquired, managed, and/or sold thousands of royalty acres and non-operated working interests in the Permian Basin. Since April 2018, Mr. DuBose has served as co-founder and member of Valor Mineral Management LLC (“Valor”). Valor is a mineral and working interest management firm which uses a proprietary software platform it has developed, known as “mineral.tech.” Since August 2016 Mr. DuBose has also served as President of Imperial Royalty Management I, LLC, which is the general partner of a company that owns certain mineral interests, and since August 2016 as the managing member of Korban Resources LLC, a company which invests in oil and gas interests. Mr. DuBose is also an attorney, licensed to practice law in the State of Texas. He earned his law degree from Georgetown Law, in Washington D.C.in 2009 and a BS in Agribusiness from Abilene Christian University in 2004.

Joseph DeWoody has served as the founder and partner of several successful minerals-rights companies, including Clear Fork Royalty, since April 2010, and Valor since May 2018. Mr. DeWoody implemented strategic initiatives at Valor, managing 80,000 oil and gas interests in over 2,000,000 gross acres across 32 States, with strong revenue growth since inception developing full P&L, strategy, and business operations. He also developed Valor’s proprietary mineral and working interest management software, known as “mineral.tech.” Mr. DeWoody has also structured and participated in multiple complex transactions in both operated and non-operated assets. He has managed reporting to partners, including quarterly compilations, annual audit, and contractual calculations and payments. Mr. DeWoody was the 2021 D CEO Energy Services and Technology Executive of the Year and is a life member of American Mensa. He received his BBA and MBA from Baylor University, where he played football. He was appointed to the Texas Board of Professional Geoscientists, and he serves as director of the National Association of Royalty Owners—Texas. He was named one of Oil and Gas Investor Magazine’s “Top 20 Under 40” and was featured in the Dallas Business Journal’s “Who’s Who in Energy.”

Lucas T. Hawkins is the Co-Founder and has served as Chief Financial Officer of Mammoth Exploration LLC, a private equity backed upstream oil and gas company, since June 2016. Since July 2013, Mr. Hawkins has served as VP—Business Development of Hawkins Exploration, Inc. (“HEI”). HEI is an independently owned oil and gas exploration company focused on the Permian Basin. Mr. Hawkins led, managed and executed numerous acquisitions and subsequent development of oil and gas properties across the Permian Basin. From 2010 to 2011, Mr. Hawkins served as an Associate with The Sterling Group, a middle market private equity group focusing on

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industrial, manufacturing and distribution businesses. From 2011 to 2013 Mr. Hawkins served as an Associate with Natural Gas Partners, an energy private equity firm. Mr. Hawkins has a background in energy investment banking and private equity and earned his BBA in Finance and Business Honors from the University of Texas at Austin.

Delvina Oelkers served as Asset Manager from March 2016 to March 2019 at Eclipse Resources and as Completions Manager from March 2019 to November 2020 at Montage Resources, in each position where she managed engineering teams, achieving cost and efficiency improvements while implementing innovative technology for substantial reserve recovery. She led her operations team through several successful M&A transactions. Ms. Oelkers designed completions for the Eclipse and Montage Resources Super Lateral Program, including the design and execution of the first world-record-setting “Purple Hayes 1H” Well. As an Asset Manager at Eclipse Resources, Ms. Delvina was responsible for leading the multidisciplinary team to prove-up the asset. By utilizing innovative technologies in design, the first exploratory well produced 35% higher than type curve.

Key Employees

Kyle Bradford has served as general manager of our subsidiary, Hudspeth Operating LLC, since September 2021. Prior to joining the Company, Mr. Bradford in the roles of Director, from February 2019 to November 2020 and VP of Drilling and Completions January 2014 to February 2019 for Eclipse Resources and Montage Resources. He led the drilling and operational teams through the development of the super-lateral program highlighted by the drilling and completion of the world record setting “Purple Hayes 1H”. He has a proven track record of implementing technological advancements to reduce costs and increasing operational efficiencies. He previously worked at Chesapeake Energy holding various positions including Senior Operations Engineer Utica Business Unit from April 2012 to January 2014, and Asset Manager of the Appalachian North Business Unit from October 2010 to April 2012. His career started in May 2002 at CNX Gas. He holds a Bachelor of Science in Petroleum Engineering from Marietta College.

Daren Rader has 16 years of experience across the MidCon and Appalachian Basins as an engineer and operations leader. From March 2016 to November 2020, Mr. Rader served as a Senior Operations Manager for Montage Resources, and from February 2017 to February 2019, served as an Operations Manager for Blue Ridge Mountain Resources. He was instrumental in creating synergy amongst the field teams through multiple mergers and acquisition transactions. Mr. Rader is highly experienced both in prolific unconventional condensate and natural gas production and completion operations. Mr. Rader has a proven track record as a team leader with a focus on optimizing and streamlining field operations to reduce cost and minimize cycle times. Mr. Rader has been with the Company since September 2021.

Non-Employee Directors

Robert Lance Cook spent 36 years at Shell Oil with final positions of Vice President of Wells Technology and Chief Scientist. Mr. Cook has extensive experience in Deepwater, Arctic, and Unconventional Research & Development and Operations. Mr. Cook is the founder and CEO of Enventure Global Technology, a joint venture between Shell and Halliburton. Mr. Cook has served as the COO of Sirius Well Manufacturing, a joint venture between Shell and CNPC and is a technologist with an extensive patent portfolio. Since retiring from Shell in 2016, Mr. Cook has served as Vice President of Production Operations for WellsX Inc. from 2017 to 2020 and in 2020, he founded and continues to serves as president and chief technology officer of Sage Geosystems Inc.

Mia Pitts is currently serving as Senior Counsel at Marsh McLennan Companies (February 2018-current) and previously was a litigator and regulatory compliance lawyer at Freshfields Bruckhaus Deringer (March 2010-March 2016), one of the world’s largest and oldest law firms. Ms. Pitts has represented corporate and individual clients in internal, regulatory, civil, and criminal investigations before the U.S. Security and Exchange Commission, Department of Justice, and state attorney generals as well as in shareholder securities litigation, class action litigations, and other private civil allegations and suits. She has also represented independent

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corporate oversight authorities appointed by the federal government, including the DOJ-appointed monitor of a global financial institution and the federal court-appointed receiver of a multi-national firm in an SEC securities fraud matter. Ms. Pitts graduated from Georgetown University Law Center and Barnard College of Columbia University.

Kristin Whitley, CPA, began her career in June 2006 as a public accounting with Whitley Penn where she worked for 10 years. While at Whitley Penn she served a variety of clients within the energy and mining industries. In August 2016, Mrs. Whitley joined Vista Minerals, a leading in-basin regional provider of sand to industrial, oil and gas companies, in the role of Chief Accounting Officer and less than a year later was named Chief Financial Officer. While at Vista Minerals, Mrs. Whitley has managed the finance and accounting, human resources, and information technology functions, participating in numerous capital raises, strategic initiatives, contract negotiations, and risk management exercises. Mrs. Whitley is a Certified Public Accountant in the State of Texas. She graduated from The University of Texas at Austin with her BBA and from Texas Christian University’s Neeley School of Business with her MBA. In 2019, Mrs. Whitley was named one of Oil and Gas Investor’s Forty Under 40 in Energy.

Conflicts of Interest

Nevada law permits corporations to adopt provisions renouncing any interest or expectancy in certain opportunities that are presented to the corporation or its directors, officers or stockholders. Our Amended and Restated Articles of Incorporation, to the maximum extent permitted from time to time by Nevada law, renounce any interest or expectancy that we have in, or right to be offered an opportunity to participate in, specified business opportunities that are from time to time presented to our directors, officers or stockholders or their respective affiliates. Our Amended and Restated Articles of Incorporation provide that, to the fullest extent permitted by law neither any director or officer nor his or her affiliates will have any duty to refrain from (i) engaging in a corporate opportunity in the same or similar lines of business in which we or our affiliates now engage or propose to engage or (ii) otherwise competing with us or our affiliates. In addition, to the fullest extent permitted by law, in the event that any director or officer acquires knowledge of a potential transaction or other business opportunity which may be a corporate opportunity for such director or officer or such person’s affiliates or for us or our affiliates, such person will have no duty to communicate or offer such transaction or business opportunity to us or any of our affiliates and they may take any such opportunity for themselves or offer it to another person or entity. We do not believe, however, that any fiduciary duties or contractual obligations of our directors or officers arising in the future would materially undermine our ability to operate our business. Our Amended and Restated Articles of Incorporation do not renounce our interest in any business opportunity that is expressly offered to a director or officer solely in his or her capacity as a director or officer of the Company. To the fullest extent permitted by law, no business opportunity will be deemed to be a potential corporate opportunity for us unless we would be permitted to undertake the opportunity under our Amended and Restated Articles of Incorporation, we have sufficient financial resources to undertake the opportunity and the opportunity would be in line with our business.

Director Independence

It is anticipated that after the Distribution a majority of the members of our Board will meet the criteria for independence as defined by the corporate governance guidelines to be adopted by our Board.

Corporate Governance Guidelines

The Board has adopted written corporate governance guidelines that serve as a flexible framework within which our Board and its committees operate. The guidelines will be available on our website at www.nextbridgehydrocarbons.com, and are available upon written request to our corporate secretary.

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Code of Business Conduct and Ethics

The Board has adopted a written code of ethics that is designed to deter wrongdoing and to promote, among other things:

• honest and ethical conduct, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships;

• the protection of the confidentiality of our non-public information;

• the responsible use of and control over our assets and resources;

• full, fair, accurate, timely and understandable disclosure in reports and documents that we file with the SEC and other regulators and in our other public communications;

• compliance with applicable laws, rules and regulations; and

• accountability for adherence to the code and prompt internal reporting of any possible violation of the code.

The code of conduct and ethics will be available on our website at www.nextbridgehydrocarbons.com, and is available upon written request to our corporate secretary.

While the Board oversees risk management, company management is charged with managing risk. Management communicates routinely with the Board and individual directors on the significant risks identified and how they are being managed. Directors are free to, and indeed often do, communicate directly with senior management.

Our Board administers its risk oversight function as a whole by making risk oversight a matter of collective consideration. Much of this work has been delegated to committees, which will meet regularly and report back to the full Board.

Committees of Our Board

We have established an audit committee, a compensation committee, a nominating and governance committee and an ESG committee, each of which operate under a written charter that will be available on our website.

In addition, our Board may, from time to time, designate one or more additional committees, which shall have the duties and powers granted to it by our Board.

Audit Committee

Upon their appointment to the Board, the members of the Audit Committee will consist of Kristin Whitley, as the chairperson, Mia Pitts and Robert L. Cook, each of whom meet the independence requirements set forth in Rule 10A-3 under the Exchange Act and our Audit Committee Charter. Each member of the Audit Committee is financially literate, and Ms. Whitley has accounting and related financial management expertise and satisfies the criteria to be an “audit committee financial expert” under the rules and regulations of the SEC, as those qualifications are interpreted by our Board in its business judgment.

The functions of the Audit Committee include:

• oversee the quality and integrity of our financial statements, accounting practices and financial information we provide to the SEC or the public;

• review our annual and interim financial statements, the report of our independent registered public accounting firm on our annual financial statements, Management’s Report on Internal Control over Financial Reporting and the disclosures under Management’s Discussion and Analysis of Financial Condition and Results of Operations;

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• select and appoint an independent registered public accounting firm;

• pre-approve all services to be provided to us by our independent registered public accounting firm;

• review related party transactions;

• review with our independent registered public accounting firm and our management the accounting firm’s significant findings and recommendations upon the completion of the annual financial audit and quarterly reviews;

• review and evaluate the qualification, performance, fees and independence of our registered public accounting firm;

• meet with our independent registered public accounting firm and our management regarding our internal controls, critical accounting policies and practices and other matters;

• discuss with our independent registered public accounting firm and our management earnings releases prior to their issuance;

• oversee our internal audit function; and

• oversee our compliance program, response to regulatory actions involving financial, accounting and internal control matters, internal controls and risk management policies.

Compensation Committee

Upon their appointment to the Board, the members of the Compensation Committee will consist of Mia Pitts, as the chairperson, Kristin Whitley and Robert L. Cook, each of whom are independent, “non-employee directors” (within the meaning of Rule 16b-3 under the Exchange Act).

The functions of our Compensation Committee include:

• setting and reviewing our general policy regarding executive compensation;

• determining the compensation of our Chief Executive Officer and other executive officers;

• approving employment agreements for our Chief Executive Officer and other executive officers;

• reviewing the benefits provided to our Chief Executive Officer and other executive officers;

• overseeing our overall compensation structure, practices and benefits plans;

• administering our executive bonus and equity-based incentive plans; and

• assessing the independence of compensation consultants, legal counsel and other advisors to the Compensation Committee and hiring, approving the fees and overseeing the work of, and terminating the services of such advisors.

Corporate Governance and Nominating Committee

Upon their appointment to the Board, the members of the Corporate Governance and Nominating Committee will consist of Robert L. Cook, as the chairperson, Kristin Whitley and Mia Pitts, each of whom are independent, “non-employee directors” (within the meaning of Rule 16b-3 under the Exchange Act).

The functions of our Corporate Governance and Nominating Committee include:

• overseeing our corporate governance practices;

• reviewing and recommending to our Board amendments to our committee charters and other corporate governance guidelines;

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• reviewing and making recommendations to our Board regarding the structure of our various board committees;

• identifying, reviewing and recommending to our Board individuals for election to the Board;

• adopting and reviewing policies regarding the consideration of board candidates proposed by stockholders and other criteria for Board membership; and

• overseeing our Board’s annual self-evaluation.

ESG Committee

Upon their appointment to the Board, the members of the ESG Committee will consist of Joseph DeWoody, as the chairperson, Kristin Whitley and Robert L. Cook.

The functions of our ESG Committee include:

• provide oversight with respect to ESG matters;

• advise and assist the Board with its responsibilities for the oversight of ESG matters; and

• provide oversight with respect to our annual sustainability report, which we plan to make available through our website.

Board Leadership Structure and Role in Risk Oversight

Governance Structure

The position of Board chairman is filled by our Chief Executive Officer (the “CEO”). We believe this combined leadership structure is appropriate for us because our Chairman and CEO (i) conveys a singular, cohesive message to our stockholders, employees, industry partners and the investment community, (ii) eliminates any ambiguity as to who is accountable for our performance and (iii) is able to draw on his knowledge of our operations to provide the Board with leadership and properly focus discussions on the issues of greatest importance to the Company and our stockholders. Our directors and management team engage frequently and directly in the flow of information and ideas and we believe our combined leadership structure facilitates the quality, quantity and timeliness of the information flow and communication.

Since our Board chairman is also a member of management, our Board has designated Robert L. Cook, a non-management director, as “Lead Director.” The responsibilities of the Lead Director include:

• Coordinating the scheduling of board meetings and preparation of agenda material for board meetings and executive sessions;

• Defining the scope, quality, quantity and timeliness of the flow of information between management and the Board;

• Chairing all meetings of non-management directors and of the executive committee;

• Overseeing the process of hiring, firing, evaluating and compensating the CEO;

• Approving the retention of consultants who report directly to the Board;

• Facilitating communication between the directors and the CEO, and communicating the directors’ perspectives and consensus view to the CEO; provided, that the Lead Director may not, in his sole discretion, override the CEO on any matters without majority approval of the Board;

• Assisting the Board and officers in assuring compliance with and implementation of our governance principles;

• Leading the annual evaluation of the chairman;

• Serving as an independent point of contact for stockholders wishing to communicate with the Board;

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• Acting as principal liaison between the independent directors and the CEO on sensitive issues; and

• Leading the Board in anticipating and responding to crises.

The Board’s Role in Risk Oversight

The Board oversees that the assets of the Company are properly safeguarded, that the appropriate financial and other controls are maintained, and that our business is conducted wisely and in compliance with applicable laws and regulations and proper governance. Included in these responsibilities is the Board’s oversight of the various risks facing our company. In this regard, our board seeks to understand and oversee critical business risks. The Board does not view risk in isolation. Risks are considered in virtually every business decision and as part of our business strategy. The Board recognizes that it is neither possible nor prudent to eliminate all risk. Indeed, purposeful and appropriate risk-taking is essential for the Company to be competitive on a global basis and to achieve its objectives.

Related Party Transactions

The Board has adopted a written policy regarding the approval of related party transactions. At regularly scheduled audit committee meetings, management will recommend any related party transactions that are contemplated, and such transactions will require the audit committee’s approval. Generally, a “related party” is each of our executive officers, directors, nominees for director, any stockholder owning greater than five percent of our outstanding shares, including any immediate family member of each of the foregoing, and any entity owned or controlled by any of the foregoing. Transactions that are available to all of our employees generally or totaling less than $5,000 when aggregated with all similar transactions are excluded from the policy.

Legal Proceedings

None of our current and future directors and executive officers has been involved in legal proceedings that would be material to an evaluation of our management team.

Director Compensation

We are currently in the process of developing the details regarding the compensation packages of only those directors who are considered independent directors. Following the Spin-Off, we expect to grant each of our directors who are not employed by us or any of our subsidiaries (“non-employee directors”) an option to purchase approximately 412,500 shares of our Common Stock. The vesting of these options will be subject to achievement of certain performance-based conditions on substantially the same terms as the options expected to be granted to our named executive officers described below under “Performance-Based Options.”

We did not pay any compensation or grant any equity or other incentive awards to any of non-employee directors during the fiscal year ended December 31, 2021, nor did any of our non-employee directors receive any such compensation or awards from Meta or any of our other affiliates for their services during such fiscal year.

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EXECUTIVE COMPENSATION

We are currently in the process of determining the philosophy and design of our compensation plans and programs to be offered to our senior management team, which we expect will incorporate elements of compensation to attract, retain and motivate highly talented individuals of our management team, align the interests of management with the interests of our stockholders and incentivize behaviors that we believe are necessary to enable us to succeed in our mission while upholding our values in a highly competitive marketplace. All decisions with respect to management compensation are made by the Board (and after the Spin-Off, will be made by the Compensation Committee).

Incentive Compensation Awards

Our executive officers have not historically been paid bonuses or received equity awards, and our Board and Compensation Committee has not yet established a formal compensation policy for the determination of such awards. If our revenue grows and bonuses become affordable and justifiable, we expect to use the following parameters in justifying and quantifying bonuses for our executive officers: (1) the growth in our revenue, (2) the growth in our earnings before interest, taxes, depreciation and amortization, as adjusted (“EBITDA”), and (3) the value of our Common Stock. The Board and Compensation Committee has not adopted specific performance goals and target bonus amounts for any of its fiscal years, but may do so in the future. Subject to approval by the sole stockholder, we also expect that our executive officers will be granted performance-based stock options under our 2022 Plan (described below) in connection with or immediately following the Spin-Off and may be granted additional equity awards in future years under the 2022 Plan or a successor plan. The Compensation Committee will recommend to the Board the size, type and other terms of such equity awards.

Employment Agreements

In connection with the Spin-Off, we entered into new employment agreements with certain of our named executive officers identified in the Summary Compensation Table below to be effective immediately following the Spin-Off. These agreements do not have a specified term and provide for the executive to receive an annual base salary as follows: Mr. DuBose – $400,000; Mr. DeWoody - $395,000; Mr. Hawkins - $390,000 and Ms. Oelkers - $385,000. Each executive is also eligible for an annual discretionary bonus as determined by the Compensation Committee, with a target bonus equal to 50% of the executive’s base salary, and to participate in our benefit plans to be made available to employees generally. If the executive’s employment with the Company is terminated by the Company without “cause” or by the executive for “good reason” (as defined in the agreement), the executive will receive severance of 12 months base salary, payable in installments over a 12-month period, a pro-rated amount of the executive’s target bonus for the year of termination, payment of the executive’s COBRA premiums for 12 months, and 12 months’ accelerated vesting of the executive’s then-outstanding and unvested equity awards granted by the Company (except that, in the case of Mr. DuBose the cash severance and pro-rated target bonus will be payable only if such termination occurs following the initial 12 months after the Spin-Off). However, if such a termination of the executive’s employment occurs in connection with or within 12 months following a change in control of the Company, the executive’s cash severance will equal 18 months of base salary (paid in a lump sum together with the pro-rated target bonus), the executive will be entitled to payment of COBRA premiums for 18 months, and the executive’s then-outstanding equity awards granted by the Company will be fully vested. In each case, the executive’s right to receive these severance benefits is subject to the executive’s providing a release of claims to the Company and continued compliance with confidentiality, non-competition, non-solicitation and other covenants in favor of the Company set forth in the employment agreement. Mr. DuBose, Mr. DeWoody and Ms. Oelkers were each party to an employment agreement with Hudspeth Operating, LLC, one of our subsidiaries (as reflected in the Summary Compensation Table below). The agreements between Hudspeth Operating, LLC and Mr. DuBose, Mr. DeWoody and Ms. Oelkers have been superseded by their new employment agreements with us.

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Performance-Based Options

In connection with the Spin-Off, we expect to grant each of the following executive officers a performance-based stock option under the 2022 Plan described below with respect to the following number of shares: for Mr. DuBose, an amount equal to three percent (3%) of outstanding shares; and for Mr. DeWoody, Mr. Hawkins and Ms. Oelkers, an amount equal to one percent (1%) of outstanding shares (the “Option Percentage”). The exercise price of each of these options will be established at grant based on an implied fair market value of $199,500,000 for the Company’s working interest in the Orogrande Project (which is significantly higher than the estimated fair market value of the Company’s interest as of the date of the Spin-Off and is intended to create an additional incentive for the executives to increase the value of the Company’s working interest above that threshold amount). If the Company increases its working interest in the Orogrande Project while the option is outstanding and subject to compliance with applicable tax laws, the option agreement will provide that the exercise price will increase proportionally based on an implied fair market value of $300,000,000 if the Company’s working interest were to increase to 100%. If the executive’s interest represented by the option is diluted by an increase in the Company’s working interest, the executive may be entitled to an additional option grant to restore their Option Percentage. The vesting of the option will generally be contingent on the optionee’s continued employment or service for at least one year following the Spin-Off (or such longer period as provided in the option agreement). Each of these options will have a maximum term of 10 years and will be granted under, and subject to the terms of, the 2022 Plan described below.

Equity Incentive Plan

Our Board adopted the 2022 Equity Incentive Plan (the “2022 Plan”) to provide an additional means through the grant of awards to attract, motivate, retain and reward selected employees and other eligible persons. Meta, as the current sole stockholder, approved the 2022 Plan prior to the Spin-Off. The summary of the 2022 Plan below is qualified in its entirety by the full text of the plan document, which is being filed with the SEC as an exhibit to this amendment to the Registration Statement on Form S-1, of which this prospectus is a part and is available through the SEC’s internet site at http://www.sec.gov.

Employees, officers, directors and consultants that provide services to us or one of our subsidiaries may be selected to receive awards under the 2022 Plan. Our Compensation Committee will administer the 2022 Plan. The Compensation Committee has broad authority to:

• select participants and determine the types of awards that they are to receive;

• determine the number of shares that are to be subject to awards and the terms and conditions of awards, including the price (if any) to be paid for the shares or the award and establish the vesting conditions (if applicable) of such shares or awards;

• cancel, modify or waive our rights with respect to, or modify, discontinue, suspend or terminate any or all outstanding awards, subject to any required consents;

• construe and interpret the terms of the 2022 Plan and any agreements relating to the plan;

• accelerate or extend the vesting or exercisability or extend the term of any or all outstanding awards subject to any required consent;

• subject to the other provisions of the 2022 Plan, make certain adjustments to an outstanding award and authorize the termination, conversion, substitution or succession of an award; and

• allow the purchase price of an award or shares of our Common Stock to be paid in the form of cash, check or electronic funds transfer, by the delivery of previously-owned shares of our Common Stock or by a reduction of the number of shares deliverable pursuant to the award, by services rendered by the recipient of the award, by notice and third party payment or cashless exercise on such terms as the administrator may authorize or any other form permitted by law.

The number of shares of our Common Stock initially reserved for issuance with respect to awards granted under the 2022 Plan is 50,000,000. The share limit will automatically increase on the first trading day in January of

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each year (commencing with January 2023). Any shares subject to awards that are not paid, delivered or exercised before they expire or are canceled or terminated, fail to vest, as well as shares used to pay the purchase or exercise price of awards or related tax withholding obligations, will become available for other award grants under the 2022 Plan. As of the date of this prospectus, no awards have been granted under the 2022 Plan, and the full number of shares reserved under the 2022 Plan is available for award purposes.

Awards under the 2022 Plan may be in the form of incentive or nonqualified stock options, stock appreciation rights, stock bonuses, restricted stock, stock units and other forms of awards including cash awards. Awards under the plan generally will not be transferable other than by will or the laws of descent and distribution, except that the plan administrator may authorize certain transfers.

Nonqualified and incentive stock options may not be granted at prices below the fair market value of the common stock on the date of grant. Incentive stock options must have an exercise price that is at least equal to the fair market value of our Common Stock on the date of grant (or 110% of the fair market value of our Common Stock for incentive stock option grants to any 10% owner of our Common Stock). The maximum term of options and stock appreciation rights granted under the plan is 10 years (or five years for incentive stock option grants to any 10% owner of our Common Stock). These and other awards may also be issued solely or in part for services. Awards are generally paid in shares of our Common Stock or in cash. The plan administrator may provide for the deferred payment of awards and may determine the terms applicable to deferrals.

As is customary in incentive plans of this nature, the number and type of shares available under the 2022 Plan and any outstanding awards, as well as the exercise or purchase prices of awards, will be subject to adjustment in the event of certain reorganizations, mergers, combinations, recapitalizations, stock splits, stock dividends or other similar events that change the number or kind of shares outstanding, and extraordinary dividends or distributions of property to the stockholders. In no case (except due to an adjustment referred to above or any repricing that may be approved by our stockholders) will any adjustment be made to a stock option or stock appreciation right award under the 2022 Plan (by amendment, cancellation and regrant, exchange or other means) that would constitute a repricing of the per-share exercise or base price of the award.

Generally, and subject to limited exceptions set forth in the 2022 Plan, if we dissolve or undergo certain corporate transactions such as a merger, business combination or other reorganization, or a sale of all or substantially all of its assets, all awards then-outstanding under the 2022 Plan will become fully vested or paid, as applicable, and will terminate or be terminated in such circumstances, unless the plan administrator provides for the assumption, substitution or other continuation of the award. The plan administrator also has the discretion to establish other change in control provisions with respect to awards granted under the 2022 Plan. For example, the administrator could provide for the acceleration of vesting or payment of an award in connection with a corporate event that is not described above and provide that any such acceleration shall be automatic upon the occurrence of any such event.

Our Board will have the ability to amend or terminate the 2022 Plan at any time, but no such action will affect any outstanding award in any manner materially adverse to a participant without the consent of the participant. Plan amendments will be submitted to stockholders for their approval as required by applicable law or any applicable listing agency. The 2022 Plan will not be exclusive – our Board and Compensation Committee may grant stock and performance incentives or other compensation, in stock or cash, under other plans or authority.

The 2022 Plan terminates on the tenth anniversary date of the adoption. However, the plan administrator will retain its authority under the 2022 Plan until all outstanding awards are exercised or terminated.

Benefits

At this stage of our business, we provide no benefits or prerequisites for our employees other than health insurance and vacation benefits that we believe are generally comparable to those offered by other small private

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and public companies or as may be required by applicable state employment laws. We do not have a 401(k) retirement plan or any other retirement plan for our employees NEOs. We may adopt these plans and confer other fringe benefits for our executive officers in the future.

Summary Compensation Table—Fiscal Year 2021

As an emerging growth company, we have opted to comply with the executive compensation disclosure rules applicable to “smaller reporting companies,” as such term is defined under the Securities Act of 1933, as amended, which require compensation disclosure for our principal executive officer and up to two other executive officers who were employed by our wholly owned subsidiary Hudspeth Operating, LLC as of December 31, 2021 (also referred to as our “named executive officers” or “NEOs”). The table below sets forth the annual compensation for services rendered during 2021 by our named executive officers.

Name and Principal Position	Year		Salary ($)		Bonus ($)		Stock Awards ($)		Option Awards ($)		Non-Equity Incentive Plan Compensation ($)		Non-Qualified Deferred Compensation Earnings ($)		All Other Compensation ($)			Total ($)
Clifton DuBose, Jr.(2)		2021		126,667		—		—		—		—		—		11,300	(1)		137,967
Chief Executive Officer
Joseph DeWoody(2)		2021		63,333		—		—		—		—		—		11,300	(1)		74,633
President
Delvina Oelkers(2)		2021		121,915		—		—		—		—		—		11,300	(1)		133,215
Chief Operating Officer

(1) The amount includes insurance reimbursements paid to Mr. DuBose, Mr. DeWoody and Ms. Oelkers.

(2) Mr. DuBose, Mr. DeWoody and Ms. Oelkers each commenced employment with one of our subsidiaries, Hudspeth Operating, LLC, on September 7, 2021 each as a general manager.

Outstanding Equity Awards as of December 31, 2021

As of December 31, 2021, our NEOs did not hold any outstanding equity awards with respect to our equity securities or equity securities of Meta or any of its affiliated companies.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

All of the Common Stock is currently beneficially owned by Meta. After the Spin-Off, Meta will not own any of the Common Stock. The following table provides information with respect to the expected beneficial ownership of the Common Stock after giving effect to the Spin-Off by (i) each person who we believe will be a beneficial owner of more than 5% of the outstanding Common Stock, (ii) each of our directors and our NEOs, and (iii) all directors and executive officers as a group. We based the share amounts on each person’s beneficial ownership of Series A Preferred Stock as of                     , 2022, unless we indicate some other basis for the share amounts, and assuming a distribution ratio of one share of our Common Stock for each share of Meta’s Series A Preferred Stock.

To the extent our directors and officers own Series A Preferred Stock at the time of the Spin-Off, they will participate in the Spin-Off on the same terms as other holders of Series A Preferred Stock.

Except as otherwise noted in the footnotes below, each person or entity identified below has sole voting and investment power with respect to such securities. Following the Spin-Off, we will have outstanding an aggregate of shares of Common Stock based upon shares of Series A Preferred Stock outstanding on                     , 2022 and applying the distribution ratio of one share of our Common Stock for each share of Series A Preferred Stock held as of the Record Date.

Name of Beneficial Owner	Number of Series A Preferred Stock Beneficially Owned Before Distribution			Percentage of Series A Preferred Stock Beneficially Owned Before Distribution			Number of Common Stock Beneficially Owned After Distribution		Percentage of Common Stock Beneficially Owned After Distribution
5% or More Stockholders
Gregory McCabe 6015 Green Hill Ct. Midland, TX 79707		19,605,348	(1)		11.84	%		19,605,348		11.84	%
Directors and Executive Officers
Robert L. Cook		300,000			0.18	%		300,000		0.18	%
Clifton DuBose Jr.		—			—			—		—
Joseph DeWoody		—			—			—		—
Lucas T. Hawkins		—			—			—		—
Delvina Oelkers		—			—			—		—
Mia Pitts		—			—			—		—
Kristin Whitley		—			—			—		—
Kyle Bradford		—			—			—		—
Daren Rader		—			—			—		—
All officers and directors as a group (9 persons)		300,000			0.18	%		300,000		0.18	%

(1) Represents shares of Series A Preferred Stock owned personally by Mr. McCabe and further includes 797,099 shares out of 19,605,348 shares owned by G MC Exploration, LLC, an entity that is owned 50% by Mr. McCabe.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

With respect to the standards applied by the audit committee when deciding whether to approve a related party transaction, the audit committee shall approve or ratify the transaction if it is on terms believed to be comparable to those that could be obtained in arm’s length dealings with an unrelated third party. We believe that the transactions and agreements discussed below (including renewals of any existing agreements) between us and related third parties are at least as favorable to us as could have been obtained from unrelated parties at the time they were entered into.

Transactions with Stockholder Gregory McCabe

On August 7, 2014, our predecessor entered into a Purchase Agreement (the “Purchase Agreement”) with Hudspeth Oil Corporation (“Hudspeth”), McCabe Petroleum Corporation (“MPC”), and Gregory McCabe, Meta’s former Chairman. Mr. McCabe was the sole owner of both Hudspeth and MPC. Mr. McCabe has, at his option, a 10% working interest back-in after payout and a reversionary interest if drilling obligations are not met, all under the terms and conditions of a participation and development agreement among Hudspeth, MPC and Mr. McCabe that was entered into as a part of the Purchase Agreement (the “Participation Agreement”). As of December 31, 2021, leases covering approximately 134,000 acres remain in effect that are subject to the Participation Agreement. As of June 30, 2022, we had a balance of $165,238 for an account receivable due from McCabe Petroleum Corporation for amounts advanced related to the Orogrande Project pursuant to the terms of the Participation Agreement.

Mr. McCabe also owns a controlling interest in Wolfbone Investments, LLC (“Wolfbone”), the owner of certain properties in the Orogrande Project. On August 6, 2018, we and Hudspeth entered into a Purchase & Settlement Agreement (the “Settlement Agreement”) with Founders Oil & Gas Operating, LLC, Wolfbone and MPC, which agreement provided for Founders assigning its 50% working interest in the oil and gas leases of the Orogrande Project to Hudspeth and Wolfbone equally, with each entity receiving 25% working interest.

Under that certain Farmout Agreement, by and among Hudspeth, Pandora Energy LP, Founders Oil & Gas, LLC, MPC and Mr. McCabe dated as of September 23, 2015, as amended, future well capital spending obligations remained the same 50% contribution from Hudspeth and 50% from Wolfbone until such time as the $40.5 million to be spent on the project. Cumulative capital spending did not exceed $40.5 million until after the closing of the Arrangement. With such $40.5 MM threshold being met, Wolfbone will bear 25% of the costs of the wells being drilled in the Orogrande acreage going forward provided that Wolfbone elects to participate in drilling such wells.

Additionally, Mr. McCabe owns a controlling interest in Magdalena Royalties, LLC (“Magdalena”), an entity that holds a 4.5% overriding royalty interest in the Orogrande acreage. Magdalena’s overriding royalty interest in the Orogrande acreage, which was obtained prior to, and was not a part of any of the transactions with us or subsidiaries.

Effective April 4, 2016, Torchlight Energy, Inc. (“TEI”) acquired from MPC a 66.66% working interest in approximately 12,000 acres in the Midland Basin. As part of that transaction, MPC, TEI, and Imperial Exploration, LLC entered into Participation Agreement effective as of May 1, 2016. MPC and another unrelated working interest owner retained a back-in after payout working interest of 25% in that same acreage, and the interest will be triggered back to MPC upon the proceeds from production equal the costs of developing the project area.

Lastly, on August 13, 2020, our subsidiaries TEI and Torchlight Hazel, LLC (collectively, “Torchlight Subs”) entered into the Option Agreement with MHP and MPC. Under the Option Agreement, MHP was obligated to satisfy certain drilling obligations on the Hazel Project. Further, under the terms of the Option Agreement (which was amended in September 2020), MHP had the option to purchase the entire Hazel Project no later than May 31, 2021. The Option Agreement provided that if MHP declined to exercise the option to acquire the property, we

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would be obligated to reimburse MHP for its cost of the development activity to the extent that the wells produced revenues beyond the date of the option’s lapse until the total amount of development expenses are reimbursed. MHP declined to exercise the option in 2021. Additionally, MPC holds a reversionary interest burdening our proportionate interest in the Hazel Project of 20%.

For a discussion regarding prior transactions and our ongoing relationship with Mr. McCabe and certain entities controlled by Mr. McCabe with respect to the Orogrande Project and Hazel Project, please refer to Note 4 of the notes accompanying the financial statements included elsewhere in this Prospectus.

Transactions with Meta

Following the Spin-Off, we and Meta will operate independently, and neither will have any ownership interest in the other. In order to govern the ongoing relationship between us and Meta after the Spin-Off, we and Meta have entered into certain agreements, and under which we and Meta have agreed to indemnify each other against certain liabilities arising from our respective businesses. The following summarizes the material terms of these agreements.

Assignment of Company Interests

Pursuant to an Assignment of Company Interests and Stock Power dated as of June 28, 2022 between Meta and us, Meta assigned and conveyed to us one hundred percent (100%) of the equity interest of each of Torchlight Energy, Inc., Torchlight Hazel, LLC and Hudspeth Oil Corporation, such that following such assignment and conveyance, each of such entities became our wholly-owned subsidiaries.

2021 Note

In 2021, we entered into a note payable with Meta to borrow up to $15 million. On October 1, 2021, the Company issued the 2021 Note, which bears interest at 8% per annum, computed on the basis of a 360-day year, and matures March 31, 2023 (the “2021 Note Maturity Date”); provided, however, if we raise $30 million or more in capital through debt or equity or a combination thereof by the 2021 Note Maturity Date, the 2021 Note Maturity Date will be extended to September 30, 2023, and the outstanding principal of the 2021 Note will amortize in six equal monthly installments. If an event of default has occurred and is continuing under the 2021 Note, interest on the 2021 Note may accrue at the default rate of 12% per annum. The outstanding principal of the 2021 Note, together with all accrued interest thereon, becomes due on the 2021 Note Maturity Date. The 2021 Note includes a restrictive covenant that, subject to certain exceptions and qualifications, restricts the Company’s ability to merge or consolidate with another person or entity, or sell or transfer all or substantially all of its assets, unless the Company is the surviving entity or the successor entity assumes all of obligations under the 2021 Note. The 2021 Note is secured by a security interest in 1,515,000 shares of common stock of Meta beneficially owned by Mr. McCabe and by a lien on Wolfbone’s 25% working interest in the Orogrande Project.

Loan Agreement

We entered into the Loan Agreement with Meta as the lender which governs the unsecured term loans previously advanced to us on April 14, 2022, May 4, 2022, May 12, 2022, May 26, 2022, June 1, 2022, June 13, 2022, June 28, 2022, August 11, 2022 and August 29, 2022, for an aggregate principal balance outstanding of $5 million, each bearing interest at 8% per annum. For additional discussion regarding the terms of the Loan Agreement, see the discussion under the heading “Liquidity and Capital Resources” included elsewhere in this Prospectus.

Distribution Agreement

We have entered into a Distribution Agreement with Meta. The Distribution Agreement sets forth our agreements with Meta regarding the principal actions to be taken in connection with the Spin-Off. It also sets forth other agreements that govern aspects of our relationship with Meta following the Spin-Off.

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Intercompany Arrangements. All agreements, arrangements, commitments and understandings, including most intercompany accounts payable or accounts receivable, between us, on the one hand, and Meta, on the other hand, will terminate effective as of the Distribution, except specified agreements and arrangements that are intended to survive the Distribution.

The Distribution. The Distribution Agreement governs Meta’s and our respective rights and obligations regarding the Distribution. Prior to the Distribution, Meta will deliver all the issued and outstanding shares of our Common Stock to the distribution agent. Following the Distribution Date, the distribution agent will distribute the shares of our Common Stock to Meta stockholders in book-entry form based on the distribution ratio and will not issue any physical stock certificates, other than upon request. The Meta Board will have the sole and absolute discretion to determine the terms of, and whether to proceed with, the Distribution.

Settlement of Expenses. Within 90 days after consummation of the Spin-Off, we and Meta have agreed to negotiate the settlement and agreement regarding (i) advances made to us by Meta or expenses paid by Meta on our behalf, whether before or after the Spin-Off and (ii) costs related to the Spin-Off that are to be borne by us. In addition, to the extent Meta signs or guaranties any credit applications with trade creditors on our behalf to allow us to meet our drilling obligations, any amounts drawn under such credit applications would be included in the settlement. All the above mentioned amounts owed by us to Meta are expected to become payable pursuant to a promissory note on terms to be negotiated.

Conditions. The Distribution Agreement provides that several conditions must be satisfied or waived by Meta in its sole and absolute discretion before the Distribution can occur. For further information about these conditions, see “The Spin-Off—Conditions to the Spin-Off.” The Meta Board may, in its sole and absolute discretion, determine the Record Date and the Distribution Date and may at any time prior to the completion of the Spin-Off decide to abandon or modify the Spin-Off.

Exchange of Information. We and Meta have agreed to provide each other with information reasonably necessary to comply with reporting, disclosure, filing or other requirements of any national securities exchange or governmental authority, for use in judicial, regulatory, administrative and other proceedings and to satisfy audit, accounting, litigation and other similar requests. We and Meta have also agreed to use reasonable best efforts to retain such information in accordance with our respective record retention policies as in effect on the date of the Distribution Agreement. Until the end of the first full fiscal year following the Distribution, each party has also agreed to use its reasonable best efforts to assist the other with its financial reporting and audit obligations.

Termination. The Meta Board, in its sole and absolute discretion, may terminate the Distribution Agreement at any time prior to the Distribution.

Release of Claims. We and Meta have each agreed to release the other and its affiliates, successors and assigns, and all persons that prior to the Distribution have been the other’s stockholders, directors, officers, members, agents and employees, and their respective heirs, executors, administrators, successors and assigns, from certain claims against any of them that arise out of or relate to events, circumstances or actions occurring or failing to occur or any conditions existing at or prior to the time of the Distribution other than certain claims against current and former directors and officers of Meta and its predecessor Torchlight.

Indemnification. We and Meta have each agreed to indemnify the other and each of the other’s current, former and future directors, officers and employees, and each of the heirs, administrators, executors, successors and assigns of any of them, against certain liabilities incurred in connection with the Spin-Off and our and Meta’s respective businesses. The Distribution Agreement also specifies procedures regarding claims subject to indemnification, including our entitlement to indemnification with respect to the matters described under “Legal Proceedings” in this Prospectus.

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Tax Matters Agreement

The Tax Matters Agreement governs Meta’s and our respective rights, responsibilities and obligations with respect to taxes (including taxes arising in the ordinary course of business and taxes incurred as a result of the Spin-Off), tax attributes, tax returns, tax contests and certain other tax matters.

The Tax Matters Agreement allocates responsibility for the preparation and filing of certain tax returns (and the

payment of taxes reflected thereon), including Meta’s consolidated federal income tax return, tax returns

associated with both the Meta business and our business, and tax returns associated with either the Meta business

or our business, and provides for certain reimbursements by the parties.

Under the Tax Matters Agreement, we are liable for taxes of Meta attributable to us or our subsidiaries or arising or resulting from the Spin-Off. We will bear liability for any transfer taxes incurred on the Spin-Off.

Each of Meta and the Company agree to indemnify each other against certain taxes allocated to such party under the Tax Matters Agreement, and related out-of-pocket costs and expenses.

We encourage you to read the Tax Matters Agreement carefully.

Related Party Transactions

Policy and Procedures Governing Related Person Transactions

Our audit committee of the Board will adopt written procedures in evaluating the terms and provisions of proposed related party transactions or agreements in accordance with the Exchange Act, and the fiduciary duties of directors under Nevada law. Our related party transaction procedures will contemplate audit committee review and approval of all new agreements, transactions or courses of dealing with related parties, including any modifications, waivers or amendments to existing related party transactions. We will ensure that the terms of related party transactions are at least as favorable to us as could have been obtained from unrelated parties at the time of the transaction. The audit committee will consider, at a minimum, the nature of the relationship between us and the related party, the history of the transaction (in the case of modifications, waivers or amendments), the terms of the proposed transaction, our rationale for entering into the transaction and the terms of comparable transactions with unrelated third parties. In addition, management and internal audit will annually analyze all existing related party agreements and transactions and review them with the audit committee.

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DESCRIPTION OF OUR CAPITAL STOCK

General

Prior to the Distribution Date, Meta, as our sole stockholder, approved and adopted our Amended and Restated Articles of Incorporation, and our Board approved and adopted our Amended and Restated By-laws. The following summarizes information concerning our capital stock, including material provisions of our Amended and Restated Articles of Incorporation, our Amended and Restated By-laws and certain provisions of Nevada law. You are encouraged to read our Amended and Restated Articles of Incorporation and our Amended and Restated By-laws, which have been filed as exhibits to the Registration Statement on Form S-1, of which this Prospectus is a part, for greater detail with respect to these provisions.

The Company was incorporated on August 31, 2021, and 1 share of Common Stock was issued to Meta. Subsequent to the formation of the Company, we have not sold any securities of the Company; provided, that as of July 2022, the Company issued 165,523,362 additional shares of Common Stock to Meta.

Authorized Capital Stock

Immediately following the Spin-Off, our authorized capital stock will consist of 500,000,000 shares of Common Stock, par value $0.0001 per share, and 50,000,000 shares of preferred stock, par value $0.0001 per share.

Common Stock

Shares Outstanding. Immediately following the Spin-Off, we estimate that approximately 165.5 million shares of our Common Stock will be issued and outstanding, based on the approximate number of shares of Series A Preferred Stock outstanding as of August 30, 2022. The actual number of shares of our Common Stock outstanding immediately following the Spin-Off will depend on the actual number of shares of Series A Preferred Stock outstanding on the Record Date.

Voting Rights. The holders of our Common Stock will be entitled to one vote for each share held of record on all matters submitted to a vote of the stockholders. Holders of shares of our Common Stock will not have cumulative voting rights.

Other Rights. Subject to the preferential liquidation rights of any preferred stock that may be outstanding, upon our liquidation, dissolution or winding-up, the holders of our Common Stock will be entitled to share ratably in our assets legally available for distribution to our stockholders.

Fully Paid. The issued and outstanding shares of our Common Stock are fully paid and non-assessable. Any additional shares of Common Stock that we may issue in the future will also be fully paid and non-assessable.

The holders of our Common Stock will not have preemptive rights or preferential rights to subscribe for shares of our capital stock.

Preferred Stock

Our Amended and Restated Articles of Incorporation authorize our Board to designate and issue from time to time one or more series of preferred stock without stockholder approval. If we offer a new series of preferred stock, a more specific description may be filed with the SEC, and the designations and rights of such preferred stock will be described in an accompanying prospectus supplement, including the following terms:

• the series, the number of shares offered, and the liquidation value of the preferred stock;

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• the price at which the preferred stock will be issued;

• the dividend rate, the dates on which the dividends will be payable, and other terms relating to the payment of dividends on the preferred stock;

• the liquidation preference of the preferred stock;

• the voting rights of the preferred stock;

• whether the preferred stock is redeemable, or subject to a sinking fund, and the terms of any such redemption or sinking fund;

• whether the preferred stock is convertible, or exchangeable for any other securities, and the terms of any such conversion or exchange; and

• any additional rights, preferences, qualifications, limitations, and restrictions of the preferred stock.

The description of the terms of the preferred stock that will be set forth in an applicable prospectus will not be complete and will be subject to and qualified in its entirety by reference to the certificate of designation relating to the applicable series of preferred stock. The registration statement, of which this prospectus forms a part, will include the certificate of designation as an exhibit or incorporate it by reference.

Undesignated preferred stock may enable our Board to render more difficult or to discourage an attempt to obtain control of us by means of a tender offer, proxy contest, merger, or otherwise and to thereby protect the continuity of our management. The issuance of shares of preferred stock may adversely affect the rights of the holders of our Common Stock. For example, any preferred stock issued may:

• rank senior to our common stock as to dividend rights, liquidation preference, or both;

• have full or limited voting rights; and

• be convertible into shares of common stock or another series of preferred stock.

The issuance of additional preferred stock could adversely affect the voting power, conversion or other rights of holders of Common Stock.

Certain Provisions of Nevada Law

Combination with Interested Stockholders Statute

Sections 78.411 to 78.444 of the Nevada Revised Statutes (N.R.S.), which apply to any Nevada corporation with more than 200 stockholders, prohibits an “interested stockholder” from entering into a “combination” with the corporation for two years, unless certain conditions are met. A “combination” includes:

• any merger of the corporation or any subsidiary of the corporation with an “interested stockholder,” or any other entity, whether or not itself an “interested stockholder,” which is, or after and as a result of the merger would be, an affiliate or associate of an “interested stockholder,”

• any sales, lease, exchange, mortgage, pledge, transfer, or other disposition in one transaction, or a series of transactions, to or with an “interested stockholder” or any affiliate or associate of an “interested stockholder,” of assets of the corporation or any subsidiary of the corporation:

• having an aggregate market value equal to more than 5% of the aggregate market value of the corporation’s assets, determined on a consolidated basis;

• having an aggregate market value equal to more than 5% of the aggregate market value of all of the outstanding shares of the corporation; or

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• representing more than 10% of the earning power or net income, determined on a consolidated basis, of the corporation; or

• the issuance or transfer by the corporation or any subsidiary, of any shares of the corporation or any subsidiary to an “interested stockholder” or any affiliate or associate of an “interested stockholder,” having an aggregate market value equal to 5% or more of the aggregate market value of all of the outstanding voting shares of the corporation, except under the exercise of warrants or rights to purchase shares offered, or a dividend or distribution paid or made, pro rata to all stockholders of the resident domestic corporation;

• the adoption of any plan, or proposal for the liquidation or dissolution of the corporation, under any agreement, arrangement or understanding, with the “interested stockholder.” or any affiliate or associated of the “interested stockholder;”

• if any of the following actions occurs:

• a reclassification of the corporation’s securities, including, without limitation, any splitting of shares, share dividend, or other distribution of shares with respect to other shares, or any issuance of new shares in exchange for a proportionately greater number of old shares;

• recapitalization of the corporation;

• merger of consolidation of the corporation with any subsidiary; or

• any other transaction, whether or not with or into or otherwise involving the interested stockholder, under any agreement, arrangement or understanding, whether or not in writing, with the interested stockholder or any affiliate or associate of the interested stockholder, which has the immediate and proximate effect of increasing the proportionate share of the outstanding shares of any class or series of voting shares or securities convertible into voting shares of the corporation or any subsidiary of the corporation which is beneficially owned by the interested stockholder or any affiliate or associate of the interested stockholder;

• any receipt by an “interested stockholder” or any affiliate or associate of an “interested stockholder” except proportionately as a stockholder of the corporation, of the benefit of any loan, advance, guarantee, pledge or other financial assistance or any tax credit or other tax advantage provided by or through the corporation

An “interested stockholder” is a person who is:

• directly or indirectly, the beneficial owner of 10% or more of the voting power of the outstanding voting shares of the corporation; or

• an affiliate or associate of the corporation, which at any time within two years immediately before the date in question was the beneficial owner, directly or indirectly, of 10% or more of the voting power of the then outstanding shares of the corporation.

A corporation to which the Combinations with Interested Stockholders Statute applies may not engage in a “combination” within two years after the interested stockholder first became an interested stockholder, unless the combination meets all of the requirements of the corporation’s articles of incorporation and (i) the combination or the transaction by which the person first became an interested stockholder is approved by the board of directors before the person first became an interested stockholder, or (ii)(a) the combination is approved by the board of directors and (b) at or after that time, the combination is approved at an annual or special meeting of the stockholders, and not by written consent, by the affirmative vote of the stockholders representing at least sixty percent (60%) of the outstanding voting power of the corporation not beneficially owned by the interested stockholder or the affiliates or associates of the interested stockholder. If this approval is not obtained, the combination may be consummated after the two year period expires if either (i)(a) the combination or transaction

76

by which the person first became an interested stockholder is approved by the board of directors before such person first became an interested stockholder, (b) the combination is approved by a majority of the outstanding voting power of the corporation not beneficially owned by the interested stockholder or any affiliate or associate of the interested stockholder, or (c) the combination otherwise meets the requirements of the Combination with Interested Stockholders Statute. Alternatively, a combination with an interested stockholder engaged in more than 2 years after the date the person first became an interested stockholder may be permissible if the aggregate amount of cash and the market value of consideration other than cash to be received by holders of shares of common stock and holders of any other class or series of shares meets the minimum requirements set forth in the statue, and prior to the completion of the combination, except in limited circumstances, the interested stockholder has not become the beneficial owner of additional voting shares of the corporation.

Acquisition of Controlling Interest Statute

In addition, Nevada’s “Acquisition of Controlling Interest Statute,” prohibits an acquiror, under certain circumstances, from voting shares of a target corporation’s stock after crossing certain threshold ownership percentages, unless the acquiror obtains the approval of the target corporation’s stockholders. Sections 78.378 to 78.3793 of the N.R.S. only apply to Nevada corporations with at least 200 stockholders, including at least 100 record stockholders who are Nevada residents, that do business directly or through an affiliated corporation in Nevada and whose articles of incorporation or bylaws in effect 10 days following the acquisition of a controlling interest by an acquiror do not prohibit its application.

We do not intend to “do business” in Nevada within the meaning of the Acquisition of Controlling Interest Statute. Therefore, we believe it is unlikely that this statute will apply to us. The statute specifies three thresholds:

• at least one-fifth but less than one-third;

• at least one-third but less than a majority; and

• a majority or more, of the outstanding voting power. Once an acquiror crosses one of these thresholds, shares which it acquired in the transaction taking it over the threshold (or within ninety days preceding the date thereof) become “control shares” which could be deprived of the right to vote until a majority of the disinterested stockholders restore that right.

A special stockholders’ meeting may be called at the request of the acquiror to consider the voting rights of the acquiror’s shares. If the acquiror requests a special meeting and gives an undertaking to pay the expenses of said meeting, then the meeting must take place no earlier than 30 days (unless the acquiror requests that the meeting be held sooner) and no more than 50 days (unless the acquiror agrees to a later date) after the delivery by the acquiror to the corporation of an information statement which sets forth the range of voting power that the acquiror has acquired or proposes to acquire and certain other information concerning the acquiror and the proposed control share acquisition.

If no such request for a stockholders’ meeting is made, consideration of the voting rights of the acquiror’s shares must be taken at the next special or annual stockholders’ meeting. If the stockholders fail to restore voting rights to the acquiror, or if the acquiror fails to timely deliver an information statement to the corporation, then the corporation may, if so provided in its articles of incorporation or bylaws in effect on the tenth day following the acquisition, call certain of the acquiror’s shares for redemption at the average price paid for such shares by the acquiror.

Our restated articles of incorporation and amended and restated bylaws do not currently permit us to redeem an acquiror’s shares under these circumstances, but could be amended to so provide within ten days following the acquisition. The Acquisition of Controlling Interest Statute also provides that in the event the stockholders restore full voting rights to a holder of control shares that owns a majority of the voting stock, then, unless the

77

corporation’s articles of incorporation or bylaws in effect on the tenth day following the acquisition otherwise provide, all other stockholders who do not vote in favor of restoring voting rights to the control shares may demand payment for the “fair value” of their shares as determined by a court in dissenters rights proceeding pursuant to Chapter 92A of the N.R.S.

Limitations of Liability and Indemnification Matters

Our Amended and Restated Articles of Incorporation contain provisions that limit the liability of our current and former directors for monetary damages to the fullest extent permitted by Nevada law. Nevada law provides that directors of a corporation will not be personally liable for monetary damages for any breach of fiduciary duties as directors, unless the presumption that the directors have acted in good faith, on an informed basis, and with a view to the interests of the corporation has been rebutted, in which case directors may be liable for damages resulting from intentional misconduct, fraud or a knowing violation of law. To the extent that indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or persons controlling our company pursuant to the foregoing provisions, we have been informed that, in the opinion of the SEC, such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable. If a claim for indemnification against such liabilities (other than the payment by us of expenses incurred or paid by a director, officer or controlling person of our company in the successful defense of any action, suit or proceeding) is asserted by any of our directors, officers or controlling persons in connection with the securities being registered, we will, unless in the opinion of our counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by us is against public policy as expressed in the Securities Act and will be governed by the final adjudication of that issue.

Transfer Agent and Registrar

The transfer agent and registrar for the Common Stock is American Stock Transfer & Trust Company LLC.

No Listing

Our Common Stock is not listed on any securities exchange and will not be eligible for electronic trading through DTC or any other established clearing corporation.

LEGAL MATTERS

Certain legal matters in connection with the distribution of our Common Stock in the Spin-Off described in this Prospectus will be passed upon for us by O’Melveny & Myers, LLP, Dallas, Texas, and by Woodburn and Wedge, Reno, Nevada, with respect to matters of Nevada law.

EXPERTS

The consolidated financial statements of Next Bridge Hydrocarbons, Inc. as of December 31, 2021 and 2020, and for each of the fiscal years then ended, appearing in this Prospectus, have been audited by BF Borgers, CPA, an independent registered public accounting firm, as set forth in their report thereon appearing elsewhere herein, and are included in reliance upon such reports given on the authority of such firm as experts in accounting and auditing.

Estimates of the oil and gas reserves of the Company and related future net cash flows and the present values were based upon reserve reports prepared by PeTech Enterprises, Inc. have been included in this Prospectus. We have included these estimates in reliance on the authority of such firm as an expert in such matters.

78

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 under the Securities Act to register the shares of our Common Stock to be distributed in the Spin-Off. The term registration statement means the original registration statement and any and all amendments thereto, including the exhibits and schedules to the original registration statement and any amendments. This Prospectus, which constitutes a part of the registration statement, does not contain all of the information set forth in the registration statement or the exhibits and schedules filed therewith. For further information with respect to us, reference is made to the registration statement and the exhibits and schedules filed therewith. Statements contained in this Prospectus regarding the contents of any contract or any other document that is filed as an exhibit to the registration statement are not necessarily complete, and each such statement is qualified in all respects by reference to the full text of such contract or other document filed as an exhibit to the registration statement. A copy of the registration statement, along with the exhibits and schedules filed therewith, may be inspected without charge at the SEC’s website. The SEC maintains an internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC.

The information contained on or accessible through our website shall not be deemed to be a part of this Prospectus or the registration statement on Form S-1, of which this Prospectus is a part.

You may request a copy of any of our filings with the SEC at no cost by writing us at the following address:

Investor Relations

Next Bridge Hydrocarbons, Inc.

6300 Ridglea Place, Suite 950, Fort Worth, Texas 76116

We have not authorized anyone to give any information or make any representation about the Spin-Off or of the Company that is different from, or in addition to, that contained in this Prospectus. Therefore, if anyone does give you information of this sort, you should not rely on it. If you are in a jurisdiction where offers to sell, or solicitations of offers to purchase, the securities offered by this Prospectus or the solicitation of proxies is unlawful, or if you are a person to whom it is unlawful to direct these types of activities, then the offer presented in this Prospectus does not extend to you. The information contained in this Prospectus speaks only as of the date of this Prospectus unless the information specifically indicates that another date applies.

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INDEX TO FINANCIAL STATEMENTS

	PAGE
Consolidated Financial Statements (audited)
Report of Independent Registered Public Accounting Firm		F-1
Consolidated Balance Sheets as of December 31, 2021 and 2020		F-2
Consolidated Statements of Operations for the years ended December  31, 2021 and 2020		F-3
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2021 and 2020		F-4
Consolidated Statements of Cash Flows for the years ended December  31, 2021 and 2020		F-5
Notes to Consolidated Financial Statements		F-6
Condensed Consolidated Financial Statements (unaudited)
Consolidated Balance Sheets as of June 30, 2022 and December 31, 2021		F-21
Consolidated Statements of Operations for the three and six months ended June 30, 2022 and 2021		F-22
Consolidated Statements of Stockholders’ Equity for the three and six months ended June 30, 2022 and 2021		F-24
Consolidated Statements of Cash Flows for the six months ended June 30, 2022 and 2021		F-26
Notes to Unaudited Condensed Consolidated Financial Statements		F-27
Pro Forma Combined Financial Statements (unaudited)
Combined Statements of Operations for the year ended December  31, 2021		F-44
Combined Statements of Operations for the six months ended June 30, 2022		F-45
Combined Balance Sheets as of June 30, 2022		F-46
Notes to Unaudited Pro Forma Combined Financial Statements		F-47

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and the board of directors of Next Bridge Hydrocarbons, Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Next Bridge Hydrocarbons, Inc. as of December 31, 2021 and 2020, the related statements of operations, stockholders’ equity (deficit), and cash flows for the years then ended, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States.

Substantial Doubt about the Company’s Ability to Continue as a Going Concern

The accompanying financial statements have been prepared assuming that the Company will continue as a going concern. As discussed in Note 2 to the financial statements, the Company has suffered recurring losses from operations and has a significant accumulated deficit. In addition, the Company continues to experience negative cash flows from operations. These factors raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis for Opinion

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

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

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

/S/ BF Borgers CPA PC

BF Borgers CPA PC

PCAOB ID: 5041

We have served as the Company’s auditor since 2022

Lakewood, CO

July 15, 2022

F-1

Next Bridge Hydrocarbons, Inc. and its Subsidiaries

Consolidated Balance Sheets

	December 31, 2021			December 31, 2020
ASSETS
Current assets:
Cash	$	1,989,419		$	130,504
Accounts receivable, related party		163,366			69,056
Grants and other receivables		74,310			161,064
Prepaid expenses		2,667			103,672
Total current assets		2,229,762			464,296
Oil and natural gas properties, net		45,663,470			30,857,959
Property and equipment		—			4,549
Other assets		25,000			—
TOTAL ASSETS	$	47,918,232		$	31,326,804
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	2,828,326		$	708,260
Accrued liabilities		—			1,213,779
Notes payable, related party		12,708,889			—
Total current liabilities		15,537,215			1,922,039
Asset retirement obligations		21,937			21,844
Total liabilities		15,559,152			1,943,883
Commitments and contingencies
Stockholder’s equity:
Preferred stock, par value $0.0001; 25,000,000 shares authorized; 0 issued and outstanding
Common stock, par value $0.0001; 250,000,000 shares authorized; 1 issued and outstanding		—			—
Additional paid-in capital		100,546,596			89,331,629
Accumulated deficit		(68,187,516	)		(59,948,708	)
Total stockholder’s equity		32,359,080			29,382,921
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	47,918,232		$	31,326,804

F-2

Next Bridge Hydrocarbons, Inc. and its Subsidiaries

Consolidated Statements of Operations

For the Years Ended December 31, 2021 and 2020

	2021			2020
Oil sales	$	4,675		$	4,484
Natural gas sales		11,229			2,422
Revenue		15,904			6,906
Operating expenses
Lease operating expenses		75,330			86,988
Production and ad valorem tax		1,001			498
General and administrative		8,050,443			2,557,975
Depreciation, depletion and amortization		4,642			820,814
Impairment		—			2,108,301
Total operating expenses		8,131,416			5,574,576
Other income (expense)
Interest expense		(212,201	)		(11,121	)
Gain (loss) on sale of assets		1,000			(170,215	)
Gain on extinguishment of debt		77,477			—
Interest income		10,428			—
Total other income (expense)—net		(123,296	)		(181,336	)
Loss before income taxes		(8,238,808	)		(5,749,006	)
Provision for income tax		—			—
Net loss	$	(8,238,808	)	$	(5,749,006	)

F-3

Next Bridge Hydrocarbons, Inc. and its Subsidiaries

Consolidated Statements of Stockholders’ Equity

For the Years Ended December 31, 2021 and 2020

	Common stock shares		Common stock amount		Additional paid-in capital		Accumulated deficit			Total
Balance, December 31, 2019		1	$	—	$	88,203,178	$	(54,199,702	)	$	34,003,476
Contributions from parent		—		—		1,128,451		—			1,128,451
Net loss		—		—		—		(5,749,006	)		(5,749,006	)
Balance, December 31, 2020		1	$	—	$	89,331,629	$	(59,948,708	)	$	29,382,921
Contributions from parent		—		—		11,214,967		—			11,214,967
Net loss		—		—		—		(8,238,808	)		(8,238,808	)
Balance, December 31, 2021		1	$	—	$	100,546,596	$	(68,187,516	)	$	32,359,080

F-4

Next Bridge Hydrocarbons, Inc. and its Subsidiaries

Consolidated Statements of Cash Flows

For the Years Ended December 31, 2021 and 2020

	2021			2020
Cash Flows From Operating Activities
Net loss	$	(8,238,808	)	$	(5,749,006	)
Adjustments to reconcile net loss to net cash from operations:
Depreciation, depletion and amortization		4,642			820,814
Impairment loss		—			2,108,301
Paid in kind interest		208,889			—
Change in:
Accounts receivable, related party		(94,310	)		(27,684	)
Grants and other receivables		86,754			—
Prepaid expenses		101,005			(7,666	)
Accounts payable		2,120,066			(617,952	)
Accrued liabilities		(1,213,779	)		172,603
Other assets		(25,000	)		—
Net cash from operating activities		(7,050,541	)		(3,300,590	)
Cash Flows From Investing Activities
Investment in oil and natural gas properties		(14,805,511	)		(236,807	)
Proceeds from sale of oil and natural gas properties		—			2,508,775
Net cash from investing activities		(14,805,511	)		2,271,968
Cash Flows From Financing Activities
Contributions from parent		11,214,967			1,128,451
Proceeds from notes payable, related party		12,500,000			—
Net cash from financing activities		23,714,967			1,128,451
Net increase in cash		1,858,915			99,829
Cash—beginning of year		130,504			30,675
Cash—end of year	$	1,989,419		$	130,504
Supplemental disclosure of cash flow information: (Non Cash Items)
Cash paid for interest	$	—		$	—
Cash paid for state franchise tax	$	—		$	—

F-5

NEXT BRIDGE HYDROCARBONS, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. NATURE OF BUSINESS

Next Bridge Hydrocarbons, Inc., formerly OilCo Holdings, Inc., (the “Company”, “we”, “our”) was incorporated in August 2021 under the laws of the State of Nevada. We are engaged in the acquisition, exploration and development of oil and natural gas properties in the United States. We operate our business through our subsidiaries Torchlight Energy Inc., Hudspeth Operating, LLC, Hudspeth Oil Corporation, and Torchlight Hazel LLC.

Prior to the formation of Next Bridge Hydrocarbons, Inc. (formerly named OilCo Holdings, Inc.), our subsidiaries were consolidated into the financial statements of our parent, Meta Materials Inc. (formerly named Torchlight Energy Resources, Inc. (“TERI”)). All intercompany transactions have been eliminated in the consolidated financial statements of Meta Materials, Inc.

On June 29, 2021, TERI acquired Metamaterial Inc., an Ontario corporation, and changed its name to Meta Materials, Inc. (with Metamaterial Inc. being the accounting acquiror).

2. GOING CONCERN

At December 31, 2021, the Company had not yet achieved profitable operations. We had a net loss of $8,238,808 for the year ended December 31, 2021. We expect to incur further losses in the development of our business. The Company had a working capital deficit as of December 31, 2021 of $13,307,453. These conditions raise substantial doubt about the Company’s ability to continue as a going concern.

The Company’s ability to continue as a going concern is dependent on its ability to generate future profitable operations and/or to obtain the necessary financing to meet its obligations and repay its liabilities arising from normal business operations when they come due. Management’s plan to address the Company’s ability to continue as a going concern includes: (1) obtaining debt or equity funding from private placement, institutional, or public sources; (2) obtain loans from financial institutions, where possible; or (3) participating in joint venture transactions with third parties. Although management believes that it will be able to obtain the necessary funding to allow the Company to remain a going concern through the methods discussed above, there can be no assurances that such methods will prove successful.

These consolidated financial statements have been prepared assuming that the Company will continue as a going concern and therefore, the financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amount and classifications of liabilities that may result from the outcome of this uncertainty.

3. SIGNIFICANT ACCOUNTING POLICIES

The Company maintains its accounts on the accrual method of accounting in accordance with accounting principles generally accepted in the United States of America. Accounting principles followed and the methods of applying those principles, which materially affect the determination of financial position, results of operations and cash flows are summarized below:

Use of estimates—The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and certain assumptions that affect the amounts reported in these consolidated financial statements and accompanying notes. Actual results could differ from these estimates.

Basis of presentation—The financial statements are presented on a consolidated basis and include all of the accounts of the Company and its wholly owned subsidiaries, Torchlight Energy, Inc., Hudspeth Operating, LLC,

F-6

Hudspeth Oil Corporation, and Torchlight Hazel LLC. All significant intercompany balances and transactions have been eliminated between the Company and its subsidiaries.

Risks and uncertainties—The Company’s operations are subject to significant risks and uncertainties, including financial, operational, technological, and other risks associated with operating an emerging business, including the potential risk of business failure.

In January 2020, the World Health Organization (“WHO”) announced a global health emergency because of a new strain of coronavirus (“COVID-19”) and the significant risks to the international community and economies as the virus spreads globally beyond its point of origin. In March 2020, the WHO classified COVID-19 as a pandemic, based on the rapid increase in exposure globally, and thereafter, COVID-19 continued to spread throughout the U.S. and worldwide. In addition, actions taken by OPEC members and other exporting nations on the supply and demand in global oil and natural gas markets resulted in significant negative pricing pressure in the first half of 2020, followed by a recovery in pricing and an increase in demand in the second half of 2020 and into 2021. However, multiple variants emerged in 2021 and became highly transmissible, which contributed to additional pricing volatility during 2021 and into 2022. The financial results of companies in the oil and natural gas industry have been impacted materially as a result of changing market conditions. Such circumstances generally increase uncertainty in the Company’s accounting estimates. Although demand and market prices for oil and natural gas have increased, due to the rising energy use and the improvement in U.S. economic activity, we cannot predict events that may lead to future price volatility and the near term energy outlook remains subject to heightened levels of uncertainty.

We are continuing to closely monitor the overall impact and the evolution of the COVID-19 pandemic, including the ongoing spread of any variants, along with future OPEC actions on all aspects of our business, including how these events may impact our future operations, financial results, liquidity, employees, and operators. Additional actions may be required in response to the COVID-19 pandemic on a national, state, and local level by governmental authorities, and such actions may further adversely affect general and local economic conditions, particularly if the 2021 resurgence and spread of the COVID-19 pandemic continues. We cannot predict the long-term impact of these events on our liquidity, financial position, results of operations or cash flows due to uncertainties including the severity of COVID-19 or any of the ongoing variants, and the effect the virus will have on the demand for oil and natural gas. These situations remain fluid and unpredictable, and we are actively managing our response.

Concentration of risks—At times the Company’s cash balances are in excess of amounts guaranteed by the Federal Deposit Insurance Corporation. The Company’s cash is placed with a highly rated financial institution, and the Company regularly monitors the credit worthiness of the financial institutions with which it does business.

Fair value of financial instruments—Financial instruments consist of cash, receivables, convertible note receivable, payables and promissory notes, if any. The estimated fair values of cash, receivables, and payables approximate the carrying amount due to the relatively short maturity of these instruments. The carrying amounts of any promissory notes approximate their fair value giving affect for the term of the note and the effective interest rates.

For assets and liabilities that require re-measurement to fair value the Company categorizes them in a three-level fair value hierarchy as follows:

• Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.

• Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration.

• Level 3 inputs are unobservable inputs based on management’s own assumptions used to measure assets and liabilities at fair value.

F-7

A financial asset or liability’s classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement.

Cash and cash equivalents—Cash and cash equivalents include certain investments in highly liquid instruments with original maturities of three months or less.

Accounts receivable—Accounts receivable consist of uncollateralized oil and natural gas revenues due under normal trade terms, as well as amounts due from working interest owners of oil and natural gas properties for their share of expenses paid on their behalf by the Company. Management reviews receivables periodically and reduces the carrying amount by a valuation allowance that reflects management’s best estimate of the amount that may not be collectible. As of December 31, 2021 and 2020, no valuation allowance was considered necessary. Bad debt expense for the years ended December 31, 2021 and 2020 was $0 and $15,606, respectively.

Oil and natural gas properties—The Company uses the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (“SEC”). Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities.

Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Oil and natural gas property costs excluded represent investments in unevaluated properties and include non-producing leasehold, geological, and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. The Company allocates a portion of its acquisition costs to unevaluated properties based on relative value. Costs are transferred to the full cost pool as the properties are evaluated over the life of the reservoir. Unevaluated properties are reviewed for impairment at least quarterly and are determined through an evaluation considering, among other factors, seismic data, requirements to relinquish acreage, drilling results, remaining time in the commitment period, remaining capital plan, and political, economic, and market conditions.

Gains and losses on the sale of oil and natural gas properties are not generally reflected in income unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves. Sales of less than 100% of the Company’s interest in the oil and natural gas property are treated as a reduction of the capital cost of the field, with no gain or loss recognized, as long as doing so does not significantly affect the unit-of-production depletion rate. Costs of retired equipment, net of salvage value, are usually charged to accumulated depreciation.

Capitalized interest—The Company capitalizes interest on unevaluated properties during the periods in which they are excluded from costs being depleted or amortized. During the years ended December 31, 2021 and 2020, the Company capitalized $141,048, and $2,353,700 respectively, of interest on unevaluated properties.

Depreciation, depletion, and amortization—The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of accumulated depreciation, depletion, and amortization (“DD&A”), estimated future development costs and asset retirement costs not included in oil and natural gas properties, less costs excluded from amortization. The depreciable base of oil and natural gas properties is amortized on a unit-of-production method.

Ceiling test—Future production volumes from oil and natural gas properties are a significant factor in determining the full cost ceiling limitation of capitalized costs. Under the full cost method of accounting, the Company is required to periodically perform a “ceiling test” that determines a limit on the book value of oil and natural gas properties. If the net capitalized cost of proved oil and natural gas properties, net of related deferred income taxes, plus the cost of unproved oil and natural gas properties, exceeds the present value of estimated future net cash flows discounted at ten percent, net of related realizable tax affects, plus the cost of unproved oil

F-8

and natural gas properties, the excess is charged to expense and reflected as additional accumulated DD&A. The Company recorded an impairment expense of $-0- and $2,108,301 for the years ended December 31, 2021 and 2020, respectively, to recognize the adjustment required by the ceiling test.

The ceiling test calculation uses a commodity price assumption which is based on the unweighted arithmetic average of the price on the first day of each month for each month within the prior 12-month period and excludes future cash outflows related to estimated abandonment costs.

The determination of oil and natural gas reserves is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Subsequent re-evaluation of reserves and cost estimates related to future development of proved oil and natural gas reserves could result in significant revisions to proved reserves. Other issues, such as changes in regulatory requirements, technological advances, and other factors which are difficult to predict could also affect estimates of proved reserves in the future.

Asset retirement obligations—The fair value of a liability for an asset’s retirement obligation (“ARO”) is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, with the corresponding charge capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then-present value each subsequent period, and the capitalized cost is depleted over the useful life of the related asset. Abandonment costs incurred are recorded as a reduction of the ARO liability.

Inherent in the fair value calculation of an ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and natural gas property balance. Settlements greater than or less than amounts accrued as ARO are recorded as a gain or loss upon settlement.

Income taxes—Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

Authoritative guidance for uncertainty in income taxes requires that the Company recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an examination. Management has reviewed the Company’s tax positions and determined there were no uncertain tax positions requiring recognition in the consolidated financial statements. Company tax returns remain subject to Federal and State tax examinations. Generally, the applicable statutes of limitation are three to four years from their respective filings.

Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits are classified as a component of tax expense in the statements of operation. The Company has not recorded any interest or penalties associated with unrecognized tax benefits for any periods covered by these financial statements.

Revenue recognition—The Company’s revenue is typically generated from contracts to sell natural gas, crude oil or NGLs produced from interests in oil and natural gas properties owned by the Company. Contracts for the sale

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of natural gas and crude oil are evidenced by (1) base contracts for the sale and purchase of natural gas or crude oil, which document the general terms and conditions for the sale, and (2) transaction confirmations, which document the terms of each specific sale. The transaction confirmations specify a delivery point which represents the point at which control of the product is transferred to the customer. The Company elects to treat contracts to sell oil and natural gas production as normal sales, which are then accounted for as contracts with customers. The Company has determined that these contracts represent multiple performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point.

Revenue is measured based on considerations specified in the contract with the customer, and excludes any amounts collected on behalf of third parties. The Company recognizes revenue in the amount that reflects the consideration it expects to be entitled to in exchange for transferring control of those goods to the customer. Amounts allocated in the Company’s price contracts are based on the standalone selling price of those products in the context of long-term contracts. Payment is generally received one or two months after the sale has occurred.

Gain or loss on derivative instruments is outside the scope of ASC 606 and is not considered revenue from contracts with customers subject to ASC 606. The Company may in the future use financial or physical contracts accounted for as derivatives as economic hedges to manage price risk associated with normal sales, or in limited cases may use them for contracts the Company intends to physically settle but do not meet all of the criteria to be treated as normal sales.

Producer Gas Imbalances. The Company applies the sales method of accounting for natural gas revenue. Under this method, revenues are recognized based on the actual volume of natural gas sold to purchasers.

Environmental laws and regulations—The Company is subject to extensive federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their future economic benefit. The Company believes that it is in compliance with existing laws and regulations. The Company accrued no liability as of December 31, 2021 and 2020.

Recently adopted accounting pronouncements—

Effective January 1, 2021, we adopted ASU 2019-12 on a prospective basis. The new standard was issued in December 2019 with the intent of simplifying the accounting for income taxes. The accounting update removes certain exceptions to the general principles in ASC 740 Income Taxes as well as provides simplification by clarifying and amending existing guidance. The adoption of this ASU did not have a material impact on our consolidated financial statements.

In October 2020, the FASB issued ASU 2020-09, Debt- Debt (Topic 470): Amendments to SEC Paragraphs Pursuant to SEC Release No. 33-10762 (“ASU 2020-09”). The amendments in ASU 2020-09 amend rules focused on the provision of material, relevant, and decision-useful information regarding guarantees and other credit enhancements, and eliminate prescriptive requirements that have imposed unnecessary burdens and incentivized issuers of securities with guarantees and other credit enhancements to offer and sell those securities on an unregistered basis. The adopted amendments relate to the financial disclosure requirements for guarantors and issuers of guaranteed securities registered or being registered in Rule 3-10 of Regulation S-X, and affiliates whose securities collateralize securities registered or being registered in Rule 3-16 of Regulation S-X. The amendments in ASU 2020-09 are effective for public business entities for annual periods beginning after December 15, 2020. The Company has evaluated the provisions of ASU 2020-09 and noted no material impact to our consolidated financial statements or disclosures from the adoption of this ASU.

In October 2020, the FASB issued ASU 2020-10, Codification Improvements, which updated various codification topics by clarifying or improving disclosure requirements to align with the SEC’s regulations. The

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amendments in ASU 2020-10 are effective for annual periods beginning after December 15, 2020, for public business entities. The Company adopted ASU 2020-10 on January 1, 2021 and its adoption did not have a material effect on the Company’s financial statements and related disclosures.

Recent accounting pronouncements not yet adopted—

In June 2016, the FASB issued ASU 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which adds a new Topic 326 to the Codification and removes the thresholds that companies apply to measure credit losses on financial instruments measured at amortized cost, such as loans, receivables, and held-to-maturity debt securities. Under current GAAP, companies generally recognize credit losses when it is probable that the loss has been incurred. The revised guidance will remove all recognition thresholds and will require companies to recognize an allowance for credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost that the company expects to collect over the instrument’s contractual life. ASU 2016-13 also amends the credit loss measurement guidance for available-for sale debt securities and beneficial interests in securitized financial assets. The guidance is applicable for fiscal years beginning after December 15, 2019 and interim periods within those years, however, the FASB extended the effective date for smaller reporting companies to fiscal years beginning after December 15, 2022. The Company is currently evaluating the potential impact of the adoption of this standard on its related disclosures.

Other recently issued or adopted accounting pronouncements are not expected to have, or did not have, a material impact on the Company’s financial position or results from operations.

4. OIL & NATURAL GAS PROPERTIES

The following table presents the capitalized costs for oil & natural gas properties of the Company:

	December 31, 2021		December 31, 2020
Evaluated costs subject to amortization	$	—	$	15,656,182
Unevaluated costs		45,663,470		29,794,015
Total capitalized costs		45,663,470		45,450,197
Less accumulated depreciation, depletion and amortization		—		(15,656,182	)
Total oil and natural gas properties	$	45,663,470	$	30,857,959

Unevaluated costs as of December 31, 2021 and 2020 include cumulative costs on developing projects including the Orogrande and Hazel Projects in West Texas.

The Company periodically adjusts for the separation of evaluated versus unevaluated costs within its full cost pool to recognize the value impairment related to the expiration of, or changes in market value, of unevaluated leases. The impact of reclassifications as they become necessary is to increase the basis for calculation of future period’s depletion, depreciation and amortization which effectively recognizes the impairment on the consolidated statement of operations over future periods. Reclassified costs also become evaluated costs for purposes of ceiling tests and which may cause recognition of increased impairment expense in future periods. The remaining cumulative unevaluated costs which have been reclassified within our full cost pool totals $0 as of December 31, 2021. As of December 31, 2021, evaluated costs are $-0- since we have no proved reserve value associated with our properties.

Due to the volatility of commodity prices, should oil and natural gas prices decline in the future, it is possible that a further write-down could occur. Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids, which geological and engineering data demonstrate with reasonable certainty to be recoverable from

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known reservoirs under existing economic and operating conditions. The independent engineering estimates include only those amounts considered to be proved reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place or for which transportation and/or marketing contracts are not in place. Estimated reserves to be developed through secondary or tertiary recovery processes are classified as unevaluated properties.

Current Projects

We are an energy company engaged in the acquisition, exploration, exploitation and development of oil and natural gas properties in the United States. We are primarily focused on the acquisition of early stage projects, the development and delineation of these projects, and then the monetization of those assets once these activities are completed.

Since 2010, our primary focus has been the development of interests in oil and natural gas projects we hold in the Permian Basin in West Texas. We also hold minor interests in certain other oil and natural gas projects in Central Oklahoma that we are in the process of divesting.

As of December 31, 2021, we had interests in three oil and gas projects: the Orogrande Project in Hudspeth County, Texas, the Hazel Project in Sterling, Tom Green, and Irion Counties, Texas, and two wells in Central Oklahoma.

Orogrande Project, West Texas

On August 7, 2014, our predecessor entered into a Purchase Agreement with Hudspeth Oil Corporation (“Hudspeth”), McCabe Petroleum Corporation (“MPC”), and Gregory McCabe, Meta’s former Chairman. Mr. McCabe was the sole owner of both Hudspeth and MPC. Under the terms and conditions of the Purchase Agreement, our predecessor acquired 100% of the capital stock of Hudspeth which held certain oil and natural gas assets, including a 100% working interest in approximately 172,000 predominately contiguous acres in the Orogrande Basin in West Texas. Mr. McCabe has, at his option, a 10% working interest back-in after payout and a reversionary interest if drilling obligations are not met, all under the terms and conditions of a participation and development agreement among Hudspeth, MPC and Mr. McCabe. Mr. McCabe also holds a 4.5% overriding royalty interest in the Orogrande acreage, which he obtained prior to, and was not a part of the August 2014 transaction. As of December 31, 2021, leases covering approximately 134,000 acres remain in effect.

Effective March 27, 2017, the property became subject to a DDU Agreement which allows for all 192 existing leases covering approximately 134,000 net acres leased from University Lands to be combined into one drilling and development unit for development purposes. The term of the DDU Agreement expires on December 31, 2023, and the time to drill on the drilling and development unit continues through December 2023. The DDU Agreement also grants the right to extend the DDU Agreement through December 2028 if compliance with the DDU Agreement is met and the extension fee associated with the additional time is paid.

Our drilling obligations include five wells per year in years 2021, 2022 and 2023. The drilling obligations are minimum yearly requirements and may be exceeded if acceleration is desired.

We believe all drilling obligations through December 31, 2021 have been met.

On July 25, 2018, we and Hudspeth entered into a Settlement & Purchase Agreement (the “Settlement Agreement”) with University Founders (and Founders Oil & Gas Operating, LLC, former Operator), Wolfbone Investments, LLC (“Wolfbone”) and MPC (entities controlled by a related party), which agreement provided for Founders assigning all of its working interest in the oil and gas leases of the Orogrande Project to Hudspeth and Wolfbone equally. Future well capital spending obligations remained the same 50% contribution from Hudspeth

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and 50% from Wolfbone until such time as the $40.5 million to be spent on the project. Cumulative capital spending did not exceed $40.5 million until after the closing of the Arrangement.

The Company has drilled fourteen test wells in the Orogrande Project properties in order to stay in compliance with University Lands D&D Unit Agreement, as well as, to test for potential shallow pay zones and deeper pay zones that may be present on structural plays. Development of the wells continued through the year ended December 31, 2021 to further capture and document the scientific base in support of demonstrating the production potential of the property.

On March 9, 2020, holders of certain notes payable by the Company entered into a Conversion Agreement under which the noteholders elected to convert principal of $6,000,000 and approximately $1,331,000 of accrued interest on the notes, in accordance with their terms, into an aggregate 6% working interest (of all such holders) in the Orogrande Project.

Following the Spin-Off, the Company intends to make offers and enter into agreements with one or more of the other current working interest owners in the Orogrande Project (each an “Orogrande Owner” and collectively, the “Orogrande Owners”). The Company anticipates offering the Orogrande Owners shares of Common Stock in exchange for their respective working interest in the Orogrande Project. The Company intends to offer the number of shares of Common Stock necessary such that each participating Orogrande Owner would own the percentage of Common Stock then outstanding in proportion to the percentage owned in the working interest of the Orogrande Project. For illustration purposes, if an Orogrande Owner owns ten percent (10%) of the working interest of the Orogrande Project, and such Orogrande Owner elects to participate and accept our offer of shares of Common Stock, then such Orogrande Owner will be offered ten percent (10%) of the aggregate amount of outstanding shares of Common Stock. The Company’s decision to enter into these transactions will depend on ability of the Company and each Orogrande Owner to negotiate and enter into definitive agreements related to such transaction and the Company’s board of directors receiving an industry-standard fairness opinion from an investment banking firm. One of the Orogrande Owners is Wolfbone Investments LLC, an entity controlled by Gregory McCabe, who will own, directly and indirectly through entities he owns or controls, over 11% of the Common Stock following the Spin-Off, which would increase if the proportionate exchange of working interest for shares of our Common Stock is consummated.

The Orogrande Project ownership as of December 31, 2021 is detailed as follows:

	Revenue Interest			Working Interest
University Lands—Mineral Owner		20.000	%		n/a
ORRI—Magdalena Royalties, LLC, an entity controlled by Gregory McCabe, Meta’s former Chairman		4.500	%		n/a
ORRI—Unrelated Party		0.500	%		n/a
Hudspeth Oil Corporation, a subsidiary of Torchlight Energy Resources Inc.		49.875	%		66.500	%
Wolfbone Investments LLC, an entity controlled by Gregory McCabe, Meta’s former Chairman		18.750	%		25.000	%
Conversion by Note Holders in March, 2020		4.500	%		6.000	%
Unrelated Party		1.875	%		2.500	%
		100.000	%		100.000	%

Hazel Project in the Midland Basin in West Texas

Effective April 4, 2016, Torchlight Energy, Inc. (“TEI”) acquired from MPC a 66.66% working interest in approximately 12,000 acres in the Midland Basin. A back-in after payout of a 25% working interest was retained by MPC and another unrelated working interest owner.

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In October 2016, the holders of all of Torchlight Energy Resources, Inc. then-outstanding shares of Series C Preferred Stock (which were issued in July 2016) elected to convert into a total 33.33% working interest in our Hazel Project, reducing our ownership from 66.66% to a 33.33% working interest.

Acquisition of Additional Interests in Hazel Project

On January 30, 2017, we entered into and closed an Agreement and Plan of Reorganization and a Plan of Merger with an entity which was wholly owned by Mr. McCabe, which resulted in the acquisition of approximately 40.66% working interest in the 12,000 gross acres, 9,600 net acres, in the Hazel Project.

Also, on January 30, 2017, the Company entered into and closed a Purchase and Sale Agreement with Wolfbone. Under the agreement, we acquired certain of Wolfbone’s Hazel Project assets, including its interest in the Flying B Ranch #1 well and the 40 acre unit surrounding the well.

Upon the closing of the transactions, our working interest in the Hazel Project increased by 40.66% to a total ownership of 74%.

Effective June 1, 2017, we acquired an additional 6% working interest from unrelated working interest owners increasing our working interest in the Hazel Project to 80%, and an overall net revenue interest of 75%.

The Company has drilled seven test wells on the Hazel Project to capture and document the scientific base in support of demonstrating the production potential of the property.

Option Agreement with Masterson Hazel Partners, LP

On August 13, 2020, our subsidiaries Torchlight Energy, Inc. and Torchlight Hazel, LLC (collectively, “Torchlight Subs”) entered into an option agreement (the “Option Agreement”) with Masterson Hazel Partners, LP (“MHP”) and McCabe Petroleum Corporation. Under the agreement, MHP was obligated to drill and complete, or cause to be drilled and completed, at its sole cost and expense, a new lateral well (the “Well”) on our Hazel Project, sufficient to satisfy Torchlight’s continuous development obligations on the southern half of the prospect no later than September 30, 2020. MHP has satisfied this drilling obligation. MHP paid to Torchlight Subs $1,000 as an option fee at the time of execution of the Option Agreement. MHP is entitled to receive, as its sole recourse for the recoupment of drilling costs, the revenue from production of the well attributable to Torchlight Subs’s interest until such time as it has recovered its reasonable costs and expenses for drilling, completing, and operating the well.

In exchange for MHP satisfying the above drilling obligations, Torchlight Subs granted to MHP the exclusive right and option to perform operations, at MHP’s sole cost and expense, on the Hazel Project sufficient to satisfy Torchlight Subs’s continuous development obligations on the northern half of the prospect. Because MHP exercised this drilling option and satisfied the continuous development obligations on the northern half of the prospect, under the terms of the Option Agreement (as amended in September 2020) MHP had the option to purchase the entire Hazel Project no later than May 31, 2021. Such purchase would be under the terms of a form of Purchase and Sale Agreement included as an exhibit to the Option Agreement, at an aggregate purchase price of $12,690,704 for approximately 9,762 net mineral acres, and not less than 74% net revenue interest (approximately $1,300 per net mineral acre). MHP declined to exercise the Option in 2021.

Hunton Play, Central Oklahoma

Presently, we are producing from one well in the Viking Area of Mutual Interest and one well in Prairie Grove.

5. RELATED PARTY BALANCES

As of December 31, 2021 and 2020, related party payables were $-0- and $98,805, respectively, due to our executive officers and directors included in accounts payable on the consolidated balance sheets. Accrued payroll was $-0- and $1,213,779, respectively, consisting of accrued and unpaid compensation due to our executive officers.

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As of December 31, 2021, and 2020, the Company had a balance of $163,366 and $69,056, respectively, for an account receivable due from McCabe Petroleum Corporation for amounts advanced related to the Orogrande Project participation and development agreement.

6. COMMITMENTS AND CONTINGENCIES

Leases

The Company is subject to a sublease for occupancy of its office premises which requires monthly rent payments of $8,300.

Legal Matters

On January 31, 2020, Torchlight Energy Resources, Inc. and its wholly owned subsidiaries Torchlight Energy, Inc. and Torchlight Energy Operating, LLC were served with a lawsuit brought by Goldstone Holding Company, LLC (Goldstone Holding Company, LLC v. Torchlight Energy, Inc., et al., in the 160th Judicial District Court of Dallas County, Texas). On February 24, 2020, Torchlight Energy Resources, Inc., Torchlight Energy, Inc., and Torchlight Energy Operating, LLC timely filed their answer, affirmative defenses, and requests for disclosure. The suit, which sought monetary relief over $1 million, made unspecified allegations of misrepresentations involving a November 2015 participation agreement and a 2016 amendment to the participation agreement. Torchlight denied the allegations and asserted several affirmative defenses including but not limited to, that the suit is barred by the applicable statute of limitations, that the claims had been released, and that the claims were barred because of contractual disclaimers between sophisticated note parties. Torchlight also asserted counterclaims for attorney fees. On January 14, 2021, Goldstone Holding Company, LLC dismissed its claims without prejudice, leaving Torchlight’s counterclaims for attorney fees as the only pending claim in the case. On February 26, 2021, Torchlight filed a non-suit without prejudice on its counterclaims for attorney fees, leaving no claims in the case. The court signed a final order disposing of the entire case on March 5, 2021. However, Goldstone Holding Company, LLC asked the court to re-instate its claims, and a hearing was held on April 13, 2021. On June 16, 2021, the court signed an order denying the motion to reinstate Goldstone Holding Company, LLC’s claims, and the case is closed.

On April 30, 2020, the Company’s wholly owned subsidiary, Hudspeth Oil Corporation, filed suit against Datalog LWT, Inc. d/b/a Cordax Evaluation Technologies. The suit seeks the recovery of approximately $1.4 million in costs incurred as a result of a tool failure during drilling activities on the University Founders A25 #2 well that is located in the Orogrande Field. Working interest owner Wolfbone Investments, LLC, a company owned by the Meta’s former Chairman Gregory McCabe, is a co-plaintiff in that action. After the suit was filed, Cordax filed a mineral lien in the amount of $104,500 against the Orogrande Field and has sued the operator and counterclaimed against Hudspeth for breach of contract, seeking the same amount as the lien. The Company has added the manufacturer of one of the tool components that the Company contends was a cause of the tool failure. It was later discovered that Datalog LWT, Inc. d/b/a Cordax Evaluation Technologies forfeited its charter to conduct business in the State of Texas by failing to timely pay its franchise taxes, and the Company added members of the board of directors to the case pursuant to the Texas Tax Code. It was recently disclosed that Datalog LWT, Inc. d/b/a Cordax Evaluation Technologies is the subsidiary of a Canadian parent company, Cordax Evaluation Technologies, Inc., who has also been added to the case. The suit, Hudspeth Oil Corporation and Wolfbone Investments, LLC v. Datalog LWT, Inc. d/b/a Cordax Evaluation Technologies, was filed in the 189^th Judicial District Court of Harris County, Texas. Gregory McCabe, Meta’s former Chairman of the Board filed a special appearance after being served with citation, alleging that he was a Canadian citizen with no meaningful ties to Texas. After discovery was conducted on this issue, Meta filed a nonsuit without prejudice for this Defendant, dismissing him from the case. The remaining parties are currently engaged in preliminary discovery and are scheduling mediation.

On March 18, 2021, Datalog LWT, Inc. d/b/a Cordax Evaluation Technologies filed a lawsuit in Hudspeth County, Texas seeking to foreclose its mineral lien against the Orogrande Field in the amount of $104,500 and

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recover related attorney’s fees. The foreclosure action, Datalog LWT Inc. d/b/a Cordax Evaluation Technologies v. Torchlight Energy Resources, Inc., was filed in the 205th Judicial District Court of Hudspeth County, Texas. We are contesting the lien in good faith and filed a Plea in Abatement on May 10, 2021, seeking a stay in the Hudspeth County lien foreclosure case pending final disposition of the related case currently pending in Harris County, Texas.

Environmental Matters

The Company is subject to contingencies as a result of environmental laws and regulations. Present and future environmental laws and regulations applicable to the Company’s operations could require substantial capital expenditures or could adversely affect its operations in other ways that cannot be predicted at this time. As of December 31, 2021 and 2020, no amounts had been recorded because no specific liability has been identified that is reasonably probable of requiring the Company to fund any future material amounts.

7. STOCKHOLDERS’ EQUITY

Next Bridge Hydrocarbons, Inc. has preferred and common stock both at a par value of $.0001. As of December 31, 2021, the Company has issued 1 share of common stock and 0 shares of preferred stock.

8. INCOME TAXES

The Company recorded no income tax provision for 2021 and 2020 because of losses incurred.

There are no uncertain tax positions accounted for in this tax provision.

The following is a reconciliation between the federal income tax benefit computed at statutory federal income tax rates and actual income tax provision for the years ended December 31, 2021 and 2020:

	Year Ended December 31, 2021			Year Ended December 31, 2020
Federal income tax benefit at statutory rate	$	(1,686,283	)	$	(1,207,291	)
Permanent Differences		390,419			308
Annual reconciling adjustment		(451,708	)		(19,077	)
Change in valuation allowance		1,747,572			1,226,060
Provision for income taxes	$	—		$	—

The tax effects of temporary differences that gave rise to significant portions of deferred tax assets and liabilities at December 31, 2021 and 2020 are as follows:

	December 31, 2021			December 31, 2020
Deferred tax assets:
Net operating loss carryforward	$	12,491,191		$	10,335,223
Disallowed interest expense		—			2,404
Other		385			9,824
Deferred tax liabilities:
Investment in oil and gas properties		(2,765,485	)		(2,368,932	)
Net deferred tax assets and liabilities		9,726,091			7,978,519
Less valuation allowance		(9,726,091	)		(7,978,519	)
Total deferred tax assets and liabilities	$	—		$	—

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The Company had a net deferred tax asset related to federal net operating loss carryforwards of $59,481,861 and $49,215,346 at December 31, 2020 and December 31, 2019, respectively. The federal net operating loss carryforward will begin to expire in 2033. Realization of the deferred tax asset is dependent, in part, on generating sufficient taxable income prior to expiration of the loss carryforwards. The Company has placed a 100% valuation allowance against the net deferred tax asset because future realization of these assets is not assured.

9. PROMISSORY NOTES

Certain assets of the Company were used as collateral for promissory notes entered into by TERI.

Promissory Notes Issued in 2017

On April 10, 2017, TERI sold two 12% unsecured promissory notes with a total of $8,000,000 in principal amount to David A. Straz, Jr. Foundation (the “Straz Foundation”) and the David A. Straz, Jr. Irrevocable Trust DTD 11/11/1986 (the “Straz Trust”) in a private transaction. Interest only was due and payable on the notes each month at the rate of 12% per annum, with a balloon payment of the outstanding principal due and payable at maturity on April 10, 2020. The holders of the notes also received annual payments of common stock in TERI at the rate of 2.5% of principal amount outstanding, based on a volume-weighted average price. Both notes were sold at an original issue discount of 94.25% and accordingly, TERI received total proceeds of $7,540,000 from the investors. TERI used the proceeds for working capital and general corporate purposes, which includes, without limitation, drilling capital, lease acquisition capital and repayment of prior debt.

The effective interest rate was 16.15%.

On February 20, 2020, TERI extended the maturity on $4 million of the 12% unsecured promissory notes previously due in April 2020. The maturity date of the subject promissory note had been extended for one year, from April 10, 2020, to April 10, 2021.

During the quarter ended March 31, 2021, the notes were retired in full by conversion into TERI’s common stock.

Promissory Notes Issued in 2018

On February 6, 2018, TERI sold to the Straz Trust in a private transaction a 12% unsecured promissory note with a principal amount of $4,500,000. Interest only was due and payable on the note each month at the rate of 12% per annum, with a balloon payment of the outstanding principal due and payable at maturity on April 10, 2020. The holder of the note also received annual payments of common stock in TERI at the rate of 2.5% of principal amount outstanding, based on a volume-weighted average price. TERI sold the note at an original issue discount of 96.27% and accordingly, TERI received total proceeds of $4,332,150 from the investor. TERI used the proceeds for working capital and general corporate purposes, which includes, without limitation, drilling capital, lease acquisition capital and repayment of prior debt.

The effective interest rate was 15.88%.

During the quarter ended March 31, 2021, the notes were retired in full by conversion into TERI’s common stock.

Extension of Promissory Notes

On April 24, 2020, TERI entered into a Note Amendment Agreement with each of the Straz Foundation, as a lender, the Straz Trust, as a lender and collateral agent, and The Northern Trust Company and Christopher M. Straz, as co-trustees of the Straz Trust. Under the Note Amendment Agreement, the parties agreed to amend and restate the two promissory notes issued to the Straz Trust on April 10, 2017 and February 6, 2018 that have total principal outstanding of $8,500,000, along with the promissory note issued to the Straz Foundation on April 10,

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2017 which had an outstanding principal amount of $4,000,000. Under the Note Amendment Agreement, the maturity dates of the two promissory notes held by the Straz Trust and the Note held by the Foundation were extended to April 10, 2021. TERI had previously extended the maturity date of the promissory note held by the Straz Foundation to April 10, 2021.

Under the Note Amendment Agreements, we and our subsidiaries provided a first priority lien on certain collateral in favor of the collateral agent for the benefit of the lenders. The collateral includes all assets and property held by Hudspeth Oil Corporation and Torchlight Hazel, LLC, which includes without limitation our working interest in certain oil and gas leases in Hudspeth County, Texas, known as the “Orogrande Project” and our working interest in certain oil and gas leases in the Midland Basin in West Texas, known as the “Hazel Project.” Further, we and TERI, provided guaranty with respect to payment of the three promissory notes. The Note Amendment Agreements also provided restrictions on the use of proceeds if the Orogrande Project or the Hazel Project were sold.

Additionally, the promissory notes, as amended, provided conversion rights whereby the lenders have the right, at each such lender’s option, to convert any portion of principal and interest into shares of common stock of TERI at a conversion price of $1.50 per share.

These notes payable issued in 2017 and 2018 totaling $12,500,000 were retired by conversion into TERI common stock in 2021.

Convertible Notes Issued in October 2018

On October 17, 2018, TERI sold to certain investors in a private transaction 16% Series C Unsecured Convertible Promissory Notes with a total principal amount of $6,000,000. Interest and principal were due and payable on the notes in one balloon payment at maturity on April 17, 2020. The notes were convertible, at the election of the holders, into an aggregate 6% working interest in certain oil and gas leases in Hudspeth County, Texas, known as our “Orogrande Project.” After an analysis of the transaction and a review of applicable accounting pronouncements, management concluded that the notes issued on October 17, 2018 which contained a conversion right for holders to convert into a working interest in the Orogrande Project of the Company, meet a specific scope exception to the provisions requiring derivative accounting.

On March 9, 2020, each of the noteholders entered into a Conversion Agreement with us and our subsidiary Hudspeth Oil Corporation (“Hudspeth”), under which the noteholders elected to convert the notes, in accordance with their terms, into an aggregate 6% working interest (of all such holders) in the “Orogrande Project.” Principal of $6,000,000 and approximately $1,331,000 of accrued interest were converted at March 9, 2020.

The Conversion Agreements also provided additional consideration to the noteholders including a limited carry, a top-off obligation of Meta or Hudspeth, and warrants to purchase a total of 750,000 restricted shares of TERI common stock, which warrants will have a term of five years and an exercise price of $0.70 per share. The limited carry provides that for the remainder of the 2020 calendar year, Hudspeth will pay all costs and expenses attributable to the assigned working interests, except where prohibited by law or regulation. The top-off obligation provides that, subject to the terms and conditions of the Conversion Agreements, if (a) Hudspeth sells the entire working interest in the Orogrande Project, (b) as part of such sale, the holders’ entire working interests are sold, and (c) the gross proceeds received by all the holders in such transaction are equal to less than $9,000,000; then Meta or Hudspeth must pay the holders an amount equal to $9,000,000, (i) less gross proceeds the holders received in the transaction, (ii) less the amount of the carry the holders received under the Conversion Agreements, and (iii) less any gross proceeds the holders received in any farmouts occurring prior to the transaction.

The transaction was treated as an extinguishment of debt by TERI.

F-18

Convertible Notes Issued in First Quarter 2019

On February 11, 2019 TERI raised a total of $2,000,000 from investors through the sale of two 14% Series D Unsecured Convertible Promissory Notes. Principal was payable in a lump sum at maturity on May 11, 2020 with payments of interest payable monthly at the rate of 14% per annum. Holders of the notes had the right to convert principal and interest at any time into common stock of TERI at a conversion price of $1.08 per share. TERI had the right to redeem the notes at any time, provided that the redemption amount must include all interest that would have been earned through maturity. TERI evaluated the notes for beneficial conversion features and derivative accounting criteria and concluded that derivative accounting treatment was not applicable.

On April 21, 2020, TERI entered into agreements to amend the two 14% Series D Unsecured Convertible Promissory Notes that were originally issued on February 11, 2019. Under the amendment agreements, (a) the maturity dates were extended from May 11, 2020 to November 11, 2021, (b) the conversion price under which the noteholders may convert into our common stock was changed from $1.08 to $0.43, and (c) the noteholders were provided the right, at each noteholder’s election, to convert their notes into either (i) a working interest in the Orogrande Project at the rate of one acre per $1,100 of principal and unpaid interest converted, or (ii) a working interest in the Hazel Project at the rate of one acre per $1,300 of principal and unpaid interest converted; provided, that the noteholders’ right to convert into either such working interest is subject to approval of the collateral agent of the Note Amendment Agreement with the Straz parties.

Under the note amendments, the noteholders agreed to forebear demand or collection on all interest payments due and payable under the Note, including any past due interest payments, for 20 days after the execution of the Note Amendment Agreement. Further, we agreed to (a) issue each holder 20,000 restricted shares of common stock immediately and (b) pay each holder a fee of $10,000, at the same time as the payment of past due interest is paid. The past due interest and fee was paid.

These two promissory notes required monthly payments of interest only at the rate of 14% per annum, with a balloon payment of the outstanding principal due and payable at maturity.

These notes payable have been converted into TERI common stock. $1,000,000 was converted in December 2020 and the remaining $1,000,000 was converted in April 2021.

Convertible Notes Issued in Fourth Quarter 2019

Effective October 31, 2019, TERI issued 10% unsecured convertible promissory notes in the amount of $540,000. Principal and interest were due at maturity on December 3, 2020. The principal and accrued interest on the notes were convertible into shares of common stock at $0.75 per common share at any time after the original issue date. The notes were alternatively convertible, at the election of the holders, into an aggregate 0.367% working interest in our Orogrande Project.

These convertible notes were retired by conversion into TERI common stock in December 2020.

10. NOTE PAYABLE, RELATED PARTY

In 2021, the Company entered into a note payable with Meta to borrow up to $15 million. On October 1, 2021, the Company issued a secured, revolving promissory note in an original principal amount of up to $15 million in favor of Meta (the “2021 Note”). The 2021 Note bears interest at 8% per annum, computed on the basis of a 360-day year, and matures March 31, 2023 (the “2021 Note Maturity Date”); provided, however, if we raise $30 million or more in capital through debt or equity or a combination thereof by the 2021 Note Maturity Date, the 2021 Note Maturity Date will be extended to September 30, 2023, and the outstanding principal of the 2021 Note will amortize in six equal, monthly installments. If an event of default has occurred and is continuing, interest on the 2021 Note may accrue at the default rate of 12% per annum. The outstanding principal of the 2021

F-19

Note, together with all accrued interest thereon, becomes due on the 2021 Note Maturity Date. The 2021 Note includes a restrictive covenant that, subject to certain exceptions and qualifications, restricts the Company’s ability to merge or consolidate with another person or entity, or sell or transfer all or substantially all of its assets, unless the Company is the surviving entity or the successor entity assumes all of obligations under the 2021 Note. The note payable is collateralized by shares of common stock in Meta held by one of its stockholders, Wolfbone Investments, LLC, and by a lien on a 25% interest in the Orogrande prospect.

The balance on the loan as of December 31, 2021 is $12,500,000 and the Company incurred interest that is paid in kind of $208,889 for the year ended December 31, 2021. The Company subsequently drew the additional $2,500,000 on the note payable in 2022.

11. ASSET RETIREMENT OBLIGATIONS

The following is a reconciliation of the asset retirement obligations liability through December 31, 2021:

Asset retirement obligations—December 31, 2020	$	21,844
Accretion expense		93
Estimated liabilities recorded		—
Liability reduction at sale of property		—
Asset retirement obligations—December 31, 2021	$	21,937

12. SUBSEQUENT EVENTS

In July 2022, the Company issued 165,523,362 shares of its common stock to Meta.

On April 14, 2022, May 4, 2022, May 12, 2022, May 26, 2022, June 1, 2022, June 13, 2022, June 28, 2022, August 11, 2022 and August 29, 2022, respectively, the Company borrowed as advances to be subject to a loan agreement between the Company and Meta an aggregate amount of borrowings equal to $5.0 million, bearing interest at a per annum rate equal to 8% and which become due and payable on March 31, 2023. See Note 12 of the accompanying notes to the unaudited condensed consolidated financial statements included elsewhere in this prospectus.

F-20

NEXT BRIDGE HYDROCARBONS, INC.

UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS

	June 30, 2022			December 31, 2021
ASSETS
Current assets:
Cash	$	998,260		$	1,989,419
Accounts receivable, related party		165,238			163,366
Grants and other receivables		50,970			74,310
Prepaid expenses		9,677			2,667
Total current assets		1,224,145			2,229,762
Oil and natural gas properties, net		47,155,236			45,663,470
Other assets		25,000			25,000
TOTAL ASSETS	$	48,404,381		$	47,918,232
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
Accounts payable	$	169,760		$	2,828,326
Notes payable, related party		18,137,111			12,708,889
Total current liabilities		18,306,871			15,537,215
Asset retirement obligations		21,937			21,937
Total liabilities		18,328,808			15,559,152
Commitments and contingencies
Stockholder’s equity:
Preferred stock, par value $0.0001; 25,000,000 shares authorized; 0 issued and outstanding		—			—
Common stock, par value $0.001; 500,000,000 and 250,000,000 shares authorized; 1 issued and outstanding		—			—
Additional paid-in capital		100,863,195			100,546,596
Accumulated deficit		(70,787,622	)		(68,187,516	)
Total stockholder’s equity		30,075,573			32,359,080
TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY	$	48,404,381		$	47,918,232

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

F-21

NEXT BRIDGE HYDROCARBONS, INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended June 30, 2022			Three Months Ended June 30, 2021
Oil sales	$	9,688		$	1,692
Natural gas sales		7,716			1,810
Revenue		17,404			3,502
Operating expenses
Lease operating expenses		30,200			(71,440	)
Production and ad valorem tax		1,253			248
General and administrative		1,162,957			4,202,008
Depreciation, depletion and amortization		—			421
Total operating expenses		1,194,410			4,131,237
Other income (expense)
Interest expense		(300,000	)		(1,394	)
Interest income		157			1,462
Total other income (expense) – net		(299,843	)		1,068
Loss before income taxes		(1,476,849	)		(4,126,667	)
Provision for income tax		—			—
Net loss	$	(1,476,849	)	$	(4,126,667	)

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

F-22

NEXT BRIDGE HYDROCARBONS, INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

	Six Months Ended June 30, 2022			Six Months Ended June 30, 2021
Oil sales	$	9,688		$	2,858
Natural gas sales		7,716			3,115
Revenue		17,404			5,973
Operating expenses
Lease operating expenses		40,821			38,309
Production and ad valorem tax		1,253			426
General and administrative		1,988,694			5,236,601
Depreciation, depletion and amortization		—			935
Total operating expenses		2,030,768			5,276,271
Other income (expense)
Interest expense		(587,222	)		(3,312	)
Gain on extinguishment of debt		—			77,477
Interest income		480			1,919
Total other income (expense) - net		(586,742	)		77,084
Loss before income taxes		(2,600,106	)		(5,193,214	)
Provision for income tax		—			—
Net loss	$	(2,600,106	)	$	(5,193,214	)

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

F-23

NEXT BRIDGE HYDROCARBONS, INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

	Common stock shares		Common stock amount		Additional paid-in capital			Accumulated deficit			Total
Three Months Ended June 30, 2021 Balance, March 30, 2021		1	$	—	$	104,169,630		$	(61,015,255	)	$	43,154,375
Distributions to parent		—		—		(4,503,794	)		—			(4,503,794	)
Net loss		—		—		—			(4,126,667	)		(4,126,667	)
Balance, June 30, 2021		1	$	—	$	99,665,836		$	(65,141,922	)	$	34,523,914
Three Months Ended June 30, 2021 Balance, March 30, 2022		1	$	—	$	100,864,388		$	(69,310,773	)	$	31,553,615
Distributions to parent		—		—		(1,193	)		—			(1,193	)
Net loss		—		—		—			(1,476,849	)		(1,476,849	)
Balance, June 30, 2022		1	$	—	$	100,863,195		$	(70,787,622	)	$	30,075,573

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

F-24

NEXT BRIDGE HYDROCARBONS, INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

	Common stock shares		Common stock amount		Additional paid-in capital		Accumulated deficit			Total
Balance, December 31, 2020		1	$	—	$	88,267,685	$	(59,948,708	)	$	28,318,977
Contributions from parent		—		—		11,398,151		—			11,398,151
Net loss		—		—		—		(5,193,214	)		(5,193,214	)
Balance, June 30, 2021		1	$	—	$	99,665,836	$	(66,141,922	)	$	34,523,914
Balance, December 31, 2021		1	$	—	$	100,546,596	$	(68,187,514	)	$	32,359,080
Contributions from parent		—		—		316,599		—			316,599
Net loss		—		—		—		(2,600,106	)		(2,600,106	)
Balance, June 30, 2022		1	$	—	$	100,863,195	$	(70,787,622	)	$	30,075,573

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

F-25

NEXT BRIDGE HYDROCARBONS, INC.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Six Months Ended June 30, 2022			Six Months Ended June 30, 2021
Cash Flows From Operating Activities
Net loss	$	(2,600,106	)	$	(5,193,214	)
Adjustments to reconcile net loss to net cash from operations:
Depreciation, depletion and amortization		—			935
Paid in kind interest		587,222			—
Change in:
Accounts receivable, related party		(1,872	)		(54,443	)
Grants and other receivables		23,340			110,094
Prepaid expenses		(7,010	)		(219,576	)
Accounts payable		(2,658,566	)		(714,096	)
Accrued liabilities		—			(1,213,779	)
Net cash from operating activities		(4,656,992	)		(5,855,887	)
Cash Flows From Investing Activities
Investment in oil and natural gas properties		(1,491,766	)		(1,713,604	)
Net cash from investing activities		(1,491,766	)		(1,713,604	)
Cash Flows From Financing Activities
Contributions from parent		316,599			11,398,151
Proceeds from notes payable, related party		4,841,000			—
Net cash from financing activities		5,157,599			11,398,151
Net (decrease) increase in cash		(991,159	)		3,828,660
Cash—beginning of period		1,989,419			130,504
Cash—end of period	$	998,260		$	3,959,164
Supplemental disclosure of cash flow information: (Non Cash Items)
Cash paid for interest	$	—		$	—
Cash paid for state franchise tax	$	—		$	—

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

F-26

NEXT BRIDGE HYDROCARBONS, INC.

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. NATURE OF BUSINESS

Next Bridge Hydrocarbons, Inc. (formerly OilCo Holdings, Inc.) (“the Company”, “we”, “our”) was incorporated in August 2021 under the laws of the State of Nevada. We are engaged in the acquisition, exploration and development of oil and natural gas properties in the United States. We operate our business through our subsidiaries Torchlight Energy Inc., Hudspeth Operating, LLC, Hudspeth Oil Corporation, and Torchlight Hazel LLC.

Prior to the formation our subsidiaries were consolidated into Meta Materials Inc., an affiliated company. All intercompany transactions have been eliminated in the consolidated financial statements.

On June 29, 2021, our former parent, Torchlight Energy Resources, Inc. (“TERI”) acquired Metamaterial, Inc., an Ontario corporation, and changed its name to Meta Materials, Inc. (with Metamaterial Inc. being the accounting acquiror).

2. GOING CONCERN

At June 30, 2022, the Company had not yet achieved profitable operations. We had a net loss of $2,600,106 for the six months ended June 30, 2022. We expect to incur further losses in the development of our business. The Company had a working capital deficit as of June 30, 2022 of $17,082,726. These conditions raise substantial doubt about the Company’s ability to continue as a going concern.

The Company’s ability to continue as a going concern is dependent on its ability to generate future profitable operations and/or to obtain the necessary financing to meet its obligations and repay its liabilities arising from normal business operations when they come due. Management’s plan to address the Company’s ability to continue as a going concern includes: (1) obtaining debt or equity funding from private placement, institutional, or public sources; (2) obtain loans from financial institutions, where possible, or (3) participating in joint venture transactions with third parties. Although management believes that it will be able to obtain the necessary funding to allow the Company to remain a going concern through the methods discussed above, there can be no assurances that such methods will prove successful.

These consolidated financial statements have been prepared assuming that the Company will continue as a going concern and therefore, the financial statements do not include any adjustments to reflect the possible future effects on the recoverability and classification of assets or the amount and classifications of liabilities that may result from the outcome of this uncertainty.

3. SIGNIFICANT ACCOUNTING POLICIES

The Company maintains its accounts on the accrual method of accounting in accordance with accounting principles generally accepted in the United States of America. Accounting principles followed and the methods of applying those principles, which materially affect the determination of financial position, results of operations and cash flows are summarized below:

Use of estimates—The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and certain assumptions that affect the amounts reported in these consolidated financial statements and accompanying notes. Actual results could differ from these estimates.

Basis of presentation—The financial statements are presented on a consolidated basis and include all of the accounts of Next Bridge Hydrocarbons, Inc. and its wholly owned subsidiaries, Torchlight Energy, Inc., Hudspeth Operating, LLC, Hudspeth Oil Corporation, and Torchlight Hazel LLC. All significant intercompany balances and transactions have been eliminated.

F-27

These interim financial statements are unaudited and have been prepared pursuant to the rules and regulations of the SEC regarding interim financial reporting. Certain disclosures have been condensed or omitted from these financial statements. Accordingly, they do not include all the information and notes required by accounting principles generally accepted in the United States of America (“GAAP”) for complete consolidated financial statements, and should be read in conjunction with the audited consolidated financial statements and notes thereto included herein for the year ended December 31, 2021.

In the opinion of management, the accompanying unaudited financial condensed consolidated financial statements include all adjustments, consisting of normal recurring adjustments, necessary to fairly present the financial position as of, and the results of operations for, all periods presented. In preparing the accompanying financial statements, management has made certain estimates and assumptions that affect reported amounts in the condensed financial statements and disclosures of contingencies. Actual results may differ from those estimates. The results for interim periods are not necessarily indicative of annual results.

Risks and uncertainties—The Company’s operations are subject to significant risks and uncertainties, including financial, operational, technological, and other risks associated with operating an emerging business, including the potential risk of business failure.

In January 2020, the World Health Organization (“WHO”) announced a global health emergency because of a new strain of coronavirus (“COVID-19”) and the significant risks to the international community and economies as the virus spreads globally beyond its point of origin. In March 2020, the WHO classified COVID-19 as a pandemic, based on the rapid increase in exposure globally, and thereafter, COVID-19 continued to spread throughout the U.S. and worldwide. In addition, actions taken by OPEC members and other exporting nations on the supply and demand in global oil and natural gas markets resulted in significant negative pricing pressure in the first half of 2020, followed by a recovery in pricing and an increase in demand in the second half of 2020 and into 2021. However, multiple variants emerged in 2021 and became highly transmissible, which contributed to additional pricing volatility during 2021 to date. The financial results of companies in the oil and natural gas industry have been impacted materially as a result of changing market conditions. Such circumstances generally increase uncertainty in the Partnership’s accounting estimates. Although demand and market prices for oil and natural gas have recently increased, due to the rising energy use and the improvement in U.S. economic activity, we cannot predict events that may lead to future price volatility and the near term energy outlook remains subject to heightened levels of uncertainty.

We are continuing to closely monitor the overall impact and the evolution of the COVID-19 pandemic, including the ongoing spread of any variants, along with future OPEC actions on all aspects of our business, including how these events may impact our future operations, financial results, liquidity, employees, and operators. Additional actions may be required in response to the COVID-19 pandemic on a national, state, and local level by governmental authorities, and such actions may further adversely affect general and local economic conditions, particularly if the 2021 resurgence and spread of the COVID-19 pandemic continues. We cannot predict the long-term impact of these events on our liquidity, financial position, results of operations or cash flows due to uncertainties including the severity of COVID-19 or any of the ongoing variants, and the effect the virus will have on the demand for oil and natural gas. These situations remain fluid and unpredictable, and we are actively managing our response.

Concentration of risks—At times the Company’s cash balances are in excess of amounts guaranteed by the Federal Deposit Insurance Corporation. The Company’s cash is placed with a highly rated financial institution, and the Company regularly monitors the credit worthiness of the financial institutions with which it does business.

Fair value of financial instruments—Financial instruments consist of cash, receivables, convertible note receivable, payables and promissory notes, if any. The estimated fair values of cash, receivables, and payables approximate the carrying amount due to the relatively short maturity of these instruments. The carrying amounts

F-28

of any promissory notes approximate their fair value giving affect for the term of the note and the effective interest rates.

For assets and liabilities that require re-measurement to fair value the Company categorizes them in a three-level fair value hierarchy as follows:

• Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities.

• Level 2 inputs are quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration.

• Level 3 inputs are unobservable inputs based on management’s own assumptions used to measure assets and liabilities at fair value.

A financial asset or liability’s classification within the hierarchy is determined based on the lowest level input that is significant to the fair value measurement.

Cash and cash equivalents – Cash and cash equivalents include certain investments in highly liquid instruments with original maturities of three months or less.

Accounts receivable – Accounts receivable consist of uncollateralized oil and natural gas revenues due under normal trade terms, as well as amounts due from working interest owners of oil and natural gas properties for their share of expenses paid on their behalf by the Company. Management reviews receivables periodically and reduces the carrying amount by a valuation allowance that reflects management’s best estimate of the amount that may not be collectible. As of June 30, 2022 and December 31, 2021, no valuation allowance was considered necessary.

Oil and natural gas properties – The Company uses the full cost method of accounting for exploration and development activities as defined by the Securities and Exchange Commission (“SEC”). Under this method of accounting, the costs of unsuccessful, as well as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to property acquisition, exploration and development activities but does not include any costs related to production, general corporate overhead or similar activities.

Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Oil and natural gas property costs excluded represent investments in unevaluated properties and include non-producing leasehold, geological, and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. The Company allocates a portion of its acquisition costs to unevaluated properties based on relative value. Costs are transferred to the full cost pool as the properties are evaluated over the life of the reservoir. Unevaluated properties are reviewed for impairment at least quarterly and are determined through an evaluation considering, among other factors, seismic data, requirements to relinquish acreage, drilling results, remaining time in the commitment period, remaining capital plan, and political, economic, and market conditions.

Gains and losses on the sale of oil and natural gas properties are not generally reflected in income unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves. Sales of less than 100% of the Company’s interest in the oil and natural gas property are treated as a reduction of the capital cost of the field, with no gain or loss recognized, as long as doing so does not significantly affect the unit-of-production depletion rate. Costs of retired equipment, net of salvage value, are usually charged to accumulated depreciation.

Capitalized interest – The Company capitalizes interest on unevaluated properties during the periods in which they are excluded from costs being depleted or amortized. During the six months ended June 30, 2022 and 2021, the Company capitalized $-0, and $141,048 respectively, of interest on unevaluated properties.

F-29

Depreciation, depletion, and amortization – The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of accumulated depreciation, depletion, and amortization (“DD&A”), estimated future development costs and asset retirement costs not included in oil and natural gas properties, less costs excluded from amortization. The depreciable base of oil and natural gas properties is amortized on a unit-of-production method.

Ceiling test – Future production volumes from oil and natural gas properties are a significant factor in determining the full cost ceiling limitation of capitalized costs. Under the full cost method of accounting, the Company is required to periodically perform a “ceiling test” that determines a limit on the book value of oil and natural gas properties. If the net capitalized cost of proved oil and natural gas properties, net of related deferred income taxes, plus the cost of unproved oil and natural gas properties, exceeds the present value of estimated future net cash flows discounted at 10 percent, net of related realizable tax affects, plus the cost of unproved oil and natural gas properties, the excess is charged to expense and reflected as additional accumulated DD&A. The Company recorded an impairment expense of $-0- for the six months ended June 30, 2022 and 2021, respectively, to recognize the adjustment required by the ceiling test.

The ceiling test calculation uses a commodity price assumption which is based on the unweighted arithmetic average of the price on the first day of each month for each month within the prior 12-month period and excludes future cash outflows related to estimated abandonment costs.

The determination of oil and natural gas reserves is a subjective process, and the accuracy of any reserve estimate depends on the quality of available data and the application of engineering and geological interpretation and judgment. Estimates of economically recoverable reserves and future net cash flows depend on a number of variable factors and assumptions that are difficult to predict and may vary considerably from actual results. In particular, reserve estimates for wells with limited or no production history are less reliable than those based on actual production. Subsequent re-evaluation of reserves and cost estimates related to future development of proved oil and natural gas reserves could result in significant revisions to proved reserves. Other issues, such as changes in regulatory requirements, technological advances, and other factors which are difficult to predict could also affect estimates of proved reserves in the future.

Asset retirement obligations – The fair value of a liability for an asset’s retirement obligation (“ARO”) is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made, with the corresponding charge capitalized as part of the carrying amount of the related long-lived asset. The liability is accreted to its then-present value each subsequent period, and the capitalized cost is depleted over the useful life of the related asset. Abandonment costs incurred are recorded as a reduction of the ARO liability.

Inherent in the fair value calculation of an ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement, and changes in the legal, regulatory, environmental, and political environments. To the extent future revisions to these assumptions impact the fair value of the existing ARO liability, a corresponding adjustment is made to the oil and natural gas property balance. Settlements greater than or less than amounts accrued as ARO are recorded as a gain or loss upon settlement.

Income taxes – Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss carry forwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.

F-30

Authoritative guidance for uncertainty in income taxes requires that the Company recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an examination. Management has reviewed the Company’s tax positions and determined there were no uncertain tax positions requiring recognition in the consolidated financial statements. Company tax returns remain subject to Federal and State tax examinations. Generally, the applicable statutes of limitation are three to four years from their respective filings.

Estimated interest and penalties related to potential underpayment on any unrecognized tax benefits are classified as a component of tax expense in the statements of operation. The Company has not recorded any interest or penalties associated with unrecognized tax benefits for any periods covered by these financial statements.

Revenue recognition – The Company’s revenue is typically generated from contracts to sell natural gas, crude oil or NGLs produced from interests in oil and natural gas properties owned by the Company. Contracts for the sale of natural gas and crude oil are evidenced by (1) base contracts for the sale and purchase of natural gas or crude oil, which document the general terms and conditions for the sale, and (2) transaction confirmations, which document the terms of each specific sale. The transaction confirmations specify a delivery point which represents the point at which control of the product is transferred to the customer. The Company elects to treat contracts to sell oil and natural gas production as normal sales, which are then accounted for as contracts with customers. The Company has determined that these contracts represent multiple performance obligations which are satisfied when control of the commodity transfers to the customer, typically through the delivery of the specified commodity to a designated delivery point.

Revenue is measured based on consideration specified in the contract with the customer, and excludes any amounts collected on behalf of third parties. The Company recognizes revenue in the amount that reflects the consideration it expects to be entitled to in exchange for transferring control of those goods to the customer. Amounts allocated in the Company’s price contracts are based on the standalone selling price of those products in the context of long-term contracts. Payment is generally received one or two months after the sale has occurred.

Gain or loss on derivative instruments is outside the scope of ASC 606 and is not considered revenue from contracts with customers subject to ASC 606. The Company may in the future use financial or physical contracts accounted for as derivatives as economic hedges to manage price risk associated with normal sales, or in limited cases may use them for contracts the Company intends to physically settle but do not meet all of the criteria to be treated as normal sales.

Producer Gas Imbalances. The Company applies the sales method of accounting for natural gas revenue. Under this method, revenues are recognized based on the actual volume of natural gas sold to purchasers.

Basic and diluted earnings (loss) per share – Basic earnings (loss) per common share is computed by dividing net income (loss) available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings (loss) per common share is computed in the same way as basic earnings (loss) per common share except that the denominator is increased to include the number of additional common shares that would be outstanding if all potential common shares had been issued and if the additional common shares were dilutive. The calculation of diluted earnings per share excludes 0 shares.

Environmental laws and regulations – The Company is subject to extensive federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their future economic benefit. The Company believes that it is in compliance with existing laws and regulations. The Company accrued no liability as of June 30, 2022 and December 31, 2021.

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Recent accounting pronouncements not yet adopted—

In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which adds a new Topic 326 to the Codification and removes the thresholds that companies apply to measure credit losses on financial instruments measured at amortized cost, such as loans, receivables, and held-to-maturity debt securities. Under current GAAP, companies generally recognize credit losses when it is probable that the loss has been incurred. The revised guidance will remove all recognition thresholds and will require companies to recognize an allowance for credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost that the company expects to collect over the instrument’s contractual life. ASU 2016-13 also amends the credit loss measurement guidance for available-for sale debt securities and beneficial interests in securitized financial assets. The guidance is applicable for fiscal years beginning after December 15, 2019 and interim periods within those years, however, the FASB extended the effective date for smaller reporting companies to fiscal years beginning after December 15, 2022. The Company is currently evaluating the potential impact of the adoption of this standard on its related disclosures.

Other recently issued or adopted accounting pronouncements are not expected to have, or did not have, a material impact on the Company’s financial position or results from operations.

4. OIL & NATURAL GAS PROPERTIES

The following table presents the capitalized costs for oil & natural gas properties of the Company:

	June 30, 2022		December 31, 2021
Evaluated costs subject to amortization	$	—	$	—
Unevaluated costs		47,155,236		45,663,470
Total capitalized costs		47,155,236		45,663,470
Less accumulated depreciation, depletion and amortization		—		—
Total oil and natural gas properties	$	47,155,125	$	45,663,470

Unevaluated costs as of June 30, 2022 and December 31, 2021 include cumulative costs on developing projects including the Orogrande and Hazel projects in West Texas.

The Company periodically adjusts for the separation of evaluated versus unevaluated costs within its full cost pool to recognize the value impairment related to the expiration of, or changes in market value, of unevaluated leases. The impact of reclassifications as they become necessary is to increase the basis for calculation of future period’s depletion, depreciation and amortization which effectively recognizes the impairment on the consolidated statement of operations over future periods. Reclassified costs also become evaluated costs for purposes of ceiling tests and which may cause recognition of increased impairment expense in future periods. The remaining cumulative unevaluated costs which have been reclassified within our full cost pool totals $0 as of June 30, 2022. As of June 30, 2022, evaluated costs are $-0- since we have no proved reserve value associated with our properties.

Due to the volatility of commodity prices, should oil and natural gas prices decline in the future, it is possible that a further write-down could occur. Proved reserves are estimated quantities of crude oil, natural gas, and natural gas liquids, which geological and engineering data demonstrate with reasonable certainty to be recoverable from known reservoirs under existing economic and operating conditions. The independent engineering estimates include only those amounts considered to be proved reserves and do not include additional amounts which may result from new discoveries in the future, or from application of secondary and tertiary recovery processes where facilities are not in place or for which transportation and/or marketing contracts are not in place. Estimated reserves to be developed through secondary or tertiary recovery processes are classified as unevaluated properties.

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Current Projects

We are an energy company engaged in the acquisition, exploration, exploitation and/or development of oil and natural gas properties in the United States. We are primarily focused on the acquisition of early stage projects, the development and delineation of these projects, and then the monetization of those assets once these activities are completed.

Since 2010, our primary focus has been the development of interests in oil and natural gas projects we hold in the Permian Basin in West Texas. We also hold minor interests in certain other oil and natural gas projects in Central Oklahoma that we are in the process of divesting.

As of June 30, 2022, we had interests in three oil and gas projects: the Orogrande Project in Hudspeth County, Texas, the Hazel Project in Sterling, Tom Green, and Irion Counties, Texas, and two wells in Central Oklahoma.

Orogrande Project, West Texas

On August 7, 2014, we entered into a Purchase Agreement with Hudspeth Oil Corporation (“Hudspeth”), McCabe Petroleum Corporation (“MPC”), and Gregory McCabe, Meta’s former Chairman. Mr. McCabe was the sole owner of both Hudspeth and MPC. Under the terms and conditions of the Purchase Agreement, we purchased 100% of the capital stock of Hudspeth which held certain oil and natural gas assets, including a 100% working interest in approximately 172,000 predominately contiguous acres in the Orogrande Basin in West Texas. Mr. McCabe has, at his option, a 10% working interest back-in after payout and a reversionary interest if drilling obligations are not met, all under the terms and conditions of a participation and development agreement among Hudspeth, MPC and Mr. McCabe. Mr. McCabe also holds a 4.5% overriding royalty interest in the Orogrande acreage,—which he obtained prior to, and was not a part of the August 2014 transaction. As of June 30, 2022, leases covering approximately 134,000 acres remain in effect.

Effective March 27, 2017, the property became subject to a DDU Agreement which allows for all 192 existing leases covering approximately 134,000 net acres leased from University Lands to be combined into one drilling and development unit for development purposes. The term of the DDU Agreement expires on December 31, 2023, and the time to drill on the drilling and development unit continues through December 2023. The DDU Agreement also grants the right to extend the DDU Agreement through December 2028 if compliance with the DDU Agreement is met and the extension fee associated with the additional time is paid.

Our drilling obligations include five wells per year in years 2021, 2022 and 2023. The drilling obligations are minimum yearly requirements and may be exceeded if acceleration is desired.

We believe all drilling obligations through June 30, 2022, have been met.

On July 25, 2018, we and Hudspeth entered into a Settlement & Purchase Agreement (the “Settlement Agreement”) with University Founders (and Founders Oil & Gas Operating, LLC, former Operator), Wolfbone and MPC (entities controlled by a related party), which agreement provided for Founders assigning all of its working interest in the oil and gas leases of the Orogrande Project to Hudspeth and Wolfbone equally. Future well capital spending obligations remained the same 50% contribution from Hudspeth and 50% from Wolfbone until such time as the $40.5 million to be spent on the project. Cumulative capital spending did not exceed $40.5 million until after the closing of the Arrangement.

The Company has drilled fourteen test wells in the Orogrande in order to stay in compliance with University Lands D&D Unit Agreement, as well as, to test for potential shallow pay zones and deeper pay zones that may be present on structural plays. Development of the wells continued through the three months ended June 30, 2022, to further capture and document the scientific base in support of demonstrating the production potential of the property.

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On March 9, 2020, holders of certain notes payable by the Company entered into a Conversion Agreement under which the noteholders elected to convert principal of $6,000,000 and approximately $1,331,000 of accrued interest on the notes, in accordance with their terms, into an aggregate 6% working interest (of all such holders) in the Orogrande Project. See Note 9 to these Notes to Unaudited Condensed Consolidated Financial Statements for a discussion of the Conversion Agreement and related contingent liabilities of the Company that become due and payable in the event the Orogrande Project is sold.

Following the Spin-Off, the Company intends to make offers and enter into agreements with one or more of the other current working interest owners in the Orogrande Project (each an “Orogrande Owner” and collectively, the “Orogrande Owners”). The Company anticipates offering the Orogrande Owners shares of Common Stock in exchange for their respective working interest in the Orogrande Project. The Company intends to offer the number of shares of Common Stock necessary such that each participating Orogrande Owner would own the percentage of Common Stock then outstanding in proportion to the percentage owned in the working interest of the Orogrande Project. For illustration purposes, if an Orogrande Owner owns ten percent (10%) of the working interest of the Orogrande Project, and such Orogrande Owner elects to participate and accept out offer of shares of Common Stock, then such Orogrande Owner will be offered ten percent (10%) of the aggregate amount of outstanding shares of Common Stock. The Company’s decision to enter into these transactions will depend on ability of the Company and each Orogrande Owner to negotiate and enter into definitive agreements related to such transaction and the Company’s board of directors receiving an industry-standard fairness opinion from an investment banking firm. One of the Orogrande Owners is Wolfbone Investments LLC, an entity controlled by Gregory McCabe, who will own, directly and indirectly through entities he owns or controls, over 11% of the Common Stock following the Spin-Off, which would increase if the proportionate exchange of working interest for shares of our Common Stock is consummated.

The Orogrande Project ownership as of June 30, 2022 is detailed as follows:

	Revenue Interest			Working Interest
University Lands—Mineral Owner		20.000	%		n/a
ORRI—Magdalena Royalties, LLC, an entity controlled by Gregory McCabe, Meta’s former Chairman		4.500	%		n/a
ORRI—Unrelated Party		0.500	%		n/a
Hudspeth Oil Corporation, a subsidiary of Torchlight Energy Resources Inc.		49.875	%		66.500	%
Wolfbone Investments LLC, an entity controlled by Gregory McCabe, Meta’s former Chairman		18.750	%		25.000	%
Conversion by Note Holders in March, 2020		4.500	%		6.000	%
Unrelated Party		1.875	%		2.500	%
		100.000	%		100.000	%

Hazel Project in the Midland Basin in West Texas

Effective April 4, 2016, TEI acquired from MPC a 66.66% working interest in approximately 12,000 acres in the Midland Basin. A back-in after payout of a 25% working interest was retained by MPC and another unrelated working interest owner.

In October 2016, the holders of all of Torchlight Energy Resources, Inc. then-outstanding shares of Series C Preferred Stock (which were issued in July 2016) elected to convert into a total 33.33% working interest in our Hazel Project, reducing our ownership from 66.66% to a 33.33% working interest.

Acquisition of Additional Interests in Hazel Project

On January 30, 2017, we entered into and closed an Agreement and Plan of Reorganization and a Plan of Merger with an entity which was wholly-owned by Mr. McCabe, which resulted in the acquisition of approximately 40.66% working interest in the 12,000 gross acres, 9,600 net acres, in the Hazel Project.

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Also, on January 30, 2017, the Company entered into and closed a Purchase and Sale Agreement with Wolfbone. Under the agreement, we acquired certain of Wolfbone’s Hazel Project assets, including its interest in the Flying B Ranch #1 well and the 40 acre unit surrounding the well.

Upon the closing of the transactions, our working interest in the Hazel Project increased by 40.66% to a total ownership of 74%.

Effective June 1, 2017, we acquired an additional 6% working interest from unrelated working interest owners increasing our working interest in the Hazel project to 80%, and an overall net revenue interest of 75%.

The Company has drilled seven test wells on the Hazel Project to capture and document the scientific base in support of demonstrating the production potential of the property.

Option Agreement with Masterson Hazel Partners, LP

On August 13, 2020, our subsidiaries Torchlight Energy, Inc. and Torchlight Hazel, LLC (collectively, “Torchlight”) entered into an option agreement (the “Option Agreement”) with Masterson Hazel Partners, LP (“MHP”) and McCabe Petroleum Corporation. Under the agreement, MHP was obligated to drill and complete, or cause to be drilled and completed, at its sole cost and expense, a new lateral well (the “Well”) on our Hazel Project, sufficient to satisfy Torchlight’s continuous development obligations on the southern half of the prospect no later than September 30, 2020. MHP has satisfied this drilling obligation. MHP paid to Torchlight $1,000 as an option fee at the time of execution of the Option Agreement. MHP is entitled to receive, as its sole recourse for the recoupment of drilling costs, the revenue from production of the Well attributable to Torchlight’s interest until such time as it has recovered its reasonable costs and expenses for drilling, completing, and operating the well.

In exchange for MHP satisfying the above drilling obligations, Torchlight granted to MHP the exclusive right and option to perform operations, at MHP’s sole cost and expense, on the Hazel Project sufficient to satisfy Torchlight’s continuous development obligations on the northern half of the prospect. Because MHP exercised this drilling option and satisfied the continuous development obligations on the northern half of the prospect, under the terms of the Option Agreement (as amended in September 2020) MHP had the option to purchase the entire Hazel Project no later than May 31, 2021. Such purchase would be under the terms of a form of Purchase and Sale Agreement included as an exhibit to the Option Agreement, at an aggregate purchase price of $12,690,704 for approximately 9,762 net mineral acres, and not less than 74% net revenue interest (approximately $1,300 per net mineral acre). MHP declined to exercise the Option in 2021.

Hunton Play, Central Oklahoma

Presently, we are producing from one well in the Viking Area of Mutual Interest and one well in Prairie Grove.

5. RELATED PARTY BALANCES

As of June 30, 2022 and December 31, 2021, the Company had a balance of $165,238 and $163,366, respectively, for an account receivable due from McCabe Petroleum Corporation for amounts advanced related to the Orogrande development cost sharing agreement.

6. COMMITMENTS AND CONTINGENCIES

Leases

The Company is subject to a sublease agreement on a month-to-month term for occupancy of its office premises which requires monthly rent payments of $8,300.

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Legal Matters

On January 31, 2020, Torchlight Energy Resources, Inc. and its wholly owned subsidiaries Torchlight Energy, Inc. and Torchlight Energy Operating, LLC were served with a lawsuit brought by Goldstone Holding Company, LLC (Goldstone Holding Company, LLC v. Torchlight Energy, Inc., et al., in the 160th Judicial District Court of Dallas County, Texas). On February 24, 2020, Torchlight Energy Resources, Inc., Torchlight Energy, Inc., and Torchlight Energy Operating, LLC timely filed their answer, affirmative defenses, and requests for disclosure. The suit, which sought monetary relief over $1 million, made unspecified allegations of misrepresentations involving a November 2015 participation agreement and a 2016 amendment to the participation agreement. Torchlight denied the allegations and asserted several affirmative defenses including but not limited to, that the suit is barred by the applicable statute of limitations, that the claims had been released, and that the claims were barred because of contractual disclaimers between sophisticated note parties. Torchlight also asserted counterclaims for attorney fees. On January 14, 2021, Goldstone Holding Company, LLC dismissed its claims without prejudice, leaving Torchlight’s counterclaims for attorney fees as the only pending claim in the case. On February 26, 2021, Torchlight filed a non-suit without prejudice on its counterclaims for attorney fees, leaving no claims in the case. The court signed a final order disposing of the entire case on March 5, 2021. However, Goldstone Holding Company, LLC asked the court to re-instate its claims, and a hearing was held on April 13, 2021. On June 16, 2021, the court signed an order denying the motion to reinstate Goldstone Holding Company’s, LLC’s claims, and the case is closed.

On April 30, 2020, The Company’s wholly owned subsidiary, Hudspeth Oil Corporation, filed suit against Datalog LWT, Inc. d/b/a Cordax Evaluation Technologies. The suit seeks the recovery of approximately $1.4 million in costs incurred as a result of a tool failure during drilling activities on the University Founders A25 #2 well that is located in the Orogrande Field. Working interest owner Wolfbone Investments, LLC, a company owned by Meta’s former Chairman Gregory McCabe, is a co-plaintiff in that action. After the suit was filed, Cordax filed a mineral lien in the amount of $104,500 against the Orogrande Field and has sued the operator and counterclaimed against Hudspeth for breach of contract, seeking the same amount as the lien. The Company has added the manufacturer of one of the tool components that the Company contends was a cause of the tool failure. It was later discovered that Datalog LWT, Inc. d/b/a Cordax Evaluation Technologies forfeited its charter to conduct business in the State of Texas by failing to timely pay its franchise taxes, and the Company added members of the board of directors to the case pursuant to the Texas Tax Code. It was recently disclosed that Datalog LWT, Inc. d/b/a Cordax Evaluation Technologies is the subsidiary of a Canadian parent company, Cordax Evaluation Technologies, Inc., who has also been added to the case. The suit, Hudspeth Oil Corporation and Wolfbone Investments, LLC v. Datalog LWT, Inc. d/b/a Cordax Evaluation Technologies, was filed in the 189^th Judicial District Court of Harris County, Texas. The Company’s current Chairman of the Board filed a special appearance after being served with citation, alleging that he was a Canadian citizen with no meaningful ties to Texas. After discovery was conducted on this issue, the Company filed a nonsuit without prejudice for this Defendant, dismissing him from the case. The remaining parties are currently engaged in preliminary discovery and are scheduling mediation.

On March 18, 2021, Datalog LWT, Inc. d/b/a Cordax Evaluation Technologies filed a lawsuit in Hudspeth County, Texas seeking to foreclose its mineral lien against the Orogrande Field in the amount of $104,500.01 and recover related attorney’s fees. The foreclosure action, Datalog LWT Inc. d/b/a Cordax Evaluation Technologies v. Torchlight Energy Resources, Inc., was filed in the 205th Judicial District Court of Hudspeth County, Texas. We are contesting the lien in good faith and filed a Plea in Abatement on May 10, 2021, seeking a stay in the Hudspeth County lien foreclosure case pending final disposition of the related case currently pending in Harris County, Texas.

On January 3, 2022, a putative securities class action lawsuit was filed in the U.S. District Court for the Eastern District of New York captioned Maltagliati v. Meta Materials Inc., et al., No. 1:21-cv-07203, against Meta, Meta’s former Chief Executive Officer, and Meta’s former Chief Financial Officer, Torchlight’s former Chairman of the Board of Directors, and Torchlight’s former Chief Executive Officer. On January 26, 2022, a

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similar putative securities class action lawsuit was filed in the U.S. District Court for the Eastern District of New York captioned McMillan v. Meta Materials Inc., et al., No. 1:22-cv-00463. The McMillan complaint names the same defendants and asserts the same claims on behalf of the same purported class as the Maltagliati complaint. The complaints, purportedly brought on behalf of all purchasers of our publicly traded securities from September 21, 2020 through and including December 14, 2021, assert claims under Sections 10(b) and 20(a) of the Exchange Act arising primarily from a short-seller report and statements related to our business combination with Torchlight. The complaints seek unspecified compensatory damages and reasonable costs and expenses, including attorneys’ fees. On April 11, 2022, the Court held a hearing on motions to consolidate the two actions and to appoint a lead plaintiff or lead plaintiffs, but has not yet ruled on the motions.

On January 14, 2022, a shareholder derivative action was filed in the U.S. District Court for the Eastern District of New York captioned Hines v. Palikaras, et al., No. 1:22-cv-00248. The complaint names as defendants certain of Meta’s current officers and directors, certain former Torchlight officers and directors, and us (as nominal defendant). The complaint, purportedly brought on behalf of Meta, asserts claims under Section 14(a) of the Exchange Act, contribution claims under Sections 10(b) and 21D of the Exchange Act, and various state law claims such as breach of fiduciary duties and unjust enrichment. The complaint seeks, among other things, unspecified compensatory damages in favor of Meta, certain corporate governance related actions, and an award of costs and expenses to the derivative plaintiff, including attorneys’ fees. On March 9, 2022, the Court entered a stipulated order staying this action until there is a ruling on a motion to dismiss in the Securities Class Action.

Environmental Matters

The Company is subject to contingencies as a result of environmental laws and regulations. Present and future environmental laws and regulations applicable to the Company’s operations could require substantial capital expenditures or could adversely affect its operations in other ways that cannot be predicted at this time. As of June 30, 2022 and December 31, 2021, no amounts had been recorded because no specific liability has been identified that is reasonably probable of requiring the Company to fund any future material amounts.

7. STOCKHOLDERS’ EQUITY

Next Bridge Hydrocarbons, Inc. has preferred and common stock both at a par value of $.0001. As of June 30, 2022, the Company has issued 1 share of common stock and 0 shares of preferred stock.

8. INCOME TAXES

The Company recorded no income tax provision at June 30, 2022 and December 31, 2021 because of losses incurred.

The Company estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which it operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the quarter in which they occur. The Company recorded no income tax expense for the six months ended June 30, 2022 because the Company expects to incur a tax loss in the current year. Similarly, no income tax expense was recognized for the six months ended June 30, 2021.

The Company had a net deferred tax asset related to federal net operating loss carryforwards of $65,730,932 and $59,481,861 at June 30, 2022 and December 31, 2021, respectively. The federal net operating loss carryforward will begin to expire in 2033. Realization of the deferred tax asset is dependent, in part, on generating sufficient taxable income prior to expiration of the loss carryforwards. The Company has placed a 100% valuation allowance against the net deferred tax asset because future realization of these assets is not assured.

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9. PROMISSORY NOTES

Certain assets of the Company were used as collateral for promissory notes entered into by TERI.

Promissory Notes Issued in 2017

On April 10, 2017, TERI sold two 12% unsecured promissory notes with a total of $8,000,000 in principal amount to the Straz Foundation and the Straz Trust in a private transaction. Interest only was due and payable on the notes each month at the rate of 12% per annum, with a balloon payment of the outstanding principal due and payable at maturity on April 10, 2020. The holders of the notes also received annual payments of common stock in TERI at the rate of 2.5% of principal amount outstanding, based on a volume-weighted average price. Both notes were sold at an original issue discount of 94.25% and accordingly, TERI received total proceeds of $7,540,000 from the investors. TERI used the proceeds for working capital and general corporate purposes, which includes, without limitation, drilling capital, lease acquisition capital and repayment of prior debt.

The effective interest rate was 16.15%.

On February 20, 2020, the TERI extended the maturity on $4 million of the 12% unsecured promissory notes previously due in April 2020. The maturity date of the subject promissory note had been extended for one year, from April 10, 2020, to April 10, 2021.

During the quarter ended March 31, 2021, the notes were retired in full by conversion into TERI’s common stock.

Promissory Notes Issued in 2018

On February 6, 2018, TERI sold to the Straz Trust in a private transaction a 12% unsecured promissory note with a principal amount of $4,500,000. Interest only was due and payable on the note each month at the rate of 12% per annum, with a balloon payment of the outstanding principal due and payable at maturity on April 10, 2020. The holder of the note also received annual payments of common stock in TERI at the rate of 2.5% of principal amount outstanding, based on a volume-weighted average price. TERI sold the note at an original issue discount of 96.27% and accordingly, TERI received total proceeds of $4,332,150 from the investor. TERI used the proceeds for working capital and general corporate purposes, which includes, without limitation, drilling capital, lease acquisition capital and repayment of prior debt.

The effective interest rate was 15.88%.

During the quarter ended March 31, 2021, the notes were retired in full by conversion into TERI’s common stock.

Extension of Promissory Notes

On April 24, 2020, TERI entered into a Note Amendment Agreement with each of the Straz Foundation, as a lender, the Straz Trust, as a lender and collateral agent, and The Northern Trust Company and Christopher M. Straz, as co-trustees of the Straz Trust. Under the Note Amendment Agreement, the parties agreed to amend and restate the two promissory notes issued to the Straz Trust on April 10, 2017 and February 6, 2018 that have total principal outstanding of $8,500,000, along with the promissory note issued to the Straz Foundation on April 10, 2017 which had an outstanding principal amount of $4,000,000. Under the Note Amendment Agreement, the maturity dates of the two promissory notes held by the Straz Trust and the Note held by the Foundation were extended to April 10, 2021. TERI had previously extended the maturity date of the promissory note held by the Straz Foundation to April 10, 2021.

Under the Note Amendment Agreements, we and our subsidiaries provided a first priority lien on certain collateral in favor of the collateral agent for the benefit of the lenders. The collateral includes all assets and

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property held by Hudspeth Oil Corporation and Torchlight Hazel, LLC, which includes without limitation our working interest in certain oil and gas leases in Hudspeth County, Texas, known as the “Orogrande Project” and our working interest in certain oil and gas leases in the Midland Basin in West Texas, known as the “Hazel Project.” Further, we and TERI, provided guaranty with respect to payment of the three promissory notes. The Note Amendment Agreements also provided restrictions on the use of proceeds if the Orogrande Project or the Hazel Project were sold.

Additionally, the promissory notes, as amended, provided conversion rights whereby the lenders have the right, at each such lender’s option, to convert any portion of principal and interest into shares of common stock of TERI at a conversion price of $1.50 per share.

These notes payable issued in 2017 and 2018 totaling $12,500,000 were retired by conversion into TERI common stock in 2021.

Convertible Notes Issued in October 2018

On October 17, 2018, TERI sold to certain investors in a private transaction 16% Series C Unsecured Convertible Promissory Notes with a total principal amount of $6,000,000. Interest and principal were due and payable on the notes in one balloon payment at maturity on April 17, 2020. The notes were convertible, at the election of the holders, into an aggregate 6% working interest in certain oil and gas leases in Hudspeth County, Texas, known as our “Orogrande Project.” After an analysis of the transaction and a review of applicable accounting pronouncements, management concluded that the notes issued on October 17, 2018 which contained a conversion right for holders to convert into a working interest in the Orogrande Project of the Company, meet a specific scope exception to the provisions requiring derivative accounting.

On March 9, 2020, each of the noteholders entered into a Conversion Agreement with us and our subsidiary Hudspeth Oil Corporation (“Hudspeth”), under which the noteholders elected to convert the notes, in accordance with their terms, into an aggregate 6% working interest (of all such holders) in the “Orogrande Project.” Principal of $6,000,000 and approximately $1,331,000 of accrued interest were converted at March 9, 2020.

The Conversion Agreements also provided additional consideration to the noteholders including a limited carry, a top-off obligation of Meta or Hudspeth, and warrants to purchase a total of 750,000 restricted shares of TERI common stock, which warrants will have a term of five years and an exercise price of $0.70 per share. The limited carry provides that for the remainder of the 2020 calendar year, Hudspeth will pay all costs and expenses attributable to the assigned working interests, except where prohibited by law or regulation. The top-off obligation provides that, subject to the terms and conditions of the Conversion Agreements, if (a) Hudspeth sells the entire working interest in the Orogrande Project, (b) as part of such sale, the holders’ entire working interests are sold, and (c) the gross proceeds received by all the holders in such transaction are equal to less than $9,000,000; then Meta or Hudspeth must pay the holders an amount equal to $9,000,000, (i) less gross proceeds the holders received in the transaction, (ii) less the amount of the carry the holders received under the Conversion Agreements, and (iii) less any gross proceeds the holders received in any farmouts occurring prior to the transaction.

The transaction was treated as an extinguishment of debt by TERI.

Convertible Notes Issued in First Quarter 2019

On February 11, 2019 TERI raised a total of $2,000,000 from investors through the sale of two 14% Series D Unsecured Convertible Promissory Notes. Principal was payable in a lump sum at maturity on May 11, 2020 with payments of interest payable monthly at the rate of 14% per annum. Holders of the notes had the right to convert principal and interest at any time into common stock of TERI at a conversion price of $1.08 per share. TERI had the right to redeem the notes at any time, provided that the redemption amount must include all interest that would have been earned through maturity. TERI evaluated the notes for beneficial conversion features and derivative accounting criteria and concluded that derivative accounting treatment was not applicable.

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On April 21, 2020, TERI entered into agreements to amend the two 14% Series D Unsecured Convertible Promissory Notes that were originally issued on February 11, 2019. Under the amendment agreements, (a) the maturity dates were extended from May 11, 2020 to November 11, 2021, (b) the conversion price under which the noteholders may convert into our common stock was changed from $1.08 to $0.43, and (c) the noteholders were provided the right, at each noteholder’s election, to convert their notes into either (i) a working interest in the Orogrande Project at the rate of one acre per $1,100 of principal and unpaid interest converted, or (ii) a working interest in the Hazel Project at the rate of one acre per $1,300 of principal and unpaid interest converted; provided, that the noteholders’ right to convert into either such working interest is subject to approval of the collateral agent of the Note Amendment Agreement with the Straz parties.

Under the note amendments, the noteholders agreed to forebear demand or collection on all interest payments due and payable under the Note, including any past due interest payments, for 20 days after the execution of the Note Amendment Agreement. Further, we agreed to (a) issue each holder 20,000 restricted shares of common stock immediately and (b) pay each holder a fee of $10,000, at the same time as the payment of past due interest is paid. The past due interest and fee was paid.

These two promissory notes required monthly payments of interest only at the rate of 14% per annum, with a balloon payment of the outstanding principal due and payable at maturity.

These notes payable have been converted into TERI common stock. $1,000,000 was converted in December 2020 and the remaining $1,000,000 was converted in 2021.

Convertible Notes Issued in Fourth Quarter 2019

Effective October 31, 2019, TERI issued 10% unsecured convertible promissory notes in the amount of $540,000. Principal and interest were due at maturity on December 3, 2020. The principal and accrued interest on the notes were convertible into shares of common stock at $0.75 per common share at any time after the original issue date. The notes were alternatively convertible, at the election of the holders, into an aggregate 0.367% working interest in our Orogrande Project.

These notes payable were retired by conversion into TERI common stock in December 2020.

10. NOTES PAYABLE, RELATED PARTY

In 2021, the Company entered into a note payable with Meta to borrow up to $15 million. On October 1, 2021, the Company issued the 2021 Note, which bears interest at 8% per annum, computed on the basis of a 360-day year, and matures March 31, 2023 (the “2021 Note Maturity Date”); provided, however, if we raise $30 million or more in capital through debt or equity or a combination thereof by the 2021 Note Maturity Date, the 2021 Note Maturity Date will be extended to September 30, 2023, and the outstanding principal of the 2021 Note will amortize in six equal, monthly installments. If an event of default has occurred and is continuing, interest on the 2021 Note may accrue at the default rate of 12% per annum. The outstanding principal of the 2021 Note, together with all accrued interest thereon, becomes due on the 2021 Note Maturity Date. The 2021 Note includes a restrictive covenant that, subject to certain exceptions and qualifications, restricts the Company’s ability to merge or consolidate with another person or entity, or sell or transfer all or substantially all of its assets, unless the Company is the surviving entity or the successor entity assumes all of obligations under the 2021 Note. The note payable is collateralized by certain shares of common stock in Meta held by one of its stockholders, Gregory McCabe, and by a lien on a 25% interest in the Orogrande Project owned by Wolfbone Investments, LLC, an affiliate of Mr. McCabe.

The balance on the loan as of June 30, 2022 and December 31, 2021 is $15,000,000 and $12,500,000, respectively. The Company incurred interest that is paid in kind of $208,889 for the year ended December 31, 2021. The Company incurred interest that is paid in kind of $587,222 for the six months ended June 30, 2022.

F-40

In July 2022, the Company issued 165,523,362 shares of its common stock to Meta.

As of June 28, 2022, the Company borrowed $1.9 million as an advance converted into a term loan under the Loan Agreement (defined below), which was in addition to previously advanced amounts equal to $441,000, and resulted in a total of $2.34 million principal amount outstanding, the proceeds of which were used for working capital and general corporate purposes. The term loans bear interest at a per annum rate equal to 8%. The commitments under the Loan Agreement expire on December 31, 2022. The loans become due and payable on March 31, 2023.

11. ASSET RETIREMENT OBLIGATIONS

The following is a reconciliation of the asset retirement obligations liability through June 30, 2022:

Asset retirement obligations—December 31, 2021	$	21,937
Accretion expense		—
Estimated liabilities recorded		—
Liability reduction at sale of property		—
Asset retirement obligations—June 30, 2022	$	21,937

12. SUBSEQUENT EVENTS

On September 2, 2022, we entered into a loan agreement with Meta, as lender (the “Loan Agreement”) that would govern prior loan amounts advanced to the Company from Meta. As of August 11, 2022 and August 29, 2022, we borrowed an additional $1.2 million and $1.46 million, respectively, the remaining amount available for borrowing under the Loan Agreement, and resulting in a total of $5.0 million principal amount outstanding related to the Loan Agreement, the proceeds of which were used for working capital and general corporate purposes. The term loans under the Loan Agreement bear interest at a per annum rate equal to 8% and mature on March 31, 2023 (the “Maturity Date”); provided, however, if we raise $30 million or more in capital through debt or equity, or a combination thereof by the Maturity Date, the Maturity Date will be extended to October 3, 2023 and the term loan would be amortized in six equal monthly installments. The Loan Agreement includes customary representations and covenants that, subject to exceptions and qualifications, restrict our ability to do certain things, such as: engage in mergers, acquisitions, and asset sales; transact with affiliates; undergo a change in control; incur additional indebtedness; incur liens; make loans and investments; declare dividends or redeem or repurchase equity interests; and enter into certain restrictive agreements. In addition, the Loan Agreement contains customary events of default, mandatory prepayment events and affirmative covenants, including, without limitation, covenants regarding the payment of taxes and other obligations, maintenance of insurance, maintenance of our material properties, reporting requirements, compliance with applicable laws and regulations, and formation or acquisition of new subsidiaries.

F-41

UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

Next Bridge Hydrocarbons, Inc. (the “Company”, “we”, “our”, “Next Bridge”) is a holding company formed to own an interest in, and act as the sole owner of, Torchlight Energy Inc., Hudspeth Operating, LLC, Hudspeth Oil Corporation, and Torchlight Hazel LLC following the Distribution.

The unaudited pro forma condensed combined balance sheet as of June 30, 2022 (the “pro forma balance sheet”), and the unaudited pro forma condensed combined statement of operations for the six months ended June 30, 2022 and the year ended December 31, 2021 (the “pro forma statement of operations,” together with the pro forma balance sheet and the corresponding notes hereto, the “pro forma financial statements”) present the pro forma financial statements of the Company after giving effect to the transfer and assignment to us by Meta of the three subsidiaries described above and the consummation of the Distribution:

The pro forma financial statements have been prepared in accordance with Article 11 of Regulation S-X as amended by the final rule, Release No. 33-10786, “Amendments to Financial Disclosures about Acquired and Disposed Businesses,” using the assumptions set forth in the notes to the pro forma financial statements. The pro forma financial statements have been adjusted to include transaction accounting adjustments in accordance with GAAP, linking the effects of the Distribution to the historical consolidated financial statements of the Company, the accounting predecessor to the Company, and the historical combined financial statements of the Company and its subsidiaries.

Prior to the formation of Next Bridge Hydrocarbons, Inc. (formerly named OilCo Holdings, Inc.), our subsidiaries were consolidated into the financial statements of our parent, Meta Materials Inc. (formerly named Torchlight Energy Resources, Inc. (“TERI”)). All intercompany transactions have been eliminated in the consolidated financial statements of Meta Materials, Inc.

On June 29, 2021, TERI acquired Metamaterial Inc., an Ontario corporation, and changed its name to Meta Materials, Inc. (with Metamaterial Inc. being the accounting acquiror).

The assumptions and estimates used to determine the adjustments are described in the notes to the pro forma financial statements. The final determination of the adjustments will be based on the actuals that exist as of the Distribution Date and, therefore, cannot be made prior to its completion.

The pro forma financial statements have been prepared from the respective historical consolidated financial statements of Next Bridge with respect to the oil and natural gas assets held by Torchlight Energy Inc., Hudspeth Operating, LLC, Hudspeth Oil Corporation, and Torchlight Hazel LLC, adjusted to give pro forma effect to the Distribution. The pro forma statement of operations for the six months ended June 30, 2022 and the year ended December 31, 2021, combine the historical consolidated statements of operations of Next Bridge, giving effect to the Distribution as if it had been consummated on January 1, 2021. The pro forma balance sheet combines the historical consolidated balance sheet of Next Bridge as of June 30, 2022, giving effect to the Distribution as if it had been consummated on June 30, 2022.

The pro forma financial statements are presented to reflect the Distribution and do not represent what the Company’s financial position or results of operations would have been had the Distribution occurred on the dates noted above, nor do they project the financial position or results of operations of the Company following the Distribution. The transaction accounting adjustments are based on available information and certain assumptions that management believes are factually supportable and are expected to have a continuing impact on the Company’s results of operations with the exception of certain non-recurring charges to be incurred in connection with the Distribution, as further described below. In the opinion of management, all adjustments necessary to present fairly the pro forma financial statements have been made.

The Company anticipates that certain non-recurring charges will be incurred in connection with the Distribution. Any such charge could affect the future results of the Company in the period in which such charges are incurred;

F-42

however, these costs are not expected to be incurred in any period beyond 12 months from the Distribution Date. Accordingly, the pro forma statement of operations for the six months ended June 30, 2022 and the year ended December 31, 2021 reflects the effects of these non-recurring charges.

As a result of the foregoing, the accounting adjustments are preliminary and subject to change as additional information becomes available and additional analysis is performed. The transaction accounting adjustments have been made solely for the purpose of providing the pro forma financial statements presented below.

The pro forma financial statements should be read together with “The Spin-Off,” “Capitalization,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Certain Relationships and Related Party Transactions,” and the annual and interim financial statements and accompanying notes thereto of Next Bridge included elsewhere in this Prospectus.

F-43

Next Bridge Hydrocarbons, Inc. and its Subsidiaries

Unaudited Pro Forma Combined Statement of Operations

For the Year Ended December 31, 2021

	Year Ended December 31, 2021			Pro Forma Adjustments			Pro Forma Year Ended December 31, 2021
Oil sales	$	4,675					$	4,675
Natural gas sales		11,229						11,229
Revenue, net		15,904			—			15,904
Operating expenses
Lease operating expenses		75,330						75,330
Production and ad valorem tax		1,001						1,001
General and administrative		8,050,443			2,131,413	(c)		10,181,856
Depreciation, depletion and amortization		4,642						4,642
Total operating expenses		8,131,416			—			10,262,829
Other income (expense)
Interest expense		(212,201	)		(400,000	)(b)		(612,201	)
Gain (loss) on sale of assets		1,000						1,000
Gain on extinguishment of debt		77,477						77,477
Interest income		10,428						10,428
Total other expense—net		(123,296	)		(400,000	)		(523,296	)
Loss before income taxes		(8,238,808	)		(2,531,413	)		(10,770,221	)
Provision for income tax		—
Net loss	$	(8,238,808	)	$	(2,531,413	)		(10,770,221	)
Basic and Diluted EPS	$	(8,238,808	)		(2,531,413	)	$	(.07	)
Weighted average number of common shares outstanding:
Basic and Diluted		1			165,523,362	(a)		165,523,363

F-44

Next Bridge Hydrocarbons, Inc. and its Subsidiaries

Unaudited Pro Forma Combined Statements of Operations

For the Six Months Ended June 30, 2022

	Six Months Ended June 30, 2022			Pro Forma Adjustments			Six Months Ended June 30, 2022
Oil Sales	$	9,688		$	—		$	9,688
Natural gas sales		7,716			—			7,716
Revenue, net		17,404			—			17,404
Operating expenses (income)
Lease operating expenses		40,821			—			40,821
Production and ad valorem tax		1,253			—			1,253
General and administrative		1,988,694			2,131,413	(c)		4,120,107
Total operating expenses		2,030,768			2,131,413			4,162,181
Other income (expense)
Interest expense		(587,222	)		(146,360	)(b)		(733,582	)
Interest income		480			—			480
Total other expense – net		(586,742	)		(146,360	)		(733,102	)
Loss before income taxes		(2,600,106	)		(2,277,773	)		(4,877,879	)
Provision for income tax		—			—			—
Net loss	$	(2,600,106	)	$	(2,277,773	)	$	(4,877,879	)
Basic and Diluted	$	(2,600,106.00	)	$	(0.01	)		(0.03	)
Weighted average number of common shares outstanding:
Basic and Diluted		1			165,523,362	(a)		165,523,363

F-45

Next Bridge Hydrocarbons, Inc. and its Subsidiaries

Unaudited Pro Forma Balance Sheet

As of June 30, 2022

	Historical			Pro Forma Adjustments			Pro Forma
ASSETS
Current assets:
Cash	$	998,260		$	2,659,000	(b)	$	3,657,260
Accounts receivable, related party		165,238						165,238
Grants and other receivables		50,970						50,970
Prepaid expenses		9,677						9,677
Total current assets		1,224,145			2,659,000			3,883,145
Oil and natural gas properties, net		47,155,236						47,155,236
Other assets		25,000						25,000
TOTAL ASSETS	$	48,404,381		$	2,659,000		$	51,063,381
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	169,760		$	1,131,413	(c)	$	1,301,173
Notes payable, related party		18,137,111			3,805,360	(b)		21,942,471
Total current liabilities		18,306,871			4,936,773			23,243,644
Asset retirement obligations		21,937						21,937
Total liabilities		18,328,808			4,936,773			23,265,581
Commitments and contingencies
Stockholders’ equity:
Preferred stock, par value $0.0001; 25,000,000 shares authorized; 0 issued and outstanding		—			—
Common stock, par value $0.001; 500,000,000 and 250,000,000 shares authorized; 1 issued and outstanding		—			16,552	(a)		16,552	(a)
Additional paid-in capital		100,863,195			(16,552	)(a)		100,846,643
Accumulated deficit		(70,787,622	)		(2,277,773	)(b), (c)		(73,065,395	)
Total stockholders’ equity		30,075,573			(2,277,773	)		27,797,800
TOTAL LIABILITIES AND STOCKHOLDERS’ EQUITY	$	48,404,381		$	2,659,000		$	51,063,381

F-46

NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS

NOTE 1—BASIS OF PRESENTATION AND DESCRIPTION OF TRANSACTIONS

In connection with the Distribution, the Company’s common stock will be distributed to the holders of Meta’s Series A Preferred Stock on a 1:1 basis.

The pro forma financial statements have been prepared in accordance with Article 11 of Regulation S-X as amended by the final rule, Release No. 33-10786, “Amendments to Financial Disclosures about Acquired and Disposed Businesses,” and present the pro forma financial condition and results of operations of the Company based upon the historical financial information of Next Bridge after giving effect to the Distribution and related adjustments set forth in the notes to the pro forma financial statements. The historical consolidated financial statements of Next Bridge were prepared in accordance with U.S. GAAP and shown in U.S. dollars

The pro forma financial statements do not purport to be indicative of the financial position or results of operations of the Company that would have occurred if the Distribution had occurred on the dates indicated, nor are they indicative of Next Bridge’s future financial position or results of operations. In addition, future results may vary significantly from those reflected in such statements due to factors discussed under “Risk Factors” included elsewhere in the Prospectus.

NOTE 2—PRO FORMA ADJUSTMENTS

The pro forma financial statements have been adjusted to reflect the following:

(a) Represents the 165,523,362 shares of the Company’s common stock issued to Meta and distributed to the holders of the Series A Preferred Stock in the Distribution.

(b) Represents the Loan Agreement entered into with Meta, including accrued interest expense. As of August 29, 2022, we borrowed advances converted into term loans under the Loan Agreement in the aggregate amount of $5.0 million, the maximum amount available under the Loan Agreement, the proceeds in each case were used for working capital and general corporate purposes. The term loans bears interest at a per annum rate equal to 8%. The Company and Meta intend to enter into an additional promissory note with an estimated principal balance of $1.0 million in respect of costs and expenses incurred in connection with the Distribution which were paid by Meta on behalf of the Company. The Company may enter into additional credit or note payable agreements with Meta in order to secure financing for operations. The amount of this additional commitment is not known.

(c) Reflects the accrual of non-recurring costs of $1,131,413 related to the Distribution. The Company may also enter into credit arrangements with certain contractors in order to secure financing for ongoing operations. The amount of credit arrangements are not known.

(d) The pro forma amount does not reflect any amounts owed to Meta under the Tax Matters Agreement, including in respect of any taxes incurred by Meta in connection with the Spin-Off. Based on a valuation of the Company’s assets as of June 28, 2021, Meta’s net operating loss (“NOLs”) balance as of June 28, 2021, and certain assumptions relating to the results of Meta’s operations since June 28, 2021 through the end of the taxable year that includes the Spin-Off, limitations imposed under applicable law on the utilization of Meta’s NOLs and the adjusted tax basis of Meta in the Company’s Common Stock, Meta would not be expected to incur a U.S. federal income tax liability in connection with the Spin-Off. Meta’s analysis of the tax impact of the Spin-Off is ongoing, however, and Meta may incur a U.S. federal or state income or other tax liability in connection with the Spin-Off by offsetting any such tax liability with a portion of Meta’s consolidated NOLs. Any such use of Meta’s consolidated NOLs will reduce the aggregate NOLs that the Company would otherwise have retained as shown above in the Company’s interim unaudited financial statements as of June 30, 2022. Based on the current estimated value of the Distribution, Meta is estimating that approximately $6.0 million of these NOLs will be used, and the Company’s NOLs after the Spin-Off will be reduced by a corresponding amount. The Spin-Off has the potential to limit any U.S. federal and state NOLs owned by the Company. The Company has continued to have a full valuation against any deferred tax asset related to these NOLs.

F-47

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

Item 13. Other Expenses of Issuance and Distribution.

The following table sets forth an itemization of all estimated expenses in connection with the issuance and distribution of the securities to be registered:

Item	Amount
Registration Statement filing fee	$	5.11
Accountants fees and expenses		59,000
Legal fees and expenses		1,287,000
Printing		50,000
Transfer and distribution agent fees and expenses		17,500
Miscellaneous		20,000
Total	$	1,433,505.11

Item 14. Indemnification of Directors and Officers.

The Company’s Amended and Restated Articles of Incorporation and Bylaws provide that, to the fullest extent permitted by the laws of the State of Nevada, any officer or director of the Company, who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative, by reason of the fact that he/she is or was or has agreed to serve at the request of the Company as a director, officer, employee or agent of the Company, or while serving as a director or officer of the Corporation, is or was serving or has agreed to serve at the request of the Company as a director, officer, employee or agent (which, for purposes hereof, shall include a trustee, partner or manager or similar capacity) of another corporation, partnership, joint venture, trust, employee benefit plan or other enterprise, or by reason of any action alleged to have been taken or omitted in such capacity. For the avoidance of doubt, the foregoing indemnification obligation includes, without limitation, claims for monetary damages against indemnitee to the fullest extent permitted under Section 78.7502 and 78:751 of the Nevada Revised Statutes as in existence on the date hereof.

The indemnification provided shall be from and against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred by indemnitee or on indemnitee’s behalf in connection with such action, suit or proceeding and any appeal therefrom, but shall only be provided if indemnitee acted in good faith and in a manner indemnitee reasonably believed to be in or not opposed to the best interests of the Company, and, with respect to any criminal action, suit or proceeding, had no reasonable cause to believe indemnitee’s conduct was unlawful.

In the case of any threatened, pending or completed action or suit by or in the right of the Company to procure a judgment in its favor by reason of the fact that he/she is or was a director, officer, employee or agent of the Company, or while serving as a director or officer of the Company, is or was serving or has agreed to serve at the request of the Company as a director, officer, employee or agent of another corporation, partnership, joint venture, trust, employee benefit plan or other enterprise, no indemnification shall be made in respect of any claim, issue or matter as to which indemnitee shall have been adjudged to be liable to the Company unless, and only to the extent that, the Nevada courts or the court in which such action or suit was brought shall determine upon application that, despite the adjudication of liability but in view of all the circumstances of the case, Indemnitee is fairly and reasonably entitled to indemnity for such expenses which the Nevada courts or such other court shall deem proper.

The termination of any action, suit or proceeding by judgment, order, settlement, conviction, or upon a plea of nolo contendere or its equivalent, shall not, of itself, create a presumption that the indemnitee did not act in good

II-1

faith and in a manner which indemnitee reasonably believed to be in or not opposed to the best interests of the Company, and, with respect to any criminal action or proceeding, had reasonable cause to believe that indemnitee’s conduct was unlawful.

To the extent that indemnification for liabilities arising under the Securities Act may be permitted to directors, officers or persons controlling our company pursuant to the foregoing provisions, we have been informed that, in the opinion of the SEC, such indemnification is against public policy as expressed in the Securities Act and is therefore unenforceable. If a claim for indemnification against such liabilities (other than the payment by us of expenses incurred or paid by a director, officer or controlling person of our company in the successful defense of any action, suit or proceeding) is asserted by any of our directors, officers or controlling persons in connection with the securities being registered, we will, unless in the opinion of our counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by us is against public policy as expressed in the Securities Act and will be governed by the final adjudication of that issue.

Item 15. Recent Sales of Unregistered Securities.

None

Item 16. Exhibits and Financial Statement Schedules.

(a) Exhibits.

Exhibit Number	Exhibit Description
2.1	Distribution Agreement between Meta Materials Inc. and Next Bridge Hydrocarbons, Inc.**
3.1	First Amended and Restated Articles of Incorporation of Next Bridge Hydrocarbons, Inc.**
3.2	Amended and Restated By-laws of Next Bridge Hydrocarbons, Inc.**
5.1	Opinion of Woodburn and Wedge**
10.1	Assignment Agreement between Meta Materials Inc. and Next Bridge Hydrocarbons, Inc.**
10.2	Tax Matters Agreement between Meta Materials Inc. and Next Bridge Hydrocarbons, Inc. **
10.3+	Executive Employment Agreement of Chief Executive Officer‡
10.4+	Executive Employment Agreement of President‡
10.5+	Executive Employment Agreement of Chief Financial Officer‡
10.6+	Executive Employment Agreement of Chief Operating Officer‡
10.7+	2022 Equity Incentive Plan of Next Bridge Hydrocarbons, Inc.**
10.8	Purchase & Settlement Agreement, dated August 6, 2018, between Torchlight Energy Resources, Inc., Hudspeth Oil Corporation, Founders Oil & Gas, LLC, Founders Oil & Gas Operating, LLC, Wolfbone Investments, LLC and McCabe Petroleum. Corporation**†
10.9	Purchase Agreement dated April 4, 2016, by and among McCabe Petroleum Corporation, Torchlight Energy Resources, Inc. and Torchlight Energy, Inc.**
10.10	Option Agreement, by and among Torchlight Energy, Inc., Torchlight Hazel, LLC, Masterson Hazel Partners, LP and McCabe Petroleum Corporation, dated August 13, 2020**†

II-2

Exhibit Number	Exhibit Description
10.11	First Amendment to Option Agreement, by and among Torchlight Energy, Inc., Torchlight Hazel, LLC, Masterson Hazel Partners, LP and McCabe Petroleum Corporation, dated September 18, 2020**†
10.12	Second Amendment to Option Agreement, by and among Torchlight Energy, Inc., Torchlight Hazel, LLC, Masterson Hazel Partners, LP and McCabe Petroleum Corporation, dated April 15, 2021**†
10.13	Secured Promissory Note, between Next Bridge Hydrocarbons, Inc., as debtor, and Meta Materials, Inc., as holder, dated October 1, 2021.**
10.14	First Amendment to Secured Promissory Note, between Next Bridge Hydrocarbons, Inc., as debtor, and Meta Materials, Inc., as holder, dated September 2, 2022.**
10.15	Loan Agreement between Meta Materials, Inc. and Next Bridge Hydrocarbons, Inc.**†
10.16	Participation Agreement by and between McCabe Petroleum Corporation, Gregory McCabe and Hudspeth Oil Corporation, dated September 23, 2014*
10.17	Amendment to Participation Agreement, by and between McCabe Petroleum Corporation, Gregory McCabe and Hudspeth Oil Corporation, dated January 5, 2015*
10.18	Second Amendment to Participation Agreement, by and between McCabe Petroleum Corporation, Gregory McCabe and Hudspeth Oil Corporation, dated December 31, 2015*
10.19	Form of Conversion Agreement, dated March 9, 2020, by and between Torchlight Energy Resources, Inc., Hudspeth Oil Corporation and each of the previous holders of 16% Series C Unsecured Convertible Promissory Notes*
21.1	List of subsidiaries of Next Bridge Hydrocarbons, Inc.**
23.1	Consent of BF Borgers, CPA (independent registered public accountant)*
23.2	Consent of Woodburn and Wedge (included in Exhibit 5.1)**
23.3	Consent of Independent Petroleum Engineers*
24.1	Power of Attorney (Included on the Signature Pages to the Registration Statement)**
99.1	Report of Independent Petroleum Engineers*
99.2	Consent of Clifton DuBose, Jr. to be Named as Director**
99.3	Consent of Joseph DeWoody to be Named as Director**
99.4	Consent of Mia Pitts to be Named as Director**
99.5	Consent of Kristin Whitley to be Named as Director**
107	Filing Fee Table**

† Certain exhibits and schedules to this Exhibit have been omitted in accordance with Regulation S-K Item 601(a)(5). The Registrant hereby agrees to furnish a copy of any omitted exhibits and schedules to the SEC upon its request.

‡ To be filed.

+ Indicates a management contract or compensatory plan.

* Filed herewith.

** Previously filed, and incorporated herein by reference.

(b) Financial Statement Schedules

No financial statement schedules are provided because the information called for is not required or is shown either in our consolidated financial statements or notes thereto.

II-3

Item 17. Undertakings.

(a)(1) The undersigned registrant hereby undertakes to file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement: (i) To include any prospectus required by Section 10(a)(3) of the Securities Act of 1933; (ii) To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the SEC pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than 20 percent change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement; and (iii) To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.

(2) The undersigned registrant hereby undertakes that, for the purpose of determining any liability under the Securities Act of 1933, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

(3) The undersigned registrant hereby undertakes to remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

(b) Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act of 1933 and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act of 1933 and will be governed by the final adjudication of such issue.

II-4

SIGNATURES

Pursuant to the requirements of the Securities Act, Next Bridge Hydrocarbons, Inc. has duly caused this amendment to registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the city of Fort Worth, Texas, on October 5, 2022.

NEXT BRIDGE HYDROCARBONS, INC.
By:	/s/ Ken Rice
Name: Ken Rice
Title: Chairman and Chief Financial Officer

SIGNATURES

Pursuant to the requirements of the Securities Act, this registration statement has been signed by the following persons in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Ken Rice Ken Rice	Chairman and Chief Financial Officer	October 5, 2022
* George Palikaras	President, Director	October 5, 2022
* Robert L. Cook	Director	October 5, 2022

*By:	/s/ Ken Rice
	Attorney-in-fact

II-Signature Page

EX-10.16

Exhibit 10.16

LOAN AGREEMENT

dated as of

September 2, 2022

among

NEXT BRIDGE HYDROCARBONS, INC.

TORCHLIGHT ENERGY, INC.

TORCHLIGHT HAZEL, LLC

HUDSPETH OIL CORPORATION

HUDSPETH OPERATING, LLC

as Borrowers

and

META MATERIALS, INC.

as Lender

TABLE OF CONTENTS

		Page
ARTICLE 1 DEFINITIONS
Section 1.01.	Defined Terms		5
Section 1.02.	Terms Generally		17
Section 1.03.	Accounting Terms; GAAP		18
ARTICLE 2 THE LOANS
Section 2.01.	Commitment		18
Section 2.02.	Loans and Borrowings		18
Section 2.03.	Requests for Loans		19
Section 2.04.	Termination and Reduction of Commitments		19
Section 2.05.	Repayment of Loans; Evidence of Debt		19
Section 2.06.	Prepayment of Loans		19
Section 2.07.	Interest		21
Section 2.08.	Withholding of Taxes; Gross-Up		21
Section 2.09.	Payments Generally; Pro Rata Treatment; Sharing of Setoffs		22
Section 2.10.	Continuing Guaranty		22
ARTICLE 3 REPRESENTATIONS AND WARRANTIES
Section 3.01.	Organization; Powers		24
Section 3.02.	Authorization; Enforceability		25
Section 3.03.	Governmental Approvals; No Conflicts		25
Section 3.04.	Financial Condition; No Material Adverse Change		25
Section 3.05.	Properties		25
Section 3.06.	Litigation and Environmental Matters		25
Section 3.07.	Compliance with Laws and Agreements		26
Section 3.08.	Investment Company Status		26
Section 3.09.	Taxes		26
Section 3.10.	ERISA		26
Section 3.11.	Disclosure		26
Section 3.12.	Anti-Corruption Laws and Sanctions		27
Section 3.13.	Plan Assets; Prohibited Transactions		27
Section 3.14.	Margin Regulations		27
Section 3.15.	Solvency		27
ARTICLE 4 CONDITIONS
Section 4.01.	Effective Date		27
Section 4.02.	Each Credit Event		28

ARTICLE 5 AFFIRMATIVE COVENANTS
Section 5.01.	Financial Statements; Ratings Change and Other Information	29
Section 5.02.	Notices of Material Events	30
Section 5.03.	Existence; Conduct of Business	31
Section 5.04.	Payment of Obligations	31
Section 5.05.	Maintenance of Properties; Insurance	32
Section 5.06.	Books and Records; Inspection Rights	32
Section 5.07.	Compliance with Laws	32
Section 5.08.	Use of Proceeds	32
Section 5.09.	Accuracy of Information	32
ARTICLE 6 NEGATIVE COVENANTS
Section 6.01.	Indebtedness	33
Section 6.02.	Liens	33
Section 6.03.	Fundamental Changes	34
Section 6.04.	Dispositions	34
Section 6.05.	Investments, Loans, Advances, Guarantees and Acquisitions	35
Section 6.06.	Swap Agreements	35
Section 6.07.	Restricted Payments	35
Section 6.08.	Transactions with Affiliates	36
Section 6.09.	Restrictive Agreements	36
ARTICLE 7 EVENTS OF DEFAULT
Section 7.01.	Events of Default	36
Section 7.02.	Remedies Upon an Event of Default	38
Section 7.03.	Application of Payments	39
ARTICLE 8 MISCELLANEOUS
Section 8.01.	Notices	39
Section 8.02.	Waivers; Amendments	40
Section 8.03.	Expenses; Limitation of Liability; Indemnity, Etc	40
Section 8.04.	Successors and Assigns	41
Section 8.05.	Survival	42
Section 8.06.	Counterparts; Integration; Effectiveness; Electronic Execution	43
Section 8.07.	Severability	44
Section 8.08.	Right of Setoff	44
Section 8.09.	Governing Law; Jurisdiction; Consent to Service of Process	44
Section 8.10.	WAIVER OF JURY TRIAL	45
Section 8.11.	Headings	45
Section 8.12.	Interest Rate Limitation	45
Section 8.13.	No Fiduciary Duty, etc	46
Section 8.14.	USA PATRIOT Act	46

3

SCHEDULES:

Schedule 2.01A – Commitments

Schedule 3.06 – Disclosed Matters

Schedule 6.01 – Existing Indebtedness

Schedule 6.02 – Existing Liens

Schedule 6.09 – Existing Restrictions

Schedule 8.01 – Addresses

4

Exhibit 10.16

PARTICIPATION AGREEMENT

This Participation Agreement (this “Agreement”), is made and entered into this 4th day of June, 2014 (“Effective Date”), by and between MCCABE PETROLEUM CORPORATION, a Texas Corporation, 500 W. Texas Ave., Ste. 890, Midland, Texas 79701 (“MPC”), GREG MCCABE, INDIVIDUALLY, whose address is 500 W. Texas Ave., Ste. 890, Midland, Texas 79701 (“McCabe”) and HUDSPETH OIL CORPORATION, whose address is 500 W. Texas Ave., Ste. 890, Midland, Texas 79701 (“Hudspeth”). MPC, McCabe and Hudspeth are sometimes hereinafter sometimes hereinafter referred to as the “Parties”).

RECITALS

WHEREAS, McCabe Petroleum Corporation (“MPC”) on behalf of Greg McCabe, Individually (“McCabe”), has informed Hudspeth Oil Corporation (“Hudspeth”) that MPC, as a nominee title holder for the benefit of McCabe, has acquired certain oil & gas leases (the “Leases”) as described on the attached Exhibit A, which leases cover the lands in Hudspeth and El Paso Counties, Texas (said leases insofar as they cover and affect said land shall hereinafter be referred to as the “Contract Acreage”);

WHEREAS, McCabe has agreed to cause MPC to sell and Hudspeth has agreed to purchase the Leases subject to the following terms and conditions; and

NOW, THEREFORE, in consideration of the foregoing and the respective covenants and agreements contained herein, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties, intending to be legally bound, hereby covenant and agree as follows:

I.    PURCHASE, ASSIGNMENT AND JOA

1. Hudspeth agrees to purchase from McCabe and likewise, McCabe agrees to cause MPC to convey and deliver the Leases to Hudspeth. In consideration for the Leases, Hudspeth shall convey and transfer 10,000 shares of common stock (which is 100% of all shares issued and outstanding) to McCabe in the form of a mutually agreeable stock certificate.

2. Hudspeth shall serve as operator of the Contract Acreage under substantially the same terms and provisions of the Joint Operating Agreement (“JOA”) attached as Exhibit B. The well(s) proposed under this Agreement, shall be drilled and produced under the JOA. Any acreage acquired under the AMI, described below, will be added to the Contract Acreage of the JOA. It is agreed that Hudspeth will market all oil and gas from the Contract Acreage or AMI according to industry standards for the benefit of the non-operators.

II.    AREA OF MUTUAL INTEREST

1. The parties to this Agreement hereby create an Area of Mutual Interest (“AMI”), which includes all lands with at least one boarder within two statute miles of the land described in the attached Exhibit A and any acreage in Block G of the University Lands in Hudspeth County or Block 11 or 12, PSL, Hudspeth County. Should any party acquire directly or indirectly any royalty, mineral, leasehold, or other oil and gas interest, or acquire the right to acquire such interest within the AMI, then the party acquiring such interest or right shall within fifteen (15) days of completion of such acquisition, give written notice to all other parties hereto of the acquisition including full particulars of the interest or right acquired, the costs and terms of such acquisition, and an invoice for the notified party’s share of the costs of such acquisition, if any, along with available supporting data. Each of the parties receiving such notice shall then have fifteen (15) days after receipt within which to elect to participate in such acquisition by paying within said fifteen days its proportionate share of the cost thereto as invoiced, if any, and/or participate in the requirement to such acquisition. Provided, however, that if a well, subject to this agreement or otherwise, is drilling in the Contract Acreage within one mile of the acquisition, notice of acquisition shall be given as promptly as possible, and the notice of election shall be given within forty-eight (48) hours of receipt of the notice of acquisition. In this event, the invoices for the non-acquiring parties’ proportionate share shall be mailed as soon as possible, whether with the notice of acquisition or not, and shall be due within fifteen (15) days of receipt. Failure to timely reply and to timely pay invoiced amounts shall, at the acquiring party’s option, be construed and constitute an election not to share in the acquisition. Upon receipt of invoiced costs if any, the acquiring party shall promptly assign to all participating parties their proportionate shares of any acquired lease or interest, said assignment to be without warranty of title, either express or implied, except as to claims of all persons claiming by, through or under the assigning party, but not otherwise.

2. If any party elects not to take its proportionate share of an acquisition, then all parties participating therein shall have the right, but not the obligation, to share such non-participating party’s proportionate share in the proportions that their respective interest bear to the total interest of all parties who elect to participate. The acquiring party shall retain any of such non-participating party’s proportionate share declined by the participating parties. Any interest acquired shall be subject to the JOA but, if less than all parties to the JOA elect to acquire the interest, the interest shall be deemed to be a separate contract area under the JOA.

3. If the oil and gas interest acquired covers lands both inside and outside of the AMI, the acquiring party shall offer the entire oil and gas interest to the other parties hereto. If all of the parties hereto acquire their proportionate shares of the oil and gas interest, the lands lying outside the AMI shall become a part of the Contract Acreage, but the AMI shall not be enlarged.

4. As used in this Article if Project Payout has occurred, then “proportionate share” means 10% of the working interest acquired as to McCabe and 90% of the working interest acquired as to Hudspeth on a heads up basis. If however, Project Payout has not occurred, then the “proportionate share” means 100% working interest is acquired by Hudspeth and McCabe shall have the 10% Back-in rights pursuant to this Agreement on the new acreage.

5. Said AMI shall terminate on December 31, 2017. The provisions of this AMI shall not apply to sales and acquisitions for interests that have previously been acquired by the parties.

III.    BACK IN AFTER PROJECT PAYOUT

1. It is understood and agreed that the Contract Acreage is subject to a reversionary interest (“Back-in”), equal to ten percent (10%) of the interest assigned hereunder and to any interests acquired by Hudspeth under the terms of the AMI, to be exercised by McCabe, at the sole option of McCabe, upon Project Payout. “Project Payout” shall be defined as the point in time when the proceeds of all production from all operations conducted on the Contract Acreage (exclusive of royalty, overriding royalty and taxes chargeable to the working interest) equals the actual cost incurred by Hudspeth in drilling, testing, equipping and the cost of operating the well(s), inclusive of overhead charges (as defined in the COPAS agreement to the JOA), any additional acreage acquisition, and seismic costs. No proceeds from sales of working interests shall ever be included in or characterized as revenues attributable to ownership of the oil and gas leases for purposes of calculating Project Payout under the Agreement, except as described under the Tag Along Provision below.

2. Hudspeth shall furnish McCabe with quarterly statements of the production, income, costs, and expenditures incurred in connection with the operation of the Contract Acreage and any additional acreage pursuant to the AMI defined herein for the preceding quarter, itemized sufficiently to reasonably to fulfil industry standard accounting requirements. McCabe shall have access at all reasonable times during the Project Payout period to review Hudspeth’s books and accounts pertaining to the Project Payout.

3. Upon reaching Project Payout and receipt of the election of McCabe, or payment as applicable, Hudspeth agrees to assign and issue a bill of sale and conveyance (which shall be mutually agreed upon) to McCabe for the interest in the Back-in provided for above in the proportionate interest and rights in the following:

(i) all of right, title and interest in and to Contract Acreage and AMI;

(ii) all other right, title and interest (of whatever kind or character, whether legal or equitable, and whether vested or contingent) of Hudspeth in and to the oil, gas and other minerals in and under or that may be produced from the Contract Acreage and AMI

(including interests in Leases and oil, gas and mineral leases covering such lands, overriding royalties, carried, backin, farmout, farmin, reversionary interest, production payments and net profits interests in such lands or such Leases, and fee mineral interests, fee royalty interests and other interests in such oil, gas and other minerals), whether such lands be described in the Contract Acreage or AMI, even though Hudspeth’s interest in such oil, gas and other minerals may be incorrectly described in, or omitted from, such Contract Acreage or AMI (the Properties described in clause (i) and this clause (ii) being hereinafter called the “Oil and Gas Properties”);

(iii) all rights, titles and interests of Hudspeth in and to, or otherwise derived from, all presently existing and valid oil, gas or mineral unitization, pooling, or communitization agreements, declarations and/or orders and in and to the properties covered and the units created thereby (including all units formed under orders, rules, regulations, or other official acts of any federal, state, or other authority having jurisdiction, voluntary unitization agreements, designations and/or declarations) relating to the properties described in clauses (i) and (ii) above;

(iv) all rights, titles and interests of Hudspeth in and to all presently existing and valid production sales (and sales related) contracts, operating agreements, and other agreements and contracts which relate to the Contract Acreage and the AMI, or which relate to the exploration, development, operation, or maintenance thereof or the treatment, storage, transportation or marketing of production therefrom (or allocated thereto);

(v) all rights, titles and interests of Hudspeth in and to all materials, supplies, machinery, equipment, improvements and other personal property and fixtures (including all wells, wellhead equipment, pumping units, flowlines, tanks, buildings, injection facilities, saltwater disposal facilities, compression facilities, gathering systems, and other equipment), and all easements, rights-of-way, surface leases and other surface rights, all permits and licenses, and all other appurtenances being used or held for use in connection with, or otherwise related to, the exploration, development, operation or maintenance of any of the properties within the Contract Acreage and the AMI in which McCabe and Hudspeth are participating, or the treatment, storage, transportation or marketing of production therefrom (or allocated thereto); and

(vi) all of Hudspeth’s lease files, title files, abstracts and title opinions, division order files, unitization files, contract files, land surveys and maps (including those in electronic or digital format), data sheets, land and mineral owner correspondence, joint operating agreement files, environmental and regulatory files and reports, operational files and engineering, production records, well files, accounting records relating directly to the properties described above (but not including general financial and accounting records), seismic records and surveys (to the extent freely assignable to McCabe without restrictions of any kind), gravity maps, electric logs, geological or geophysical data and records, (to the extent freely assignable to McCabe without restrictions of any kind), paleontological, geochemical and technical files, which relate to the properties described above that Hudspeth have the right, power and authority to sell, transfer, convey or disclose to McCabe.

4. The reversionary working interest will not be burdened by any overrides created subsequent to this Agreement. The effective date of the assignment shall be the first day of the month ensuing after the date of Project Payout.

5. It is further agreed that McCabe shall have the absolute option (which this option shall trump all conflicting provisions herein or in any other agreement), but not the obligation, at any time, to elect to pay his proportionate share of the Project Payout balance to Hudspeth, and the Back-in reserved herein shall become effective upon such payment, at which point the Back-in will convert to a standard working interest.

6. McCabe shall have the absolute right (which such right shall trump any provision herein to the contrary) to assign such Back-in, subject to Hudspeth’s consent, which will not be unreasonably withheld. Hudspeth shall not be required to give notices to or take actions on behalf of such assignee until thirty (30) days after receiving actual notice of such assignment.

7. The Back-In After Payout shall extend to and be binding upon any renewal(s), extension(s), or top lease(s) taken within one (1) year of termination of the underlying interest.

IV.    TAG ALONG AND ACCESS

1. Tag Along Provision: In the event Hudspeth acquires the Interests hereunder and subsequently enters into an agreement or agreements with definitive terms and conditions (the “Definitive Agreements”) to sell, assign or transfer to an unaffiliated third party (the “Prospective Purchaser”) all or a material portion of its ownership rights in the Interests (a “Proposed Transfer”), Hudspeth shall be obligated, as a condition to its being permitted hereunder to make such assignment, to provide the McCabe herein, or McCabe’s successors or assigns (including the back-in interest owners), written notice setting for the material terms and conditions

of such sale, and all other material information in the possession of Hudspeth relating to the Proposed Transfer (the “Tag-Along Notice”). McCabe shall treat the Tag Along Notice and all information included therein as confidential information. From the date of its receipt of the Tag-Along Notice, McCabe shall have ten (10) business days (the “Election Period”) to elect, subject to the terms and conditions of this provision, to sell 100% of its ownership interests in the leases and lands included in such Proposed Transfer, pursuant to a separate Definitive Agreement between the Prospective Purchaser and McCabe (the “Tag-Along Purchase Agreement”) containing the same or substantially similar terms and conditions as the Proposed Transfer (except as modified to account for McCabe’s quantum of interest in the leases and lands).

2. If McCabe elects to participate in the Proposed Transfer pursuant to a Tag-Along Purchase Agreement, it shall deliver to Hudspeth herein, prior to the expiration of the Election Period, written notice of its election to so participate subject to the terms and conditions of this paragraph. Upon receipt by Hudspeth of McCabe’s timely notice, Hudspeth shall promptly inform the Prospective Purchaser that McCabe also desires to sell on the same or substantially the same terms and conditions as Hudspeth and for the same consideration (as adjusted to reflect McCabe’s quantum of interest in the leases and lands included in the Proposed Transfer), 100% of its ownership rights in the leases and lands included in the Proposed Transfer as provided in this paragraph, pursuant to the Tag-Along Purchase Agreement. If a Definitive Agreement regarding the Proposed Transfer between Hudspeth and the Prospective Purchaser is executed, then, except as otherwise provided below, the Prospective Purchaser is obligated to execute a Tag-Along Purchase Agreement with McCabe if McCabe desires to sell on the same terms and conditions and for the same consideration (as adjusted to reflect McCabe’s quantum of interest in the leases and lands included in the Proposed Transfer) as Hudspeth. Provided, however, if the transaction between Hudspeth and the Prospective Purchaser does not close for any reason and the transactions contemplated thereby are not consummated, the Prospective Purchaser is not required to close and consummate the transaction between the Prospective Purchaser and McCabe even if a Tag-Along Purchase Agreement has been executed between such parties. In other words, Prospective Purchaser’s obligation to close pursuant to the Tag-Along Purchase Agreement is subject to the consummation of the transaction between Hudspeth and the Prospective Purchaser. Similarly, if McCabe elects to participate in the Proposed Transfer and executes a Tag-Along Purchase Agreement, but such transaction between McCabe and Prospective Purchaser does not close for any reason (or if the closing is delayed), than at the option of Hudspeth and the Prospective Purchaser, Hudspeth and Prospective Purchaser may nevertheless close on the scheduled closing date(s) and consummate the transactions contemplated by the Definitive Agreements without any obligation or liability to McCabe (except for any liability of the Prospective Purchaser to McCabe under the express terms of the Tag-Along Purchase Agreement for any breach committed by such Prospective Purchaser that gave rise to the failure to close).

3. Notwithstanding anything in this provision to the contrary, in the event that (i) McCabe elects to not participate in a Proposed Transfer, or (ii) McCabe fails to timely elect and notify the Hudspeth of an election to participate within the Election Period, the McCabe shall have no right to participate in or interfere with the Proposed Transfer, and Hudspeth and the Prospective Purchaser may consummate its Proposed Transfer without any obligation or liability to McCabe under this provision.

4. Following the consummation of a Proposed Transfer, and provided that Hudspeth conveys all its right, title and interest to the lands and leases subject to the Proposed Transfer, the provisions of this paragraph shall not apply to the interest purchased by such new party and Hudspeth or McCabe can transfer their respective ownership rights in their remaining lands and leases without any obligation to offer such new party a right to tag-along or participate in such transfer or any Proposed Transfer. However, between Hudspeth and McCabe, the tag-along provision shall continue to apply as to all lands and leases that are not subject to a prior consummated Proposed Transfer.

5. Subject to all applicable trade secret and confidentiality protections, for the sole purpose of evaluating the Proposed Transfer, McCabe, or his appointed representative, will have access to all geologic data regarding this prospect, including, but not limited to, daily drilling reports, electric logs, mud logs, cores, DST’s, pressure tests, and seismic. Greg McCabe, or his appointed representative, will not be denied reasonable access to any location while drilling and completion operations are being conducted. McCabe, or his representative’s, access to be at their sole risk and expense.

V.    INITIAL WELL AND CONTINUOUS DEVELOPMENT CLAUSE

1. Hudspeth shall commence or cause to be commenced actual drilling operations (as defined herein) of a well on the Contract Acreage on or before March 31, 2015 or 90 days after the University Lands Department executes the Drilling and Development Agreement, whichever date is later. The first well (the “Initial Well”) shall be drilled to a depth sufficient to test the Wolfcamp Formation, and the well shall be drilled to completion in good faith and in a good and workmanlike manner.

2. After the Initial Well is completed or abandoned pursuant to this Agreement, Hudspeth shall continue to drill and complete subsequent wells with good-faith prosecution of drilling operations and in a good and workmanlike manner on the Contract Acreage with reasonable diligence and with no lapse of more than one hundred and eighty (180) consecutive days between the completion or abandonment of any well (as determined herein) and the commencement of additional actual drilling operations. This drilling obligation shall continue until wells have been drilled on the Contract Acreage to the maximum density permitted by the rules, regulations, or orders of the by the Railroad Commission of Texas or other controlling governmental agency, or any other agreement, whichever is most controlling. For each well drilled on the Contact Acreage, Hudspeth shall permit

and drill such well to a minimum depth sufficient to test the Wolfcamp Formation. Provided, however, and for the avoidance of doubt, the University Lands will be treated as a single drilling unit for the purposes of calculating the continuous drilling obligation under this Agreement.

3. As used herein, (i) actual drilling operations shall be deemed to have commenced upon the actual entry of the rotating drillbit of a drilling rig capable of achieving the total depth permitted and approved by the Railroad Commission of Texas or other applicable regulatory agency into the soil of the leased premises, or the actual re-entry into an existing wellbore with a drilling or workover rig capable of re-entering such well for the purposes of completing such well in a previously uncompleted and unproduced zone, and (ii) a well shall be deemed to have been either completed or abandoned as follows: (A) three (3) days after a vertically, diagonally or horizontally drilled well reaches total depth, in the event no attempt is made to complete such well as a producer of oil and/or gas (i.e., a dry hole), (B) thirty (30) days after the date the last string of production casing is cemented in a vertically, diagonally or horizontally drilled well (as reflected by the cementing affidavit required to be filed with the Railroad Commission of Texas or other applicable regulatory agency), in the event an attempt is made to complete such well as a producer of oil and/or gas, or (C) thirty (30) days after the date a horizontal drainhole well completed as a producer of oil or gas reaches the total length of its horizontal drainhole(s), if such date is later than the date in (B) above.

4. If Hudspeth does not drill an initial test well or upon cessation of this Initial Well and Continuous Development Clause, this Agreement and all rights in the Contract Acreage shall automatically terminate and automatically revert back to McCabe as to all right, title and interest in any of the lands or leases covered by this Agreement, save and except, any additionally acreage acquired pursuant to the AMI and as to each well on the Contract Acreage then capable of producing oil or gas in paying quantities, the producing or proration unit surrounding the well, as established by the applicable governmental agency, provided that the Hudspeth acreage shall also terminate as to all depths below the base of the deepest producing formation in each well. Within 30 days after a partial or total termination of this Agreement, Hudspeth shall execute and deliver to McCabe, or any person or entity that McCabe designates, a recordable assignment of all lands and leases covered by this Agreement, save and except any additionally acreage acquired pursuant to the AMI and the acreage and depths allocated to each producing or proration unit.

5. It is agreed however, that the Back-in provision and the AMI provision of this Agreement shall survive in perpetuity any partial or total termination of this Agreement due to this Initial Well and Continuous Development Clause.

6. Hudspeth acknowledges the existence of a proposed Unit Development Agreement between Hudspeth and the State of Texas. Such agreement also contains terms and conditions for certain drilling activities to be performed before certain dates. If there is ever a conflict between this Agreement and the Unit Development Agreement, then Hudspeth shall comply with whichever term or condition requires the earlier action.

VI.    INDEMNIFICATION

1. Indemnification from Purchaser. Hudspeth agrees to and shall indemnify, defend (with legal counsel reasonably acceptable to the McCabe) and hold the MPC, McCabe and their respective officers, directors, affiliates, agents, legal counsel, successors and assigns (collectively, the “Seller Group”) harmless at all times after the date of the Agreement from and against any and all actions, suits, claims, demands, debts, liabilities, obligations, losses, damages, costs, expenses, penalties or injury (including reasonable attorney’s fees and costs of any suit related thereto) suffered or incurred by any of Seller Group, arising from any and all suit, action, proceeding, claim or investigation against Seller Group which arises from or which is based upon or pertaining to Hudspeth’s actions after the effective date of this Agreement.

2. Defense of Claims. If any lawsuit enforcement action or any attempt to collect on an alleged liability is filed against any party entitled to the benefit of indemnity hereunder, written notice thereof shall be given to the indemnifying party within ten (10) business days after receipt of notice or other date by which action must be taken; provided that the failure of any indemnified party to give timely notice shall not affect rights to indemnification hereunder except to the extent that the indemnifying party will be prejudiced by such failure. After such notice, the indemnifying party shall be entitled, if it so elects, to take control of the defense and investigation of such lawsuit or action and to employ and engage attorneys of its own choice to handle and defend the same, at the indemnifying party’s cost, risk and expense; and such indemnified party shall cooperate in all reasonable respects, at its cost, risk and expense, with the indemnifying party and such attorneys in the investigation, trial and defense of such lawsuit or action and any appeal arising therefrom; provided, however, that the indemnified party may, at its own cost, participate in such investigation, trial and defense of such lawsuit or action and any appeal arising therefrom. The indemnifying party shall not, without the prior written consent of the indemnified party, effect any settlement of any proceeding in respect of which any indemnified party is a party and indemnity has been sought hereunder unless such settlement of a claim, investigation, suit, or other proceeding only involves a remedy for the payment of money by the indemnifying party and includes an unconditional release of such indemnified party from all liability on claims that are the subject matter of such proceeding.

3. Default of Indemnification Obligation. If an entity or individual having an indemnification, defense and hold harmless obligation, as above provided, shall fail to assume such obligation, then the party or entities or both, as the case may be, to whom such indemnification, defense and hold harmless obligation is due shall have the right, but not the obligation, to assume and maintain such defense (including reasonable counsel fees and costs of any suit related thereto) and to make any settlement or pay any judgment or verdict as the individual or entities deem

necessary or appropriate in such individuals or entities absolute sole discretion and to charge the cost of any such settlement, payment, expense and costs, including reasonable attorneys’ fees, to the entity or individual that had the obligation to provide such indemnification, defense and hold harmless obligation and same shall constitute an additional obligation of the entity or of the individual or both, as the case may be.

VII.    RECORDING FEES

1. Hudspeth and McCabe agree to equally share all of the costs associated with recording all of the various assignments related to this transaction (including the various assignments from predecessors in title that may be necessary to record) in the El Paso and Hudspeth real property records as well as with the University Lands department.

2. Hudspeth shall be entitled to add its proportionate share of such recording costs to the Project Payout amount defined above.

3. If either McCabe or Hudspeth pays the other party’s recording costs, then such party that paid such costs shall be entitled to an adjustment of the Project Payout amount for the amount paid on behalf of the other party.

VIII.    GENERAL PROVISIONS

1. No Partnership or Joint Venture. Nothing in this agreement or the JOA is intended to create and nothing herein or therein shall ever be construed as creating a partnership, joint venture, mining partnership, association or other relationship whereby any party hereto shall ever be held liable for the acts or debts of another. The duties, obligations and liabilities of each of the parties hereto set forth in this agreement shall be several and not joint so that any party shall be liable only for its proportionate share of the duties, obligations and liabilities under the terms of this agreement.

2. Amendment; Waiver. Neither this Agreement nor any provision hereof may be amended, modified or supplemented unless in writing, executed by all the parties hereto. Except as otherwise expressly provided herein, no waiver with respect to this Agreement shall be enforceable unless in writing and signed by the party against whom enforcement is sought. Except as otherwise expressly provided herein, no failure to exercise, delay in exercising, or single or partial exercise of any right, power or remedy by any party, and no course of dealing between or among any of the parties, shall constitute a waiver of, or shall preclude any other or further exercise of, any right, power or remedy.

3. Notices. Any notices or other communications required or permitted hereunder shall be sufficiently given if in writing and delivered in Person or sent by registered or certified mail (return receipt requested) or nationally recognized overnight delivery service, postage pre-paid, addressed as follows, or to such other address has such party may notify to the other parties in writing:

a.   If to the MPC:	Greg McCabe
	500 W. Texas, Suite 1110
	Midland, Texas 79702
b.  If to the Greg McCabe:	Greg McCabe
	500 W. Texas, Suite 1110
	Midland, Texas 79702
c.   If to the Hudspeth:	Greg McCabe
	500 W. Texas, Suite 1110
	Midland, Texas 79702

d. A notice or communication will be effective (i) if delivered in Person or by overnight courier, on the business day it is delivered and (ii) if sent by registered or certified mail, three (3) business days after dispatch.

e. Any party may change its address by sending written notice to all Parties to this Agreement.

4. Severability. Whenever possible, each provision of this Agreement shall be interpreted in such manner as to be effective and valid under applicable law, but if any provision of this Agreement is held to be prohibited by or invalid under applicable law, such provision will be ineffective only to the extent of such prohibition or invalidity, without invalidating the remainder of this Agreement.

5. Assignments. This agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and permitted assigns. This agreement may not be assigned by any party hereto except with the prior written consent of the other party, which consent shall not be unreasonably withheld or delayed, and any such assignment not consented to shall be void and of no force or effect. All assignments, conveyances or any other agreement by any party to this Agreement or their respective successors and permitted assigns transferring any right under this Agreement either express or implied must be made in writing expressly making such transfer of rights conditional and subject to this Agreement.

6. Choice of Law. This Agreement shall be governed by, and construed in accordance with, the laws of the State of Texas without regard to principles of conflict of laws. In any action between or among any of the parties, whether arising out of this Agreement or otherwise, each of the parties irrevocably consents to the exclusive jurisdiction and venue of the federal and state district courts located in Midland County, Dallas County, or Harris County, Texas.

7. Execution. This Agreement may be executed in two or more counterparts, all of which when taken together shall be considered one and the same agreement and shall become effective when counterparts have been signed by each party and delivered to the other party, it being understood that both parties need not sign the same counterpart. In the event that any signature is delivered by facsimile transmission or by e-mail delivery of a “.pdf’ format data file, such signature shall

create a valid and binding obligation of the party executing (or on whose behalf such signature is executed) with the same force and effect as if such facsimile or “.pdf’ signature page were an original thereof.

8. Section Headings. The section and subsection headings in this Agreement are used solely for convenience of reference, do not constitute a part of this Agreement, and shall not affect its interpretation.

9. No Third-Party Beneficiaries. Nothing in this Agreement will confer any third party beneficiary or other rights upon any person (specifically including any employees of the parties) or any entity that is not a party to this Agreement.

10. Further Assurances. Each party covenants that at any time, and from time to time, whether before or after the closing date, it will execute such additional instruments and take such actions as may be reasonably be requested by the other parties to confirm or perfect or otherwise to carry out the intent and purposes of this Agreement.

11. Attorney Review - Construction. In connection with the negotiation and drafting of this Agreement, the parties represent and warrant to each other that they have had the opportunity to be advised by attorneys of their own choice and, therefore, the normal rule of construction to the effect that any ambiguities are to be resolved against the drafting party shall not be employed in the interpretation of this Agreement or any amendments hereto.

12. Time is of the Essence. INTENTIONALLY DELETED.

13. Parties Bound. All the rights and obligations arising under this Agreement will be binding on the parties’ respective successors, heirs, and assigns.

14. Conflicting Terms. In the case of conflict between this agreement and the JOA or any other agreement related in any way to the Contract Acreage or AMI of this Agreement, this Agreement shall control in all cases.

INTENTIONALLY BLANK — SIGNATURE PAGE FOLLOWS

IN WITNESS WHEREOF, this instrument is executed on September 23, 2014, but shall be effective for all purposes on June 4, 2014.

MCCABE PETROLEUM CORPORATION

By: /s/ Greg McCabe

Printed Name: Greg McCabe

Title:	President
GREG MCCABE, INDIVIDUALLY

By: /s/ Greg McCabe

Printed Name: Greg McCabe

Title: NA

HUDSPETH OIL CORPORATION

By: /s/ Greg McCabe

Printed Name: Greg McCabe

Title: President

Exhibit A

University Lands

Hudspeth County, Texas

Tract	UL Lease Number	Recording Information	Block	Section	Effective Date	Acreage
1	115099	138149	A	1	April 10, 2013	686.7
2	115100	138150	A	2	April 10, 2013	686.7
3	115101	138151	A	3	April 10, 2013	686.7
4	115102	138152	A	4	April 10, 2013	686.7
5	115103	138153	A	5	April 10, 2013	686.7
6	115104	138154	A	6	April 10, 2013	686.7
7	115105	138155	A	7	April 10, 2013	686.7
8	115106	138156	A	8	April 10, 2013	686.7
9	115107	138157	A	9	April 10, 2013	686.7
10	115108	138158	A	10	April 10, 2013	686.7
11	115109	138159	A	11	April 10, 2013	686.7
12	115110	138160	A	12	April 10, 2013	686.7
13	115111	138161	A	13	April 10, 2013	686.7
14	115112	138162	A	14	April 10, 2013	686.7
15	115113	138163	A	15	April 10, 2013	686.7
16	115114	138164	A	16	April 10, 2013	686.7
17	115115	138165	A	17	April 10, 2013	686.7
18	115116	138166	A	18	April 10, 2013	686.7
19	115117	138167	A	19	April 10, 2013	686.7
20	115118	138168	A	20	April 10, 2013	686.7
21	115119	138169	A	21	April 10, 2013	686.7
22	115120	138170	A	22	April 10, 2013	686.7
23	115121	138171	A	23	April 10, 2013	686.7
24	115122	138172	A	24	April 10, 2013	686.7
25	115123	138173	A	25	April 10, 2013	686.7
26	115124	138174	A	26	April 10, 2013	686.7
27	115125	138204	A	27	April 10, 2013	686.7
28	115126	138146	A	28	April 10, 2013	686.7
29	115127	138175	A	29	April 10, 2013	686.7
30	115128	138176	A	30	April 10, 2013	686.7
31	115129	138177	A	31	April 10, 2013	686.7
32	115130	138178	A	32	April 10, 2013	686.7
33	115131	138179	A	33	April 10, 2013	686.7
34	115132	138180	A	34	April 10, 2013	686.7
35	115133	138181	A	35	April 10, 2013	686.7
36	115134	138182	A	36	April 10, 2013	686.7
37	115135	138147	A	37	April 10, 2013	686.7
38	115136	138183	A	38	April 10, 2013	686.7

Tract	UL Lease Number	Recording Information	Block	Section	Effective Date	Acreage
39	115137	138184	A	39	April 10, 2013	686.7
40	115138	138185	A	40	April 10, 2013	686.7
41	115139	138186	A	41	April 10, 2013	686.7
42	115140	138187	A	42	April 10, 2013	686.7
43	115141	138188	A	43	April 10, 2013	686.7
44	115142	138189	A	44	April 10, 2013	686.7
45	115143	138190	A	45	April 10, 2013	686.7
46	115144	138191	A	46	April 10, 2013	686.7
47	115145	138192	A	47	April 10, 2013	686.7
48	115146	138193	A	48	April 10, 2013	686.7
49	115147	138194	B	1	April 10, 2013	686.7
50	115148	138195	B	2	April 10, 2013	686.7
51	115149	138196	B	3	April 10, 2013	686.7
52	115150	138197	B	4	April 10, 2013	686.7
53	115151	138198	B	5	April 10, 2013	686.7
54	115152	138199	B	6	April 10, 2013	686.7
55	115153	138200	B	7	April 10, 2013	686.7
56	115154	138201	B	8	April 10, 2013	686.7
57	115155	138202	B	9	April 10, 2013	686.7
58	115156	138203	B	10	April 10, 2013	686.7
59	115157	138205	B	11	April 10, 2013	686.7
60	115158	138206	B	12	April 10, 2013	686.7
61	115159	138207	B	13	April 10, 2013	686.7
62	115160	138208	B	14	April 10, 2013	686.7
63	115161	138209	B	15	April 10, 2013	686.7
64	115162	138210	B	16	April 10, 2013	686.7
65	115163	138211	B	17	April 10, 2013	686.7
66	115164	138212	B	18	April 10, 2013	686.7
67	115165	138213	B	19	April 10, 2013	686.7
68	115166	138214	B	20	April 10, 2013	686.7
69	115167	138215	B	21	April 10, 2013	686.7
70	115168	138216	B	22	April 10, 2013	686.7
71	115169	138217	B	23	April 10, 2013	686.7
72	115170	138218	B	24	April 10, 2013	686.7
73	11.5171	138219	B	25	April 10, 2013	686.7
74	115172	138148	B	26	April 10, 2013	686.7
75	115173	138220	B	27	April 10, 2013	686.7
76	115174	138221	B	28	April 10, 2013	686.7
77	115175	138222	B	29	April 10, 2013	686.7
78	115176	138223	B	30	April 10, 2013	686.7
79	115177	138224	B	31	April 10, 2013	686.7
80	115178	138225	B	32	April 10, 2013	686.7
81	115179	138226	B	33	April 10, 2013	686.7

Tract	UL Lease Number	Recording Information	Block	Section	Effective Date	Acreage
82	115180	138227	B	34	April 10, 2013	686.7
83	115181	138228	B	35	April 10, 2013	686.7
84	115182	138229	B	36	April 10, 2013	686.7
85	115183	138230	B	37	April 10, 2013	686.7
86	115184	138231	B	38	April 10, 2013	686.7
87	115185	138232	B	39	April 10, 2013	686.7
88	115186	138233	B	40	April 10, 2013	686.7
89	115187	138234	B	41	April 10, 2013	686.7
90	115188	138235	B	42	April 10, 2013	686.7
91	115189	138236	B	43	April 10, 2013	686.7
92	115190	138237	B	44	April 10, 2013	686.7
93	115191	138238	B	45	April 10, 2013	686.7
94	115192	138239	B	46	April 10, 2013	686.7
95	115193	138240	B	47	April 10, 2013	686.7
96	115194	138241	B	48	April 10, 2013	686.7
97	115195	138242	E	1	April 10, 2013	686.7
98	115196	138243	E	2	April 10, 2013	686.7
99	115197	138244	E	3	April 10, 2013	686.7
100	115198	138245	E	4	April 10, 2013	686.7
101	115199	138247	E	5	April 10, 2013	686.7
102	115200	138248	E	6	April 10, 2013	686.7
103	115201	138249	E	7	April 10, 2013	686.7
104	115202	138250	E	8	April 10, 2013	686.7
105	115203	138251	E	9	April 10, 2013	686.7
106	115204	138252	E	10	April 10, 2013	686.7
107	115205	138253	E	11	April 10, 2013	686.7
108	115206	138254	E	12	April 10, 2013	686.7
109	115207	138255	E	13	April 10, 2013	686.7
110	115208	138256	E	14	April 10, 2013	686.7
111	115209	138257	E	15	April 10, 2013	686.7
112	115210	138258	E	16	April 10, 2013	686.7
113	115211	138259	E	17	April 10, 2013	686.7
114	115212	138260	E	18	April 10, 2013	686.7
115	115213	138261	E	19	April 10, 2013	686.7
116	115214	138262	E	20	April 10, 2013	686.7
117	115215	138263	E	21	April 10, 2013	686.7
118	115216	138264	E	22	April 10, 2013	686.7
119	115217	138265	E	23	April 10, 2013	686.7
120	115218	138266	E	24	April 10, 2013	686.7
121	115219	138267	E	25	April 10, 2013	686.7
122	115220	138268	E	26	April 10, 2013	686.7
123	115221	138269	E	27	April 10, 2013	686.7
124	115222	138270	E	28	April 10, 2013	686.7

Tract	UL Lease Number	Recording Information	Block	Section	Effective Date	Acreage
125	115223	138271	E	29	April 10, 2013	686.7
126	115224	138272	E	30	April 10, 2013	686.7
127	115225	138273	E	31	April 10, 2013	686.7
128	115226	138274	E	32	April 10, 2013	686.7
129	115227	138275	E	33	April 10, 2013	686.7
130	115228	138276	E	34	April 10, 2013	686.7
131	115229	138277	E	35	April 10, 2013	686.7
132	115230	138278	E	36	April 10, 2013	686.7
133	115231	138279	E	37	April 10, 2013	686.7
134	115232	138280	E	38	April 10, 2013	686.7
135	115233	138281	E	39	April 10, 2013	686.7
136	115234	138282	E	40	April 10, 2013	686.7
137	115235	138283	E	41	April 10, 2013	686.7
138	115236	138284	E	42	April 10, 2013	686.7
139	115237	138285	E	43	April 10, 2013	686.7
140	115238	138286	E	44	April 10, 2013	686.7
141	115239	138287	E	45	April 10, 2013	686.7
142	115240	138288	E	46	April 10, 2013	686.7
143	115241	138289	E	47	April 10, 2013	686.7
144	115242	138290	E	48	April 10, 2013	686.7
145	115243	138291	F	1	April 10, 2013	686.7
146	115244	138292	F	2	April 10, 2013	686.7
147	115245	138293	F	3	April 10, 2013	686.7
148	115246	138294	F	4	April 10, 2013	686.7
149	115247	138295	F	5	April 10, 2013	686.7
150	115248	138296	F	6	April 10, 2013	686.7
151	115249	138297	F	7	April 10, 2013	686.7
152	115250	138298	F	8	April 10, 2013	686.7
153	115251	138299	F	9	April 10, 2013	686.7
154	115252	138300	F	10	April 10, 2013	686.7
155	115253	138301	F	11	April 10, 2013	686.7
156	115254	138302	F	12	April 10, 2013	686.7
157	115255	138303	F	13	April 10, 2013	686.7
158	115256	138304	F	14	April 10, 2013	686.7
159	115257	138305	F	15	April 10, 2013	686.7
160	115258	138306	F	16	April 10, 2013	686.7
161	115259	138307	F	17	April 10, 2013	686.7
162	115260	138308	F	18	April 10, 2013	686.7
163	115261	138309	F	19	April 10, 2013	686.7
164	115262	138310	F	20	April 10, 2013	686.7
165	115263	138311	F	21	April 10, 2013	686.7
166	115264	138312	F	22	April 10, 2013	686.7
167	115265	138313	F	23	April 10, 2013	686.7

Tract	UL Lease Number	Recording Information	Block	Section	Effective Date	Acreage
168	115266	138314	F	24	April 10, 2013	686.7
169	115267	138315	F	25	April 10, 2013	686.7
170	115268	138316	F	26	April 10, 2013	686.7
171	115269	138317	F	27	April 10, 2013	686.7
172	115270	138318	F	28	April 10, 2013	686.7
173	115271	138319	F	29	April 10, 2013	686.7
174	115272	138320	F	30	April 10, 2013	686.7
175	115273	138321	F	31	April 10, 2013	686.7
176	115274	138322	F	32	April 10, 2013	686.7
177	115275	138323	F	33	April 10, 2013	686.7
178	115276	138324	F	34	April 10, 2013	686.7
179	115277	138325	F	35	April 10, 2013	686.7
180	115278	138326	F	36	April 10, 2013	686.7
181	115279	138327	F	37	April 10, 2013	686.7
182	115280	138328	F	38	April 10, 2013	686.7
183	115281	138329	F	39	April 10, 2013	686.7
184	115282	138330	F	40	April 10, 2013	686.7
185	115283	138331	F	41	April 10, 2013	686.7
186	115284	138332	F	42	April 10, 2013	686.7
187	115285	138333	F	43	April 10, 2013	686.7
188	115286	138334	F	44	April 10, 2013	686.7
189	115287	138335	F	45	April 10, 2013	686.7
190	115288	138336	F	46	April 10, 2013	686.7
191	115289	138337	F	47	April 10, 2013	686.7
192	115290	138338	F	48	April 10, 2013	686.7

Cerro Alto Leases

Hudspeth County, Texas

1) Oil and Gas Lease dated December 1, 2012, by and between the State of Texas, acting by and through its agent, Cerro Alto, Ltd., a Texas limited partnership, as Lessor and Clay Johnson, a single man, as Lessee, being recorded in Document No. 20130007975 of the Official Public Records of El Paso County, Texas, and covering the following described lands:

BLOCK 1, PUBLIC SCHOOL LAND SURVEY

All of Sections 1, 2, 3, 10, 11, 12, 13, 14 and 24

2) Oil and Gas Lease dated December 1, 2012, by and between the State of Texas, acting by and through its agent, Cerro Alto, Ltd., a Texas limited partnership, as Lessor and Clay Johnson, a single man, as Lessee, being recorded in Document No. 00000137473 of the Official Public Records of Hudspeth County, Texas and covering the following described lands:

BLOCK 2, PUBLIC SCHOOL LAND SURVEY

All of Sections 2, 3, 4, 5, 6, 7, 9 and 11

3) Oil and Gas lease dated December 1, 2012, by and between the State of Texas, acting by and through its agent, Cerro Alto, Ltd., a Texas limited partnership, as Lessor and Clay Johnson, a single man, as Lessee, being recorded in Document No. 00000137472 of the Official Public Records of Hudspeth County, Texas and covering the following described lands:

BLOCK 4, PUBLIC SCHOOL LAND SURVEY

All of Sections 7, 8, 13, 14 and 15; 635.782 acres out of Section 17, being that portion lying North of Hwy. 62; 251.96 acres out of Section 19, being that portion lying North and West of Hwy. 62; 53.19 acres out of Section 20, being that portion lying North and East of Hwy. 62; and 333.46 acres out of Section 21, being that portion lying North and East of Hwy. 62

4) Oil and Gas Lease dated December 1, 2012, by and between the State of Texas, acting by and through its agent, Cerro Alto, Ltd., as Texas limited partnership, as Lessor and Clay Johnson, a single man, as Lessee, being recorded in Document No. 00000137471 of the Official Public Records of Hudspeth County, Texas and covering the following described lands:

BLOCK 4, PUBLIC SCHOOL LAND SURVEY

All of Sections 1, 2, 3, 4, 5, 6, 9, 10, 11 and 12, less a 653.00 acre tract of land being the description of a portion of the Russell Menzies Survey (Scrap File No. 15240), portion of Sections 1 and 12, Block 4, PSL Survey, Hudspeth County, Texas, and being more particularly described by metes and bounds in that certain General Warranty Deed dated September 9, 2004 from John and Estela Turner Family Limited Partnership to Jobe Concrete Products, Inc., recorded in Volume 251, Page 419, Deed Records, Hudspeth County, Texas.

5) Oil and Gas Lease dated December 1, 2012, by and between the State of Texas, acting by and through its agent, Cerro Alto, Ltd., a Texas limited partnership, as Lessor and Clay Johnson, a single man, as Lessee, being recorded in Document No. 00000137470 of the Official Public Records of Hudspeth County, Texas and covering the following described lands:

BLOCK 3, PUBLIC SCHOOL LAND SURVEY

All of Section 13, 16, 17, 18, 20, 21, 22, 23, and 24, less a 404.49 acre tract of land being the description of a portion of the Russell Menzies Survey (Scrap File No. 15240), portion of Sections 13 and 24, Block 3, PSL Survey, Hudspeth County, Texas, and being more particularly described by metes and bounds in that certain General Warranty Deed dated September 9, 2004 from John and Estela Turner Family Limited Partnership to Jobe Concrete Products, Inc., recorded in Volume 251, Page 419, Deed Records, Hudspeth County, Texas. The East Half of Section 19

BLOCK 3, PUBLIC SCHOOL LAND SURVEY

All of Sections 2, 3, 4, 9, 10, 11, 12, 14 and 15

6) Oil and Gas Lease dated December 1, 2012, by and between the State of Texas, acting by and through its agent, Cerro Alto, Ltd., a Texas limited partnership, as Lessor and Clay Johnson, a single man, as Lessee, being recorded in Document No. 00000137468 of the Official Public Records of Hudspeth County, Texas and covering the following described lands:

BLOCK 2, PUBLIC SCHOOL LAND SURVEY

All of Sections 15, 16, 17, 18, 19, 21, 22, 23 and 24

Exhibit B

A.A.P.L. FORM 610 - 1989

MODEL FORM OPERATING AGREEMENT

OPERATING AGREEMENT

DATED

June 4, 2014

OPERATOR Hudspeth Oil Corporation

CONTRACT AREA Oil and Gas Leases in Hudspeth County, Texas, further described on Exhibit A

COUNTY OR PARISH OF     Hudspeth                , STATE OF      Texas                                                                                                                                    

COPYRIGHT 1989 - ALL RIGHTS

RESERVED AMERICAN

ASSOCIATION OF PETROLEUM

LANDMEN, 4100 FOSSIL CREEK

BLVD. FORT WORTH, TEXAS,

76137, APPROVED FORM.

A.A.P.L. NO. 610 - 1989

A.A.P.L. FORM 610 - MODEL FORM OPERATION AGREEMENT - 1989

TABLE OF CONTENTS

Article		Title	Page
I.	DEFINITIONS			1
II.	EXHIBITS			2
III.	INTERESTS OF PARTIES			3
	A.	Oil and Gas Interests:		3
	B.	Interests of Parties in Costs and Production:		3
	C.	Subsequently Created Interests:		3
IV.	TITLES			3
	A.	Title Examination		3
	B.	Loss or Failure of Title		4
		1.     Failure of Title		4
		2.     Loss by Non-Payment or Erroneous Payment of Amount Due		4
		3.     Other Losses		4
		4.     Curing Title		4
V.	OPERATOR			5
	A.	Designation and Responsibilities of Operator		5
	B.	Resignation or Removal of Operator and Selection of Successor		5
		1.     Resignation or Removal of Operator		5
		2.     Selection of Successor Operator		5
	C.	Employees and Contractors		5
	D.	Rights and Duties of Operator		5
		1.     Competitive Rates and Use of Affiliates		5
		2.     Discharge of Joint Account Obligations		5
		3.     Protection from Liens		5
		4.     Custody of Funds		6
		5.     Access to Contract Area and Records		6
		6.     Filing and Furnishing Governmental Reports		6
		7.     Drilling and Testing Operations		6
		8.     Cost Estimates		6
		9.     Insurance		6
VI.	DRILLING AND DEVELOPMENT			6
	A.	Initial Well		6
	B.	Subsequent Operations		6
		1.     Proposed Operations		6
		2.     Operations by Less Than All Parties		8
		3.     Stand-By Costs		9
		4.     Deepening		10
		5.     Sidetracking		10
		6.     Order of Preference of Operations.		10
		7.     Conformity to Spacing Pattern		11
		8.     Paying Wells.		11
	C.	Completion of Wells; Reworking and Plugging Back		11
		1.     Completion		11
		2.     Rework, Recomplete or Plug Back		11
	D.	Other Operations		11
	E.	Abandonment of Wells		12
		1.     Abandonment of Dry Holes.		12
		2.     Abandonment of Wells That Have Produced		13
		3.     Abandonment of Non-Consent Operations.		13
	F.	Termination of Operations		13
	G.	Taking Production in Kind		13
VII.	EXPENDITURES AND LIABILITY OF PARTIES			14
	A.	Liability of Parties		14
	B.	Liens and Security Interests		15
	C.	Advances		15
	D.	Defaults and Remedies		15
		1.     Suspension of Rights		16
		2.     Suit for Damages		16
		3.     Deemed Non-Consent		16
		4.     Advance Payment		16
		5.     Costs and Attorneys’ Fees		16
	E.	Rentals, Shut-in Well Payments and Minimum Royalties		16
	F.	Taxes		16
VIII.	ACQUISITION, MAINTENANCE OR TRANSFER OF INTEREST			17
	A.	Surrender of Leases		17
	B.	Renewal or Extension of Leases		17
	C.	Acreage or Cash Contributions		17
	D.	Assignment; Maintenance of Uniform Interest		18

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A.A.P.L. FORM 610 - MODEL FORM OPERATION AGREEMENT - 1989

IX.	INTERNAL REVENUE CODE ELECTION		18
X.	CLAIMS AND LAWSUITS		18
XI.	FORCE MAJEURE		19
XII.	NOTICES		19
XIII.	TERM OF AGREEMENT		19
XIV.	COMPLIANCE WITH LAWS AND REGULATIONS		19
	A.	Laws, Regulations and Orders	19
	B.	Governing Law	19
	C.	Regulatory Agencies	19
XV.	MISCELLANEOUS		20
	A.	Execution	20
	B.	Successors and Assigns	20
	C.	Counterparts	20
	D.	Severability	20
XVI.	OTHER PROVISIONS		20

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A.A.P.L. FORM 610 - MODEL FORM OPERATION AGREEMENT – 1989

OPERATING AGREEMENT

THIS AGREEMENT, entered into by and between Hudspeth Oil Corporation                                                          hereinafter designated and referred to as “Operator,” and the signatory party or parties other than Operator, sometimes hereinafter referred to individually as “Non-Operator,” and collectively as “Non-Operators.”

WITNESSETH:

WHEREAS, the parties to this agreement are owners of Oil and Gas Leases and/or Oil and Gas Interests in the land identified in Exhibit “A,” and the parties hereto have reached an agreement to explore and develop these Leases and/or Oil and Gas Interests for the production of Oil and Gas to the extent and as hereinafter provided,

NOW, THEREFORE, it is agreed as follows:

ARTICLE I.

DEFINITIONS

As used in this agreement, the following words and terms shall have the meanings here ascribed to them:

A.    The term “AFE” shall mean an Authority for Expenditure prepared by a party to this agreement for the purpose of estimating the costs to be incurred in conducting an operation hereunder. /An AFE for a Horizontal or Multi-lateral Well shall clearly stipulate that the well being proposed is a Horizontal or Multi-lateral Well and shall include all Completion operations for the proposed Horizontal or Multi-lateral Well.

B.    The term “Completion” or “Complete” shall mean a single operation intended to complete a well as a producer of Oil and Gas in one or more Zones, including, but not limited to, the setting of production casing, perforating, well stimulation and production testing conducted in such operation. / When used in connection with a Horizontal or Multi-lateral Well, the term “Completion or “Complete” shall mean a series of operations within the Lateral(s) intended to complete a well as a producer of Oil and Gas, including, but not limited to, the setting of production casing, perforating, hydraulic fracturing, well stimulation and production testing.

C.    The term “Contract Area” shall mean all of the lands, Oil and Gas Leases and/or Oil and Gas Interests intended to be developed and operated for Oil and Gas purposes under this agreement. Such lands, Oil and Gas Leases and Oil and Gas Interests are described in Exhibit “A.”

D.    The term “Deepen” shall mean a single operation whereby a well is drilled to an objective Zone below the deepest Zone in which the well was previously drilled, or below the Deepest Zone proposed in the associated AFE, whichever is the lesser. / When used in connection with a Multi-lateral or Horizontal Well, the term “Deepen” shall mean an operation, whereby a Lateral is drilled to a horizontal distance greater than the distance set out in the well proposal approved by the Consenting Parties, or to a horizontal distance greater than the horizontal distance to which the lateral was previously drilled.

E.    The terms “Drilling Party” and “Consenting Party” shall mean a party who agrees to join in and pay its share of the cost of any operation conducted under the provisions of this agreement.

F.    The term “Drilling Unit’ shall mean the area fixed for the drilling of one well by order or rule of any state or federal body having authority. If a Drilling Unit is not fixed by any such rule or order, a Drilling Unit shall be the drilling unit as established by the pattern of drilling in the Contract Area unless fixed by express agreement of the Drilling Parties.

G.    The term “Drillsite” shall mean the Oil and Gas Lease or Oil and Gas Interest on which a proposed well is to be located. / The term “Drillsite” when used in connection with a Horizontal or Multi-lateral Well shall mean the surface location and the Oil and Gas Leases or Oil and Gas Interests within the spacing unit on which the wellbores, including all Laterals, are located.

H.    The term “Initial Well” shall mean the well required to be drilled by the parties hereto as provided in Article VI.A.

I.    The term “Non-Consent Well” shall mean a well in which less than all parties have conducted an operation as provided in Article VI.B.2.

J.    The terms “Non-Drilling Party” and “Non-Consenting Party” shall mean a party who elects not to participate in a proposed operation.

K.    The term “Oil and Gas” shall mean oil, gas, casinghead gas, gas condensate, and/or all other liquid or gaseous hydrocarbons and other marketable substances produced therewith, unless an intent to limit the inclusiveness of this term is specifically stated.

L.    The term “Oil and Gas Interests” or “Interests” shall mean unleased fee and mineral interests in Oil and Gas in tracts of land lying within the Contract Area which are owned by parties to this agreement.

M.    The terms “Oil and Gas Lease,” “Lease” and “Leasehold” shall mean the oil and gas leases or interests therein covering tracts of land lying within the Contract Area which are owned by the parties to this agreement.

N.    The term “Plug Back” shall mean a single operation whereby a deeper Zone is abandoned in order to attempt a Completion in a shallower Zone. / When used in connection with a horizontal or Multi-lateral Well, the term “Plug Back” shall mean an operation to test or Complete the well at a stratigraphically shallower geological horizon in which the operation has been or is being Completed and which is not within an existing Lateral. Any operation to reduce the length of any Lateral shall not be considered a Plug-back.

O.    The term “Recompletion” or “Recomplete” shall mean an operation whereby a Completion in one Zone is abandoned in order to attempt a Completion in a different Zone within the existing wellbore. / The term “Recompletion” or “Recomplete” when used in connection with a Horizontal or a Multi-Lateral well shall mean Completion operations within an existing Lateral that are conducted after the original Completion operations in the Horizontal or a Multi-lateral Well are conducted.

P.    The term “Rework” shall mean an operation conducted in the wellbore of a well after it is Completed to secure, restore, or improve production in a Zone which is currently open to production in the wellbore. Such operations include, but are not limited to, well stimulation operations but exclude any routine repair or maintenance work or drilling, Sidetracking, Deepening, Completing, Recompleting, or Plugging Back of a well.

Q.    The term “Sidetrack” shall mean the directional control and intentional deviation of a well from vertical so as to change the bottom hole location unless done to straighten the hole or drill around junk in the hole or to overcome other mechanical difficulties. When used in connection with a Horizontal or Multi-lateral Well, the term “Sidetrack” shall mean the directional control and intentional deviation of a well outside the existing Lateral(s) so as to change the Zone or the radial direction of a Lateral as originally proposed. Drilling operations which are intended recover penetration or the target interval which are conducted in a Horizontal or Multi-lateral well shall be considered as included in the original proposed drifting operations.

R.    The term “Zone” shall mean a stratum of earth containing or thought to contain a common accumulation of Oil and Gas separately producible from any other common accumulation of Oil and Gas.

S.    The term “Lateral” shall mean that portion of a wellbore that deviates from approximate vertical orientation to approximate horizontal orientation and all wellbore beyond such deviation to Total Measured Depth.

T.    The term “Horizontal Well” shall mean a well containing a single Lateral which is drilled, Completed, or Recompleted in a manner in which the horizontal component of the completion interval (1) extends at least one hundred (100’) feet in the objective formation and (2) exceeds the vertical component of the completion interval in the objective formation.

U.    The term “Multi-lateral Well” shall mean a well which contains more than one Lateral which is drilled, Completed or Recompleted in a manner in which the horizontal component of the completion interval of each Lateral (1) extends at least one hundred (100’) feet in the objective formation(s) and (2) exceeds the vertical component of the completion interval in the objective formation(s).

V.    The term “Total Measured Depth” when used in connection with a Multi-lateral or Horizontal Well, shall mean the distance from the surface of the ground to the terminus of the wellbore, as measured along the wellbore. Each Lateral taken together with the common vertical wellbore shall be considered a single wellbore and shall have a corresponding Total Measured Depth. Notwithstanding the foregoing, in the case of a Multi-Lateral Well, if the production from each Lateral is to be commingled in the common vertical wellbore then the Laterals and vertical wellbore shall be considered collectively as one wellbore. When the proposed operation(s) is the drilling of, or operation on a Horizontal or Multi-Lateral Well, the terms “depth” or “total depth” wherever used in the Agreement shall be deemed to read “Total Measured Depth” insofar as it applies to such well.

W.    The term “Vertical Well” shall mean a well drilled, Completed or Recompleted other than a horizontal or Multi- lateral Well.

Unless the context otherwise clearly indicates, words used in the singular include the plural, the word “person” includes natural and artificial persons, the plural includes the singular, and any gender includes the masculine, feminine, and neuter.

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A.A.P.L. FORM 610 - MODEL FORM OPERATION AGREEMENT – 1989

ARTICLE II.

EXHIBITS

The following exhibits, as indicated below and attached hereto, are incorporated in and made a part hereof:

A.    Exhibit “A: shall include the following information:

(1) Description of lands subject to this agreement,

(2) Restrictions, if any, as to depths, formations, or substances,

(3) Parties to agreement with addresses and telephone numbers for notice purposes,

(4) Percentages or fractional interests of parties to this agreement,

(5) Oil and Gas Leases and/or Oil and Gas Interests subject to this agreement,

(6) Burdens on production,

B.    Exhibit “B,” Form of Lease.

C.    Exhibit “C,” Accounting Procedure.

D.    Exhibit “D,” Insurance.

E.    Exhibit “E,” Gas Balancing Agreement.

F.    Exhibit “F,” Non-Discrimination and Certification of Non-Segregated Facilities.

G.    Exhibit “G,” Tax Partnership.

H.    Other: Not applicable                                                                                                      .

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A.A.P.L. FORM 610 - MODEL FORM OPERATION AGREEMENT – 1989

If any provision of any exhibit, except Exhibits “E,” “F” and “G,” is inconsistent with any provision contained in the body of this agreement, the provisions in the body of this agreement shall prevail.

ARTICLE III.

INTERESTS OF PARTIES

A. Oil and Gas Interests:

If any party owns an Oil and Gas Interest in the Contract Area, that Interest shall be treated for all purposes of this agreement and during the term hereof as if it were covered by the form of Oil and Gas Lease attached hereto as Exhibit “B,” and the owner thereof shall be deemed to own both royalty interest in such lease and the interest of the lessee thereunder.

B. Interests of Parties in Costs and Production:

Unless changed by other provisions, all costs and liabilities incurred in operations under this agreement shall be borne and paid, and all equipment and materials acquired in operations on the Contract Area shall be owned, by the parties as their interests are set forth in Exhibit “A.” In the same manner, the parties shall also own all production of Oil and Gas from the Contract Area subject, however, to the payment of royalties and other burdens on production as described hereafter.

Regardless of which party has contributed any Oil and Gas Lease or Oil and Gas Interest on which royalty or other burdens may be payable and except as otherwise expressly provided in this agreement, each party shall pay or deliver, or cause to be paid or delivered, all burdens on its share of the production from the Contract Area up to, but not in excess of,                  and shall indemnify, defend and hold the other parties free from any liability therefor. Except as otherwise expressly provided in this agreement, if any party has contributed hereto any Lease or Interest which is burdened with any royalty, overriding royalty, production payment or other burden on production in excess of the amounts stipulated above, such party so burdened shall assume and alone bear all such excess obligations and shall indemnify, defend and hold the other parties hereto harmless from any and all claims attributable to such excess burden. However, so long as the Drilling Unit for the productive Zone(s) is identical with the Contract Area, each party shall pay or deliver, or cause to be paid or delivered, all burdens on production from the Contract Area due under the terms of the Oil and Gas Lease(s) which such party has contributed to this agreement, and shall indemnify, defend and hold the other parties free from any liability therefor.

No party shall ever be responsible, on a price basis higher than the price received by such party, to any other party’s lessor or royalty owner, and if such other party’s lessor or royalty owner should demand and receive settlement on a higher price basis, the party contributing the affected Lease shall bear the additional royalty burden attributable to such higher price.

Nothing contained in this Article III.B. shall be deemed an assignment or cross-assignment of interests covered hereby, and in the event two or more parties contribute to this agreement jointly owned Leases, the parties’ undivided interests in said Leaseholds shall be deemed separate leasehold interests for the purposes of this agreement.

C. Subsequently Created Interests:

If any party has contributed hereto a Lease or Interest that is burdened with an assignment of production given as security for the payment of money, or if, after the date of this agreement, any party creates an overriding royalty, production payment, net profits interest, assignment of production or other burden payable out of production attributable to its working interest hereunder, such burden shall be deemed a “Subsequently Created Interest.” Further, if any party has contributed hereto a Lease or Interest burdened with an overriding royalty, production payment, net profits interests, or other burden payable out of production created prior to the date of this agreement, and such burden is not shown on Exhibit “A,” such burden also shall be deemed a Subsequently Created Interest to the extent such burden causes the burdens on such party’s Lease or Interest to exceed the amount stipulated in Article III.B. above.

The party whose interest is burdened with the Subsequently Created Interest (the “Burdened Party”) shall assume and alone bear, pay and discharge the Subsequently Created Interest and shall indemnify, defend and hold harmless the other parties from and against any liability therefor. Further, if the Burdened Party fails to pay, when due, its share of expenses chargeable hereunder, all provisions of Article VII.B. shall be enforceable against the Subsequently Created Interest in the same manner as they are enforceable against the working interest of the Burdened Party. If the Burdened Party is required under this agreement to assign or relinquish to any other party, or parties, all or a portion of its working interest and/or the production attributable thereto, said other party, or parties, shall receive said assignment and/or production free and clear of said Subsequently Created Interest, and the Burdened Party shall indemnify, defend and hold harmless said other party, or parties, from any and all claims and demands for payment asserted by owners of the Subsequently Created Interest.

ARTICLE IV.

TITLES

A. Title Examination:

Title examination shall be made on the Drillsite of any proposed well prior to commencement of drilling operations and if a majority in interest of the Drilling Parties so request or Operator so elects, title examination shall be made on the entire Drilling Unit, or maximum anticipated Drilling Unit, of the well. The opinion will include the ownership of the working interest, minerals, royalty, overriding royalty and production payments under the applicable Leases. Each party contributing Leases and/or Oil and Gas Interests to be included in the Drillsite or Drilling Unit, if appropriate, shall furnish to Operator all abstracts (including federal lease status reports), title opinions, title papers and curative material in its possession free of charge. All such information not in the possession of or made available to Operator by the parties, but necessary for the examination of the title, shall be obtained by Operator. Operator shall cause title to be examined by attorneys on its staff or by outside attorneys. Copies of all title opinions shall be furnished to each Drilling Party. Costs insured by Operator in procuring abstracts, fees paid outside attorneys for title examination (including preliminary, supplemental, shut in royalty opinions and division order title opinions) and other direct charges as provided in Exhibit “C” shall be borne by the Drilling Parties in the proportion that the interest of each Drilling Party bears to the total interest of all Drilling Parties as such interests appear in Exhibit “A”. Operator shall make no charge for services rendered by its staff attorneys or other personnel in the performance of the above functions.

Each party shall be responsible for securing curative matter and pooling amendments or agreements required in connection with Leases or Oil and Gas Interests contributed by such party. Operator shall be responsible for the preparation and recording of pooling designations or declarations and communitization agreements as well as the conduct of hearings before governmental agencies for the securing of spacing or pooling orders or any other orders necessary or appropriate to the conduct of operations hereunder. This shall not prevent any party from appearing on its own behalf at such hearings.    Costs incurred by Operator, including fees paid to outside attorneys, which are associated with hearings before governmental agencies, and which costs are necessary and proper for the activities contemplated under this agreement, shall be direct charges to the joint account and shall not be covered by the administrative overhead charges as provided in Exhibit “C.”

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A.A.P.L. FORM 610 - MODEL FORM OPERATION AGREEMENT – 1989

Operator shall make no charge for services rendered by its staff attorneys or other personnel in the performance of the above functions.

No well shall be drilled on the Contract Area until after (1) the title to the Drillsite or Drilling Unit, if appropriate, has been examined as above provided, and (3) the title has been approved by the examining attorney or title has been accepted by all of the Drilling Parties in such well.

B. Loss or Failure of Title:

1. Failure of Title: (a) Should any Oil and Gas Interest or Oil and Gas Lease be lost through failure of title, which results in a reduction of interest from that shown on Exhibit “A,” the party credited with contributing the affected Lease or Interest (including, if applicable, a successor in interest to such party) shall have ninety (90) days from final determination of title failure to acquire a new lease or other instrument curing the entirety of the title failure, which acquisition will not be subject to Article VIII.B., and failing to do so, this agreement, nevertheless, shall continue in force as to all remaining Oil and Gas Leases and Interests; and,

(a) The party credited with contributing the Oil and Gas Lease or Interest affected by the title failure (including, if applicable, a successor in interest to such party) shall bear alone the entire loss and it shall not be entitled to recover from Operator or the other parties any development or operating costs which it may have previously paid or incurred, but there shall be no additional liability on its part to the other parties hereto by reason of such title failure;

(b) There shall be no retroactive adjustment of expenses incurred or revenues received from the operation of the Lease or Interest which has failed, but the interests of the parties contained on Exhibit “A” shall be revised on an acreage basis, as of the time it is determined finally that title failure has occurred, so that the interest of the party whose Lease or Interest is affected by the title failure will thereafter be reduced in the Contract Area by the amount of the Lease or Interest failed;

(c) If the proportionate interest of the other parties hereto in any producing well previously drilled on the Contract Area is increased by reason of the title failure, the party who bore the costs incurred in connection with such well attributable to the Lease or Interest which has failed shall receive the proceeds attributable to the increase in such interest (less costs and burdens attributable thereto) until it has been reimbursed for unrecovered costs paid by it in connection with such well attributable to such failed Lease or Interest;

(d) Should any person not a party to this agreement, who is determined to be the owner of any Lease or Interest which has failed, pay in any manner any part of the cost of operation, development, or equipment, such amount shall be paid to the party or parties who bore the costs which are so refunded;

(e) Any liability to account to a person not a party to this agreement for prior production of Oil and Gas which arises by reason of title failure shall be borne severally by each party (including a predecessor to a current party) who received production for which such accounting is required based on the amount of such production received, and each such party shall severally indemnify, defend and hold harmless all other parties hereto for any such liability to account;

(f) No charge shall be made to the joint account for legal expenses, fees or salaries in connection with the defense of the Lease or Interest claimed to have failed, but if die party contributing such Lease or Interest hereto elects to defend its title it shall bear all expenses in connection therewith; and

(g) If any party is given credit on Exhibit “A” to a Lease or Interest which is limited solely to ownership of an interest in the wellbore of any well or wells and the production therefrom, such party’s absence of interest in the remainder of the Contract Area shall be considered a Failure of Title as to such remaining Contract Area unless that absence of interest is reflected on Exhibit “A.”

2. Loss by Non-Payment or Erroneous Payment of Amount Due: If, through mistake or oversight, any rental, shut-in well payment, minimum royalty or royalty payment, or other payment necessary to maintain all or a portion of an Oil and Gas Lease or interest is not paid or is erroneously paid, and as a result a Lease or Interest terminates, there shall be no monetary liability against the party who failed to make such payment. Unless the party who failed to make the required payment secures a new Lease or Interest covering the same interest within ninety (90) days from the discovery of the failure to make proper payment, which acquisition will not be subject to Article VIII.B., the interests of the parties reflected on Exhibit “A” shall be revised on an acreage basis, effective as of the date of termination of the Lease or Interest involved, and the party who failed to make proper payment will no longer be credited with an interest in the Contract Area on account of ownership of the Lease or Interest which has terminated. If the party who failed to make the required payment shall not have been fully reimbursed, at the time of the loss, from the proceeds of the sale of Oil and Gas attributable to the lost Lease or Interest, calculated on an acreage basis, for the development and operating costs previously paid on account of such Lease or Interest, it shall be reimbursed for unrecovered actual costs previously paid by it (but not for its share of the cost of any dry hole previously drilled or wells previously abandoned) from so much of the following as is necessary to effect reimbursement:

(a) Proceeds of Oil and Gas produced prior to termination of the Lease or Interest, less operating expenses and lease burdens chargeable hereunder to the person who failed to make payment, previously accrued to the credit of the lost Lease or Interest, on an acreage basis, up to the amount of unrecovered costs;

(b) Proceeds of Oil and Gas, less operating expenses and lease burdens chargeable hereunder to the person who failed to make payment, up to the amount of unrecovered costs attributable to that portion of Oil and Gas thereafter produced and marketed (excluding production from any wells thereafter drilled) which, in the absence of such Lease or Interest termination, would be attributable to the lost Lease or Interest on an acreage basis and which as a result of such Lease or Interest termination is credited to other parties, the proceeds of said portion of the Oil and Gas to be contributed by the other parties in proportion to their respective interests reflected on Exhibit “A”; and,

(c) Any monies, up to the amount of unrecovered costs, that may be paid by any party who is, or becomes, the owner of the Lease or Interest lost, for the privilege of participating in the Contract Area or becoming a party to this agreement.

3. Other Losses: All losses of Leases or Interests committed to this agreement, other than those set forth in Articles IV.B.I. and IV.B.2. above, shall be joint losses and shall be borne by all parties in proportion to their interests shown on Exhibit “A.” This shall include but not be limited to the loss of any Lease or Interest through failure to develop or because express or implied covenants have not been performed (other than performance which requires only the payment of money), and the loss of any Lease by expiration at the end of its primary term if it is not renewed or extended. There shall be no readjustment of interests in the remaining portion of the Contract Area on account of any joint loss.

4. Curing Title: In the event of a Failure of Title under Article 1V.B.I. or a loss of title under Article IV.B.2. above, any Lease or Interest acquired by any party hereto (other than the party whose interest has failed or was lost) during the ninety (90) day period provided by Article IV.B.1. and Article IV.B.2. above covering all or a portion of the interest that has failed or was lost shall be offered at cost to the party whose interest has failed or was lost, and the provisions of Article VIII.B. shall not apply to such acquisition.

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A.A.P.L. FORM 610 - MODEL FORM OPERATION AGREEMENT – 1989

ARTICLE V.

OPERATOR

A. Designation and Responsibilities of Operator:

Hudspeth Oil Corporation shall be the Operator of the Contract Area, and shall conduct and direct and have full control of all operations on the Contract Area as permitted and required by, and within the limits of this agreement. In its performance of services hereunder for the Non-Operators, Operator shall be an independent contractor not subject to the control or direction of the Non-Operators except as to the type of operation to be undertaken in accordance with the election procedures contained in this agreement. Operator shall not be deemed, or hold itself out as, the agent of the Non-Operators with authority to bind them to any obligation or liability assumed or incurred by Operator as to any third party. Operator shall conduct its activities under this agreement as a reasonable prudent operator, in a good and workmanlike manner, with due diligence and dispatch, in accordance with good oilfield practice, and in compliance with applicable law and regulation, but in no event shall it have any liability as Operator to the other parties for losses sustained or liabilities incurred except such as may result from gross negligence or willful misconduct.

B. Resignation or Removal of Operator and Selection of Successor:

1. Resignation or Removal of Operator: Operator may resign at any time by giving written notice thereof to Non-Operators. If Operator terminates its legal existence, no longer owns an interest hereunder in the Contract Area, or is no longer capable of serving as Operator, Operator shall be deemed to have resigned without any action by Non-Operators, except the selection of a successor. Operator may be removed only for good cause by the affirmative vote of Non-Operators owning a majority interest based on ownership as shown on Exhibit “A” remaining after excluding the voting interest of Operator, such vote shall not be deemed effective until a written notice has been delivered to the Operator by a Non-Operator detailing the alleged default and Operator has failed to cure the default within thirty (30) days from its receipt of the notice or, if the default concerns an operation then being conducted, within forty-eight (48) hours of its receipt of the notice. For purposes hereof, “good cause” shall mean not only gross negligence or willful misconduct but also the material breach of or inability to meet the standards of operation contained in Article V.A. or material failure or inability to perform its obligations under this agreement.

Subject to Article VII.D.1., such resignation or removal shall not become effective until 7:00 o’clock A.M. on the first day of the calendar month following the expiration of ninety (90) days after the giving of notice of resignation by Operator or action by the Non-Operators to remove Operator, unless a successor Operator has been selected and assumes the duties of Operator at an earlier date. Operator, after effective date of resignation or removal, shall be bound by the terms hereof as a Non-Operator. A change of a corporate name or structure of Operator or transfer of Operator’s interest to any single subsidiary, parent or successor corporation shall not be the basis for removal of Operator.

2. Selection of Successor Operator: Upon the resignation or removal of Operator under any provision of this agreement, a successor Operator shall be selected by the parties. The successor Operator shall be selected from the parties owning an interest in the Contract Area at the time such successor Operator is selected. The successor Operator shall be selected by the affirmative vote of two (2) or more parties owning a majority interest based on ownership as shown on Exhibit “A,” provided, however, if an Operator which has been removed or is deemed to have resigned fails to vote or votes only to succeed itself, the successor Operator shall be selected by the affirmative vote of the party or parties owning a majority interest based on ownership as shown on Exhibit “A” remaining after excluding the voting interest of the Operator that was removed or resigned. The former Operator shall promptly deliver to the successor Operator all records and data relating to the operations conducted by the former Operator to the extent such records and data are not already in the possession of the successor operator. Any cost of obtaining or copying the former Operator’s records and data shall be charged to the joint account.

3. Effect of Bankruptcy: If Operator becomes insolvent, bankrupt or is placed in receivership, it shall be deemed to have resigned without any action by Non-Operators, except the selection of a successor. If a petition for relief under the federal bankruptcy laws is filed by or against Operator, and the removal of Operator is prevented by the federal bankruptcy court, all Non-Operators and Operator shall comprise an interim operating committee to serve until Operator has elected to reject or assume this agreement pursuant to the Bankruptcy Code, and an election to reject this agreement by Operator as a debtor in possession, or by a trustee in bankruptcy, shall be deemed a resignation as Operator without any action by Non-Operators, except the selection of a successor. During the period of time the operating committee controls operations, all actions shall require the approval of two (2) or more parties owning a majority interest based on ownership as shown on Exhibit “A.” In the event there are only two (2) parties to this agreement, during the period of time the operating committee controls operations, a third party acceptable to Operator, Non-Operator and the federal bankruptcy court shall be selected as a member of the operating committee, and all actions shall require the approval of two (2) members of the operating committee without regard for their interest in the Contract Area based on Exhibit “A.”

C. Employees and Contractors:

The number of employees or contractors used by Operator in conducting operations hereunder, their selection, and the hours of labor and the compensation for services performed shall be determined by Operator, and all such employees or contractors shall be the employees or contractors of Operator.

D. Rights and Duties of Operator:

1. Competitive Rates and Use of Affiliates: All wells drilled on the Contract Area shall be drilled on a competitive contract basis at the usual rates prevailing in the area. If it so desires, Operator may employ its own tools and equipment in the drilling of wells, but its charges therefor shall not exceed the prevailing rates in the area and the rate of such charges shall be agreed upon by the parties in writing before drilling operations are commenced, and such work shall be performed by Operator under the same terms and conditions as are customary and usual in the area in contracts of independent contractors who are doing work of a similar nature. All work performed or materials supplied by affiliates or related parties of Operator shall be performed or supplied at competitive rates, pursuant to written agreement, and in accordance with customs and standards prevailing in the industry.

2. Discharge of Joint Account Obligations: Except as herein otherwise specifically provided, Operator shall promptly pay and discharge expenses incurred in the development and operation of the Contract Area pursuant to this agreement and shall charge each of the parties hereto with their respective proportionate shares upon the expense basis provided in Exhibit “C.”    Operator shall keep an accurate record of the joint account hereunder, showing expenses incurred and charges and credits made and received.

3. Protection from Liens: Operator shall pay, or cause to be paid, as and when they become due and payable, all accounts of contractors and suppliers and wages and salaries for services rendered or performed, and for materials supplied on, to or in respect of the Contract Area or any operations for the joint account thereof, and shall keep the Contract Area free from liens and encumbrances resulting therefrom except for those resulting from a bona fide dispute as to services rendered or materials supplied.

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A.A.P.L. FORM 610 - MODEL FORM OPERATION AGREEMENT – 1989

4. Custody of Funds: Operator shall hold for the account of the Non-Operators any funds of the Non-Operators advanced or paid to the Operator, either for the conduct of operations hereunder or as a result of the sale of production from the Contract Area, and such funds shall remain the funds of the Non-Operators on whose account they are advanced or paid until used for their intended purpose or otherwise delivered to the Non-Operators or applied toward the payment of debts as provided in Article VII.B. Nothing in this paragraph shall be construed to establish a fiduciary relationship between Operator and Non-Operators for any purpose other than to account for Non-Operator funds as herein specifically provided. Nothing in this paragraph shall require the maintenance by Operator of separate accounts for the funds of Non-Operators unless the parties otherwise specifically agree.

5. Access to Contract Area and Records: Operator shall, except as otherwise provided herein, permit each Non-Operator or its duly authorized representative, at the Non-Operator’s sole risk and cost, full and free access at all reasonable times to all operations of every kind and character being conducted for the joint account on the Contract Area and to the records of operations conducted thereon or production therefrom, including Operator’s books and records relating thereto. Such access rights shall not be exercised in a manner interfering with Operator’s conduct of an operation hereunder and shall not obligate Operator to furnish any geologic or geophysical data of an interpretive nature unless the cost of preparation of such interpretive data was charged to the joint account. Operator will furnish to each Non-Operator upon request copies of any and all reports and information obtained by Operator in connection with production and related items, including, without limitation, meter and chart reports, production purchaser statements, nix tickets and monthly gauge reports, but excluding purchase contracts and pricing information to the extent not applicable to the production of the Non-Operator seeking the information. Any audit of Operator’s records relating to amounts expended and the appropriateness of such expenditures shall be conducted in accordance with the audit protocol specified in Exhibit “C.”

6. Filing and Furnishing Governmental Reports: Operator will file, and upon written request promptly furnish copies to each requesting Non-Operator not in default of its payment obligations, all operational notices, reports or applications required to be filed by local, State, Federal or Indian agencies or authorities having jurisdiction over operations hereunder. Each Non-Operator shall provide to Operator on a timely basis all information necessary to Operator to make such filings.

7. Drilling and Testing Operations: The following provisions shall apply to each well drilled hereunder, including but not limited to the Initial Well:

(a) Operator will promptly advise Non-Operators of the date on which the well is spudded, or the date on which drilling operations are commenced.

(b) Operator will send to Non-Operators such reports, test results and notices regarding the progress of operations on the well as the Non-Operators shall reasonably request, including, but not limited to, daily drilling reports, completion reports, and well logs.

(c) Operator shall adequately test all Zones encountered which may reasonably be expected to be capable of producing Oil and Gas in paying quantities as a result of examination of the electric log or any other logs or cores or tests conducted hereunder.

Any information furnished to or obtained by a Non-Operator pursuant to Articles V.D.5, V.D.6 and V.D.7 shall be maintained as confidential by the Non-operator and shall not be disclosed by the Non-Operator without the written consent of Operator. Notwithstanding anything in this Agreement to the contrary, the rights of a Non-Operator as set forth in Articles V.D.5., V.D.6. and V.D.7 shall only apply in favor of those Non-Operator parties who are Consenting Parties with respect to a proposed operation, until such time as the Consenting Parties are no longer entitled to the Non-Consenting Party’s share of production, or the proceeds therefrom attributable to the proposed operation in which the non-Consenting Parties did not participate.

8. Cost Estimates: Upon request of any Consenting Party, Operator shall furnish estimates of current and cumulative costs incurred for the joint account at reasonable intervals during the conduct of any operation pursuant to this agreement. Operator shall not be held liable for errors in such estimates so long as the estimates are made in good faith.

9. Insurance: At all times while operations are conducted hereunder. Operator shall comply with the workers compensation law of the state where the operations are being conducted, provided, however, that Operator may be a self- insurer for liability under said compensation laws in which event the only charge that shall be made to the joint account shall be as provided in Exhibit “C.” Operator shall also carry or provide insurance for the benefit of the joint account of the parties as outlined in Exhibit “D” attached hereto and made a part hereof. Operator shall require all contractors engaged in work on or for the Contract Area to comply with the workers compensation law of the state where the operations are being conducted and to maintain such other insurance as Operator may require.

In the event automobile liability insurance is specified in said Exhibit “D,” or subsequently receives the approval of the parties, no direct charge shall be made by Operator for premiums paid for such insurance for Operators automotive equipment.

ARTICLE VI.

DRILLING AND DEVELOPMENT

A. Initial Well:

On or before the     31     day of     March    ,     2015    , Operator shall commence the drilling of the Initial Well at the following location

To be determined by Operator in its absolute discretion.

and shall thereafter continue the drilling of the well with due diligence to

at a minimum to the Wolfcamp Formation.

The drilling of the Initial Well and the participation therein by all parties is obligatory, subject to Article VI.C.1. as to participation in Completion operations and Article VI.F. as to termination of operations and Article XI as to occurrence of force majeure.

B. Subsequent Operations:

1. Proposed Operations: If any party hereto should desire to drill any well on the Contract Area other than the Initial Well, or

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if any party should desire to Rework, Sidetrack, Deepen, Recomplete or Plug Back a dry hole or a well no longer capable of producing in paying quantities in which such party has not otherwise relinquished its interest in the proposed objective Zone under this agreement, the party desiring to drill, Rework, Sidetrack, Deepen, Recomplete or Plug Back such a well shall give written notice of the proposed operation to the parties who have not otherwise relinquished their interest in such objective Zone

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under this agreement and to all other parties in the case of a proposal for Sidetracking or Deepening, specifying the work to be performed, the location, proposed depth, objective Zone and the estimated cost of the operation. The parties to whom such a notice is delivered shall have thirty (30) days after receipt of the notice within which to notify the party proposing to do the work whether they elect to participate in the cost of the proposed operation. If a drilling rig is on location, notice of a proposal to Rework, Sidetrack, Recomplete, Plug Back or Deepen may be given by telephone and the response period shall be limited to forty- eight (48) hours, exclusive of Saturday, Sunday and legal holidays. Failure of a party to whom such notice is delivered to reply within the period above fixed shall constitute an election by that party not to participate in the cost of the proposed operation. Any proposal by a party to conduct an operation conflicting with the operation initially proposed shall be delivered to all parties within the time and in the manner provided in Article VI.B.6.

If all parties to whom such notice is delivered elect to participate in such a proposed operation, the parties shall be contractually committed to participate therein provided such operations are commenced within the time period hereafter set forth, and Operator shall, no later than ninety (90) days after expiration of the notice period of thirty (30) days (or as promptly as practicable after the expiration of the forty-eight (48) hour period when a drilling rig is on location, as the case may be), actually commence the proposed operation and thereafter complete it with due diligence at the risk and expense of the parties participating therein; provided, however, said commencement date may be extended upon written notice of same by Operator to the other parties, for a period of up to thirty (30) additional days if, in the sole opinion of Operator, such additional time is reasonably necessary to obtain permits from governmental authorities, surface rights (including rights-of- way) or appropriate drilling equipment, or to complete title examination or curative matter required for title approval or acceptance. If the actual operation has not been commenced within the time provided (including any extension thereof as specifically permitted herein or in the force majeure provisions of Article XI) and if any party hereto still desires to conduct said operation, written notice proposing same must be resubmitted to the other parties in accordance herewith as if no prior proposal had been made. Those parties that did not participate in the drilling of a well for which a proposal to Deepen or Sidetrack is made hereunder shall, if such parties desire to participate in the proposed Deepening or Sidetracking operation, reimburse the Drilling Parties in accordance with Article VI.B.4. in the event of a Deepening operation and in accordance with Article VI B.5. in the event of a Sidetracking operation.

2. Operations by Less Than All Parties:

(a) Determination of Participation. If any party to whom such notice is delivered as provided in Article VI.B.1. or VI.C.1. (Option No. 2) elects not to participate in the proposed operation, then, in order to be entitled to the benefits of this Article, the party or parties giving the notice and such other parties as shall elect to participate in the operation shall, no later than ninety (90) days after the expiration of the notice period of thirty (30) days (or as promptly as practicable after the expiration of the forty-eight (48) hour period when a drilling rig is on location, as the case may be) actually commence the proposed operation and complete it with due diligence. Operator shall perform all work for the account of the Consenting Parties; provided, however, if no drilling rig or other equipment is on location, and if Operator is a Non-Consenting Party, the Consenting Parties shall either: (i) request Operator to perform the work required by such proposed operation for the account of the Consenting Parties, or (ii) designate one of the Consenting Parties as Operator to perform such work. The rights and duties granted to and imposed upon the Operator under this agreement are granted to and imposed upon the party designated as Operator for an operation in which the original Operator is a Non-Consenting Party. Consenting Parties, when conducting operations on the Contract Area pursuant to this Article VI.B.2., shall comply with all terms and conditions of this agreement.

If less than all parties approve any proposed operation, the proposing party, immediately after the expiration of the applicable notice period, shall advise all Parties of the total interest of the parties approving such operation and its recommendation as to whether the Consenting Parties should proceed with the operation as proposed. Each Consenting Party, within forty-eight (48) hours (exclusive of Saturday, Sunday, and legal holidays) after delivery of such notice, shall advise the proposing party of its desire to (i) limit participation to such party’s interest as shown on Exhibit “A” or (ii) carry only its proportionate part (determined by dividing such party’s interest in the Contract Area by the interests of all Consenting Parties in the Contract Area) of Non-Consenting Parties interests, or (iii) carry its proportionate part (determined as provided in (ii)) of Non-Consenting Parties’ interests together with all or a portion of its proportionate part of any Non-Consenting Parties’ interests that any Consenting Party did not elect to take. Any interest of Non-Consenting Parties that is not carried by a Consenting Party shall be deemed to be carried by the party proposing the operation if such party does not withdraw its proposal. Failure to advise the proposing party within the time required shall be deemed an election under (i). In the event a drilling rig is on location, notice may be given by telephone, and the time permitted for such a response shall not exceed a total of forty-eight (48) hours (exclusive of Saturday, Sunday and legal holidays). The proposing party, at its election, may withdraw such proposal if there is less than 100% participation and shall notify all parties of such decision within ten (10) days, or within twenty-four (24) hours if a drilling rig is on location, following expiration of the applicable response period. If 100% subscription to the proposed operation is obtained, the proposing party shall promptly notify the Consenting Parties of their proportionate interests in the operation and the party serving as Operator shall commence such operation within the period provided in Article VI.B.1., subject to the same extension right as provided therein.

(b) Relinquishment of Interest for Non-Participation. The entire cost and risk of conducting such operations shall be borne by the Consenting Parties in the proportions they have elected to bear same under the terms of the preceding paragraph. Consenting Parties shall keep the leasehold estates involved in such operations free and clear of all liens and encumbrances of every kind created by or arising from the operations of the Consenting Parties. If such an operation results in a dry hole, then subject to Articles VI.B.6. and VI.E.3., the Consenting Parties shall plug and abandon the well and restore the surface location at their sole cost, risk and expense; provided, however, that those Non-Consenting Parties that participated in the drilling, Deepening or Sidetracking of the well shall remain liable for, and shall pay, their proportionate shares of the cost of plugging and abandoning the well and restoring the surface location insofar only as those costs were not increased by the subsequent operations of the Consenting Parties. If any well drilled, Reworked, Sidetracked, Deepened, Recompleted or Plugged Back under the provisions of this Article results in a well capable of producing Oil and/or Gas in paying quantities, the Consenting Parties shall Complete and equip the well to produce at their sole cost and risk, and the well shall then be turned over to Operator (if the Operator did not conduct the operation) and shall be operated by it at the expense and for the account of the Consenting Parties. Upon commencement of operations for the drilling, Reworking, Sidetracking, Recompleting, Deepening or Plugging Back of any such well by Consenting Parties in accordance with the provisions of this Article, each Non-Consenting Party shall be deemed to have relinquished to Consenting Parties, and the Consenting Parties shall own and be entitled to receive, in proportion to their respective interests, all of such Non- Consenting Party’s interest in the well and share of production therefrom or, in the case of a Reworking, Sidetracking,

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Deepening, Recompleting or Plugging Back, or a Completion pursuant to Article VI.C.1. Option No. 2, all of such Non- Consenting Party’s interest in the production obtained from the operation in which the Non-Consenting Party did not elect to participate. Such relinquishment shall be effective until the proceeds of the sale of such share, calculated at the well, or market value thereof if such share is not sold (after deducting applicable ad valorem, production, severance, and excise taxes, royalty, overriding royalty and other interests not excepted by Article III.C. payable out of or measured by the production from such well accruing with respect to such interest until it reverts), shall equal the total of the following:

(i) 200% of each such Non-Consenting Party’s share of the cost of any newly acquired surface equipment beyond the wellhead connections (including but not limited to stock tanks, separators, treaters, pumping equipment and piping), plus 100% of each such Non-Consenting Party’s share of the cost of operation of the well commencing with first production and continuing until each such Non-Consenting Party’s relinquished interest shall revert to it under other provisions of this Article, it being agreed that each Non-Consenting Party’s share of such costs and equipment will be that interest which would have been chargeable to such Non-Consenting Party had it participated in the well from the beginning of the operations; and

(ii) 400% of (a) that portion of the costs and expenses of drilling, Reworking, Sidetracking, Deepening, Plugging Back, testing, Completing, and Recompleting, after deducting any cash contributions received under Article VIII.C., and of (b) that portion of the cost of newly acquired equipment in the well (to and including the wellhead connections), which would have been chargeable to such Non-Consenting Party if it had participated therein.

Notwithstanding anything to the contrary in this Article VI.B., if the well does not reach the deepest objective Zone described in the notice proposing the well for reasons other than the encountering of granite or practically impenetrable substance or other condition in the hole rendering further operations impracticable, Operator shall give notice thereof to each Non-Consenting Party who submitted or voted for an alternative proposal under Article VI.B.6. to drill the well to a shallower Zone than the deepest objective Zone proposed in the notice under which the well was drilled, and each such Non- Consenting Party shall have the option to participate in the initial proposed Completion of the well by paying its share of the cost of drilling the well to its actual depth, calculated in the manner provided in Article VI.B.4. (a). If any such Non- Consenting Party does not elect to participate in the first Completion proposed for such well, the relinquishment provisions of this Article VI.B.2. (b) shall apply to such party’s interest.

(c) Reworking, Recompleting or Plugging Back. An election not to participate in the drilling, Sidetracking or Deepening of a well shall be deemed an election not to participate in any Reworking or Plugging Back operation proposed in such a well, or portion thereof, to which the initial non-consent election applied that is conducted at any time prior to full recovery by the Consenting Parties of the Non-Consenting Party’s recoupment amount. Similarly, an election not to participate in the Completing or Recompleting of a well shall be deemed an election not to participate in any Reworking operation proposed in such a well, or portion thereof, to which the initial non-consent election applied that is conducted at any time prior to full recovery by the Consenting Parties of the Non-Consenting Party’s recoupment amount. Any such Reworking, Recompleting or Plugging Back operation conducted during the recoupment period shall be deemed part of the cost of operation of said well and there shall be added to the sums to be recouped by the Consenting Parties 400% of that portion of the costs of the Reworking, Recompleting or Plugging Back operation which would have been chargeable to such Non-Consenting Party had it participated therein. If such a Reworking, Recompleting or Plugging Back operation is proposed during such recoupment period, the provisions of this Article VI.B. shall be applicable as between said Consenting Parties in said well.

(d) Recoupment Matters. During the period of time Consenting Parties are entitled to receive Non-Consenting Party’s share of production, or the proceeds therefrom, Consenting Parties shall be responsible for the payment of all ad valorem, production, severance, excise, gathering and other taxes, and all royalty, overriding royalty and other burdens applicable to Non-Consenting Party’s share of production not excepted by Article III.C.

In the case of any Reworking, Sidetracking, Plugging Back, Recompleting or Deepening operation, the Consenting Parties shall be permitted to use, free of cost, all casing, tubing and other equipment in the well, but the ownership of all such equipment shall remain unchanged; and upon abandonment of a well after such Reworking, Sidetracking, Plugging Back, Recompleting or Deepening, the Consenting Parties shall account for all such equipment to the owners thereof, with each party receiving its proportionate part in kind or in value, less cost of salvage.

Within ninety (90) days after the completion of any operation under this Article, the party conducting the operations for the Consenting Parties shall furnish each Non-Consenting Party with an inventory of the equipment in and connected to the well, and an itemized statement of the cost of drilling, Sidetracking, Deepening, Plugging Back, testing, Completing, Recompleting, and equipping the well for production; or, at its option, the operating party, in lieu of an itemized statement of such costs of operation, may submit a detailed statement of monthly billings. Each month thereafter, during the time the Consenting Parties are being reimbursed as provided above, the party conducting the operations for the Consenting Parties shall furnish the Non-Consenting Parties with an itemized statement of all costs and liabilities incurred in the operation of the well, together with a statement of the quantity of Oil and Gas produced from it and the amount of proceeds realized from the sale of the well’s working interest production during the preceding month. In determining the quantity of Oil and Gas produced during any month, Consenting Parties shall use industry accepted methods such as but not limited to metering or periodic well tests. Any amount realized from the sale or other disposition of equipment newly acquired in connection with any such operation which would have been owned by a Non-Consenting Party had it participated therein shall be credited against the total unreturned costs of the work done and of the equipment purchased in determining when the interest of such Non-Consenting Party shall revert to it as above provided; and if there is a credit balance, it shall be paid to such Non-Consenting Party.

If and when the Consenting Parties recover from a Non-Consenting Party’s relinquished interest the amounts provided for above, the relinquished interests of such Non-Consenting Party shall automatically revert to it as of 7:00 a.m. on the day following the day on which such recoupment occurs, and, from and after such reversion, such Non-Consenting Party shall own the same interest in such well, the material and equipment in or pertaining thereto, and the production therefrom as such Non-Consenting Party would have been entitled to had it participated in the drilling, Sidetracking, Reworking, Deepening, Recompleting or Plugging Back of said well. Thereafter, such Non-Consenting Party shall be charged with and shall pay its proportionate part of the further costs of the operation of said well in accordance with the terms of this agreement and Exhibit “C” attached hereto.

3. Stand-By Costs: When a well which has been drilled or Deepened has reached its authorized depth and all tests have been completed and the results thereof furnished to the parties, or when operations on the well have been otherwise terminated pursuant to Article VI.F., stand-by costs incurred pending response to a party’s notice proposing a Reworking,

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Sidetracking, Deepening, Recompleting, Plugging Back or Completing operation in such a well (including the period required under Article VI.B.6 to resolve competing proposals) shall be charged and borne as part of the drilling or Deepening operation just completed. Stand-by costs subsequent to all parties responding, or expiration of the response time permitted, whichever first occurs, and prior to agreement as to the participating interests of all Consenting Parties pursuant to the terms of the second grammatical paragraph of Article VI.B.2. (a), shall be charged to and borne as part of the proposed operation, but if the proposal is subsequently withdrawn because of insufficient participation, such stand-by costs shall be allocated between the Consenting Parties in the proportion each Consenting Party’s interest as shown on Exhibit “A” bears to the total interest as shown on Exhibit “A” of all Consenting Parties.

In the event that notice for a Sidetracking operation is given while the drilling rig to be utilized is on location, any party may request and receive up to five (5) additional days after expiration of the forty-eight hour response period specified in Article VI.B.1. within which to respond by paying for all stand-by costs and other costs incurred during such extended response period; Operator may require such party to pay the estimated stand-by time in advance as a condition to extending the response period. If more than one party elects to take such additional time to respond to the notice, standby costs shall be allocated between the parties taking additional time to respond on a day-to-day basis in the proportion each electing party’s interest as shown on Exhibit “A” bears to the total interest as shown on Exhibit “A” of all the electing parties.

4. Deepening: If less than all parties elect to participate in a drilling, Sidetracking, or Deepening operation proposed pursuant to Article VI.B.1., the interest relinquished by the Non-Consenting Parties to the Consenting Parties under Article VI.B.2. shall relate only and be limited to the lesser of (i) the total depth actually drilled or (ii) the objective depth or Zone of which the parties were given notice under Article VI.B.1. (“Initial Objective”). Such well shall not be Deepened beyond the Initial Objective without first complying with this Article to afford the Non-Consenting Parties the opportunity to participate in the Deepening operation.

In the event any Consenting Party desires to drill or Deepen a Non-Consent Well to a depth below the Initial Objective, such party shall give notice thereof, complying with the requirements of Article VI.B.1., to all parties (including Non- Consenting Parties). Thereupon, Articles VI.B.1. and 2. shall apply and all parties receiving such notice shall have the right to participate or not participate in the Deepening of such well pursuant to said Articles VI.B.1. and 2. If a Deepening operation is approved pursuant to such provisions, and if any Non-Consenting Party elects to participate in the Deepening operation, such Non-Consenting party shall pay or make reimbursement (as the case may be) of the following costs and expenses.

(a) If the proposal to Deepen is made prior to the Completion of such well as a well capable of producing in paying quantities, such Non-Consenting Party shall pay (or reimburse Consenting Parties for, as the case may be) that share of costs and expenses incurred in connection with the drilling of said well from the surface to the Initial Objective which Non- onsenting Party would have paid had such Non-Consenting Party agreed to participate therein, plus the Non-Consenting arty’s share of the cost of Deepening and of participating in any further operations on the well in accordance with the other provisions of this Agreement; provided, however, all costs for testing and Completion or attempted Completion of the well incurred by Consenting Parties prior to the point of actual operations to Deepen beyond the Initial Objective shall be for the sole account of Consenting Parties.

(b) If the proposal is made for a Non-Consent Well that has been previously Completed as a well capable of producing in paying quantities, but is no longer capable of producing in paying quantities, such Non-Consenting Party shall pay (or reimburse Consenting Parties for, as the case may be) its proportionate share of all costs of drilling, Completing, and equipping said well from the surface to the Initial Objective, calculated in the manner provided in paragraph (a) above, less those costs recouped by the Consenting Parties from the sale of production from the well. The Non-Consenting Party shall also pay its proportionate share of all costs of re-entering said well. The Non-Consenting Parties’ proportionate part (based on the percentage of such well Non-Consenting Party would have owned had it previously participated in such Non-Consent Well) of the costs of salvable materials and equipment remaining in the hole and salvable surface equipment used in connection with such well shall be determined in accordance with Exhibit “C.” If the Consenting Parties have recouped the cost of drilling, Completing, and equipping the well at the time such Deepening operation is conducted, then a Non- Consenting Party may participate in the Deepening of the well with no payment for costs incurred prior to re-entering the well for Deepening

The foregoing shall not imply a right of any Consenting Party to propose any Deepening for a Non-Consent Well prior to the drilling of such well to its Initial Objective without the consent of the other Consenting Parties as provided in Article VI.F.

This Article VI.B.4. shall not apply to Deepening operations within an existing lateral of a Horizontal or Multi-lateral Well.

5. Sidetracking. Any party having the right to participate in a proposed Sidetracking operation that does not own an interest in the affected wellbore at the time of the notice shall, upon electing to participate, tender to the wellbore owners its proportionate share (equal to its interest in the Sidetracking operation) of the value of that portion of the existing wellbore to be utilized as follows:

(a) If the proposal is for Sidetracking an existing dry hole, reimbursement shall be on the basis of the actual costs incurred in the initial drilling of the well down to the depth at which the Sidetracking operation is initiated.

(b) If the proposal is for Sidetracking a well which has previously produced, reimbursement shall be on the basis of such party’s proportionate share of drilling and equipping costs incurred in the initial drilling of the well down to the depth at which the Sidetracking operation is conducted, calculated in the manner described in Article VI.B.4(b) above. Such party’s proportionate share of the cost of the well’s salvable materials and equipment down to the depth at which the Sidetracking operation is initiated shall be determined in accordance with the provisions of Exhibit “C.”

This Article VI.B.5. “Sidetracking” shall not apply to operations in an existing Lateral of a Horizontal or Multi-lateral Well. Drilling operations which are intended to recover penetration of the objective formation(s) which are conducted in a Horizontal or Multi-lateral Well shall be considered as included in the original proposed drilling operations.

6. Order of Preference of Operations. Except as otherwise specifically provided in this agreement, if any party desires to propose the conduct of an operation that conflicts with a proposal that has been made by a party under this Article VI, such party shall have fifteen (15) days from delivery of the initial proposal, in the case of a proposal to drill a well or to perform an operation on a well where no drilling rig is on location, or twenty-four (24) hours, exclusive of Saturday, Sunday and legal holidays, from delivery of the initial proposal, if a drilling rig is on location for the well on which such operation is to be conducted, to deliver to all parties entitled to participate in the proposed operation such party’s alternative proposal, such alternate proposal to contain the same information required to be included in the initial proposal. Each party receiving such proposals shall elect by delivery of notice to Operator within five (5) days after expiration of the proposal period, or within twenty-four (24) hours (exclusive of Saturday, Sunday and legal holidays) if a drilling rig is on location for the well that is the subject of the proposals, to participate in one of the competing proposals. Any party not electing within the time required shall be deemed not to have voted. The proposal receiving the vote of parties owning the largest aggregate percentage interest of the parties voting shall have priority over all other competing proposals; in the case of a tie vote, the

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initial proposal shall prevail. Operator shall deliver notice of such result to all parties entitled to participate in the operation within five (5) days after expiration of the election period (or within twenty-four (24) hours, exclusive of Saturday, Sunday and legal holidays, if a drilling rig is on location). Each party shall then have two (2) days (or twenty-four (24) hours if a rig is on location) from receipt of such notice to elect by delivery of notice to Operator to participate in such operation or to relinquish interest in the affected well pursuant to the provisions of Article VI.B.2.; failure by a party to deliver notice within such period shall be deemed an election not to participate in the prevailing proposal.

7. Conformity to Spacing Pattern. Notwithstanding the provisions of this Article VI.B.2., it is agreed that no wells shall be proposed to be drilled to or Completed in or produced from a Zone from which a well located elsewhere on the Contract Area is producing, unless such well conforms to the then-existing well spacing pattern, or an approved exception, for such Zone.

8. Paying Wells. No party shall conduct any Reworking, Deepening, Plugging Back, Completion, Recompletion, or Sidetracking operation under this agreement with respect to any well then capable of producing in paying quantities except with the consent of all parties that have not relinquished interests in the well at the time of such operation.

C. Completion of Wells: Reworking and Plugging Back:

1. Completion: Without the consent of all parties, no well shall be drilled, Deepened or Sidetracked, except any well drilled, Deepened or Sidetracked pursuant to the provisions of Article VI.B.2. of this agreement. Consent to the drilling, Deepening or Sidetracking shall include:

☑ Option No. 1: All necessary expenditures for the drilling, Deepening or Sidetracking, testing, Completing and equipping of the well, including necessary tankage and/or surface facilities. / For any Horizontal or Multi-lateral Well subject to this Agreement. Completion operations shall be included in the proposed drilling operations for such well.

☑ Option No. 2: All necessary expenditures for the drilling, Deepening or Sidetracking and testing of the well a Vertical Well. When such well has reached its authorized depth, and all logs, cores and other tests have been completed, and the results thereof furnished to the parties, Operator shall give immediate notice to the Non-Operators having the right to participate in a Completion attempt whether or not Operator recommends attempting to Complete the well, together with Operator’s AFE for Completion costs if not previously provided. The parties receiving such notice shall have forty-eight (48) hours (exclusive of Saturday, Sunday and legal holidays) in which to elect by delivery of notice to Operator to participate in a recommended Completion attempt or to make a Completion proposal with an accompanying AFE. Operator shall deliver any such Completion proposal, or any Completion proposal conflicting with Operator’s proposal, to the other parties entitled to participate in such Completion in accordance with the procedures specified in Article VI.B.6. Election to participate in a Completion attempt shall include consent to all necessary expenditth ures for the Completing and equipping of such well, including necessary tankage and/or surface facilities but excluding any stimulation operation not contained on the Completion AFE. Failure of any party receiving such notice to reply within the period above fixed shall constitute an election by that party not to participate in the cost of the Completion attempt, provided, that Article VI.B.6. shall control in the case of conflicting Completion proposals. If one or more, but less than all of the parties, elect to attempt a Completion, the provision of Article VI.B.2. hereof (the phrase “Reworking, Sidetracking, Deepening, Recompleting or Plugging Back” as contained in Article VI.B.2 shall be deemed to include “Completing”) shall apply to the operations thereafter conducted by less than all parties; provided, however, that Article VI.B.2. shall apply separately to each separate Completion or Recompletion attempt undertaken hereunder, and an election to become a Non-Consenting Party as to one Completion or Recompletion attempt shall not prevent a party from becoming a Consenting Party in subsequent Completion or Recompletion attempts regardless whether the Consenting Parties as to earlier Completions or Recompletion have recouped their costs pursuant to Article VI.B.2., provided further, that any recoupment of costs by a Consenting Party shall be made solely from the production attributable to the Zone in which the Completion attempt is made. Election by a previous Non-Consenting party to participate in a subsequent Completion or Recompletion attempt shall require such party to pay its proportionate share of the cost of salvable materials and equipment installed in the well pursuant to the previous Completion or Recompletion attempt, insofar and only insofar as such materials and equipment benefit the Zone in which such party participates in a Completion attempt.

/ Notwithstanding anything herein to, the contrary, Option 1 shall apply to any Horizontal or Multi-lateral Well and Option 2 shall apply to any vertical well.

2. Rework, Recomplete or Plug Back: No well shall be Reworked, Recompleted or Plugged Back except a well Reworked, Recompleted, or Plugged Back pursuant to the provisions of Article VI.B.2. of this agreement. Consent to the Reworking, Recompleting or Plugging Back of a well shall include all necessary expenditures in conducting such operations and Completing and equipping of said well, including necessary tankage and/or surface facilities.

D. Other Operations:

Operator shall not undertake any single project reasonably estimated to require an expenditure in excess of                                                                                                                                                     Dollars ($                    ) except in connection with the drilling, Sidetracking, Reworking, Deepening, Completing, Recompleting or Plugging Back of a well that has been previously authorized by or pursuant to this agreement; provided, however, that, in case of explosion, fire, flood or other sudden emergency, whether of the same or different nature, Operator may take such steps and incur such expenses as in its opinion are required to deal with the emergency to safeguard life and property but Operator, as promptly as possible, shall report the emergency to the other parties. If Operator prepares an AFE for its own use, Operator shall furnish any Non-Operator so requesting an information copy thereof for any single project costing in excess of _______________________________________ Dollars ($____________________). Any party who has not relinquished its interest in a well shall have the right to propose that Operator perform repair work or undertake the installation of artificial lift equipment or ancillary production facilities such as salt water disposal wells or to conduct additional work with respect to a well drilled hereunder or other similar project (but not including the installation of gathering lines or other transportation or marketing facilities, the installation of which shall be governed by separate agreement between the parties) reasonably estimated to require an expenditure in excess of the amount first set forth above in this Article VI.D. (except in connection with an operation required to be proposed under Articles VI.B.1. or VI.C.1. Option No. 2, which shall be governed exclusively be those Articles). Operator shall deliver such proposal to all parties entitled to participate therein. If within thirty (30) days thereof Operator secures the written consent of any party or parties owning at least ____________% of the interests of the parties entitled to participate in such operation, each party having the right to participate in such project shall be bound by the terms of such proposal and shall be obligated to pay its proportionate share of the costs of the proposed project as if it had consented to such project pursuant to the terms of the proposal.

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E. Abandonment of Wells:

1. Abandonment of Dry Holes. Except for any well drilled or Deepened pursuant to Article VI.B.2., any well which has been drilled or Deepened under the terms of this agreement and is proposed to be completed as a dry hole shall not be

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plugged and abandoned without the consent of all parties. Should Operator, after diligent effort, be unable to contact any party, or should any party fail to reply within forty-eight (48) hours (exclusive of Saturday, Sunday and legal holidays) after delivery of notice of the proposal to plug and abandon such well, such party shall be deemed to have consented to the proposed abandonment. All such wells shall be plugged and abandoned in accordance with applicable regulations and at the cost, risk and expense of the parties who participated in the cost of drilling or Deepening such well. Any party who objects to plugging and abandoning such well by notice delivered to Operator within forty-eight (48) hours (exclusive of Saturday, Sunday and legal holidays) after delivery of notice of the proposed plugging shall take over the well as of the end of such forty-eight (48) hour notice period and conduct further operations in search of Oil and/or Gas subject to the provisions of Article VI.B.; failure of such party to provide proof reasonably satisfactory to Operator of its financial capability to conduct such operations or to take over the well within such period or thereafter to conduct operations on such well or plug and abandon such well shall entitle Operator to retain or take possession of the well and plug and abandon the well. The party taking over the well shall indemnify Operator (if Operator is an abandoning party) and the other abandoning parties against liability for any further operations conducted on such well except for the costs of plugging and abandoning the well and restoring the surface, for which the abandoning parties shall remain proportionately liable.

2. Abandonment of Wells That Have Produced: Except for any well in which a Non-Consent operation has been conducted hereunder for which the Consenting Parties have not been fully reimbursed as herein provided, any well which has been completed as a producer shall not be plugged and abandoned without the consent of all parties. If all parties consent to such abandonment, the well shall be plugged and abandoned in accordance with applicable regulations and at the cost, risk and expense of all the parties hereto. Failure of a party to reply within sixty (60) days of delivery of notice of proposed abandonment shall be deemed an election to consent to the proposal. If, within sixty (60) days after delivery of notice of the proposed abandonment of any well, all parties do not agree to the abandonment of such well, those wishing to continue its operation from the Zone then open to production shall be obligated to take over the well as of the expiration of the applicable notice period and shall indemnify Operator (if Operator is an abandoning party) and the other abandoning parties against liability for any further operations on the well conducted by such parties. Failure of such party or parties to provide proof reasonably satisfactory to Operator of their financial capability to conduct such operations or to take over the well within the required period or thereafter to conduct operations on such well shall entitle operator to retain or take possession of such well and plug and abandon the well.

Parties taking over a well as provided herein shall tender to each of the other parties its proportionate share of the value of the well’s salvable material and equipment, determined in accordance with the provisions of Exhibit “C,” less the estimated cost of salvaging and the estimated cost of plugging and abandoning and restoring the surface; provided, however, that in the event the estimated plugging and abandoning and surface restoration costs and the estimated cost of salvaging are higher than the value of the well’s salvable material and equipment, each of the abandoning parties shall tender to the parties continuing operations their proportionate shares of the estimated excess cost. Each abandoning party shall assign to the non-abandoning parties, without warranty, express or implied, as to title or as to quantity, or fitness for use of the equipment and material, all of its interest in the wellbore of the well and related equipment, together with its interest in the Leasehold insofar and only insofar as such Leasehold covers the right to obtain production from that wellbore in the Zone then open to production. If the interest of the abandoning party is or includes and Oil and Gas Interest, such party shall execute and deliver to the non- abandoning party or parties an oil and gas lease, limited to the wellbore and the Zone then open to production, for a term of one (1) year and so long thereafter as Oil and/or Gas is produced from the Zone covered thereby, such lease to be on the form attached as Exhibit “B.” The assignments or leases so limited shall encompass the Drilling Unit upon which the well is located. The payments by, and the assignments or leases to, the assignees shall be in a ratio based upon the relationship of their respective percentage of participation in the Contract Area to the aggregate of the percentages of participation in the Contract Area of all assignees. There shall be no readjustment of interests in the remaining portions of the Contract Area.

Thereafter, abandoning parties shall have no further responsibility, liability, or interest in the operation of or production from the well in the Zone then open other than the royalties retained in any lease made under the terms of this Article. Upon request, Operator shall continue to operate the assigned well for the account of the non-abandoning parties at the rates and charges contemplated by this agreement, plus any additional cost and charges which may arise as the result of the separate ownership of the assigned well. Upon proposed abandonment of the producing Zone assigned or leased, the assignor or lessor shall then have the option to repurchase its prior interest in the well (using the same valuation formula) and participate in further operations therein subject to the provisions hereof.

3. Abandonment of Non-Consent Operations. The provisions of Article VI.E.1. or VI.E.2. above shall be applicable as between Consenting Parties in the event of the proposed abandonment of any well excepted from said Articles; provided, however, no well shall be permanently plugged and abandoned unless and until all parties having the right to conduct further operations therein have been notified of the proposed abandonment and afforded the opportunity to elect to take over the well in accordance with the provisions of this Article VI.E.; and provided further, that Non-Consenting Parties who own an interest in a portion of the well shall pay their proportionate shares of abandonment and surface restoration cost for such well as provided in Article VI.B.2.(b).

F. Termination of Operations:

Upon the commencement of an operation for the drilling, Reworking, Sidetracking, Plugging Back, Deepening, testing, Completion or plugging of a well, including but not limited to the Initial Well, such operation shall not be terminated without consent of parties bearing     % of the costs of such operation; provided, however, that in the event granite or other practically impenetrable substance or condition in the hole is encountered which renders further operations impractical. Operator may discontinue operations and give notice of such condition in the manner provided in Article VI.B.1, and the provisions of Article VI.B. or VI.E. shall thereafter apply to such operation, as appropriate.

G. Taking Production in Kind:

☐ Option No. 1: Gas Balancing Agreement Attached

Each party shall take in kind or separately dispose of its proportionate share of all Oil and Gas produced from the Contract Area, exclusive of production which may be used in development and producing operations and in preparing and treating Oil and Gas for marketing purposes and production unavoidably lost. Any extra expenditure incurred in the taking in kind or separate disposition by any party of its proportionate share of the production shall be borne by such party. Any party taking its share of production in kind shall be required to pay for only its proportionate share of such part of Operator’s surface facilities which it uses.

Each party shall execute such division orders and contracts as may be necessary for the sale of its interest in production front the Contract Area, and, except as provided in Article VII.B., shall be entitled to receive payment directly from the purchaser thereof for its share of all production.

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If any party fails to make the arrangements necessary to take in kind or separately dispose of its proportionate share of the Oil produced from the Contract Area, Operator shall have the right, subject to the revocation at will by the party owning it, but not the obligation, to purchase such Oil or sell it to others at any time and from time to time, for the account of the non-taking party. Any such purchase or sale by Operator may be terminated by Operator upon at least ten (10) days written notice to the owner of said production and shall be subject always to the right of the owner of the production upon at least ten (10) days written notice to Operator to exercise at any time its right to take in kind, or separately dispose of, its share of all Oil not previously delivered to a purchaser. Any purchase or sale by Operator of any other party’s share of Oil shall be only for such reasonable periods of time as are consistent with the minimum needs of the industry under the particular circumstances, but in no event for a period in excess of one (1) year.

Any such sale by Operator shall be in a manner commercially reasonable under the circumstances but Operator shall have no duty to share any existing market or to obtain a price equal to that received under any existing market. The sale or delivery by Operator of a non-taking party’s share of Oil under the terms of any existing contract of Operator shall not give the non-taking party any interest in or make the non-taking party a party to said contract. No purchase shall be made by Operator without first giving the non-taking party at least ten (10) days written notice of such intended purchase and the price to be paid or the pricing basis to be used.

All parties shall give timely written notice to Operator of their Gas marketing arrangements for the following month, excluding price, and shall notify Operator immediately in the event of a change in such arrangements. Operator shall maintain records of all marketing arrangements, and of volumes actually sold or transported, which records shall be made available to Non-Operators upon reasonable request.

In the event one or more parties’ separate disposition of its share of the Gas causes split-stream deliveries to separate pipelines and/or deliveries which on a day-to-day basis for any reason are not exactly equal to a party’s respective proportion- ate share of total Gas sales to be allocated to it, the balancing or accounting between the parties shall be in accordance with any Gas balancing agreement between the parties hereto, whether such an agreement is attached as Exhibit “E” or is a separate agreement. Operator shall give notice to all parties of the first sales of Gas from any well under this agreement.

☐ Option No. 2: No Gas Balancing Agreement:

Each party shall take in kind or separately dispose of its proportionate share of all Oil and Gas produced from the Contract Area, exclusive of production which may be used in development and producing operations and in preparing and treating Oil and Gas for marketing purposes and production unavoidably lost. Any extra expenditures incurred in the taking in kind or separate disposition by any party of its proportionate share of the production shall be borne by such party. Any party taking its share of production in kind shall be required to pay for only its proportionate share of such part of Operator’s surface facilities which it uses.

Each party shall execute such division orders and contracts as may be necessary for the sale of its interest in production from the Contract Area, and, except as provided in Article VII.B., shall be entitled to receive payment directly from the purchaser thereof for its share of all production.

If any party fails to make the arrangements necessary to take in kind or separately dispose of its proportionate share of the Oil and/or Gas produced from the Contract Area, Operator shall have the right, subject to the revocation at will by the party owning it, but not the obligation, to purchase such Oil and/or Gas or sell it to others at any time and from time to time, for the account of the non-taking party. Any such purchase or sale by Operator may be terminated by Operator upon at least ten (10) days written notice to the owner of said production and shall be subject always to the right of the owner of the production upon at least ten (10) days written notice to Operator to exercise its right to take in kind, or separately dispose of, its share of all Oil and/or Gas not previously delivered to a purchaser, provided, however, that the effective date of any such revocation may be deferred at Operator’s election for a period not to exceed ninety (90) days if Operator has committed such production to a purchase contract having a term extending beyond such ten (10) -day period. Any purchase or sale by Operator of any other party’s share of Oil and/or Gas shall be only for such reasonable periods of time as are consistent with the minimum needs of the industry under the particular circumstances, but in no event for a period in excess of one (1) year.

Any such sale by Operator shall be in a manner commercially reasonable under the circumstances, but Operator shall have no duty to share any existing market or transportation arrangement or to obtain a price or transportation fee equal to that received under any existing market or transportation arrangement. The sale or delivery by Operator of a non-taking party’s share of production under the terms of any existing contract of Operator shall not give the non-taking party any interest in or make the non-taking party a party to said contract. No purchase of Oil and Gas and no sale of Gas shall be made by Operator without first giving the non-taking party ten days written notice of such intended purchase or sale and the price to be paid or the pricing basis to be used. Operator shall give notice to all parties of the first sale of Gas from any well under this Agreement.

All parties shall give timely written notice to Operator of their Gas marketing arrangements for the following month, excluding price, and shall notify Operator immediately in the event of a change in such arrangements. Operator shall maintain records of all marketing arrangements, and of volumes actually sold or transported, which records shall be made available to Non-Operators upon reasonable request.

ARTICLE VII.

EXPENDITURES AND LIABILITY OF PARTIES

A. Liability of Parties:

The liability of the parties shall be several, not joint or collective. Each party shall be responsible only for its obligations, and shall be liable only for its proportionate share of the costs of developing and operating the Contract Area. Accordingly, the liens granted among the parties in Article VII.B. are given to secure only the debts of each severally, and no party shall have any liability to third parties hereunder to satisfy the default of any other party in the payment of any expense or obligation hereunder. It is not the intention of the parties to create, nor shall this agreement be construed as creating, a mining or other partnership, joint venture, agency relationship or association, or to render the parties liable as partners, co-venturers, or principals. In their relations with each other under this agreement, the parties shall not be considered fiduciaries or to have established a confidential relationship but rather shall be free to act on an arm’s-length basis in accordance with their own respective self-interest, subject, however, to the obligation of the parties to act in good faith in their dealings with each other with respect to activities hereunder.

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B. Liens and Security Interests:

Each party grants to the other parties hereto a lien upon any interest it now owns or hereafter acquires in Oil and Gas Leases and Oil and Gas Interests in the Contract Area, and a security interest and/or purchase money security interest in any interest it now owns or hereafter acquires in the personal property and fixtures on or used or obtained for use in connection therewith, to secure performance of all of its obligations under this agreement including but not limited to payment of expense, interest and fees, the proper disbursement of all monies paid hereunder, the assignment or relinquishment of interest in Oil and Gas Leases as required hereunder, and the proper performance of operations hereunder. Such lien and security interest granted by each party hereto shall include such party’s leasehold interests, working interests, operating rights, and royalty and overriding royalty interests in the Contract Area now owned or hereafter acquired and in lands pooled or unitized therewith or otherwise becoming subject to this agreement, the Oil and Gas when extracted therefrom and equipment situated thereon or used or obtained for use in connection therewith (including, without limitation, all wells, tools, and tubular goods), and accounts (including, without limitation, accounts arising from gas imbalances or from the sale of Oil and/or Gas at the wellhead), contract rights, inventory and general intangibles relating thereto or arising therefrom, and all proceeds and products of the foregoing.

To perfect the lien and security agreement provided herein, each party hereto shall execute and acknowledge the recording supplement and/or any financing statement prepared and submitted by any party hereto in conjunction herewith or at any time following execution hereof, and Operator is authorized to file this agreement or the recording supplement executed herewith as a lien or mortgage in the applicable real estate records and as a financing statement with the proper officer under the Uniform Commercial Code in the state in which the Contract Area is situated and such other states as Operator shall deem appropriate to perfect the security interest granted hereunder. Any party may file this agreement, the recording supplement executed herewith, or such other documents as it deems necessary as a lien or mortgage in the applicable real estate records and/or a financing statement with the proper officer under the Uniform Commercial Code.

Each party represents and warrants to the other parties hereto that the lien and security interest granted by such party to the other parties shall be a first and prior lien, and each party hereby agrees to maintain the priority of said lien and security interest against all persons acquiring an interest in Oil and Gas Leases and Interests covered by this agreement by, through or under such party. All parties acquiring an interest in Oil and Gas Leases and Oil and Gas Interests covered by this agreement, whether by assignment, merger, mortgage, operation of law, or otherwise, shall be deemed to have taken subject to the lien and security interest granted by this Article VII.B. as to all obligations attributable to such interest hereunder whether or not such obligations arise before or after such interest is acquired.

To the extent that parties have a security interest under the Uniform Commercial Code of the state in which the Contract Area is situated, they shall be entitled to exercise the rights and remedies of a secured party under the Code. The bringing of a suit and the obtaining of judgment by a party for the secured indebtedness shall not be deemed an election of remedies or otherwise affect the lien rights or security interest as security for the payment thereof. In addition, upon default by any party in the payment of its share of expenses, interests or fees, or upon the improper use of funds by the Operator, the other parties shall have the right, without prejudice to other rights or remedies, to collect from the purchaser the proceeds from the sale of such defaulting party’s share of Oil and Gas until the amount owed by such party, plus interest as provided in “Exhibit C,” has been received, and shall have the right to offset the amount owed against the proceeds from the sale of such defaulting party’s share of Oil and Gas. All purchasers of production may rely on a notification of default from the non-defaulting party or parties stating the amount due as a result of the default, and all parties waive any recourse available against purchasers for releasing production proceeds as provided in this paragraph.

If any party fails to pay its share of cost within one hundred twenty (120) days after rendition of a statement therefor by Operator, the non-defaulting parties, including Operator, shall upon request by Operator, pay the unpaid amount in the proportion that the interest of each such party bears to the interest of all such parties. The amount paid by each party so paying its share of the unpaid amount shall be secured by the liens and security rights described in Article VII.B., and each paying party may independently pursue any remedy available hereunder or otherwise.

If any party does not perform all of its obligations hereunder, and the failure to perform subjects such party to foreclosure or execution proceedings pursuant to the provisions of this agreement, to the extent allowed by governing law, the defaulting party waives any available right of redemption from and after the date of judgment, any required valuation or appraisement of the mortgaged or secured property prior to sale, any available right to stay execution or to require a marshaling of assets and any required bond in the event a receiver is appointed. In addition, to the extent permitted by applicable law, each party hereby grants to the other parties a power of sale as to any property that is subject to the lien and security rights granted hereunder, such power to be exercised in the manner provided by applicable law or otherwise in a commercially reasonable manner and upon reasonable notice.

Each party agrees that the other parties shall be entitled to utilize the provisions of Oil and Gas lien law or other lien law of any state in which the Contract Area is situated to enforce the obligations of each party hereunder. Without limiting the generality of the foregoing, to the extent permitted by applicable law, Non-Operators agree that Operator may invoke or utilize the mechanics’ or materialmen’s lien law of the state in which the Contract Area is situated in order to secure the payment to Operator of any sum due hereunder for services performed or materials supplied by Operator.

C. Advances:

Operator, at its election, shall have the right from time to time to demand and receive from one or more of the other parties payment in advance of their respective shares of the estimated amount of the expense to be incurred in operations hereunder during the next succeeding month, which right may be exercised only by submission to each such party of an itemized statement of such estimated expense, together with an invoice for its share thereof. Each such statement and invoice for the payment in advance of estimated expense shall be submitted on or before the 20th day of the next preceding month. Each party shall pay to Operator its proportionate share of such estimate within fifteen (15) days after such estimate and invoice is received. If any party fails to pay its share of said estimate within said time, the amount due shall bear interest as provided in Exhibit “C” until paid. Proper adjustment shall be made monthly between advances and actual expense to the end that each party shall bear and pay its proportionate share of actual expenses incurred, and no more.

D. Defaults and Remedies:

If any party fails to discharge any financial obligation under this agreement, including without limitation the failure to make any advance under the preceding Article VII.C. or any other provision of this agreement, within the period required for such payment hereunder, then in addition to the remedies provided in Article VII.B. or elsewhere in this agreement, the remedies specified below shall be applicable. For purposes of this Article VII.D., all notices and elections shall be delivered

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only by Operator, except that Operator shall deliver any such notice and election requested by a non-defaulting Non-Operator, and when Operator is the party in default, the applicable notices and elections can be delivered by any Non-Operator. Election of any one or more of the following remedies shall not preclude the subsequent use of any other remedy specified below or otherwise available to a non-defaulting party.

1. Suspension of Rights: Any party may deliver to the party in default a Notice of Default, which shall specify the default, specify the action to be taken to cure the default, and specify that failure to take such action will result in the exercise of one or more of the remedies provided in this Article. If the default is not cured within thirty (30) days of the delivery of such Notice of Default, all of the rights of the defaulting party granted by this agreement may upon notice be suspended until the default is cured, without prejudice to the right of the non-defaulting party or parties to continue to enforce the obligations of the defaulting party previously accrued or thereafter accruing under this agreement. If Operator is the party in default, the Non-Operators shall have in addition the right, by vote of Non-Operators owning a majority in interest in the Contract Area after excluding the voting interest of Operator, to appoint a new Operator effective immediately. The rights of a defaulting party that may be suspended hereunder at the election of the non-defaulting parties shall include, without limitation, the right to receive information as to any operation conducted hereunder during the period of such default, the right to elect to participate in an operation proposed under Article VI.B. of this agreement, the right to participate in an operation being conducted under this agreement even if the party has previously elected to participate in such operation, and the right to receive proceeds of production from any well subject to this agreement.

2. Suit for Damages: Non-defaulting parties or Operator for the benefit of non-defaulting parties may sue (at joint account expense) to collect the amounts in default, plus interest accruing on the amounts recovered from the date of default until the date of collection at the rate specified in Exhibit “C” attached hereto. Nothing herein shall prevent any party from suing any defaulting party to collect consequential damages accruing to such party as a result of the default.

3. Deemed Non-Consent: The non-defaulting party may deliver a written Notice of Non-Consent Election to the defaulting party at any time after the expiration of the thirty-day cure period following delivery of the Notice of Default, in which event if the billing is for the drilling a new well or the Plugging Back, Sidetracking, Reworking or Deepening of a well which is to be or has been plugged as a dry hole, or for the Completion or Recompletion of any well, the defaulting party will be conclusively deemed to have elected not to participate in the operation and to be a Non-Consenting Party with respect thereto under Article VI.B. or VI.C., as the case may be, to the extent of the costs unpaid by such party, notwithstanding any election to participate theretofore made. If election is made to proceed under this provision, then the non-defaulting parties may not elect to sue for the unpaid amount pursuant to Article VII.D.2.

Until the delivery of such Notice of Non-Consent Election to the defaulting party, such party shall have the right to cure its default by paying its unpaid share of costs plus interest at the rate set forth in Exhibit ‘C,” provided, however, such payment shall not prejudice the rights of the non-defaulting parties to pursue remedies for damages incurred by the non- defaulting patties as a result of the default. Any interest relinquished pursuant to this Article VII.D.3. shall be offered to the non-defaulting parties in proportion to their interests, and the non-defaulting parties electing to participate in the ownership of such interest shall be required to contribute their shares of the defaulted amount upon their election to participate therein.

4. Advance Payment: If a default is not cured within thirty (30) days of the delivery of a Notice of Default, Operator, or Non-Operators if Operator is the defaulting party, may thereafter require advance payment from the defaulting party of such defaulting party’s anticipated share of any item of expense for winch Operator, or Non-Operators, as the case may be, would be entitled to reimbursement under any provision of this agreement, whether or not such expense was the subject of the previous default. Such right includes, but is not limited to, the right to require advance payment for the estimated costs of drilling a well or Completion of a well as to which an election to participate in drilling or Completion has been made. If the defaulting party fails to pay the required advance payment, the non-defaulting parties may pursue any of the remedies provided in the Article VII.D. or any other default remedy provided elsewhere in this agreement. Any excess of funds advanced remaining when the operation is completed and all costs have been paid shall be promptly returned to the advancing party.

5. Costs and Attorneys’ Fees: In the event any party is required to bring legal proceedings to enforce any financial obligation of a party hereunder, the prevailing party in such action shall be entitled to recover all court costs, costs of collection, and a reasonable attorney’s fee, which the lien provided for herein shall also secure.

E. Rentals, Shut-in Well Payments and Minimum Royalties:

Rentals, shut-in well payments and minimum royalties which may be required under the terms of any lease shall be paid by the party or parties who subjected such lease to this agreement at its or their expense. In the event two or more parties own and have contributed interests in the same lease to this agreement, such parties may designate one of such parties to make said payments for and on behalf of all such parties. Any party may request, and shall be entitled to receive, proper evidence of all such payments. In the event of failure to make proper payment of any rental, shut-in well payment or minimum royalty through mistake or oversight where such payment is required to continue the lease in force, any loss which results from such non-payment shall be borne in accordance with the provisions of Article IV.B.2.

Operator shall notify Non-Operators of the anticipated completion of a shut-in well, or the shutting in or return to production of a producing well, at least five (5) days (excluding Saturday, Sunday, and legal holidays) prior to taking such action, or at the earliest opportunity permitted by circumstances, but assumes no liability for failure to do so. In the event of failure by Operator to so notify Non-Operators, the loss of any lease contributed hereto by Non-Operators for failure to make timely payments of any shut-in well payment shall be borne jointly by the parties hereto under the provisions of Article IV.B.3.

F. Taxes:

Beginning with the first calendar year after the effective date hereof, Operator shall render for ad valorem taxation all property subject to this agreement which by law should be rendered for such taxes, and it shall pay all such taxes assessed thereon before they become delinquent. Prior to the rendition date, each Non-Operator shall furnish Operator information as to burdens (to include, but not be limited to, royalties, overriding royalties and production payments) on Leases and Oil and Gas Interests contributed by such Non-Operator. If the assessed valuation of any Lease is reduced by reason of its being subject to outstanding excess royalties, overriding royalties or production payments, the reduction in ad valorem taxes resulting therefrom shall inure to the benefit of the owner or owners of such Lease, and Operator shall adjust the charge to such owner or owners so as to reflect the benefit of such reduction. If the ad valorem taxes are based in whole or in part upon separate valuations of each party’s working interest, then notwithstanding anything to the contrary herein, charges to the joint account shall be made and paid by the parties hereto in accordance with the tax value generated by each party’s working interest. Operator shall bill the other parties for their proportionate shares of all tax payments in the manner provided in Exhibit “C.”

- 16 -

A.A.P.L. FORM 610 - MODEL FORM OPERATION AGREEMENT – 1989

If Operator considers any tax assessment improper, Operator may, at its discretion, protest within the time and manner prescribed by law, and prosecute the protest to a final determination, unless all parties agree to abandon the protest prior to final determination. During the pendency of administrative or judicial proceedings, Operator may elect to pay, under protest, all such taxes and any interest and penalty. When any such protested assessment shall have been finally determined, Operator shall pay the tax for the joint account, together with any interest and penalty accrued, and the total cost shall then be assessed against the parties, and be paid by them, as provided in Exhibit ‘C.’

Each party shall pay or cause to be paid all production, severance, excise, gathering and other taxes imposed upon or with respect to the production or handling of such party’s share of Oil and Gas produced under the terms of this agreement.

ARTICLE VIII.

ACQUISITION, MAINTENANCE OR TRANSFER OF INTEREST

A. Surrender of Leases:

The Leases covered by this agreement, insofar as they embrace acreage in the Contract Area, shall not be surrendered in whole or in part unless all parties consent thereto.

However, should any party desire to surrender its interest in any Lease or in any portion thereof, such party shall give written notice of the proposed surrender to all parties, and the parties to whom such notice is delivered shall have thirty (30) days after delivery of the notice within which to notify the party proposing the surrender whether they elect to consent thereto. Failure of a party to whom such notice is delivered to reply within said 30-day period shall constitute a consent to the surrender of the Leases described in the notice. If all parties do not agree or consent thereto, the party desiring to surrender shall assign, without express or implied warranty of title, all of its interest in such Lease, or portion thereof, and any well, material and equipment which may be located thereon and any rights in production thereafter secured, to the parties not consenting to such surrender. If the interest of the assigning party is or includes an Oil and Gas Interest, the assigning party shall execute and deliver to the party or parties not consenting to such surrender an oil and gas lease covering such Oil and Gas Interest for a term of one (1) year and so long thereafter as Oil and/or Gas is produced from the land covered thereby, such lease to be on the form attached hereto as Exhibit “B.” Upon such assignment or lease, the assigning party shall be relieved from all obligations thereafter accruing, but not theretofore accrued, with respect to the interest assigned or leased and the operation of any well attributable thereto, and the assigning party shall have no further interest in the assigned or leased premises and its equipment and production other than the royalties retained in any lease made under the terms of this Article. The party assignee or lessee shall pay to the party assignor or lessor the reasonable salvage value of the latter’s interest in any well’s salvable materials and equipment attributable to the assigned or leased acreage. The value of all salvable materials and equipment shall be determined in accordance with the provisions of Exhibit ‘C,’ less the estimated cost of salvaging and the estimated cost of plugging and abandoning and restoring the surface. If such value is less than such costs, then the party assignor or lessor shall pay to the party assignee or lessee the amount of such deficit. If the assignment or lease is in favor of more than one party, the interest shall be shared by such parties in the proportions that the interest of each bears to the total interest of all such parties. If the interest of the parties to whom the assignment is to be made varies according to depth, then the interest assigned shall similarly reflect such variances.

Any assignment, lease or surrender made under this provision shall not reduce or change the assignor’s, lessor’s or surrendering party’s interest as it was immediately before the assignment, lease or surrender in the balance of the Contract Area; and the acreage assigned, leased or surrendered, and subsequent operations thereon, shall not thereafter be subject to the terms and provisions of this agreement but shall be deemed subject to an Operating Agreement in the form of this agreement.

B. Renewal or Extension of Leases:

If any party secures a renewal or replacement of an Oil and Gas Lease or Interest subject to this agreement, then all other parties shall be notified promptly upon such acquisition or, in the case of a replacement Lease taken before expiration of an existing Lease, promptly upon expiration of the existing Lease. The parties notified shall have the right for a period of thirty (30) days following delivery of such notice in which to elect to participate in the ownership of the renewal or replacement Lease, insofar as such Lease affects lands within the Contract Area, by paying to the party who acquired it their proportionate shares of the acquisition cost allocated to that part of such Lease within the Contract Area, which shall be in proportion to the interest held at that time by the parties in the Contract Area. Each party who participates in the purchase of a renewal or replacement Lease shall be given an assignment of its proportionate interest therein by the acquiring party.

If some, but less than all, of the parties elect to participate in the purchase of a renewal or replacement Lease, it shall be owned by the parties who elect to participate therein, in a ratio based upon the relationship of their respective percentage of participation in the Contract Area to the aggregate of the percentages of participation in the Contract Area of all parties participating in the purchase of such renewal or replacement Lease. The acquisition of a renewal or replacement Lease by any or all of the parties hereto shall not cause a readjustment of the interests of the parties stated in Exhibit “A,” but any renewal or replacement Lease in which less than all parties elect to participate shall not be subject to this agreement but shall be deemed subject to a separate Operating Agreement in the form of this agreement.

If the interests of the parties in the Contract Area vary according to depth, then their right to participate proportionately in renewal or replacement Leases and their right to receive an assignment of interest shall also reflect such depth variances.

The provisions of this Article shall apply to renewal or replacement Leases whether they are for the entire interest covered by the expiring Lease or cover only a portion of its area or an interest therein. Any renewal or replacement Lease taken before the expiration of its predecessor Lease, or taken or contracted for or becoming effective within six (6) months after the expiration of the existing Lease, shall be subject to this provision so long as this agreement is in effect at the time of such acquisition or at the time the renewal or replacement Lease becomes effective; but any Lease taken or contracted for more than six (6) months after the expiration of an existing Lease shall not be deemed a renewal or replacement Lease and shall not be subject to the provisions of this agreement.

The provisions in this Article shall also be applicable to extensions of Oil and Gas Leases.

C. Acreage or Cash Contributions:

While this agreement is in force, if any party contracts for a contribution of cash towards the drilling of a well or any other operation on the Contract Area, such contribution shall be paid to the party who conducted the drilling or other operation and shall be applied by it against the cost of such drilling or other operation. If the contribution be in the form of acreage, the party to whom the contribution is made shall promptly tender an assignment of the acreage, without warranty of title, to the Drilling Parties in the proportions said Drilling Parties shared the cost of drilling the well. Such acreage shall become a separate Contract Area and, to the extent possible, be governed by provisions identical to this agreement. Each party shall promptly notify all other parties of any acreage or cash contributions it may obtain in support of any well or any other operation on the Contract Area. The above provisions shall also be applicable to optional rights to earn acreage outside the Contract Area which are in support of well drilled inside Contract Area.

- 17 -

A.A.P.L. FORM 610 - MODEL FORM OPERATION AGREEMENT – 1989

If any party contracts for any consideration relating to disposition of such party’s share of substances produced hereunder, such consideration shall not be deemed a contribution as contemplated in this Article VIII.C.

D. Assignment; Maintenance of Uniform Interest:

For the purpose of maintaining uniformity of ownership in the Contract Area in the Oil and Gas Leases, Oil and Gas Interests, wells, equipment and production covered by this agreement no party shall sell, encumber, transfer or make other disposition of its interest in the Oil and Gas Leases and Oil and Gas Interests embraced within the Contract Area or in wells, equipment and production unless such disposition covers either

1. the entire interest of the party in all Oil and Gas Leases, Oil and Gas Interests, wells, equipment and production; or

2. an equal undivided percent of the party’s present interest in all Oil and Gas Leases, Oil and Gas Interests, wells, equipment and production in the Contract Area.

Every sale, encumbrance, transfer or other disposition made by any party shall be made expressly subject to this agreement and shall be made without prejudice to the right of the other parties, and any transferee of an ownership interest in any Oil and Gas Lease or Interest shall be deemed a party to this agreement as to the interest conveyed from and after the effective date of the transfer of ownership; provided, however, that the other parties shall not be required to recognize any such sale, encumbrance, transfer or other disposition for any purpose hereunder until thirty (30) days after they have received a copy of the instrument of transfer or other satisfactory evidence thereof in writing from the transferor or transferee. No assignment or other disposition of interest by a party shall relieve such party of obligations previously incurred by such party hereunder with respect to the interest transferred, including without limitation the obligation of a party to pay all costs attributable to an operation conducted hereunder in which such party has agreed to participate prior to making such assignment, and the lien and security interest granted by Article VII.B. shall continue to burden the interest transferred to secure payment of any such obligations.

If, at any time the interest of any party is divided among and owned by four or more co-owners, Operator, at its discretion, may require such co-owners to appoint a single trustee or agent with full authority to receive notices, approve expenditures, receive billings for and approve and pay such party’s share of the joint expenses, and to deal generally with, and with power to bind, the co-owners of such party’s interest within the scope of the operations embraced in this agreement; however, all such co- owners shall have the right to enter into and execute all contracts or agreements for the disposition of their respective shares of the Oil and Gas produced from the Contract Area and they shall have the right to receive, separately, payment of the sale proceeds thereof.

E. Waiver of Rights to Partition:

If permitted by the laws of the state or states in which the property covered hereby is located, each party hereto owning an undivided interest in the Contract Area waives any and all rights it may have to partition and have set aside to it in severalty its undivided interest therein.

F. Preferential Right to Purchase:

☐ (Optional; Check if applicable.)

Should any party desire to sell all or any part of its interests under this agreement, or its rights and interests in the Contract Area, it shall promptly give written notice to the other parties, with full information concerning its proposed disposition, which shall include the name and address of the prospective transferee (who must be ready, willing and able to purchase), the purchase price, a legal description sufficient to identify the property, and all other terms of the offer. The other parties shall then have an optional prior right, for a period of ten (10) days after the notice is delivered, to purchase for the stated consideration on the same terms and conditions the interest which the other party proposes to sell; and, if this optional right is exercised, the purchasing parties shall share the purchased interest in the proportions that the interest of each bears to the total interest of all purchasing parties. However, there shall be no preferential right to purchase in those cases where any party wishes to mortgage its interests, or to transfer title to its interests to its mortgagee in lieu of or pursuant to foreclosure of a mortgage of its interests, or to dispose of its interests by merger, reorganization, consolidation, or by sale of all or substantially all of its Oil and Gas assets to any party, or by transfer of its interests to a subsidiary or parent company or to a subsidiary of a parent company, or to any company in which such party owns a majority of the stock.

ARTICLE IX.

INTERNAL REVENUE CODE ELECTION

If, for federal income tax purposes, this agreement and the operations hereunder are regarded as a partnership, and if the parties have not otherwise agreed to form a tax partnership pursuant to Exhibit “G” or other agreement between them, each party thereby affected elects to be excluded from the application of all of the provisions of Subchapter “K,” Chapter 1, Subtitle “A,” of the Internal Revenue Code of 1986, as amended (“Code”), as permitted and authorized by Section 761 of the Code and the regulations promulgated thereunder. Operator is authorized and directed to execute on behalf of each party hereby affected such evidence of this election as may be required by the Secretary of the Treasury of the United States or the Federal Internal Revenue Service, including specifically, but not by way of limitation, all of the returns, statements, and the data required by Treasury Regulation §1.761. Should there be any requirement that each party hereby affected give further evidence of this election, each such party shall execute such documents and furnish such other evidence as may be required by the Federal Internal Revenue Service or as may be necessary to evidence this election. No such party shall give any notices or take any other action inconsistent with the election made hereby. If any present or future income tax laws of the state or states in which the Contract Area is located or any future income tax laws of the United States contain provisions similar to those in Subchapter “K,” Chapter 1, Subtitle “A,” of the Code, under which an election similar to that provided by Section 761 of the Code is permitted, each party hereby affected shall make such election as may be permitted or required by such laws. In making the foregoing election, each such party states that the income derived by such party from operations hereunder can be adequately determined without the computation of partnership taxable income.

ARTICLE X.

CLAIMS AND LAWSUITS

Operator may settle any single uninsured third party damage claim or suit arising from operations hereunder if the expenditure does not exceed One-Hundred-Thousand Dollars ($ 100,000) and if the payment is in complete settlement of such claim or suit. If the amount required for settlement exceeds the above amount, the parties hereto shall assume and take over the further handling of the claim or suit, unless such authority is delegated to Operator. All costs and expenses of handling settling, or otherwise discharging such claim or suit shall be at the joint expense of the parties participating in the operation from which the claim or suit arises. If a claim is made against any party or if any party is sued on account of any matter arising from operations hereunder over which such individual has no control because of the rights given Operator by this agreement, such party shall immediately notify all other parties, and the claim or suit shall be treated as any other claim or suit involving operations hereunder.

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A.A.P.L. FORM 610 - MODEL FORM OPERATION AGREEMENT – 1989

ARTICLE XI.

FORCE MAJEURE

If any party is rendered unable, wholly or in part, by force majeure to carry out its obligations under this agreement, other than the obligation to indemnify or make money payments or furnish security, that party shall give to all other parties prompt written notice of the force majeure with reasonably full particulars concerning it; thereupon, the obligations of the party giving the notice, so far as they are affected by the force majeure, shall be suspended during, but no longer than, the continuance of the force majeure. The term “force majeure,” as here employed, shall mean an act of God, strike, lockout, or other industrial disturbance, act of the public enemy, war, blockade, public riot, lightening, fire, storm, flood or other act of nature, explosion, governmental action, governmental delay, restraint or inaction, unavailability of equipment, and any other cause, whether of the kind specifically enumerated above or otherwise, which is not reasonably within the control of the party claiming suspension.

The affected party shall use all reasonable diligence to remove the force majeure situation as quickly as practicable. The requirement that any force majeure shall be remedied with all reasonable dispatch shall not require the settlement of strikes, lockouts, or other labor difficulty by the party involved, contrary to its wishes; how all such difficulties shall be handled shall be entirely within the discretion of the party concerned.

ARTICLE XII.

NOTICES

All notices authorized or required between the parties by any of the provisions of this agreement, unless otherwise specifically provided, shall be in writing and delivered in person or by United States mail, courier service, telegram, telex, telecopier or any other form of facsimile, postage or charges prepaid, and addressed to such parties at the addresses listed on Exhibit “A.” All telephone or oral notices permitted by this agreement shall be confirmed immediately thereafter by written notice. The originating notice given under any provision hereof shall be deemed delivered only when received by the party to whom such notice is directed, and the time for such party to deliver any notice in response thereto shall run from the date the originating notice is received. “Receipt” for purposes of this agreement with respect to written notice delivered hereunder shall be actual delivery of the notice to the address of the party to be notified specified in accordance with this agreement, or to the telecopy, facsimile or telex machine of such party. The second or any responsive notice shall be deemed delivered when deposited in the United States mail or at the office of the courier or telegraph service, or upon transmittal by telex, telecopy or facsimile, or when personally delivered to the party to be notified, provided, that when response is required within 24 or 48 hours, such response shall be given orally or by telephone, telex, telecopy or other facsimile within such period. Each party shall have the right to change its address at any time, and from time to time, by giving written notice thereof to all other parties. If a party is not available to receive notice orally or by telephone when a party attempts to deliver a notice required to be delivered within 24 or 48 hours, the notice may be delivered in writing by any other method specified herein and shall be deemed delivered in the same manner provided above for any responsive notice.

ARTICLE XIII.

TERM OF AGREEMENT

This agreement shall remain in full force and effect as to the Oil and Gas Leases and/or Oil and Gas Interests subject hereto for the period of time selected below, provided, however, no party hereto shall ever be construed as having any right, title or interest in or to any Lease or Oil and Gas Interest contributed by any other party beyond the term of this agreement.

☑ Option No. 1: So long as any of the Oil and Gas Leases subject to this agreement remain or are continued in force as to any part of the Contract Area, whether by production, extension, renewal or otherwise.

☐ Option No. 2: In the event the well described in Article VI.A., or any subsequent well drilled under any provision of this agreement, results in the Completion of a well as a well capable of production of Oil and/or Gas in paying quantities, this agreement shall continue in force so long as any such well is capable of production, and for an additional period of                  days thereafter; provided, however, if, prior to the expiration of such additional period, one or more of the parties hereto are engaged in drilling, Reworking, Deepening, Sidetracking, Plugging Back, testing or attempting to Complete or Re-complete a well or wells hereunder, this agreement shall continue in force until such operations have been completed and if production results therefrom, this agreement shall continue in force as provided herein. In the event the well described in Article VI.A., or any subsequent well drilled hereunder, results in a dry hole, and no other well is capable of producing Oil and/or Gas from the Contract Area, this agreement shall terminate unless drilling, Deepening, Sidetracking, Completing, Re- completing, Plugging Back or Reworking operations are commenced within                                                                       days from the date of abandonment of said well. “Abandonment” for such purposes shall mean either (i) a decision by all parties not to conduct any further operations on the well or (ii) the elapse of 180 days from the conduct of any operations on the well, whichever first occurs.

The termination of this agreement shall not relieve any party hereto from any expense, liability or other obligation or any remedy therefor which has accrued or attached prior to the date of such termination.

Upon termination of this agreement and the satisfaction of all obligations hereunder, in the event a memorandum of this Operating Agreement has been filed of record, Operator is authorized to file of record in all necessary recording offices a notice of termination, and each party hereto agrees to execute such a notice of termination as to Operator’s interest, upon request of Operator, if Operator has satisfied all its financial obligations.

ARTICLE XIV.

COMPLIANCE WITH LAWS AND REGULATIONS

A. Laws, Regulations and Orders:

This agreement shall be subject to the applicable laws of the state in which the Contract Area is located, to the valid rules, regulations, and orders of any duly constituted regulatory body of said state; and to all other applicable federal, state, and local laws, ordinances, rules, regulations and orders.

B. Governing Law:

This agreement and all matters pertaining hereto, including but not limited to matters of performance, non- performance, breach, remedies, procedures, rights, duties, and interpretation or construction, shall be governed and determined by the law of the slate in which the Contract Area is located. If the Contract Area is in two or more states, the law of the stale of Texas       shall govern.

C. Regulatory Agencies:

Nothing herein contained shall grant, or be construed to grant, Operator the right or authority to waive or release any rights, privileges, or obligations which Non-Operators may have under federal or state laws or under rules, regulations or orders promulgated under such laws in reference to oil gas and mineral operations, including the location, operation, or production of wells, on tracts offsetting or adjacent to the Contract Area.

- 19 -

A.A.P.L. FORM 610 - MODEL FORM OPERATION AGREEMENT – 1989

With respect to the operations hereunder, Non-Operators agree to release Operator from any and all losses, damages, injuries, claims and causes of action arising out of, incident to or resulting directly or indirectly from Operator’s interpretation or application of rules, rulings, regulations or orders of the Department of Energy or Federal Energy Regulatory Commission or predecessor or successor agencies to the extent such interpretation or application was made in good faith and does not constitute gross negligence. Each Non-Operator further agrees to reimburse Operator for such Non-Operator’s share of production or any refund, fine, levy or other governmental sanction that Operator may be required to pay as a result of such an incorrect interpretation or application, together with interest and penalties thereon owing by Operator as a result of such incorrect interpretation or application.

ARTICLE XV.

MISCELLANEOUS

A. Execution:

This agreement shall be binding upon each Non-Operator when this agreement or a counterpart thereof has been executed by such Non-Operator and Operator notwithstanding that this agreement is not then or thereafter executed by all of the parties to which it is tendered or which are listed on Exhibit “A” as owning an interest in the Contract Area or which own, in fact, an interest in the Contract Area. Operator may, however, by written notice to all Non-Operators who have become bound by this agreement as aforesaid, given at any time prior to the actual spud date of the Initial Well but in no event later than five days prior to the date specified in Article VI.A for commencement of the Initial Well, terminate this agreement if Operator in its sole discretion determines that there is insufficient participation to justify commencement of drilling operations. In the event of such a termination by Operator, all further obligations of the parties hereunder shall cease as of such termination. In the event any Non-Operator has advanced or prepaid any share of drilling or other costs hereunder, all sums so advanced shall be returned to such Non-Operator without interest. In the event Operator proceeds with drilling operations for the Initial Well without the execution hereof by all persons listed on Exhibit “A” as having a current working interest in such well, Operator shall indemnify Non-Operators with respect to all costs incurred for the Initial Well which would have been charged to such person under this agreement if such person had executed the same and Operator shall receive all revenues which would have been received by such person under this agreement if such person had executed the same.

B. Successors and Assigns:

This agreement shall be binding upon and shall inure to the benefit of the parties hereto and their respective heirs, devisees, legal representatives, successors and assigns, and the terms hereof shall be deemed to run with the Leases or Interests included within the Contract Area.

C. Counterparts:

This instrument may be executed in any number of counterparts, each of which shall be considered an original for all purposes.

D. Severability:

For the purposes of assuming or rejecting this agreement as an executory contract pursuant to federal bankruptcy laws, this agreement shall not be severable, but rather must be assumed or rejected in its entirety, and the failure of any party to this agreement to comply with all of its financial obligations provided herein shall be a material default.

ARTICLE XVI.

OTHER PROVISIONS

A. Conflict of Terms.

Notwithstanding anything in this Agreement to the control, in the event of any conflict between the provisions of Article I through Article XV of this Agreement and the provisions of this Article XVI, the provisions of this Article XVI shall control.

B. Priority of Operations — Horizontal Wells.

Notwithstanding Article VI.B.6 or anything else in this Agreement to the contrary, it is agreed that where a Horizontal or Multi-lateral Well subject to this Agreement has been drilled to the objective formation and the Consenting Parties cannot agree upon the sequence and timing of further operations regarding such Horizontal or Multi-lateral Well, the following elections shall control in the order of priority enumerated hereafter:

1. An election to do additional logging, coring, or testing;

2. An election to attempt to Complete all proposed Laterals;

3. An election to Deepen a Lateral;

4. An election to Sidetrack and drill an additional Lateral in the same formation;

5. An election to Sidetrack and drill an additional Lateral in a different formation:

6. An election to Plug Back the well to a formation or Zone above the formation in a which a Lateral was drilled: if there is more than one proposal to Plug Back, the proposal to Plug Back to the next deepest prospective Zone or formation shall have priority over a proposal to plug back to a shallower prospective Zone or formation; and

7. An election to plug and abandon said help as provided for in Article VI.F.

It is provided however, that if, at the time the Consenting Parties are considering any of the above elections, the hole is in such a condition that a reasonably prudent Operator would not conduct the operations contemplated by the particular involved for fear of placing the hole in jeopardy or losing the hole prior to Completing the Horizontal or Muti-lateral Well in the objective formation, such election shall be eliminated from priorities hereinabove set forth.

C. Relinquishment For Non-Consent Horizontal Drilling.

In the event any party to this Agreement elects not to participate in a Horizontal or Multi-lateral Well which is proposed pursuant to Article VI.B, the non-Consenting Parties shall, on commencement of operations for the Horizontal or Multi-lateral Well, relinquish to the Consenting Parties one hundred percent (100%) of the Non-Consenting Party’s right, title, and interest in and to that portion of the Contract Area included within the Drilling Unit for the Horizontal or Multi-lateral Well and one hundred percent (100%) of the Non-Consenting Party’s right, title, and interest in and to that portion of the Contract Area included within two adjacent Drilling Units to be selected by the Consenting Parties within thirty (30) days (inclusive of Saturdays, Sunday and legal holidays) from rig release of the Horizontal or Multi-lateral Well.

D. Replacement of Overtime with Affiliate

Operator may assign its rights, obligations, and function as Operator to an affiliate or related person or entity without the consent of Non-Operators, provided that such transfer: (a) fully complies with all applicable laws and regulations; and b) as subject to the Participation Agreement and this JOA.

E. Conflicts.

To the extent there is a conflict beta ern this JOA and the Participation Agreement, the terms of the Participation Agreement control.

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A.A.P.L. FORM 610 - MODEL FORM OPERATION AGREEMENT – 1989

IN WITNESS WHEREOF, this agreement shall be effective as of the            day of                                                   ,                .

                             , who has prepared and circulated this form for execution, represents and warrants that the form was printed from and, with the exception(s) listed below, is identical to the AAPL Form 610-1989 Model Form Operating Agreement, as published in computerized form by Forms On-A-Disk, Inc. No changes, alterations, or modifications, other than those made by strikethrough and/or insertion and that are clearly recognizable as changes in Articles                               , have been made to the form.

ATTEST OR WITNESS:	OPERATOR
	By
	Type or print name
	Title
	Date

Tax ID or S.S. No.

NON-OPERATORS
	By
	Type or print name
	Title
	Date

Tax ID or S.S. No.

By

Type or print name

Title

Date

Tax ID or S.S. No.

By

Type or print name

Title

Date

Tax ID or S.S. No.

- 1 -

A.A.P.L. FORM 610 - MODEL FORM OPERATION AGREEMENT – 1989

ACKNOWLEDGMENTS

Note: The following forms of acknowledgment are the short forms approved by the Uniform Law on Notarial Acts.The validity and effect of these forms in any state will depend upon the statutes of that state.

Individual acknowledgment:

State of                                  )

                                               ) ss.

County of                              )

                This instrument was acknowledged before me on

                                                                                                           by                                                                                                                                           

(Seal, if any)

Title (and Rank)

My commission expires:

Acknowledgment in representative capacity:

State of                                  )

                                               ) ss.

County of                              )

                This instrument was acknowledged before me on

                                                                      by                                                                                                                                                                            as

                                             of                                                                                                                                                                                                         

(Seal, if any)

Title (and Rank)

My commission expires:

- 2 -

Exhibit A

University Lands

Hudspeth County, Texas

Tract	UL Lease Number	Recording Information	Block	Section	Effective Date	Acreage
1	115099	138149	A	1	April 10, 2013	686.7
2	115100	138150	A	2	April 10, 2013	686.7
3	115101	138151	A	3	April 10, 2013	686.7
4	115102	138152	A	4	April 10, 2013	686.7
5	115103	138153	A	5	April 10, 2013	686.7
6	115104	138154	A	6	April 10, 2013	686.7
7	115105	138155	A	7	April 10, 2013	686.7
8	115106	138156	A	8	April 10, 2013	686.7
9	115107	138157	A	9	April 10, 2013	686.7
10	115108	138158	A	10	April 10, 2013	686.7
11	115109	138159	A	11	April 10, 2013	686.7
12	115110	138160	A	12	April 10, 2013	686.7
13	115111	138161	A	13	April 10, 2013	686.7
14	115112	138162	A	14	April 10, 2013	686.7
15	115113	138163	A	15	April 10, 2013	686.7
16	115114	138164	A	16	April 10, 2013	686.7
17	115115	138165	A	17	April 10, 2013	686.7
18	115116	138166	A	18	April 10, 2013	686.7
19	115117	138167	A	19	April 10, 2013	686.7
20	115118	138168	A	20	April 10, 2013	686.7
21	115119	138169	A	21	April 10, 2013	686.7
22	115120	138170	A	22	April 10, 2013	686.7
23	115121	138171	A	23	April 10, 2013	686.7
24	115122	138172	A	24	April 10, 2013	686.7
25	115123	138173	A	25	April 10, 2013	686.7
26	115124	138174	A	26	April 10, 2013	686.7
27	115125	138204	A	27	April 10, 2013	686.7
28	115126	138146	A	28	April 10, 2013	686.7
29	115127	138175	A	29	April 10, 2013	686.7
30	115128	138176	A	30	April 10, 2013	686.7
31	115129	138177	A	31	April 10, 2013	686.7
32	115130	138178	A	32	April 10, 2013	686.7
33	115131	138179	A	33	April 10, 2013	686.7
34	115132	138180	A	34	April 10, 2013	686.7
35	115133	138181	A	35	April 10, 2013	686.7
36	115134	138182	A	36	April 10, 2013	686.7
37	115135	138147	A	37	April 10, 2013	686.7

Tract	UL Lease Number	Recording Information	Block	Section	Effective Date	Acreage
38	115136	138183	A	38	April 10, 2013	686.7
39	115137	138184	A	39	April 10, 2013	686.7
40	115138	138185	A	40	April 10, 2013	686.7
41	115139	138186	A	41	April 10, 2013	686.7
42	115140	138187	A	42	April 10, 2013	686.7
43	115141	138188	A	43	April 10, 2013	686.7
44	115142	138189	A	44	April 10, 2013	686.7
45	115143	138190	A	45	April 10, 2013	686.7
46	115144	138191	A	46	April 10, 2013	686.7
47	115145	138192	A	47	April 10, 2013	686.7
48	115146	138193	A	48	April 10, 2013	686.7
49	115147	138194	B	1	April 10, 2013	686.7
50	115148	138195	B	2	April 10, 2013	686.7
51	115149	138196	B	3	April 10, 2013	686.7
52	115150	138197	B	4	April 10, 2013	686.7
53	115151	138198	B	5	April 10, 2013	686.7
54	115152	138199	B	6	April 10, 2013	686.7
55	115153	138200	B	7	April 10, 2013	686.7
56	115154	138201	B	8	April 10, 2013	686.7
57	115155	138202	B	9	April 10, 2013	686.7
58	115156	138203	B	10	April 10, 2013	686.7
59	115157	138205	B	11	April 10, 2013	686.7
60	115158	138206	B	12	April 10, 2013	686.7
61	115159	138207	B	13	April 10, 2013	686.7
62	115160	138208	B	14	April 10, 2013	686.7
63	115161	138209	B	15	April 10, 2013	686.7
64	115162	138210	B	16	April 10, 2013	686.7
65	115163	138211	B	17	April 10, 2013	686.7
66	115164	138212	B	18	April 10, 2013	686.7
67	115165	138213	B	19	April 10, 2013	686.7
68	115166	138214	B	20	April 10, 2013	686.7
69	115167	138215	B	21	April 10, 2013	686.7
70	115168	138216	B	22	April 10, 2013	686.7
71	115169	138217	B	23	April 10, 2013	686.7
72	115170	138218	B	24	April 10, 2013	686.7
73	11.5171	138219	B	25	April 10, 2013	686.7
74	115172	138148	B	26	April 10, 2013	686.7
75	115173	138220	B	27	April 10, 2013	686.7
76	115174	138221	B	28	April 10, 2013	686.7
77	115175	138222	B	29	April 10, 2013	686.7
78	115176	138223	B	30	April 10, 2013	686.7
79	115177	138224	B	31	April 10, 2013	686.7
80	115178	138225	B	32	April 10, 2013	686.7

Tract	UL Lease Number	Recording Information	Block	Section	Effective Date	Acreage
81	115179	138226	B	33	April 10, 2013	686.7
82	115180	138227	B	34	April 10, 2013	686.7
83	115181	138228	B	35	April 10, 2013	686.7
84	115182	138229	B	36	April 10, 2013	686.7
85	115183	138230	B	37	April 10, 2013	686.7
86	115184	138231	B	38	April 10, 2013	686.7
87	115185	138232	B	39	April 10, 2013	686.7
88	115186	138233	B	40	April 10, 2013	686.7
89	115187	138234	B	41	April 10, 2013	686.7
90	115188	138235	B	42	April 10, 2013	686.7
91	115189	138236	B	43	April 10, 2013	686.7
92	115190	138237	B	44	April 10, 2013	686.7
93	115191	138238	B	45	April 10, 2013	686.7
94	115192	138239	B	46	April 10, 2013	686.7
95	115193	138240	B	47	April 10, 2013	686.7
96	115194	138241	B	48	April 10, 2013	686.7
97	115195	138242	E	1	April 10, 2013	686.7
98	115196	138243	E	2	April 10, 2013	686.7
99	115197	138244	E	3	April 10, 2013	686.7
100	115198	138245	E	4	April 10, 2013	686.7
101	115199	138247	E	5	April 10, 2013	686.7
102	115200	138248	E	6	April 10, 2013	686.7
103	115201	138249	E	7	April 10, 2013	686.7
104	115202	138250	E	8	April 10, 2013	686.7
105	115203	138251	E	9	April 10, 2013	686.7
106	115204	138252	E	10	April 10, 2013	686.7
107	115205	138253	E	11	April 10, 2013	686.7
108	115206	138254	E	12	April 10, 2013	686.7
109	115207	138255	E	13	April 10, 2013	686.7
110	115208	138256	E	14	April 10, 2013	686.7
111	115209	138257	E	15	April 10, 2013	686.7
112	115210	138258	E	16	April 10, 2013	686.7
113	115211	138259	E	17	April 10, 2013	686.7
114	115212	138260	E	18	April 10, 2013	686.7
115	115213	138261	E	19	April 10, 2013	686.7
116	115214	138262	E	20	April 10, 2013	686.7
117	115215	138263	E	21	April 10, 2013	686.7
118	115216	138264	E	22	April 10, 2013	686.7
119	115217	138265	E	23	April 10, 2013	686.7
120	115218	138266	E	24	April 10, 2013	686.7
121	115219	138267	E	25	April 10, 2013	686.7
122	115220	138268	E	26	April 10, 2013	686.7
123	115221	138269	E	27	April 10, 2013	686.7

Tract	UL Lease Number	Recording Information	Block	Section	Effective Date	Acreage
124	115222	138270	E	28	April 10, 2013	686.7
125	115223	138271	E	29	April 10, 2013	686.7
126	115224	138272	E	30	April 10, 2013	686.7
127	115225	138273	E	31	April 10, 2013	686.7
128	115226	138274	E	32	April 10, 2013	686.7
129	115227	138275	E	33	April 10, 2013	686.7
130	115228	138276	E	34	April 10, 2013	686.7
131	115229	138277	E	35	April 10, 2013	686.7
132	115230	138278	E	36	April 10, 2013	686.7
133	115231	138279	E	37	April 10, 2013	686.7
134	115232	138280	E	38	April 10, 2013	686.7
135	115233	138281	E	39	April 10, 2013	686.7
136	115234	138282	E	40	April 10, 2013	686.7
137	115235	138283	E	41	April 10, 2013	686.7
138	115236	138284	E	42	April 10, 2013	686.7
139	115237	138285	E	43	April 10, 2013	686.7
140	115238	138286	E	44	April 10, 2013	686.7
141	115239	138287	E	45	April 10, 2013	686.7
142	115240	138288	E	46	April 10, 2013	686.7
143	115241	138289	E	47	April 10, 2013	686.7
144	115242	138290	E	48	April 10, 2013	686.7
145	115243	138291	F	1	April 10, 2013	686.7
146	115244	138292	F	2	April 10, 2013	686.7
147	115245	138293	F	3	April 10, 2013	686.7
148	115246	138294	F	4	April 10, 2013	686.7
149	115247	138295	F	5	April 10, 2013	686.7
150	115248	138296	F	6	April 10, 2013	686.7
151	115249	138297	F	7	April 10, 2013	686.7
152	115250	138298	F	8	April 10, 2013	686.7
153	115251	138299	F	9	April 10, 2013	686.7
154	115252	138300	F	10	April 10, 2013	686.7
155	115253	138301	F	11	April 10, 2013	686.7
156	115254	138302	F	12	April 10, 2013	686.7
157	115255	138303	F	13	April 10, 2013	686.7
158	115256	138304	F	14	April 10, 2013	686.7
159	115257	138305	F	15	April 10, 2013	686.7
160	115258	138306	F	16	April 10, 2013	686.7
161	115259	138307	F	17	April 10, 2013	686.7
162	115260	138308	F	18	April 10, 2013	686.7
163	115261	138309	F	19	April 10, 2013	686.7
164	115262	138310	F	20	April 10, 2013	686.7
165	115263	138311	F	21	April 10, 2013	686.7
166	115264	138312	F	22	April 10, 2013	686.7

Tract	UL Lease Number	Recording Information	Block	Section	Effective Date	Acreage
167	115265	138313	F	23	April 10, 2013	686.7
168	115266	138314	F	24	April 10, 2013	686.7
169	115267	138315	F	25	April 10, 2013	686.7
170	115268	138316	F	26	April 10, 2013	686.7
171	115269	138317	F	27	April 10, 2013	686.7
172	115270	138318	F	28	April 10, 2013	686.7
173	115271	138319	F	29	April 10, 2013	686.7
174	115272	138320	F	30	April 10, 2013	686.7
175	115273	138321	F	31	April 10, 2013	686.7
176	115274	138322	F	32	April 10, 2013	686.7
177	115275	138323	F	33	April 10, 2013	686.7
178	115276	138324	F	34	April 10, 2013	686.7
179	115277	138325	F	35	April 10, 2013	686.7
180	115278	138326	F	36	April 10, 2013	686.7
181	115279	138327	F	37	April 10, 2013	686.7
182	115280	138328	F	38	April 10, 2013	686.7
183	115281	138329	F	39	April 10, 2013	686.7
184	115282	138330	F	40	April 10, 2013	686.7
185	115283	138331	F	41	April 10, 2013	686.7
186	115284	138332	F	42	April 10, 2013	686.7
187	115285	138333	F	43	April 10, 2013	686.7
188	115286	138334	F	44	April 10, 2013	686.7
189	115287	138335	F	45	April 10, 2013	686.7
190	115288	138336	F	46	April 10, 2013	686.7
191	115289	138337	F	47	April 10, 2013	686.7
192	115290	138338	F	48	April 10, 2013	686.7

Cerro Alto Leases

Hudspeth County, Texas

1) Oil and Gas Lease dated December 1, 2012, by and between the State of Texas, acting by and through its agent, Cerro Alto, Ltd., a Texas limited partnership, as Lessor and Clay Johnson, a single man, as Lessee, being recorded in Document No. 20130007975 of the Official Public Records of El Paso County, Texas, and covering the following described lands:

BLOCK 1, PUBLIC SCHOOL LAND SURVEY

All of Sections 1, 2, 3, 10, 11, 12, 13, 14 and 24

2) Oil and Gas Lease dated December 1, 2012, by and between the State of Texas, acting by and through its agent, Cerro Alto, Ltd., a Texas limited partnership, as Lessor and Clay Johnson, a single man, as Lessee, being recorded in Document No. 00000137473 of the Official Public Records of Hudspeth County, Texas and covering the following described lands:

BLOCK 2, PUBLIC SCHOOL LAND SURVEY

All of Sections 2, 3, 4, 5, 6, 7, 9 and 11

3) Oil and Gas lease dated December 1, 2012, by and between the State of Texas, acting by and through its agent, Cerro Alto, Ltd., a Texas limited partnership, as Lessor and Clay Johnson, a single man, as Lessee, being recorded in Document No. 00000137472 of the Official Public Records of Hudspeth County, Texas and covering the following described lands:

BLOCK 4, PUBLIC SCHOOL LAND SURVEY

All of Sections 7, 8, 13, 14 and 15; 635.782 acres out of Section 17, being that portion lying North of Hwy. 62; 251.96 acres out of Section 19, being that portion lying North and West of Hwy. 62; 53.19 acres out of Section 20, being that portion lying North and East of Hwy. 62; and 333.46 acres out of Section 21, being that portion lying North and East of Hwy. 62

4) Oil and Gas Lease dated December 1, 2012, by and between the State of Texas, acting by and through its agent, Cerro Alto, Ltd., as Texas limited partnership, as Lessor and Clay Johnson, a single man, as Lessee, being recorded in Document No. 00000137471 of the Official Public Records of Hudspeth County, Texas and covering the following described lands:

BLOCK 4, PUBLIC SCHOOL LAND SURVEY

All of Sections 1, 2, 3, 4, 5, 6, 9, 10, 11 and 12, less a 653.00 acre tract of land being the description of a portion of the Russell Menzies Survey (Scrap File No. 15240), portion of Sections 1 and 12, Block 4, PSL Survey, Hudspeth County, Texas, and being more particularly described by metes and bounds in that certain General Warranty Deed dated September 9, 2004 from John and Estela Turner Family Limited Partnership to Jobe Concrete Products, Inc., recorded in Volume 251, Page 419, Deed Records, Hudspeth County, Texas.

5) Oil and Gas Lease dated December 1, 2012, by and between the State of Texas, acting by and through its agent, Cerro Alto, Ltd., a Texas limited partnership, as Lessor and Clay Johnson, a single man, as Lessee, being recorded in Document No. 00000137470 of the Official Public Records of Hudspeth County, Texas and covering the following described lands:

BLOCK 3, PUBLIC SCHOOL LAND SURVEY

All of Section 13, 16, 17, 18, 20, 21, 22, 23, and 24, less a 404.49 acre tract of land being the description of a portion of the Russell Menzies Survey (Scrap File No. 15240), portion of Sections 13 and 24, Block 3, PSL Survey, Hudspeth County, Texas, and being more particularly described by metes and bounds in that certain General Warranty Deed dated September 9, 2004 from John and Estela Turner Family Limited Partnership to Jobe Concrete Products, Inc., recorded in Volume 251, Page 419, Deed Records, Hudspeth County, Texas. The East Half of Section 19

BLOCK 3, PUBLIC SCHOOL LAND SURVEY

All of Sections 2, 3, 4, 9, 10, 11, 12, 14 and 15

6) Oil and Gas Lease dated December 1, 2012, by and between the State of Texas, acting by and through its agent, Cerro Alto, Ltd., a Texas limited partnership, as Lessor and Clay Johnson, a single man, as Lessee, being recorded in Document No. 00000137468 of the Official Public Records of Hudspeth County, Texas and covering the following described lands:

BLOCK 2, PUBLIC SCHOOL LAND SURVEY

All of Sections 15, 16, 17, 18, 19, 21, 22, 23 and 24

COPAS 2005 Accounting Procedure Recommended by COPAS

Exhibit “C”

ACCOUNTING PROCEDURE

JOINT OPERATIONS

Attached to and made part of Joint Operation Agreement dated June 4, 2014, with Hudspeth, Oil Corporation as Operator                                                     

I. GENERAL PROVISIONS

IF THE PARTIES FAIL TO SELECT EITHER ONE OF COMPETING “ALTERNATIVE” PROVISIONS, OR SELECT ALL THE COMPETING “ALTERNATIVE” PROVISIONS, ALTERNATIVE 1 IN EACH SUCH INSTANCE SHALL BE DEEMED TO HAVE BEEN ADOPTED BY THE PARTIES AS A RESULT OF ANY SUCH OMISSION OR DUPLICATE NOTATION.

IN THE EVENT THAT ANY “OPTIONAL” PROVISION OF THIS ACCOUNTING PROCEDURE IS NOT ADOPTED BY THE PARTIES TO THE AGREEMENT BY A TYPED, PRINTED OR HANDWRITTEN INDICATION, SUCH PROVISION SHALL NOT FORM A PART OF THIS ACCOUNTING PROCEDURE, AND NO INFERENCE SHALL BE MADE CONCERNING THE INTENT OF THE PARTIES IN SUCH EVENT.

1. DEFINITIONS

All terms used in this Accounting Procedure shall have the following meaning, unless otherwise expressly defined in the Agreement:

“Affiliate” means for a person, another person that controls, is controlled by, or is under common control with that person. In this definition, (a) control means the ownership by one person, directly or indirectly, of more than fifty percent (50%) of the voting securities of a corporation or, for other persons, the equivalent ownership interest (such as partnership interests), and (b) “person” means an individual, corporation, partnership, trust, estate, unincorporated organization, association, or other legal entity.

“Agreement” means the operating agreement, farmout agreement, or other contract between the Parties to which this Accounting Procedure is attached.

“Controllable Material” means Material that, at the time of acquisition or disposition by the Joint Account, as applicable, is so classified in the Material Classification Manual most recently recommended by the Council of Petroleum Accountants Societies (COPAS).

“Equalized Freight” means the procedure of charging transportation cost to the Joint Account based upon the distance from the nearest Railway Receiving Point to the property.

“Excluded Amount” means a specified excluded trucking amount most recently recommended by COPAS.

“Field Office” means a structure, or portion of a structure, whether a temporary or permanent installation, the primary function of which is to directly serve daily operation and maintenance activities of the Joint Property and which serves as a staging area for directly chargeable field personnel.

“First Level Supervision” means those employees whose primary function in Joint Operations is the direct oversight of the Operator’s field employees and/or contract labor directly employed On-site in a field operating capacity. First Level Supervision functions may include, but are not limited to:

• Responsibility for field employees and contract labor engaged in activities that can include field operations, maintenance, construction, well remedial work, equipment movement and drilling

• Responsibility for day-to-day direct oversight of rig operations

• Responsibility for day-to-day direct oversight of construction operations

• Coordination of job priorities and approval of work procedures

• Responsibility for optimal resource utilization (equipment, Materials, personnel)

• Responsibility for meeting production and field operating expense targets

• Representation of the Parties in local matters involving community, vendors, regulatory agents and landowners, as an incidental part of the supervisor’s operating responsibilities

• Responsibility for all emergency responses with field staff

• Responsibility for implementing safety and environmental practices

• Responsibility for field adherence to company policy

• Responsibility for employment decisions and performance appraisals for field personnel

• Oversight of sub-groups for field functions such as electrical, safety, environmental, telecommunications, which may have group or team leaders.

“Joint Account” means the account showing the charges paid and credits received in die conduct of the Joint Operations that are to be shared by the Parties, but does not include proceeds attributable to hydrocarbons and by-products produced under the Agreement.

“Joint Operations” means all operations necessary or proper for the exploration, appraisal, development, production, protection, maintenance, repair, abandonment, and restoration of the Joint Property.

COPYRIGHT © 2005 by Council of Petroleum Accountants Societies, Inc. (COPAS)

1

COPAS 2005 Accounting Procedure Recommended by COPAS

“Joint Property” means the real and personal property subject to the Agreement.

“Laws” means any laws, rules, regulations, decrees, and orders of the United States of America or any state thereof and all other governmental bodies, agencies, and other authorities having jurisdiction over or affecting the provisions contained in or the transactions contemplated by the Agreement or the Parties and their operations, whether such laws now exist or are hereafter amended, enacted, promulgated or issued.

“Material” means personal property, equipment, supplies, or consumables acquired or held for use by the Joint Property.

“Non-Operators” means the Parties to the Agreement other than the Operator.

“Offshore Facilities” means platforms, surface and subsea development and production systems, and other support systems such as oil and gas handling facilities, living quarters, offices, shops, cranes, electrical supply equipment and systems, fuel and water storage and piping, heliport, marine docking installations, communication facilities, navigation aids, and other similar facilities necessary in the conduct of offshore operations, all of which are located offshore.

“Off-site” means any location that is not considered On-site as defined in this Accounting Procedure.

“On-site” means on the Joint Property when in direct conduct of Joint Operations. The term “On-site” shall also include that portion of Offshore Facilities, Shore Base Facilities, fabrication yards, and staging areas from winch Joint Operations are conducted, or other facilities that directly control equipment on the Joint Property, regardless of whether such facilities are owned by the Joint Account.

“Operator” means the Party designated pursuant to the Agreement to conduct the Joint Operations.

“Parties” means legal entities signatory to the Agreement or their successors and assigns. Parties shall be referred to individually as “Party.”

“Participating Interest” means the percentage of the costs and risks of conducting an operation under the Agreement that a Party agrees, or is otherwise obligated, to pay and bear.

“Participating Party” means a Party that approves a proposed operation or otherwise agrees, or becomes liable, to pay and bear a share of the costs and risks of conducting an operation under the Agreement.

“Personal Expenses” means reimbursed costs for travel and temporary living expenses.

“Railway Receiving Point” means the railhead nearest the Joint Property for which freight rates are published, even though an actual railhead may not exist.

“Shore Base Facilities” means onshore support facilities that during Joint Operations provide such services to the Joint Property as a receiving and transshipment point for Materials; debarkation point for drilling and production personnel and services; communication, scheduling and dispatching center; and other associated functions serving the Joint Property.

“Supply Store” means a recognized source or common stock point for a given Material item.

“Technical Services” means services providing specific engineering, geoscience, or other professional skills, such as those performed by engineers, geologists, geophysicists, and technicians, required to handle specific operating conditions and problems for the benefit of Joint Operations; provided, however, Technical Services shall not include those functions specifically identified as overhead under the second paragraph of the introduction of Section III (Overhead). Technical Services may be provided by the Operator, Operator’s Affiliate, Non-Operator, Non-Operator Affiliates, and/or third parties.

2. STATEMENTS AND BILLINGS

The Operator shall bill Non-Operators on or before the last day of the month for their proportionate share of the Joint Account for the preceding month Such bills shall be accompanied by statements that identify the AFE (authority for expenditure), lease or facility, and all charges and credits summarized by appropriate categories of investment and expense. Controllable Material shall be separately identified and fully described in detail, or at the Operator’s option, Controllable Material may be summarized by major Material classifications. Intangible drilling costs, audit adjustments, and unusual charges and credits shall be separately and clearly identified.

The Operator may make available to Non-Operators any statements and bills required under Section I.2 and/or Section I.3.A (Advances and Payments by the Parties) via email, electronic data interchange, internet websites or other equivalent electronic media in lieu of paper copies. The Operator shall provide the Non-Operators instructions and any necessary information to access and receive the statements and bills within the timeframes specified herein. A statement or billing shall be deemed as delivered twenty-four (24) hours (exclusive of weekends and holidays) after the Operator notifies the Non-Operator that the statement or billing is available on the website and/or sent via email or electronic data interchange transmission. Each Non-Operator individually shall elect to receive statements and billings electronically, if available from the Operator, or request paper copies. Such election may be changed upon thirty (30) days prior written notice to the Operator.

COPYRIGHT © 2005 by Council of Petroleum Accountants Societies, Inc. (COPAS)

2

COPAS 2005 Accounting Procedure Recommended by COPAS

3. ADVANCES AND PAYMENTS BY THE PARTIES

A. Unless otherwise provided for in the Agreement, the Operator may require the Non-Operators to advance their share of the estimated cash outlay for the succeeding month’s operations within fifteen (15) days after receipt of the advance request or by the first day of the month for which the advance is required, whichever is later. The Operator shall adjust each monthly billing to reflect advances received from the Non-Operators for such month. If a refund is due, the Operator shall apply the amount to be refunded to the subsequent month’s billing or advance, unless the Non-Operator sends the Operator a written request for a cash refund. The Operator shall remit the refund to the Non-Operator within fifteen (15) days of receipt of such written request.

B. Except as provided below, each Party shall pay its proportionate share of all bills in full within fifteen (15) days of receipt date. If payment is not made within such time, the unpaid balance shall bear interest compounded monthly at the prime rate published by the Wall Street Journal, on the first day of each month the payment is delinquent, plus three percent (3%), per annum, or the maximum contract rate permitted by the applicable usury Laws governing the Joint Property, whichever is the lesser, plus attorney’s fees, court costs, and other costs in connection with the collection of unpaid amounts. If the Wall Street Journal ceases to be published or discontinues publishing a prime rate, the unpaid balance shall bear interest compounded monthly at the prime rate published by the Federal Reserve plus three percent (3%), per annum. Interest shall begin accruing on the first day of the month in which the payment was due. Payment shall not be reduced or delayed as a result of inquiries or anticipated credits unless the Operator has agreed. Notwithstanding the foregoing, the Non-Operator may reduce payment, provided it furnishes documentation and explanation to the Operator at the time payment is made, to the extent such reduction is caused by:

(1) being billed at an incorrect working interest or Participating Interest that is higher than such Non-Operator’s actual working interest or Participating Interest, as applicable, or

(2) being billed for a project or AFE requiring approval of the Parties under the Agreement that the Non-Operator has not approved or is not otherwise obligated to pay under the Agreement; or

(3) being billed for a property in which the Non-Operator no longer owns a working interest, provided the Non-Operator has furnished the Operator a copy of the recorded assignment or letter in-lieu. Notwithstanding the foregoing, the Non-Operatorshall remain responsible for paying bills attributable to the interest it sold or transferred for any bills rendered during the thirty(30) day period following the Operator’s receipt of such written notice; or

(4) charges outside the adjustment period, as provided in Section I.4 (Adjustments).

4. ADJUSTMENTS

A. Payment of any such bills shall not prejudice the right of any Party to protest or question the correctness thereof; however, all bills and statements, including payout statements, rendered during any calendar year shall conclusively be presumed to be true and correct, with respect only to expenditures, after twenty-four (24) months following the end of any such calendar year, unless within said period a Party takes specific detailed written exception thereto making a claim for adjustment. The Operator shall provide a response to all smitten exceptions, whether or not contained in an audit report, within the time periods prescribed in Section I.5 (Expenditure Audits).

B. All adjustments initiated by the Operator, except those described in items (1) through (4) of this Section I.4.B, are limited to the twenty-four (24) month period following the end of the calendar year in which the original charge appeared or should have appeared on the Operator’s Joint Account statement or payout statement. Adjustments that may be made beyond the twenty-four (24) month period are limited to adjustments resulting from the following:

(1) a physical inventory of Controllable Material as provided for in Section V (Inventories of Controllable Material), or

(2) an offsetting entry (whether in whole or in part) that is the direct result of a specific joint interest audit exception granted by the Operator relating to another property, or

(3) a government/regulatory audit, or

(4) a working interest ownership or Participating Interest adjustment.

5. EXPENDITURE AUDITS

A. A Non-Operator, upon written notice to the Operator and all other Non-Operators, shall have the right to audit the Operator’s accounts and records relating to the Joint Account within the twenty-four (24) month period following the end of such calendar year in which such bill was rendered; however, conducting an audit shall not extend the time for the taking of written exception to and the adjustment of accounts as provided for in Section I.4 (Adjustments). Any Party that is subject to payout accounting under the Agreement shall have the right to audit the accounts and records of the Party responsible for preparing the payout statements, or of the Party furnishing information to the Party responsible for preparing payout statements. Audits of payout accounts may include the volumes of hydrocarbons produced and saved and proceeds received for such hydrocarbons as they pertain to payout accounting required under the Agreement. Unless otherwise provided in the Agreement, audits of a payout account shall be conducted within the twenty-four (24) month period following the end of the calendar year in which the payout statement was rendered.

Where there are two or more Non-Operators, the Non-Operators shall make every reasonable effort to conduct a joint audit in a manner that will result in a minimum of inconvenience to the Operator. The Operator shall bear no portion of the Non-Operators’ audit cost incurred under this paragraph unless agreed to by the Operator. The audits shall not be conducted more than once each year without prior approval of the Operator, except upon the resignation or removal of the Operator, and shall be made at the expense of those Non-Operators approving such audit.

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The Non-Operator leading the audit (hereinafter “lead audit company”) shall issue the audit report within ninety (90) days after completion of the audit testing and analysis; however, the ninety (90) day time period shall not extend the twenty-four (24) month requirement for taking specific detailed written exception as required in Section I 4.A (Adjustments) above. All claims shall be supported with sufficient documentation.

A timely filed written exception or audit report containing written exceptions (hereinafter “written exceptions”) shall, with respect to the claims made therein, preclude the Operator from asserting a statute of limitations defense against such claims, and the Operator hereby waives its right to assert any statute of limitations defense against such claims for so long as any Non-Operator continues to comply with the deadlines for resolving exceptions provided in this Accounting Procedure. If the Non-Operators fail to comply with the additional deadlines in Section I.5.B or I.5.C, the Operator’s waiver of its rights to assert a statute of limitations defense against the claims brought by the Non-Operators shall lapse, and such claims shall then be subject to the applicable statute of limitations, provided that such waiver shall not lapse in the event that the Operator has failed to comply with the deadlines in Section 1.5.B or 1.5.C.

B. The Operator shall provide a written response to all exceptions in an audit report within one hundred eighty (180) days after Operator receives such report. Denied exceptions should be accompanied by a substantive response. If the Operator fails to provide substantive response to an exception within this one hundred eighty (180) day period, the Operator will owe interest on that exception or portion thereof, if ultimately granted, from the date it received the audit report. Interest shall be calculated using the rate set forth in Section I.3.B (Advances and Payments by the Parties).

C. The lead audit company shall reply to the Operator’s response to an audit report within ninety (90) days of receipt, and the Operator shall reply to the lead audit company’s follow-up response within ninety (90) days of receipt; provided, however, each Non-Operator shall have the right to represent itself if it disagrees with the lead audit company’s position or believes the lead audit company is not adequately fulfilling its duties. Unless otherwise provided for in Section 1.5.E, if the Operator fails to provide substantive response to an exception within this ninety (90) day period, the Operator will owe interest on that exception or portion thereof, if ultimately granted, from the date it received the audit report. Interest shall be calculated using the rate set forth in Section 1.3.B (Advances and Payments by the Parties).

D. If any Party fails to meet the deadlines in Sections I.5.B or I.5.C or if any audit issues are outstanding fifteen (15) months after Operator receives the audit report, the Operator or any Non-Operator participating itt the audit has the right to call a resolution meeting, as set forth in this Section I.5.D or it may invoke the dispute resolution procedures included in the Agreement, if applicable. The meeting will require one month’s written notice to the Operator and all Non-Operators participating in the audit. The meetingshall be held at the Operator’s office or mutually agreed location, and shall be attended by representatives of the Parties with authority to resolve such outstanding issues. Any Party who fails to attend the resolution meeting shall be bound by any resolution reached at the meeting. The lead audit company will make good faith efforts to coordinate the response and positions of the Non-Operator participants throughout the resolution process; however, each Non-Operator shall have the right to represent itself. Attendees will make good faith efforts to resolve outstanding issues, and each Party will be required to present substantive information supporting its position. A resolution meeting may be held as often as agreed to by the Parties. Issues unresolved at one meeting may be discussed at subsequent meetings until each such issue is resolved.

If the Agreement contains no dispute resolution procedures and the audit issues cannot be resolved by negotiation, the dispute shall be submitted to mediation. In such event, promptly following one Party’s written request for mediation, the Parties to the dispute shall choose a mutually acceptable mediator and share the costs of mediation services equally. The Parties shall each have present at the mediation at least one individual who has the authority to settle the dispute. The Parties shall make reasonable efforts to ensure that the mediation commences within sixty (60) days of the date of the mediation request. Notwithstanding the above, any Party may file a lawsuit or complaint (1) if the Parties are unable after reasonable efforts, to commence mediation within sixty (60)days of the date of the mediation request, (2) for statute of limitations reasons, or (3) to seek a preliminary injunction or other provisional judicial relief, if in its sole judgment an injunction or other provisional relief is necessary to avoid irreparable damage or to preserve the status quo Despite such action, the Parties shall continue to try to resolve the dispute by mediation.

E. ☐ (Optional Provision — Forfeiture Penalties)

If the Non-Operators fail to meet the deadline in Section I.5.C, any unresolved exceptions that were not addressed by the Non-Operators within one (1) year following receipt of the last substantive response of the Operator shall he deemed to have been withdrawn by the Non-Operators. If the Operator fails to meet the deadlines in Section I.5.13 or I.5.C, any unresolved exceptions that were not addressed by the. Operator within one (I) year following receipt of the audit report or receipt of the last substantive response of the Non-Operators, whichever is later, shall be deemed to have been granted by the Operator and adjustments shall be made, without interest, to the Joint Account.

6. APPROVAL BY PARTIES

A. GENERAL MATTERS

Where an approval or other agreement of the Parties or Non-Operators is expressly required under other Sections of this Accounting Procedure and if the Agreement to which this Accounting Procedure is attached contains no contrary provisions in regard thereto, the Operator shall notify all Non-Operators of the Operator’s proposal and the agreement or approval of a majority in interest of the Non-Operators shall be controlling on all Non-Operators.

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This Section I.6.A applies to specific situations of limited duration where a Party proposes to change the accounting for charges from that prescribed in this Accounting Procedure. This provision does not apply to amendments to this Accounting Procedure, which are covered by Section 1.6.B.

B. AMENDMENTS

If the Agreement to which this Accounting Procedure is attached contains no contrary provisions in regard thereto, this Accounting Procedure can be amended by an affirmative vote of One (1) or more Parties, one of which is the Operator, having a combined working interest of at least Fifty-One percent (    51    %), which approval shall be binding on all Parties, provided, however, approval of at least one (1) Non-Operator shall be required.

C. AFFILIATES

For the purpose of administering the voting procedures of Sections I.6.A and I.6.B, if Parties to this Agreement are Affiliates of each other, then such Affiliates shall be combined and treated as a single Party having the combined working interest or Participating Interest of such Affiliates.

For the purposes of administering the voting procedures in Section I.6.A, if a Non-Operator is an Affiliate of the Operator, votes under Section I.6.A shall require the majority in interest of the Non-Operator(s) after excluding the interest of the Operator’s Affiliate.

II. DIRECT CHARGES

The Operator shall charge the Joint Account with the following items:

1. RENTALS AND ROYALTIES

Lease rentals and royalties paid by the Operator, on behalf of all Parties, for the Joint Operations.

2. LABOR

A. Salaries and wages, including incentive compensation programs as set forth in COPAS MFI-37 (“Chargeability of Incentive Compensation Programs”), for:

(1) Operator’s field employees directly employed On-site in the conduct of Joint Operations,

(2) Operator’s employees directly employed on Shore Base Facilities, Offshore Facilities, or other facilities serving the Joint Property if such costs are not charged under Section II.6 (Equipment and Facilities Furnished by Operator) or are not a function covered under Section III (Overhead),

(3) Operator’s employees providing First Level Supervision,

(4) Operator’s employees providing On-site Technical Services for the Joint Property if such charges are excluded from the overhead rates in Section III (Overhead),

(5) Operator’s employees providing Off-site Technical Services for the Joint Property if such charges are excluded from the overhead rates in Section III (Overhead).

Charges for the Operator’s employees identified in Section II.2.A may be made based on the employee’s actual salaries and wages, or in lieu thereof, a day rate representing the Operator’s average salaries and wages of the employee’s specific job category.

Charges for personnel chargeable under this Section II.2.A who are foreign nationals shall not exceed comparable compensation paid to an equivalent U.S. employee pursuant to this Section II.2.B, unless otherwise approved by the Parties pursuant to Section 1.6.A (General Matters).

B. Operator’s cost of holiday, vacation, sickness, and disability benefits, and other customary allowances paid to employees whose salaries and wages are chargeable to the Joint Account under Section II.2.A. excluding severance payments or other termination allowances. Such costs under this Section II.2.13 may be charged on a “when and as-paid basis” or by “percentage assessment” on the amount of salaries and wages chargeable to the Joint Account under Section II.2.A. If percentage assessment is used, the rate shall be based on the Operator’s cost experience.

C. Expenditures or contributions made pursuant to assessments imposed by governmental authority that are applicable to costs chargeable to the Joint Account under Sections II.2.A and B.

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D. Personal Expenses of personnel whose salaries and wages are chargeable to the Joint Account under Section II.2.A when the expenses are incurred in connection with directly chargeable activities.

E. Reasonable relocation costs incurred in transferring to the Joint Property personnel whose salaries and wages are chargeable to the Joint Account under Section II.2.A. Notwithstanding the foregoing, relocation costs that result from reorganization or merger of a Party, or that are for the primary benefit of the Operator, shall not be chargeable to the Joint Account. Extraordinary relocation costs, such as those incurred as a result of transfers from remote locations, such as Alaska or overseas, shall not be charged to the Joint Account unless approved by the Parties pursuant to Section I.6.A (General Matters).

F. Training costs as specified in COPAS MFI-35 (“Charging of Training Costs to the Joint Account”) for personnel whose salaries and wages are chargeable under Section II.2.A. This training charge shall include the wages, salaries, training course cost, and Personal Expenses incurred during the training session. The training cost shall be charged or allocated to the property or properties directly benefiting from the training. The cost of the training course shall not exceed prevailing commercial rates, where such rates are available.

G. Operator’s current cost of established plans for employee benefits, as described in COPAS MFI-27 (“Employee Benefits Chargeable to Joint Operations and Subject to Percentage Limitation”), applicable to the Operator’s labor costs chargeable to the Joint Account under Sections 11.2.A and B based on the Operator’s actual cost not to exceed the employee benefits limitation percentage most recently recommended by COPAS.

H. Award payments to employees, in accordance with COPAS MFI-49 (“Awards to Employees and Contractors”) for personnel whose salaries and wages are chargeable under Section 11.2.A.

3. MATERIAL

Material purchased or furnished by the Operator for use on the Joint Property in the conduct of Joint Operations as provided under Section IV (Material Purchases, Transfers, and Dispositions). Only such Material shall be purchased for or transferred to the Joint Property as may be required for immediate use or is reasonably practical and consistent with efficient and economical operations. The accumulation of surplus stocks shall be avoided.

4. TRANSPORTATION

A. Transportation of the Operator’s, Operator’s Affiliate’s, or contractor’s personnel necessary for Joint Operations.

B. Transportation of Material between the Joint Property and another property, or from the Operator’s warehouse or other storage point to the Joint Property, shall be charged to the receiving property using one of the methods listed below. Transportation of Material from the Joint Property to the Operator’s warehouse or other storage point shall be paid for by the Joint Property using one of the methods listed below:

(1) If the actual trucking charge is less than or equal to the Excluded Amount the Operator may charge actual trucking cost or a theoretical charge from the Railway Receiving Point to the Joint Property. The basis for the theoretical charge is the per hundred weight charge plus fuel surcharges from the Railway Receiving Point to the Joint Property. The Operator shall consistently apply the selected alternative.

(2) If the actual trucking charge is greater than the Excluded Amount, the Operator shall charge Equalized Freight. Accessorial charges such as loading and unloading costs, split pick-up costs, detention, call out charges, and permit fees shall be charged directly to the Joint Property and shall not be included when calculating the Equalized Freight.

5. SERVICES

The cost of contract services, equipment, and utilities used in the conduct of Joint Operations, except for contract services, equipment, and utilities covered by Section III (Overhead), or Section II.7 (Affiliates), or excluded under Section II.9 (Legal Expense). Awards paid to contractors shall be chargeable pursuant to COPAS MF1-49 (“Awards to Employees and Contractors”).

The costs of third party Technical Services are chargeable to the extent excluded from the overhead rates under Section III (Overhead).

6. EQUIPMENT AND FACILITIES FURNISHED BY OPERATOR

In the absence of a separately negotiated agreement, equipment and facilities famished by the Operator will be charged as follows:

A. The Operator shall charge the Joint Account for use of Operator-owned equipment and facilities, including but not limited to production facilities, Shore Base Facilities, Offshore Facilities, and Field Offices, at rates commensurate with the costs of ownership and operation. The cost of Field Offices shall be chargeable to the extent the Field Offices provide direct service to personnel who are chargeable pursuant to Section II.2.A (Labor). Such rates may include labor, maintenance, repairs, other operating expense, insurance, taxes, depreciation using straight line depreciation method, and interest on gross investment less accumulated depreciation not to exceed     Twenty     percent (    20    %) per annum; provided, however, depreciation shall not be charged when the

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equipment and facilities investment have been fully depreciated. The rate may include an element of the estimated cost for abandonment, reclamation, and dismantlement. Such rates shall not exceed the average commercial rates currently prevailing in the immediate area of the Joint Property.

B. In lieu of charges in Section II.6.A above, the Operator may elect to use average commercial rates prevailing in the immediate area of the Joint Property, less twenty percent (20%). If equipment and facilities are charged under this Section II.6.B, the Operator shall adequately document and support commercial rates and shall periodically review and update the rate and the supporting documentation. For automotive equipment, the Operator may elect to use rates published by the Petroleum Motor Transport Association (PMTA) or such other organization recognized by COPAS as the official source of rates.

7. AFFILIATES

A. Charges for an Affiliate’s goods and/or services used in operations requiring an AFE or other authorization front the Non-Operators may be made without the approval of the Parties provided (i) the Affiliate is identified and the Affiliate goods and services are specifically detailed in the approved AFE or other authorization, and (ii) the total costs for such Affiliate’s goods and services billed to such individual project do not exceed $ 2,000,1100                 If the total costs for an Affiliate’s goods and services charged to such individual project are not specifically detailed in the approved AFE or authorization or exceed such amount, charges for such Affiliate shall require approval of the Parties, pursuant to Section I.6.A (General Matters).

B. For an Affiliate’s goods and/or services used in operations not requiring an AFE or other authorization from the Non-Operators, charges for such Affiliate’s goods and services shall require approval of the Parties, pursuant to Section 1.6.A (General Matters), if the charges exceed $ 6,000,000                 in a given calendar year.

C. The cost of the Affiliate’s goods or services shall not exceed average commercial rates prevailing in the area of the Joint Property, unless the Operator obtains the Non-Operators’ approval of such rates. The Operator shall adequately document and support commercial rates and shall periodically review and update the rate and the supporting documentation; provided, however, documentation of commercial rates shall not be required if the Operator obtains Non-Operator approval of its Affiliate’s rates or charges prior to billing Non-Operators for such Affiliate’s goods and services. Notwithstanding the foregoing, direct charges for Affiliate-owned communication facilities or systems shall be made pursuant to Section II.12 (Communications).

If the Parties fail to designate an amount in Sections II.7.A or II.7.13, in each instance the amount deemed adopted by the Parties as a result of such omission shall be the amount established as the Operator’s expenditure limitation in the Agreement. If the Agreement does not contain an Operator’s expenditure limitation, the amount deemed adopted by the Parties as a result of such omission shall be zero dollars ($ 0.00).

8. DAMAGES AND LOSSES TO JOINT PROPERTY

All costs or expenses necessary for the repair or replacement of Joint Property resulting from damages or losses incurred, except to the extent such damages or losses result from a Party’s or Parties’ gross negligence or willful misconduct, in which case such Party or Parties shall be solely liable.

The Operator shall furnish the Non-Operator written notice of damages or losses incurred as soon as practicable after a report has been received by the Operator.

9. LEGAL EXPENSE

Recording fees and costs of handling, settling, or otherwise discharging litigation, claims, and liens incurred in or resulting from operations under the Agreement, or necessary to protect or recover the Joint Property, to the extent permitted under the Agreement. Costs of the Operator’s or Affiliate’s legal staff or outside attorneys, including fees and expenses, are not chargeable unless approved by the Parties pursuant to Section I.6.A (General Matters) or otherwise provided for in the Agreement.

Notwithstanding the foregoing paragraph, costs for procuring abstracts, fees paid to outside attorneys for title examinations (including preliminary, supplemental, shut-in royalty opinions, division order title opinions), and curative work shall be chargeable to the extent permitted as a direct charge in the Agreement.

10. TAXES AND PERMITS

All taxes and permitting fees of every kind and nature, assessed or levied upon or in connection with the Joint Property, or the production therefrom, and which have been paid by the Operator for the benefit of the Parties, including penalties and interest, except to the extent the penalties and interest result from the Operator’s gross negligence or willful misconduct.

If ad valorem taxes paid by the Operator are based in whole or in part upon separate valuations of each Party’s working interest, then notwithstanding any contrary provisions, the charges to the Parties will be made in accordance with the tax value generated by each Party’s working interest.

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Costs of tax consultants or advisors, the Operator’s employees, or Operator’s Affiliate employees in matters regarding ad valorem or other tax matters, are not permitted as direct charges unless approved by the Parties pursuant to Section I.6.A (General Matters).

Charges to the Joint Account resulting from sales/use tax audits, including extrapolated amounts and penalties and interest, are permitted, provided the Non-Operator shall be allowed to review the invoices and other underlying source documents which served as the basis for tax charges and to determine that the correct amount of taxes were charged to the Joint Account. If the Non-Operator is not permitted to review such documentation, the sales/use tax amount shall not be directly charged unless the Operator can conclusively document the amount owed by the Joint Account.

11. INSURANCE

Net premiums paid for insurance required to be carried for Joint Operations for the protection of the Parties. If Joint Operations are conducted at locations where the Operator acts as self-insurer in regard to its worker’s compensation and employer’s liability insurance obligation, the Operator shall charge the Joint Account manual rates for the risk assumed in its self-insurance program as regulated by the jurisdiction governing the Joint Property. In the case of offshore operations in federal waters, the manual rates of the adjacent state shall be used for personnel performing work On-site, and such rates shall be adjusted for offshore operations by the U.S. Longshoreman and Harbor Workers (USL&H) or Jones Act surcharge, as appropriate.

12. COMMUNICATIONS

Costs of acquiring, leasing, installing, operating, repairing, and maintaining communication facilities or systems, including satellite, radio and microwave facilities, between the Joint Property and the Operator’s office(s) directly responsible for field operations in accordance with the provisions of COPAS MFI-44 (“Field Computer and Communication Systems”). If the communications facilities or systems serving the Joint Property are Operator-owned, charges to the Joint Account shall be made as provided in Section 11.6 (Equipment and Facilities Furnished by Operator). If the communication facilities or systems serving the Joint Property are owned by the Operator’s Affiliate, charges to the Joint Account shall not exceed average commercial rates prevailing in the area of the Joint Property. The Operator shall adequately document and support commercial rates and shall periodically review and update the rate and the supporting documentation.

13. ECOLOGICAL ENVIRONMENTAL, AND SAFETY

Costs incurred for Technical Services and drafting to comply with ecological, environmental and safety Laws or standards recommended by Occupational Safety and Health Administration (OSHA) or other regulatory authorities. All other labor and functions incurred for ecological, environmental and safety matters, including management, administration, and permitting, shall be covered by Sections II.2 (Labor), II.5 (Services), or Section III (Overhead), as applicable.

Costs to provide or have available pollution containment and removal equipment plus actual costs of control and cleanup and resulting responsibilities of oil and other spills as well as discharges from permitted outfalls as required by applicable Laws, or other pollution containment and removal equipment deemed appropriate by the Operator for prudent operations, are directly chargeable.

14. ABANDONMENT AND RECLAMATION

Costs incurred for abandonment and reclamation of the Joint Property, including costs required by lease agreements or by Laws.

15. OTHER EXPENDITURES

Any other expenditure not covered or dealt with in the foregoing provisions of this Section II (Direct Charges), or in Section III (Overhead) and which is of direct benefit to the Joint Property and is incurred by the Operator in the necessary and proper conduct of the Joint Operations. Charges made under this Section II.15 shall require approval of the Parties, pursuant to Section I.6.A (General Matters).

III. OVERHEAD

As compensation for costs not specifically identified as chargeable to the Joint Account pursuant to Section II (Direct Charges), the Operator shall charge the Joint Account in accordance with this Section III.

Functions included in the overhead rates regardless of whether performed by the Operator, Operator’s Affiliates or third parties and regardless of location, shall include, but not be limited to, costs and expenses of:

• warehousing, other than for warehouses that are jointly owned under this Agreement

• design and drafting (except when allowed as a direct charge under Sections II.13, III.1.A(ii), and III.2, Option B)

• inventory costs not chargeable under Section V (Inventories of Controllable Material)

• procurement

• administration

• accounting and auditing

• gas dispatching and gas chart integration

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• human resources

• management

• supervision not directly charged under Section II.2 (Labor)

• legal services not directly chargeable under Section II.9 (Legal Expense)

• taxation, other than those costs identified as directly chargeable under Section II.10 (Taxes and Permits)

• preparation and monitoring of permits and certifications; preparing regulatory reports; appearances before or meetings with governmental agencies or other authorities having jurisdiction over the Joint Property, other than On-site inspections; reviewing, interpreting, or submitting comments on or lobbying with respect to Laws or proposed Laws.

Overhead charges shall include the salaries or wages plus applicable payroll burdens, benefits, and Personal Expenses of personnel performing overhead functions, as well as office and other related expenses of overhead functions.

1. OVERHEAD—DRILLING AND PRODUCING OPERATIONS

As compensation for costs incurred but not chargeable under Section II (Direct Charges) and not covered by other provisions of this Section III, the Operator shall charge on either

☐ (Alternative 1) Fixed Rate Basis, Section III.1.B.

☐ (Alternative 2) Percentage Basis, Section III.1.C.

A. TECHNICAL SERVICES

(i) Except as otherwise provided in Section II.13 (Ecological, Environmental, and Safety) and Section III.2 (Overhead - Major Construction and Catastrophe), or by approval of the Parties pursuant to Section I.6.A (General Matters), the salaries, wages, related payroll burdens and benefits, and Personal Expenses for On-site Technical Services, including third party Technical Services:

☑ (Alternative 1 — Direct) shall be charged direct to the Joint Account.

☐ (Alternative 2 — Overhead) shall be covered by the overhead rates.

(ii) Except as otherwise provided in Section II.13 (Ecological, Environmental, and Safety) and Section III.2 (Overhead – Major Construction and Catastrophe), or by approval of the Parties pursuant to Section I.6.A (General Matters), the salaries, wages, related payroll burdens and benefits, and Personal Expenses for OR-site Technical Services, including third party Technical Services:

☐ (Alternative 1 — All Overhead) shall be covered by the overhead rates.

☑ (Alternative 2 — All Direct) shall be charged direct to the Joint Account.

☐ (Alternative 3 — Drilling Direct) shall be charged direct to the Joint Account, only to the extent such Technical Services are directly attributable to drilling, redrilling, deepening, or sidetracking operations, through completion, temporary abandonment, or abandonment if a dry hole. Off-site Technical Services for all other operations, including workover, recompletion, abandonment of producing wells, and the construction or expansion of fixed assets not covered by Section III.2 (Overhead - Major Construction and Catastrophe) shall be covered by the overhead rates.

Notwithstanding anything to the contrary in this Section III, Technical Services provided by Operator’s Affiliates are subject to limitations set forth in Section II.7 (Affiliates). Charges for Technical personnel performing non-technical work shall not be governed by this Section III.1.A, but instead governed by other provisions of this Accounting Procedure relating to the type of work being performed.

B. OVERHEAD—FIXED RATE BASIS

(1) The Operator shall charge the Joint Account at the following rates per well per month:

Drilling Well Rate per month $ 5.500                 (prorated for less than a full month)

Producing Well Rate per month $ 550                

(2) Application of Overhead—Drilling Well Rate shall be as follows:

(a) Charges for onshore drilling wells shall begin on the spud date and terminate on the date the drilling and/or completion equipment used on the well is released, whichever occurs later. Charges for offshore and inland waters drilling wells shall begin on the date the drilling or completion equipment arrives on location and terminate on the date the drilling or completion equipment moves off location, or is released, whichever occurs first. No charge shall be made during suspension of drilling and/or completion operations for fifteen (15) or more consecutive calendar days.

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(b) Charges for any well undergoing any type of workover, recompletion, and/or abandonment for a period of five (5) or more consecutive work-days shall be made at the Drilling Well Rate. Such charges shall be applied for the period from date operations, with rig or other units used in operations, commence through date of rig or other unit release, except that no charges shall be made during suspension of operations for fifteen (15) or more consecutive calendar days.

(3) Application of Overhead—Producing Well Rate shall be as follows:

(a) An active well that is produced, injected into for recovery or disposal, or used to obtain water supply to support operations for any portion of the month shall be considered as a one-well charge for the entire month.

(b) Each active completion in a multi-completed well shall be considered as a one-well charge provided each completion is considered a separate well by the governing regulatory authority.

(c) A one-well charge shall be made for the month in which plugging and abandonment operations are completed on any well, unless the Drilling Well Rate applies, as provided in Sections III.1.B.(2)(a) or (b). This one-well charge shall be made whether or not the well has produced.

(d) An active gas well shut in because of overproduction or failure of a purchaser, processor, or transporter to take production shall be considered as a one-well charge provided the gas well is directly connected to a permanent sales outlet.

(e) Any well not meeting the criteria set forth in Sections III.1.B.(3)(a), (b), (c), or (d) shall not qualify for a producing overhead charge.

(4) The well rates shall be adjusted on the first day of April each year following the effective date of the Agreement; provided, however, if this Accounting Procedure is attached to or otherwise governing the payout accounting under a farmout agreement, the rates shall be adjusted on the first day of April each year following the effective date of such farmout agreement. The adjustment shall be computed by applying the adjustment factor most recently published by COPAS. The adjusted rates shall be the initial or amended rates agreed to by the Parties increased or decreased by the adjustment factor described herein, for each year from the effective date of such rates, in accordance with COPAS MFI-47 (“Adjustment of Overhead Rates”).

C. OVERHEAD—PERCENTAGE BASIS

(1) Operator shall charge the Joint Account at the following rates:

(a) Development Rate                     percent (        )’% of the cost of development of the Joint Property, exclusive of costs provided under Section II.9 (Legal Expense) and all Material salvage credits.

(b) Operating Rate                     percent (    %) of the cost of operating the Joint Property, exclusive of costs provided under Sections II.1 (Rentals and Royalties) and II.9 (Legal Expense); all Material salvage credits; the value of substances purchased for enhanced recovery; all property and ad valorem taxes, and any other taxes and assessments that are levied, assessed, and paid upon the mineral interest in and to the Joint Property.

(2) Application of Overhead—Percentage Basis shall be as follows:

(a) The Development Rate shall be applied to all costs in connection with:

[i] drilling, redrilling, sidetracking, or deepening of a well

[ii] a well undergoing plugback or workover operations for a period of five (5) or more consecutive work-days

[iii] preliminary expenditures necessary in preparation for drilling

[iv] expenditures incurred in abandoning when the well is not completed as a producer

[v] construction or installation of fixed assets, the expansion of fixed assets and any other project clearly discernible as a fixed asset, other than Major Construction or Catastrophe as defined in Section III.2 (Overhead-Major Construction and Catastrophe).

(b) The Operating Rate shall be applied to all other costs in connection with Joint Operations, except those subject to Section III.2 (Overhead-Major Construction and Catastrophe).

2. OVERHEAD—MAJOR CONSTRUCTION AND CATASTROPHE

To compensate the Operator for overhead costs incurred in connection with a Major Construction project or Catastrophe, the Operator shall either negotiate a rate prior to the beginning of the project, or shall charge the Joint Account for overhead based on the following rates for any Major Construction project in excess of the Operator’s expenditure limit under the Agreement, or for any Catastrophe regardless of the amount. If the Agreement to which this Accounting Procedure is attached does not contain an expenditure limit, Major Construction Overhead shall be assessed for any single Major Construction project costing in excess of $100,000 gross.

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Major Construction shall mean the construction and installation of fixed assets, the expansion of fixed assets, and any other project clearly discernible as a fixed asset required for the development and operation of the Joint Property, or in the dismantlement, abandonment, removal, and restoration of platforms, production equipment, and other operating facilities.

Catastrophe is defined as a sudden calamitous event bringing damage, loss, or destruction to property or the environment, such as an oil spill, blowout, explosion, fire, storm, hurricane, or other disaster. The overhead rate shall be applied to those costs necessary to restore the Joint Property to the equivalent condition that existed prior to the event.

A. If the Operator absorbs the engineering, design and drafting costs related to the project:

(1)                 % of total costs if such costs are less than $100,000; plus

(2)                 % of total costs in excess of $100,000 but less than $1,000,000, plus

(3)                 % of total costs in excess of $1,000,000.

B. If the Operator charges engineering, design and drafting costs related to the project directly to the Joint Account:

(1)                 % of total costs if such costs are less than $100,000; plus

(2)                 % of total costs in excess of $100,000 but less than $1,000,000; plus

(3)                 % of total costs in excess of $1,000,000.

Total cost shall mean the gross cost of any one project. For the purpose of this paragraph, the component parts of a single Major Constriction project shall not be treated separately, and the cost of drilling and workover wells and purchasing and installing pumping units and downhole artificial lift equipment shall be excluded. For Catastrophes, the rates shall be applied to all costs associated with each single occurrence or event.

On each project, the Operator shall advise the Non-Operator(s) in advance which of the above options shall apply.

For the purposes of calculating Catastrophe Overhead, the cost of drilling relief wells, substitute wells, or conducting other well operations directly resulting from the catastrophic event shall be included. Expenditures to which these rates apply shall not be reduced by salvage or insurance recoveries. Expenditures that qualify for Major Construction or Catastrophe Overhead shall not qualify for overhead under any other overhead provisions.

In the event of any conflict between the provisions of this Section II.2 and the provisions of Sections II.2 (Labor), II.5 (Services), or II.7 (Affiliates), the provisions of this Section III 2 shall govern.

3. AMENDMENT OF OVERHEAD RATES

The overhead rates provided for in this Section III may be amended from time to time if, in practice, the rates are found to be insufficient or excessive, in accordance with the provisions of Section I.6.B (Amendments).

IV. MATERIAL PURCHASES, TRANSFERS, AND DISPOSITIONS

The Operator is responsible for Joint Account Material and shall make proper and timely charges and credits for direct purchases, transfers, and dispositions. The Operator shall provide all Material for use in the conduct of Joint Operations; however, Material may be supplied by the Non-Operators, at the Operator’s option. Material furnished by any Party shall be furnished without any express or implied warranties as to quality, fitness for use, or any other matter.

1. DIRECT PURCHASES

Direct purchases shall be charged to the Joint Account at the price paid by the Operator after deduction of all discounts received. The Operator shall make good faith efforts to take discounts offered by suppliers, but shall not be liable for failure to take discounts except to the extent such failure was the result of the Operator’s gross negligence or willful misconduct. A direct purchase shall be deemed to occur when an agreement is made between an Operator and a third party for the acquisition of Material for a specific well site or location. Material provided by the Operator under “vendor stocking programs,” where the initial use is for a Joint Property and title of the Material does not pass from the manufacturer, distributor, or agent until usage, is considered a direct purchase. If Material is found to be defective or is returned to the manufacturer, distributor, or agent for any other reason, credit shall be passed to the Joint Account within sixty (60) days after the Operator has received adjustment from the manufacturer, distributor, or agent.

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COPAS 2005 Accounting Procedure Recommended by COPAS

2. TRANSFERS

A transfer is determined to occur when the Operator (i) furnishes Material from a storage facility or from another operated property, (ii) has assumed liability for the storage costs and changes in value, and (iii) has previously secured and held title to the transferred Material. Similarly, the removal of Material from the Joint Property to a storage facility or to another operated property is also considered a transfer; provided, however. Material that is moved front the Joint Property to a storage location for safe-keeping pending disposition may remain charged to the Joint Account and is not considered a transfer. Material shall be disposed of in accordance with Section IV.3 (Disposition of Surplus) and the Agreement to which this Accounting Procedure is attached.

A. PRICING

The value of Material transferred to/from the Joint Property should generally reflect the market value on the date of physical transfer. Regardless of the pricing method used, the Operator shall make available to the Non-Operators sufficient documentation to verify the Material valuation. When higher than specification grade or size tubulars are used in the conduct of Joint Operations, the Operator shall charge the Joint Account at the equivalent price for well design specification tubulars, unless such higher specification grade or sized tubulars are approved by the Parties pursuant to Section I.6.A (General Matters). Transfers of new Material will be priced using one of the following pricing methods; provided, however, the Operator shall use consistent pricing methods, and not alternate between methods for the purpose of choosing the method most favorable to the Operator for a specific transfer:

(1) Using published prices in effect on date of movement as adjusted by the appropriate COPAS Historical Price Multiplier (HPM) or prices provided by the COPAS Computerized Equipment Pricing System (CEPS).

(a) For oil country tubulars and line pipe, the published price shall be based upon eastern mill carload base prices (Houston, Texas, for special end) adjusted as of date of movement, plus transportation cost as defined in Section IV.2.B (Freight).

(b) For other Material, the published price shall be the published list price in effect at date of movement, as listed by a Supply Store nearest the Joint Property where like Material is normally available, or point of manufacture plus transportation costs as defined in Section IV.2.B (Freight).

(2) Based on a price quotation from a vendor that reflects a current realistic acquisition cost.

(3) Based on the amount paid by the Operator for like Material in the vicinity of the Joint Property within the previous twelve (12) months from the date of physical transfer.

(4) As agreed to by the Participating Parties for Material being transferred to the Joint Property, and by the Parties owning the Material for Material being transferred from the Joint Property.

B. FREIGHT

Transportation costs shall be added to the Material transfer price using the method prescribed by the COPAS Computerized Equipment Pricing System (CEPS). If not using CEPS, transportation costs shall be calculated as follows:

(1) Transportation costs for oil country tubulars and line pipe shall be calculated using the distance from eastern mill to the Railway Receiving Point based on the carload weight basis as recommended by the COPAS MF1-38 (“Material Pricing Manual”) and other COPAS MFIs in effect at the time of the transfer.

(2) Transportation costs for special mill items shall be calculated from that mill’s shipping point to the Railway Receiving Point. For transportation costs from other than eastern mills, the 30,000-pound interstate track rate shall be used. Transportation costs for macaroni tubing shall be calculated based on the interstate truck rate per weight of tubing transferred to the Railway Receiving Point.

(3) Transportation costs for special end tubular goods shall be calculated using the interstate truck rate from Houston, Texas, to the Railway Receiving Point.

(4) Transportation costs for Material other than that described in Sections IV.2.B.(1) through (3), shall be calculated from the Supply Store or point of manufacture, whichever is appropriate, to the Railway Receiving Point

Regardless of whether using CEPS or manually calculating transportation costs, transportation costs from the Railway Receiving Point to the Joint Property are in addition to the foregoing, and may be charged to the Joint Account based on actual costs incurred. All transportation costs are subject to Equalized Freight as provided in Section II.4 (Transportation) of this Accounting Procedure.

C. TAXES

Sales and use taxes shall be added to the Material transfer price using either the method contained in the COPAS Computerized Equipment Pricing System (CEPS) or the applicable tax rate in effect for the Joint Property at the time and place of transfer. In either case, the Joint Account shall be charged or credited at the rate that would have governed had the Material been a direct purchase.

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COPAS 2005 Accounting Procedure Recommended by COPAS

D. CONDITION

(1) Condition “A” - New and unused Material in sound and serviceable condition shall be charged at one hundred percent (100%) of the price as determined in Sections IV.2.A (Pricing), IV.2.B (Freight), and IV.2.C (Taxes). Material transferred from the Joint Property that was not placed in service shall be credited as charged without pin or loss; provided, however, any unused Material that was charged to the Joint Account through a direct purchase will be credited to the Joint Account at the original cost paid less restocking fees charged by the vendor. New and unused Material transferred from the Joint Property may be credited at a price other than the price originally charged to the Joint Account provided such price is approved by the Parties owning such Material, pursuant to Section I.6.A (General Matters). All refurbishing costs required or necessary to return the Material to original condition or to correct handling, transportation, or other damages will be borne by the divesting property. The Joint Account is responsible for Material preparation, handling, and transportation costs for new and unused Material charged to the Joint Property either through a direct purchase or transfer. Any preparation costs incurred, including any internal or external coating and wrapping, will be credited on new Material provided these services were not repeated for such Material for the receiving property.

(2) Condition “B” - Used Material in sound and serviceable condition and suitable for reuse without reconditioning shall be priced by multiplying the price determined in Sections IV.2.A (Pricing), IV.2.B (Freight), and IV.2.C (Taxes) by seventy-five percent (75%).

Except as provided in Section IV.2.D(3), all reconditioning costs required to return the Material to Condition “B” or to correct handling, transportation or other damages will be borne by the divesting property.

If the Material was originally charged to the Joint Account as used Material and placed in service for the Joint Property, the Material will be credited at the price determined in Sections IV.2.A (Pricing), IV.2.B (Freight), and IV.2.C (Taxes) multiplied by sixty-five percent (65%).

Unless otherwise agreed to by the Parties that paid for such Material, used Material transferred from the Joint Property that was not placed in service on the property shall be credited as charged without gain or loss.

(3) Condition “C” - Material that is not in sound and serviceable condition and not suitable for its original function until after reconditioning shall be priced by multiplying the price determined in Sections IV.2.A (Pricing), IV.2.B (Freight), and IV.2.C (Taxes) by fifty percent (50%).

The cost of reconditioning may be charged to the receiving property to the extent Condition “C” value, plus cost of reconditioning, does not exceed Condition “B” value.

(4) Condition “13” - Material that (i) is no longer suitable for its original purpose but useable for some other purpose, (ii) isobsolete, or (iii) does not meet original specifications but still has value and can be used in other applications as a substitute for items with different specifications, is considered Condition “D” Material. Casing, tubing, or drill pipe used as line pipe shall be priced as Grade A and B seamless line pipe of comparable size and weight. Used casing, tubing, or drill pipe utilized as line pipe shall be priced at used line pipe prices. Casing, tubing, or drill pipe used as higher pressure service lines than standard line pipe, e.g., power oil lines, shall be priced under normal pricing procedures for casing, tubing, or drill pipe. Upset tubular goods shall be priced on a non-upset basis. For other items, the price used should result in the Joint Account being charged or credited with the value of the service rendered or use of the Material, or as agreed to by the Parties pursuant to Section I.6.A (General Matters).

(5) Condition “E” - Junk shall be priced at prevailing scrap value prices.

E. OTHER PRICING PROVISIONS

(1) Preparation Costs

Subject to Section II (Direct Charges) and Section III (Overhead) of this Accounting Procedure, costs incurred by the Operatorin making Material serviceable including inspection, third party surveillance services, and other similar services will be charged to the Joint Account at prices which reflect the Operator’s actual costs of the services. Documentation must be provided to the Non-Operators upon request to support the cost of service. New coating and/or wrapping shall be considered a component ofthe Materials and priced in accordance with Sections IV.1 (Direct Purchases) or IV.2.A (Pricing), as applicable. No charges or credits shall be made for used coating or wrapping. Charges and credits for inspections shall be made in accordance withCOPAS MFI-38 (“Material Pricing Manual”).

(2) Loading and Unloading Costs

Loading and unloading costs related to the movement of the Material to the Joint Property shall be charged in accordance withthe methods specified in COPAS MFI-38 (“Material Pricing Manual”).

COPYRIGHT © 2005 by Council of Petroleum Accountants Societies, Inc. (COPAS)

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COPAS 2005 Accounting Procedure Recommended by COPAS

3. DISPOSITION OF SURPLUS

Surplus Material is that Material, whether new or used, that is no longer required for Joint Operations. The Operator may purchase, but shall be under no obligation to purchase, the interest of the Non-Operators in surplus Material.

Dispositions for the purpose of this procedure are considered to be the relinquishment of title of the Material from the Joint Property to either a third party, a Non-Operator, or to the Operator. To avoid the accumulation of surplus Material, the Operator should make good faith efforts to dispose of surplus within twelve (12) months through buy/sale agreements, trade, sale to a third party, division in kind, or other dispositions as agreed to by the Parties.

Disposal of surplus Materials shall be made in accordance with the terms of the Agreement to which this Accounting Procedure is attached. If the Agreement contains no provisions governing disposal of surplus Material, the following terms shall apply:

• The Operator may, through a sale to an unrelated third party or entity, dispose of surplus Material having a gross sale value that is less than or equal to the Operator’s expenditure limit as set forth in the Agreement to which this Accounting Procedure is attached without the prior approval of the Parties owning such Material.

• If the gross sale value exceeds the Agreement expenditure limit, the disposal must be agreed to by the Parties owning such Material.

• Operator may purchase surplus Condition “A” or “B” Material without approval of the Parties owning such Material, based on the pricing methods set forth in Section IV.2 (Transfers).

• Operator may purchase Condition “C” Material without prior approval of the Parties owning such Material if the value of the Materials, based on the pricing methods set forth in Section IV.2 (Transfers), is less than or equal to the Operator’s expenditure limitation set forth in the Agreement. The Operator shall provide documentation supporting the classification of the Material as Condition C.

• Operator may dispose of Condition “D” or “E” Material under procedures normally utilized by Operator without prior approval of the Parties owning such Material.

4. SPECIAL PRICING PROVISIONS

A. PREMIUM PRICING

Whenever Material is available only at inflated prices due to national emergencies, strikes, government imposed foreign trade restrictions, or other unusual causes over which the Operator has no control, for direct purchase the Operator may charge the Joint Account for the required Material at the Operator’s actual cost incurred in providing such Material, making it suitable for use, and moving it to the Joint Property. Material transferred or disposed of during premium pricing situations shall be valued in accordance with Section IV.2 (Transfers) or Section IV.3 (Disposition of Surplus), as applicable.

B. SHOP-MADE ITEMS

Items fabricated by the Operator’s employees, or by contract laborers under the direction of the Operator, shall be priced using the value of the Material used to construct the item plus the cost of labor to fabricate the item. If the Material is from the Operator’s scrap or junk account, the Material shall be priced at either twenty-five percent (25%) of the current price as determined in Section IV.2.A (Pricing) or scrap value, whichever is higher. In no event shall the amount charged exceed the value of the item commensurate with its use.

C. MILL REJECTS

Mill rejects purchased as “limited service” casing or tubing shall be priced at eighty percent (80%) of K-55/J-55 price as determined in Section IV.2 (Transfers). Line pipe converted to casing or tubing with casing or tubing couplings attached shall be priced as K.-55/J-55 casing or tubing at the nearest size and weight.

V. INVENTORIES OF CONTROLLABLE MATERIAL

The Operator shall maintain records of Controllable Material charged to the Joint Account, with sufficient detail to perform physical inventories.

Adjustments to the Joint Account by the Operator resulting from a physical inventory of Controllable Material shall be made within twelve (12) months following the taking of the inventory or receipt of Non-Operator inventory report. Charges and credits for overages or shortages will be valued for the Joint Account in accordance with Section IV.2 (Transfers) and shall be based on the Condition “B” prices in effect on the date of physical inventory unless the inventorying Parties can provide sufficient evidence another Material condition applies.

COPYRIGHT © 2005 by Council of Petroleum Accountants Societies, Inc. (COPAS)

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COPAS 2005 Accounting Procedure Recommended by COPAS

1. DIRECTED INVENTORIES

Physical inventories shall be performed by the Operator upon written request of a majority in working interests of the Non-Operators (hereinafter, “directed inventory”), provided, however, the Operator shall not be required to perform directed inventories more frequently than once every five (5) years. Directed inventories shall be commenced within one hundred eighty (180) days after the Operator receives written notice that a majority in interest of the Non-Operators has requested the inventory. All Parties shall be governed by the results of any directed inventory.

Expenses of directed inventories will be borne by the Joint Account; provided, however, costs associated with any post-report follow-upwork in settling the inventory will be absorbed by the Party incurring such costs. The Operator is expected to exercise judgment in keeping expenses within reasonable limits. Any anticipated disproportionate or extraordinary costs should be discussed and agreed upon prior to commencement of the inventory. Expenses of directed inventories may include the following:

A. A per diem rate for each inventory person, representative of actual salaries, wages, and payroll burdens and benefits of the personnel performing the inventory or a rate agreed to by the Parties pursuant to Section I.6.A (General Matters). The per diem rate shall also be applied to a reasonable number of days for pre-inventory work and report preparation.

B. Actual transportation costs and Personal Expenses for the inventory team.

C. Reasonable charges for report preparation and distribution to the Non-Operators.

2. NON-DIRECTED INVENTORIES

A. OPERATOR INVENTORIES

Physical inventories that are not requested by the Non-Operators may be performed by the Operator, at the Operator’s discretion. The expenses of conducting such Operator-initiated inventories shall not be charged to the Joint Account.

B. NON-OPERATOR INVENTORIES

Subject to the terms of the Agreement to which this Accounting Procedure is attached, the Non-Operators may conduct a physical inventory at reasonable times at their sole cost and risk after giving the Operator at least ninety (90) days prior written notice. The Non-Operator inventory report shall be furnished to the Operator in writing within ninety (90) days of completing the inventory fieldwork.

C. SPECIAL INVENTORIES

The expense of conducting inventories other than those described in Sections V.1 (Directed Inventories), V.2.A (Operator Inventories), or V.2.B (Non-Operator Inventories), shall be charged to the Party requesting such inventory; provided, however, inventories required due to a change of Operator shall be charged to the Joint Account in the same manner as described in Section V.1 (Directed Inventories).

COPYRIGHT © 2005 by Council of Petroleum Accountants Societies, Inc. (COPAS)

15

EX-10.17

Exhibit 10.17

Amendment to Participation Agreement

This Amendment to Participation Agreement (this “Amendment”), by and between MCCABE PETROLEUM CORPORATION, a Texas Corporation, 500 W. Texas Ave., Ste. 890, Midland, Texas 79701 (“MPC”), GREG MCCABE, INDIVIDUALLY, whose address is 500 W. Texas Ave., Ste. 890, Midland, Texas 79701 (“McCabe”) and HUDSPETH OIL CORPORATION, whose address is 5700 W. Plano Parkway, Suite 3600, Plano, Texas 75093 (“Hudspeth”). MPC, McCabe and Hudspeth are sometimes hereinafter sometimes hereinafter referred to as the “Parties”).

RECITALS

WHEREAS, on September 23, 2014, the Parties entered into that certain Participation Agreement (“Participation Agreement”) covering the assignment of certain oil and gas leases located in Hudspeth and El Paso Counties (the “Lands”);

WHEREAS, in Paragraph V(1) of the Participation Agreement the Parties agreed that an initial well would be drilled “...on or before March 31, 2015 or 90 days after the University Lands Department executed the proposed and contemplated Drilling and Development Agreement.” The Parties intent was that a well be drilled on the Lands on or before March 31, 2015, but in the case that the University Lands Department was still negotiating a development agreement, the deadline for drilling should be extended;

WHEREAS, since the execution of the Participation Agreement, the University Lands Department has informed the Parties that it does not intend on entering into a drilling and development agreement until at least one well is drilled on the Lands. In light of this new information, it is the Parties desire to amend the provision to require a well to be drilled on or before March 31, 2015.

AGREEMENT

NOW, THEREFORE, in consideration of the foregoing and the respective covenants and agreements contained herein, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties, intending to be legally bound, hereby covenant and agree as follows:

The Parties acknowledge and agree that Paragraph V(1) of the Participation Agreement shall be amended in its entirety, as of the Effective Date, to following:

Hudspeth shall commence or cause to be commenced actual drilling operations (as defined herein) of a well on the Contract Acreage on or before March 31, 2015. The first well (the “Initial Well’) shall be drilled to a depth sufficient to test the Wolfcamp Formation, and the well shall be drilled to completion in good faith and in a good and workmanlike manner.

In all other respects, the terms of the Participation Agreement shall remain unchanged.

This Amendment shall be binding for all purposes on the Parties and their respective heirs, personal representatives, successors, and assigns.

IN WITNESS WHEREOF, this Amendment is executed by the Parties as of January 2, 2015, but shall be effective for all purposes on June 4, 2014 (the “Effective Date”).

MCCABE PETROLEUM CORPORATION

  By: /s/ Greg McCabe

Printed Name: Greg McCabe

Title: President

GREG MCCABE, INDIVIDUALLY

By: /s/ Greg McCabe

Printed Name: Greg McCabe

Title: Owner

HUDSPETH OIL CORPORATION

By: /s/ John Brda

Printed Name: John Brda

Title: President

EX-10.18

Exhibit 10.18

Second Amendment to Participation Agreement

This Second Amendment to Participation Agreement (this “2nd Amendment”), by and between MCCABE PETROLEUM CORPORATION, a Texas Corporation, 500 W. Texas Ave., Ste. 890, Midland, Texas 79701 (“MPC”), GREG MCCABE, INDIVIDUALLY, whose address is 500 W. Texas Ave., Ste. 890, Midland, Texas 79701 (“McCabe”) and HUDSPETH OIL CORPORATION, whose address is 5700 W. Plano Parkway, Suite 3600, Plano, Texas 75093 (“Hudspeth”). MPC, McCabe and Hudspeth are sometimes hereinafter sometimes hereinafter referred to as the “Parties”).

RECITALS

WHEREAS, on September 23, 2014, the Parties entered into that certain Participation Agreement (“Participation Agreement”) covering the assignment of certain oil and gas leases located in Hudspeth and El Paso Counties (the “Lands”);

WHEREAS, certain terms of the Participation Agreement were amended by that certain Amendment of Participation Agreement, executed by the Parties on January 2, 2015.

WHEREAS, the Parties desire to again amend certain terms of the Participation Agreement by this 2nd Amendment.

AGREEMENT

NOW, THEREFORE, in consideration of the foregoing and the respective covenants and agreements contained herein, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties, intending to be legally bound, hereby covenant and agree as follows:

1. The entire first sentence (and only the first sentence) of Article II.1 (Area of Mutual Interest) of the Participation Agreement which in whole reads as follows:

The parties to this Agreement hereby create an Area of Mutual Interest (“AMU), which includes all lands with at least one boarder within two statute miles of the land described in the attached Exhibit A and any acreage in Block G of the University Lands in Hudspeth County or Block 11 or 12, PSL, Hudspeth County.

SHALL be herein amended and replaced with the following:

The parties to this Agreement hereby create an Area of Mutual Interest (“AMI”), which includes all lands with at least one boarder within eight statute miles of the land described in the attached Exhibit A.

2. The following provisions shall be added to Article II — Area of Mutual Interest:

If Hudspeth, MPC, McCabe, their heirs, successors, assigns, parent companies, affiliates, agents or employees directly or indirectly acquires any additional leasehold interest pursuant to this Article II (Area of Mutual Interest), then MPC, its heirs, assigns or its

designee shall be shall be entitled to an overriding royalty interest in 8/8ths of the leases and all oil, gas, and other minerals produced, saved, and marketed from the lands and leases acquired (the “Override”). Such Override percentage shall be equal to the positive difference, if any, between: (i) twenty-five (25); and (ii) one-hundred (100) minus the NRI attributable to 8/8ths of the working interest in each respective lease. However, in no event shall the Override for any individual lease be greater than 5% of 8/8ths; and in the event that an acquisition of a lease subject to this paragraph is less than 8/8ths of the working interest, then the Override will be proportionately reduced by the share of working interest acquired. For example:

A. 100% of working interest acquired in a lease with 80% NRI attributable to all of the working interest in the lease

• 100 — 80 = 20; then

• 25 — 20 = 5; thus

• 5.00% of 8/8ths Override to MPC

B. 100% of working interest acquired with 70% NRI attributable to all of the working interest lease

• 100 — 70 = 30; then

• 25 — 30 = -5; thus

• MPC does not receive the Override because the difference is negative

C. 100% of working interest acquired with 90% NRI attributable to all of the working interest in the lease

• 100 — 90 = 10; then

• 25 — 10 = 15; thus

• 5.00% of 8/8ths Override to MPC because the override cannot exceed 5.00% of 8/8ths

D. 30% of working interest acquired with 80% NRI attributable to all of the working interest in the lease

• 100 — 80 = 20; then

• 25 — 20 = 5; then

• 5 x 0.30 = 1.5; thus

• 1.5% of 8/8ths Override to MPC because of proportionate reduction

3. Article II.5 shall be amended whereby the termination date of the AMI shall now be defined as December 31, 2025.

4. As a onetime occurrence, the Parties agree that the provision contained in Article V.2 (Initial Well and Continuous Development Clause) of the Participation Agreement requiring that the drilling of an additional well must be commenced within 180 days of completion of any prior well shall be suspended for 90 days from June 1, 2015.

It is agreed that after the 90 day suspension of the continuous drilling requirement, Article V.2 shall automatically resume in all respects. The 180 day period that a new well shall be drilled shall immediately resume as if the end of this suspension period defined herein was the date of the previous well’s completion or abandonment date as defined in Article V of the Participation Agreement. For the purposes of this provision, time shall be of the essence.

5. Article III.2 (Back In After Project Payout) shall be amended to:

Hudspeth shall furnish McCabe with monthly statements of the production, income, costs, and expenditures incurred in connection with the operation of the Contract Acreage and any additional acreage pursuant to the AMI defined herein for the preceding month, itemized sufficiently to reasonably to fulfil industry standard accounting requirements. McCabe shall have access at all reasonable times during the Project Payout period to review Hudspeth’s books and accounts pertaining to the Project Payout.

6. Article III.7 (Back In After Project Payout) shall be amended to:

The Back-In After Payout created herein, shall apply to every extension, renewal, top lease or modification of any of the Leases taken on any of the Contract Acreage, or any portion thereof, taken by Hudspeth, its successors, assigns, parent companies, affiliates, agents or employees, and to any new lease taken by Hudspeth, its successors, assigns, parent companies, affiliates, agents or employees on the Contract Acreage, or any portion thereof, covered by the Leases within one year of the expiration, termination or surrender of any of the Leases. This provisions shall also apply to any leases taken pursuant to the AMI and the override contemplated by the AMI shall apply.

7. The reference to “Wolfcamp Formation” in Article V.1 and V.2 (Initial Well and Continuous Development Clause), shall be amended to “Pennsylvanian Formation”.

8. Hudspeth, its heirs and assigns agree to do any and all acts necessary to maintain in full force and effect any and all leases in their entirety created by or subject to the Participation Agreement. This obligation shall include, but shall not be limited to payment of delay rentals, compensatory royalties or other payments. If at any time, Hudspeth, its heirs or assigns cannot perform the actions contemplated by this provision, then it shall give McCabe written notice of the required action, the deadline of performance of such action and the reason why it cannot perform such act. Such notice shall be given to McCabe at least 30 days before the deadline of performance of such action. McCabe, his heirs or assigns shall have the right to complete such act and Hudspeth, its heirs or assigns agree that they shall be required to repay McCabe, its heirs

or assigns for any expenses that they pay for pursuant to this provision. The Parties agree that any amount that McCabe, its heirs or assigns pays pursuant to this provision shall accrue simple interest at the rate of 18% per anum. Notwithstanding anything else to the contrary, this provision shall be effective for all actions due after January 1, 2015.

9. In all other respects, the terms of the Participation Agreement shall remain unchanged and binding upon the Parties in all respects.

This Amendment shall be binding for all purposes on the Parties and their respective heirs, personal representatives, successors, and assigns.

IN WITNESS WHEREOF, this Amendment is executed by the Parties as of December 31, 2014, but shall be effective for all purposes on June 4, 2014 (the “Effective Date”).

MCCABE PETROLEUM CORPORATION

  By: /s/ Greg McCabe

Printed Name: Greg McCabe

Title: President

GREG MCCABE, INDIVIDUALLY

By: /s/ Greg McCabe

Printed Name: Greg McCabe

Title: individually

HUDSPETH OIL CORPORATION

By: /s/ John Brda

Printed Name: John Brda

Title: CEO

EX-10.19

Exhibit 10.19

CONVERSION AGREEMENT

This Conversion Agreement (the “Agreement”) executed and effective on March     , 2020 and effective as of the date set forth below, by and between Torchlight Energy Resources, Inc., a Nevada corporation (the “Company”), Hudspeth Oil Corporation, a Texas corporation and wholly-owned subsidiary of the Company (“Hudspeth”), and                                  (“Holder”). The Company, Hudspeth and Holder will each be referred to herein as a “Party” and collectively referred to herein as “Parties.”

WHEREAS, the Company issued the Holder a 16% Series C Unsecured Convertible Promissory Note on October 17, 2018 (the “Note”);

WHEREAS, the Holder desires to convert its entire principal amount and all accrued and unpaid interest thereon under the Note into a Working Interest (as defined in the Note), according to the conditions of the Note;

WHEREAS, to induce Holder to elect such conversion, the Company has agreed to provide additional consideration to Holder, as provided in this Agreement;

NOW, THEREFORE, in consideration of the mutual covenants and agreements contained herein, including the recitals set forth hereinabove, and for other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the signatory parties hereto agree to enter this Agreement, on the following terms:

1.     Conversion. The Holder hereby elects to convert the entire principal amount and all accrued and unpaid interest thereon under the Note into a Working Interest (as defined in the Note), according to the conditions of the Note, whereby all principal and interest will convert into the Working Interest (the “Conversion”). The Holder surrenders and has attached to this Agreement the original version of the Note for conversion and cancellation, along with an executed Notice of Conversion (Annex A to the Note).

2.     Working Interest Assignment and Limited Carry. Upon the Conversion, Hudspeth will assign to Holder a proportionate share of working interest as reflected in the form assignment attached to this Agreement as Exhibit A and incorporated herein by reference (“Assignment”). The Assignment is subject to the consent of the lessor of the underlying leases and will not be effective unless and until that consent is received. For the remainder of the 2020 calendar year, Hudspeth shall pay all costs and expenses attributable to the assigned Working interest, except where prohibited by law or regulation. Beginning January 1, 2021, Holder’s Working interest will be treated as a cost bearing interest consistent with the underlying operating agreements and lease obligations.

Conversion Agreement

Page 1 of 1

3.     Top-Off Obligation. If (a) the Company sells its entire interest in Hudspeth or Hudspeth sells its entire working interest in the Orogrande Project (as defined in the Note), (b) as part of such sale, either the Company or Hudspeth exercises its drag-along rights or the Holder exercises its tag-along rights under the Participation Agreement (as defined in the Assignment) and the Holder’s entire Working Interest is sold, and (c) the gross proceeds received by the Company/Hudspeth and the Holder in such transaction (a “Liquidation Transaction”) are equal to less than $3,000,000; then the Company shall pay the Holder an amount equal to $3,000,000, (i) less gross proceeds the Holder received in the Liquidation Transaction, (ii) less the amount of the carry the Holder received under section 2 of this Agreement prior to the Liquidation Transaction, and (iii) less any gross proceeds the Holder received in any farmouts occurring prior to the Liquidation Transaction. Neither the Company nor Hudspeth will have any obligations under this section in a transaction where the Holder sells the Working Interest or any portion thereof in a transaction that is not a Liquidation Transaction. Further, if the Holder transfers the Working Interest or any portion thereof in any transaction, the transferee thereof will have no rights under this section with respect to the interest it received and all rights hereunder will be deemed terminated with respect to that interest.

4.     Warrant to Purchase Common Stock. The Company will issue the Holder a warrant to purchase 250,000 restricted shares of common stock of the Company, which warrant will have a term of five years and an exercise price of $0.70 per share.

5.     Representations and Warranties of Parties. Each of the Parties hereto represents and warrants that (i) such Party has the full right, power and authority to enter into this Agreement; and (ii) when fully executed by all Parties, this Agreement will constitute the binding obligation of such Party, fully enforceable against such Party in accordance with the terms of the Agreement.

6.     Representations and Warranties of Holder. The Holder represents and warrants that (i) the Holder owns the Note free and clear of any liens, claims, equities, charges, options, rights of first refusal, encumbrances or other restrictions, and (ii) the Holder is an “accredited investor” as that term is defined pursuant to Section 501 of Regulation D under the Act.

7.     Notices. All communications required or permitted under this Agreement shall be in writing and any communication or delivery hereunder shall be deemed to have been duly given the first business day following the date of actual receipt if hand delivered, or one day after sent by nationally recognized overnight courier, or on the second business day after mailing if mailed by registered or certified mail, postage prepaid, addressed to the party being notified as set forth below. Any party may, by written notice so delivered to the other, change the address to which delivery shall thereafter be made. Notices to the parties hereto shall be made at the addresses set forth be low:

(a) If to the Company or Hudspeth, to:

Torchlight Energy Resources, Inc.

Attn: John Brda, President

5700 Plano Parkway, Ste. 3600

Plano, Texas 75093

(b) If to Holder, to:

Conversion Agreement

Page 2 of 2

8.     Binding Effect. This Agreement will be binding upon, inure to the benefit of and be enforceable by the Parties and their respective representatives, successors, affiliates, assigns and heirs.

9.     Governing Law. This Agreement shall be governed by, and construed in accordance with, the laws of the State of Texas, without regard to principles of conflict of laws. In any action between or among any of the parties, whether arising out of this Agreement or otherwise, each of the parties irrevocably consents to the exclusive jurisdiction and venue of the federal and state courts located in Collin County, Texas.

10.     Severability. Wherever possible, each provision of this Agreement, shall be interpreted in such a manner as to be effective and valid under applicable law, but if any provision of this Agreement shall be prohibited or invalidated under applicable law, such provision shall be ineffective to the extent of such provision only and the remaining provisions of this Agreement shall remain fully effective.

11.     Counterparts. This Agreement may be executed in multiple counterparts, each of which shall be deemed an original but all of which shall be deemed one instrument. In the event that any signature is delivered by facsimile transmission or by e-mail delivery of a “.pdf” format data file, such signature shall create a valid and binding obligation of the party executing (or on whose behalf such signature is executed) with the same force and effect as if such facsimile or “.pdf” signature page were an original thereof.

12.     Entire Agreement. This Agreement constitutes the entire agreement among the Parties hereto pertaining to the subject matter hereof and supersede all prior agreements, understandings, negotiations and discussions, whether oral or written, of the parties pertaining to the subject matter hereof, and there are no warranties, representations or other agreements among the parties in connection with the subject matter hereof except as specifically set forth herein or in documents delivered pursuant hereto. No supplement, amendment, alteration, modification, waiver or termination of this Agreement shall be binding unless executed in writing by all of the parties hereto. Each of the Parties expressly acknowledges that no promises, inducements or agreements not herein expressed have been made to them and that the terms of this Agreement are contractual and not merely a recital.

13.     Further Assurances. Each Party covenants that at any time, and from time to time, it will execute such additional instruments and take such actions as may be reasonably requested by the any other party to confirm or perfect or otherwise to carry out the intent and purposes of this Agreement.

Conversion Agreement

Page 3 of 3

14.     Expenses. All expenses incurred by the Parties hereto in connection with or related to the authorization, preparation and execution of this Agreement or the transactions contemplated hereby, shall be borne solely and entirely by the party which has incurred the same. Each of the Parties expressly understands and agrees that in the event it shall become necessary for any party hereto to seek enforcement hereof, or in the event of any dispute arising hereunder, the costs and expenses of the prevailing party, including attorney’s fees, shall be paid by the non-prevailing party.

15.     Voluntary Nature of Agreement. Each of the Parties expressly acknowledges that each of them has had the opportunity to discuss this Agreement with their respective legal counsel; that each of them has read this Agreement; that each of them understands the terms of this Agreement, the significance and effect of this Agreement, and the release of the matters referenced herein and enters into same voluntarily and with full knowledge of the effect thereof, and believes the release of the matters upon the terms and conditions set forth in this Agreement to be in each party’s respective best interest.

IN WITNESS WHEREOF, the Parties hereto have executed or caused this Agreement to be executed as of the date set forth above.

TORCHLIGHT ENERGY RESOURCES, INC.

By:

John Brda, President

HUDSPETH OIL CORPORATION

By:

John Brda, President

HOLDER:

Conversion Agreement

Page 4 of 4

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation in this Amendment No. 2 to Registration Statement on Form S-1 filed with the SEC on October 5, 2022 of our report dated July 15, 2022, relating to the financial statements of Next Bridge Hydrocarbons, Inc. as of December 31, 2021 and 2020 and to all references to our firm included in this Amendment No.2 to Registration Statement on Form S-1.

/s/ B.F. Borgers CPA PC

Certified Public Accountants

Lakewood, CO

October 5, 2022

EX-23.3

Exhibit 23.3

CONSENT OF PETECH ENTERPRISES, INC.

We hereby consent to Next Bridge Hydrocarbon Inc.’s inclusion of our estimates of the oil and natural gas reserves as of December 31, 2021 contained in our report dated April 28, 2022, as revised September 27, 2022, in the form and context in which they appear in the registration statement on Form S-1 and the related prospectus (including any amendments thereto, the “Registration Statement”) filed with the Securities and Exchange Commission by Next Bridge Hydrocarbons, Inc., the successor-in-interest to the oil and natural gas assets of Torchlight Energy Resources, Inc. We also consent to the references to PeTech Enterprises, Inc. as the independent petroleum engineering firm under the heading “Experts” in the Registration Statement.

PETECH ENTERPRISES, INC.
By:	/s/ Amiel David
	Amiel David, PE
	Houston, Texas
	October 5, 2022

EX-99.1

Exhibit 99.1

September 27, 2022

Mr. Roger Wurtele

Torchlight Energy Resources, Inc.

5700 W. Plano Parkway #3600

Plano, TX 75093

Dear Mr.Wurtele,

At your request PeTech Enterprises, Inc. (“PEI”) has prepared an estimate of certain hydrocarbon reserves owned by Torchlight Energy Resources, Inc. (“TER”) in the State of Texas as of December 31, 2021. It is our understanding that the proved reserves estimates shown herein constitute all of the proved reserves owned by TER. This evaluation was completed by April 28, 2022, and revised as of August 18, 2022 and September 27, 2022.

These estimates include only Proved and Producing reserves and were prepared following the United States Securities and Exchange Commission (“SEC”) guidelines rule 4-10 Regulation S-X for evaluating and reporting oil and gas reserves. This report has been prepared for TER’s use in connection with public disclosures in its filings with the SEC. Rule 4-10 defines reserves as “...those quantities of oil and gas, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations before the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for estimation….Reserves which can be produced through the application of improved recovery techniques….Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12 months before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion. A complete ruling is available on the SEC website.

Acceptable evaluation geological, engineering, and accounting (cost, taxes, etc.) practice principles were utilized to reach the results of this evaluation. Results were based on historical oil production information,

geological maps, logs, and offsetting lease analogs. The evaluation is based on information provided by or through TER for the year ended December 31, 2021. Data such as production rates, lease operating costs, ownership interests, and projections for future activities were relied on to be true. In all cases, PEI has reviewed the data to ensure reasonable values, consistency, and dependability and in PEI’s opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for TER’s purposes of filing this report with the SEC.

OPERATIONS TEXAS

The Hazel project is located in Sterling and Tom Green counties, TX. The company drilled five wells of which the Flying “B” Ranch #3H and #4H are producing. Production is from the Wolfcamp formation. The properties are operated by Maverick Operating. The company drilled or converted a well to be used for saltwater disposal. The currently operating expenses reflect a substantial reduction from previous years as water is now disposed of on location and electric power is available. Initial gross oil production reached 8,319 bbl per month and 31,613 bbl per month of water. It is anticipated that the well has an ultimate oil recovery of 154 Mbbl. The Flying B well 4H had an initial production rate of 4,200 bbl of oil and has an ultimate oil recovery of 192 Mbbl.

NOTE. AS A RESULT OF THE EXISTENCE OF A REMAINING OUTSTANDING COST REIMBURSEMENT BALANCE OF $4,768,323.73 TO MASTERSON HAZEL PARTNERS LP 2021, THESE WELLS DO NOT REFLECT A POSITIVE PRESENT VALUE TO TORCHLIGHT ENERGY RESOURCES, INC.

PRODUCTS PRICE

PRODUCTS PRICE Prices used by TER are based on the twelve months unweighted average of the first day of the month prices for oil (WTI) was used in calculating the 2021 average price resulting in $63.04 per barrel.

Oil and gas price differentials were calculated from the actual prices realized and were utilized in this evaluation. The average oil and gas prices were held constant throughout the economic life of the leases

OPERATING EXPENSES and CAPITAL COSTS reoccurring lease operating expenses were provided by the company and accepted when they seemed reasonable for the type of operation and area. Lease operating expenses were held constant throughout the life of the reserve.

TAXES

Production and ad valorem taxes were based on the Texas regulatory rates. Hedge values were not considered in this evaluation.

Note that oil and gas reserves, as well as gross and net revenues, are ESTIMATES that may change as additional production and other technical data become available or due to prices change. All estimates are subject to change due to the inherent uncertainty in the application of judgmental factors as well as the regulatory environment.

PEI did not physically visit the field, PEI accepted as true all ownership interests. PEI has not evaluated any potential environmental liability. PEI does not own an economic interest in any of the

2

company’s assets. PEI used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy, that PEI considered to be appropriate and necessary to establish the conclusions set forth herein.

As of December 31, 2021

	PROVED DEVELOPED PRODUCING				PROVED UNDEVELOPED
	OIL, Mbbl		GAS MMcf		OIL, Mbbl		GAS,MMcf
GROSS ULTIMATE RESERVES		346.3		NA		NA		NA
GROSS REMAINING RESERVES		253.1		NA		NA		NA
NET REMAINING RESERVES		151.9		NA		NA		NA

Values of the proved reserves in this report are expressed in terms of ESTIMATED future gross revenue, future net revenue, and present worth using a discount factor of 10%. Future gross revenue is the revenue that will accrue to the appraised interests from the production and sale of the estimated net reserves. Net revenue is the gross revenue less production and ad valorem taxes, operating expenses, and capital costs. Operating expenses include direct field expenses but exclude general administration costs. Federal income tax was not included in this analysis.

AS OF DECEMBER 31, 2021

	PROVED
	DEVELOPED PRODUCING		UNDEVELOPED
FUTURE GROSS INCOME, M$		9098.1		NA
PRODUCTION AND ADVALOREM TAX, M$		419.8		NA
OPERATING EXPENSES, M$		4361.8		NA
CAPITAL COST, M$		0		NA
FUTURE NET REVENUE, M$		4316.6		NA
PRESENT VALOE, DISC AT 10%, M$		2896.8		NA

This report is followed by detailed cash flow for each well, followed by production plots. Qualifications of the evaluator are also attached.

Submitted,

/s/ Amiel David
Amiel David, Ph.D., P.E. #50970

For PeTech Enterprises, Inc. Registration# F-15360

3

			Estimated 8/8 Ths Production						Net Production
			Oil		NGL		Gas		Oil		NGL		Gas		Oil		NGL		Gas
Year	Wells		Mbbl		Mgal		MMcf		Mbbl		Mgal		MMcf		$/bbl		$/gal		$/Mcf
2021		0		0.12		0.00		0.00		0.07		0.00		0.00		59.86		0.00		0.00
2022		2		32.86		0.00		0.00		19.71		0.00		0.00		59.88		0.00		0.00
2023		2		24.05		0.00		0.00		14.43		0.00		0.00		59.89		0.00		0.00
2024		2		19.94		0.00		0.00		11.97		0.00		0.00		59.89		0.00		0.00
2025		2		17.35		0.00		0.00		10.41		0.00		0.00		59.89		0.00		0.00
2026		2		15.59		0.00		0.00		9.35		0.00		0.00		59.89		0.00		0.00
2027		2		14.27		0.00		0.00		8.56		0.00		0.00		59.89		0.00		0.00
2028		2		13.28		0.00		0.00		7.97		0.00		0.00		59.89		0.00		0.00
2029		2		12.41		0.00		0.00		7.45		0.00		0.00		59.89		0.00		0.00
2030		2		11.72		0.00		0.00		7.03		0.00		0.00		59.89		0.00		0.00
2031		2		11.12		0.00		0.00		6.67		0.00		0.00		59.89		0.00		0.00
2032		2		10.59		0.00		0.00		6.36		0.00		0.00		59.89		0.00		0.00
2033		2		10.04		0.00		0.00		6.02		0.00		0.00		59.89		0.00		0.00
2034		2		9.53		0.00		0.00		5.72		0.00		0.00		59.89		0.00		0.00
2035		2		9.06		0.00		0.00		5.43		0.00		0.00		59.89		0.00		0.00
Sub-T				211.93		0.00		0.00		127.16		0.00		0.00		59.89		0.00		0.00
After				41.17		0.00		0.00		24.70		0.00		0.00		60.03		0.00		0.00
Total				253.10		0.00		0.00		151.86		0.00		0.00		59.91		0.00		0.00
Cum.				93.25		0.00		0.00
Ult.				346.34		0.00		0.00

			Company Future Gross Revenue								Prod & Adv Taxes				Revenue
Year	Oil		NGL		Gas		Other		Total		Prod Tax		Adv Tax		after Sev & Adv
	M$		M$		M$		M$		M$		M$		M$		M$
2021		4.41		0.00		0.00		0.00		4.41		0.20		0.00		4.20
2022		1,180.49		0.00		0.00		0.00		1,180.49		54.46		0.00		1,126.02
2023		864.20		0.00		0.00		0.00		864.20		39.87		0.00		824.33
2024		716.60		0.00		0.00		0.00		716.60		33.06		0.00		683.54
2025		623.30		0.00		0.00		0.00		623.30		28.76		0.00		594.55
2026		560.10		0.00		0.00		0.00		560.10		25.84		0.00		534.26
2027		512.94		0.00		0.00		0.00		512.94		23.66		0.00		489.28
2028		477.27		0.00		0.00		0.00		477.27		22.02		0.00		455.25
2029		445.99		0.00		0.00		0.00		445.99		20.58		0.00		425.42
2030		421.09		0.00		0.00		0.00		421.09		19.43		0.00		401.66
2031		399.63		0.00		0.00		0.00		399.63		18.44		0.00		381.19
2032		380.67		0.00		0.00		0.00		380.67		17.56		0.00		363.11
2033		360.64		0.00		0.00		0.00		360.64		16.64		0.00		344.00
2034		342.62		0.00		0.00		0.00		342.62		15.81		0.00		326.81
2035		325.50		0.00		0.00		0.00		325.50		15.02		0.00		310.48
Sub-T		7,615.45		0.00		0.00		0.00		7,615.45		351.34		0.00		7,264.10
After		1,482.69		0.00		0.00		0.00		1,482.69		1,482.69		0.00		1,414.28
Total		9,098.13		0.00		0.00		0.00		9,098.13		419.72		0.00		8,678.39

Deductions										Future Net Income Before Income Taxes
		Lease		Net		Trans.		Net		Undiscounted				Discounted Ann		Disc. Cum.
Year		Net Costs M$		Investments M$		Costs M$		Profits M$		Annual M$		Cumulative M$		@ 10.00% M$		Annual @ 10.00% M$
	2021		0.62		0.00		0.00		0.00		3.58		3.58		3.58		3.58
	2022		230.40		0.00		0.00		0.00		895.62		895.62		857.36		860.94
	2023		230.40		0.00		0.00		0.00		593.93		593.93		516.13		1,377.07
	2024		230.40		0.00		0.00		0.00		453.14		453.14		357.74		1,734.82
	2025		230.40		0.00		0.00		0.00		364.15		364.15		261.22		1,996.04
	2026		230.40		0.00		0.00		0.00		303.86		303.86		198.13		2,194.16
	2027		230.40		0.00		0.00		0.00		258.88		258.88		153.44		2,347.60
	2028		230.40		0.00		0.00		0.00		224.85		224.85		121.14		2,468.75
	2029		230.40		0.00		0.00		0.00		195.02		195.02		95.49		2,564.24
	2030		230.40		0.00		0.00		0.00		171.26		171.26		76.24		2,640.48
	2031		230.40		0.00		0.00		0.00		150.79		150.79		61.02		2,701.50
	2032		230.40		0.00		0.00		0.00		132.71		132.71		48.83		2,750.33
	2033		230.40		0.00		0.00		0.00		113.60		113.60		37.99		2,788.33
	2034		230.40		0.00		0.00		0.00		96.41		96.41		29.32		2,817.64
	2035		230.40		0.00		0.00		0.00		80.08		80.08		22.14		2,839.79
	Sub-T		3,226.22		0.00		0.00		0.00		4,037.88		4,037.88		2,839.79		2,839.79
	After		1,135.59		0.00		0.00		0.00		278.69		278.69		57.02		57.02
	Total		4,361.81		0.00		0.00		0.00		4,316.58		4,316.58		2,896.81		2,896.81

Eco. Indicators		Present Worth Profile (M$)
Return on Investment (disc):	0.000		PW	5.00	%	3,451.35
Return on Investment (undisc):	0.000		PW	8.00	% :	3,092.24
Years to Payout :	0.00		PW	9.00	% :	2,990.77
Internal Rate of Return (%):	0.00		PW	12.00	%:	2,728.45
			PW	15.00	%:	2,515.83
			PW	20.00	% :	2,239.27

Date: 04/28/2022    1:04:40PM

FLYING ‘B’ RANCH 3H – 3H GARDEN CITY, S. Field, STERLING (TX) Co., TX Operator: MAVERICK OPERATING, LLC Reservoir: WOLFCAMP TORCHLIGHT ENERGY, INC Reserve and Economic Projection As of 12/31/2021 Custom Selection Proved Producing

	Estimated 8/8 Ths Production								Net Production
			Estimated 8/8 Ths Production						Net Production
			Oil		NGL		Gas		Oil		NGL		Gas		Oil		NGL		Gas
Year	Wells		Mbbl		Mgal		MMcf		Mbbl		Mgal		MMcf		$/bbl		$/gal		$/Mcf
2021		0		0.06		0.00		0.00		0.03		0.00		0.00		59.64		0.00		0.00
2022		1		13.86		0.00		0.00		8.32		0.00		0.00		59.64		0.00		0.00
2023		1		9.90		0.00		0.00		5.94		0.00		0.00		59.64		0.00		0.00
2024		1		8.11		0.00		0.00		4.87		0.00		0.00		59.64		0.00		0.00
2025		1		7.02		0.00		0.00		4.21		0.00		0.00		59.64		0.00		0.00
2026		1		6.28		0.00		0.00		3.77		0.00		0.00		59.64		0.00		0.00
2027		1		5.74		0.00		0.00		3.44		0.00		0.00		59.64		0.00		0.00
2028		1		5.33		0.00		0.00		3.20		0.00		0.00		59.64		0.00		0.00
2029		1		4.97		0.00		0.00		2.98		0.00		0.00		59.64		0.00		0.00
2030		1		4.69		0.00		0.00		2.82		0.00		0.00		59.64		0.00		0.00
2031		1		4.45		0.00		0.00		2.67		0.00		0.00		59.64		0.00		0.00
2032		1		4.24		0.00		0.00		2.54		0.00		0.00		59.64		0.00		0.00
2033		1		4.02		0.00		0.00		2.41		0.00		0.00		59.64		0.00		0.00
2034		1		3.82		0.00		0.00		2.29		0.00		0.00		59.64		0.00		0.00
2035		1		3.63		0.00		0.00		2.18		0.00		0.00		59.64		0.00		0.00
Sub-T				86.11		0.00		0.00		51.67		0.00		0.00		59.64		0.00		0.00
After				3.17		0.00		0.00		1.90		0.00		0.00		59.64		0.00		0.00
Total				89.28		0.00		0.00		53.57		0.00		0.00		59.64		0.00		0.00
Cum.				64.89		0.00		0.00
Ult.				154.17		0.00		0.00

	Company Future Gross Revenue										Prod & Adv Taxes				Revenue
Year	Oil M$		NGL M$		Gas M$		Other M$		Total M$		Prod Tax M$		Adv Tax M$		after Sev & Adv M$
2021		2.07		0.00		0.00		0.00		2.07		0.10		0.00		1.98
2022		496.05		0.00		0.00		0.00		496.05		22.89		0.00		473.16
2023		354.17		0.00		0.00		0.00		354.17		16.34		0.00		337.83
2024		290.32		0.00		0.00		0.00		290.32		13.39		0.00		276.93
2025		251.04		0.00		0.00		0.00		251.04		11.58		0.00		239.46
2026		224.78		0.00		0.00		0.00		224.78		10.37		0.00		214.41
2027		205.36		0.00		0.00		0.00		205.36		9.47		0.00		195.89
2028		190.75		0.00		0.00		0.00		190.75		8.80		0.00		181.95
2029		178.01		0.00		0.00		0.00		178.01		8.21		0.00		169.80
2030		167.90		0.00		0.00		0.00		167.90		7.75		0.00		160.15
2031		159.26		0.00		0.00		0.00		159.26		7.35		0.00		151.92
2032		151.71		0.00		0.00		0.00		151.71		7.00		0.00		144.71
2033		143.73		0.00		0.00		0.00		143.73		6.63		0.00		137.09
2034		136.54		0.00		0.00		0.00		136.54		6.30		0.00		130.24
2035		129.72		0.00		0.00		0.00		129.72		5.98		0.00		123.74
Sub-T		3,081.42		0.00		0.00		0.00		3,081.42		142.17		0.00		2,939.25
After		113.35		0.00		0.00		0.00		113.35		5.23		0.00		108.12
Total		3,194.77		0.00		0.00		0.00		3,194.77		147.39		0.00		3,047.37

Deductions									Future Net Income Before Income Taxes
	Lease		Net		Trans.		Net		Undiscounted				Discounted Ann		Disc. Cum.
Year	Net Costs M$		Investments M$		Costs M$		Profits M$		Annual M$		Cumulative M$		@ 10.00% M$		Annual @ 10.00% M$
2021		0.31		0.00		0.00		0.00		1.67		1.67		1.67		1.67
2022		115.20		0.00		0.00		0.00		357.96		359.63		342.78		344.45
2023		115.20		0.00		0.00		0.00		222.63		582.26		193.54		537.99
2024		115.20		0.00		0.00		0.00		161.73		743.99		127.72		665.72
2025		115.20		0.00		0.00		0.00		124.26		868.25		89.16		754.88
2026		115.20		0.00		0.00		0.00		99.21		967.46		64.71		819.59
2027		115.20		0.00		0.00		0.00		80.69		1,048.14		47.84		867.42
2028		115.20		0.00		0.00		0.00		66.75		1,114.89		35.97		903.40
2029		115.20		0.00		0.00		0.00		54.60		1,169.49		26.74		930.14
2030		115.20		0.00		0.00		0.00		44.95		1,214.44		20.02		950.15
2031		115.20		0.00		0.00		0.00		36.72		1,251.16		14.86		965.02
2032		115.20		0.00		0.00		0.00		29.51		1,280.67		10.87		975.88
2033		115.20		0.00		0.00		0.00		21.89		1,302.56		7.33		983.21
2034		115.20		0.00		0.00		0.00		15.04		1,317.61		4.58		987.79
2035		115.20		0.00		0.00		0.00		8.54		1,326.15		2.37		990.16
Sub-T		1,613.11		0.00		0.00		0.00		1,326.15		1,326.15		990.16		990.16
After		105.60		0.00		0.00		0.00		2.52		2.52		0.64		0.64
Total		1,718.71		0.00		0.00		0.00		1,328.66		1,328.66		990.80		990.80

Eco. Indicators			Ownership Interests						Present Worth Profile (M$)
			Initial		1st Rev.		2nd Rev.
Return on Investment (disc):	0.000									PW	5.00	%	1,131.93
Return on Investment (undisc):	0.000	W. I. :		0.80000000		0.00000000		0.00000000		PW	8.00	% :	1,042.08
Years to Payout :	0.00	Net R. I. :		0.60000000		0.00000000		0.00000000		PW	9.00	% :	1,015.67
Internal Rate of Return (%):	0.00	Rev. Date :								PW	12.00	%:	945.17
										PW	15.00	%:	885.50
										PW	20.00	% :	804.29

Date: 04/28/2022    1:04:40PM

FLYING ‘B’ RANCH 4H – 4H GARDEN CITY, S. Field, STERLING (TX) Co., TX Operator: Reservoir: WOLFCAMP TORCHLIGHT ENERGY, INC Reserve and Economic Projection As of 12/31/2021 Custom Selection Proved Producing

	Estimated 8/8 Ths Production								Net Production
			Estimated 8/8 Ths Production						Net Production
			Oil		NGL		Gas		Oil		NGL		Gas		Oil		NGL		Gas
Year	Wells		Mbbl		Mgal		MMcf		Mbbl		Mgal		MMcf		$/bbl		$/gal		$/Mcf
2021		0		0.06		0.00		0.00		0.04		0.00		0.00		60.06		0.00		0.00
2022		1		18.99		0.00		0.00		11.40		0.00		0.00		60.06		0.00		0.00
2023		1		14.15		0.00		0.00		8.49		0.00		0.00		60.06		0.00		0.00
2024		1		11.83		0.00		0.00		7.10		0.00		0.00		60.06		0.00		0.00
2025		1		10.33		0.00		0.00		6.20		0.00		0.00		60.06		0.00		0.00
2026		1		9.31		0.00		0.00		5.58		0.00		0.00		60.06		0.00		0.00
2027		1		8.54		0.00		0.00		5.12		0.00		0.00		60.06		0.00		0.00
2028		1		7.95		0.00		0.00		4.77		0.00		0.00		60.06		0.00		0.00
2029		1		7.44		0.00		0.00		4.46		0.00		0.00		60.06		0.00		0.00
2030		1		7.03		0.00		0.00		4.22		0.00		0.00		60.06		0.00		0.00
2031		1		6.67		0.00		0.00		4.00		0.00		0.00		60.06		0.00		0.00
2032		1		6.35		0.00		0.00		3.81		0.00		0.00		60.06		0.00		0.00
2033		1		6.02		0.00		0.00		3.61		0.00		0.00		60.06		0.00		0.00
2034		1		5.72		0.00		0.00		3.43		0.00		0.00		60.06		0.00		0.00
2035		1		5.43		0.00		0.00		3.26		0.00		0.00		60.06		0.00		0.00
Sub-T				125.82		0.00		0.00		75.49		0.00		0.00		60.06		0.00		0.00
After				38.00		0.00		0.00		22.80		0.00		0.00		60.06		0.00		0.00
Total				163.82		0.00		0.00		98.29		0.00		0.00		60.06		0.00		0.00
Cum.				28.36		0.00		0.00
Ult.				192.18		0.00		0.00

	Company Future Gross Revenue										Prod & Adv Taxes				Revenue
Year	Oil M$		NGL M$		Gas M$		Other M$		Total M$		Prod Tax M$		Adv Tax M$		after Sev & Adv M$
2021		2.33		0.00		0.00		0.00		2.33		0.11		0.00		2.23
2022		684.44		0.00		0.00		0.00		684.44		31.58		0.00		652.86
2023		510.03		0.00		0.00		0.00		510.03		23.53		0.00		486.50
2024		426.28		0.00		0.00		0.00		426.28		19.67		0.00		406.61
2025		372.26		0.00		0.00		0.00		372.26		17.17		0.00		355.08
2026		335.32		0.00		0.00		0.00		335.32		15.47		0.00		319.85
2027		307.58		0.00		0.00		0.00		307.58		14.19		0.00		293.39
2028		286.52		0.00		0.00		0.00		286.52		13.22		0.00		273.31
2029		267.98		0.00		0.00		0.00		267.98		12.36		0.00		255.62
2030		253.19		0.00		0.00		0.00		253.19		11.68		0.00		241.51
2031		240.36		0.00		0.00		0.00		240.36		11.09		0.00		229.27
2032		228.96		0.00		0.00		0.00		228.96		10.56		0.00		218.40
2033		216.91		0.00		0.00		0.00		216.91		10.01		0.00		206.90
2034		206.07		0.00		0.00		0.00		206.07		9.51		0.00		196.57
2035		195.78		0.00		0.00		0.00		195.78		9.03		0.00		186.74
Sub-T		4,534.03		0.00		0.00		0.00		4,534.03		209.18		0.00		4,324.85
After		1,369.34		0.00		0.00		0.00		1,369.34		63.17		0.00		1,306.16
Total		5,903.37		0.00		0.00		0.00		5,903.37		272.35		0.00		5,631.01

Deductions									Future Net Income Before Income Taxes
	Lease		Net		Trans.		Net		Undiscounted				Discounted Ann		Disc. Cum.
Year	Net Costs M$		Investments M$		Costs M$		Profits M$		Annual M$		Cumulative M$		@ 10.00% M$		Annual @ 10.00% M$
2021		0.31		0.00		0.00		0.00		1.92		1.92		1.92		1.92
2022		115.20		0.00		0.00		0.00		537.66		539.58		514.58		516.49
2023		115.20		0.00		0.00		0.00		371.30		910.88		322.58		839.08
2024		115.20		0.00		0.00		0.00		291.41		1,202.29		230.02		1,069.10
2025		115.20		0.00		0.00		0.00		239.88		1,442.18		172.06		1,241.16
2026		115.20		0.00		0.00		0.00		204.65		1,646.82		133.42		1,374.58
2027		115.20		0.00		0.00		0.00		178.19		1,825.02		105.60		1,480.18
2028		115.20		0.00		0.00		0.00		158.11		1,983.12		85.17		1,565.35
2029		115.20		0.00		0.00		0.00		140.42		2,123.54		68.75		1,634.10
2030		115.20		0.00		0.00		0.00		126.31		2,249.85		56.22		1,690.32
2031		115.20		0.00		0.00		0.00		114.07		2,363.92		46.16		1,736.48
2032		115.20		0.00		0.00		0.00		103.20		2,467.12		37.97		1,774.45
2033		115.20		0.00		0.00		0.00		91.70		2,558.83		30.67		1,805.12
2034		115.20		0.00		0.00		0.00		81.37		2,640.20		24.74		1,829.85
2035		115.20		0.00		0.00		0.00		71.54		2,711.74		19.78		1,849.63
Sub-T		1,613.11		0.00		0.00		0.00		2,711.74		2,711.24		1,849.63		1,849.63
After		1,029.99		0.00		0.00		0.00		276.18		276.18		56.38		56.38
Total		2,643.10		0.00		0.00		0.00		2,987.92		2,987.92		1,906.01		1,906.01

			Ownership Interests						Present Worth Profile (M$)
Eco. Indicators			Initial		1st Rev.		2nd Rev.
Return on Investment (disc):	0.000									PW	5.00	%	2,319.42
Return on Investment (undisc):	0.000	W. I. :		0.80000000		0.00000000		0.00000000		PW	8.00	% :	2,050.16
Years to Payout :	0.00	Net R. I. :		0.60000000		0.00000000		0.00000000		PW	9.00	% :	1,975.10
Internal Rate of Return (%):	0.00	Rev. Date :								PW	12.00	%:	1,783.28
										PW	15.00	%:	1,630.33
										PW	20.00	% :	1,434.98

04/28/2022     1:06:44PM Project Name: TORCHLIGHT ENERGY, INC Ownership Group: All Cases Economic One-Liners As of Date: 12/31/2021

		Net Reserves				Net Revenue										Cash Flow
Lease Name Risked/UnRisked	Reserve Category	Oil, Cond, NGL * (Mbbl)		Gas (MMcf)		Oil, Cond NGL * (M$)		Gas (M$)		Other (M$)		Expense & Tax (M$)		Invest. (M$)		Non-Disc. (M$)		Disc. CF (M$)		Life (years)
FLYING ‘B’ RANCH 3H – 3H	P-DP		53.57		0.00		3,914.77		0.00		0.00		1,866.10		0.00		1,328.66		990.80		14.92
Grand Total	Total		98.29		0.00		5,903.37		0.00		0.00		2,915.45		0.00		2,987.92		1,906.01		22.94
FLYING ‘B’ RANCH 4H – 4 H	P-DP		98.29		0.00		5,903.37		0.00		0.00		2,915.45		0.00		2,987.92		1,906.01		22.94

* Assumes Oil, Condensate and NGL are all using the same units.

1

Case Name: FLYING ‘B’ RANCH 3H Field: GARDEN CITY, S. County, State: STERLING (TX), WX Oper: MAVERICK OPERATING, LLC      Disc Value: 990.80 M$

Case Name: FLYING ‘B’ RANCH 4H Field: GARDEN CITY, S. County, State: STERLING (TX), WX Oper:      Disc Value: 1,906.01 M$

Appraiser Qualifications

Amiel David Amiel David is a Registered Petroleum Engineer in the State of Texas, having a license # 50970. Amiel is the owner of PeTech Enterprises, Inc having a Firm Registration number F-15360. Amiel has been practicing petroleum engineering since his college graduation and as a Professional Registered Engineer since 1982. His consulting practice covers all major basins in the US and Canada. He also performed evaluation on assets outside North America. Amiel graduated from the U of Tulsa with a BS in Petroleum Engineering, from the U of Pennsylvania with a MSE in Chemical Engineering, from Stanford U with a PhD in Petroleum Engineering and an MBA from the U of Pittsburgh. Amiel is a member of the Society of Petroleum Engineers and The Society of Petroleum Evaluation Engineers. He has authored over twenty papers on subjects related to his profession.