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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K/A

Commission File Number: 333-266143

NEXT BRIDGE HYDROCARBONS, INC.
(Exact name of registrant as specified in its charter)

500 W. Texas Ave., Suite 890
Midland TX 79701
(Address of principal executive offices) (Zip Code)

(432) 553-9745
(Registrant’s telephone number, including area code)

6300 Ridgelea Place, Suite 950
Fort Worth TX 76116
(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act: None

Our common stock is not publicly traded and is not eligible for electronic transfer through the Depository Trust Company book-entry system or any other established clearing corporation.

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

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes o No x

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No o

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

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

Indicate by check mark whether the registrant has filed a report on and attestation to its management assessment of the effectiveness of its internal controls over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. o

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. o

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to (§240.10D-1(b)). o

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

The Registrant was not a public company as of the last business day of its most recently completed second fiscal quarter and, therefore, cannot calculate the aggregate market value of its voting and non-voting common equity held by non-affiliates as of such date.

DOCUMENTS INCORPORATED BY REFERENCE

None

EXPLANATORY NOTE

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

The information contained in this 10-K/A includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These forward-looking statements are identified by their use of terms such as “can,” “could,” “continuing,” “may,” “will,” “expect,” “anticipate,” “aim,” “estimate,” “intend,” “ongoing,” “plan,” “predict,” “potential,” “project,” “should,” “seeks,” “believe,” “likely to” and similar words, phrases or expressions. All statements, other than statements of historical facts, included in this report, are forward-looking statements, including statements mentioned under “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” regarding:

Our actual results and condition could differ materially from those implied or expressed in the forward-looking statements for any reason. They can be affected by a number of factors, including, among others:

Moreover, we operate in a rapidly evolving environment. New risk factors and uncertainties emerge from time to time, and it is not possible for our management to predict all the risk factors and uncertainties, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. We qualify all of our forward-looking statements by these cautionary statements.

You should not rely upon forward-looking statements as predictions of future events. The forward-looking statements made in this report relate only to events or information available to us as of the date of this report. Except as required by law, we undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

DEFINITIONS

The following are abbreviations and definitions of terms commonly used in the oil and gas industry and in this report. Natural gas equivalents and crude oil equivalents are determined using the ratio of six Mcf to one barrel. Unless the context otherwise requires, all references to “us,” “our,” “we,” “NBH,” the “Company” or “Next Bridge” mean Next Bridge Hydrocarbons, Inc. and where applicable, its consolidated subsidiaries including Torchlight Hazel, LLC, a Texas limited liability company (“Torchlight Hazel”), Hudspeth Oil Corporation, a Texas corporation (“Hudspeth”), Hudspeth Operating, LLC, a Texas limited liability company (“Hudspeth Operating”), and Torchlight Energy, Inc., a Nevada corporation (“TEI”) and Wolfbone Investments LLC, a Texas limited liability company (“Wolfbone”).

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

“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.

“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.

Part I

Items 1 and 2. Business and Properties

The following description of the business of Next Bridge Hydrocarbons, Inc. should be read in conjunction with the information included elsewhere in this report on Form 10-K/A for the years ended December 31, 2023 and 2022.

Overview

We were incorporated in Nevada on August 31, 2021, as OilCo Holdings, Inc. and changed our name to Next Bridge Hydrocarbons, Inc. pursuant to our Amended and Restated Articles of Incorporation filed on June 30, 2022. We spun-off from Meta Materials, Inc. (“Meta”) on December 14, 2022 pursuant to which we became an independent company. Prior to the Spin-Off, we were a wholly-owned subsidiary of Meta.

We are an energy company engaged in the acquisition, exploration, exploitation and 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 Hudspeth County, Texas (the “Orogrande Project”). In addition, we have minor interests in the Eastern edge of the Midland Basin in Sterling, Tom Green and Irion Counties, Texas (the “Hazel Project”), and two minor well interests located in Oklahoma (the “Oklahoma Properties”).

We operate our business through five wholly owned subsidiaries: TEI, Hudspeth, Torchlight Hazel, Wolfbone Investments LLC, and Hudspeth Operating.

As of December 31, 2023, we had interests in three oil and natural gas projects: the Orogrande Project, the Hazel Project, and the Oklahoma Properties in partnership with Kodiak Oil & Gas Exploration Inc. in Central Oklahoma.

In August 2020, our subsidiaries entered into the Option Agreement (defined below) with MHP (defined below), under which, in exchange for satisfying certain drilling obligations, MHP had the option to purchase the entire Hazel Project, which MHP determined not to exercise; 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. See “Current Projects” below for additional discussion regarding our oil and natural gas properties.

Market Opportunity

The market for any oil and natural gas that we may 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.

Our Competitive Strengths

Experienced People. As of December 31, 2023, we had five full-time employees, but presently we have two employees. We engage consultants for various roles as needed including high quality exploration and technical partners. Our internal operations team serves as the foundation of our values-driven culture and commitment to developing a skilled, agile, diverse and engaged workforce. Advancing a safe, ethical, inclusive and diverse culture creates an environment that attracts and retains the high-performing workforce needed to successfully execute our strategy. We plan to continue to build on the expertise and experiences of our management and operations teams and seek guidance from outside advisors as well as our Board.

Project Focus. We are focusing primarily on exploration projects backed by a high degree of scientific information. 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.

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 Strategy

Our mission is to safely increase production and cash flow from our oil and natural gas properties which we believe are rich in opportunities through a disciplined allocation of capital and operational management for the benefit of our shareholders. Our business strategy is designed to accomplish this mission by focusing on two key objectives: (1) maximize the value of our producing assets; and (2) progress our discovered resources into proved reserves, production, and cash flow through efficient appraisal, development and exploitation. 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. We believe 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 December 31, 2023, we had interests in three oil and natural gas projects: the Orogrande Project, the Hazel Project, and the Oklahoma Properties. Additionally, we acquired lease interests in certain Louisiana projects in March 2024.

Orogrande Project, West Texas

On August 7, 2014, our predecessor entered into a Purchase Agreement with Hudspeth, McCabe Petroleum Corporation (“MPC”), and Gregory McCabe (“Mr. McCabe”), the sole owner of Wolfbone Investments, LLC (“Wolfbone”). 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; provided, that the Company now has an interest in approximately 134,000 based on the expiration of certain leases since acquired. 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 owns a controlling interest in Magdalena, an entity that 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.

Effective March 27, 2017, the Orogrande acreage became subject to a Development Unit Agreement 2837 with University Lands (“DDU Agreement”), which allows for all 192 existing leases covering approximately 134,000 gross acres leased from University Lands to be combined into one drilling and development unit for development purposes. The term of the DDU Agreement expired on December 31, 2024. The DDU Agreement also grants the right to extend the DDU Agreement through December 31, 2029, if compliance with the DDU Agreement is met and the extension fee associated with the additional time is paid. As of December 31, 2023, the Company expected to exercise its option to extend the term under the DDU Agreement prior to its expiration. Reference Note 13 Subsequent Events.

Drilling obligations under the DDU Agreement included five wells per year in the years 2021, 2022 and 2023. The drilling obligations are minimum yearly requirements and may be exceeded if acceleration is desired.

On November 7, 2022, we extended the term applicable to our 2022 fiscal year drilling obligations in the Orogrande Project in order to stay in compliance with the continuous drilling clause under the DDU Agreement. As of December 31, 2023, we were in compliance with our drilling obligations under the DDU Agreement.

As of December 31, 2023, leases covering approximately 134,000 acres remained in effect.

While drilling wells under our 2022 drilling obligation, our operations team deployed a new mist drilling solution that increased hole stability, which we believe will result in meaningful cost savings for additional wells drilled in the Orogrande Project. Multiple test wells were drilled in the Orogrande Project in order to stay in compliance with the DDU Agreement. While these previously drilled wells may have potential to produce hydrocarbons to sell commercially in the future, we have no immediate plans to deploy the additional capital necessary to sell production from these wells to third parties. Instead, we plan to use the results from these wells to determine our drilling plans for future wells, including reservoir locations, target depths and designated acreage, in the Orogrande Project. Notwithstanding the foregoing, development of the wells continued through December 31, 2023, to further capture and document the scientific base in support of demonstrating the production potential of the property.

We have drilled a total of 18 test wells in the Orogrande Project properties to test for potential shallow pay zones and deeper pay zones that may be present on structural plays. Two horizontal wells were successfully completed for hydrocarbons through the 2020 drilling program. However, as of December 31, 2023, both wells remain shut-in waiting for hook up to a gas pipeline. The various wells drilled on the Orogrande Basin through 2022 confirmed that there are at least five potential distinct reservoirs under our acreage. While these wells may have potential to produce hydrocarbons to sell commercially in the future, due to capital constraints we have no immediate plans to deploy the capital necessary to sell production from these wells to third parties. Instead, we plan to use the results from these wells to determine our drilling plans for future wells, including well locations, target depths and designated acreage, in the Orogrande Project. The remaining wells can be used for future development for various applications such as re-entering the wellbores for horizontal unconventional development, fresh water supply, or salt water disposal and/or plugged and abandoned.

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) (“Founders”), Wolfbone and MPC (entities controlled by a related party), which agreement provided for Founders assigning all of its working interest in the oil and natural 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 merger between Meta and Torchlight Energy Resources, Inc. in June 2021.

Effective as of October 6, 2023, the Company and certain investor participants (each a “Participant” and collectively the “Participants”) entered into twenty-five separate Participation Agreements (the “Participation Agreements”) to conduct drilling of wells in the Company’s approximately 17,000 acre Johnson Prospect in Hudspeth County, Texas, which is a portion of the Company’s Orogrande Prospect.

Pursuant to the Participation Agreement, the Participants collectively funded the cost of drilling, of approximately $9,000,000, which was used to (i) acquire the rights to drill on the Johnson Prospect and (ii) finance the drilling of five (5) vertical wells in the Johnson Prospect in connection with the Company’s 2023 drilling program requirements under its University Lands Drilling and Development Unit Agreement. Each Participant will have the right to participate in the drilling of additional wells on the Johnson Prospect in the future, including an additional five (5) vertical wells in locations determined by Hudspeth Operating, LLC, the Company’s wholly owned subsidiary (“Hudspeth”), in its sole discretion, in 2024. The Participation Agreement provides for an initial allocation of the working interests and net revenue interests among each Participant and the Company and then a re-allocation upon payout or payment to such Participant of drilling and completion costs for each well drilled. Following payout, the Company will own 25% of working interest as described below and 18.75% net revenue interest in each well. Hudspeth will be the operator of the Johnson Prospect pursuant to a joint operating agreement (the “Operating Agreement”) entered into in connection with the Participation Agreement. The Participation Agreement and the Operating Agreement required, among other things, that Hudspeth and the Company drill and complete at least five (5) vertical wells by December 31, 2023, unless the term of the Participation Agreement is extended. The wells were completed by December 31, 2023.

The Company reserved a twenty-five percent (25%) back-in interest, which shall automatically revert to the Company following the date that each Participant first recovers 100% of the costs attributable to the drilling and development of the wells in which such Participant has participated.

Further, within a specified period following drilling of the initial five (5) wells, pursuant to the Participation Agreement each Participant had the option to elect to transfer and assign all its interests to the Company in exchange for the issuance of shares of common stock of the Company at a conversion factor of $1.20 per share. The option was exercised by the Participants on December 31, 2024.

One of the Participants is McCabe Petroleum Corporation, an entity controlled by Mr. McCabe, the Chairman of the Company’s Board of Directors, the largest shareholder of the Company and a lender of the Company. As such, entry into the Participation Agreement and the related transactions pursuant thereto constitute related party transactions, which have been duly approved by the Company’s Board of Directors and Audit Committee.

Acquisition of Working Interest

On December 21, 2022, the Company entered into that certain Agreement and Plan of Merger (the “Merger Agreement”) with Hudspeth, Wolfbone, MPC and Mr. McCabe, pursuant to which in a series of transactions the oil and natural gas leases, the lands covered by such leases, pooling and communitization agreements, rights-of-way, the surface estate of the lands and all wells located in Orogrande Project will be transferred, conveyed and assigned to Hudspeth (or its designated assignee) in consideration of (1) treating the Orogrande Obligations (as defined in the Merger Agreement) as having been irrevocably satisfied and discharged in full with respect to MPC and (2) an issuance of 56,297,638 shares of Company common stock to Mr. McCabe (such series of transactions collectively, the “Merger”).

The Merger became effective on April 25, 2023. As a result of the Merger, the Company acquired Wolfbone’s 22.6249% remaining rights to working interest in the Orogrande Project in consideration of the issuance by the Company of the 56,297,638 shares of the Company’s common stock to Mr. McCabe.

The Merger was completed in accordance with the Texas Business Organizations Code, whereby (a) the Company formed NBH MergeCo, LLC with the State of Texas (“MergeCo”) in order to cause Hudspeth to assign all of its rights under the Merger Agreement to MergeCo and MergeCo assumed Hudspeth’s obligations under the Merger Agreement, (b) MergeCo, Wolfbone and MPC merged with each of Wolfbone and MPC as surviving entities, and (c) Wolfbone became a direct and wholly-owned subsidiary of the Company. The closing of the transactions contemplated by the Merger Agreement occurred on May 11, 2023.

On May 11, 2023, the Company and its wholly owned subsidiary, Hudspeth, entered into a contribution and exchange agreement with each of the prior working interest owners in the Orogrande Project named in the table below (each an “Orogrande Owner” and collectively, the “Orogrande Owners”), pursuant to which, the Company issued to the Orogrande Owners the number of shares of the Company’s common stock set forth opposite such Orogrande Owner’s name below in exchange for and in order to acquire such Orogrande Owner’s rights to working interest in the Orogrande Project.

The Orogrande Project ownership as of December 31, 2023, is detailed as follows:

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.’s 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. No wells were drilled on the Hazel Project during the year ended December 31, 2023.

Option Agreement with Masterson Hazel Partners, LP

On August 13, 2020, our subsidiaries TEI and Torchlight Hazel (collectively, “Torchlight Subs”) entered into an option agreement (the “Option Agreement”) with Masterson Hazel Partners, LP (“MHP”) and MPC. 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 Subs’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.

Full impairment of the historical cost incurred in prior periods for the Hazel Project has been previously recognized.

Oklahoma Properties in the Hunton Play of Central Oklahoma

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

Full impairment of the historical cost incurred in prior periods for the Oklahoma Properties has been previously recognized.

Louisiana Projects

In March 2024, we entered into and closed a Contribution Agreement with Wildcat Partners SPV, LLC, a Delaware limited liability company (“Wildcat”), under which Wildcat transferred to us 100% of the issued and outstanding membership interests in each of (a) Wildcat Cowboy, LLC, a Texas limited liability company (“Cowboy”), (b) Wildcat Packer, LLC, a Texas limited liability company (“Packer”), (c) Wildcat Panther, LLC, a Texas limited liability company (“Panther”) and (d) Wildcat Valentine, LLC, a Texas limited liability company (“Valentine”). As consideration, we issued 2,500,000 shares of our common stock, under the terms and conditions of the Contribution Agreement.

MPC previously owned and sold to Wildcat the underlying oil and gas prospects owned by Cowboy, Packer, Panther and Valentine. MPC always retained a 25% back-in after payout and various overriding royalty interests in the prospects owned by Cowboy, Packer, Panther and Valentine, but MPC agreed to waive its 25% back-in after payout but retain its overriding royalty interests in all such prospects in an effort to facilitate the transactions described below, including the sale of the leases owned by Valentine, including a leasehold estates in approximately 3,878.90 gross acres and 3,626.25 net acres of land situated in Lafourche Parish, Louisiana (the “Valentine Leases”), and the leases owned by Panther, including leasehold estates in approximately 618 gross acres and 618 net acres of land situated in Acadia Parish, Louisiana (the “Panther Leases”), the leases owned by Packer, including leasehold estates in approximately 4,349 gross acres and 4,349 net acres of land situated in Acadia and Lafourche Parish, Louisiana (the “Packer Leases”), the leases owned by Cowboy, including leasehold estates in approximately 835 gross acres and 835 net acres of land situated in Acadia Parish, Louisiana (the “Cowboy Leases”).

Concurrent with the closing of the above transactions with Wildcat, we entered into and closed a Participation Agreement with Magnetar Exploration L.P. (“Magnetar”) under which we sold to Magnetar a 100% working interest, entitled to not less than a 75% net revenue interest, in and to the Valentine Leases, along with a 100% right, title and interest in all contracts affecting the Valentine Leases, all under the terms and conditions of such Participation Agreement, including the following consideration: (a) Magnetar paid $964,448 from which we are required to pay bonuses of $240,000 to ORX Exploration and $60,000 to Zebrowski Consulting, resulting in net proceeds to us of $664,448; (b) Magnetar agrees to pay all delay rentals pertaining to the Valentine Leases which accrue during calendar year 2024 and during the months of January through August of 2025, provided, however, that if the initial test well is commenced at any time prior to the end of August, 2025, Magnetar’s obligation to bear delay rental expenses thereafter will be deemed terminated, and the obligation for the payment of subsequent delay rentals shall be governed by the subject operating agreement; (c) in the event Magnetar has not commenced actual drilling operations on lands covered by the Valentine Leases on or prior August 31, 2025, then Magnetar shall have the option to continue paying rentals or extending the leases within the Area of Mutual Interest (the “AMI”) until December 31, 2026; (d) we will have the option to participate for up to a 1/3 working interest in the initial test well to be undertaken by Magnetar on lands covered by the Valentine Leases, with this right to extend to subsequent wells to be undertaken by Magnetar, subject to the further provisions regarding operations; and (e) at least three working days prior to its spudding the initial test well, Magnetar will pay to us a spud fee of $600,000 of which $240,000 of the cost thereof will be shared with ORX Exploration and $120,000 will be shared with Zebrowski Consulting, leaving us with $240,000.

Also concurrent with the closing of the above transactions with Wildcat, we enter into and closed a Participation Agreement with Magnetar under which we sold to Magnetar a 100% working interest, entitled to not less than a 75% net revenue interest, in and to the Panther Leases covering approximately 618 gross acres of land situated within the AMI provided therein, along with a 100% right, title and interest in all contracts affecting the Panther Leases, for the following consideration: (a) Magnetar paid $428,918.05 to us and $70,081.95 to MPC for delay rentals paid by it; (b) Magnetar agrees to reimburse McCabe for its payment of delay rentals to sustain certain of the Panther Leases coming due in March and April 2024 in the amount of $70,081.98; (c) Magnetar agrees to pay all delay rentals pertaining to the Panther Leases which accrue during calendar year 2024, shown to be $23,888.90; (d) in the event Magnetar is unable to commence actual drilling operations on lands covered by the Subject Panther Leases on or prior February 1, 2025, then Magnetar shall have the option to extend or take new leases on any of the Panther Leases that would expire during the following 12 calendar months; (e) we will have the option to participate up to a 1/3 working interest in the initial test well to be undertaken by Magnetar on lands covered by the Panther Leases, with this right to extend to subsequent wells to be undertaken by Magnetar, subject to the further provisions regarding operations; (f) prior to its spudding the initial test well, Magnetar will pay to us a spud fee equal to $100,000 of which $20,000 will be shared with Zebrowski Consulting.

Reference Note 13 regarding the valuation of common stock issued and its impact on the recording of the subsequent sale of a portion of the assets acquired.

Oil and Natural Gas Reserves

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 2023, 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, 2023, 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 initial gross monthly production rate for the Flying B Ranch #4H was estimated to be 4,200 Bbl, although we will receive no future revenue from these wells until their estimated depletion because all of such revenue, after deducting expenses to produce the oil, is to be received by MHP directly and credited toward the recoupment of drilling costs incurred by MHP.

As of December 31, 2023, our proved developed nonproducing reserves related to the Producing Hazel Wells totaled -0- BOE, after giving effect to the obligation to reimburse drilling costs incurred by MHP. As of December 31, 2023, the outstanding cost reimbursement balance owed to MHP was $3,364,823.

Production, Price and Cost Summary

Oklahoma Properties

During the year ended December 31, 2022, we produced and sold 183 Bbls net to our interest (168 for the predecessor period plus 15 for the successor period) at an average sale price of $98.75 per Bbl. We produced and sold 3,031 Mcf of natural gas net to our interest (2,789 for the predecessor period plus 242 for the successor period) at an average sales price of $7.51 per Mcf. Our average production cost including lease operating expenses and direct production taxes was $42.68 per BOE. Our depreciation, depletion, and amortization expense was $-0- per BOE.

During the year ended December 31, 2023, we produced and sold 244 barrels of oil net to our interest at an average sale price of $76.50 per Bbl. We produced and sold 3,558 Mcf of gas net to our interest at an average sales price of $2.07 per Mcf. Our average production cost including lease operating expenses and direct production taxes was $18.90 per BOE. Our depreciation, depletion, and amortization expense was $-0- per BOE.

Hazel Project

During the year ended December 31, 2022, 22,511 barrels of oil net to our interest (21,647 for the predecessor period plus 864 for the successor period) were sold at an average sale price of approximately $55.98 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 -0- Mcf of natural gas net to our interest.

During the year ended December 31, 2023, 10,860 barrels of oil net to our interest were sold at an average sale price of approximately $70.99 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 -0- Mcf of natural gas net to our interest.

The net producing reserves from 2022 and 2023 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. Since we have no reserve value as of December 31, 2022 and December 31, 2023, Standardized Measure is not presented.

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.

Investments to support our oil and natural gas properties during the years ended December 31, 2023 and 2022 were $8.6 million and $6.9 million.

Original Property acquisition costs for the year ended December 31, 2023, stated above were $16,015,592 representing the value of 83,358,275 shares of common stock and cancellation of an account receivable given in exchange for 33.5% working interest in the Company’s Orogrande Project. Original 2023 Property acquisition costs have been restated to $723,669.

Property development costs presented above exclude interest capitalized into the full cost pool. For the years ended December 31, 2023 and 2022, we capitalized $2,498,184 and $1,363,538 of interest on unevaluated properties, respectively.

The development costs 2023 and 2022 include work solely in the Orogrande Project. We made progress during 2023 and 2022 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 $11.1 million in 2023 and $8.2 million in 2022 related 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. Additionally, the Company and certain investor participants entered into twenty-five separate Participation Agreements to conduct drilling of wells in the Company’s approximately 17,000 acre Johnson Prospect in Hudspeth County, Texas, which is a portion of the Company’s Orogrande Prospect to satisfy the 2023 drilling requirement.

No development costs were incurred in 2023 or 2022 for the Oklahoma Properties.

During the fiscal years ended December 31, 2023 and 2022, development and exploratory net wells were drilled as set forth in the table below.

Drilling Activity Summary

Effective as of October 6, 2023, the Company and certain investor participants entered into twenty-five separate Participation Agreements to conduct drilling of wells in approximately 17,000 acre Johnson Prospect in Hudspeth County, Texas, which is a portion of the Company’s Orogrande Prospect.

Pursuant to the Participation Agreement, the Participants collectively funded the cost of drilling which was used to (i) acquire the rights to drill on the Johnson Prospect and (ii) finance the drilling of five (5) vertical wells in the Johnson Prospect in connection with the Company’s 2023 drilling program requirements under its University Lands Drilling and Development Unit Agreement.

The Participation Agreement provides for an initial allocation of the working interests and net revenue interests among each Participant and the Company and then a re-allocation upon payout or payment to such Participant of drilling and completion costs for each well drilled. Following payout, the Company will own 25% of working interest and 18.75% net revenue interest in each well.

Well status as of December 31, 2023 includes the five wells drilled under the Participation Agreements and which satisfied the 2023 drilling requirement. Since the Participants hold the working interest in those wells until payout, the Net Interest is unchanged from 2022.

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. Two horizontal wells were successfully completed for hydrocarbons through the 2020 drilling program, however as of December 31, 2023 both wells remain shut-in waiting for hook-up to a gas pipeline. The various wells drilled on the Orogrande Basin through 2023 confirmed that there are at least five potential distinct reservoirs under our acreage. While these wells may have potential to produce hydrocarbons to sell commercially in the future, due to capital constraints we have no immediate plans to deploy the capital necessary to sell production from these wells to third parties. Instead, we plan to use the results from these wells to determine our drilling plans for future wells, including well locations, target depths and designated acreage, in the Orogrande Project. The remaining wells can be used for future development for various applications such re-entering the wellbores for horizontal unconventional development, fresh water supply, or salt water disposal and/or plugged and abandoned.

Producing Well Summary

Acreage.

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

Marketing and Customers

The market for any oil and natural gas that we may 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.

Competition

The oil and gas industry is highly competitive. Competitors include major oil companies, other independent energy companies and individual producers and operators, many of which have financial resources, personnel and facilities substantially greater than we do. We face intense competition for the acquisition of oil and natural gas properties and leases for oil and gas exploration. Not only do our competitors 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.

Regulation

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 U.S. 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 (“RCRA”), 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 (“NSPS”) in 40 C.F.R. Part 60, Subpart OOOOa (“Quad Oa”), the Federal Occupational Safety and Health Act (“OSHA”) and other state equivalent laws and regulations. In December 2023, the EPA finalized NSPS Subpart OOOOb, which seeks to reduce methane and volatile organic compound emissions from the oil and natural gas source category and NSPS Subpart OOOOc, which create, for the first-time, emission guidelines for existing oil and natural gas sources that would be included in individual states’ implementation plans. These standards expand upon previously issued NSPS Subparts OOOO and OOOOa published by the EPA in 2012 and 2016, respectively. For further discussion of the risks to our results of operations arising out of our environmental regulatory compliance, see “Risks Relating 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.”

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:

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.

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 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.

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 U.S. Department of the Interior Bureau of Land Management (“BLM”) 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 GHG 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 GHG 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.

Human Capital

The health and safety of our employees and those that work with us is a priority. Employees and contractors are expected to take all necessary and reasonable actions to ensure safe operations by following safe work practices, complying with relevant policies and regulations, and completing all applicable training. To support our dedication to health, safety and the environment, we have a health and safety policy and that applies to all employees and contractors. In addition to adoption of our employment policies, the Company fosters a strong safety culture through training.

Corporate Information

Our principal executive office is located at 500 W. Texas Ave., Suite 890, Midland, TX 79701. We currently share this office space with companies owned by our CEO, Gregory McCabe, and believe that the condition and size of those offices are adequate for our current needs. Our website is nextbridgehydrocarbons.com. Information contained on or accessible through our website, when available, shall not be incorporated by reference herein.

Available Information

We file annual, quarterly and current reports, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934. The SEC maintains a website that contains reports, proxy and information statements, and other information that is electronically filed with the SEC. The public can obtain any documents that we file with the SEC at www.sec.gov. We also make available free of charge on our website, our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we file such material with, or furnish it to, the SEC.

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 that are included elsewhere in this report. 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 report, particularly under the section titled “Cautionary Statement Concerning Forward-Looking Statements.”

Overview

Our consolidated financial statements have been prepared on a stand-alone basis. Our consolidated financial statements reflect our financial position, results of operations and cash flows in conformity with GAAP.

A Change in Reporting Entity became effective at December 14, 2022, resulting from the spinoff lacking economic substance and requiring the inclusion of pre-spinoff historical financial reporting periods in all subsequent filings.

Where applicable certain items have been restated as notated throughout the consolidated financials statements and disclosures following.

The historical costs and expenses reflected in our 2022 restated consolidated comparative 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 restated consolidated 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. We now perform these functions using our own resources and purchased services.

On December 21, 2022, we entered into that certain Agreement and Plan of Merger (the “Merger Agreement”) with Hudspeth, Wolfbone, MPC and Mr. McCabe, pursuant to which in a series of transactions the oil and natural gas leases, the lands covered by such leases, pooling and communitization agreements, rights-of-way, the surface estate of the lands and all wells located in the Orogrande Project will be transferred, conveyed and assigned to Hudspeth (or its designated assignee) in consideration of (1) treating the Orogrande Obligations (as defined in the Merger Agreement) as having been irrevocably satisfied and discharged in full with respect to MPC and (2) an issuance of 56,297,638 shares of our common stock to Mr. McCabe (such series of transactions collectively, the “Merger”). The Merger was completed in May 2023 in accordance with the Texas Business Organizations Code, whereby (a) the Company will form NBH MergeCo, LLC with the State of Texas (“MergeCo”) in order to cause Hudspeth to assign all of its rights under the Merger Agreement to MergeCo and MergeCo will assume Hudspeth’s obligations under the Merger Agreement, (b) Hudspeth (or MergeCo, as its assignee), Wolfbone and MPC shall merge with each of Wolfbone and MPC as surviving entities, and (c) Wolfbone became a direct and wholly-owned subsidiary of the Company. The closing of the transactions contemplated by the Merger Agreement were subject to the satisfaction of certain customary closing conditions, including filing and acceptance of the certificate of merger by the Secretary of State of the State of Texas.

In connection with the Merger, on December 22, 2022, the Company entered into the 2022 Note (defined below). The Company is entitled to request advances under the 2022 Note in a minimum principal amount of $100,000 each. Mr. McCabe is the largest shareholder of our common stock. As such, the Merger and 2022 Note constitute related party transactions which have been duly approved by our Board and Audit Committee. As of December 31, 2023, the Company had drawn $20 million on the 2022 Note. The maturity date of the loan had been amended to September 30, 2024.

Recent Developments

We met our 2022 drilling obligations under the DDU Agreement to drill five new wells in the Orogrande Project in advance of the March 31, 2023, deadline under University Lands lease requirement. The data collected from these five wells, in addition to the five wells drilled in 2021, confirmed that there are at least five potential distinct reservoirs under our acreage. Also, our operations team deployed a new mist drilling solution which increased hole stability, which we believe will result in meaningful cost savings for additional wells drilled in the Orogrande Project. While these wells may have potential to produce hydrocarbons to sell commercially in the future, we have no immediate plans to deploy the additional capital necessary to sell production from these wells to third parties. Instead, we plan to use the results from these wells to determine our drilling plans for future wells, including reservoir locations, target depths and designated acreage, in the Orogrande Project.

Effective as of October 6, 2023, the Company and certain investor participants (each a “Participant” and collectively the “Participants”) entered into twenty-five separate Participation Agreements (the “Participation Agreements”) to conduct drilling of wells in the Company’s approximately 17,000 acre Johnson Prospect in Hudspeth County, Texas, which is a portion of the Company’s Orogrande Prospect.

Pursuant to the Participation Agreement, the Participants collectively funded the cost of drilling, of approximately $9,000,000, which was used to (i) acquire the rights to drill on the Johnson Prospect and (ii) finance the drilling of five (5) vertical wells in the Johnson Prospect in connection with the Company’s 2023 drilling program requirements under its University Lands Drilling and Development Unit Agreement. Each Participant will have the right to participate in the drilling of additional wells on the Johnson Prospect in the future, including an additional five (5) vertical wells in locations determined by Hudspeth Operating, LLC, the Company’s wholly owned subsidiary (“Hudspeth”), in its sole discretion, in 2024. The Participation Agreement provides for an initial allocation of the working interests and net revenue interests among each Participant and the Company and then a re-allocation upon payout or payment to such Participant of drilling and completion costs for each well drilled. Following payout, the Company will own 25% of working interest as described below and 18.75% net revenue interest in each well. Hudspeth will be the operator of the Johnson Prospect pursuant to a joint operating agreement (the “Operating Agreement”) entered into in connection with the Participation Agreement. The Participation Agreement and the Operating Agreement required, among other things, that Hudspeth and the Company drill and complete at least five (5) vertical wells by December 31, 2023, unless the term of the Participation Agreement is extended.

The wells were completed by December 31, 2023 satisfying the 2023 drilling obligation under the DDU Agreement.

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, 2023 and 2022 – Restated

Historical Results for the Years Ended December 31, 2023 - Restated

For the year ended December 31, 2023, we had a restated net loss of $10,389,372 compared to a restated net loss of $8,950,166 for the year ended December 31, 2022. At December 31, 2023, we had restated current assets of $2,085,810 and total assets of $55,863,568. As of December 31, 2023, we had restated current liabilities of $49,180,169. Restated stockholders’ equity was $6,434,748 at December 31, 2023.

Historical Results for the Years Ended December 31, 2022 - Restated

For the year ended December 31, 2022, we had a restated net loss of $8,950,166. The net loss was primarily due to restated general and administrative expenses for the year ended December 31, 2022.

At December 31, 2022, we had restated current assets of $959,117 and restated total assets of $42,658,863. As of December 31, 2022, we had restated current liabilities of $31,092,824. Restated stockholders’ equity was $11,319,173 at December 31, 2022.

Revenue and Gross Profit

Production Revenues and Cost of Revenue

For the year ended December 31, 2023, we had production revenue of $26,031 compared to $40,834 in 2022 . The change in revenue was primarily due to the increase in oil and natural gas production from 692 BOE for the 2022 period to 837 BOE for the 2023 period from the Oklahoma Properties, a decrease in the average price of oil from $98.75 in 2022 to $76.50 in 2023 and a decrease in the average price of natural gas from $7.51 in 2022 to $2.07 in 2023. Our cost of revenue, consisting of lease operating expenses and production taxes, was $169,551 for the year ended December 31, 2022 compared with $60,933 for the year ended December 31, 2023. For each of the years ended December 31, 2022 and 2023, production and revenue are detailed as follows:

Expenses for the Years Ended December 31, 2023 and 2022 - Restated

We recorded depreciation, depletion and amortization expense of $-0- for the year ended December 31, 2023 compared to $-0- for the year ended December 31, 2022.

Operating Expenses

General and Administrative Expenses

Our general and administrative expense for the year ended December 31, 2023 was $12,095,611 compared to $8,821,945 for the year ended December 31, 2022. 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 2023, compared to 2022, is primarily due to employee compensation and an increase in consulting fees, filing fees, legal fees, director and officer liability insurance, and investor relations expenses.

Cash Flows, Liquidity and Capital Resources.

Cash Flows - Restated

The following table summarizes sources and uses of cash and cash equivalents:

At December 31, 2023, we had cash and cash equivalents of $1,668,847 compared to $569,298 as of December 31, 2022.

Cash Flows From Operating Activities - Restated

Cash used in operating activities for the year ended December 31, 2023, was $7,558,092 compared to $4,446,093 for the restated year ended December 31, 2022.

Cash used in operating activities for the year ended December 31, 2023 can be attributed principally to net loss from operations of $10,389,372 adjusted for $4,781,279 in expense related to stock based compensation and changes in other liabilities, and accounts payable and accrued expenses.

Cash Flows from Investing Activities - Restated

Cash used in investing activities for the year ended December 31, 2023 was $8,653,640 compared to $6,790,628 for the restated year ended December 31, 2022. Cash used in investing activities consisted primarily of investments in oil and natural gas properties.

Cash Flows from Financing Activities - Restated

Cash provided by financing activities for the year ended December 31, 2023 was $17,311,281 compared to $9,816,600 for the year ended December 31, 2022. Cash flows provided by financing activities consisted primarily of loans from a related party.

We expect to continue to have cash flows 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.

Reference the Restated 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 flows in operating activities until such time as we achieve sufficient commercial oil and natural gas production to cover our operating costs.

Capital Expenditures - Restated

Our capital expenditures are summarized in the following table:

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.

The 2021 Note

Prior to the date on which our shares of common stock were distributed to the holders of Series A Preferred Stock of Meta (the “Spin-Off”), 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 was issued to provide capital to engage certain consultants and satisfy the minimum drilling requirements under the DDU Agreement, which was necessary to preserve our interests in the oil and gas properties. Though Meta had no intentions to operate the oil and natural gas assets as an independent business, Meta would need to maintain the oil and natural gas interests until a sale of such assets or the Spin-Off could be consummated as it was obligated to do under its charter documents. 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. 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 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” or “Mr. McCabe”) and Meta (the “Stock Pledge Agreement”), 1,515,000 shares of Meta’s common stock 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 (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 Project as defined in the Security Agreement. Following the Merger, we expect Wolfbone to become an indirect subsidiary of the Company and the Security Agreement to remain in place.

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 and in August 2022, we borrowed $1.9 million and $2.7 million as an advance from Meta to be treated as an unsecured term loan, in addition to $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 report, we had an aggregate principal amount outstanding of $5.0 million, which is the maximum amount available under the Loan Agreement. The loans were due and payable on March 31, 2023 (the “Maturity Date”), unless extended as described in the following sentence. 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. 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.

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.

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.

See the discussion under the caption “Recent Developments” and Note 7 of the notes to our financial statements as of and for the year ended December 31, 2023 included in this report for information about the amendments to the 2021 Note and the Loan Agreement entered into subsequent to the end of fiscal year 2023.

The 2022 Note

On December 22, 2022, we issued an unsecured promissory note in the principal amount of up to $20 million in favor of Mr. McCabe (the “2022 Note”). The 2022 Note bears interest at 5% per annum, computed on the basis of a 365-day year, and matures on June 30, 2024 (the “2022 Note Maturity Date”); provided, however, if we raise $30 million or more in capital through debt or equity or a combination thereof by the 2022 Note Maturity Date, the 2022 Note Maturity Date will be extended to October 3, 2023. The outstanding principal of the 2022 Note, together with all accrued interest thereon, becomes due on June 21, 2023. The revolving commitment under the 2022 Note expires on 2022 Note Maturity Date. As of December 31, 2022, we had $2 million principal amount outstanding and $18 million of available borrowings under the 2022 Note.

The 2022 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 2022 Note.

Upon the occurrence and during the continuance of an event of default under the 2022 Note, Mr. McCabe as the lender may declare all outstanding principal and accrued and unpaid interest under the 2022 Note immediately due and payable, may terminate any remaining commitment to make advances under the 2022 Note, and may exercise the other rights and remedies provided for under the 2022 Note. The events of default under the 2022 Note include among other things, subject to grace periods in certain instances, payment defaults, breaches of covenants, bankruptcy and insolvency events with respect us or our subsidiaries, cross defaults with certain of our other material indebtedness, and material judgments against us.

Following the Spin-Off, our management considered ways to mitigate certain risks of having its indebtedness held by a third party lender following the Spin-Off and retain some flexibility in respect of negotiating the terms of the 2021 Note and Loan Agreement. Our management team believed that having all of the corporate debt transferred to Mr. McCabe was in the best interest of the Company and its stockholders. In light of Mr. McCabe acting as a guarantor of the obligations of the 2021 Note, consolidating the debt with Mr. McCabe would also mitigate any risks that the lender would seek recourse against Mr. McCabe in the event we were unable to satisfy our obligations thereunder. On August 7, 2023, Mr. McCabe and Meta entered into a Loan Sale Agreement whereby Mr. McCabe purchased from Meta (i) the 2021 Note and (ii) all outstanding loans made to us by Meta pursuant to the Loan Agreement (the “Loan Purchase”). As a result of the Loan Purchase, Mr. McCabe replaced Meta as the lender and a secured party under the 2021 Note and the Loan Agreement. As consideration for the Loan Purchase, Mr. McCabe agreed to pay to Meta $6,000,000 in cash and agreed to purchase shares of common stock of Meta in the amount of $6,000,000 over a period of time at a price per share equal to a 120% premium to the Meta’s common stock price as of closing on the last trading day of each quarter. Additionally, as part of the Loan Purchase, Meta assigned to Mr. McCabe the lien on 25% of the Orogrande Prospect. After Mr. McCabe purchased $500,000 worth of shares of Meta’s common stock (in two equal tranches), Mr. McCabe and Meta came to an agreement to settle the Loan Purchase by allowing Mr. McCabe to make one additional $700,000 cash payment to Meta and surrender the shares of common stock he previously acquired, while retaining the rights as lender under the 2021 Note and the Loan Agreement. Our obligations and responsibilities under the 2021 Note, the Loan Agreement and the 2022 Note remain unchanged. Following certain amendments entered into in order to extend the 2022 Note, the maturity date was extended to June 30, 2025.

Contractual Obligations

Our most significant contractual obligations relate to the Loan Agreement, the 2021 Note, 2022 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, which incurs interest at 8% per annum and matures on March 31, 2024. 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 September 30, 2024.

On December 21, 2022, we issued the 2022 Note that governs the term loans advanced to us from Mr. McCabe on December 22, 2022, for an aggregate principal balance up to $20 million. Draws on the loan through December 31, 2023 total $20,000,000. The term loan incurs interest at a per annum rate equal to 5% and matures on June 21, 2023. Under each of the 2021 Note, the Loan Agreement and the 2022 Note, if we raise additional capital through debt or equity, or any combination thereof, of at least $30 million 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. Amendment to the Note terms has extended the maturity date to September 30, 2024.

For the year ended December 31, 2022, we incurred an aggregate interest on the 2022 Note, the 2021 Note and under the Loan Agreement of $1,571,336. Interest incurred during the year ended December 31, 2023, was $2,498,184. See the discussion under the caption “Liquidity and Capital Resources.”

In addition to our debt commitments, the Orogrande Project leases representing approximately 134,000 gross acres in the Orogrande Basin in West Texas were subject to expiration in 2024 in the event we failed to drill five wells during the 2024 calendar year in compliance with our drilling obligations under the DDU Agreement. For a discussion of the risks relating to our drilling obligations, see “Risk Factors—Risks Relating 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 7 of the notes to our financial statements as of and for the year ended December 31, 2023.

Management believes that currently available resources may not provide sufficient funds to enable us to meet our financing and drilling obligations for future years. 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, including credit application arrangements with our third party servicers, or a combination of the foregoing. 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 natural 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 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.

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%, 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 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 consolidated financial statements and the accompanying notes thereto found elsewhere in this report contain a description of recent accounting pronouncements.

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

The consolidated financial statements of Next Bridge Hydrocarbons, Inc. appearing in this report have been audited by M&K CPAS, PLLC 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.

We are responsible for the fairness and reliability of the financial statements and other financial data included in this report. In the preparation of the financial statements, it is necessary for us to make informed estimates and judgments based on currently available information on the effects of certain events and transactions. Estimates of the oil and natural 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 report. All of the Company’s properties are unevaluated properties with the exception of the Hazel Project. The reserve report for 2023 included in this filing is necessary to compare proved reserves for the Hazel Project to the remaining balance of reimbursements due to MHP (the Optionee) is entitled to receive, as its sole recourse for the recoupment of drilling costs, All revenue from Hazel production is payable to MHP until such time as MHP has recovered its reasonable costs and expenses for drilling, completing, and operating the well. As of December 31, 2023, and 2022 the balance due to MHP exceeded the value of the proved reserves resulting in reportable reserves of $-0-.

We have included these estimates in reliance on the authority of such firm as an expert in such matters.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders

Next Bridge Hydrocarbons, Inc.

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Next Bridge Hydrocarbons, Inc. (the Company) as of December 31, 2023 and 2022, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the years in the two-year period ended December 31, 2023, and the related notes (collectively referred to as the " consolidated financial statements"). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2023 in conformity with accounting principles generally accepted in the United States of America.

Going Concern

The accompanying consolidated financial statements have been prepared assuming the Company will continue as a going concern. As discussed in Note 4 to the consolidated financial statements, the company has an accumulated deficit, negative cash flows from operations, and has a working capital deficiency as of December 31, 2023, which raises substantial doubt about its ability to continue as a going concern. Management’s plans regarding these matters are also described in Note 4. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis for Opinion

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

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

Our audits included performing procedures to assess the risks of material misstatement of the consolidated 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 consolidated financial statements. Our audits also included evaluating the accounting principles used and the significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe our audits provide a reasonable basis for our opinion.

Restatement of the 2023 and 2022 Consolidated Financial Statements

As discussed in Note 2 to the consolidated financial statements, the accompanying 2023 and 2022 consolidated financial statements have been restated to correct for errors.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing separate opinions on the critical audit matter or on the accounts or disclosures to which it relates.

Oil and Natural Gas Properties

As discussed in Note 2, 5 and 6 to the consolidated financial statements, the Company accounts for its oil and gas properties using the full-cost method of accounting. Management capitalizes certain oil and gas acquisition and drilling costs in unproved and unevaluated properties. To determine whether there is impairment related to the unproved and unevaluated properties, the Company evaluates considerations of lease renewals and extensions, considerations of exploratory drilling, and the ability of access of capital to develop and extend current leases.

Auditing management's evaluation of unproved and unevaluated properties can be a significant judgement given the fact that the Company uses management’s estimates and development intentions on future development plans, which are difficult to substantiate.

To evaluate the appropriateness of management's development plans, we evaluated the key factors and assumptions used to determine the development plans for unproved and unevaluated oil and gas. The procedures included, among other (i) evaluating the intentions and ability to attain lease renewals and extensions, (ii) evaluating the ability to access capital to develop and extend current leases, (iii) evaluating exploratory drilling, and (iv) management’s ongoing economic commitment related to the unproved and unevaluated properties.