NASDAQ: VGASW

As of December 31, 2025, we are still in the process of deploying our STG+® technology and have not derived revenue from our principal business activities.

“Clean” or “lower-carbon” as used to describe the Company’s products refers to lower carbon intensity (“CI”), lower lifecycle emissions, and lower quantity of greenhouse gas (“GHG”) emissions resulting directly from fuel combustion, relative to gasoline derived from petroleum refining. “Renewable” as used in relation to the Company’s products refers to energy or fuel derived from biomass feedstock.

Recent Developments

On February 6, 2026, we announced the suspension of development of the Permian Basin Project (as defined below) primarily as a result of changing market conditions driven by increasing demand for natural gas in the Permian Basin.

On February 18, 2026, we announced a revised strategy to deploy our innovative and proprietary liquid fuels processing technology through capital-lite opportunities. The shift in strategy is intended to identify the most effective pathways to commercialize the STG+® technology with a disciplined approach to capital allocation. Related to our revised strategy, we have implemented and intend to continue implementing aggressive cost savings initiatives targeting a 50% reduction in costs in 2026 as compared to 2025. In connection with this initiative, our Board of Directors has created a Restructuring Committee and appointed director Jonathan Siegler as the sole member of that committee. The Restructuring Committee’s mandate includes overseeing all aspects of our revised strategy and evaluation of strategic alternatives while ensuring we remain fully NASDAQ-compliant. In connection with our cost savings initiatives, we are streamlining our Board of Directors. Related thereto, current directors Martijn Dekker and Dail St. Claire will not be standing for re-election at the end of their term.

On March 20, 2026, we announced the appointment of George Burdette as Chief Executive Officer (“CEO”) and engagement of Roth Capital Partners (“Roth”) as financial advisor to assist the Company in evaluating strategic alternatives. These announcements are part of the Company’s continued advancement of its previously announced restructuring and cost reduction initiatives. Mr. Burdette succeeds Ernie Miller who is stepping down from his role as CEO to pursue another opportunity. Mr. Miller will remain with the Company as a senior advisor. Mr. Burdette, who has served as the Company’s Chief Financial Officer (“CFO”) since October 2024, will also continue in that role.

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Technology

We acquired our STG+® technology from Primus Green Energy (“Primus”) in 2020, which was originally founded in 2007 and invested over $110 million in developing and demonstrating such technology, including the construction and operation of the demonstration plant. The demonstration plant represents the scalable nature of our operational modular commercial design which has fully integrated reactors and recycle lines and is designed with key variables, like gas velocity and catalyst bed length, at a one-to-one scale with our commercial design. The demonstration plant began operations in 2013, completed over 10,000 hours of operation and is currently maintained in an idle state.

Our STG+® process is designed to convert syngas into fully finished liquid fuels that require no additional refining. Syngas can be produced using conventional processes from a variety of feedstocks, including natural gas and biomass, using established reforming or gasification technologies. Our innovative and proprietary STG+® process compresses and passes syngas through a series of four catalytic reactors in a proprietary sequence operating in a continuous vapor-phase loop to produce fully finished liquid fuels.

The STG+® process utilizes fixed-bed catalytic reactors, minimal rotating equipment, and conventional refinery and gas-plant hardware, contributing to predictable catalyst cycles and steady-state continuous operation. Because the process remains in the vapor phase throughout, it eliminates intermediate condensation, handling, purification, and re-vaporization steps typical of legacy methanol-to-gasoline technologies. The catalysts employed in our process are standard and widely available through established commercial supply chains.

The STG+® process is capable of producing higher-value clean transportation fuels, including reformulated blendstock for oxygenate blending (“RBOB”) gasoline that is free of sulfur and benzene. The gasoline produced is suitable to be considered a “drop-in” substitute for petroleum-derived gasoline and is designed to meet applicable [ASTM] specifications after standard downstream blending. We have developed two different pathways to gasoline production, namely natural gas-to-gasoline and biomass-to-gasoline. In each case, syngas is generated from the feedstock, which is then processed into RBOB gasoline through the STG+® process. Our STG+® process has also been adapted to produce methanol and may be adapted to produce other transportation fuels, which could include sustainable aviation fuel or renewable diesel.

Competition

Commercial production plants that utilize the STG+® technology face competition, including companies in the incumbent petroleum-based industry, as well as those in the emerging renewable fuels industry and others selling carbon credits as a commodity

In the gas-to-liquids (“GTL”) and methanol-to-gasoline (“MTG”) technology markets, we primarily compete with established Fischer-Tropsch (“FT”) technologies and other MTG-based processes. Conventional FT technologies typically convert syngas into a broad distribution of hydrocarbons, including significant heavy wax fractions that require substantial downstream upgrading and refining infrastructure. In the MTG-to-gasoline market specifically, there are only two other companies of which we are aware that have proprietary technologies designed to convert syngas or methanol into gasoline: ExxonMobil Corporation (“Exxon”) and Topsoe A/S (“Topsoe”). We expect that other market participants and/or emerging technologies may also present competition to us in the future.

Key differentiators of our STG+® technology relative to conventional FT and certain MTG technologies are as follows:

Continuous Vapor-Phase Design. Our STG+® process operates in a continuous vapor-phase loop through a sequence of fixed-bed catalytic reactors. We believe our continuous vapor-phase design may reduce intermediate processing steps and simplify plant configuration relative to certain legacy MTG technologies that require condensation and re-vaporization steps. In addition, we believe our process may reduce equipment count and simplify plant configuration.

Fully Finished Liquid Fuels. Our STG+® process is designed to selectively produce fully finished liquid fuels that require no additional refining. This is distinctly different than conventional FT technologies, which typically produce a broad range of hydrocarbons, including heavy wax fractions that require substantial downstream upgrading and refining infrastructure.

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Distributed Scale Application. Commercial production plants that utilize the STG+® technology are expected to be operated on a smaller or "distributed" scale relative to traditional large scale GTL facilities. We believe this distributed scale configuration may provide advantages when deployed near constrained or localized feedstock sources, such as stranded natural gas or biomass-derived feedstocks.

Deployment

The STG+® technology is engineered for industrial-scale deployment and intended to be delivered in standardized modular units.

Key differentiators of our deployment model are as follows:

Standard Equipment. Our STG+® process utilizes standard process equipment, including fixed-bed catalytic reactors, standard refinery and gas-plant hardware, and commercially available catalysts. This approach is intended to support predictable catalyst cycles, steady-state continuous operation, and supply chain flexibility.

Modular Deployment. Our STG+® technology is engineered for delivery in standardized modular units that can be fabricated and assembled offsite prior to installation. This modular approach is intended to reduce construction complexity, improve schedule predictability, and enable scalable capacity expansion through replicable unit blocks.

Key Inputs and Suppliers

Commercial production plants that utilize the STG+® technology are not expected to be dependent on sole source or limited source suppliers for raw materials or chemicals. The STG+® technology relies upon syngas as the primary input. Syngas can be produced using conventional processes from a variety of feedstocks, including natural gas and biomass, using established reforming or gasification technologies. Other key inputs to commercial production plants that utilize the STG+® technology include key utilities such as power and water.

When using natural gas as the feedstock, our process may provide an alternative use for natural gas that is stranded or would otherwise be vented or flared by converting such natural gas to RBOB gasoline. Our technology generates in-basin demand for associated natural gas resulting from oil production, alleviating pipeline and takeaway constraints. This could enable oil and gas companies to transform surplus associated natural gas into a higher-value marketable product while reducing carbon emissions.

When using biomass as the feedstock, our process may provide an alternative to landfill disposal of organic matter such as agricultural byproducts by converting such biomass to renewable gasoline. Our renewable gasoline, when paired with carbon capture and sequestration, represents a significant reduction in lifecycle carbon emissions as compared to the carbon emissions resulting from gasoline derived from petroleum refining. Our renewable gasoline could also benefit from various federal and state carbon credit programs designed to incentivize reductions in lifecycle CI and GHG emissions.

The STG+® process also utilizes standard process equipment and commercially available catalysts, which can be sourced from a variety of suppliers.

Intellectual Property

We own or have rights to use the intellectual property associated with the STG+® technology. We have a portfolio of patents that protect key aspects of our STG+® technology related to our ability to produce commodity-grade gasoline from syngas and the specific fuel composition produced by our proprietary systems.

We hold patents related to such key aspects of our STG+® technology in the U.S. as well as 14 other jurisdictions. We actively manage and maintain our patent portfolio to preserve and extend protection of our intellectual property where

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appropriate. Patents related to our ability to produce commodity-grade gasoline from syngas are generally valid through 2031 and patents related to the specific fuel composition produced by our proprietary systems are generally valid through 2033.

Strategy

Our current strategy is focused on the deployment of our STG+® technology through capital-lite opportunities. Such opportunities include licensing technology and providing engineering, technical, and operational services to customers to enable them to build, own, and operate commercial production plants that utilize the STG+® technology.

We had previously been focused on the deployment of our STG+® technology through development of capital-intensive commercial production plants. The shift in strategy is intended to identify the most effective pathways to commercialize the STG+® technology with a disciplined approach to capital allocation. Related to our revised strategy, announced on February 18, 2026, we have implemented and intend to continue implementing aggressive cost savings initiatives. Related to the change in strategy, we have eliminated roles related to the development of capital-intensive commercial production plants that are no longer aligned with our current operating plan.

Customers

Potential customers for the liquid fuels produced at commercial production plants that utilize the STG+® technology include fuel refiners, importers, distributors, blenders, retailers, and trading organizations. Such customers may be obligated by clean fuel standards or regulations to purchase physical volumes of renewable fuel.

Potential customers that may develop commercial production plants that utilize the STG+® technology include consumers of the liquid fuels that would be produced as well as energy companies, project developers, and industrial operators.

Commercial production plants that utilize the STG+® technology could also derive value from environmental attributes associated with renewable fuels. For example, certain gasoline produced from renewable feedstock, such as cellulosic biomass, qualifies under the federal renewable fuel standard (“RFS”) for a D3 renewable identification number ("RIN"), a renewable fuel credit based, in part, on GHG intensity. Similarly, we believe that gasoline produced in this fashion may qualify for various state carbon programs including California’s low carbon fuel standard ("LCFS"). The availability and value of environmental attributes are subject to potential changes in regulatory environment and market conditions.

Relationships

Bluescape. Our primary stockholder is Holdings. Holdings is an affiliate of Bluescape Energy Partners, an alternative investment firm.

Diamondback. Our second largest stockholder is Cottonmouth. Cottonmouth is a wholly-owned subsidiary of Diamondback, an independent oil and natural gas company.

Shaw. In June 2024, we entered into a contract with Chemex Global, LLC (“Chemex”), a Shaw Group company (“Shaw”), for a front-end engineering and design (“FEED”) study related to the Permian Basin Project (defined below). The FEED study was completed in December 2025; however, the Permian Basin Project was suspended in February 2026. We believe the FEED study will continue to be useful as we explore other opportunities to deploy the STG+® technology.

Koch Modular. Koch Modular Process Systems, LLC (“Koch Modular”) specializes in the design and manufacturing of modular mass transfer systems for the chemical process industry. Koch Modular was engaged to design standardized modular units for the STG+® technology for the Permian Basin Project. We believe the standardized modular units designed will continue to be useful as we explore other opportunities to deploy the STG+® technology.

Formation, Business Combination and Related Transactions

On February 15, 2023 (the “Closing Date”), we consummated (the "Closing") a business combination (the "Business Combination") pursuant to a business combination agreement, dated as of August 12, 2022 (“Business Combination Agreement”), by and among CENAQ Energy Corp. (“CENAQ”), a Delaware corporation, Verde Clean Fuels OpCo, LLC,

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a Delaware limited liability company and a wholly owned subsidiary of CENAQ (“OpCo”), Holdings, Bluescape Clean Fuels Intermediate Holdings, LLC, a Delaware limited liability company and a wholly-owned subsidiary of Holdings (“Intermediate”), and CENAQ Sponsor LLC (“Sponsor”). Immediately upon the completion of the Business Combination, CENAQ was renamed as "Verde Clean Fuels, Inc."

Pursuant to the Business Combination Agreement: (i) CENAQ filed a fourth amended and restated certificate of incorporation (the “Fourth A&R Charter”) with the Secretary of State of the State of Delaware reflecting the name change to “Verde Clean Fuels, Inc.” and increasing the number of authorized shares of Verde Clean Fuels’ capital stock, par value $0.0001 per share, to 376,000,000 shares, consisting of (A) 350,000,000 shares of Class A Common Stock, (B) 25,000,000 shares of Class C common stock, par value $0.0001 per share (the "Class C Common Stock" and together with the Class A Common Stock, the "Common Stock") and (C) 1,000,000 shares of preferred stock, par value $0.0001 per share; (ii) (A) CENAQ contributed to OpCo (1) all of its assets (excluding its interests in OpCo and the aggregate amount of cash required to satisfy any exercise by CENAQ stockholders of their Redemption Rights (as defined below)) and (2) 22,500,000 newly issued shares of Class C Common Stock (such shares, the “Holdings Class C Shares”) and (B) in exchange therefor, OpCo issued to CENAQ a number of Class A common units of OpCo (the “Class A OpCo Units”) equal to the number of total shares of Class A Common Stock issued and outstanding immediately after the consummation of the transactions (the “Transactions”) contemplated by the Business Combination Agreement (such transactions, the “SPAC Contribution”); and (iii) immediately following the SPAC Contribution, (A) Holdings contributed to OpCo 100% of the issued and outstanding limited liability company interests of Intermediate and (B) in exchange therefor, OpCo transferred to Holdings (1) 22,500,000 Class C common units of OpCo (the “Class C OpCo Units” and, together with the Class A OpCo Units, the “OpCo Units”) and (2) the Holdings Class C Shares (such transactions, the "Holdings Contribution"). Additionally, the following transactions occurred in connection with the Business Combination:

•The issuance and sale of 3,200,000 shares of Class A Common Stock for a purchase price of $10.00 per share (Holdings purchased 800,000 of these shares of Class A Common Stock), for an aggregate purchase price of $32,000,000, in a private placement (the “PIPE Financing”);

•An aggregate of $158.8 million was paid from the CENAQ trust account to holders of 15,403,880 shares of Class A Common Stock that exercised their redemption rights (“Redemption Rights”) and the balance of $19,031,516 of proceeds from CENAQ’s trust account related to non-redeeming holders of 1,846,120 shares of Class A Common Stock was released from trust and delivered to Verde Clean Fuels as part of the Business Combination;

•We repaid $3,750,000 of capital contributions made by Holdings and paid $10,043,793 of transaction expenses including deferred underwriting fees of $1,700,000;

•As additional consideration for the Holdings Contribution, the Company will cause OpCo to transfer to Holdings up to 3,500,000 Class C OpCo Units and a corresponding 3,500,000 shares of Class C Common Stock (the “Earn Out Equity”), upon the occurrence of a Triggering Event (as defined below). A Triggering Event occurs on the date on which the Company's Class A Common Stock's volume-weighted average share price for any 20 trading days within any period of 30 consecutive trading days during the period between the Closing Date, being February 15, 2023, and the earlier of the five-year anniversary of the Closing Date or the date a Company Sale (as defined in the Business Combination Agreement) is consummated (the “Earn Out Period”) is greater than or equal to $15.00 (“Triggering Event I”) or $18.00 (“Triggering Event II” and, together with Triggering Event I, Triggering Event"). Upon the occurrence of Triggering Event I within the Earn Out Period, an aggregate of 1,750,000 Class C OpCo Units and a corresponding 1,750,000 shares of Class C Common Stock will be transferred to Holdings, and upon the occurrence of Triggering Event II within the Earn Out Period, an aggregate of 1,750,000 Class C OpCo Units and a corresponding 1,750,000 shares of Class C Common Stock will be transferred to Holdings. If there is a Company Sale during the Earn Out Period pursuant to which the Company or any of its holders of Class A Common Stock have the right to receive consideration implying a value per share of Class A Common Stock that is greater than or equal to the applicable price specified in the Triggering Events, any Earn Out Equity that has not previously transferred will be deemed to have been transferred immediately prior to the closing of such Company Sale, and Holdings will be eligible to participate in such Company Sale with respect to the Earn Out Equity

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deemed transferred on the same terms, and subject to the same conditions, as apply to the holders of Class A Common Stock generally. Upon consummation of a Company Sale, the Earn Out Period will terminate and Holdings will have no further right to receive or earn the Earn Out Equity other than in accordance with the Triggering Events, with respect to such Company Sale;

•The Sponsor agreed to forfeit 2,475,000 of its Private Placement Warrants (as defined below), retaining 2,475,000 Private Placement Warrants for which it paid $2,475,000 to CENAQ in a private placement transaction that occurred concurrent with the closing of the initial public offering;

•Sponsor agreed to subject 3,234,375 shares (the “Sponsor Subject Shares”) of its 3,487,500 shares of Class A Common Stock received upon conversion of its founder shares to forfeiture if a Triggering Event does not occur during the time period between the Closing Date, being February 15, 2023, and the earlier of (i) the five-year anniversary of the Closing Date or (ii) the date a Company Sale is consummated (the “Forfeiture Period”); 50% of the Sponsor Subject Shares will no longer be subject to forfeiture if Triggering Event I occurs during the Forfeiture Period and the balance of 50% of the Sponsor Subject Shares will no longer be subject to forfeiture if Triggering Event II occurs during the Forfeiture Period. If during the Forfeiture Period there is a Company Sale pursuant to which the Company or its holders of Class A Common Stock have the right to receive consideration implying a per share value of Class A Common Stock of greater than or equal to $15.00 or $18.00, respectively, then a Triggering Event will be deemed to have occurred. If neither Triggering Event occurs during the Forfeiture Period, upon the expiration of the Forfeiture Period, the Sponsor Subject Shares will immediately be forfeited to the Company for no consideration and immediately cancelled;

•The forfeiture by underwriters of 189,750 shares of Class A Common Stock; and

•The issuance of 253,125 and 825,000 shares of Class A Common Stock to the Sponsor and certain other investors in CENAQ’s initial public offering upon conversion of shares of Class B common stock of CENAQ.

Total proceeds raised from the Business Combination were $51,122,970 consisting of $32,000,000 in PIPE Financing proceeds, $19,031,516 from the CENAQ trust, and $91,454 from the CENAQ operating account offset by $10,043,793 in transaction expenses which were recorded as a reduction to additional paid in capital, and offset by a $3,750,000 capital repayment to Holdings, resulting in net proceeds of $37,329,178. As of the consummation of the Business Combination, there were (i) 31,858,620 shares of our Common Stock issued and outstanding, comprised of 9,358,620 shares of Class A Common Stock and 22,500,000 shares of Class C Common Stock and (ii) 2,475,000 shares of our Class A Common Stock reserved for issuance upon exercise of 2,475,000 private placement warrants originally issued by CENAQ (“Private Placement Warrants”) and 12,937,479 shares of our Class A Common Stock reserved for issuance upon exercise of our 12,937,479 public warrants issued in the initial public offering (“Public Warrants” and, together with the Private Placement Warrants, the “Warrants”). Each of the Warrants is currently exercisable to purchase one share of Class A Common Stock at $11.50 per share on or prior to February 15, 2028, except for 29,216 Public Warrants that were exercised for cash of $335,984 in connection with the issuance of 29,216 shares of Class A Common Stock during the fiscal year beginning January 1, 2023.

Prior to the Business Combination, Verde Clean Fuels, previously CENAQ, was a special purpose acquisition company (“SPAC”) incorporated for the purpose of effecting a merger, share exchange, asset acquisition, share purchase, reorganization or similar business combination with one or more businesses.

Pursuant to Accounting Standards Codification ("ASC") 805 – Business Combinations (“ASC 805”), the Business Combination was accounted for as a common control reverse recapitalization where Intermediate was deemed the accounting acquirer and Verde Clean Fuels was treated as the accounting acquiree, with no goodwill or other intangible assets recorded, in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”). The Business Combination was not treated as a change in control of Intermediate. This determination reflects Holdings holding a majority of the voting power of Verde Clean Fuels, Intermediate’s pre-Business Combination operations being the majority post-Business Combination operations of Verde Clean Fuels, and Intermediate’s management

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team retaining similar roles at Verde Clean Fuels. Further, Holdings continues to control the Company's Board of Directors (the "Board" or "Board of Directors") through its majority voting rights. Under ASC 805, the assets, liabilities, and noncontrolling interests of Intermediate are recognized at their carrying amounts on the date of the Business Combination.

Following the completion of the Business Combination, the combined company is organized in an “Up-C” structure and the only direct assets of Verde Clean Fuels consists of equity interests in OpCo, whose only direct assets consists of equity interests in Intermediate. The Up-C structure allows Holdings to retain its equity ownership through OpCo, an entity that is classified as a partnership for U.S. federal income tax purposes, in the form of Class C OpCo Units, and provides potential future tax benefits for Verde Clean Fuels when the holders of Class C OpCo Units ultimately exchange their Class C OpCo Units and shares of the Company’s Class C Common Stock for shares of Class A Common Stock in Verde Clean Fuels. We are the sole managing member of OpCo. As such, we consolidate OpCo, and the unitholders that hold economic interests directly in OpCo are presented as redeemable noncontrolling interests in our financial statements.

Holders of Class C OpCo Units, other than Verde Clean Fuels, have the right (a "redemption right"), subject to certain limitations, to exchange all or a portion of its Class C OpCo Units and a corresponding number of shares of Class C Common Stock for, at OpCo’s election, (i) shares of Class A Common Stock on a one-for-one basis, subject to adjustment for stock splits, stock dividends, reorganizations, recapitalizations and the like, or (ii) an equivalent amount of cash.

On the Closing Date, in connection with the consummation of the Business Combination, Verde Clean Fuels entered into a tax receivable agreement (the “Tax Receivable Agreement”) with Holdings (together with its permitted transferees, the “TRA Holders,” and each a “TRA Holder”). Pursuant to the Tax Receivable Agreement, Verde Clean Fuels is required to pay each TRA Holder 85% of the amount of realized tax benefit, if any, in U.S. federal, state and local income and franchise tax that Verde Clean Fuels actually realizes (computed using certain simplifying assumptions) or is deemed to realize in certain circumstances in periods after the Closing Date as a result of, as applicable to each such TRA Holder, (i) certain increases in tax basis that occur as a result of Verde Clean Fuels’ acquisition (or deemed acquisition for U.S. federal income tax purposes) of all or a portion of such TRA Holder’s Class C OpCo Units pursuant to the exercise of the OpCo exchange right, a mandatory exchange or the call right (collectively referred to as “Exchange Right, a Mandatory Exchange or the Call Right”) and (ii) imputed interest deemed to be paid by Verde Clean Fuels as a result of, and additional tax basis arising from, any payments Verde Clean Fuels makes under the Tax Receivable Agreement. Verde Clean Fuels will retain the benefit of the remaining 15% of these net cash savings. The Tax Receivable Agreement contains a payment cap of $50,000,000 (the "Payment Cap"), which applies only to certain payments required to be made in connection with the occurrence of a change of control. The Payment Cap would not be reduced or offset by any amounts previously paid under the Tax Receivable Agreement or any amounts that are required to be paid (but have not yet been paid) for the year in which the change of control occurs or any prior years.

Cottonmouth and Permian Basin Project

Concurrent with the Business Combination, Cottonmouth made a $20 million equity investment in Verde and entered into an equity participation right agreement pursuant to which Verde granted Cottonmouth the right to participate and jointly develop facilities in the Permian Basin utilizing Verde’s STG+® technology for the production of gasoline derived from economically disadvantaged natural gas feedstocks. Cottonmouth is a wholly-owned subsidiary of Diamondback, an independent oil and natural gas company.

In February 2024, Verde and Cottonmouth entered into a joint development agreement (the “JDA”) related to the proposed development, construction, and operation of a natural gas-to-gasoline plant in the Permian Basin utilizing Verde's STG+® technology and associated natural gas from Diamondback's operations (the "Permian Basin Project"). The JDA frames the contracts contemplated to be entered into between the parties and outlines the conditions precedent for the parties to enter into definitive documents and achieve final investment decision (“FID”) to proceed with the Permian Basin Project. The JDA conditions precedent include finalizing applicable project contracts, obtaining necessary permits, obtaining project financing on terms satisfactory to each party, and receiving FID by each party.

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In December 2024, we entered into a Class A Common Stock Purchase Agreement with Cottonmouth (the “Purchase Agreement"), pursuant to which we agreed to issue and sell to Cottonmouth in a private placement an aggregate of 12,500,000 shares (the “PIPE Shares”) of our Class A common stock, par value $0.0001 (“Class A Common Stock”), at a price of $4.00 per share for an aggregate purchase price of $50,000,000 (the “PIPE Investment”). Closing of the PIPE Investment occurred on January 29, 2025. Proceeds from the PIPE Investment were intended to further the development and construction of potential natural gas-to-gasoline production plants in the Permian Basin and for other general corporate purposes.

In February 2026, the Company suspended development of the Permian Basin Project primarily as a result of changing market conditions driven by increasing demand for natural gas in the Permian Basin. For the year ended December 31, 2025, the Company recorded an impairment of the full carrying value of its construction in progress assets related to the Permian Basin Project. See Notes 4, 5, 7 and 14 in the accompanying consolidated financial statements for further information.

Demand for Renewable and Lower-Carbon Gasoline

Energy markets are undergoing dramatic changes as they shift from fossil fuels to carbon-reduced and carbon-free sources. A series of technological, economic, regulatory, social and investor pressures are leading the drive to decarbonize energy and sectors that are major energy consumers, such as transportation.

According to the U.S. Energy Information Administration’s (the “EIA”) “U.S. Energy-Related Carbon Dioxide Emissions, 2023,” gasoline accounted for more than 20% of the U.S.’s energy-related carbon dioxide (“CO2”) emissions in 2023 and overall, transportation represented approximately 39% of total U.S. energy-related CO2 emissions (or 1,856 million tons of CO2). Within the approximately 39% of total U.S. energy-related CO2 emissions caused by the transportation sector, in 2023, gasoline accounted for approximately 56% of the total (or 1,033 million tons of CO2) and accounted for over twice the emissions of diesel (which produced approximately 460 million tons of CO2) and over four times the emissions of jet fuel (which produced approximately 247 million tons of CO2). Uptake on competing emissions-reduction technologies, such as electric vehicles, is growing, but, according to BloombergNEF, is only expected to reach 24% of the projected 2035 total vehicle fleet in the U.S. As a result, the EIA predicts 2035 gasoline demand to be at 92-102% of 2022 levels. According to the EIA’s “2022 Annual Energy Outlook,” petroleum and natural gas are projected to remain as the most-consumed source of energy in the U.S. through 2050, and motor gasoline is projected to be the most commonly used transportation fuel despite electric vehicles gaining market share.

Production of renewable gasoline paired with carbon capture and sequestration results in a fuel that has a negative CI score, meaning that more carbon is sequestered in the production of a gallon of fuel than is emitted by the consumption of that same quantity of fuel.

According to the U.S. Department of Energy, there are approximately 241 million tons per year of waste forest resources and 318 million tons per year of agricultural waste generated annually in the U.S. Using Verde’s STG+® process to produce gasoline from biomass, waste from forest and agricultural sources could produce over 25 billion gallons of gasoline per year. Achieving production of 25 billion gallons of renewable gasoline could meet approximately 19% of the EIA’s estimated 2022 gasoline demand of 132 billion gallons. Renewable gasoline can be utilized within the existing 268 million internal combustion engine (“ICE”) vehicles in the U.S. without vehicle modification. We believe that our renewable gasoline will be able to utilize essentially all of the existing fossil fuel gasoline distribution and retailing infrastructure, including existing gas stations, making our renewable gasoline a drop-in solution that does not require a change in consumer behavior.

Based on the Fuel Institute’s “Life Cycle Analysis Comparison, 2022,” a single conventional ICE vehicle is accountable for approximately 66 tons of CO2 over a 200,000-mile life, which includes 5 tons of CO2 generated from the manufacturing process, 12 tons of CO2 generated from the production and processing of the oil and gasoline fuel used in the vehicle and 48 tons of CO2 generated from vehicle emissions. We estimate that an ICE vehicle utilizing renewable gasoline produced using our STG+® process with carbon sequestration would be accountable for approximately negative 81 tons of CO2 over

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a 200,000-mile life, which includes five tons of CO2 generated from the manufacturing process, negative 134 tons of CO2 from the production of the renewable gasoline fuel used in the vehicle and 48 tons of CO2 generated from vehicle emissions. As a result, we estimate that an ICE vehicle running solely on renewable gasoline produced using our STG+® process with carbon sequestration would account for over 200% less CO2 emissions over its lifecycle than the same vehicle running on traditional hydrocarbon-based gasoline.

Regulatory Environment

Demand for renewable fuel has grown significantly over the past several years and is expected to continue to grow due in part to federal requirements for cellulosic biofuel volume obligations through programs such as the RFS, which was created under the Energy Policy Act of 2005 (the “Energy Act”), which amended the Clean Air Act (“CAA”) and was expanded through the Energy Independence and Security Act of 2007 (the “EISA”). The EISA requires the use of specific volumes of biofuel in the U.S. and is aimed at (i) increasing energy security by reducing U.S. dependence on foreign oil and establishing domestic green fuel related industries and (ii) improving the environment through the reduction of GHG emissions. Under the RFS program, transportation fuel sold in the U.S. must contain a certain minimum volume of renewable fuel. The U.S. Environmental Protection Agency (the "EPA") administers the RFS program with volume requirements for several categories of renewable fuels, which volume requirements are established through a notice-and-comment rulemaking process intended to occur at least 14 months prior to the year in which the volume will be required. In July 2023 (as corrected in August 2023), the EPA issued its latest final rule that establishes the biofuel volume requirements for 2023 to 2025. Importantly, these most recent volume requirements include a steady growth of biofuels for 2023, 2024 and 2025. In June 2025, the EPA issued a proposed rule, “Renewable Fuel Standard (RFS) Program: Standards for 2026 and 2027, Partial Waiver of 2025 Cellulosic Biofuel Volume Requirement, and Other Changes.” The final rule is currently under interagency review with the Office of Management and Budget (the “OMB”). See “Item 1. Business—Environmental, Social and Governance—Sustainability” for more information. However, as stated above, the RFS program is subject to change, including by modification or repeal by Congressional action or action by the EPA or the EPA administrator and EPA has, in some cases, failed to issue volume requirements sufficiently far in advance, which can contribute to uncertainty for producers of renewable fuels. Similarly, state-level programs like California’s LCFS are also subject to change.

Our future operations are subject to stringent and complex laws and regulations governing environmental protection and human health and safety. Compliance with such laws and regulations can be costly, and noncompliance can result in substantial penalties. Laws and regulations that may have an impact on our business include:

•The federal Comprehensive Environmental Response, Compensation and Liability Act (or “CERCLA”) and analogous state laws, impose joint and several liability, without regard to fault or the legality of the original act, on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the owner and operator of the site where the release occurred, past owners and operators of the site, and companies that disposed of or arranged for the disposal of hazardous substances found at the site. Responsible parties under CERCLA may be liable for the costs of cleaning up hazardous substances that have been released into the environment and for damages to natural resources. Additionally, it is not uncommon for third parties to assert claims for personal injury and property damage allegedly caused by the release of hazardous substances or other pollutants into the environment.

•The federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act (or “RCRA”), is the principal federal statute governing the management of wastes, including the treatment, storage and disposal of hazardous wastes. RCRA imposes stringent operating requirements and liability for failure to meet such requirements, on a person who is either a generator or transporter of hazardous waste or an owner or operator of a hazardous waste treatment, storage, or disposal facility. We anticipate that many wastes generated by our manufacturing facility or process will be governed by RCRA.

•The federal Water Pollution Control Act (also referred to as the “Clean Water Act”) imposes restrictions and controls on the discharge of pollutants into navigable waters. These controls have become more stringent over the

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years, and it is possible that additional restrictions may be imposed in the future. Permits must be obtained to discharge pollutants into state and federal waters. The Clean Water Act provides for civil, criminal and administrative penalties for discharges of oil and other pollutants and imposes liability on parties responsible for those discharges for the costs of cleaning up any environmental damage caused by the release and for natural resource damages resulting from the release. Comparable state statutes impose liability and authorize penalties in the case of an unauthorized discharge of petroleum or its derivatives or other pollutants into state waters.

•The CAA and associated state laws and regulations restrict the emission of air pollutants from many sources, including facilities involved in manufacturing biofuels. New facilities are generally required to obtain permits before operations can commence, and new or existing facilities may be required to incur certain capital expenditures to install air pollution control equipment in connection with obtaining and maintaining operating permits and approvals. Federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with permits or other requirements of the CAA and associated state laws and regulations.

•The federal Endangered Species Act, the federal Marine Mammal Protection Act and similar federal and state wildlife protection laws prohibit or restrict activities that could adversely impact protected plant and animal species or habitats. Construction of facilities could be prohibited or delayed in areas where such protected species or habitats may be located, or mitigation may be required to accommodate such activities. There is also increasing interest in nature-related matters beyond protected species, such as general biodiversity, which may similarly require us or our customers to incur costs or take other measures which may adversely impact our business or operations.

•The Inflation Reduction Act of 2022 (the “IR Act”) provides for, among other things, a new clean hydrogen production tax credit, a new credit for sustainable aviation fuel, credits for the production and purchase of electric vehicles, expanding eligibility for and increasing the value of the carbon capture and sequestration credit, extending the biodiesel, renewable diesel and alternative fuels tax credit, funding biofuel refueling infrastructure and providing additional funding for working lands conservation programs for farmers. However, in January 2025, President Trump issued an executive order directing an immediate pause on the disbursement of funds appropriated through the Infrastructure Investment and Jobs Act (the "IIJ Act") and the IR Act. This pause on disbursements is subject to ongoing legal challenges. Further, on July 4, 2025, the One Big Beautiful Bill Act (the "OBBB Act"), through Congressional budget reconciliation was signed into law by President Trump. The OBBB Act made significant changes to the IR Act and rescinded unobligated funds that the IIJ Act has appropriated. The OBBB Act could have several potential impacts on our business that we are continuing to evaluate, including new opportunities to access production tax credits and carbon sequestration credits.

We may be required to obtain certain permits to construct and operate our facilities, including those related to air emissions, solid and hazardous waste management and water quality. These permits can be difficult and expensive to obtain and maintain. Our ability to obtain these permits could be impacted by opposition from various stakeholders. Once operational, our facilities will also need to maintain compliance with these permits.

In addition to compliance with environmental regulations, we expect that our future operations will be subject to federal RFS program regulations. The EPA administers the RFS program with volume requirements for several categories of renewable fuels, which volume requirements are established through a notice-and-comment rulemaking process intended to occur at least 14 months prior to the year in which the volume will be required. In July 2023 (as corrected in August 2023), EPA issued a final rule that establishes the biofuel volume requirements for 2023 to 2025. As noted above, the final rule for biofuel volume requirements for 2026 and 2027 are currently under interagency review with the OMB. The EPA calculates a blending standard annually based on estimates of gasoline usage from the EIA. Different quotas and blending requirements are determined for cellulosic biofuels, biomass-based diesel, advanced biofuels and total renewable fuel. RINs are used to ensure that the prescribed levels of blending are met. EPA’s RFS regulations establish rules for fuel supplied and administer the RIN system for compliance, trading credits and rules for waivers. We anticipate that our renewable gasoline and other future products will benefit from the RFS program. However, as stated above, the use

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requirements of the RFS program or state programs could change, which may impact our products and harm our ability to operate profitably. See “Item 1. Business—Environmental, Social and Governance—Sustainability" for more information.

Environmental, Social and Governance (“ESG”)

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and may continue to be made at the international, national, regional, and state levels of government to monitor and limit emissions of GHGs, with the reduction of GHG from the energy and transportation sectors being a key focus.

The RFS program was created under the Energy Act, which amended the CAA. The EISA further amended the CAA by expanding the RFS program. The EPA implements the RFS program under the guidance of the U.S. Department of Agriculture and the Department of Energy.

We have participated in carbon lifecycle studies to validate the scoring of our CI, which we define as the quantity of GHG emissions associated with producing, distributing, and consuming a fuel, per unit of fuel energy and reduced lifecycle emissions (the GHG emissions associated with the production, distribution, and consumption of a fuel) of our renewable gasoline as well as fuel, blending and engine testing to validate the specification and performance of our gasoline product. Our CI score is based on an analysis styled after the Department of Energy’s Greenhouse gases Regulated Emissions, and Energy use in Technologies (“GREET”) lifecycle analysis.

We believe our gasoline produced from renewable feedstock, such as biomass, would qualify under the RFS program for a D3 RIN, which could have significant value. Similarly, gasoline produced from our process may qualify for various state carbon programs, including California’s LCFS.

The RFS program is a federal policy that requires a certain volume of renewable fuel to replace or reduce the quantity of petroleum-based transportation fuel, heating oil or aviation fuel. The four renewable fuel categories under the RFS are each assigned a “D-code” — a code that identifies the renewable fuel type — based on the feedstock used, fuel type produced, energy inputs and GHG reduction thresholds, among other requirements. The four categories of renewable fuel have the following assigned D-codes, as shown below. Lifecycle GHG reduction comparisons are based on a 2005 petroleum baseline as mandated by EISA. Biofuel facilities (domestic and foreign) that were producing fuel prior to enactment of EISA in 2007 are considered “grandfathered” under the statute, meaning these facilities are not required to meet the GHG reductions.

•Cellulosic biofuel, must be produced from cellulose, hemicellulose or lignin and must meet a 60% lifecycle GHG reduction, is assigned a D-code of 3 (cellulosic biofuel) or a D-code of 7 (cellulosic diesel);

•Biomass-based diesel, which must meet a 50% lifecycle GHG reduction, is assigned a D-code of 4;

•Advanced biofuel which can be produced from qualifying renewable biomass (except corn starch) and must meet a 50% GHG reduction, is assigned a D-code of 5; and

•Renewable fuel (non-advanced/conventional biofuel, like ethanol from corn starch) is assigned a D-code of 6 (grandfathered fuels are also assigned a D-code of 6) and must meet a 20% lifecycle GHG reduction threshold.

The 2007 enactment of EISA significantly increased the size of the program and included key changes, including:

•boosting the long-term goals to 36 billion gallons of renewable fuel;

•extending yearly volume requirements out to 2022 by statute and, after 2022, establishing a notice-and-comment rulemaking process by which EPA must determine the applicable volumes at least 14 months prior to the year in which the volume will be required;

•adding explicit definitions for renewable fuels to qualify (e.g., renewable biomass, GHG emissions) versus a 2005 petroleum baseline;

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•creating grandfathering allowances for volumes from certain existing facilities; and

•including specific types of waiver authorities.

The EPA has the authority to adjust cellulosic, advanced and total volumes set by Congress as part of the annual rule process.

The statute also contains a general waiver authority that allows the Administrator to waive the RFS volumes, in whole or in part, based on a determination that implementation of the program is causing severe economic or environmental harm, or based on inadequate domestic supply.

The EPA has approved fuel pathways under the RFS program under all four categories of renewable fuel. Advanced pathways already approved include ethanol made from sugarcane, jet fuel made from camelina, cellulosic ethanol made from corn stover, compressed natural gas from municipal wastewater treatment facility digesters and others. We believe our fuel may qualify for Pathway M.

Lifecycle GHG reduction comparisons are based on a 2005 petroleum baseline as mandated by EISA. Biofuel facilities (domestic and foreign) that were producing fuel prior to enactment of EISA in 2007 are “grandfathered” under the statute, meaning these facilities are not required to meet the GHG reductions.

The EPA continues to review and approve new pathways, including for fuels made with advanced technologies or with new feedstocks. Certain biofuels, such as our renewable gasoline, are similar enough to gasoline or diesel that they do not have to be blended, but can be simply “dropped in” to existing petroleum-based fuels. These drop-in biofuels directly replace petroleum-based fuels and hold particular promise for the future.

Obligated parties under the RFS program are refiners or importers of gasoline or diesel fuel (“Obligated Parties”). Compliance is achieved by blending renewable fuels into transportation fuel, or by obtaining credits, RINs, to meet an EPA-specified renewable volume obligation (“RVO”).

The EPA calculates and establishes RVOs every year through rulemaking, based on the CAA volume requirements and projections of gasoline and diesel production for the coming year. The standards are converted into a percentage and Obligated Parties must demonstrate compliance annually.

Obligated Parties use RINs to demonstrate compliance with the standard. These parties must obtain sufficient RINs for each category in order to demonstrate compliance with the annual standard. Some of the regulations regarding RINs include the following:

•RINs are generated when a producer makes a gallon of renewable fuel;

•At the end of the compliance year, Obligated Parties use RINs to demonstrate compliance;

•RINs can be traded between parties;

•Obligated Parties can buy gallons of renewable fuel with RINs attached, and they can also buy RINs on the open market; and

•Obligated Parties can carry over unused RINs between compliance years. They may carry a compliance deficit into the next year. This deficit must be made up the following year.

The RFS program’s four renewable fuel categories are “nested” within each other. This means the fuel with a higher GHG reduction threshold can be used to meet the standards for a lower GHG reduction threshold. For example, fuels or RINs for advanced biofuel (e.g., cellulosic, biodiesel or sugarcane ethanol) can be used to meet the total renewable fuel standards.

For cellulosic standards, an additional flexibility is provided by statute. Cellulosic waiver credits (“CWCs”) have historically been offered at a price determined by a formula in the Energy Act. Obligated Parties had the option of

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purchasing CWCs plus an advanced RIN in lieu of blending cellulosic biofuel or obtaining a cellulosic RIN. As a result, CWCs, in some cases, set a ceiling for cellulosic RIN prices. However, in the EPA’s July 2023 rule (as corrected in August 2023), EPA interpreted its authority in setting RIN volumes for 2023 through 2025 (which, for the first time were not set forth in statute) so as to preclude it from issuing CWCs in those years, absent a future waiver of EPA-established cellulosic standards. As noted above, the final rule for biofuel volume requirements for 2026 and 2027 are currently under interagency review with the OMB.

In November 2021, the IIJ Act was signed into law that includes $65 billion in funding for power and grid investments. This includes investments in grid reliability and resiliency as well as clean energy technologies such as carbon capture, hydrogen and advanced nuclear, including small modular reactors. Additionally, in December 2021, President Biden signed an executive order mandating all electricity procured by the government be 100% carbon pollution-free by 2030, including at least 50% from around-the-clock dispatchable generation sources. The order also requires that federally owned buildings produce no net emissions by 2045 and that each federal agency achieve 100% zero-emission vehicle acquisitions by 2035. In January 2025, President Trump issued an executive order directing an immediate pause on the disbursement of funds appropriated through the IIJ Act and the IR Act. This pause on disbursements is subject to ongoing legal challenges. Furthermore, on July 4, 2025, the OBBB Act, was signed into law by President Trump. The OBBB Act made significant changes to the IR Act and rescinded unobligated funds that the IIJ Act has appropriated..

Efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols intended to address global climate change issues. These include the Paris Agreement (an international agreement from the 21st Conference of the Parties ("COP") of the United Nations Framework Convention on Climate Change that is aimed at addressing climate change with member countries agreeing to nationally determine their contributions and set GHG emission reduction goals every five years, and the Global Methane Pledge, a pact that aims to reduce global methane emissions at least 30% below 2020 levels by 2030, including “all feasible reductions” in the energy sector. Since its formal launch at the 26th COP, over 150 countries have joined the pledge. At the 27th COP, the EPA’s supplemental proposed rule to reduce methane emissions from existing oil and gas sources was announced and the U.S. agreed, in conjunction with the European Union and a number of other partner countries, to develop standards for monitoring and reporting methane emissions to help create a market for low methane intensity natural gas. Subsequently, at the 28th COP, member countries (including the United States) entered into an agreement that calls for actions toward achieving, at a global scale, a tripling of renewable energy capacity and doubling energy efficiency improvements by 2030. At the 29th COP, participants representing 159 countries met to review progress toward the goals of the Global Methane Pledge and the addition of nearly $500 million in new grant funding for methane abatement. However, in January 2025, President Trump issued an executive order directing immediate notice to the United Nations of the United States’ withdrawal from the Paris Agreement and all other agreements made under the United Nations Framework Convention on Climate Change. The full impact of these actions remains unclear at this time. However,many state and local leaders have intensified or stated their intent to intensify efforts to support international climate commitments and treaties, in addition to considering or enacting laws requiring the disclosure of climate-related information and developing programs that are aimed at reducing GHG emissions by means of cap and trade programs, carbon taxes or encouraging the use of renewable energy or alternative low-carbon fuels. Many such initiatives at the international, state and local levels are expected to continue.

In addition, in March 2024, the SEC issued final rules regarding the enhancement and standardization of mandatory climate-related disclosures for investors. In April 2024, the SEC issued an administrative stay of the implementation of the rules, pending judicial review. In March 2025, the SEC voted to cease defending the rules in court. Accordingly, we cannot predict whether the rules will be implemented as finalized, when they may become effective, if at all, nor the costs of implementation or any potential resulting adverse impacts.

Human Capital Resources

As of December 31, 2025, our workforce consisted of 12 employees and 4 contractors. In February 2026, we announced a revised strategy and elimination of roles related to the development of capital-intensive commercial production plants that

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are no longer aligned with our current operating plan. As of March 27, 2026, our workforce consisted of 9 employees and 3 contractors.

Our workforce is mostly concentrated in proximity to our offices in Houston, Texas and Hillsborough, New Jersey. We have not experienced any work stoppages and consider our relationship with our employees to be in good standing.

Available Information

Our website address is www.verdecleanfuels.com.

We furnish or file with the SEC our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, and our Current Reports on Form 8-K. We make these documents available free of charge on our website under the “Investors” tab as soon as reasonably practicable after they are filed or furnished with the SEC. In addition, corporate governance information, including our corporate governance guidelines and code of ethics, is also available on our investor relations website under the heading “Governance Documents.” Information contained on, or accessible through, our website is not incorporated by reference into this Annual Report or any of our other filings with the SEC. The SEC also maintains an website that contains reports, proxy statements and other information about issuers, like us, that file electronically with the SEC. The SEC website address is www.sec.gov.

Emerging Growth Company and Smaller Reporting Company Status

We qualify as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”). Section 107 of the JOBS Act permits an “emerging growth company” to take advantage of an extended transition time to comply with new or revised accounting standards as applicable to public companies. Thus, an emerging growth company can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We have irrevocably opted out of this exemption from new or revised accounting standards and, therefore, will be subject to the same new or revised accounting standards as other public companies that are not emerging growth companies. As a result, our financial statements may not be comparable to other emerging growth companies that elect to take advantage of the extended transition period.

We will cease to be an “emerging growth company” upon the earliest to occur of: (i) the last day of the fiscal year in which we have more than $1.235 billion in annual revenue; (ii) the date we qualify as a large accelerated filer, with at least $700 million of equity securities held by non-affiliates; (iii) the date on which we have, in any three-year period, issued more than $1 billion in non-convertible debt securities; and (iv) December 31, 2026 (the last day of the fiscal year following the fifth anniversary of CENAQ becoming a public company).

We are also a “smaller reporting company” as defined in the Exchange Act and may continue to be a smaller reporting company even after we are no longer an emerging growth company. We may take advantage of certain of the scaled disclosures and reporting requirements available to smaller reporting companies until the fiscal year following the determination that our voting and non-voting common stock held by non-affiliates is $250 million or more measured on the last business day of our second fiscal quarter, or our annual revenues are $100 million or more during the most recently completed fiscal year and our voting and non-voting common stock held by non-affiliates is $700 million or more measured on the last business day of our second fiscal quarter.

Controlled Company Status

We are a “controlled company” within the meaning of the Nasdaq Stock Market LLC corporate governance standards. As a controlled company, we may elect not to comply with certain Nasdaq corporate governance standards. See “