Net Power Inc.

As a smaller reporting company, we are not required to provide the information called for by this Item. We are nonetheless providing the risk factors set forth below, which reflect risks associated with recent developments in our business and strategy. These risk factors supplement and, to the extent inconsistent, supersede the risk factors disclosed in Part I, Item 1A of our Annual Report, which you should also carefully consider. The risk factors below are not a complete statement of the risks we face.

We may be unable to negotiate and enter into binding energy services or power offtake agreements on acceptable terms, on our anticipated timeline, or at all, which would adversely affect our ability to reach a final investment decision and obtain project financing for our Initial Project.

We are negotiating an energy services agreement for our Initial Project with a prospective customer, a leading developer of frontier artificial intelligence models, and are pursuing power offtake arrangements for other projects. Discussions, indications of interest, requests for proposals, term sheets, memoranda of understanding, and similar instruments do not constitute binding commitments unless and until definitive agreements are executed. If we are unable to execute binding energy services or power offtake agreements at prices and on terms sufficient to support project economics and financing, our final investment decision, construction commencement, and commercial operation dates could be delayed or may not occur, and our liquidity and capital requirements would be adversely affected. We also expect that any energy services or power offtake agreement we enter into would require us to provide substantial reciprocal credit support, in the form of cash, letters of credit or guarantees, scaled to the capacity committed and maintained through development, construction and operations, which would further reduce the liquidity available to us for other purposes.

If we do not enter into an energy services agreement for our Initial Project, our recovery of the related equipment and engineering costs will be limited and conditional, and our reimbursement arrangement restricts our ability to pursue other customers for that equipment.

In August 2026, we entered into the Cost Reimbursement Agreement with a prospective customer as an interim arrangement while we negotiate an energy services agreement for our Initial Project. The customer is not obligated to enter into that agreement. If an energy services agreement is not executed by February 14, 2027, or if the customer terminates the arrangement earlier, it may elect to take assignment of the covered equipment and contracts and reimburse our costs for approved expense items, in which case that equipment would no longer be available for our projects. Alternatively, it could decline to do so, in which case the extent of our recovery will depend on the arrangement’s termination provisions. Reimbursement is subject to an aggregate cap of approximately $180.0 million, extends only to approved expense items, and excludes specified costs. The cap does not represent an unconditional payment obligation. Other than the milestone payment made at closing, costs under the EPC Agreement will be covered only if the customer approves that agreement following execution of a change order relocating the project, and the customer may decline to approve additional equipment or other costs. The customer’s payment obligations are suspended if we are in material breach of specified obligations. Until the arrangement expires, we may not solicit or negotiate with third parties for the sale of the covered equipment or for an energy services or power purchase agreement that uses it, and if we fail to fund covered items on schedule, the customer may step in, at our cost, to direct or make payments for them. If we do not enter into a definitive agreement with the customer, we would bear any costs the arrangement does not cover, and our liquidity, results of operations, and prospects could be materially and adversely affected.

Demand for the power we intend to sell is concentrated in a limited category of large-load customers whose electricity requirements depend on capital investment cycles that may not continue at current levels.

Our offtake efforts are directed primarily at data center developers, computing infrastructure providers and other large-load customers whose electricity requirements reflect sustained capital investment in computing capacity. That investment is concentrated among a limited number of counterparties and is discretionary. A reduction, deferral, or geographic reallocation of capital spending by these counterparties (whether resulting from changes in expected returns on computing investment, financing conditions, technological developments that reduce power intensity per unit of computing output, siting, permitting, or community opposition constraints, regulatory or governmental restrictions on the development or interconnection of data centers, including in ERCOT, or general economic conditions) could reduce the number of potential offtakers, extend negotiation timelines, or reduce the pricing, contract tenor, or capacity commitments available to us. Because we expect to rely on long-term offtake agreements to support project-level financing, the concentration, contract tenor, and creditworthiness of our counterparties will also affect our ability to obtain financing on acceptable terms. We may be unable to identify alternative customers for capacity developed in reliance on this demand. Our Initial Project is being developed to serve a single prospective customer on a data center campus being developed by a third party, and its development depends on the commitments of both. Developments affecting that customer, including changes in its plans for computing capacity, its other infrastructure commitments, its financing and legal or governmental actions directed at it, could cause it to delay or decline the commitments the Initial Project requires, and could make lenders, suppliers or contractors less willing to support a project that serves it. We expect lenders to evaluate the Initial Project largely by reference to that customer’s creditworthiness. If they require more credit support than the customer agrees to provide, or price the project debt at levels the project cannot support, we may be unable to finance the Initial Project on acceptable terms or at all.

Our business strategy has changed substantially, and we expect to develop our projects, at least initially, without carbon capture.

We have repositioned our business to focus on natural gas power generation for co-located large-load customers, initially without carbon capture, and we have indefinitely suspended development of the Oxy-Combustion Cycle. We do not currently expect our Initial Project to include carbon capture, and we are not designing it to accommodate the later addition of carbon capture. Any deployment of carbon capture at later projects or phases would depend on definitive technology, customer and financing arrangements. This repositioning reflects, among other things, current market conditions in which many prospective customers prioritize the speed and quantity of reliable power over carbon abatement and may be unwilling to pay a premium for lower-carbon power in the near term. The configuration, capacity and carbon capture scope of each of our projects will depend on customer requirements, commercial arrangements, site rights, permits, equipment availability and financing, and may include natural gas generation deployed in advance of, or without, carbon capture.

We may be unable to realize any value from our Oxy-Combustion Cycle intellectual property and the La Porte Demonstration Facility, which have been fully impaired.

During the second quarter of 2026, we recognized a full impairment of the Developed Technology Asset Group, and those assets are carried at no value. We have no current plans to resume development of the Oxy-Combustion Cycle, and any recovery of value would depend on a sale, license, or other disposition of all or part of the Oxy-Combustion Cycle intellectual property and our improvements, equipment, and lease interests at the La Porte Demonstration Facility, or on a royalty under our license agreement with affiliates of Baker Hughes. The value that a counterparty would ascribe to the intellectual property may be limited because our license from 8 Rivers is exclusive only in the field of carbonaceous gas fuels other than those derived from certain solid fuel sources, and because several of the licensed patents expire beginning in 2030. In September 2026, we entered into agreements with affiliates of Baker Hughes that indefinitely suspend our joint development and commercial agreements with them and amend our license agreement with them. Under those agreements, Baker Hughes’ rights of access to, and exclusivity over, the La Porte Demonstration Facility ended, but Baker Hughes retains its exclusive license to manufacture and sell utility-scale equipment packages for the Oxy-Combustion Cycle. Further, the provision under which that exclusivity could be lost is suspended and would not revive automatically if the joint development agreement is reinstated. Baker Hughes also holds a royalty-free license, exclusive subject to rights we retained, to manufacture and sell industrial-scale products incorporating the technology, and a license to install and operate industrial plants incorporating those products, for which the royalty has not been agreed and, absent agreement, would be determined by an independent expert. Baker Hughes is not obligated to deploy any plant, and we may never receive a royalty. These licenses, and our obligation to use commercially reasonable efforts to disclose technical information to Baker Hughes at no charge, may reduce the value of the intellectual property to other counterparties and limit the transactions available to us. We have not entered into any binding agreement for a disposition, and there can be no assurance that any transaction will be agreed or consummated, or as to its terms or timing. In addition, we are evaluating alternatives for the La Porte Demonstration Facility, including a sale of all or part of the facility or its equipment and an early termination of the land lease. Depending on the outcome, the timing and cost of decommissioning the facility, which we currently expect to occur by June 2027, and the treatment of those obligations in any sale or other disposition may differ from our current estimates.

Our pursuit of co-located large-load projects exposes us to execution risks that are new to us and to governmental intervention in Texas, any of which may delay, restrict, or prevent our projects.

We are pursuing the development of power generation projects for co-located large-load facilities such as data centers. Activities of this type are new to us and expose us to risks we have not previously borne, including land acquisition and site-control risk, construction and counterparty risk, contractual performance risk, regulatory risk, and additional capital requirements at a time when we do not have sufficient committed capital to fund our Initial Project through commercial operation. If a co-located facility requires grid-supplied power, whether as a supplement or as backup, our customer or we would be subject to large-load interconnection processes and to competition for available capacity, either of which could delay the project. We may also face competition for sites, interconnection positions and end users from parties with substantially greater resources and relevant experience. We have not obtained the land or development rights that our Initial Project and the broader contemplated build-out at Project Permian would require, and we may change the site, configuration or sequencing of our projects in response to customer, land, permitting and other developments, as we have done for our Initial Project. Our Initial Project depends on site rights that we would obtain from a third-party data center developer and on that developer’s progress in developing its campus. If we do not obtain the necessary rights on acceptable terms, our projects may be limited in size, delayed, reconfigured, or not developed. To preserve our schedule, we have committed, and expect to continue to commit, material capital to power generation equipment and related engineering before binding offtake, land, partner, and project-financing arrangements are in place, including through our acquisition in August 2026 of the owner’s position under the EPC Agreement. If a project does not proceed, a portion of those expenditures may not be recoverable, and we may incur cancellation or other costs. If these activities are unsuccessful, we could incur costs without corresponding benefit, and our results of operations, liquidity, and project timelines could be materially and adversely affected.

An islanded project must meet the customer’s power-quality and reliability requirements without routine support from the ERCOT grid. Doing so may require additional generating capacity, redundancy, fuel-supply arrangements, controls, maintenance coverage and other infrastructure beyond the generating units currently under contract. Equipment outages, fuel interruptions or failure to meet contractual availability and performance requirements could interrupt service, require additional capital expenditures and expose us to damages or other contractual remedies. We have not finalized the technical configuration or contractual allocation of these risks for our Initial Project.

These processes are also subject to intervention by Texas state officials. On August 3, 2026, the Governor of Texas directed the Public Utility Commission of Texas and ERCOT to conduct a comprehensive verification and audit of all data center projects advancing through ERCOT’s interconnection process before any additional data center projects are approved to move forward, and directed that any project failing to comply with applicable requirements be denied connection to the Texas grid. The directive requires the collection of information from each data center project regarding public financial assistance received or expected, projected electricity consumption and any on-site generation, projected water consumption and cooling technology, measures to mitigate impacts on neighboring communities, and project ownership and control. The Governor also indicated that he intended to work with the Texas legislature to address concerns regarding data centers. On September 14, 2026, the Governor directed the Texas Water Development Board to seek penalties against data centers that do not respond to the state’s annual water use survey. On September 21, 2026, the Governor directed the Texas Commission on Environmental Quality (“TCEQ”) to pause the issuance of all permits related to data center projects until ERCOT completes its review. The directive does not expressly exclude generation that serves a data center without a connection to the ERCOT grid. On October 19, 2026, TCEQ informed the Governor that it had paused the issuance of all permits related to the construction or development of infrastructure directly supporting data centers, that it was screening pending applications and had paused those subject to the directive, and that it was suspending, where possible, authorizations for data center activities claimed without an affirmatively issued permit. ERCOT has stated that it intends to publish its report on or before December 10, 2026, but no date has been set for the pause to end. On November 3, 2026, Texas voters elected a new Governor, who will take office in January 2027 and who called during the campaign for a moratorium on new data center approvals until the Texas legislature adopts statewide rules governing them and has reaffirmed that position since the election. Whether a moratorium or other restrictions will be adopted, and their scope and timing, are uncertain. The directive contemplates that TCEQ will use information from the audits to review proposed permits, so the completion of ERCOT’s review will not by itself determine when permits for data center projects will be issued.

Our projects require air permits, and we expect the pause to apply to those required for our Initial Project. On October 21, 2026, TCEQ announced that it had temporarily shut down its electronic permitting system, through which applications are ordinarily submitted, so that its staff could review applications to determine whether they relate to data centers. On November 9, 2026, TCEQ confirmed that electronic submissions were available for applications under its Construction, Multi-Sector and Concrete Production General Permits. Those applications require staff review to determine whether they relate to data centers and no longer receive automatic approval or provisional coverage. The restoration of electronic submissions does not lift the permitting pause for data center projects or establish when applications for our Initial Project will be processed or authorizations issued. If TCEQ does not accept an application submitted during the outage, we may be required to resubmit it, which could delay review. TCEQ has also begun suspending, where possible, authorizations for data center activities claimed without an affirmatively issued permit, and any authorization we obtain could be suspended. We cannot predict the scope, duration, or outcome of these processes, the requirements the Public Utility Commission of Texas, ERCOT, or TCEQ may adopt in response, the policies of the new administration, or any resulting legislation, including any moratorium on new data centers or the generation that serves them. These processes may delay or prevent the permitting of our projects or the interconnection or permitting of data centers and other large loads that we expect to serve, extend the timelines on which prospective customers are prepared to commit to energy services or power offtake, alter the criteria on which customers select sites, or reduce the number of prospective customers able to proceed in Texas. Our prospective customer for the Initial Project has indicated that it may defer its commitment, or pursue sites outside Texas, if permits are not obtained on its timeline or it expects further restrictions in Texas, and that it expects to decide before the end of 2026 whether to proceed with its plans in Texas. Any of these outcomes could delay or prevent our reaching a final investment decision for our Initial Project, delay or prevent project-level financing, and adversely affect our business, financial condition, results of operations, and prospects.

Grid interconnection and related regulatory processes, including ERCOT’s batch framework for interconnecting large loads, may delay or restrict our projects.

Our Initial Project is being designed to serve co-located load without a connection to the ERCOT grid, and we are no longer pursuing the generation interconnection request we previously submitted for Project Permian. Our projects and our customers’ facilities may nonetheless depend on the large-load interconnection processes applicable to co-located loads, including for supplemental or backup grid-supplied power, whether those loads are developed, owned, or contracted for by our customers, our partners, or us, and future projects or phases, including at Project Permian, may require interconnection to the ERCOT grid. These processes are new, evolving and subject to eligibility criteria, timelines, financial-security requirements and allocation decisions outside of our control. Delays or adverse outcomes could delay project development, increase project costs, reduce the attractiveness of our projects to customers and adversely affect our results.

Texas’s large-load interconnection rule became effective on October 8, 2026. Covered interconnections require additional disclosures, agreements, financial security, and payments for interconnection facilities. Intermediate-stage financial security generally starts at $50,000 per MW, with additional security potentially required. These requirements could increase the capital needed by customers seeking grid service and delay their commitments to our projects. Applicability depends on the particular load and interconnection configuration; the proposed islanded configuration of our Initial Project does not establish that every future project or customer configuration would fall outside these requirements.

We depend on the availability, cost, and delivery timing of power generation equipment and related long-lead equipment.

Manufacturer backlogs for power generation equipment, including gas turbines and reciprocating engines, and related equipment currently extend multiple years. We have contracted for certain gas turbine equipment and, through our acquisition in August 2026 of the owner’s position under the EPC Agreement, for reciprocating engine generating units and related equipment. The configuration we are evaluating for our Initial Project would require additional generating capacity that we have not secured, and we may be unable to secure it on acceptable terms or timelines, or at all. Changes in delivery schedules, cost escalation, supplier or contractor performance, or the loss of reserved manufacturing slots could delay our projects and increase their cost, and replacement equipment may not be available on acceptable terms or timelines, or at all. Prevailing market prices for equipment comparable to the units for which we have contracted have increased materially since we contracted for them, and any additional equipment we procure is likely to cost more than the equipment we hold.

We do not have a binding agreement for post-combustion carbon capture technology, and we may not deploy carbon capture at our projects.

Our prior letter of intent with Entropy expired by its terms and has not been replaced, and we have not entered into definitive agreements with Entropy or any other provider of post-combustion carbon capture technology. Any definitive arrangement may require capital commitments, licensing fees, or other payments in amounts and on schedules that have not been determined. If we elect to deploy carbon capture at later phases or projects and are unable to enter into definitive agreements on commercially acceptable terms, we would need to identify and qualify an alternative technology provider, which would require additional time and expense, may not be available on terms or timelines supporting our project schedules, and could prevent or delay carbon capture at those phases or projects.

The economics of any carbon capture we deploy would depend in part on carbon capture tax credits, which are subject to availability, transferability, monetization and other restrictions.

The economics of projects incorporating carbon capture depend in part on federal tax credits, including the credit under Section 45Q of the Internal Revenue Code, the value, transferability and monetization of which are subject to statutory and regulatory requirements, including restrictions relating to foreign entities of concern. The credit value available with respect to any project will depend on, among other things, whether construction begins before January 1, 2033, when the applicable facility or equipment is placed in service, whether prevailing wage and apprenticeship requirements are satisfied, and the manner in which captured CO₂ is stored, used, or otherwise disposed of. In addition, legislation enacted in 2025 that increased certain credit values, including for CO₂ used in enhanced oil recovery, may be amended or repealed. If such credits are unavailable, reduced, restricted, or cannot be efficiently monetized, our project economics and offtake pricing could be adversely affected.

Customers may not attribute value to carbon capture, and regulatory developments may reduce requirements that would otherwise support demand for lower-carbon generation.

Our long-term strategy contemplates that some customers may eventually value, and pay for, power generated with carbon capture. Our near-term strategy does not assume that customers will pay a premium for lower-carbon power, and our Initial Project is not currently expected to include carbon capture. Recent development activity in our target markets has emphasized speed to power, available capacity, and price, and certain large purchasers of electricity have modified or extended timelines associated with previously announced emissions commitments. In September 2026, the EPA finalized a partial repeal of the 2024 greenhouse gas standards for fossil fuel-fired electric generating units, including the carbon-capture-based Phase 2 standards for new baseload stationary combustion turbines. The final rule is scheduled to become effective on November 16, 2026. The EPA has separately proposed broader rescission of remaining greenhouse gas requirements for these generating units. These actions could reduce regulatory incentives for customers to select generation incorporating carbon capture. If applicable emissions requirements are reduced or eliminated and customers do not independently attribute value to carbon capture, pricing available for lower-carbon power may not exceed pricing for conventional generation by an amount sufficient to recover the incremental capital and operating costs of carbon capture. In that event, we may deploy generation without carbon capture, defer carbon capture investment, or realize returns below those we currently anticipate.

We compete for customers, equipment and capital with substantially larger and better-capitalized participants, including participants pursuing gas generation with carbon capture.

Following the repositioning of our business, we compete directly with integrated energy companies, independent power producers, equipment manufacturers and developers pursuing natural gas generation for large-load customers, including projects incorporating carbon capture. Many of these market participants have greater financial resources, lower costs of capital, established customer relationships, existing carbon dioxide transportation and sequestration infrastructure, priority access to constrained equipment manufacturing capacity, and the ability to commit capital in advance of securing offtake. We may be unable to compete successfully on schedule, price, or credit terms.

We will need substantial additional capital to develop our projects, which may not be available on acceptable terms or at all, and our share price, public float, and changed asset base may limit our access to capital and result in substantial dilution.

Following the impairment of the Developed Technology Asset Group and our acquisition in August 2026 of the owner’s position under the EPC Agreement, our assets consist primarily of cash, cash equivalents and investments, and equipment deposits and other capitalized costs for our projects. We have no revenue and no binding energy services or power offtake agreement; we have not made a final investment decision for our Initial Project, and we do not have sufficient committed capital to fund the project through commercial operation. The capital required to bring the Initial Project to commercial operation substantially exceeds our cash and investments. In addition to the remaining payments under the EPC Agreement and our other equipment commitments, the Initial Project will require additional generating capacity, balance-of-plant, electrical and fuel-supply equipment and infrastructure, credit support under any energy services agreement, and project-level debt and equity, none of which has been committed. Costs that our prospective customer has not approved in advance are not covered by the Cost Reimbursement Agreement. Those costs currently include engineering and other work for the Initial Project, including work under the limited notice to proceed we are negotiating with Saulsbury, and we have incurred, and may continue to incur, such costs to maintain the project schedule. If we cannot obtain the capital we need on acceptable terms and on a timeline that meets our prospective customer’s requirements, we may have to delay, reduce the scope of, or abandon the Initial Project, and we may be unable to recover the amounts we have spent on it. Our Board of Directors may also consider strategic alternatives, which could include partnerships, project-level or corporate transactions, a sale of assets or a reduction or discontinuation of some or all of our development activities, and there can be no assurance that any alternative would be available on acceptable terms or at all or would preserve value for our stockholders.

Our ability to raise equity capital depends on the market price of our Class A Common Stock and on the aggregate market value of our common equity held by non-affiliates. If we rely on General Instruction I.B.6 of Form S-3 for primary offerings while our public float is below $75 million, the aggregate value of securities sold under that instruction during the applicable rolling 12-month period generally may not exceed one-third of our public float, calculated under the instruction. Prior sales under that instruction reduce the capacity available for additional sales. A decline in the market price of our Class A Common Stock would further reduce the capital available to us through such offerings, increase the dilution to existing stockholders resulting from any equity issuance, and could make equity financing unavailable on acceptable terms or at all. In addition, the remaining consideration for work performed under the BHES JDA through December 31, 2025 is payable partly in shares of our Class B Common Stock and Class A OpCo Units, and share-settled payments made when the ten-day volume-weighted average price of our Class A Common Stock is below $4.00 per share require incremental cash payments, as described in Note 12 to our condensed consolidated financial statements.

The market price of our Class A Common Stock has been below $1.00, and our securities could be delisted from the New York Stock Exchange.

Our Class A Common Stock and warrants are listed on the New York Stock Exchange and are subject to applicable continued listing standards. The price standard applicable to our Class A Common Stock generally requires an average closing price of at least $1.00 over a consecutive 30-trading-day period. The closing price of our Class A Common Stock has been below $1.00 since October 22, 2026. If the NYSE notifies us that we do not meet that standard, we must, within ten business days after receiving the notice, notify the NYSE of our intent to cure the deficiency, and we would generally have six months to regain compliance. Regaining compliance may require a reverse stock split, which would require stockholder approval; in that case, we would need to obtain that approval no later than our next annual meeting and implement the split promptly afterward, and the split may not increase the market price of our Class A Common Stock proportionately or for a sustained period. If our Class A Common Stock again fails the price standard within one year after a reverse stock split, we would not be eligible for a cure period. The NYSE may also suspend trading and begin delisting proceedings without a cure period in certain circumstances, including if the trading price of our Class A Common Stock falls to an abnormally low level. Beginning July 1, 2027, the NYSE will immediately suspend trading in, and begin proceedings to delist, any listed security whose closing price is below $0.25 on any trading day, without a cure period. If we fail to satisfy applicable continued listing standards and do not cure the deficiency within the applicable period, our securities could be suspended from trading and delisted. Delisting would reduce the liquidity of our securities and further impair our access to capital, and could depress their market price, cause us to lose the ability to use Form S-3, and reduce analyst coverage of, and investor interest in, our securities.

We are subject to the risk of becoming an investment company.

We are an energy technology and project development company. We are not primarily engaged in the business of investing, reinvesting or trading in securities, and we do not hold ourselves out as being engaged in those activities; our historical development, our public representations and the activities of our officers and directors support the conclusion that we are an operating company. Under Section 3(a)(1)(C) of the Investment Company Act of 1940, as amended (the “ICA”), an issuer may be an investment company if it owns or proposes to acquire investment securities exceeding 40% of the value of its total assets, excluding Government securities and cash items, determined on an unconsolidated basis, unless an applicable exclusion or exemption is available. Pending its use in our primary business, we hold cash, including cash obtained in connection with our 2023 merger, in bank deposits, United States Treasury securities and government money market funds to conserve capital and liquidity. United States Treasury securities are excluded from the numerator and denominator of the statutory asset test. The treatment of any money market fund shares as cash items depends on the characteristics of the funds and the applicability of SEC staff positions. If those positions do not apply to our holdings, or if our asset composition changes, we could exceed the 40% threshold unless an exclusion or exemption is available. As a result of recently recognized impairment losses, these holdings constitute a larger portion of our total assets than previously, and to maintain compliance with the ICA, we monitor the composition of our assets and may need to make investments that are less advantageous than if we did not have ICA concerns, or forgo otherwise desirable investments or transactions.

Rule 3a-2 under the ICA provides a one-year grace period for a transient investment company that has a bona fide intent to be engaged primarily in a non-investment business, but the grace period is available no more than once every three years and may not be available when we seek to rely on it, and reliance on it could require us to dispose of securities or limit our investments, joint ventures, or other activities.

We intend to conduct our business so that we are not deemed an investment company, but there can be no assurance that we will succeed. If we were deemed an investment company, we would be required to register under the ICA, obtain exemptive relief, or modify our business and organizational structure to fall outside the definition. Registration would subject us to substantial regulation concerning management, operations, transactions with affiliates and portfolio composition, which would significantly affect our ability to operate as contemplated and could have a material adverse effect on our business, financial condition and results of operations. If we failed to register when required, we could be subject to monetary penalties or injunctive relief in an action brought by the SEC, and we could be unable to enforce contracts with third parties.

We are subject to a pending securities class action, and may become subject to additional litigation or regulatory proceedings, any of which could result in substantial costs and divert management’s attention.

We are a defendant in a putative federal securities class action arising from alleged misstatements concerning the timing and costs of developing our first planned utility-scale power plant incorporating the Oxy-Combustion Cycle, which we then referred to as Project Permian. This matter is described in Part II, Item 1, “Legal Proceedings,” and in Note 14 to our condensed consolidated financial statements. We intend to defend this matter vigorously, but we cannot predict the outcome, and we are unable to estimate a reasonably possible loss or range of loss. We are also a nominal defendant in two stockholder derivative actions, described in the same places, that assert claims on our behalf against certain of our current and former directors and officers based on the same alleged misstatements.

Litigation of this type is expensive, may continue for years, and diverts the attention of management and other personnel from our business, regardless of outcome. An unfavorable ruling or a settlement could require us to pay substantial amounts, and our insurance may be insufficient, subject to significant retentions, or unavailable for some or all of these matters. We also have indemnification and expense-advancement obligations to our current and former officers and directors. The underlying events, these actions, or our disclosures regarding them could give rise to additional litigation or to inquiries or investigations by regulatory authorities.

Cybersecurity incidents could disrupt our operations, compromise our information or expose us to costs and liability.

The third parties on which we rely have been, and will continue to be, targets of cyberattacks. In 2026, unauthorized parties obtained data from a third-party software platform that we used. We have not determined that incident to be material. This or future incidents could result in operational disruption; the loss, theft or misuse of confidential, proprietary or personal information; remediation and other costs; litigation; regulatory inquiries; or reputational harm, any of which could adversely affect our business, financial condition, results of operations and prospects.

Additional risks and uncertainties not presently known to us, or that we currently deem immaterial, may also materially and adversely affect our business, financial condition, results of operations, and prospects.