First production and growing biomethane portfolio at AleAnna (Nasdaq: ANNA)
Rhea-AI Filing Summary
AleAnna, Inc. reports its first full year as a public company with initial production from the Longanesi gas field and a growing renewable natural gas platform in Italy. The company generated $22.4 million of natural gas revenue and $2.7 million of electricity revenue in 2025.
Total proved natural gas reserves reached 25,827 (106 ft3) at year-end 2025, with 23,461 (106 ft3) classified as proved developed after Longanesi start-up. PV-10 increased to $120.5 million, supported by an average realized price of $12.84 per 103 ft3.
AleAnna completed a SPAC business combination in December 2024 and invested about $250 million over 15 years to build its Italian asset base. It also acquired three Italian renewable gas plants for about €9.0 million and plans to fund further growth mainly from Longanesi, Gradizza and Trava cash flows plus additional financing.
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Insights
First gas production and higher reserves mark a key transition, but the profile remains early-stage and capital intensive.
AleAnna has shifted from pure development to production, with Longanesi onstream and 2025 natural gas revenue of $22.4 million. Total proved reserves rose to 25,827 (106 ft3), driving PV-10 up to $120.5 million, helped by a natural gas price of $12.84/103 ft3.
The business remains concentrated in a few Italian fields and subject to complex permitting, environmental and royalty regimes, including 10% onshore gas royalties. The renewable natural gas strategy adds diversification but requires acquisitions and upgrades under evolving biomethane incentive schemes.
The SPAC reverse recapitalization and the $9.5 million of transaction costs highlight ongoing financing needs. Future performance will depend on executing additional Longanesi phases, bringing Gradizza and Trava to production, and scaling biomethane projects within Italy’s incentive framework.
Key Figures
Key Terms
PV-10 financial
proved undeveloped reserves financial
Environmental Impact Assessment regulatory
Gas Sales Agreement financial
PiTESAI regulatory
Guarantees of Origin financial
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
FOR THE FISCAL YEAR ENDED
or
FOR THE TRANSITION PERIOD FROM ___________ TO __________
COMMISSION FILE NUMBER:
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Securities registered pursuant to Section 12(b) of the Act:
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Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
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| ☒ | Smaller reporting company | |||
| Emerging growth company |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No
The aggregate market value of common stock held by non-affiliates of the registrant as of June 30, 2025 (the last business date of the registrant’s most recently completed second fiscal quarter), based on the $7.20 closing price as of such date, was approximately $
As of March 30, 2026, there were
Table of Contents
| Glossary of Commonly Used Terms, Abbreviations and Measurements | ii | |
| Cautionary Note Regarding Forward-Looking Statements | v | |
| Summary of Risk Factors | vii | |
| PART I | ||
| Item 1. Business | 1 | |
| Item 1A. Risk Factors | 24 | |
| Item 1B. Unresolved Staff Comments | 50 | |
| Item 1C. Cybersecurity | 50 | |
| Item 2. Properties | 52 | |
| Item 3. Legal Proceedings | 52 | |
| Item 4. Mine Safety Disclosures | 52 | |
| PART II | ||
| Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | 53 | |
| Item 6. [Reserved] | 53 | |
| Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations | 54 | |
| Item 7A. Quantitative and Qualitative Disclosures About Market Risk | 68 | |
| Item 8. Financial Statements and Supplementary Data | F-1 | |
| Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | 69 | |
| Item 9A. Controls and Procedures | 69 | |
| Item 9B. Other Information | 71 | |
| Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections | 71 | |
| PART III | ||
| Item 10. Directors, Executive Officers and Corporate Governance | 72 | |
| Item 11. Executive Compensation | 72 | |
| Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 72 | |
| Item 13. Certain Relationships and Related Transactions, and Director Independence | 72 | |
| Item 14. Principal Accountant Fees and Services | 72 | |
| PART IV | ||
| Item 15. Exhibits and Financial Statement Schedules | 73 | |
| Item 16. Form 10-K Summary | 74 |
i
Glossary Of Selected Industry Terms
“AleAnna Energy” - AleAnna Energy, LLC, a Delaware limited liability company.
“Bcf” - billion cubic feet.
“Bcfe” - billion cubic feet of natural gas equivalents, with one barrel of NGLs and oil being equivalent to 6,000 cubic feet of natural gas.
“Blugas” - Blugas Infrastructure S.r.l.
“Blugas Settlement Agreement” - agreement with Blugas Infrastructure S.r.l. (“Blugas”) regarding the Blugas overriding royalty interest (“ORRI”) whereby Blugas was entitled to physical delivery of 20% of the first 350 million standard cubic meters (approximately 2,472 106ft3) produced from the Longanesi field.
“Carbon Negative Renewable Natural Gas” - Renewable natural gas (“RNG”) is considered carbon negative if it captures more greenhouse gases than it emits. RNG produced from organic waste that would otherwise decay and create methane emissions are considered carbon negative as the methane emissions from the decay is captured and converted to a usable fuel source (RNG) which then displaces traditional fossil based natural gas (methane). The avoided emissions from natural decay and the substitution of fossil based natural gas results in a negative carbon life cycle score. In the U.S., the California Air Resources Board has given dairy and agricultural based carbon negative RNG projects a carbon intensity Score (gCO2e/MJ) of -250 (or lower). Such projects are similar to those pursued by AleAnna’s Renewable Natural Gas business.
“Company” - AleAnna, Inc. together with its subsidiaries, is collectively referred to herein as the “Company” or “AleAnna”), AleAnna Inc. is comprised of wholly owned subsidiaries, AleAnna Energy, LLC, AleAnna Resources, LLC, AleAnna Italia S.p.A. (“AleAnna Italia”) and AleAnna Renewable Energy S.r.L. (“AleAnna Renewable”). AleAnna Renewable is comprised of various subsidiaries that hold its renewable natural gas assets (the “RNG Subsidiaries”). “DeGolyer” - DeGolyer & MacNaughton
“Development” - drilling and other post-exploration activities aimed at the production of oil and gas.
“Development well” - a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
“ESG” - environmental, social and governance.
“Exploration” - oil and natural gas exploration that includes land surveys, geological and geophysical studies, seismic data gathering and analysis and well drilling.
“Exploratory well” - a well drilled to find a new field or new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well.
“Extension well” - a well drilled to extend the limits of a known reservoir.
“Gas” - all references to “gas” in this Form 10-K refer to natural gas.
“Gcal” - Gigacalories
“Greenhouse gases (GHG)” - gases in the atmosphere, transparent to solar radiation, that trap infrared radiation emitted by the earth’s surface. The greenhouse gases relevant within the Company’s activities are carbon dioxide (CO2), methane (CH4) and nitrous oxide (N2O). GHG emissions are commonly reported in CO2 equivalent (CO2eq) according to Global Warming Potential values in line with IPCC AR4, 4th Assessment Report.
“Gross” - “gross” natural gas and oil wells or “gross” acres equal the total number of wells or acres in which we have a working interest.
“G&A” - general and administrative.
“Hedging” - the use of derivative commodity and interest rate instruments to reduce financial exposure to commodity price and interest rate volatility.
“HoldCo” - Swiftmerge HoldCo LLC, a Delaware limited liability company and wholly-owned subsidiary of AleAnna, Inc.
ii
“Hydrocarbons” - means oil, gas, condensate and other gaseous and liquid hydrocarbons or any combination thereof, and all minerals, products and substances extracted, separated, processed and produced therefrom or therewith.
“LNG” - Liquefied Natural Gas obtained through the cooling of natural gas to minus 160 °C at normal pressure. The gas is liquefied to allow transportation from the place of extraction to the sites at which it is transformed back into its natural gaseous state and consumed. One tonne of LNG corresponds to approximately 1,400 cubic meters of gas.
“Mcf” - thousand cubic feet.
“Merger Agreement” – Agreement and Plan of Merger, as amended, dated June 4, 2024, by and among Swiftmerge, HoldCo, Swiftmerge Merger Sub LLC, a Delaware limited liability company and wholly-owned subsidiary of HoldCo, and AleAnna Energy.
“MMcf” - million cubic feet.
“MMsmc” - million standard cubic meters.
“mmscfd” - million standard cubic feet per day.
“mscfd” - thousand standard cubic feet per day.
“Natural gas liquids (NGL)” - liquid or liquefied hydrocarbons recovered from natural gas through separation equipment or natural gas treatment plants. Propane, normal-butane and isobutane, isopentane and pentane plus, that were previously defined as natural gasoline, are natural gas liquids.
“Net” - “net” natural gas and oil wells or “net” acres equals the sum of our fractional ownership working interests we have in gross wells or acres.
“Net acres or Net wells” - the sum of the fractional working interest owned in gross acres or gross wells expressed in whole numbers and fractions of whole numbers.
“Oil and Gas Contract” - means any Hydrocarbon production sharing contract, lease or license or other similar agreement or right binding on AleAnna or any of the AleAnna Subsidiaries to explore for, develop, use, produce, sever, process and operate any Hydrocarbons, whether onshore or offshore, and associated fixtures or structures for a specified period of time, including any material farm-out or farm-in agreement, operating agreement, unit agreement, pooling or communitization agreement, declaration or order, joint venture, option or acquisition agreement, any material Hydrocarbons production, sales, marketing, gathering, treating, transportation, exchange and processing contract and agreement, or any other contract held for exploration or production of any Hydrocarbons, or the disposition of any Hydrocarbons produced therefrom, in each case to which AleAnna or any of the AleAnna Subsidiaries is a party.
“Padana” - Società Padana Energia S.r.l.
“Possible reserves” - possible reserves are those additional reserves that are less certain to be recovered than probable reserves.
“Probable reserves” - probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
“Productive well” - a well that is producing oil or gas or that is capable of production.
“Proved developed reserves” - proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
iii
“Proved reserves” - proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations, prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Reserves are classified as either developed and undeveloped. Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well, and through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Proved undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
“Proved undeveloped reserves (PUDs)” - means proved reserves that are expected to be recovered from undrilled well locations on existing acreage or from existing wells where a relatively major expenditure is required for recompletion within the five year development window, according to the SEC or Society of Petroleum Engineers definition of PUD
“ORRI” - Blugas overriding royalty interest
“Reserves” - reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
“Reservoir” - a porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
“Service well” - well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include, among other things, gas injection, water injection and salt-water disposal.
“Swiftmerge” or “SPAC” - Swiftmerge Acquisition Corp., a Cayman Islands exempted company.
“Undeveloped acreage” - means acreage under lease on which wells have not been drilled or completed such that there is not production of commercial quantities of hydrocarbons;
“Unproved reserves” - reserves that are based on geoscience and/or engineering data similar to that used in estimates of proved reserves, but technical or other uncertainties preclude such reserves being classified as proved reserves. Unproved reserves may be further categorized as probable reserves and possible reserves.
“Working interest” - An interest that gives the owner the right to drill, produce and conduct operating activities on a property and receive a share of any production.
“/d” - Per day.
“/y” - Per year.
iv
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K (“Form 10-K”) contains forward-looking statements that involve substantial risks and uncertainties within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. All statements other than statements of historical facts contained in this Form 10-K, including statements regarding the Company’s future financial position, business strategy and plans and objectives of management for future operations, are forward-looking statements. In some cases, you can identify forward-looking statements by terminology such as “may,” “will,” “should,” “expects,” “plans,” “anticipates,” “could,” “intends,” “targets,” “projects,” “contemplates,” “believes,” “estimates,” “predicts,” “potential” or “continue” or the negative of these terms or other similar expressions. Forward-looking statements include, without limitation, the Company’s expectations concerning the outlook for its business, market size, exploration and development plans, regulatory matters, competition and competitive position, operational performance, developments in the capital markets and expected future financial performance, as well as any information concerning possible or assumed future results of operations of the Company as set forth in the sections of this Form 10-K titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and “Business.”
Forward-looking statements involve a number of risks, uncertainties and assumptions, and actual results or events may differ materially from those projected or implied in those statements. Important factors that could cause such differences include, but are not limited to:
| ● | the Company’s financial condition and results of operations; |
| ● | the development of our estimated proved undeveloped reserves; |
| ● | the Company’s reserves estimates; |
| ● | the timing of acquisition, financing, construction and development of new projects; |
| ● | the Company’s ability to raise financing in the future; |
| ● | changes in public acceptance and support of renewable energy development and projects; |
| ● | the Company’s ability to obtain necessary regulatory and governmental permits and approvals; |
| ● | the effects of competition; |
| ● | the Company’s ability to identify, acquire, develop and operate renewable natural gas facilities; |
| ● | governmental incentives for renewable energy generation; |
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| ● | the demand for renewable energy not being sustained; |
| ● | political, economic and other uncertainties, including those related to the European Union’s (“EU”) clean energy transition; |
| ● | changes in environmental laws and regulations; |
| ● | disruptions in the supply chain, fluctuation in price of product inputs, and market conditions and global and economic factors beyond the Company’s control; |
| ● | the Company’s success in retaining or recruiting, or changes required in, its officers, key employees or directors; |
| ● | the effect of legal, tax and regulatory changes; |
| ● | we may be subject to liabilities and losses that may not be covered by insurance; and, |
| ● | the other matters described in the section titled “Risk Factors” beginning on page 24. |
The forward-looking statements included in this Form 10-K involve risks and uncertainties that could cause actual results to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements as a prediction of actual results. We have based these forward-looking statements on current expectations and assumptions about future events, taking into account all information currently known by us. While we consider these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties, many of which are difficult to predict and beyond our control. The risks and uncertainties that may affect the operations, performance and results of our business and forward-looking statements include, but are not limited to, those set forth in Item 1A., “Risk Factors” in this Form 10-K, and other documents we file from time to time with the SEC.
Any forward-looking statement speaks only as of the date on which such statement is made, and, except as required by law, we do not intend to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise.
Reserve engineering is a process of estimating underground accumulations of natural gas, NGLs and oil that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and our development program. Accordingly, reserve estimates may differ significantly from the quantities of natural gas, NGLs and oil that are ultimately recovered.
In reviewing any agreements incorporated by reference in or filed with this Form 10-K, remember such agreements are included to provide information regarding the terms of such agreements and are not intended to provide any other factual or disclosure information about us. The agreements may contain representations and warranties by us, which should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties to such agreements should those statements prove to be inaccurate. The representations and warranties were intended to be relied upon solely by the applicable party to such agreement and were made only as of the date of the relevant agreement or such other date or dates as may be specified in such agreement and are subject to more recent developments. Accordingly, such representations and warranties alone may not describe our actual state of affairs or the affairs of our affiliates as of the date they were made or at any other time and should not be relied upon as statements of fact.
vi
SUMMARY RISK FACTORS
Summary Risk Factors
The following is a summary of the principal risks that may materially adversely affect our business, financial condition, results of operations and cash flows. The following should be read in conjunction with the more complete discussion of the risk factors we face, which are set forth in the section entitled “Item 1A: Risk Factors” in this report.
Risks Related to our Conventional Natural Gas Business and the Conventional Natural Gas Industry
| ● | We currently have few producing properties and there is no assurance that we will be able to convert our exploration drilling to producing wells. If our assets are not commercially productive of natural gas, any funds spent on exploration and production may be lost. |
| ● | The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. |
| ● | While we have drilled and tested certain exploration wells, we have no history of converting the exploration wells to producing natural gas wells and there can be no assurance that we will successfully establish natural gas operations or profitably produce natural gas. |
| ● | Restrictions on drilling activities intended to protect the environment and the ecosystem may adversely affect our ability to conduct drilling activities areas where we operate. |
| ● | Drilling for and producing natural gas is a high-risk and costly activity with many uncertainties, including the risk that drilling will not result in commercially viable natural gas production or that we will not recover all or any portion of our investment in drilled wells. |
| ● | Our drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of when they are drilled, if at all. |
| ● | The amount and timing of actual future natural gas production is difficult to predict and may vary significantly from our estimates, which may reduce our earnings. |
| ● | Unless we replace our reserves, our reserves and production will naturally decline, which would adversely affect our business, financial condition and results of operations. |
| ● | Our proved reserves are estimates that are based on many assumptions that may prove to be inaccurate. Any significant change in these underlying assumptions will greatly affect the quantities and present value of our reserves. |
| ● | Our limited history, limited revenue and limited liquidity makes it difficult to evaluate our business and prospects and may increase the risks associated with your investment. |
| ● | Significant capital investment is required to develop and conduct our operations and we intend to raise additional funds through debt financing for our planned operations and these funds may not be available when needed. |
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Risks Related to our Renewable Natural Gas Business and the Renewable Natural Gas Industry
| ● | Failure to protect our intellectual property, inability to enforce our intellectual property rights or loss of our intellectual property rights through costly litigation or administrative proceedings, could adversely affect our ability to compete and our business. |
| ● | Our strategic success and financial results depend on our ability to identify, acquire, develop and operate renewable natural gas facilities. |
| ● | Revenue from any plants we complete may be adversely affected if there is a decline in public acceptance or support of renewable energy, or regulatory agencies, local communities, or other third parties delay, prevent, or increase the cost of constructing and operating our facilities. |
| ● | A policy revision with respect to the Italian government sponsored renewable natural gas floor price and renewable natural gas capital expenditure reimbursements could have a material adverse effect on our long-term business prospects, financial condition and results of operations. |
| ● | The financial performance of our business depends upon tax and other governmental incentives for renewable energy generation, any of which could change at any time and such changes may negatively impact our growth strategy. |
| ● | Our commercial success depends on our ability to develop and operate production facilities for the commercial production of renewable natural gas. |
| ● | We may be subject to liabilities and losses that may not be covered by insurance. |
| ● | Significant capital investment is required to develop and conduct our operations and we intend to raise additional funds through debt financing for our planned operations and these funds may not be available when needed. |
| ● | We have entered into relatively new markets for renewables, including renewable natural gas, and these new markets are highly volatile and have significant risk associated with current market conditions. |
| ● | Fluctuations in the price of product inputs, including renewable feedstocks, natural gas and other feedstocks, may affect our cost structure. |
| ● | Our proposed growth projects may not be completed or, if completed, may not perform as expected and our project development activities may consume a significant portion of our management’s focus, and if not successful, reduce our profitability. |
| ● | We may not be able to develop, maintain and grow strategic relationships, identify new strategic relationship opportunities, or form strategic relationships, in the future. |
| ● | Failure of third parties to manufacture quality products or provide reliable services in accordance with schedules, prices, quality and volumes that are acceptable to us could cause delays in developing and operating our commercial production facilities, which could damage our reputation, adversely affect our partner relationships or adversely affect our growth. |
| ● | Our facilities and processes may fail to produce renewable natural gas at the volumes, rates and costs we expect. |
| ● | Our actual costs may be greater than expected in developing our commercial production facilities or growth projects, causing us to realize significantly lower profits or greater losses. |
| ● | Disruption in the supply chain, including increases in costs, shortage of materials or other disruption of supply, or in the workforce could materially adversely affect our business. |
viii
Risks Related to Foreign Operations and Regulatory Matters
| ● | Our primary operations are in a foreign country, and we are subject to political, economic and other uncertainties. |
| ● | All of our natural gas properties are located in the country of Italy, making us vulnerable to risks associated with operating in one geographic area. |
| ● | We may expand our operations globally, which would subject us to anti-corruption, anti-bribery, anti-money laundering, trade compliance, economic sanctions and similar laws, and non-compliance with such laws may subject us to criminal or civil liability and harm our business, financial condition and/or results of operations. |
| ● | Our results of operations, financial condition and cash flows could be adversely affected by changes in environmental laws and regulations. |
Risks Related to our Organizational Structure, Class A Common Stock and Public Warrants
| ● | AleAnna is a holding company and its organizational structure is commonly referred to as an umbrella partnership C corporation (or “Up-C”) structure, it is dependent upon distributions from HoldCo to pay taxes and cover its corporate and other overhead expenses. |
| ● | Our management team has limited recent experience in operating a public company. |
| ● | We are controlled by Nautilus Resources, LLC (“Nautilus”), whose interests may conflict with ours and the interests of other stockholders. |
| ● | If our estimates or judgments relating to our critical accounting policies prove to be incorrect or financial reporting standards or interpretations change, our operating results could be adversely affected. |
| ● | AleAnna, Inc. has identified material weaknesses in its internal control over financial reporting. If we are unable to develop and maintain an effective system of internal control over financial reporting, we may not be able to accurately report our financial results in a timely manner, which may adversely affect investor confidence in us and materially and adversely affect our business and operating results, and we may face litigation as a result. |
| ● | The market price of our Class A common stock, par value $0.0001 per share (“Class A Common Stock”) could be adversely affected by sales of substantial amounts of our Class A Common Stock in the public or private markets or the perception in the public markets that these sales may occur, including sales by the members of Nautilus after the redemption of any Class C HoldCo Units, together with an equal number of our Class C common stock, par value $0.0001 per share (“Class C Common Stock”), in exchange for shares of our Class A Common Stock, or other large holders. |
We describe these risks in greater detail under Item 1A., “Risk Factors.”
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PART 1
Item 1: Business
The following discussion reflects the business of AleAnna both prior to and after giving effect to the Business Combination, as the context indicates. Unless the context otherwise requires, all references in this section to “AleAnna,” the “Company,” “we,” “us,” and “our,” refer to AleAnna, Inc. and its consolidated subsidiaries.
Overview
AleAnna is a natural gas resource company focused on delivering critical natural gas supplies to Europe through both onshore conventional natural gas exploration and development and renewable natural gas development in Italy. We have several conventional natural gas discoveries including the Longanesi field, located in the Po Valley in Northern Italy, which is one of Italy’s largest modern natural gas discoveries. We have a 33.5% working interest in the Longanesi field with our working interest partner, and operator, Padana. We acquired our working interest in the Longanesi field in 2016. We also retain wholly-owned concessions, permits, and pending applications on other exploration and development prospects across Italy which are supported by proprietary modern 3D seismic reservoir imaging. In 2023, we launched a renewable natural gas development business focused on bringing to market carbon negative renewable natural gas derived from animal and agricultural waste. Between March 2024 and July 2024, we successfully completed three separate strategic acquisitions of renewable natural gas plant projects in Italy for an aggregate €9.0 million or approximately $9.8 million. The plants are fully permitted and are in various stages of the production lifecycle, with one greenfield plant that is a new development and two brownfield plants that are currently operational. We plan to develop and upgrade these sites for renewable natural gas production in the future.
Over the past 15 years, we have invested approximately $250 million in the acquisition and initial development of our properties, and we own a portfolio of conventional natural gas properties, including Longanesi, Gradizza, and Trava, containing approximately 25.8 (109ft3) net recoverable proved natural gas reserves according to our independent third-party reserve engineer, DeGolyer & MacNaughton (“DeGolyer”). Beyond our net recoverable natural gas reserves, we have 13 development prospects at various stages of permitting, supported by 3D seismic surveys, and leases on approximately 2.7 million net acres — paving the way for future exploration and development. Our recent activities involve the drilling and testing of three Longanesi development wells (2022 and 2023) as well as the completion of two original discovery wells. Tie-in of these wells is complete, and we are currently executing the installation of a temporary processing facility. We and Padana achieved first production of the five wells in the Longanesi field in March 2025 through use of a temporary processing facility. The permanent processing facility is under construction and is expected to be installed in phases during 2026, with completion and commissioning expected in early 2027. On October 29, 2024, we entered into a gas sale agreement (“GSA”) with Shell Energy Europe Limited (“SEEL”), whereby SEEL became the exclusive buyer of our share of the natural gas produced from the Longanesi field net of (i) any consumption and/or losses incurred in the transport, treatment and compression of gas before delivery; (ii) any volume to be allocated for regulated royalties auctions, if applicable; and (iii) any other volume contractually allocated to other parties before August 31, 2022. Future sales under the GSA are contingent upon the commencement of gas production. As of December 31, 2025, we have derived $22.4 million of revenue from our conventional natural gas business.
Additionally, our renewable gas team has built a substantial backlog of acquisition targets that we believe are poised to support rapid growth in the Italian biomethane market.
We expect to be able to fund the majority of our future growth primarily out of cash from operations from the Longanesi, Gradizza, and Trava developments and with cash on hand. In addition, we will be seeking to inject additional financing into the business to further drive our growth in the future.
We believe that our highly experienced and credentialed management team, consisting of former executives of Shell, Eni Ecofuels (“Eni”), Exxon, and other blue-chip companies, provides the company access to a best-in-class technology platform, an excellent in-country business development network, strong collaboration with Italian regulators, and experience with local regulatory processes. Our senior management team has over 100 years of combined experience in the upstream conventional and renewable energy industries. We are managed by William (“Bill”) Dirks, our Executive Director, and Marco Brun, our Chief Executive Officer, under the direction of our Board.
AleAnna is headquartered in Dallas, Texas, and has offices in Rome and Milan, Italy.
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Business Combination
On December 13, 2024, we consummated the previously announced business combination pursuant to the Agreement and Plan of Merger, as amended, dated June 4, 2024, by and among Swiftmerge, HoldCo, Swiftmerge Merger Sub LLC, a Delaware limited liability company and wholly-owned subsidiary of HoldCo, and AleAnna Energy. Pursuant to the terms of the Merger Agreement, on December 13, 2024, SPAC migrated to and domesticated as a Delaware corporation in accordance with Section 388 of the Delaware General Corporation Law, as amended, and the Companies Act (As Revised) of the Cayman Islands and changed its name to AleAnna, Inc. The transactions contemplated by the Merger Agreement are collectively referred to herein as the “Business Combination.”
The Business Combination was accounted for as a common control transaction with respect to AleAnna Energy which is akin to a reverse recapitalization. This conclusion was based on the fact that Nautilus Resources LLC (“Nautilus”) had a controlling financial interest in AleAnna Energy prior to the Business Combination and has a controlling financial interest in AleAnna, which includes AleAnna Energy as a wholly owned subsidiary. The net assets of SPAC are stated at their historical carrying amounts with no goodwill or intangible assets recognized in accordance with the accounting principles generally accepted in the United States of America (“GAAP”). The Business Combination with respect to AleAnna Energy was not treated as a change in control primarily due to Nautilus receiving the controlling voting stake in AleAnna and the ability of Nautilus to nominate the full board of directors and management of AleAnna.
Under a reverse recapitalization, SPAC is treated as the “acquired” company for financial reporting purposes. Accordingly, for accounting purposes, the Business Combination is treated as the equivalent of AleAnna Energy issuing stock for the net assets of SPAC, accompanied by a recapitalization.
We incurred $9.5 million in transaction costs related to the Business Combination. Approximately $0.6 million of these costs were recorded as a reduction to additional paid-in capital, up to the amount of cash proceeds received in the transaction. Of the remaining $8.9 million, approximately $0.5 million represented prepaid directors and officers insurance premiums that were recorded to other assets in the consolidated balance sheet, and $8.4 million represented legal, accounting, consulting and advisory fees that were recorded as Business Combination transaction expenses in the consolidated statement of operations and comprehensive income (loss).
Our Business Strategies
Conventional Natural Gas Business
We leverage the technical and operational expertise of our management team, particularly with the use of 3D seismic and Direct Hydrocarbon Indicators (“DHIs”), to achieve attractive success rates and growth of reserves, production and cash flow. We believe the following factors are key to achieving these goals:
| ● | the use of industry-leading technologies and techniques to significantly increase the probability of drilling success; |
| ● | a robust natural gas price environment, with current takeaway prices of approximately $10-$15 per (103ft3), which are approximately 3-4 times the current Henry Hub spot price; |
| ● | geographically advantaged developments that are adjacent to a well-developed pipeline network containing large excess transport capacity; |
| ● | relatively low-cost, low-risk, onshore operations through which our natural gas can be brought to market at costs of approximately $1-3 per 103ft3; |
| ● | short expected payout periods and high expected rates of return on developments, supported by high quality, high flow rate, reservoirs, and a low combined federal and regional royalty regime (10%); |
| ● | nimble operating model with a focus on utilizing outsourced resources to control costs; and |
| ● | proactive relationships with larger enterprises (like Shell and Eni) to further our marketing and potential hedging strategies, and to support our ongoing conventional natural gas exploration and development aspirations. |
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Renewable Natural Gas Business
We are working to develop and grow our renewable natural gas business through the acquisition of operational Anaerobic Digesters (or “AD’s”) and their conversion to biomethane facilities. We believe the following factors are key to achieving this goal:
| ● | existing AD’s (“Brownfield Facilities”) are cheaper to acquire and have a lower risk profile than new-build opportunities (“Greenfield Facilities” or “Greenfield”) and their conversion to bio methane is relatively efficient and can be accomplished within a short time frame through installation of an “off-the-shelf” biogas upgrading unit; |
| ● | we believe we have unique regional overlap across our conventional and renewable natural gas businesses as our conventional focus area, Italy’s Po Valley, contains the majority of the existing Italian AD’s and is adjacent to a comprehensive natural gas pipeline network operated by Snam S.p.A. (“SNAM”), Italy’s primary natural gas transmission system operator, which exists in close proximity to our conventional business and the Po Valley AD’s; |
| ● | as one of a few licensed Italian Exploration & Production (“E&P”) operators, we believe we have the means, mechanisms, and market relationships to bring biomethane to market, whereas those tasks are above the capabilities of most family farms and farm association who currently own and operated existing AD’s; |
| ● | by either including the family farm as a working-interest partner or entering into bespoke feedstock contracts, we believe we can enlist the farms’ support in creating necessary AD fuels and in the disposal of waste products from the AD (which are converted into fertilizer), without our business having to become proficient in farming; |
| ● | we believe that a combination of additional equity and project level debt financing will satisfy the near-term capital requirements of our renewable natural gas portfolio; and |
| ● | as discussed in more detail below, the Italian government’s 15-year guaranteed biomethane floor price of $39.30 per 103ft3 substantially mitigates pricing risk from the renewable natural gas business and the Italian government as also implemented an investment aid, or capital expenditure reimbursement program, covering up to 40% of eligible investment costs. |
Natural Gas Demand
Although Italy has numerous hydrocarbon-producing basins with significant undeveloped oil and gas deposits, both onshore and offshore, in 2022 Italy imported 96% of its natural gas and has one of the highest concentrations of natural gas as a component of total energy use, at almost 40% by kilotons of oil equivalent. Its reliance on imports has led to a paradigm shift in the Italian political landscape towards securing domestic energy supply. In addition, Italy has in recent decades opened oil and gas exploration and development permits to the global E&P industry beyond the historical domain of Italy’s former National Oil Company (“NOC”), Eni.
Catering to this renewed emphasis on secure domestic energy supply, we are focused on exploitation and producing activities in the prolific and well-derisked Po Valley of northern Italy using modern proprietary 3D seismic surveys, which has led us to believe the Po Valley contains numerous opportunities to explore for and develop conventional natural gas fields. The Po Valley is ripe with access to a dense network of government-controlled natural gas pipelines that can transport our products to industrial, power generation and residential customers throughout Italy and into the southern EU. Additionally, according to Eurostat, Italy is second only to Germany in the EU in terms of the value of natural gas sold for industrial power and heat requirements, and the Po Valley is adjacent to Italy’s core, high-energy demand, manufacturing centers. Supporting the vital energy needs of this industrial production base, Po Valley reservoirs are largely high-quality with unique properties that allow for the application of an important exploration and development technology known as DHIs, through which natural gas deposits can be “seen” on modern seismic surveys. We believe the use of DHI technology dramatically increases the probability of drilling success and lower development costs.
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In addition, throughout the central and southern EU (but primarily focused in Italy and Germany), member states’ interest in creating new sources of renewable energy has supported the construction of nearly 10,000 AD’s over the past 15 years. Largely family-farm owned and operated and fueled by crop and livestock wastes, these AD’s are currently creating a meaningful, sustainable, supply of raw biogas (approximately 50% methane and 50% CO2 and other waste gases) according to the European Biogas Association, the precursor to pipeline-quality biomethane (99.5% pure methane). Virtually all existing AD’s were designed to burn raw biogas in highly inefficient reciprocating engines to produce electricity. However, the Italian government’s financial incentives and subsidies supporting these activities are set to expire in June 2027 absent additional government action and have been largely replaced by attractive biomethane capital and pricing incentives to stimulate conversion of these AD’s to the production of biomethane production. Such incentives are designed to bring biomethane into the national pipeline transmission system in order to deliver the natural gas to higher efficiency, utility-scale, natural gas power generation stations. In order to continue biogas operations, the farms are forced to seek a new use for the product, which will be dominated by conversion to biomethane. To support this conversion, Italy has implemented a government-backed biomethane floor price through the end of 2039 of €124 per MWh, equivalent, as of December 31, 2025 to $39.25 per 103ft3. The Italian government is expected to issue additional incentives in the first quarter of 2026 with similar economic conditions.
Our Operations
Conventional Natural Gas Business
We began studying Italian opportunities in 2007 and, over the last 15 years, have invested approximately $250 million to build a large asset base and exploration and development prospect inventory. Our portfolio is largely comprised of a group of three discoveries, one developed (Longanesi), one currently awaiting regulatory approval (Trava), and one which recently received approval (Gradizza), surrounded by an additional 13 development and exploration prospects within the Longanesi and Ponte dei Grilli “Clusters” that are at various stages of permitting and are supported by proprietary 3D seismic surveys. According to our independent third-party reserve engineer, DeGolyer, these clusters contain approximately 25.8 (109ft3) of proved recoverable natural gas net to us primarily related to our working interest in the Longanesi field but do not include the additional development prospects we have identified and likely intend to drill in the near future.
In addition, our investments in approximately 140,000 acres (approximately 567 km2) of modern, high-quality, 3D seismic surveys in the eastern Po Valley underpin our conventional natural gas growth plan and many of our expected development and exploration prospects are in advanced stages of permitting. Our immediate focus is on the extension of the Longanesi Field together with Padana.
On October 29, 2024, we entered into a Gas Sales Agreement (“GSA”) with Shell Energy Europe Ltd, whereby SEEL became the exclusive buyer of our share of the natural gas produced from the Longanesi field net of (i) any consumption and/or losses incurred in the transport, treatment and compression of gas before delivery; (ii) any volume to be allocated for regulated royalties auctions, if applicable; and (iii) any other volume contractually allocated to other parties before August 31, 2022. Future sales under the GSA are contingent upon the commencement of gas production.
Over the course of 2022 and 2023, together with Padana, we completed the drilling and testing of three conventional natural gas development wells (in addition to the completion of the two original Longanesi field discovery wells). Subsequently, during the first half of 2024, we and Padana completed the construction of the flow lines tying the five wells to a central processing facility, and the facility has been connected to the flow lines and to the SNAM national pipeline system. We and Padana began production from its working interest in five wells in the Longanesi field in March 2025, a key milestone for our business. The Company began recognizing revenue and related expenses, including depreciation and depletion, associated with Longanesi production in the second quarter of 2025.
From 2026 through 2027, we and Padana expect to develop a second phase of Longanesi field development aimed at bringing an additional two conventional wells online (bringing the field to seven total wells). Post 2027, we also expect to enter into a third phase of development, targeting drilling and completion of three additional wells.
Additionally, the infrastructure installed at the Longanesi field (the flow lines and the processing unit) is expected to benefit our future development and exploration prospects in the area. Through the cash flow from Longanesi, Gradizza, and Trava once these latter two discoveries are brought on production, we plan to continue to grow both our conventional and renewable natural gas businesses. As we progress phase two and phase three of Longanesi development, we also expect to begin a new phase of exploration drilling, focused initially on our Fornace and Armonia exploration prospects.
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Renewable Natural Gas Business
We expect our renewable natural gas business will methodically acquire and retrofit a significant number of existing anaerobic digester facilities in the future. We are concentrating our acquisition efforts on Brownfield Facilities in the Po Valley of northern Italy, but will seek other profitable facilities, including greenfields, as circumstances warrant.
On March 20, 2024, we closed the acquisition of the Campagnatico Greenfield natural gas facility in Tuscany, Italy for €2.0 million, or approximately $2.2 million. The facility is fully permitted, and construction is expected to begin on an additional facility in the fourth quarter of 2026.
In 2026 we expect to begin upgrading construction activities at two sites: Casalino (formerly known as Fattoria Delle Jersey) a Brownfield facility (a conversion of an existing AD into a biomethane facility) and Campopiano which is also a Brownfield facility. We will then sequentially stage construction at each additional facility we acquire. Both Casalino and Campopiano are currently fully permitted for production of electricity through conversion of crop and animal waste bio feedstocks. It is the Company’s intention to begin upgrading the sites to refine biogas into renewable natural gas (biomethane) through upgrading units. Following the upgrade process to transition the assets to biogas to renewable natural gas conversion, the Company expects to sell renewable natural gas to customer(s) by trucking or piping the renewable natural gas to the interstate pipeline system (SNAM). Until the plant assets are upgraded, the Company will actively source bio feedstocks for the assets in order to produce biogas which will be processed through reciprocating generators in order to generate electricity which is then sold onto the grid through a metered interconnection. Casalino and Campopiano derive revenues from the sale of such electricity to the local state-owned electrical utility (Gestore dei Servizi Energetici SpA or “GSE”).
Led by the renewable natural gas expertise and Italian networking capabilities of Giuseppe Perrone, our Executive Vice President of Renewable Natural Gas (previously the CEO of Ecofuel SpA and President of EniBioCH4in SpA, subsidiaries of Eni), over the past three years, we have built a significant backlog of potential acquisition opportunities (primarily consisting of existing operational AD’s currently producing biogas for electricity generation). These target AD’s and facilities are undergoing an extensive, and largely proprietary, due-diligence processes focused on both economic and operational feasibility. Our diligence includes, among other things, threshold financial returns, the evaluation of acquisition costs, operating costs, proximity to the existing SNAM pipeline system, feedstock availability, and optimization and expansion potential. We anticipate rapidly expanding our renewable natural gas production portfolio over the next several years.
We aim to acquire a majority working interest (80-100%) and operatorship of all renewable natural gas projects. We strive to form and enter into a joint venture with the farm (typically the seller of the existing AD infrastructure), thereby ensuring a secure supply of raw materials (biomass) and disposal of waste products (digestate). In facilities where we acquire a 100% working interest, we may enter into bespoke feedstock supply and digestate disposal contracts.
We aim to finance this expansion through additional equity financing in our RNG business as well as project level debt financing.
Development Plan and Permitting
Longanesi Field, Phase 1: The Production Concession has been awarded and the approved five production wells have been drilled, completed and tested. First production was achieved in March 2025. The Company began recognizing revenue and related expenses, including depreciation and depletion, associated with Longanesi production in the second quarter of 2025.
Gradizza Field: The discovery well, which will act as the production well, has been completed and tested and all commitments under the Exploration Permit have been finished. Application for the Production Concession has been made, and the required extension of the Environmental Impact Assessment (“VIA”) has been completed and submitted for approval.
Trava Field: The discovery well, which will act as the production well, has been completed and tested and all commitments under the Exploration Permit have been finished. Application for the Production Concession has been made, and the required VIA is being finalized for submission to the Federal Ministry. Prior to first production there are three major authorizations that must be obtained: (i) approval of the VIA by the Federal Ministry, (ii) authorization of the Production Concession by the Emilia Romagna Region (the “Intesa”), and (iii) authorization of the Production Concession from the Federal Ministry.
Fornace Exploration Well: The required VIA has been completed and submitted to the Region and Federal Ministry for approval. The drilling application will be submitted as soon as VIA approval has been obtained from both agencies.
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Gas production activities (both conventional natural gas and renewable natural gas) are subject to several environmental laws and regulations. The main reference is the Consolidated Environmental Act issued by Legislative Decree 152/2006.
The Renewable Natural Gas Development Plan (the “Development Plan”) is subject to the authorization for the construction of the biomethane facility and the production of renewable natural gas. The Development Plan is subject to environmental permitting, through Environmental Impact Assessments.
The Development of conventional natural gas is subject to and controlled by a Federal Production Concession, which is obtained after subjecting the Development Plan to technical, economic and environmental review; moreover, it is the subject of an agreement between the State and the regional government for onshore activities.
Industry
EU Demand for Secure Energy Supply and Growth in Renewable Natural Gas
We believe the EU and Italian energy markets are undergoing dramatic changes as a result of two factors: (1) Russian natural gas imports into the EU have declined approximately two-thirds (from 45% of total imports to 15% of total imports) since the outbreak of the Russia-Ukraine war due to sanctions against Russia and the cancellation of supply contracts, and (2) the shift from fossil fuels to carbon-reduced and carbon-free sources. An immediate need to replace Russian gas with a stable, secure, long-term gas supply has induced EU member nations to focus on increasing access to domestic sources of supply and new liquified natural gas (“LNG”) imports, and a series of technological, economic, regulatory, social, and investor pressures are leading the drive to decarbonize energy at a greatly accelerated pace, which is being supported by significant and long-term renewable gas incentives implemented in Italy and other EU members.
The EU finds itself in a position where reliance on conventional natural gas as a transition fuel becomes imperative for several reasons:
| ● | Despite recent attempts in Germany, adding a significant amount of new coal-fired power in the EU is not a viable option. Domestic coal-fired electricity generation declined to all-time lows in 2022, and much of Europe’s imported coal is from Russia. In addition, increasing coal-fired generation would require the suspension of EU carbon market regulations and the carbon emissions caps that all member nations have strongly endorsed; |
| ● | Similarly, we do not believe new nuclear power generation is a viable substitute given the lengthy permitting and construction timelines associated with such projects. Long lead times make nuclear power including attractive small nuclear reactors a multi-decade solution at best; |
| ● | Replacing Russian gas with LNG imports is very challenging, given supply constraints, limited global liquefaction capacity, and recent moves by the US to slow or stop new LNG export projects. In addition, the EU lacks sufficient LNG import terminals to increase intake significantly in a timely manner given the time and regulatory delays of constructing new LNG import facilities; |
| ● | Renewable power generation suffers from three key problems: intermittency, seasonality, and energy density. Battery technology today can only support 4-6 hours of discharge, which then requires significant and costly capital expenditures on storage to mitigate intermittency; and |
| ● | Recent advancements in Artificial Intelligence (“AI”) are leading to increased global power demand for data centers. The growth in European data center power demand may surpass the total annual power demand of some EU member states. It is anticipated that a significant portion of new data center developments will be supported by combined cycle natural gas turbine power generation. Such generation provides the steady baseload power that data centers require, and, unlike renewable power generation, does not suffer from many of the intermittency and seasonality challenges. The potential power generation and infrastructure demands that may emerge from AI technology may create natural gas demand and power price tightness that could positively impact upstream natural gas prices. |
Renewable natural gas (biomethane) is compositionally identical to the biogenic natural gas in the Po Valley, can be transported on the same pipeline systems, is used by the same consumers, and offers a sustainable, low-carbon fuel that can be used to help transform the energy economy of the EU. As a result, the EU has published very aggressive targets for biomethane development, and its member states, including Italy, are supporting development with high biomethane floor prices and capital investment incentive programs to aid in financing AD conversions to upgrade biogas production to biomethane.
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Social and Environmental Preferences and Investor Pressures
The effects of climate change, including extreme weather events, rising temperatures, and the increased health and socio-economic stability of at-risk populations, have emphasized the need to reduce GHGs and move toward reduced carbon energy solutions. As a result, environmentally conscious policies, initiatives, and businesses are growing in value and preference.
ESG investing has accelerated as institutional investors shift their portfolios away from carbon-intensive assets. This shift in investor sentiment has caused many large integrated energy companies to set decarbonization strategies and diversify into different forms of carbon-free and carbon-reduced energy. However, such large integrated energy companies often have expensive cost structures and cumbersome processes and generally lack the agility to pursue grass-roots smaller energy transition projects being pursued by us. We believe such factors bode well for our competitive positioning in the marketplace. We also believe sizeable integrated energy companies will look to inorganically acquire and integrate aggregated renewables businesses in the future after more nimble companies like AleAnna have built up a larger renewable portfolio of profitable biomethane facilities.
Reserve Information
Preparation of Reserve Estimates
Our reserve estimates as of December 31, 2025 and 2024 included herein are based on reports prepared by DeGolyer, our independent reserve engineer, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC in effect at such time. A copy of the December 31, 2025 report is included as Exhibit 99.1 hereto. DeGolyer provides a variety of services to the oil and gas industry, including field studies, oil and gas reserve estimations, appraisals of oil and gas properties and exploration and development prospects and reserve reports for their clients.
Proved reserves are reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expires, unless evidence indicates that renewal is reasonably certain. Our proved reserves were estimated assuming a 5-year reserve life. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil or natural gas actually recovered will equal or exceed the estimate. The technical and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, well-test data, production data (including flow rates), well data (including lateral lengths), historical price and cost information, and property ownership interests. Our independent reserve engineer uses this technical data, together with standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and analogy. The proved developed reserves are estimated using performance analysis and volumetric analysis. The estimates of the proved developed reserves are used to estimate the proved undeveloped reserves for each proved undeveloped location (utilizing type curves, statistical analysis, and analogy). Proved undeveloped drilling locations that are more than one offset from a proved developed well utilized reliable technologies to confirm reasonable certainty. The reliable technologies that were utilized in estimating these reserves include log data, performance data, log cross sections, seismic data, core data, and statistical analysis.
Internal Controls
Our internal staff of petroleum engineers and geoscience professionals works closely with DeGolyer to ensure the integrity, accuracy and timeliness of data furnished to DeGolyer. Periodically, our technical team meets with DeGolyer to review properties and discuss methods and assumptions used by us to prepare reserve estimates.
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DeGolyer is an independent petroleum engineering and geological services firm. The independent evaluation of reserves referenced herein has been supervised by Mr. Regnald A. Boles, an Executive Vice President and Division Manager with DeGolyer, a Registered Professional Engineer in the State of Texas and a member of the Society of Petroleum Engineers, the Society of Petroleum Evaluation Engineers, and the European Association of Geoscientists & Engineers. He has over 41 years of oil and gas industry experience. Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs.
For all of our properties, our internally prepared reserve estimates and the reserve reports prepared by DeGolyer, are reviewed and approved by our Executive Director, William K. Dirks, a greater than 40-year industry veteran who has successfully explored, developed, and operated reserves in multiple global jurisdictions.
The following table summarizes our proved developed and undeveloped natural gas reserves using average first-day-of-the-month closing prices for the prior 12 months and disaggregated by product.
Reserve Data
| December 31, 2025 | December 31, 2024 | |||||||||||||||
| Natural Gas | Natural Gas | Percentage | ||||||||||||||
| (106ft3) | (106ft3) | Change | Change | |||||||||||||
| Estimated proved developed reserves | 23,461 | - | 23,461 | NM | ||||||||||||
| Estimated proved undeveloped reserves | 2,366 | 17,621 | (15,255 | ) | -86.6 | % | ||||||||||
| Estimated total proved reserves | 25,827 | 17,621 | 8,206 | 46.6 | % | |||||||||||
The following table summarizes our proved developed and undeveloped reserves using average first-day-of-the-month closing prices for the prior twelve months and disaggregated by discovery.
| December 31, 2025 | December 31, 2024 | |||||||||||||||||||||||||||||||
| Longanesi | Gradizza | Trava | Total | Longanesi | Gradizza | Trava | Total | |||||||||||||||||||||||||
| (106ft3) | (106ft3) | |||||||||||||||||||||||||||||||
| Proved developed reserves | 23,461 | - | - | 23,461 | - | - | - | - | ||||||||||||||||||||||||
| Proved undeveloped reserves | - | 703 | 1,663 | 2,366 | 17,241 | 380 | - | 17,621 | ||||||||||||||||||||||||
| Total proved reserves | 23,461 | 703 | 1,663 | 25,827 | 17,241 | 380 | - | 17,621 | ||||||||||||||||||||||||
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Proved Developed Reserves
Our proved developed reserves increased for the year ended December 31, 2025 compared to the same period in 2024 primarily due to the startup and first production for Longanesi. The following table provides a roll-forward of our proved developed reserves.
| Proved Developed Reserves | ||||
| (106ft3) | ||||
| Balance at January 1, 2025 | - | |||
| Revision of previous estimates | - | |||
| Extensions, discoveries and other revisions | 23,461 | |||
| Balance at December 31, 2025 | 23,461 | |||
Proved Undeveloped Reserves
Our proved undeveloped reserves for the year ended December 31, 2025 decreased compared to the same period in 2024 primarily due to the first production at Longanesi, and to a lesser extent changes in the forecasted startup date for Trava and Gradizza. The following table provides a roll-forward of our proved undeveloped reserves.
| Proved Undeveloped Reserves | ||||
| (106ft3) | ||||
| Balance at January 1, 2025 | 17,621 | |||
| Revision of previous estimates | ||||
| Extensions, discoveries and other revisions | (15,255 | ) | ||
| Balance at December 31, 2025 | 2,366 | |||
As of December 31, 2025 , we had no wells with proved undeveloped reserves that had remained undeveloped for more than five years from their time of booking. Our Trava and Gradizza wells are classified by DeGolyer as proved undeveloped reserves as such wells have not yet started production and require future investments to install production pipelines and production facilities prior to being fully completed and producible.
On May 28, 2024, we reached a settlement agreement (the “Blugas Settlement Agreement”) with Blugas Infrastructure S.r.l. (“Blugas”) regarding the Blugas overriding royalty interest (“ORRI”) whereby Blugas was entitled to physical delivery of 20% of the first 350 million standard cubic meters (approximately 2,472 106ft3) produced from the Longanesi field. Under the terms of the Blugas Settlement Agreement, we paid Blugas approximately €5 million, plus an additional €1.1 million in applicable VAT. In exchange, we were released from any future liability related to the Blugas ORRI. As a result of the transactions contemplated by the Blugas Settlement Agreement, our 33.5% working interest (net revenue interest) in the Longanesi field, as established under the terms of the Unified Operating Agreement arrangement originally signed between ENI and Grove and dated September 26, 2009, is now unencumbered except for normal government royalties (10%). The Blugas Settlement was accounted for as an acquisition of the Blugas ORRI claim with a corresponding increase to the expected future cash flows from our reserves. Our year-end December 31, 2024 reserve quantities included the 20% of 350 million standard cubic meters (approximately 2,472 106ft3) allocable to the Blugas ORRI in our proved gas reserves, however, the previously required payments to Blugas associated with the sale of such quantities are no longer reflected as cash outflows (costs) as if such amounts were paid to Blugas. As the cash outflows (costs) are no longer reflected as if paid to Blugas, such amounts are reflected in our December 31, 2025 reserve report as allocable to our unencumbered 33.5% working interest.
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Present Value of Future Net Cash Flows Discounted at 10%
The following table provides the estimated future net cash flows from proved reserves, the present value of those net cash flows discounted at a rate of 10% (PV-10) and the prices used in projecting net cash flows over the past two years. Our reserve estimates and related cash flows do not include any probable or possible reserves.
| Years Ended December 31, | ||||||||
| 2025 | 2024 | |||||||
| (Thousands, unless otherwise noted) | ||||||||
| Future net cash flows(a) | $ | 181,810 | $ | 130,333 | ||||
| Present value of net cash flows discounted at a rate of 10%(b) | 120,523 | 107,202 | ||||||
| Prices | ||||||||
| Natural gas price ($/103ft3)(c) | $ | 12.84 | $ | 11.73 | ||||
| (a) | Future net cash flows represent future cash flows which are reduced by estimated production costs, administrative costs, costs to develop and produce the proved reserves and abandonment costs, all based on current economic conditions at each year-end. This amount excludes future income taxes and is prior to any discounting. |
| (b) | Present value of net cash flows represents future net cash flows discounted to present value using a discount rate of 10%. Such amount also excludes future income taxes. See “Reconciliation of Standardized Measure to PV-10” for a calculation of the standardized measure of estimated future net cash flows from natural gas and oil reserves. |
| (c) | Gas prices are based on a reference price. Gross gas price is calculated as the unweighted arithmetic average of the first day-of-the-month price prevailing in Italy for each month within a 12-month period prior to the end of the reporting period. The volume-weighted average price attributable to the estimated proved reserves was $12.84 and $11.73 per thousand cubic feet of gas for the year ended December 31, 2025, and 2024, respectively. |
Future net cash flows represent projected revenues from the sale of proved reserves net of production and development costs (including transportation and gathering expenses, operating expenses and production taxes). Revenues are based on a twelve-month unweighted average of the first-day-of-the-month pricing, without escalation. Future cash flows are reduced by estimated production costs, administrative costs, costs to develop and produce the proved reserves and abandonment costs, all based on current economic conditions at each year-end. There can be no assurance that the proved reserves will be produced in the future or that prices, production or development costs will remain constant. There are numerous uncertainties inherent in estimating reserves and related information. See Note 16 to the financial statements included herein for further discussion of the preparation of, and year-over-year changes in, our reserves estimate and calculation of the standardized measure of estimated future net cash flows from natural gas and oil reserves.
As previously noted, the Blugas settlement was accounted for as an acquisition of the Blugas ORRI claim with a corresponding increase to the expected future cash flows from our reserves. Our year-end December 31, 2024 reserve quantities included the 20% of 350 million standard cubic meters (approximately 2,472 106ft3) allocable to the Blugas ORRI in our proved gas reserves, however, the previously required payments to Blugas associated with the sale of such quantities are no longer reflected as cash outflows (costs) as if such amounts were paid to Blugas. As the cash outflows (costs) are no longer reflected as if paid to Blugas, such amounts are reflected in our December 31, 2024 reserve report as allocable to our unencumbered 33.5% working interest. Our year-end December 31, 2025 reserve quantities continue to include the 20% of 350 million standard cubic meters (approximately 2,472 106ft3).
Reconciliation of Standardized Measure to PV-10
The present value of net cash flows discounted at a rate of 10%, or, “PV-10,” is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas assets. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas assets. PV-10, however, is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves.
10
The following table provides a reconciliation of the GAAP standardized measure of discounted future net cash flows to PV-10 (non-GAAP) at December 31, 2025 and 2024:
| Years Ended December 31, | ||||||||
| 2025 | 2024 | |||||||
| (Thousands, unless otherwise noted) | ||||||||
| Standardized measure of discounted future net cash flows | $ | 87,728 | $ | 89,033 | ||||
| Present value of future income taxes discounted at a rate of 10% | 32,795 | 18,169 | ||||||
| Present value of net cash flows discounted at a rate of 10% (PV-10) | $ | 120,523 | $ | 107,202 | ||||
Acreage
The following table summarizes our acreage as of December 31, 2025 and 2024. As we have achieved first production at the Longanesi wells, we have classified 6,590 acres as developed (productive) acreage. We have not commenced production at the remaining wells, as such, the remaining acreage is considered undeveloped acreage.
| December 31, 2025 | December 31, 2024 | |||||||
| Production Concessions(1) | ||||||||
| Total gross productive acreage | 6,590 | - | ||||||
| Total net productive acreage | 2,208 | - | ||||||
| Exploration Permits(2) | ||||||||
| Total gross productive acreage | - | - | ||||||
| Total net productive acreage | - | - | ||||||
| Applications(3) | ||||||||
| Total gross productive acreage | - | - | ||||||
| Total net productive acreage | - | - | ||||||
| Total gross productive acreage | 6,590 | - | ||||||
| Total net productive acreage | 2,208 | - | ||||||
| Production Concessions(1) | ||||||||
| Total gross undeveloped acreage | 13,275 | 24,142 | ||||||
| Total net undeveloped acreage | 13,275 | 19,710 | ||||||
| Exploration Permits(2) (3) | ||||||||
| Total gross undeveloped acreage | 567,376 | 682,802 | ||||||
| Total net undeveloped acreage | 567,376 | 682,802 | ||||||
| Applications(4) (5) | ||||||||
| Total gross undeveloped acreage | 1,580,205 | 1,623,209 | ||||||
| Total net undeveloped acreage | 1,580,205 | 1,623,209 | ||||||
| Total gross undeveloped acreage | 2,160,856 | 2,330,153 | ||||||
| Total net undeveloped acreage | 2,160,856 | 2,325,721 | ||||||
| (1) | Encompasses three distinct production concession areas including Longanesi, Valle del Mezzano (Trava), and Gradizza. No expiries prior to 2032. |
| (2) | Encompasses 10 distinct permits. AleAnna has an active permit extension program in place. In the event that production is not established or if extensions are not granted by the Italian government, 130,558 net acres will expire by December 31, 2026 and an additional 331,845 acres will expire by December 31, 2027. |
| (3) | AleAnna has notified the Italian Ministry of its intent to relinquish 114,309 acres of Permits in 2026; these relinquishment notices have not yet been processed by the Ministry. |
| (4) | Encompasses 13 distinct areas and applications. Applications are rights of mineral development controlled by AleAnna whose activation may be deferred. AleAnna has not yet initiated activation, but has the right to do so in the future. Once AleAnna initiates activation the 1,580,205 net acres will have initial permit periods of six year. |
| (5) | AleAnna has notified the Italian Ministry of its intent to relinquish 1,255,429 acres of Applications in 2026; these relinquishment notices have not yet been processed by the Ministry. |
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Productive Wells
On March 13, 2025, AleAnna achieved a key milestone with the first production from its five wells in the Longanesi field and began recognizing revenue and related expenses, including depreciation and depletion, related to this production during the second quarter of 2025. We did not have any productive wells as of December 31, 2024. As of December 31, 2025, our Trava and Gradizza wells all required future investments to install production pipelines and production facilities prior to being fully completed and producible. As a result, as of December 31, 2025, five wells of Longanesi field were classified by DeGolyer as proved developed reserves. The remaining wells are classified as proved undeveloped reserves as such wells have not yet started production.
Drilling Activities
Our primary activities currently involve the tie-in of three Longanesi development wells together with our working interest partner, Padana. The Company had no exploratory or development drilling activity during the year ended December 31, 2025, or 2024. The completion of the gross Longanesi development well and workover and the completion of one additional Longanesi development well (0.335 net to our interest) were completed during the year ended December 31, 2023.
Following tie-in of the Longanesi wells and the installation of a temporary processing facility, we and Padana achieved first production of the five wells in the Longanesi field in March 2025. The permanent processing facility is under construction and will be installed in phases during 2026, with completion and commissioning expected in early 2027.
Net Volumes Sold, Prices and Production Costs
As of December 31, 2025, we generated approximately $22.4 million of revenue from sales of natural gas from the Longanesi field and approximately $2.7 million from sales of electricity from our RNG plants. As of December 31, 2024, we had not generated any revenue from our operations other than from sales of electricity of $1.4 million from two renewable gas assets that were purchased in July 2024.
Delivery Commitments
We are not currently party to any long-term delivery commitments as of December 31, 2025 or 2024.
Governmental Regulations
With regard to environmental laws and compliance, the activities are subject to Environmental Impact Assessment, whose main rules are provided by the Consolidated Environmental Act issued by Legislative Decree 152/2006.
Environmental laws and regulations and environmental permitting require significant investments from the company to ensure compliance with laws and regulations. This entails the need for a structure that constantly monitors compliance activities.
Conventional Natural Gas
Our operations are subject to stringent and complex laws and regulations governing environmental protection, human health and safety, and long-term “sustainability”. We are required to obtain certain permits, requiring approval at both the Italian national and regional government levels, to construct and operate our conventional facilities, which will contain constraints including those related to air emissions, solid and hazardous waste management, water quality, and control of construction/industrial traffic. These permits can be difficult and time-consuming to obtain and maintain. We have spent over a decade acquiring necessary permits required for the development of our Conventional business, and while we view this as a competitive advantage, our ability to obtain these permits in the future may be impacted by opposition from citizens or other groups or other political pressures. Compliance with such laws and regulations can be costly, and noncompliance can result in substantial penalties.
The Italian hydrocarbons industry is regulated by a combination of constitutional provisions, statutes, governmental decrees and other regulations that have been enacted and modified from time to time, including legislation enacted to implement EU requirements (collectively, the “Hydrocarbons Laws”).
Pursuant to the Hydrocarbons Laws, all hydrocarbons existing in their natural condition in strata in Italy or beneath its territorial waters (including its continental shelf) are property of the State. Exploration activities require an exploration permit, while production activities require an exploiting concession granted by the Ministero dell’Ambiente e della Sicurezza Energetica — MASE or, in some specific cases (e.g. special-status region) by the Region.
In particular oil and gas exploration can be undertaken after the award of an exploration license that can last up to twelve years, provided that the permit holder complies with the approved exploration program. If the permit holder drills and discovers an exploitable hydrocarbon field, it has a right to obtain a production concession. All exploration and production activities are subject to environment assessment procedures.
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Hydrocarbon exploration and production activities in Italy are governed mainly by Law no. 6/1957, “Exploration and production of liquid and gaseous hydrocarbons” and Legislative Decree No. 625 of November 25, 1996 “Implementation of Directive 94/22/EEC on the conditions for granting and using authorizations for the prospection, exploration, and production of hydrocarbons”. Mining titles are granted by a Decree of MASE. The two main types of mining titles are:
(a) Exploration permits — exclusive mining titles that can be requested on areas with a maximum footprint of 750 km2. If multiple operators request the same area, MASE manages a competitive process to select the permit holder. In addition to an initial six-year validation period, there are two possible extension periods of three years each. However, such periods may be subject to suspension for justified reasons. The exploration permit allows the acquisition of geophysical data as well as the permission to drill one or more exploratory wells. If the exploratory well yields a positive result and a new hydrocarbon field is identified, the operator may apply for a production concession, which, once granted, allows the deposit itself to be brought into production.
The reference legislation for issuing the exploration permit is the following:
| ● | art. 8 “Granting of permits”, paragraph 1, of the Presidential Decree. 18 April 1994, n. 484 “Regulation governing the procedures for awarding prospecting or exploration and granting concessions for the production of hydrocarbons on land and at sea”; |
| ● | art. 6 “Awarding of the exploration permit, its dimensions and duration”, paragraph 4, of law 9 January 1991, n. 9 “Regulations for the implementation of the new national energy plan: institutional aspects, hydroelectric plants and power lines, hydrocarbons and geothermal energy, self-production and tax provisions”; |
| ● | for onshore, art. 1, paragraph 7, letter n) of law 23 August 2004 n. 239 “Reorganization of the energy sector, as well as delegation to the Government for the reorganization of the provisions in force on energy”. |
| ● | The exploration permit is issued following a single procedure, governed by article 1 paragraphs 77 and 79 of law 23 August 2004, n. 239. MASE reviews the project after hearing the opinion of a consultative body, the Ministerial commission on hydrocarbons (CIRM), within which the competent state and regional administrations are represented. The projects are subjected to the environmental eligibility procedure and/or the expression of an environmental compatibility judgment by the MASE or the Region concerned. MASE then issues onshore permits in agreement with the regions involved. |
(b) Production Concessions are exclusive mineral titles requested on a portion of the exploration permit area where a new hydrocarbon field was discovered (with a maximum area of 300 km2). In addition to an initial validation period of 20 or 30 years, an operator may apply for further extension period of 10 years and then for further extension periods of five years until the end of the field economic life. All activities relating to the production of hydrocarbons can be carried out within the scope of a production concession, including the drilling of development wells and construction of facilities. Production concessions are awarded to the holders of exploration permits so long as liquid and/or gaseous hydrocarbons are found and so long as the operator demonstrates adequate economic and technical capacities.
The production concession decree is granted and issued by MASE and contains all the requirements and constraints established by the various bodies that examined the project during the administrative procedure. The concession holder may freely sell the products extracted from the hydrocarbon field and must pay a royalty to the national and local governments. Yearly rentals are due based on the areas under the permits and are due to the national government.
The concession holder has an exclusive right on exploration, development and production activities, sustaining all the operational risks and costs related to the exploration and development activities, and it is entitled to the productions realized. As a compensation for mineral concessions, pays royalties on production and taxes on oil revenues to the state in accordance with local tax legislation.
Proved reserves to which we are entitled are determined by applying our share of production to total proved reserves of the contractual area, in respect of the duration of the relevant mineral right.
In general, we are required to pay income tax on income generated from production activities. The taxes imposed upon gas production profits and activities may be substantially higher than those imposed on other businesses.
The initial duration of an exploration permit is six years, with the possibility of obtaining two three-year extensions and an additional one-year extension to complete activities underway. We have an active permit extension program in place. In the event that production is not established or if extensions are not granted by the Italian government, our permits will expire on December 31, 2026 and December 31, 2027. Applications are rights of mineral development controlled by us whose activation may be deferred. we have not yet initiated activation, but has the right to do so in the future. Once we initiates activation the respective net acres will have initial permit periods of six years. Upon each of the three-year extensions, 25% of the area under exploration must be relinquished to the State of Italy (only for initial acreage larger than 300 square kilometers). The initial duration of a production concession is up to 30 years, with the possibility of obtaining a ten-year extension and additional five-year extensions until the end of the field economic life.
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These provisions had to be coordinated with a new law effective as of February 12, 2019 (Law 12/2019, conversion of Decree-Law 135/2008 — “D.L. Semplificazioni”) and further amendments, which requires certain Italian administrative bodies to define and adopt a plan (PiTESAI) aiming to identify areas suitable for exploration, development, and production of hydrocarbons in the national territory, including the territorial seawaters. Such plan was adopted on December 28, 2021 with Ministerial Decree, in accordance with the article 11-ter of Decree-Law 135/2018.
However, PiTESAI has been considered too restrictive by industry operators (including AleAnna) which lodged several appeals against the PiTESAI before the Lazio Regional Administrative Court — Rome (TAR Lazio). On February 12, 2024, TAR Lazio with rulings no. 2858 and no. 2872 declared void the PiTESAI. MASE did not file an appeal before the Council of State within the appeal period in order to restore the validity of the PiTESAI and began a procedure to return all of the acres affected by the PiTESAI, once acquired for those operators who want to reacquire their mining titles and permit applications with the original extension. This procedure aims to restore the integrity of all the titles affected by the PiTESAI and returns to the operators of all of the suitable areas for hydrocarbon exploration, development and production activities.
Therefore, exploration permits maintain their efficacy in areas identified as suitable and limited to gas exploration target.
Starting from June 1, 2019, the annual fee for all licensees (exploration permits and production concessions) have been increased 25 times.
In 2019 the Decree-Law 124/2019, converted into Law 157/2019, established at article 38 the property tax on marine structures (IMPI) starting from year 2020.
On March 1, 2022, the Italian government issued a first Decree-Law (Decree-Law 17/2022 — ” D.L. Energia”) aimed at boosting the national production by mitigating the effects of PiTESAI. This was converted into law on April 27, 2022 (Law 34/2022).
A second Decree-Law, with the same objectives, was issued on December 9, 2023 (Decree-Law 181/2023), promoting new upstream development opportunities converted into law on February 2, 2024 (Law 11/2024).
On October 11, 2024, the Council of Ministers approved the Decree-Law 153/2024 converted into Law 191/2024 (D.L. Ambiente), which amended several articles of the Decree-Law 135/2018. Paragraph 1 of article 2 of the 153/2024 repealed paragraphs 1, 2, 3, 4, 5, 6, 7, 8 and 13 of Article 11-ter of Decree-Law 135/2018, and the PiTESAI was therefore annulled. The measures adopted by the MASE following the adoption of the PiTESAI such as revocation and re-implementation measures were also annulled. Following the repealing of paragraph 13 of article 2 of the Decree-Law 135/2018, the public utility character of hydrocarbon prospecting, exploration and production activities has been recognized.
Furthermore, paragraph 2 of article 2 of the Decree-Law 153/2024 confirmed the prohibition established by PiTESAI on the granting of new oil production licenses on the national territory and at sea, however, operators who have already been granted oil or oil and gas licenses may continue their activities, even for the purpose of granting concessions; even concessions for the production of liquid hydrocarbons that have already been granted may continue their production activities until the deposit found is fully developed.
Article 2, paragraph 3, of the Decree-Law 153/2024 stated that the granting of extensions of hydrocarbon production concessions must also take into account the reserves and extraction potential still to be produced and the time required to complete their rational production up to the useful life of the deposit. The concession area that is functional for production and the exploration and development activities still to be carried out must also be duly taken into account, with the areas no longer functional being re-zoned.
Article 2, paragraph 4 of the Decree-Law 153/2024 reduced the limit of 12 nautical miles for upstream activities to nine nautical miles, amending the article 6, paragraph 17 of the Environmental Code (Legislative Decree 152/2006).
Article 2, paragraph 5 of the Decree-Law 153/2024 allowed for the release of concessions in the Adriatic Sea for which applications had already been submitted at the time the Decree-Law 153/2024 went into force, provided that the party concerned complies with the long-term supply procedures. In addition, the fields in question must have the potential to produce a certain amount of gas reserves above a threshold of 500 mmscfd.
14
Regardless of the validity and the effects of PiTESAI, such plan did not entail any significant and adverse consequence on our development and producing activities in relation to its Italian concessions and concession applications. Some permits where investments on exploration had been made were affected by the plan and part or all of their areas was declared incompatible. Since the PiTESAI was voided, we now hope to be able to start again exploration activity on part of the areas declared incompatible by the PiTESAI. On December 13, 2024, we, as requested by MASE, notified MASE of our willingness to reacquire the mining titles and permit applications with the original extension.
Royalties
The Hydrocarbons’ Laws require the payment of royalties for hydrocarbon production. As per Legislative Decree No. 625 of November 25, 1996, subsequent modifications and integrations (the last modification was introduced by Law 160/2019 — Budget Law 2020, art. 1 par. 736 & 737) and Law Decree No. 83 of June 22, 2012, royalties are equal to 10% for gas and oil productions onshore, to 10% for gas and 7% for oil offshore, with exemptions only for on shore gas concessions with production lower than 10 MMsmc/year and off shore gas concessions with production lower than 30 MMsmc. (Only in the Autonomous Region of Sicily, following the Regional Law No. 9 of May 15, 2013, royalties onshore for oil and gas are equal to 20.06%, with no exemptions).
Environmental Regulation
Exploration and production of conventional natural gas is highly regulated and is subject to environmental laws and compliance, whose main rules are provided by the Consolidated Environmental Act issued by Legislative Decree 152/2006. Our activities are subject to Environmental Impact Assessments. Environmental laws and regulations and environmental permitting require significant investments to ensure compliance. For this reason, a structure that constantly monitors compliance activities is needed.
Our operations are subject to stringent and complex laws and regulations governing environmental protection, human health and safety, and long-term “sustainability”. Oil and gas companies are required to obtain certain permits, requiring approval at both the Italian national and regional government levels, to construct and operate conventional facilities, which will contain constraints including those related to air emissions, solid and hazardous waste management, water quality, and control of construction/industrial traffic. These permits can be difficult and time-consuming to obtain and maintain. We are acquiring necessary permits required for the development of its conventional business, and while we view this as a competitive advantage, our ability to obtain these permits in the future may be impacted by opposition from citizens or other groups or other political pressures. Compliance with such laws and regulations can be costly, and noncompliance can result in substantial penalties.
Italian Gas Market Regulations
In the last decade a number of new rules have been introduced in order to improve liquidity and efficient functioning of the Italian wholesale gas market, fostering competition and at the same time improving the system security of supply. Among such new rules, it is worth mentioning the market-based mechanisms for the allocation of storage capacities and of regasification capacities. The past allocation criteria based on tariffs has been replaced with new auction mechanisms that enabled market players to express the market-value of storage and of regasification capacities, while at the same time ensuring the allowed revenues of storage operators and LNG terminal operators by means of specific parallel measures.
An organized market platform (MGAS) for gas trading and gas balancing market, managed by the independent operator Gestore dei Mercati Energetici (GME) also acts as a central counterparty, where different market participants (including the Transmission System Operator — TSO) can carry out spot and forward transactions at the “Punto di Scambio Virtuale” (PSV — Virtual Trading Point). In addition, since February 2018 voluntary market making activity has been introduced in the spot section of the gas exchange MGAS: such activity is based on the service provided by some liquidity providers, in order to boost liquidity and trading activity on the same exchange, initially for the day-ahead market but with possible future extension to the within-day section and to the forward section of the MGAS.
15
In addition, a gas balancing regime has entered into force since October 2016 as an evolution of the one already in place and in compliance with the EU regulatory framework. This system is based on the principle that network users have to balance their daily position, also in accordance with the timely information provided by the TSO about daily gas consumption. The new gas balancing regime provides the incentive for shippers to balance their position via penalizing imbalance prices and at the same time provides the possibility for shippers to modify intra-day their gas flow nominations and to trade on the market with other shippers and/or with the TSO itself (that can access the market under some constraints, in order to address overall system balancing needs that may arise on top of shippers’ activities).
Following the liberalization of the natural gas sector introduced in the year 2000 by Decree No. 164, prices of natural gas in the wholesale market, which includes industrial and power generation customers are freely negotiated. However, the ARERA (the Italian Regulatory Authority for Energy, Networks and Environment) retains a power of surveillance on this matter as per Law No. 481/1995 (establishing the ARERA) and Legislative Decree No. 164/2000. Furthermore, the ARERA is still entrusted (as per the Presidential Decree dated October 31, 2002) with the power of regulating natural gas prices to residential customers, also with a view of containing inflationary pressure deriving from increasing energy costs. Consistently with those provisions, companies which sell natural gas to residential customers are currently required to offer to those customers the regulated tariffs set by ARERA beside their own price proposals.
In 2013, a new tariff regime was fully enacted by ARERA targeting Italian residential clients who are entitled to be safeguarded in accordance with current regulations. Clients who are eligible for the tariff mechanism set by the ARERA are residential clients. With Resolution No. 196 effective from October 1, 2013, the ARERA reformulated the pricing mechanism of gas supplies to those customers by providing a full indexation of the raw material cost component of the tariff to spot prices at the TTF (Title Transfer Facility) hub in Northern Europe, replacing the then current regime that provided a mix between an oil-based indexation and spot prices.
This tariff regime also reduced the tariff components intended to cover storage and transportation costs. Finally, it also increased the specific pricing component intended to remunerate certain marketing costs incurred by retail operators, including administrative and retention costs, losses incurred due to customer default and a return on capital employed.
This new gas tariff indexation aiming at safeguarding the households was initially intended to remain effective till July 1, 2019 (as provided by Law 124/17). However, this deadline had been already prorogated by one year (as per Law Decree 91/2018), and finally has been prorogated to January 2024. From that point onwards, in Italy households other than vulnerable customers will no longer have access to regulated tariffs for gas supplies. Consumers will have to choose among the different pricing proposals made by gas selling companies, while only vulnerable customers will be entitled to the regulated tariff after January 2024. The ARERA has established that gas selling companies comply with certain requirements about the offerings to customers which include at least two pricing indexations (fixed and variable), both complemented with contractual conditions regulated by the ARERA. This regulatory development might increase competition in the Italian retail market for selling gas.
Given the context of rising prices that occurred between 2021 and 2022 in gas market, ARERA carried out a series of investigations to evaluate interventions on commodity prices and then decided to switch the gas raw material reference from TTF to PSV, with monthly update of the component covering wholesale natural gas supply costs for regulated customers.
Other Key Regulatory Developments
Within the scope of the costs and criteria for accessing the main logistic infrastructures of the gas system, the main risk factors for the business are linked to the periodic processes for defining the economic conditions and the current rules for the services. The regulation criteria for gas transportation tariffs in Italy have recently been redefined for the four-year period 2024-2027, but the re-definition of transportation tariffs criteria at pre-established deadlines, as well as the timely definition on an annual basis of the specific applicable tariff values, is an element that all European countries have in common and which in the future could determine impacts on logistic costs.
16
Moreover, the energy crisis scenario that materialized in 2022 has directed legislators, at European and individual country level, towards evolutions of the legislation and the consequent regulations that can impact the market dynamics, with the aim of containing prices for end customers and improve the security of supplies (e.g. possible obligations to reduce final consumption, caps on prices of derivatives on wholesale gas products traded on regulated markets, possible storage obligations, obligations of ex-ante notification to the European Commission concerning new supply contracts).
The Italian Government has adopted a number of various measures to contain retail prices such as:
| ● | cancellation of general system charges; |
| ● | strengthening of social bonuses. |
In the medium term, it is likely that gas demand at European level will be supported by the need of accelerating the phase-out of coal-based power generation in view of the decarbonization targets. On the other side, with the implementation of the EU Green Deal and of the subsequent and more ambitious decarbonization interventions, in the coming years the regulation of the gas sector will presumably be affected by potentially significant changes, as a consequence of adjustments in the market design and/or new obligations or constraints on operators in the sector which will accompany the evolution of European regulations, in the context of energy transition and consistently with the decarbonization objectives of the energy sector (including the related objectives for the development of renewable or decarbonized gases, for the promotion of technologies enabling greater integration between the electricity and gas sectors, for the reduction of methane emissions). These changes might cause pressure on the natural gas business, but on the other side they will likely open and support new business opportunities in the renewable and decarbonized gases business that we are ready to pursue.
Renewable Natural Gas
The permitting framework provided by the Legislative Decree No. 190 of November 25, 2024 on “Regulation of administrative regimes for the production of energy from renewable sources, pursuant to Article 26, paragraphs 4 and 5, letters b) and d), of Law No. 118 of August 5, 2022.” requires for the construction and operation of biomethane production facilities and related modification projects:
| ● | the “Simplified Authorization Procedure” (“S.A.P.”): |
| a) | “for new biomethane production facilities with a production capacity, not exceeding 500 standard cubic meters/hour; |
| b) | developments on operating biomethane production facilities that do not result in an increase in the area already modifications, including the strengthening, repowering, refurbishment, reactivation and reconstruction, even complete, of existing, authorized or licensed renewable energy plants for the production of electricity, with the exception of biomethane production plants, provided that they do not result in an increase in the area occupied by the existing plant of more than 20 percent; |
| c) | for partial or complete reconversion to biomethane production not exceeding 500 standard cubic meters/hour of power generation facilities fueled by biogas; |
| d) | for developments on operating biomethane production facilities that do not result in an increase in the area already subject to authorization, or in any changes in the types of matrices already authorized, subject to the following conditions: |
| 1. | the nameplate of the upgrading system indicates the production capacity value resulting from the implementation of the developments: |
in the case of grid-connected facilities, there is the willingness of the grid operator to inject the additional volumes resulting from the implementation of the developments;
| 2. | in the case of grid-connected facilities, there is the willingness of the grid operator to inject the additional volumes resulting from the implementation of the developments; |
| 3. | the operations do not involve any changes in the types of matrices already authorized any increase in areas dedicated to anaerobic digestion is no more than 50 percent of those already authorized.” |
| ● | the “Sole Authorization” (“S.A.”) in other cases. |
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The application for the S.A. procedure, defined by article 9 of the Legislative Decree No. 190 of November 25, 2024, is submitted by the proponent to the competent region. Within 10 days the documents are published by the authority granting the authorization. Within the following 20 days the competent authorities shall verify and may request the proponent integrations to be filed within 30 days and might be extended 90 days upon request by the proponent. The authority granting the authorization shall proceed to convene the “service conference” which is the meeting attended by all public bodies interested in the project to give opinions of competence or request clarifications from the proponent. The proceedings for the S.A. are ordinarily closed within 120 days of the services conference, and in cases where the “environmental impact assessment” proceedings are started it may be suspended for up to 90 days. The procedure ends with the adoption of the managerial determination of the competent region.
The application for the S.A.P. procedure, defined by article 8 of the Legislative Decree No. 190 of November 25, 2024, is submitted by the proponent to the municipality at least 30 days before the start of work on the plant. Within 30 days of the application, the municipality must verify the conditions of the S.A.P.; alternatively, after the 30-day period has elapsed, the application is considered granted.
Renewables Regulation in the Biomethane Production Sector
In order to support the achievement of the renewables target in the transport sector established by the EU and national laws, the Ministerial Decree of March 2, 2018 and of September 15, 2022, provide the legislative framework to incentivize the production of both biomethane and other advanced biofuels to be used in the transport sector. The Decrees provide incentives for biogas facilities that are converted to biomethane production.
The incentive consists in an allocation of a certificate for every 10 Gcal of biomethane produced and partial subsidies on investments on biomethane facilities. The certificate has a market value since fossil fuel marketers have to sell a minimum percentage of biofuels annually, for which they receive the same certificates.
In order to access to incentives, producers must comply with legal and technical regulations governing the quality and certification of the produced biomethane, verified by the competent Authority (Gestore dei Servizi Energetici SpA, GSE).
These measures aim to favor advanced biofuels production through the valorization of waste, notably of agricultural and farm/zootechnical waste.
Regarding biomethane, the incentive scheme has been replaced, following approval by the European Commission, by the Ministerial Decree of September 15, 2022. The mechanism consists of an operating aid — in the form of a CfD linked to the market value of natural gas and of the biomethane Guarantee of Origin, auctioned through a competitive procedure — and an investment aid — covering up to 40% of the eligible investment costs and funded by the NRRP. The mechanism differentiates between new facilities and refurbishments and between agro or waste-based facilities. Law 136/2023 introduced an inflation-linked indexation for the base tariffs set by MD September 15, 2022. In every auction, tariffs will be updated following the total inflation accrued between November 2021 and the auction’s opening month.
At the end of 2020, the Ministerial Decree of October 2014 on conditions, criteria and implementation of biofuels (conventional and advanced) obligations for suppliers was modified. Among the novelties, were introduced the increase of the overall 2021 target from 9% to 10% and a new additional target of 0-5% of advanced liquid biofuels to be mandatory blended by each supplier (outside the incentive scheme provided by DM 2018).
Law 238/2021 (European Law 2019-2020) confirmed the GHG saving requirement (6%) previously set for the year 2020 only and revised the calculation methodology for the current 7% maximum threshold for food-and-crop derived biofuels. The law excludes from the calculation fuels based on double counting feedstock.
The Directive (EU) 2018/2001 on the promotion of the use of energy from renewable sources has been transposed with the Legislative Decree No 199/2021. The Decree set new targets for RES penetration in the transport sector (16%) and introduced some innovations in the transport sector’s regulatory framework: (i) palm-oil, PFAD and EFB based fuels cannot contribute to RES targets in the transport sector. However, they can be taken into account if certified as low-ILUC risk (ii) biomethane support schemes — as defined by the Ministerial Decree of March 2, 2018 — have been updated (iii) Recycled Carbon Fuels count as renewable towards the general target, on the basis of the upcoming EU delegated acts and (iv) confirms the use of some wastes as feedstock for the production of biofuels.
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Occupational Health, Safety and Environment Legislation
Our activity is subject to Italian and European legislation on environmental protection and safety in the workplace. Although we carry out our activities in compliance with these laws and regulations, the risk of incurring unforeseen charges, including claims for compensation for damage to property and persons, as well as reputation risk, are inherent in the nature of the activities carried out by us.
In particular, our industrial activities in the hydrocarbon exploration, development, and production sectors and biomethane production are exposed to operational risks related to the chemical and physical characteristics of raw materials and products (e.g., flammability, toxicity, instability) and to technical failures, equipment malfunctions, containment leaks, well accidents, and incidents that can result in events such as explosions, fires, and spills of oil, gas, and other harmful substances. These risks are influenced by the specifics of the territorial areas in which operations are conducted, the complexity of industrial activities, and the objective technical difficulties in carrying out recovery and containment of hydrocarbons or other liquid chemicals spilled into the environment or harmful emissions into the atmosphere, closure and safety operations of damaged wells or production facilities, or in case of uncontrolled release of oil or natural gas from a well or from a biomethane production plant. Severe soil, groundwater, or air pollution caused by operational activity could result in modest oil or other contaminant spills or small gas spills due to lack of maintenance, corroded or obsolete piping or infrastructure, lack of controls, or other factors, which if protracted over time could cause significant damage. For these reasons, activities in the hydrocarbon and biomethane sectors are subject to strict regulations to protect the environment and the health and safety of people, both at the national/local level and through international protocols and conventions.
We may in the future be required to meet compensation obligations arising from the violation of environmental regulations, as well as to incur significant investments to comply with obligations from applicable environmental regulations.
Occupational safety, health and hygiene are kept under control by continuously updating and carrying out legally required inspections.
We are aware that our activities could produce effects that interfere with the protection of occupational health, safety, and the environment and that the same activities could have an impact on the fulfillment of the requirements of workers and other stakeholders.
The working relationship for employees in Italy is regulated by the pertaining collective work agreement, which provides for the basic standard conditions applicable depending on the employee’s level of seniority. Levels of welfare and social security are guaranteed by Italian working regulation. In order to maintain a workplace free of any discrimination and to establishing appropriate measures for health and safety at work, as well as for professional development, equal opportunities and work-life balance, we regularly review the working place conditions and assesses related regulations.
We therefore recognize the proper management of these aspects as a strategic objective. The importance of respecting health, occupational safety and the environment are not considered as mere regulatory compliance, but as dutiful behaviors directed toward respecting the natural and fundamental rights of the individual. In this regard, we are committed to:
| ● | carrying out our activities in compliance with current laws on occupational health and safety prevention, environment and current regulations with impact on quality aspects and voluntarily subscribed standards; |
| ● | promote activities that can directly or indirectly ensure: the protection and preservation of occupational health and safety, the environment, biodiversity and ecosystems, including in the interest of future generations; |
| ● | consider prevention in occupational health and safety and environment a goal of at least equal importance to profitability and productivity; |
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| ● | protect the health and welfare and promote the occupational safety of all persons directly or indirectly involved in its operations; |
| ● | pursue excellence in behavior and continuous improvement in occupational health and safety and accident prevention, in environmental protection and preservation; |
| ● | ensure the centrality of the individual by fostering consultation the participation of workers and other stakeholders and ensure the sharing of experience and knowledge; |
| ● | design, implement and manage each activity taking into account the need to ensure the protection of the health and safety of employees and third parties, the protection of the environment and public safety; |
| ● | promote the use of natural gas in a safe, efficient and environmentally friendly manner; and |
| ● | train staff and exchange information and knowledge, which are considered fundamental tools for achieving health, safety, environmental and public safety objectives, with a view to continuous improvement. |
In view of the above, we intend to pursue the above principles by committing to the following aims:
| ● | manage activities in full compliance with current legislation and signed voluntary standards and agreements as well as national and international best practices, ensuring compliance obligations and assessment of risks and opportunities, consistent with the Code of Ethics, Corporate Model 231 and all HSE Policy regulations; |
| ● | ensure that each worker is aware of, responsible for, and participates in the company’s efforts to manage the aspects of occupational health and safety and environmental protection and quality assurance related to their activities, with the understanding that the responsible behavior of each person is a prerequisite for the success of the entire system; |
| ● | ensure the protection of workers’ health and safety by adopting the most advanced principles, national standards, organizational solutions, adopting safe and healthy working conditions, using materials and equipment with the least risk to health, safety and the environment for the elimination of hazards and minimization of risks, with a view to the prevention of accidents, injuries, occupational diseases and emergency situations; |
| ● | implement every effort in organizational, operational and technological terms to prevent water, air and soil pollution, minimizing, where technically possible, environmental impacts related to the company’s activities, with particular reference to the control of air emissions, water discharges, waste management, energy saving and recovery; |
| ● | support the conservation of natural resources with actions aimed at effective and efficient use of energy, minimizing the consumption of energy, water, and materials, also in the interest of future generations; |
| ● | involve and consult workers, including through their health, safety and environmental representatives; |
| ● | use qualified suppliers and promote their development according to the principles of this policy, committing them to maintain behavior consistent with it even when they operate outside the company; |
| ● | conduct periodic system audits, inspections, audits, and reviews to analyze performance, contextual factors, stakeholder needs, risks and opportunities, objectives, programs, and policy to assess their effectiveness and take consequent action to pursue the goal of continuous improvement; and |
| ● | putting in place actions to prevent any intentional or negligent event that may cause actual or potential harm to persons and tangible and intangible assets of the company. |
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Government Funding and Other Forms of Support
Conventional Natural Gas
Recently, due to the increased importance of energy security, the Italian Government adopted measures to promote domestic production and accelerate the increase of local gas production. An example of this policy is the 2023 Energy Decree (Law Decree 181/2023), which simplified into a single integrated administrative procedure any new concessions, extensions and modifications of existing concessions, the authorizations for production concessions, and the execution and review of environmental assessments. The single integrated administrative procedures target feedback within three months from the date of submission for applicants who have expressed interest in entering into natural gas supply contracts with the Italian government. In addition, Legislative Decree 135/2018, which introduced a plan to limit the areas where E&P activities may be undertaken, was voided by the Rome Administrative Tribunal in February 2024.
Renewable Natural Gas
Increasingly, the security of supply has become critical for the EU and Italy, creating a more favorable regulatory environment for local production of fossil energy, especially gas and renewable energy. The National Recovery and Resilience Plan (NRP), part of the Next Generation Europe program, was launched by the EU to balance the economic and social consequences of the COVID-19 pandemic. For Italy, the PNRR allocated €191.5 billion, including nearly €60 billion earmarked to the energy transition, including the development of biomethane.
Decree 340 of September 15, 2022 implemented new incentives around biomethane. Specifically, that biomethane production will be supported and incentivized through a capital subsidy of up to 40% for the upgrading of existing biogas facilities and the construction of new biomethane facilities, as well as a new 15-year subsidized tariff (price floor). These incentives were further increased by Law 136 on October 9, 2023, to account for cumulative average inflation. Further, DM No. 224, issued in July 2023, expanded the sectors to which Guarantees of Origin can be sold, including industry and heating.
Customers
As of December 31, 2025, we have generated $22.4 million of revenue from sales of natural gas from the Longanesi field and $2.7 million of revenue from sales of electricity. Our customers primarily consists of Shell as well as industrial, power generation and residential customers throughout Italy and into the southern EU, As of December 31, 2024, we generated $1.4 million of revenue from sales of electricity from two renewable gas assets that were purchased in July 2024.
Competition
Conventional Natural Gas
Competition in the Italian E&P industry is limited to a relatively small number of licensed operators. Historically led by the former Italian NOC Eni (who has transformed itself into an international company), the industry over the past approximately ten years has come to be dominated by smaller public and private companies. In the Po Valley, overlapping with AleAnna, direct competitors include Energean PLC, Società Padana Energia, Po Valley Energy, and Pengas Italiana Srl. Royal Dutch Shell and Total remain significant producers of the legacy producing oils fields (principally Val’d Agri and Tempa Rossa in the southern part of the country) but are no longer active in Italian oil and gas exploration activities.
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Renewable Natural Gas
Competition in this rapidly emerging market space is still evolving in Italy. While some private equity groups are beginning to explore Italian renewable natural gas opportunities, the landscape remains fragmented. However, in the recent past, Eni and midstream operator SNAM attempted early entry by acquiring approximately 50 operational anaerobic digesters. Eni has since sought at least partial divestment of these assets and an exit from the biomethane production market in order to focus on other Renewables initiatives. Other major energy firms such as Royal Dutch Shell, BP, and Total have focused their early efforts on attempts to lock up longer-term biomethane marketing agreements but have yet to actively invest in biomethane production operations.
Active investors in the facility acquisition and operations space are principally characterized in two groups: companies such as AleAnna and asset management firms like Goldman Sachs Assets Management and Lazard.
In addition, a number of EPC contractors offer design, construction, and turn-key operations services for biomethane facilities. Examples include IES Biogas (a SNAM company) and BTS Biogas. However, to date, these players have not competed as full owner-operators.
Raw Materials and Suppliers
Conventional Natural Gas
We have access to numerous sources of oilfield supplies and services in Italy, and we will use specific vendors on each project based upon a combination of availability, cost-effectiveness, availability of specific equipment, and performance reputation. Examples of vendors we have used in the past and are likely to use for future operations include:
| Category | Vendors | |
| Drilling rigs and laborers | Pergemine SpA, LP Drilling | |
| Well logging and evaluation | Schlumberger, Baker Hughes | |
| Well casing, cementing and completion services | Schlumberger, Halliburton, Baker Hughes, Weatherford | |
| Drill bits and downhole equipment | Schlumberger, Baker Hughes | |
| Plant engineering and construction | Rosetti Marino, Max Streicher, Italfluid, TESI | |
| Seismic acquisition | Geofizyka Torun, Geotec, Schlumberger, Doland Geophysical | |
| Purchase of existing Seismic | Eni, CGG, Fugro | |
| Seismic processing | Tricon, CGG | |
| Seismic and well log interpretation software | Schlumberger, S&P Global (IHS Markit), GeoSoftware | |
| Well testing | Schlumberger, Dajan, Italfluid, SMAPE |
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Renewable Natural Gas
We have had discussions with, and in some cases, entered into agreements with providers of investment opportunities, project developers, commodity traders for the supply of agricultural waste, bio-digester manufacturers, upgrading facility suppliers, and major marketing groups. Examples of vendors we are currently engaged with include:
| Category | Vendors | |
| Investment opportunities | VLF Srl | |
| Project developers | Renove Srl, MFZ | |
| Commodity traders | Rivecom, HBA, Conages, Biological Care | |
| Bio-digester manufacturers | Rota Srl, Micropower, Corradi e Ghisolfi, BTS | |
| Biomethane upgrading facilities | Prodeval Srl, AB, Nippongases, Nordsol | |
| Marketing groups | Shell Energy Europe, ENI |
Human Capital Resources
As of December 31, 2025, we had nine full-time employees and engaged seven contractors on a part-time basis, and one contractor on a full-time basis. Our workforce is concentrated in Italy (principally in the Rome and Milan areas). The working relationship for employees in Italy is regulated by the pertaining collective work agreement, which provides for the basic standard conditions applicable depending on the employee’s level of seniority. In Italy, levels of welfare and social security are guaranteed. We have a seasoned leadership team with over 100 years of cumulative experience in the conventional and renewables industry. Our employees are a key factor to our strategies, and we are committed to maintaining a workplace free of any discrimination and to establishing appropriate measures for health and safety at work, as well as for professional development, equal opportunities and work-life balance. Our management team places significant focus and attention on matters concerning our human capital assets and is focused on expanding our diversity, enhancing capability development, and succession planning. Accordingly, we regularly review employee development and succession plans for each of our functions to identify and develop our talent pipeline. To date, we have not experienced any work stoppages and consider our relationship with our employees to be in good standing.
Corporate Information and Facilities
AleAnna is a corporation incorporated under the laws of Delaware. Our headquarters is currently in Dallas, Texas, and houses our US-based management team and certain support individuals. Our Italian management team is housed in Rome and Milan, Italy-based offices. Our website is located at www.aleannainc.com.
Leasing our facilities gives us the flexibility to expand or reduce our office space as appropriate. We believe our current facilities are adequate for our current operating needs, and we anticipate that we will have access to other facilities, through future contractual arrangements, for development, testing, and production.
We have completed or partially completed production facilities for conventional natural gas at the Longanesi field (near Lugo, Italy), the Gradizza Field (near Copparo, Italy), and the Trava Field (near Ostellato, Italy). These conventional gas facilities do not require human intervention on a 24/7 basis and thus house no field staff. We have existing facilities and/or land under construction for renewable natural gas at the Campagnatico plant (Tuscany) and, following a successful acquisition, we expect to begin upgrading construction on the Casalino (Fattoria Delle Jersey) plant near Milan.
Legal Proceedings
We do not have any claims, lawsuits or proceedings currently pending against us, individually or in the aggregate. However, from time to time, we may be subject to various claims, lawsuits and other legal and administrative proceedings that may arise in the ordinary course of business. Some of these claims, lawsuits and other proceedings may involve highly complex issues that are subject to substantial uncertainties, and could result in damages, fines, penalties, non-monetary sanctions or relief. We recognize provisions for claims or pending litigation when we determine that an un-favorable outcome is probable and the amount of loss can be reasonably estimated. Due to the inherent uncertain nature of litigation, the ultimate outcome or actual cost of settlement may materially vary from estimates.
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Item 1A. Risk Factors
Any investment in shares of our securities involves a high degree of risk. The following risks and other information in this Form 10-K or incorporated in this Form 10-K by reference, including our consolidated financial statements and related notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” should be read carefully before investing in our securities. However, such risks are not the only ones we face. Additional risks and uncertainties that we are unaware of, or that we currently believe are not material, may also become important factors that adversely affect us. If any of the risks described herein materialize, our business, financial condition and results of operations could be materially and adversely affected. In that case, you may lose all or part of your investment. This Form 10-K is qualified in its entirety by these risk factors.
Risks Related to our Conventional Natural Gas Business and the Conventional Natural Gas Industry
We currently have few producing properties and there is no assurance that we will be able to convert our pending exploration drilling to producing wells. If our assets are not commercially productive of natural gas, any funds spent on exploration and production may be lost.
As of December 31, 2025, many of our properties were not connected to midstream transportation, nor had we engaged service providers or contractors necessary for the productive development of such assets. There is no assurance that we will be able to obtain the midstream transportation or services necessary at economic costs, if at all. We are dependent on establishing sufficient reserves for additional cash flow and a return of our investment. If our properties are not economic, all of the funds that we have invested, or will invest, will be lost.
The development of our estimated PUDs may take longer and may require higher levels of capital expenditure than we currently anticipate. Therefore, our estimated PUDs may not ultimately be developed or produced.
Most of the reserves attributable to our properties are undeveloped. Development of proved undeveloped reserves may take longer and require higher levels of capital expenditure than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the value of our estimated PUDs and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could require us to reclassify our PUDs as unproved reserves.
While we have drilled and tested certain exploration and development wells, we have no history of converting the exploration and development wells to producing natural gas wells and there can be no assurance that we will successfully establish natural gas operations or profitably produce natural gas.
We achieved first production of five drilled and tested wells in the Longanesi field in March 2025, following the installation of the temporary processing facility. The permanent processing facility is expected to be constructed through 2026 and commissioned in 2027. Natural gas exploration and production have a high degree of risk. The future development of a significant portion of our properties will require obtaining permits and may require additional financing. As a result, we are subject to all of the risks associated with establishing new drilling operations and business enterprises, including, among others:
| ● | the need to obtain necessary environmental and other governmental approvals and permits, the timing and conditions of those approvals and permits, and litigation concerning those approvals and permits; |
| ● | the availability and cost of funds to finance the drilling and development of our properties; |
| ● | the timing and cost, which can be considerable, of the supporting infrastructure to our natural gas drilling and production operations; |
| ● | the ability to obtain midstream offtake capacity for our future natural gas production; |
| ● | drainage resulting from the development of offsetting properties from other operators in the area; |
| ● | commodity prices and our ability to find suitable customers for our future production; |
| ● | inflation and potential increases in costs of labor, power, supplies, services and other support; and |
| ● | the availability and retention of executives overseeing our operations and of skilled labor and equipment to support our drilling operations. |
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There is no assurance that our drilling activities will result in the successful production of natural gas. Moreover, there is no assurance that even if we are able to successfully produce natural gas that such production would be economical for commercial production. Natural gas production is dependent upon a number of factors and significantly influenced by the technical skill of our operations personnel involved. The commercial viability of our possible future production is also dependent upon a number of factors which are beyond our control, including the quality of our natural gas, commodity prices, government policies and regulation, and environmental protection requirements. There is no certainty that the expenditures that have been made and may be made in the future by us related to the acquisition and development of our properties will result in commercially viable production and our past and future expenditures may be partially or entirely lost.
Since we are a development-stage company with limited operating history and minimal revenue generation related to the production of natural gas assets, investors have a very limited basis to evaluate our ability to operate profitably as an E&P business.
We face many of the risks commonly encountered by other new businesses, including the lack of an established operating history, need for additional capital and personnel, and competition. There is no assurance that our business will be successful or that we can operate profitably long-term. We may not be able to effectively manage the demands required, such that we may be unable to implement our business plan.
Restrictions on drilling activities intended to protect the environment and the ecosystem may adversely affect our ability to conduct drilling activities areas where we operate.
Natural gas operations in our operating areas may be adversely affected by restrictions on drilling activities designed to protect the environment and the ecosystem. Such restrictions could prohibit drilling in certain areas, require the implementation of expensive mitigation measures or could result in limitations on our exploration and production activities that could have a material adverse impact on our ability to develop and produce our reserves or find new reserves on our undeveloped lands and permits.
In 2015, the Italian government published the Law 208/2015 which prohibited research, prospection and exploitation in waters within a 12-mile limit of the Italian Peninsula. Rockhopper Italia S.p.A., Rockhopper Mediterranean Ltd, and Rockhopper Exploration Plc (collectively, “Rockhopper”), was subsequently denied an application for an offshore production concession which had been pending since 2008. Rockhopper filed a request for arbitration to the International Center for the Settlement of the Investment Disputes (ICSID) against Italian Republic for the latter’s alleged failure to fulfill the legislative and regulatory commitments made in relation to the investments in the Ombrina Mare oil and gas field located off the Italian coast in the Adriatic Sea (ICSID Case no. ARB/17/14). On August 23, 2022, Italy was ordered to pay compensation to Rockhopper for the breach of its obligations. The Italian Republic sought to annul the award, and the related proceeding is still pending at ICSID for the decision of the “ad hoc Committee”. The Italian Republic also filed a request to continue the stay of the enforcement of the award. On April 24, 2023, the “ad hoc Committee” issued a decision on the provisional stay of enforcement of the award, providing that the provisional stay of enforcement is set to be lifted once Rockhopper puts in place relevant escrow arrangements. Similarly, the enactment of a legislative ban on exploration and production could result in indirect expropriation of our investment and assets.
Drilling for and producing natural gas is a high-risk and costly activity with many uncertainties. Our future financial position, cash flows and results of operations depend on the success of our development and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable natural gas production or that we will not recover all or any portion of our investment in drilled wells.
Many factors may curtail, delay or cancel our scheduled drilling projects, or the development schedule, including the following:
| ● | delays imposed by or resulting from compliance with regulatory requirements, including limitations resulting from permitting, emission of greenhouse gases (“GHGs”), and other limitations and regulatory requirements; |
| ● | intervention by local or federal governments or a foreign sovereign, such as appropriation of assets or technology or imposition of a ban on exploration or production activities; |
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| ● | shortages of or delays in obtaining equipment, rigs, materials or qualified personnel; |
| ● | supply chain disruptions or labor shortage impacts; |
| ● | equipment failures, accidents or other unexpected operational events; |
| ● | lack of available capacity on interconnecting transportation pipelines; |
| ● | adverse weather conditions, such as flooding, droughts, freeze-offs, landslides, blizzards and ice storms; |
| ● | exposure to acts of terrorism or military or other armed conflict or political instability in regions that affect our business or operations; |
| ● | issues related to compliance with environmental regulations; |
| ● | environmental hazards; |
| ● | declines in natural gas market prices; |
| ● | limited availability of financing at acceptable terms; |
| ● | ongoing litigation or adverse court rulings; |
| ● | public opposition to our operations; |
| ● | title, surface access, coal mining and right of way issues; and |
| ● | limitations in the market for natural gas. |
In addition, we may become subject to additional laws or regulations issued by federal or state government bodies, which are subject to influence resulting from frequent changes in political party control or changes to political priorities or policies. We may need to adapt compliance strategies and operations to meet new regulatory requirements, which can be costly and time-consuming.
Any of these risks can cause a delay in our development program, or result in substantial financial losses, personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties. Adjustments to our planned development schedule or the development schedule of non-operated wells in which we have a working interest could impact our future sales volume, operating revenues and expenses, per unit metrics and capital expenditures.
We are subject to risks associated with the operation of our wells.
Our business is and will be subject to all of the inherent hazards and risks normally incidental to drilling for, producing, transporting, storing, processing, gathering and compressing natural gas, such as fires, explosions, slips, landslides, blowouts, and well cratering; pipe and other equipment and system failures; delays imposed by, or resulting from, compliance with regulatory requirements; formations with abnormal or unexpected pressures; shortages of, or delays in, obtaining equipment and qualified personnel; adverse weather conditions, such as freeze offs of wells and pipelines due to cold weather; issues related to compliance with environmental regulations; environmental hazards, such as natural gas leaks, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized releases of toxic gases or other pollutants into the environment. We also may face various risks or threats in the future to the operation and security of our or third parties’ facilities and infrastructure, such as processing plants, compressor stations and pipelines. Any of these risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property, equipment and natural resources, pollution or other environmental damage, loss of hydrocarbons, disruptions to our operations, regulatory investigations and penalties, suspension of our operations, repair and remediation costs, and loss of sensitive confidential information. Moreover, in the event that one or more of these hazards occur, there can be no assurance that a response will be adequate to limit or reduce damage. Although we maintain property insurance, there can be no assurance that such coverage will be adequate or will cover any particular incident in the event of a catastrophe or significant disruption of our business, or that we will be able to obtain sufficient insurance coverage in the future.
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We have limited control over the activities on properties we do not operate.
Presently Società Padana Energia (“Padana”) is the operator of the Longanesi field under a Unitized Operating Agreement and other companies in the future may operate some of the properties in which we have an interest. We may also enter into a future joint venture with respect to our properties. Except for mutually agreed governance provisions in the Unitized Operating Agreement, we have limited ability to influence or control the operation or future development of the Longanesi field and potential future non-operated properties including any properties that may be operated shared control joint ventures where we may share control with third parties, including compliance with environmental, safety and other regulations or the amount of capital expenditures that we are required to fund with respect to them. The failure of an operator of our wells or joint venture participant to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues. Our dependence on the operator and other working interest owners, including a joint venture participant, for these projects and our limited ability to influence or control the operation and future development of these properties could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and lead to unexpected future costs.
Our drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of when they are drilled, if at all.
Our management team has specifically identified and scheduled certain well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations (prospects) represent a significant part of our business strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas prices; the availability and cost of capital; drilling and production costs; the availability of drilling services and equipment; drilling results; topography; gathering system and pipeline transportation costs and constraints; regulatory approvals; and other factors. Because of these uncertain factors, we do not know if the drilling locations we have identified will ever be drilled or if we will be able to produce natural gas from these or any other drilling locations.
The amount and timing of actual future natural gas production is difficult to predict and may vary significantly from our estimates, which may reduce our earnings.
Because the rate of production from natural gas wells generally declines as reserves are depleted, our future success depends upon our ability to develop additional reserves that are economic and our failure to do so may reduce our earnings. Our drilling and subsequent maintenance of wells can involve significant risks, including those related to timing, cost overruns and operational efficiency, and these risks can be affected by the availability of capital, leases, rigs, equipment and a qualified work force, as well as weather conditions, natural gas price volatility, regulatory approvals, geology, equipment failure or accidents and other factors. Drilling for natural gas can be unprofitable, not only due to dry wells, but also as a result of productive wells that perform below expectations or that do not produce sufficient revenues to return a profit. Low natural gas prices may further limit the types of reserves that we can develop and produce economically.
Except to the extent that we acquire additional properties containing proved reserves, conduct successful exploration and development activities or otherwise, our proved reserves will decline as reserves are produced. Our future natural gas production, therefore, is highly dependent upon our level of success in acquiring or finding additional reserves that are economically recoverable. We cannot be certain that we will be able to find or acquire and develop additional reserves at an acceptable cost. Without continued successful development or acquisition activities, together with efficient operation of existing wells, our reserves and production, together with associated revenues, will decline as a result of our current reserves being depleted by production.
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Unless we replace our reserves, our reserves and production will naturally decline, which would adversely affect our business, financial condition and results of operations.
Unless we conduct successful development or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our natural gas reserves and production, and therefore our cash flows and income, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations will be adversely affected.
Our proved reserves are estimates that are based on many assumptions that may prove to be inaccurate. Any significant change in these underlying assumptions will greatly affect the quantities and present value of our reserves.
Reserve engineering is a subjective process involving estimates of underground accumulations of natural gas and assumptions concerning future prices, production levels and operating and development costs, some of which are beyond our control. These estimates and assumptions are inherently imprecise, and we may adjust our estimates of proved reserves based on changes in these estimates or assumptions. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Any significant variance from our assumptions could greatly affect our estimates of reserves, the economically recoverable quantities of natural gas, the classifications of reserves based on risk of recovery and estimates of future net cash flows. To the extent we experience a sustained period of reduced commodity prices, there is a risk that a portion of our proved reserves could be deemed uneconomic and no longer be classified as proved. Although we believe our estimates are reasonable, actual production, revenues and costs to develop reserves will likely vary from our estimates and these variances could be material. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of natural gas we ultimately recover being different from our reserve estimates.
The standardized measure of discounted future net cash flows from our proved reserves is not the same as the current market value of our estimated natural gas reserves.
You should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated natural gas reserves. In accordance with SEC requirements, we based the discounted future net cash flows from our proved reserves on the twelve-month unweighted arithmetic average of the first-day-of-the-month price for the preceding 12 months without giving effect to derivative transactions. Actual future net cash flows from our reserves will be affected by factors such as the actual prices we receive for natural gas, the amount, timing and cost of actual production and changes in governmental regulations or taxation. The timing of both our production and our incurrence of expenses in connection with the development and production of natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating the standardized measure may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our operations or the natural gas industry in general.
Natural gas prices are affected by a number of factors beyond our control, including many of which are unknown and cannot be anticipated, and we cannot predict with certainty future potential movements in the price for these commodities.
Our primary business involves the exploration, production and sale of natural gas. Consequently, our revenue, profitability, future rate of growth, liquidity and financial position depend upon the market prices for natural gas in Italy.
The prices for natural gas in Italy have historically been volatile and have been particularly volatile in recent years. We expect commodity price volatility to continue in the future due to macroeconomic uncertainty and geopolitical tensions.
Commodity prices are affected by a number of factors beyond our control, which include:
| ● | weather conditions and seasonal trends; |
| ● | global and regional supply of and demand for natural gas; |
| ● | regulatory constraints on pricing, prevailing prices in the areas in which we operate, and expectations about future commodity prices; |
| ● | new or continuing armed conflicts or hostilities, or acts of terrorism; |
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| ● | national and worldwide economic and political conditions, particularly those in, or affecting, other countries which are significant producers of natural gas; |
| ● | new and competing exploratory finds of natural gas; |
| ● | changes in exports of natural gas producing countries, such as the United States and Russia; |
| ● | the effect of energy conservation efforts; |
| ● | the price, availability and consumer demand for alternative fuels; |
| ● | the availability, proximity, capacity and cost of pipelines, other transportation facilities, and gathering, processing and storage facilities and other factors that result in differentials to benchmark prices; |
| ● | technological advances affecting energy consumption and production; |
| ● | the actions of the Organization of Petroleum Exporting Countries; |
| ● | the level and effect of trading in commodity futures markets, including commodity price speculators and others; |
| ● | the cost of exploring for, developing, producing and transporting natural gas; |
| ● | risks associated with drilling, completion and production operations; and |
| ● | governmental regulations, tariffs and taxes, including environmental and climate change regulation. |
A prolonged period of low natural gas prices may have an adverse effect on our revenue, profitability, future rate of growth, liquidity and financial position.
Prolonged low, and/or significant or extended declines in natural gas prices may adversely affect our revenues, operating income, cash flows, financial projections, and financial position, particularly if we are unable to control our development costs during periods of lower natural gas prices. Declines in prices could also adversely affect our drilling activities and the amount of natural gas that we can produce economically, which may result in our having to make significant downward adjustments to the value of our assets and could cause us to incur non-cash impairment charges to earnings. Reductions in cash flows from lower commodity prices may require us to incur debt or reduce our capital spending, which could reduce our production and our reserves, negatively affecting our future rate of growth.
A financial crisis or deterioration in general economic, business or geopolitical conditions could materially adversely affect our operations and financial condition.
Concerns over global economic conditions, stock market volatility, energy costs, geopolitical issues (including continued hostilities between Russia and Ukraine as well as other conflicts, including in the Middle East), inflation and central bank interest rate fluctuations in response thereto, the availability and cost of credit, and slowing of global economic growth and fears of a recession have contributed and may continue to contribute to increased economic uncertainty and diminished expectations for the global economy. Global economic conditions, geopolitical issues and inflation have and may continue to constrain global and domestic supply chains, which may in the future impact our ability to develop our reserves in accordance with our drilling and completions schedule. Additionally, global economic conditions have a significant impact on commodity prices and any stagnation or deterioration in global economic conditions could result in decreased demand and, thus, lower prices for natural gas. Such uncertainty could also result in higher natural gas prices, which could potentially result in increased inflation worldwide and could negatively impact demand for natural gas.
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Developments related to climate change may expedite a transition away from the use of carbon-intensive sources for energy generation and products derived from certain fossil fuels, which could have a material and adverse effect on us if we are not able to demonstrate that our products align with a low-carbon transition.
Governmental and regulatory bodies, investors, consumers, industry participants and other stakeholders have been increasingly focused on combating the effects of climate change. This focus, together with changes in consumer, industrial and commercial behavior, preferences and attitudes with respect to the generation and consumption of energy, and the use of products manufactured with, or powered by, fossil fuels, has led to, and in the long-term is anticipated to continue to result in, (i) the enactment of climate change-related regulations, policies and initiatives, (ii) technological advances with respect to the generation, transmission, storage and consumption of energy, and (iii) increased consumer, industrial and commercial demand for low-carbon energy sources and products manufactured with, or powered by, demonstrably low carbon-intensive sources. This has in turn led to increased scrutiny over the carbon-intensity of various fossil fuels, including the natural gas we intend to produce and sell. While the EU has identified natural gas as a critical bridging resource in its 2050 climate neutrality pledge, there is no guarantee that perspective will be maintained and if we are not able to demonstrate that our products align with a transition to a low-carbon economy, the demand and prices for our products could be negatively impacted depending on the pace of such transition and potential future demands for low-carbon products. Such developments may also adversely impact, among other things, the availability of third-party services and facilities that we rely on, which may increase our operational costs and adversely affect our ability to successfully carry out our business strategy. Climate change-related developments may also impact the market prices of, or our access to, raw materials such as energy and water and therefore result in increased costs to our business.
Further, there have been efforts in recent years to influence the investment community, including investment advisors, insurance companies, and certain sovereign wealth, pension and endowment funds and other groups, by promoting divestment of fossil fuel equities and pressuring lenders to limit funding and insurance underwriters to limit coverages to companies engaged in the extraction of fossil fuel reserves. Financial institutions may elect in the future to shift some or all of their investment into non-fossil fuel related sectors. There is also a risk that financial institutions may be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Certain investment banks and asset managers based both domestically and internationally have announced that they are adopting climate change guidelines for their banking and investing activities. Institutional lenders who provide financing to energy companies have also become more attentive to sustainable lending practices, and some may elect not to provide traditional energy producers or companies that support such producers with funding. Ultimately, the foregoing factors could make it more difficult to secure funding for exploration and production activities or adversely impact the cost of capital for both us and our customers, and could thereby adversely affect the demand and price of our securities. Limitation of investments in and financings for energy companies could also result in the restriction, delay or cancellation of infrastructure projects and energy production activities.
Our operations have substantial capital requirements, and we may not be able to obtain needed capital or financing on satisfactory terms, or at all.
Our business is capital intensive. We make and expect to continue to make substantial capital expenditures for the development and acquisition of natural gas reserves, as well as related infrastructure. If these projects are undertaken, they may not be completed on schedule, at the budgeted cost or at all. To date, we have invested approximately $250m in the initial development of our properties. While we expect to be able to fund our future growth primarily out of cash currently on our balance sheet, from cash flow from the Longanesi, Trava, and Gradizza developments, and through recycling of cash flow from future developments, we do not have available commitments from debt financing sources. While we are exploring Resource Backed Loan (“RBL”) financing products with several financial institutions, there is no guarantee that such financing will be available to us. We believe that the cash currently on our balance sheet is sufficient, at a minimum, to cover general and administrative expenses and continue operating our revenue-producing assets through at least the end of the first quarter of 2027.Despite first production at Longanesi being achieved in March 2025 and having adequate cash on hand to cover general and administrative expenses and maintain operations, we may be required to curtail discretionary development efforts on Gradizza, Trava, renewable natural gas asset acquisitions, and other conventional prospects. Lower-than-expected cash flow from or an interruption in operations of Longanesi, combined with delays in development of Gradizza, Trava, renewable natural gas asset acquisitions, and other conventional prospects may lead to a deteriorated financial condition, erode potential value due to delays in our discretionary developments, and adversely affect our results of operations.
The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, natural gas prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.
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Our cash flows from operations and access to capital are subject to a number of variables, including:
| ● | our level of proved reserves and production; |
| ● | the level of hydrocarbons we are able to produce from existing wells; |
| ● | our access to, and the cost of accessing, end markets for our production; |
| ● | the prices at which our production is sold; |
| ● | our ability to acquire, locate and produce new reserves; |
| ● | the levels of our operating expenses; and |
| ● | our ability to access the public or private debt and equity capital and lending markets. |
If we are unable to obtain the capital necessary for our planned capital budget or our operations, we could be required to curtail our operations and the development of our properties, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, results of operations and financial position.
Derivative transactions may limit our potential gains and involve other risks.
To manage our exposure to price risk, we may in the future enter into derivative arrangements, utilizing commodity derivatives with respect to a portion of our future production. Such hedges are designed to lock in prices in order to limit volatility and increase the predictability of cash flow. These transactions may be required to the extent we utilize RBL financing in the future and limit our potential gains if natural gas prices rise above the price established by the hedge, and we may be required to post cash collateral or letters of credit with our hedge counterparties to the extent our liability under the derivative contract exceeds specified thresholds, which would negatively impact our liquidity. Derivative transactions may expose us to the risk of financial loss in certain circumstances, including instances in which our production is less than expected or an event materially impacts natural gas prices or the relationship between the hedged price index and the natural gas sales price.
We cannot be certain that any derivative transaction we may enter into will adequately protect us from declines in the prices of natural gas. Furthermore, where we choose not to engage in derivative transactions in the future, we may be more adversely affected by changes in natural gas prices than our competitors who engage in derivative transactions. Lower natural gas prices may also negatively impact our ability to enter into derivative contracts at favorable prices.
Derivative transactions may also expose us to a risk of financial loss if a counterparty fails to perform under a derivative contract or enters bankruptcy or encounters some other similar proceeding or liquidity constraint. In this case, we may not be able to collect all or a significant portion of amounts owed to us by the distressed entity or entities. During periods of falling commodity prices our hedge receivable positions increase, which increases our exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.
Our business and prospects depend significantly on our ability to build our brand and we may not succeed in continuing to establish, maintain, and strengthen our brand, and our brand and reputation could be harmed by negative publicity regarding our company.
Our business and prospects are dependent on our ability to develop, maintain, and strengthen our brand. Promoting and positioning our brand will depend significantly on our ability to execute our business strategies and build market relationships. In addition, we expect that our ability to develop, maintain, and strengthen our brand will also depend heavily on the success of our branding efforts. To promote our brand, we need to incur increased expenses, such as the costs associated with attending trade conferences. Brand promotion activities may not yield increased revenue, and even if they do, the increased revenue may not offset the expenses we incur in building and maintaining our brand and reputation. If we fail to promote and maintain our brand successfully, or if we incur substantial expenses in an unsuccessful attempt to promote and maintain our brand, we may fail to build a market presence and we may fail to be viewed as an attractive investment platform in which case our business and financial condition may be adversely affected.
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We also believe that the protection of our trademark rights is an important factor in protecting our brand and maintaining goodwill. We may be unable to obtain trademark protection for our technologies, logos, slogans and brands, and our existing trademark registrations and applications, and any trademarks that may be used in the future, may not provide us with competitive advantages or distinguish us from those of our competitors. Further, we may not timely or successfully register our trademarks. If we do not adequately protect our rights in our trademarks from infringement and unauthorized use, any goodwill that we have developed in those trademarks could be lost or impaired, which could harm our brand and our business.
Moreover, any negative publicity relating to our employees, current or future partners, our technology, our natural gas, or customers who use our technology or natural gas, or others associated with these parties may also tarnish our own reputation simply by association and may reduce the value of our brand. Additionally, if safety or other incidents or defects in our natural gas pipeline occur or are perceived to have occurred, whether or not such incidents or defects are our fault, we could be subject to adverse publicity, which could be particularly harmful to our business given our limited operating history. Given the popularity of social media, any negative publicity about our products, whether true or not, could quickly proliferate and harm customer and community perceptions and confidence in our brand. Other businesses, including our competitors, may also be incentivized to fund negative campaigns against our company to damage our brand and reputation to further their own purposes. Future customers of our products and services may have similar sensitivities and may be subject to similar public opinion and perception risks. Damage to our brand and reputation may result in difficulty attracting and retaining investors, reduced demand for our products and increased risk of losing market share to our competitors. Any efforts to restore the value of our brand and rebuild our reputation may be costly and may not be successful, and our inability to develop and maintain a strong brand could have an adverse effect on our business, prospects, financial condition, and operating results.
Cyber incidents targeting our digital work environment or other technologies or energy infrastructure may adversely impact our operations.
The natural gas industry has become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications, and the maintenance of our financial and other records has long been dependent upon such technologies. We may depend on this technology to record and store data, estimate quantities of natural gas reserves, analyze and share operating data and communicate internally and externally. Computers and mobile devices control nearly all of the natural gas distribution systems globally, which will be necessary to transport our products to market.
Energy assets might be specific targets of cyber or other security or physical threats, and the continuing armed conflict between Russia and Ukraine and associated economic sanctions on Russia may have increased the likelihood of such threats. We can provide no assurance that we will not suffer such attacks in the future. Deliberate attacks on, or unintentional events affecting, our digital work environment or other technologies and infrastructure, the systems or infrastructure of third parties or the cloud could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in production or delivery of natural gas, difficulty in completing and settling transactions, challenges in maintaining our books and records, communication interruptions, environmental damage, personal injury, property damage, other operational disruptions and third-party liability. Further, as cyber incidents continue to evolve and cyber attackers become more sophisticated, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. The cost to remedy an unintended dissemination of sensitive information or data may be significant. Furthermore, the continuing and evolving threat of cyber-attacks has resulted in increased regulatory focus on prevention. To the extent we face increased regulatory requirements, we may be required to expend significant additional resources to meet such requirements.
The unavailability or high cost of additional drilling rigs, completion services, equipment, supplies, personnel, and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.
The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers, and other professionals in the natural gas industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages or higher costs. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could materially adversely affect our business, results of operations, cash flows and financial position.
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The loss of key personnel could adversely affect our ability to execute our strategic, operational and financial plans.
Our operations are dependent upon key management and technical personnel, and one or more of these individuals could leave our employment. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on us. In addition, the success of our operations will depend, in part, on our ability to identify, attract, develop and retain experienced personnel. There is competition within our industry for experienced technical personnel and certain other professionals, which could increase the costs associated with identifying, attracting and retaining such personnel. If we cannot identify, attract, develop and retain our technical and professional personnel or attract additional experienced technical and professional personnel, our ability to compete in our industry could be harmed.
We will depend on state-owned midstream providers for midstream services, and our failure to obtain and maintain access to the necessary infrastructure to successfully deliver natural gas to market on acceptable terms may adversely affect our earnings, cash flows and results of operations.
Our delivery of natural gas depends upon the availability, proximity and capacity of pipelines, other transportation facilities and gathering and facilities that are state-owned. To the extent these services are delayed or unavailable, we would be unable to realize revenue from wells served by such state-owned infrastructure until suitable arrangements are made to market our production. Access to midstream assets may be unavailable due to market conditions, regulatory constraints or mechanical or other reasons. Further, changes in the Italian Transmission Operator’s Network may have an adverse effect on us. In addition, due to regulatory and economic constraints, construction of new pipelines and building of such infrastructure may occur more slowly. A lack of access to needed infrastructure, or an extended interruption of access to or service from state-owned pipelines and facilities for any reason, including vandalism, terroristic acts, sabotage or cyber-attacks on such pipelines and facilities or service interruptions due to gas quality, could result in adverse consequences to us, such as delays in producing and selling our natural gas.
Unexpected increases in fees related to transportation facilities and providers may negatively impact our financial position or projections.
A significant increase in transportation fees and fuel prices may adversely affect our transportation costs and business. Transportation providers (rail and truck) in some circumstances have limited ability to provide additional resources in times of peak demand. Moreover, the ability of our transportation providers to maintain a staff of qualified personnel is critical to the success of our business. Regulatory requirements and an improvement in the economy could require us to pay higher transportation fees as our transportation providers seek to pass on additional labor costs associated with attracting and retaining personnel.
Failure to protect our intellectual property, inability to enforce our intellectual property rights or loss of our intellectual property rights through costly litigation or administrative proceedings, could adversely affect our ability to compete and our business.
Our success depends in large part on our ability to protect proprietary intellectual property rights for commercially important trade secrets and know-how related to our business including our proprietary seismic imaging and interpretation techniques and our renewable natural gas acquisition pipeline and our ability to defend and enforce intellectual property rights and preserve confidentiality. We must also operate without infringing, misappropriating, or violating the valid and enforceable patents and other intellectual property rights of third parties. We rely on various intellectual property rights, including trade secrets, as well as confidentiality provisions and contractual arrangements, and other forms of statutory protection to protect our proprietary rights. We will be able to protect our proprietary rights from unauthorized use by third parties only to the extent that our proprietary trade secrets, know-how, and technologies are covered by valid and enforceable patents or are effectively maintained as trade secrets. If we do not protect and enforce our intellectual property rights adequately and successfully, our competitive position may suffer, which could have a material adverse effect on our business, prospects, financial condition, and operating results.
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Risks Related to our Renewable Natural Gas Business and the Renewable Natural Gas Industry
Our strategic success and financial results depend on our ability to identify, acquire, develop and operate natural gas plants.
Our renewable natural gas business strategy includes growth primarily through the acquisition and expansion of existing renewable natural gas plants. In particular, we intend to develop and grow our renewable natural gas business through the acquisition of operational anaerobic digesters and their conversion to biomethane plants. This strategy depends on our ability to successfully identify and evaluate acquisition opportunities and complete acquisitions on favorable terms. However, we cannot assure you that we will be able to successfully identify new opportunities or consummate the acquisition of existing renewable natural gas plants, on favorable terms or at all. In addition, we will compete with other companies and private equity sponsors for these opportunities, which may increase our costs or cause us to refrain from making acquisitions at all. If we are unable to successfully identify and consummate future project opportunities or acquisitions of existing plants it will impede our ability to execute our growth strategy.
Our ability to acquire, develop and operate renewable natural gas plants, is subject to various risks, including:
| ● | regulatory changes that affect the value of renewable natural gas, including revisions to government sponsored price floors and any potential inability to qualify or potential disqualification from such programs, which could have a significant effect on the financial performance of the number of potential plants with attractive economics; |
| ● | regulatory changes that imposed restrictions on the type of feedstock we are allowed to use; |
| ● | changes in energy commodity prices, such as natural gas and wholesale electricity prices, which could have a significant effect on our revenues and expenses; |
| ● | changes in pipeline gas quality standards or other regulatory changes that may limit our ability to transport renewable natural gas on pipelines for delivery to third parties or increase the costs of processing renewable natural gas to allow for such deliveries; |
| ● | changes in the broader waste collection industry, including changes affecting the waste collection and biogas potential of the farming industry, which could limit the renewable natural gas resource that we currently target for our plants; |
| ● | substantial construction risks, including the risk of delay, that may arise due to forces outside of our control, including those related to engineering and environmental problems, inclement weather and labor disruptions; |
| ● | in order to construct new commercial and modify existing production facilities, we typically face a potentially lengthy and variable design, fabrication, and construction development cycle that requires resource commitments and may create fluctuations in whether and when revenue is recognized; |
| ● | operating risks and the effect of disruptions on our business, including the effects of weather conditions, catastrophic events such as fires, explosions, earthquakes, droughts and acts of terrorism, and other force majeure events on us, our customers, suppliers, distributors and subcontractors; |
| ● | accidents involving personal injury or the loss of life, as a result of work conditions including, but not limited to, hazardous worksite site conditions and gas exposure; |
| ● | the ability to obtain financing for a project on acceptable terms or at all and the need for substantially more capital than initially budgeted to complete plants and exposure to liabilities as a result of unforeseen environmental, construction, technological or other complications; |
| ● | failures or delays in obtaining desired or necessary land rights, including ownership, leases, easements, zoning rights and building permits; |
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| ● | a decrease in the availability, pricing and timeliness of delivery of raw materials and components necessary for the operation of plants; |
| ● | obtaining and keeping in good standing permits, authorizations and consents from governmental organizations; |
| ● | unknown regulatory changes for renewable natural gas which may increase the transportation cost for delivering under contracts in place; |
| ● | the consent and authorization of local utilities or other energy development off-takers to ensure successful interconnection to energy grids to enable power and gas sales; and |
| ● | difficulties in identifying, obtaining and permitting suitable sites for new plants. |
Any of these factors could prevent us from acquiring, developing, or operating plants, or otherwise adversely affect our business, financial condition and results of operations.
Acquiring existing plants involves numerous risks.
The acquisition of existing renewable natural gas plants or conventional assets involves numerous risks, many of which may be undiscoverable through the due diligence process, including exposure to previously existing liabilities and unanticipated costs associated with the pre-acquisition period; difficulty in integrating the acquired plants into our existing business; and, if the plants are in new markets, the risks of entering markets where we have limited experience, less knowledge of differences in market terms for gas rights agreements and off-take arrangements. While we perform due diligence on prospective acquisitions, we may not be able to discover all potential operational deficiencies in such plants. A failure to achieve the financial returns we expect when we acquire renewable natural gas plants or conventional assets could have a material adverse effect on our ability to implement our growth strategy and, ultimately, our business, financial condition, and results of operations. Risks related to acquiring existing plants, include:
| ● | the acquired companies or assets may not produce as planned or may entail significant unexpected or unbudgeted costs; |
| ● | we may have difficulty integrating the operations and personnel of the acquired companies; |
| ● | key personnel and customers of the acquired companies may terminate their relationships with the acquired companies as a result of or following the acquisition; |
| ● | we may experience additional financial and accounting challenges and complexities in areas such as joint venture accounting, tax planning, and financial reporting; |
| ● | we may incur additional costs and expenses related to complying with additional laws, rules or regulations in new jurisdictions; |
| ● | we may assume or be held liable for risks and liabilities (including for environmental-related costs) as a result of our acquisitions, some of which we may not discover during our due diligence or adequately adjust for in our acquisition arrangements; |
| ● | our ongoing business and management’s attention may be disrupted or diverted by transition or integration issues and the complexity of managing geographically diverse enterprises; |
| ● | we may incur one-time write-offs or restructuring charges in connection with an acquisition; |
| ● | we may acquire goodwill and other intangible assets that are subject to amortization or impairment tests, which could result in future charges to earnings; and |
| ● | we may not be able to realize the expected cash flows or other financial benefits we anticipated. |
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Revenue from any renewable natural gas plants we complete may be adversely affected if there is a decline in public acceptance or support of renewable energy, or regulatory agencies, local communities, or other third parties delay, prevent, or increase the cost of constructing and operating our plants.
Certain persons, associations and groups could oppose renewable energy plants in general or our plants specifically, citing, for example, misuse of water resources, landscape degradation, land use, food scarcity or price increase and harm to the environment. Moreover, regulations may restrict the development of renewable energy plants in certain areas. Biogas production activities (both conventional natural gas and renewable natural gas) are subject to several environmental laws and regulations. The main environmental legislation governing environmental matters for our renewable natural gas developments is the Consolidated Environmental Act issued by Legislative Decree 152/2006.
We are also subject to authorization and permitting procedures which are outlined in Legislative Decree No. 28/2011, which offers three main pathways to permitting:
| 1. | Notification: Used for minor modifications to existing renewable natural gas plants. |
| 2. | Simplified Authorization Procedure (S.A.P.): Applicable to: |
| ● | New plants with a production capacity under 500 standard cubic meters/hour. |
| ● | Converting existing power plants to biomethane production. |
| ● | Expanding existing renewable natural gas plants within certain limits. |
| 3. | Sole Authorization (S.A.): Required for projects outside the scope of S.A.P. |
For S.A., applications are submitted to regional authorities, followed by a service conference involving relevant public bodies. The process typically concludes within 90 days, unless extended for assessments or document reviews. Under S.A.P., applications go to municipalities, with a decision required within 30 days; otherwise, approval is automatic. Recent legislative updates, like Law No. 95 of July 26, 2023, simplify authorization for biomethane projects, focusing on plants up to 500 smc/h, to facilitate faster connection to the national grid. These changes aim to streamline renewable natural gas development across Italy while ensuring environmental compliance.
Thus, in order to develop a renewable energy project, we are typically required to obtain, among other things, environmental impact permits or other authorizations and building permits, which in turn require environmental impact studies to be undertaken and public hearings and comment periods to be held during which any person, association or group may oppose a project. Any such opposition may be taken into account by government officials responsible for granting the relevant permits, which could result in the permits being delayed or not being granted or being granted solely on the condition that we carry out certain corrective measures to the proposed project. Opposition to our plants’ requests for permits or successful challenges or appeals to permits issued for our plants could adversely affect our operating plans.
As a result, renewable energy plants we currently plan to develop or, to the extent applicable, are developing, may not ultimately be authorized or accepted by the local authorities or the local population. For example, the local population could oppose the construction of a renewable energy plant or infrastructure at the local government level, which could in turn lead to the imposition of more restrictive requirements. This type of negative response may lead to legal, public relations or other challenges that could impede our ability to meet our construction targets, achieve commercial operations for a project on schedule, address the changing needs of our plants over time or generate revenues.
If a significant portion of the local population were to mobilize against a renewable energy plant, it may become difficult, or impossible, for us to obtain or retain the required building permits and authorizations. Moreover, such challenges could result in the cancellation or modification of existing authorizations including adoption of additional mitigation requirements or even, in extreme cases, the dismantling of existing renewable energy plants.
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Authorization for the use, construction, and operation of systems and associated transmission facilities on state and local lands will also require the assessment and evaluation of private rights-of-way, and other easements; environmental, agricultural, cultural, recreational, and aesthetic impacts; and the likely mitigation of adverse effects to these and other resources and uses. The inability to obtain the required permits and other state and local approvals, and any excessive delays in obtaining such permits and approvals due, for example, to litigation or third-party appeals, could potentially prevent us from successfully constructing and operating such plants in a timely manner and could result in the potential forfeiture of any deposit we have made with respect to a given project. Moreover, project approvals subject to project modifications and conditions, including mitigation requirements and costs, could affect the financial success of a given project. Changing regulatory requirements and the discovery of unknown site conditions could also adversely affect the financial success of a given project.
A decrease in acceptance of renewable energy plants by local populations, an increase in the number of legal challenges, or an unfavorable outcome of such legal challenges could adversely affect our business, financial condition and results of operations. We may also be subject to labor unavailability due to multiple simultaneous plants in a geographic region. If we are unable to grow and manage the capacity that we expect from our plants in our anticipated timeframe, it could adversely affect our business, financial condition and results of operations.
We may not be fully reimbursed for a portion of our renewable natural gas construction costs or may only receive payment on a delayed basis.
Under a recently implemented Italian renewable natural gas subsidy regime, we expect to be reimbursed for a portion of our capital expenditures related to our renewable natural gas development facilities. Such capital expenditure reimbursements are expected to reduce the amount of equity capital required as we grow our renewable natural gas asset portfolio. We expect to continue incurring significant acquisition and construction costs related to our renewable natural gas business. If policy is altered and such capital expenditure reimbursement subsidies are not available to us, if the timing of such reimbursements is delayed beyond our expectations, or if such expenditures are not reimbursable as we expect, it could significantly affect our cash flows and our development plan.
A prolonged environment of reduced demand for renewable natural gas or renewable electricity could have a material adverse effect on our long-term business prospects, financial condition and results of operations.
Long-term renewable natural gas and renewable electricity prices may fluctuate substantially due to factors outside of our control. The price of electricity can vary significantly for many reasons.
Demand can vary significantly for many reasons, including increases and decreases in generation capacity in our markets; changes in power transmission or fuel transportation capacity constraints or inefficiencies; power supply disruptions; weather conditions; seasonal fluctuations; changes in the demand for power or in patterns of power usage, including the potential development of demand-side management tools and practices; development of new fuels or new technologies for the production of power; and governmental regulations. Further, the amount of power consumed by the electric utility industry is affected primarily by the overall demand for electricity, environmental and other governmental regulations and the price and availability of fuels such as nuclear, coal, natural gas and oil, as well as sources of renewable energy. Slow growth or a long-term reduction in overall demand for energy could have a material adverse effect on our business strategy and could, in turn, have a material adverse effect on our business, financial condition and results of operations.
A policy revision with respect to the Italian government sponsored renewable natural gas floor price and renewable natural gas capital expenditure reimbursements could have a material adverse effect on our long-term business prospects, financial condition and results of operations.
A decline in prices for certain fuels or reduced Italian governmental incentives for renewable energy sources, or renewable natural gas specifically, could also make renewable natural gas less cost-competitive on an overall basis. If the price of alternative energy sources falls, including crude oil, any revenues that we generate from renewable natural gas could decline and we may be unable to produce products that are a commercially viable alternative to alternative energy sources. Further, throughout the central and southern EU (but primarily focused in Italy and Germany), member states’ interest in creating new sources of renewable energy has supported the construction of nearly 10,000 biogas and biomethane production facilities over the past 15 years. However, the Italian government’s financial incentives and subsidies supporting these activities are set to expire in June 2027 absent additional government action and are expected to be replaced by attractive biomethane incentives. Such incentives are designed to bring biomethane into the national pipeline transmission system in order to deliver the gas to higher efficiency, utility-scale, natural gas power generation stations. In order to continue biogas operations, the farms are forced to seek a new use for the product, which will be dominated by conversion to biomethane. To support this conversion, the Italian government has implemented a government-backed biomethane floor price through the end of 2039 of €124 per MWh, equivalent to $37.60 per (103ft3). If pricing of alternative energy sources becomes more favorable or the Italian government revises its energy policy to suspend or halt financial support of renewable natural gas, our business, financial condition and results of operations will be adversely affected.
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We will face competition on the prices we receive for our renewable electricity and for rights to manage or develop renewable natural gas plants.
We will face competition from both conventional and renewable energy companies in connection with the prices that we can obtain for the renewable electricity we sell during the interim period before we complete the conversion of existing plants from electricity generation to renewable natural gas production and that we produce and sell into energy markets at market prices. The prices that these energy companies can offer are dependent on a variety of factors, including their fuel sources, transmission costs, capacity factor, technological advances and their operations and management. If these companies are able to offer their energy at lower prices, this will reduce the prices we are able to obtain in these markets, which could have a material adverse effect on our results of operations. Our competitors may also offer energy solutions at prices below cost, devote significant resources to competing with us or attempt to recruit our key personnel, any of which could improve their competitive positions. In addition, the technologies that we use may be rendered obsolete or uneconomic by technological advances, more efficient and cost-effective processes or entirely different approaches developed by one or more of our competitors or others. Moreover, if the demand for renewable energy increases, new companies may enter the market, and the influx of added competition could pose an increased risk to us.
In the renewable natural gas industry, we believe our primary competitors will be other renewable natural gas companies with existing plants and farm owners that either operate their own renewable natural gas plants or may do so in the future. Increased competition for such plants, equipment, and suppliers may increase the price we pay for the acquisition costs for existing plants or the amount we have to pay farm owners in the form of equity interests or feedstock supply contracts, which may have a material adverse effect on our results of operations. We may also find ourselves competing more frequently with farm owners to the extent they decide to develop their own renewable natural gas plants, which would also reduce the number of opportunities for us to develop new renewable natural gas plants. While we anticipate receiving the subsidized floor price for our renewable natural gas, we may also compete with other renewable natural gas developers for production off-take agreements with existing and potential buyers of renewable natural gas.
Our renewable energy plants may not produce expected levels of output, and the amount of renewable natural gas actually produced at each of our plants will vary over time and, when a farm closes, eventually decline.
Farms contain organic material whose decomposition causes the generation of gas consisting primarily of methane, which renewable natural gas plants use to generate renewable natural gas or renewable electricity, and carbon dioxide. The estimation of renewable natural gas production volume may be inaccurate and can lead to an inexact process and is dependent on many site-specific conditions, including the estimated annual waste volume, composition of waste, weather conditions and the capacity and construction of the farm. Production levels are subject to a number of additional risks, including illness and disease risks in the farm’s agriculture producing the waste feedstock, a failure or wearing out of our or our farm owners’ or operators’ equipment, an inability to find suitable replacement equipment or parts, lower than expected supply or quality of the project’s source of renewable natural gas and faster than expected diminishment of such renewable natural gas supply, or volume disruption in our fuel supply collection system. As a result, the amount of renewable natural gas actually produced by the farm sites from which our production facilities will collect renewable natural gas or the volume of electricity or renewable natural gas generated from those sites may in the future vary from our initial estimates, and those variations may be material.
In addition, the renewable natural gas available to our plants is dependent in part on the actions of other persons, such as farm operators. We may not be able to ensure the responsible management of the farm site by owners and operators, which may result in less feedstock to be used for the production of biomethane. Other events that can result in a reduction in renewable natural gas output include: extreme hot or cold temperatures or excessive rainfall; liquid levels within a farm increasing; oxidation within a farm, which can kill the anaerobic microbes that produce renewable natural gas; and the buildup of sludge. The occurrence of these or any other changes within any of the farms where our production facilities operate could lead to a reduction in the amount of renewable natural gas being available to operate our production facilities, which could have a material adverse effect on our business, financial condition and results of operations.
We will be dependent on contractual arrangements with, and the cooperation of, farm site owners and operators for access to and operations on their sites.
While we expect to own the anaerobic digesters and upgrading units and underlying land on the farm sites in which our plants will operate, we will not own the entirety of farm sites and we may only own equipment and enter into surface or easement leases. Therefore, we may depend on contractual relationships with, and the cooperation of, the farm site owners and operators for our operations. We cannot guarantee that we will be able to renew any feedstock supply contracts that expire in the future on commercial terms that are attractive to us or at all. Any failure to do so, or any other disruption in the relationship with any of the farm operators from whose farm sites our plants reside on, may have a material adverse effect on our business operations, prospects, financial condition and operational results.
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In addition, the ownership interests in the land subject to these easements, leases and rights-of-way may be subject to mortgages securing loans or other liens (such as tax liens) and other easements, lease rights and rights-of-way of third parties that were created prior to our plants’ easements, leases and rights-of-way. As a result, some of our plants’ rights under these easements, leases or rights-of-way may be subject, and subordinate, to the rights of those third parties. In the event we do not own the land underlying our facilities, we may not be able to protect our operating plants against all risks of loss of our rights to use the land on which our plants are located, and any such loss or curtailment of our rights to use the land on which our plants are located and any increase in rent due on such lands could adversely affect our business, financial condition and results of operations.
The financial performance of our business depends upon tax and other governmental incentives for renewable energy generation, any of which could change at any time and such changes may negatively impact our growth strategy.
Our financial performance and growth strategy depend in part on government policies that support renewable generation and enhance the economic viability of owning renewable natural gas or renewable electric assets. If we are unable to utilize government incentives to acquire additional renewable assets in the future, or the terms of such incentives are revised in a manner that is less favorable to us, we may suffer a material adverse effect on our business, financial condition, results of operations and cash flows.
We will rely on both pipeline and electrical interconnection and transmission facilities that we do not own or control and that are subject to transmission constraints within a number of our regions. If these facilities fail to provide us with adequate transmission capacity or have unplanned disruptions, we may be restricted in our ability to deliver electric power and renewable natural gas to our customers and we may either incur additional costs or forego revenues.
We depend on electric interconnection and transmission facilities and gas pipelines owned and operated by others to deliver the energy we generate at our plants to our customers. A failure or delay in the operation or development of these distribution channels or a significant increase in the costs charged by their owners and operators could result in the loss of revenues. Such failures or delays could limit the amount of energy our operating facilities deliver or delay the completion of our construction plants, which may also result in adverse consequences under our gas rights agreements and off-take agreements. Additionally, such failures, delays or increased costs could have a material adverse effect on our business, financial condition and results of operations.
Increased attention to environmental, social, and governance (“ESG”) matters may adversely impact our business.
Investor advocacy groups, certain institutional investors, investment funds and other influential investors have in the past increased attention to climate change, circular economy, and other ESG matters, as well as investor and societal expectations regarding voluntary ESG disclosures and consumer expectations regarding sustainability may result in increased costs, reduced demand for our products, or other adverse impacts on our business, results of operations, and financial condition. For example, renewable natural gas faces competition from several other low-carbon energy technologies, such as solar or wind energy production, among others. Regulatory bodies may adopt rules that substantially favor certain energy alternatives over others, which may not always include renewable natural gas. Additionally, energy generation from the combustion of renewable natural gas results in GHG emissions. Fines, carbon taxes, or additional infrastructure to control methane emissions at both our conventional and renewable natural gas facilities may increase our costs. As such, certain consumers may elect not to consider renewable natural gas for their renewable energy or other ESG goals. The trend of increased environmental regulation is not linear and can fluctuate depending on the administration and jurisdiction, even within the same country. For example, at the same time, “anti-ESG” sentiment has recently gained momentum with a number of stakeholders, government entities, regulators and lawmakers. The proposal or enactment of anti-ESG legislation, regulation, policies and enforcement priorities may result in increased scrutiny, reputational risk, lawsuits or market access restrictions. We cannot foresee the potential impact and unintended consequences that future executive actions or the changes in enforcement of existing laws, rules, and orders may have on our business. Though we are closely following developments in this area and changes in the regulatory landscape in the United States and other jurisdictions, we cannot predict with precision or quantify how or when challenges may arise and ultimately impact our business.
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In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and activism around our operations could lead to negative investor sentiment toward us and the renewable natural gas industry and to the diversion of investment capital to other industries, which could have a negative impact on our stock price and our access to and costs of capital. Also, certain institutional lenders may decide not to provide funding to us based on ESG concerns, which could adversely affect our operations, financial condition and access to capital for potential growth plants.
Maintenance, expansion and refurbishment of renewable natural gas facilities involve significant risks that could result in unplanned outages or reduced output.
Our future facilities may require periodic upgrading and improvement. Any unexpected operational or mechanical failure, including failure associated with breakdowns and forced outages, could reduce our facilities’ generating capacity below expected levels and reduce our revenue and cash flows. Unanticipated capital expenditures associated with maintaining, upgrading or repairing our facilities may also reduce profitability. If we make any major modifications to our facilities, such modifications could likely result in substantial additional capital expenditures. We may also choose to re-power, refurbish or upgrade our facilities based on our assessment that such activity will provide adequate financial returns. Such facilities require time for development and capital expenditures before commencement of commercial operations, and key assumptions underpinning a decision to make such an investment may prove incorrect, including assumptions regarding construction costs, timing, available financing and future renewable natural gas and renewable electricity prices. This could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Risks Related to Foreign Operations and Regulatory Matters
Our primary operations are in Italy, making us vulnerable to risks associated with operating in one geographic area and we are subject to political, economic and other uncertainties.
All of our natural gas assets and renewable gas assets are currently located in the country of Italy with risks may include, among other things:
| ● | loss of revenue, property and equipment as a result of hazards such as expropriation, war, insurrection and other political risks; |
| ● | increases in taxes, including VAT taxes and potential future energy tax measures and governmental royalties; |
| ● | renegotiation of contracts with governmental entities; |
| ● | failure of the government to provide necessary permits within the anticipated timeframe, or at all; |
| ● | changes in laws and policies governing operations of foreign-based companies; and |
| ● | currency restrictions and exchange rate fluctuations. |
Our international operations may also be adversely affected by laws and policies of the United States affecting foreign trade and taxation.
Realization of any of these factors could have a material adverse effect on our business, financial condition and results of operations.
We are subject to pricing restrictions enforced by the Italian Regulatory Authority for Energy, Networks and Environment with respect to the residential customers we intend to service.
AleAnna’s businesses are also subject to regulatory risks mainly in Italy’s domestic market. The Italian Regulatory Authority for Energy, Networks and Environment (the “Authority”) is entrusted with certain powers in the matter of natural gas and power pricing. Specifically, the Authority retains a surveillance power on pricing in the natural gas market in Italy and the power to establish selling tariffs for the supply of natural gas to residential and commercial users who are opting for adhering to regulated tariffs until the market is fully opened. Developments in the regulatory framework intended to increase the level of market liquidity or of deregulation or intended to reduce operators’ ability to transfer to customers cost increases in raw materials may negatively affect future sales margins of gas and electricity, operating results, and cash flow.
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All of our natural gas and renewable gas properties are located in the country of Italy, making us vulnerable to risks associated with operating in one geographic area.
While we maintain access to acreage across Italy, all of our physical conventional natural gas assets, and most of our permits, are located in the Po Valley in Northern Italy and all of our current renewable natural gas assets are located in the region of Tuscany in Central Italy. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, appropriation and banning, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of natural gas. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic natural gas producing areas, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. We operate in geographic areas with a constantly evolving political landscape, to the extent regulatory regimes or prohibitions are implemented or return in the areas in which we operate, our business will be disproportionately affected due to our geographic concentration. Due to the concentrated geographic nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Additionally, we do not hold title to our properties, but hold exploration permits and exploitation concessions granted by the Italian government. Under Italian law, each exploration permit is an exclusive right to explore for hydrocarbons and is subject to two renewals of three years each, being granted after the initial term of six years (article 6, paragraph 4, of Law 9/1991). To the extent we are unable to timely renew or obtain permits, our operations could be delayed or interrupted. Such delays or interruptions could have a material adverse effect on our business, financial condition and results of operations.
We currently have global operations, including in Italy, which subjects us to additional anti-corruption, anti-bribery, anti-money laundering, trade compliance, economic sanctions and similar laws, and non-compliance with such laws may subject us to criminal or civil liability and harm our business, financial condition and/or results of operations. We may also be subject to governmental export and import controls that could impair our ability to compete in international markets or subject us to liability if we violate the controls.
We currently have global operations, including in Italy, which subjects to the U.S. Foreign Corrupt Practices Act of 1977, as amended, U.S. domestic bribery laws, and other anti-corruption and anti-money laundering laws in the countries in which we conduct business. Anti-corruption and anti-bribery laws have been enforced aggressively in recent years and are interpreted broadly to generally prohibit companies, their employees, and their third-party intermediaries from authorizing, offering, or providing, directly or indirectly, improper payments or benefits to recipients in the public or private sector. If we engage in international operations, sales and business with partners and third-party intermediaries to market our products, we may be required to obtain additional permits, licenses, and other regulatory approvals. In addition, we or our third-party intermediaries may have direct or indirect interactions with officials and employees of government agencies or state-owned or affiliated entities. If third-party intermediaries, or our employees, agents, representatives, contractors, or partners engage in violations while engaging in business on behalf of the Company, we may be subject to criminal or civil liability, even if we do not authorize such activities.
Our results of operations, financial condition and cash flows could be adversely affected by changes in currency exchange rates.
We are exposed to foreign currency risk from our foreign operations. A weakening U.S. dollar will have the effect of increasing costs, while a strengthening U.S. dollar will have the effect of reducing operating costs. The exchange rate between the Euro and the U.S. dollar has fluctuated in recent years in response to international political conditions, general economic conditions, and other factors beyond our control. Our financial statements, presented in U.S. dollars, may be affected by foreign currency fluctuations through both translation risk and transaction risk.
We do not currently utilize derivative instruments to manage these foreign currency risks. As a result, our consolidated earnings and cash flows may be impacted by movements in the exchange rates.
Our business may be affected by changes in applicable sanctions or export controls laws and regulations. Similarly, significant changes or developments in U.S. laws or policies, including changes in U.S. trade policies and tariffs and the reaction of other countries thereto, may have a material adverse effect on our business and financial statements.
Our international operations expose us to compliance obligations and risks under applicable economic sanctions, export controls and trade embargoes, such as those imposed, administered and enforced by the United States and the United Kingdom and other relevant sanctions authorities. In response to ongoing military hostilities between Russia and Ukraine, the United States, the United Kingdom, the European Union, and other jurisdictions imposed new and additional economic sanctions, export controls and other trade restrictions targeting Russia, Belarus and certain regions of Ukraine, including measures that impose: (i) restrictions on engaging in specified activities or transactions, or any and all activities and transactions, with, involving or for the benefit of certain designated Russian and Belarusian entities or individuals; (ii) a specific prohibition on new investment in the Russian energy sector, broadly defined to include the procurement, exploration, extraction, drilling, mining, harvesting, production, refinement, liquefaction, gasification, regasification, conversion, enrichment, fabrication or transport of petroleum, natural gas, liquified natural gas, natural gas liquids, or petroleum products or other products capable of producing energy; and (iii) a broad prohibition on new investment in Russia.
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Additionally, the ongoing conflicts in the Middle East, the political, economic and social instability in Venezuela and the Russian invasion of Ukraine and related sanctions have collectively disrupted supply chains for crude oil and natural gas in certain of the markets in which we operate. The Russia-Ukraine conflict and other geopolitical tensions, as well as the related international response, have exacerbated global supply chain disruptions, which have resulted in, and may continue to result in, shortages in materials and services and related uncertainties. Such shortages have resulted in, and may continue to result in, cost increases for labor, fuel, materials and services, and could continue to cause costs to increase and also result in the scarcity of certain materials. Any economic slowdown or recession in Europe or globally, including as a result of such supply chain disruptions or sanctions, may also impact demand and depress the price for crude oil, natural gas or other products, which could have significant adverse consequences on our financial condition and the financial condition of our customers, suppliers and other counterparties, and could diminish our liquidity. Further, the ongoing conflicts in the Middle East and political, economic and social instability in Venezuela could escalate into broader conflicts or greater economic and social instability that could further disrupt energy operations and supply chains globally.
Significant changes or developments in U.S. laws and policies, such as laws and policies surrounding international trade, foreign affairs, manufacturing and development and investment in the territories and countries where we, our customers or suppliers operate, can materially adversely affect our business and financial statements. The adoption or expansion of tariffs in the future, the occurrence of a trade war, or other governmental action related to tariffs, trade agreements or related policies may have a material adverse effect on our supply chain and access to equipment, our costs and profit margins. This could cause our business and financial results to suffer.
Our results of operations, financial condition and cash flows could be adversely affected by changes in environmental laws and regulations.
Our operations must comply with intensive environmental laws and regulations. Increased regulation of environmental matters and the need to obtain stricter environmental local and governmental approvals and permits, might increase operational costs and timing and conditions of those approvals and permits.
Increased environmental standards, issues related to compliance with environmental regulations and decreased subsidies programs may curtail, delay or cancel our scheduled projects, or the development schedule.
Our business is and will be subject to issues related to compliance with environmental regulations, to environmental hazards, such as biomethane plant leaks, pipeline and tank ruptures, and unauthorized releases of toxic gases or other pollutants into the environment. Any of these risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property, equipment and natural resources, pollution or other environmental damage, disruptions to our operations, regulatory investigations and penalties, suspension of our operations, repair and remediation costs.
Risks Relating to our Organizational Structure, our Class A Common Stock and Public Warrants
We are a holding company and our organizational structure is what is commonly referred to as an Up-C structure, whereby all of the equity interests in AleAnna Energy are held by HoldCo and our sole material asset is our equity interest in HoldCo and we are accordingly dependent upon distributions from HoldCo to pay taxes and cover our corporate and other overhead expenses.
We are a holding company and have no material assets other than our equity interest in HoldCo. We have no independent means of generating revenue. To the extent that we need funds and HoldCo or its subsidiaries are restricted from making such distributions under applicable law or regulation or under the terms of any financing or other contractual arrangements, or are otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition. If HoldCo does not distribute sufficient funds to us to pay our taxes or other liabilities, we may default on contractual obligations or have to borrow additional funds. In the event that we are required to borrow additional funds, it could adversely affect our liquidity and expose us to additional restrictions imposed by lenders.
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We anticipate that the distributions received from HoldCo may, in certain periods, exceed its actual tax liabilities and other financial obligations. Our Board of Directors (the “Board”), in its sole discretion, will make any determination from time to time with respect to the use of any such excess cash so accumulated. We will have no obligation to distribute such cash (or other available cash other than any declared dividend) to our stockholders.
In addition, the up-C structure confers certain benefits upon the members of HoldCo that will not benefit the holders of our Class A Common Stock to the same extent as it will benefit the HoldCo members. If HoldCo makes distributions to us, the HoldCo members will be entitled to receive equivalent distributions from HoldCo on a pro rata basis. However, because we must pay taxes, amounts ultimately distributed as dividends, if any in the future, to holders of our Class A Common Stock are expected to be less on a per share basis than the amounts distributed by HoldCo to its members on a per unit basis. This and other aspects of the up-C structure may adversely impact the trading market for your Class A Common Stock.
If HoldCo were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, we and HoldCo might be subject to potentially significant tax inefficiencies.
We intend to operate such that HoldCo does not become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes. A “publicly traded partnership” is a partnership the interests of which are traded on an established securities market or are readily tradable on a secondary market or the substantial equivalent thereof. Under certain circumstances, the exchange of units of Class C HoldCo Units pursuant to (i) a holder’s right to exchange all or a portion of its Class C HoldCo Units, together with an equal number of Class C Common Stock, for shares of Class A Common Stock (the “ HoldCo Holder Redemption Right”) or (ii) the right of HoldCo upon a change of control of HoldCo or in the discretion of AleAnna with the consent of 50% of the holders of Class C HoldCo Units, to cause the exchange of all of the outstanding Class C HoldCo Units and an equal number of Class C Common Stock for shares of Class A Common Stock (a “Mandatory Exchange”) or (iii) other transfers of Class C HoldCo Units could cause HoldCo to be treated as a publicly traded partnership. Applicable U.S. Treasury regulations provide for certain safe harbors from treatment as a publicly traded partnership, and we intend to operate such that redemptions or other transfers of Class C HoldCo Units qualify for one or more of such safe harbors. For example, we limited the number of holders of Class C HoldCo Units, and the limited liability company agreement of HoldCo (the “A&R HoldCo LLC Agreement”), provides for certain limitations on the ability of holders of Class C HoldCo Units to transfer their Class C HoldCo Units and provides us, as the manager of HoldCo, with the right to prohibit the exercise of a HoldCo Holder Redemption Right if it determines (based on the advice of counsel) there is a material risk that HoldCo would be a publicly traded partnership as a result of such exercise.
If HoldCo were to become a publicly traded partnership taxable as a corporation for U.S. federal income tax purposes, significant tax inefficiencies might result for us and for HoldCo, including as a result of our inability to file a consolidated U.S. federal income tax return with HoldCo.
In certain circumstances, HoldCo is required to make tax distributions to the HoldCo unitholders, including us, and the tax distributions that HoldCo is required to make may be substantial. The HoldCo tax distribution requirement may complicate our ability to maintain our intended capital structure.
In certain circumstances, HoldCo may be required to make quarterly tax distributions to the HoldCo unitholders, including us. Such distributions are to be made pro rata and in an amount sufficient to cause each HoldCo unitholder to receive a distribution at least equal to such HoldCo unitholder’s allocable share of net taxable income (in the case of each HoldCo unitholder other than us, taking into account prior normal operating pro rata distributions made to such HoldCo unitholders in such year and calculated under certain assumptions) multiplied by an assumed tax rate. The assumed tax rate for this purpose will be the combined maximum U.S. federal, state, and local rate of tax applicable to us for the applicable taxable year unless otherwise determined by HoldCo. As a result of certain assumptions in calculating the tax distribution payments, we may receive tax distributions from HoldCo in excess of its actual tax liability.
The receipt of such excess distributions would complicate our ability to maintain certain aspects of our capital structure. Such cash, if retained, could cause the value of a Class C HoldCo Unit to deviate from the value of a share of Class A Common Stock. If we retain such cash balances, the holders of Class C HoldCo Units would benefit from any value attributable to such accumulated cash balances as a result of their exercise of the HoldCo Holder Redemption Right or a Mandatory Exchange. We intend to take steps to eliminate any material cash balances. Such steps could include distributing such cash balances as dividends on our Class A Common Stock and reinvesting such cash balances in HoldCo for additional Class C HoldCo Units (with an accompanying stock dividend with respect to our Class A Common Stock or an adjustment to the one-to-one exchange ratio applicable to the exercise of the HoldCo Holder Redemption Right or a Mandatory Exchange).
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The tax distributions to the HoldCo unitholders may be substantial and may, in the aggregate, exceed the amount of taxes that HoldCo would have paid if it were a similarly situated corporate taxpayer. Funds used by HoldCo to satisfy its tax distribution obligations will generally not be available for reinvestment in its business.
If we cannot meet the continued listing requirements of The Nasdaq Capital Market (“Nasdaq”), Nasdaq may delist our securities.
As a public company, we are subject to the reporting requirements and the rules and regulations of the applicable listing standards of Nasdaq. If we fail to maintain compliance with the continued listing standards of Nasdaq, our securities may be delisted, which could negatively affect the market price and liquidity of our Class A Common Stock. In such case, we may seek to regain compliance by implementing a number of available options, including implementation of a reverse stock split to regain compliance with the Nasdaq’s minimum bid price requirement.
Volatility in the stock market may prevent investors from selling their securities at or above the price they paid for the shares.
The stock market is known for its volatility, and the market price of our securities may fluctuate significantly due to a number of factors that are both under our control and beyond our control. These factors include, among others, variations in our operating results, changes in expectations of future financial performance or changes in estimates of securities analysts, changes in the operating and stock price performance of other companies that investors deem comparable to us, and news reports relating to trends in our markets or general economic conditions. As a result, investors might not be able to sell their shares at or above the price they paid, which may result in substantial losses to the investor.
We are controlled by Nautilus, whose interests may conflict with ours and the interests of other stockholders.
Nautilus holds 84.85% of the voting power of AleAnna. Nautilus has the ability to determine all corporate actions requiring stockholder approval, including the election and removal of directors and the size of the Board, any amendment to our Certificate of Incorporation (the “Certificate of Incorporation”) or our Bylaws (the “Bylaws”), or the approval of any merger or other significant corporate transaction, including a sale of substantially all of our assets. This could have the effect of delaying or preventing a change in control or otherwise discouraging a potential acquirer from attempting to obtain control of us, which could cause the market price of our Class A Common Stock to decline or prevent stockholders from realizing a premium over the market price for our Class A Common Stock. The interests of Nautilus may conflict with our interests as a company or the interests of our other stockholders.
We are a “controlled company” within the meaning of Nasdaq Capital Market rules and, as a result, qualify for exemptions from certain corporate governance requirements, and as a result, you will not have the same protections afforded to stockholders of companies that are not exempt from such corporate governance requirements.
Over 50% of our voting power for the election of directors is held by Nautilus. As a result, we are a controlled company within the meaning of Nasdaq Capital Market corporate governance standards. Under Nasdaq Capital Market rules, a controlled company may elect not to comply with certain Nasdaq corporate governance requirements, including the requirements that:
| ● | a majority of the Board consist of independent directors under Nasdaq Capital Market rules; |
| ● | the nominating and governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and |
| ● | the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities. |
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These requirements will not apply to us as long as we remain a controlled company. We may utilize some or all of these exemptions. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of Nasdaq Capital Market.
The market price of our Class A Common Stock could be adversely affected by sales of substantial amounts of our Class A Common Stock in the public or private markets or the perception in the public markets that these sales may occur, including sales by the members of AleAnna Energy after the redemption of any Class C HoldCo Units, together with an equal number of our Class C Common Stock, in exchange for shares of our Class A Common Stock, or other large holders.
We have provided registration rights to certain large stockholders, including Nautilus, pursuant to the A&R Registration Rights Agreement (as defined herein). Sales of shares of our Class A Common Stock by Nautilus, including after the redemption of any Class C HoldCo Units, together with the cancellation of an equal number of our Class C Common Stock, for shares of our Class A Common Stock, or by other large holders of a substantial number of shares of our Class A Common Stock in the public markets following the business combination, or the perception that such sales might occur, could have a material adverse effect on the price of our Class A Common Stock or could impair our ability to obtain capital through an offering of equity securities in the future. Approximately 63,922,582 shares of Class A Common Stock are subject to registration rights in the Registration Rights Agreement.
Future sales and issuances of our Class A Common Stock could result in additional dilution of the percentage ownership of our stockholders and could cause our share price to fall.
We expect that additional capital may be needed in the future to pursue our growth plan. Particularly if natural gas prices negatively diverge from current levels or if our expectations around capital expenditure and operating costs are incorrect. To raise capital, we may sell shares of our Class A Common Stock, convertible securities or other equity securities in one or more transactions at prices and in a manner we determine from time to time. If we sell shares of our Class A Common Stock, convertible securities or other equity securities, investors may be materially diluted by subsequent sales. Such sales may also result in material dilution to our existing stockholders, and new investors could gain rights, preferences, and privileges senior to existing holders of our Class A Common Stock.
If our estimates or judgments relating to our critical accounting policies prove to be incorrect or financial reporting standards or interpretations change, our operating results could be adversely affected.
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates, judgments, and assumptions that affect the amounts reported in our financial statements and accompanying notes. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances. The results of these estimates form the basis for making judgments about the carrying values of assets, liabilities, and equity as of the date of the financial statements, and the amount of revenue and expenses, during the periods presented, that are not readily apparent from other sources. Significant assumptions and estimates used in preparing our financial statements include those related to impairment of intangible and long-lived assets, and share-based compensation. Our operating results may be adversely affected if our assumptions change or if actual circumstances differ from those in our assumptions, which could cause our operating results to fall below the expectations of industry or financial analysts and investors, resulting in a decline in the trading price of our Class A Common Stock.
Additionally, we regularly monitor our compliance with applicable financial reporting standards and review new pronouncements and drafts thereof that are relevant to us. As a result of new standards, changes to existing standards, and changes in interpretation, we might be required to change our accounting policies, alter our operational policies, or implement new or enhance existing systems so that they reflect new or amended financial reporting standards, or we may be required to restate our published financial statements. Changes to existing standards or changes in their interpretation may have an adverse effect on our reputation, business, financial position, and profit, or cause an adverse deviation from our revenue and operating profit target, which may negatively impact our financial results.
We have identified material weaknesses in our internal control over financial reporting. If we are unable to develop and maintain an effective system of internal control over financial reporting, we may not be able to accurately report the Company’s financial results in a timely manner, which may adversely affect investor confidence in us and materially and adversely affect our business and operating results, and we may face litigation as a result.
Effective internal controls are necessary to provide reliable financial reports and prevent fraud. We are a relatively new public company that is in the process of adding resources with the appropriate level of experience and technical expertise to oversee our business processes and controls. Despite significant progress made in 2025, at this time, we do not have the necessary business processes and related internal controls formally designed and implemented.
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As a result, in connection with the preparation of our financial statements as of and for the year ended December 31, 2025, our management identified material weaknesses in its internal control over financial reporting.
A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of annual or interim financial statements would not be prevented or detected on a timely basis.
Effective internal controls are necessary to provide reliable financial reports and prevent fraud, and material weaknesses could limit the ability to prevent or detect a misstatement of accounts or disclosures that could result in a material misstatement of annual or interim financial statements. We have made significant progress on designing and implementing a plan to remediate the material weaknesses identified. Our plan includes the below:
| ● | Designing and implementing a risk assessment process supporting the identification of risks facing us. |
| ● | Implementing controls to enhance our review of significant accounting transactions and other new technical accounting and financial reporting issues and preparing and reviewing accounting memoranda addressing these issues. |
| ● | Hiring additional experienced accounting, financial reporting and internal control personnel and changing roles and responsibilities of our personnel as we transition to being a public company and are required to comply with Section 404 of the Sarbanes-Oxley Act. |
| ● | Implementing controls to enable an accurate and timely review of accounting records that support our accounting processes and maintain documents for internal accounting reviews. |
We cannot assure you that these measures will remediate the material weaknesses described above. The implementation of these remediation measures is in progress and will require further validation and testing of the design and operating effectiveness of the Company’s internal controls over a sustained period of financial reporting cycles and, as a result, the timing of when the Company will be able to remediate the material weaknesses is uncertain and the Company may not remediate these material weaknesses during the year ended December 31, 2026. If the steps the Company takes do not remediate the material weaknesses in a timely manner, there could be a reasonable possibility that these control deficiencies or others may result in a material misstatement of its annual or interim financial statements that would not be prevented or detected on a timely basis. This, in turn, could jeopardize the Company’s ability to comply with its reporting obligations, limit its ability to access the capital markets and adversely impact its stock price.
As a result of becoming a public company, we are required to develop and maintain proper and effective internal control over financial reporting in order to comply with Section 404 of the Sarbanes-Oxley Act. We may not complete our analysis of our internal control over financial reporting in a timely manner, or these internal controls may not be determined to be effective, which may adversely affect investor confidence in us and, as a result, the value of our Class A Common Stock. In addition, because of our status as an emerging growth company, you will not be able to depend on any attestation from our independent registered public accountants as to our internal control over financial reporting for the foreseeable future.
We are required by Section 404 of the Sarbanes-Oxley Act to furnish a report by management on, among other things, the effectiveness of our internal control over financial reporting. The process of designing and implementing internal control over financial reporting required to comply with this requirement will be time-consuming, costly and complicated. If during the evaluation and testing process we identify one or more other material weaknesses in our internal control over financial reporting our management will be unable to assert that our internal control over financial reporting is effective. In addition, if we fail to achieve and maintain the adequacy of our internal controls, as such standards are modified, supplemented or amended from time to time, we may not be able to ensure that we can conclude on an ongoing basis that we have effective internal controls over financial reporting in accordance with Section 404 of the Sarbanes-Oxley Act.
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In addition, our independent registered public accounting firm will not be required to attest formally to the effectiveness of our internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act for as long as we qualify for scaled “smaller reporting company” disclosure under the Exchange Act. Accordingly, you will not be able to depend on any attestation concerning our internal control over financial reporting from our independent registered public accountants for the foreseeable future.
We cannot be certain as to the timing of completion of our evaluation, testing and any remediation actions or the impact of the same on our operations. If we are not able to implement the requirements of Section 404 of the Sarbanes-Oxley Act in a timely manner or with adequate compliance. As a result, there could be a negative reaction in the financial markets due to a loss of confidence in the reliability of our financial statements. In addition, we may be required to incur costs in improving our internal control system and the hiring of additional personnel. Any such action could negatively affect our results of operations and cash flows.
We do not have extensive experience operating as a public company subject to U.S. federal securities laws and may not be able to adequately develop and implement the governance, compliance, risk management and control infrastructure and culture required for a public company, including compliance with the Sarbanes-Oxley Act.
We do not have extensive experience operating as a public company subject to U.S. federal securities laws. Our failure to comply with all applicable laws, rules and regulations could subject us to U.S. regulatory scrutiny or sanction, which could harm our reputation and share price.
AleAnna has not previously been required to establish and maintain the disclosure controls and procedures, and internal control over financial reporting applicable to a public company under U.S. federal securities laws, including the Sarbanes-Oxley Act. We may experience errors, mistakes and lapses in processes and controls, resulting in failure to meet requisite U.S. standards.
As a public company subject to U.S. federal securities laws, we will incur significant legal, accounting, insurance, compliance, and other expenses. Compliance with reporting, internal control over financial reporting and corporate governance obligations may require members of our management and our finance and accounting staff to divert time and resources from other responsibilities to ensure these new regulatory requirements are fulfilled.
If we fail to adequately implement the required governance and control framework, we may fail to comply with the applicable rules or requirements associated with being a public company subject to U.S. federal securities laws. Such failure could result in the loss of investor confidence, could harm our reputation, and cause the market price of our Class A Common Stock, and any other securities it may list in the future, to decline.
Due to inadequate governance and internal control policies, misstatements or omissions due to error or fraud may occur and may not be detected, which could result in failures to make required filings in a timely manner or result in making filings containing incorrect or misleading information. Any of these outcomes could result in SEC enforcement actions, monetary fines or other penalties, as well as damage to our reputation, business, financial condition, operating results and share price.
The JOBS Act permits “emerging growth companies” like us to take advantage of certain exemptions from various reporting requirements applicable to other public companies that are not emerging growth companies.
We qualify as an “emerging growth company” as defined in Section 2(a)(19) of the Securities Act of 1933, as amended (the “Securities Act”), as modified by the JOBS Act. As such, we take advantage of certain exemptions from various reporting requirements applicable to other public companies that are not emerging growth companies, including (i) the exemption from the auditor attestation requirements with respect to internal control over financial reporting under Section 404 of the Sarbanes-Oxley Act, (ii) the exemptions from say-on-pay, say-on-frequency and say-on-golden parachute voting requirements and (iii) reduced disclosure obligations regarding executive compensation in our periodic reports and registration statements. As a result, our stockholders may not have access to certain information they deem important. We will remain an emerging growth company until the earliest of (i) the last day of the fiscal year (a) following the fifth anniversary of the closing of SPAC’s IPO, which is December 14, 2021, (b) in which we have total annual gross revenue of at least $1.235 billion, or (c) in which we are deemed to be a large accelerated filer, which means the market value of our common equity that is held by non-affiliates exceeds $700 million as of the end of the prior fiscal year’s second fiscal quarter; and (ii) the date on which we have issued more than $1.00 billion in non-convertible debt securities during the prior three-year period. References herein to “emerging growth company” shall have the meaning associated with it in the JOBS Act.
In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the exemption from complying with new or revised accounting standards provided in Section 7(a)(2)(B) of the Securities Act as long as we are an emerging growth company. An emerging growth company can therefore delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. The JOBS Act provides that a company can elect to opt out of the extended transition period and comply with the requirements that apply to non-emerging growth companies, but any such election to opt out is irrevocable. We have elected not to irrevocably opt out of such extended transition period, which means that when a standard is issued or revised and it has different application dates for public or private companies, we may adopt the new or revised standard at the time public companies adopt the new or revised standard.
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Because we have no current plans to pay regular cash dividends on our Class A Common Stock, you may not receive any return on investment unless you sell your Class A Common Stock for a price greater than that which you paid for it.
We do not anticipate paying any regular cash dividends on our Class A Common. Any decision to declare and pay dividends in the future will be made at the discretion of our Board and will depend on, among other things, our results of operations, financial condition, cash requirements, contractual restrictions and other factors that our Board may deem relevant. In addition, our ability to pay dividends may in the future be limited by covenants of existing and any future outstanding indebtedness we or our subsidiaries incur. Therefore, any return on investment in our Class A Common Stock is solely dependent upon the appreciation of the price of our Class A Common Stock on the open market, which may not occur.
If securities or industry analysts do not publish or cease publishing research or reports about us, our business or our market, or if they change their recommendations regarding our Class A Common Stock adversely, the price and trading volume of our Class A Common Stock could decline.
The trading market for our shares of our Class A Common Stock will be influenced by the research and reports that industry or securities analysts may publish about us, our business, our market or our competitors. If any of the analysts who may cover us change their recommendation regarding our stock adversely, or provide more favorable relative recommendations about our competitors, the price of our shares of our Class A Common Stock would likely decline. If any analyst who may cover us were to cease their coverage or fail to regularly publish reports on us, we could lose visibility in the financial markets, which could cause our stock price or trading volume to decline.
Our Certificate of Incorporation designates the Court of Chancery of the State of Delaware as the exclusive forum for certain litigation that may be initiated by our shareholders, which could limit our shareholders’ ability to obtain a favorable judicial forum for disputes with us.
Pursuant to our Certificate of Incorporation, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware will be the sole and exclusive forum for (i) any derivative action or proceeding brought on behalf of us, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action or proceeding asserting a claim against us arising pursuant to any provision of the Delaware General Corporation Law (“DGCL”) or the Certificate of Incorporation or our Bylaws, (iv) any action to interpret, apply, enforce or determine the validity of the our Certificate of Incorporation or our Bylaws or (v) any action or proceeding asserting a claim against us governed by the internal affairs doctrine, in each case subject to said Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. The forgoing provisions will not apply to any claims arising under the Exchange Act or the Securities Act and, unless we consent in writing to the selection of an alternative forum, the federal district courts of the United States of America will be the sole and exclusive forum for resolving any action asserting a claim arising under the Securities Act.
This choice of forum provision in our Certificate of Incorporation may limit a shareholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or any of our directors, officers, or other employees, which may discourage lawsuits with respect to such claims. There is uncertainty as to whether a court would enforce such provisions, and the enforceability of similar choice of forum provisions in other companies’ charter documents has been challenged in legal proceedings. It is possible that a court could find these types of provisions to be inapplicable or unenforceable, and if a court were to find the choice of forum provision contained in the Certificate of Incorporation to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such action in other jurisdictions, which could harm our business, results of operations and financial condition. These exclusive-forum provisions may limit a shareholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or our directors, officers, or other employees and this limitation may have the effect of discouraging lawsuits or make our securities less attractive to investors. Further, while the Delaware courts have determined that such choice of forum provisions are facially valid, a shareholder may nevertheless seek to bring such a claim arising under the Securities Act against our directors, officers, or other employees in a venue other than in the federal district courts of the United States of America. In such instance, we would expect to vigorously assert the validity and enforceability of the exclusive forum provisions of the Certificate of Incorporation. This may require significant additional costs associated with resolving such action in other jurisdictions and we cannot assure you that the provisions will be enforced by a court in those other jurisdictions. If a court were to find either exclusive-forum provision in our Certificate of Incorporation to be inapplicable or unenforceable in an action, it may incur further significant additional costs associated with resolving the dispute in other jurisdictions, all of which could harm our business.
The Company may redeem unexpired Public Warrants prior to their exercise at a time that is disadvantageous to the holder, thereby making the Public Warrants worthless.
We have the ability to redeem the outstanding Public Warrants at any time after they become exercisable and prior to their expiration, at a price of $0.01 per Public Warrant, if, among other things, the last sales price of our Class A Common Stock equals or exceeds $18.00 per share for a period of 20 trading days within any 30 trading day period. If and when the Public Warrants become redeemable by us, we may exercise our redemption right. Redemption of the outstanding Public Warrants as described above could force holders to (i) exercise the Public Warrants and pay the exercise price therefor at a time when it may be disadvantageous for holders to do so, (ii) sell the Public Warrants at the then-current market price when holders might otherwise wish to hold the Public Warrants or (iii) accept the nominal redemption price which, at the time the outstanding Public Warrants are called for redemption, we expect would be substantially less than the market value of the Public Warrants.
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We have the ability to require holders of the Public Warrants to exercise such Public Warrants on a cashless basis, which will cause holders to receive fewer shares of Class A Common Stock upon their exercise of the Public Warrants than they would have received had they been able to exercise their Public Warrants for cash.
If the Company calls the Public Warrants for redemption after the redemption criteria is satisfied, we have the option to require any holder that wishes to exercise their Public Warrants to do so on a “cashless basis.” If the Company’s management chooses to require holders to exercise their Public Warrants on a cashless basis, the number of our Class A Common Stock received by a holder upon exercise will be fewer than it would have been had such holder exercised the Public Warrant for cash. This will have the effect of reducing the potential “upside” of the holder’s investment in the Company.
The exclusive forum clause set forth in the warrant agreement governing the Public Warrants may have the effect of limiting an investor’s rights to bring legal action against us and could limit the investor’s ability to obtain a favorable judicial forum for disputes with us.
Our outstanding Public Warrants provide for investors to consent to exclusive forum to state or federal courts located in New York, New York. This exclusive forum may have the effect of limiting the ability of investors to bring a legal claim against us due to geographic limitations and may limit an investor’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us. Alternatively, if a court were to find this exclusive forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business and financial condition. Notwithstanding the foregoing, nothing in the warrant limits or restricts the federal district court in which a holder of a warrant may bring a claim under the federal securities laws.
Our business and operations could be negatively affected if we become subject to any securities litigation or shareholder activism, which could cause us to incur significant expense, hinder execution of business and growth strategy and impact our stock price.
In the past, following periods of volatility in the market price of a company’s securities, securities class action litigation has often been brought against that company. Shareholder activism, which could take many forms or arise in a variety of situations, has been increasing recently. Volatility in the stock price of our Class A Common Stock or other reasons may in the future cause it to become the target of securities litigation or shareholder activism. Securities litigation and shareholder activism, including potential proxy contests, could result in substantial costs and divert management’s and the Board’s attention and resources from our business. Additionally, such securities litigation and shareholder activism could give rise to perceived uncertainties as to our future, adversely affect our relationships with service providers and make it more difficult to attract and retain qualified personnel. Also, we may be required to incur significant legal fees and other expenses related to any securities litigation and activist shareholder matters. Further, our stock price could be subject to significant fluctuation or otherwise be adversely affected by the events, risks and uncertainties of any securities litigation and shareholder activism.
A substantial number of the Company’s Class A Common Stock are restricted securities and as a result, there may be limited liquidity for our Class A Common Stock.
A substantial portion of our outstanding shares of Class A Common Stock currently constitute restricted securities and “control” securities for purposes of Rule 144 of the Securities Act or are otherwise subject to a contractual lockup. As a result, there may initially be limited liquidity in the trading market for our Class A Common Stock until these shares are sold pursuant to an effective registration statement under the Securities Act or the shares become available for resale without volume limitations or other restrictions under Rule 144 and are otherwise no longer subject to a lockup agreement. Even once these are no longer restricted or a registration statement for such shares has become effective, the liquidity for our Class A Common Stock may remain limited given the substantial holdings of such stockholders, which could make the price of our Class A Common Stock more volatile and may make it more difficult for investors to buy or sell large amounts of our Class A Common Stock.
Future resales of our Class A Common Stock may cause the market price of our Class A Common Stock to drop significantly, even if the Company’s business is doing well.
AleAnna Energy’s pre-Business Combination equity holders hold the substantial majority of our outstanding Class A Common Stock as of December 31, 2025. The resale, or expected or potential resale, of a substantial number of our Class A Common Stock in the public market could adversely affect the market price for our Class A Common Stock and make it more difficult for you to sell your Class A Common Stock at times and prices that you feel are appropriate.
Further, sales of our Class A Common Stock upon expected expiration of resale restrictions could encourage short sales by market participants. Generally, short selling means selling a security, contract or commodity not owned by the seller. The seller is committed to eventually purchase the financial instrument previously sold. Short sales are used to capitalize on an expected decline in the security’s price. As such, short sales of our Class A Common Stock could have a tendency to depress the price of our Class A Common Stock, which could further increase the potential for short sales.
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If our existing shareholders sell or indicate an intention to sell substantial amounts of our Class A Common Stock in the public market, the trading price of our Class A Common Stock could decline. In addition, shares underlying any future outstanding options and restricted stock units will become eligible for sale if exercised or settled, as applicable, and to the extent permitted by the provisions of various vesting agreements and Rule 144 of the Securities Act. The Company may also issue shares in the ordinary course of its business, and cannot predict the size of future issuances or sales of our Class A Common Stock or the effect, if any, that future issuances and sales of our Class A Common Stock will have on the market price of our Class A Common Stock. Sales of substantial amounts of our Class A Common Stock, including issuances made in the ordinary course of the Company’s business, or the perception that such sales could occur, may materially and adversely affect prevailing market prices of our Class A Common Stock. If these additional shares are sold, or if it is perceived that they will be sold in the public market, the trading price of our Class A Common Stock could decline.
Although Sponsor and certain other holders of our Class A Common Stock are subject to certain restrictions regarding the transfer of our Class A Common Stock, these shares may be sold after the expiration of their respective lock-ups. We intend to file one or more registration statements to provide for the resale of such shares from time to time. As restrictions on resale end and the registration statements are available for use, the market price of our Class A Common Stock could decline if the holders of currently restricted shares sell them or are perceived by the market as intending to sell them. In addition, registration rights we may grant in the future, including in the ordinary course of the Company’s business, may further depress market prices if these registration rights are exercised or shares of our Class A Common Stock are sold under the registration statements, the presence of additional shares trading in the public market may also adversely affect the market price of our Class A Common Stock.
Our acquisitions, divestitures and other strategic transactions may not produce anticipated results, which could have a material adverse effect on our business, financial condition or results of operations.
As our growth strategy evolves, we anticipate that we will continue to explore opportunities to create value through strategic transactions, whether through mergers and acquisitions, divestitures, joint ventures or similar business transactions. Evaluating potential transactions, including acquisitions and joint ventures, requires additional expenditures (including legal, accounting, and due diligence expenses, higher administrative costs to support the acquired entities and information technology, personnel, and other integration expenses) and may divert the attention of our management from day-to-day operating matters. Companies or operations we acquire or joint ventures we enter into may not be profitable or may not achieve the anticipated profitability that justify our investments. With respect to acquisitions, we may not be able to identify suitable candidates, consummate a transaction on terms that are favorable to us, or achieve expected returns and other benefits as a result of integration challenges. Our corporate development activities may present financial and operational risks and may have adverse effects on existing business relationships with suppliers and customers. Future acquisitions also could result in potentially dilutive issuances of equity securities, the incurrence of debt, contingent liabilities, and depreciation and amortization expenses related to certain tangible and intangible assets and increased operating expenses, all of which could, individually or collectively, adversely affect our business, financial condition, results of operations, and cash flows. There are risks inherent in any strategic transaction, and such risks could negatively affect the benefits, outcomes and synergies anticipated to be obtained from executing such strategic transactions.
Item 1B. Unresolved Staff Comments
Not Applicable.
Item 1C. Cybersecurity
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Despite these efforts, our policies and procedures may not be properly followed in every instance and may not always be effective. Our risk factors, which can found be found in Part I, Item 1A. “Risk Factors,” include further detail about the material cybersecurity risks we face. We have had no cybersecurity incidents or other risks from cybersecurity threats to date that have materially affected, or are reasonably likely to materially affect, us, including our business strategy, results of operations, or financial condition.
Cyber Risk Management and Strategy
Our cybersecurity assessments include identification of reasonably foreseeable internal and external risks, the likelihood and potential damage that could result from such risks, and the sufficiency of existing policies, procedures, systems, and safeguards in place to manage such risks. Following these risk assessments, if necessary, we would re-design and implement reasonable additional safeguards to minimize identified risks and address any identified gaps in existing safeguards.
Primary responsibility for assessing, monitoring, and managing our cybersecurity risks rests with our
As part of our overall risk management system, we monitor and test our safeguards and we train our relevant employees on these safeguards, in collaboration with our third-party IT provider and management. Since users are typically the weakest link in any information system, we periodically train all our employees on good cybersecurity practices, including password management, phishing prevention, and other security awareness issues.
Governance
Our Chief Financial Officer is primarily responsible for assessing and managing our material risks from cybersecurity threats with assistance from our third-party IT service provider.
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Item 2. Properties
AleAnna is a corporation incorporated under the laws of Delaware. Our headquarters is currently in Dallas, Texas, and houses our US-based management team and certain support individuals. Our Italian management team is housed in Rome and Milan, Italy-based offices.
Leasing our facilities gives us the flexibility to expand or reduce our office space as appropriate. We believe our current facilities are adequate for our current operating needs, and we anticipate that we will have access to other facilities, through future contractual arrangements, for development, testing, and production.
We have completed or partially completed production facilities for conventional natural gas at the Longanesi Field (near Lugo, Italy), the Gradizza Field (near Copparo, Italy), and the Trava Field (near Ostellato, Italy). These conventional gas facilities do not require human intervention on a 24/7 basis and thus house no field staff. See Item 1., “Business” for a more detailed description of our conventional natural gas properties.
We have existing facilities and/or land under construction for renewable natural gas at the Campagnatico plant (Tuscany) and, following successful acquisitions, in short order, we expect to begin upgrading construction on the Casalino plant (near Milan) and the Campopiano plant (Tuscany).
Item 3. Legal Proceedings
We do not have any claims, lawsuits or proceedings currently pending against us, individually or in the aggregate. However, from time to time, we may be subject to various claims, lawsuits and other legal and administrative proceedings that may arise in the ordinary course of business. Some of these claims, lawsuits and other proceedings may involve highly complex issues that are subject to substantial uncertainties, and could result in damages, fines, penalties, non-monetary sanctions or relief. We recognize provisions for claims or pending litigation when we determine that an un-favorable outcome is probable and the amount of loss can be reasonably estimated. Due to the inherent uncertain nature of litigation, the ultimate outcome or actual cost of settlement may materially vary from estimates.
Item 4. Mine Safety Disclosures
Not Applicable.
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PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information
AleAnna Class A Common Stock and Public Warrants currently trade on Nasdaq under the trading symbols of “ANNA” and “ANNAW,” respectively, and on March 19, 2026, the Company had 40,659,881 shares of Class A Common Stock issued and outstanding, 25,994,400 shares of Class C Common Stock issued and outstanding and 11,150,543 Warrants issued and outstanding.
Holders
On March 19, 2026, there were 43 holders of record of our Class A Common Stock, one holder of record of our Class C Common Stock and one holder of record of our Public Warrants. We believe a substantially greater number of beneficial owners hold shares of Class A Common Stock and Public Warrants through brokers, banks or other nominees.
Dividends
The Company has never declared or paid any cash dividends and does not plan to pay cash dividends in the foreseeable future. The payment of cash dividends in the future will be dependent upon our revenues and earnings, if any, capital requirements and general financial condition. The payment of any cash dividends will be within the discretion of the Company’s board of directors at such time. In addition, the Company’s board of directors is not currently contemplating and does not anticipate declaring any stock dividends in the foreseeable future.
Recent Sales of Unregistered Securities
There were no sales of unregistered securities during the year ended December 31, 2025 that were not previously reported on a Quarterly Report on Form 10-Q or a Current Report on Form 8-K.
Issuer Purchases of Equity Securities
We did not repurchase any shares of our equity securities during the years ended December 31, 2025 or 2024.
Item 6. [Reserved]
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations should be read together with our consolidated financial statements and the related notes appearing elsewhere in this Form 10-K. The discussion and analysis should also be read together with the section entitled “Business”. This discussion and analysis contains forward-looking statements that reflect our plans, estimates and beliefs that involve risks and uncertainties that may be outside our control. See the section titled “Cautionary Note Regarding Forward-Looking Statements”. As a result of many factors, such as those set forth in Part 1, Item 1A.“Risk Factors” and elsewhere in this Form 10-K, our actual results may differ materially from those anticipated in these forward-looking statements. Unless the context otherwise requires, all references in this section to “we,” “us,” “our,” “AleAnna,” or the “Company” refer to AleAnna, Inc.
Overview
AleAnna is a natural gas resource developer focused on delivering critical natural gas supplies to Europe through both onshore conventional natural gas exploration and renewable natural gas development in Italy. We have several conventional natural gas discoveries including the Longanesi field, located in the Po Valley in Northern Italy, which is one of Italy’s largest modern gas discoveries. We retain a 33.5% working interest in the Longanesi field with our working interest partner, and operator, Padana. We acquired our working interest in the Longanesi field through a 2016 transaction with Enel. We also retain wholly owned concessions, permits, and pending applications on other exploration and development prospects across Italy which are supported by proprietary modern 3D seismic imaging.
Our recent drilling and exploration activities involve the drilling and testing of three Longanesi development wells (during 2022 and 2023) as well as the re-completion of two original discovery wells. We had no drilling activity during the years ended December 31, 2025 or 2024. We had no other exploratory or development drilling during years ended December 31, 2025 or 2024. Our Trava and Gradizza wells were classified by DeGolyer as proved undeveloped reserves as such wells had not yet started production as of December 31, 2025 and require future investments to install production facilities prior to being fully completed and producible. However, as noted in the “Recent Developments” section below, we achieved first production from the Longanesi field in March 2025.
In 2023, we launched a renewable natural gas development business focused on bringing to market carbon-negative renewable natural gas derived from animal and agricultural waste. We currently generate revenue from electricity sales from two renewable natural gas assets.
The Transactions
On December 13, 2024, we consummated the previously announced business combination pursuant to the Merger Agreement, dated June 4, 2024, by and among Swiftmerge, HoldCo, Swiftmerge Merger Sub LLC, a Delaware limited liability company and wholly-owned subsidiary of HoldCo, and AleAnna Energy. Pursuant to the terms of the Merger Agreement, on December 13, 2024, SPAC migrated to and domesticated as a Delaware corporation in accordance with Section 388 of the Delaware General Corporation Law, as amended, and the Companies Act (As Revised) of the Cayman Islands and changed its name to AleAnna, Inc. The transactions contemplated by the Merger Agreement are collectively referred to herein as the “Business Combination.”
The Business Combination was accounted for as a common control transaction with respect to AleAnna Energy which is akin to a reverse recapitalization. This conclusion was based on the fact that Nautilus Resources LLC (“Nautilus”) had a controlling financial interest in AleAnna Energy prior to the Business Combination and has a controlling financial interest in AleAnna, which includes AleAnna Energy as a wholly owned subsidiary. The net assets of SPAC are stated at their historical carrying amounts with no goodwill or intangible assets recognized in accordance with the accounting principles generally accepted in the United States of America (“U.S. GAAP” or “GAAP”). The Business Combination with respect to AleAnna Energy was not treated as a change in control primarily due to Nautilus receiving the controlling voting stake in AleAnna and the ability of Nautilus to nominate the full board of directors and management of AleAnna.
Under a reverse recapitalization, SPAC is treated as the “acquired” company for financial reporting purposes. Accordingly, for accounting purposes, the Business Combination is treated as the equivalent of AleAnna Energy issuing stock for the net assets of SPAC, accompanied by a recapitalization.
We incurred $9.5 million in transaction costs related to the Business Combination. Approximately $0.6 million of these costs were recorded as a reduction to additional paid-in capital, up to the amount of cash proceeds received in the transaction. Of the remaining $8.9 million, approximately $0.5 million represented prepaid directors and officers insurance premiums that were recorded to other assets in the consolidated balance sheet, and $8.4 million represented legal, accounting, consulting and advisory fees which were recorded as Business Combination transaction expenses in the consolidated statement of operations and comprehensive income (loss).
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Recent Developments
Gradizza Concession – Regional Intesa Approval
During the third quarter of 2025, we reached an agreement with the Emilia Romagna Region (the “Intesa”) in support of our pending application for a production concession related to the Gradizza field. The second application was approved in January 2026. These approvals represent a significant milestone required prior to first production.
AleAnna holds a 100% working interest in the Gradizza field and serves as the operator. Gradizza is expected to become the Company’s first operated producing asset. According to the Company’s reserve report as of December 31, 2025, Gradizza contains 703 MMcf of proved reserves.
First Production at Longanesi
On March 13, 2025, we achieved a key milestone with the first production from our working interest in five wells in the Longanesi field, and the field reached sustained maximum production during the first half of 2025. The Company began recognizing revenue and related expenses, including depreciation and depletion, associated with Longanesi production in the second quarter of 2025.
In connection with the Longanesi start-up in 2025, we issued a $3.1 million bank guarantee to secure our contingent consideration obligation to Enel. The guarantee required $1.2 million in cash collateral, which is classified as restricted cash as of December 31, 2025. The collateral may be used to satisfy the contingent consideration liability as payments become due.
Gas Sale Agreement
On October 29, 2024, we entered into a gas sale agreement with Shell Energy Europe Limited, under which SEEL became the exclusive buyer of our share of the natural gas produced from the Longanesi field net of (i) any consumption and/or losses incurred in the transport, treatment and compression of gas before delivery; (ii) any volume to be allocated for regulated royalties auctions, if applicable; and (iii) any other volume contractually allocated to other parties before August 31, 2022.
Renewable Natural Gas Acquisitions
Between March 2024 and July 2024, we successfully completed three separate strategic acquisitions of renewable natural gas plant projects in Italy for an aggregate of approximately $9.5 million. The plants are fully permitted and are in various stages of the development lifecycle, with one greenfield plant (Campagnatico) that is a new development and two brownfield plants (Casalino and Campopiano) that are currently operational.
Capital Contributions
Between January 2024 and May 2024, we received an aggregate of $62.1 million in capital contributions from our members, resulting in the issuance of 62,100 Class 1 Preferred Units, to fund operating costs and capital expenditures and provide working capital to meet our liabilities and commitments as they become due for at least the upcoming 12 months. These capital contributions were the final capital contributions to AleAnna Energy before the Business Combination and that all equity of AleAnna Energy, including the Class 1 Preferred Units, were exchanged for Class A and Class C Common stock as part of the December 13, 2024. We are using these funds to fulfill Longanesi gas pipeline and plant activity obligations, as well as general and administrative expenses.
Blugas Settlement
On May 28, 2024, we reached a settlement agreement (the “Blugas Settlement Agreement”) with Blugas Infrastructure S.r.l. (“Blugas”) regarding the Blugas overriding royalty interest (“ORRI”) whereby Blugas was entitled to physical delivery of 20% of the first 350 million standard cubic meters (approximately 2,472 106ft3) produced from the Longanesi field. Under the terms of the Blugas Settlement Agreement, we paid Blugas approximately €5 million, plus an additional €1.1 million in applicable VAT. In exchange, we were released from any future liability related to the Blugas ORRI. As a result of the transactions contemplated by the Blugas Settlement Agreement, our 33.5% working interest (net revenue interest) in the Longanesi field, as established under the terms of the Unified Operating Agreement arrangement originally signed between ENI and Grove and dated September 26, 2009, is now unencumbered except for normal government royalties (10%). The Blugas Settlement Agreement was accounted for as an acquisition of the Blugas ORRI claim with a corresponding increase to the expected future cash flows from our reserves. Our year-end December 31, 2023 reserve quantities included the 20% of 350 million standard cubic meters (approximately 2,472 106ft3) allocable to the Blugas ORRI in our proved gas reserves. However, the required payments to Blugas associated with the sale of such quantities were reflected as cash outflows (costs) in our year-end December 31, 2023 reserve report as if such amounts were paid to Blugas. Following settlement, our year-end December 31, 2024 reserve quantities continue to include the 20% of 350 million standard cubic meters (approximately 2,472 106ft3), however, the previously required payments to Blugas associated with the sale of such quantities are no longer reflected as cash outflows (costs) as if such amounts were paid to Blugas. As the cash outflows (costs) are no longer reflected as if paid to Blugas, such amounts are reflected in our December 31, 2024 reserve report as allocable to our unencumbered 33.5% working interest.
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Key Factors Affecting our Performance, Prospects and Future Results
We believe that our performance and future success depends on a number of factors that present significant opportunities for us but also pose risks and challenges, including competition from other carbon-based and non-carbon-based fuel producers, regulatory hurdles posed by the Italian government, and other factors discussed under the section titled “Risk Factors.” We believe the factors described below are key to our success.
Continued Development of Conventional Natural Gas Projects
As previously discussed, we and Padana achieved first production of the five wells in the Longanesi field in March 2025 through use of a temporary processing facility. The permanent processing facility is expected to be constructed over the remainder of 2026.
We believe achieving first production of the Longanesi field was a key milestone that will fuel our potential growth. We also believe that we have potentially viable discoveries in our Gradizza and Trava fields, which are expected to achieve first production in the future.
Expanding Renewable Natural Gas Operations
In 2023, we launched a renewable natural gas development business focused on bringing to market carbon negative renewable natural gas derived from animal and agricultural waste. As previously discussed, the first three renewable natural gas assets were purchased between March 2024 and July 2024, with additional renewable natural gas projects expected to be purchased in the future.
We believe expanding the renewable natural gas business is another key to our potential growth and may unlock potential partnership or joint venture opportunities.
Key Components of Results of Operations
We are an early-stage company, and our historical results may not be indicative of our future results. Accordingly, the drivers of our future financial results, as well as the components of such results, may not be comparable to our historical results of operations or our future results of operations.
Revenue
During the year ended December 31, 2025, we generated approximately $25.0 million of total revenue, comprised of $22.4 million of revenue from our Conventional segment and $2.7 million of revenue from our Renewable segment.
During the year ended December 31, 2025, revenue from our Conventional segment was comprised of sales of our share of natural gas from the Longanesi field. During the year ended December 31, 2025, results from the Longanesi field have outperformed expectations, with a stabilized total production rate of approximately 25 to 30 million cubic feet per day (“MMcf/d”), which was achieved ahead of the anticipated 3-month ramp up timeline for this milestone. During the year ended December 31, 2025, revenue from our Renewable segment was comprised of electricity sales at two renewable natural gas assets acquired in July 2024 (the “Casalino” and “Campopiano” plants). The plant assets are fully permitted for production of electricity through conversion of crop and animal waste bio feedstocks. The plant assets are currently biomethane to electricity conversion assets. It is our intention to begin upgrading the sites to refine biomethane into renewable natural gas through upgrading units. Following the upgrade process to transition the assets to biomethane to renewable natural gas conversion, we expect to sell renewable natural gas to customer(s) by trucking or piping the renewable natural gas to the interstate pipeline system. Until the plant assets are upgraded, we will actively source bio feedstocks for the assets in order to produce biomethane which will be processed through reciprocating generators in order to generate electricity which is then sold onto the grid through a metered interconnection. Casalino and Campopiano derive revenues from the sale of such electricity to the local state-owned electrical utility (Gestore dei Servizi Energetici SpA or “GSE”). Energy generation revenue is recognized as the electricity generated by the Casalino and Campopiano assets is delivered to GSE. Revenues are based on actual output and “on-the-spot” predetermined prices for small renewable energy producers.
Expenses
Cost of Revenues
Cost of revenues primarily consists of biofeedstock purchased by the RNG Subsidiaries. This feedstock fuels the anaerobic digesters (“ADs”), which produce biomethane that is then converted to electricity and sold onto the grid. Cost of revenues from sales of electricity consists of feedstock costs, direct labor and overhead necessary to produce RNG and generate electricity. Cost of revenues from sales of natural gas consists of gas tariffs and royalties, as well as rent expense.
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Lease Operating Expenses
Lease operating expenses reflect ongoing costs related to the Longanesi field which commenced production in the second quarter of 2025. Such costs are passed down to us by the Longanesi field operator, Padana, and include accrued royalties payable to the Italian government, pipeline fees, repairs and maintenance, and other field-related costs.
General and Administrative (G&A) Expense
G&A expenses consist of compensation costs for personnel in executive, finance, accounting, and other administrative functions. G&A expenses also include legal fees, professional fees paid for accounting, auditing and consulting services, and insurance costs. As a newly public company, we expect that we will incur higher G&A expenses for public company costs such as compliance with the regulations of the Securities and Exchange Commission (the “SEC”) and the Nasdaq Capital Market.
Depreciation and Depletion
Depreciation includes expense related to the Casalino and Campopiano renewable plant assets, which is recorded on a straight-line basis over the estimated useful lives of the assets. It also includes depreciation of lease and well equipment at the Longanesi field, which is calculated using the units-of-production method based on estimated proved developed reserves.
Depletion reflects the systematic allocation of the capitalized costs of our natural gas properties over the estimated proved developed reserves on a units-of-production basis. These costs include acquisition, exploration, and development expenditures associated with the Longanesi field. Depletion expense fluctuates based on production volumes and changes in our reserve estimates.
Business Combination transaction expenses
Business Combination transaction expenses represent legal, consulting, advisory, accounting and other transaction fees and expenses related to the Business Combination, accounted for as a common control reverse recapitalization, that were expensed in connection with the Business Combination. A portion of the total costs incurred were recorded as a reduction in additional paid-in capital, up to the $0.6 million of proceeds received from the Trust, with costs in excess of funds raised from the Business Combination required to be expensed under U.S. GAAP. Management separated these expenses on its audited consolidated statement of operations for the year ended December 31, 2024 due to the significant and discrete nature of the expenses.
Interest and Other Income (Expenses)
Interest and other income (expenses) primarily includes interest earned on cash and cash equivalents.
Income Tax Effects
Our income tax consequences have been reflected in our consolidated financial statements in accordance with ASC 740, Income Taxes. After consideration of all positive and negative evidence, the Company concluded that it is more likely than not that the deferred tax assets for all entities will not be realizable as of December 31, 2025. This conclusion was based on the evaluation of positive and negative evidence, including the Longanesi field commencing production in 2025 and our recent history of losses. The negative evidence outweighed positive evidence. Consequently, we maintain $50.0 million of valuation allowance against its deferred tax assets with $43.6 million of the valuation allowance being recorded against Italian deferred tax assets and $6.4 million of the valuation allowance being recorded against U.S. deferred tax assets. We will continue to evaluate all available evidence in the future periods.
We are also subject to a Valued-Added Tax (“VAT”) which is a broadly-based consumption tax assessed on the value added to goods and services. VAT generally applies to most goods and services bought and sold within the EU. In certain cases, including cross-border sales to business customers and sales of biogas within Italy, we are not required to collect VAT on revenues. To date, we have incurred higher VAT on purchases (input VAT) than we have collected on sales (output VAT), resulting in a net VAT refund receivable. As of December 31, 2025 and 2024, we had VAT receivables of $9.6 million, and $6.8 million, respectively. Under Italian tax law, VAT receivables may be used to offset other tax liabilities, including payroll taxes, income taxes, and other taxes payable to the Italian government.
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Operations
Our net income attributable to the common stockholder was $1.8 million for the year ended December 31, 2025, as compared to net loss attributable to the common stockholder of $167.8 million for the same period of 2024. As of December 31, 2025 and December 31, 2024, we had an accumulated deficit of $189.2 million and $191.0 million, respectively. The majority of these accumulated losses stem from costs associated with the Longanesi field drilling and development, including asset impairments from previous years, as well as seismic imaging, exploratory costs for other conventional natural gas prospects, and general and administrative expenses. The accumulated deficits also include historical deemed dividends to the redemption value of AleAnna Energy’s previous Class 1 Preferred Units (exchanged for Class A and Class C common stock in connection with the Business Combination) based on the redemption features of those units and the related accounting requirements. See “Note 9— Equity” to the audited consolidated financial statements for further details. We expect to continue to incur substantial expenses related to our operations, exploration, and development activities, including pre-commercialization efforts as we continue our development of, and seek regulatory approval for, our discoveries and exploration prospects. We achieved net income for the first time in 2025.
Consolidated Results of Operations
The following table shows our consolidated results of operations for the years ended December 31, 2025 and 2024:
| For the Year Ended December 31, | Dollar | Percentage | ||||||||||||||
| 2025 | 2024 | Change | Change | |||||||||||||
| Revenues | $ | 25,035,737 | $ | 1,420,030 | $ | 23,615,707 | 1,663 | % | ||||||||
| Operating expenses: | ||||||||||||||||
| Cost of revenues | $ | 6,195,475 | $ | 1,043,174 | $ | 5,152,301 | 494 | % | ||||||||
| Lease operating expense | 3,207,562 | - | 3,207,562 | NM | ||||||||||||
| General and administrative | 9,664,653 | 6,264,087 | 3,400,566 | 54 | % | |||||||||||
| Depreciation and depletion | 2,933,481 | 133,516 | 2,799,965 | 2,097 | % | |||||||||||
| Accretion of asset retirement obligation | 132,002 | 133,239 | (1,237 | ) | -1 | % | ||||||||||
| Business combination transaction expenses | - | 8,398,653 | (8,398,653 | ) | -100 | % | ||||||||||
| Total operating expenses | 22,133,172 | 15,972,669 | 6,160,503 | 39 | % | |||||||||||
| Operating income (loss) | 2,902,565 | (14,552,639 | ) | 17,455,204 | 120 | % | ||||||||||
| Other income: | ||||||||||||||||
| Interest and other income | 1,242,899 | 1,948,281 | (705,382 | ) | -36 | % | ||||||||||
| Change in fair value of derivative liability | - | 173,177 | (173,177 | ) | -100 | % | ||||||||||
| Total other income | 1,242,899 | 2,121,458 | (878,559 | ) | -41 | % | ||||||||||
| Income (loss) before income taxes | 4,145,464 | (12,431,181 | ) | 16,579,645 | 133 | % | ||||||||||
| Income tax expense | (1,263,396 | ) | - | (1,263,396 | ) | NM | ||||||||||
| Net income (loss) | 2,882,068 | (12,431,181 | ) | 15,313,249 | 123 | % | ||||||||||
| Deemed dividend to Class 1 Preferred Units redemption value | - | (155,423,177 | ) | 155,423,177 | 100 | % | ||||||||||
| Net loss (income) attributable to noncontrolling interests | (1,082,958 | ) | 87,511 | (1,170,469 | ) | -1338 | % | |||||||||
| Net income (loss) attributable to Class A Common stockholders or holders of Common Member Units | $ | 1,799,110 | $ | (167,766,847 | ) | $ | 169,565,957 | 101 | % | |||||||
| Other comprehensive income (loss) | ||||||||||||||||
| Currency translation adjustment | 4,111,281 | (1,548,154 | ) | 5,659,435 | 366 | % | ||||||||||
| Comprehensive income (loss) | 6,993,349 | (13,979,335 | ) | 20,972,684 | 150 | % | ||||||||||
| Comprehensive income attributable to noncontrolling interests | (3,332,249 | ) | 87,511 | (3,419,760 | ) | -3908 | % | |||||||||
| Total comprehensive income (loss) attributable to Class A Common stockholders | $ | 3,661,100 | $ | (13,891,824 | ) | $ | 17,552,924 | 126 | % | |||||||
Revenues and Cost of Revenues
During the year ended December 31, 2025, our revenue was earned primarily through sales of our share of natural gas production from the Longanesi field and, to a lesser extent, from electricity generation and sales at the Casalino and Campopiano renewable natural gas plants. Cost of revenues from sales of electricity consists of feedstock costs, direct labor and overhead necessary to produce RNG and generate electricity. Cost of revenues from sales of natural gas consists of gas tariffs and royalties, as well as rent expense. See Critical Accounting Policies and Estimates for further details of our revenue recognition accounting policies.
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Total revenues increased by $23.6 million, or 1663%, for the year ended December 31, 2025 to $25.0 million compared to $1.4 million for the year ended December 31, 2024, primarily driven by sustained maximum production at the five wells in the Longanesi field during the 2025 fiscal year. Cost of revenues increased by $6.2 million, or 494% to $5.8 million for the year ended December 31, 2025, compared to $1.0 million for the year ended December 31, 2024, primarily driven by increased production costs from the Longanesi field.
Lease Operating Expenses
Lease operating expense was $3.2 million for the year ended December 31, 2025 due to the commencement of new leases related to the Longanesi field. We did not incur any lease operating expense for the year ended December 31, 2024.
General and Administrative (G&A) Expenses
General and administrative expenses (exclusive of Business Combination transaction expenses) increased by $3.4 million, or 54% to $9.7 million for the year ended December 31, 2025, compared to $6.3 million for the year ended December 31, 2024. The increase was primarily due to increases in legal, audit and consulting fees to support public company operations as well as delivering improved control over our operations.
Business Combination transaction expenses
See “Expenses” above for a description of the Business Combination transaction expenses. These expenses were specific to the Business Combination that closed in the prior year, with no similar expenses incurred in 2025.
Depreciation and Depletion
Depreciation and depletion increased by $2.8 million, or 2097% to $2.9 million for the year ended December 31, 2025, compared to $0.1 million for the year ended December 31, 2024. As of December 31, 2024, the Longanesi field had not commenced production. The Casalino and Campopiano plants were acquired during 2024. Accordingly, period-over-period comparisons for these expense categories are not meaningful.
Contingent Consideration Liability
As of December 31, 2025 and 2024, the contingent consideration liability was recorded at $28.2 million and $25.0 million, respectively. The estimate of the contingent consideration liability was determined based on inputs including the following as of December 31, 2025 and 2024: the intercontinental exchange futures prices for European natural gas, Euro to USD exchange rates of 1.18 and 1.04, respectively, and management’s future expected annual Longanesi production. We are required to make formulaic deferred consideration payments effectively equating to 20% to 50% of revenue above certain European natural gas threshold prices. The calculation and timing of such payments are primarily driven by future expected Longanesi production, as modeled by DeGolyer, as well as forward European natural gas prices. While the timing and quantities of expected Longanesi production were unchanged from December 31, 2024 to December 31, 2025, and we had fully accrued the total capped Euro amount of the liability, average annual European natural gas forward prices declined slightly.
Since the total capped Euro-denominated liability was recorded as of December 31, 2025, December 31, 2024, and December 31, 2023, any changes in the USD-equivalent amount were entirely due to foreign exchange rate fluctuations. As such, these changes were included in currency translation adjustment for the years ended 2025 and 2024.
Interest and Other Income (Expenses)
Interest and other income decreased by $0.7 million or 36% to $1.2 million during the year ended December 31, 2025 compared to $1.9 million for the same period in 2024, primarily due to lower interest earned during the 2025 period due to lower interest rates as compared to the 2024 period.
Change in Fair Value of Derivative Liability
The change in the fair value of derivative liability related to the Class 1 Preferred Units was zero during the year ended December 31, 2025, compared to $0.2 million during the same period in 2024. The fair value gain recorded during the year ended December 31, 2024 (representing a decrease in the liability) was primarily due to a higher liquidation threshold which was driven by capital contributions made during the first quarter of 2024 through the Class 1 Preferred Units. The derivative liability was derecognized in conjunction with the Business Combination in the prior year.
Income Tax Expense
The increase in income tax expense in the current year is due to the Company generating pre-tax income, compared to a pre-tax loss in the prior period. The shift to taxable earnings in the current year led to the recognition of income tax expense based on applicable statutory rates.
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Currency Translation Adjustment
For the purpose of presenting consolidated financial statements, the assets and liabilities of our Euro operations are translated to USD at the exchange rate on the reporting date. The income and expenses are translated using average exchange rates. Foreign currency differences that arise on translation for consolidated purposes are recognized as a currency translation adjustment in other comprehensive income (loss) on the consolidated statements of operations and comprehensive income (loss).
The currency translation adjustment increased by $5.7 million for the year ended December 31, 2025 compared to the same period in 2024. This increase was primarily driven by fluctuation of the exchange rates between the Euro and the U.S. Dollar as well as the level of our Euro-denominated activities. The spot rate strengthened from December 31, 2024 to December 31, 2025, and the average exchange rate was higher during 2025, resulting in a larger positive currency translation adjustment relative to the prior period.
Non-GAAP Financial Measures
In addition to amounts presented in accordance with U.S. GAAP, we also present certain supplemental non-GAAP financial measures. We believe that the presentation of non-GAAP financial measures provides both management and investors with a greater understanding of our operating results and trends in addition to the results measured in accordance with U.S. GAAP and provides greater comparability across time periods. These measures should not be considered a substitute to GAAP basis measures, nor should they be viewed as a substitute for operating results determined in accordance with U.S. GAAP. The non-GAAP financial measures do not have any standardized meaning and are therefore unlikely to be comparable to similarly titled measures used by other companies. In compliance with GAAP, our non-GAAP measures are reconciled to net income, the most directly comparable GAAP performance measure.
EBITDA and Adjusted EBITDA
EBITDA is a supplemental non-GAAP financial measure defined as net income (loss) adjusted for interest and other expenses, income taxes, depreciation, depletion, and amortization. The purpose of presenting EBITDA is to highlight earnings without finance, taxes, and depreciation, depletion and amortization expense, and its use is limited to specialized analysis. Our definition of Adjusted EBITDA differs from EBITDA because we further adjust non-GAAP EBITDA for stock-based compensation expense and acquisition costs such as transaction expenses. We calculate Adjusted EBITDA as EBITDA plus stock compensation expense and transaction expenses. The purpose of presenting Adjusted EBITDA is to adjust for items that we do not believe represent the operations of the core business such as transactions expenses, share based compensation, and other non-recurring costs.
The following table is a reconciliation of net income to EBITDA and Adjusted EBITDA:
| Year Ended December 31, | ||||||||
| 2025 | 2024 | |||||||
| Net Income (loss) | 2,882,068 | $ | (12,431,181 | ) | ||||
| Add (deduct): | ||||||||
| Interest and other income | (1,242,899 | ) | (1,948,281 | ) | ||||
| Tax expense | 1,263,396 | - | ||||||
| Depreciation, depletion and amortization | 2,933,481 | 133,516 | ||||||
| EBITDA | 5,836,046 | $ | (14,245,946 | ) | ||||
| Add: | ||||||||
| Stock compensation expense | 774,220 | - | ||||||
| Transaction expense | - | 8,398,653 | ||||||
| Adjusted EBITDA | 6,610,266 | $ | (5,847,293 | ) | ||||
Segment Results
During 2025, in connection with the commencement of production at the Longanesi field, the Company’s evaluation of operating results between conventional and renewable operations became more relevant to the chief operating decision maker, resulting in further disaggregation of the Company’s single reportable segment. As a result, as of December 31, 2025, we determined that we have two operating segments, each of which also qualifies as a reportable segment, based on the manner in which the chief operating decision makers (“CODM”), the Company’s Chief Executive Officer and Executive Director collectively, review financial information to assess performance and allocate resources.
| ● | The Conventional segment consists of the natural gas exploration and production activities conducted by AleAnna Italia. The primary product of this segment is conventional natural gas produced from onshore exploration and development in Italy. |
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| ● | The Renewable segment consists of the RNG and electricity production activities conducted by AleAnna Renewable and the RNG Subsidiaries. The segment’s primary output is electricity generated from RNG derived from animal and agricultural waste. |
Reconciling items include items not directly attributable to either reportable segment. These include corporate financing and investing activities, as well as administrative functions that support the Company’s overall operations. These items are presented in the segment reconciliation but do not constitute a reportable segment.
The CODM evaluates segment performance primarily using segment operating income (loss), which is consistent with the presentation in the Company’s consolidated statements of operations. The CODM monitors revenues and operating expenses by segment for purposes of strategic decision-making and resource allocation, including the evaluation of the timing and amount of future investment in, or development of, the conventional and renewable reportable segments. The expense categories reviewed by the CODM are consistent with those presented in the consolidated statements of operations and in the segment operating results presented below. The CODM also evaluates segment performance using adjusted EBITDA. Adjusted EBITDA is defined as net income (loss) adjusted for interest and other income (expense), provisions for income taxes, depreciation, depletion, and amortization, stock-based compensation expense and acquisition costs such as transaction expenses. Adjusted EBITDA is a non-GAAP financial measure and should not be considered a substitute to GAAP basis measures, nor should they be viewed as a substitute for operating results determined in accordance with U.S. GAAP.
All of the Company’s revenue is generated with external customers and located in Italy. All of the Company’s assets, other than corporate assets primarily comprised of cash located in the U.S., are located in Italy.
The year ended December 31, 2025 reflects the revenue and expense categories noted above in the consolidated Results of Operations. The Company had minimal revenue and operating expenses outside of corporate general and administrative expenses for the same period of 2024. The vast majority of natural gas development activities were capitalized prior to the second quarter of 2025.
Selected financial information by segment is presented in the tables below:
| Year Ended December 31, 2025 | ||||||||||||
| Conventional | Renewable | Total | ||||||||||
| Revenues | 22,369,981 | 2,665,756 | 25,035,737 | |||||||||
| Less: | ||||||||||||
| Cost of revenues | 2,948,756 | 3,246,718 | 6,195,474 | |||||||||
| Lease operating expense | 3,207,562 | - | 3,207,562 | |||||||||
| Segment general and administrative | 2,653,853 | 1,889,476 | 4,543,329 | |||||||||
| Accretion of asset retirement obligation | 132,002 | - | 132,002 | |||||||||
| Segment EBITDA (Non-GAAP) | 13,427,808 | (2,470,438 | ) | 10,957,370 | ||||||||
| Less: Corporate general and administrative (excluding stock compensation expense) | - | - | 4,347,104 | |||||||||
| Adjusted EBITDA (Non-GAAP) | 13,427,808 | (2,470,438 | ) | 6,610,266 | ||||||||
| Reconciling items: | ||||||||||||
| Depreciation and depletion | 2,586,565 | 346,916 | ||||||||||
| Segment operating income (loss) | 10,841,243 | (2,817,354 | ) | 8,023,889 | ||||||||
| Reconciling items: | ||||||||||||
| Less: Corporate general and administrative (excluding stock compensation expense) | 4,347,104 | |||||||||||
| Stock compensation expense | 774,220 | |||||||||||
| Interest and other income | 1,242,899 | |||||||||||
| Income (loss) before income taxes | 4,145,464 | |||||||||||
| Segment assets | $ | 67,310,047 | $ | 16,133,887 | $ | 83,443,934 | ||||||
| Corporate and other assets | 17,852,386 | |||||||||||
| Total assets | $ | 101,296,320 | ||||||||||
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| Year Ended December 31, 2024 | ||||||||||||
| Conventional | Renewable | Total | ||||||||||
| Revenues | $ | - | $ | 1,420,030 | $ | 1,420,030 | ||||||
| Less: | ||||||||||||
| Cost of revenues | $ | - | $ | 1,043,174 | $ | 1,043,174 | ||||||
| Segment general and administrative | 2,639,824 | 1,502,054 | 4,141,878 | |||||||||
| Accretion of asset retirement obligation | 133,239 | - | 133,239 | |||||||||
| Segment EBITDA (Non-GAAP) | $ | (2,773,063 | ) | $ | (1,125,198 | ) | $ | (3,898,261 | ) | |||
| Less: Corporate general and administrative (excluding stock compensation expense) | - | - | 2,122,209 | |||||||||
| Segment Adjusted EBITDA (Non-GAAP) | $ | (2,773,063 | ) | $ | (1,125,198 | ) | $ | (3,898,261 | ) | |||
| Reconciling items: | ||||||||||||
| Depreciation and depletion | - | 133,516 | 133,516 | |||||||||
| Segment operating loss | $ | (2,773,063 | ) | $ | (1,258,714 | ) | $ | (4,031,777 | ) | |||
| Reconciling items: | ||||||||||||
| Less: Corporate general and administrative (excluding stock compensation expense) | $ | 2,122,209 | ||||||||||
| Business combination transaction expenses | (8,398,653 | ) | ||||||||||
| Change in fair value of derivative liability | 173,177 | |||||||||||
| Interest and other income | 1,948,281 | |||||||||||
| Loss before income taxes | $ | (12,431,181 | ) | |||||||||
| Segment assets | $ | 44,962,865 | $ | 14,150,411 | $ | 59,113,276 | ||||||
| Corporate and other assets | 23,973,315 | |||||||||||
| Total assets | $ | 83,086,591 | ||||||||||
Liquidity, Capital Resources and Operations
We have begun generating revenues from our operations in both conventional gas and renewable gas businesses. We had an accumulated deficit of $189.2 million and $191.0 million as of December 31, 2025 and 2024, respectively. We had $31.8 million and $28.3 million in unrestricted cash and cash equivalents on December 31, 2025 and 2024, respectively. Our continuing operations, as intended, are dependent upon our ability to generate cash flows or obtain raise proceeds from equity or debt issuances. In 2025, we also received approximately $1.1 million from exercises of Public Warrants between January 2025 and May 2025. In addition, we are exploring Resource Backed Loan (“RBL”) financing and renewable natural gas project loan products and other financing arrangements with several financial institutions; however, there is no guarantee that such financing will be available to us. As a normal part of our business, depending on market conditions, we may from time to time consider opportunities to issue equity or debt securities to raise additional capital. Changes in our operating plans, lower than anticipated revenues, increased expenses, acquisitions or other events may cause us to seek additional debt or equity financing in future periods. There can be no guarantee that financing will be available on acceptable terms or at all.
Presently, Padana is the operator of the Longanesi field under a Unitized Operating Agreement, and other companies in the future may operate some of the properties in which we have an interest. The failure of an operator of our wells or joint venture participant to adequately perform operations, an operator’s breach of the applicable agreements or an operator’s failure to act in ways that are in our best interest could reduce our production and revenues.
To mitigate operator risks, we monitor the operational risks, credit risk, financial position and liquidity of Padana. Operational risks are monitored and acted on through: (i) periodic meetings with Padana, through a formal committee known as the “Technical Committee”, to examine upcoming activities and discuss questions and concerns, (ii) through the receipt and analysis of daily reports, (iii) through requesting unscheduled calls with Padana where areas of concern are identified, and (iv) through occasional site visits. Further, Padana’s credit risk, financial position, and liquidity are periodically evaluated through review of the financial condition of Padana’s parent organization, Gas Plus S.p.A., which is a publicly-traded company on the Italian Stock Exchange (Euronext Milan). We are able to continuously monitor financial health of Gas Plus S.p.A. through exchange-required public disclosures, including half-annual and annual financial statements, corporate presentations, and press releases.
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Cash Flows
The following table includes our cash flow data for the years ended December 31, 2025 and 2024:
| For the Year Ended December 31, | ||||||||
| 2025 | 2024 | |||||||
| Consolidated Statement of Cash Flows Data: | ||||||||
| Net cash provided by (used) in operating activities | $ | 10,155,902 | $ | (16,897,557 | ) | |||
| Net cash used in investing activities | $ | (7,005,061 | ) | $ | (23,066,287 | ) | ||
| Net cash provided by financing activities | $ | 1,143,652 | $ | 62,106,468 | ||||
Cash provided by (used in) operating activities
Cash generated through operating activities increased by $27.1 million for the year ended December 31, 2025, compared to the year ended December 31, 2024. The increase primarily reflects revenue collections generated from the Longanesi field from the second half of 2025, collections on electricity sales receivable from RNG plants, and the timing of payments of accounts payable during the year ended December 31, 2025 compared to the same period in 2024.
Cash used in investing activities
Cash used in investing activities decreased by $16.1 million for the year ended December 31, 2025, compared to the year ended December 31, 2024.
In both periods presented, investing cash flows primarily reflected continued development of the Longanesi wells. The increase of cash used in investing activities during the year ended December 31, 2025 was driven by a lower level of completion, and tie-in activity relative to the same period in 2024. During the second quarter of 2025, the five Longanesi wells were brought online, resulting in only a partial year of capitalized costs. Capital expenditures during the year ended December 31, 2025 primarily reflected final tie-in work and capital calls from our operating partner, Padana, for the permanent Longanesi processing facility. In year ended December 31, 2024, cash used in investing activities also reflects approximately $9.5 million of cash used to purchase three separate renewable natural gas assets, and approximately $5.1 million paid to Blugas as part of the Blugas Settlement (exclusive of VAT).
Cash provided by financing activities
Cash provided by financing activities decreased $61.0 million for the year ended December 31, 2025, compared to the year ended December 31, 2024.
Cash provided by financing activities during the year ended December 31, 2025 reflects proceeds from cash exercises of Public Warrants. Cash provided by financing activities during the year ended December 31, 2024 reflects pre-Business Combination issuances of AleAnna Energy Class 1 Preferred Units used to fund our operations. Such Class 1 Preferred Units were exchanged for Class A and Class C commons stock as part of the Business Combination. The cash proceeds from the Business Combination, net of expenses allowed to be capitalized, had a negligible impact on financing cash flows as the majority of the Business Combination transaction expenses were required to be expensed and were included in net loss within operating cash flows.
Contractual Obligations and Other Commitments
Participation Agreements and Blugas ORRI
In the normal course of business, we enter into agreements with other entities to assist in the performance of drilling of the Longanesi field. On June 26, 2009, we entered into a Participation Agreement with Padana for the drilling of the ‘Longanesi 1 exploration well, ‘San Potito’ concession and ‘Abbadessee 1’ exploration,’ collectively referred to as the Longanesi field.
The Unified Operating Agreement arrangement was originally signed between Eni and Grove and dated September 26, 2009. However, Padana has succeeded Eni as the operator and 66.5% working interest owner, and we succeeded Grove as the non-operator and 33.5% working interest owner. On July 13, 2016, we acquired a 33.5% working interest in the Longanesi field from Enel, and, as part of the purchase, acquired a legacy contingent liability arising from an agreement between the Longanesi working interest’s original owner Grove Energy and Blugas. Blugas retained an interest akin to an ORRI, whereby Blugas was entitled to physical delivery of 20% of the first 350 million standard cubic meters (approximately 2,472 106ft3) produced from the Longanesi field. Prior to the Blugas settlement in May 2024 (as further described below), in accounting for the acquisition of the 33.5% working interest, we did not recognize an asset or liability in the consolidated financial statements related to the Blugas ORRI as our SEC Case reserves estimates contemplated the contractual arrangement and physical gas delivery to Blugas, such that the gas revenues attributable to our 33.5% working interest were reduced to reflect sale of the Blugas quantity and payment of such revenues (cash outflows to Blugas).
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The physical volumes due to Blugas were being contested by us as usury because we considered, among other reasons, that extraction services and all associated risks are executed by us and that participation by Blugas was limited to financing a part of the sum necessary to start drilling, without participation in the construction and exploitation of the reservoir, and therefore do not share the risks or costs, which had increased compared to the initial forecast of the investment.
On May 28, 2024, we entered into the Blugas Settlement Agreement regarding the Blugas ORRI whereby Blugas was entitled to physical delivery of 20% of the first 350 million standard cubic meters (approximately 2,472 106ft3) produced from the Longanesi field. Under the terms of the Blugas Settlement Agreement, we paid Blugas approximately €5 million, plus an additional €1.1 million in applicable VAT, or a total of approximately $6.6 million. In exchange, we were released from any future liability related to the Blugas ORRI. As a result of the transactions contemplated by the Blugas Settlement Agreement, our 33.5% working interest in the Longanesi field is now unencumbered except for normal government royalties (10%). The Blugas Settlement Agreement was accounted for as an acquisition of the Blugas ORRI claim with a corresponding increase to the expected future cash flows from our reserves. Our year-end December 31, 2023 reserve quantities included the 20% of 350 million standard cubic meters (approximately 2,472 106ft3) allocable to the Blugas ORRI in our proved gas reserves. However, the required payments to Blugas associated with the sale of such quantities were reflected as cash outflows (costs) in our year-end December 31, 2023 reserve report as if such amounts were paid to Blugas. Following settlement, our year-end December 31, 2024 reserve quantities continue to include the 20% of 350 million standard cubic meters (approximately 2,472 106ft3), however, the previously required payments to Blugas associated with the sale of such quantities are no longer reflected as cash outflows (costs) as if such amounts were paid to Blugas. As the cash outflows (costs) are no longer reflected as if paid to Blugas, such amounts are reflected in our December 31, 2024 reserve report as allocable to our unencumbered 33.5% working interest.
Contingent Consideration Liability
In connection with our purchase of our 33.5% working interest in the Longanesi field, consideration paid included €7 million cash and up to €24 million of deferred consideration payable upon production of the Longanesi field. The deferred consideration is payable based on a formulaic calculation which is predominantly dependent on sales volumes and spot natural gas prices during the first 12 years of production (the “Earn-Out Period”). There will be no deferred consideration due if Longanesi is not developed and no deferred consideration due if average annual gas prices are less than €3.65/Mcf over the Earn-Out Period. Upon first production, we were also required to issue a bank guarantee of €3 million secured by cash collateral of €1 million related to the contingent consideration liability which is classified as restricted cash as of December 31, 2025. The cash collateral may be used to satisfy the contingent consideration liability as payments become due.
We recognized a liability for the contingent consideration in accounting for the asset acquisition in accordance with ASC 450, Contingencies (“contingent consideration liability”). As of December 31, 2025, and December 31, 2024, the total contingent consideration liability was recorded at $28.2 million and $25.0 million, respectively, with $11.6 million and nil being classified as a short-term and $16.7 million and the entire balance being classified as a long-term liability for the respective periods.
Internal Control over Financial Reporting
Effective internal controls are necessary to provide reliable financial reports and prevent fraud. AleAnna is a newly public company that is in the process of adding resources with the appropriate level of experience and technical expertise to oversee AleAnna’s business processes and controls. At this time, AleAnna does not have the necessary business processes and related internal controls formally designed and implemented.
As a result, AleAnna previously identified material weaknesses in its internal control over financial reporting. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of annual or interim financial statements would not be prevented or detected on a timely basis.
In connection with the preparation of AleAnna’s financial statements as of and for the year ended December 31, 2025, management of AleAnna identified material weaknesses in its internal control over financial reporting.
We have made significant progress on our remediation plan specific to material weakness identified with completion of the following tasks:
| ● | Designing and implementing a risk assessment process supporting the identification of risks facing AleAnna. |
| ● | Implementing controls to enhance our review of significant accounting transactions and other new technical accounting and financial reporting issues and preparing and reviewing accounting memoranda addressing these issues. |
| ● | Hiring additional experienced accounting, financial reporting and internal control personnel and changing roles and responsibilities of our personnel as we transition to being a public company and are required to comply with Section 404 of the Sarbanes-Oxley Act. |
| ● | Implementing controls to enable an accurate and timely review of accounting records that support our accounting processes and maintain documents for internal accounting reviews. |
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The Company believes that these measures described above will remediate the identified material weakness and strengthen the Company’s internal control over financial reporting. Management has begun to take these actions to remediate the Material Weaknesses and may take additional measures to address control deficiencies or determine to modify, or in the appropriate circumstances not to complete, certain of the remediation measures identified. The Material Weaknesses will not be considered remediated until the remediation plan has been implemented and there has been appropriate time to conclude through testing that the controls are operating effectively. If the steps the Company takes do not remediate the material weakness in a timely manner, there could be a reasonable possibility that these control deficiencies or others may result in a material misstatement of its annual or interim financial statements that would not be prevented or detected on a timely basis. This, in turn, could jeopardize the Company’s ability to comply with its reporting obligations, limit its ability to access the capital markets and adversely impact its stock price.
Emerging Growth Company Accounting Election
Section 102(b)(1) of the JOBS Act exempts emerging growth companies from being required to comply with new or revised financial accounting standards until private companies are required to comply with the new or revised financial accounting standards. The JOBS Act provides that a company can elect not to take advantage of the extended transition period and comply with the requirements that apply to non-emerging growth companies, and any such election to not take advantage of the extended transition period is irrevocable. We expect to be an emerging growth company at least through 2026.
Critical Accounting Policies and Estimates
Our consolidated financial statements are based on the selection and application of significant accounting policies. The preparation of our management’s discussion and analysis of our financial condition and results of operations is based on our audited consolidated financial statements as of and for the years ended December 31, 2025 and 2024, which have been prepared in accordance with U.S. GAAP. In preparing these financial statements, we make estimates and assumptions impacting asset and liability amounts, disclosure of contingent liabilities, and expenses incurred.
The estimates are based on our historical experience and on various other factors that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. We regularly assess these estimates; however, actual amounts could differ materially from those estimates under different assumptions or conditions. The most significant items involving management’s estimates include estimates of contingencies including the contingent consideration liability discussed below. The impact of changes in estimates is recorded in the period in which they become known.
The accounting policies discussed below are critical to understanding our historical and future performance, as these policies relate to the more significant areas involving management’s judgments and estimates.
Conventional Natural Gas Properties
We use the successful efforts method of accounting for conventional gas-producing activities. Under this method, the cost of productive wells and related equipment, development dry holes, and any permits related to productive acreage are capitalized, and depleted using the unit-of-production method. Depletion expense is calculated using the units-of-production method, which allocates the cost of natural resources based on the number of units extracted during a period. These costs include other internal costs directly attributable to production activities. Costs for exploratory dry holes, exploratory geological and geophysical activities, and delay rentals as well as other property carrying costs are charged to exploration expense.
Proved gas reserves, are those quantities of gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward from known reservoirs and under existing economic conditions, operating methods and government regulations prior to the time at which contracts providing the right to operate expire unless evidence indicates that renewal is reasonably certain regardless of whether deterministic or probabilistic methods are used for the estimation.
The estimates of proved natural gas reserves (“SEC Case”) utilized in the preparation of our consolidated financial statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. The development of our natural gas reserve quantities requires management to make significant estimates and assumptions related to the intent and ability to complete undeveloped proved reserves within a five-year development period, as prescribed by SEC guidelines. Management engaged DeGolyer to prepare reserves estimates for our estimated proved reserves at December 31, 2025, and 2024. The technologies used in the estimation of our net proved undeveloped reserves include, but are not limited to, empirical evidence through drilling results and well performance, production data, decline curve analysis, well logs, geologic maps, core data, seismic data, demonstrated relationship between geologic parameters and performance, and the implementation and application of statistical analysis.
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Management has confirmed that none of the Unitized Operating Agreement’s reserves nor the Proved Undeveloped Reserves (“PUDs”) are scheduled to be developed on a date more than five years from the date the reserves were initially recognized as PUDs as prescribed by SEC guidelines. PUDs are converted from undeveloped to developed as applicable wells begin production.
Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. Such estimates are subject to the uncertainties inherent in the application of judgmental factors in interpreting such information. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the volume of natural gas reserves, the remaining estimated lives of natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per-unit depletion rates, while decreases in recoverable economic volumes generally increase per-unit depletion rates.
Impairment of Natural Gas Properties
The carrying values of the Company’s natural gas properties are reviewed for impairment when events or circumstances indicate that the remaining carrying value may not be recoverable. To determine whether impairment of the Company’s natural gas properties has occurred, the Company compares the estimated expected undiscounted future cash flows to the carrying values of those properties. Estimated future cash flows are based on proved and, if determined reasonable by management, risk-adjusted probable reserves and assumptions generally consistent with the assumptions used by the Company for internal planning and budgeting purposes, including, among other things, the intended use of the asset, anticipated production from reserves, future market prices for natural gas adjusted for basis differentials, future operating costs and inflation. Proved gas properties that have carrying amounts in excess of estimated future undiscounted cash flows are written down to fair value, which is estimated by discounting the estimated future cash flows using discount rates and other assumptions that marketplace participants would use in their fair value estimates. The company recorded no impairment of natural gas properties during 2025 or 2024.
Revenue Recognition
General — We follow the guidance of FASB Accounting Standards Codification 606, Revenue from Contracts with Customers (“ASC 606”). The core principle underlying revenue recognition under ASC 606 is that revenue should be recognized as goods or services are transferred to customers in an amount that reflects the consideration to which we expect to be entitled. ASC 606 defines a five-step process to achieve recognition and mandates additional disclosure about the nature, amount, timing and uncertainty of revenues and cash flows arising from customer contracts, including significant judgments, and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract.
Conventional Natural Gas (“Conventional”) — On October 29, 2024, we entered into a gas sale agreement (“GSA”) with Shell Energy Europe Limited, under which SEEL became the exclusive purchaser of AleAnna’s share of natural gas produced from the Longanesi field net of (i) any consumption and/or losses incurred in the transport, treatment and compression of gas before delivery; (ii) any volume to be allocated for regulated royalties auctions, if applicable; and (iii) any other volume contractually allocated to other parties before August 31, 2022.
The GSA features variable pricing based on a published benchmark, the Punto di Scambio Virtuale (“PSV”), with fixed discounting. Accordingly, revenue under the GSA is highly sensitive to market prices and may fluctuate significantly as natural gas prices rise or fall. SEEL typically remits payment monthly, shortly after delivery. The timing of payment does not introduce a significant financing component.
AleAnna is not subject to return or refund obligations under the GSA unless the transmission operator refuses delivery of gas that does not meet industry-standard specifications. The gas sold generally conforms to such specifications, which are verified at the point of transfer to the transmission system.
All consideration under the GSA is variable, reflecting both price and volume. Revenue is recognized based on the amount of variable consideration allocated to distinct units of natural gas delivered. This allocation reflects the total consideration AleAnna expects to receive for completed deliveries, and the variability in consideration is directly tied to the satisfaction of the performance obligations. Our performance obligations under our hydrocarbon sales agreements are to deliver our entire working interest in the natural gas production from the Longanesi field.
Under the working interest agreement with Padana, AleAnna receives its share of processed gas in-kind and sells it to SEEL. AleAnna’s performance obligation is satisfied upon delivery of the processed gas to SEEL at the designated delivery point, which is the entry point on the Italian transmission system, as defined in the GSA.
Trade receivables arising from these sales of electricity and natural gas are evaluated for impairment under ASC 326 using the simplified approach. Based on the short-term nature of the receivables and the credit quality of the customers, the Company generally does not record an allowance for credit losses.
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Renewable Natural Gas —We earn revenue through electricity generation sales from the conversion of bio feedstocks to biogas which is then converted to electricity through reciprocating generators. Such electricity is then delivered onto the grid through a metered interconnection and sold to the local state-owned electrical utility responsible for the purchase and marketing of energy produced by small-scale renewable energy assets. Upon delivery of the electricity to the grid, all performance obligations have been satisfied, and energy generation revenue is recognized based on actual output and non-company specific predetermined prices for small renewable energy producers of €280/MWh, established under Ministerial Decree (D.M.) 18 December 2008, which sets tariff rates for small renewable energy producers in Italy.
Revenue is recognized over time as we transfer the electricity to the grid at a metered interconnection. The customer obtains control of the product upon delivery onto the electrical grid. We generally have a single performance obligation in our arrangements with our customers. We have no long-term contracts containing quantity or electricity volume production requirements and there is no variable consideration present in our performance obligations. Per ASC 606-10-25-27(a), delivery of units of power that are simultaneously received and consumed by the customer would satisfy the criteria to be accounted for as a performance obligation satisfied over time and the same method would be used to measure the entity’s progress towards complete satisfaction of the performance obligation to transfer each distinct unit of power in the series to the customer. Our performance obligation related to the sales of electricity are satisfied over time upon delivery to the customer. Revenue is measured as the amount of consideration we expect to receive in exchange for transferring our products. We apply a practical expedient in FASB ASC 606-10-55-18 applicable to our sales by assessing whether our right to consideration corresponds directly with the value to our customers (the “invoice practical expedient”). We concluded that pricing corresponds to the value provided to the customer.
Business Combinations and Asset Acquisitions
We evaluate whether a transaction meets the definition of a business. We first apply a screen test to determine if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or group of similar identifiable assets. If the screen test is met, the transaction is accounted for as an asset acquisition. If the screen test is not met, we further consider whether the set of assets acquired have, at a minimum, inputs and processes that have the ability to create outputs in the form of revenue. If the assets acquired meet this criteria, the transaction is accounted for as a business combination.
Acquisitions that qualify as an asset acquisition are accounted for using a cost accumulation model where the purchase price of the acquisition is allocated to the assets acquired on a relative fair value basis on the date of acquisition. We generally account for acquisitions of renewable natural gas assets as asset acquisitions. Inputs used to determine such fair values are primarily based upon internally-developed estimates, estimates developed by third-party valuation firms, and publicly-available data regarding renewable natural gas asset transactions consummated by other buyers and sellers, as applicable. These fair values are considered Level 3 assets in the fair value hierarchy. Any associated acquisition costs are generally capitalized.
Acquisitions that qualify as a business combination are accounted for using the acquisition method of accounting. The fair value of consideration transferred for an acquisition is allocated to the assets acquired and liabilities assumed based on their fair value on a nonrecurring basis on the acquisition date and are subject to fair value adjustments under certain circumstances. The excess of the consideration transferred over the fair value of assets acquired and liabilities assumed is recorded as goodwill. Conversely, in the event the fair value of assets acquired and liabilities assumed is greater than the consideration transferred, a bargain purchase gain is recognized.
Determining the fair value of assets acquired and liabilities assumed requires judgment and often involves the use of significant estimates and assumptions as fair values are not always readily determinable. Different techniques may be used to determine fair values, including market prices (where available), comparisons to transactions for similar assets and liabilities and the discounted net present value of estimated future cash flows, among others. We engage third-party valuation firms when appropriate to assist in the fair value determination of assets acquired and liabilities assumed. Acquisition-related expenses and transaction costs associated with business combinations are expensed as incurred. We may adjust the amounts recognized in an acquisition during a measurement period not to exceed one year from the date of acquisition, as a result of subsequently obtaining additional information that existed at the acquisition date.
Where applicable, asset acquisitions may be owned together with unaffiliated outside parties. In acquisitions where we have a majority direct controlling interest, the unaffiliated outside ownership is shown as noncontrolling interests in members’ equity in our consolidated financial statements.
Contingent Consideration Liability
On July 13, 2016, AleAnna Europa S.r.l., a former subsidiary of AleAnna Resources LLC (which was subsequently merged into AleAnna Italia S.p.A. in December 2022), purchased a 33.5% working interest in the Longanesi field, which was accounted for as an asset acquisition. Consideration paid included €7 million cash and up to €24 million of deferred consideration payable upon production of the Longanesi field. The deferred consideration is payable based on a formulaic calculation which is predominantly dependent on sales volumes and spot natural gas prices during the first 12 years of the Earn-Out Period.
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We recognized a liability for the contingent consideration in accounting for the asset acquisition in accordance with ASC 450, Contingencies (the “contingent consideration liability”) based on our assessment of probability of the occurrence of payment and deemed the liability estimable based on the formulaic nature. See Note 6 for more information.
Income Taxes
The Company follows the asset and liability method of accounting for income taxes under ASC 740, “Income Taxes.” Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the consolidated financial statements carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that included the enactment date. Valuation allowances are established, when necessary, to reduce deferred tax assets to the amount expected to be realized.
ASC 740 prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. For those benefits to be recognized, a tax position must be more likely than not to be sustained upon examination by taxing authorities. The Company recognizes accrued interest and penalties related to unrecognized tax benefits as income tax expense. There were no unrecognized tax benefits and no amounts accrued for interest and penalties as of December 31, 2025 or 2024. The Company is currently not aware of any issues under review that could result in significant payments, accruals or material deviation from its position. The Company is subject to income tax examinations by major taxing authorities since inception.
Asset Retirement Obligation
We recognize a liability for asset retirement obligations (“AROs”) based on an estimate of the amount and timing of settlement at the time a legal obligation is incurred. Upon initial recognition of an ARO, we increase the carrying amount of the long-lived asset by the same amount as the liability. The initial capitalized costs will be depleted over the useful (productive) lives of the related assets.
Our asset retirement obligations relate to the abandonment of gas production facilities including reclaiming well pads, reclaiming water impoundments, plugging wells and dismantling related structures. Estimates are based on historical experience of plugging and abandoning wells and reclaiming of disposing other assets and estimated remaining (productive) lives of the wells and assets. No incremental ARO liabilities were incurred during the years ended December 31, 2025 or 2024.
Long-Term Incentive Plan
We utilize the closing stock price on the date of grant to determine the fair value of stock awards and service-vesting awards, which includes restricted stock units (“RSUs”), and performance stock units (“PSUs”) with a performance condition. For PSUs with a market condition, grant date fair value is determined using a Black-Scholes Model. Unvested awards are entitled to dividends or dividend equivalents which are accrued and distributed to award recipients at the time such awards vest. Dividends are forfeitable if the related award is forfeited. For RSUs and PSUs with performance conditions, forfeitures are recognized in the period in which they occur. For PSU awards with market conditions, forfeitures are only recognized if the award recipient does not render the required service during the measurement period.
Share-based compensation expense for restricted stock awards with no requisite service period is recognized in the financial statements immediately on date of grant. Share-based compensation expense for RSUs with a requisite service period is recognized in the financial statements over the awards’ vesting periods using the graded-vesting method.
Item 7A: Quantitative and Qualitative Disclosure About Market Risk
Pursuant to Item 305(e) of Regulation S-K (§ 229.305(e)), the Company is not required to provide the information required by this Item as it is a “smaller reporting company,” as defined by Rule 229.10(f)(1).
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Item 8. Financial Statements and Supplementary Data
Index to Financial Statements
Report of Independent Registered Public Accounting Firm (PCAOB ID: | F-2 |
| Consolidated Balance Sheets | F-3 |
| Consolidated Statements of Operations and Comprehensive Income (Loss) | F-4 |
| Consolidated Statements of Changes in Stockholders’ and Members’ Equity | F-5 |
| Consolidated Statements of Cash Flows | F-6 |
| Notes to the Consolidated Financial Statements | F-7 |
F-1
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the stockholders and the Board of Directors of AleAnna, Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of AleAnna, Inc. and subsidiaries (the “Company”) as of December 31, 2025 and 2024, the related consolidated statements of operations and comprehensive income (loss), changes in stockholders’ equity, and cash flows, for each of the two years in the period ended December 31, 2025, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/
March 30, 2026
We have served as the Company’s auditor since 2023.
F-2
ALEANNA, INC.
CONSOLIDATED BALANCE SHEETS
AS OF DECEMBER 31, 2025 AND 2024
| Footnote Reference | December 31, 2025 | December 31, 2024 | ||||||||||
| ASSETS | ||||||||||||
| Current Assets: | ||||||||||||
| Cash and cash equivalents | $ | $ | ||||||||||
| Restricted cash | ||||||||||||
| Accounts receivable | ||||||||||||
| Prepaid expenses and other assets | ||||||||||||
| Total Current Assets | ||||||||||||
| Non-current assets: | ||||||||||||
| Natural gas and other properties, successful efforts method, net of accumulated depreciation and depletion of $ | 7 | |||||||||||
| Renewable natural gas properties, net of accumulated depreciation of $ | 7 | |||||||||||
| Value-added tax refund receivable | ||||||||||||
| Operating lease right-of-use assets | ||||||||||||
| Total Non-current Assets | ||||||||||||
| Total Assets | $ | $ | ||||||||||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||||||
| Current Liabilities: | ||||||||||||
| Accounts payable and accrued expenses | $ | $ | ||||||||||
| Income tax payable | ||||||||||||
| Lease liability, short-term | ||||||||||||
| Contingent consideration liability, short-term | 6 | |||||||||||
| Total Current Liabilities | ||||||||||||
| Non-current Liabilities: | ||||||||||||
| Asset retirement obligation | 3 | |||||||||||
| Deferred tax liability | ||||||||||||
| Lease liability, long-term | ||||||||||||
| Contingent consideration liability, long-term | 6 | |||||||||||
| Total Non-current Liabilities | ||||||||||||
| Total Liabilities | ||||||||||||
| Commitments and Contingencies | 8 | |||||||||||
| Stockholders’ Equity: | ||||||||||||
| Class A Common Stock, par value $ | ||||||||||||
| Class C Common Stock, par value $ | ||||||||||||
| Additional paid-in capital | ||||||||||||
| Accumulated other comprehensive loss | ( | ) | ( | ) | ||||||||
| Accumulated deficit | ( | ) | ( | ) | ||||||||
| Noncontrolling interest | ||||||||||||
| Total Stockholders’ Equity | ||||||||||||
| Total Liabilities and Stockholders’ Equity | $ | $ | ||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-3
ALEANNA, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
FOR THE YEARS ENDED DECEMBER 31, 2025 AND 2024
| Footnote | For the Year Ended December 31, | |||||||||
| Reference | 2025 | 2024 | ||||||||
| Revenues | 14 | $ | $ | |||||||
| Operating expenses: | ||||||||||
| Cost of revenues | $ | $ | ||||||||
| Lease operating expense | ||||||||||
| General and administrative | ||||||||||
| Depreciation and depletion | 7 | |||||||||
| Accretion of asset retirement obligation | ||||||||||
| Business combination transaction expenses | 2 | |||||||||
| Total operating expenses | ||||||||||
| Operating income (loss) | ( | ) | ||||||||
| Other income: | ||||||||||
| Interest and other income | ||||||||||
| Change in fair value of derivative liability | ||||||||||
| Total other income | ||||||||||
| Income (loss) before income taxes | ( | ) | ||||||||
| Income tax expense | 11 | ( | ) | |||||||
| Net income (loss) | ( | ) | ||||||||
| Deemed dividend to Class 1 Preferred Units redemption value | ( | ) | ||||||||
| Net loss (income) attributable to noncontrolling interests | ( | ) | ||||||||
| Net income (loss) attributable to Class A Common stockholders or holders of Common Member Units | $ | $ | ( | ) | ||||||
| Other comprehensive income (loss) | ||||||||||
| Currency translation adjustment | $ | $ | ( | ) | ||||||
| Comprehensive income (loss) | ( | ) | ||||||||
| Comprehensive loss (income) attributable to noncontrolling interests | ( | ) | ||||||||
| Total comprehensive income (loss) attributable to Class A Common stockholders or holders of Common Member Units | $ | $ | ( | ) | ||||||
| Weighted average shares of Class A Common Stock outstanding, basic and diluted | ||||||||||
| Net income (loss) per share of Class A Common Stock, basic and diluted | 13 | $ | ||||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-4
ALEANNA, INC.
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ AND MEMBERS’ EQUITY
FOR THE YEARS ENDED DECEMBER 31, 2025 and 2024
| Stockholders’ Equity | ||||||||||||||||||||||||||||||||||||
| Class A | Class C | Additional | Accumulated other | Total | ||||||||||||||||||||||||||||||||
| Common Stock | Amount | Common Stock | Amount | paid-in capital | Accumulated deficit | comprehensive income (loss) | Noncontrolling interest | Stockholders’ Equity | ||||||||||||||||||||||||||||
| Balance, December 31, 2024 | $ | $ | $ | $ | ( | ) | $ | ( | ) | $ | $ | |||||||||||||||||||||||||
| Exercises of warrants | ||||||||||||||||||||||||||||||||||||
| Foreign currency translation | - | - | ||||||||||||||||||||||||||||||||||
| Stock compensation expense | - | - | ||||||||||||||||||||||||||||||||||
| Net income | - | - | ||||||||||||||||||||||||||||||||||
| Balance, December 31, 2025 | $ | $ | $ | $ | ( | ) | $ | ( | ) | $ | $ | |||||||||||||||||||||||||
| Temporary Equity | Members’ Equity | |||||||||||||||||||||||||||||||||||||||||||||||||||
| Class 1 | Common | Class A | Class C | Additional | Accumulated Other | Total | ||||||||||||||||||||||||||||||||||||||||||||||
| Preferred Units | Amount | Member Units | Amount | Common Stock | Amount | Common Stock | Amount | paid-in capital | Accumulated deficit | comprehensive loss | Noncontrolling interest | Stockholders’ Equity | ||||||||||||||||||||||||||||||||||||||||
| Balance, December 31, 2023 | $ | $ | $ | $ | $ | $ | ( | ) | $ | ( | ) | $ | $ | ( | ) | |||||||||||||||||||||||||||||||||||||
| Shares issued | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Deemed dividend to redemption value | - | - | - | - | ( | ) | ( | ) | ||||||||||||||||||||||||||||||||||||||||||||
| Recapitalization transaction | ( | ) | ( | ) | ( | ) | ||||||||||||||||||||||||||||||||||||||||||||||
| Foreign currency translation | - | - | - | - | ( | ) | ( | ) | ( | ) | ||||||||||||||||||||||||||||||||||||||||||
| Net loss | - | - | - | - | ( | ) | ( | ) | ( | ) | ||||||||||||||||||||||||||||||||||||||||||
| Noncontrolling interest acquired | - | - | - | - | ||||||||||||||||||||||||||||||||||||||||||||||||
| Balance, December 31, 2024 | $ | $ | $ | $ | $ | $ | ( | ) | $ | ( | ) | $ | $ | |||||||||||||||||||||||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
F-5
ALEANNA, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 2025 AND 2024
| Footnote | For the Year Ended December 31, | |||||||||
| Reference | 2025 | 2024 | ||||||||
| Cash flows from operating activities | ||||||||||
| Net income (loss) | $ | $ | ( | ) | ||||||
| Adjustments to reconcile net income (loss) to net cash used in operating activities: | ||||||||||
| Depreciation, depletion, and amortization | 7 | |||||||||
| Accretion of asset retirement obligation | ||||||||||
| Share based compensation | 10 | |||||||||
| Deferred tax liability | 11 | |||||||||
| Change in fair value of derivative liability | ( | ) | ||||||||
| Changes in operating assets and liabilities: | ||||||||||
| Accounts receivable | ( | ) | ( | ) | ||||||
| Prepaid expenses and other assets | ( | ) | ||||||||
| Value-added tax refund receivable | ( | ) | ( | ) | ||||||
| Accounts payable and accrued expenses | ||||||||||
| Income tax payable | ||||||||||
| Related party payables | ( | ) | ||||||||
| Change in operating lease liability | ( | ) | ||||||||
| Net cash provided by (used in) operating activities | ( | ) | ||||||||
| Cash flows from investing activities | ||||||||||
| Additions to renewable natural gas properties | 7 | ( | ) | ( | ) | |||||
| Additions to conventional natural gas properties | 7 | ( | ) | ( | ) | |||||
| Net cash used in investing activities | ( | ) | ( | ) | ||||||
| Cash flows from financing activities | ||||||||||
| Proceeds from exercises of warrants | 9 | |||||||||
| Business Combination transaction expenses eligible for capitalization | ( | ) | ||||||||
| AleAnna Energy Class 1 Preferred Units issued for cash | ||||||||||
| Net cash provided by financing activities | ||||||||||
| Effect of foreign currency translation on cash | ( | ) | ||||||||
| Change in cash, cash equivalents and restricted cash during the period | ||||||||||
| Cash, cash equivalents and restricted cash, beginning of period | ||||||||||
| Cash, cash equivalents and restricted cash, end of period | $ | $ | ||||||||
| Noncash investing and financing activities: | ||||||||||
| Deemed dividend to Class 1 Preferred Units redemption value | 9 | $ | $ | ( | ) | |||||
The accompanying notes are an integral part of these consolidated financial statements.
F-6
ALEANNA, INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
AS OF AND FOR THE YEARS ENDED DECEMBER 31, 2025 AND 2024
NOTE 1 – NATURE OF OPERATIONS AND RECENT EVENTS
AleAnna, Inc. (together with its subsidiaries, the “Company” or “AleAnna”), a Delaware corporation, was formed on
Conventional Natural Gas
AleAnna is a natural gas resource developer focused on delivering critical natural gas supplies to Europe through both onshore conventional natural gas exploration and renewable natural gas development in Italy. The Company has several conventional natural gas discoveries including the Longanesi field, located in the Po Valley in Northern Italy, which is one of Italy’s largest modern gas discoveries. AleAnna retains a
On October 29, 2024, the Company entered into a gas sale agreement (“GSA”) with Shell Energy Europe Limited (“SEEL”), whereby SEEL became the exclusive buyer of AleAnna’s share of the natural gas produced from the Longanesi field net of (i) any consumption and/or losses incurred in the transport, treatment and compression of gas before delivery; (ii) any volume to be allocated for regulated royalties auctions, if applicable; and (iii) any other volume contractually allocated to other parties before August 31, 2022. Future sales under the GSA are contingent upon the commencement of gas production.
On March 13, 2025, AleAnna achieved a key milestone with the first production from its working interests in five wells in the Longanesi field, and the field reached sustained maximum production during the second quarter of 2025. The Company began recognizing revenue and related expenses, including depreciation and depletion, associated with Longanesi production in the second quarter of 2025.
Renewable Natural Gas (“RNG”)
In 2023, AleAnna launched a renewable natural gas (“RNG”) development business focused on bringing to market carbon negative renewable natural gas derived from animal and agricultural waste.
Between March 2024 and July 2024, the Company successfully completed three separate strategic acquisitions of RNG assets in Italy for an aggregate of approximately $
Campagnatico Asset Acquisition
In the first quarter of 2024, the Company closed the acquisition of the Campagnatico Greenfield (“Campagnatico”) asset to be converted into a biomethane producing plant in Tuscany, Italy for approximately $
Casalino and Campopiano Asset Acquisitions
On July 8, 2024, the Company closed the acquisition of the Società Agricola Fattoria delle Jersey S.S. plant asset (“Casalino”) for approximately $
The Company plans to begin upgrading the sites to refine biogas into biomethane through upgrading units. Following the upgrade process to transition the assets to biomethane conversion, the Company expects to sell renewable natural gas to customer(s) by trucking or via connection to the interstate pipeline system.
F-7
The Company has a
AleAnna Energy Member Contributions
During 2024, AleAnna Energy received $
NOTE 2 – REVERSE RECAPITALIZATION TRANSACTION
On December 13, 2024 (the “Closing Date”), the previously announced business combination was consummated pursuant to that certain Agreement and Plan of Merger (as amended by that certain First Amendment to the Merger Agreement, dated as of October 8, 2024, the “Merger Agreement”), dated June 4, 2024, by and among Swiftmerge Acquisition Corp., a Cayman Islands exempted company (“Swiftmerge”), Swiftmerge HoldCo LLC, a Delaware limited liability company and wholly-owned subsidiary of Swiftmerge (“HoldCo”), Swiftmerge Merger Sub LLC, a Delaware limited liability company and wholly-owned subsidiary of HoldCo (“Merger Sub”) and AleAnna Energy (the “Merger”). The transactions contemplated by the Merger Agreement are collectively referred to herein as the “Business Combination.”
The Business Combination included, among other things:
| ● | (i) SPAC undergoing the Domestication and changing its name to “AleAnna, Inc.”; (ii) each Swiftmerge Class A Ordinary Share converting into one share of Class A Common Stock; (iii) each Swiftmerge Class B Ordinary Share converting into one share of Class B Common Stock in the Domestication and then each share of Class B Common Stock converting into one share of Class A Common Stock at the completion of the Business Combination; (iv) each warrant to purchase Swiftmerge Class A Ordinary Shares becoming exercisable by its terms to purchase an equal number of shares of Class A Common Stock; and (v) a series Class C Common Stock being authorized, each share of which will have voting rights equal to a share of Class A Common Stock but which shall have no entitlement to earnings or distributions of the Company; |
| ● | following the Domestication but prior to the Merger, (i) the Company contributed to HoldCo (a) all of its assets (excluding its interests in HoldCo), including, for the avoidance of doubt, the Available Cash (as defined herein), and (b) a number of shares of Class C Common Stock equal to the number of Class C HoldCo Units designated to be issued to the AleAnna Members, and (ii) HoldCo issued to the Company a number of Class A HoldCo Units which equaled the number of shares of Class A Common Stock issued and outstanding immediately after the Closing; and |
| ● | following the Pre-Closing Contribution, Merger Sub merged with and into AleAnna Energy, with AleAnna Energy being the surviving company and a wholly-owned subsidiary of HoldCo. Each AleAnna Energy Member received its pro rata portion of |
| ● | AleAnna, Inc. received |
| ● | Nautilus Resources LLC received |
| ● | Bonanza Resources (Texas) Inc., the only other AleAnna Energy Member, received |
The Business Combination was accounted for as a common control transaction with respect to AleAnna Energy, which is akin to a reverse recapitalization. Nautilus Resources LLC (“Nautilus”), the majority owner of AleAnna Energy, had a controlling financial interest in AleAnna Energy prior to the Business Combination and has a controlling financial interest in the Company, as AleAnna Energy is a subsidiary of HoldCo, in which AleAnna, Inc. holds a majority economic interest. The net assets of Swiftmerge are stated at their historical carrying amounts with no goodwill or intangible assets recognized in accordance with U.S. GAAP. The Business Combination with respect to AleAnna Energy was not treated as a change in control primarily due to Nautilus receiving the controlling voting stake in the Company and the ability of Nautilus to nominate the full board of directors and management of the Company.
In accounting for the Business Combination, Swiftmerge was treated as the “acquired” company for financial reporting purposes. Accordingly, for accounting purposes, the Business Combination was treated as the equivalent of AleAnna Energy issuing stock for the net assets of Swiftmerge, accompanied by a recapitalization.
F-8
The Class A common stock, par value $
Total proceeds raised from the Business Combination were $
As of December 31, 2025, shares of Class C Common Stock had been exchanged for shares of Class A Common Stock.
NOTE 3 – BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation — The accompanying consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America (“U.S. GAAP”) as determined by the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) ,and in conformity with the rules and regulations of the Securities and Exchange Commission (“SEC”).
Principles of Consolidation — The Company’s policy is to consolidate all entities that the Company controls by ownership interest or other contractual rights giving the Company control over the most significant activities of an investee. The consolidated financial statements include the accounts of AleAnna and its wholly-owned subsidiaries HoldCo, AleAnna Energy, AleAnna Resources, LLC, AleAnna Italia S.p.A., AleAnna Renewable and the RNG Subsidiaries. All intercompany balances and transactions have been eliminated in consolidation.
Use of Estimates — The preparation of consolidated financial statements in conformity with accounting principles U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of expenses, assets, liabilities and disclosure of contingent assets and liabilities. The Company regularly assesses these estimates; however, actual amounts could differ from those estimates. The most significant items involving management’s estimates include estimates of contingencies including contingent consideration and estimates of the timing and amount of asset retirement obligations. The impact of changes in estimates is recorded in the period in which they become known.
Significant Accounting Policies — The preparation of financial statements in conformity with U.S. GAAP requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities, revenues and expenses, and disclosures related to these amounts at the date of the financial statements. The Company evaluates these estimates and assumptions on an ongoing basis based on current and historical developments, market conditions, industry trends and other information that the Company believes to be reasonable under the circumstances. The Company can make no assurance that actual results will conform to its estimates and assumptions; reported results of operations may be materially affected by changes in these estimates and assumptions.
Emerging Growth Company — The Company is an “emerging growth company” as defined in Section 2(a) of the Securities Act, as modified by the Jumpstart Our Business Startups Act of 2012 (the “JOBS Act”), and it may take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that are not emerging growth companies including, but not limited to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002, reduced disclosure obligations regarding executive compensation in its periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and stockholder approval of any golden parachute payments not previously approved.
Further, Section 102(b)(1) of the JOBS Act exempts emerging growth companies from being required to comply with new or revised financial accounting standards until private companies (that is, those that have not had a Securities Act registration statement declared effective or do not have a class of securities registered under the Exchange Act) are required to comply with the new or revised financial accounting standards. The JOBS Act provides that an emerging growth company can elect to opt out of the extended transition period and comply with the requirements that apply to non-emerging growth companies but any such election to opt out is irrevocable. The Company has elected not to opt out of such extended transition period, which means that when a standard is issued or revised and it has different application dates for public or private companies, the Company, as an emerging growth company, can adopt the new or revised standard at the time private companies adopt the new or revised standard. This may make comparison of the Company’s consolidated financial statements with another public company that is neither an emerging growth company nor an emerging growth company that has opted out of using the extended transition period difficult because of the potential differences in accounting standards used.
F-9
Risks and Uncertainties — The development of the Company’s projects is subject to a number of risks and uncertainties including, but not limited to, the receipt of the necessary permits and regulatory approvals, commodity price risk impacting the decision to go forward with the projects, and the availability and ability to obtain the necessary financing for the development of projects.
The Company’s ability to develop and operate commercial production facilities, as well as expand production at future commercial production facilities, is subject to many risks beyond its control, including regulatory developments, construction risks, and global and regional macroeconomic developments.
Functional and Reporting Currency — The functional currency of an entity is the currency of the primary economic environment in which the entity operates. The functional currency of the Italian subsidiary is the Euro, and the Company is the United States Dollar (“USD” or “U.S. Dollar”). The determination of functional currency was made in accordance with ASC 830, Foreign Currency Matters.
The Company’s reporting currency is the USD. For the purposes of presenting consolidated financial statements, the assets and liabilities of the Company’s Euro operations are translated to USD at the exchange rate at the end of each month prior to consolidation procedures. The income and expenses are translated using average exchange rates for the applicable period. Foreign currency differences that arise on translation for consolidated purposes are recognized in accumulated other comprehensive income (loss) on the consolidated balance sheet and in other comprehensive income (loss) as a currency translation adjustment on the consolidated statements of operations and comprehensive income (loss).
Concentration of Credit Risk — Financial instruments that potentially subject the Company to concentrations of credit risk consist of cash accounts in financial institution which, at times may exceed the Federal Depository Insurance Corporation coverage limit of $
Business Combinations and Asset Acquisitions — To evaluate whether an acquiree meets the definition of a business, the Company first applies a screen test to determine if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or group of similar identifiable assets. If the screen test is met, the transaction is accounted for as an asset acquisition. If the screen test is not met, the Company further considers whether the set of assets acquired have, at a minimum, inputs and processes that have the ability to create outputs in the form of revenue. If the assets acquired meet this criteria, the transaction is accounted for as a business combination.
Acquisitions that qualify as an asset acquisition are accounted for using a cost accumulation model where the purchase price of the acquisition is allocated to the assets acquired on a relative fair value basis on the date of acquisition. The Company generally accounts for acquisitions of RNG assets as asset acquisitions. Inputs used to determine such fair values are primarily based upon internally-developed estimates, estimates developed by third-party valuation firms, and publicly-available data regarding RNG asset transactions consummated by other buyers and sellers, as applicable. These fair values are considered Level 3 assets in the fair value hierarchy. Any associated acquisition costs are generally capitalized.
Acquisitions that qualify as a business combination are accounted for using the acquisition method of accounting. The fair value of consideration transferred for an acquisition is allocated to the assets acquired and liabilities assumed based on their fair value on a nonrecurring basis on the acquisition date and are subject to fair value adjustments under certain circumstances. The excess of the consideration transferred over the fair value of assets acquired and liabilities assumed is recorded as goodwill. Conversely, in the event the fair value of assets acquired and liabilities assumed is greater than the consideration transferred, a bargain purchase gain is recognized.
Determining the fair value of assets acquired and liabilities assumed requires judgment and often involves the use of significant estimates and assumptions as fair values are not always readily determinable. Different techniques may be used to determine fair values, including market prices (where available), comparisons to transactions for similar assets and liabilities and the discounted net present value of estimated future cash flows, among others. The Company engages third-party valuation firms when appropriate to assist in the fair value determination of assets acquired and liabilities assumed. Acquisition-related expenses and transaction costs associated with business combinations are expensed as incurred. The Company may adjust the amounts recognized in an acquisition during a measurement period not to exceed one year from the date of acquisition, as a result of subsequently obtaining additional information that existed at the acquisition date.
Where applicable, asset acquisitions may be owned together with unaffiliated outside parties. In acquisitions where the Company has majority direct controlling interest, the unaffiliated outside ownership is shown as noncontrolling interests (“NCI”) in stockholders’ equity in the Company’s consolidated financial statements.
Cash and Cash Equivalents — Cash and cash equivalents represent cash and short-term, highly liquid investments with maturities of three months or less at the time of purchase. Cash equivalents consisted of a money market fund which is recorded at fair value. The Company had approximately $
F-10
Restricted Cash — Restricted cash consists of amounts that are held in escrow accounts or otherwise segregated to satisfy specific contractual obligations. The Company’s restricted cash relates to amounts reserved in connection with its contingent consideration liability (see Note 6).
| For the year ended December 31, | ||||||||
| 2025 | 2024 | |||||||
| Beginning of year: | ||||||||
| Cash and cash equivalents | $ | $ | ||||||
| Restricted cash | ||||||||
| $ | $ | |||||||
| End of year: | ||||||||
| Cash and cash equivalents | $ | $ | ||||||
| Restricted cash | $ | |||||||
| $ | $ | |||||||
Financial Instruments — The carrying values of the Company’s financial instruments, consisting of cash and cash equivalents and accounts payable, approximate their fair value due to the short maturity of such instruments. Unless otherwise noted, it is management’s opinion that the Company is not exposed to significant interest or currency risks arising from these financial instruments.
Fair Value Measurement — The Company applies fair value accounting to all financial assets and liabilities measured on a recurring and nonrecurring basis. Fair value is defined as an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. As such, fair value is a market-based measurement that should be determined based on assumptions that market participants would use in pricing an asset or a liability.
The accounting guidance establishes a fair value hierarchy based on three levels of inputs, of which the first two are considered observable and the last unobservable, used to determine the fair value of its financial instruments. A financial instrument’s level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement.
| Level 1 | Quoted prices in active markets for identical assets or liabilities that the entity has the ability to access. | |
| Level 2 | Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities, quoted prices in markets that are not active, or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets and liabilities. | |
| Level 3 | Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets and liabilities. |
In some circumstances, the inputs used to measure fair value might be categorized within different levels of the fair value hierarchy. In those instances, the fair value measurement is categorized in its entirety in the fair value hierarchy based on the lowest level input that is significant to the fair value measurement.
Conventional Natural Gas Properties — The Company uses the successful efforts method of accounting for gas producing activities. Under this method, the cost of productive wells and related equipment, development dry holes, and any permits related to productive acreage are capitalized, and depleted using the unit-of-production method. Depletion expense is calculated using the units-of-production method, which allocates the cost of natural resources based on the number of units extracted during a period. These costs include other internal costs directly attributable to production activities. Costs for exploratory dry holes, exploratory geological and geophysical activities, and delay rentals as well as other property carrying costs are charged to exploration expense.
There were no exploratory wells drilled and there were no capitalized exploratory well costs incurred during the years ended December 31, 2025 and 2024. Asset additions in 2025 primarily related to the construction of the Longanesi processing facility. Asset additions in 2024 primarily related to the drilling and testing of three incremental Longanesi development wells.
F-11
The estimates of proved natural gas reserves (“SEC Case”) utilized in the preparation of the Consolidated Financial Statements are estimated in accordance with the rules established by the Securities and Exchange Commission and the FASB. These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. The development of the Company’s natural gas reserve quantities requires management to make significant estimates and assumptions related to the intent and ability to complete undeveloped proved reserves within a five-year development period, as prescribed by SEC guidelines. Management engaged DeGolyer and MacNaughton, independent reserve engineers, to prepare reserves estimates for the Company’s estimated proved reserves at December 31, 2025 and 2024. The technologies used in the estimation of the Company’s net proved undeveloped reserves include, but are not limited to, empirical evidence through drilling results and well performance, production data, decline curve analysis, well logs, geologic maps, core data, seismic data, demonstrated relationship between geologic parameters and performance, and the implementation and application of statistical analysis.
Management has confirmed that none of the Unitized Operating Agreements (“UOAs”) nor the Proved Undeveloped Reserves (“PUDs”) are scheduled to be developed on a date more than five years from the date the reserves were initially recognized as PUDs as prescribed by the SEC guidelines. PUDs are converted from undeveloped to developed as applicable wells begin production.
Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. Such estimates are subject to the uncertainties inherent in the application of judgmental factors in interpreting such information. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of natural gas reserves, the remaining estimated lives of natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates, while decreases in recoverable economic volumes generally increase per unit depletion rates.
Impairment of Natural Gas Properties — The carrying values of the Company’s natural gas properties are reviewed for impairment when events or circumstances indicate that the remaining carrying value may not be recoverable. To determine whether impairment of the Company’s natural gas properties has occurred, the Company compares the estimated expected undiscounted future cash flows to the carrying values of those properties. Estimated future cash flows are based on proved and, if determined reasonable by management, risk-adjusted probable reserves and assumptions generally consistent with the assumptions used by the Company for internal planning and budgeting purposes, including, among other things, the intended use of the asset, anticipated production from reserves, future market prices for natural gas adjusted for basis differentials, future operating costs and inflation. Proved gas properties that have carrying amounts in excess of estimated future undiscounted cash flows are written down to fair value, which is estimated by discounting the estimated future cash flows using discount rates and other assumptions that marketplace participants would use in their fair value estimates. The company recorded no impairment of natural gas properties during 2025 or 2024.
Value-Added Tax Refund Receivable — The Valued-Added Tax (“VAT”) is a broadly-based consumption tax that is assessed to the value that is added to goods and services. The VAT applies to nearly all goods and services that are bought and sold within the European Union. Italian law allows for certain VAT payments to be recovered through ongoing applications for refunds. The Company has incurred higher VAT input paid (i.e., VAT paid on purchases) than the VAT output collected (i.e., VAT collected on sales), resulting in a net VAT refund receivable.
Under Italian tax law, VAT refunds receivable may be applied against future tax liabilities. Given the legal framework ensuring recoverability of these amounts, management believes the risk of non-collection is minimal, and therefore no reserve for uncollectible amounts is applied against the receivable.
Leases — The Company recognizes right-of-use assets and lease liabilities for leases with terms greater than 12 months. Leases are classified as either finance or operating leases. This classification dictates whether lease expense is recognized based on an effective interest method or on a straight-line basis over the term of the lease. Short-term leases (leases with an initial term of 12 months or less or leases that are cancelable by the lessee and lessor without significant penalties) are not capitalized but are expensed on a straight-line basis over the lease term.
Non-842 Leases: Leases to explore for or use minerals, oil, natural gas, and similar nonregenerative resources (see ASC 930, Extractive Activities — Mining, and ASC 932, Extractive Activities — Oil and Gas) are excluded from the scope of ASC 842, Leases. The Company has surface and use agreements for Longanesi, Gradizza, Trava, and Armonia in Italy. These agreements are directly related to accessing the subsurface minerals and are assessed as part of the oil and gas properties.
Credit Losses — The Company uses a forward-looking expected credit loss model for in-scope financial assets. Provisions for credit losses that are estimated through the Company’s prescribed method of estimating losses are recorded against earnings through a corresponding entry to Allowance for Credit Losses. Financial assets are presented net of the Allowance for Credit Losses. Any recoveries of amounts previously estimated as a credit loss are recorded against Allowance for Credit Losses.
In accordance with ASC 326, Financial Instruments — Credit Losses, the Company estimates the allowance for credit losses using relevant available information about expected credit losses. Inputs to the model include benchmarking against other companies, customer attributes, past events, current conditions, and reasonable and supportable forecasts. Adjustments to historical loss information are made for differences in current receivable-specific risk characteristics such as changes in the economy and demand trends, or other relevant factors. The Company’s financial assets measured at amortized cost primarily consist of trade receivables.
F-12
The assessment of the correlation between historical losses, current conditions, and forecasted economic conditions requires judgment. Alternative interpretations of these factors could have resulted in different conclusions regarding the allowance for credit losses. The amount of credit loss is sensitive to changes in circumstances and forecasted economic conditions. The Company’s experience, current conditions, and forecast of economic conditions may also not be representative of the customers’ actual default experience in the future.
Income Taxes — The Company follows the asset and liability method of accounting for income taxes under ASC 740, “Income Taxes.” Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the consolidated financial statements carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that included the enactment date. Valuation allowances are established, when necessary, to reduce deferred tax assets to the amount expected to be realized.
ASC 740 prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions taken or expected to be taken in a tax return. For those benefits to be recognized, a tax position must be more likely than not to be sustained upon examination by taxing authorities. The Company recognizes accrued interest and penalties related to unrecognized tax benefits as income tax expense. There were no unrecognized tax benefits and no amounts accrued for interest and penalties as of December 31, 2025 or 2024. The Company is currently not aware of any issues under review that could result in significant payments, accruals or material deviation from its position. The Company is subject to income tax examinations by major U.S. and Italian taxing authorities since inception.
Warrants and Derivative Liability — The Company accounts for the Public Warrants in accordance with the guidance contained in Accounting Standards Codification 815, Derivatives and Hedging (“ASC 815”) under which the warrants meet the criteria for equity treatment and are recorded as equity. Such guidance provides that the Public Warrants are not precluded from equity classification because they are indexed to the Company’s own stock and do not require cash settlement. Additionally, the warrants meet the criteria for equity classification as they (i) do not provide the holder with rights that are contingently redeemable, (ii) are not considered to be freestanding derivatives requiring liability classification under ASC 480, and (iii) do not have terms that would require the Company to net cash settle to the warrants. Equity-classified contracts are initially measured at fair value (or allocated value). Subsequent changes in fair value are not recognized as long as the contracts continue to be classified in equity. During the year ending December 31, 2025, holders exercised an aggregate
The Company evaluates the existence of separable embedded features within applicable debt or equity instruments pursuant to ASC 815. Professional standards generally provide three criteria that, if met, require companies to bifurcate embedded features from their host instruments and separately account for them as derivative. These three criteria include circumstances in which (a) the economic characteristics and risks of the embedded derivative instrument are not clearly and closely related to the economic characteristics and risks of the host contract, (b) the hybrid instrument that embodies both the embedded derivative instrument and the host contract is not re-measured at fair value under otherwise applicable generally accepted accounting principles with changes in fair value reported in earnings as they occur and (c) a separate instrument with the same terms as the embedded derivative instrument would be considered a derivative instrument.
Asset Retirement Obligations — The Company recognizes a liability for asset retirement obligations (“AROs”) based on an estimate of the amount and timing of settlement at the time a legal obligation is incurred. Upon initial recognition of an ARO, the Company increases the carrying amount of the long-lived asset by the same amount as the liability. The initial capitalized costs are depleted over the useful (productive) lives of the related assets.
The Company’s asset retirement obligations relate to the abandonment of gas production facilities including reclaiming well pads, reclaiming water impoundments, plugging wells and dismantling related structures. Estimates are based on historical experience of plugging and abandoning wells and reclaiming or disposing other assets and estimated remaining (productive) lives of the wells and assets.
The following table presents a reconciliation of the beginning and ending carrying amounts of the Company’s asset retirement obligations included in non-current liabilities in the Consolidated Balance Sheets.
| December 31, 2025 | December 31, 2024 | |||||||
| Balance January 1 | $ | $ | ||||||
| Liabilities incurred | ||||||||
| Accretion | ||||||||
| Ending balance | $ | $ | ||||||
No incremental ARO liabilities were incurred during the year ended December 31, 2025 or 2024. Changes in the ARO relate to the accretion of the existing liability. The Company does not have any assets that are legally restricted for purposes of settling these obligations.
Contingent Consideration liability — The Company recognized a liability for the contingent consideration in accounting for the asset acquisition in accordance with ASC 450, Contingencies (“contingent consideration liability”) based on the Company’s assessment of probability of the occurrence of payment and deemed the liability estimable based on the formulaic nature. See Note 6 for more information.
F-13
Long-Term Incentive Plan — The Company utilizes the closing stock price on the date of grant to determine the fair value of stock awards and service-vesting awards, which for the Company includes restricted stock units (“RSUs”), and performance stock units (“PSUs”) with a performance condition. For PSUs with a market condition, grant date fair value is determined using a Black-Scholes Model. Unvested awards are entitled to dividends or dividend equivalents which are accrued and distributed to award recipients at the time such awards vest. Dividends are forfeitable if the related award is forfeited. For RSUs and PSUs with performance conditions, forfeitures are recognized in the period in which they occur. For PSU awards with market conditions, forfeitures are only recognized if the award recipient does not render the required service during the measurement period.
Share-based compensation expense for restricted stock awards with no requisite service period is recognized in the financial statements immediately on date of grant. Share-based compensation expense for RSUs with a requisite service period is recognized in the financial statements over the awards’ vesting periods using the graded-vesting method.
Revenue Recognition — The Company follows the guidance of the ASC 606, Revenue from Contracts with Customers (“ASC 606”). The core principle underlying revenue recognition under ASC 606 is that revenue should be recognized as goods or services are transferred to customers in an amount that reflects the consideration to which the Company expects to be entitled. ASC 606 defines a five-step process to achieve recognition and mandates additional disclosure about the nature, amount, timing and uncertainty of revenues and cash flows arising from customer contracts, including significant judgments, and changes in judgments and assets recognized from costs incurred to obtain or fulfill a contract.
Renewable Natural Gas (“RNG”) — The RNG Subsidiaries earn revenue through electricity generation sales from the conversion of bio feedstocks to biogas which is then converted to electricity through reciprocating generators. Such electricity is then delivered onto the grid through a metered interconnection and sold to the local state-owned electrical utility responsible for the purchase and marketing of energy produced by small-scale renewable energy assets. Upon delivery of the electricity to the grid, all performance obligations have been satisfied, and energy generation revenue is recognized based on actual output and non-company specific predetermined prices for small renewable energy producers of €
Revenue is recognized as the Company transfers the electricity to the grid at a metered interconnection. The customer obtains control of the product upon delivery onto the electrical grid. The Company generally has a single performance obligation in its arrangements with its customers. The Company has no long-term contracts containing quantity or electricity volume production requirements and there is no variable consideration present in the Company’s performance obligations. Per ASC 606-10-25-27(a), delivery of units of power that are simultaneously received and consumed by the customer would satisfy the criteria in to be accounted for as a performance obligation satisfied over time and the same method would be used to measure the entity’s progress towards complete satisfaction of the performance obligation to transfer each distinct unit of power in the series to the customer. The Company’s performance obligation related to the sales of electricity are satisfied over time upon delivery to the customer. Revenue is measured as the amount of consideration the Company expects to receive in exchange for transferring its products. The Company applies a practical expedient in FASB ASC 606-10-55-18 applicable to its sales by assessing whether the Company’s right to consideration corresponds directly with the value to the Company’s customer (the “invoice practical expedient”). The Company concluded that its pricing corresponds to the value provided to the customer. Consideration for each transaction is based upon non-company specific predetermined prices for small renewable energy producers of €
Conventional Natural Gas (“Conventional”) — On October 29, 2024, the Company entered into a GSA with Shell Energy Europe Limited (“SEEL”), under which SEEL became the exclusive purchaser of AleAnna’s share of natural gas produced from the Longanesi field net of (i) any consumption and/or losses incurred in the transport, treatment and compression of gas before delivery; (ii) any volume to be allocated for regulated royalties auctions, if applicable; and (iii) any other volume contractually allocated to other parties before August 31, 2022.
The GSA features variable pricing based on a published benchmark, the Punto di Scambio Virtuale (“PSV”), with fixed discounting. Accordingly, revenue under the GSA is highly sensitive to market prices and may fluctuate significantly as natural gas prices rise or fall. SEEL typically remits payment monthly, shortly after delivery. The timing of payment does not introduce a significant financing component.
AleAnna is not subject to return or refund obligations under the GSA unless the transmission operator refuses delivery of gas that does not meet industry-standard specifications. The gas sold generally conforms to such specifications, which are verified at the point of transfer to the transmission system.
All consideration under the GSA is variable, reflecting both price and volume. Revenue is recognized based on the amount of variable consideration allocated to distinct units of natural gas delivered. This allocation reflects the total consideration the Company expects to receive for completed deliveries, and the variability in consideration is directly tied to the satisfaction of the performance obligations. The performance obligations under our hydrocarbon sales agreements are to deliver our entire working interest in the natural gas production from the Longanesi field.
F-14
Under the working interest agreement with Padana, AleAnna receives its share of processed gas in-kind and sells it to SEEL. AleAnna’s performance obligation is satisfied upon delivery of the processed gas to SEEL at the designated delivery point, which is the entry point on the Italian transmission system, as defined in the GSA.
Trade receivables arising from these sales of electricity and natural gas are evaluated for impairment under ASC 326 using the simplified approach. Based on the short-term nature of the receivables and the credit quality of the customers, the Company generally does not record an allowance for credit losses.
For the year ended December 31, 2025, the Company’s Conventional segment sold all conventional gas production to Shell Energy Europe Limited, which accounted for approximately $
NOTE 4 – RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS
Accounting Changes Recently Adopted
In December 2023, the FASB issued ASU 2023-09 to improve disclosures and presentation requirements to the transparency of the income tax disclosures by requiring consistent categories and greater disaggregation of information in the rate reconciliation and income taxes paid disaggregated by jurisdiction. The amendments are effective in annual periods beginning after December 15, 2024, with early adoption permitted. The Company adopted the guidance beginning January 1, 2025, and adoption has no material effect on the consolidated financial statements and disclosures.
Effective for the year ended December 31, 2025, the Company adopted ASC 280 and ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, due to the Company’s evaluation of operating results between conventional and renewable operations becoming more relevant to the chief operating decision maker in connection with the commencement of production at the Longanesi field. In accordance with the transition guidance, the Company applied these changes retrospectively to all prior periods presented. See Note 14 for further details. The amendments require disclosure of significant segment expense categories that are regularly provided to the Chief Operating Decision Maker (“CODM”) and included in each reported measure of segment profit or loss, disclosure of an amount for other segment items and a description of its composition, extension of certain annual segment disclosures to interim periods, and disclosure of the title and position of the CODM and how the CODM uses the reported segment measure(s).
Accounting Changes Not Yet Adopted
In November 2024, the FASB issued ASU 2024-03 to improve the disclosures about a public business entity’s expenses. The update requires more detailed information on expense components, such as inventory purchases, employee compensation, depreciation, amortization, and depletion, within commonly reporting categories like cost of sales, SG&A, and research and development. These amendments are effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. The Company is currently evaluating the provisions of the amendments and the impact on its future consolidated statements and disclosures.
NOTE 5 – RIGHT-OF-USE ASSETS AND RELATED LIABILITIES
In July 2024, in conjunction with the Casalino acquisition, AleAnna entered into a lease of the land that holds the biomethane processing and conversion asset utilized to produce electricity. The lease term is from July 1, 2024 through December 31, 2032, with an
The Company does not have any borrowings; therefore, it does not have a readily determinable incremental borrowing rate readily determinable, and there was no incremental borrowing rate implicit in the Casalino land lease. As such, the Company utilized a discount rate of
F-15
NOTE 6 – CONTINGENT CONSIDERATION LIABILITY
On July 13, 2016, AleAnna Europa S.r.L., a former subsidiary of AleAnna Resources LLC (which was subsequently merged into AleAnna Italia S.p.A. in December 2022), purchased a
The Company recognized a liability for the contingent consideration in accounting for the asset acquisition in accordance with ASC 450, Contingencies (the “contingent consideration liability”).
In connection with Longanesi start-up in May 2025, the Company issued a $
As of December 31, 2025 the contingent consideration liability was recorded at $
Changes in the contingent consideration liability attributable to factors other than foreign currency exchange rates are recognized in the consolidated statements of operations. Changes in the contingent consideration liability attributable to foreign currency translation are recognized in other comprehensive income (loss) within the consolidated statement of operations and comprehensive income (loss). The change in the contingent consideration liability for all periods presented is attributable to changes in foreign exchange rates.
NOTE 7 – NATURAL GAS PROPERTIES
Conventional Natural Gas Properties
A summary of conventional natural gas properties is as follows:
| December 31, 2025 | December 31, 2024 | |||||||
| Natural gas properties | $ | $ | ||||||
| Less: Accumulated impairment | ( | ) | ( | ) | ||||
| Less: Accumulated depreciation and depletion | ( | ) | ||||||
| Natural gas and other properties, net | $ | $ | ||||||
The Company uses the successful efforts method of accounting for conventional natural gas-producing activities. Under this method, the cost of productive wells and related equipment, development dry holes, and any permits related to productive acreage are capitalized and depleted using the unit-of-production method. Costs for exploratory dry holes, exploratory geological and geophysical activities, and delay rentals as well as other property carrying costs are charged to exploration expense.
There were no exploratory wells drilled and there were material capitalized exploratory well costs incurred during the years ended December 31, 2025 or 2024. Asset additions during the year ended December 31, 2025 primarily related to the construction of the Longanesi processing facility. Asset additions during the year ended December 31, 2024 primarily related to the drilling and testing of three incremental Longanesi development wells. The company recorded impairment of natural gas properties during the years ended December 31, 2025 or 2024. The change in accumulated impairment relates to the effects of foreign currency translation adjustments.
First Production at Longanesi
On March 13, 2025, AleAnna achieved a key milestone with the first production from its five wells in the Longanesi field and began recognizing revenue and related expenses, including depreciation and depletion, related to this production during the second quarter of 2025. AleAnna generated approximately $
F-16
Renewable Natural Gas Properties
A summary of renewable natural gas properties is as follows:
| December 31, 2025 | December 31, 2024 | |||||||
| Renewable natural gas properties | $ | $ | ||||||
| Less: Accumulated depreciation and depletion | ( | ) | ( | ) | ||||
| Renewable natural gas properties, net | $ | $ | ||||||
During the year ended December 31, 2025, all RNG revenue was derived from a single source (sales of electricity) and a single customer (the local state-owned electrical utility). As of December 31, 2025, the Company had $
As of December 31, 2025 and 2024, renewable natural gas properties included $
NOTE 8 – COMMITMENTS AND CONTINGENCIES
Participation Agreements
In conjunction with the closing of the Enel acquisition, AleAnna became a participant in the Longanesi Unitization Agreement (“UA”) with Società Padana Energia (“Padana”). The UA governs Padana’s San Potito Concession and AleAnna’s San Marco Concession into a production unit. At the same time, AleAnna became a participant in the Unified Operating Agreement (“UOA”), which governs the bylaws by which Padana and AleAnna agree to develop the unit and fund future operations.
Under the UOA, AleAnna and Padana have agreed to jointly develop the Longanesi field per a plan approved by the Italian Ministry of the Environment (“MISE”). AleAnna and Padana entered the UOA with initial participating shares in the Longanesi field equal to
AleAnna and Padana fund their respective working interest shares of the capital required for Longanesi development and receive their respective shares of the production output from the unitized field. However, such working interest percentages may be subsequently amended as more certainty is obtained over the Gas Originally in Place (“GOIP”) through redetermination procedures prescribed by the UOA. The redetermination process evaluates the results of the current development drilling program (well logs, production tests, etc.) and other new data that may be gathered prior to or during the drilling process (such as 3D seismic imaging) to determine if new data gathered have changed the respective working interest percentages. If a redetermination process suggests GOIP changes, but AleAnna and Padana do not agree on revised working interest percentages, an independent third party will opine and set the revised working interest allocations. Adjustments to future production entitlements and capital contributions may be made accordingly. Cash payments may be made between the participants where there is insufficient production to true up contributions to date. If a true up of historical capital contributions is required as a result of redetermination, such capital true-up amounts will include an interest charge based on the nine-month Euribor and the date of the original capital contribution.
On October 26, 2023, Padana formally called for the First Redetermination process, as defined in the UOA, to begin. However, the outcome of this or any future redetermination, which may impact working interest percentages and require a capital contribution rebalancing, is highly uncertain and such amounts are not estimable at this time. Accordingly, as of December 31, 2025, AleAnna had not recorded any receivable from or payable to Padana related to the redetermination process.
Contingencies and Legal Proceedings
The Company is subject to loss contingencies related to litigation, claims, investigations and legal and administrative cases and proceedings arising in the ordinary course of business. The Company evaluates these contingencies on a regular basis and accrues a liability for such matters when the Company believes that a loss is probable, and the amount of the loss can be reasonably estimated. Any such accruals are adjusted thereafter as appropriate to reflect changed circumstances. In the event the Company determines that (i) a loss to the Company is probable, but the amount of the loss cannot be reasonably estimated, or (ii) a loss to the Company is less likely than probable but is reasonably possible, then the Company is required to disclose the matter herein, although the Company is not required to accrue such loss.
When able, the Company determines an estimate of reasonably possible losses or ranges of reasonably possible losses, whether in excess of any related accrued liability or where there is no accrued liability, for legal proceedings.
In instances where such estimates can be made, any such estimates are based on the Company’s analysis of currently available information and are subject to significant judgment and a variety of assumptions and uncertainties and may change as new information is obtained.
F-17
The ultimate outcome of the matters described below, such as whether the likelihood of loss is remote, reasonably possible, or probable, or if and when the range of loss is reasonably estimable, is inherently uncertain.
Furthermore, due to the inherent subjectivity of the assessments and unpredictability of outcomes of legal proceedings, any amounts accrued or estimated as possible losses may not represent the ultimate loss to the Company from the legal proceedings in question and the Company’s exposure and ultimate losses may be higher, and possibly significantly so, than the amounts accrued or estimated.
As described in Note 1, AleAnna acquired a
On May 28, 2024, the Company entered into the Blugas Settlement Agreement with Blugas regarding the Blugas ORRI. Under the terms of the Blugas Settlement Agreement, the Company paid Blugas approximately €
The Blugas Settlement Agreement was accounted for as an acquisition of the Blugas ORRI claim with a corresponding increase to the estimated future cash flows from our reserves. As such, the cost of the acquisition is included in natural gas and other properties, with the VAT portion included in value-added tax refund receivable in the consolidated balance sheet as of December 31, 2025 and December 31, 2024. The Company’s year-end December 31, 2023 reserve quantities included the
NOTE 9 – EQUITY
AleAnna Common Stock and Noncontrolling Interests – As of December 31, 2025, the Company had
Following the Business Combination, AleAnna, Inc. became the sole managing member of HoldCo and received
As of December 31, 2025, AleAnna, Inc. held approximately
As of December 31, 2025 the noncontrolling interest presented in the Company’s consolidated financial statements primarily relates to the
F-18
Warrants – There were
The Company may call the Public Warrants for redemption:
| ● | in whole and not in part; | |
| ● | at a price of $ | |
| ● | upon not less than 30 days’ prior written notice of redemption (the “30-day redemption period”) to each Public Warrant holder; | |
| ● | if, and only if, the reported last sale price of the Class A Common Stock equals or exceeds $ | |
| ● | if, and only if, there is a current registration statement in effect with respect to the Class A Common Stock underlying such Public Warrants. |
In the event that the Company elects to redeem all of the redeemable Public Warrants, it will fix a date for the redemption. Pursuant to the terms of the warrant agreement, notice of redemption will be mailed by first class mail, postage prepaid, by not less than 30 days prior to the redemption date to the registered holders of the redeemable Public Warrants to be redeemed at their last addresses as they appear on the registration books. Any notice mailed in the manner provided in the warrant agreement will be conclusively presumed to have been duly given whether or not the registered holder received such notice.
The Company has established the last of the redemption criterion discussed above to prevent a redemption call unless there is at the time of the call a significant premium to the Public Warrant exercise price. If the foregoing conditions are satisfied and the Company issues a notice of redemption of the Public Warrants, each Public Warrant holder will be entitled to exercise his, her or its Public Warrant prior to the scheduled redemption date. However, the price of the Class A Common Stock may fall below the $
Through December 31, 2025, holders had exercised an aggregate
AleAnna Energy Members’ Equity (pre-Business Combination) – Prior to the Business Combination the Company had Common Units and Class 1 Preferred Units issued and outstanding.
Due to the redemption features of the Class 1 Preferred Units, they were recorded at redemption value and classified as temporary equity in the consolidated balance. The difference between the book value of Class 1 Preferred Units issued and the redemption value, less the amount attributable to the derivative liability, was recorded as a deemed dividend in periods prior to the Business Combination. AleAnna Energy’s Class 1 Preferred Units and Common Units were exchanged for AleAnna common stock in connection with the Business Combination.
NOTE 10 – EXECUTIVE COMPENSATION
Employment Agreements
On September 1, 2022, the Company entered into an employment agreement with the CEO. Within this employment agreement, there is a Medium/Long Term Incentive Plan (“M/LTIP” or the “Plan”) outlined, which includes cash bonus amounts to be paid based on the completion of certain milestones within the established thresholds. Such payments could result in total payments ranging from €
The Company tracks each of the milestones for the executive compensation package based on the current and future business plans. Based on the metrics and performance indicators outlined in the executive compensation package, management has concluded that the likelihood of achieving each of these metrics is not probable based on the financial performance as of December 31, 2025.
AleAnna, Inc. 2025 Long-Term Incentive Plan
On June 12, 2025, the stockholders approved and adopted the AleAnna, Inc. 2025 Long-Term Incentive Plan (“LTIP”). The LTIP provides for the grant of both incentive stock options (“ISOs”) and nonqualified stock options (“NSOs” and together with ISOs, “Stock Options”), as well as the grant of stock appreciation rights (“SARs”), restricted stock, restricted stock units (“RSUs”), performance awards, dividend equivalent rights, and other awards, which may be granted separately or in combination or in tandem with other awards, and which may be paid in cash or shares of our common stock.
F-19
The Company filed a registration statement on Form S-8 to register the underlying shares on October 1, 2025. On October 29, 2025 the Compensation Committee granted awards under the 2025 Long-Term Incentive Plan. Restricted stock units (“RSUs”) generally vest one-third each year over a three-year period following the grant date based on a continuous service requirement. Certain RSUs vest the earliest of the one year anniversary of the grant date or the next annual meeting of the stockholders, provided that such annual meeting occurs at least 52 weeks following the prior annual meeting of the stockholders, and further provided that the participant is employed by or providing services to the Company or subsidiary on such date. Performance stock units (“PSUs”) vest in their entirety on the date the Compensation Committee determines the applicable performance milestone has been satisfied.
The Company accounts for the LTIP in accordance with U.S. GAAP on share-based payments, which requires that compensation cost relating to share-based payments be recognized in the consolidated financial statements based on the fair value of each award. Compensation cost is measured based on the fair value of the award at the grant date and recognized over the service period. Fair value of restricted stock awards and units is based on the grant date value of the underlying stock derived from quoted market prices. The Company recognized stock-based compensation expense, which is included in “General and administrative” expense on the Company’s Consolidated Statement of Operations, of $
Restricted Stock Units (“RSU’s”)
RSU’s are granted to certain employees and non-employee directors. The company has different classes of RSU’s. Generally, RSU’s vest one-third each year over a three-year vesting schedule following the grant date, subject to the holder’s continuous service requirement. Annual RSU’s generally vest upon the earliest of the one year anniversary of the grant date or the next annual meeting of the stockholders, provided that such annual meeting occurs at least 52 weeks following the prior annual meeting of the stockholders, and subject to the holder’s continuous service on such date.
| Number of Shares of RSUs | ||||
| Unvested as of December 31, 2024 | ||||
| Granted | ||||
| Vested | ||||
| Forfeited | ||||
| Unvested as of December 31, 2025 | ||||
| Number of Shares of Annual RSUs | ||||
| Unvested as of December 31, 2024 | ||||
| Granted | ||||
| Vested | ||||
| Forfeited | ||||
| Unvested as of December 31, 2025 | ||||
During the year ended December 31, 2025, the fair value of both RSU’s and Annual RSU’s was $
Performance Stock Units (“PSU’s”)
PSU’s are granted to certain employees at no cost to the recipient and are subject to vesting based on achieving certain performance metrics. Outstanding PSU’s may be settled in cash or shares of common stock or a combination thereof at the sole discretion of the Company.
| Number of Shares of PSUs | ||||
| Unvested as of December 31, 2024 | ||||
| Granted | ||||
| Vested | ||||
| Forfeited | ||||
| Unvested as of December 31, 2025 | ||||
During the year ended December 31, 2025, the fair value of PSUs with a performance-based condition was $
F-20
NOTE 11 – INCOME TAXES
As of December 31, 2025 and 2024, AleAnna, Inc. held
AleAnna Energy was historically and remains a disregarded subsidiary of a partnership for purposes with each partner being separately taxed on its share of taxable income or loss. As a direct result of the Business Combination, HoldCo became the sole member of AleAnna Energy. As such, HoldCo’s distributive share of any net taxable income or loss and any related tax credits of AleAnna Energy are then distributed to the Company.
For the days and periods prior to the closing of the Business Combination, AleAnna Energy was a disregarded subsidiary of an entity treated as a partnership. As such, its net taxable loss and any related tax credits were allocated to its members. The period as of and for the year ended December 31, 2025 discussed below represents the period beginning January 1, 2025 and ending December 31, 2025.
AleAnna’s Italian subsidiary (AleAnna Italia, S.p.A.) is a joint stock company or S.p.A and is considered a corporation under the Italian tax code. Therefore, the statutorily determined cumulative taxable loss of AleAnna Italia was tax affected and recognized as a deferred tax asset as of December 31, 2025 and 2024. The Company has also recorded deferred tax assets for temporary differences between the book and tax basis in the underlying assets and liabilities.
Domestic and foreign income (loss) before provision for income taxes is comprised of the following:
| Years Ended December 31, | ||||||||
| 2025 | 2024 | |||||||
| Domestic | $ | ( | ) | $ | ( | ) | ||
| Foreign | ( | ) | ||||||
| Total | $ | $ | ( | ) | ||||
Income tax expense attributable to operations is comprised of the following:
| Years Ended December 31, | ||||||||
| 2025 | 2024 | |||||||
| Current | ||||||||
| Federal | $ | $ | ||||||
| State | ||||||||
| Foreign | ||||||||
| Total current tax expense | $ | $ | ||||||
| Deferred | ||||||||
| Federal | $ | $ | ||||||
| State | ||||||||
| Foreign | ||||||||
| Total deferred tax expense | ||||||||
| Income tax expense | $ | $ | ||||||
F-21
The Company’s income tax rate differs from the amounts computed by applying the U.S. federal income tax rate of
| Years Ended December 31, | ||||||||||||||||
| Effective tax rate | 2025 | 2024 | ||||||||||||||
| Amount | Percent | Amount | Percent | |||||||||||||
| U.S. federal statutory tax rate | $ | % | $ | ( | ) | % | ||||||||||
| Foreign tax effects | ||||||||||||||||
| Italy | ||||||||||||||||
| Tax rate differential | % | - | % | |||||||||||||
| Regional taxes | % | % | ||||||||||||||
| Deferred tax adjustments | ( | ) | - | % | % | |||||||||||
| Changes in valuation allowance | % | - | % | |||||||||||||
| Other | % | ( | ) | % | ||||||||||||
| Changes in valuation allowance - U.S. | ( | ) | - | % | - | % | ||||||||||
| Nontaxable or Nondeductible Items | ||||||||||||||||
| Partnership income and NCI | % | - | % | |||||||||||||
| Equity compensation | % | % | ||||||||||||||
| Deferred tax adjustments | ( | ) | - | % | % | |||||||||||
| Other | % | % | ||||||||||||||
| $ | % | $ | % | |||||||||||||
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.
| December 31, 2025 | December 31, 2024 | |||||||
| Deferred tax assets: | ||||||||
| Net operating loss carryforwards | $ | $ | ||||||
| Property and equipment | ||||||||
| Asset impairment | ||||||||
| Asset retirement obligation | ||||||||
| Contingent consideration | ||||||||
| Lease liabilities | ||||||||
| Business Combination transaction expenses | ||||||||
| Investment in partnership | ||||||||
| Other assets | ||||||||
| Total deferred tax assets | $ | |||||||
| Valuation allowance | ( | ) | ( | ) | ||||
| Net deferred tax asset | $ | $ | ||||||
| Deferred tax liabilities: | ||||||||
| Accounts receivable | $ | $ | ||||||
| Right-of-use assets | ||||||||
| Property and equipment | ||||||||
| Other | ||||||||
| Total deferred tax liabilities | ||||||||
| Net deferred tax liabilities | $ | ( | ) | $ | ||||
The Company has assessed the realizability of the net deferred tax assets, and in that analysis, has considered the relevant positive and negative evidence available to determine whether it is more likely than not that some portion or all of the deferred tax assets will be realized. In making such a determination, the Company considered all available positive and negative evidence, including future reversals of existing taxable temporary differences, projected future taxable income, tax planning strategies, and recent results of operations. After consideration of all positive and negative evidence, the Company concluded that it is more likely than not that the deferred tax assets for all entities will not be realizable as of December 31, 2025. This conclusion was based on the evaluation of positive and negative evidence, including the Longanesi field commenced production in 2025 and the Company’s recent history of losses. The negative evidence outweighed positive evidence. Consequently, the Company maintains $
F-22
As of December 31, 2025, the Company had $
The Company recognizes the financial statement effects of uncertain income tax positions when it is more likely than not, based on the technical merits, that the position will be sustained upon examination. To the extent the Company’s assessment of such tax positions changes, the change in estimate will be recorded in the period in which the determination is made. As of December 31, 2025 and 2024, the Company had not recorded any uncertain tax positions or accrued interest and penalties on the consolidated balance sheets.
The Company’s income tax filings will be subject to audit by various taxing jurisdictions. The Company will monitor the status of U.S. Federal, state and local income tax returns and Italian tax returns that may be subject to audit in future periods. No U.S. Federal, state and local income tax returns or Italian tax returns are currently under examination by the respective taxing authorities.
On July 4, 2025, the One Big Beautiful Bill Act “OBBBA” was signed into law. The OBBBA makes permanent several items of the Tax Cuts and Jobs Act, including
NOTE 12 – RELATED PARTY TRANSACTIONS
The Company follows FASB ASC subtopic 850-10, Related Party Disclosures, for the identification of related parties and disclosure of related party transactions.
Certain executive officers of AleAnna are currently employed by and participate in employee benefit plans sponsored by an affiliate of Nautilus and provide administrative and support services to AleAnna under a master services agreement. As of December 31, 2025, AleAnna had outstanding payables of $
NOTE 13 – INCOME (LOSS) PER SHARE
The Business Combination was accounted for as a common control transaction with respect to AleAnna Energy which is akin to a reverse recapitalization. This conclusion was based on Nautilus’s controlling financial interest in AleAnna Energy prior to the Business Combination and its continued control over the combined entity. Following the Business Combination, Nautilus holds Class A Common Stock, representing a direct controlling economic interest, and Class C HoldCo Units and Class C Common Stock, representing a noncontrolling economic interest classified as NCI in stockholders’ equity in the Company’s consolidated financial statements.
Prior to the closing of the Business Combination, AleAnna Energy operated as a limited liability company with ownership interests consisting of Common Units and Class 1 Preferred Units. The application of a hypothetical exchange ratio to convert these units into shares of Class A and Class C Common Stock for periods prior to the Business Combination would not reflect the Company’s post-transaction capital structure. Accordingly, the Company has not retroactively applied the hypothetical exchange ratio or presented earnings (net loss) per unit for those historical periods, as such information would not be meaningful or comparable to earnings (net loss) per share presented for periods after the Business Combination. See Note 2, “Reverse Recapitalization Transaction,” for further discussion. EPS for the period from the closing of the Business Combination on December 13, 2024 through December 31, 2024 was immaterial.
For the year ended December 31, 2025, basic net income per share was computed by dividing net income attributable to holders of Class A Common Stock by the weighted average number of shares of Class A Common Stock outstanding during the respective periods. Diluted net income per share was computed by dividing net income attributable to holders of Class A Common Stock by the weighted-average number of shares of Class A Common Stock outstanding, adjusted to give effect to potentially dilutive securities.
For the year ended December 31, 2025, the Company excluded potentially dilutive securities from the computation of diluted net income per share because their inclusions would have been anti-dilutive. As a result, the weighted average number of shares of Class A Common Stock outstanding used to calculate basic and diluted net loss per share is the same. The Class C Common Stock are not participating securities; thus, the application of the two-class method is not required.
F-23
The following table sets forth the computation of net income (loss) used to compute basic net income (loss) per share of Class A Common Stock for the year ended December 31, 2025:
| Year ended December 31, | ||||
| 2025 | ||||
| Net income (loss) | $ | |||
| Income (loss) attributable to noncontrolling interests | ( | ) | ||
| Net Income (loss) attributable to holders of Class A Common Stock | $ | |||
| Weighted average shares of Class A Common Stock outstanding, basic and diluted | ||||
| Net income (loss) per share of Class A Common Stock, basic and diluted | $ | |||
The below shares have been excluded from the computation of diluted per share amounts because their effect would have been anti-dilutive as of December 31, 2025:
| Year ended December 31, | ||||
| 2025 | ||||
| Performance Stock Units | ||||
| Restricted Stock Units | ||||
| Public Warrants | ||||
| Class C Common Shares | ||||
| Total shares excluded | ||||
NOTE 14 – SEGMENT REPORTING
During the first half of 2025, in connection with the commencement of production at the Longanesi field, the Company’s evaluation of operating results between conventional and renewable operations became more relevant to the chief operating decision maker, resulting in further disaggregation of the Company’s reportable segment, As a result, the Company determined it has
| ● | The Conventional segment consists of the natural gas exploration and production activities conducted by AleAnna Italia. The primary product of this segment is conventional natural gas produced from onshore exploration and development in Italy. |
| ● | The Renewable segment consists of the RNG and electricity production activities conducted by AleAnna Renewable and the RNG Subsidiaries. The segment’s primary output is electricity generated from RNG derived from animal and agricultural waste. |
Reconciling items include items not directly attributable to either reportable segment. These include corporate financing and investing activities, as well as administrative functions that support the Company’s overall operations. These items are presented in the segment reconciliation but do not constitute a reportable segment.
All of the Company’s revenue is generated with external customers and located in Italy. All of the Company’s assets, other than corporate assets primarily comprised of cash located in the U.S., are located in Italy.
F-24
Selected financial information by segment is presented in the tables below:
| Year Ended December 31, 2025 | ||||||||||||
| Conventional | Renewable | Total | ||||||||||
| Revenues | $ | $ | $ | |||||||||
| Less: | ||||||||||||
| Cost of revenues | $ | $ | ||||||||||
| Lease operating expense | ||||||||||||
| Segment general and administrative | ||||||||||||
| Depreciation and depletion | ||||||||||||
| Accretion of asset retirement obligation | ||||||||||||
| Segment operating income (loss) | $ | $ | ( | ) | $ | |||||||
| Reconciling items: | ||||||||||||
| Less: Corporate general and administrative | ||||||||||||
| Interest and other income | ||||||||||||
| Income (loss) before income taxes | $ | |||||||||||
| Segment assets | $ | $ | $ | |||||||||
| Corporate and other assets | ||||||||||||
| Total assets | $ | |||||||||||
| Year Ended December 31, 2024 | ||||||||||||
| Conventional | Renewable | Total | ||||||||||
| Revenues | $ | $ | $ | |||||||||
| Less: | ||||||||||||
| Cost of revenues | $ | $ | ||||||||||
| Segment general and administrative | ||||||||||||
| Depreciation and depletion | ||||||||||||
| Accretion of asset retirement obligation | ||||||||||||
| Segment operating income (loss) | $ | ( | ) | $ | ( | ) | $ | ( | ) | |||
| Reconciling items: | ||||||||||||
| Less: Corporate general and administrative | $ | |||||||||||
| Business combination transaction expenses | ( | ) | ||||||||||
| Interest and other income | ||||||||||||
| Change in fair value of derivative liability | ||||||||||||
| Income (loss) before income taxes | $ | ( | ) | |||||||||
| Segment assets | $ | $ | $ | |||||||||
| Corporate and other assets | ||||||||||||
| Total Assets | $ | |||||||||||
F-25
NOTE 15 – SUBSEQUENT EVENTS
The Company evaluated subsequent events and transactions that occurred after the balance sheet date up through the date that the financial statements were issued and determined that there have been no events that have occurred that would require adjustments to our disclosures in the consolidated financial statements.
NOTE 16 – CONVENTIONAL NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED)
The following supplemental information presents the results of natural gas activities in accordance with the successful efforts method of accounting.
The following table presents capitalized costs related to the development of natural gas discoveries (primarily the Longanesi field). See Note 7 for aggregate capitalized costs.
| For the Year Ended December 31, | ||||||||
| 2025 | 2024 | |||||||
| Capitalized costs | ||||||||
| Proved properties | $ | $ | ||||||
| Less: Accumulated depreciation and depletion | ( | ) | ||||||
| Net capitalized costs | $ | $ | ||||||
The following table presents costs incurred for acquisition of properties, exploration costs and development costs. As the Company’s primary activities in 2025 and 2024 involved the development of the Longanesi field, and there were no new acquisitions and minimal exploration activities, the primary costs incurred during 2025 and 2024 were development costs.
| For the Year Ended December 31, | ||||||||
| 2025 | 2024 | |||||||
| Acquisition of properties | $ | $ | ||||||
| Exploration costs | ||||||||
| Development costs | ||||||||
The $
Reserve Information
Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment. Proved undeveloped reserves represent proved reserves expected to be recovered from new wells after substantial development costs are incurred.
F-26
The net reserve information disclosed herein encompasses only the Company’s proved developed and undeveloped Gradizza, Longanesi, and Trava discoveries. Other probable and possible reserves related to Gradizza, Longanesi, and Trava have been excluded. Other prospective resources related to AleAnna’s additional exploration prospects beyond Gradizza, Longanesi, and Trava have also been excluded.
| December 31, 2025 | December 31, 2024 | |||||||
| Natural gas | (106ft3) | |||||||
| Proved developed and undeveloped reserves: | ||||||||
| Balance at January 1 | ||||||||
| Revision of previous estimates | ||||||||
| Due to extensions(1) | ||||||||
| Due to discoveries(1) | ||||||||
| Due to changes in sales prices(1) | ||||||||
| Due to other revisions(1) | ( | ) | ( | ) | ||||
| Balance at December 31 | ||||||||
| Proved developed reserves: | ||||||||
| Balance at January 1 | ||||||||
| Due to extensions(1) | ||||||||
| Balance at December 31 | ||||||||
| Proved undeveloped reserves: | ||||||||
| Balance at January 1 | ||||||||
| Revision of previous estimates | ||||||||
| Due to extensions(1) | ||||||||
| Due to discoveries(1) | ||||||||
| Due to changes in sales prices(1) | ||||||||
| Due to other revisions(1) | ( | ) | ( | ) | ||||
| Balance at December 31 | ||||||||
| (1) |
Standard Measure of Discounted Future Cash Flow
Future net cash flows represent projected revenues from the sale of proved reserves, net of production and development costs (including transportation and gathering expenses, operating expenses and production taxes). Revenues are based on a twelve-month unweighted average of the first-day-of-the-month pricing, without escalation. Future cash flows are reduced by estimated production costs, administrative costs, costs to develop and produce the proved reserves and abandonment costs, all based on current economic conditions at each year-end. There can be no assurance that the proved reserves will be produced in the future or that prices, production or development costs will remain constant. There are numerous uncertainties inherent in estimating reserves and related information.
Management cautions that the standard measure of discounted future cash flows should not be viewed as an indication of the fair market value of natural gas producing properties, nor of the future cash flows expected to be generated. The information presented does not give recognition to future changes in estimated reserves, selling prices or costs and has been discounted at a rate of
F-27
The following table summarizes the estimated future net cash flows from natural gas reserves (in thousands). All amounts noted relate to the Company’s onshore Italian gas assets. The Company has no other gas assets in other jurisdictions.
| December 31, 2025 | December 31, 2024 | |||||||
| Consolidated entities: | ||||||||
| Future cash inflows(1) | $ | $ | ||||||
| Future production and development costs(1) | ( | ) | ( | ) | ||||
| Future income tax expenses(1) | ( | ) | ( | ) | ||||
| Future net cash flows | $ | $ | ||||||
| 10% annual discount for estimated timing of cash flows | ( | ) | ( | ) | ||||
| Standardized measure of discounted future net cash flows | $ | $ | ||||||
| Total consolidated interests in the standardized measure of discounted future cash flows | $ | $ | ||||||
| (1) |
The following table summarizes the aggregate change in the standardized measure of discounted future net cash flows for individually significant sources of change (in thousands).
| December 31, 2025 | December 31, 2024 | |||||||
| Beginning standardized measure of discounted future net cash flows | $ | $ | ||||||
| Net change in sales prices related to future production(1) | ( | ) | ||||||
| Changes in estimated future development costs and abandonment costs | ( | ) | ||||||
| Sales and transfers of oil and gas produced during the period, net of production costs | ( | ) | ||||||
| Net change due to extensions, discoveries, and improved recovery(2) | ||||||||
| Net change due to purchase of royalty interest(3) | ||||||||
| Net changes due to revisions in quantity estimates | ||||||||
| Previously estimated development costs incurred during the period | ||||||||
| Net change in income taxes | ( | ) | ||||||
| Accretion of discount | $ | $ | ||||||
| Aggregate change in the standardized measure of discounted future net cash flows(3) | ( | ) | ||||||
| Ending standardized measure of discounted future net cash flows | $ | $ | ||||||
| (1) |
| (2) |
| (3) |
F-28
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
On December 13, 2024 the Audit Committee approved the dismissal of Marcum LLP (“Marcum”) as our independent registered public accounting firm, effective December 13, 2024 (the “Auditor Change Effective Date”). Marcum’s report on Swiftmerge’s financial statements as of December 31, 2023 and as of December 31, 2022 and the related statements of operations, changes in stockholders’ deficit and cash flows for the years ended December 31, 2023 and 2022 did not contain any adverse opinion or disclaimer of opinion, nor were they qualified or modified as to uncertainty, audit scope or accounting principles, other than included an explanatory paragraph as to Swiftmerge’s ability to continue as a going concern.
During the years ended December 31, 2023 and 2022 and the subsequent period through December 13, 2024, there were no “disagreements” (as that term is described in Item 304(a)(1)(iv) of Regulation S-K under the Exchange Act, and the related instructions to Item 304 of Regulation S-K under the Exchange Act) with Marcum on any matter of accounting principles or practices, financial statement disclosures or audited scope or procedures, which disagreements if not resolved to Marcum’s satisfaction would have caused Marcum to make reference to the subject matter of the disagreement in connection with its report. During the years ended December 31, 2023 and 2022 and the subsequent period through December 13, 2024, there have been no “reportable events” (as defined in Item 304(a)(1)(v) of Regulation S-K under the Exchange Act), other than the material weakness in internal controls identified by management related to the lack of ability to account for complex financial instruments. In addition, as part of such process, Swiftmerge identified a material weakness in internal control related to Swiftmerge’s review controls over the recording of an unbilled amount due to a third-party service provider and interest income, which affected the year ended December 31, 2023.
The Company has provided Marcum with a copy of the foregoing disclosures and requested that Marcum furnish us with a letter addressed to the SEC stating whether it agrees with the above statements and, if not, stating the respects in which it does not agree.
On December 13, 2024, the Board approved the engagement of Deloitte & Touche LLP (“Deloitte”) as its independent registered public accounting firm, effective upon the Auditor Change Effective Date. Deloitte previously served as the independent registered public accounting firm of AleAnna Energy prior to the Business Combination. During the years ended December 31, 2023 and 2022 and the subsequent period through December 13, 2024, neither the Company, nor anyone on the Company’s behalf consulted with Deloitte, on behalf of the Company, regarding the application of accounting principles to a specified transaction (either completed or proposed), the type of audit opinion that might be rendered on the Company’s financial statements, or any matter that was either the subject of a “disagreement,” as defined in Item 304(a)(1)(iv) of Regulation S-K, or a “reportable event,” as defined in Item 304(a)(1)(v) of Regulation S-K.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in Company reports filed or submitted under the Exchange Act is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.
As required by Rules 13a-15 and 15d-15 under the Exchange Act, our Chief Executive Officer and Chief Financial Officer carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2025. Based upon their evaluation, our Chief Executive Officer and Chief Financial Officer identified material weaknesses in our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act).
Effective internal controls are necessary to provide reliable financial reports and prevent fraud. We are a newly public company that is in the process of adding resources with the appropriate level of experience and technical expertise to oversee our business processes and controls. At this time, we do not have the necessary business processes and related internal controls formally designed and implemented.
69
Notwithstanding the conclusion by our Chief Executive Officer and Chief Financial Officer that our disclosure controls and procedures as of December 31, 2025 were not effective, and notwithstanding the material weakness in our internal control over financial reporting described below, management believes that the consolidated financial statements and related financial information included in this Annual Report on Form 10-K fairly present in all material respects our financial condition, results of operations and cash flows as of the dates presented, and for the periods ended on such dates, in conformity with U.S. GAAP.
As a result, AleAnna identified material weaknesses in its internal control over financial reporting. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of annual or interim financial statements would not be prevented or detected on a timely basis.
Limitations of the Effectiveness of Control
A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Because of the inherent limitations of any control system, no evaluation of controls can provide absolute assurance that all control issues, if any, within a company have been detected.
Management’s Report on Internal Controls Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external reporting purposes in accordance with GAAP. Our internal control over financial reporting includes those policies and procedures that:
| (1) | pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of our Company, |
| (2) | provide reasonable assurance that transactions are recorded as necessary to permit preparation of consolidated financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors, and |
| (3) | provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the consolidated financial statements. |
Because of its inherent limitations, internal control over financial reporting may not prevent or detect errors or misstatements in our financial statements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree or compliance with the policies or procedures may deteriorate. Management assessed the effectiveness of our internal control over financial reporting at December 31, 2025. In making these assessments, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013). Based on our assessments and those criteria, management identified a material weakness its internal controls over financial reporting as of December 31, 2025, as described above.
In connection with the preparation of AleAnna’s financial statements as of and for the year ended December 31, 2025, our management identified material weaknesses in our internal control over financial reporting. Our management did not maintain an effective control environment in accordance with the COSO framework, as we did not maintain a sufficient complement of accounting and reporting resources commensurate with our financial reporting requirements. Specifically, we did not have adequately designed and documented controls over the preparation, review, and approval of journal entries and account reconciliations and did not have adequate controls over the identification of significant contract terms that may have accounting implications.
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A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of annual or interim financial statements would not be prevented or detected on a timely basis.
Remediation Plan for Material Weakness
Management, with oversight by the Audit Committee of the Board, is devoting significant attention and resources to remediate the material weakness and to strengthen its internal control over financial reporting. The Company has made significant progress on its remediation plan specific to the material weakness, with the completion of the following remediation activities below:
| ● | Designing and implementing a risk assessment process supporting the identification of risks facing AleAnna. |
| ● | Implementing controls to enhance our review of significant accounting transactions and other new technical accounting and financial reporting issues and preparing and reviewing accounting memoranda addressing these issues. |
| ● | Hiring additional experienced accounting, financial reporting and internal control personnel and changing roles and responsibilities of our existing personnel. |
| ● | Implementing controls to enable an accurate and timely review of accounting records that support our accounting processes and maintain documents for internal accounting reviews. |
The Company believes that the measures described above will remediate the identified material weakness and strengthen the Company’s internal control over financial reporting. Management has begun to take these actions to remediate the material weakness and may take additional measures to address control deficiencies or determine to modify, or in the appropriate circumstances not to complete, certain of the remediation measures identified. The material weakness will not be considered remediated until the remediation plan has been implemented and there has been appropriate time to conclude through testing that the controls are operating effectively. If the steps we take do not remediate the material weakness in a timely manner, there could be a reasonable possibility that these control deficiencies or others may result in a material misstatement of our annual or interim financial statements that would not be prevented or detected on a timely basis. This, in turn, could jeopardize our ability to comply with our reporting obligations, limit our ability to access the capital markets and adversely impact our stock price.
No Attestation Report of Registered Public Accounting Firm
This Form 10-K does not include an attestation report of our independent registered public accounting firm regarding internal controls over financial reporting due to our status as an emerging growth company under the JOBS Act.
Changes in Internal Control over Financial Reporting
No change in our internal control over financial reporting during the most recently completed fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other information
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
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PART III
Item 10. Directors, Executive Officers and Corporate Governance
The information called for by this Item 10 will be incorporated herein by reference to AleAnna’s definitive proxy statement on Schedule 14A relating to the 2026 annual meeting of stockholders (the “2026 Proxy Statement”) to be filed no later than 120 days after the end of the fiscal year covered by this Form 10-K.
The Company has
Item 11. Executive Compensation
The information called for by this Item 11 will be incorporated herein by reference to our 2026 Proxy Statement to be filed no later than 120 days after the end of the fiscal year covered by this Form 10-K.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information called for by this Item 12 will be incorporated herein by reference to our 2026 Proxy Statement to be filed no later than 120 days after the end of the fiscal year covered by this Form 10-K.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information called for by this Item 13 will be incorporated herein by reference to our 2026 Proxy Statement to be filed no later than 120 days after the end of the fiscal year covered by this Form 10-K.
Item 14. Principal Accountant Fees and Services
The information called for by this Item 14 will be incorporated herein by reference to our 2026 Proxy Statement to be filed no later than 120 days after the end of the fiscal year covered by this Form 10-K.
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PART IV
Item 15. Exhibits and Financial Statement Schedules
The following documents are filed as part of this Form 10-K:
(1) Consolidated Financial Statements:
See Part II, Item 8. Financial Statements and Supplementary Data in this Form 10-K.
(2) Consolidated Financial Statement Schedules:
None.
(3) Exhibits: The exhibits listed below are filed or incorporated by reference as a part of this report.
| Exhibits | Description | |
| 2.1† | Agreement and Plan of Merger, dated as of June 4, 2024, by and among Swiftmerge, HoldCo, Merger Sub and AleAnna (incorporated by reference to Exhibit 2.1 to the Company’s Registration Statement on Form S-4 (File No. 333-280699) filed with the Securities and Exchange Commission on July 5, 2024). | |
| 2.2 | First Amendment to Agreement and Plan of Merger, dated as of October 8, 2024, by and among Swiftmerge, HoldCo, Merger Sub and the Company (incorporated by reference to Exhibit 2.2 to the Company’s Registration Statement on Form S-4/A (File No. 333-280699) filed with the Securities and Exchange Commission on October 8, 2024). | |
| 3.1 | Certificate of Incorporation of AleAnna, Inc. (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K (File No. 001-41164), filed with the Securities and Exchange Commission on December 19, 2024). | |
| 3.2 | Bylaws of AleAnna, Inc. (incorporated by reference to Exhibit 3.2 of the Company’s Current Report on Form 8-K (File No. 001-41164), filed with the Securities and Exchange Commission on December 19, 2024). | |
| 4.1 | Specimen Warrant Certificate of Swiftmerge (incorporated by reference to Exhibit 4.3 of the Company’s Registration Statement on Form S-1/A (File No. 333-254633), filed with the Securities and Exchange Commission on October 4, 2021). | |
| 4.2 | Warrant Agreement, dated as of December 14, 2021, by and between Continental Stock Transfer & Trust Company and Swiftmerge (incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K (File No. 001-41164), filed with the Securities and Exchange Commission on December 20, 2021). | |
| 4.3* | Description of Securities of AleAnna, Inc. | |
| 10.1 | Amended and Restated Letter Agreement, dated June 4, 2024, by and between Swiftmerge Holdings, LP, Swiftmerge and the Company (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-41164), filed with the Securities and Exchange Commission on December 19, 2024). | |
| 10.2 | Investment Management Trust Agreement, dated as of December 17, 2021, by and between Swiftmerge and Continental Stock Transfer & Trust Company (incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K (File No. 001-41164), filed with the Securities and Exchange Commission on December 20, 2021). | |
| 10.3 | Amended and Restated Limited Liability Company Agreement of HoldCo (incorporated by reference to Exhibit 10.15 of the Company’s Current Report on Form 8-K (File No. 001-41164), filed with the Securities and Exchange Commission on December 19, 2024). | |
| 10.4 | Form of Investor Letter, dated June 4, 2024, by and between Swiftmerge, certain qualified institutional buyers or institutional accredited investors and certain unaffiliated third-party investors (incorporated by reference to Exhibit 10.16 of the Company’s Current Report on Form 8-K (File No. 001-41164), filed with the Securities and Exchange Commission on December 19, 2024). | |
| 10.5 | Amended and Restated Registration Rights Agreement, dated as of December 13, 2024, by and among the Company, Swiftmerge Holdings, LP, Nautilus Resources LLC, and certain other persons named therein (incorporated by reference to Exhibit 10.17 of the Company’s Current Report on Form 8-K (File No. 001-41164), filed with the Securities and Exchange Commission on December 19, 2024). | |
| 10.6+ | Form of Indemnification Agreement for directors and executive officers of AleAnna, Inc. (incorporated by reference to Exhibit 10.18 of the Company’s Current Report on Form 8-K (File No. 001-41164), filed with the Securities and Exchange Commission on December 19, 2024). | |
| 10.7+ | Employment Agreement, dated as of September 1, 2022, by and between Marco Brun and AleAnna (incorporated by reference to Exhibit 10.25 to the Company’s Registration Statement on Form S-4/A (File No. 333-280699) filed with the Securities and Exchange Commission on November 5, 2024). |
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| 10.8+*# | Employment Agreement, dated August 13, 2025, by and between AleAnna, Inc. and Ivan Ronald. | |
| 10.9 | Form of Director Initial Restricted Stock Unit Agreement (Time Vesting Deferral). (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (File No. 001-41164), filed with the Securities and Exchange Commission on November 3, 2025). | |
| 10.10 | Form of Director Initial Restricted Stock Unit Agreement (Time Vesting No Deferral) (incorporated by reference to Exhibit 10.2 of the Company’s Current Report on Form 8-K (File No. 001-41164), filed with the Securities and Exchange Commission on November 3, 2025). | |
| 10.11 | Form of Director Annual Restricted Stock Unit Agreement (Time Vesting Deferral) (incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K (File No. 001-41164), filed with the Securities and Exchange Commission on November 3, 2025). | |
| 10.12 | Form of Director Annual Restricted Stock Unit Agreement (Time Vesting No Deferral) (incorporated by reference to Exhibit 10.4 of the Company’s Current Report on Form 8-K (File No. 001-41164), filed with the Securities and Exchange Commission on November 3, 2025). | |
| 10.13 | Form of Restricted Stock Unit Agreement (Time Vesting) (incorporated by reference to Exhibit 10.5 of the Company’s Current Report on Form 8-K (File No. 001-41164), filed with the Securities and Exchange Commission on November 3, 2025). | |
| 10.14 | Form of Restricted Stock Unit Agreement (Performance Vesting) (incorporated by reference to Exhibit 10.6 of the Company’s Current Report on Form 8-K (File No. 001-41164), filed with the Securities and Exchange Commission on November 3, 2025). | |
| 10.15+ | Aleanna Inc. 2025 Long-Term Incentive Plan (Incorporated by reference to Annex A of the Company’s Definitive Proxy Statement on Schedule 14A (File No. 001-41164), filed with the Securities and Exchange Commission on April 29, 2025). | |
| 19.1 | Insider Trading Policy (incorporated by reference to Exhibit 19.1 of the Company’s Quarterly Report on Form 10-Q (File No. 001-41164), filed with the Securities and Exchange Commission on May 15, 2025). | |
| 21.1 | Subsidiaries of the Company (incorporated by reference to Exhibit 21.1 of the Company’s Annual Report on Form 10-K (File No. 001-41164), filed with the Securities and Exchange Commission on March 31, 2025). | |
| 23.1* | Consent of Deloitte and Touche, LLP. | |
| 31.1* | Certification of Principal Executive Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| 31.2* | Certification of Principal Financial Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | |
| 32.1** | Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
| 32.2** | Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
| 97.1 | Clawback Policy of AleAnna, Inc. (incorporated by reference to Exhibit 97.1 of the Company’s Annual Report on Form 10-K (File No. 001-41164), filed with the Securities and Exchange Commission on March 31, 2025). | |
| 99.1* | Report of DeGolyer and MacNaughton, Summary of Reserves at December 31, 2025. | |
| 101.INS* | Inline XBRL Instance Document (the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document). | |
| 101.SCH* | Inline XBRL Taxonomy Extension Schema Document. | |
| 101.CAL* | Inline XBRL Taxonomy Extension Calculation Linkbase Document. | |
| 101.DEF* | Inline XBRL Taxonomy Extension Definition Linkbase Document. | |
| 101.LAB* | Inline XBRL Taxonomy Extension Label Linkbase Document. | |
| 101.PRE* | Inline XBRL Taxonomy Extension Presentation Linkbase Document. | |
| 104* | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). |
| † | Certain schedules or similar attachments to this exhibit have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The Company agrees to provide a copy of any omitted schedule or similar attachment to the SEC upon request. |
| # | Certain personally identifiable information has been omitted from this exhibit pursuant to Item 601(a)(6) of Regulation S-K. |
| + | Indicates management contract or compensatory plan. |
| * | Filed herewith. |
| ** | The certifications attached as Exhibit 32.1 and Exhibit 32.2 are not deemed “filed” with the Securities and Exchange Commission and are not to be incorporated by reference into any filing of AleAnna, Inc. under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, whether made before or after the date of this Form 10-K, irrespective of any general incorporation language contained in such filing. |
Item 16. Form 10-K Summary
None.
74
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.
| March 30, 2026 | AleAnna, Inc. | |
| By: | /s/ Ivan Ronald | |
| Name: | Ivan Ronald | |
| Title: | Chief Financial Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
| Name | Title | Date | ||
| /s/ Marco Brun | Chief Executive Officer and Director | March 30, 2026 | ||
| Marco Brun | (Principal Executive Officer) | |||
| /s/ Ivan Ronald | Chief Financial Officer | March 30, 2026 | ||
| Ivan Ronald | (Principal Financial Officer) | |||
| /s/Graham van’t Hoff | Chairman of the Board | March 30, 2026 | ||
| Graham van’t Hoff | ||||
| /s/ William K. Dirks | Director | March 30, 2026 | ||
| William K. Dirks | ||||
| /s/ Duncan Palmer | Director | March 30, 2026 | ||
| Duncan Palmer | ||||
| /s/ Curtis Hébert, Jr. | Director | March 30, 2026 | ||
| Curtis Hébert, Jr. |
75
FAQ
What is AleAnna (ANNA)'s core business according to the latest 10-K?
How much revenue did AleAnna (ANNA) generate in 2025?
What are AleAnna (ANNA)'s proved natural gas reserves and PV-10 value?
What is the significance of the Longanesi field for AleAnna (ANNA)?
How is AleAnna (ANNA) expanding its renewable natural gas operations?
What major corporate transaction did AleAnna (ANNA) complete recently?
How did regulatory changes in Italy affect AleAnna (ANNA)'s upstream assets?
