UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2024

or

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM ___________ TO __________

COMMISSION FILE NUMBER: 001-41164

AleAnna, Inc.

(Exact name of registrant as specified in its charter)

(469) 398-2200

(Registrant’s telephone number, including area code)

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

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  ☐ No  ☒ 

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  ☐  No  ☒

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

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

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

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

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. ☒

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

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 December 31, 2024: $382,100

As of March 31, 2025, 40,584,455 shares of Class A common stock,  par value $0.0001 per share, and 25,994,400 shares of Class C common stock, par value $0.0001 per share, of the registrant were outstanding.

Table of Contents

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.

“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.

“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.

“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 1,400 cubic meters of gas.

“Mcf” - thousand cubic feet.

“Merger Agreement” - Agreement and Plan of Merger, as amended.

“MMcf” - million cubic feet.

“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.

“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.

“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.

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

Risks Related to our Renewable Natural Gas Business and the Renewable Natural Gas Industry

Risks Related to Foreign Operations and Regulatory Matters

Risks Related to our Organizational Structure, Class A Common Stock and Public Warrants

We describe these risks in greater detail under Item 1A., “Risk Factors.”

CAUTIONARY STATEMENTS

This Annual Report on 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 forward-looking statements included in this Annual Report on 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 Annual Report on 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 Annual Report on 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.

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 development-stage 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 2021, 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 €9,087,882, or approximately $9,829,034. 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. We expect to begin construction on our Camapagnatico greenfield facility in 2025 and that Campagnatico has been preliminarily approved for government-backed incentives for both capital expenditure reimbursement and a biomethane floor price through the end of 2039 of €124 per MWh, equivalent, as of December 31, 2024, to $37.60 per 103ft³. Such incentives are subject to successful completion and start-up of the Campagnatico facility. As a development-stage company, while we have generated electricity revenue from our RNG plants, we had not yet generated any revenue from our principal business activities as of December 31, 2024.

Over the past 15 years, we have invested approximately $227 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 17.6 (10⁶ft³) net recoverable proved undeveloped 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 expected to be constructed over the course of 2025 and early 2026 and commissioned in mid-2026. 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, 2024, we have not derived revenue from its conventional natural gas business.

Additionally, our renewable gas team has built a substantial backlog of acquisition targets we believe are poised to support rapid growth in the Italian bio-methane market. With several conventional and renewable projects under development, expected to initially generate revenue in the next 18 to 24 months.

We expect to be able to fund our future growth primarily out of cash from operations from the Longanesi, Gradizza, and Trava developments and with cash on hand. We believe that the synergies of our conventional and renewable natural gas businesses will provide us the financial flexibility to shift capital deployment between the two businesses as the energy transition unfolds.

We believe that our highly experienced and credentialed management team, consisting of former executives of Shell, Eni, and Exxon, 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, Italy.

Business Combination

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 (“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 sheeet, 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 loss.

Our Business Strategies

Conventional Natural Gas Business

We intend to 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:

Renewable Natural Gas Business

We intend 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:

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.

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 January 2025 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, 2024 to $39.25 per 10³ft³ .

Our Operations

Conventional Natural Gas Business

We began studying Italian opportunities in 2007 and, over the last 15 years, have invested approximately $227 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) and two currently awaiting regulatory approval (Gradizza, and Trava), 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 17.6 (10⁶ft³) 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. We expect to drill two additional high-quality development wells by year end 2026, bringing the Longanesi field to a total of seven wells. In addition to the Longanesi expansion, we are simultaneously focused on 13 100% working interest exploration prospects that currently reside at various stages of permitting.

On October 29, 2024, we entered into a Gas Sales Agreement (“GSA”) with Shell Energy Europe Ltd (“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.

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 of the Longanesi field in March 2025, a key milestone for our business.

From 2025 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.

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 €2,000,000, or approximately $2,150,000. The facility is fully permitted, and construction began in the fourth quarter of 2024.

In 2025 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. The plant assets are currently biomethane to electricity conversion assets. It is the company’s 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, 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 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”).

Led by the renewable natural gas expertise and Italian networking capabilities of Giuseppe Perrone (ex-CEO of Eni), over the past approximately 18 months, 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.

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.

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. Prior to first production there are two major authorizations that must be obtained: i) authorization of the Production Concession from the Emilia Romagna Region (the “Intesa”), and ii) authorization of the Production Concession from the Federal Ministry.

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 from 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.

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:

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 (with a goal of 30% of EU natural gas by 2030), 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.

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, 2024 and 2023 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. Copies of the December 31, 2024 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.

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

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.

Proved Undeveloped Reserves

Our 2024 proved undeveloped reserves decreased slightly compared to 2023 primarily due to slight changes in the forecasted startup dates for Longanesi and Gradizza. The following table provides a roll-forward of our proved undeveloped reserves.

As of December 31, 2024 , we had no wells with proved undeveloped reserves that had remained undeveloped for more than five years from their time of booking. Our Longanesi, 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, 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.

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.

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 17 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, 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.

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.

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, 2024 and 2023:

Acreage

The following table summarizes our acreage as of December 31, 2024 and 2023. As AleAnna has not commenced production, the Company has not yet classified any acreage as developed (productive) acreage.

Productive Wells

We did not have any productive wells as of December 31, 2024, 2023, or 2022. As of December 31, 2024, our Longanesi, 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, 2024, our wells were classified by DeGolyer as proved undeveloped reserves as such wells had 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. Our recent drilling activity consisted of the following: no activity during year-to-date December 31, 2024, drilling and completion of two gross Longanesi development wells (0.67 net wells to our interest) during the year ended December 31, 2022, and drilling and completion of one gross Longanesi development well and workover and completion of one additional Longanesi development well (0.335 net to our interest) during the year ended December 31, 2023. We had no other exploratory or development drilling during the year-to-date December 31, 2024 or the years ended December 31, 2023 or 2022. Our Longanesi, Trava and Gradizza wells were classified by DeGolyer as proved undeveloped reserves as such wells had not yet started production and required future investments to install production pipelines and production facilities prior to being fully completed and producible. Following tie-in of the Longanesi wells and the installation of a temporary processing facility, we and Padana achived first production of the five wells in the Longanesi field in March 2025. The permanent processing facility is expected to be constructed over the course of 2025 and early 2026 and commissioned in mid-2026.

Net Volumes Sold, Prices and Production Costs

As of  December 31, 2024 and December 31, 2023, we have not generated any revenue from our operations other than from sales of electricity from two renewable gas assets that were purchased in July 2024. As of December 31, 2023 and 2022, we had not derived revenue from our principal business activities.

Delivery Commitments

We are not currently party to any long-term delivery commitments as of December 31, 2024, 2023, or 2022.

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.

Hydrocarbon exploration and production activities in Italy are governed by Law no. 6/1957, “Exploration and production of liquid and gaseous 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 three-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:

(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 periods of five or 10 years. 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. 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, AleAnna’s permits will expire in December 31, 2026 and December 31, 2027. 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 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 (only for initial acreage larger than 300 square kilometers). The initial duration of a production concession is 20 years, with the possibility of obtaining a ten-year extension and additional five-year extensions until the end of the field economic life.

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 research 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.

Regardless of the validity and the effects of PiTESAI, such plan did not entail any significant and adverse consequence on AleAnna’s 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, AleAnna now hopes to be able to start again exploration activity on part of the areas declared incompatible by the PiTESAI. On December 13, 2024, AleAnna, as requested by MASE, notified MASE of its willingness to reacquire the mining titles and permit applications with the original extension. AleAnna has filed appeals that are still pending with the administrative Courts to request payments of indemnity for loss of such areas.

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 Msmc/year and off shore gas concessions with production lower than 30 Msmc. (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.

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 the 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 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.

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 adopted a number of various measures to contain retail prices such as:

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. 28/2011 requires for the construction and operation of biomethane production facilities and related modification projects:

The application for the S.A. procedure, defined by Legislative Decree No. 387/2003, is submitted by the proponent to the competent region, along with the final project and the plan for decommissioning and restoration works in the area (Ministerial Decree 10.09.2010). Once the documents have been verified, within 30 days the Region 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 90 days of the services conference, except in cases where the “environmental impact assessment” proceedings are started or in case of suspension of deadlines for documentary additions. The procedure ends with the adoption of the managerial determination of the competent region.

The application for the S.A.P. procedure, defined by Legislative Decree No. 28/2011, is submitted by the proponent to the municipality at least 30 days before the start of work on the plant. The application must be supported by the technical drawings of the project. 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.

During 2023 and 2024, through several decrees, the procedures for obtaining authorization for the conversion of existing AD’s (or the construction of new biomethane facilities) were simplified, with key regulatory protocols as follows:

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 (CIC) 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, 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.

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:

In view of the above, we intend to pursue the above principles by committing to the following aims:

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, 2024 and December 31, 2023, we have not generated any revenue from our operations other than from sales of electricity from two renewable gas assets that were purchased in July 2024. We anticipate that our customers will largely consist of Shell as well as industrial, power generation and residential customers throughout Italy and into the southern EU.

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.

Renewable Natural Gas

Competition in this rapidly emerging market space is not yet well-organized 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

AleAnna has 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:

Renewable Natural Gas

AleAnna has 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:

Human Capital Resources

As of December 31, 2024, we had seven full-time employees and engaged six contractors on a part-time basis, and one contractor on a full-time basis. Our workforce is concentrated in Texas and 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, 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 successful acquisition, in short order, we expect to begin upgrading construction on the 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.

Blugas Settlement

On May 28, 2024, we entered into the Blugas Settlement Agreement with Blugas, regarding Blugas’ retained interest in the physical volumes extracted from the Longanesi field. We contested the existence of Blugas’ right to receive the Blugas ORRI. Under the terms of the Blugas Settlement Agreement, we agreed to pay Blugas approximately €5 million, plus an additional €1.1 million in applicable VAT (a total of approximately $6.6 million in U.S. Dollars). In exchange for such payment, Blugas agreed to irrevocably waive, among other things, the Blugas ORRI and release us 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 its proved gas reserves. However, the required payments to Blugas associated with the sale of such quantities were reflected as cash outflows (costs) 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.

Item 1A. Risk Factors

Any investment in shares of our Class A Common Stock involves a high degree of risk. You should carefully consider all of the information contained herein including our financial statements and related notes thereto, before deciding whether to purchase shares of our Class A Common Stock. 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.

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, 2024, 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 expenditures than we currently anticipate. Therefore, our estimated PUDs may not ultimately be developed or produced.

All of the reserves attributable to our properties are undeveloped. Development of proved undeveloped reserves may take longer and require higher levels of capital expenditures 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 have drilled and tested certain exploration and development wells, but as of December 31, 2024, we had not successfully converted an exploration well or development well to a producing natural gas well nor successfully produced hydrocarbons, or revenues from drilling operations. 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 over the remainder of 2025 and early 2026 and commissioned in mid-2026. Natural gas exploration and production has 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:

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 are a development-stage company. As of  December 31, 2024 and December 31, 2023, we have not generated any revenue from our operations other than from sales of electricity from two renewable gas assets that were purchased in July 2024. 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 ever operate profitably. We may not be able to effectively manage the demands required, such that we may be unable to implement our business plan or achieve profitability.

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, our failure to obtain necessary government authorizations or 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:

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 operation 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.

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.

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 that 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 or increase in the future due to rising macroeconomic uncertainty and geopolitical tensions.

Commodity prices are affected by a number of factors beyond our control, which include:

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 increases 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 constrained 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.

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 and initial development of our properties. While we expect to be able to fund our future growth primarily out of cash currently on AleAnna’s balance sheet, from cash flow from the Longanesi, Trava, and Gradizza developments, and through recycling of cash flow from future developments, we have not generated any revenue from our principal business activities to date and 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 AleAnna’s 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 2026. 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.

Our cash flows from operations and access to capital are subject to a number of variables, including:

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 such 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.

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.

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.

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 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.

Our strategic success and financial results depend on our ability to identify, acquire, develop and operate renewable 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:

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 involves numerous risks, many of which may be indiscoverable 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 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:

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, regulation 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:

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, we cannot guarantee that the renewable energy plants we currently plan to develop or, to the extent applicable, are developing, will 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.

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 timeframes, 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 AD’s over the past 15 years. However, the Italian government’s financial incentives and subsidies supporting these activities are set to expire in January 2025 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.

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 is an inexact process and dependent on many site-specific conditions, including the estimated annual waste volume, composition of waste, regional climate 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, and 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.

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, certain 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 various 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.

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.

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 another country 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. Our operations in areas outside the United States are subject to various risks inherent in foreign operations. These risks may include, among other things:

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 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.

All of our natural gas and renewable gas properties are located in 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 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 in Italy, 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 have less control over our investments in foreign properties than we would have over domestic investments.

Our exploration, development and production activities are subject to various political, economic and other uncertainties, including but not limited to changes, sometimes frequent or marked, in energy policies or the personnel administering them, expropriation of property, cancellation or modification of contract rights, changes in laws and policies governing operations of foreign-based companies, unilateral renegotiation of contracts by governmental entities, uncertainties as to whether the laws and regulations will be applicable in any particular circumstance, uncertainty as to whether we will be able to demonstrate to the satisfaction of the applicable governing authorities compliance with governmental or contractual requirements, redefinition of international boundaries or boundary disputes, foreign exchange restrictions, currency fluctuations, foreign currency availability, royalty and tax increases, changes to tax legislation or the imposition of new taxes, the imposition of production bonuses or other charges and other risks arising out of governmental sovereignty over the areas in which our operations are conducted.

Our operations require, and any future opportunistic acquisitions may require, protracted negotiations with host governments, local governments and communities, local competent authorities, national companies, and third parties. Host governments may also conduct audits of our operations, the results of which may have a significant negative impact on our reported earnings or cash flows. Host governments may seek to participate in natural gas projects in a manner that could be diluted to our interests. Host governments may also require us to hire a specified percentage of local citizens in our operations. In addition, if a dispute arises with respect to our foreign operations, we may be subject to the exclusive jurisdiction of foreign courts or may not be successful in subjecting foreign persons, especially foreign ministries and national companies, to the jurisdiction of the U.S.

We may expand our operations globally, which would subject 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.

If we expand our operations globally, we would be subject 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 would 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 widely in recent years in response to international political conditions, general economic conditions, the European sovereign debt crisis 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 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 subject us to additional restrictions imposed by lenders.

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).

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 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.

Our management team has limited recent experience in operating a public company.

Our executive officers have limited recent experience in the management of a publicly traded company. Our management team may not successfully or effectively manage our operations to comply with the regulatory oversight and reporting obligations under federal securities laws. We may not have adequate personnel with the appropriate level of knowledge, experience, and training in the policies, practices or internal controls over financial reporting required of public companies in the United States. As a result, we may be required to pay higher outside legal, accounting or consulting costs than our competitors, and our management team may have to devote a higher proportion of their time to issues relating to compliance with the laws applicable to public companies, both of which might put us at a disadvantage relative to competitors.

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:

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 previously 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. 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 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, 2024, management of AleAnna identified material weaknesses in our internal control over financial reporting. Specifically, AleAnna management did not maintain an effective control environment in accordance with the COSO framework as the Company did not maintain a sufficient complement of accounting and reporting resources commensurate with our financial reporting requirements.

In connection with the preparation of AleAnna’s financial statements as of and for the years ended December 31, 2024 and 2023, management of AleAnna identified material weaknesses in its internal control over financial reporting as follows:

We are in the early stages of designing and implementing a plan to remediate the material weaknesses identified. Our plan includes the below:

We cannot assure you that these measures will remediate the material weaknesses described above. The implementation of these remediation measures is in the early stages and will require 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, 2025. 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 in our second annual report following the completion of the Business Combination. 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.

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 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 experience operating as a public company subject to U.S. federal securities laws. Our officers and directors have limited recent experience in managing a public company subject to U.S. federal securities laws, which makes their ability to comply with applicable laws, rules and regulations uncertain. Our failure to comply with all applicable laws, rules and regulations could subject us to U.S. regulatory scrutiny or sanction, which could harm its reputation and share price.

AleAnna has not previously been required to prepare or file periodic or other reports with the SEC or to comply with the other requirements of U.S. federal securities laws. Additionally, 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.

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.

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. 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.

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.

Risks Associated with Strategic Transactions

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. 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

None.

Item 1C. Cybersecurity

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, 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.

Blugas Settlement

On May 28, 2024, we entered into the Blugas Settlement Agreement with Blugas, regarding Blugas’ retained interest in the physical volumes extracted from the Longanesi field. We contested the existence of Blugas’ right to receive the Blugas ORRI. Under the terms of the Blugas Settlement Agreement, we agreed to pay Blugas approximately €5 million, plus an additional €1.1 million in applicable VAT (a total of approximately $6.6 million in U.S. Dollars). In exchange for such payment, Blugas agreed to irrevocably waive, among other things, the Blugas ORRI and release us 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%). We accounted for the Blugas settlement 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 its proved gas reserves. Our working interest (net revenue interest) as established under the terms of the Unified Operating Agreement arrangement originally signed between ENI and Grove and dated September 26, 2009, remains unchanged at 33.5%.

Item 4. Mine Safety Disclosures

Not Applicable.

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 31, 2025, the Company had 40,584,455 shares of Class A Common Stock issued and outstanding, 25,994,000 shares of Class C Common Stock issued and outstanding and 11,225,969 Warrants issued and outstanding.

Holders

On March 31, 2025, 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

None other than as previously reported.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

We did not repurchase any Class A Common Stock or Public Warrants during the three months ended December 31, 2024.

Item 6. [Reserved]

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. As a result of many factors, such as those set forth under the headings “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 company 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 reservoir imaging. In 2021, we launched a renewable natural gas development business focused on bringing to market carbon-negative renewable natural gas derived from animal and agricultural waste.

Planned principal operations have not yet commenced. As of December 31, 2024, although we had generated revenue from electricity sales from two renewable natural gas assets, we had not generated any revenues from our principal business activities to date. 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. We had no drilling activity during the year ended December 31, 2024, and drilled and completed one gross Longanesi development well and worked over and completed one additional Longanesi development well (0.335 net to our interest) during the year ended December 31, 2023. We had no other exploratory or development drilling during years ended December 31, 2024 or 2023. Our Longanesi, Trava and Gradizza wells were classified by DeGolyer as proved undeveloped reserves as such wells had not yet started production as of December 31, 2024 and require future investments to install production pipelines and production facilities prior to being fully completed and producible. Following tie-in of these 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 expected to be constructed over the remainder of 2025 and early 2026 and commissioned in mid-2026.

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 (“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 loss.

Recent Developments

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.

In connection with this milestone, AleAnna will be required to reserve $3.1 million related to the contingent consideration liability due to Enel (see Note 6). These funds will be classified as restricted cash in future balance sheets and 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 (“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.

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.

Key Factors Affecting our Performance, Prospects and Future Results

We believe that our performance and future success depend 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.

Achieving First Production at Longanesi

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 2025 and early 2026 and commissioned mid 2026.

We believe our achieving first production of the Longanesi field is a key milestone that will fuel our potential growth. We also have potentially viable discoveries in our Gradizza and Trava fields that are expected to achieve first production in the future.

Commencing and Expanding Renewable Natural Gas Operations

In 2021, 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, 2024, we generated approximately $1.4 million of revenue from 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 (SNAM). 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.

In addition to sales of renewable natural gas, we expect to generate a significant portion of our future revenue from the sale of conventional natural gas.

Expenses

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.

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 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.

Income Tax Effects

AleAnna’s income tax consequences have been reflected in its consolidated financial statements in accordance with ASC 740, Income Taxes. Given AleAnna’s history of losses, and because future production remains uncertain, a full valuation allowance was applied against deferred tax assets as of December 31, 2024 and December 31, 2023, and no income tax liabilities or expenses were recognized as of or for the years ended December 31, 2024 or 2023.

We are also subject to a Valued-Added Tax (“VAT”) which 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 EU. Italian law allows for certain VAT payments to be recovered through ongoing applications for refunds. We have 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. As of December 31, 2024 and 2023, we had VAT receivables of $6.6 million, and $4.4 million, respectively.

Operations

Our net losses were $12.4 million and $5.2 million for the years ended December 31, 2024 and 2023, respectively. As of December 31, 2024 and December 31, 2023, we had an accumulated deficit of $191.0 million and $146.4 million, respectively. The majority of these 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 10 — Equity” to the audited condensed 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. Since inception, we have incurred net losses annually and do not expect to achieve sustained profitability until 2025. These shares were all exchanged for Class A and Class C common stock in connection with the Business Combination.

Results of Operations

Comparison of the year ended December 31, 2024 and 2023:

Revenues and Cost of Revenues

During the year ended December 31, 2024, all of our revenue was earned through electricity generation and sales at the Casalino and Campopiano renewable natural gas plants that were purchased in July 2024. Cost of revenues consists of feedstock costs, direct labor and overhead necessary to produce RNG and generate electricity. All cost of revenues was related to the RNG assets that were purchased in 2024. See Critical Accounting Policies and Estimates for further details of our revenue recognition accounting policies.

General and Administrative (G&A) Expenses

General and administrative expenses consist of salaries and benefits, outside professional services including legal, human resources, audit and accounting services, and development stage expenses. We expect to continue to incur expenses to support operations as a public company, including expenses related to existing and future compliance with rules and regulations of the SEC and the Nasdaq, insurance expenses, investor relations, audit fees, professional services and general overhead and administrative costs.

General and administrative expenses (exclusive of Business Combination transaction expenses) increased by $0.6 million, or 11%, for the year ended December 31, 2024, compared to the year ended December 31, 2023. The increase was primarily due to increases in legal, audit and consulting fees.

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 on December 13, 2024, with no similar expenses incurred in 2023.

Contingent Consideration Liability

As of December 31, 2024 and December 31, 2023, the contingent consideration liability was recorded at $25.0 million and $26.5 million, respectively. The estimate of the contingent consideration liability was determined based on inputs including the following as of December 31, 2024 and December 31, 2023: the intercontinental exchange futures prices for European natural gas, Euro to USD exchange rates of 1.04 and 1.11, 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, 2023 to December 31, 2024, 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, 2024, December 31, 2023, and December 31, 2022, 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 2024 and 2023.

Interest and Other Income (Expenses)

Interest and other income (expenses) primarily includes interest earned on cash and cash equivalents. Interest and other income increased by $2.1 million during the year ended December 31, 2024 compared to the same period in 2023, primarily due to interest earned on larger average cash balances during the 2024 period compared to the 2023 period presented. The larger cash balances were a result of the previously mentioned capital contributions in January and May of 2024. In 2023, the activity primarily related to lease operating expenses with minimal interest earned on lower cash and cash equivalents balances.

Change in Fair Value of Derivative Liability

The change in the fair value of derivative liability related to the Class 1 Preferred Units was $0.2 million during the year ended December 31, 2024, compared to $0.7 million during the same period in 2023. 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. Part of the change was also driven by a lower estimated business value as of September 30, 2024 compared to December 31, 2023 due to a decline in forward natural gas prices. The derivative liability was reduced from $0.2 million as of December 31, 2023 to zero as of September 30, 2024 and was ultimately derecognized in conjunction with the Business Combination.