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)

 Delaware

 1311

 98-1582153

 (State or other jurisdiction of

incorporation or organization)

 (Primary Standard Industrial

Classification Code Number)

 (I.R.S. Employer

Identification Number)

 (469) 398-2200

 (Registrant's telephone number, including area
code)

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

 Title of each class

 Trading symbol(s)

 Name of each exchange on which registered

 Class A common stock, par value $0.0001 per share

 ANNA

 The Nasdaq Capital Market

 Warrants, each whole warrant exercisable for one share of Class A common stock

 ANNAW

 The Nasdaq Capital Market

 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.

 Large accelerated filer

 Accelerated filer

 Non-accelerated filer

 Smaller reporting company

 Emerging growth company

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

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

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

 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.

 Glossary of Commonly Used Terms, Abbreviations and Measurements

 ii

 Summary of Risk Factors

 v

 Cautionary Statements

 viii

 Item 1. Business

 Item 1A. Risk Factors

 Item 1B. Unresolved Staff Comments

 Item 1C. Cybersecurity

 Item 2. Properties

 Item 3. Legal Proceedings

 Item 4. Mine Safety Disclosures

 Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 Item 6: [Reserved]

 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

 Item 7A. Quantitative and Qualitative Disclosures About Market Risk

 Item 8. Financial Statements and Supplementary Data

 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 Item 9A. Controls and Procedures

 Item 9B. Other Information

 Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

 Item 10. Directors, Executive Officers and Corporate Governance

 Item 11. Executive Compensation

 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 Item 13. Certain Relationships and Related Transactions, and Director Independence

 Item 14. Principal Accountant Fees and Services

 Item 15. Exhibits and Financial Statement Schedules

 Item 16. Form 10-K Summary

 i

 Glossary Of Selected Industry Terms

 "AleAnna Energy" - AleAnna Energy,
LLC, a Delaware limited liability company.

 "Bcf" - billion cubic feet.

 "Bcfe" - billion cubic feet of natural
gas equivalents, with one barrel of NGLs and oil being equivalent to 6,000 cubic feet of natural gas.

 "Blugas"
- Blugas Infrastructure S.r.l.

 "Blugas
Settlement Agreement" - agreement with Blugas Infrastructure S.r.l. ("Blugas") regarding the Blugas overriding royalty
interest ("ORRI") whereby Blugas was entitled to physical delivery of 20% of the first 350 million standard cubic meters
(approximately 2,472 10 6 ft 3) 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.

 ii

 "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.

 iii

 "Proved undeveloped reserves (PUDs)"
- means proved reserves that are expected to be recovered from undrilled well locations on existing acreage or from existing wells where
a relatively major expenditure is required for recompletion within the five year development window, according to the SEC or Society of
Petroleum Engineers definition of PUD

 "ORRI"
- Blugas overriding royalty interest

 "Reserves" - reserves are estimated
remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application
of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will
exist, the produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market,
and all permits and financing required to implement the project.

 "Reservoir" - a porous and permeable
underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water
barriers and is separate from other reservoirs.

 "Service well" - well drilled or completed
for the purpose of supporting production in an existing field. Specific purposes of service wells include, among other things, gas injection,
water injection and salt-water disposal.

 "Swiftmerge" or "SPAC"
- Swiftmerge Acquisition Corp., a Cayman Islands exempted company.

 "Undeveloped acreage" - means acreage
under lease on which wells have not been drilled or completed such that there is not production of commercial quantities of hydrocarbons;

 "Unproved reserves" - reserves that are based on geoscience
and/or engineering data similar to that used in estimates of proved reserves, but technical or other uncertainties preclude such reserves
being classified as proved reserves. Unproved reserves may be further categorized as probable reserves and possible reserves.

 "Working interest" - An interest that gives the owner the
right to drill, produce and conduct operating activities on a property and receive a share of any production.

 "/d" - Per day.

 "/y" - Per year.

 iv

 SUMMARY RISK FACTORS

 Summary Risk Factors

 The following is a summary of the principal
risks that may materially adversely affect our business, financial condition, results of operations and cash flows. The following should
be read in conjunction with the more complete discussion of the risk factors we face, which are set forth in the section entitled "Item
1A: Risk Factors" in this report.

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

 We
 currently have no producing properties and there is no assurance that we will be able to
 convert our exploration drilling to producing wells. If our assets are not commercially productive
 of natural gas, any funds spent on exploration and production may be lost.

 The
 development of our estimated proved undeveloped reserves ("PUDs") may take longer
 and may require higher levels of capital expenditures than we currently anticipate.

 While
 we have drilled and tested certain exploration wells, we have no history of converting the
 exploration wells to producing natural gas wells and there can be no assurance that we will
 successfully establish natural gas operations or profitably produce natural gas.

 Restrictions
 on drilling activities intended to protect the environment and the ecosystem may adversely
 affect our ability to conduct drilling activities areas where we operate.

 Drilling
 for and producing natural gas is a high-risk and costly activity with many uncertainties,
 including the risk that drilling will not result in commercially viable natural gas production
 or that we will not recover all or any portion of our investment in drilled wells.

 Our
 drilling locations are scheduled out over many years, making them susceptible to uncertainties
 that could materially alter the occurrence or timing of when they are drilled, if at all.

 The
 amount and timing of actual future natural gas production is difficult to predict and may
 vary significantly from our estimates, which may reduce our earnings.

 Unless
 we replace our reserves, our reserves and production will naturally decline, which would
 adversely affect our business, financial condition and results of operations.

 v

 Our
 proved reserves are estimates that are based on many assumptions that may prove to be inaccurate.
 Any significant change in these underlying assumptions will greatly affect the quantities
 and present value of our reserves.

 Our
 limited history, lack of revenue and limited liquidity makes it difficult to evaluate our
 business and prospects and may increase the risks associated with your investment.

 Significant
 capital investment is required to develop and conduct our operations and we intend to raise
 additional funds through debt financing for our planned operations and these funds may not
 be available when needed.

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

 Failure
 to protect our intellectual property, inability to enforce our intellectual property rights
 or loss of our intellectual property rights through costly litigation or administrative proceedings,
 could adversely affect our ability to compete and our business.

 Our
 strategic success and financial results depend on our ability to identify, acquire, develop
 and operate renewable natural gas facilities.

 Revenue
 from any plants we complete may be adversely affected if there is a decline in public acceptance
 or support of renewable energy, or regulatory agencies, local communities, or other third
 parties delay, prevent, or increase the cost of constructing and operating our facilities.

 A
 policy revision with respect to the Italian government sponsored renewable natural gas floor
 price and renewable natural gas capital expenditure reimbursements could have a material
 adverse effect on our long-term business prospects, financial condition and results of operations.

 The
 financial performance of our business depends upon tax and other governmental incentives
 for renewable energy generation, any of which could change at any time and such changes may
 negatively impact our growth strategy.

 Our
 commercial success depends on our ability to develop and operate production facilities for
 the commercial production of renewable natural gas.

 We
 may be subject to liabilities and losses that may not be covered by insurance.

 Significant
 capital investment is required to develop and conduct our operations and we intend to raise
 additional funds through debt financing for our planned operations and these funds may not
 be available when needed.

 We
 have entered into relatively new markets for renewables, including renewable natural gas,
 and these new markets are highly volatile and have significant risk associated with current
 market conditions.

 Fluctuations
 in the price of product inputs, including renewable feedstocks, natural gas and other feedstocks,
 may affect our cost structure.

 Our
 proposed growth projects may not be completed or, if completed, may not perform as expected
 and our project development activities may consume a significant portion of our management's
 focus, and if not successful, reduce our profitability.

 vi

 We
 may not be able to develop, maintain and grow strategic relationships, identify new strategic
 relationship opportunities, or form strategic relationships, in the future.

 Failure
 of third parties to manufacture quality products or provide reliable services in accordance
 with schedules, prices, quality and volumes that are acceptable to us could cause delays
 in developing and operating our commercial production facilities, which could damage our
 reputation, adversely affect our partner relationships or adversely affect our growth.

 We
 may be subject to liabilities and losses that may not be covered by insurance.

 Our
 facilities and processes may fail to produce renewable natural gas at the volumes, rates
 and costs we expect.

 Our
 actual costs may be greater than expected in developing our commercial production facilities
 or growth projects, causing us to realize significantly lower profits or greater losses.

 Disruption
 in the supply chain, including increases in costs, shortage of materials or other disruption
 of supply, or in the workforce could materially adversely affect our business.

 Risks
Related to Foreign Operations and Regulatory Matters

 Our
 primary operations are in a foreign country, and we are subject to political, economic and
 other uncertainties.

 All
 of our natural gas properties are located in the country of Italy, making us vulnerable to
 risks associated with operating in one geographic area.

 We
 may expand our operations globally, which would subject us to anti-corruption, anti-bribery,
 anti-money laundering, trade compliance, economic sanctions and similar laws, and non-compliance
 with such laws may subject us to criminal or civil liability and harm our business, financial
 condition and/or results of operations.

 Our
 results of operations, financial condition and cash flows could be adversely affected by
 changes in environmental laws and regulations.

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

 AleAnna
 is a holding company and its organizational structure is commonly referred to as an umbrella
 partnership C corporation (or "Up-C") structure, it is dependent upon distributions
 from HoldCo to pay taxes, and cover its corporate and other overhead expenses.

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

 We
 are controlled by Nautilus Resources, LLC ("Nautilus"), whose interests may conflict
 with ours and the interests of other stockholders.

 If
 our estimates or judgments relating to our critical accounting policies prove to be incorrect
 or financial reporting standards or interpretations change, our operating results could be
 adversely affected.

 AleAnna,
 Inc. has identified material weaknesses in its internal control over financial reporting.
 If we are unable to develop and maintain an effective system of internal control over financial
 reporting, we may not be able to accurately report our financial results in a timely manner,
 which may adversely affect investor confidence in us and materially and adversely affect
 our business and operating results, and we may face litigation as a result.

 The
 market price of our Class A Common Stock could be adversely affected by sales of substantial
 amounts of our Class A Common Stock in the public or private markets or the perception
 in the public markets that these sales may occur, including sales by the members of Nautilus
 after the redemption of any Class C HoldCo Units, together with an equal number of our
 Class C Common Stock, in exchange for shares of our Class A Common Stock, or other
 large holders.

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

 vii

 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
 Company's financial condition and results of operations;

 the
 development of our estimated proved undeveloped reserves;

 the
 Company's reserves estimates;

 the
 timing of acquisition, financing, construction and development of new projects;

 the
 Company's ability to raise financing in the future;

 in public acceptance and support of renewable energy development and projects;

 the
 Company's ability to obtain necessary regulatory and governmental permits and approvals;

 the
 effects of competition;

 the
 Company's ability to identify, acquire, develop and operate renewable natural gas facilities;

 governmental
 incentives for renewable energy generation;

 the
 demand for renewable energy not being sustained;

 political,
 economic and other uncertainties, including those related to the European Union's ("EU")
 clean energy transition;

 in environmental laws and regulations;

 disruptions
 in the supply chain, fluctuation in price of product inputs, and market conditions and global
 and economic factors beyond the Company's control;

 viii

 the
 Company's success in retaining or recruiting, or changes required in, its officers,
 key employees or directors;

 the
 effect of legal, tax and regulatory changes;

 we
 may be subject to liabilities and losses that may not be covered by insurance; and,

 the
 other matters described in the section titled " Risk
 Factors " beginning on page 23

 The
forward-looking statements included in this Annual Report on Form 10-K involve risks and uncertainties that could cause actual results
to differ ma terially 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.

 ix

 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 103ft 3. 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 (10 6 ft 3)
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-20 26. 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:

 the
 use of industry-leading technologies and techniques to significantly increase the probability
 of drilling success;

 a
 robust natural gas price environment, with current takeaway prices of approximately $10-$15
 per (10 3 ft 3), which are approximately 3-4 times the current Henry
 Hub spot price;

 geographically
 advantaged developments that are adjacent to a well-developed pipeline network containing
 large excess transport capacity;

 relatively
 low-cost, low-risk, onshore operations through which our natural gas can be brought to market
 at costs of approximately $1-3 per 10 3 ft 3;

 short
 expected payout periods and high expected rates of return on developments, supported by high
 quality, high flow rate, reservoirs, and a low combined federal and regional royalty regime
 (10%);

 nimble
 operating model with a focus on utilizing outsourced resources to control costs; and

 proactive
 relationships with larger enterprises (like Shell and Eni Ecofuels ("Eni")) to
 further our marketing and potential hedging strategies, and to support our ongoing conventional
 natural gas exploration and development aspirations.

 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:

 existing
 AD's ("Brownfield Facilities") are cheaper to acquire and have a lower
 risk profile than new-build opportunities ("Greenfield Facilities" or "Greenfield")
 and their conversion to bio methane is relatively efficient and can be accomplished within
 a short time frame through installation of an "off-the-shelf" biogas upgrading
 unit;

 we
 believe we have unique regional overlap across our conventional and renewable natural gas
 businesses as our conventional focus area, Italy's Po Valley, contains the majority
 of the existing Italian AD's and is adjacent to a comprehensive natural gas pipeline
 network operated by the Italian-sponsored SNAM, which exists in close proximity to our conventional
 business and the Po Valley AD's;

 as
 one of a few licensed Italian Exploration & Production ("E&P") operators,
 we believe we have the means, mechanisms, and market relationships to bring biomethane to
 market, whereas those tasks are above the capabilities of most family farms and farm association
 who currently own and operated existing AD's;

 the
 construction and operation of a biomethane facility is similar to the operation of a conventional
 natural gas facility, a capability which we already possess;

 by
 either including the family farm as a working-interest partner or entering into bespoke feedstock
 contracts, we believe we can enlist the farms' support in creating necessary AD fuels
 and in the disposal of waste products from the AD (which are converted into fertilizer),
 without our business having to become proficient in farming;

 we
 believe that a combination of free cash flows from our conventional natural gas business,
 together with other cash on hand, and future project level debt financing will satisfy the
 near-term capital requirements of our renewable natural gas portfolio; and

 as
 discussed in more detail below, the Italian government's 15-year guaranteed biomethane
 floor price of $39.30 per 103ft 3 substantially mitigates pricing risk from the
 renewable natural gas business and the Italian government as also implemented an investment
 aid, or capital expenditure reimbursement program, covering up to 40% of eligible investment
 costs.

 Natural
Gas Demand

 Although Italy has numerous
hydrocarbon-producing basins with significant undeveloped oil and gas deposits, both onshore and offshore, in 2022 Italy imported 96%
of its natural gas and has one of the highest concentrations of natural gas as a component of total energy use, at almost 40% by kilotons
of oil equivalent. Its reliance on imports has led to a paradigm shift in the Italian political landscape towards securing domestic energy
supply. In addition, Italy has in recent decades opened oil and gas exploration and development permits to the global E&P industry
beyond the historical domain of Italy's former National Oil Company ("NOC"), Eni.

 Catering to this renewed emphasis
on secure domestic energy supply, we are focused on exploitation and producing activities in the prolific and well-derisked Po Valley
of northern Italy using modern proprietary 3D seismic surveys, which has led us to believe the Po Valley contains numerous opportunities
to explore for and develop conventional natural gas fields. The Po Valley is ripe with access to a dense network of government-controlled
natural gas pipelines that can transport our products to industrial, power generation and residential customers throughout Italy and into
the southern EU. Additionally, according to Eurostat, Italy is second only to Germany in the EU in terms of the value of natural
gas sold for industrial power and heat requirements, and the Po Valley is adjacent to Italy's core, high-energy demand, manufacturing
centers. Supporting the vital energy needs of this industrial production base, Po Valley reservoirs are largely high-quality with unique
properties that allow for the application of an important exploration and development technology known as DHIs, through which natural
gas deposits can be "seen" on modern seismic surveys. We believe the use of DHI technology dramatically increases the probability
of drilling success and lower development costs.

 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
10 3 ft 3.

 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 (10 6 ft 3)
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 km 2) 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:

 Despite
 recent attempts in Germany, adding a significant amount of new coal-fired power in the EU
 is not a viable option. Domestic coal-fired electricity generation declined to all-time lows
 in 2022, and much of Europe's imported coal is from Russia. In addition, increasing
 coal-fired generation would require the suspension of EU carbon market regulations and the
 carbon emissions caps that all member nations have strongly endorsed;

 Similarly,
 we do not believe new nuclear power generation is a viable substitute given the lengthy permitting
 and construction timelines associated with such projects. Long lead times make nuclear power
 including attractive small nuclear reactors a multi-decade solution at best;

 Replacing
 Russian gas with LNG imports is very challenging, given supply constraints, limited global
 liquefaction capacity, and recent moves by the US to slow or stop new LNG export projects.
 In addition, the EU lacks sufficient LNG import terminals to increase intake significantly
 in a timely manner given the time and regulatory delays of constructing new LNG import facilities;

 Renewable
 power generation suffers from three key problems: intermittency, seasonality, and energy
 density. Battery technology today can only support 4-6 hours of discharge, which
 then requires significant and costly capital expenditures on storage to mitigate intermittency.

 Recent
 advancements in Artificial Intelligence ("AI") are leading to increased global
 power demand for data centers. The growth in European data center power demand may surpass
 the total annual power demand of some EU member states. It is anticipated that a significant
 portion of new data center developments will be supported by combined cycle natural gas turbine
 power generation. Such generation provides the steady baseload power that data centers require,
 and, unlike renewable power generation, does not suffer from many of the intermittency and
 seasonality challenges. The potential power generation and infrastructure demands that may
 emerge from AI technology may create natural gas demand and power price tightness that could
 positively impact upstream natural gas prices.

 Renewable natural gas (biomethane)
is compositionally identical to the biogenic natural gas in the Po Valley, can be transported on the same pipeline systems, is used by
the same consumers, and offers a sustainable, low-carbon fuel that can be used to help transform the energy economy of the EU. As
a result, the EU has published very aggressive targets for biomethane development (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

 2024

 Natural Gas

 (10 6 ft 3)

 Estimated proved developed reserves

 —

 Estimated proved undeveloped reserves

 Estimated total proved reserves

 The following table summarizes
our proved developed and undeveloped reserves using average first-day-of-the-month closing prices for the prior twelve months and
disaggregated by discovery.

 December 31, 2024

 Longanesi

 Gradizza

 Trava

 Total

 (10 3 ft 3)

 Proved undeveloped reserves

 17,241

 —

 Total proved reserves

 17,241

 —

 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.

 Proved
 Undeveloped
 Reserves

 (10 6 ft 3)

 Balance at January 1, 2024

 Revision of previous estimates

 Extensions, discoveries and other revisions

 (68
)

 Balance at December 31, 2024

 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 10 6 ft 3) 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
10 6 ft 3) 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 10 6 ft 3), 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.

 Years Ended December 31,

 2024

 2023

 (Thousands, unless
 otherwise noted)

 Future net cash flows (a)

 $
 130,333

 $
 132,492

 Present value of net cash flows discounted at a rate of 10% (b)

 107,202

 102,672

 Prices

 Natural gas price ($/10 3 ft 3) (c)

 $
 11.73

 $
 14.13

 (a)
 Future net cash flows represent future cash flows which are
reduced by estimated production costs, administrative costs, costs to develop and produce the proved reserves and abandonment costs,
all based on current economic conditions at each year-end. This amount excludes future income taxes and is prior to any discounting.

 (b)
 Present value of net cash flows represents future net cash
flows discounted to present value using a discount rate of 10%. Such amount also excludes future income taxes. See "Reconciliation
of Standardized Measure to PV-10" for a calculation of the standardized measure of estimated future net cash flows from natural
gas and oil reserves.

 (c)
 Gas prices are based on a reference price. Gross gas price
is calculated as the unweighted arithmetic average of the first day-of-the-month price prevailing in Italy for each month within
a 12-month period prior to the end of the reporting period. The volume-weighted average price attributable to the estimated proved reserves
was $11.73 and $14.13 per thousand cubic feet of gas for the year ended December 31, 2024, and 2023, respectively.

 Future
net cash flows represent projected revenues from the sale of proved reserves net of production and development costs (including transportation
and gathering expenses, operating expenses and production taxes). Revenues are based on a twelve-month unweighted average of the first-day-of-the-month
pricing, without escalation. Future cash flows are reduced by estimated production costs, administrative costs, costs to develop and produce
the proved reserves and abandonment costs, all based on current economic conditions at each year-end. There can be no assurance that the
proved reserves will be produced in the future or that prices, production or development costs will remain constant. There are numerous
uncertainties inherent in estimating reserves and related information. See Note 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 10 6 ft 3) 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 10 6 ft 3),
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:

 Years Ended December 31,

 2024

 2023

 (Thousands, unless

 otherwise noted)

 Standardized measure of discounted future net cash flows

 $
 89,033

 $

 Present value of future income taxes discounted at a rate of 10%

 18,169

 32,748

 Present value of net cash flows discounted at a rate of 10% (PV-10)

 $
 107,202

 $
 102,672

 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.

 2024

 2023

 Production Concessions (1)

 Total gross productive acreage

 —

 —

 Total net productive acreage

 —

 —

 Exploration Permits (2)

 Total gross productive acreage

 —

 —

 Total net productive acreage

 —

 —

 Applications (3)

 Total gross productive acreage

 —

 —

 Total net productive acreage

 —

 —

 Total gross productive acreage

 —

 —

 Total net productive acreage

 —

 —

 Production Concessions (1)

 Total gross undeveloped acreage

 24,142

 24,142

 Total net undeveloped acreage

 19,710

 19,710

 Exploration Permits (2)

 Total gross undeveloped acreage

 682,802

 682,802

 Total net undeveloped acreage

 682,802

 682,802

 Applications (3)

 Total gross undeveloped acreage

 1,623,209

 1,623,209

 Total net undeveloped acreage

 1,623,209

 1,623,209

 Total gross undeveloped acreage

 2,330,153

 2,330,153

 Total net undeveloped acreage

 2,325,721

 2,325,721

 (1)
 Encompasses three distinct production concession areas including
Longanesi, Valle del Mezzano (Trava), and Gradizza. No expiries prior to 2032.

 (2)
 Encompasses 10 distinct permits. AleAnna has an active permit
extension program in place. In the event that production is not established or if extensions are not granted by the Italian government,
130,558 net acres will expire by December 31, 2026 and an additional 331,845 acres will expire by December 31, 2027. Included
in the 682,802 are three permits totaling 104,815 net acres are currently held in suspense pending review and revision of the PiTESAI
as further described in the "Governmental Regulations" section below. The Italian Government has initiated a procedure to
return to Aleanna all of the acres affected by the PiTESAI.

 (3)
 Encompasses 14 distinct areas and applications. Applications
are rights of mineral development controlled by AleAnna whose activation may be deferred. AleAnna has not yet initiated activation, but
has the right to do so in the future. Once AleAnna initiates activation the 1,623,209 net acres will have initial permit periods of six years.

 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.

 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 km 2. 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:

 art.
 8 "Granting of permits", paragraph 1, of the Presidential Decree. 18 April 1994,
 n. 484 "Regulation governing the procedures for awarding prospecting or exploration
 and granting concessions for the production of hydrocarbons on land and at sea";

 art.
 6 "Awarding of the exploration permit, its dimensions and duration", paragraph 4,
 of law 9 January 1991, n. 9 "Regulations for the implementation of the new national
 energy plan: institutional aspects, hydroelectric plants and power lines, hydrocarbons and
 geothermal energy, self-production and tax provisions";

 for
 onshore, art. 1, paragraph 7, letter n) of law 239/2004 "Reorganization of
 the energy sector, as well as delegation to the Government for the reorganization of the
 provisions in force on energy".

 The
 exploration permit is issued following a single procedure, governed by article 1 paragraphs
 77 and 79 of law 23 August 2004, n. 239 and subsequent amendments. MASE reviews the
 project after hearing the opinion of a consultative body, the Ministerial commission on hydrocarbons
 (CIRM), within which the competent state and regional administrations are represented. The
 projects are subjected to the environmental eligibility procedure and/or the expression of
 an environmental compatibility judgment by the MASE or the Region concerned. MASE then issues
 onshore permits in agreement with the regions involved.

 (b) Production Concessions
are exclusive mineral titles requested on a portion of the exploration permit area where a new hydrocarbon field was discovered (with
a maximum area of 300 km 2). 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:

 cancellation
 of general system charges;

 strengthening
 of social bonuses; and

 decrease
 of VAT in the gas sector (until December 31, 2023).

 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
 "notification" to the competent authority for the modifications are non-substantial;

 the
 "Simplified Authorization Procedure" ("S.A.P."):

 a)
 "for
 new facilities with a production capacity, as defined in accordance with Article 21,
 paragraph 2, not exceeding 500 standard cubic meters/hour;

 a-bis)
 for
 partial or complete reconversion to biomethane production of power generation facilities
 fueled by biogas, landfill gas or residual gas from purification processes;

 a-ter)
 for
 developments on operating biomethane production facilities that do not result in an increase
 in the area already subject to authorization, regardless of the resulting amount of biomethane
 fed into the grid as a result of such developments, subject to the following conditions:

 1.
 in
 the case of grid-connected facilities, there is the willingness of the grid operator to inject
 the additional volumes resulting from the implementation of the developments;

 2.
 the
 operations do not involve any changes in the types of matrices already authorized;

 3.
 the
 nameplate of the upgrading system indicates the production capacity value resulting from
 the implementation of the developments;

 4.
 any
 increase in areas dedicated to anaerobic digestion is no more than 50 percent of those already
 authorized."

 the
 "Sole Authorization" ("S.A.") in other cases.

 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:

 Law
 No. 95 of July 26, 2023, introduced urgent measures to simplify the procedures for authorization
 and connection to the national grid. In particular, the new measures indicate how to obtain
 authorization for the conversion or construction of biomethane facilities, which also included
 a simplified municipal authorization procedure for facilities up to 500 smc/h.

 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:

 carrying
 out our activities in compliance with current laws on occupational health and safety prevention,
 environment and current regulations with impact on quality aspects and voluntarily subscribed
 standards;

 promote
 activities that can directly or indirectly ensure: the protection and preservation of occupational
 health and safety, the environment, biodiversity and ecosystems, including in the interest
 of future generations;

 consider
 prevention in occupational health and safety and environment a goal of at least equal importance
 to profitability and productivity;

 protect
 the health and welfare and promote the occupational safety of all persons directly or indirectly
 involved in its operations;

 pursue
 excellence in behavior and continuous improvement in occupational health and safety and accident
 prevention, in environmental protection and preservation;

 ensure
 the centrality of the individual by fostering consultation the participation of workers and
 other stakeholders and ensure the sharing of experience and knowledge;

 design,
 implement and manage each activity taking into account the need to ensure the protection
 of the health and safety of employees and third parties, the protection of the environment
 and public safety;

 promote
 the use of natural gas in a safe, efficient and environmentally friendly manner; and

 train
 staff and exchange information and knowledge, which are considered fundamental tools for
 achieving health, safety, environmental and public safety objectives, with a view to continuous
 improvement.

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

 manage
 activities in full compliance with current legislation and signed voluntary standards and
 agreements as well as national and international best practices, ensuring compliance obligations
 and assessment of risks and opportunities, consistent with the Code of Ethics, Corporate
 Model 231 and all HSE Policy regulations;

 ensure
 that each worker is aware of, responsible for, and participates in the company's efforts
 to manage the aspects of occupational health and safety and environmental protection and
 quality assurance related to their activities, with the understanding that the responsible
 behavior of each person is a prerequisite for the success of the entire system;

 ensure
 the protection of workers' health and safety by adopting the most advanced principles,
 national standards, organizational solutions, adopting safe and healthy working conditions,
 using materials and equipment with the least risk to health, safety and the environment for
 the elimination of hazards and minimization of risks, with a view to the prevention of accidents,
 injuries, occupational diseases and emergency situations;

 implement
 every effort in organizational, operational and technological terms to prevent water, air
 and soil pollution, minimizing, where technically possible, environmental impacts related
 to the company's activities, with particular reference to the control of air emissions,
 water discharges, waste management, energy saving and recovery;

 support
 the conservation of natural resources with actions aimed at effective and efficient use of
 energy, minimizing the consumption of energy, water, and materials, also in the interest
 of future generations;

 involve
 and consult workers, including through their health, safety and environmental representatives;

 use
 qualified suppliers and promote their development according to the principles of this policy,
 committing them to maintain behavior consistent with it even when they operate outside the
 company;

 conduct
 periodic system audits, inspections, audits, and reviews to analyze performance, contextual
 factors, stakeholder needs, risks and opportunities, objectives, programs, and policy to
 assess their effectiveness and take consequent action to pursue the goal of continuous improvement;
 and

 putting
 in place actions to prevent any intentional or negligent event that may cause actual or potential
 harm to persons and tangible and intangible assets of the company.

 Government
Funding and Other Forms of Support

 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

 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, Societ
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

 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:

 Category

 Vendors

 Drilling rigs and laborers

 Pergemine SpA, LP Drilling

 Well logging and evaluation

 Schlumberger, Baker Hughes

 Well casing and cementing services

 Schlumberger, Baker Hughes

 Drill bits and downhole equipment

 Schlumberger, Baker Hughes

 Plant engineering and construction

 Saipem, Demont Srl

 Seismic acquisition

 Schlumberger, Doland Geophysical

 Purchase of existing Seismic

 Eni, CGG

 Seismic processing

 Tricon, CGG

 Seismic and well log interpretation software

 Schlumberger, S&P Global (IHS Markit)

 Drilling rigs and laborers

 Pergemine SpA, LP Drilling

 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:

 Category

 Vendors

 Investment opportunities

 VLF Srl

 Project developers

 Renove Srl

 Commodity traders

 Rivecom

 Bio-digester manufacturers

 Rota Srl

 Biomethane upgrading facilities

 Prodeval Srl

 Marketing groups

 Shell Energy Europe

 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 10 6 ft 3) 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 10 6 ft 3), 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:

 the
 need to obtain necessary environmental and other governmental approvals and permits, the
 timing and conditions of those approvals and permits, and litigation concerning those approvals
 and permits;

 the
 availability and cost of funds to finance the drilling and development of our properties;

 the
 timing and cost, which can be considerable, of the supporting infrastructure to our natural
 gas drilling and production operations;

 the
 ability to obtain midstream offtake capacity for our future natural gas production;

 drainage
 resulting from the development of offsetting properties from other operators in the area;

 commodity
 prices and our ability to find suitable customers for our future production;

 inflation
 and potential increases in costs of labor, power, supplies, services and other support; and

 the
 availability and retention of executives overseeing our operations and of skilled labor and
 equipment to support our drilling operations.

 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:

 delays
 imposed by or resulting from compliance with regulatory requirements, including limitations
 resulting from permitting, emission of greenhouse gases ("GHGs"), and other limitations
 and regulatory requirements;

 intervention
 by local or federal governments or a foreign sovereign, such as appropriation of assets or
 technology or imposition of a ban on exploration or production activities; 15

 shortages
 of or delays in obtaining equipment, rigs, materials or qualified personnel;

 supply
 chain disruptions or labor shortage impacts;

 equipment
 failures, accidents or other unexpected operational events;

 lack
 of available capacity on interconnecting transportation pipelines;

 adverse
 weather conditions, such as flooding, droughts, freeze-offs, landslides, blizzards and ice
 storms;

 exposure
 to acts of terrorism or military or other armed conflict or political instability in regions
 that affect our business or operations;

 issues
 related to compliance with environmental regulations;

 environmental
 hazards;

 declines
 in natural gas market prices;

 limited
 availability of financing at acceptable terms;

 ongoing
 litigation or adverse court rulings;

 public
 opposition to our operations;

 title,
 surface access, coal mining and right of way issues; and

 limitations
 in the market for natural gas.

 In
addition, we may become subject to additional laws or regulations issued by federal or state government bodies, which are subject to
influence resulting from frequent changes in political party control or changes to political priorities or policies. We may need to adapt
compliance strategies and 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 Societ 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:

 weather conditions and seasonal trends;

 global and regional supply of and demand for natural gas;

 regulatory constraints on pricing, prevailing prices in the
areas in which we operate, and expectations about future commodity prices;

 new or continuing armed conflicts or hostilities, or acts
of terrorism;

 national
 and worldwide economic and political conditions, particularly those in, or affecting, other
 countries which are significant producers of natural gas;

 new
 and competing exploratory finds of natural gas;

 in exports of natural gas producing countries, such as the United States and Russia;

 the
 effect of energy conservation efforts;

 the
 price, availability and consumer demand for alternative fuels;

 the
 availability, proximity, capacity and cost of pipelines, other transportation facilities,
 and gathering, processing and storage facilities and other factors that result in differentials
 to benchmark prices;

 technological
 advances affecting energy consumption and production;

 the
 actions of the Organization of Petroleum Exporting Countries;

 the
 level and effect of trading in commodity futures markets, including commodity price speculators
 and others;

 the
 cost of exploring for, developing, producing and transporting natural gas;

 risks
 associated with drilling, completion and production operations; and

 governmental
 regulations, tariffs and taxes, including environmental and climate change regulation.

 A prolonged
period of low natural gas prices may have an adverse effect on our revenue, profitability, future rate of growth, liquidity and financial
position.

 Prolonged
l ow, 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:

 our
 level of proved reserves and production;

 the
 level of hydrocarbons we are able to produce from existing wells;

 our
 access to, and the cost of accessing, end markets for our production;

 the
 prices at which our production is sold;

 our
 ability to acquire, locate and produce new reserves;

 the
 levels of our operating expenses; and

 our
 ability to access the public or private debt and equity capital and lending markets.

 If
we are unable to obtain the capital necessary for our planned capital budget or our operations, we could be required to curtail our operations
and the development of our properties, which in turn could lead to a decline in our reserves and production, and could adversely
affect our business, results of operations and financial position.

 Derivative transactions may limit our potential
gains and involve other risks.

 To manage our exposure to price
risk, we may in the future enter into derivative arrangements, utilizing commodity derivatives with respect to a portion of our future
production. Such hedges are designed to lock in prices in order to limit volatility and increase the predictability of cash flow. These
transactions may be required to the extent we utilize RBL financing in the future and 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 exi sting renewable natural gas plants, on favorable terms or at all. In
addition, we will compete with other companies and private equity sponsors for these opportunities, which may increase our costs or cause
us to refrain from making acquisitions at all. If we are unable to successfully identify and consummate future project opportunities
or acquisitions of existing plants it will impede our ability to execute our growth strategy.

 Our
ability to acquire, develop and operate renewable natural gas plants, is subject to various risks, including:

 regulatory
 changes that affect the value of renewable natural gas, including revisions to government
 sponsored price floors and any potential inability to qualify or potential disqualification
 from such programs, which could have a significant effect on the financial performance of
 the number of potential plants with attractive economics;

 in energy commodity prices, such as natural gas and wholesale electricity prices, which could
 have a significant effect on our revenues and expenses;

 in pipeline gas quality standards or other regulatory changes that may limit our ability
 to transport renewable natural gas on pipelines for delivery to third parties or increase
 the costs of processing renewable natural gas to allow for such deliveries;

 in the broader waste collection industry, including changes affecting the waste collection
 and biogas potential of the farming industry, which could limit the renewable natural gas
 resource that we currently target for our plants;

 substantial
 construction risks, including the risk of delay, that may arise due to forces outside of
 our control, including those related to engineering and environmental problems, inclement
 weather and labor disruptions;

 In
 order to construct new commercial and modify existing production facilities, we typically
 face a potentially lengthy and variable design, fabrication, and construction development
 cycle that requires resource commitments and may create fluctuations in whether and when
 revenue is recognized;

 operating
 risks and the effect of disruptions on our business, including the effects of weather conditions,
 catastrophic events such as fires, explosions, earthquakes, droughts and acts of terrorism,
 and other force majeure events on us, our customers, suppliers, distributors and subcontractors;

 accidents
 involving personal injury or the loss of life, as a result of work conditions including,
 but not limited to, hazardous worksite site conditions and gas exposure;

 the
 ability to obtain financing for a project on acceptable terms or at all and the need for
 substantially more capital than initially budgeted to complete plants and exposure to liabilities
 as a result of unforeseen environmental, construction, technological or other complications;

 failures
 or delays in obtaining desired or necessary land rights, including ownership, leases, easements,
 zoning rights and building permits;

 a
 decrease in the availability, pricing and timeliness of delivery of raw materials and components
 necessary for the operation of plants;

 obtaining
 and keeping in good standing permits, authorizations and consents from governmental organizations;

 unknown
 regulatory changes for renewable natural gas which may increase the transportation cost for
 delivering under contracts in place;

 the
 consent and authorization of local utilities or other energy development off-takers to ensure
 successful interconnection to energy grids to enable power and gas sales; and

 difficulties
 in identifying, obtaining and permitting suitable sites for new plants.

 Any
of these factors could prevent us from acquiring, developing, or operating plants, or otherwise adversely affect our business, financial
condition and results of operations.

 Acquiring
existing plants involves numerous risks.

 The
acquisition of existing renewable natural gas plants 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:

 the
 purchase price we pay could significantly deplete our cash reserves;

 the
 acquired companies or assets may not produce as planned or may entail significant unexpected
 or unbudgeted costs;

 we
 may have difficulty integrating the operations and personnel of the acquired companies;

 key
 personnel and customers of the acquired companies may terminate their relationships with
 the acquired companies as a result of or following the acquisition;

 we
 may experience additional financial and accounting challenges and complexities in areas such
 as joint venture accounting, tax planning, and financial reporting;

 we
 may incur additional costs and expenses related to complying with additional laws, rules
 or regulations in new jurisdictions;

 we
 may assume or be held liable for risks and liabilities (including for environmental-related
 costs) as a result of our acquisitions, some of which we may not discover during our due
 diligence or adequately adjust for in our acquisition arrangements;

 our
 ongoing business and management's attention may be disrupted or diverted by transition
 or integration issues and the complexity of managing geographically diverse enterprises;

 we
 may incur one-time write-offs or restructuring charges in connection with an acquisition;

 we
 may acquire goodwill and other intangible assets that are subject to amortization or impairment
 tests, which could result in future charges to earnings; and

 we
 may not be able to realize the expected cash flows or other financial benefits we anticipated.

 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:

 1.
 Notification: Used
for minor modifications to existing renewable natural gas plants.

 2.
 Simplified
Authorization Procedure (S.A.P.): Applicable to:

 New
plants with a production capacity under 500 standard cubic meters/hour.

 Converting
existing power plants to biomethane production.

 Expanding
existing renewable natural gas plants within certain limits.

 3.
 Sole
Authorization (S.A.): Required for projects outside the scope of S.A.P.

 For
S.A., applications are submitted to regional authorities, followed by a service conference involving relevant public bodies. The process
typically concludes within 90 days, unless extended for assessments or document reviews. Under S.A.P., applications go to municipalities,
 with a decision required within 30 days; otherwise, approval is automatic. Recent legislative updates, like Law No. 95 of
July 26, 2023, simplify authorization for biomethane projects, focusing on plants up to 500 smc/h, to facilitate faster connection
to the national grid. These changes aim to streamline renewable natural gas development across Italy while ensuring environmental compliance.

 Thus, in order to develop a
renewable energy project, we are typically required to obtain, among other things, environmental impact permits or other authorizations
and building permits, which in turn require environmental impact studies to be undertaken and public hearings and comment periods to be
held during which any person, association or group may oppose a project. Any such opposition may be taken into account by government officials
responsible for granting the relevant permits, which could result in the permits being delayed or not being granted or being granted solely
on the condition that we carry out certain corrective measures to the proposed project. Opposition to our plants' requests for permits
or successful challenges or appeals to permits issued for our plants could adversely affect our operating plans.

 As a result, 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 (10 3 ft 3).
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:

 loss
 of revenue, property and equipment as a result of hazards such as expropriation, war, insurrection
 and other political risks;

 increases
 in taxes, including VAT taxes and potential future energy tax measures and governmental royalties;

 renegotiation
 of contracts with governmental entities;

 failure
 of the government to provide necessary permits within the anticipated timeframe, or at all;

 in laws and policies governing operations of foreign-based companies; and

 currency
 restrictions and exchange rate fluctuations.

 Our international operations
may also be adversely affected by laws and policies of the United States affecting foreign trade and taxation.

 Realization of any of these
factors could have a material adverse effect on our business, financial condition and results of operations.

 We are subject to pricing restrictions enforced
by the Italian Regulatory Authority for Energy, Networks and Environment with respect to the residential customers we intend to service.

 AleAnna's businesses
are 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:

 a
 majority of the Board consist of independent directors under Nasdaq Capital Market rules;

 the
 nominating and governance committee be composed entirely of independent directors with a
 written charter addressing the committee's purpose and responsibilities; and

 the
 compensation committee be composed entirely of independent directors with a written charter
 addressing the committee's purpose and responsibilities.

 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 corpor ate 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:

 Management did not maintain an effective control environment in accordance with the COSO framework as it did not maintain a sufficient complement of accounting and reporting resources commensurate with its financial reporting requirements. This material weakness contributed to the following material weaknesses:

 Management did not design, implement, and operate controls over the selection and implementation of accounting policies to ensure amounts recorded and disclosed were fairly stated in accordance with GAAP.

 Management did not design or maintain appropriate account reconciliation and journal entry review controls to review the work of third-party consultants used to assist management in recording transactions.

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

 Designing and implementing a risk assessment process supporting the identification of risks facing AleAnna.

 Implementing controls to enhance our review of significant accounting transactions and other new technical accounting and financial reporting issues and preparing and reviewing accounting memoranda addressing these issues.

 Hiring additional experienced accounting, financial reporting and internal control personnel and changing roles and responsibilities of our personnel as we transition to being a public company and are required to comply with Section 404 of the Sarbanes-Oxley Act.

 Implementing controls to enable an accurate and timely review of accounting records that support our accounting processes and maintain documents for internal accounting reviews.

 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 b e
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

 Risk management and strategy

 We have established
processes for assessing, identifying, and managing material risk from cybersecurity threats, and have integrated these processes into
our overall risk management systems and processes. We routinely assess material risks from cybersecurity threats, including any potential
unauthorized attempts to access our information systems that may result in adverse effects on the confidentiality, integrity, or availability
of those systems.

 These risk assessments
include identification of reasonably foreseeable internal and external risks, the likelihood and potential damage that could result from
such risks, and the sufficiency of existing policies, procedures, systems, and safeguards in place to manage such risks. Following these
risk assessments, if necessary, we would re-design and implement reasonable additional safeguards to minimize identified risks and address
any identified gaps in existing safeguards.

 Primary responsibility
for assessing, monitoring, and managing our cybersecurity risks rests with our third-party IT service provider who reports to our Chief
Accounting Officer, to manage the risk assessment and mitigation process.

 As part of our overall
risk management system, we monitor and test our safeguards and we train our relevant employees on these safeguards, in collaboration with
our third-party IT provider and management. Since users are typically the weakest link in any information system, we periodically train
all our employees on good cybersecurity practices, including password management, phishing prevention, and other security awareness issues.

 We have not encountered
cybersecurity threats or challenges that have materially impaired our operations, business strategy or financial condition.

 Governance

 Our Board of Directors is responsible
for monitoring and assessing strategic risk exposure including cybersecurity risk, and our executive officers are responsible for the
day-to-day management of the material risks we face. Our Board of Directors administers its cybersecurity risk oversight function directly
as a whole, as well as through the Audit Committee.

 Our Chief Accounting
Officer is primarily responsible for assessing and managing our material risks from cybersecurity threats with assistance from our third-party
IT service provider.

 Our
Chief Accounting Officer oversees our cybersecurity policies and processes, coordinating with our third-party IT service provider,
which has over 20 years of experience and expertise in cybersecurity risk management. The third-party service provider is responsible
for implementing cybersecurity measures and monitoring for threats. Our Chief Accounting Officer will provide periodic briefings to the
Executive Director, the Audit Committee and/or the Board of Directors as needed regarding any material cybersecurity risks or activities,
including any recent cybersecurity incidents and related responses, based on information provided by the third-party service provider.

 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 10 6 ft 3)
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 10 6 ft 3) 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 10 6 ft 3) 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 10 6 ft 3), 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 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:

 For the Year Ended December 31,

 Dollar

 Percentage

 2024

 2023

 Change

 Change

 Revenues

 $
 1,420,030

 $
 -

 $
 1,420,030

 NM

 Operating Expenses:

 Cost of revenues

 $
 1,043,174

 $
 -

 $
 1,043,174

 NM

 General and administrative

 6,264,087

 5,634,150

 629,937

 %

 Depreciation

 133,516

 -

 133,516

 NM

 Accretion of asset retirement obligation

 -

 %

 8,398,653

 -

 8,398,653

 NM

 Total Operating Expenses

 15,972,669

 5,767,389

 10,205,280

 %

 Other Income (Expense):

 Interest and other income (expense)

 1,948,281

 (102,041
)

 2,050,322

 2009
 %

 Change in fair value of derivative liability

 173,177

 708,869

 (535,692
)

 -76
 %

 Total Other Income (Expense)

 2,121,458

 606,828

 1,514,630

 %

 $
 (12,431,181
)

 $
 (5,160,561
)

 $
 (7,270,620
)

 %

 Deemed dividend to Class 1 Preferred Units redemption value

 (155,423,177
)

 (53,219,200
)

 (102,203,977
)

 %

 Noncontrolling interests in earnings of subsidiaries

 -

 NM

 Net loss attributable to Class A Common stockholders or holders of Common Member Units

 $
 (167,766,847
)

 $
 (58,379,761
)

 $
 (109,387,086
)

 %

 Other Comprehensive Income (Loss)

 Currency translation adjustment

 (1,548,154
)

 (1,767,062
)

 %

 Comprehensive Loss

 $
 (13,979,335
)

 $
 (4,941,653
)

 $
 (9,037,682
)

 %

 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.

 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.

 Currency Translation Adjustment

 For the purposes of presenting
consolidated financial statements, the assets and liabilities of our Euro operations are translated to USD at the exchange rate on the
reporting date. The income and expenses are translated using average exchange rates. Foreign currency differences that arise on translation
for consolidated purposes are recognized as a currency translation adjustment in other comprehensive loss on the consolidated statements
of operations and comprehensive loss.

 The currency translation adjustment
decreased by $1.8 million for the year ended December 31, 2024 compared to the same period in 2023. This decrease was due to
the fluctuation of the exchange rates between the Euro and the U.S. Dollar as well as the level of our activities.

 Segment Considerations

 Our operations consist of one
reportable segment reflecting the manner in which operations are managed and the criteria used by the chief operating decision maker ("CODM"),
our Executive Chairman and Chief Executive Officer, collectively, to evaluate performance, develop strategy, and allocate resources.

 AleAnna's principal products
include conventional natural gas produced from onshore exploration and development, and electricity and RNG derived from animal and agricultural
waste. As of December 31, 2024, we had not yet generated revenue from our conventional natural gas activities and had only recently begun
deriving revenue from sales of electricity related to our RNG business.

 While we have recently acquired
three RNG assets, these assets are still in the early stages of development which may include expansion and installation of upgrading
units to refine biomethane into renewable natural gas (rather than conversion to electricity). These assets have not generated significant
revenues or incurred material expenses. As of and for the year ended December 31, 2024, the CODM was primarily focused on capital investing
decisions, strategy, and forward-looking investment economics. While the CODM monitors cash reserves and overall enterprise liquidity,
extensive review and analysis of the our performance and loss statements is not performed beyond review of the consolidated financial
statements. As such, the CODM continues to assess our financial performance as a single enterprise on a consolidated basis, without distinguishing
between conventional natural gas and RNG operations. Given we have not generated significant revenue or profits and are focused on development
activities, the CODM does not utilize a specific measure of profit or loss to assess performance. The CODM does not monitor specific expense
categories separately. The financial information reviewed by the CODM is consistent with the audited consolidated balance sheets and statements
of operations and cash flows included herein.

 All of the Company's
primary operating activities and assets remain located in Italy. We will continue to assess the need for including multiple reportable
segments as the business evolves.

 Liquidity, Capital Resources and Operations

 We have generated minimal revenues
from our operations to date and we had an accumulated deficit of $191.0 million a s of
December 31, 2024. We had $28.3 million in cash and cash equivalents on December 31, 2024. The Company's continuing operations,
as intended, are dependent upon its ability to generate cash flows or obtain additional financing. Between January 2024 and May 2024,
prior to the Business Combination, we received an aggregate of $62.1 million in capital contributions from AleAnna Energy members
resulting in the issuance of 62,100 Class 1 Preferred Units, to fund operating costs, capital expenditures, Business Combination
related transaction expenses, and to provide working capital to meet our liabilities and commitments as they become due. In addition,
we are exploring Resource Backed Loan ("RBL") financing and renewable natural gas project loan products with several financial
institutions; however, there is no guarantee that such financing will be available to us. As a normal part of our business, depending
on market conditions, we may from time to time consider opportunities to repay, redeem, repurchase or refinance the indebtedness of our
subsidiaries or issue equity securities to raise additional capital. Changes in our operating plans, lower than anticipated revenues,
increased expenses, acquisitions or other events may cause us to seek additional debt or equity financing in future periods. There can
be no guarantee that financing will be available on acceptable terms or at all.

 Presently, Padana is the operator
of the Longanesi field under a Unitized Operating Agreement, and other companies in the future may operate some of the properties in which
we have an interest. The failure of an operator of our wells or joint venture participant to adequately perform operations, an operator's
breach of the applicable agreements or an operator's failure to act in ways that are in our best interest could reduce our production
and revenues.

 To mitigate operator risks,
we monitor the operational risks, credit risk, financial position and liquidity of Padana. Operational risks are monitored and acted on
through: (i) periodic meetings with Padana, through a formal committee known as the "Technical Committee", to examine
upcoming activities and discuss questions and concerns, (ii) through the receipt and analysis of daily reports, (iii) through
requesting unscheduled calls with Padana where areas of concern are identified, and (iv) through occasional site visits. Further,
Padana's credit risk, financial position, and liquidity are periodically evaluated through review of the financial condition of
Padana's parent organization, Gas Plus S.p. A., which is a publicly-traded company on the Italian Stock Exchange (Euronext Milan).
We are able to continuously monitor financial health of Gas Plus S.p. A. through exchange-required public disclosures, including half-annual
and annual financial statements, corporate presentations, and press releases.

 Cash Flows

 The following table includes
our cash flow data for the years ended December 31, 2024 and 2023:

 For the Year Ended December 31,

 2024

 2023

 Consolidated Statement of Cash Flows Data:

 Net cash used in operating activities

 (16,897,557
)

 (5,749,303
)

 Net cash used in investing activities

 (23,066,287
)

 (8,924,941
)

 Net cash provided by financing activities

 62,106,468

 21,004,132

 Cash used in operating activities

 Cash used in operating activities
increased by $11.1 million for the year ended December 31, 2024, compared to the year ended December 31, 2023. Overall, increases
in cash used in operating activities reflect increased operating expenditures primarily related to legal, consulting and audit fees and
salaries and wage expenses, in addition to the Business Combination transaction expenses.

 Cash used in investing activities

 Cash used in investing activities
increased by $14.1 million for the year ended December 31, 2024, compared to the year ended December 31, 2023.

 In all periods presented, cash
used in investing includes continued drilling, completion, and tie in of Longanesi-2D and Longanesi-3D wells. In year ended December 31,
2024, cash used in investing activities also reflects approximately $9.5 million of cash used to purchase three separate renewable natural
gas assets, and approximately $5.1 million paid to Blugas as part of the Blugas Settlement (exclusive of VAT). These transactions
are discussed in more detail in the Recent Developments section.

 Cash provided by financing activities

 Cash provided by financing
activities in all periods presented reflects pre-Business Combination issuances of AleAnna Energy Class 1 Preferred Units used
to fund our operations. Such Class 1 Preferred Units were exchanged for Class A and Class C commons stock as part of the Business Combination.
The cash proceeds from the Business Combination, net of expenses allowed to be capitalized, had a negligible impact on financing cash
flows as the majority of the Business Combination transaction expenses were required to be expensed and were included in net loss within
operating cash flows.

 Contractual Obligations and Other Commitments

 Participation Agreements and Blugas ORRI

 In the normal course of business,
we enter into agreements with other entities to assist in the performance of drilling of the Longanesi field. On June 26, 2009, we
entered into a Participation Agreement with Padana for the drilling of the 'Longanesi 1 exploration well, 'San Potito'
concession and 'Abbadessee 1' exploration,' collectively referred to as the Longanesi field.

 The Unified Operating Agreement
arrangement was originally signed between Eni and Grove and dated September 26, 2009. However, Padana has succeeded Eni as the operator
and 66.5% working interest owner, and we succeeded Grove as the non-operator and 33.5% working interest owner. On July 13, 2016,
we acquired a 33.5% working interest in the Longanesi field from Enel, and, as part of the purchase, acquired a legacy contingent liability
arising from an agreement between the Longanesi working interest's original owner Grove Energy and Blugas. Blugas retained an interest
akin to an ORRI, whereby Blugas was entitled to physical delivery of 20% of the first 350 million standard cubic meters (approximately
2,472 10 6 ft 3) produced from the Longanesi field. Prior to the Blugas settlement in May 2024 (as further described
below), in accounting for the acquisition of the 33.5% working interest, we did not recognize an asset or liability in the consolidated
financial statements related to the Blugas ORRI as our SEC Case reserves estimates contemplated the contractual arrangement and physical
gas delivery to Blugas, such that the gas revenues attributable to our 33.5% working interest were reduced to reflect sale of the Blugas
quantity and payment of such revenues (cash outflows to Blugas).

 The physical volumes due to
Blugas were being contested by us as usury because we considered, among other reasons, that extraction services and all associated risks
are executed by us and that participation by Blugas was limited to financing a part of the sum necessary to start drilling, without participation
in the construction and exploitation of the reservoir, and therefore do not share the risks or costs, which had increased compared to
the initial forecast of the investment.

 On May 28, 2024, we entered
into the Blugas Settlement Agreement regarding the Blugas ORRI whereby Blugas was entitled to physical delivery of 20% of the first 350 million
standard cubic meters (approximately 2,472 10 6 ft 3) produced from the Longanesi field. Under the terms of the Blugas
Settlement Agreement, we paid Blugas approximately 5 million, plus an additional 1.1 million in applicable VAT,
or a total of approximately $6.6 million. In exchange, we were released from any future liability related to the Blugas ORRI. As
a result of the transactions contemplated by the Blugas Settlement Agreement, our 33.5% working interest in the Longanesi field is now
unencumbered except for normal government royalties (10%). The Blugas Settlement Agreement was accounted for as an acquisition of the
Blugas ORRI claim with a corresponding increase to the expected future cash flows from our reserves. Our
year-end December 31, 2023 reserve quantities included the 20% of 350 million standard cubic meters (approximately 2,472
10 6 ft 3) 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 10 6 ft 3), however, the previously required payments to Blugas associated
with the sale of such quantities are no longer reflected as cash outflows (costs) as if such amounts were paid to Blugas. As the cash
outflows (costs) are no longer reflected as if paid to Blugas, such amounts are reflected in our December 31, 2024 reserve report as allocable
to our unencumbered 33.5% working interest.

 Contingent Consideration Liability

 In connection with our purchase
of our 33.5% working interest in the Longanesi field, consideration paid included 7 million cash and up to 24 million
of deferred consideration payable upon production of the Longanesi field. The deferred consideration is payable based on a formulaic calculation
which is predominantly dependent on sales volumes and spot natural gas prices during the first 12 years of production (the "Earn-Out
Period"). There will be no deferred consideration due if Longanesi is not developed and no deferred consideration due if average
annual gas prices are less than 3.65/Mcf over the Earn-Out Period. Upon first production, AleAnna will also be required to reserve
cash collateral of 3 million related to the contingent consideration liability which will be classified as restricted cash in future
balance sheets and may be used to satisfy the contingent consideration liability as payments become due.

 We recognized a liability for
the contingent consideration in accounting for the asset acquisition in accordance with ASC 450, Contingencies ("contingent
consideration liability"). As of December 31, 2024, and December 31, 2023, the total contingent consideration liability was
recorded a t $25.0 million and $26.5 million, respectively.

 Internal Control over Financial Reporting

 Effective internal controls
are necessary to provide reliable financial reports and prevent fraud. AleAnna is a newly public company that is in the process of adding
resources with the appropriate level of experience and technical expertise to oversee AleAnna's business processes and controls.
At this time, AleAnna does not have the necessary business processes and related internal controls formally designed and implemented.

 As a result, AleAnna previously
identified material weaknesses in its internal control over financial reporting. A material weakness is a deficiency, or a combination
of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement
of annual or interim financial statements would not be prevented or detected on a timely basis.

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

 Management did not maintain an effective control environment
in accordance with the COSO framework as it did not maintain a sufficient complement of accounting and reporting resources commensurate
with its financial reporting requirements. This material weakness contributed to the following material weaknesses:

 Management did not design, implement, and operate controls over
the selection and implementation of accounting policies to ensure amounts recorded and disclosed were fairly stated in accordance with
GAAP.

 Management did not design or maintain appropriate account reconciliation
and journal entry review controls to review the work of third-party consultants used to assist management in recording transactions.

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

 Designing and implementing a risk assessment process supporting
the identification of risks facing AleAnna.

 Implementing controls to enhance our review of significant accounting
transactions and other new technical accounting and financial reporting issues and preparing and reviewing accounting memoranda addressing
these issues.

 Hiring additional experienced accounting, financial reporting
and internal control personnel and changing roles and responsibilities of our personnel as we transition to being a public company and
are required to comply with Section 404 of the Sarbanes-Oxley Act.

 Implementing controls to enable an accurate and timely review
of accounting records that support our accounting processes and maintain documents for internal accounting reviews.

 The Company 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, 2024. 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.

 Emerging Growth Company Accounting Election

 Section 102(b)(1) of
the JOBS Act exempts emerging growth companies from being required to comply with new or revised financial accounting standards until
private companies are required to comply with the new or revised financial accounting standards. The JOBS Act provides that a company
can elect not to take advantage of the extended transition period and comply with the requirements that apply to non-emerging growth companies,
and any such election to not take advantage of the extended transition period is irrevocable. We expect to be an emerging growth company
at least through 2025.

 Critical Accounting Policies and Estimates

 Our unaudited consolidated
financial statements are based on the selection and application of significant accounting policies. The preparation of our management's
discussion and analysis of our financial condition and results of operations is based on our audited consolidated financial statements
as of and for the years ended December 31, 2024 and 2023, which have been prepared in accordance with GAAP. In preparing
these financial statements, we make estimates and assumptions impacting asset and liability amounts, disclosure of contingent liabilities,
and expenses incurred.

 The estimates are based on
our historical experience and on various other factors that we believe are reasonable under the circumstances, the results of which form
the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. We
regularly assess these estimates; however, actual amounts could differ materially from those estimates under different assumptions or
conditions. The most significant items involving management's estimates include estimates of contingencies including the contingent
consideration liability discussed below. The impact of changes in estimates is recorded in the period in which they become known.

 The accounting policies discussed
below are critical to understanding our historical and future performance, as these policies relate to the more significant areas involving
management's judgments and estimates.

 Conventional Natural Gas Properties

 We use the successful efforts
method of accounting for conventional gas-producing activities. Under this method, the cost of productive wells and related equipment,
development dry holes, and any permits related to productive acreage are capitalized, and depleted using the unit-of-production method.
These costs include other internal costs directly attributable to production activities. We are not yet recognizing depletion as assets
are not yet producing and therefore have not yet been placed in service. Costs for exploratory dry holes, exploratory geological and geophysical
activities, and delay rentals as well as other property carrying costs are charged to exploration expense.

 There were no exploratory wells
drilled or capitalized exploratory well costs in the years ended December 31, 2024 or 2023. All asset additions in the years ended
2024 and 2023, relate to the drilling of three Longanesi development wells. Such wells began production in March 2025.

 Proved gas reserves, are those
quantities of gas that, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically
producible from a given date forward from known reservoirs and under existing economic conditions, operating methods and government regulations
prior to the time at which contracts providing the right to operate expire unless evidence indicates that renewal is reasonably certain
regardless of whether deterministic or probabilistic methods are used for the estimation.

 The estimates of proved natural
gas reserves ("SEC Case") utilized in the preparation of our consolidated financial statements are estimated in accordance
with the rules established by the SEC and the Financial Accounting Standards Board ("FASB"). These rules require that reserve
estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price
and cost escalations in future years except by contractual arrangements. The development of our natural gas reserve quantities requires
management to make significant estimates and assumptions related to the intent and ability to complete undeveloped proved reserves within
a five-year development period, as prescribed by SEC guidelines. Management engaged DeGolyer to prepare reserves estimates for our estimated
proved reserves at December 31, 2024, and 2023. The technologies used in the estimation of our net proved undeveloped reserves include,
but are not limited to, empirical evidence through drilling results and well performance, production data, decline curve analysis, well
logs, geologic maps, core data, seismic data, demonstrated relationship between geologic parameters and performance, and the implementation
and application of statistical analysis.

 Management has confirmed that
none of the Unitized Operating Agreement's reserves nor the Proved Undeveloped Reserves ("PUDs") are scheduled to be
developed on a date more than five years from the date the reserves were initially recognized as PUDs as prescribed by SEC guidelines.
PUDs are converted from undeveloped to developed as applicable wells begin production.

 Reserve estimates are inherently
imprecise. Accordingly, the estimates are expected to change as more current information becomes available. Such estimates are subject
to the uncertainties inherent in the application of judgmental factors in interpreting such information. It is possible that, because
of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues,
the volume of natural gas reserves, the remaining estimated lives of natural gas properties, or any combination of the above may be increased
or decreased. Increases in recoverable economic volumes generally reduce per-unit depletion rates, while decreases in recoverable economic
volumes generally increase per-unit depletion rates.

 Revenue Recognition

 General — We
follow the guidance of FASB Accounting Standards Codification 606, Revenue from Contracts with Customers ("ASC 606").
The core principle underlying revenue recognition under ASC 606 is that revenue should be recognized as goods or services are transferred
to customers in an amount that reflects the consideration to which we expect to be entitled. ASC 606 defines a five-step process
to achieve recognition and mandates additional disclosure about the nature, amount, timing and uncertainty of revenues and cash flows
arising from customer contracts, including significant judgments, and changes in judgments and assets recognized from costs incurred to
obtain or fulfill a contract.

 Renewable Natural Gas — As
of December 31, 2024, we primarily earn revenue through electricity generation revenue from the conversion of bio feedstocks to biomethane
which is then converted to electricity through reciprocating generators. Such electricity is then delivered onto the grid through a metered
interconnection and sold to the local state-owned electrical utility responsible for the purchase and marketing of energy produced by
small-scale renewable energy assets. Upon delivery of the electricity to the grid, all performance obligations have been satisfied and
energy generation revenue is recognized based on actual output and non-company specific predetermined prices for small renewable energy
producers of 280/MWh, established under Ministerial Decree (D.M.) 18 December 2008, which sets tariff rates for small renewable
energy producers in Italy.

 Revenue is recognized over
time as we transfer the electricity to the grid at a metered interconnection. The customer obtains control of the product upon delivery
onto the electrical grid. We generally have a single performance obligation in our arrangements with our customers. We have no long-term
contracts containing quantity or electricity volume production requirements and there is no variable consideration present in our performance
obligations. Per ASC 606-10-25-27(a), delivery of units of power that are simultaneously received and consumed by the customer would
satisfy the criteria to be accounted for as a performance obligation satisfied over time and the same method would be used to measure
the entity's progress towards complete satisfaction of the performance obligation to transfer each distinct unit of power in the
series to the customer. Our performance obligation related to the sales of electricity are satisfied over time upon delivery to the customer.
Revenue is measured as the amount of consideration we expect to receive in exchange for transferring our products. We apply a practical
expedient in FASB ASC 606-10-55-18 applicable to our sales by assessing whether our right to consideration corresponds directly with
the value to our customers (the "invoice practical expedient"). We concluded that pricing corresponds to the value provided
to the customer. Consideration for each transaction is based upon non-company specific predetermined prices for small renewable energy
producers of 280/MWh, established under Ministerial Decree (D.M.) 18 December 2008, which sets tarrif rates for small renewable
energy producers in Italy. Payment terms are typically two months after the invoice date and there are no return or refund rights.

 Business Combinations and Asset Acquisitions

 We evaluate whether a transaction
meets the definition of a business. We first apply a screen test to determine if substantially all of the fair value of the gross assets
acquired is concentrated in a single identifiable asset or group of similar identifiable assets. If the screen test is met, the transaction
is accounted for as an asset acquisition. If the screen test is not met, we further consider whether the set of assets acquired have,
at a minimum, inputs and processes that have the ability to create outputs in the form of revenue. If the assets acquired meet this criteria,
the transaction is accounted for as a business combination.

 Acquisitions that qualify as
an asset acquisition are accounted for using a cost accumulation model where the purchase price of the acquisition is allocated to the
assets acquired on a relative fair value basis on the date of acquisition. We generally account for acquisitions of renewable natural
gas assets as asset acquisitions. Inputs used to determine such fair values are primarily based upon internally-developed estimates, estimates
developed by third-party valuation firms, and publicly-available data regarding renewable natural gas asset transactions consummated by
other buyers and sellers, as applicable. These fair values are considered Level 3 assets in the fair value hierarchy. Any associated acquisition
costs are generally capitalized.

 Acquisitions that qualify as
a business combination are accounted for using the acquisition method of accounting. The fair value of consideration transferred for an
acquisition is allocated to the assets acquired and liabilities assumed based on their fair value on a nonrecurring basis on the acquisition
date and are subject to fair value adjustments under certain circumstances. The excess of the consideration transferred over the fair
value of assets acquired and liabilities assumed is recorded as goodwill. Conversely, in the event the fair value of assets acquired and
liabilities assumed is greater than the consideration transferred, a bargain purchase gain is recognized.

 Determining the fair value
of assets acquired and liabilities assumed requires judgment and often involves the use of significant estimates and assumptions as fair
values are not always readily determinable. Different techniques may be used to determine fair values, including market prices (where
available), comparisons to transactions for similar assets and liabilities and the discounted net present value of estimated future cash
flows, among others. We engage third-party valuation firms when appropriate to assist in the fair value determination of assets acquired
and liabilities assumed. Acquisition-related expenses and transaction costs associated with business combinations are expensed as incurred.
We may adjust the amounts recognized in an acquisition during a measurement period not to exceed one year from the date of acquisition,
as a result of subsequently obtaining additional information that existed at the acquisition date.

 Where applicable, asset acquisitions
may be owned together with unaffiliated outside parties. In acquisitions where we have a majority direct controlling interest, the unaffiliated
outside ownership is shown as noncontrolling interests in members' equity in our consolidated financial statements.

 Contingent Consideration Liability

 On July 13, 2016, AleAnna
Europa S.r.l., a former subsidiary of AleAnna Resources LLC (which was subsequently merged into AleAnna Italia S.p. A. in December 2022),
purchased a 33.5% working interest in the Longanesi field, which was accounted for as an asset acquisition. Consideration paid included
 7 million cash and up to 24 million of deferred consideration payable upon production of the Longanesi field. The
deferred consideration is payable based on a formulaic calculation which is predominantly dependent on sales volumes and spot natural
gas prices during the first 12 years of the Earn-Out Period. There will be no deferred consideration due if Longanesi is not developed
and no deferred consideration due if average annual gas prices are less than 3.65/Mcf over the Earn-Out Period.

 We recognized a liability for
the contingent consideration in accounting for the asset acquisition in accordance with ASC 450, Contingencies (the "contingent
consideration liability") based on our assessment of probability of the occurrence of payment and deemed the liability estimable
based on the formulaic nature. See Note 3 for more information.

 Income Taxes

 The Company follows the asset
and liability method of accounting for income taxes under ASC 740, "Income Taxes." Deferred tax assets and liabilities are
recognized for the estimated future tax consequences attributable to differences between the consolidated financial statements carrying
amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted
tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.
The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that included the enactment
date. Valuation allowances are established, when necessary, to reduce deferred tax assets to the amount expected to be realized.

 ASC 740
prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions
taken or expected to be taken in a tax return. For those benefits to be recognized, a tax position must be more likely than not to be
sustained upon examination by taxing authorities. The Company recognizes accrued interest and penalties related to unrecognized tax benefits
as income tax expense. There were no unrecognized tax benefits and no amounts accrued for interest and penalties as of December 31, 2024
or 2023. The Company is currently not aware of any issues under review that could result in significant payments, accruals or material
deviation from its position. The Company is subject to income tax examinations by major taxing authorities since inception.

 Asset Retirement Obligation

 We recognize a liability for
asset retirement obligations ("AROs") based on an estimate of the amount and timing of settlement at the time a legal obligation
is incurred. Upon initial recognition of an ARO, we increase the carrying amount of the long-lived asset by the same amount as the liability.
The initial capitalized costs will be depleted over the useful (productive) lives of the related assets.

 Our asset retirement obligations
relate to the abandonment of gas production facilities including reclaiming well pads, reclaiming water impoundments, plugging wells and
dismantling related structures. Estimates are based on historical experience of plugging and abandoning wells and reclaiming of disposing
other assets and estimated remaining (productive) lives of the wells and assets.

 No
incremental ARO liabilities were incurred during the year ended December 31, 2024. During the year ended December 31, 2023,
we incurred incremental ARO liabilities, for one new development area associated with Longanesi (Casale Cocchi 1). Otherwise, changes
in ARO between periods presented only relate to the accretion of the liability. We do not have any assets that are legally restricted
for purposes of settling these obligations.

 Item 7A: Quantitative and Qualitative Disclosure About Market Risk

 Pursuant to Item 305(e) of Regulation S-K (§ 229.305(e)), the
Company is not required to provide the information required by this Item as it is a " smaller reporting company, " as
defined by Rule 229.10(f)(1).

 Item 8. Financial Statements and
Supplementary Data

 Report of Independent Registered Public Accounting Firm (PCAOB ID: 34)

 Consolidated Balance Sheets

 Consolidated Statements of Operations and Comprehensive Loss

 Statements of Consolidated Changes in Stockholders'
and Members' Equity

 Consolidated Statements of Cash Flows

 Notes to the Consolidated Financial Statements

 F- 1

 REPORT OF INDEPENDENT REGISTERED
PUBLIC ACCOUNTING FIRM

 To the stockholders and the Board of Directors of AleAnna, Inc.

 Opinion on the Financial Statements

 We have audited the
accompanying consolidated balance sheets of AleAnna, Inc. and subsidiaries (the "Company") as of December 31, 2024 and
2023, the related consolidated statements of operations and comprehensive loss, changes in stockholders' equity, and cash
flows, for each of the two years in the period ended December 31, 2024, and the related notes (collectively referred to as the
"financial statements"). In our opinion, the financial statements present fairly, in all material respects, the
financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of
the two years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United
States of America.

 Basis for Opinion

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

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

 Our audits included performing
procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures
that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the
financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management,
as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for
our opinion.

 /s/ Deloitte & Touche LLP

 Dallas, Texas

 We have served as the Company's auditor since 2023.

 F- 2

 CONSOLIDATED BALANCE SHEETS

 AS OF DECMBER 31, 2024 AND 2023

 2024

 2023

 ASSETS

 Current Assets:

 Cash and cash equivalents

 $
 28,330,159

 $
 6,759,265

 Accounts receivable

 1,225,297

 -

 Prepaid expenses and other assets

 1,666,155

 27,485

 Total Current Assets

 31,221,611

 6,786,750

 Non-current assets:

 Natural gas and other properties, successful efforts method

 33,979,014

 22,480,830

 Renewable natural gas properties, net of accumulated depreciation of $ 132,094

 9,296,039

 -

 Value-added tax refund receivable

 6,845,030

 4,425,353

 Operating lease right-of-use assets

 1,744,897

 -

 Total Non-current Assets

 51,864,980

 26,906,183

 Total Assets

 $
 83,086,591

 $
 33,692,933

 LIABILITIES AND EQUITY

 Current Liabilities:

 Accounts payable and accrued expenses

 $
 2,204,208

 $
 1,053,819

 Related party payables

 -

 525,276

 Lease liability, short-term

 163,865

 -

 Derivative liability, at fair value

 -

 173,177

 Total Current Liabilities

 2,368,073

 1,752,272

 Non-current Liabilities:

 Asset retirement obligation

 4,375,919

 4,242,680

 Lease liability, long-term

 1,579,443

 -

 Contingent consideration liability, long-term

 24,994,315

 26,482,682

 Total Non-current Liabilities

 30,949,677

 30,725,362

 Total Liabilities

 33,317,750

 32,477,634

 Commitments and Contingencies (Note 6)

 Temporary Equity:

 Class 1 Preferred Units, no par value, 43,611 units authorized, issued and outstanding; liquidation preference $ 152,637,776 as of December 31, 2023

 -

 152,464,599

 Stockholders' and Members' Equity:

 Class A Common Stock, par value $ 0.0001 per share, 150,000,000 shares authorized, 40,560,433 shares issued and outstanding as of December 31, 2024

 4,056

 -

 Class C Common Stock, par value $ 0.0001 per share, 70,000,000 shares authorized, 25,994,400 shares issued and outstanding as of December 31, 2024

 2,599

 -

 Additional paid-in capital

 226,722,424

 -

 Accumulated other comprehensive loss

 ( 5,803,378
)

 ( 4,859,933
)

 Accumulated deficit

 ( 191,047,953
)

 ( 146,389,367
)

 Noncontrolling interest

 19,891,093

 -

 Total Equity (Deficit)

 49,768,841

 ( 151,249,300
)

 Total Liabilities and Equity

 $
 83,086,591

 $
 33,692,933

 The accompanying notes are an integral part
of these financial statements.

 F- 3

 CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS

 FOR THE YEARS ENDED DECMBER 31, 2024 AND 2023

 For the Year Ended

 2024

 2023

 Revenues

 $
 1,420,030

 $
 —

 Operating expenses:

 Cost of revenues

 $
 1,043,174

 $
 —

 General and administrative

 6,264,087

 5,634,150

 Depreciation

 133,516

 —

 Accretion of asset retirement obligation

 8,398,653

 —

 Total operating expenses

 15,972,669

 5,767,389

 Operating loss

 ( 14,552,639
)

 ( 5,767,389
)

 Other income (expense):

 Interest and other income (expense)

 1,948,281

 ( 102,041
)

 Change in fair value of derivative liability

 173,177

 708,869

 Total other income (expense)

 2,121,458

 606,828

 $
 ( 12,431,181
)

 $
)

 Deemed dividend to Class 1 Preferred Units redemption value

)

 ( 53,219,200
)

 Net loss attributable to noncontrolling interests

 —

 Net loss attributable to Class A Common stockholders or holders of Common Member Units

 $
 ( 167,766,847
)

 $
 ( 58,379,761
)

 Other comprehensive income (loss)

 Currency translation adjustment

 ( 1,548,154
)

 Comprehensive loss

 ( 13,979,335
)

 ( 4,941,653
)

 Comprehensive loss attributable to noncontrolling interests

 —

 Total comprehensive loss attributable to Class A Common stockholders

 $
 ( 13,891,824
)

 $
 ( 4,941,653
)

 Weighted average shares of Class A Common Stock outstanding, basic and diluted

 38,286,170

 31,643,646

 Net loss per share of Class A Common Stock, basic and diluted

 $
 ( 4.38
)

 $
 ( 1.84
)

 The accompanying notes are
an integral part of these financial statements.

 F- 4

 CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' AND MEMBERS' EQUITY

 FOR THE YEARS ENDED DECEMBER 31, 2024 and 2023

 Temporary

 Members'

 Class 1

 Common

 Additional

 Accumulated

 Accumulated other

 Total Members'

 Preferred Units

 Member Units

 paid-in capital

 deficit

 comprehensive loss

 Balance, December
 31, 2022

 22,606

 78,241,267

 266,503

 -

 13,173,784

 ( 101,183,390
)

 ( 5,078,841
)

 ( 93,088,447
)

 Shares issued

 21,004

 21,004,132

 -

 -

 -

 -

 -

 -

 Deemed dividend to redemption
 value

 -

 53,219,200

 -

 -

 ( 13,173,784
)

 ( 40,045,416
)

 -

 ( 53,219,200
)

 Foreign currency translation

 -

 -

 -

 -

 -

 -

 -

 -

 -

 -

 -

)

 -

)

 Balance, December 31, 2023

 43,610

 152,464,599

 266,503

 -

 -

 ( 146,389,367
)

 ( 4,859,933
)

 ( 151,249,300
)

 Temporary

 Members'

 Stockholders'

 Class

 Common

 Class
 A

 Class
 C

 Additional

 Accumulated
 other

 Total

 Preferred
 Units

 Member
 Units

 Common
 Stock

 Common
 Stock

 paid-in
 capital

 Accumulated

 deficit

 comprehensive
 loss

 Noncontrolling

interest

 Stockholders'

 Balance,

 43,610

 152,464,599

 266,503

 -

 -

 -

 -

 -

 -

 ( 146,389,367
)

 ( 4,859,933
)

 -

 ( 151,249,300
)

 Shares
 issued

 62,100

 62,100,000

 -

 -

 -

 -

 -

 -

 -

 -

 -

 -

 -

 Deemed
 dividend to redemption value

 -

 155,423,177

 -

 -

 -

 -

 -

 -

 -

)

 -

 -

)

 Recapitalization
 transaction

 ( 105,710
)

 ( 369,987,776
)

 ( 266,503
)

 -

 40,560,433

 4,056

 25,994,400

 2,599

 226,722,424

 123,108,261

 -

 20,156,904

 369,994,244

 Foreign
 currency translation

 -

 -

 -

 -

 -

 -

 -

 -

 -

 -

 ( 943,445
)

 ( 604,709
)

 ( 1,548,154
)

 Net
 loss

 -

 -

 -

 -

 -

 -

 -

 -

 -

 ( 12,343,670
)

 -

 ( 87,511
)

 (12, 431,181
)

 Noncontrolling
 interest acquired

 -

 -

 -

 -

 -

 -

 -

 -

 -

 -

 -

 426,409

 426,409

 Balance,
 December 31, 2024

 -

 -

 -

 -

 40,560,433

 4,056

 25,994,400

 2,599

 226,722,424

 ( 191,047,953
)

 ( 5,803,378
)

 19,891,093

 49,768,841

 The accompanying notes are an integral part
of these financial statements.

 F- 5

 CONSOLIDATED STATEMENTS OF CASH FLOWS

 FOR THE YEARS ENDED DECMBER 31, 2024 AND 2023

 For the Year Ended December 31,

 2024

 2023

 Cash flows from operating activities:

 $
 ( 12,431,181
)

 $
)

 Adjustments to reconcile net loss to net cash used in operating activities:

 Depreciation and amortization

 213,514

 —

 Impairment of assets

 —

 30,786

 Accretion of asset retirement obligation

 Change in fair value of derivative liability

 ( 173,177
)

 ( 708,869
)

 Changes in working capital items:

 Accounts receivable

 ( 1,275,246
)

 —

 Prepaid expenses and other assets

 ( 1,251,773
)

 ( 29,618
)

 Value-added tax refund receivable

 ( 2,789,575
)

 ( 1,418,231
)

 Accounts payable and accrued expenses

 1,281,916

 878,675

 Related party payables

 ( 525,276
)

 525,276

 Change in operating lease liability

 ( 79,998
)

 —

 Net cash used in operating activities

 ( 16,897,557
)

 ( 5,749,303
)

 Cash flows from investing activities

 Additions to renewable natural gas properties

 ( 9,721,376
)

 —

 Additions to conventional natural gas properties

 ( 13,344,911
)

 ( 8,924,941
)

 Net cash used in investing activities

 ( 23,066,287
)

 ( 8,924,941
)

 Cash flows from financing activities

 Proceeds from Business Combination

 648,122

 —

 Business Combination transaction expenses eligible for capitalization

 ( 641,654
)

 —

 AleAnna Energy Class 1 Preferred Units issued for cash

 62,100,000

 21,004,132

 Net cash provided by financing activities

 62,106,468

 21,004,132

 Effect of foreign currency translation on cash

 ( 571,729
)

 135,698

 Change in cash during the year

 21,570,894

 6,465,586

 Cash, beginning of year

 6,759,265

 293,679

 Cash, end of year

 $
 28,330,159

 $
 6,759,265

 Noncash investing and financing activities:

 Deemed dividend to Class 1 Preferred Units redemption value (see Note 10)

 $
)

 $
 ( 53,219,200
)

 Supplemental disclosures:

 Noncash recognition of new land lease (see Note 5)

 $
 1,882,275

 —

 The accompanying notes are an integral part
of these financial statements.

 F- 6

 NOTE 1 – NATURE OF OPERATIONS AND RECENT
EVENTS

 AleAnna, Inc. (together with
its subsidiaries, the "Company" or "AleAnna"), a Delaware corporation, was formed on December 13, 2024, in connection
with the Business Combination (defined below). AleAnna Energy, LLC ("AleAnna Energy"), a Delaware Limited Liability Company,
was formed on July 13, 2007. AleAnna Energy is comprised of wholly owned subsidiaries AleAnna Resources, LLC, AleAnna Italia S.p. A.
and AleAnna Renewable Energy S.r. L. ("AleAnna Renewable"). AleAnna Renewable is comprised of various subsidiaries that hold
its renewable natural gas assets (the "RNG Subsidiaries").

 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 renewable natural gas development in Italy. AleAnna has several conventional natural gas discoveries including the Longanesi
field, located in the Po Valley in Northern Italy, which is one of Italy's largest modern gas discoveries. AleAnna retains a 33.5 %
working interest in the Longanesi field with its working interest partner, and operator, Societa Padana Energia ("Padana").
AleAnna acquired its working interest in the Longanesi field through a 2016 transaction with Enel, accounted for as an asset acquisition.
AleAnna also retains 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. Planned principal operations have not yet commenced. As
of December 31, 2024, the Company had not derived revenue from its conventional natural gas activities. AleAnna's primary
activities currently involve the drilling, testing, and tie-in of three Longanesi development wells together with its working interest
partner, Padana. Tie-in of these wells and the installation of the temporary processing facility are complete. AleAnna 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 course of 2025 and early 2026 and commissioned in mid-2026.

 On October 29, 2024, the Company
entered into a gas sale agreement ("GSA") with Shell Energy Europe Limited ("SEEL"), whereby SEEL became the exclusive
buyer of AleAnna's share of the natural gas produced from the Longanesi field net of (i) any consumption and/or losses incurred
in the transport, treatment and compression of gas before delivery; (ii) any volume to be allocated for regulated royalties auctions,
if applicable; and (iii) any other volume contractually allocated to other parties before August 31, 2022. Future sales under the GSA
are contingent upon the commencement of gas production.

 Renewable Natural Gas ("RNG")

 In 2021, AleAnna launched a
renewable natural gas ("RNG") development business focused on bringing to market carbon negative renewable natural gas derived
from animal and agricultural waste.

 Between March 2024 and
July 2024, the Company successfully completed three separate strategic acquisitions of renewable natural gas ("RNG")
assets in Italy for an aggregate of approximately $ 9.5 million. The plant assets are fully permitted and are in various stages of the
development lifecycle, with one greenfield plant asset that is a new development (Campagnatico) and two brownfield plant assets (Casalino
and Campopiano) that are currently operational. The Company plans to develop and upgrade these assets for RNG production in the future.

 Campagnatico Asset Acquisition

 On March 20, 2024, the
Company closed the acquisition of the Campagnatico Greenfield ("Campagnatico") natural gas asset in Tuscany, Italy for approximately
$ 2.1 million. The greenfield site is fully permitted for future construction of a RNG plant asset.

 Casalino and Campopiano Asset Acquisitions

 On July 8, 2024, the Company
closed the acquisition of the Societa Agricola Fattoria delle Jersey S.S. plant asset ("Casalino") for approximately $ 3.6
million. On July 29, 2024, the Company closed the acquisition of a 90 % interest in the Societ Agricola Campopiano Societ
in nome collettivo di Vasellini Amedeo ("Compapiano") plant asset for approximately $ 3.8 million. The plant assets are fully
permitted for production of electricity through conversion of crop and animal waste bio feedstocks. The plant assets currently convert
biomethane to electricity for sale. 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") responsible for the purchase and marketing of energy produced
by small-scale renewable energy assets. 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 a non-company specific predetermined price for small renewable
energy producers of 280 /MWh, established under Ministerial Decree (D.M.) 18 December 2008, which sets tariff rates for small renewable
energy producers in Italy.

 F- 7

 The Company has a 90 % direct
controlling interest in the Campopiano asset, while unaffiliated owners retain a 10 % economic interest in the asset. The unaffiliated
outside ownership in Campopiano is shown as noncontrolling interests ("NCI") in stockholders' equity in the Company's
consolidated financial statements.

 AleAnna Energy Member Contributions

 During 2024, AleAnna Energy
received $ 62.1 million in capital contributions from its members, resulting in the issuance of 62,100 Class 1 Preferred Units,
which have since been converted to Class A common stock and Class C common stock as a result of the Business Combination (see Note 2 below).
These funds have been and will continue to be used to fund the Longanesi tie-in and permanent gas plant construction obligations, to develop
and upgrade existing RNG assets, to acquire new RNG assets (at the discretion of management), as well as to fund general and administrative
expenses of AleAnna and its subsidiaries.

 NOTE 2 – REVERSE RECAPITALIZATION TRANSACTION

 On December 13, 2024
(the "Closing Date"), the previously announced business combination was consummated pursuant to that certain Agreement and
Plan of Merger (as amended by that certain First Amendment to the Merger Agreement, dated as of October 8, 2024, the "Merger Agreement"),
dated June 4, 2024, by and among Swiftmerge Acquisition Corp., a Cayman Islands exempted company ("Swiftmerge"), Swiftmerge
HoldCo LLC, a Delaware limited liability company and wholly-owned subsidiary of Swiftmerge ("HoldCo"), Swiftmerge Merger Sub
LLC, a Delaware limited liability company and wholly-owned subsidiary of HoldCo ("Merger Sub") and AleAnna Energy (the "Merger").
The transactions contemplated by the Merger Agreement are collectively referred to herein as the "Business Combination."

 The Business Combination included,
among other things:

 •
 (i) SPAC undergoing the Domestication and changing its name
to "AleAnna, Inc."; (ii) each Swiftmerge Class A Ordinary Share converting into one share of Class A Common
Stock; (iii) each Swiftmerge Class B Ordinary Share converting into one share of Class B Common Stock in the Domestication
and then each share of Class B Common Stock converting into one share of Class A Common Stock at the completion of the Business
Combination; (iv) each warrant to purchase Swiftmerge Class A Ordinary Shares becoming exercisable by its terms to purchase
an equal number of shares of Class A Common Stock; and (v) a series Class C Common Stock being authorized, each share
of which will have voting rights equal to a share of Class A Common Stock but which shall have no entitlement to earnings or distributions
of the Company;

 •
 following the Domestication but prior to the Merger, (i) the
Company contributed to HoldCo (a) all of its assets (excluding its interests in HoldCo), including, for the avoidance of doubt,
the Available Cash (as defined herein), and (b) a number of shares of Class C Common Stock equal to the number of Class C
HoldCo Units designated to be issued to the AleAnna Members, and (ii) HoldCo issued to the Company a number of Class A
HoldCo Units which equaled the number of shares of Class A Common Stock issued and outstanding immediately after the Closing;
and

 •
 following the Pre-Closing Contribution, Merger Sub merged
with and into AleAnna Energy, with AleAnna Energy being the surviving company and a wholly-owned subsidiary of HoldCo. Each AleAnna
Energy Member received its pro rata portion of 65,098,476 shares of (a) Class A Common Stock or (b) Class C
Common Stock (with one Class C HoldCo Unit to accompany each share of Class C Common Stock) in the Merger, as determined by
the AleAnna Energy Board. Nautilus, which owned approximately 97 % of AleAnna Energy prior to the transaction, received 25,994,400 shares
of Class C Common Stock and 25,994,400 Class C HoldCo Units in the Merger, as well as 37,134,194 shares of Class A
Common Stock. The other AleAnna Energy Member, Bonanza Resources (Texas) Inc. received 1,969,882 shares of Class A Common Stock.

The Business Combination was accounted for as a common control transaction with respect to AleAnna Energy, which is akin to a reverse
recapitalization. Nautilus Resources LLC ("Nautilus"), the majority owner of AleAnna Energy, had a controlling financial interest
in AleAnna Energy prior to the Business Combination and has a controlling financial interest in the Company, as AleAnna Energy is a subsidiary
of HoldCo, in which AleAnna, Inc. holds a majority economic interest. The net assets of Swiftmerge are stated at their historical carrying
amounts with no goodwill or intangible assets recognized in accordance with U.S. GAAP. The Business Combination with respect to AleAnna
Energy was not treated as a change in control primarily due to Nautilus receiving the controlling voting stake in the Company and the
ability of Nautilus to nominate the full board of directors and management of the Company.

 In accounting for the Business
Combination, Swiftmerge was treated as the "acquired" company for financial reporting purposes. Accordingly, for accounting
purposes, the Business Combination was treated as the equivalent of AleAnna Energy issuing stock for the net assets of Swiftmerge, accompanied
by a recapitalization.

 F- 8

The Class A common stock, par value $ 0.0001 per share, of AleAnna, Inc. (the "Class A Common Stock") and the 11,250,000 warrants
issued as part of units in the initial public offering of Swiftmerge (the "Public Warrants") commenced trading on Nasdaq under
the symbols "ANNA" and "ANNAW," respectively, on December 16, 2024. Each share of Class C Common Stock has voting
rights equal to a share of Class A Common Stock but have no entitlement to earnings or distributions of AleAnna. Each share of Class C
Common Stock is exchangeable, subject to certain conditions, for one share of Class A Common Stock. The exchange feature does not allow
for cash settlement. AleAnna is organized in an "Up-C" structure effective with the Business Combination, and the only direct
assets of AleAnna consist of equity interests in HoldCo, whose only direct assets consist of equity interests in AleAnna Energy. The Company's
business is conducted through AleAnna Energy and its subsidiaries.

 Total proceeds raised from
the Business Combination were $ 0.6 million, representing the proceeds from the Swiftmerge operating account after Swiftmerge public shareholder
redemptions. These proceeds were offset by $ 9.5 million of transaction costs. Approximately $ 0.6 million of the transaction expenses
were recorded as a reduction to additional paid-in capital (up to the amount of cash proceeds from the Business Combination). Approximately
$ 0.5 million represented prepaid directors and officers insurance premiums and were recorded to prepaid expenses and other assets. The
remaining $ 8.4 million of costs incurred were expensed and presented as Business Combination transaction expenses in the consolidated
statement of operations for the year ended December 31, 2024.

 As of December 31, 2024, no
shares of Class C Common Stock had been exchanged for shares of Class A Common Stock.

 NOTE 3 – SUMMARY OF SIGNIFICANT ACCOUNTING
POLICIES

 Basis of Presentation — The
Company's consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the
United States of America ("U.S. GAAP") as determined by the Financial Accounting Standards Board ("FASB")
Accounting Standards Codification ("ASC").

 These audited consolidated
financial statements, in the opinion of management, reflect all adjustments (all of which are considered of a normal recurring nature)
considered necessary to present fairly the Company's financial position, results of operations and cash flows for the periods and
dates presented.

 Immaterial Restatement
of Prior Period Financial Statements — In the fourth quarter of 2024, we identified an error in the classification
of the contingent consideration liability and an error in the computation of foreign currency translation adjustments as of and for the
year ended December 31, 2023. Refer to Note 16 for quantification of the prior period restatement impacts. Additionally, comparative
prior period amounts in the applicable notes to the consolidated financial statements have been restated.

 Principles of Consolidation — The
Company's policy is to consolidate all entities that the Company controls by ownership interest or other contractual rights giving
the Company control over the most significant activities of an investee. The consolidated financial statements include the accounts of
AleAnna and its wholly-owned subsidiaries HoldCo, AleAnna Energy, AleAnna Resources, LLC, AleAnna Italia S.p. A., AleAnna Renewable and
the RNG Subsidiaries. All intercompany balances and transactions have been eliminated in consolidation.

 Use of Estimates — The
preparation of consolidated financial statements in conformity with accounting principles U.S GAAP requires management to make estimates
and assumptions that affect the reported amounts of expenses, assets, and liabilities and disclosure of contingent assets and liabilities.
The Company regularly assesses these estimates; however, actual amounts could differ from those estimates. The most significant items
involving management's estimates include estimates of contingencies including contingent consideration and estimates of the timing
and amount of asset retirement obligations. The impact of changes in estimates is recorded in the period in which they become known.

 Emerging Growth Company — The
Company is an "emerging growth company," as defined in Section 2(a) of the Securities Act, as modified by the Jumpstart
Our Business Startups Act of 2012 (the "JOBS Act"), and it may take advantage of certain exemptions from various
reporting requirements that are applicable to other public companies that are not emerging growth companies including, but not limited
to, not being required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act of 2002,
reduced disclosure obligations regarding executive compensation in its periodic reports and proxy statements, and exemptions from the
requirements of holding a nonbinding advisory vote on executive compensation and stockholder approval of any golden parachute payments
not previously approved.

 F- 9

 Further, Section 102(b)(1) of
the JOBS Act exempts emerging growth companies from being required to comply with new or revised financial accounting standards until
private companies (that is, those that have not had a Securities Act registration statement declared effective or do not have a class
of securities registered under the Exchange Act) are required to comply with the new or revised financial accounting standards. The
JOBS Act provides that an emerging growth company can elect to opt out of the extended transition period and comply with the requirements
that apply to non-emerging growth companies but any such an election to opt out is irrevocable. The Company has elected not to opt out
of such extended transition period, which means that when a standard is issued or revised and it has different application dates for public
or private companies, the Company, as an emerging growth company, can adopt the new or revised standard at the time private companies
adopt the new or revised standard. This may make comparison of the Company's consolidated financial statements with another public
company that is neither an emerging growth company nor an emerging growth company that has opted out of using the extended transition
period difficult because of the potential differences in accounting standards used.

 Risks and Uncertainties — The
Company is currently in the development stage and has not yet commenced principal operations or generated revenue from its conventional
natural gas business. The development of the Company's projects is subject to a number of risks and uncertainties including, but
not limited to, the receipt of the necessary permits and regulatory approvals, commodity price risk impacting the decision to go forward
with the projects, and the availability and ability to obtain the necessary financing for the development of projects.

 The Company's ability
to develop and operate commercial production facilities, as well as expand production at future commercial production facilities, is subject
to many risks beyond its control, including regulatory developments, construction risks, and global and regional macroeconomic developments.

 Functional and Reporting
Currency — The functional currency of an entity is the currency of the primary economic environment in which the
entity operates. The functional currency of the Italian subsidiary is the Euro, and the Company is the United States Dollar ("USD"
or "U.S. Dollar"). The determination of functional currency was made in accordance with 830, Foreign Currency Matters.

 The Company's reporting
currency is the USD. For the purposes of presenting consolidated financial statements, the assets and liabilities of the Company's
Euro operations are translated to USD at the exchange rate at the end of each month prior to consolidation procedures. The income and
expenses are translated using average exchange rates for the applicable period. Foreign currency differences that arise on translation
for consolidated purposes are recognized in accumulated other comprehensive loss on the consolidated balance sheet and in other comprehensive
loss as a currency translation adjustment on the consolidated statements of operations and comprehensive loss.

 Concentration of Credit
Risk — Financial instruments that potentially subject the Company to concentrations of credit risk consist of
cash accounts in financial institution which, at times may exceed the Federal Depository Insurance Corporation coverage limit of $ 250,000
in the U.S. or the Interbank Deposit Protection Fund limit of 100.000 in Italy. However, the majority of the Company's cash and
cash equivalents are held with a U.S.-based global systemically important financial institution. The Company has not experienced losses
on these accounts, and management believes the Company is not exposed to significant credit risk on such balances.

 Business Combinations
and Asset Acquisitions — To evaluate whether an acquiree meets the definition of a business, the Company first applies a
screen test to determine if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable
asset or group of similar identifiable assets. If the screen test is met, the transaction is accounted for as an asset acquisition. If
the screen test is not met, the Company further considers whether the set of assets acquired have, at a minimum, inputs and processes
that have the ability to create outputs in the form of revenue. If the assets acquired meet this criteria, the transaction is accounted
for as a business combination.

 Acquisitions that qualify
as an asset acquisition are accounted for using a cost accumulation model where the purchase price of the acquisition is allocated to
the assets acquired on a relative fair value basis on the date of acquisition. The Company generally accounts for acquisitions of RNG
assets as asset acquisitions. Inputs used to determine such fair values are primarily based upon internally-developed estimates, estimates
developed by third-party valuation firms, and publicly-available data regarding RNG asset transactions consummated by other buyers and
sellers, as applicable. These fair values are considered Level 3 assets in the fair value hierarchy. Any associated acquisition costs
are generally capitalized.

 Acquisitions that qualify
as a business combination are accounted for using the acquisition method of accounting. The fair value of consideration transferred for
an acquisition is allocated to the assets acquired and liabilities assumed based on their fair value on a nonrecurring basis on the acquisition
date and are subject to fair value adjustments under certain circumstances. The excess of the consideration transferred over the fair
value of assets acquired and liabilities assumed is recorded as goodwill. Conversely, in the event the fair value of assets acquired and
liabilities assumed is greater than the consideration transferred, a bargain purchase gain is recognized.

 F- 10

 Determining the fair value
of assets acquired and liabilities assumed requires judgment and often involves the use of significant estimates and assumptions as fair
values are not always readily determinable. Different techniques may be used to determine fair values, including market prices (where
available), comparisons to transactions for similar assets and liabilities and the discounted net present value of estimated future cash
flows, among others. The Company engages third-party valuation firms when appropriate to assist in the fair value determination of assets
acquired and liabilities assumed. Acquisition-related expenses and transaction costs associated with business combinations are expensed
as incurred. The Company may adjust the amounts recognized in an acquisition during a measurement period not to exceed one year from the
date of acquisition, as a result of subsequently obtaining additional information that existed at the acquisition date.

 Where applicable, asset acquisitions
may be owned together with unaffiliated outside parties. In acquisitions where the Company has majority direct controlling interest, the
unaffiliated outside ownership is shown as noncontrolling interests ("NCI") in stockholders' equity in the Company's
consolidated financial statements.

 Cash and Cash Equivalents — Cash
and cash equivalents represent cash and short-term, highly liquid investments with maturities of three months or less at the time
of purchase. The Company had $ 28.3 million of cash equivalents as of December 31, 2024. The Company did not have any cash equivalents
as of December 31, 2023.

 Financial Instruments — The
carrying values of the Company's financial instruments, consisting of cash and cash equivalents and accounts payable, approximate
their fair value due to the short maturity of such instruments. Unless otherwise noted, it is management's opinion that the Company
is not exposed to significant interest or currency risks arising from these financial instruments.

 Fair Value Measurement — The
Company applies fair value accounting to all financial assets and liabilities measured on a recurring and nonrecurring basis. Fair value
is defined as an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly
transaction between market participants at the measurement date. As such, fair value is a market-based measurement that should be determined
based on assumptions that market participants would use in pricing an asset or a liability.

 The accounting guidance establishes
a fair value hierarchy based on three levels of inputs, of which the first two are considered observable and the last unobservable, used
to determine the fair value of its financial instruments. A financial instrument's level within the fair value hierarchy is based
on the lowest level of any input that is significant to the fair value measurement.

 Level 1

 Quoted prices in active markets for identical assets or liabilities that the entity has the ability to access.

 Level 2

 Inputs other than Level 1 that are observable, either directly or indirectly, such as quoted prices for similar assets or liabilities, quoted prices in markets that are not active, or other inputs that are observable or can be corroborated by observable market data for substantially the full term of the assets and liabilities.

 Level 3

 Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets and liabilities.

 In some circumstances, the
inputs used to measure fair value might be categorized within different levels of the fair value hierarchy. In those instances, the fair
value measurement is categorized in its entirety in the fair value hierarchy based on the lowest level input that is significant to the
fair value measurement.

 Conventional Natural
Gas Properties — The Company uses the successful efforts method of accounting for gas producing activities. Under
this method, the cost of productive wells and related equipment, development dry holes, and any permits related to productive acreage
are capitalized, and depleted using the unit-of-production method. These costs include other internal costs directly attributable to production
activities. AleAnna is not yet recognizing depletion as assets are not yet producing and therefore have not yet been placed in service.
Costs for exploratory dry holes, exploratory geological and geophysical activities, and delay rentals as well as other property carrying
costs are charged to exploration expense.

 There were no exploratory
wells drilled and there were no capitalized exploratory well costs incurred during the years ended December 31, 2024 and 2023.
All asset additions in 2024 and 2023 relate to the drilling and testing of three incremental Longanesi development wells. All five Longanesi
wells began production in March 2025.

 The estimates of proved natural
gas reserves ("SEC Case") utilized in the preparation of the Consolidated Financial Statements are estimated in accordance
with the rules established by the Securities and Exchange Commission ("the SEC") and the FASB. These rules require that
reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision
for price and cost escalations in future years except by contractual arrangements. The development of the Company's natural
gas reserve quantities requires management to make significant estimates and assumptions related to the intent and ability to complete
undeveloped proved reserves within a five-year development period, as prescribed by SEC guidelines. Management engaged DeGolyer and MacNaughton,
independent reserve engineers, to prepare reserves estimates for the Company's estimated proved reserves at December 31, 2024
and 2023. The technologies used in the estimation of the Company's net proved undeveloped reserves include, but are not limited
to, empirical evidence through drilling results and well performance, production data, decline curve analysis, well logs, geologic maps,
core data, seismic data, demonstrated relationship between geologic parameters and performance, and the implementation and application
of statistical analysis.

 F- 11

 Management has confirmed
that none of the Unitized Operating Agreements ("UOAs") nor the Proved Undeveloped Reserves ("PUDs") are scheduled
to be developed on a date more than five years from the date the reserves were initially recognized as PUDs as prescribed by the
SEC guidelines. PUDs are converted from undeveloped to developed as applicable wells begin production.

 Reserve estimates are inherently
imprecise. Accordingly, the estimates are expected to change as more current information becomes available. Such estimates are subject
to the uncertainties inherent in the application of judgmental factors in interpreting such information. It is possible that, because
of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues,
the amount of natural gas reserves, the remaining estimated lives of natural gas properties, or any combination of the above may be increased
or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates, while decreases in recoverable economic
volumes generally increase per unit depletion rates.

 Impairment of Natural
Gas Properties — The carrying values of the Company's natural gas properties are reviewed for impairment
when events or circumstances indicate that the remaining carrying value may not be recoverable. To determine whether impairment of the
Company's natural gas properties has occurred, the Company compares the estimated expected undiscounted future cash flows to the
carrying values of those properties. Estimated future cash flows are based on proved and, if determined reasonable by management, risk-adjusted
probable reserves and assumptions generally consistent with the assumptions used by the Company for internal planning and budgeting purposes,
including, among other things, the intended use of the asset, anticipated production from reserves, future market prices for natural gas
adjusted for basis differentials, future operating costs and inflation. Proved gas properties that have carrying amounts in excess of
estimated future undiscounted cash flows are written down to fair value, which is estimated by discounting the estimated future cash flows
using discount rates and other assumptions that marketplace participants would use in their fair value estimates. The company recorded
no impairment of natural gas properties during 2024 or 2023.

 Value-Added Tax Refund
Receivable — The Valued-Added Tax ("VAT") is a broadly-based consumption tax that is assessed to the
value that is added to goods and services. The VAT applies to nearly all goods and services that are bought and sold within the European
Union. Italian law allows for certain VAT payments to be recovered through ongoing applications for refunds. The Company has incurred
higher VAT input paid (i.e., VAT paid on purchases) than the VAT output collected (i.e., VAT collected on sales), resulting in a net VAT
refund receivable.

 Under Italian tax law, VAT
refunds receivable may be refunded in cash or applied against future taxes liabilities. Given the legal framework ensuring recoverability
of these amounts, management believes the risk of non-collection is minimal, and therefore no reserve for uncollectible amounts is applied
against the receivable.

 Leases — The
Company recognizes right-of-use assets and lease liabilities for leases with terms greater than 12 months. Leases are classified
as either finance or operating leases. This classification dictates whether lease expense is recognized based on an effective interest
method or on a straight-line basis over the term of the lease.

 Short-term leases (leases
with an initial term of 12 months or less or leases that are cancelable by the lessee and lessor without significant penalties) are
not capitalized but are expensed on a straight-line basis over the lease term.

 Credit Losses — The
Company uses a forward-looking expected credit loss model for in-scope financial assets. Provisions for credit losses that are estimated
through the Company's prescribed method of estimating losses are recorded against earnings through a corresponding entry to Allowance
for Credit Losses. Financial assets are presented net of the Allowance for Credit Losses. Any recoveries of amounts previously estimated
as a credit loss are recorded against Allowance for Credit Losses.

 In accordance with ASC 326,
 Financial Instruments — Credit Losses, the Company estimates the allowance for credit losses using relevant available
information about expected credit losses. Inputs to the model include benchmarking against other companies, customer attributes, past
events, current conditions, and reasonable and supportable forecasts. Adjustments to historical loss information are made for differences
in current receivable-specific risk characteristics such as changes in the economy and demand trends, or other relevant factors. The Company's
financial assets measured at amortized cost primarily consist of trade receivables.

 The assessment of the correlation
between historical losses, current conditions, and forecasted economic conditions requires judgment. Alternative interpretations of these
factors could have resulted in different conclusions regarding the allowance for credit losses. The amount of credit loss is sensitive
to changes in circumstances and forecasted economic conditions. The Company's experience, current conditions, and forecast of economic
conditions may also not be representative of the customers' actual default experience in the future.

 F- 12

 Income Taxes — The
Company follows the asset and liability method of accounting for income taxes under ASC 740, "Income Taxes." Deferred tax
assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the consolidated financial
statements carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are
measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to
be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period
that included the enactment date. Valuation allowances are established, when necessary, to reduce deferred tax assets to the amount expected
to be realized.

 ASC
740 prescribes a recognition threshold and a measurement attribute for the financial statement recognition and measurement of tax positions
taken or expected to be taken in a tax return. For those benefits to be recognized, a tax position must be more likely than not to be
sustained upon examination by taxing authorities. The Company recognizes accrued interest and penalties related to unrecognized tax benefits
as income tax expense. There were no unrecognized tax benefits and no amounts accrued for interest and penalties as of December 31, 2024
or 2023. The Company is currently not aware of any issues under review that could result in significant payments, accruals or material
deviation from its position. The Company is subject to income tax examinations by major U.S. and Italian taxing authorities since inception.

 Warrants and Derivative
Liability — The Company accounts for the Public Warrants in accordance with the guidance contained in Accounting
Standards Codification ("ASC") 815, Derivatives and Hedging ("ASC 815") under which the warrants meet the
criteria for equity treatment and are recorded as equity. Such guidance provides that the Public Warrants are not precluded from equity
classification because they are indexed to the Company's own stock and do not require cash settlement. Additionally, the warrants
meet the criteria for equity classification as they (i) do not provide the holder with rights that are contingently redeemable, (ii) are
not considered to be freestanding derivatives requiring liability classification under ASC 480, and (iii) do not have terms that would
require the Company to net cash settle the warrants. Equity-classified contracts are initially measured at fair value (or allocated value).
Subsequent changes in fair value are not recognized as long as the contracts continue to be classified in equity. No Public Warrants had
been exercised as of December 31, 2024.

 The Company evaluates the
existence of separable embedded features within applicable debt or equity instruments pursuant to ASC 815. Professional standards
generally provide three criteria that, if met, require companies to bifurcate embedded features from their host instruments and separately
account for them as derivative. These three criteria include circumstances in which (a) the economic characteristics and risks of
the embedded derivative instrument are not clearly and closely related to the economic characteristics and risks of the host contract,
(b) the hybrid instrument that embodies both the embedded derivative instrument and the host contract is not re-measured at fair
value under otherwise applicable generally accepted accounting principles with changes in fair value reported in earnings as they occur
and (c) a separate instrument with the same terms as the embedded derivative instrument would be considered a derivative instrument.
See Note 7 for a discussion of the Company's derivative liability that existed as of December 31, 2023, but was derecognized
in conjunction with the Business Combination.

 Asset Retirement Obligations — The
Company recognizes a liability for asset retirement obligations ("AROs") based on an estimate of the amount and timing of
settlement at the time a legal obligation is incurred. Upon initial recognition of an ARO, the Company increases the carrying amount of
the long-lived asset by the same amount as the liability.

 The initial capitalized costs
will be depleted over the useful (productive) lives of the related assets.

 The Company's asset
retirement obligations relate to the abandonment of gas production facilities including reclaiming well pads, reclaiming water impoundments,
plugging wells and dismantling related structures. Estimates are based on historical experience of plugging and abandoning wells and reclaiming
or disposing other assets and estimated remaining (productive) lives of the wells and assets.

 The following table presents
a reconciliation of the beginning and ending carrying amounts of the Company's asset retirement obligations included in non-current
liabilities in the Consolidated Balance Sheets.

 2024

 2023

 Balance January 1

 $
 4,242,680

 $
 3,847,784

 Liabilities incurred

 -

 261,657

 Accretion

 Ending balance

 $
 4,375,919

 $
 4,242,680

 No incremental ARO liabilities
were incurred during the year ended December 31, 2024. For year ended December 31, 2023, the Company incurred incremental ARO liabilities,
for one new development area associated with Longanesi (Casale Cocchi 1). Changes in ARO in 2024 only relate to the accretion of the existing
liability. The Company does not have any assets that are legally restricted for purposes of settling these obligations. The incremental
ARO liability incurred in 2023 was discounted to present value at a rate of 4.22 %.

 F- 13

 Contingent Consideration
liability — The Company recognized a liability for the contingent consideration in accounting for the asset acquisition
in accordance with ASC 450, Contingencies ("contingent consideration liability") based on the Company's assessment
of probability of the occurrence of payment and deemed the liability estimable based on the formulaic nature. See Note 6 for more
information.

 Revenue Recognition —
 The Company follows the guidance of the ASC 606, Revenue from Contracts with Customers ("ASC 606"). The core
principle underlying revenue recognition under ASC 606 is that revenue should be recognized as goods or services are transferred to customers
in an amount that reflects the consideration to which the Company expects to be entitled. ASC 606 defines a five-step process to achieve
recognition and mandates additional disclosure about the nature, amount, timing and uncertainty of revenues and cash flows arising from
customer contracts, including significant judgments, and changes in judgments and assets recognized from costs incurred to obtain or fulfill
a contract.

 Renewable Natural Gas ("RNG")
 — As of December 31, 2024, the Company primarily earns revenue through electricity generation revenue from the conversion
of bio feedstocks to biomethane which is then converted to electricity through reciprocating generators. Such electricity is then delivered
onto the grid through a metered interconnection and sold to the local state-owned electrical utility responsible for the purchase and
marketing of energy produced by small-scale renewable energy assets. Upon delivery of the electricity to the grid, all performance obligations
have been satisfied and energy generation revenue is recognized based on actual output and non-company specific predetermined prices for
small renewable energy producers of 280 /MWh (D.M. 18/12/2008).

 Revenue is recognized over
time as the Company transfers the electricity to the grid at a metered interconnection. The customer obtains control of the product upon
delivery onto the electrical grid. The Company generally has a single performance obligation in its arrangements with its customers. The
Company has no long-term contracts containing quantity or electricity volume production requirements and there is no variable consideration
present in the Company's performance obligations. Per ASC 606-10-25-27(a), delivery of units of power that are simultaneously
received and consumed by the customer would satisfy the criteria in to be accounted for as a performance obligation satisfied over time
and the same method would be used to measure the entity's progress towards complete satisfaction of the performance obligation to
transfer each distinct unit of power in the series to the customer. The Company's performance obligation related to the sales of
electricity are satisfied over time upon delivery to the customer. Revenue is measured as the amount of consideration the Company expects
to receive in exchange for transferring its products. The Company applies a practical expedient in FASB ASC 606-10-55-18 applicable
to its sales by assessing whether the Company's right to consideration corresponds directly with the value to the Company's
customer (the "invoice practical expedient"). The Company concluded that pricing that corresponds to the value provided to
the customer. Consideration for each transaction is based upon non-company specific predetermined prices for small renewable energy
producers of 280 /MWh, established under Ministerial Decree (D.M.) 18 December 2008, which sets tariff rates for small renewable
energy producers in Italy. Payment terms are typically two months after the invoice date and there are no return or refund rights.

 During the year ended December
31, 2024, all revenue was derived from a single source (sales of electricity) and a single customer (the local state-owned electrical
utility). As of December 31, 2024, the Company had $ 1.2 million of revenue receivable related to electricity sales.

 NOTE 4 – RECENTLY ISSUED ACCOUNTING PRONOUNCEMENTS

 In November 2024, the FASB
issued ASU 2024-03 to improve the disclosures about a public business entity's expenses. The update requires more detailed information
on expense components, such as inventory purchases, employee compensation, depreciation, amortization, and depletion, within commonly
reporting categories like cost of sales, SG&A, and research and development. These amendments are effective for annual reporting periods
beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. The Company is currently evaluating
the provisions of the amendments and the impact on its future consolidated statements and disclosures.

 In November 2023, the
FASB issued ASU 2023-07 to enhance disclosures of significant expense and segment profitability categories and amounts for each of
the Company's reportable business segments. These enhanced disclosures apply to entities that have a single reportable segment.
The Company adopted ASU 2023-07 as of December 31, 2024. As a result, although the Company only has a single reportable segment, it has
included all disclosures required by the amendments in ASU 2023-07 as well as all existing segment disclosures in Topic 280. See Note
15 for more information.

 In December 2023, the
FASB issued ASU 2023-09 to improve disclosures and presentation requirements to the transparency of the income tax disclosures by
requiring consistent categories and greater disaggregation of information in the rate reconciliation and income taxes paid disaggregated
by jurisdiction. The amendments are effective in annual periods beginning after December 15, 2024, with early adoption permitted.
The Company is currently evaluating the provisions of the amendments and the impact on its future consolidated financial statements and
disclosures.

 F- 14

 Other recent accounting pronouncements
issued by the FASB, including its Emerging Issues Task Force, the American Institute of Certified Public Accountants, and the SEC did
not or in management's opinion will not have a material impact on the Company's present or future consolidated financial statements.

 NOTE 5 – LEASES, RIGHT-OF-USE
ASSETS AND RELATED LIABILITIES

 Leases to explore for or use
minerals, oil, natural gas, and similar nonregenerative resources (see ASC 930, Extractive Activities — Mining,
and ASC 932, Extractive Activities — Oil and Gas) are excluded from the scope of ASC 842, Leases.
The Company has surface and use agreements for Longanesi, Gradizza, Trava, and Armonia in Italy. These agreements are directly related
to accessing the subsurface minerals and are assessed as part of the oil and gas properties. As of December 31, 2023, all leases
in AleAnna's portfolio, in addition to its lease of office space, are short-term leases ( 12 months or less) and did not require
recognition on the balance sheet.

 In July 2024, in conjunction
with the Casalino acquisition, AleAnna entered into a lease of the land that holds the biomethane processing and conversion asset utilized
to produce electricity. The lease term is from July 1, 2024 through December 31, 2032, with an option to extend the lease until
December 31, 2041. The annual rent is 278,200 and must be paid in advance in four installments by the end of each calendar
quarter. The total rent for the lease term until December 31, 2032 is 2,364,700. As of December 31, 2024, the Company's
operating lease right of use assets totaled $ 1.8 million, short term lease liabilities totaled $ 0.2 million, and long-term lease liabilities
totaled $ 1.7 million. The Company recognized $ 0.1 million of operating lease expense during the year ended December 31, 2024 which
was included in cost of revenues as the land being leased is directly related to the production and sale of electricity at Casalino.

 The Company does not have any
borrowings; therefore, it does not have an incremental borrowing rate readily determinable, and there was no incremental borrowing rate
implicit in the Casalino land lease. As such, the company utilized a discount rate of 7.709 % to measure its lease liability. This represents
the Company's estimated incremental borrowing rate, determined using the 3-month EURIBOR rate of 3.709 % as of July 2024, plus
an estimated spread of 400 basis points ( 4.000 %), to reflect the Company's credit risk profile. This reflects best estimate of the
rate of interest that the Company would have to pay to borrow an amount equal to the lease payments on a collateralized basis over a similar
term.

 NOTE 6 – CONTINGENT CONSIDERATION
LIABILITY

 On July 13, 2016, AleAnna
Europa S.r. L., a former subsidiary of AleAnna Resources LLC (which was subsequently merged into AleAnna Italia S.p. A. in December 2022),
purchased a 33.5 % working interest in the Longanesi field, which was accounted for as an asset acquisition. Consideration paid included
 7 million cash and up to 24 million of deferred consideration payable upon production of the Longanesi field. The
deferred consideration is payable based on a formulaic calculation which is predominantly dependent on sales volumes and spot natural
gas prices during the first 12 years of production (the "Earn-Out Period"). There will be no deferred consideration due
if Longanesi is not developed and no deferred consideration due if average annual gas prices are less than 3.65 /Mcf over the Earn-Out
Period.

 In connection with the achievement
of first production and related revenue generation at Longanesi, AleAnna will be required to reserve $ 3.1 million related to the contingent
consideration liability due to Enel (see Note 17). 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. Payments become due 14 months after the first day of
the month following the date of first production.

 The Company recognized a liability
for the contingent consideration in accounting for the asset acquisition in accordance with ASC 450, Contingencies (the "contingent
consideration liability").

 As of December 31, 2024 and
2023, the contingent consideration liability was recorded at $ 25.0 million and $ 26.5 million, respectively, with the entire balance classified
as long-term since all payments are due more than one year after the respective balance sheet dates. The estimate of the contingent consideration
liability was determined based on inputs including the following as of December 31, 2024, and 2023: futures prices for European natural
gas, Euro to USD exchange rates of 1.04 and 1.12, respectively, and management's future expected annual Longanesi production. AleAnna
is required to make formulaic deferred consideration payments effectively equating to 20 % to 50 % of revenue based on 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 and MacNaughton, as well as forward European natural gas prices.

 Changes in the contingent consideration
liability attributable to factors other than foreign currency exchange rates are recognized in the consolidated statement of operations.
Changes in the contingent consideration liability attributable to foreign currency translation, are recognized in other comprehensive
loss within the consolidated statement of operations and comprehensive loss. The change in the contingent consideration liability
for all periods presented is attributable to changes in foreign exchange rates.

 F- 15

 NOTE 7 – DERIVATIVE LIABILITY

 As of December 31, 2023,
the Company recorded a derivative liability associated with certain embedded features of the Company's Class 1 Preferred Units which
entitle holders to a payout of 3.5x times their investment in the event of a company sale transaction or redemption at the option of the
Company (the "3.5x Redemption Feature"). Since the potential payoff upon occurrence of company sale transaction and redemption
at the option of the Company are the same, the Company analyzed the features as a single embedded feature for bifurcation. Based on the
Company's analysis of the host contract pursuant to ASC 815 — Derivatives and Hedging, the Company has concluded
the Class 1 Preferred Units represent a debt host. The embedded 3.5x Redemption Feature involves a substantial premium and is
contingent upon occurrence of company sale transaction, thus is not clearly and closely related to the debt host contract.

 Further, the feature meets
the definition of a derivative and other criteria under ASC 815 and requires bifurcation and separate recognition from the host contract
as a derivative.

 Accordingly, the Company recorded
a derivative liability representing the estimated fair value of the 3.5x Redemption Feature. Fair value is determined using a discounted
cash flow model to isolate the excess fair value attributable to the 3.5x redemption above the 35 % rate of return stated in the Class 1
Preferred Unit agreement. Further, the Company developed probability-weighted redemption scenarios which could occur during the time period
in which a 3.5x payoff would be applicable, to determine the ultimate fair value. The derivative liability was adjusted to reflect fair
value using these Level 3 inputs at each period end (i.e., measured on a recurring basis) with changes in fair value recorded in the consolidated
statements of operations and comprehensive loss.

 The derivative liability was
$ 0.2 million as of December 31, 2023 but was derecognized in conjunction with the closing of the Business Combination as the related Class
1 Preferred Units were exchanged for AleAnna common stock.

 The following is a summary of the assumptions
used in calculating the estimated fair value of such derivative liability as of December 31, 2023:

 2023

 Range of assumed years of company sale transaction

 2024 to 2026

 Range of probability weights of a company sale transaction occurring in a given year

 15 % - 35 %

 Overall probability of company sale transaction occurring at any point in the future

 26 %

 Discount rate applied to company sale transaction scenarios

 35 %

 Discount rate for business valuation utilized in company sale transaction scenarios

 10 %

 NOTE 8 – NATURAL GAS PROPERTIES

 Conventional Natural Gas Properties

 A summary of conventional natural gas properties is as follows:

 2024

 2023

 Natural gas properties

 56,977,091

 45,478,907

 Less: Accumulated Impairment

 ( 22,998,077
)

 ( 22,998,077
)

 Natural gas and other properties, net

 $
 33,979,014

 $
 22,480,830

 The Company uses the successful
efforts method of accounting for conventional natural gas-producing activities. Under this method, the cost of productive wells and related
equipment, development dry holes, and any permits related to productive acreage are capitalized and depleted using the unit-of-production
method. No depletion was recorded in either period presented as the Company had not yet commenced production as of December 31, 2024.

 Renewable Natural Gas Properties

 As of December 31, 2024, renewable
natural gas properties included $ 9.4 million of land, improvements and other assets related to the purchase of three renewable natural
gas plant assets across Italy between March 2024 and July 2024. The estimated fair values of these assets at the date of acquisition
are considered Level 3 assets in the fair value hierarchy. The brownfield renewable natural gas plant assets (Casalino and Campopiano)
have average estimated useful lives of 20 years. All depreciation expense included in the Condensed Consolidated Statements of Operations
relate to the Company's renewable natural gas plant assets.

 F- 16

 NOTE 9 – COMMITMENTS AND CONTINGENCIES

 Participation Agreements

 On June 26, 2009, the
Company entered into a Participation Agreement with Societa Padana Energia ("Padana") for the drilling of the "Longanesi
1 exploration well", "San Potito concession" and "Abbadessee 1 exploration" collectively referred to as
the "Longanesi field".

 The Unified Operating Agreement
("UOA") was originally signed between ENI and Grove and dated September 26, 2009. However, Padana has succeeded ENI as
the operator, and AleAnna has succeeded Grove as the non-operator.

 Under the UOA, AleAnna and
Padana have agreed to develop the Longanesi field to optimize the economic value of the identified reserves. AleAnna and Padana entered
the UOA with initial participating shares in the Longanesi field equal to 33.5 % for AleAnna and 66.5 % for Padana, with Padana appointed
as the operator. Padana is obliged to maintain the accounting records concerning the operations under the UOA in compliance with the laws
and generally accepted accounting practices followed in the Italian oil and gas industry.

 AleAnna and Padana fund their
respective working interest shares of the capital required for Longanesi development and will receive their respective shares of the production
output from the unitized field. However, such working interest percentages may be subsequently amended as more certainty is obtained over
the Gas Originally in Place ("GOIP") through redetermination procedures prescribed by the UOA. The redetermination process
evaluates the results of the current development drilling program (well logs, production tests, etc.) and other new data that may be gathered
from time to time (such as 3D seismic imaging) to determine if changes in GOIP have changed the respective working interest percentages.
If a redetermination process suggests GOIP changes, but AleAnna and Padana do not agree on revised working interest percentages, an independent
third party will opine and set the revised working interest allocations. Adjustments to future production entitlements and capital contributions
may be made accordingly. Cash payments may be made between the participants where there is insufficient production to true up contributions
to date. If a true up of historical capital contributions is required as a result of redetermination, such capital true-up amounts will
include an interest charge based on the nine-month Euro interbank offered rate ("Euribor") and the date of the original capital
contribution.

 On October 26, 2023, Padana
formally called for the First Redetermination process, as defined in the UOA, to begin. However, the outcome of this or any future redetermination,
which may impact working interest percentages and require a capital contribution rebalancing, is highly uncertain and such amounts are
not estimable at this time. Accordingly, AleAnna has not recorded any receivable from or payable to Padana related to the redetermination
process.

 Contingencies and Legal Proceedings

 The Company is subject to loss
contingencies related to litigation, claims, investigations and legal and administrative cases and proceedings arising in the ordinary
course of business. The Company evaluates these contingencies on a regular basis and accrues a liability for such matters when the Company
believes that a loss is probable, and the amount of the loss can be reasonably estimated. Any such accruals are adjusted thereafter as
appropriate to reflect changed circumstances. In the event the Company determines that (i) a loss to the Company is probable, but
the amount of the loss cannot be reasonably estimated, or (ii) a loss to the Company is less likely than probable but is reasonably
possible, then the Company is required to disclose the matter herein, although the Company is not required to accrue such loss.

 When able, the Company determines
an estimate of reasonably possible losses or ranges of reasonably possible losses, whether in excess of any related accrued liability
or where there is no accrued liability, for legal proceedings.

 In instances where such estimates
can be made, any such estimates are based on the Company's analysis of currently available information and are subject to significant
judgment and a variety of assumptions and uncertainties and may change as new information is obtained.

 The ultimate outcome of the
matters described below, such as whether the likelihood of loss is remote, reasonably possible, or probable, or if and when the range
of loss is reasonably estimable, is inherently uncertain.

 Furthermore, due to the inherent
subjectivity of the assessments and unpredictability of outcomes of legal proceedings, any amounts accrued or estimated as possible losses
may not represent the ultimate loss to the Company from the legal proceedings in question and the Company's exposure and ultimate
losses may be higher, and possibly significantly so, than the amounts accrued or estimated.

 As described in Note 1,
AleAnna acquired a 33.5 % working interest in the Longanesi field. As part of the purchase, a legacy owner, Blugas Infrastructure S.r. L.
("Blugas"), retained an interest akin to an overriding royalty interest ("ORRI"), whereby Blugas is entitled to
physical delivery of 20 % of the first 350 million standard cubic meters ("SCM") produced from the Longanesi field. In
accounting for the acquisition of the 33.5 % working interest, the Company did not recognize an asset or liability in the consolidated
financial statements related to the Blugas ORRI. Further, in December 31, 2023, the Company's SEC Case reserves estimates contemplated
the contractual arrangement and physical gas delivery to Blugas, such that the net cash flows related to the gas reserves attributable
to the Company's 33.5 % working interest were reduced.

 F- 17

 On
May 28, 2024, the Company reached a settlement agreement (the "Blugas Settlement Agreement") with Blugas regarding the
Blugas ORRI. Under the terms of the Blugas Settlement Agreement, the Company paid Blugas approximately 5 million, plus an additional
 1.1 million in applicable VAT, or approximately $ 6.6 million. In exchange, the Company was released from any future liability
related to the Blugas ORRI. As a result of the transactions contemplated by the Blugas Settlement Agreement, the Company's 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 estimated
future cash flows from our reserves. As such, the cost of the acquisition is included in natural gas and other properties, with the VAT
portion included in value-added tax refund receivable in the consolidated balance sheet as of December 31, 2024. The Company's year-end December 31,
2023 reserve quantities included the 20 % of 350 million standard cubic meters (approximately 2,472 10 6 ft 3)
allocable to the Blugas ORRI in the Company's proved gas reserves. However, the required payments to Blugas associated with the sale of
such quantities were reflected as cash outflows (costs) in the Company's year-end December 31, 2023 reserve report as if such amounts
were paid to Blugas. Following settlement, the Company's year-end December 31, 2024 reserve quantities continue to include the 20 % of
 350 million standard cubic meters (approximately 2,472 10 6 ft 3); however, the previously required payments to Blugas
associated with the sale of such quantities are no longer reflected as cash outflows (costs) given the acquisition of the Blugas ORRI.
As the cash outflows (costs) are no longer reflected as if paid to Blugas, such amounts are reflected in the Company's December 31, 2024
reserve report as allocable to the Company's unencumbered 33.5 % working interest.

 NOTE 10 – EQUITY

 AleAnna Common Stock
and Noncontrolling Interests – As of December 31, 2024, the Company had 40,560,433 shares of Class A Common Stock outstanding
and 25,994,400 shares of Class C Common Stock outstanding. See Note 2, Business Combination, for more details of the Company's
Class A Common Stock and Class C Common Stock as of December 31, 2024.

 Following the Business Combination,
holders of Class A Common Stock own a direct controlling economic interest in the results of the combined entity. Holders of Class C HoldCo
Units and Class C Common Stock own an economic interest in the Company, shown as noncontrolling interests ("NCI") in stockholders'
equity in the Company's consolidated financial statements. Holders of Class C Common Stock have voting rights equal to holders of
Class A Common Stock but no entitlement to earnings or distributions. The ownership interests of the Class A Common Stockholders and the
NCI were 60.94 % and 39.06 %, respectively. The NCI may decrease as holders of Class C HoldCo Units (which represent an economic interest
in HoldCo) and their corresponding shares of Class C Common Stock (which provide voting rights in AleAnna, Inc.) exchange both securities
together for shares of Class A Common Stock. Each share of Class C Common Stock must be surrendered along with a corresponding Class C
HoldCo Unit in order to receive one share of Class A Common Stock. As of December 31, 2024, no such exchanges had occurred.

 The financial statements also
reflect NCI related to the 10 % economic interest held in the Campopiano RNG asset by an unaffiliated third party, as discussed in Note
1.

 Warrants –
There were 11,250,000 Public Warrants outstanding as of December 31, 2024. Each warrant entitles the registered holder to purchase one share
of Class A common stock at a price of $ 11.50 per share, subject to adjustment as discussed below, at any time commencing 30 days
after the completion of our Business Combination.

 The Company may call the Public Warrants for redemption:

 in whole and not in part;

 at a price of $ 0.01 per Public Warrant;

 upon not less than 30 days' prior written notice of
redemption (the "30-day redemption period") to each Public Warrant holder;

 if, and only if, the reported last sale price of the Class A
Common Stock equals or exceeds $ 18.00 per share (as adjusted for share splits, share capitalizations, reorganizations, recapitalizations
and the like) on each of 20 trading days within a 30-trading day period ending on the third trading day before the Company
sends the notice of redemption to the Public Warrant holders; and

 if, and only if, there is a current registration statement in
effect with respect to the Class A Common Stock underlying such Public Warrants.

 F- 18

 In the event that the Company
elects to redeem all of the redeemable Public Warrants, its will fix a date for the redemption. Pursuant to the terms of the warrant agreement,
notice of redemption will be mailed by first class mail, postage prepaid, by not less than 30 days prior to the redemption date to
the registered holders of the redeemable Public Warrants to be redeemed at their last addresses as they appear on the registration books.
Any notice mailed in the manner provided in the warrant agreement will be conclusively presumed to have been duly given whether or not
the registered holder received such notice.

 The Company has established
the last of the redemption criterion discussed above to prevent a redemption call unless there is at the time of the call a significant
premium to the Public Warrant exercise price. If the foregoing conditions are satisfied and the Company issues a notice of redemption
of the Public Warrants, each Public Warrant holder will be entitled to exercise his, her or its Public Warrant prior to the scheduled
redemption date. However, the price of the Class A Common Stock may fall below the $ 18.00 redemption trigger price (as adjusted for
share splits, share capitalizations, reorganizations, recapitalizations and the like) as well as the $ 11.50 Public Warrant exercise price
after the redemption notice is issued.

 AleAnna Energy Equity
(pre-Business Combination) – As of both December 13, 2024, immediately prior to the Business Combination, and as of December 31,
2023, the Company had 266,503 Common Units authorized, issued, and outstanding. The Common Units had no par value.

 As of December 13, 2024, immediately
prior to the Business Combination, and as of December 31, 2023, the Company had 105,711 and 43,610 shares of Class 1 Preferred
Units authorized, issued, and outstanding, respectively. The Class 1 Preferred Units had no par value. The Class 1
Preferred Units were held by the majority equity owner, Nautilus.

 Due to the redemption features
of the Class 1 Preferred Units, they were recorded at redemption value and classified as temporary equity in the consolidated balance
sheets as of December 31, 2023. The difference between the book value of Class 1 Preferred Units issued and the redemption value,
less the amount attributable to the derivative liability discussed in Note 7, was recorded as a deemed dividend. AleAnna Energy's
Class 1 Preferred Units and Common Units were exchanged for AleAnna common stock in connection with the Business Combination (see Note
2).

 NOTE 11 – EXECUTIVE COMPENSATION

 On September 1, 2022,
the Company entered into an employment agreement with the CEO. Within this employment agreement, there is a Medium/Long Term Incentive
Plan ("M/LTIP" or the "Plan") outlined, which includes cash bonus amounts to be paid based on the completion of
certain milestones within the established thresholds. Such payments could result in total payments ranging from 375,000 to 1,125,000.
Threshold dates for such payments range from May 31, 2024, through December 31, 2026.

 The Company tracks each
of the milestones for the executive compensation package based on the current and future business plans. Based on the metrics and performance
indicators outlined in the executive compensation package, management has identified that the likelihood of achieving each of these metrics
is not probable based on the financial performance as of December 31, 2024.

 NOTE 12 – INCOME TAXES

 As of December 31, 2024, AleAnna,
Inc. held 60.94 % of the economic interest in HoldCo, which is treated as a partnership for U.S. federal income tax purposes. As a partnership,
HoldCo generally is not subject to U.S. federal income tax under current U.S. tax laws as its net taxable income (loss) and any related
tax credits are passed through to its members and included in their tax returns, even though such net taxable income (loss) or tax credits
may not have actually been distributed. AleAnna, Inc. is subject to U.S. federal income taxes, in addition to state and local income taxes,
with respect to its distributive share of the net taxable income (loss) and any related tax credits of HoldCo.

 AleAnna Energy was historically
and remains a disregarded subsidiary of a partnership for U.S. Federal income tax purposes with each partner being separately taxed on
its share of taxable income or loss. As a direct result of the Business Combination, HoldCo became the sole member of AleAnna Energy.
As such, HoldCo's distributive share of any net taxable income or loss and any related tax credits of AleAnna Energy are then distributed
to the Company.

 For the days and periods prior
to the closing of the Business Combination, AleAnna Energy was a disregarded subsidiary of an entity treated as a partnership. As such,
its net taxable loss and any related tax credits were allocated to its members. The period as of and for the year ended December 31, 2024
discussed below represents the period beginning January 1, 2024 and ending December 31, 2024.

 AleAnna's Italian subsidiary
(AleAnna Italia, S.p. A.) is a joint stock company or S.p. A and is considered a corporation under the Italian tax code. Therefore, the
statutorily determined cumulative taxable loss of AleAnna Italia was tax affected and recognized as a deferred tax asset as of December
31, 2024 and December 31, 2023. The Company has also recorded deferred tax assets for temporary differences between the book and
tax basis in the underlying assets and liabilities. Given AleAnna's history of losses, and because future production remained uncertain
as of December 31, 2024, a full valuation allowance was applied against the deferred tax assets. AleAnna Energy had no current or deferred
income tax expense for the year ended December 31, 2023 due to its disregarded entity status.

 F- 19

 The applicable U.S. and
Italian corporate tax rates were 21 % and 24 %, respectively, and the effective tax rates were 0 % during the years ended December 31,
2024 and 2023, given the losses incurred and the application of a full valuation allowance against deferred tax assets. Income
(loss) before provision for income taxes consisted of the following:

 Years Ended December 31,

 2024

 2023

 Domestic

 $
 ( 8,732,939
)

 $
 ( 742,017
)

 Foreign

 ( 3,698,242
)

 ( 4,418,544
)

 Total

 $
 ( 12,431,181
)

 $
)

 Deferred income taxes reflect
the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and
the amounts used for income tax purposes. The Company's deferred tax assets as of the balance sheet dates were as follows:

 2024

 2023

 Deferred tax assets:

 Net operating loss carryforwards

 $
 13,005,867

 $
 11,128,340

 Property and equipment

 17,955,431

 2,414,550

 Asset retirement obligation

 704,613

 664,855

 Contingent consideration

 5,980,895

 6,065,049

 1,753,919

 -

 Investment in partnership

 5,381,564

 -

 Total deferred tax assets

 $
 44,782,289

 $
 20,272,794

 Valuation allowance

 ( 44,489,087
)

 ( 20,272,794
)

 Net deferred tax asset

 $
 293,202

 $
 -

 Deferred tax liabilities:

 Accounts receivable

 $
 293,202

 $
 -

 Other

 -

 -

 Total deferred tax liabilities

 293,202

 -

 Net deferred tax assets (liabilities)

 $
 -

 $
 -

 The Company has assessed the
realizability of the net deferred tax assets, and in that analysis, has considered the relevant positive and negative evidence available
to determine whether it is more likely than not that some portion or all of the deferred tax assets will be realized. In making such a
determination, the Company considered all available positive and negative evidence, including future reversals of existing taxable temporary
differences, projected future taxable income, tax planning strategies, and recent results of operations. After consideration of all available
evidence, given AleAnna's history of losses, and because future production remained uncertain as of December 31, 2024 and 2023, the Company
recorded a full valuation allowance against its deferred tax assets as of December 31, 2024 and 2023. This valuation allowance will be
maintained until there is sufficient evidence to support the reversal of all or some portion of these allowances. As noted above, the
valuation allowances completely offset the deferred tax assets, which resulted in a net zero impact to the Company's consolidated
balance sheets as of December 31, 2024 and 2023.

 F- 20

 As of December 31, 2024,
the Company had a U.S. federal net operating loss ("NOL") carryforward totaling $ 54.2 million, which does not expire.

 The Company recognizes the
financial statement effects of uncertain income tax positions when it is more likely than not, based on the technical merits, that the
position will be sustained upon examination. To the extent the Company's assessment of such tax positions changes, the change in
estimate will be recorded in the period in which the determination is made. As of December 31, 2024 and 2023, the Company had not recorded
any uncertain tax positions or accrued interest and penalties on the consolidated balance sheets.

 The Company's income
tax filings will be subject to audit by various taxing jurisdictions. The Company will monitor the status of U.S. Federal, state and local
income tax returns and Italian tax returns that may be subject to audit in future periods. No U.S. Federal, state and local income tax
returns or Italian tax returns are currently under examination by the respective taxing authorities.

 NOTE 13 – RELATED PARTY TRANSACTIONS

 The Company follows FASB ASC
subtopic 850-10, Related Party Disclosures, for the identification of related parties and disclosure of related party transactions.

 As of December 31, 2023,
AleAnna Energy had outstanding payables of $ 525,276, to its parent company, Nautilus, primarily related to the payment of legal fees by
Nautilus on behalf of AleAnna. These intercompany payables are presented as related party payables on the accompanying condensed consolidated
balance sheets and were settled in the normal course of business. Except for capital contributions received from Nautilus during the year
ended December 31, 2024, and 2023, as presented in the consolidated statements of changes in shareholders' and members'
equity, or as otherwise disclosed, there were no other related party transactions entered into during the periods presented that required
recognition or disclosure.

 NOTE 14 – LOSS PER SHARE

 The Business Combination was
accounted for as a common control transaction with respect to AleAnna Energy which is akin to a reverse recapitalization. This conclusion
was based on Nautilus's controlling financial interest in AleAnna Energy prior to the Business Combination and its continued control over
the combined entit. Following the Business Combination, Nautilus holds Class A Common Stock, representing a direct controlling economic
interest, and Class C HoldCo Units and Class C Common Stock, representing a noncontrolling economic interest classified as NCI in stockholders'
equity in the Company's consolidated financial statements.

 Given this change in equity
structure and the requirements of ASC 260, Earnings per Share, the Company retrospectively adjusted its calculation of loss per share
for the prior-year period to reflect the impact of the new capital structure in accordance with applicable reverse recapitalization guidance.
As a result, the weighted average shares outstanding for the year ended December 31, 2023, were calculated by applying the implied conversion
ratio from the Business Combination to the pre-merger AleAnna Energy LLC units, ensuring comparability with the post-Business Combination
period.

 Basic net loss per share has
been computed by dividing net loss attributable to holders of Class A Common Stock by the weighted average number of shares of Class A
Common Stock outstanding during the respective periods. Diluted earnings per share of Class A Common Stock was computed by dividing net
loss attributable to holders of Class A Common Stock by the weighted-average number of shares of Class A Common Stock outstanding adjusted
to give effect to potentially dilutive securities.

 The Company's potentially
dilutive securities have been excluded from the computation of diluted net loss per share as the effect would be to reduce the net loss
per share. Therefore, the weighted average number of shares of Class A Common Stock outstanding used to calculate both basic and diluted
net loss per share is the same. The following table sets forth the computation of net loss used to compute basic net loss per share of
Class A Common Stock for the years ended December 31, 2024 and 2023.

 Year Ended December 31,

 2024

 2023

 Net loss attributable to Class A Common stockholders before deemed dividend

 $
 ( 12,343,670
)

 $
)

 Deemed dividend to AleAnna Energy Class 1 Preferred Units redemption value

)

 ( 53,219,200
)

 Income attributable to noncontrolling interests

 -

 Net Loss attributable to holders of Class A Common Stock

 ( 167,766,847
)

 ( 58,379,761
)

 Weighted average shares of Class A Common Stock outstanding, basic and diluted

 38,286,170

 31,643,646

 Net loss per share of Class A Common Stock, basic and diluted

 $
 ( 4.38
)

 $
 ( 1.84
)

 F- 21

 The AleAnna Energy Class 1
Preferred Units were not considered to be participating based on their contractual rights. However, due to the redemption features of
the Class 1 Preferred Units, they were recorded at redemption value and classified as temporary equity in the consolidated balance sheets
prior to the Business Combination. The difference between the book value of Class 1 Preferred Units issued and the redemption value, less
the amount attributable to the derivative liability discussed in note discussed in Note 7 prior to the Business Combination, was recorded
as a deemed dividend. The deemed dividend reduced the net loss attributable to holders of Common Member Units (and subsequently holders
of Class A Common Stock) in the calculation of the numerator above.

 The 25,994,400 shares of Class
C Common Stock and the 11,250,000 Public Warrants were not included in the calculation of diluted weighted average shares of Class A Common
Stock outstanding as their inclusion would have been anti-dilutive. Shares of Class C Common Stock are not participating securities; thus,
the application of the two-class method is not required.

 NOTE 15 – SEGMENT REPORTING

 The Company's operations
consist of one operating segment and reportable segment, reflecting the manner in which operations are managed and the criteria used by
the chief operating decision maker ("CODM"), the Company's Executive Chairman and Chief Executive Officer, collectively,
to evaluate performance, develop strategy, and allocate resources.

 AleAnna's principal products
include conventional natural gas produced from onshore exploration and development and RNG derived from animal and agricultural waste.
The Company has not yet generated revenue from its conventional natural gas activities and has only recently begun deriving revenue from
sales of electricity related to its RNG business.

 While the Company has recently
acquired three RNG assets, these assets are still in the early stages of development which may include expansion and installation of upgrading
units to refine biomethane into renewable natural gas (rather than conversion to electricity). These assets have not generated significant
revenues or incurred material expenses. As of, and for the period ending December 31, 2024, the Company's CODM was primarily focused
on capital investing decisions, strategy, and forward-looking investment economics. While the CODM monitors cash reserves and overall
enterprise liquidity, extensive review and analysis of the Company's performance and loss statements is not performed beyond review
of the consolidated financial statements. As such, the CODM continues to assess the financial performance of the Company as a single enterprise
on a consolidated basis, without distinguishing between conventional natural gas and RNG operations. Given the Company has not generated
significant revenue or profits and is focused on development activities, the CODM does not utilize a specific measure of profit or loss
to assess performance. The CODM does not monitor specific expense categories separately. The financial information reviewed by the CODM
is consistent with the audited consolidated balance sheets and statements of operations and cash flows included herein.

 All of the Company's
primary operating activities and assets remain located in Italy. The Company will continue to assess the need for including multiple reportable
segments as the business evolves.

 NOTE 16 – IMMATERIAL RESTATEMENT OF PRIOR PERIOD FINANCIAL
STATEMENTS

 Subsequent to the
issuance of the Company's consolidated financial statements as of and for the year ending December 31, 2023, errors were
identified related to the classification of the contingent consideration liability and in the computation of foreign currency
translation adjustments. As a result, the Company has restated the prior period financial statements and related
disclosures to correct the errors. Management evaluated the materiality of the errors and concluded that they were not material,
individually or in the aggregate, to the prior period financial statements. The Company will also correct previously reported
financial information for such immaterial errors in future filings, as applicable.

 The following tables reflect the effects of the
corrections on all affected line items of the Company's previously reported December 31, 2023 consolidated financial statements presented
in this Form 10-K:

 CONSOLIDATED STATEMENT OF OPERATIONS

 AND COMPREHENSIVE LOSS

 Previously Reported

 Correction

 As Corrected

 Operating expenses:

 Increase in contingent consideration liability

 $

 $
 ( 866,519
)

 $
 -

 Total operating expenses

 6,633,908

 ( 866,519
)

 5,767,389

 Operating loss

 ( 6,633,908
)

 ( 5,767,389
)

 ( 6,027,080
)

)

 Net loss attributable to Common Member Units

 ( 59,246,280
)

 ( 58,379,761
)

 Other comprehensive income (loss)

 Currency translation adjustment

 135,698

 83,210

 Comprehensive loss

 $
 ( 5,891,382
)

 $

 $
 ( 4,941,653
)

 F- 22

 CONSOLIDATED BALANCE SHEET

 Previously Reported

 Correction

 As Corrected

 ASSETS

 Natural gas and other properties, successful efforts method

 $
 21,531,101

 $

 $
 22,480,830

 Total Non-current assets

 25,956,454

 26,906,183

 Total Assets

 $
 32,743,204

 $

 $
 33,692,933

 LIABILITIES AND MEMBERS EQUITY

 Current Liabilities:

 Contingent consideration liability, short-term

 $
 14,888,021

 $
 ( 14,888,021
)

 -

 Total Current Liabilities

 16,640,293

 ( 14,888,021
)

 1,752,272

 Non-current Liabilities:

 Contingent consideration liability, long-term

 11,594,021

 14,888,021

 26,482,042

 Total Non-current Liabilities

 15,837,341

 14,888,021

 30,725,362

 Members' Equity:

 Accumulated other comprehensive loss

 ( 4,943,143
)

 83,210

 ( 4,859,933
)

 Accumulated deficit

 ( 147,255,886
)

 ( 146,389,367
)

 Members Equity (Deficit)

 ( 152,199,029
)

 ( 151,249,300
)

 Total Liabilities, Temporary Equity, and Members' Equity

 $
 32,743,204

 $

 $
 33,692,933

 CONSOLIDATED STATEMENT OF CASH FLOWS

 Previously Reported

 Correction

 As Corrected

 Cash flows from operating activities:

 $
 ( 6,027,080
)

 $

 $
)

 Adjustments to reconcile net loss to net cash used in operating activities:

 Change in fair value of contingent consideration

 $

 $
 ( 866,519
)

 $
 -

 Net cash used in operating activities

 $
 ( 5,749,303
)

 $
 -

 $
 ( 5,749,303
)

 NOTE 17 – SUBSEQUENT EVENTS

 The Company evaluated subsequent
events and transactions that occurred after the balance sheet date up to March 31, 2025, the date that the financial statements were issued.

 Warrant Exercises

 In January and February 2025,
holders exercised an aggregate 24,022 Public Warrants, resulting in the issuance 24,022 shares of Class A Common Stock at an exercise
price of $ 11.50 per share. These exercises generated approximately $ 0.3 million in cash proceeds.

 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.

 NOTE 18 – CONVENTIONAL NATURAL GAS PRODUCING
ACTIVITIES (UNAUDITED)

 The following supplemental
information presents the results of natural gas activities in accordance with the successful efforts method of accounting.

 F- 23

 The following table presents
capitalized costs related to the development of natural gas discoveries (primarily the Longanesi field). See Note 8 for aggregate
capitalized costs.

 For the Year Ended

 2024

 2023

 Capitalized costs

 Proved properties

 $
 11,498,184

 $
 9,091,621

 Less: Accumulated depreciation and depletion

 -

 -

 Net capitalized costs

 $
 11,498,184

 $
 9,091,621

 The following table presents
costs incurred for acquisition of properties, exploration costs and development costs. As the Company's primary activities in 2023
and 2024 involved the development of the Longanesi field, and there were no new acquisitions and minimal exploration activities, the primary
costs incurred during 2023 and 2024 were development costs.

 For the Year Ended

 2024

 2023

 Acquisition of properties

 $
 5,207,800

 $
 -

 Exploration costs

 -

 -

 Development costs

 6,290,384

 9,091,621

 The $ 5.2 million in acquisition of properties in
the table above is related to the Blugas Settlement Agreement discussed in further detail in Note 9.

 Reserve Information

 Proved developed reserves represent
only those reserves expected to be recovered from existing wells and support equipment. Proved undeveloped reserves represent proved reserves
expected to be recovered from new wells after substantial development costs are incurred.

 F- 24

 The net reserve information
disclosed herein encompasses only the Company's proved undeveloped Gradizza, Longanesi, and Trava discoveries. Other probable and
possible reserves related to Gradizza, Longanesi, and Trava have been excluded. Other prospective resources related to AleAnna's
additional exploration prospects beyond Gradizza, Longanesi, and Trava have also been excluded. The following table summarizes estimated
net natural gas reserves in millions of cubic feet.

 2024

 2023

 Natural gas

 (10 6 ft 3)

 Proved developed and undeveloped reserves:

 Balance at January 1

 13,778

 Revision of previous estimates

 -

 Due to extensions (1)

 -

 3,911

 Due to discoveries (1)

 -

 -

 Due to changes in sales prices (1)

 -

 -

 Due to other revisions (1)

 ( 68
)

 -

 Balance at December 31

 Proved developed reserves:

 Balance at January 1

 -

 -

 Balance at December 31

 -

 -

 Proved undeveloped reserves:

 Balance at January 1

 13,778

 Revision of previous estimates

 Due to extensions (1)

 -

 3,911

 Due to discoveries (1)

 -

 -

 Due to changes in sales prices (1)

 -

 -

 Due to other revisions (1)

 ( 68
)

 -

 Balance at December 31

 (1)
 The slight decrease during the year ended December 31, 2024 due to other revisions was primarily related to the expected timing of forecasted startup dates for Longanesi and Gradizza. Increases from extensions during the year ended December 31, 2023 were solely related to the Company's recent Longanesi development drilling. Recent drilling activity consisted of the drilling and completion of one gross Longanesi development well and workover and completion of one additional Longanesi development well (0.335 net to AleAnna's interest) during the year ended December 31, 2023. The 3,911 10 6 ft 3 of reserves added during the year ended December 31, 2023 relate to the drilling and completion of one gross Longanesi development well (0.335 net to AleAnna's interest) during the year ended December 31, 2023. There were no other positive or negative revisions to reserves in 2023 other than the reserves added as a result of drilling. We had no other exploratory or development drilling during the years ended December 31, 2024, or 2023. AleAnna's existing reserves were considered economic and were expected to be recovered at the volume-weighted average price attributable to the estimated proved reserves of $ 11.73 and $ 14.13 per thousand cubic feet of gas for the year ended December 31, 2024, and 2023. As a result, there were no revisions to volumes in either year as a result of changes in sales prices during the years ended December 31, 2024, and 2023. The Company also had no other additions during the years ended December 31, 2024, or 2023.

 F- 25

 Standard Measure of Discounted Future Cash Flow

 Future net cash flows represent
projected revenues from the sale of proved reserves, net of production and development costs (including transportation and gathering expenses,
operating expenses and production taxes). Revenues are based on a twelve-month unweighted average of the first-day-of-the-month pricing,
without escalation. Future cash flows are reduced by estimated production costs, administrative costs, costs to develop and produce the
proved reserves and abandonment costs, all based on current economic conditions at each year-end. There can be no assurance that the proved
reserves will be produced in the future or that prices, production or development costs will remain constant. There are numerous uncertainties
inherent in estimating reserves and related information.

 Management cautions that the
standard measure of discounted future cash flows should not be viewed as an indication of the fair market value of natural gas producing
properties, nor of the future cash flows expected to be generated. The information presented does not give recognition to future changes
in estimated reserves, selling prices or costs and has been discounted at a rate of 10 %. Further, the Company's December 31, 2023
SEC Case reserves estimates contemplated the contractual arrangement and physical gas delivery to Blugas, such that the net cash flows
attributable to the Company's 33.5 % working interest were reduced, as previously discussed in Note 9. Followin g
settlement, the Company's year-end December 31, 2024 reserve quantities continue to include the 20 % of 350 million standard cubic meters
(approximately 2,472 10 6 ft 3), 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 the Company's December 31, 2024 reserve report as allocable to the
Company's unencumbered 33.5 % working interest.

 The following table summarizes
the estimated future net cash flows from natural gas reserves (in thousands). All amounts noted relate to the Company's onshore
Italian gas assets. The Company has no other gas assets in other jurisdictions.

 2024

 2023

 Consolidated entities:

 Future cash inflows (1)

 206,696

 249,944

 Future production and development costs (1)

 ( 76,363
)

 ( 117,452
)

 Future income tax expenses (1)

 ( 22,793
)

 ( 41,888
)

 Future net cash flows

 107,540

 90,604

 10% annual discount for estimated timing of cash flows

 ( 18,507
)

 ( 20,680
)

 Standardized measure of discounted future net cash flows

 $
 89,033

 $

 Total consolidated interests in the standardized measure of discounted future cash flows

 $
 89,033

 $

 (1)
 Gas prices are based on a reference price. Gross gas price is
calculated as the unweighted arithmetic average of the first day-of-the-month price for each month within a 12-month period prior
to the end of the reporting period. The volume-weighted average price attributable to the estimated proved reserves was $ 11.73 and $ 14.13
per thousand cubic feet of gas for the year ended December 31, 2024, and 2023, respectively. Future net cash flows were computed
using the volume-weighted average price used in estimating AleAnna's proved gas reserves, year-end costs, and statutory tax rates
that relate to existing proved gas reserves.

 F- 26

 The
following table summarizes the aggregate change in the standardized measure of discounted future net cash flows for individually significant
sources of change (in thousands).

 2024

 2023

 Beginning standardized measure of discounted future net cash flows

 $

 $
 90,474

 Net change in sales prices related to future production (1)

 ( 54,042
)

 ( 96,635
)

 Net change due to extensions (2)

 -

 51,044

 Net change due to purchase of royalty interest (3)

 40,750

 -

 Previously estimated development costs incurred during the period

 7,015

 3,281

 Net change in income taxes

 19,095

 21,579

 Accretion of discount

 $
 6,291

 $

 Aggregate change in the standardized measure of discounted future net cash flows (3)

 19,109

 ( 20,550
)

 Ending standardized measure of discounted future net cash flows

 $
 89,033

 $

 (1)
 Gas prices are based on a reference price. Gross gas price is
calculated as the unweighted arithmetic average of the first day-of-the-month price for each month within a 12-month period prior to
the end of the reporting period. The volume-weighted average price attributable to the estimated proved reserves was $ 11.73 and $ 14.13
per thousand cubic feet of gas for the year ended December 31, 2024, and 2023, respectively.

 (2)
 Increases from extensions are solely related to the Company's recent Longanesi development drilling. Recent drilling activity consisted of the following: drilling and completion of one gross Longanesi development well and workover and completion of one additional Longanesi development well (0.335 net to AleAnna's interest) during the year ended December 31, 2023. The 3,911 10 6 ft 3 of reserves added during the year ended December 31, 2023 relate to the drilling and completion of one gross Longanesi development well (0.335 net to AleAnna's interest) during the year ended December 31, 2023. There were no other positive or negative revisions to reserves other than the reserves added as a result of drilling. The Company had no other exploratory or development drilling during the years ended December 31, 2024 or 2023. AleAnna's existing reserves were considered economic and were expected to be recovered at the volume-weighted average price attributable to the estimated proved reserves of $ 11.73 and $ 14.13 per thousand cubic feet of gas for the year ended December 31, 2024, and 2023. As a result, there were no revisions to volumes in either year as a result of changes in sales prices during the years ended December 31, 2024 and 2023. The Company also had no other additions during the years ended December 31, 2024 or 2023.

 (3)
 The Company's December 31, 2023 SEC Case reserves estimates contemplated the contractual arrangement and physical gas delivery to Blugas, such that the net cash flows attributable to the Company's 33.5 % working interest were reduced, as previously discussed in Note 9. Following the purchase of the Blugas ORRI as discussed in Note 9, the Company's year-end December 31, 2024 reserve quantities continue to include the 20 % of 350 million standard cubic meters (approximately 2,472 10 6 ft 3). 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 the Company's December 31, 2024 reserve report as allocable to the Company's unencumbered 33.5 % working interest.

 (4)
 From December 31, 2022 to December 31, 2023, the standardized
measure of discounted future net cash flows decreases as a result of lower prices as noted immediately above in footnote 1. The decrease
in price more than offset the increase in reserves from extensions during the year ended December 31, 2023, resulting in a net decrease
to the standardized measure of discounted future cash flows from December 31, 2022 to December 31, 2023. From December 31, 2023 to December
31, 2024, the standardized measure of discounted future net cash flows decreases as a result of lower prices as noted immediately above
in footnote 1. The decrease in price more than offset the increase in reserves from extensions during the year ended December 31, 2024,
resulting in a net decrease to the standardized measure of discounted future cash flows from December 31, 2023 to December 31, 2024.

 F- 27

 Item 9. Changes
in and Disagreements with Accountants on Accounting and Financial Disclosure

 On December 13, 2024 the
Audit Committee approved the dismissal of Marcum LLP ("Marcum") as our independent registered public accounting firm,
effective December 13, 2024 (the "Auditor Change Effective Date"). Marcum's report on Swiftmerge's financial statements
as of December 31, 2023 and as of December 31, 2022 and the related statements of operations, changes in stockholders' deficit and
cash flows for the years ended December 31, 2023 and 2022 did not contain any adverse opinion or disclaimer of opinion, nor were they
qualified or modified as to uncertainty, audit scope or accounting principles, other than included an explanatory paragraph as to Swiftmerge's
ability to continue as a going concern.

 During the years ended December
31, 2023 and 2022 and the subsequent period through December 13, 2024, there were no "disagreements" (as that term is described
in Item 304(a)(1)(iv) of Regulation S-K under the Exchange Act, and the related instructions to Item 304 of Regulation S-K under the Exchange
Act) with Marcum on any matter of accounting principles or practices, financial statement disclosures or audited scope or procedures,
which disagreements if not resolved to Marcum's satisfaction would have caused Marcum to make reference to the subject matter of
the disagreement in connection with its report. During the years ended December 31, 2023 and 2022 and the subsequent period through December
13, 2024, there have been no "reportable events" (as defined in Item 304(a)(1)(v) of Regulation S-K under the Exchange Act),
other than the material weakness in internal controls identified by management related to the lack of ability to account for complex financial
instruments. In addition, as part of such process, Swiftmerge identified a material weakness in internal control related to Swiftmerge's
review controls over the recording of an unbilled amount due to a third-party service provider and interest income, which affected the
year ended December 31, 2023.

 The Company has provided
Marcum with a copy of the foregoing disclosures and requested that Marcum furnish us with a letter addressed to the SEC stating whether
it agrees with the above statements and, if not, stating the respects in which it does not agree.

 On December 13, 2024, the
Board approved the engagement of Deloitte & Touche LLP ("Deloitte") as its independent registered public accounting firm,
effective upon the Auditor Change Effective Date. Deloitte previously served as the independent registered public accounting firm of AleAnna
Energy prior to the Business Combination. During the years ended December 31, 2023 and 2022 and the subsequent period through December
13, 2024, neither the Company, nor anyone on the Company's behalf consulted with Deloitte, on behalf of the Company, regarding the
application of accounting principles to a specified transaction (either completed or proposed), the type of audit opinion that might be
rendered on the Company's financial statements, or any matter that was either the subject of a "disagreement," as defined
in Item 304(a)(1)(iv) of Regulation S-K, or a "reportable event," as defined in Item 304(a)(1)(v) of Regulation S-K.

 Item 9A. Controls and
Procedures

 Evaluation of Disclosure Controls and Procedures

 Disclosure controls and procedures
are controls and other procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted
under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and
forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required
to be disclosed in Company reports filed or submitted under the Exchange Act is accumulated and communicated to management, including
our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosure.

 As required by Rules 13a-15
and 15d-15 under the Exchange Act, our Chief Executive Officer and Chief Financial Officer carried out an evaluation of the effectiveness
of the design and operation of our disclosure controls and procedures as of December 31, 2024. Based upon their evaluation, our Chief
Executive Officer and Chief Financial Officer identified material weaknesses in our disclosure controls and procedures (as defined in
Rules 13a-15(e) and 15d-15(e) under the Exchange Act).

 Effective internal controls
are necessary to provide reliable financial reports and prevent fraud. 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. 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. Specifically, the Company did not have adequately designed and documented controls over the preparation,
review, and approval of journal entries and account reconciliations and did not have adequate controls over the identification of significant
contract terms that may have accounting implications.

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

 Designing and implementing a risk assessment process supporting
the identification of risks facing AleAnna.

 Implementing controls to enhance our review of significant accounting
transactions and other new technical accounting and financial reporting issues and preparing and reviewing accounting memoranda addressing
these issues.

 Hiring additional experienced accounting, financial reporting
and internal control personnel and changing roles and responsibilities of our existing personnel.

 Implementing controls to enable an accurate and timely review
of accounting records that support our accounting processes and maintain documents for internal accounting reviews.

 The Company 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 our 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 does 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 our annual or interim financial statements that would not be prevented
or detected on a timely basis. This, in turn, could jeopardize our ability to comply with our reporting obligations, limit our ability
to access the capital markets and adversely impact our stock price.

 Limitations of the Effectiveness of Control

 A control system, no matter
how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met.
Because of the inherent limitations of any control system, no evaluation of controls can provide absolute assurance that all control issues,
if any, within a company have been detected.

 Management's Report on Internal Controls
Over Financial Reporting

 As required by SEC rules and
regulations implementing Section 404 of the Sarbanes-Oxley Act, our management is responsible for establishing and maintaining adequate
internal control over financial reporting. Our internal control over financial reporting is designed to provide reasonable assurance regarding
the reliability of financial reporting and the preparation of our consolidated financial statements for external reporting purposes in
accordance with GAAP. Our internal control over financial reporting includes those policies and procedures that:

 (1)
 pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of our Company,

 (2)
 provide reasonable assurance that transactions are recorded as
necessary to permit preparation of consolidated financial statements in accordance with GAAP, and that our receipts and expenditures
are being made only in accordance with authorizations of our management and directors, and

 (3)
 provide reasonable assurance regarding prevention or timely detection
of unauthorized acquisition, use or disposition of our assets that could have a material effect on the consolidated financial statements.

 Because of its inherent limitations,
internal control over financial reporting may not prevent or detect errors or misstatements in our financial statements. Also, projections
of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in
conditions, or that the degree or compliance with the policies or procedures may deteriorate. Management assessed the effectiveness of
our internal control over financial reporting at December 31, 2024. In making these assessments, management used the criteria set forth
by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework (2013).
Based on our assessments and those criteria, management identified a material weakness its internal controls over financial reporting
as of December 31, 2024, as described above.

 This Annual Report on Form
10-K does not include an attestation report of our independent registered public accounting firm due to our status as an emerging growth
company under the JOBS Act.

 Changes in Internal Control over Financial
Reporting

 Other than changes that are
being implemented as a result of the material weakness remediation activities noted above, there has been no change in our internal control
over financial reporting during the most recently completed fiscal quarter that has materially affected, or is reasonably likely to materially
affect, our internal control over financial reporting.

 Item 9B. Other information

 None.

 Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent
Inspections

 Not applicable.

 Item 10. Directors, Executive Officers
and Corporate Governance

 In accordance with General
Instruction G(3) to Form 10-K, the information called for by Item 9 will be set forth in AleAnna's definitive proxy statement relating
to the 2025 annual meeting of stockholders (the "2025 Proxy Statement"), the Company intends to file with the 2025 Proxy Statement
not later than 120 days after the end of the fiscal year covered by this Form 10-K.

 Item 11. Executive Compensation

 The information called for
by Item 13 will be set forth in the 2025 Proxy Statement and is incorporated herein by reference pursuant to Instruction G to Form 10-K.

 Item 12. Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters

 The information called for
by Item 13 will be set forth in the 2025 Proxy Statement and is incorporated herein by reference pursuant to Instruction G to Form 10-K.

 Item 13. Certain Relationships and Related Transactions, and Director
Independence

 The information called for
by Item 13 will be set forth in the 2025 Proxy Statement and is incorporated herein by reference pursuant to Instruction G to Form 10-K.

 Item 14. Principal Accountant Fees and Services

 The information called for
by Item 13 will be set forth in the 2025 Proxy Statement and is incorporated herein by reference pursuant to Instruction G to Form 10-K.

 Item 15. Exhibits and Financial Statement Schedules

 The following documents are filed as part of this Form 10-K:

 (1) Consolidated Financial Statements:

 See Item 8. Financial Statements and Supplementary
Data.

 (2) Consolidated Financial Statement Schedules:

 None.

 (3) Exhibits

 We hereby file as part of this
Report the exhibits listed in the attached Exhibit Index. Exhibits which are incorporated herein by reference can be inspected and copied
at the public reference facilities maintained by the SEC, 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Copies of such material
can also be obtained from the Public Reference Section of the SEC, 100 F Street, N.E., Washington, D.C. 20549, at prescribed rates or
on the SEC website at www.sec.gov.

 Exhibits

 Description

 2.1

 Agreement and Plan of Merger, dated as of June 4, 2024, by and among Swiftmerge, HoldCo, Merger Sub and AleAnna (incorporated by reference to Exhibit 2.1 to the Company's Registration Statement on Form S-4 (File No. 333-280699) filed with the Securities and Exchange Commission on July 5, 2024).

 2.2

 First Amendment to Agreement and Plan of Merger, dated as of October 8, 2024, by and among Swiftmerge, HoldCo, Merger Sub and the Company (incorporated by reference to Exhibit 2.2 to the Company's Registration Statement on Form S-4/A (File No. 333-280699) filed with the Securities and Exchange Commission on October 8, 2024).

 3.1

 Certificate of Incorporation of AleAnna, Inc. (incorporated by reference to Exhibit 3.1 of the Company's Current Report on Form 8-K (File No. 001-41164), filed with the Securities and Exchange Commission on December 19, 2024).

 3.2

 Bylaws of AleAnna, Inc. (incorporated by reference to Exhibit 3.2 of the Company's Current Report on Form 8-K (File No. 001-41164), filed with the Securities and Exchange Commission on December 19, 2024).

 4.1

 Specimen Warrant Certificate of Swiftmerge (incorporated by reference to Exhibit 4.3 of the Company's Registration Statement on Form S-1/A (File No. 333-254633), filed with the Securities and Exchange Commission on October 4, 2021).

 4.2

 Warrant Agreement, dated as of December 14, 2021, by and between Continental Stock Transfer & Trust Company and Swiftmerge (incorporated by reference to Exhibit 4.1 of the Company's Current Report on Form 8-K (File No. 001-41164), filed with the Securities and Exchange Commission on December 20, 2021).

 4.3*

 Description of Securities of AleAnna, Inc.

 10.1

 Amended and Restated Letter Agreement, dated June 4, 2024, by and between Swiftmerge Holdings, LP, Swiftmerge and the Company (incorporated by reference to Exhibit 10.1 of the Company's Current Report on Form 8-K (File No. 001-41164), filed with the Securities and Exchange Commission on December 19, 2024).

 10.2

 Investment Management Trust Agreement, dated as of December 17, 2021, by and between Swiftmerge and Continental Stock Transfer & Trust Company (incorporated by reference to Exhibit 10.3 of the Company's Current Report on Form 8-K (File No. 001-41164), filed with the Securities and Exchange Commission on December 20, 2021).

 10.3

 Amended and Restated Limited Liability Company Agreement of HoldCo (incorporated by reference to Exhibit 10.15 of the Company's Current Report on Form 8-K (File No. 001-41164), filed with the Securities and Exchange Commission on December 19, 2024).

 10.4

 Form of Investor Letter, dated June 4, 2024, by and between Swiftmerge, certain qualified institutional buyers or institutional accredited investors and certain unaffiliated third-party investors (incorporated by reference to Exhibit 10.16 of the Company's Current Report on Form 8-K (File No. 001-41164), filed with the Securities and Exchange Commission on December 19, 2024).

 10.5

 Amended and Restated Registration Rights Agreement, dated as of December 13, 2024, by and among the Company, Swiftmerge Holdings, LP, Nautilus Resources LLC, and certain other persons named therein (incorporated by reference to Exhibit 10.17 of the Company's Current Report on Form 8-K (File No. 001-41164), filed with the Securities and Exchange Commission on December 19, 2024).

 10.6+

 Form of Indemnification Agreement for directors and executive officers of AleAnna, Inc. (incorporated by reference to Exhibit 10.18 of the Company's Current Report on Form 8-K (File No. 001-41164), filed with the Securities and Exchange Commission on December 19, 2024).

 10.7+

 Employment Agreement, dated as of September 1, 2022, by and between Marco Brun and AleAnna (incorporated by reference to Exhibit 10.25 to the Company's Registration Statement on Form S-4/A (File No. 333-280699) filed with the Securities and Exchange Commission on November 5, 2024).

 21.1*

 Subsidiaries of the Company

 24.1*

 Power of Attorney (included in signature pages).

 31.1*

 Certification of Principal Executive Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 31.2*

 Certification of Principal Financial Officer Pursuant to Rules 13a-14(a) and 15d-14(a) under the Securities Exchange Act of 1934, as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 32.1*

 Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 32.2*

 Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 97.1*

 Clawback Policy of AleAnna, Inc.

 99.1*

 Report of DeGolyer and MacNaughton, Summary of Reserves at December 31, 2024.

 101.INS*

 101.SCH*

 101.CAL*

 101.DEF*

 101.LAB*

 101.PRE*

 104*

 Certain schedules or similar attachments to this exhibit have
been omitted pursuant to Item 601(a)(5) of Regulation S-K. The Company agrees to provide a copy of any omitted schedule
or similar attachment to the SEC upon request.

 +
 Indicates management contract or compensatory plan.

 *
 Filed herewith.

 Item 16. Form 10-K Summary

 None.

 SIGNATURES

 Pursuant to the requirements of Section 13 or 15(d) of the Securities
Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

 AleAnna, Inc.

 By:

 /s/ Tristan Yopp

 Name:

 Tristan Yopp

 Title:

 Chief Financial Officer

 POWER OF ATTORNEY

 Each person whose individual signature appears
below hereby authorizes and appoints Tristan Yopp as his or her true and lawful attorney-in-fact and agent to act in his or her name,
place and stead and to execute in the name and on behalf of each person, individually and in each capacity stated below, and to file any
and all amendments to this Annual Report on Form 10-K and to file the same, with all exhibits thereto, and other documents in connection
therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power
and authority to do and perform each and every act and thing, ratifying and confirming all that said attorneys-in-fact and agents or any
of them or their or his or her substitute or substitutes may lawfully do or cause to be done by virtue thereof.

 Pursuant to the requirements of the Securities
Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the registrant and in the capacities and
on the dates indicated.

 Signature

 Title

 Date

 /s/ Marco Brun

 Chief Executive Officer and Director

 Marco Brun

 (Principal Executive Officer)

 /s/ Tristan Yopp

 Chief Financial Officer

 Tristan Yopp

 (Principal Financial Officer)

 /s/ Charles Roscopf

 Chief Accounting Officer

 Charles Roscopf

 (Principal Accounting Officer)

 /s/ Graham van't Hoff

 Chairman of the Board

 Graham van't Hoff

 /s/ William K. Dirks

 Director

 William K. Dirks

 /s/ Duncan Palmer

 Director

 Duncan Palmer

 /s/ Curtis H bert, Jr.

 Director

 Curtis H bert, Jr.

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