UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
☒ ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR
THE FISCAL YEAR ENDED DECEMBER 31, 2024
or
☐ TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM ___________ TO __________
COMMISSION FILE NUMBER: 001-41164
AleAnna, Inc.
(Exact name of registrant as specified in its charter)
(469)398-2200
(Registrant’s telephone number, including area
code)
Securities registered pursuant to Section 12(b)
of the Act:
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
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.
Table of Contents
Glossary of Commonly Used Terms, Abbreviations and Measurements ii
Summary of Risk Factors v
Cautionary Statements viii
PART I 1
Item 1. Business 1
Item 1A. Risk Factors 23
Item 1B. Unresolved Staff Comments 53
Item 1C. Cybersecurity 53
Item 2. Properties 54
Item 3. Legal Proceedings 54
Item 4. Mine Safety Disclosures 54
Item 6: [Reserved] 55
Item 7A. Quantitative and Qualitative Disclosures About Market Risk 67
Item 8. Financial Statements and Supplementary Data F-1
Item 9A. Controls and Procedures 69
Item 9B. Other Information 70
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections 70
PART III 71
Item 10. Directors, Executive Officers and Corporate Governance 71
Item 11. Executive Compensation 71
Item 14. Principal Accountant Fees and Services 71
Item 15. Exhibits and Financial Statement Schedules 72
i
Glossary Of Selected Industry Terms
“AleAnna Energy” - AleAnna Energy,
LLC, a Delaware limited liability company.
“Bcf” - billion cubic feet.
“Bcfe” - billion cubic feet of natural
gas equivalents, with one barrel of NGLs and oil being equivalent to 6,000 cubic feet of natural gas.
“Blugas”
- Blugas Infrastructure S.r.l.
“Blugas
Settlement Agreement” - agreement with Blugas Infrastructure S.r.l. (“Blugas”) regarding the Blugas overriding royalty
interest (“ORRI”) whereby Blugas was entitled to physical delivery of 20% of the first 350 million standard cubic meters
(approximately 2,472 106ft3) produced from the Longanesi field.
“Carbon Negative Renewable Natural Gas”
- Renewable natural gas (RNG) is considered carbon negative if it captures more greenhouse gases than it emits. RNG produced from organic
waste that would otherwise decay and create methane emissions are considered carbon negative as the methane emissions from the decay is
captured and converted to a usable fuel source (RNG) which then displaces traditional fossil based natural gas (methane). The avoided
emissions from natural decay and the substitution of fossil based natural gas results in a negative carbon life cycle score. In the U.S.,
the California Air Resources Board has given dairy and agricultural based carbon negative RNG projects a carbon intensity Score (gCO2e/MJ)
of -250 (or lower). Such projects are similar to those pursued by AleAnna’s Renewable Natural Gas business.
“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
v
Risks
Related to our Renewable Natural Gas Business and the Renewable Natural Gas Industry
vi
Risks
Related to Foreign Operations and Regulatory Matters
Risks
Related to our Organizational Structure, Class A Common Stock and Public Warrants
We
describe these risks in greater detail under Item 1A., “Risk Factors.”
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 Company’s ability to raise financing in the future;
● the effects of competition;
● governmental incentives for renewable energy generation;
● the demand for renewable energy not being sustained;
● changes in environmental laws and regulations;
viii
● the effect of legal, tax and regulatory changes;
The
forward-looking statements included in this Annual Report on Form 10-K involve risks and uncertainties that could cause actual results
to differ materially from projected results. Accordingly, investors should not place undue reliance on forward-looking statements
as a prediction of actual results. We have based these forward-looking statements on current expectations and assumptions about future
events, taking into account all information currently known by us. While we consider these expectations and assumptions to be reasonable,
they are inherently subject to significant business, economic, competitive, regulatory and other risks and uncertainties, many of which
are difficult to predict and beyond our control. The risks and uncertainties that may affect the operations, performance and results
of our business and forward-looking statements include, but are not limited to, those set forth in Item 1A., “Risk Factors”
in this Annual Report on Form 10-K, and other documents we file from time to time with the SEC.
Any forward-looking statement speaks
only as of the date on which such statement is made, and, except as required by law, we do not intend to correct or update any forward-looking
statement, whether as a result of new information, future events or otherwise.
Reserve engineering is a process of
estimating underground accumulations of natural gas, NGLs and oil that cannot be measured in an exact way. The accuracy of any reserve
estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers.
In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously.
If significant, such revisions would change the schedule of any further production and our development program. Accordingly, reserve estimates
may differ significantly from the quantities of natural gas, NGLs and oil that are ultimately recovered.
In reviewing any agreements incorporated
by reference in or filed with this Annual Report on Form 10-K, remember such agreements are included to provide information regarding
the terms of such agreements and are not intended to provide any other factual or disclosure information about us. The agreements may
contain representations and warranties by us, which should not in all instances be treated as categorical statements of fact, but rather
as a way of allocating the risk to one of the parties to such agreements should those statements prove to be inaccurate. The representations
and warranties were intended to be relied upon solely by the applicable party to such agreement and were made only as of the date of the
relevant agreement or such other date or dates as may be specified in such agreement and are subject to more recent developments. Accordingly,
such representations and warranties alone may not describe our actual state of affairs or the affairs of our affiliates as of the date
they were made or at any other time and should not be relied upon as statements of fact.
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 103ft3. Such incentives are subject to successful completion and start-up of the Campagnatico facility.
As a development-stage company, while we have generated electricity revenue from our RNG plants, we had not yet generated any revenue
from our principal business activities as of December 31, 2024.
Over the past 15 years,
we have invested approximately $227 million in the acquisition and initial development of our properties, and we own a portfolio
of conventional natural gas properties, including Longanesi, Gradizza, and Trava, containing approximately 17.6 (106ft3)
net recoverable proved undeveloped natural gas reserves according to our independent third-party reserve engineer, DeGolyer & MacNaughton
(“DeGolyer”). Beyond our net recoverable natural gas reserves, we have 13 development prospects at various stages of permitting,
supported by 3D seismic surveys, and leases on approximately 2.7 million net acres — paving the way for future exploration
and development. Our recent activities involve the drilling and testing of three Longanesi development wells (2022 and 2023) as well as
the completion of two original discovery wells. Tie-in of these wells is complete, and we are currently executing the installation of
a temporary processing facility. We and Padana achieved first production of the five wells in the Longanesi field in March 2025 through
use of a temporary processing facility. The permanent processing facility is expected to be constructed over the course of 2025 and early
2026 and commissioned in mid-2026. On October 29, 2024, we entered into a gas sale agreement (“GSA”)
with Shell Energy Europe Limited (“SEEL”), whereby SEEL became the exclusive buyer of our share of the natural gas produced
from the Longanesi field net of (i) any consumption and/or losses incurred in the transport, treatment and compression of gas before delivery;
(ii) any volume to be allocated for regulated royalties auctions, if applicable; and (iii) any other volume contractually allocated to
other parties before August 31, 2022. Future sales under the GSA are contingent upon the commencement of gas production. As of December
31, 2024, we have not derived revenue from its conventional natural gas business.
Additionally, our renewable
gas team has built a substantial backlog of acquisition targets we believe are poised to support rapid growth in the Italian bio-methane
market. With several conventional and renewable projects under development, expected to initially generate revenue in the next 18 to 24 months.
We expect to be able to fund
our future growth primarily out of cash from operations from the Longanesi, Gradizza, and Trava developments and with cash on hand. We
believe that the synergies of our conventional and renewable natural gas businesses will provide us the financial flexibility to shift
capital deployment between the two businesses as the energy transition unfolds.
We believe that our highly
experienced and credentialed management team, consisting of former executives of Shell, Eni, and Exxon, provides the company access to
a best-in-class technology platform, an excellent in-country business development network, strong collaboration with Italian regulators,
and experience with local regulatory processes. Our senior management team has over 100 years of combined experience in the upstream
conventional and renewable energy industries. We are managed by William (“Bill”) Dirks, our Executive Director, and Marco
Brun, our Chief Executive Officer, under the direction of our Board.
AleAnna is headquartered in
Dallas, Texas, and has offices in Rome, Italy.
1
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:
2
Renewable Natural Gas Business
We
intend to develop and grow our renewable natural gas business through the acquisition of operational Anaerobic Digesters (or “AD’s”)
and their conversion to biomethane facilities. We believe the following factors are key to achieving this goal:
Natural
Gas Demand
Although Italy has numerous
hydrocarbon-producing basins with significant undeveloped oil and gas deposits, both onshore and offshore, in 2022 Italy imported 96%
of its natural gas and has one of the highest concentrations of natural gas as a component of total energy use, at almost 40% by kilotons
of oil equivalent. Its reliance on imports has led to a paradigm shift in the Italian political landscape towards securing domestic energy
supply. In addition, Italy has in recent decades opened oil and gas exploration and development permits to the global E&P industry
beyond the historical domain of Italy’s former National Oil Company (“NOC”), Eni.
Catering to this renewed emphasis
on secure domestic energy supply, we are focused on exploitation and producing activities in the prolific and well-derisked Po Valley
of northern Italy using modern proprietary 3D seismic surveys, which has led us to believe the Po Valley contains numerous opportunities
to explore for and develop conventional natural gas fields. The Po Valley is ripe with access to a dense network of government-controlled
natural gas pipelines that can transport our products to industrial, power generation and residential customers throughout Italy and into
the southern EU. Additionally, according to Eurostat, Italy is second only to Germany in the EU in terms of the value of natural
gas sold for industrial power and heat requirements, and the Po Valley is adjacent to Italy’s core, high-energy demand, manufacturing
centers. Supporting the vital energy needs of this industrial production base, Po Valley reservoirs are largely high-quality with unique
properties that allow for the application of an important exploration and development technology known as DHIs, through which natural
gas deposits can be “seen” on modern seismic surveys. We believe the use of DHI technology dramatically increases the probability
of drilling success and lower development costs.
3
In addition, throughout the
central and southern EU (but primarily focused in Italy and Germany), member states’ interest in creating new sources of renewable
energy has supported the construction of nearly 10,000 AD’s over the past 15 years. Largely family-farm owned and operated
and fueled by crop and livestock wastes, these AD’s are currently creating a meaningful, sustainable, supply of raw biogas (approximately
50% methane and 50% CO2 and other waste gases) according to the European Biogas Association, the precursor to pipeline-quality biomethane
(99.5% pure methane). Virtually all existing AD’s were designed to burn raw biogas in highly inefficient reciprocating engines to
produce electricity. However, the Italian government’s financial incentives and subsidies supporting these activities are set to
expire in January 2025 absent additional government action and have been largely replaced by attractive biomethane capital and pricing
incentives to stimulate conversion of these AD’s to the production of biomethane production. Such incentives are designed to bring
biomethane into the national pipeline transmission system in order to deliver the natural gas to higher efficiency, utility-scale, natural
gas power generation stations. In order to continue biogas operations, the farms are forced to seek a new use for the product, which will
be dominated by conversion to biomethane. To support this conversion, Italy has implemented a government-backed biomethane floor price
through the end of 2039 of €124 per MWh, equivalent, as of December 31, 2024 to $39.25 per
103ft3 .
Our Operations
Conventional Natural Gas Business
We began studying Italian opportunities
in 2007 and, over the last 15 years, have invested approximately $227 million to build a large asset base and exploration and
development prospect inventory. Our portfolio is largely comprised of a group of three discoveries, one developed (Longanesi) and two
currently awaiting regulatory approval (Gradizza, and Trava), surrounded by an additional 13 development and exploration prospects within
the Longanesi and Ponte dei Grilli “Clusters” that are at various stages of permitting and are supported by proprietary 3D
seismic surveys. According to our independent third-party reserve engineer, DeGolyer, these clusters contain approximately 17.6 (106ft3)
of proved recoverable natural gas net to us primarily related to our working interest in the Longanesi field but do not include the additional
development prospects we have identified and likely intend to drill in the near future.
In addition, our investments
in approximately 140,000 acres (approximately 567 km2) of modern, high-quality, 3D seismic surveys in the eastern Po Valley
underpin our conventional natural gas growth plan and many of our expected development and exploration prospects are in advanced stages
of permitting. Our immediate focus is on the extension of the Longanesi Field together with Padana. We expect to drill two additional
high-quality development wells by year end 2026, bringing the Longanesi field to a total of seven wells. In addition to the Longanesi
expansion, we are simultaneously focused on 13 100% working interest exploration prospects that currently reside at various stages of
permitting.
On October 29, 2024, we
entered into a Gas Sales Agreement (“GSA”) with Shell Energy Europe Ltd (“SEEL”), whereby SEEL became the exclusive
buyer of our share of the natural gas produced from the Longanesi field net of (i) any consumption and/or losses incurred in the
transport, treatment and compression of gas before delivery; (ii) any volume to be allocated for regulated royalties auctions, if
applicable; and (iii) any other volume contractually allocated to other parties before August 31, 2022. Future sales under the
GSA are contingent upon the commencement of gas production.
Over the course of 2022
and 2023, together with Padana, we completed the drilling and testing of three conventional natural gas development wells (in addition
to the completion of the two original Longanesi field discovery wells). Subsequently, during the first half of 2024, we and Padana completed
the construction of the flow lines tying the five wells to a central processing facility, and the facility has been connected to the flow
lines and to the SNAM national pipeline system. We and Padana began production of the Longanesi field in March 2025, a key milestone for
our business.
From 2025 through 2027, we
and Padana expect to develop a second phase of Longanesi field development aimed at bringing an additional two conventional wells online
(bringing the field to seven total wells). Post 2027, we also expect to enter into a third phase of development, targeting drilling and
completion of three additional wells.
Additionally, the infrastructure
installed at the Longanesi field (the flow lines and the processing unit) is expected to benefit our future development and exploration
prospects in the area. Through the cash flow from Longanesi, Gradizza, and Trava once these latter two discoveries are brought on production,
we plan to continue to grow both our conventional and renewable natural gas businesses. As we progress phase two and phase three of Longanesi
development, we also expect to begin a new phase of exploration drilling, focused initially on our Fornace and Armonia exploration prospects.
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Renewable Natural Gas Business
We expect our renewable natural
gas business will methodically acquire and retrofit a significant number of existing anaerobic digester facilities in the future. We are
concentrating our acquisition efforts on Brownfield Facilities in the Po Valley of northern Italy, but will seek other profitable facilities,
including Greenfields, as circumstances warrant.
On March 20, 2024, we
closed the acquisition of the Campagnatico Greenfield natural gas facility in Tuscany, Italy for €2,000,000, 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.
5
Gas production activities
(both conventional natural gas and renewable natural gas) are subject to several environmental laws and regulations. The main reference
is the Consolidated Environmental Act issued by Legislative Decree 152/2006.
The Renewable Natural Gas Development
Plan (the “Development Plan”) is subject to the authorization for the construction of the biomethane facility and the production
of renewable natural gas. The Development Plan is subject to environmental permitting, through Environmental Impact Assessments.
The Development of
conventional natural gas is subject to and controlled by a Federal Production Concession, which is obtained after
subjecting the Development Plan to technical, economic and environmental review; moreover, it is the subject of an agreement
between the State and the regional government for onshore activities.
Industry
EU Demand for Secure Energy Supply and Growth
in Renewable Natural Gas
We believe the EU and Italian
energy markets are undergoing dramatic changes as a result of two factors: (1) Russian natural gas imports into the EU have declined
approximately two-thirds (from 45% of total imports to 15% of total imports) since the outbreak of the Russia-Ukraine war due to sanctions
against Russia and the cancellation of supply contracts, and (2) the shift from fossil fuels to carbon-reduced and carbon-free sources.
An immediate need to replace Russian gas with a stable, secure, long-term gas supply has induced EU member nations to focus on increasing
access to domestic sources of supply and new liquified natural gas (“LNG”) imports, and a series of technological, economic,
regulatory, social, and investor pressures are leading the drive to decarbonize energy at a greatly accelerated pace, which is being supported
by significant and long-term renewable gas incentives implemented in Italy and other EU members.
The EU finds itself in a position
where reliance on conventional natural gas as a transition fuel becomes imperative for several reasons:
Renewable natural gas (biomethane)
is compositionally identical to the biogenic natural gas in the Po Valley, can be transported on the same pipeline systems, is used by
the same consumers, and offers a sustainable, low-carbon fuel that can be used to help transform the energy economy of the EU. As
a result, the EU has published very aggressive targets for biomethane development (with a goal of 30% of EU natural gas by 2030), and
its member states, including Italy, are supporting development with high biomethane floor prices and capital investment incentive programs
to aid in financing AD conversions to upgrade biogas production to biomethane.
6
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.
7
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
Natural Gas
Estimated proved developed reserves —
Estimated proved undeveloped reserves 17,621