NYSE: EONR

We are an independent oil and natural gas company
based in Texas and formed in 2017 that is focused on the acquisition, development, exploration, production and divestiture of oil and
natural gas properties in the Permian Basin. The Permian Basin is located in west Texas and southeastern New Mexico and is characterized
by high oil and liquids-rich natural gas content, multiple vertical and horizontal target horizons, extensive production histories, long-lived
reserves and historically high drilling success rates. Our properties are in the Grayburg-Jackson Field (the “GJF”) in Eddy
County, New Mexico, and South Justis Field (the “SJF”) in Lea County, New Mexico which are both in the sub-area of the Permian
Basin. LHO Operating, LLC, a subsidiary of the Company (“LHO”), focuses primarily on production through waterflooding recovery
methods.

Currently, we have 20 employees (5 executive officers, 1 support staff
and, 14 field staff in New Mexico). From time to time, on an as needed basis, contract workers handle additional necessary responsibilities.

Our assets as mentioned above consist of contiguous
leasehold positions in the GJF of approximately 13,700 gross (13,700 net) acres with an average working interest of 100%. We operate 100%
of the net acreage across the GJF assets, all of which is net operated acreage of vertical wells with average depths of approximately
3,810 feet. In addition, the SJF has contiguous leasehold positions of approximately 5,400 gross (5,400) acres with an average working
interest of 94%. We operate 100% of the net acreage across the SJF assets, all of which is net operated acreage of vertical wells with
average depths of approximately 6,000 feet.

Our average daily
production for the year ended December 31, 2025 was 734 barrel of oil equivalent (“BOE”) per day. Our average daily production
for the year ended December 31, 2024, was 798 BOE per day. The decrease in production is due to an increase in well downtime and water
injection flowlines that needed repair or replacement.

Purchase

On December 27, 2022, we, entered into the
MIPA, which was amended and restated on August 28, 2023 and further amended on November 15, 2023. Our stockholders approved the transactions
contemplated by the MIPA at a special meeting of stockholders that was originally convened October 30, 2023, adjourned, and then reconvened
on November 13, 2023 (the “Special Meeting”).

On November 15, 2023 (the “Closing Date”),
as contemplated by the MIPA:

● We
filed a Second Amended and Restated Certificate of Incorporation (the “Second A&R Charter”) with the Secretary of State
of the State of Delaware, pursuant to which the number of authorized shares of our capital stock, par value $0.0001 per share, was increased
to 121,000,000 shares, consisting of (i) 100,000,000 shares of Class A Common Stock, (ii) 20,000,000 shares of Class B Common Stock,
and (iii) 1,000,000 shares of preferred stock, par value $0.0001 per share;

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● Our
shares of common stock were reclassified as Class A Common Stock; the Class B Common Stock has no economic rights but entitles its holder
to one vote on all matters to be voted on by stockholders generally; holders of shares of Class A Common Stock and shares of Class B
Common Stock will vote together as a single class on all matters presented to our stockholders for their vote or approval, except as
otherwise required by applicable law or by the Second A&R Charter;

● (A)
We contributed to OpCo (i) all of our assets (excluding our interests in OpCo and the aggregate amount of cash required to satisfy any
exercise by our stockholders of their Redemption Rights (as defined below)) and (ii) 2,000,000 newly issued shares of Class B Common
Stock (such shares, the “Seller Class B Shares”) and (B) in exchange therefor, OpCo issued to us a number of Class A common
units of OpCo (the “OpCo Class A Units”) equal to the number of total shares of Class A Common Stock issued and outstanding
immediately after the closing (the “Closing”) of the transactions contemplated by the MIPA (following the exercise by EON
stockholders of their Redemption Rights) (such transactions, the “SPAC Contribution”);

● Immediately
following the SPAC Contribution, OpCo contributed $900,000 to SPAC Subsidiary in exchange for 100% of the outstanding common stock of
SPAC Subsidiary (the “SPAC Subsidiary Contribution”); and

● Immediately
following the SPAC Subsidiary Contribution, Seller sold, contributed, assigned, and conveyed to (A) OpCo, and OpCo acquired and accepted
from Seller, ninety-nine percent (99.0%) of the outstanding membership interests of Pogo Resources, LLC, a Texas limited liability
company (“Pogo” or the “Target”), and (B) SPAC Subsidiary, and SPAC Subsidiary purchased and accepted from Seller,
one percent (1.0%) of the outstanding membership interest of Target (together with the ninety-nine percent (99.0%) interest, the “Target
Interests”), in each case, in exchange for (x) $900,000 of the Cash Consideration (as defined below) in the case of SPAC Subsidiary
and (y) the remainder of the Aggregate Consideration (as defined below) in the case of OpCo (such transactions, together with the SPAC
Contribution and SPAC Subsidiary Contribution and the other transactions contemplated by the MIPA, the “Purchase”.

The “Aggregate Consideration” for
the Target Interests was: (a) cash in the amount of $31,074,127 in immediately available funds (the “Cash Consideration”),
(b) 2,000,000 Class B common units of OpCo (“OpCo Class B Units”) valued at $10.00 per unit (the “Common Unit Consideration”),
were exchangeable into 2,000,000 shares of Class A Common Stock issuable upon exercise of the OpCo Exchange Right (as defined below),
(c) the Seller Class B Shares, (d) $15,000,000 payable through a promissory note to Seller (the “Seller Note”), (e) 1,500,000
preferred units (the “OpCo Preferred Units” and together with the Opco Class A Units and the OpCo Class B Units, the “OpCo
Units”) of OpCo (the “Preferred Unit Consideration”, and, together with the Common Unit Consideration, the “Unit
Consideration”), and (f) an agreement for Buyer, on or before November 21, 2023, to settle and pay to Seller $1,925,873 from sales
proceeds received from oil and gas production attributable to Pogo, including pursuant to its third party contract with affiliates of
Chevron. At Closing, 500,000 Seller Class B Shares (the “Escrowed Share Consideration”) were placed in escrow for the benefit
of Buyer pursuant to an escrow agreement and the indemnity provisions in the MIPA.

In connection with the Purchase, holders of 3,323,707
shares of common stock sold in EON’s initial public offering (the “public shares”) properly exercised their right to
have their public shares redeemed (the “Redemption Rights”) for a pro rata portion of the trust account (the “Trust
Account”) which held the proceeds from EON’s initial public offering, funds from EON’s payments to extend the time to
consummate a business combination and interest earned, calculated as of two business days prior to the Closing, which was approximately
$10.95 per share, or $49,362,479 in the aggregate. The remaining balance in the Trust Account (after giving effect to the Redemption Rights)
was $12,979,300.

Immediately upon the Closing, Pogo Royalty, LLC,
a Texas limited liability company, an affiliate of Seller and Seller’s designated recipient of the Aggregate Consideration (“Pogo
Royalty”) exercised the OpCo Exchange Right as it related to 200,000 OpCo Class B units (and 200,000 shares of Class B Common Stock).
After giving effect to the Purchase, the redemption of public shares as described above and the exchange mentioned in the preceding sentence,
were (i) 5,097,009 shares of Class A Common Stock issued and outstanding, (ii) 1,800,000 shares of Class B Common Stock issued and outstanding
and (iii) no shares of preferred stock issued and outstanding.

The Class A Common Stock and EON warrants continue
to trade, but now as an operating company, on the NYSE American under the symbols “EONR” and “EONR.WS”.

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OpCo A&R LLC Agreement

In connection with the Closing, EON and Pogo Royalty,
entered into an amended and restated limited liability company agreement of OpCo (the “OpCo A&R LLC Agreement”). Pursuant
to the A&R OpCo LLC Agreement, Pogo Royalty the right (the “OpCo Exchange Right”) to exchange all or a portion of its
OpCo Class B Units for, at OpCo’s election, (i) shares of Class A Common Stock at an exchange ratio of one share
of Class A Common Stock for each OpCo Class B Unit exchanged, subject to conversion rate adjustments for stock splits, stock
dividends and reclassifications and other similar transactions, or (ii) an equivalent amount of cash. In connection with any exchange
of OpCo Class B Units pursuant to the OpCo Exchange Right or acquisition of OpCo Class B Units pursuant to a Mandatory
Exchange, a corresponding number of shares of Class B Common Stock held by the relevant OpCo unitholder were cancelled. During the
year ended December 31, 2024, Pogo Royalty exercised its right to exchange 1,300,000 shares of OpCo Class B Units for 1,300,000 shares
of Class A Common Stock.

The OpCo Preferred Units were to be automatically
converted into OpCo Class B Units on the two-year anniversary of the issuance date of such OpCo Preferred Units (the
“Mandatory Conversion Trigger Date”) at a rate determined by dividing (i) $20.00 per unit (the “Stated Conversion
Value”), by (ii) the simple average of the daily VWAP of the Class A Common Stock during the five (5) trading days
prior to the date of conversion.

In connection with the consummation of the transactions
contemplated by the PSTE Agreement (as defined below), no OpCo Class B Units or OpCo Preferred Units remained outstanding, and EON became
the sole owner of the equity interests of OpCo.

Backstop Agreement

In connection with
the Closing, EON entered a Backstop Agreement (the “Backstop Agreement”) with Pogo Royalty and certain of EON’s founders
listed therein (the “Founders”) whereby Pogo Royalty had the right (“Put Right”) to cause the Founders to purchase
Pogo Royalty’s OpCo Preferred Units at a purchase price determined therein.

As security that the Founders will be able to
purchase the OpCo Preferred Units upon exercise of the Put Right, the Founders placed 1,300,000 shares of Class A Common
Stock into escrow (the “Trust Shares”). The Backstop Agreement was terminated in connection with the PSTE Agreement.

Founder Pledge Agreement

In connection with the Closing, EON entered a
Founder Pledge Agreement (the “Founder Pledge Agreement”) with the Founders whereby, in consideration of placing the Trust
Shares into escrow and entering into the Backstop Agreement, EON agreed: (a) by January 15, 2024, to issue to the Founders an aggregate
number of newly issued shares of Class A Common Stock equal to 10% of the number of Trust Shares; and (b) by January 15, 2024, to issue
to the Founders number of warrants to purchase an aggregate number of shares of Class A Common Stock equal to 10% of the number of Trust
Shares, which such warrants shall be exercisable for five years from issuance at an exercise price of $11.50 per share.

Purchase, Sale, Termination and Exchange
Agreement

On February 10, 2025, the Company entered into
a Purchase, Sale, Termination and Exchange Agreement (as amended, the “PSTE Agreement”), by and among the Company, OpCo, SPAC
Subsidiary, EON Energy, LLC, a wholly owned subsidiary of the Company (“EON Energy”), Pogo Royalty, CIC, DenCo, Pogo Management,
and 4400.

On September 9, 2025, the transactions contemplated
by the PSTE Agreement were consummated (the “PSTE Closing”). Pursuant to the PSTE Agreement, at the PSTE Closing, (i) the
Company purchased a 10% overriding royalty interest in existing leases and wells in the GJF (the “Pogo ORRI”) from Pogo Royalty
for $13,675,000 in cash; (ii) Pogo Royalty waived all outstanding interest accrued under the Seller Note, reduced the outstanding principal
amount of the Seller Note to $7,000,000 and settled and discharged the Seller Note in exchange for the payment of $7,000,000 in cash by
the Company; (iii) Pogo Royalty assigned and transferred the 1,500,000 OpCo Preferred Units to the Company in exchange for the issuance
by the Company of 1,500,000 shares of Class A Common Stock.

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The Company recorded $13,500,000 of the purchase
amount of as an increase to the leasehold cost basis under ASC 932, with the additional $175,000 being for the final Pogo ORRI liability
payment through the PSTE Closing date. The Company reclassified the value of the noncontrolling interest associated with the OpCo Preferred
Units to additional paid in capital related to the issuance of the 1,500,000 shares of Class A Common Stock with no gain or loss recognized
in accordance with ASC 505.

New ORRI Agreement and Conveyance

On September 9, 2025, LHO entered into an Agreement
regarding Overriding Royalty Interest (the “2025 ORRI Agreement”) with an investor (the “ORRI Investor”) wherein
two different overriding royalty interests were purchased and sold and agreed to be transferred under an instrument titled Conveyance
of Overriding Royalty Interest (the “2025 ORRI Conveyance”). Pursuant to the 2025 ORRI Conveyance executed September 9, 2025,
LHO conveyed an overriding royalty interest (each a “2025 ORRI”) in and to certain leasehold interests, hydrocarbons and wells
to Investor. The two 2025 ORRIs are as follows: (i) a 15% perpetual overriding royalty interest in existing leases and wells in the GJF
(the “Waterflood ORRI”); and (ii) a 5% perpetual overriding royalty interest in the San Andres Formation (as defined in the
2025 ORRI Conveyance) in wells to be drilled by Virtus Energy Assets, LLC (“Virtus”), an affiliate of Virtus Energy partners,
LLC under the Farmout Program (defined below) (the “Horizontal ORRI”).

The 2025 ORRI Agreement governs, among other things,
the terms of disbursements to be made to the ORRI Investor in connection with the Waterflood ORRI. Pursuant to the 2025 ORRI Agreement,
commencing on January 1, 2026, LHO is required to fund, or cause to be funded, qualified petroleum, exploration, development and production
activities in an amount not less than $3,000,000 in each year through and including December 1, 2028 (the “Annual Capital Commitment”).
If the Annual Capital Commitment is not met, the percentages of the Waterflood ORRI will increase by an amount (expressed in percentage
points) equal to the product of (a) (i) 1.0 minus (ii) the amount of qualified expenditures divided by the Annual Capital Commitment,
multiplied by (b) 0.02. Furthermore, LHO agreed to execute a conveyance of overriding royalty interests for any subsequently acquired
interests in the subject interests, hydrocarbons and leases described in the 2025 ORRI Conveyances.

The ORRI Investor has
no right or power to participate in the operations of the GJF as a result of the 2025 ORRI Conveyances. LHO is required to use commercially
reasonable efforts to market the subject hydrocarbons and utilize reasonable prudent operator standards in operating the GJF. LHO is not
permitted to transfer any of the interests that are subject to the Investor ORRI Conveyance or to assign or delegate any rights or obligations
with respect to the 2025 ORRIs without the prior consent of the ORRI Investor (except as described below in the Farmout Program).

In exchange for
the 15% Waterflood ORRI in existing leases and wells in GJF, the Company received proceeds of $20,000,000.

In exchange for the 5%
Horizontal ORRI in the San Andres Formation in wells to be drilled under the Farmout Program, the Company received proceeds of $20,500,000.

Virtus Farmout
Program

On
September 9, 2025, LHO and Virtus entered into a Joint Development, Leasehold Purchase, and Area of Mutual Interest Agreement (the “Farmout
Program”). Pursuant to the Farmout Program, Virtus paid LHO $5,000,000 in cash in consideration of the farmout of LHO’s rights
in the San Andres Formation in the GJF in which Virtus will own a 65% operated working interest (the “Assigned Interest”)
and LHO retained a 35% non-operated working interest. In connection with such farmout, Virtus has agreed to conduct certain confirmatory
evaluation studies and to fund, drill, complete, and equip three horizontal wells within the GJF, with LHO’s interest in such initial
operations to be carried to the tanks by Virtus without cost by LHO. If further drilling is determined to be commercially viable by Virtus,
Virtus will drill up to 12 additional horizontal wells targeting the GJF on or before December 31, 2030, to be completed on a “heads-up”
basis meaning each party is responsible for their own expense interest subject to non-consent provisions of the applicable Joint Operating
Agreement. If Virtus does not complete such drilling commitment by December 31, 2030, Virtus will be required to reassign to LHO all right,
title and interest to the Assigned Interest, other than wellbores drilled by Virtus and other specified exceptions.

Furthermore, for five
years following September 9, 2025, if either the ORRI Investor or Virtus acquire any oil, gas or mineral leasehold rights, wellbore interest,
or other interests in oil gas, or mineral estate in certain designated sections of the GJF, then such party will be required to give the
other party the option to participate in such acquisition up to its Subsequent AMI Participation Percentage (35% for LHO and 65% for Virtus).

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The Farmout Program also
provides for a mutual five-year right of first offer in the event that either of the parties determines to sell its interests that are
subject to the Farmout Program to a third-party. If such right of first offer is exercised, the exercising party will have 45 days to
negotiate in good faith and consummate the transaction for the sale of the offered interests in accordance with the material terms and
conditions under which the selling party proposed to sell the offered interests.

SJF Acquisition

On June 17, 2025, the Company and EON Energy entered
into a Purchase and Sale Agreement (the “SJF PSA”) with WPP NM, L.L.C. and Northwest Central, L.L.C. (collectively the “SJF
Seller”) to acquire all of the SJF Seller’s respective estates and mineral rights created by the oil and gas leases and mineral
estates in the SJF located in the Permian Basin in Lea County, New Mexico (the “SJF Leases”), (ii) all oil, gas, water injection
wells, water disposal and other wells located on the SJF Leases or on lands pooled therewith, together with (iii) all of the SJF Seller’s
interest in the rights, appurtenances, contracts, personal property, and records related thereto (collectively, the “SJF Assets”).
The transactions contemplated by the SJF PSA were consummated at a closing held on June 20, 2025.

In consideration of EON Energy’s purchase
of the SJF Assets, the Company issued 1,000,000 shares of its Class A Common Stock.

Market Conditions

The price that EON receives for the oil and natural
gas we produce is largely a function of market supply and demand. Because EON’s oil and gas revenues are heavily weighted toward
oil, EON is more significantly impacted by changes in oil prices than by changes in the price of natural gas. World-wide supply in
terms of output, especially production from properties within the United States, the production quota set by OPEC, and the strength
of the U.S. dollar can adversely impact oil prices.

Historically, commodity prices have been volatile,
and EON expects the volatility to continue in the future. Factors impacting the future oil supply balance are world-wide demand for
oil, as well as the growth in domestic oil production.

Key Producing Region

As of December 31, 2025, all of the Company’s
properties were located exclusively within the Northwest Shelf of the Permian Basin. As of December 2024, the Permian Basin had the
highest level of drilling activity in the United States with greater than 300 drilling rigs operating. By comparison, The Eagle Ford
Shale region located in Southwest-central Texas has less than 60 rigs operating. The Permian Basin includes three major geologic
provinces: the Delaware Basin to the west, the Midland Basin to the east and the Central Basin Platform in between. The Northwest Shelf
is the western limits of the Delaware Basin, a sub-basin within the Permian Basin complex. The Delaware Basin is identified by an
abundant amount of oil-in-place, stacked pay potential across an approximately 3,900-foot hydrocarbon column, attractive well economics,
favorable operating environment, well developed network of oilfield service providers, and significant midstream infrastructure in place
or actively under construction. One hundred percent (100%) of our working interests are located as of December 31, 2025, on the New
Mexico side of the Delaware Basin. According to the USGS, the Delaware Basin contains the largest recoverable reserves among all unconventional
basins in the United States.

We believe the stacked-play potential of the Delaware
Basin combined with favorable drilling economics support continued production growth as Pogo develops its leasehold position and improve
well-spacing and completion techniques. Relative to other basins in the continental United States, Pogo believes the Delaware Basin is
in a mid-stage of well development and that per-well returns will improve as Pogo continues to employ enhanced oil recovery technologies
on its leasehold acreage. The Company believes these enhanced oil recoveries will continue to support development activity where it holds
significant working interest, with predictable returns leading to increasing cash flows with low maintenance costs.

Working Interests in the GJF

As of December 31, 2025, the Company owns a 100% working interest
in 13,700 gross acres located in Eddy County, New Mexico, with a 69% weighted average net revenue interest. The 13,700 gross acres are
strategically located in the GJF. Working interests granted to the Lessee (Pogo) under an Oil and Gas Lease are real property interests
that grant ownership of the crude oil and natural gas underlying a specific tract of land and the rights to explore for, drill for and
produce crude oil and natural gas on that land or to lease those exploration and development rights to a third party. Those rights to
explore for, drill for and produce crude oil and natural gas on that land have a set period of time for the working interest owner to
exercise those rights. Typically, an Oil and Gas Lease can be automatically extended beyond the initial lease term with continuous drilling,
production or other operating activities or through negotiated contractual lease extension options. Only when production and drilling
cease, the lease terminates.

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As of December 31, 2025, 100% of the Company’s
working interests are held by production (“HBP”) meaning that EON is not under time sensitive obligation to drill or work-over any
wells on its 13,700 acres. As of December 31, 2025, 100% of the wells and leases are operated by EON. EON is the official Operator
of record with the state and federal regulatory agencies. As of December 31, 2025, the Company generates a substantial majority of
its revenues and cash flows from its working interests when crude oil and natural gas are produced and sold from its acreage.

Currently, EON’s
working interests reside entirely in the Northwest Shelf of the Permian Basin, which EON believes is one of the premier crude oil and
natural gas producing regions in the United States. As of December 31, 2025, EON’s working interests covered 13,700 gross
acres, with the outside royalty owners retaining a weighted average of approximately 30% royalty. The following table summarizes EON’s
working interest’s position in the lands comprising its leasehold as of December 31, 2025.

LH Operating, LLC Northwest Shelf (Permian Basin) Leasehold

Date of Acquisition
Gross

Acres
Federal

Leases
State

Leases
Working

Interest
NRI

(weighted avg.)(1)
Royalty

Interest(2)
Operations
HBP

2018
13,700
20
3
100 %
69 %
31 %
100 %
100 %

(1) The Company’s
net revenue interests are based on its weighted average royalty interests across its entire leasehold

(2)
No unleased royalty interests as of December 31, 2025. This represents royalty interests paid to third party royalty holders.

As of December 31, 2025, EON has working
interests in 342 shallow (above 4,000 ft), vertical wells producing oil and gas in paying quantities. 95 of the 342 producing wells
were completed between 2019 and June 2022 by EON. In 2019, EON initiated a 4-well pilot water injection project into the Seven
Rivers (“7R”) oil reservoir underlying its 13,700-acre leasehold. After an evaluation period extending into early 2020,
EON determined the pilot project was successful by producing oil in paying quantities by simply adding perforations in the 7R reservoir
in previously drilled and completed wells. Following the successful completion of the 4-well pilot project, EON commenced a work-over program
by adding perforations in the 7R reservoir in 91 previously drilled wells between 2019 and June 2022. Prior to initiating the 4-well pilot
project the legacy wells were averaging 275 BOE/d. By December 2024, the total production increased to 1,022 BOE/d. EON’s management
team has determined, and verified by Haas and Cobb Petroleum Consultants, LLC (“Haas and Cobb”), that 115 proved well patterns,
developed but non-producing, are scheduled to be brought into production between 2026 and 2030.

As of December 31, 2025, the estimated proved
crude oil and natural gas reserves attributable to EON’s interests in its underlying acreage were 2,610 MBOE (96% oil and 4% natural
gas), based on a reserve report prepared by Haas and Cobb, worldwide petroleum consultants. Of these reserves, approximately 75% were
classified as proved developed producing (“PDP”) reserves, 25% were classified as proved developed non-producing (“PDNP”)
reserves. An additional 9,211 MBOE were classified as probable. The combined proven and probable PDNP reserves total of 5,468,929 barrels
of oil of which 12% are proven and 88% are probable reserves. Included in the probable reserves are an additional 4,178,377 barrels of
undeveloped oil reserves.

EON’s working interest development strategy
anticipates shifting any drilling activity associated with its Probable reserves following EON’s completion of its PDNP reserves.
The work-over costs attributable to adding perforations in wells previously drilled and completed is significantly less than drilling
new wells. As of December 31, 2025, The Company’s leasehold position has 25.7 wells per square mile. EON expects to see increases
in its production, revenue and discretionary cash flows from the development of 115 well patterns in the 7R reservoir. EON believes its
current leasehold working interests provide the potential for significant long-term organic revenue growth as EON develops its PDNP
reserves to increase crude oil and natural gas production.

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Under the terms of the Farmout Program, Virtus
acquired the right to develop the Company’s San Andres formation within the GJF. Virtus believes there are as many as 92 horizontal
drilling locations that are prospective. A subsidiary of Virtus will be the designated operator of the horizontal wells and lead the development
efforts. The Company has a 35% working interest in the Farmout where Virtus has estimated that the Company’s probable reserves are
38.9 million barrels of oil and 53.1 billion cubic feet of natural gas.

Working Interests in South-Justis Field

As of December 31, 2025, the estimated proved crude oil reserves attributable
to EON’s interests in its underlying acreage were 170 MBOE (100% oil), of which 67 MBOE were classified as proved developed producing
(“PDP”) reserves and 103 MBOE were classified as proved developed non-producing (“PDNP”) reserves.

Business Strategies

The Company’s primary business objective
is to generate discretionary cash flow by maintaining its strong cash flow from the PDP reserves and increasing cash flow by developing
predictable, low cost PDNP reserves in its Permian Basin asset. The Company intends to accomplish this objective by executing the following
strategies:

Generate strong cash flow supported by means
of disciplined development of its PDNP Reserves. As the sole working interest owner, the Company benefits from the continued organic
development of its acreage in the Permian Basin. As of December 31, 2025, EON, in conjunction with Haas and Cobb, a third-party engineering
consulting firm, has confirmed that EON has 127 low cost, well patterns to be developed during 2025 to 2028. A single well pattern consists
of a producing well with its corresponding or dedicated water injection wells, with each injection well situated on four sides of the
producing well. Water injection wells are necessary to maintain reservoir pressure in its original state and to move the oil in place
toward the producing well. Pressure maintenance helps ensure maximum oil and gas recovery. Without pressure maintenance, oil recoveries
from a producing oil reservoir generally do not exceed 10% of the original oil in place (“OOIP”). With pressure maintenance
by re-injecting produced water into the oil reservoir, then EON expects to see ultimate oil recoveries 25% or greater of the OOIP. Offsetting
oil wells on its leasehold also take advantage of the water injected into the oil reservoir, and is able to convert a high percentage
of its revenue to discretionary cash flow. Because EON owns 100% working interests it incurs 100% of the monthly leasehold operating costs
for the production of crude oil and natural gas or capital costs for the drilling and completion of wells on its acreage. Because these
wells are shallow oil producers, with vertical depths between 1500 ft and 4000 ft, the monthly operating expenses are relatively low.

Focus primarily on the Permian Basin. All
of the Company’s working interests are currently located in the Permian Basin, one of the most prolific oil and gas basins in the
United States. We believe the Permian Basin provides an attractive combination of highly-economic and oil-weighted geologic
and reservoir properties, opportunities for development with significant inventory of drilling locations and zones to be delineated our
top-tier management team.

● Business
Relations. Leverage expertise and relationships to continue acquiring Permian Basin targets with high working interests in actively
producing oil fields from top-tier E&P operators, with predictable, stable cash flow, and with significant growth potential.
the Company has a history of evaluating, pursuing and consummating acquisitions of crude oil and natural gas targets in the Permian Basin
and other oil producing basins. the Company’s management team intends to continue to apply this experience in a disciplined manner
when identifying and acquiring working interests. The Company believes that the current market environment is favorable for oil and gas
acquisitions in the Permian Basin and other oil generating basins. Numerous asset packages from sellers presents attractive opportunities
for assets that meet the Company’s target investment criteria. With sellers seeking to monetize their investments, we intend to
continue to acquire working interests that have substantial resource potential in the Permian Basin. We expect to focus on acquisitions
that complement our current footprint in the Permian Basin while targeting working interests underlying large scale, contiguous acreage
positions that have a history of predictable, stable oil and gas production rates, and with attractive growth potential. Furthermore,
the Company seeks to maximize its return on capital by targeting acquisitions that meet the following criteria:

● sufficient
visibility to production growth;

● attractive
economics;

● de-risked geology
supported by stable production;

● targets
from top-tier E&P operators; and

● a
geographic footprint that we believe is complementary to its current Permian Basin asset and maximizes its potential for upside reserve
and production growth.

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Maintain conservative
and flexible capital structure to support the Company’s business and facilitate long-term operations. The Company
is committed to maintaining a conservative capital structure that will afford it the financial flexibility to execute its business strategies
on an ongoing basis. The Company believes that internally generated cash flows from its working interests and operations, available borrowing
capacity under its revolving credit facility, and access to capital markets will provide it with sufficient liquidity and financial flexibility
to continue to acquire attractive targets with high working interests that will position it to grow its cash flows in order to distributed
to its shareholders as dividends and/or reinvested to further expand its base of cash flow generating assets. The Company intends to maintain
a conservative leverage profile and utilize a mix of cash flows from operations and issuance of debt and equity securities to finance
future acquisitions.

Competitive Strengths

The Company believes that the following competitive
strengths will allow it to successfully execute its business strategies and achieve its primary business objective:

● Permian
Basin focused public company positioned as a preferred buyer in the basin. The Company believes that its focus on the Permian
Basin will position it as a preferred buyer of Permian Basin working interests in known producing oil and gas fields. As of December 31,
2025, 100% of its current leasehold is located in an area with proven results from multiple stacked productive zones. The Company’s
properties in the Permian Basin are high-quality, high-margin, and oil weighted, and the Company believes we will be viewed favorably
by the investment community as compared to equity consideration diluted by lower quality assets located in less prolific basins. The
Company targets acquisitions of operated properties with high working interest percentages that are relatively undeveloped in the Permian
Basin, and it believes the organic development of its acreage will result in substantial production growth regardless of acquisition
activity.

● Favorable
and stable operating environment in the Permian Basin. With over 400,000 wells drilled in the Permian Basin since 1900, the region
features a reliable and predictable geological and regulatory environment, according to Enverus. The Company believes that the impact
of new technology, combined with the substantial geological information available about the Permian Basin, also reduces the risk of development
and exploration activities as compared to other, emerging hydrocarbon basins. As of December 31, 2025, 100% of the Company’s
acreage was located in New Mexico and does not require federal approval to develop its 115 well patterns classified as PDNP reserves
and does not have impediments in order to deliver EON’s production to market.

● Experienced
team with an extensive track record. The Company’s team has deep industry experience focused on development in the Permian
Basin as well as other significant oil producing regions and has a track record of identifying acquisition targets, negotiating agreements,
and successfully consummating acquisitions, and operating the acquired target using industry standards. EON plans to continue to evaluate
and pursue acquisitions of all sizes. EON expects to benefit from the industry relationships fostered by its management team’s
decades of experience in the oil and natural gas industry with a focus on the Permian Basin, in addition to leveraging its relationships
with many E & P company executives.

● Development
potential of the properties underlying the Company’s Permian Basin working interests. The Company’s assets consist
of 100% working interests in a gross 13,700 acres located in the Northwest Shelf of the Permian Basin. The Company expects production
from its working interest ownership to increase its oil and gas production by 1,358 BOE/d as it develops its PDNP reserves after completing
115 well patterns. The Company believes its assets in the Permian Basin is in an earlier to mid-stage of development and that the
average number of producing wells per section in its 13,700-acre leasehold will increase as EON continues to add PUD well patterns,
which would allow the Company to achieve higher realized cash flows to distributed to its shareholders as dividends and/or reinvested
to further expand its base of cash flow generating assets. The Company believes that once it completes its PDNP and PUD program as detailed
in the Haas and Cobb reserve report, The Company expects its BOE/d will increase to 2,853 BOE/d combined with PDP.

Crude Oil and Natural Gas Data

In this report, we include estimates of reserves associated with the
assets located in New Mexico as of December 31, 2025 and 2024. Such reserve estimates are based on evaluations prepared by the independent
petroleum engineering firm of Haas and Cobb, in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves
Information promulgated by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC. The Haas
and Cobb reserve report as of December 31, 2025 is included in this filing and covers 94% of our reserves as of December 31, 2025, while
the remaining 6% were developed by our internal reserve engineers.

8

Haas and Cobb is an independent consulting firm
founded in 1983. Its compensation is not contingent on the results obtained or reported. Frank J. Marek, a Registered Texas Professional
Engineer and a senior technical advisor of Haas and Cobb, is primarily responsible for overseeing the preparation of the reserve report.
His professional qualifications meet or exceed the qualifications of reserve estimators set forth in the “Standards Pertaining to
Estimation and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers. His qualifications
include: Bachelor of Science degree in Petroleum Engineering from Texas A&M University 1977; member of the Society of Petroleum Engineers;
member of the Society of Petroleum Evaluation Engineers; and 40 years of experience in estimating and evaluating reserve information
and estimating and evaluating reserves; he is proficient in judiciously applying industry standard practices to engineering and geoscience
evaluations as well as applying SEC and other industry reserve definitions and guidelines.

Preparation of Reserve Estimates

In accordance with rules and regulations of the
SEC applicable to companies involved in crude oil and natural gas producing activities, proved reserves are those quantities of crude
oil and natural 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. The term “reasonable certainty” means deterministically, the quantities of crude oil and/or natural gas are much
more likely to be achieved than not, and probabilistically, there should be at least a 90% probability of recovering volumes equal to
or exceeding the estimate. All of our proved reserves were estimated using a deterministic method. The estimation of reserves involves
two distinct determinations. The first determination results in the estimation of the quantities of recoverable crude oil and natural
gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance
with the definitions established under SEC rules. The process of estimating the quantities of recoverable reserves relies on the use of
certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (i) production
performance-based methods, (ii) material balance-based methods; (iii) volumetric-based methods and (iv) analogy. These
methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves
for proved developed producing wells were estimated using production performance methods. Non-producing reserve estimates, for developed
and undeveloped properties, were forecast using a pattern simulation model.

To estimate economically recoverable proved reserves
and related future net cash flows, EON considered many factors and assumptions, including the use of reservoir parameters derived from
geological and engineering data that cannot be measured directly, economic criteria based on current costs and the SEC pricing requirements
and forecasts of future production rates.

Under SEC rules, reasonable certainty can be established
using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or
by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies
(including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency
and repeatability in the formation being evaluated or in an analogous formation. To establish reasonable certainty with respect to EON’s
estimated proved reserves, the technologies and economic data used in the estimation of its proved reserves have been demonstrated to
yield results with consistency and repeatability, and include production and well test data, downhole completion information, geologic
data, electrical logs, radioactivity logs, core data, and historical well cost and operating expense data.

Internal Controls

Our internal staff of petroleum engineers and
geoscience professionals work closely with its independent reserve engineer to ensure the integrity, accuracy and timeliness of data furnished
to such independent reserve engineer in their preparation of reserve estimates. 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. See “Risk Factors Related to Our Business”
appearing elsewhere in this report. Our engineering group is responsible for the internal review of reserve estimates.

No portion of EON’s
engineering group’s compensation is directly dependent on the quantity of reserves booked. The engineering group reviews the estimates
with the third-party petroleum consultant, Haas and Cobb, an independent petroleum engineering firm.

9

Reconciliation of Standardized Measure to PV-10

Neither PV-10 nor PV-10 after ARO are financial
measures defined under accounting principles generally accepted in the United States of America (“GAAP”); therefore, the following
table reconciles these amounts to the standardized measure of discounted future net cash flows, which is the most directly comparable
GAAP financial measure. Management believes that the non-GAAP financial measures of PV-10 and PV-10 after ARO are relevant and useful
for evaluating the relative monetary significance of oil and natural gas properties. PV-10 and PV-10 after ARO are used internally when
assessing the potential return on investment related to oil and natural gas properties and in evaluating acquisition opportunities. Management
believes that the presentation of PV-10 and PV-10 after ARO provide useful information to investors because they are widely used by professional
analysts and sophisticated investors in evaluating oil and natural gas companies. PV-10 and PV-10 after ARO are not measures of financial
or operating performance under GAAP, nor are they intended to represent the current market value of our estimated oil and natural gas
reserves. PV-10 after ARO is equivalent to the standardized measure of discounted future net cash flows as defined under GAAP. Investors
should not assume that PV-10, or PV-10 after ARO, of our proved oil and natural gas reserves shown above represent a current market value
of our estimated oil and natural gas reserves.

The reconciliation of PV-10 and PV-10 after ARO
to the standardized measure of discounted future net cash flows relating to our estimated proved oil and natural gas reserves is as follows
(in thousands):

December 31,

2025
December 31,

2024

Present value of estimated future net revenues (PV-10)
$ 37,545
$ 207,666

Present value of estimated ARO, discounted at 10%
(105 )
(404 )

Present value of estimated income taxes, discounted at 10%
(6,256 )
(34,149 )

Standardized measure
$ 31,184
$ 173,113

Summary of Reserves

The following table presents EON’s estimated
proved reserves as of December 31, 2025 and 2024. The reserve estimates presented in the table below are based on reports prepared
by Haas and Cobb, EON’s independent petroleum engineers, and reports generated by EON’s internal reserve engineers, which
reports were prepared in accordance with current SEC rules and regulations regarding oil and natural gas reserve reporting:

December 31,

2025(1)
December 31,

2024(2)

Estimated proved developed producing reserves:

Crude Oil (MBbls)
2,024
3,870

Natural Gas (MMcf)
632
931

NGLs (MBbls)
-
-

Total (MBOE)
2,129
4,025

Estimated proved non-producing reserves:

Crude Oil (MBbls)
661
5,933

Natural Gas (MMcf)
(63 )
1,125

NGLs (MBbls)
-
-

Total (MBOE)
651
6,120

Estimated proved undeveloped reserves:

Crude Oil (MBbls)
-
4,215

Natural Gas (MMcf)
-
784

NGLs (MBbls)
-
-

Total (MBOE)
-
4,346

Estimated proved reserves:

Crude Oil (MBbls)
2,685
14,018

Natural Gas (MMcf)
569
2,840

NGLs (MBbls)
-
-

Total (MBOE)
2,780
14,492

(1) EON’s
estimated proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with
SEC guidance. For crude oil volumes, the average WTI posted price of $64.54 per Bbl as of December 31, 2025, was adjusted for quality,
transportation fees and a regional price differential. For natural gas volumes, the average Henry Hub spot price of $2.82 per MMBtu as
of December 31, 2025, was adjusted for energy content, transportation fees and a regional price differential. The average adjusted
product prices weighted by production over the remaining lives of the proved properties are $64.54 per Bbl of crude oil and $2.82 per
Mcf of natural gas as of December 31, 2025.

10

(2)
EON’s estimated proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For crude oil volumes, the average WTI posted price of $75.48 per Bbl as of December 31, 2024, was adjusted for quality, transportation fees and a regional price differential. For natural gas volumes, the average Henry Hub spot price of $2.13 per MMBtu as of December 31, 2024, was adjusted for energy content, transportation fees and a regional price differential. The average adjusted product prices weighted by production over the remaining lives of the proved properties are $77.10 per Bbl of crude oil and $1.62 per Mcf of natural gas as of December 31, 2024.

Reserve engineering is a process of estimating
volumes of economically recoverable crude 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 crude oil and natural gas that are ultimately recovered. Estimates
of economically recoverable crude 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. Please read “Risk
Factors Related to Our Business.”

PUDs

As of December 31, 2025, EON estimated its PUD
reserves to be 0 MBbls of crude oil and 0 MMcf of natural gas for a total of 0 MBOE. As of December 31, 2024, EON estimated its PUD reserves
to be 4,215 MBbls of crude oil and 784 MMcf of natural gas for a total of 4,346 MBOE. PUDs will be converted from undeveloped to
developed as the applicable wells begin production.

The following table summarizes EON’s changes
in PUD reserves during the years ended December 31, 2025 and 2024 (in MBOE):

Proved

Undeveloped

Reserves

(MBOE)

Balance, December 31, 2023
4,279

Acquisitions of Reserves
0

Extensions and Discoveries
0

Revisions of Previous Estimates
67

Transfers to Estimated Proved Developed
0

Balance, December 31, 2024
4,346

Acquisitions of Reserves
0

Extensions and Discoveries
0

Revisions of Previous Estimates
(4,346 )

Transfers to Estimated Proved Developed
0

Balance, December 31, 2025
0

Changes in EON’s PUD reserves that occurred during the year ended
December 31, 2025 were due to reclassification of wells from proved to probable as a result of expected timing to complete outside of
5 years. Changes in EON’s PUD reserves that occurred during the year ended December 31, 2024 were primarily due to increased operating
costs.

11

EON has not made any capital expenditures in order
to convert its existing PUDs because EON has been allocating its capital resources to convert PDNP reserves to PDP reserves and not to
convert its PUD reserves to PDNP or PDP reserves.

Probable Reserves

As of December 31, 2025, EON estimated its probable reserves to be
8,986 MBbls of crude oil and 1,347 MMcf of natural gas for a total of 9,211 MBOE. The Company’s development plan for probable reserves
is to complete the PDNP and probable reserves over the next five years.

Crude Oil and Natural Gas Production Prices and Costs

Production and Price History

The following table sets forth information regarding
net production of crude oil and natural gas and certain price and cost information for each of the periods indicated:

Year Ended

December 31,

2025
Year Ended

December 31,

2024

Production data:

Crude Oil (MBbls)
244
256

Natural Gas (MMcf)
142
213

NGLs (MBbls)
0
0

Total (MBOE)
268
291

Average realized prices:

Crude Oil (per Bbl)
$ 63.93
$ 75.52

Natural Gas (per Mcf)
$ 1.89
$ 2.27

NGLs (per Bbl)
$ 0.00
$ 0.00

Total (per BOE)(1)
$ 59.29
$ 67.96

Average cost (per BOE):

Lease Operating Expenses
$ 38.33
$ 29.59

Production and ad valorem taxes
$ 6.07
$ 5.89

(1)
“Btu-equivalent” production volumes are presented on an oil-equivalent basis using a conversion factor of six Mcf of natural gas per Bbl of “oil equivalent,” which is based on approximate energy equivalency and does not reflect the price or value relationship between crude oil and natural gas.

Productive Wells

Productive wells located on our leasehold consist
of producing vertical wells that are capable of producing oil and gas in paying quantities and are not dry wells. As of December 31, 2025,
we owned working interests in 472 producing wells, 207 water injectors, and one water source well, all located on its 13,700 gross acre
leasehold. Only one well owned by the Company is approved to be plugged and abandoned.

EON is not aware of any dry holes drilled on the
acreage underlying its working interest during the relevant periods.

The following table sets forth the total number
of gross and net productive wells, all of which are oil wells.

As of December 31, 2025

Gross
Net

Productive
361
342

Dry holes
—
—

Total
361
342

12

Drilling and other exploration and development
activities

For the years ended 2025 and 2024, we did not
drill any new wells.

As of December 31, 2025, there were no wells being
completed or waiting on completion. Furthermore, we were not installing any waterfloods or pressure maintenance systems or engaging in
any other development activity as of such date.

Acreage and Ownership

GJF

The following figures sets forth information relating
to our acreage for its working interests as of December 31, 2025:

We own 100% working interests that is subject to a 23.1% weighted average
net royalty interest across its 13,700 gross acres as of December 31, 2025. For information regarding the impact of lease expirations
on our interests, please see “Risks Related to Our Business.” All of our 13,700 acres are held by production and or
not under any mandatory lease expiration.

EON’s leasehold is 100% operated through
its wholly owned subsidiary LH Operating and 100% of its 13,700 gross acre leasehold is HBP. The leasehold is comprised of 23 total
leases, 20 BLM and 3 NM State leases. Ninety-seven percent of its leasehold classified as PDP has title opinion coverage. For regulatory
purposes, the current producing reservoirs, 7R, Queen, Grayburg, and San Andres, are considered a single, unitized pool (“pool”)
for all current PDP reserves and PDNP reserves. No regulatory approval is required prior to performing workovers on existing wells within
the pool (i.e., perforations, fracking, or acidizing, etc.).

13

LH Operating, LLC was created to solely manage
this asset on behalf of Pogo. LH Operating has performed its duties for two (2) years without any known liabilities, and are in good
standing with regulatory agencies. LH Operating is fully bonded to operate in New Mexico.

SJF

The SJF is located in Lea County, New Mexico in the Central Basin of
the Permian Basin, the most prolific oil-producing region in the United States. The SJF is located a short distance from our GJF
in Eddy County, New Mexico allowing for efficiencies of scale. We own 94% working interests that is subject to a 18% weighted average
net royalty interest across its 5,360 gross acres as of December 31, 2025. The property includes 5,360 leasehold acres with a total of
208 wells comprised of half being oil producing and the other half being water injection wells. There are 19 active oil producing wells.

Leasehold acreage

The following table sets forth certain information
regarding the total developed and undeveloped acreage in which we owned an interest as of December 31, 2025.

Developed Acres

Undeveloped Acres

Gross

Net

Gross

Net

Grayburg-Jackson

13,700

13,700

—

—

South Justis

5,360

5,360

Total

19,060

19,060

All leasehold acreage of EON is considered to
be “Developed Acres” because completed producing wells or wells capable of producing in economic quantities are located throughout
the entirety of the acreage such that the acreage allocated to such wells for production on a spacing, allocated, unitized or pooled basis
comprise the entire 19,060 acres leased by EON. The interests of EON in the oil, gas and other minerals in “Developed Acres”
are, or may be, composed of one or multiple stratigraphic zones producing or capable of producing oil and gas in economic quantities.

The leasehold of EON has undergone development
activities, including drilling, completion, and production operations in the Grayburg/San Andres zones (“legacy zones”) and/or
the Seven Rivers waterflood zones. As a result, there are no remaining leasehold portions that require initial development. EON has identified
new potential proved undeveloped reserves within the incremental waterflood zone of the Seven Rivers. EON intends to develop and produce
the Seven Rivers zone comprised of approximately 1,677 acres underlying a portion of the Developed Acres including, without limitation,
infield drilling or perforation and recompletion of existing wells.

Regulation

The following disclosure describes regulations
directly associated with E&P companies who are classified with state and federal regulatory agencies as Operator of record of crude
oil and natural gas properties, including EON.

Crude oil and natural gas operations are subject
to various types of legislation, regulation and other legal requirements enacted by governmental authorities. This legislation and regulation
affecting the crude oil and natural gas industry is under constant review for amendment or expansion. Some of these requirements carry
substantial penalties for failure to comply. The regulatory burden on the crude oil and natural gas industry increases the cost of doing
business.

Environmental Matters

Crude oil and natural
gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials
into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations
have the potential to impact production on the properties in which EON owns working interest, which could materially adversely affect
its business and its prospects. Numerous federal, state and local governmental agencies, such as the EPA, issue regulations that often
require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in
injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences,
restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling
and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically
sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging
abandoned wells or closing earthen pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require
that additional pollution controls be installed and impose substantial liabilities for pollution resulting from operations. The strict,
joint and several liability nature of such laws and regulations could impose liability upon the Operator of record regardless of fault.
Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage
allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. Changes in environmental
laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage,
transport, disposal or cleanup requirements could materially adversely affect our business and prospects.

14

Non-Hazardous and Hazardous Waste

The Resource Conservation and Recovery Act (“RCRA”),
and comparable state statutes and regulations promulgated thereunder, affect crude oil and natural gas exploration, development, and production
activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and
non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in
conjunction with their own, more stringent requirements. Administrative, civil and criminal penalties can be imposed for failure to comply
with waste handling requirements. Although most wastes associated with the exploration, development and production of crude oil and natural
gas are exempt from regulation as hazardous wastes under RCRA, these wastes typically constitute nonhazardous solid wastes that are subject
to less stringent requirements. From time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal
standards for nonhazardous wastes, including crude oil and natural gas wastes. Moreover, it is possible that some wastes generated in
connection with exploration and production of oil and gas that are currently classified as nonhazardous may, in the future, be designated
as “hazardous wastes,” resulting in the wastes being subject to more rigorous and costly management and disposal requirements.
On May 4, 2016, a coalition of environmental groups filed a lawsuit against EPA in the U.S. District Court for the District
of Columbia for failing to update its RCRA Subtitle D criteria regulations governing the disposal of certain crude oil and natural gas
drilling wastes. In December 2016, EPA and the environmental groups entered into a consent decree to address EPA’s alleged
failure. In response to the consent decree, in April 2019, the EPA signed a determination that revision of the regulations is not
necessary at this time. However, any changes in the laws and regulations could have a material adverse effect on the Operator of record
(EON) of its properties’ capital expenditures and operating expenses, which in turn could affect production from the acreage underlying
our working interests and adversely affect our business and prospects.

Remediation

The Comprehensive Environmental Response, Compensation,
and Liability Act (“CERCLA”) and analogous state laws generally impose strict, joint and several liability, without regard
to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous
substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner
or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous
substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” may be subject
to strict, joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed
of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources
and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file
claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In addition,
the risk of accidental spills or releases could expose EON’s working interests underlying its leasehold acreage to significant liabilities
that could have a material adverse effect on the operators’ businesses, financial condition and results of operations. Liability
for any contamination under these laws could require us to make significant expenditures to investigate and remediate such contamination
or attain and maintain compliance with such laws and may otherwise have a material adverse effect on their results of operations, competitive
position or financial condition.

Water Discharges

The Clean Water Act (“CWA”), the
SDWA, the Oil Pollution Act of 1990 (“OPA”), and analogous state laws and regulations promulgated thereunder
impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other
crude oil and natural gas wastes, into regulated waters. The definition of regulated waters has been the subject of significant
controversy in recent years. The EPA and U.S. Army Corps of Engineers published a revised definition on January 18, 2023,
which has been challenged in court. To the extent any future rule expands the scope of jurisdiction, it may impose greater
compliance costs or operational requirements on EON as the Operator of record. The discharge of pollutants into regulated waters is
prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The CWA and regulations implemented
thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless
authorized by an appropriately issued permit. In addition, spill prevention, control and countermeasure plan requirements under
federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in
the event of a petroleum hydrocarbon tank spill, rupture or leak. Production EPA has also adopted regulations requiring certain
crude oil and natural gas facilities to obtain individual permits or coverage under general permits for storm water discharges, and
in June 2016, the EPA finalized effluent limitation guidelines for the discharge of wastewater from hydraulic fracturing.

15

The OPA is the primary federal law for crude oil
spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into regulated
waters, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must
develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential
environmental cleanup and restoration costs. The OPA subject’s owners of facilities to strict, joint and several liability for all
containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding
to a release of crude oil into surface waters.

Noncompliance with the CWA, the SDWA, or the OPA
may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations, for the Operator of record
(EON) underlying its leasehold working interest.

Air Emissions

The Clean Air Act (“CAA”), and comparable
state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements.
The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New
facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits
and incur capital costs in order to remain in compliance. For example, in June 2016, the EPA established criteria for aggregating
multiple small surface sites into a single source for air quality permitting purposes, which could cause small facilities, on an aggregate
basis, to be deemed a major source subject to more stringent air permitting processes and requirements. These laws and regulations may
increase the costs of compliance for crude oil and natural gas producers and impact production of the acreage underlying EON’s working
interests. In addition, federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with
air permits or other requirements of the federal CAA and associated state laws and regulations. Moreover, obtaining or renewing permits
has the potential to delay the development of crude oil and natural gas projects.

Climate Change

Climate change continues to attract considerable
public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international,
national, regional and state levels of government to monitor and limit emissions of carbon dioxide, methane and other GHGs. These efforts
have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly
limit GHG emissions from certain sources.

In the United States,
no comprehensive climate change legislation has been implemented at the federal level. However, President Biden has highlighted addressing
climate change as a priority of his administration and has issued several executive orders addressing climate change. Moreover, following
the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the CAA, the EPA has adopted regulations that, among
other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the
monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and
together with the DOT, implementing GHG emissions limits on vehicles manufactured for operation in the United States. The regulation
of methane from oil and gas facilities has been subject to uncertainty in recent years. In September 2020, the Trump Administration
revised regulations initially promulgated in June 2016 to rescind certain methane standards and remove the transmission and storage
segments from the source category for certain regulations. However, subsequently, the U.S. Congress approved, and President Biden
signed into law, a resolution under the Congressional Review Act to repeal the September 2020 revisions to the methane standards,
effectively reinstating the prior standards. Additionally, in November 2021, the EPA issued a proposed rule that, if finalized, would
establish new source and first-time existing source standards of performance for methane and volatile organic compound emissions
for oil and gas facilities. Operators of affected facilities will have to comply with specific standards of performance to include leak
detection using optical gas imaging and subsequent repair requirement, and reduction of emissions by 95% through capture and control systems.
The EPA issued supplemental rules regarding methane emissions on December 6, 2022. The IRA established the Methane Emissions Reduction
Program, which imposes a charge on methane emissions from certain petroleum and natural gas facilities, which may apply to our operations
in the future and may require us to expend material sums. We cannot predict the scope of any final methane regulatory requirements or
the cost to comply with such requirements. However, given the long-term trend toward increasing regulation, future federal GHG regulations
of the oil and gas industry remain a significant possibility.

16

Separately, various states and groups of states
have adopted or are considering adopting legislation, regulation or other regulatory initiatives that are focused on such areas as GHG
cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. For example, New Mexico has adopted
regulations to restrict the venting or flaring of methane from both upstream and midstream operations. At the international level, the
United Nations-sponsored “Paris Agreement” requires member states to submit non-binding, individually-determined reduction
goals known as Nationally Determined Contributions every five years after 2020. President Biden recommitted the United States
to the Paris Agreement and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below
2005 levels by 2030; however, in January 2025, President Trump withdrew the United States from the Paris Agreement. The full impact of
these actions cannot be predicted at this time.

Governmental, scientific, and public concern over
the threat of climate change arising from GHG emissions has resulted in increasing political risks in the United States, including
climate change related pledges made by certain candidates now in public office.

There are also increasing financial risks for
fossil fuel producers as shareholders currently invested in fossil-fuel energy companies may elect in the future to shift some or
all of their investments into non-fossil fuel related sectors. Institutional lenders who provide financing to fossil fuel energy
companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil
fuel energy companies. For example, at COP26, GFANZ announced that commitments from over 450 firms across 45 countries had resulted in
over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants
to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions
by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding
provided to the fossil fuel sector.

The adoption and implementation of new or more
stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards
for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural
gas or generate the GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for oil
and natural gas, which could reduce the profitability of EON’s working interests. Additionally, political, litigation and financial
risks may result in EON restricting or cancelling production activities, incurring liability for infrastructure damages as a result of
climatic changes, or impairing their ability to continue to operate in an economic manner, which also could reduce the profitability of
EON’s working interests. One or more of these developments could have a material adverse effect on EON’s business, financial
condition and results of operation.

Climate change may
also result in various physical risks, such as the increased frequency or intensity of extreme weather events or changes in meteorological
and hydrological patterns, that could adversely impact our operations and EON’s supply chains. Such physical risks may result in
damage to EON’s facilities or otherwise adversely impact our operations, such as if they become subject to water use curtailments
in response to drought, or demand for their products, such as to the extent warmer winters reduce the demand for energy for heating purposes.
Extreme weather conditions can interfere with production and increase costs and damage resulting from extreme weather may not be fully
insured. However, at this time, EON is unable to determine the extent to which climate change may lead to increased storm or weather hazards
affecting its business.

Regulation of Hydraulic Fracturing

Hydraulic fracturing is an important and common
practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand
and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing operations
have historically been overseen by state regulators as part of their crude oil and natural gas regulatory programs.

However, several agencies have asserted regulatory
authority over certain aspects of the process. For example, in August 2012, the EPA finalized regulations under the federal CAA that
establish new air emission controls for crude oil and natural gas production and natural gas processing operations. Federal regulation
of methane emissions from the oil and gas sector has been subject to substantial controversy in recent years.

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In addition, governments have studied the environmental
aspects of hydraulic fracturing practices. These studies, depending on their degree of pursuit and whether any meaningful results are
obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory authorities. For example,
in December 2016, the EPA issued its final report on a study it had conducted over several years regarding the effects of hydraulic
fracturing on drinking water sources. The final report, concluded that “water cycle” activities associated with hydraulic
fracturing may impact drinking water under certain limited circumstances.

Several states have adopted, or are considering
adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the
composition of hydraulic fracturing fluids. For example, the Railroad Commission of Texas has previously issued a “well integrity
rule,” which updates the requirements for drilling, putting pipe down, and cementing wells. The rule also includes new testing and
reporting requirements, such as: (i) the requirement to submit cementing reports after well completion or after cessation of drilling,
whichever is later; and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well
integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating
the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular or prohibit the performance
of well drilling in general or hydraulic fracturing in particular.

State and federal regulatory agencies recently
have focused on a possible connection between the hydraulic fracturing related activities, particularly the disposal of produced water
in underground injection wells, and the increased occurrence of seismic activity. When caused by human activity, such events are called
induced seismicity. In some instances, operators of injection wells in the vicinity of seismic events have been ordered to reduce injection
volumes or suspend operations. Some state regulatory agencies, including those in Colorado, Ohio, Oklahoma and Texas, have modified their
regulations to account for induced seismicity. For example, in October 2014, the Railroad Commission published a new rule governing
permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events
occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating
to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the produced water
or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to
be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the permit application or existing operating
permit for that well. The Railroad Commission of Texas has used this authority to deny permits for waste disposal wells. In some instances,
regulators may also order that disposal wells be shut in. In late 2021, the Railroad Commission of Texas issued a notice to operators
of disposal wells in the Midland area, to reduce saltwater disposal well actions and provide certain data to the commission. Separately,
in November 2021, New Mexico implemented protocols requiring operators to take various actions within a specified proximity of certain
seismic activity, including a requirement to limit injection rates if a seismic event is of a certain magnitude. As a result of these
developments, EON as the Operator of record may be required to curtail operations or adjust development plans, which may adversely impact
EON’s business.

The USGS has identified
six states with the most significant hazards from induced seismicity, including New Mexico, Oklahoma and Texas. In addition, a number
of lawsuits have been filed, most recently in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties
or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and
restrictions on the use of injection wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional
costs and restrictions on EON’s properties and on their waste disposal activities.

If new laws or regulations that significantly
restrict hydraulic fracturing and related activities are adopted, such laws could make it more difficult or costly to perform fracturing
to stimulate production from tight formations. In addition, if hydraulic fracturing is further regulated at the federal or state level,
fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction
specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant
permitting delays and potential increases in costs. Such legislative changes could cause EON to incur substantial compliance costs, and
compliance or the consequences of any failure to comply could have a material adverse effect on EON’s financial condition and results
of operations. At this time, it is not possible to estimate the impact on EON’s business of newly enacted or potential federal or
state legislation governing hydraulic fracturing.

Endangered Species Act

The ESA restricts activities that may affect endangered
and threatened species or their habitats. The designation of previously unidentified endangered or threatened species could cause E&P
operators to incur additional costs or become subject to operating delays, restrictions or bans in the affected areas. Recently, there
have been renewed calls to review protections currently in place for the dunes sagebrush lizard, whose habitat includes parts of the Permian
Basin, and to reconsider listing the species under the ESA. For example, in October 2019 environmental groups filed a lawsuit
against the FWS seeking to compel the agency to list the species under the ESA, and in July 2020, FWS agreed to initiate a 12-month review
to determine whether listing the species was warranted, which determination remains outstanding. Additionally, in June 2021, the
FWS proposed to list two distinct population sections of the Lesser Prairie Chicken, including one in portions of the Permian Basin, under
the ESA, which was finalized on November 25, 2022. To the extent species are listed under the ESA or similar state laws, or
previously unprotected species are designated as threatened or endangered in areas where EON’s properties are located, operations
on those properties could incur increased costs arising from species protection measures and face delays or limitations with respect to
production activities thereon.

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Employee Health and Safety

Operations on EON’s properties are subject
to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”) and
comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard,
the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act, and
comparable state statutes require that information be maintained concerning hazardous materials used or produced in operations and that
this information be provided to employees, state and local government authorities and citizens.

Other Regulation of the Crude Oil and Natural
Gas Industry

The crude oil and natural gas industry is extensively
regulated by numerous federal, state and local authorities. Legislation affecting the crude oil and natural gas industry is under constant
review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal
and state, are authorized by statute to issue rules and regulations that are binding on the crude oil and natural gas industry and its
individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the crude oil and
natural gas industry increases the cost of doing business, these burdens generally do not affect us any differently or to any greater
or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

The availability, terms and conditions and cost
of transportation significantly affect sales of crude oil and natural gas. The interstate transportation of crude oil and natural gas
and the sale for resale of natural gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate
transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal
and state regulations govern the price and terms for access to crude oil and natural gas pipeline transportation. FERC’s regulations
for interstate crude oil and natural gas transmission in some circumstances may also affect the intrastate transportation of crude oil
and natural gas.

EON cannot predict whether new legislation to
regulate crude oil and natural gas might be proposed, what proposals, if any, might actually be enacted by the U.S. Congress or the
various state legislatures, and what effect, if any, the proposals might have on its operations. Sales of crude oil and condensate are
not currently regulated and are made at market prices.

Drilling and Production

The operations on EON’s properties are subject
to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling
of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which EON operates also
regulate one or more of the following:

● the
location of wells;

● the
method of drilling and casing wells;

● the
timing of construction or drilling activities, including seasonal wildlife closures;

● the
rates of production or “allowables”;

● the
surface use and restoration of properties upon which wells are drilled;

● the
plugging and abandoning of wells;

● and
notice to, and consultation with, surface owners and other third parties.

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State laws regulate the size and shape of drilling
and spacing units or proration units governing the pooling of crude oil and natural gas properties. Some states allow forced pooling or
integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced
pooling or unitization may be implemented by third parties and may reduce EON’s interest in the unitized properties. In addition,
state conservation laws establish maximum rates of production from crude oil and natural gas wells, generally prohibit the venting or
flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount
of crude oil and natural gas that the EON’s properties can produce from EON’s wells or limit the number of wells or the locations
at which can be drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of
crude oil and natural gas within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation,
but EON cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of
crude oil and natural gas that may be produced from our wells, negatively affect the economics of production from these wells or to limit
the number of locations operators can drill.

Federal, state and local regulations provide detailed
requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration
in areas where EON operates. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for
plugging and abandonment, decommissioning and site restoration. Although the U.S. Army Corps of Engineers does not require bonds
or other financial assurances, some state agencies and municipalities do have such requirements.

Natural Gas Sales and Transportation

FERC has jurisdiction over the transportation
and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”)
and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted which have resulted in the complete
removal of all price and non-price controls for sales of domestic natural gas sold in “first sales.”

Under the Energy Policy Act of 2005,
FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including
the ability to assess substantial civil penalties. FERC also regulates interstate natural gas transportation rates and service conditions
and establishes the terms under which EON’s properties may use interstate natural gas pipeline capacity, as well as the revenues
received for release of natural gas pipeline capacity. Interstate pipeline companies are required to provide nondiscriminatory transportation
services to producers, marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company.
FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits
all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines.

Gathering service, which occurs upstream of jurisdictional
transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering
facilities from regulation by FERC under the NGA. FERC has in the past reclassified certain jurisdictional transmission facilities
as non-jurisdictional gathering facilities, which may increase the operators’ costs of transporting gas to point-of-sale locations.
This may, in turn, affect the costs of marketing natural gas that EON’s properties produce.

Historically, the natural gas industry was more
heavily regulated; therefore, we cannot guarantee that the regulatory approach currently pursued by FERC and the U.S. Congress will
continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on its natural gas
related activities.

Crude Oil Sales and Transportation

Crude oil sales are affected by the availability,
terms and cost of transportation. The transportation of crude oil in common carrier pipelines is also subject to rate regulation. FERC
regulates interstate crude oil pipeline transportation rates under the Interstate Commerce Act and intrastate crude oil pipeline transportation
rates are subject to regulation by state regulatory commissions. The basis for intrastate crude oil pipeline regulation, and the degree
of regulatory oversight and scrutiny given to intrastate crude oil pipeline rates, varies from state to state. Insofar as effective interstate
and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of crude oil transportation rates
will not affect its operations in any materially different way than such regulation will affect the operations of its competitors.

Further, interstate and intrastate common carrier
crude oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer
service to all similarly situated shippers requesting service on the same terms and under the same rates. When crude oil pipelines operate
at full capacity, access is governed by pro-rationing provisions set forth in the pipelines’ published tariffs. Accordingly,
EON believes that access to crude oil pipeline transportation services of EON’s properties will not materially differ from our competitors’
access to crude oil pipeline transportation services.

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State Regulation

New Mexico regulates the drilling for, and the
production, gathering and sale of, crude oil and natural gas, including imposing severance taxes and requirements for obtaining drilling
permits. New Mexico currently imposes a 3.75% severance tax on the market value of crude oil and natural gas production as well as other
production taxes for conservation, schools, ad valorem, and equipment. Combined, these taxes amount to 8-9% tax on market value of
crude and natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the
prevention of waste of crude oil and natural gas resources.

States may regulate rates of production and may
establish maximum daily production allowables from crude oil and natural gas wells based on market demand or resource conservation, or
both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but EON cannot assure you that they
will not do so in the future. Should direct economic regulation or regulation of wellhead prices by the states increase, this could limit
the amount of crude oil and natural gas that may be produced from wells on EON’s properties and the number of wells or locations
EON’s properties can drill.

The petroleum industry is also subject to compliance
with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment
opportunity. EON does not believe that compliance with these laws will have a material adverse effect on its business.

Title to Properties

Prior to completing an acquisition of a target
or working interests, EON performs a title review on each tract to be acquired. EON’s title review is meant to confirm the working
interests owned by a prospective seller, the property’s lease status and royalty amount as well as encumbrances or other related
burdens. As a result, title examinations have been obtained on substantially all of EON’s properties.

In addition to EON’s initial title work,
EON often will conduct a thorough title examination prior to leasing any new acres, and/or drilling a well. Should any further title work
uncover any further title defects, EON will perform curative work with respect to such defects. EON generally will not commence drilling
operations on a property until any material title defects on such property have been cured.

EON believes that
the title to its assets is satisfactory in all material respects. Although title to these properties is in some cases subject to encumbrances,
such as customary royalty interest generally retained in connection with the acquisition of crude oil and gas interests, non-participating royalty
interests and other burdens, easements, restrictions or minor encumbrances customary in the crude oil and natural gas industry, EON believes
that none of these encumbrances will materially detract from the value of these properties or from its interest in these properties.

Competition

The crude oil and natural gas business is highly
competitive; we primarily compete with companies for the acquisition of targets with high percentage of working interests underlying
crude oil and natural gas leases. Many of our competitors not only own and acquire working interests but also explore for and produce
crude oil and natural gas and, in some cases, carry on midstream and refining operations and market petroleum and other products on a
regional, national or worldwide basis. By engaging in such other activities, our competitors may be able to develop or obtain information
that is superior to the information that is available to us. In addition, certain of our competitors may possess financial or other resources
substantially larger than EON possesses. Our ability to acquire additional working interests and properties and to discover reserves in
the future will be dependent upon its ability to evaluate and select suitable properties and to consummate transactions in a highly competitive
environment.

In addition, crude oil and natural gas products
compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity,
coal, and fuel oils. Changes in the availability or price of crude oil and natural gas or other forms of energy, as well as business conditions,
conservation, legislation, regulations, and the ability to convert to alternate fuels and other forms of energy may affect the demand
for crude oil and natural gas.

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Seasonality of Business

Weather conditions affect the demand for, and
prices of, natural gas and can also delay drilling activities, disrupting Our overall business plans. Additionally, EON’s properties
are located in areas adversely affected by seasonal weather conditions, primarily in the winter and spring. During periods of heavy snow,
ice or rain, EON may be unable to move their equipment between locations, thereby reducing its ability to operate EON’s wells, reducing
the amount of crude oil and natural gas produced from the wells on EON’s properties during such times. Additionally, extended drought
conditions in the areas in which EON’s properties are located could impact its ability to source sufficient water or increase the
cost for such water. Furthermore, demand for natural gas is typically higher during the winter, resulting in higher natural gas prices
for EON’s natural gas production during its first and fourth quarters. Certain natural gas users utilize natural gas storage facilities
and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal
weather conditions can limit drilling and producing activities and other crude oil and natural gas operations in EON’s operating
areas. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of the results
that it may realize on an annual basis.

Employees and Human Working Capital

We have salaried and regular pay employees in the field as well as
management at our corporate offices. As of December 31, 2025, we employed 14 full-time salaried and regular pay field individuals
under no ongoing employment contracts who provided direct support to EON’s operations. As of December 31, 2025, we employed 6 full-time salaried
employees at our corporate offices, all of which have ongoing employment contracts. None of these employees are covered by collective
bargaining agreements.

Human capital management is critical to our ongoing
business success, which requires investing in our people. Our aim is to create a highly engaged and motivated workforce where employees
are inspired by leadership, engaged in purpose-driven, meaningful work and have opportunities for growth and development. We are an equal
opportunity employer and we are fundamentally committed to creating and maintaining a work environment in which employees are treated
with respect and dignity. All human resources policies, practices and actions related to hiring, promotion, compensation, benefits and
termination are administered in accordance with the principles of equal employment opportunity and other legitimate criteria without regard
to race, color, religion, sex, sexual orientation, gender expression or identity, ethnicity, national origin, ancestry, age, mental or
physical disability, genetic information, any veteran status, any military status or application for military service, or membership in
any other category protected under applicable laws.

An effective approach to human capital management
requires that we invest in talent, development, culture and employee engagement. We aim to create an environment where our employees are
encouraged to make positive contributions and fulfill their potential.

Our Board of Directors is also actively involved
in reviewing and approving executive compensation, selections and succession plans so that we have leadership in place with the requisite
skills and experience to deliver results the right way.

Emerging Growth Company

We are an “emerging growth company,”
as defined in the JOBS Act. As such, we are eligible to 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, reduced disclosure obligations
regarding executive compensation in our periodic reports and proxy statements, and exemptions from the requirements of holding a non-binding advisory
vote on executive compensation and stockholder approval of any golden parachute payments not previously approved. If some investors find
our securities less attractive as a result, there may be a less active trading market for our securities and the prices of our securities
may be more volatile.

In addition, Section 107 of the JOBS Act
also provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B)
of the Securities Act for complying with new or revised accounting standards. In other words, an “emerging growth company”
can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We intend to
take advantage of the benefits of this extended transition period. Accordingly, the information we provide to you may be different than
you might get from other public companies in which you hold securities.

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We will remain an emerging growth company until
the earliest of (i) the last day of the fiscal year following the fifth anniversary of the closing of our Initial Public Offering,
or December 31, 2027, (ii) the last day of the fiscal year in which we have total annual gross revenue of at least $1.07 billion,
(iii) the last day of the fiscal year in which we are deemed to be a “large accelerated filer” as defined in Rule 12b-2 under
the Securities Exchange Act of 1934, as amended (the “Exchange Act”), which would occur if the market value of our common
stock held by non-affiliates exceeded $700.0 million as of the last business day of the second fiscal quarter of such year or
(iv) the date on which we have issued more than $1.00 billion in non-convertible debt securities during the prior three-year period.

Facilities

We currently maintain our executive offices at
3730 Kirby Drive, Suite 1200, Houston, Texas 77098. We recently leased a space at 10810 Old Katy Rd, Katy, TX 77494 just beyond the Houston
city limits for our engineering and geological center. The cost for the two spaces combined is approximately $3,000 per month. We consider
our current office space adequate for our current operations.