UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the fiscal year ended December 31, 2025

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

For the transition period from                      to                     

EON Resources, Inc.

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code: (713) 834-1145

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

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ☐ No ☒

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

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

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

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

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

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

The aggregate market value of the voting common equity stock held by non-affiliates of the Registrant was approximately $11.2 million based on the last sale price on June 30, 2025. 

As of September 25, 2026, 55,824,861 shares of Class A Common Stock, par value $0.0001 per share, and no shares of Class B Common Stock, par value $0.0001 per share, were issued and outstanding.

TABLE OF CONTENTS 

CERTAIN TERMS

Unless otherwise stated in this Annual Report on Form 10-K (this “Report”), or the context otherwise requires, references to:

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Some statements contained in this Report may constitute “forward-looking statements” for purposes of United States federal securities laws. Our forward-looking statements include, but are not limited to, statements regarding our or our management team’s expectations, hopes, beliefs, intentions or strategies regarding the future. In addition, any statements that refer to projections, forecasts or other characterizations of future events or circumstances, including any underlying assumptions, are forward-looking statements. The words “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “intends,” “may,” “might,” “plan,” “possible,” “potential,” “predict,” “project,” “should,” “would” and similar expressions may identify forward-looking statements, but the absence of these words does not mean that a statement is not forward-looking. Forward-looking statements in this report may include, for example, statements about:

The forward-looking statements contained in this Report are based on our current expectations and beliefs concerning future developments and their potential effects on us. There can be no assurance that future developments affecting us will be those that we have anticipated. These forward-looking statements involve a number of risks, uncertainties (some of which are beyond our control) or other assumptions that may cause actual results or performance to be materially different from those expressed or implied by these forward-looking statements. These risks and uncertainties include, but are not limited to, those factors described under the heading “Risk Factors.” Should one or more of these risks or uncertainties materialize, or should any of our assumptions prove incorrect, actual results may vary in material respects from those projected in these forward-looking statements. We undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws. These risks and others described under “Risk Factors” may not be exhaustive.

By their nature, forward-looking statements involve risks and uncertainties because they relate to events and depend on circumstances that may or may not occur in the future. We caution you that forward-looking statements are not guarantees of future performance and that our actual results of operations, financial condition and liquidity, and developments in the industry in which we operate may differ materially from those made in or suggested by the forward-looking statements contained in this Report. In addition, even if our results or operations, financial condition and liquidity, and developments in the industry in which we operate are consistent with the forward-looking statements contained in this Report, those results or developments may not be indicative of results or developments in subsequent periods.

SUMMARY OF SIGNIFICANT RISKS AFFECTING OUR COMPANY

Our business is subject to multiple risks and uncertainties, as more fully described in “Risk Factors” and elsewhere in this Report. We urge you to read the disclosures under the caption “Risk Factors” and this Report in full. Our significant risks may be summarized as follows:

PART I

ITEM 1. BUSINESS

Overview

EON Resources, Inc. (the “Company” or “EON”), was incorporated in Delaware as a blank check company formed for the purpose of effecting a merger, capital stock exchange, asset acquisition, stock purchase, reorganization or similar business combination with one or more businesses or entities. Prior to closing the Purchase, our efforts were limited to organizational activities, completion of an initial public offering and the evaluation of possible business combinations. On February 15, 2022, we consummated the Initial Public Offering of 7,500,000 units (the “Units”), at $10.00 per Unit, generating proceeds of $75,000,000. Additionally, the underwriter fully exercised its option to purchase 1,125,000 additional Units, for which we received cash proceeds of $11,250,000. Simultaneously with the closing of the Initial Public Offering, we consummated the sale of 505,000 private placement units at a price of $10.00 per unit generating proceeds of $5,050,000 in a private placement to our Sponsor and EF Hutton (formerly Kingswood Capital Markets) (“EF Hutton”). On April 4, 2022, the Units separated into Class A Common Stock and warrants, and ceased trading. On April 4, 2022, the Class A Common Stock and warrants commenced trading on the NYSE American. On September 16, 2024, the Company filed a Certificate of Amendment (the “Certificate of Amendment”) to its Amended and Restated Certificate of Incorporation with the Secretary of State of the State of Delaware to change the Company’s name from “HNR Acquisition Corp” to “EON Resources, Inc.”, effective on September 17, 2024.

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:

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”.

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.

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).

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.

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. 

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.

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.

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:

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.

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. 

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):

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:

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):

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.

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:

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.

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.).

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.

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. 

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.

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. 

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.

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.

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:

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.

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.

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.

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.

ITEM 1A. RISK FACTORS

An investment in our securities involves a high degree of risk. You should consider carefully all of the risks described below, together with the other information contained in this Report, before making a decision to invest in our securities. If any of the following events occur, our business, financial condition and operating results may be materially adversely affected. In that event, the trading price of our securities could decline, and you could lose all or part of your investment.

Risks Related to Our Business

There is substantial doubt about our ability to continue as a “going concern.”

As of December 31, 2025, we had $375,036 in cash and a working capital deficit of $21,814,454. Further, we had negative cash flow from operations of $7,645,418 for the year ended December 31, 2025. These factors raise substantial doubt about our ability to continue as a going concern. Management’s plans to alleviate this substantial doubt include improving profitability through streamlining costs, maintaining active hedge positions for its proven reserve production, and the issuance of additional shares of Class A Common Stock through the ELOC Purchase Agreement with White Lion, which can fund our operations and production growth, and be used to reduce our liabilities. While management believes that its plans and the overall outlook of the oil and gas industry sufficiently alleviate the factors raising substantial doubt about its ability to continue as a going concern, there can be no assurance of success.

Our producing properties are located in the Permian Basin, making it vulnerable to risks associated with operating in a single geographic area.

All of our producing properties are currently geographically concentrated in the Permian Basin. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of the processing or transportation of crude oil and natural gas. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic crude oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of EON’s portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on its results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.

As a result of our exclusive focus on the Permian Basin, it may be less competitive than other companies in bidding to acquire assets that include properties both within and outside of that basin. Although we are currently focused on the Permian Basin, it may from time to time evaluate and consummate the acquisition of asset packages that include ancillary properties outside of that basin, which may result in the dilution of its geographic focus. 

Title to the properties in which we have an interest may be impaired by title defects.

EON is not required to, and under certain circumstances it may elect not to, incur the expense of retaining lawyers to examine the title to its operating interests. In such cases, we would rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before acquiring an operating interest. The existence of a material title deficiency can render an interest worthless and can materially adversely affect our results of operations, financial condition and cash flows. No assurance can be given that EON will not suffer a monetary loss from title defects or title failure. Additionally, undeveloped acreage has a greater risk of title defects than developed acreage. If there are any title defects in properties in which we holds an interest, it may suffer a financial loss.

We depend on various services for the development and production activities on the properties it operates. Substantially all our revenue is derived from these producing properties. A reduction in the expected number of wells to be developed on EON’s acreage by or the failure of EON to develop and operate the wells on its acreage could have an adverse effect on its results of operations and cash flows adequately and efficiently.

Our assets consist primarily of operating interests. The failure of the Company to perform operations adequately or efficiently or to act in ways that are not in our best interests could reduce production and revenues. Additionally, certain investors have requested that operators adopt initiatives to return capital to investors, which could also reduce the capital available to us for investment in development and production activities. Moreover, should a low commodity price environment incur, we may also opt to reduce development activity that could further reduce production and revenues.

If production on our acreage decreases due to decreased development activities, because of a low commodity price environment, limited availability of development capital, production-related difficulties or otherwise, our results of operations may be adversely affected. EON is not obligated to undertake any development activities other than those required to maintain their leases on our acreage. In the absence of a specific contractual obligation, any development and production activities will be subject to their reasonable discretion (subject to certain implied obligations to develop imposed by the laws of some states). EON could determine to develop wells on our acreage than is currently expected. The success and timing of development activities on our properties, depends on a number of factors that are largely outside of our control, including:

EON may elect not to undertake development activities, or may undertake these activities in an unanticipated fashion, which may result in significant fluctuations in EON’s results of operations and cash flows. Sustained reductions in production by EON on EON’s properties may also adversely affect EON’s results of operations and cash flows. Additionally, if EON were to experience financial difficulty, EON might not be able to pay invoices to continue its operations, which could have a material adverse impact on EON’s cash flows. 

Our future success depends on replacing reserves through acquisitions and the exploration and development activities.

Producing crude oil and natural gas wells are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future crude oil and natural gas reserves and our production thereof and our cash flows are highly dependent on the successful development and exploitation of our current reserves and its ability to successfully acquire additional reserves that are economically recoverable. Moreover, the production decline rates of our properties may be significantly higher than currently estimated if the wells on its properties do not produce as expected. We may also not be able to find, acquire or develop additional reserves to replace the current and future production of its properties at economically acceptable terms. If we are not able to replace or grow its oil and natural gas reserves, its business, financial condition and results of operations would be adversely affected.

Our failure to successfully identify, complete and integrate acquisitions of properties or businesses could materially and adversely affect its growth, results of operations and cash flows.

We depend, in part, on acquisitions to grow its reserves, production and cash flows. Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses and seismic data, and other information, the results of which are often inconclusive and subject to various interpretations. The successful acquisition of properties requires an assessment of several factors, including:

The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that it believes to be generally consistent with industry practices, given the nature of its interests. Our review will not reveal all existing or potential problems, nor will it permit it to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Inspections are often not performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Even if we do identify attractive acquisition opportunities, it may not be able to complete the acquisition or do so on commercially acceptable terms. Unless we further develop our existing properties, we will depend on acquisitions to grow our reserves, production and cash flow.

There is intense competition for acquisition opportunities in our industry. Competition for acquisitions may increase the cost of, or cause us to refrain from, completing acquisitions. Additionally, acquisition opportunities vary over time. Our ability to complete acquisitions is dependent upon, among other things, our ability to obtain debt and equity financing and, in some cases, regulatory approvals. Further, these acquisitions may be in geographic regions in which EON does not currently hold assets, which could result in unforeseen operating difficulties. In addition, if we acquire interests in new states, it may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on EON and its management, cause it to expend additional time and resources in compliance activities and increase its exposure to penalties or fines for non-compliance with such additional legal requirements. Further, the success of any completed acquisition will depend on our ability to effectively integrate the acquired business into its existing business. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, potential future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions.

No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired assets into its existing operations successfully or to minimize any unforeseen difficulties could materially and adversely affect its financial condition, results of operations and cash flows. The inability to effectively manage these acquisitions could reduce Our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact its growth, results of operations and cash flows.

We may acquire properties that do not produce as projected, and it may be unable to determine reserve potential, identify liabilities associated with such properties or obtain protection from sellers against such liabilities.

Acquiring crude oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not necessarily reveal all existing or potential problems. In the course of due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made. We may not be able to obtain contractual indemnities from the seller for liabilities created prior to its purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with its expectations.

Any acquisitions that EON completes will be subject to substantial risks.

Even if we make acquisitions that we believe will increase its cash generated from operations, these acquisitions may nevertheless result in a decrease in its cash flows. Any acquisition involves potential risks, including, among other things:

Our identified development activities are susceptible to uncertainties that could materially alter the occurrence or timing of our development activities.

The ability of the Company to perform development activities depends on a number of uncertainties, including the availability of capital, construction of and limitations on access to infrastructure, inclement weather, regulatory changes and approvals, crude oil and natural gas prices, costs, development activity results and the availability of water. Further, any identified potential development activities are in various stages of evaluation, ranging from wells that are ready to be developed to wells that require substantial additional interpretation. The use of technologies and the study of producing fields in the same area will not enable us to know conclusively prior to development activities whether crude oil and natural gas will be present or, if present, whether crude oil and natural gas will be present in sufficient quantities to be economically viable. Even if enough crude oil or natural gas exist, we may damage the potentially productive hydrocarbon-bearing formation or experience mechanical difficulties while performing development activities, possibly resulting in a reduction in production from the well or abandonment of the well. If EON performs additional development activities on wells that do not respond or they produce at quantities less than desired these wells may materially harm our business.

There is no guarantee that the conclusions we draw from available data and other wells near the EON acreage will be applicable to our development activities. Further, initial production rates reported by us in the areas in which ours reserves are located may not be indicative of future or long-term production rates. Additionally, actual production from wells may be less than expected. For example, a number of E&P operators have recently announced that newer wells drilled close in proximity to already producing wells have produced less oil and gas than forecast. Because of these uncertainties, EON does not know if the potential development activities that have been identified will ever be able to produce crude oil and natural gas from these or any other potential development activities. As such, the actual development activities of EON may materially differ from those presently identified, which could adversely affect our business, results of operation and cash flows. 

Acquisitions and development of our leases will require substantial capital, and our company may be unable to obtain needed capital or financing on satisfactory terms or at all.

The crude oil and natural gas industry is capital intensive. EON made substantial capital expenditures in connection with the acquisition and development of its properties. Our company may continue to make substantial capital expenditures in connection with the acquisition and development of properties. Our company will finance capital expenditures primarily with funding from cash generated by operations and borrowings under its revolving credit facility.

In the future, EON may need capital more than the amounts it retains in its business or borrows under its revolving credit facility. The level of borrowing base available under our revolving credit facility is largely based on its estimated proved reserves and its lenders’ price decks and underwriting standards in the reserve-based lending space and may be reduced to the extent commodity prices decrease and cause underwriting standards to tighten or the lending syndication market is not sufficiently liquid to obtain lender commitments to a full borrowing base in an amount appropriate for our assets. Furthermore, EON cannot assure you that it will be able to access other external capital on terms favorable to it or at all. For example, a significant decline in prices for crude oil and broader economic turmoil may adversely impact our ability to secure financing in the capital markets on favorable terms. Additionally, our ability to secure financing or access the capital markets could be adversely affected if financial institutions and institutional lenders elect not to provide funding for fossil fuel energy companies in connection with the adoption of sustainable lending initiatives or are required to adopt policies that have the effect of reducing the funding available to the fossil fuel sector. If EON is unable to fund its capital requirements, EON may be unable to complete acquisitions, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on its results of operation and free cash flow.

EON is also dependent on the availability of external debt, equity financing sources and operating cash flows to maintain its development program. If those financing sources are not available on favorable terms or at all, then EON expects the development of its properties to be adversely affected. If the development of our properties is adversely affected, then revenues from our operations may decline. If we issue additional equity securities or securities convertible into equity securities, existing stockholders will experience dilution and the new equity securities could have rights senior to those of our Class A Common Stock.

EON currently holds and plans to continue to enter hedging arrangements with respect to the production of crude oil, and possibly natural gas which is a smaller portion of the reserves. EON will mitigate the exposure to the impact of decreases in the prices by establishing a hedging plan and structure that protects the earnings to a reasonable level, and the debt service requirements.

EON holds and plan to continue to enter into hedging arrangements to establish, in advance, a price for the sale of the crude oil and possibly natural gas produced from its properties. The hedging plan and structure will be at a level to balance the debt service requirements and also allow EON to realize the benefit of any short-term increase in the price of crude oil and natural gas. A portion of the crude oil and natural gas produced from its properties will not be protected against decreases in the price of crude oil and natural gas, or prolonged periods of low commodity prices. Hedging arrangements may limit our ability to realize the benefit of rising prices and may result in hedging losses.

The intent of the hedging arrangements is to mitigate the volatility in its cash flows due to fluctuations in the price of crude oil and natural gas. However, these hedging activities may not be as effective as our company intends in reducing the volatility of its cash flows and, if entered into, are subject to the risks of the terms of the derivative instruments derivative contract, there may be a change in the expected differential between the underlying commodity price in the derivative instrument and the actual price received, our company’s hedging policies and procedures may not be properly followed and the steps our company takes to monitor its derivative financial instruments may not detect and prevent violations of its risk management policies and procedures, particularly if deception or other intentional misconduct is involved. Further, our company may be limited in receiving the full benefit of increases in crude oil as a result of these hedging transactions. The occurrence of any of these risks could prevent EON from realizing the benefit of a derivative contract.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of its reserves.

It is not possible to measure underground accumulation of crude oil and natural gas in an exact way. Crude oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of crude oil and natural gas and assumptions concerning future crude oil and natural gas prices, production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved reserves, projections of future production rates and the timing of development expenditures may turn out to be incorrect. Estimates of our proved reserves and related valuations as of December 31, 2025 and December 31, 2024 were prepared by Haas and Cobb. Haas and Cobb conducted a detailed review of 94% of our properties for the December 31, 2025 period and 100% of our properties for the December 31, 2024 period covered by its reserve report using information provided by EON. Over time, EON may make material changes to reserve estimates taking into account the results of actual drilling, testing and production and changes in prices. In addition, certain assumptions regarding future crude oil and natural gas prices, production levels and operating and development costs may prove incorrect. A substantial portion of our reserve estimates are made without the benefit of a lengthy production history, which are less reliable than estimates based on a lengthy production history. Any significant variance from these assumptions to actual figures could greatly affect our estimates of reserves and future cash generated from operations. Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of crude oil and natural gas that are ultimately recovered being different from its reserve estimates.

Furthermore, the present value of future net cash flows from our proved reserves is not necessarily the same as the current market value of its estimated reserves. In accordance with rules established by the SEC and the Financial Accounting Standards Board (the “FASB”), EON bases the estimated discounted future net cash flows from its proved reserves on the twelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month, and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor EON uses when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with EON or the crude oil and natural gas industry in general. 

Operating hazards and partially insured or uninsured risks may result in substantial losses to EON and any losses could adversely affect our results of operations and cash flows.

The operations of EON will be subject to all of the hazards and operating risks associated with drilling for and production of crude oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering, uncontrollable flows of crude oil and natural gas and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses and environmental hazards such as crude oil spills, natural gas leaks and ruptures or discharges of toxic gases. In addition, their operations will be subject to risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives. The occurrence of any of these events could result in substantial losses to EON due to injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigations and penalties, suspension of operations and repairs required to resume operations.

Loss of our information and computer systems, including as a result of cyber-attacks, could materially and adversely affect our business.

EON relies on electronic systems and networks to control and manage our respective businesses. If any of such programs or systems were to fail for any reason, including as a result of a cyber-attack, or create erroneous information in our hardware or software network infrastructure, possible consequences could be significant, including loss of communication links and inability to automatically process commercial transaction or engage in similar automated or computerized business activities. Although EON has multiple layers of security to mitigate risks of cyber-attacks, cyber-attacks on business have escalated in recent years. Moreover, EON is becoming increasingly dependent on digital technologies to conduct certain exploration, development, production and processing activities, including interpreting seismic data, managing drilling rigs, production activities and gathering systems, conducting reservoir modeling and estimating reserves. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. If EON becomes the target of cyber-attacks of information security breaches, their business operations may be substantially disrupted, which could have an adverse effect on our results of operations. In addition, our efforts to monitor, mitigate and manage these evolving risks may result in increased capital and operating costs, and there can be no assurance that such efforts will be sufficient to prevent attacks or breaches from occurring.

Political instability or armed conflict in crude oil or natural gas producing regions could have a material adverse impact on our business, financial condition or future results.

Our business, financial condition and future results are subject to political and economic risks and uncertainties, including instability resulting from civil unrest, political demonstrations, mass strikes or armed conflict or other crises in crude oil or natural gas producing areas. For example, while there are currently broad-ranging economic sanctions on Russia and certain Russian individuals, banking entities and corporations as a response to the Russia-Ukraine war, an end to the Russia-Ukraine conflict and an easing or elimination of the related sanctions against Russia could result in a decrease in commodity prices as Russian hydrocarbons become more readily accessible on global markets, which could put downward pressure on demand for our services and cause a reduction in our revenues. In addition, the instability in the Middle East has contributed to volatility in oil and gas prices, as well as disruptions to supply chains. Further escalation of conflict in the Middle East, in particular with Iran, a major oil producer, could have an adverse effect on demand for our services and cause a reduction in our revenues. Further, beginning in late 2025, the U.S. seized several oil tankers suspected of transporting oil from Venezuela, and, in early 2026, the U.S. launched a limited military intervention in Venezuela which culminated in the capture of Venezuela’s incumbent president. As the situation stabilizes and U.S.-Venezuela relations improve, it is expected that approximately 50 million barrels of sanctioned oil may become available for export as U.S. sanctions are lifted. The resumption of such exports may cause a depression in global oil prices as the market adjusts to such an increase in supply. The ultimate geopolitical and macroeconomic consequences of these conflicts cannot be predicted, and such events could severely impact the world economy and may adversely affect our financial condition. Although the Company does not have operations overseas, these conflicts elevate the likelihood of supply chain disruptions, heightened volatility in crude oil and natural gas prices and negative effects on our ability to raise additional capital when required and could have a material adverse impact on our business, financial condition or future results.

We believe EON currently has ineffective internal control over its financial reporting.

A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of our annual or interim consolidated financial statements may not be prevented or detected on a timely basis. We identified material weaknesses and believe that EON currently has ineffective internal control over financial reporting, primarily due to: the lack of sufficient accounting personnel to manage the Company’s financial accounting process including lack of proper preparation and review of account reconciliations, lack of segregation of duties, proper accounting for complex financial instruments and lack of design and implementation of controls related to oil and gas activities.

We intend to remediate these deficiencies by putting into place proper internal controls and accounting systems to ensure effective internal control over its financial reporting. We plan to enhance our processes to identify and appropriately apply applicable accounting requirements to better evaluate and understand the nuances of the complex accounting standards that apply to our financial statements. Our plans at this time include providing enhanced access to accounting literature, research materials and documents and increased communication among our personnel and third-party professionals with whom we consult regarding complex accounting applications. The elements of our remediation plan can only be accomplished over time, and we can offer no assurance that these initiatives will ultimately have the intended effects.

However, completion of remediation does not provide assurance that our remediation or other controls will continue to operate properly or remain adequate and we cannot assure you that we will not identify additional material weaknesses in our internal control over financial reporting in the future. If we are unable to maintain effective internal control over financial reporting or disclosure controls and procedures, our ability to record, process and report financial information accurately, and to prepare financial statements within the time periods specified by the rules and forms of the SEC, could be adversely affected. This failure could negatively affect the market price and trading liquidity of our stock, cause investors to lose confidence in our reported financial information, subject us to civil and criminal investigations and penalties and generally materially and adversely impact our business and financial condition.

We are dependent upon our executive officers and directors and their departure could adversely affect our ability to operate.

Our operations are dependent upon a relatively small group of individuals. We believe that our success depends on the continued service of our executive officers and directors. In addition, our executive officers and directors are not required to commit any specified amount of time to our affairs and, accordingly, will have conflicts of interest in allocating management time among various business activities. The unexpected loss of the services of one or more of our directors or executive officers could have a detrimental effect on us.

Certain of our executive officers and directors are now, and all of them may in the future become, affiliated with entities engaged in business activities similar to those conducted by us.

Our executive officers and directors are, or may in the future become, affiliated with entities that are engaged in business activities similar to our own.

Our officers and directors also may become aware of business opportunities which may be appropriate for presentation to us and the other entities to which they owe certain fiduciary or contractual duties. Accordingly, they may have conflicts of interest in determining to which entity a particular business opportunity should be presented. These conflicts may not be resolved in our favor and a potential target business may be presented to another entity prior to its presentation to us. Our Second A&R Charter provides that we renounce our interest in any corporate opportunity offered to any director or officer unless such opportunity is expressly offered to such person solely in his or her capacity as a director or officer of our company and such opportunity is one we are legally and contractually permitted to undertake and would otherwise be reasonable for us to pursue.

Our executive officers, directors, security holders and their respective affiliates may have competitive pecuniary interests that conflict with our interests.

We have not adopted a policy that expressly prohibits our directors, executive officers, security holders or affiliates from having a direct or indirect pecuniary or financial interest in any investment to be acquired or disposed of by us or in any transaction to which we are a party or have an interest. We also do not have a policy that expressly prohibits any such persons from engaging for their own account in business activities of the types conducted by us. Accordingly, such persons or entities may have a conflict between their interests and ours.

Increased costs of capital could adversely affect our business.

Our business and ability to raise capital and make acquisitions could be harmed by factors such as the availability, terms, and cost of capital, increases in interest rates or a reduction in our credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit its access to capital, limit its ability to pursue acquisition opportunities, and place it at a competitive disadvantage. A significant reduction in the availability of capital could materially and adversely affect our ability to achieve our planned growth and operating results.

For example, since March 2022, the Federal Reserve has raised its target range for the federal funds rate multiple times, and additional rate hikes may continue to occur. An increase in the interest rates associated with our floating rate debt would increase our debt service costs and affect our results of operations and cash flow available for payments of our debt obligations. In addition, an increase in interest rates could adversely affect our future ability to obtain financing or materially increase the cost of any additional financing.

EON may be involved in legal proceedings that could result in substantial liabilities.

Like many crude oil and natural gas companies, EON may from time to time be involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of its business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on EON because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition.

Accruals for such liability, penalties or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material. 

Risks Related to Our Industry

A substantial majority of our revenues from crude oil and gas producing activities are derived from its operating properties that are based on the price at which crude oil and natural gas produced from the acreage underlying its interests are sold. Prices of crude oil and natural gas are volatile due to factors beyond our control. A substantial or extended decline in commodity prices may adversely affect our business, financial condition, results of operations and cash flows.

Our revenues, operating results, discretionary cash flows, profitability, liquidity and the carrying value of its interests depend significantly upon the prevailing prices for crude oil and natural gas. Historically, crude oil and natural gas prices and their applicable basis differentials have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, including:

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements accurately. Lower commodity prices may reduce our operating margins, cash flow and borrowing ability. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to develop future reserves or make acquisitions could be adversely affected. Also, using lower prices in estimating proved reserves may result in a reduction in proved and reserve volumes due to economic limits. In addition, sustained periods with oil and natural gas prices at levels lower than current West Texas Intermediate (“WTI”) and Henry Hub strip prices may adversely affect our drilling economics, cash flow and our ability to raise capital, which may require us to re-evaluate and postpone or substantially restrict our development program, and result in the reduction of some of our proved undeveloped reserves and related PV-10. 

Any substantial decline in the price of crude oil and natural gas, or prolonged period of low commodity prices will materially adversely affect our business, financial condition, results of operations and cash flows. In addition, lower crude oil and natural gas may reduce the amount of crude oil and natural gas that can be produced economically, which may reduce our willingness to develop its properties. This may result in EON having to make substantial downward adjustments to our estimated proved reserves, which could negatively impact its ability to fund its operations. If this occurs or if production estimates change or exploration or development results deteriorate, the successful efforts method of accounting principles may require EON to write down, as a non-cash charge to earnings, the carrying value of its crude oil and natural gas properties. EON could also determine during periods of low commodity prices to shut in or curtail production from wells on our properties. In addition, we could determine during periods of low commodity prices to plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, they may abandon any well if they reasonably believe that the well can no longer produce crude oil or natural gas in commercially paying quantities. EON may choose to use various derivative instruments in connection with anticipated crude oil and natural gas to minimize the impact of commodity price fluctuations. However, we cannot hedge the entire exposure of our operations from commodity price volatility. To the extent we do not hedge against commodity price volatility, or its hedges are not effective, our results of operations and financial position may be diminished.

If commodity prices decrease to a level such that our future undiscounted cash flows from its properties are less than their carrying value, EON may be required to take write-downs of the carrying values of its properties.

Accounting rules require that EON periodically review the carrying value of its properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, production data, economics and other factors, EON may be required to write down the carrying value of its properties. EON evaluates the carrying amount of its proved oil and natural gas properties for impairment whenever events or changes in circumstances indicate that a property’s carrying amount may not be recoverable. If the carrying value exceeds the estimated undiscounted future cash flows EON would estimate the fair value of its properties and record an impairment charge for any excess of the carrying value of the properties over the estimated fair value of the properties. Factors used to estimate fair value may include estimates of proved reserves, future commodity prices, future production estimates and a commensurate discount rate. The risk that EON will be required to recognize impairments of its crude oil and natural gas properties increases during periods of low commodity prices. In addition, impairments would occur if EON were to experience sufficient downward adjustments to its estimated proved reserves or the present value of estimated future net revenues. An impairment recognized in one period may not be reversed in a subsequent period. EON may incur impairment charges in the future, which could materially adversely affect its results of operations for the periods in which such charges are taken.

The unavailability, high cost or shortages of rigs, equipment, raw materials, supplies or personnel may restrict or result in increased costs to develop and operate our properties.

The crude oil and natural gas industry is cyclical, which can result in shortages of drilling/workover rigs, equipment, raw materials (particularly water and sand and other proppants), supplies and personnel. When shortages occur, the costs and delivery times of rigs, equipment and supplies increase and demand for, and wage rates of, qualified drilling/workover rig crews also rise with increases in demand. EON cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. In accordance with customary industry practice, EON relies on independent third-party service providers to provide many of the services and equipment necessary to drill new development wells. If EON is unable to secure a sufficient number of drilling/workover rigs at reasonable costs, our financial condition and results of operations could suffer. Shortages of drilling/workover rigs, equipment, raw materials, supplies, personnel, trucking services, tubulars, hydraulic fracturing and completion services and production equipment could delay or restrict our development operations, which in turn could have a material adverse effect on our financial condition, results of operations and cash flows. 

The marketability of crude oil and natural gas production is dependent upon transportation and processing and refining facilities, which EON cannot control. Any limitation in the availability of those facilities could interfere with our ability to market its production and could harm our business.

The marketability of our production depends in part on the availability, proximity and capacity of pipelines, gathering lines, tanker trucks and other transportation methods, and processing and refining facilities owned by third parties. EON does not control these third-party facilities and our access to them may be limited or denied. Insufficient production from the wells on our acreage or a significant disruption in the availability of third-party transportation facilities or other production facilities could adversely impact our ability to deliver, to market or produce oil and natural gas and thereby cause a significant interruption in our operations. If we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, they may be required to shut in or curtail production. In addition, the amount of crude oil that can be produced and sold is subject to curtailment in certain other circumstances outside of our control, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of available capacity on these systems, tanker truck availability and extreme weather conditions. Also, production from our wells may be insufficient to support the construction of pipeline facilities, and the shipment of our crude oil and natural gas on third-party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, EON is provided only with limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering system or transportation, processing or refining-facility capacity, or an inability to obtain favorable terms for delivery of the crude oil and natural gas produced from our acreage, could reduce our ability to market the production from our properties and have a material adverse effect on our financial condition, results of operations and cash flows. Our access to transportation options and the prices we receive can also be affected by federal and state regulation, including regulation of crude oil and natural gas production, transportation and pipeline safety, as well by general economic conditions and changes in supply and demand.

In addition, the third parties on whom EON relies for transportation services are subject to complex federal, state, tribal and local laws that could adversely affect the cost, manner or feasibility of conducting our business.

Drilling for and producing crude oil and natural gas are high-risk activities with many uncertainties that may materially adversely affect our business, financial condition, results of operations and cash flows.

The development drilling activities of our properties will be subject to many risks. For example, EON will not be able to assure you that wells drilled by the E&P operators of its properties will be productive. Drilling for crude oil and natural gas often involves unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient crude oil and natural gas to return a profit at then realized prices after deducting drilling, operating and other costs. The seismic data and other technologies used do not provide conclusive knowledge prior to drilling a well that crude oil and natural gas are present or that a well can be produced economically. The costs of exploration, exploitation and development activities are subject to numerous uncertainties beyond our control and increases in those costs can adversely affect the economics of a project. Further, our development drilling and producing operations may be curtailed, delayed, canceled or otherwise negatively impacted as a result of other factors, including:

Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and other regulatory penalties. In the event that planned operations, including the drilling of development wells, are delayed or cancelled, or existing wells or development wells have lower than anticipated production due to one or more of the factors above or for any other reason, our financial condition, results of operations and cash flows may be materially adversely affected. 

Competition in the crude oil and natural gas industry is intense, which may adversely affect our ability to succeed.

The crude oil and natural gas industry is intensely competitive, and our properties compete with other companies that may have greater resources. Many of these companies explore for and produce crude oil and natural gas, carry on midstream and refining operations, and market petroleum and other products on a regional, national or worldwide basis. In addition, these companies may have a greater ability to continue exploration activities during periods of low crude oil and natural gas market prices. our larger competitors may be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which would adversely affect our competitive position. EON may have fewer financial and human resources than many companies in our industry and may be at a disadvantage in bidding producing crude oil and natural gas properties. Furthermore, the crude oil and natural gas industry has experienced recent consolidation among some operators, which has resulted in certain instances of combined companies with larger resources. Such combined companies may compete against EON and thus limit our ability to acquire additional properties and add reserves.

A deterioration in general economic, business, political or industry conditions would materially adversely affect our results of operations, financial condition and cash flows.

Concerns over global economic conditions, energy costs, geopolitical issues, the impacts of the COVID-19 pandemic, inflation, the availability and cost of credit and slow economic growth in the United States have contributed to economic uncertainty and diminished expectations for the global economy. Additionally, acts of protest and civil unrest have caused economic and political disruption in the United States. Meanwhile, continued hostilities in the Middle East, Ukraine and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the economies of the United States and other countries. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices.

If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could further diminish, which could impact the price at which crude oil and natural gas from our properties are sold, affect the ability of the Company to continue operations and ultimately materially adversely impact our results of operations, financial condition and cash flows.

Conservation measures, technological advances and increasing attention to ESG matters could materially reduce demand for crude oil and natural gas, availability of capital and adversely affect our results of operations.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to crude oil and natural gas, technological advances in fuel economy and energy-generation devices could reduce demand for crude oil and natural gas. The impact of the changing demand for crude oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows. It is also possible that the concerns about the production and use of fossil fuels will reduce the sources of financing available to EON. For example, certain segments of the investor community have developed negative sentiment towards investing in the oil and gas industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition, some investors, including investment advisors and certain sovereign wealth, pension funds, university endowments and family foundations, have stated policies to divest from, or not provide funding to, the oil and gas sector based on their social and environmental considerations. Furthermore, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to environmental, social and governance (“ESG”) matters. Such ratings are used by some investors and other financial institutions to inform their investment, financing and voting decisions, and unfavorable ESG ratings may lead to increased negative sentiment toward oil and gas companies from such institutions. Additionally, the SEC proposed rules on climate change disclosure requirements for public companies which, if adopted as proposed, could result in substantial compliance costs. Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas and related infrastructure projects. Such developments, including environmental activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, and also adversely affect our availability of capital. 

Risks Related to Environmental and Regulatory Matters

Crude oil and natural gas operations are subject to various governmental laws and regulations. Compliance with these laws and regulations can be burdensome and expensive for EON, and failure to comply could result in EON incurring significant liabilities, either of which may impact its willingness to develop our interests.

Our activities on the properties in which EON holds interests are subject to various federal, state and local governmental regulations that may change from time to time in response to economic and political conditions. Matters subject to regulation include drilling operations, production and distribution activities, discharges or releases of pollutants or wastes, plugging and abandonment of wells, maintenance and decommissioning of other facilities, the spacing of wells, unitization and pooling of properties and taxation. From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of crude oil and natural gas wells below actual production capacity to conserve supplies of crude oil and natural gas. Further actions, including actions focused on addressing climate change, may negatively impact oil and gas operations and favor renewable energy projects in the United States, which may negatively impact the demand for oil and natural gas. 

In addition, the production, handling, storage and transportation of crude oil and natural gas, as well as the remediation, emission and disposal of crude oil and natural gas wastes, by-products thereof and other substances and materials produced or used in connection with crude oil and natural gas operations are subject to regulation under federal, state and local laws and regulations primarily relating to protection of worker health and safety, natural resources and the environment. Failure to comply with these laws and regulations may result in the assessment of sanctions on EON, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of our operations on our properties. Moreover, these laws and regulations have generally imposed increasingly strict requirements related to water use and disposal, air pollution control, species protection, and waste management, among other matters.

Laws and regulations governing E&P may also affect production levels. EON must comply with federal and state laws and regulations governing conservation matters, including, but not limited to:

Additionally, federal and state regulatory authorities may expand or alter applicable pipeline-safety laws and regulations, compliance with which may require increased capital costs for third-party crude oil and natural gas transporters. These transporters may attempt to pass on such costs to EON, which in turn could affect profitability on the properties in which EON owns an interest.

EON must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent our properties are shippers on interstate pipelines, they must comply with the tariffs of those pipelines and with federal policies related to the use of interstate capacity.

EON may be required to make significant expenditures to comply with the governmental laws and regulations described above and may be subject to potential fines and penalties if they are found to have violated these laws and regulations. EON believes the trend of more expansive and stricter environmental legislation and regulations will continue. The laws and regulations that affect EON could increase the operating costs of EON and delay production and may ultimately impact our ability and willingness to develop our properties. 

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could cause EON to incur increased costs, additional operating restrictions or delays and have fewer potential development locations.

EON engages in hydraulic fracturing. Hydraulic fracturing is a common practice that is used to stimulate production of hydrocarbons from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Currently, hydraulic fracturing is generally exempt from regulation under the Underground Injection Control program of the U.S. Safe Drinking Water Act (“SDWA”) and is typically regulated by state oil and gas commissions or similar agencies.

However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, in June 2016, the Environmental Protection Agency (the “EPA”) published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants. Also, from time to time, legislation has been introduced, but not enacted, in the U.S. Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. This or other federal legislation related to hydraulic fracturing may be considered again in the future, though EON cannot predict the extent of any such legislation at this time.

Moreover, some states and local governments have adopted, and other governmental entities are considering adopting, regulations that could impose more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations, including states in which our properties are located. For example, Texas, among others, has adopted regulations that impose new or more stringent permitting, disclosure, disposal and well construction requirements on hydraulic fracturing operations. States could also elect to prohibit high volume hydraulic fracturing altogether. In addition to state laws, local land use restrictions, such as city ordinances, may restrict drilling in general and/or hydraulic fracturing in particular.

Increased regulation and attention given to the hydraulic fracturing process, including the disposal of produced water gathered from drilling and production activities, could lead to greater opposition to, and litigation concerning, crude oil and natural gas production activities using hydraulic fracturing techniques in areas where EON owns properties. Additional legislation or regulation could also lead to operational delays or increased operating costs for EON in the production of crude oil and natural gas, including from the development of shale plays, or could make it more difficult for EON to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in our completion of new crude oil and natural gas wells and result in an associated decrease in the production attributable to our interests, which could have a material adverse effect on our business, financial condition and results of operations.

Legislation or regulatory initiatives intended to address seismic activity could restrict our development and production activities, as well as our ability to dispose of produced water gathered from such activities, which could have a material adverse effect on our future business, which in turn could have a material adverse effect on our business.

State and federal regulatory agencies have recently focused on a possible connection between hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. For example, in 2015, the United States Geological Study (“USGS”) identified eight states, including New Mexico, Oklahoma and Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction.

In addition, a number of lawsuits have been filed alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements in the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. For example, the Texas Railroad Commission has previously published a 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 Texas Railroad Commission 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 Texas Railroad Commission 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 may be required to curtail operations or adjust development plans, which may adversely impact EON’s business.

EON will likely dispose of produced water volumes gathered from their production operations by injecting it into wells pursuant to permits issued by governmental authorities overseeing such disposal activities. While these permits will be issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations that restrict EON’s ability to use hydraulic fracturing or dispose of produced water gathered from drilling and production activities by limiting volumes, disposal rates, disposal well locations or otherwise, or requiring them to shut down disposal wells, could have a material adverse effect on EON’s business, financial condition and results of operations. 

Restrictions on the ability of to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of crude oil and natural gas production during both the drilling and hydraulic fracturing processes. Over the past several years, parts of the country, and in particular Texas, have experienced extreme drought conditions. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. Such conditions may be exacerbated by climate change. If we are unable to obtain water to use in their operations from local sources, or if we are unable to effectively utilize flowback water, they may be unable to economically drill for or produce crude oil and natural gas from our properties, which could have an adverse effect on our financial condition, results of operations and cash flows.

Our operations are subject to a series of risks arising from 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 “greenhouse gases” (“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. As a result, numerous proposals have been made and may continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs as well as to eliminate such future emissions.

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. Litigation risks are also increasing as a number of entities have sought to bring suit against various oil and natural gas companies in state or federal court, alleging among other things, that such companies created public nuisances by producing fuels that contributed to climate change or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts. 

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. 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 our interests. Additionally, political, litigation and financial risks may result in Pogo 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 its interests. One or more of these developments could have a material adverse effect on our 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, as well as those of our operators and their supply chains. Such physical risks may result in damage to operators’ facilities or otherwise adversely impact their 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.

Increased attention to ESG matters and conservation measures may adversely impact our business.

Increasing attention to climate change, societal expectations on companies to address climate change, investor and societal expectations regarding voluntary ESG disclosures and consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, and increased investigations and litigation. Increasing attention to climate change and environmental conservation, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against EON. . To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of, or contribution to, the asserted damage, or to other mitigating factors.

Moreover, while EON may create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures are based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward EON and its industry and to the diversion of investment to other industries, which could have a negative impact on our access to and costs of capital. Also, institutional lenders may decide not to provide funding for fossil fuel energy companies based on climate change related concerns, which could affect our access to capital for potential growth projects.

Our results of operations may be materially impacted by efforts to transition to a lower-carbon economy.

Concerns over the risk of climate change have increased the focus by global, regional, national, state and local regulators on GHG emissions, including carbon dioxide emissions, and on transitioning to a lower-carbon future. A number of countries and states have adopted, or are considering the adoption of, regulatory frameworks to reduce greenhouse gas emissions. These regulatory measures may include, among others, adoption of cap and trade regimes, carbon taxes, increased efficiency standards, prohibitions on the sales of new automobiles with internal combustion engines, and incentives or mandates for battery-powered automobiles and/or wind, solar or other forms of alternative energy. Compliance with changes in laws, regulations and obligations relating to climate change could result in increased costs of compliance for EON or costs of consuming crude oil and natural gas for such products, and thereby reduce demand, which could reduce the profitability of EON. For example, EON may be required to install new emission controls, acquire allowances or pay taxes related to their greenhouse gas emissions, or otherwise incur costs to administer and manage a GHG emissions program. Additionally, EON could incur reputational risk tied to changing customer or community perceptions of its, customers contribution to, or detraction from, the transition to a lower-carbon economy. These changing perceptions could lower demand for oil and gas products, resulting in lower prices and lower revenues as consumers avoid carbon-intensive industries, and could also pressure banks and investment managers to shift investments and reduce lending.

Separately, banks and other financial institutions, including investors, may decide to adopt policies that restrict or prohibit investment in, or otherwise funding, EON based on climate change-related concerns, which could affect its or our access to capital for potential growth projects.

Approaches to climate change and transition to a lower-carbon economy, including government regulation, company policies, and consumer behavior, are continuously evolving. At this time, EON cannot predict how such approaches may develop or otherwise reasonably or reliably estimate their impact on its or its operators’ financial condition, results of operations and ability to compete. However, any long-term material adverse effect on the oil and gas industry may adversely affect our financial condition, results of operations and cash flows. 

Additional restrictions on development activities intended to protect certain species of wildlife may adversely affect our ability to conduct development activities.

In the United States, the Endangered Species Act (the “ESA”) restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”). To the extent species that are listed under the ESA or similar state laws, or are protected under the MBTA, live in the areas where EON operates, our ability to conduct or expand operations could be limited, or EON could be forced to incur additional material costs. Moreover, our development drilling activities may be delayed, restricted or precluded in protected habitat areas or during certain seasons, such as breeding and nesting seasons. For example, in June 2021, the U.S. Fish & Wildlife Service (the “FWS”) proposed to list two distinct population sections (“DPS”) of the Lesser Prairie Chicken, including one in portions of the Permian Basin, under the ESA (the “southern DPS”). On November 25, 2022, the FWS finalized the proposed rule, listing the southern DPS of the Lesser Prairie-Chicken as endangered and the northern DPS of the Lesser Prairie-Chicken as threatened.

Recently, there have also 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.

In addition, as a result of one or more settlements approved by the FWS, the agency was required to make a determination on the listing of numerous other species as endangered or threatened under the ESA by the end of the FWS’ 2017 fiscal year. The FWS did not meet that deadline, but continues to evaluate whether to take action with respect to those species. The designation of previously unidentified endangered or threatened species could cause our operations to become subject to operating restrictions or bans, and limit future development activity in affected areas. The FWS and similar state agencies may designate critical or suitable habitat areas that they believe are necessary for the survival of threatened or endangered species. Such a designation could materially restrict use of or access to federal, state and private lands.

Risks Related to Our Financial and Debt Arrangements

If we are unable to comply with the restrictions and covenants in our debt agreements, there could be an event of default under the terms of such agreements, which could result in an acceleration of repayment. 

If we are unable to comply with the restrictions and covenants in any existing or future debt agreement or if we default under the terms of any existing or future debt agreement, there could be an event of default. Our ability to comply with these restrictions and covenants, including meeting any financial ratios and tests, may be affected by events beyond our control. We cannot assure that we will be able to comply with these restrictions and covenants or meet such financial ratios and tests. In the event of a default under any debt agreement, the lenders could terminate or accelerate the loans and declare all amounts borrowed due and payable. If any of these events occur, our assets might not be sufficient to repay in full all of our outstanding indebtedness and we may be unable to find alternative financing. Even if we could obtain alternative financing, it might not be on terms that are favorable or acceptable to us. Additionally, we may not be able to amend the debt agreement or obtain needed waivers on satisfactory terms. There can be no assurance that, if needed to avoid noncompliance with our debt agreements in the future, we will obtain the necessary waivers from the applicable lenders on satisfactory terms or at all. As a result, there could be an event of default under such agreements, which could result in an acceleration of repayment.

Our debt levels may limit our flexibility to obtain additional financing and pursue other business opportunities.

Our existing and any future indebtedness could have important consequences to it, including:

Our ability to service our indebtedness will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond its control. If our operating results are not sufficient to service its current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying business activities, acquisitions, investments and/or capital expenditures, selling assets, restructuring or refinancing its indebtedness, or seeking additional equity capital or bankruptcy protection. We may not be able to effect any of these remedies on satisfactory terms or at all.

Risks Related to Our Common Stock

Our stock price is volatile, which could result in substantial losses to investors and litigation.

In addition to changes to market prices based on our results of operations and the factors discussed elsewhere in this “Risk Factors” section, the market price of and trading volume for our Class A Common Stock may continue to change for a variety of other reasons, not necessarily related to our actual operating performance. The capital markets have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our Class A Common Stock. In addition, the average daily trading volume of the securities of small companies can be very low, which may contribute to future volatility. Factors that could cause the market price of our Class A Common Stock to fluctuate significantly include:

Any of these factors, as well as broader market and industry factors, may result in large and sudden changes in the trading volume of our Class A Common Stock and could seriously harm the market price of our Class A Common Stock, regardless of our operating performance. This may prevent you from being able to sell your shares at or above the price you paid for your shares of our Class A Common Stock, if at all. In addition, following periods of volatility in the market price of a company’s securities, stockholders often institute securities class action litigation against that company. Our involvement in any class action suit or other legal proceeding could divert our senior management’s attention and could adversely affect our business, financial condition, results of operations and prospects.

The sale or availability for sale of substantial amounts of our Class A Common Stock could adversely affect the market price of our Class A Common Stock.

Sales of substantial amounts of shares of our Class A Common Stock, or the perception that these sales could occur, could adversely affect the market price of our Class A Common Stock and could impair our future ability to raise capital through common stock offerings.

We have never paid cash dividends on our Class A Common Stock and do not anticipate paying any cash dividends on our Class A Common Stock.

We have never paid cash dividends and do not anticipate paying any cash dividends on our Class A Common Stock in the foreseeable future. We currently intend to retain any earnings to finance our operations and growth. As a result, any short-term return on your investment will depend on the market price of our Class A Common Stock, and only appreciation of the price of our Class A Common Stock, which may never occur, will provide a return to stockholders. The decision whether to pay dividends will be made by our board of directors in light of conditions then existing, including, but not limited to, factors such as our financial condition, results of operations, capital requirements, business conditions, and covenants under any applicable contractual arrangements. Investors seeking cash dividends should not invest in our Class A Common Stock.

If equity research analysts do not publish research or reports about our business, or if they issue unfavorable commentary or downgrade our Class A Common Stock, the market price of our Class A Common Stock will likely decline.

The trading market for our Class A Common Stock will rely in part on the research and reports that equity research analysts, over whom we have no control, publish about us and our business. We may never obtain research coverage by securities and industry analysts. If no securities or industry analysts commence coverage of our company, the market price for our Class A Common Stock could decline. In the event we obtain securities or industry analyst coverage, the market price of our Class A Common Stock could decline if one or more equity analysts downgrade our Class A Common Stock or if those analysts issue unfavorable commentary, even if it is inaccurate, or cease publishing reports about us or our business.

The NYSE American may delist our securities from trading on its exchange, which could limit investors’ ability to make transactions in our securities and subject us to additional trading restrictions.

We have listed our Class A Common Stock and public warrants on the NYSE American. We cannot assure you that our securities will continue to be listed on the NYSE American in the future. In order to continue listing our securities on the NYSE American, we must maintain certain financial, distribution and stock price levels. Generally, we must maintain a minimum amount in stockholders’ equity (generally $2,500,000) and a minimum number of holders of our securities (generally 300 public holders).

If the NYSE American delists our securities from trading on its exchange and we are not able to list our securities on another national securities exchange, we expect our securities could be quoted on an over-the-counter market. If this were to occur, we could face significant material adverse consequences, including:

We may redeem your public warrants prior to their exercise at a time that is disadvantageous to you, thereby making such warrants worthless.

We may redeem your public warrants prior to their exercise at a time that is disadvantageous to you, thereby making such warrants worthless. We have the ability to redeem outstanding public warrants at any prior to their expiration, at a price of $0.01 per warrant, provided that the closing price of the shares of the Class A Common Stock equals or exceeds $18.00 per share (as adjusted for share subdivisions, share capitalizations, reorganizations, recapitalizations and the like) for any 20 trading days within a 30 trading day period ending on the third trading day prior to the date on which a notice of redemption is sent to the warrant holders. Please note that the closing price of our Class A Common Stock has not exceeded $18.00 per share for any of the 30 trading days prior to the date of this report. We will not redeem the warrants as described above unless a registration statement under the Securities Act covering the shares of the Class A Common Stock issuable upon exercise of such warrants is effective and a current prospectus relating to shares of the Class A Common Stock is available throughout the 30-day redemption period. If and when the public warrants become redeemable by us, we may exercise our redemption right even if we are unable to register or qualify the underlying securities for sale under all applicable state securities laws. Redemption of the outstanding public warrants could force you (i) to exercise your public warrants and pay the exercise price therefor at a time when it may be disadvantageous for you to do so, (ii) to sell your public warrants s at the then-current market price when you might otherwise wish to hold your public warrants, or (iii) to accept the nominal redemption price which, at the time the outstanding public warrants are called for redemption, is likely to be substantially less than the market value of your public warrants.

The value received upon exercise of the public warrants (1) may be less than the value the holders would have received if they had exercised their public warrants at a later time where the underlying share price is higher and (2) may not compensate the holders for the value of the public warrants. The fair value of the public warrants that may be retained by redeeming shareholders is $1.3 million based on recent trading prices, and 8,625,000 public warrants held by public shareholders. 

We may amend the terms of the public warrants in a manner that may be adverse to holders of public warrants with the approval by the holders of at least 50% of the then-outstanding public warrants. As a result, the exercise price of the public warrants could be increased, the exercise period could be shortened and the number of shares of our Class A Common Stock purchasable upon exercise of a warrant could be decreased, all without a holder’s approval.

Our public warrants were issued in registered form under a warrant agreement between Continental Stock Transfer & Trust Company, as warrant agent, and us. The warrant agreement provides that the terms of the warrants may be amended without the consent of any holder (i) to cure any ambiguity or to correct any mistake, including to conform the provisions therein to the descriptions of the terms of the warrants, or to cure, correct or supplement any defective provision, or (ii) to add or change any other provisions with respect to matters or questions arising under the warrant agreement as the parties to the warrant agreement may deem necessary or desirable and that the parties deem to not adversely affect the interests of the registered holders of the warrants. The warrant agreement requires the approval by the holders of at least 50% of the then-outstanding public warrants to make any change that adversely affects the interests of the registered holders of public warrants. Accordingly, we may amend the terms of the public warrants in a manner adverse to a holder if holders of at least 50% of the then-outstanding public warrants approve of such amendment. Although our ability to amend the terms of the public warrants with the consent of at least 50% of the then-outstanding public warrants is unlimited, examples of such amendments could be amendments to, among other things, increase the exercise price of the warrants, convert the warrants into cash or stock (at a ratio different than initially provided), shorten the exercise period or decrease the number of shares of our Class A Common Stock purchasable upon exercise of a warrant.

Purchases made pursuant to our ELOC Purchase Agreement will be made at a discount to the volume weighted average price of Class A Common Stock, which may result in negative pressure on the stock price.

On October 17, 2022, we entered into a common stock purchase agreement (the “ELOC Purchase Agreement”) and a related registration rights agreement (the “White Lion RRA”) with White Lion Capital, LLC, a Nevada limited liability company (“White Lion”). Pursuant to the ELOC Purchase Agreement, we have the right, but not the obligation to require White Lion to purchase, from time to time, up to $150,000,000 in aggregate gross purchase price of newly issued shares of our Class A Common Stock, subject to certain limitations and conditions set forth in the ELOC Purchase Agreement. On March 7, 2024, the Company entered into an Amendment No. 1 to ELOC Purchase Agreement (the “White Lion Amendment”) with White Lion. Pursuant to the White Lion Amendment, the Company and White Lion agreed to a fixed number of Commitment Shares equal to 440,000 shares of Common Stock to be issued to White Lion in consideration for commitments of White Lion under the ELOC Purchase Agreement, which the Company agreed to include all of the Commitment Shares on the initial registration statement filed by the Company related to the ELOC Purchase Agreement.

We are obligated under the ELOC Purchase Agreement and the White Lion RRA to maintain a registration statement with the SEC to register the Class A Common Stock under the Securities Act of 1933, as amended, for the resale by White Lion of shares of Class A Common Stock that we may issue to White Lion under the ELOC Purchase Agreement. The purchase price to be paid by White Lion for any shares of Class A Common Stock will equal 96% of the lowest daily volume-weighted average price of Class A Common Stock during a period of two consecutive trading days following the applicable Notice Date.

Such purchases will dilute our stockholders and could adversely affect the prevailing market price of our Class A Common Stock and impair our ability to raise capital through future offerings of equity or equity-linked securities, although we intend to carefully control such purchases as to minimize the impact. Accordingly, the adverse market and price pressures resulting from the purchase and registration of Class A Common Stock pursuant to the ELOC Purchase Agreement may continue for an extended period of time and continued negative pressure on the market price of our Class A Common Stock could have a material adverse effect on our ability to raise additional equity capital.

It is not possible to predict the actual number of shares of Class A Common Stock, if any, we will sell under the ELOC Purchase Agreement with White Lion or the actual gross proceeds resulting from those sales.

We generally have the right to control the timing and amount of any sales of the Class A Common Stock to White under the ELOC Purchase Agreement. Sales of Class A Common Stock, if any, to White Lion under the ELOC Purchase Agreement will depend upon market conditions and other factors to be determined by us. We may ultimately decide to sell to White Lion all, some or none of the Class A Common Stock that may be available for us to sell to White Lion pursuant to the ELOC Purchase Agreement.

Because the purchase price per share of Class A Common Stock to be paid by White Lion will fluctuate based on the market prices of the Class A Common Stock at the time we elect to sell Class A Common Stock to White Lion pursuant to the ELOC Purchase Agreement, if any, it is not possible for us to predict, as of the date of this report and prior to any such sales, the number of shares of Class A Common Stock that we will sell to White Lion under the ELOC Purchase Agreement, the purchase price per share that White Lion will pay for Class A Common Stock purchased from us under the ELOC Purchase Agreement, or the aggregate gross proceeds that we will receive from those purchases by White Lion under the ELOC Purchase Agreement.

The number of shares of Class A Common Stock ultimately offered for sale by White Lion is dependent upon the number of shares of Class A Common Stock, if any, we ultimately elect to sell to White Lion under the ELOC Purchase Agreement. However, even if we elect to sell Class A Common Stock to White Lion pursuant to the ELOC Purchase Agreement, White Lion may resell all, some or none of such shares at any time or from time to time in its sole discretion and at different prices. To date, the Company has issued 17,000,000 shares of common stock under the ELOC Purchase Agreement.

Because the purchase price per share to be paid by White Lion for the shares of Class A Common Stock that we may elect to sell to White Lion under the ELOC Purchase Agreement, if any, will fluctuate based on the market prices of our common stock for each purchase made pursuant to the Common Stock, if any, it is not possible for us to predict, as of the date of this report and prior to any such sales, the number of shares of Class A Common Stock that we will sell to White Lion under the ELOC Purchase Agreement, the purchase price per share that While Lion will pay for shares purchased from us under the ELOC Purchase Agreement, or the aggregate gross proceeds that we will receive from those purchases by White Lion under the Purchase Agreement, if any. 

The sale and issuance of Class A Common Stock to White Lion will cause dilution to our existing securityholders, and the resale of the Class A Common Stock acquired by White Lion, or the perception that such resales may occur, could cause the price of our Class A Common Stock to decrease.

The purchase price per share of Class A Common Stock to be paid by White Lion for the Class A Common Stock that we may elect to sell to White Lion under the ELOC Purchase Agreement, if any, will fluctuate based on the market prices of our Class A Common Stock at the time we elect to sell Class A Common Stock to White Lion pursuant to the ELOC Purchase Agreement. Depending on market liquidity at the time, resales of such Class A Common Stock by White Lion may cause the trading price of our Class A Common Stock to decrease.

If and when we elect to sell Class A Common Stock to White Lion, sales of newly issued Class A Common Stock by us to White Lion could result in substantial dilution to the interests of existing holders of our Class A Common Stock. Additionally, the sale of a substantial number of Class A Common Stock to White Lion, or the anticipation of such sales, could make it more difficult for us to sell equity or equity-related securities in the future at a time and at a price that we might otherwise wish to effect sales.

We expect to grant equity awards to employees and directors under our equity incentive plans. We may also raise capital through equity financings in the future. As part of our business strategy, we may make or receive investments in companies, solutions or technologies and issue equity securities to pay for any such acquisition or investment. Any such issuances of additional share capital may cause shareholders to experience significant dilution of their ownership interests and the per share value of our Class A Common Stock to decline. To date, the Company has issued 17,000,000 shares of common stock under the ELOC Purchase Agreement.

Investors who buy shares at different times will likely pay different prices than White Lion under the ELOC Purchase Agreement with them.

Pursuant to the ELOC Purchase Agreement, we will have discretion, subject to market demand, to vary the timing, prices, and numbers of shares sold to White Lion. If and when we do elect to sell shares of our Class A Common Stock to White Lion pursuant to the ELOC Purchase Agreement, after White Lion has acquired such shares, White Lion may resell all, some or none of such shares at any time or from time to time in its discretion and at different prices. As a result, investors who purchase shares from White Lion in this offering at different times will likely pay different prices for those shares, and so may experience different levels of dilution and in some cases substantial dilution and different outcomes in their investment results. Investors may experience a decline in the value of the shares they purchase from White Lion in this offering as a result of future sales made by us to White Lion at prices lower than the prices such investors paid for their shares in this offering.

Management will have broad discretion as to the use of the proceeds from the sale of shares to White Lion, and uses may not improve our financial condition or market value.

Because we have not designated the amount of net proceeds from the sale of shares of our Class A Common Stock to be used for any particular purpose, our management will have broad discretion as to the application of such net proceeds and could use them for purposes other than those contemplated hereby. Our management may use the net proceeds for corporate purposes that may not improve our financial condition or market value.

The JOBS Act permits “emerging growth companies” like us to take advantage of certain exemptions from various reporting requirements applicable to other public companies that are not emerging growth companies.

We qualify as an “emerging growth company” as defined in Section 2(a)(19) of the Securities Act, as modified by the JOBS Act. As such, we take advantage of certain exemptions from various reporting requirements applicable to other public companies that are not emerging growth companies, including (a) the exemption from the auditor attestation requirements with respect to internal control over financial reporting under Section 404 of the Sarbanes-Oxley Act, (b) the exemptions from say-on-pay, say-on-frequency and say-on-golden parachute voting requirements and (c) reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements. As a result, our stockholders may not have access to certain information they deem important. We will remain an emerging growth company until the earliest of (a) the last day of the fiscal year of (i)  the fifth anniversary of the closing of our Initial Public Offering, or December 31, 2027, (ii) in which we have total annual gross revenue of at least $1.235 billion (as adjusted for inflation pursuant to SEC rules from time to time) or (iii) in which we are deemed to be a large accelerated filer, which means the market value of our Class A Common Stock that is held by non-affiliates exceeds $700 million as of the last business day of our prior second fiscal quarter, and (b) the date on which we have issued more than $1.0 billion in non-convertible debt during the prior three year period. 

In addition, Section 107 of the JOBS Act provides that an emerging growth company can take advantage of the exemption from complying with new or revised accounting standards provided in Section 7(a)(2)(B) of the Securities Act as long as we are an emerging growth company. An emerging growth company can therefore delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. The JOBS Act provides that a company can elect to opt out of the extended transition period and comply with the requirements that apply to non-emerging growth companies, but any such election to opt out is irrevocable. We have elected to irrevocably opt out of such extended transition period, which means that when a standard is issued or revised and it has different application dates for public or private companies, we will adopt the new or revised standard at the time public companies adopt the new or revised standard. This may make comparison of our financial statements with another emerging growth company that has not opted out of using the extended transition period difficult or impossible because of the potential differences in accounting standards used.

We cannot predict if investors will find our Class A Common Stock less attractive because we will rely on these exemptions. If some investors find our Class A Common Stock less attractive as a result, there may be less active trading market for our Class A Common Stock and our stock price may be more volatile.

The Second A&R Charter designates state courts within the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

The Second A&R Charter provides that, unless we consent in writing to the selection of an alternative forum, (a) the Court of Chancery of the State of Delaware shall, to the fullest extent permitted by law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on behalf of the company, (ii) any action asserting a claim of breach of a fiduciary duty owed by, or other wrongdoing by, any current or former director, officer, employee or agent of the company to us or our stockholders, or a claim of aiding and abetting any such breach of fiduciary duty, (iii) any action asserting a claim against us or any of our directors, officers, employees or agents arising pursuant to any provision of the DGCL, the Second A&R Charter (as may be amended, restated, modified, supplemented or waived from time to time), (iv) any action to interpret, apply, enforce or determine the validity of the Second A&R Charter (as may be amended, restated, modified, supplemented or waived from time to time), (v) any action asserting a claim against us or any of our directors, officers, employees or agents that is governed by the internal affairs doctrine or (vi) any action asserting an “internal corporate claim” as that term is defined in Section 115 of the DGCL.

In addition, the Second A&R Charter provides that, unless we consent in writing to the selection of an alternative forum, the federal district courts of the United States of America shall, to the fullest extent permitted by law, be the sole and exclusive forum for the resolution of any complaint asserting a cause of action arising under the Securities Act and the rules and regulations promulgated thereunder. Notwithstanding the foregoing, the Second A&R Charter provides that the exclusive forum provision will not apply to claims seeking to enforce any liability or duty created by the Exchange Act or any other claim for which the U.S. federal courts have exclusive jurisdiction.

This choice of forum provision may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with us or any of our directors, officers, other employees or stockholders, which may discourage lawsuits with respect to such claims, although our stockholders will not be deemed to have waived our compliance with federal securities laws and the rules and regulations thereunder. Alternatively, if a court were to find the choice of forum provision contained in our amended and restated bylaws to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such action in other jurisdictions, which could harm our business, operating results and financial condition. 

The Second A&R Charter contains a waiver of the corporate opportunities doctrine for our directors and officers, and therefore such persons have no obligations to make opportunities available to us.

The “corporate opportunities” doctrine provides that directors and officers of a corporation, as part of their duty of loyalty to the corporation and its shareholders, generally have a fiduciary duty to disclose opportunities to the corporation that are related to its business and are prohibited from pursuing those opportunities unless the corporation determines that it is not going to pursue them. Our amended and restated certificate of incorporation waives the corporate opportunities doctrine. It states that, to the extent allowed by law, the doctrine of corporate opportunity, or any other analogous doctrine, shall not apply with respect to us or any of our officers or directors or any of their respective affiliates, in circumstances where the application of any such doctrine would conflict with any fiduciary duties or contractual obligations they may have as of the date of the amended and restated certificate of incorporation or in the future, and we renounce any expectancy that any of our directors or officers will offer any such corporate opportunity of which he or she may become aware to us, except, the doctrine of corporate opportunity shall apply with respect to any of our directors or officers with respect to a corporate opportunity that was offered to such person solely in his or her capacity as a director or officer of the company and (i) such opportunity is one that we are legally and contractually permitted to undertake and would otherwise be reasonable for us to pursue and (ii) the director or officer is permitted to refer that opportunity to us without violating any legal obligation.

Our directors and officers or their respective affiliates may pursue acquisition opportunities that may be complementary to our business and, as a result of the waiver described above, those acquisition opportunities may not be available to us. In addition, our directors and officers or their respective affiliates may have an interest in pursuing acquisitions, divestitures and other transactions that, in its judgment, could enhance its investment, even though such transactions might involve risks to you.

We are a holding company with no operations of our own, and we depend on our subsidiaries for cash to fund all of our operations, taxes and other expenses and any dividends that we may pay.

Our operations are conducted entirely through our subsidiaries. Our ability to generate cash to meet our debt and other obligations, to cover all applicable taxes payable and to declare and pay any dividends on our Class A Common Stock is dependent on the earnings and the receipt of funds through distributions from our subsidiaries. Our subsidiaries’ respective abilities to generate adequate cash depends on a number of factors, including development of reserves, successful acquisitions of complementary properties, advantageous drilling conditions, natural gas, oil prices, compliance with all applicable laws and regulations and other factors.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 1C. CYBERSECURITY

ITEM 2. PROPERTIES

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 are approximately $3,000 per month. We consider our current office space adequate for our current operations.

ITEM 3. LEGAL PROCEEDINGS

There are no material proceedings to which any director or officer, or any associate of any such director or officer, is a party that is adverse to our company or any of our subsidiaries or has a material interest adverse to our company or any of our subsidiaries. No director or executive officer has been a director or executive officer of any business which has filed a bankruptcy petition or had a bankruptcy petition filed against it during the past ten years. No current director or executive officer has been convicted of a criminal offense or is the subject of a pending criminal proceeding during the past ten years. No current director or executive officer has been the subject of any order, judgment or decree of any court permanently or temporarily enjoining, barring, suspending or otherwise limiting his involvement in any type of business, securities or banking activities during the past ten years. No current director or officer has been found by a court to have violated a federal or state securities or commodities law during the past ten years.

We are from time to time subject to claims, lawsuits and other legal and administrative proceedings arising in the ordinary course of business. Defending such proceedings is costly and can impose a significant burden on management and employees. The results of any future litigation cannot be predicted with certainty, and regardless of the outcome, litigation can have an adverse impact on us because of defense and settlement costs, diversion of management resources and other factors. We are not presently a party to any litigation the outcome of which, we believe, if determined adversely to us, would individually or taken together have a material adverse effect on our business, operating results, cash flows or financial condition. 

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

(a) Market Information

Our Class A Common Stock and public warrants are currently listed on the NYSE American under the symbol “EONR” and “EONR.WS”, respectively. On September 25, 2026 the closing sale price of our Class A Common Stock was $0.4929 per share.

(b) Holders

As of September 25, 2026, there were approximately 34 holders of record of our Class A Common Stock and there were no holders of record of our Class B Common Stock. The number of record holders was determined from the records of our transfer agent and does not include beneficial owners of our shares of Class A Common Stock whose shares are held in the names of various security brokers, dealers and registered clearing agencies.

(c) Dividends

Our Board of Directors has not adopted a formal dividend policy for a recurring fixed dividend payment to shareholders. We have not paid any cash dividends on our Class A Common Stock to date. The payment of cash dividends in the future will be dependent upon our revenues and earnings, if any, capital requirements and general financial condition subsequent to completion of a business combination. The payment of any cash dividends in the future will be within the discretion of our Board of Directors at such time. In addition, our Board of Directors is not currently contemplating and does not anticipate declaring any stock dividends in the foreseeable future. Further, if we incur any indebtedness, our ability to declare dividends may be limited by restrictive covenants we may agree to in connection therewith. 

(d) Securities Authorized for Issuance Under Equity Compensation Plans

Information about our equity compensation plans in Item 11 of Part III of this report is incorporated herein by reference.

(e) Performance Graph

Not applicable.

(f) Recent Sales of Unregistered Securities; Use of Proceeds from Registered Offerings

In January 2025, we issued 200,000 shares to a consultant for services that vested immediately.

In March 2025, we issued 116,100 shares to a consultant for services performed based on a consulting agreement to issued $15,000 of shares per month. In addition, we issued an additional 108,800 shares to the consultant in June 2025 pursuant to the agreement.

In April 2025, we issued 220,000 shares to consultants for services that vested immediately.

In September 2025, we issued 37,500 shares to a consultant for services performed based on a consulting agreement to issued 7,500 of shares per month. In addition, we issued an additional 7,500 shares to the consultant in December 2025 pursuant to the agreement.

All issuances described above were not registered under the Securities Act in reliance upon the exemption provided in Section 4(a)(2) of the Securities Act and/or Regulation D promulgated thereunder.

(g) Purchases of Equity Securities by the Issuer and Affiliated Purchasers

None.

ITEM 6. [RESERVED]

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the financial statements and the notes thereto contained elsewhere in this Report. Certain information contained in the discussion and analysis set forth below includes forward-looking statements that involve risks and uncertainties – See “CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS”.

Overview

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 GJF in Eddy County, New Mexico, and SJF in Lea County, New Mexico which are both in the sub-area of the Permian Basin. LHO focuses primarily on production through waterflooding recovery methods.

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, all of which is net operated acreage of vertical wells with average depths of approximately 3,810 feet. In addition, our 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 net production for the year ended December 31, 2025 was 734 barrel of oil equivalent (“BOE”) per day. Our average daily net 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, water injection flowlines that needed repair or replacement, increase in flaring of natural gas, and the conveyance of the 2025 ORRIs on September 9, 2025 with the recapitalization and Farmout funding.

Selected Factors That Affect Our Operating Results

Our revenues, cash flows from operations and future growth depend substantially upon:

In addition to the factors that affect companies in our industry generally, the location of substantially all of our acreage discussed above subjects our operating results to factors specific to these regions. These factors include the potential adverse impact of weather on drilling, production and transportation activities, particularly during the winter and spring months, as well as infrastructure limitations, transportation capacity, regulatory matters and other factors that may specifically affect one or more of these regions.

The price at which our oil and natural gas production are sold typically reflects either a premium or discount to the New York Mercantile Exchange (“NYMEX”) benchmark price. Thus, our operating results are also affected by changes in the oil price differentials between the applicable benchmark and the sales prices we receive for our oil production. Our oil price differential to the NYMEX benchmark price during the years ended December 31, 2025 and 2024, was $(1.53) and $(1.03) per barrel, respectively. Our natural gas price differential during the years ended December 31, 2025 and 2024, was $(1.64) and $0.08 per one thousand cubic feet (“Mcf”), respectively. Fluctuations in our price differentials and realizations are due to several factors such as gathering and transportation costs, takeaway capacity relative to production levels, regional storage capacity, gain/loss on derivative contracts and seasonal refinery maintenance temporarily depressing demand.

Market Conditions

The price that we receive for the oil and natural gas we produce is largely a function of market supply and demand. Because our oil and gas revenues are heavily weighted toward oil, we are 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 we expect 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.

Prices for various quantities of natural gas and oil that we produce significantly impact our revenues and cash flows. The following table lists average NYMEX prices for oil and natural gas for the years ended December 31, 2025 and 2024.

For the year ended December 31, 2025, the average NYMEX oil pricing was $65.46 per barrel of oil or 14% lower than the average NYMEX price per barrel for the year ended December 31, 2024. Our settled derivatives increased our realized oil price per barrel by $2.89 in the year ended December 31, 2025, and decreased our realized oil price per barrel by $1.91 for the year ended December 31, 2024, respectively. Our average realized oil price per barrel after reflecting settled derivatives and location differentials was $66.82 for the year ended December 31, 2025 compared to $73.61 for the year ended December 31, 2024.

The average NYMEX natural gas pricing for the year ended December 31, 2025, was $3.53 per Mcf, or 61% higher than the average NYMEX price per Mcf for the year ended December 31, 2024. 

Results of Operations

For the year ended December 31, 2025, 91% and 9% of production volumes from the assets were attributable to crude and natural gas, respectively. As of December 31, 2025, the Company was continuing development of the Seven Rivers waterflood interval and the SJF acquired in June 2025. 

The following table sets forth selected operating data for the periods indicated. Average sales prices are derived from accrued accounting data for the relevant period indicated.

Oil and Natural Gas Sales

Our revenues vary from year to year primarily as a result of changes in realized commodity prices and production volumes. For the year ended December 31, 2025, our oil and natural gas sales decreased 20% from the year ended December 31, 2024, driven by a 8% decrease in production volumes and a 13% decrease in realized prices, excluding the effect of settled commodity derivatives. The lower average price in the year ended December 31, 2025 compared to the year ending December 31, 2024, was driven by lower average NYMEX oil and natural gas prices during the year. Realized production from oil and gas properties decreased due to increased flaring of natural gas during the current period.

Production for the comparable periods is set forth in the following table:

Derivative Contracts

We enter into commodity derivatives instruments to manage the price risk attributable to future oil production. We recorded a gain on derivative contracts of $663,010 for the year ended December 31, 2025, compared to a loss of $850,374 for the year ended December 31, 2024. Lower commodity prices in the year ended December 31, 2025, resulted in realized gains of $706,073 compared to realized losses of $489,084 for the year ended December 31, 2024. For the year ended December 31, 2025, unrealized losses were $43,063 compared to $361,290 for the year ended December 31, 2024.

For the year ended December 31, 2025, our average realized oil price per barrel after reflecting settled derivatives was $66.82 compared to $73.61 for the year ended December 31, 2024.

As of December 31, 2025, we ended the period with a $63,334 net derivative asset compared to a net asset of $106,397 as of December 31, 2024.

Other Revenue

Other revenue was $383,196 for the year ended December 31, 2025 compared to $487,109 for year ended December 31, 2024. The revenue is related to providing water services to a third party. The contract is for one year starting on September 1, 2022, and has been renewed by mutual agreement.

Lease Operating Expenses

Lease operating expenses were $10,274,781 for the year ended December 31, 2025, compared to $8,614,080 for the year ended December 31, 2024. On a per unit basis, production expenses increased 30% from $29.59 per BOE for the year ended December 31, 2024, to $38.33 per BOE for the year ended December 31, 2025.

Production Taxes, Transportation and Processing

We pay production taxes, transportation and processing costs based on realized oil and natural gas sales. Production taxes, transportation and processing costs were $1,626,360 for the year ended December 31, 2025 compared to were $1,715,792 for the year ended December 31, 2024. As a percentage of oil and natural gas sales, these costs were 10.2% and 8.7% for the years ended December 31, 2025 and 2024 respectively. Production taxes, transportation, and processing as a percent of total oil and natural gas sales are consistent with historical trends.

Depletion, Depreciation and Amortization

Depletion, depreciation and amortization (“DD&A”) was $6,710,092 as of December 31, 2025, compared to $2,407,098 as of December 31, 2024. DD&A was $25.03 per BOE for the year ended December 31, 2025, compared to $8.27 per BOE for the year ended December 31, 2024. The aggregate increase in DD&A expense for the year ended December 31, 2025 compared to 2024 was driven by a 203% increase in the DD&A rate per BOE, partially offset by a 8% decrease in production levels. The increase in the DD&A rate per BOE was driven by the increase in the oil and gas properties balance due to the development of the Seven Rivers waterflood interval and the decrease in the reserves balance due to the net conveyance of the additional 5% overriding royalty interest to Virtus, along with a change in reserve classification from proved to probable.

Accretion of Asset Retirement Obligations

Accretion expense was $46,426 as of December 31, 2025, compared to $144,988 as of December 31, 2024. Accretion expense was $0.17 per BOE for the year ended December 31, 2025, compared to $0.50 per BOE for the year ended December 31,2024.

The aggregate decrease in accretion expense for the year ended December 31, 2025, compared to the year ended December 31, 2024, was driven was driven by changes in certain assumptions.

General and Administrative

General and administrative expenses were $12,080,450 as of December 31, 2025, compared to $10,381,095 as of December 31, 2024. The increase in general and administrative expenses is primarily due to increased legal and professional fees associated with the transactions closed during the current period, partially offset by decreased stock-based compensation in the current period of $1,067,140 compared to $2,778,991 in the comparative period.

Interest Expense and amortization of debt discount

Interest expense was $4,892,170 for the year ended of December 31, 2025, compared to $7,643,200 for the year ended December 31, 2024. The decrease in interest expense is driven by the decreases in the Private Notes Payable and the Senior Secured Term Loan, along with the eventual settlement of the Senior Term Loan.

During the year ended December 31, 2025, the Company recorded $1,475,191 related to the amortization of financing costs compared to $2,361,627 for the year ended December 31, 2024. These costs are attributable to deferred finance costs paid on the Senior Secured Term Loan, Merchant Cash Advances, convertible notes payable and discounts associated with the Private Notes Payable during 2023.

Change in fair value of forward purchase agreement

The change in fair value of forward purchase agreement consisted of a gain of $561,099 for the year ended December 31, 2024, related to the inputs used in our fair value estimate of the forward purchase agreement put option, primarily the decline in our stock price during the year ended December 31, 2024. The key inputs to the fair value estimate include our stock price, and the likelihood, timing and price of a potential dilutive offering. The forward purchase agreement put option was settled during the year ended December 31, 2024, and therefore no change in fair value was recorded in the year ended December 31, 2025.

Change in fair value of derivative liabilities

The change in fair value of derivative liabilities related to the changes in fair value of the embedded conversion option on convertible notes issued, and consisted of a loss of $2,070,278 as of December 31, 2025. The key inputs to the fair value of the derivative liability include our stock price, estimated equity volatility, estimated discount rate and the likelihood, timing and price of a potential dilutive offering.

The change in fair value of derivative liabilities, related party related to the estimated fair value of the Put Option Right, and consisted of a gain of $341,000 as of December 31, 2025, compared to a loss of $746,000 for the year ended December 31, 2024. The key inputs to the fair value of the Put Option Right estimate include our stock price, estimated tenure of the holder as CEO, and an estimated discount rate.

Gain on extinguishment of liabilities

The Company recognized a gain on extinguishment of liabilities of $540,347 during the year ended December 31, 2025, primarily related to the settlement of the Senior Term Loan and other liabilities associated with the Company’s prior acquisition.

Change in fair value of warrant and convertible note liabilities

The change in fair value of warrant liabilities consisted of a loss of $152,490 as of December 31, 2025, compared to $804,004 as of December 31, 2024. The Company also recognized a loss of $131,677 from the change in fair value of its convertible note liabilities during the year ended December 31, 2025.

Liquidity and Capital Resources

Liquidity

Our main sources of liquidity have been internally generated cash flows from operations, credit facility borrowings and equity line financing sales and issuances. Our primary use of capital has been for the development of oil and gas properties, payment to vendors and payment of debt obligations. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.

As of December 31, 2025, we had outstanding debt of $2,161,486 of convertible notes payable, $200,000 from related party notes payable and $1,517,337 from merchant cash advances. A total of $1,617,337 of this is due within one year. As of December 31, 2025, we had $375,036 of cash and cash equivalents on hand and had a working capital deficit of $21,814,454. These conditions raise substantial doubt about our ability to continue as a going concern within one year after the date that the financial statements are issued.

The Company had negative cash flow from operations of $7,645,418 for the year ended December 31, 2025. Additionally, management’s plans to alleviate this substantial doubt include improving profitability through streamlining costs, maintaining active hedge positions for its proven reserve production, and the issuance of additional shares of Class A common stock.

We have a three-year equity line ELOC Purchase Agreement with a maximum funding limit of $150,000,000 that can fund our operations and production growth, and can be used to reduce liabilities. Through the date of this filing, we have received $11,130,586 in cash proceeds related to the sale of 17,000,000 shares of common stock under the ELOC Purchase Agreement and expect to continue to utilize it to fund current operational needs. We cannot assure you, however, that any additional capital will be available to us on favorable terms or at all. Our capital expenditures could be curtailed if our cash flows decline from expected levels. 

Cash Flows

Sources and uses of cash for the years ended December 31, 2025 and 2024, are as follows:

Operating Activities

The change in net cash flow used in operating activities for the year ended December 31, 2025, as compared to 2024 is primarily due to decreased production volumes and market prices for crude oil.

Investing Activities

Net cash provided by investing activities for the year ended December 31, 2025 was primarily related to cash proceeds from the sale of the of the 2025 ORRIs and Farmout Agreement for aggregate proceeds of $45,500,000, partially offset by the repurchase of the Pogo ORRI for $13,675,000 in cash, $6,563,949 in development costs for our reserves. Cash flows used in investing activities for the year ended December 31, 2024 consisted primarily of $3,555,062 of cash paid for development costs of our reserves.

Financing Activities

Net cash used in financing activities during the year ended December 31, 2025 were primarily related to the sale of common stock under the Common Stock Purchase Agreement of $8,502,252, proceeds of $3,312,550 from short term notes payable and proceeds of $561,120 from issuance of convertible debt and proceeds of $200,000 from related party loans offset by repayments of the Senior Secured Term Loan and Seller Note of $29,215,898, and repayment of the short term notes payable of $3,572,179. Cash flows used in financing activities for year ended December 31, 2024 were primarily related to repayments of the Senior Secured Term Loan of $3,984,286, short term notes payable of $989,018 and related party notes payable of $62,750, partially offset by $2,628,334 in cash proceeds from sales of common stock under the Common Stock Purchase Agreement, $1,298,200 from the short-term notes payable, and an additional $450,000 in cash proceeds from the related party Notes Payable issued during the year ended December 31, 2024.

Off Balance Sheet Arrangements

As of December 31, 2025 and 2024, the Company did not have any off-balance sheet arrangements, as defined in the rules and regulations of the SEC.

Contractual Obligations

We have contractual commitments under our Convertible Notes Payable which include periodic interest payments. See Note 5 to our consolidated financial statements. We have contractual commitments that may require us to make payments upon future settlement of our commodity derivative contracts. See Note 4 to our consolidated financial statements.

Our other liabilities represent current and noncurrent other liabilities that are primarily comprised of environmental contingencies, asset retirement obligations and other obligations for which neither the ultimate settlement amounts nor their timings can be precisely determined in advance.

Critical Accounting Estimates

The following is a discussion of our most critical accounting estimates, judgements and uncertainties that are inherent in the Company’s application of GAAP.

Proved Reserve Estimates

Estimates of our proved reserves included in this report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a proved reserve estimate is a function of:

Our proved reserve information included in this filing as of December 31, 2025 was prepared by independent petroleum engineers covering 94% of our reserves as of December 31, 2025, while the remaining 6% were developed by our internal reserve engineers. Our proved reserve information included in this filing as of December 31, 2024 was prepared by independent petroleum engineers covering 100% of our reserves. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, proved reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify, positively or negatively, material revisions to the estimate of proved reserves.

It should not be assumed that the standardized measure included as of December 31, 2025, is the current market value of our estimated proved reserves. In accordance with SEC requirements, we based the 2025 standardized measure on a twelve-month average of commodity prices on the first day of each month in 2025 and prevailing costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs utilized in the estimate. See Note 13 of notes to the consolidated financial statements for additional information.

Our estimates of proved reserves materially impact depletion expense. If the estimates of proved reserves decline, the rate at which we records depletion expense will increase, reducing future net income. Such a decline may result from lower commodity prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of our assessment of our proved properties for impairment.

Impairment of Proved Oil and Gas Properties

We review our proved properties to be held and used whenever management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Management assesses whether or not an impairment provision is necessary based upon estimated future recoverable proved reserves, commodity price outlooks, production and capital costs expected to be incurred to recover the reserves, discount rates commensurate with the nature of the properties and net cash flows that may be generated by the properties. Proved oil and gas properties are reviewed for impairment at the level at which depletion of proved properties is calculated. See Note 2 of notes to the consolidated financial statements.

Asset Retirement Obligations

We have significant obligations to remove tangible equipment and facilities and to restore the land at the end of crude oil and natural gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, credit-adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations, a corresponding adjustment is generally made to the crude oil and natural gas property or other property and equipment balance. See Note 2 of notes to the consolidated financial statements.

Litigation and Environmental Contingencies

We make judgments and estimates in recording liabilities for ongoing litigation and environmental remediation. Actual costs can vary from such estimates for a variety of reasons. The costs to settle litigation can vary from estimates based on differing interpretations of laws and opinions and assessments on the amount of damages. Similarly, environmental remediation liabilities are subject to change because of changes in laws and regulations, developing information relating to the extent and nature of site contamination and improvements in technology. A liability is recorded for these types of contingencies if we determine the loss to be both probable and reasonably estimable. See Note 10 of notes to the consolidated financial statements. 

Derivative Instruments - Hedging

The Company uses derivative financial instruments to mitigate its exposure to commodity price risk associated with oil prices. The Company’s derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. The Company has elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, the Company recognizes the change in derivative fair value between reporting periods currently in its consolidated statements of operations. The fair value of the Company’s derivative financial instruments is determined using industry-standard models that consider various inputs including: (i) quoted forward prices for commodities, (ii) time value of money and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Realized gains and losses from the settlement of derivative financial instruments and unrealized gains and unrealized losses from valuation changes in the remaining unsettled derivative financial instruments are reported in a single line item as a component of revenues in the consolidated statements of operations. Cash flows from derivative contract settlements are reflected in operating activities in the accompanying consolidated statements of cash flows. See Note 4 for additional information about the Company’s derivative instruments.

Derivative Instruments – Other Financial instruments

We have determined that the Put Option Right is a derivative liability required to be bifurcated from its host instrument. This liability was recorded as a liability at fair value on the consolidated balance sheet as of the reporting date in accordance with ASC 815. The fair value of the liability was estimated using a Monte-Carlo Simulation in a risk-neutral framework. Specifically, the future stock price is simulated assuming a Geometric Brownian Motion (“GBM”). For each simulated path, the forward purchase value is calculated based on the estimated term to exercise and then discounted back to present. Finally, the value of the Put Option Right is calculated as the average present value over all simulated paths.

We have also determined that conversion options within our convertible notes should be classified as derivative liabilities under ASC 815 and are required to be accounted for at fair value. The fair value of the liability was estimated using a Monte-Carlo Simulation in a risk-neutral framework. Specifically, the future stock price is simulated assuming a Geometric Brownian Motion (“GBM”). For each simulated path, the forward purchase value is calculated based on the estimated term to exercise and then discounted back to present. We estimate inputs for the fair value approach, including time to maturity, expected volatility, risk free rate and a continuous discount rate. The value of the embedded conversion options are calculated as the average present value over all simulated paths.

New Accounting Pronouncements

The effects of new accounting pronouncements are discussed in Note 2 to the consolidated financial statements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information otherwise required under this item.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

This information appears following Item 16 of this report and is included herein by reference.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

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

As required by Rules 13a-15 and 15d-15 under the Exchange Act, our Chief Executive Officer (Principal Executive Officer), Chief Financial Officer (Principal Financial Officer) and Controller (Principal Accounting Officer) carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures as of December 31, 2025. Based upon their evaluation, our Chief Executive Officer (Principal Executive Officer), Chief Financial Officer (Principal Financial Officer) and Controller (Principal Accounting Officer) concluded that, our disclosure controls and procedures were not effective related to the lack of sufficient accounting personnel to manage the Company’s financial accounting process including lack of proper preparation and review of account reconciliations, lack of segregation of duties, proper accounting for complex financial instruments and lack of design and implementation of controls related to oil and gas activities which constituted material weaknesses in our internal control over financial reporting. As a result, we performed additional analysis as deemed necessary to ensure that our financial statements were prepared in accordance with U.S. generally accepted accounting principles. Accordingly, management believes that the financial statements included in this Report present fairly in all material respects our financial position, results of operations and cash flows for the period presented.

A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the company’s annual or interim financial statements will not be prevented or detected on a timely basis. Management concluded that deficiencies in internal control over financial reporting existed relating to the lack of sufficient accounting personnel to manage the Company’s financial accounting process including lack of proper preparation and review of account reconciliations, lack of segregation of duties, proper accounting for complex financial instruments and lack of design and implementation of controls related to oil and gas activities constituted material weaknesses as defined in the SEC regulations. 

Management’s Report on Internal Controls Over Financial Reporting

As required by SEC rules and regulations implementing Section 404 of the Sarbanes-Oxley Act, our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our consolidated financial statements for external reporting purposes in accordance with GAAP. Our internal control over financial reporting includes those policies and procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of our company, (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors, and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the consolidated financial statements.

Management assessed the effectiveness of our internal control over financial reporting at December 31, 2025. In making these assessments, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework (2013). Based on our assessments and those criteria, management determined that we did not maintain effective internal control over financial reporting as of December 31, 2025 due to the material weaknesses in our internal control over financial reporting described above.

We plan to enhance our processes to identify and appropriately apply applicable accounting requirements to better evaluate and understand the nuances of the complex accounting standards that apply to our financial statements. Our plans at this time include hiring additional accounting staff and providing enhanced access to accounting literature, research materials and documents and increased communication among our personnel and third-party professionals with whom we consult regarding complex accounting applications. The elements of our remediation plan can only be accomplished over time, and we can offer no assurance that these initiatives will ultimately have the intended effects.

This Report does not include an attestation report on internal control over financial reporting from our independent registered public accounting firm due to our status as an emerging growth company under the JOBS Act.

Changes in Internal Control over Financial Reporting

During the most recently completed fiscal quarter, there has been no change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION.

During the three months ended December 31, 2025, none of our directors or officers (as defined in Rule 16a-1(f) of the Exchange Act) adopted, modified or terminated a “Rule 10b5-1 trading arrangement” or a “non-Rule 10b5-1 trading arrangement” as such terms are defined under Item 408 of Regulation S-K.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS.

Not applicable. 

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Directors and Executive Officers

Our Board of Directors consists of five directors. Three of the five directors are independent. Our current directors and executive officers are as follows:

Dante Caravaggio — Chief Executive Officer, President and Director. Mr. Caravaggio joined the company and has served as our Chief Executive Officer, President, and Director since December 2023. Since April 2021, Mr. Caravaggio has served as Chairman of SWI Excavating, one of the leading regional underground utility contractors in Colorado. From January 2020 to April 2022, Mr. Caravaggio served on the board of directors of McCarl’s Inc., a leading energy constructor in the northeast United States. Prior to joining McCarl’s Inc., Mr. Caravaggio was Senior Vice President, Hydrocarbons Americas for KBR (US) since January 2018. Prior to his role with KBR (US), Mr. Caravaggio held a number of roles as an executive and project manager with Parsons Corp. and Jacobs Engineering, overseeing upstream and downstream hydrocarbon projects. Mr. Caravaggio received his MBA at Pepperdine University in Malibu, California and his BS and MS in Petroleum Engineering at the University of Southern California.

Mr. Caravaggio is qualified to serve as CEO and as a member of our board of directors based on our review of his qualifications, attributes, and skills, including his oil and gas management experience and oil and gas acquisition experience.

Mitchell B. Trotter — Chief Financial Officer and Director. Mr. Trotter joined the company and has served as our Senior Vice President of Finance since October 2022 and became Chief Financial Officer and Director in November 2023. Mr. Trotter has 41 years of experience beginning his career in 1981 as an auditor with Coopers & Lybrand for seven years. He then served as CFO of two private investor backed private companies where the first was in real estate development and the latter in the engineering and construction industry. For the next 30 years, Mr. Trotter served in various CFO and Controller positions with three publicly traded companies in the engineering and construction services industry which were: Earth Tech to 2002; Jacobs Engineering to 2017; and AECOM to 2022. In those roles Mr. Trotter managed up to 400 plus staff across six continents supporting global operations with clients in multiple industries across private, semi-public and public sectors. Mr. Trotter earned his BS Accounting from Virginia Tech in 1981 and his MBA from Virginia Commonwealth University in 1994. His professional credentials are: Certified Public Accountant in Virginia; Certified Management Accountant; and Certified in Financial Management.

David M. Smith, Esq. — Vice President, General Counsel and Secretary of the Company.  Mr. Smith has served as our General Counsel and Secretary since November 2023.  Mr. Smith is a licensed attorney in Texas with over 40 years’ experience in the legal field of oil and gas exploration and production, manufacturing, purchase and sale agreements, exploration agreements, land and leaseholds, right of ways, pipelines, surface use, joint operating agreements, joint interest agreements, participation agreements and operations as well as transactional and litigation experience in oil and gas, real estate, bankruptcy and commercial industries. Mr. Smith purchased 142,500 shares as a founder. Mr. Smith has represented a number of companies in significant oil and gas transactions, mergers and acquisitions, intellectual property research and development and sales in the oil and gas drilling business sector. Mr. Smith began his career by serving in a land and legal capacity as Vice President of Land and, subsequently, as President of a public Canadian company until beginning his legal practice as a partner with several law firms and ultimately creating his own independent legal practice. Mr. Smith holds a degree in Finance from Texas A&M University, a Doctor of Jurisprudence from South Texas College of Law and is licensed before the Texas Supreme Court. 

Joseph V. Salvucci, Sr. — Independent Director and Chairman of the Board. Joseph V. Salvucci, Sr. has served as a member of our board of directors since December 2021. JVS Alpha Property, LLC, an entity which the majority is beneficially owned by Mr. Salvucci, with the balance owned by his immediate family, purchased 940,000 shares as a founder. Mr. Salvucci acquired PEAK Technical Staffing USA (“PEAK”), peaktechnical.com in 1986 and has grown the business to be a premier provider of USA-based contract engineers and technical specialists, on assignment worldwide through a comprehensive, customer focused, enterprise-wide Managed Staffing Solution. During his 35-year tenure as owner of the company, PEAK has expanded from Pittsburgh to do business in all 50 States, Canada, Europe, South America, India, and the Philippines. He served 10 years on the board of directors culminating as President and Board Chairman of the National Technical Services Association, a trade association representing 300,000 contractors on assignment in the technical staffing industry that later merged with the American Staffing Association. He is an active member of the Young Presidents Organization (YPO GOLD), formerly known as the World Presidents Organization (WPO) and has served as a member of the WPO International Board, as well as chairman of East Central US (ECUS) Region and Pittsburgh chapters as Chairman of the Board. As a 1976 Civil Engineering graduate of the University of Pittsburgh, he was a member of the Triangle (Engineering) Fraternity and its Alumni Association. He earned the Triangle Fraternity Distinguished Alumnus Citation in 2011 and currently serves on the Board of Directors. After earning the rank of Eagle Scout in 1970, he has remained active with the Boy Scouts of America, having served as the founding Chairman of the Board of the Pittsburgh Chapter of the National Eagle Scout Association, earning the NOESA (National Outstanding Eagle Scout Award) and the Silver Beaver Award and is past VP of Development and a board member of the Laurel Highlands Council in Western Pennsylvania. He was awarded the Manifesting the Kingdom of God Award by the Catholic Diocese of Pittsburgh in 2011. He was awarded the “Big Mac Award” from the Ronald McDonald Charities. As well as earning his BS in Civil Engineering from the University of Pittsburgh in 1976 and attended Harvard Business School’s OPM 33, graduating in 2003.

Joseph V. Salvucci, Jr. — Independent Director. Joseph V. Salvucci, Jr. has served as a member of our board of directors since December 2021. Mr. Salvucci began his career with PEAK Technical Staffing USA in November 2010 and is currently serving as the Chief Executive Officer overseeing nine branches with several hundred employees, and managing strategic initiatives for the company, including Staff Training, Career Pathing, and Organic Growth. Mr. Salvucci Jr received his Executive MBA from the University of Pittsburgh. In addition to his responsibilities as President/COO of PEAK, Mr. Salvucci serves on the board of Temporary Services Insurance Limited, a Workers’ Compensation company serving staffing companies.

Kyle Bulpitt — Independent Director. Mr. Bulpitt joined the board of directors and is the chair of the audit committee since January 2026. Mr. Bulpitt is a petroleum engineer and has extensive experience in the oil and gas industry in the areas of financial analysis for debt and equity financing, acquisitions and divestitures, financial modeling, Asset Backed Securitization issuances, field economic and development modeling, and petroleum reserves analysis. He is currently the Executive Vice President for Corporate Development at Aethel Energy, a newly formed General Catalyst Energy Transformation Company. At Aethel, he leads all corporate development activities related to acquisition and divestiture efforts, overseeing technical, financial and commercial evaluation of acquisition and divestiture opportunities. Mr. Bulpitt led the underwriting efforts on their initial $400 million acquisition. He also oversees the reserves process across all operated and non-operated assets, managing internal engineers and third-party reserve firms. Mr. Bulpitt was a reservoir engineer with ConocoPhillips. Over his five years with them, he performed various roles including: resources assessments; long range portfolio planning; field development modeling; analyzed asset scheduling, production and cost to optimize long term program performance; completed field economic and development model for asset divestiture; and other petroleum reserve analysis and actions. . He graduated from Texas A&M University in 2014 with a Bachelor of Science in Petroleum Engineering, Magna Cum Laude. 

Family Relationships

There are no family relationships between any of our officers and directors, except that Mr. Joseph V. Salvucci, Sr. and Mr. Joseph V. Salvucci, Jr. are father and son, respectively.

Number and Terms of Office of Officers and Directors

Our board of directors has five directors. Our board of directors is divided into two classes with only one class of directors being elected in each year and each class (except for those directors appointed prior to our first annual meeting of stockholders) serving a two-year term. The class I directors consist of Dante Caravaggio and Joseph V. Salvucci, Jr., and their term will expire at the annual meeting of stockholders in even-numbered years. The class II directors consist of Mitchell Trotter, Kyle Bulpitt, and Joseph V. Salvucci, Sr. and their term will expire at the annual meeting of stockholders in odd-numbered years.

Our officers are elected by the board of directors and serve at the discretion of the board of directors, rather than for specific terms of office. Our board of directors is authorized to appoint persons to the offices set forth in our bylaws as it deems appropriate. Our bylaws provide that our officers may consist of a Chief Executive Officer, President, Chief Financial Officer, Vice Presidents, Secretary, Assistant Secretaries, Treasurer and such other offices as may be determined by the board of directors. 

Director Independence

The NYSE American listing standards require that a majority of our board of directors be independent. An “independent director” is defined generally as a person other than an officer or employee of the company or its subsidiaries or any other individual having a relationship which in the opinion of the company’s board of directors, would interfere with the director’s exercise of independent judgment in carrying out the responsibilities of a director. Of the current members of our board of directors, Messrs. Salvucci Sr., Salvucci Jr., and Kyle Bulpitt are each considered an “independent director” under the NYSE American listing standards and applicable SEC rules. Our independent directors will have regularly scheduled meetings at which only independent directors are present.

Committees of the Board of Directors

The standing committees of our Board of Directors consist of an audit committee (the “Audit Committee”), a compensation committee (the “Compensation Committee”), and a Nominating and Corporate Governance Committee (the “Nominating Committee”). The Audit Committee, Compensation Committee, and the Nominating Committee report to the Board of Directors.

Audit Committee

The members of our Audit Committee are Messrs. Bulpitt and Salvucci Sr., and Mr. Bulpitt serves as chairman of the Audit Committee. As a smaller reporting company under the NYSE American listing standards, we are required to have at least two members on the Audit Committee. The rules of the NYSE American and Rule 10A-3 of the Exchange Act require that the audit committee of a listed company be comprised solely of independent directors. Each of Messrs. Salvucci Sr. and Bulpitt qualifies as an independent director under applicable rules. Each member of the Audit Committee is financially literate and our board of directors has determined that Mr. Bulpitt qualifies as an “audit committee financial expert” as defined in applicable SEC rules.

We have adopted an audit committee charter, which details the principal functions of the audit committee, including:

Compensation Committee

The members of our Compensation Committee are Messrs. Salvucci Sr., Salvucci, Jr., and Bulpitt. Mr. Salvucci, Jr. serves as chairman of the Compensation Committee. Under the NYSE American listing standards and applicable SEC rules, we are required to have at least two members on the Compensation Committee, all of whom must be independent.

We have adopted a compensation committee charter, which details the principal functions of the compensation committee, including:

The charter also provides that the Compensation Committee may, in its sole discretion, retain or obtain the advice of a compensation consultant, legal counsel or other adviser and will be directly responsible for the appointment, compensation and oversight of the work of any such adviser. However, before engaging or receiving advice from a compensation consultant, external legal counsel or any other adviser, the compensation committee will consider the independence of each such adviser, including the factors required by the NYSE American and the SEC.

Nominating and Corporate Governance Committee

The members of our Nominating Committee are Messrs. Bulpitt, Salvucci Sr. and Salvucci Jr. Mr. Salvucci Jr. serves as chair of Nominating Committee.

The primary purposes of our Nominating Committee is to assist the board in:

The Nominating Committee is governed by a charter that complies with the rules of the NYSE American.

A copy of each of our Nominating Committee Charter, Compensation Committee Charter, and Audit Committee Charter are accessible at https://hnra-nyse.com/.

Director Nominations

Our Nominating Committee will recommend to the board of directors candidates for nomination for election at the annual meeting of the stockholders. The board of directors will also consider director candidates recommended for nomination by our stockholders during such times as they are seeking proposed nominees to stand for election at the next annual meeting of stockholders (or, if applicable, a special meeting of stockholders).

We have not formally established any specific, minimum qualifications that must be met or skills that are necessary for directors to possess. In general, in identifying and evaluating nominees for director, the board of directors considers educational background, diversity of professional experience, knowledge of our business, integrity, professional reputation, independence, wisdom, and the ability to represent the best interests of our stockholders.

Compensation Committee Interlocks and Insider Participation

None of our future executive officers currently serves, and in the past year has not served, as a member of the board of directors or compensation committee of any entity that has one or more executive officers serving on our board of directors.

Short Swing Profit Disgorgement

Dante Caravaggio, our Chief Executive Officer, has disbursed $550 to us in order for us to recapture short swing profits received by him when he sold shares and repurchased them for a profit in 2025.

Code of Ethics

We have adopted a Code of Ethics applicable to our directors, officers and employees. The Code of Ethics is available on our website accessible at https://eon-r.com/. In addition, a copy of the Code of Ethics will be provided without charge upon request from us. We intend to disclose any amendments to or waivers of certain provisions of our Code of Ethics in a Current Report on Form 8-K. 

Insider Trading Policy

Our board of directors has adopted an Insider Trading Policy which prohibits trading based on “material, nonpublic information” regarding our company or any company whose securities are listed for trading or quotation in the United States. The policy covers all officers and directors of the company and its subsidiaries, all other employees of the company and its subsidiaries, and consultants or contractors to the company or its subsidiaries who have or may have access to material non-public information and members of the immediate family or household of any such person. The policy is reasonably designed to promote compliance with insider trading laws, rules and regulations, and NYSE listing standards. The policy is filed as an exhibit to this Annual Report on Form 10-K.

Clawback Policy

Our board of directors has adopted a clawback policy, which provides that in the event we are required to prepare an accounting restatement due to noncompliance with any financial reporting requirements under the securities laws or otherwise erroneous data or we determine there has been a significant misconduct that causes financial or reputational harm, we shall recover a portion or all of any incentive compensation. The policy is filed as an exhibit to this Annual Report on Form 10-K.

Timing of Option Awards

We provide the following discussion of the timing of option awards in relation to the disclosure of material nonpublic information, as required by Item 402(x) of Regulation S-K. We have no policy or practice regarding option grant timing because we do not grant, and have not granted, options to our NEOs. We have not timed the disclosure of material nonpublic information to affect the value of executive compensation. During 2025, we did not grant any stock options to the NEOs during any period beginning four business days before the filing of a periodic report on Form 10-Q or Form 10-K or the filing or furnishing of a current report on Form 8-K disclosing material non-public information (other than a current report on Form 8-K disclosing a material new stock option award under Item 5.02(e) of such Form 8-K), and ending one business day after the filing or furnishing of such report with the SEC.

Executive Officers

Our executive officers are:

Biographical information for these individuals is set forth above.

Limitation on Liability and Indemnification of Officers and Directors

Our Second A&R Charter provides that our officers and directors will be indemnified by us to the fullest extent authorized by Delaware law, as it now exists or may in the future be amended. In addition, our Second A&R Charter provides that our directors will not be personally liable for monetary damages to us for breaches of their fiduciary duty as directors, except to the extent such exemption from liability or limitation thereof is not permitted by the DGCL.

Our bylaws also permit us to maintain insurance on behalf of any officer, director or employee for any liability arising out of his or her actions, regardless of whether Delaware law would permit such indemnification. We have obtained a policy of directors’ and officers’ liability insurance that insures our officers and directors against the cost of defense, settlement or payment of a judgment in some circumstances and insures us against our obligations to indemnify our officers and directors.

These provisions may discourage stockholders from bringing a lawsuit against our directors for breach of their fiduciary duty. These provisions also may have the effect of reducing the likelihood of derivative litigation against officers and directors, even though such an action, if successful, might otherwise benefit us and our stockholders. Furthermore, a stockholder’s investment may be adversely affected to the extent we pay the costs of settlement and damage awards against officers and directors pursuant to these indemnification provisions.

We believe that these provisions, the directors’ and officers’ liability insurance and the indemnification agreements are necessary to attract and retain talented and experienced officers and directors.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934, as amended, or the Exchange Act, requires our executive officers, directors and persons who beneficially own more than 10% of a registered class of our equity securities to file with the Securities and Exchange Commission initial reports of ownership and reports of changes in ownership of our shares of common stock and other equity securities. These executive officers, directors, and greater than 10% beneficial owners are required by SEC regulation to furnish us with copies of all Section 16(a) forms filed by such reporting persons.

Based solely on our review of such forms furnished to us and written representations from certain reporting persons, we believe that all filing requirements applicable to our executive officers, directors and greater than 10% beneficial owners were filed in a timely manner in 2025, except for one late Form 4 filing for each of Mitchell Trotter, Joseph Salvucci, Sr., Mark Williams, and Byron Blount, which all such filings have been made as of the date of this Annual Report on Form 10-K.

ITEM 11. EXECUTIVE COMPENSATION

Summary Compensation Table

The following table sets forth information regarding compensation earned during the years ended December 31, 2025 and 2024 by our principal executive officers and our two other most highly compensated executive officers as of the end of December 31, 2025 (“NEOs”).