EON Resources Inc.: Form 10-K for the period ended Dec 31, 2024

Overview

EON Resources, Inc. (formerly HNR Acquisition Corp) (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 identified as the initial target for our initial business combination. Our efforts to identify a prospective target business were limited to a particular industry or geographic region. While we were permitted to pursue an acquisition opportunity in any industry or sector, we focused on assets used in exploring, developing, producing, transporting, storing, gathering, processing, fractionating, refining, distributing or marketing of natural gas, natural gas liquids, crude oil or refined products in North America.

Purchase

On December 27, 2022, we, entered into a Membership Interest Purchase Agreement (the “Original MIPA”) with CIC Pogo LP, a Delaware limited partnership (“CIC”), DenCo Resources, LLC, a Texas limited liability company (“DenCo”), Pogo Resources Management, LLC, a Texas limited liability company (“Pogo Management”), 4400 Holdings, LLC, a Texas limited liability company (“4400” and, together with CIC, DenCo and Pogo Management, collectively, “Seller” and each a “Seller”), and, solely with respect to Section 7.20 of the Original MIPA, HNRAC Sponsors LLC, a Delaware limited liability company (“Sponsor”). On August 28, 2023, we, HNRA Upstream, LLC, a newly formed Delaware limited liability company which is managed by us, and is a subsidiary of ours (“OpCo”), and HNRA Partner, Inc., a newly formed Delaware corporation and wholly owned subsidiary of ours (“SPAC Subsidiary”, and together with us and OpCo, “Buyer” and each a “Buyer”), entered into an Amended and Restated Membership Interest Purchase Agreement (the “A&R MIPA”) with Seller, and, solely with respect to Section 6.20 of the A&R MIPA, the Sponsor, which amended and restated the Original MIPA in its entirety (as amended and restated, the “MIPA”). Our stockholders approved the transactions contemplated by the MIPA at a special meeting of stockholders that was originally convened October 30, 2023, adjourned, and then reconvened on November 13, 2023 (the “Special Meeting”).

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

• We filed a Second Amended and Restated Certificate of Incorporation (the “Second A&R Charter”) with the Secretary of State of the State of Delaware, pursuant to which the number of authorized shares of our capital stock, par value $0.0001 per share, was increased to 121,000,000 shares, consisting of (i) 100,000,000 shares of Class A Common Stock, (ii) 20,000,000 shares of Class B Common Stock, and (iii) 1,000,000 shares of preferred stock, par value $0.0001 per share;
• Our shares of common stock were reclassified as Class A Common Stock; the Class B Common Stock has no economic rights but entitles its holder to one vote on all matters to be voted on by stockholders generally; holders of shares of Class A Common Stock and shares of Class B Common Stock will vote together as a single class on all matters presented to our stockholders for their vote or approval, except as otherwise required by applicable law or by the Second A&R Charter;
• (A) We contributed to OpCo (i) all of our assets (excluding our interests in OpCo and the aggregate amount of cash required to satisfy any exercise by our stockholders of their Redemption Rights (as defined below)) and (ii) 2,000,000 newly issued shares of Class B Common Stock (such shares, the “Seller Class B Shares”) and (B) in exchange therefor, OpCo issued to us a number of Class A common units of OpCo (the “OpCo Class A Units”) equal to the number of total shares of Class A Common Stock issued and outstanding immediately after the closing (the “Closing”) of the transactions contemplated by the MIPA (following the exercise by EON stockholders of their Redemption Rights) (such transactions, the “SPAC Contribution”); and
• Immediately following the SPAC Contribution, OpCo contributed $900,000 to SPAC Subsidiary in exchange for 100% of the outstanding common stock of SPAC Subsidiary (the “SPAC Subsidiary Contribution”);
• Immediately following the SPAC Subsidiary Contribution, Seller sold, contributed, assigned, and conveyed to (A) OpCo, and OpCo acquired and accepted from Seller, ninety-nine percent (99.0%) of the outstanding membership interests of Pogo Resources, LLC, a Texas limited liability company (“Pogo” or the “Target”), and (B) SPAC Subsidiary, and SPAC Subsidiary purchased and accepted from Seller, one percent (1.0%) of the outstanding membership interest of Target (together with the ninety-nine percent (99.0%) interest, the “Target Interests”), in each case, in exchange for (x) $900,000 of the Cash Consideration (as defined below) in the case of SPAC Subsidiary and (y) the remainder of the Aggregate Consideration (as defined below) in the case of OpCo (such transactions, together with the SPAC Contribution and SPAC Subsidiary Contribution and the other transactions contemplated by the MIPA, the “Purchase”).

The “Aggregate Consideration” for the Target Interests was: (a) cash in the amount of $31,074,127 in immediately available funds (the “Cash Consideration”), (b) 2,000,000 Class B common units of OpCo (“OpCo Class B Units”) valued at $10.00 per unit (the “Common Unit Consideration”), which will be equal to and exchangeable into 2,000,000 shares of Class A Common Stock issuable upon exercise of the OpCo Exchange Right (as defined below), as reflected in the amended and restated limited liability company agreement of OpCo that became effective at Closing (the “A&R OpCo LLC Agreement”), (c) the Seller Class B Shares, (d) $15,000,000 payable through a promissory note to Seller (the “Seller Promissory 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. The Aggregate Consideration is subject to adjustment in accordance with 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 exercised the OpCo Exchange Right as it relates 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”.

First Amendment to Amended and Restated Membership Interest Purchase Agreement

On November 15, 2023, Buyer, Seller, and Sponsor entered into the MIPA Amendment, whereby the Parties agreed to extend the outside date for the transaction to November 30, 2023, and to place 500,000 shares of Seller Class B Shares into escrow instead of 500,000 OpCo Class B Units.

Settle Up Letter Agreement

On November 15, 2023, Buyer and Seller entered into the Settle Up Letter Agreement, whereby Seller agreed to accept a minimum amount of cash at Closing less than $33,000,000, provided that, on or before November 21, 2023, Buyer must 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.

OpCo A&R LLC Agreement

In connection with the Closing, EON and Pogo Royalty, LLC, a Texas limited liability company, an affiliate of Seller and Seller’s designated recipient of the Aggregate Consideration (“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, each OpCo unitholder (excluding EON) will, subject to certain timing procedures and other conditions set forth therein, have 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. Additionally, the holders of OpCo Class B Units will be required to exchange all of their OpCo Class B Units (a “Mandatory Exchange”) upon the occurrence of the following: (i) upon the direction of EON with the consent of at least fifty percent (50%) of the holders of OpCo Class B Units; or (ii) upon the one-year anniversary of the Mandatory Conversion Trigger Date. 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 will be cancelled.

The OpCo Preferred Units will 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 Market Price of the Class A Common Stock (the “Conversion Price”). The “Market Price” means 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. On the Mandatory Conversion Trigger Date, EON will issue a number of shares of Class B Common Stock to Pogo Royalty equivalent to the number of OpCo Class B Units issued to Pogo Royalty. If not exchanged sooner, such newly issued OpCo Class B Units shall automatically exchange into Class A Common Stock on the one-year anniversary of the Mandatory Conversion Trigger Date at a ratio of one OpCo Class B Unit for one share of Class Common Stock. An equivalent number of shares of Class B Common Stock must be surrendered with the OpCo Class B Units to us in exchange for the Class A Common Stock. As noted above, the OpCo Class B Units must be exchanged upon the one-year anniversary of the Mandatory Conversion Trigger Date.

Promissory Note

In connection with the Closing, OpCo issued the Seller Promissory Note to Pogo Royalty in the principal amount of $15,000,000. The Seller Promissory Note provides for a maturity date that is six (6) months from the Closing Date, bears an interest rate equal to 12% per annum, and contains no penalty for prepayment. If the Seller Promissory Note is not repaid in full on or prior to its stated maturity date, OpCo will owe interest from and after default equal to the lesser of 18% per annum and the highest amount permissible under law, compounded monthly. The Seller Promissory Note is subordinated to the Term Loan (as defined herein).

Registration Rights Agreement

In connection with the Closing, EON and Pogo Royalty entered into a Registration Rights Agreement (the “Registration Rights Agreement”), pursuant to which EON has agreed to provide Pogo Royalty with certain registration rights with respect to the shares of Class A Common Stock issuable upon exercise of the OpCo Exchange Right, including filing with the SEC an initial registration statement on Form S-1 covering the resale by the Pogo Royalty of the shares of Class A Common Stock issuable upon exercise of the OpCo Exchange Right so as to permit their resale under Rule 415 under the Securities Act, no later than thirty (30) days following the Closing, use its commercially reasonable efforts to have the initial registration statement declared effective by the SEC as soon as reasonably practicable following the filing thereof with the SEC, and use commercially reasonable efforts to convert the Form S-1 (and any subsequent registration statement) to a shelf registration statement on Form S-3 as promptly as practicable after EON is eligible to use a Form S-3 Shelf.

In certain circumstances, Pogo Royalty can demand our assistance with underwritten offerings, and Pogo Royalty will be entitled to certain piggyback registration rights.

Option Agreement

In connection with the Closing, EON, HNRA Royalties, LLC, a newly formed Delaware limited liability company and wholly owned subsidiary of EON (“HNRA Royalties”) and Pogo Royalty entered into an Option Agreement (the “Option Agreement”). Pogo Royalty owns certain overriding royalty interests in certain oil and gas assets owned by Pogo (the “ORR Interest”). Pursuant to the Option Agreement, Pogo Royalty granted irrevocable and exclusive option to HNRA Royalty to purchase the ORR Interest for the Option Price (as defined below) at any time prior to November 15, 2024. The option is not exercisable while the Seller Promissory Note is outstanding.

The purchase price for the ORR Interest upon exercise of the option is: (i) (1) $30,000,000 the (“Base Option Price”), plus (2) an additional amount equal to interest on the Base Option Price of twelve percent (12%), compounded monthly, from the Closing Date through the date of acquisition of the ORR Interest, minus (ii) any amounts received by Pogo Royalty in respect of the ORR Interest from the month of production in which the effective date of the Option Agreement occurs through the date of the exercise of the option (such aggregate purchase price, the “Option Price”).

The Option Agreement and the option will immediately terminate upon the earlier of (a) Pogo Royalty’s transfer or assignment of all of the ORR Interest in accordance with the Option Agreement and (b) November 15, 2024.

Pursuant to the Option Agreement, upon execution, EON issued to Pogo Royalty 10,000 shares of Class A Common Stock.

Director Nomination and Board Observer Agreement

In connection with the Closing, we entered into Director Nomination and Board Observer Agreement (the “Board Designation Agreement”) with CIC. Pursuant to the Board Designation Agreement, CIC has the right, at any time CIC beneficially owns our capital stock, to appoint two board observers to attend all meetings of our Board of Directors. In addition, after the time of the conversion of the OpCo Preferred Units owned by Pogo Royalty, CIC will have the right to nominate a certain number of members of the board of directors depending on Pogo Royalty’s ownership percentage of Class A Common Stock as further provided in the Board Designation Agreement.

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 will have the right (“Put Right”) to cause the Founders to purchase Pogo Royalty’s OpCo Preferred Units at a purchase price per unit equal to $10.00 per unit plus the product of (i) the number of days elapsed since the effective date of the Backstop Agreement and (ii) $10.00 divided by 730. Seller’s right to exercise the Put Right will survive for six (6) months following the date the Trust Shares (as defined below) are not restricted from transfer under the Letter Agreement (as defined in the MIPA) (the “Lockup Expiration Date”).

As security that the Founders will be able to purchase the OpCo Preferred Units upon exercise of the Put Right, the Founders agreed to place at least 1,300,000 shares of Class A Common Stock into escrow (the “Trust Shares”), which the Founders can sell or borrow against to meet their obligations upon exercise of the Put Right, with the prior consent of Seller. EON is not obligated to purchase the OpCo Preferred Units from Pogo Royalty under the Backstop Agreement. Until the Backstop Agreement is terminated, Pogo Royalty and its affiliates are not permitted to engage in any transaction which is designed to sell short the Class A Common Stock or any other publicly traded securities of EON.

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; (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 shares; (c) if the Backstop Agreement is not terminated prior to the Lockup Expiration Date, to issue an aggregate number of newly issued shares of Class A Common Stock equal to (i) (A) the number of Trust Shares, divided by (B) the simple average of the daily VWAP of the Class A Common Stock during the five (5) Trading Days prior to the date of the termination of the Backstop Agreement, subject to a minimum of $6.50 per share, multiplied by (C) a price between $10.00-$13.00 per share (as further described in the Founder Pledge Agreement), minus (ii) the number of Trust Shares; and (d) following the purchase of OpCo Preferred Units by a Founder pursuant to the Put Right, to issue a number of newly issued shares of Class A Common Stock equal to the number of Trust Shares sold by such Founder. Until the Founder Pledge Agreement is terminated, the Founders are not permitted to engage in any transaction which is designed to sell short the Class A Common Stock or any other publicly traded securities of EON.

Purchase, Sale, Termination and Exchange Agreement

On February 10, 2025, the Company entered into a Purchase, Sale, Termination and Exchange Agreement (the “Agreement”), by and among the Company, OpCo, SPAC Subsidiary, HNRA Royalties, Pogo Royalty, CIC, DenCo, Pogo Management, and 4400. The closing of the transactions contemplated by the Agreement (the “Closing”) is subject to the satisfaction of various conditions, including the Company obtaining financing.

Pursuant to the Agreement, the Company agreed to purchase the ORRI from Pogo Royalty for $14,000,000, payable in cash at the Closing. In addition, at the Closing, Pogo Royalty agreed to waive all outstanding interest accrued under the Seller Note, reduce the outstanding principal amount of the Seller Note to $8,000,000 and settle and discharge the Seller Note in exchange for the payment of $8,000,000 in cash. Pogo Royalty further agreed to assign and transfer the OpCo Preferred Units to OpCo in exchange for the issuance by the Company of 3,000,000 shares of Class A Common Stock at the Closing.

As consideration for entering into the Agreement, the Company agreed to release the Escrow Shares to Pogo Royalty and to promptly process any exchange notice delivered by Pogo Royalty to exchange the Escrow Share for shares of Class A Common Stock, and Pogo Royalty agreed to deliver such exchange notice within two days of the date of the Agreement. The Agreement contains customary representations, warranties, indemnification provisions closing conditions, and covenants.

The Closing is contingent upon the occurrence of certain conditions, including (i) the availability of financing to the Company, (ii) the receipt by Pogo Royalty of a consent of First International Bank & Trust to the Agreement and a written termination agreement, executed by the Company and First International Bank & Trust, terminating that certain Subordination Agreement, dated as of November 15, 2023, by and among First International Bank & Trust, the Company and Pogo Royalty, (iii) the receipt by the Company of any required stockholder consents, (iv) the respective representations and warranties of the parties being true and correct, subject to certain materiality exceptions and (v) the performance by the parties in all material respects of their respective obligations under the Agreement.

The Agreement may be terminated at any time by mutual consent of the parties thereto or by any one party if the counterparty is in material breach of the Agreement. If the Closing does not occur prior to 1:00 p.m. Central Time on June 3, 2025, the Agreement will automatically terminate. No assurances can be made that the Company will satisfy these conditions or that the Closing will otherwise occur.

Overview

Pogo is an exploration and production company that began operations in February 2017. Pogo is based in Dallas, Texas, and a field office in Loco Hills, New Mexico. As of December 31, 2024, our operating focus is the Northwest Shelf of the Permian Basin, with a specific emphasis on oil and gas producing properties located in the Grayburg-Jackson Field in Eddy County, New Mexico. Pogo is the Operator of Record of its oil and gas properties, operating its properties through its wholly owned subsidiary, LH Operating LLC. Pogo completed multiple acquisitions in 2018 and 2019. These acquisitions included multiple producing properties in Lea and Eddy counties, New Mexico. In 2020, after identifying its core development property, Pogo successfully completed a series of divestures of its non-core properties. Then, with one key asset, its Grayburg-Jackson Field in Eddy County, New Mexico, Pogo focused all of its efforts on developing this asset. This has been Pogo’s focus for 2022 and 2023.

Currently, we have 12 employees (5 executive officers where 4 are in Houston and 1 in Lubbock; 7 field staff in Loco Hills). From time to time, on an as needed basis, contract workers handle additional necessary responsibilities.

Pogo owns, manages, and operates, through its wholly owned subsidiary, LH Operating, LLC, 100% working interest in a gross 13,700 acres located on the Northwest Shelf of the prolific oil and gas producing Permian Basin. Pogo benefits from cash flow growth through continued development of its working interest’s ownership, with relatively low capital cost and lease operating expenses. As of December 31, 2024, average net daily production associated with Pogo’s working interests was 811 barrel of oil equivalent (“BOE”) per day consisting of 86% oil and 14% natural gas. Pogo expects to continue to grow its cash flow by production enhancements in its operations on its gross 13,700-acre leasehold. Furthermore, Pogo intends to make additional acquisitions within the Permian Basin, as well as other oil and gas producing regions in the USA, that meet its investment criteria for minimum risk, geologic quality, operator capability, remaining growth potential, cash flow generation and, most importantly, rate of return.

As of December 31, 2024, 100% of Pogo’s gross 13,700 leasehold acres were located in Eddy County, New Mexico, where 100% of the leasehold working interests owned by Pogo consist of state and federal lands. Pogo believes the Permian Basin offers some of the most compelling rates of return for Pogo and significant potential for cash flow growth. As a result of compelling rates of return, development activity in the Permian Basin has outpaced all other onshore U.S. oil and gas basins since the end of 2016. This development activity has driven basin-level production to grow faster than production in the rest of the United States.

Pogo’s working interests entitle it to receive an average of 97% of the net revenue from crude oil and natural gas produced from the oil and gas reservoirs underlying its acreage. Pogo is not under any mandatory obligation to fund drilling and completion costs associated with oil and gas development because 100% of its lease holdings are held by production. As a working interest owner with significant net earnings, Pogo seeks to fully capture all remaining oil and gas reserves underlying its leasehold acres by systematically developing its low risk, predictable, proven reserves by means of adding perforations in previously drilled and completed wells, were applicable, and drilling new wells in a predetermined drilling pattern. Accordingly, Pogo’s development model generates strong margins greater than 60%, at low risk, predictable, production outcomes that requires low overhead and is highly scalable. For the year ended December 31, 2024, Pogo’s lifting cost was about $28.92 per barrel of oil equivalent at a realized price of $77.01 per BOE, excluding the impact of settled commodity derivatives. Pogo is led by a management team with extensive oil and gas engineering, geologic and land expertise, long-standing industry relationships and a history of successfully managing a portfolio of working and leasehold interests, producing crude oil and natural gas assets. Pogo intends to capitalize on its management team’s expertise and relationships to increase production and cash flow in the field.

Pogo Market Conditions

The price that Pogo receives for the oil and natural gas we produce is largely a function of market supply and demand. Because Pogo’s oil and gas revenues are heavily weighted toward oil, Pogo 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 Pogo 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, 2024, all of the Company’s properties were located exclusively within the Northwest Shelf of the Permian Basin. As of December 2023, 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, 2024, 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. Pogo 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 Grayburg-Jackson Field

As of December 31, 2024, the Company owns a 100% working interest in 13,700 gross acres located in Eddy County, New Mexico, with a 74% weighted average net revenue. The 13,700 gross acres are strategically located in the prolific oil field, Grayburg-Jackson field. 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, 2024, 100% of the Company’s working interests are held by production (“HBP”) meaning that Pogo is not under time sensitive obligation to drill or work-over any wells on its 13,700 acres. As of December 31, 2023, 100% of the wells and leases are operated by Pogo. Pogo is the official Operator of record with the state and federal regulatory agencies. As of December 31, 2024, 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, Pogo’s working interests reside entirely in the Northwest Shelf of the Permian Basin, which Pogo believes is one of the premier crude oil and natural gas producing regions in the United States. As of December 31, 2024, Pogo’s working interests covered 13,700 gross acres, with the royalty owners retaining a weighted average 26% royalty. The following table summarizes Pogo’s working interest’s position in the lands comprising its leasehold as of December 31, 2024.

LH Operating, LLC Northwest Shelf (Permian Basin) Leasehold

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

(2) No unleased royalty interests as of December 31, 2024.

As of December 31, 2024, Pogo has working interests in 342 shallow (above 4,000 ft), vertical wells producing oil and gas in paying quantities. Ninety-five of the 342 producing wells were completed between 2019 and June 2022 by Pogo. In 2019, Pogo 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, Pogo 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, Pogo 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 2023, the total production increased to 1,022 BOE/d. Pogo’s management team has determined, and verified by Haas and Cobb Petroleum Consultants, LLC (“Cobb ”), that 115 proved well patterns, developed but non-producing, are scheduled to be brought into production between 2024 and 2027.

As of December 31, 2024, the estimated proved crude oil and natural gas reserves attributable to Pogo’s interests in its underlying acreage were 14,492 MBOE (97% oil and 3% natural gas), based on a reserve report prepared by Cobb , worldwide petroleum consultants. Of these reserves, approximately 28% were classified as proved developed producing (“PDP”) reserves, 42% were classified as proved developed non-producing (“PDNP”) reserves and 30% were classified as proved undeveloped (“PUD”) reserves. PUD reserves included in these estimates relate solely to wells that are not yet drilled nor were not yet producing in paying quantities as of December 31, 2024. Estimated proved reserves included in this section is presented on an actual basis, without giving pro forma effect to transactions completed after such dates.

Pogo believes its production and discretionary cash flows will grow significantly as Pogo completes its substantial PDNP inventory of 7R well patterns located on its gross 13,700 acreage. As of December 31, 2024, Pogo had production from 342 vertical wells, and it has identified 127 additional PDNP well patterns based on its assessment of current geological, engineering and land data. As of December 31, 2024, Pogo has identified 43 PUD well patterns based on its assessment of current geological, engineering and land data

Pogo’s working interest development strategy anticipates shifting any drilling activity associated with its PUD reserves following Pogo’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, 2024, Pogo’s leasehold position has 25.7 wells per square mile. Pogo expects to see increases in its production, revenue and discretionary cash flows from the development of 115 well patterns in the 7R reservoir. Pogo believes its current leasehold working interests provide the potential for significant long-term organic revenue growth as Pogo develops its PDNP reserves to increase crude oil and natural gas production.

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, 2024, EON, in conjunction with Cobb, a third-party engineering consulting firm, has confirmed that EON has 127, low cost, well patterns to be developed during 2025 to 2028. The total costs to complete these 127 well patterns have been predetermined by historical analysis. The estimated cost to complete each PDNP pattern is $339,252 and the estimated cost to complete each PUD pattern is $1,187,698. A single well pattern consists of one each 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 Pogo 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 Pogo 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. Pogo believes the Permian Basin provides an attractive combination of highly-economic and oil-weighted geologic and reservoir properties, opportunities for development with significant inventory of drilling locations and zones to be delineated our top-tier management team.

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

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. Pogo 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. Pogo intends to maintain a conservative leverage profile and utilize a mix of cash flows from operations and issuance of debt and equity securities to finance future acquisitions.

Competitive Strengths

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

• Permian Basin focused public company positioned as a preferred buyer in the basin. The Company believes that its focus on the Permian Basin will position it as a preferred buyer of Permian Basin working interests in known producing oil and gas fields. As of December 31, 2024, 100% of its current leasehold is located in an area with proven results from multiple stacked productive zones. The Company’s properties in the Permian Basin are high-quality, high-margin, and oil weighted, and the Company believes we will be viewed favorably by the investment community as compared to equity consideration diluted by lower quality assets located in less prolific basins. Pogo targets acquisitions of operated properties with high working interest percentages that are relatively undeveloped in the Permian Basin, and it believes the organic development of its acreage will result in substantial production growth regardless of acquisition activity.
• Favorable and stable operating environment in the Permian Basin. With over 400,000 wells drilled in the Permian Basin since 1900, the region features a reliable and predictable geological and regulatory environment, according to Enverus. The Company believes that the impact of new technology, combined with the substantial geological information available about the Permian Basin, also reduces the risk of development and exploration activities as compared to other, emerging hydrocarbon basins. As of December 31, 2024, 100% of the Company’s acreage was located in New Mexico and does not require federal approval to develop its 115 well patterns classified as PDNP reserves and does not have impediments in order to deliver Pogo’s production to market.
• Experienced team with an extensive track record. the Company’s team has deep industry experience focused on development in the Permian Basin as well as other significant oil producing regions and has a track record of identifying acquisition targets, negotiating agreements, and successfully consummating acquisitions, and operating the acquired target using industry standards. Pogo plans to continue to evaluate and pursue acquisitions of all sizes. Pogo expects to benefit from the industry relationships fostered by its management team’s decades of experience in the oil and natural gas industry with a focus on the Permian Basin, in addition to leveraging its relationships with many E & P company executives.
• Development potential of the properties underlying the Company’s Permian Basin working interests. The Company’s assets consist of 100% working interests in a gross 13,700 acres located in the Northwest Shelf of the Permian Basin. The Company expects production from its working interest ownership to increase its oil and gas production by 1,358 BOE/d as it develops its PDNP reserves after completing 115 well patterns. The Company believes its assets in the Permian Basin is in an earlier to mid-stage of development and that the average number of producing wells per section in its 13,700-acre leasehold will increase as Pogo continues to add PUD well patterns, which would allow the Company to achieve higher realized cash flows to distributed to its shareholders as dividends and/or reinvested to further expand its base of cash flow generating assets. The Company believes that once it completes its PDNP and PUD program as detailed in the Cobb reserve report, The Company expects its BOE/d will increase to 2,853 BOE/d combined with PDP.

Crude Oil and Natural Gas Data

In this report, we include estimates of reserves associated with the assets located in New Mexico as of December 31, 2024 and 2023. Such reserve estimates are based on evaluations prepared by the independent petroleum engineering firm of 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 December 31, 2024 and 2023 reserve reports include the total interests of Pogo Resources, LLC, including the 10% overriding royalty interest not acquired in the Purchase, and the reserve report as of December 31, 2024 is included in this filing. As such, the estimates of proved oil and gas and discounted future net cash flows include the total interests of Pogo Resources, LLC.

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 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

Our reserve estimates as of December 31, 2024 and 2023 included in this report is included are based on evaluations prepared by the independent petroleum engineering firm of Cobb Petroleum Consultants, LLC 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 December 31, 2024 and 2023 reserve reports include the total interests of Pogo Resources, LLC, including the 10% overriding royalty interest not acquired in the Purchase, and the reserve report as of December 31, 2024 is included in this filing. As such, the estimates of proved oil and gas and discounted future net cash flows include the total interests of Pogo Resources, LLC.

We selected Cobb as its independent reserve engineer for its historical experience and geographic expertise in engineering similar resources.

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, 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, 2024 and 2023. The reserve report include the total interests of Pogo Resources, LLC, including the 10% overriding royalty interest not acquired in the Purchase, and the December 31, 2024 reserve report is included in this filing as an exhibit. As such, the estimates of proved oil and gas and discounted future net cash flows include the total interests of Pogo Resources, LLC. The reserve estimates presented in the table below are based on reports prepared by Cobb, EON’s independent petroleum engineers, which reports were prepared in accordance with current SEC rules and regulations regarding oil and natural gas reserve reporting:

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

(2) EON’s estimated proved reserves were determined using average first-day-of-the-month prices for the prior 12 months in accordance with SEC guidance. For crude oil volumes, the average WTI posted price of $71.89 per Bbl as of December 31, 2023, was adjusted for quality, transportation fees and a regional price differential. For natural gas volumes, the average Henry Hub spot price of $2.52 per MMBtu as of December 31, 2023, was adjusted for energy content, transportation fees and a regional price differential. The average adjusted product prices weighted by production over the remaining lives of the proved properties are $78.40 per Bbl of crude oil and $2.38 per Mcf of natural gas as of December 31, 2023.

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, 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. As of December 31, 2023, EON estimated its PUD reserves to be 4,137 MBbls of crude oil and 850 MMcf of natural gas for a total of 4,279 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 year ended December 31, 2023 (in MBOE):

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

Changes in EON’s PUD reserves that occurred during the year ended December 31, 2024 and 2023 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.

EON’s PUD reserves at December 31, 2024 and 2023 are based on a development plan instituted by our management. All of such reserves are scheduled to be developed within five years from the date such locations were initially disclosed as PUD reserves. Our development plan is prepared annually by management and approved by the Board of Directors. Our PUD reserves only represent reserves that are scheduled, based on such plan, to be developed within five years from the date such locations were initially disclosed as PUDs. At December 31, 2024, we estimate that our future development costs relating to the development of PUD reserves are $0 in 2025, $15.7 million in 2026, $46.1 million in 2027 and $32.3 million in 2028. Under our development plan, our existing PUDs are expected to be converted to PDP reserves by 2028.

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:

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

Productive Wells

Productive wells located on our leasehold consist of producing vertical wells that are capable of producing oil and gas in paying quantities and are not dry wells. As of December 31, 2024, we owned working interests in 342 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.

Pogo 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.

14

Drilling and other exploration and development activities

For the years ended 2024 and 2023, we did not drill any new wells.

As of December 31, 2024, 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

The following figures sets forth information relating to our acreage for its working interests as of December 31, 2024:

We own 100% working interests that is subject to a 26% weighted average net royalty interest across its 13,700 gross acres as of December 31, 2024. 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.

Pogo’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.

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, 2024.

All leasehold acreage of Pogo 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 13,700 acres leased by Pogo. The interests of Pogo 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 Pogo 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. Pogo has identified new potential proved undeveloped reserves within the incremental waterflood zone of the Seven Rivers. Pogo 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 Pogo.

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 Pogo 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 (Pogo) 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 Pogo’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 Pogo.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 (Pogo) underlying its leasehold working interest.

Air Emissions

The 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 Pogo’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 has 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. Additionally, at COP26 in Glasgow in November 2021, the United States and the European Union jointly announced the launch of a Global Methane Pledge, an initiative committing to a collective goal of reducing global methane emissions by at least 30 percent from 2020 levels by 2030, including “all feasible reductions” in the energy sector. 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. In late 2021, the Federal Reserve announced that it had joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Subsequently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the Network for Greening the Financial System to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. Limitation of investments in and financing for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities. Additionally, the SEC announced its intention to promulgate rules requiring climate disclosures. Although the form and substance of these requirements is not yet known, this may result in additional costs to comply with any such disclosure requirements.

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 Pogo’s working 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 Pogo’s working interests. One or more of these developments could have a material adverse effect on Pogo’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 Pogo’s supply chains. Such physical risks may result in damage to Pogo’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, Pogo 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, Pogo as the Operator of record may be required to curtail operations or adjust development plans, which may adversely impact Pogo’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 Pogo’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 Pogo to incur substantial compliance costs, and compliance or the consequences of any failure to comply could have a material adverse effect on Pogo’s financial condition and results of operations. At this time, it is not possible to estimate the impact on Pogo’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 Pogo’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 Pogo’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.

Pogo 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 Pogo’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 Pogo operates also regulate one or more of the following:

• the location of wells;
• the method of drilling and casing wells;
• the timing of construction or drilling activities, including seasonal wildlife closures;
• the rates of production or “allowables”;
• the surface use and restoration of properties upon which wells are drilled;
• the plugging and abandoning of wells;
• and notice to, and consultation with, surface owners and other third parties.

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 Pogo’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 Pogo’s properties can produce from Pogo’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 Pogo 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 Pogo 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 Pogo’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 Pogo’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, Pogo believes that access to crude oil pipeline transportation services of Pogo’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 Pogo 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 Pogo’s properties and the number of wells or locations Pogo’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. Pogo 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, Pogo performs a title review on each tract to be acquired. Pogo’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 Pogo’s properties.

In addition to Pogo’s initial title work, Pogo 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, Pogo will perform curative work with respect to such defects. Pogo generally will not commence drilling operations on a property until any material title defects on such property have been cured.

Pogo 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, Pogo 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 competes 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 Pogo 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 Pour overall business plans. Additionally, Pogo’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, Pogo may be unable to move their equipment between locations, thereby reducing its ability to operate Pogo’s wells, reducing the amount of crude oil and natural gas produced from the wells on Pogo’s properties during such times. Additionally, extended drought conditions in the areas in which Pogo’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 Pogo’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 Pogo’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, 2024, we employed 7 full-time salaried and regular pay field individuals under no ongoing employment contracts who provided direct support to Pogo’s operations. As of December 31, 2024, we employed 5 full-time salaried employees at our corporate offices, 5 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.

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, 2024, we had $2,971,558 in cash and a working capital deficit of $31,231,674. Further, we had positive cash flow from operations of $3,700,686 for the year ended December 31, 2024. 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 Common Stock 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 Pogo’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.

Pogo 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 Pogo 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 depends 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 Pogo’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. Pogo 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). Pogo 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:

• the capital costs required for development activities on Pogo’s acreage, which could be significantly more than anticipated;
• the ability to access capital;
• prevailing commodity prices;
• the availability of suitable equipment, production and transportation infrastructure and qualified operating personnel;
• the availability of storage for hydrocarbons, expertise, operating efficiency and financial resources;
• Pogo’s expected return on investment in wells developed on Pogo’s acreage as compared to opportunities in other areas;
• the selection of technology;
• the selection of counterparties for the marketing and sale of production;
• and the rate of production of the reserves.

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

• recoverable reserves;
• future crude oil and natural gas prices and their applicable differentials;
• development plans;
• operating costs Pogo’s E&P operators would incur to develop and operate the properties;
• and potential environmental and other liabilities that E&P operators may incur.

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 Pogo 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 Pogo 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 Pourability 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 Pogo completes will be subject to substantial risks.

Even if we makes acquisitions that we believes 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:

• the validity of our assumptions about estimated proved reserves, future production, prices, revenues, capital expenditures, the operating expenses and costs to develop the reserves;
• a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to finance acquisitions;
• a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions;
• the assumption of unknown liabilities, losses or costs for which we are not indemnified or for which any indemnity it receives is inadequate;
• mistaken assumptions about the overall cost of equity or debt;
• Our ability to obtain satisfactory title to the assets it acquires;
• an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets;
• and the occurrence of other significant changes, such as impairment of crude oil and natural gas properties, goodwill or other intangible assets, asset devaluation or restructuring charges.

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 we 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 Pogo 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 Pogo 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, Pogo 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 Pogo 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. Pogo 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, Pogo 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, Pogo 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 Pogo is unable to fund its capital requirements, Pogo 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.

Pogo 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 Pogo 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.

The widespread outbreak of an illness, pandemic (like COVID-19) or any other public health crisis may have material adverse effects on our business, financial position, results of operations and/or cash flows.

Pogo faces risks related to the outbreak of illnesses, pandemics and other public health crises that are outside of its control and could significantly disrupt its operations and adversely affect its financial condition. For example, the COVID-19 pandemic has caused a disruption to the oil and natural gas industry and to our business. The COVID-19 pandemic negatively impacted the global economy, disrupted global supply chains, reduced global demand for oil and gas, and created significant volatility and disruption of financial and commodity markets, but has been improving since 2020.

The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our operations, financial results and dividend policy will also depend on future developments, which are highly uncertain and cannot be predicted. These developments include, but are not limited to, the duration and spread of the pandemic, its severity, the actions to contain the virus or treat its impact, its impact on the economy and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. While this matter may disrupt its operations in some way, the degree of the adverse financial impact cannot be reasonably estimated at this time.

Pogo currently plans to enter hedging arrangements with respect to the production of crude oil, and possibly natural gas which is a smaller portion of the reserves. Pogo 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.

Pogo does currently plan 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 Pogo 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 Pogo 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, 2024 and December 31, 2023 were prepared by Cobb. Cobb conducted a detailed review of all of our properties for the period covered by its reserve report using information provided by Pogo. Over time, Pogo 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. For example, due to the deterioration in commodity prices and operator activity in 2020 as a result of the COVID-19 pandemic and other factors, the commodity price assumptions used to calculate our reserves estimates declined, which in turn lowered its proved reserve estimates. 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”), Pogo 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 Pogo 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 Pogo or the crude oil and natural gas industry in general.

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

The operations of Pogo 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 Pogo 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.

Pogo 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 Pogo has multiple layers of security to mitigate risks of cyber-attacks, cyber-attacks on business have escalated in recent years. Moreover, Pogo 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 Pogo 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.

A terrorist attack or armed conflict could harm our business.

Terrorist activities, anti-terrorist activities and other armed conflicts involving the United States or other countries may adversely affect the United States and global economies and could prevent Pogo from meeting its financial and other obligations. For example, on February 24, 2022, Russia launched a large-scale invasion of Ukraine that has led to significant armed hostilities. As a result, the United States, the United Kingdom, the member states of the European Union and other public and private actors have levied severe sanctions on Russia. To date, this conflict has resulted in a decreased supply of hydrocarbons which has resulted in higher commodity prices. The geopolitical and macroeconomic consequences of this invasion and associated sanctions cannot be predicted, and such events, or any further hostilities in Ukraine or elsewhere, could severely impact the world economy. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for crude oil and natural gas potentially putting downward pressure on demand for our services and causing a reduction in our revenues. Crude oil and natural gas related facilities, including those of Pogo, could be direct targets of terrorist attacks, and, if infrastructure integral to Pogo is destroyed or damaged, they may experience a significant disruption in their operations. Any such disruption could materially adversely affect our financial condition, results of operations and cash flows. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

We believe Pogo 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 a material weakness and believe that Pogo currently has ineffective internal control over financial reporting, primarily due to: not maintaining a sufficient complement of personnel to permit segregation of duties among personnel with access to our accounting and information systems controls, lacking proper review evidence of controls over the reserves report prepared by the reservoir engineer, and lacking the controls needed to ensure that the accounting for certain items is accurate and complete.

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.

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

Like many crude oil and natural gas companies, Pogo 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 Pogo 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:

• the regional, domestic foreign supply of and demand for crude oil and natural gas;
• the level of prices and market expectations about future prices of crude oil and natural gas;
• the level of global crude oil and natural gas E&P;
• the cost of exploring for, developing, producing and delivering crude oil and natural gas;
• the price and quantity of foreign imports and U.S. exports of crude oil and natural gas;
• the level of U.S. domestic production;
• political and economic conditions and events in foreign oil and natural gas producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, the armed conflict in Ukraine and associated economic sanctions on Russia, conditions in South America, Central America and China and acts of terrorism or sabotage;
• global or national health concerns, including the outbreak of an illness pandemic (like COVID-19), which may reduce demand for crude oil and natural gas due to reduced global or national economic activity;
• the ability of members of OPEC and its allies and other oil exporting nations to agree to and maintain crude oil price and production controls;
• speculative trading in crude oil and natural gas derivative contracts;
• the level of consumer product demand;
• weather conditions and other natural disasters, such as hurricanes and winter storms, the frequency and impact of which could be increased by the effects of climate change;
• technological advances affecting energy consumption, energy storage and energy supply;
• domestic and foreign governmental regulations and taxes;
• the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East and economic sanctions such as those imposed by the U.S. on oil and gas exports from Iran;
• the proximity, cost, availability and capacity of crude oil and natural gas pipelines and other transportation facilities;
• the impact of energy conservation efforts;
• the price and availability of alternative fuels; and
• overall domestic and global economic conditions.

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 Pogo 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 Pogo to write down, as a non-cash charge to earnings, the carrying value of its crude oil and natural gas properties. Pogo 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. Pogo 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 does 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, Pogo may be required to take write-downs of the carrying values of its properties.

Accounting rules require that Pogo 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, Pogo may be required to write down the carrying value of its properties. Pogo 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 Pogo 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 Pogo 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 Pogo 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. Pogo 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. Pogo 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, Pogo relies on independent third-party service providers to provide many of the services and equipment necessary to drill new development wells. If Pogo 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 Pogo 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. Pogo 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, Pogo 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 receives 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 Pogo 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, Pogo 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:

• unusual or unexpected geological formations;
• loss of drilling fluid circulation;
• title problems;
• facility or equipment malfunctions;
• unexpected operational events;
• shortages or delivery delays of equipment and services;
• compliance with environmental and other governmental requirements; and
• adverse weather conditions, including the recent winter storms in February 2021 that adversely affected operator activity and production volumes in the southern United States, including in the Delaware Basin.

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. Pogo 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 Pogo 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. An oversupply and decreased demand of crude oil in 2020 led to a severe decline in worldwide crude oil prices in 2020.

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 Pogo. 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 Pogo, and failure to comply could result in Pogo incurring significant liabilities, either of which may impact its willingness to develop our interests.

Our activities on the properties in which Pogo 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 Pogo, 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. Pogo must comply with federal and state laws and regulations governing conservation matters, including, but not limited to:

• provisions related to the unitization or pooling of the crude oil and natural gas properties;
• the establishment of maximum rates of production from wells;
• the spacing of wells;
• the plugging and abandonment of wells; and
• the removal of related production equipment.

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 Pogo, which in turn could affect profitability on the properties in which Pogo owns an interest.

Pogo 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.

Pogo 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. Pogo believes the trend of more expansive and stricter environmental legislation and regulations will continue. The laws and regulations that affect Pogo could increase the operating costs of Pogo 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 Pogo to incur increased costs, additional operating restrictions or delays and have fewer potential development locations.

Pogo 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 Pogo 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 Pogo owns properties. Additional legislation or regulation could also lead to operational delays or increased operating costs for Pogo in the production of crude oil and natural gas, including from the development of shale plays, or could make it more difficult for Pogo 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, Pogo may be required to curtail operations or adjust development plans, which may adversely impact Pogo’s business.

Pogo 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 Pogo’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 Pogo’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.

In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that GHG emissions constitute a pollutant under the Clean Air Act (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 U.S. Department of Transportation (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 prior regulations 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 OOOO(b) new source and OOOO(c) 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. 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. Additionally, at the 26th Conference of the Parties to the United Nations Framework Convention on Climate Change (“COP26”) in Glasgow in November 2021, the United States and the European Union jointly announced the launch of a Global Methane Pledge, an initiative committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all feasible reductions” in the energy sector. However, in January 2025, President Trump withdrew 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. 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. For example, at COP26, the Glasgow Financial Alliance for Net Zero (“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. In late 2020, the Federal Reserve announced that is has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Subsequently, in November 2021, the Federal Reserve issued a statement in support of the efforts of the Network for Greening the Financial System to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. Limitation of investments in and financing for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities. Additionally, the SEC announced its intention to promulgate rules requiring climate disclosures. Although the form and substance of these requirements is not yet known, this may result in additional costs to comply with any such disclosure requirements.

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 Pogo. Additionally, the SEC proposed rules on climate change disclosure requirements for public companies which, if adopted as proposed, could result in substantial compliance costs. 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 Pogo 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 Pogo 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 Pogo or costs of consuming crude oil and natural gas for such products, and thereby reduce demand, which could reduce the profitability of Pogo. For example, Pogo 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, Pogo 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, Pogo 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, Pogo 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 Pogo operates, our ability to conduct or expand operations could be limited, or Pogo 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

Restrictions in our current and future debt agreements and credit facilities could limit our growth and our ability to engage in certain activities.

EON (for purposes of the Loan Agreement, the “Borrower”), OpCo, SPAC Subsidiary, Pogo, and LH Operating, LLC (for purposes of the Loan Agreement, collectively, the “Guarantors” and together with the Borrower, the “Loan Parties”), and FIBT entered into a Senior Secured Term Loan Agreement on November 15, 2023 (the “Loan Agreement”), setting forth the terms of a senior secured term loan facility in an aggregate principal amount of $28 million (the “Term Loan”). On April 18, 2024, the Company and FIBT entered into a Second Amendment to Term Loan Agreement (the “Amendment”) effective as of March 31, 2024. Pursuant to the Amendment, the Term Loan Agreement was modified to provide that the Company must, on or before December 31, 2024, deposit funds in a Debt Service Reserve Account (as defined in the Loan Agreement) such that the balance of the account equals $5,000,000 and FIBT waived the provision that such amount had to be deposited within 60 days of the closing date of the Loan Agreement. In addition, the Amendment provides that, if at any time prior to December 31, 2024, the Company or any of its affiliates enter into a sale leaseback transaction with respect to any of its equipment, the Company will deposit an amount equal to the greater of (A) $500,000 or (B) 10% of the proceeds of such transaction into the Debt Service Reserve Account on the effective date of such sale and leaseback transaction.

The Term Loan contains certain customary representations and warranties and various covenants and restrictive provisions that limit our ability to, among other things:

• incur or guarantee additional debt;
• enter into certain hedging contracts;
• pay dividends on, or redeem or repurchase, their equity interests, return capital to the holders of their equity interests, or make other distributions to holders of their equity interests;
• amend our organizational documents or certain material contracts;
• make certain investments and acquisitions;
• incur certain liens or permit them to exist;
• enter into certain types of transactions with affiliates;
• merge or consolidate with another company;
• transfer, sell or otherwise dispose of assets;
• enter into certain other lines of business;
• repay or redeem certain debt;
• use the proceeds from the Term Loan for certain purposes;
• allow certain gas imbalances, take-or-pay, or other prepayments;

A failure to comply with the provisions of the Term Loan could result in an event of default, which could enable the Lender to declare, subject to the terms and conditions of the Term Loan, any outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of the debt is accelerated, cash flows from our operations may be insufficient to repay such debt in full. The Term Loan contains events of default customary for transactions of this nature, including the occurrence of a change of control.

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 the Term Loan Agreement, the Seller Note or any future debt agreement or if we default under the terms of the Term Loan Agreement, the Seller Note or any 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 the Term Loan Agreement, the Seller Note or any future debt agreement, the lenders could terminate 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 Term Loan Agreement, the Seller Note or any future 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 obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired, or such financing may not be available on terms acceptable to it;
• covenants in the Term Loan require, and in any future credit and debt arrangement may require, us to meet financial tests that may affect our flexibility in planning for and reacting to changes in its business, including possible acquisition opportunities;
• our access to the capital markets may be limited;
• our borrowing costs may increase;
• we will use a portion of its discretionary cash flows to make principal and interest payments on its indebtedness, reducing the funds that would otherwise be available for operations, future business opportunities and payment of dividends to its stockholders; and
• our debt level will make us more vulnerable than competitors with less debt to competitive pressures or a downturn in its business or the economy generally.

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.

Our borrowings under the Term Loan Agreement expose us to interest rate risk.

Our results of operations are exposed to interest rate risk associated with borrowings under the Term Loan Agreement, which bears interest at rates based on the Secured Overnight Financing Rate (“SOFR”) or an alternative floating interest rate benchmark. In response to inflation, the U.S. Federal Reserve increased interest rates multiple times in 2022 through 2024 and signaled that additional interest rate increases may be expected in 2025. Raising or lowering of interest rates by the U.S. Federal Reserve generally causes an increase or decrease, respectively, in SOFR and other floating interest rate benchmarks. As such, if interest rates increase, so will our interest costs. If interest rates continue to increase, it may have a material adverse effect on our results of operations and financial condition.

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:

• the results of operating and financial performance and prospects of other companies in our industry;
• strategic actions by us or our competitors, such as acquisitions or restructurings;
• announcements of innovations, increased service capabilities, new or terminated customers or new, amended or terminated contracts by our competitors;
• the public’s reaction to our press releases, other public announcements, and filings with the Securities and Exchange Commission;
• lack of securities analyst coverage or speculation in the press or investment community about us or market opportunities in our industry;
• changes in government policies in the United States;
• changes in earnings estimates or recommendations by securities or research analysts who track our Class A Common Stock or failure of our actual results of operations to meet those expectations;
• market and industry perception of our success, or lack thereof, in pursuing our growth strategy;
• changes in accounting standards, policies, guidance, interpretations or principles;
• any lawsuit involving us, our services or our products;
• arrival and departure of key personnel;
• sales of Class A Common Stock by us, our investors or members of our management team; and
• changes in general market, economic and political conditions in the United States and global economies or financial markets, including those resulting from natural or man-made disasters.

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).

On April 17, 2024, we received a notice from the NYSE American that we were not in compliance with NYSE American listing standards as a result of our failure to timely file our Annual Report on Form 10-K for the fiscal year ended December 31, 2023 with the SEC. On May 3, 2024, we filed our Annual Report on Form 10-K for the fiscal year ended December 31, 2023, and regained compliance with NYSE American rules. Although we believe that the failure to timely file our Annual Report on Form 10-K for the fiscal year ended December 31, 2023 was primarily as a result of the additional time needed to account for the Purchase and we expect to file our required subsequent reports in a timely fashion, there can be no assurance that we will be able to timely file required reports or meet other continued listing requirements in the future. However, in determining whether to afford a company a cure period prior to commencing suspension or delisting procedures, the NYSE American analyzes all relevant facts including any past history of late filings, and thus the late filing of our Annual Report on Form 10-K for the fiscal year ended December 31, 2023 could be used as a factor by the NYSE American in any future decision to delist our securities from trading on its exchange.

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:

• a limited availability of market quotations for our securities;
• reduced liquidity for our securities;
• a determination that our Class A Common Stock is a “penny stock” which will require brokers trading in our Class A Common Stock to adhere to more stringent rules and possibly result in a reduced level of trading activity in the secondary trading market for our securities;
• a limited amount of news and analyst coverage; and
• a decreased ability to issue additional securities or obtain additional financing in the future.

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 warrantholders. 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 $0.4 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 following the Closing of the Purchase.

On October 17, 2022, we entered into a common stock purchase agreement (the “Common Stock 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 Common Stock 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 Common Stock Purchase Agreement. On March 7, 2024, the Company entered into an Amendment No. 1 to Common Stock 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 Common Stock 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 Common Stock Purchase Agreement.

We are obligated under the Common Stock 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 Common Stock 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 Common Stock 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 Common Stock Purchase Agreement. Sales of Class A Common Stock, if any, to White Lion under the Common Stock 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 Common Stock 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 Common Stock 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 Common Stock Purchase Agreement, the purchase price per share that White Lion will pay for Class A Common Stock purchased from us under the Common Stock Purchase Agreement, or the aggregate gross proceeds that we will receive from those purchases by White Lion under the Common Stock 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 Common Stock Purchase Agreement. However, even if we elect to sell Class A Common Stock to White Lion pursuant to the Common Stock 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 7,000,000 shares of common stock under the Common Stock 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 Common Stock 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 Common Stock Purchase Agreement, the purchase price per share that While Lion will pay for shares purchased from us under the Common Stock 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 Common Stock 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 Common Stock 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 7,000,000 shares of common stock under the Common Stock 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 Common Stock 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 Common Stock 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 pir 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.

We acknowledge the increasing importance of cybersecurity in today’s digital and interconnected world. Cybersecurity threats pose significant risks to the integrity of our systems and data, potentially impacting our business operations, financial condition and reputation.

As a smaller reporting company, we currently do not have formalized cybersecurity measures, a dedicated cybersecurity team or specific protocols in place to manage cybersecurity risks. Our approach to cybersecurity is in the developmental stage, and we have only begun to conduct comprehensive risk assessments, establish an incident response plan, and engage with external cybersecurity consultants for assessments or services. As of the date of this report, we have adopted an incident response plan which governs our assessment and response upon the occurrence of a material cybersecurity incident, including the process for informing senior management and our Board of Directors. Our Vice President of Finance and Administration has been designated as the lead for implanting our incident response plan. In addition, in 2024, we have acquired a cybersecurity insurance policy.

Given our current stage of cybersecurity development, we have not experienced any significant cybersecurity incidents to date. However, we recognize that the absence of a formalized cybersecurity framework may leave us vulnerable to cyberattacks, data breaches and other cybersecurity incidents. Such events could potentially lead to unauthorized access to, or disclosure of, sensitive information, disrupt our business operations, result in regulatory fines or litigation costs and negatively impact our reputation among customers and partners.

We are in the process of evaluating our cybersecurity needs and developing appropriate measures to enhance our cybersecurity posture. This includes considering the engagement of external cybersecurity experts to advise on best practices, conducting vulnerability assessments and developing an incident response strategy. Our goal is to establish a cybersecurity framework that is commensurate with our size, complexity and the nature of our operations, thereby reducing our exposure to cybersecurity risks.

In addition, our board of directors will oversee any cybersecurity risk management framework and a dedicated committee of our board of directors will review and approve any cybersecurity policies, strategies and risk management practices.

Despite our efforts to improve our cybersecurity measures, there can be no assurance that our initiatives will fully mitigate the risks posed by cyber threats. The landscape of cybersecurity risks is constantly evolving, and we will continue to assess and update our cybersecurity measures in response to emerging threats.

For a discussion of potential cybersecurity risks affecting us, please refer to the “Risk Factors” section.

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.

To the knowledge of our management, there is no material litigation currently pending or contemplated against us, any of our officers or directors in their capacity as such or against any of our property.

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 Grayburg-Jackson Field in Eddy County, New Mexico, which is a sub-area of the Permian Basin. Pogo focuses primarily on production through waterflooding recovery methods.

The Company’s assets as mentioned above consist of contiguous leasehold positions 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 Company’s assets, all of which is net operated acreage of vertical wells with average depths of approximately 3,810 feet.

Our average daily production for the year ended December 31, 2024, was 798 barrel of oil equivalent (“BOE”) per day, and for the year ended December 31, 2023, was 1,022 BOE per day. The decrease in production is due to an increase in well downtime, field conditions requiring certain enhancements, and the conveyance of the 10% Override royalty interest to Pogo Royalty.

Selected Factors That Affect Our Operating Results

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

• the timing and success of production and development activities;
• the prices for oil and natural gas;
• the quantity of oil and natural gas production from our wells;
• changes in the fair value of the derivative instruments we use to reduce our exposure to fluctuations in the price of oil and natural gas;
• our ability to continue to identify and acquire high-quality acreage and development opportunities; and
• the level of our operating expenses.

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, 2024 and 2023, was $(1.03) and $(4.95) per barrel, respectively. Our natural gas price differential during the years ended December 31, 2024 and 2023, was $0.08 and $(0.06) 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, 2024 and 2023.

(1) Based on average NYMEX closing prices.

For the year ended December 31, 2024, the average NYMEX oil pricing was $76.55 per barrel of oil or 1% lower than the average NYMEX price per barrel for the year ended December 31, 2023. Our settled derivatives decreased our realized oil price per barrel by $1.91 and $3.63 in the years ended December 31, 2024, and 2023, respectively. Our average realized oil price per barrel after reflecting settled derivatives and location differentials was $73.61 for the year ended December 31, 2024 compared to $69.06 for the year ended December 31, 2023.

The average NYMEX natural gas pricing for the year ended December 31, 2024, was $2.19 per Mcf, or 14% lower than the average NYMEX price per Mcf for the year ended December 31, 2023.

Pogo Royalty Overriding Royalty Interest Transaction

Effective July 1, 2023, the Predecessor transferred to Pogo Royalty, a related party, an assigned and undivided overriding royalty interest (“ORRI”) equal in amount to ten percent (10%) of Pogo Resources, LLC’s and LH Operating, LLC’s interest all oil, gas and minerals in, under and produced from each lease. The consideration received for the 10% ORRI was $10. Thus, a loss of $816,011 was recorded as a result of the conveyance during the period from January 1, 2023 to November 14, 2023 of the Predecessor. Additionally, because of this transaction, our reserve balance was decreased as well our current net production volumes and revenues. Additional details are discussed in Note 1 and Note 13 of notes to the consolidated financial statements.

Results of Operations

For the year ended December 31, 2024, 86% and 14% of sales volumes from the assets were attributable to crude and natural gas, respectively. As of December 31, 2024, the company was continuing development of the Seven River waterflood interval. Further, as of December 31, 2024, the Company owned an interest in approximately 342 gross (342 net) producing wells.

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.

54

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, 2024, our oil and natural gas sales decreased 15% from the year ended December 31, 2023 on a combined Successor and Predecessor basis, driven by a 28% decrease in production volumes offset by a 6% increase in realized prices, excluding the effect of settled commodity derivatives. The higher average price in the year ended December 31, 2024 compared to the combined year 2023, was driven by higher average NYMEX oil and natural gas prices during the first nine months of the year. Realized production from oil and gas properties decreased due to an increase in well downtime.

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

(1) Natural gas is converted to BOE at the rate of one-barrel equals six Mcf based upon the approximate relative energy content of oil and natural gas, which is not necessarily indicative of the relationship of oil and natural gas prices.

Derivative Contracts

We enter into commodity derivatives instruments to manage the price risk attributable to future oil production.

We recorded a loss on derivative contracts of $850,374 for the year ended December 31, 2024 compared to a gain of $392,765 on a combined Successor and Predecessor basis for the year ended December 31, 2023. Lower commodity prices in 2024, resulted in realized losses of $489,084 for the year ended December 31, 2024 compared to realized losses of $1,266,277 on a combined Successor and Predecessor basis for the year ended December 31, 2023. For the year ended December 31, 2024, our average realized oil price per barrel after reflecting settled derivatives was $73.61, compared to $73.82 on a combined Successor and Predecessor basis for the year ended December 31, 2023.

As of December 31, 2024, we ended the period with a $106,397 net derivative asset compared to $467,687 as of December 31, 2023.

Other Revenue

Other revenue was $487,109 for the year ended December 31, 2024, compared to $571,189 on a combined Successor and Predecessor basis for the year ended December 31, 2023. The revenue is related to providing water services to a third party and the slight decrease is due to lower volumes in 2024 from supply line disruptions during the third quarter of 2024

Lease Operating Expenses

Lease operating expenses were $8,614,080 for the year ended December 31,2024, compared to $10,146,119 on a combined Successor and Predecessor basis for the year ended December 31, 2023. On a per unit basis, production expenses increased 19% from $27.20 per BOE for the combined Successor and Predecessor year ended December 31, 2023, to $29.59 per BOE for the year ended December 31, 2024, due to increases in proactive maintenance activities, higher labor costs, and increased oil field service and supplies costs. Additionally, because of the conveyance of the 10% ORRI in July 2023, the net production volumes decreased, which increases the “per BOE” amounts.

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 $1,715,792 for the year ended December 31, 2024 compared to $2,343,862 on a combined Successor and Predecessor basis for the year ended December 31, 2023. As a percentage of oil and natural gas sales, these costs were 8.7% and 8.9% for the years ended December 31, 2024 and 2023 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 $2,407,098 as of December 31, 2024, compared to $1,849,876 on a combined Successor and Predecessor basis for the year ended December 31, 2023. DD&A was $8.27 per BOE for the year ended December 31, 2024, compared to $4.53 per BOE on a combined Successor and Predecessor basis for the year ended December 31, 2023. The aggregate increase in DD&A expense for the year ended December 31, 2024 compared to 2023 was driven by a 48% increase in the DD&A rate per BOE, partially offset by a 28% 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 conveyance of the 10% overriding royalty interest to Royalty.

Accretion of Asset Retirement Obligations

Accretion expense was $144,988 as of December 31, 2024, compared to $859,102 on a combined Successor and Predecessor basis for the year ended December 31, 2023. Accretion expense was $0.50 per BOE for the year ended December 31, 2024, compared to $2.32 per BOE on a combined Successor and Predecessor basis for the year ended December 31, 2023. The aggregate decrease in accretion expense for the fiscal year ended December 31, 2024 compared to 2023 was driven by changes in certain assumptions, specifically the inflation factor and discount rate as a result of the acquisition date where we revised our estimates as part of its fair value estimates for the acquired business.

General and Administrative

General and administrative expenses were $10,381,095 as of December 31, 2024 compared to $7,253,384 on a combined Successor and Predecessor basis for the year ended December 31, 2023. The increase for general and administrative expenses is primarily due to increased cost of outsourced legal, professional, and accounting services as a result of the transaction disclosed in Note 1 in the notes to the consolidated financial statements and the costs of being a public company, and includes stock-based compensation expense of $2,778,991 for the year ended December 31, 2024. The general and administrative expense total of $3,553,117 for the period from November 15, 2023 to December 31, 2023 for the Successor includes $1,500,000 from the 138,122 shares of Class A common stock issued to White Lion for the commitment fee on the Common Stock Purchase Agreement, $910,565 in stock-based compensation to certain Founders under the Founder Pledge Agreement, and $135,400 in other stock-based compensation.

Acquisition costs

There were no acquisition costs as of December 31, 2024, compared to $9,999,860 during the Successor period from November 15, 2023 to December 31, 2023, and included an aggregate of $7,854,660 in costs related to the Forward Purchase Agreement and the Non-Redemption Agreements, due diligence and broker fees related to closing the Purchase.

Interest Expense and amortization of debt discount

Interest expense was $7,643,200 as of December 31, 2024, compared to $1,043,312 for the period from November 15, 2023 to December 31, 2023 (Successor), $1,834,208 for the period from January 1, 2023 to November 14, 2023 (Predecessor), The Successor period interest expense is driven by the Senior Secured Term loan entered into as part of the Closing, and the Private Notes Payable. The interest expense during the Predecessor period from January 1, 2023 to November 15, 2023 was primarily due to an increase in the average amount of the Predecessor’ revolving credit facility outstanding and an increase in the weighted average interest rate. The revolving credit facility was not assumed in the Acquisition.

Amortization of debt discount was $2,361,627 as of December 31, 2024 compared to $1,191,553 period from November 15, 2023 to December 31, 2023 (Successor), and attributable to deferred finance costs paid on the Senior Secured Term Loan, 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, for the Successor related to the inputs used in the Company’s fair value estimate of the FPA Put Option. The key inputs to the fair value estimate include the Company’s stock price, which declined during the Successor period, and the likelihood, timing and price of a potential dilutive offering.

Gain on extinguishment of liabilities

The Company recognized a gain on extinguishment of liabilities of $1,638,138 during the year ended December 31, 2024. In November 2024, the Company entered into a settlement agreement with the FPA Seller to fully release the Company from the terms of the FPA. We agreed to issue to the FPA Seller 450,000 restricted Class A Common shares which had a fair value of $450,000 based on the closing price of the Company’s common stock at the agreement date. The Company recognized a gain on settlement of the FPA liability of $82,998, which is included in Gain on Extinguishment of Liabilities on the Company’s consolidated statement of operations for the year ended December 31, 2024.

The Company also recognized a gain of $1,720,000 related to the settlement of royalties payable and other claims with the Sellers. The Company recognized a loss on extinguishment of accounts payable of $76,200, and recognized a loss of $88,660 related to the exchange of certain notes payable and warrant liabilities for convertible note agreements.

Change in fair value of warrant and convertible note liabilities

The change in fair value of warrant liabilities consisted of a loss of $804,004 as of December 31, 2024, compared to a gain of $187,704 for the period from November 15, 2023 to December 31, 2023 for the Successor related to fluctuations in the trading price of the Company’s warrants, a portion of which are accounted for as liabilities due to the redemption provisions in those issued to Private Note holders. The Company also recognized a loss of $192,744 from the change in fair value of its convertible note liabilities during the year ended December 31, 2024.

Loss on asset sales

Loss on asset sales was $816,011 on a combined Successor and Predecessor basis for the year ended December 31, 2023, compared to $0 for the year ended December 31, 2024. The decrease was due to the loss that was recognized as a result of the conveyance of the 10% overriding royalty interest to Pogo Royalty in July 2023.

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, payment of debt obligations [and the return of initial invested capital to our founders]. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.

As of December 31, 2024, we had outstanding debt of $23,641,517 under our Senior Secured Term Loan, $15,000,000 under the Seller Promissory Note, $3,556,750 of outstanding private notes payable, and $948,982 from short term merchant loans. A total of $9,080,910 of this is due within one year. As of December 31, 2024, we had $2,971,558 of cash and cash equivalents on hand, of which approximately $2,600,000 is in an escrow account pursuant to the requirements of the Senior Secured Term Loan. At December 31, 2024 we had a working capital deficit of $31,213674. 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 positive cash flow from operations of $3,700,686 for the year ended December 31, 2024. 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) Common Stock Purchase Agreement with a maximum funding limit of $150,000,000 that can fund our operations and production growth, and be used to reduce liabilities. Through the date of this filing, we have received $6,992,906 in cash proceeds related to the sale of 7,000,000 shares of common stock under this 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, 2024, and 2023, are as follows:

Operating Activities

The decrease in net cash flow provided by operating activities for the year ended December 31, 2024, as compared to 2023 on a combined Successor and Predecessor basis is primarily due to increased net loss as a result of decreased prices and production volumes, and higher general and administrative costs associated with public filings.

Investing Activities

Net cash used in investing activities for the year ended December 31, 2024 was primarily due to the development of crude oil and gas properties. Net cash provided by investing activities in the Successor period from November 15, 2023 to December 31, 2023 was primarily due to Trust Account withdrawals associated with the Closing in November 2023 of $49,362,479, partially offset by the cash paid to the Sellers of EON of $30,827,804 at the Closing, net of cash acquired. Cash flows used in investing activities in the Predecessor period ending November 14, 2023 consisted of $6,769,557 of cash paid for oil and gas property costs, primarily due to significant expenditures in the previous year to upgrade certain wells and meet compliance requirements.

Financing Activities

Net cash used in financing activities for the year ended December 31, 2024 was primarily due to repayments of long-term debt offset by the proceeds from the sale of common stock under the Common Stock Purchase Agreement. Net cash used by financing activities during the Successor period from November 15, 2023 to December 31, 2023 were primarily related to the redemptions of common stock of Public Shares at Closing of $44,737,839, partially offset by the net proceeds from the Senior Secured Term Loan of $27,191,008.

Off Balance Sheet Arrangements

As of December 31, 2024 and 202, the Company did not have any off-balance sheet arrangements, as defined in the rules and regulations of the Securities and Exchange Commission (SEC).

Contractual Obligations

We have contractual commitments under our Senior Secured Term Loan, the Seller Promissory Note and the Private Notes Payable which include periodic interest payments. See Note 5 to our interim condensed consolidated unaudited 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 interim condensed consolidated unaudited 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:

• the quality and quantity of available data;
• the interpretation of that data;
• the accuracy of various mandated economic assumptions; and
• the judgment of the persons preparing the estimate.

Our proved reserve information included in this filing as of December 31, 2024 and 2023, was prepared by independent petroleum engineers. 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, 2024, is the current market value of our estimated proved reserves. In accordance with SEC requirements, we based the 2024 standardized measure on a twelve-month average of commodity prices on the first day of each month in 2024 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 5 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.

Forward Purchase Agreement Valuation

The Company has determined that the FPA Put Option, including the Maturity Consideration, within the Forward Purchase Agreement is (i) a freestanding financial instrument and (ii) a liability (i.e., an in-substance written put option). This liability was recorded as a liability at fair value on the consolidated balance sheet as of the reporting date in accordance with ASC 480. 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 contractual terms and then discounted back to present. Finally, the value of the forward is calculated as the average present value over all simulated paths. The model also considered the likelihood of a dilutive offering of common stock.

Derivative Instruments

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.

New Accounting Pronouncements

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

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.

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, 2024. Based upon his 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, 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 combined constituted a material weakness 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 Annual Report on Form 10-K 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 a deficiency in internal control over financial reporting existed relating to the lack of sufficient accounting personnel to manage the Company’s financial accounting process, 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 a material weakness 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, 2024. In making these assessments, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework (2013). Based on our assessments and those criteria, management determined that we did not maintain effective internal control over financial reporting as of December 31, 2024 due to the material weakness 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 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 Annual Report on Form 10-K 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.