EONR 10-K & 10-Q changes, risk factors and insider trading

As of December 31, 2024,2025, we had $2,971,558$375,036 in cash and a working capital deficit of $31,231,674.$21,814,454. Further, we had positivenegative cash flow from operations of $3,700,686$7,645,418 for the year ended December 31, 2024.2025. These factors raise substantial doubt about our ability to continue as a going concern. Management’s plans to alleviate this substantial doubt include improving profitability through streamlining costs, maintaining active hedge positions for its proven reserve production, and the issuance of additional shares of Class A Common Stock through the Common StockELOC Purchase Agreement with White White Lion, which can fund our operations and production growth, and be used to reduce our liabilities. While management believes that its 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.

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’sEON’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.

PogoEON 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 PogoEON will not suffer a monetary monetary loss from title defects or title failure. Additionally, undeveloped acreage has a greater risk of title defects than developed acreage. acreage. If there are any title defects in properties in which we holds an interest, it may suffer a financial loss.

We dependsdepend 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’sEON’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.

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. PogoEON 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). PogoEON 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:

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

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 urrentcurrent 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.

There is intense competition for acquisition opportunities 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 EON does not currently hold assets, which could result in unforeseen operating difficulties. In addition, if we acquire interests in new states, it may be subject to additional and unfamiliar legal and regulatory requirements. Compliance with regulatory requirements may impose substantial additional obligations on PogoEON 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 Pourabilityour ability to effectively integrate the acquired business into its existing business. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, potential future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions.

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

Even if we makesmake acquisitions that we believesbelieve 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 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 weus 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 PogoEON 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 PogoEON 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. rates. Additionally, actual production from wells may be less than expected. For example, a number of E&P operators have recently announced announced that newer wells drilled close in proximity to already producing wells have produced less oil and gas than forecast. Because of these uncertainties, PogoEON does not know if the potential development activities that have been identified will ever be able to produce crude crude oil and natural gas from these or any other potential development activities. As such, the actual development activities of Pogo EON may materially differ from those presently identified, which could adversely affect our business, results of operation and cash flows.

The crude oil and natural gas industry is capital intensive. PogoEON 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, PogoEON 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, PogoEON 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 PogoEON is unable to fund its capital requirements, PogoEON 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.

PogoEON is also dependent on the availability of external external debt, equity financing sources and operating cash flows to maintain its development program. If those financing sources are not available available on favorable terms or at all, then PogoEON 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 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.

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

PogoEON doesholds currentlyand plan to continue to enter into hedging arrangements to establish, in advance, a price for the sale of the crude oil and possibly natural gas produced from its properties. The hedging plan and structure will be at a level to balance the debt service requirements and also allow PogoEON 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 PogoEON from realizing the benefit of a derivative contract.

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 estimates of underground accumulations of crude oil and natural gas and assumptions concerning future crude oil and natural gas prices, production production levels, ultimate recoveries and operating and development costs. As a result, estimated quantities of proved reserves, projections of 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, 20242025 and December 31, 20232024 were prepared by Haas and Cobb. Haas and Cobb conducted a detailed review of all 94% of our properties for the December 31, 2025 period and 100% of our properties for the December 31, 2024 period covered by its reserve report using information provided by Pogo.EON. Over time, PogoEON 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”), PogoEON 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 PogoEON 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 PogoEON or the crude oil and natural gas industry in general.

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

The operations of PogoEON will be subject to all of 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 PogoEON 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.

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

We believe PogoEON 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 weaknessweaknesses and believe that PogoEON currently has ineffective internal control over financial reporting, primarily due to: notthe maintaining alack of sufficient complement ofaccounting personnel to permitmanage the Company’s financial accounting process including lack of proper preparation and review of account reconciliations, lack of segregation of dutiesduties, among personnel with access to ourproper accounting for complex financial instruments and informationlack systemsof controls,design lackingand proper review evidenceimplementation of controls overrelated theto reserves report prepared by the reservoir engineer,oil and lackinggas the controls needed to ensure that the accounting for certain items is accurate and complete.activities.

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

Like many crude oil and natural gas companies, PogoEON 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 PogoEON 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.

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

Accounting rules require that PogoEON 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, PogoEON may be required to write down the carrying value of its properties. PogoEON 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 PogoEON would estimate the fair value of its properties and record an impairment charge for any excess of the the carrying value of the properties over the estimated fair value of the properties. Factors used to estimate fair value may include estimates estimates of proved reserves, future commodity prices, future production estimates and a commensurate discount rate. The risk that Pogo EON will be required to recognize impairments of its crude oil and natural gas properties increases during periods of low commodity prices. In addition, impairments would occur if PogoEON 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 EON may incur impairment charges in the future, which could materially adversely affect its results of operations for the periods in which such charges are taken.

The 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. PogoEON 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, PogoEON relies on independent third-party service providers to provide many of the services and equipment necessary to drill new development wells. If PogoEON 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 PogoEON 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. PogoEON does not control these third-party facilities and our access to them may be limited 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, PogoEON 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. ourOur access to transportation options and the prices we receivesreceive can also be affected by federal and state regulation —regulation, including regulation of crude oil and natural gas production, transportation and pipeline safety — safety, as well by general economic conditions and changes in supply and demand.

In addition, the third parties on whom PogoEON 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.

The development drilling activities of our properties will be subject to many risks. For example, PogoEON 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:

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. PogoEON 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 PogoEON and and thus limit our ability to acquire additional properties and add reserves.

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.

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.EON. For example, certain segments of the investor community have developed negative sentiment towards investing in the oil and gas industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition, some investors, including investment advisors and certain sovereign wealth, pension funds, university endowments and family foundations, have stated policies to divest from, or not provide funding to, the oil and gas sector based on their social and environmental considerations. Furthermore, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to environmental, social and governance (“ESG”) matters. Such ratings are used by some investors and other financial institutions to inform their investment, financing and voting decisions, and unfavorable ESG ratings may lead to increased negative sentiment toward oil and gas companies from such institutions. Additionally, the SEC proposed rules on climate change disclosure requirements for public companies which, if adopted as proposed, could result in substantial compliance costs. Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas and related infrastructure projects. Such developments, including environmental activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, and also adversely affect our availability of capital.

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

Our activities on the properties in which Pogo EON holds interests are subject to various federal, state and local governmental regulations that may change from time to time in response to economic and political conditions. Matters subject to regulation include drilling operations, production and distribution activities, activities, discharges or releases of pollutants or wastes, plugging and abandonment of wells, maintenance and decommissioning of other facilities, 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,EON, including administrative, civil or criminal penalties, permit revocations, requirements for additional pollution controls and injunctions limiting or prohibiting some or all of our operations on our properties. Moreover, these laws and regulations have generally imposed increasingly strict requirements related to water use and disposal, air pollution control, species protection, and waste management, among other matters.

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

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

PogoEON 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.

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

PogoEON 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 PogoEON cannot predict the extent of any such legislation at this time.

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 PogoEON owns properties. Additional legislation or regulation could also lead to operational delays or increased operating costs for PogoEON in the production of crude oil and natural gas, including from the development of shale plays, or could make it more difficult for PogoEON 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.

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, PogoEON may be required to curtail operations or adjust development plans, which may adversely impact Pogo’sEON’s business.

PogoEON 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’sEON’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’sEON’s business, financial condition and and results of operations.

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

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. ourOur properties are in the Grayburg-Jackson FieldGJF in Eddy County, New Mexico, and SJF in Lea County, New Mexico which is aare both in the sub-area of the Permian Basin. PogoLHO focuses primarily on production through waterflooding recovery methods.

The Company’sOur assets as mentioned above consist of contiguous leasehold positions in the GJF of approximately 13,700 gross (13,700 net) acres with an average working interest of 100%. We operate 100% of the net acreage across the GJF, all of which is net operated acreage of vertical wells with average depths of approximately 3,810 feet. In addition, our SJF has contiguous leasehold positions of approximately 5,400 gross (5,400) acres with an average working interest of 94%. We operate 100% of the net acreage across the Company’sSJF assets, all of which is net operated acreage of vertical wells with average depths depths of approximately 3,8106,000 feet.

Our average daily net production for the year ended December 31, 2025 was 734 barrel of oil equivalent (“BOE”) per day. Our average daily net production for the year ended December 31, 2024, was 798 barrelBOE 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, fieldwater conditionsinjection requiringflowlines certainthat needed enhancements,repair or replacement, increase in flaring of natural gas, and the conveyance of the 10%2025 OverrideORRIs royaltyon interestSeptember to9, Pogo2025 Royalty.with the recapitalization and Farmout funding.

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, 20242025 and 2023,2024, was $(1.031.53) and $(4.951.03) per barrel, respectively. Our natural gas price differential during the years ended December 31, 20242025 and 2023,2024, was $0.08$(1.64) and $(0.06)$0.08 per one thousand cubic feet (“Mcf”), respectively. Fluctuations in our price differentials and realizations are due to several factors such as gathering and transportation costs, takeaway capacity relative to production levels, regional storage capacity, gain/loss on derivative contracts and seasonal refinery maintenance temporarily depressing demand.

For the year ended December 31, 2024,2025, the average NYMEX oil pricing was $76.55$65.46 per barrel of oil or 1%14% lower than the average NYMEX price per barrel for the year ended December 31, 2023. 2024. Our settled derivatives decreased increased our realized oil price per barrel by $1.91 and $3.63$2.89 in the yearsyear ended December 31, 2025, and decreased our realized oil price per barrel by $1.91 for the year 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$66.82 for the year ended December 31, 2023.2025 compared to $73.61 for the year ended December 31, 2024.

The average NYMEX natural gas pricing for the year ended December 31, 2024,2025, was $2.19$3.53 per Mcf, or 14%61% lowerhigher than the average NYMEX price per Mcf for the year ended December 31, 2023.2024.

For the year ended December 31, 2024,2025, 86%91% and 14% 9% of salesproduction volumes from the assets were attributable to crude and natural gas, respectively. As of December 31, 2024,2025, the companyCompany was continuing development of the Seven RiverRivers waterflood interval.interval Further, as of December 31, 2024,and the CompanySJF owned an interestacquired in approximately 342June gross (342 net) producing wells.2025.

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, 2024,2025, our oil and natural gas sales decreased 15% 20% from the year ended December 31, 2023 on a combined Successor and Predecessor basis,2024, driven by a 28%8% decrease in production volumes offset byand a 6%13% increasedecrease in realized prices, excluding the effect of settled commodity derivatives. The higherlower average price in the year ended December 31, 20242025 compared to the combined year 2023,ending December 31, 2024, was driven by higherlower 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 anincreased increaseflaring inof wellnatural downtime.gas during the current period.

We enter into commodity derivatives instruments to manage the price risk attributable to future oil production. We recorded a lossgain on derivative contracts of $663,010 for the year ended December 31, 2025, compared to a loss of $850,374 for the year ended December 31, 2024 compared to a gain of $392,765 on a combined Successor and Predecessor basis for the year ended December 31, 2023.2024. Lower commodity prices in 2024,the year ended December 31, 2025, resulted in realized gains of $706,073 compared to realized losses of $489,084 for the year ended December 31, 20242024. For the year ended December 31, 2025, unrealized losses were $43,063 compared to realized losses of $1,266,277 on a combined Successor and Predecessor basis$361,290 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, 2023.2024.

As of December 31, 2024,2025, we ended the period with with a $106,397$63,334 net derivative asset compared to $467,687a net asset of $106,397 as of December 31, 2023.2024.

Other revenue was $487,109$383,196 for the year ended December 31, 2024,2025 compared to $571,189 on a combined Successor and Predecessor basis$487,109 for the year ended December 31, 2023.2024. The revenue is related to providing water services to a third party. partyThe contract is for one year starting on September 1, 2022, and thehas slightbeen decreaserenewed isby duemutual to lower volumes in 2024 from supply line disruptions during the third quarter of 2024agreement.

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$1,626,360 for the year ended December 31, 20242025 compared to $2,343,862were on a combined Successor and Predecessor basis$1,715,792 for the year ended December 31, 2023.2024. As a percentage of oil and natural gas sales, these costs were 8.7%10.2% and 8.9%8.7% for the years ended December 31, 20242025 and 20232024 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 (“DD&A”) was $6,710,092 as of December 31, 2025, compared to $2,407,098 as of December 31, 2024,2024. comparedDD&A towas $1,849,876$25.03 onper a combined Successor and Predecessor basisBOE for the year ended December December 31, 2023.2025, DD&Acompared wasto $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, 2023.2024. The aggregate increase in DD&A expense for the year ended December 31, 20242025 compared to 2023 2024 was driven by a 48%203% increase in the DD&A rate per BOE, partially offset by a 28%8% decrease in production levels. The increase in the DD&A rate per BOE was driven by the increase in the oil and gas properties balance due to the development of the Seven Rivers waterflood interval and the decrease in the reserves balance due to the net conveyance of the 10%additional 5% overriding royalty interest to Royalty.Virtus, along with a change in reserve classification from proved to probable.

AmortizationDuring ofthe debtyear discount was $2,361,627 as ofended December 31, 20242025, the Company recorded $1,475,191 related to the amortization of financing costs compared to $1,191,553$2,361,627 periodfor fromthe Novemberyear 15, 2023 toended December 31, 2024. 2023These (Successor),costs andare attributable to deferred finance costs paid on the Senior Secured Term Loan, Merchant Cash Advances, convertible notes payable and discounts associated with the Private Notes Payable during 2023.

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 theour Company’s fair value estimate of the FPAforward purchase Putagreement Option.put option, primarily the decline in our stock price during the year ended December 31, 2024. The key inputs to the fair value estimate include the Company’sour stock price, which declined during the Successor period, and the likelihood, timing and price of a potential dilutive offering. The forward purchase agreement put option was settled during the year ended December 31, 2024, and therefore no change in fair value was recorded in the year ended December 31, 2025.

The change in fair value of warrant liabilities consisted of a loss of $152,490 as of December 31, 2025, compared to $804,004 as of December 31, 2024, 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.2024. The Company also recognized a loss of $192,744 $131,677 from the change in fair value of its convertible note liabilities during the year ended December 31, 2024.2025.

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

As of December 31, 2024,2025, 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$2,161,486 privateof convertible notes payable, $200,000 from related party notes payable, payable and $948,982$1,517,337 from short term merchant loans.cash advances. A total of $9,080,910$1,617,337 of this is due within one year. As of December 31, 2024,2025, we had $2,971,558$375,036 of cash and cash equivalents on hand,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 weand had a working capital deficit of $31,213674. $21,814,454. These conditions raise substantial doubt about our ability to continue as a going concern within one year after the date that the financial statements are issued.

The Company had positivenegative cash flow from operations of $3,700,686$7,645,418 for the year ended December 31, 2024.2025. Additionally, management’s plans to alleviate this substantial doubt include improving profitability through streamlining costs, maintaining active hedge positions for its proven reserve production, and the issuance of additional shares of Class A common stock.

We have a three-year equity line (ELOC) Common Stock Purchase Agreement with a maximum funding limit of $150,000,000 that can fund our operations and production growth, and can be used to reduce liabilities. Through the date of this filing, we have received $6,992,906$11,130,586 in cash proceeds related to the sale of 7,000,000 17,000,000 shares of common stock under thisthe agreementELOC Purchase Agreement and expect to continue to utilize it to fund current operational needs. We cannot assure you, however, 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.

The decreasechange in net cash flow providedused byin operating activities for the year ended December 31, 2024,2025, as compared to 2023 on a combined Successor and Predecessor basis2024 is primarily due to increased net loss as a result of decreased pricesproduction volumes and productionmarket volumes,prices for andcrude higher general and administrative costs associated with public filings.oil.

As of December 31, 20242025 and 202,2024, the Company did did not have any off-balance sheet arrangements, as defined in the rules and regulations of the Securities and Exchange Commission (SEC).SEC.

We have contractual commitments under our SeniorConvertible 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 proved reserve information included in this filing as of December 31, 2025 was prepared by independent petroleum engineers covering 94% of our reserves as of December 31, 2025, while the remaining 6% were developed by our internal reserve engineers. Our proved reserve information included in this filing as of December 31, 2024 and 2023, was prepared by independent petroleum engineers engineers.covering 100% of our reserves. Because these estimates depend on many assumptions, 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.

Derivative Instruments Instruments- Hedging

As of the date of this Quarterly Report on Form 10-Q, there have been no material changes to the risk factors disclosed in our annual report as amended on Form 10-K filed with the SEC on April 16, 2025.

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, and South JusticeJustis Field in Lea County, New Mexico which are both in the sub-area of the Permian Basin. PogoLHO focuses primarily on production through waterflooding recovery methods.

Our assets as mentioned above consist of contiguous leasehold positions in the Grayburg-Jackson Field 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 Grayburg-Jackson Field assets, all of which is net operated acreage of vertical wells with average depths of approximately 3,810 feet. In additionaddition, our South JusticeJustis Field has contiguous leasehold positions of approximately 5,400 gross (5,400) acres with an average working interest of 94%. We operate 100% of the net acreage across the Grayburg-JacksonSouth Justis field assets, assets, all of which is net operated acreage of vertical wells with average depths of approximately 6,000 feet.

Our average daily production for the sixnine months ended JuneSeptember 30, 2025 was 708749 barrel of oil equivalent (“BOE”) per day. Our average daily production for the year ended December December 31, 2024, was 798 BOE per day. The decrease in production is due to an increase in well downtime, water injection flowlines that needed repair or replacement, and the conveyance of the 10% Override royalty interest to Pogo Royalty.

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 sixnine months ended JuneSeptember 30, 2025 and 2024, was $0.84$(1.52) and $(4.572.07) per barrel, respectively. Our natural gas price differential during the sixnine months ended June September 30, 2025 and 2024, was $(0.050.36) and $0.34$0.03 per one thousand cubic feet (“Mcf”), respectively. Fluctuations in our price differentials and and realizations are due to several factors such as gathering and transportation costs, takeaway capacity relative to production levels, regional regional storage capacity, gain/loss on derivative contracts and seasonal refinery maintenance temporarily depressing demand.

Prices for various quantities of natural gas and and oil that we produce significantly impact our revenues and cash flows. The following table lists average NYMEX prices for oil and natural natural gas for the three and sixnine months ended JuneSeptember 30, 2025 and 2024.

For the sixnine months ended JuneSeptember 30, 2025, the average NYMEX oil pricing was $68.23$67.40 per barrel of oil or 14% lower than the average NYMEX price per barrel for the sixnine months ended June September 30, 2024. Our settled derivatives increased our realized oil price per barrel by $2.00$3.58 in the sixnine months ended JuneSeptember 30, 2025, and decreased our realized oil price per barrel by $3.16$2.56 in the sixnine months ended JuneSeptember 30, 2024. Our average realized oil price per barrel after reflecting settled derivatives and location differentials was $69.07$69.46 and $75.07$73.87 for the sixnine months ended June September 30, 2025 and 2024, respectively.

The average NYMEX natural gas pricing for the sixnine months ended JuneSeptember 30, 2025, was $3.67$3.45 per Mcf, or 74%64% higher than the average NYMEX price of $2.11 per Mcf for the sixnine months ended ended JuneSeptember 30, 2024.

Three months ended JuneSeptember 30, 2025 Compared to Threethree months ended JuneSeptember 30, 2024

Our revenues vary from year to year primarily as a result of changes in realized commodity prices and production volumes. For the three months ended JuneSeptember 30, 2025, our oil and natural natural gas sales decreased 28%16% from the three months ended JuneSeptember 30, 2024, excluding the effect of settled commodity derivatives, and a 15%2% decrease increase in production volumes. Production volumes decreasedincreased for the three months ended JuneSeptember 30, 2025 from the three months ended JuneSeptember 30, 2024 were stable as a result of workover efforts offset by the negative impacts on production resulted from an equal combination of on-going water injection mechanical problems and downtime required to perform acid treatments and well servicing work to return wells to production.

We enter into commodity derivatives instruments to manage the price risk attributable to future oil production. We recorded a gainloss on derivative contracts of $889,479$224,512 for the three months months ended JuneSeptember 30, 2025, compared to a lossgain of $83,478$ 1,900,662 for the three months ended JuneSeptember 30, 2024. lowerLower commodity prices in the three months ended JuneSeptember 30, 2025, resulted in realized gains of $379,350$429,241 compared to realized losses of $261,448$ 107,969 for the three months ended JuneSeptember 30, 2024. For the three months ended JuneSeptember 30, 2025, unrealized gainslosses were $510,129$653,753 compared to unrealized gains of $177,970$ 2,008,631 for the three months ended JuneSeptember 30, 2024.

For the three months ended JuneSeptember 30, 2025, our our average realized oil price per barrel after reflecting settled derivatives was $70.53$70.15 compared to $75.81$77.12 for the three months ended September June 30, 2024. For the three months ended JuneSeptember 30, 2025, our settled derivatives increased our realized oil price per barrel by $6.86$6.30 compared to decreasing the price per barrel by $3.16$1.61 for the three months ended JuneSeptember 30, 2024. As of JuneSeptember 30, 2025, we ended the period with a $674,314 $20,561 net derivative asset compared to a net asset of $106,397 as of December 31, 2024.

Other revenue was $105,089$104,587 for the three months ended JuneSeptember 30, 2025, compared to $130,230$98,452 for the three months ended JuneSeptember 30, 2024. The revenue is related to providing water services services to a third party. The contract is for one year starting on September 1, 2022, and has been renewed by mutual agreement.

Lease operating expenses were $1,993,454$2,545,969 for the the three months ended JuneSeptember 30, 2025, compared to $2,094,181$ 2,136,732 for the three months ended JuneSeptember 30, 2024. On a per unit basis, production expenses increased 5%19% from $29.50$27.87 per BOE for the three months ended JuneSeptember 30, 2024, to $33.15$33.08 per BOE for the three months ended JuneSeptember 30, 2025.

We pay production taxes, transportation and processing costs based on realized oil and natural gas sales. Production taxes, transportation and processing costs were $302,850$435,539 for the three months months ended JuneSeptember 30, 2025, compared to $408,985$489,524 for the three months ended JuneSeptember 30, 2024. As a percentage of oil and natural gas sales, these costs were 8.4%9.7% and 8.6%9% in the three months ended JuneSeptember 30, 2025 and 2024 respectively. Production taxes, transportation, and processing as a percent of total oil and natural gas sales are consistent with historical trends.

Depletion, depreciation and amortization (“DD&A”) was $458,190$526,871 for the three months ended JuneSeptember 30, 2025 compared to $522,542$507,626 for the three months ended JuneSeptember 30, 2024. DD&A was $7.62 per BOE for the three months ended June 30, 2025, compared to $7.36$6.84 per BOE for the three months ended JuneSeptember 30, 2025, compared to $6.62 per BOE for the three months ended September 30, 2024. The aggregate decrease increase in DD&A expense for the three months ended JuneSeptember 30, 2025, compared to the three months ended June September 30, 2024, was driven by the increase in the cost basis offset by a decrease in oil and gas production.

Accretion expense was $95,322$29,388 for the three months ended JuneSeptember 30, 2025, compared to $40,526$10,395 for the three months ended JuneSeptember 30, 2024. Accretion expense was $1.59$0.38 per BOE for the three months ended JuneSeptember 30, 2025, compared to $0.57$0.14 per BOE for the three months ended JuneSeptember 30, 2024. The aggregate increase in accretion expense for the three months ended JuneSeptember 30, 2025, compared to the three months ended JuneSeptember 30, 2024, was driven by changes in certain assumptions, specifically the inflationaddition factor.of the South Justice field.

General and administrative expenses were $1,941,044$2,591,296 for the three months ended JuneSeptember 30, 2025, compared to $2,323,662$2,235,263 for the three months ended JuneSeptember 30, 2024. The decreaseincrease in general and administrative expenses is primarily due to increase legal and professional fees associated with the transactions closed during the current period, partially offset by decreased stock-based compensation in the current period of $237,685$419,669 compared to $370,720$326,995 in the comparative period, and our focus on reducing overhead and overall levels of general and administrative costs.period.

Interest expense was $1,678,538$1,220,390 for the three months ended JuneSeptember 30, 2025, compared to $2,030,317$1,841,848 for the three months ended JuneSeptember 30, 2024. The decrease in interest expense is driven by the decreases in the SeniorPrivate SecuredNotes term loanPayable and the PrivateSenior NotesSecured Payable.Term Loan, along with the eventual settlement of the Senior Term Loan.

During the three months ended JuneSeptember 30, 2025, the the Company recorded $332,447$399,697 related to the amortization of financing costs compared to $662,076$507,701 for the three months ended June September 30, 2024. These costs are attributable to deferred finance costs paid on the Senior Secured Term Loan, and discounts associated with the Private Notes Payable during 2023.

The change in fair value of forward purchase agreement consisted of a lossgain of $23,717$981,337 for the three months ended JuneSeptember 30, 2024 related to the inputs used in our fair value estimate of the FPA Putforward Option,purchase agreement put option, primarily the decline in our stock price during the three months ended JuneSeptember 30, 2024. The key inputs to the fair value estimate include our stock price, which declined during the Successor period, and the likelihood, timing and price of a potential dilutive offering. The FPAforward purchase agreement put option was settled during the year ended December 31, 2024 and therefore no change in fair value was recorded in the three months ended JuneSeptember 30, 2025.

Change in fair value of warrant and convertible note liabilities

The change in fair value of warrant liabilities consisted of a gainloss of $10,030$137,911 for the three months ended JuneSeptember 30, 2025, compared to a loss of $277,167 for the three months ended June 30, 2024, related to fluctuations in the trading price of our warrants, a portion of which were accounted for as liabilities due to the redemption provisions in those issued to Private Note holders. All warrants previously accounted for as liabilities were exchanged into convertible notes during the sixnine months ended JuneSeptember 30, 2025.

The Company recognized a gain on extinguishment of liabilities of $207,307$1,846,684 during the three months ended JuneSeptember 30, 2025, primarily related to the exchangesettlement of certainthe notesSenior payableTerm Loan and warrant other liabilities forassociated convertiblewith notethe agreements.Company’s prior acquisition.

SixNine months ended JuneSeptember 30, 2025 Compared to Sixnine months ended JuneSeptember 30, 2024

Our revenues vary from year to year primarily as a result of changes in realized commodity prices and production volumes. For the sixnine months ended JuneSeptember 30, 2025, our oil and natural natural gas sales decreased 20%19% from the sixnine months ended JuneSeptember 30, 2024, excluding the effect of settled commodity derivatives, and a 13%11% decrease in production volumes. Production volumes decreased for the sixnine months ended JuneSeptember 30, 2025 from the sixnine months ended JuneSeptember 30, 2024 as a result of increased flaring of natural gas during the current period.

We enter into commodity derivatives instruments to manage the price risk attributable to future oil production. We recorded a gain on derivative contracts of $804,408$579,896 for the sixnine months ended JuneSeptember 30, 2025, compared to a loss of $2,080,725$180,063 for the sixnine months ended JuneSeptember 30, 2024. Lower commodity prices in the six nine months ended JuneSeptember 30, 2025, resulted in realized gains of $236,491$665,732 compared to realized losses of $398,602$506,571 for the sixnine months ended JuneSeptember 30, 2024. For the sixnine months ended JuneSeptember 30, 2025, unrealized gainslosses were $567,917$85,836 compared to unrealized lossesgains of $1,682,123 $326,508 for the sixnine months ended JuneSeptember 30, 2024.

For the Sixnine months ended JuneSeptember 30, 2025, our average realized oil price per barrel after reflecting settled derivatives was $69.07$69.46 compared to $75.07$73.87 for the sixnine months ended September 30, 2024. For the nine months ended June 30, 2024. For the six months ended JuneSeptember 30, 2025, our settled derivatives decreasedincreased our realized oil price per barrel by $2.00$3.58 compared to decreasing the price per barrel by $3.16$2.56 for the sixnine months ended JuneSeptember 30, 2024. As of JuneSeptember 30, 2025, we ended the period with a $674,314$20,561 net derivative asset compared to a net asset of $106,397 as of December 31, 2024.

Other revenue was $222,621$327,208 for the sixnine months ended JuneSeptember 30, 2025, compared to $260,818$359,270 for the sixnine months ended JuneSeptember 30, 2024. The revenue is related to providing water services to a third party. The contract is for one year starting on September 1, 2022, and has been renewed by mutual agreement.

Lease operating expenses were $3,914,775$6,460,744 for the the sixnine months ended JuneSeptember 30, 2025, compared to $4,393,699$6,530,431 for the sixnine months ended JuneSeptember 30, 2024. On a per unit basis, production expenses expenses increased 3%11% from $29.92$28.54 per BOE for the sixnine months ended JuneSeptember 30, 2024, to $30.69$31.59 per BOE for the sixnine months ended June September 30, 2025.

We pay production taxes, transportation and processing costs based on realized oil and natural gas sales. Production taxes, transportation and processing costs were $700,066$1,135,605 for the sixnine months months ended JuneSeptember 30, 2025, compared to $837,265$1,326,789 for the sixnine months ended JuneSeptember 30, 2024. As a percentage of oil and natural gas sales, these costs were 8.6%9.1% and 8.2%8.5% in the sixnine months ended JuneSeptember 30, 2025 and 2024, respectively. Production taxes, transportation, and processing as a percent of total oil and natural gas sales are consistent with historical trends.

Depletion, depreciation and amortization (“DD&A”) was $555,265$1,082,136 for the sixnine months ended JuneSeptember 30, 2025 compared to $998,616$1,506,242 for the sixnine months ended JuneSeptember 30, 2024. DD&A was $4.35$5.29 per BOE for the sixnine months ended JuneSeptember 30, 2025, compared to $6.80$6.58 per BOE for the sixnine months ended JuneSeptember 30, 2024. The aggregate decreaseincrease in DD&A expense for the sixnine months ended JuneSeptember 30, 2025, compared to the sixnine months ended June September 30, 2024, was driven by the increase in the cost basis offset by a decrease in oil and gas production.

Accretion expense was $251,538$44,893 for the sixnine months ended JuneSeptember 30, 2025, compared to $73,531$83,926 for the sixnine months ended JuneSeptember 30, 2024. Accretion expense was $1.97$0.22 per BOE for the nine months ended September 30, 2025, compared to $0.37 per BOE for the six months ended June 30, 2025, compared to $0.50 per BOE for the sixnine months ended JuneSeptember 30, 2024. The aggregate increase in accretion expense for the sixnine months ended JuneSeptember 30, 2025, compared to the sixnine months ended JuneSeptember 30, 2024, was driven by changes in certain assumptions, specifically the inflation factor.assumptions.

General and administrative expenses were $4,025,589$6,616,885 for the sixnine months ended JuneSeptember 30, 2025, compared to $4,633,486$6,868,749 for the sixnine months ended JuneSeptember 30, 2024. The decreaseincrease in general and administrative expenses is primarily due to increase legal and professional fees associated with the transactions closed during the current period, partially offset by a decreased stock-based compensation in the current period of $605,778$1,072,567 compared to $699,248$1,516,933 in the comparative period, and our focus on reducing overhead and overall levels of general and administrative costs.period.

Interest expense was $3,422,784$4,643,174 for the sixnine months ended JuneSeptember 30, 2025, compared to $3,890,899$5,732,747 for the sixnine months ended JuneSeptember 30, 2024. The decrease in interest expense is driven by the decreases in the Private Notes Payable and the Senior Secured termTerm loanLoan, andalong with the Privateeventual Notessettlement Payable.of the Senior Term Loan.

During the sixnine months ended JuneSeptember 30, 2025, the the Company recorded $669,817$1,069,514 related to the amortization of financing costs compared to $813,181$1,982,958 for the sixnine months ended June September 30, 2024. These costs are attributable to deferred finance costs paid on the Senior Secured Term Loan, and discounts associated with the Private Notes Payable during 2023.

The change in fair value of forward purchase agreement consisted of a lossgain of $325,472$655,865 for the sixnine months ended JuneSeptember 30, 2024 related to the inputs used in our fair value estimate of the FPA Putforward Option,purchase agreement put option, primarily the decline in our stock price during the sixnine months ended JuneSeptember 30, 2024. The key inputs to the fair value estimate include our stock price, which declined during the Successor period, and the likelihood, timing and price of a potential dilutive offering. The FPAforward purchase agreement put option was settled during the year ended December 31, 2024 and therefore no change in fair value was recorded in the sixnine months ended JuneSeptember 30, 2025.

The change in fair value of warrant liabilities consisted of a loss of $152,490 for the sixnine months ended JuneSeptember 30, 2025, compared to a loss of $346.888$484,799 for the sixnine months ended June September 30, 2024, related to fluctuations in the trading price of our warrants, a portion of which were accounted for as liabilities due to the redemption provisions in those issued to Private Note holders. All warrants previously accounted for as liabilities were exchanged into convertible notes during the sixnine months ended JuneSeptember 30, 2025.

The change in fair value of convertible note liabilities liabilities consisted of a loss of $131,677 for the sixnine months ended JuneSeptember 30, 2025.

The Company recognized a gain on extinguishment of liabilities of $299,601$2,146,285 during the sixnine months ended JuneSeptember 30, 20252025, primarily related to the settlement of the Senior Term Loan, the exchange of certain notes payable and warrant liabilities for convertible note agreements.agreements, other liabilities associated with the Company’s prior acquisition.

As of JuneSeptember 30, 2025, we had outstanding debt of $21,386,735 under our Senior Secured Term Loan, $15,000,000 under the Seller Note, and $5,650,000$4,425,000 of convertible notes payable and $1,368,402$1,248,062 from merchant cash advances. A total of $6,121,756$1,248,062 of this is due within one year. As of JuneSeptember 30, 2025, we had $3,060,971 $875,604 of cash and cash equivalents on hand, of which $2,600,000 is restricted cash in an escrow account pursuant to the requirements of the Senior Secured Term Loan,hand and had a working capital deficit of $21,731,979. $9,940,605. 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.

We had negative cash flow from operations of $1,796,949$9,520,380 for the sixnine months ended JuneSeptember 30, 2025 and positive cash flow from operations of $3,700,686 for the year ended December 31, 2024. Additionally, 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 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 $[10,435,066]$11,045,626 in cash proceeds related to the sale of 15,100,000 16,800,000 shares of common stock under this agreement and expect to continue to utilize it to fund 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.

Sources and uses of cash for the sixnine months ended ended June,September, 2025 and 2024, are as follows:

The change in net cash flow used operating activities for the sixnine months ended JuneSeptember 30, 2025, as compared to 2024 is primarily due to decreased production volumes and a reduction in payable payable balances during the current period.

Net cash used in investing activities for the six nine months ended June September 30, 2025 was primarily related to $2,638,532cash proceeds from the sale of the of the 2025 ORRI’s and Farmout Agreement for aggregate proceeds of $45,500,000, partially offset by the repurchase of the Pogo ORRI for $13,500,000 in cash and $3,612,074 in development costs for our reserves. Cash flows used in investing activities for the sixnine months ended JuneSeptember 30, 2024 consisted primarily of $3,410,552$3,275,667 of cash paid for development costs of our reserves.

Net cash provided by financing activities during the sixnine months ended JuneSeptember 30, 2025 were primarily related to the sale of common stock under the Common Stock Purchase agreement Agreement of $7,024,332 $8,117,772 and proceeds of $1,098,048$1,676,300 from short term notes payable offset by repayments of the Senior Secured Term Loan of $2,309,681$22,215,898, repayment of the seller note of $7,000,000 and Private Notes Payable of $1,287,805.$2,102,794. Cash flows used in financing activities for sixnine months ended JuneSeptember 30, 2024 were primarily related to repayments of the Senior Secured Term Loan of $887,174$2,945,312 and Private Notes Payable of $33,750,$43,750, partially offset by an additional $250,000$1,184,272 in cash proceeds from sales of common stock under the Common Stock Purchase Agreement, $967,500 in cash proceeds from merchant cash advances, and an additional $450,000 in cash proceeds from the Private Notes Payable issued during the sixnine months ended JuneSeptember 30, 2024.

We did not have any off-balance sheet arrangements as of June September 30, 2025.

We have contractual commitments under our SeniorPrivate Secured Term Loan, the Seller Note and the Private Notes Payable which include periodic interest payments. See Note 45 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 34 to our interim condensed consolidated unaudited financial statements.