References in this report (the “Quarterly Report”) to “we,” “us” or the “Company” refer to EON Resources, Inc. (formerly HNR Acquisition Corp.). References to our “management” or our “management team” refer to our officers and directors, and references to the “Sponsor” refer to HNRAC Sponsors, LLC. References to the Predecessor refer to the business of Pogo Resources, LLC and its subsidiaries prior to the Closing Date. The following discussion and analysis of the Company’s financial condition and results of operations should be read in conjunction with the unaudited consolidated financial statements and the notes thereto contained elsewhere in this Quarterly Report. Certain information contained in the discussion and analysis set forth below includes forward-looking statements that involve risks and uncertainties. Special Note Regarding Forward-Looking Statements This Quarterly Report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Exchange Act that are not historical facts and involve risks and uncertainties that could cause actual results to differ materially from those expected and projected. All statements, other than statements of historical fact included in this Form 10-Q including, without limitation, statements in this “Management’s Discussion and Analysis of Financial Condition and Results of Operations” regarding the Company’s financial position, business strategy and the plans and objectives of management for future operations, are forward-looking statements. Words such as “expect,” “believe,” “anticipate,” “intend,” “estimate,” “seek” and variations and similar words and expressions are intended to identify such forward-looking statements. Such forward-looking statements relate to future events or future performance, but reflect management’s current beliefs, based on information currently available. A number of factors could cause actual events, performance or results to differ materially from the events, performance and results discussed in the forward-looking statements. For information identifying important factors that could cause actual results to differ materially from those anticipated in the forward-looking statements, please refer to the Risk Factors section of the Company’s Annual Report on Form 10-K filed with the SEC. The Company’s securities filings can be accessed on the EDGAR section of the SEC’s website at www.sec.gov. Except as expressly required by applicable securities law, the Company disclaims any intention or obligation to update or revise any forward-looking statements whether as a result of new information, future events or otherwise. 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, and South Justis Field in Lea County, New Mexico which are both in the sub-area of the Permian Basin. LHO focuses primarily on production through waterflooding recovery methods. Our assets as mentioned above consist of contiguous leasehold positions in the 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 addition, our South Justis 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 South Justis field 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 nine months ended September 30, 2025 was 749 barrel of oil equivalent (“BOE”) per day. Our average daily production for the year ended December 31, 2024, was 798 BOE per day. The decrease in production is due to an increase in well downtime, water injection flowlines that needed repair or replacement, and the conveyance of the 10% Override royalty interest to Pogo Royalty. 30 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 nine months ended September 30, 2025 and 2024, was $(1.52) and $(2.07) per barrel, respectively. Our natural gas price differential during the nine months ended September 30, 2025 and 2024, was $(0.36) and $0.03 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 three and nine months ended September 30, 2025 and 2024. For the three months ended September 30, 2025 2024 Average NYMEX Prices (1) Oil (per Bbl) $ 65.74 $ 76.24 Natural gas (per Mcf) $ 3.03 $ 2.11 31 For the nine months ended September 30, 2025 2024 Average NYMEX Prices (1) Oil (per Bbl) $ 67.40 $ 78.50 Natural gas (per Mcf) $ 3.45 $ 2.11 (1) Based on average NYMEX closing prices. For the nine months ended September 30, 2025, the average NYMEX oil pricing was $67.40 per barrel of oil or 14% lower than the average NYMEX price per barrel for the nine months ended September 30, 2024. Our settled derivatives increased our realized oil price per barrel by $3.58 in the nine months ended September 30, 2025, and decreased our realized oil price per barrel by $2.56 in the nine months ended September 30, 2024. Our average realized oil price per barrel after reflecting settled derivatives and location differentials was $69.46 and $73.87 for the nine months ended September 30, 2025 and 2024, respectively. The average NYMEX natural gas pricing for the nine months ended September 30, 2025, was $3.45 per Mcf, or 64% higher than the average NYMEX price of $2.11 per Mcf for the nine months ended September 30, 2024. Results of Operations Three months ended September 30, 2025 Compared to three months ended September 30, 2024 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. Three Months Ended September 30, 2025 Three Months Ended September 30, 2024 Revenues Crude oil $ 4,351,800 $ 5,275,254 Natural gas and natural gas liquids 132,466 89,978 Gain (loss) on derivative instruments, net (224,512 ) 1,900,662 Other revenue 104,587 98,452 Total revenues $ 4,364,341 7,364,346 Average sales prices: Oil (per Bbl) $ 63.85 $ 78.74 Effect on gain (loss) of settled oil derivatives on average price (per Bbl) 6.30 (1.61 ) Oil net of settled oil derivatives (per Bbl) 70.15 77.13 Natural gas (per Mcf) $ 2.50 $ 1.55 Realized price on a BOE basis excluding settled commodity derivatives $ 58.26 $ 69.98 Effect of gain (loss) on settled commodity derivatives on average price (per BOE) 5.58 (1.41 ) Realized price on a BOE basis including settled commodity derivatives $ 63.84 $ 68.57 Expenses Production taxes, transportation and processing 435,539 489,524 Lease operating 2,545,969 2,136,732 Depletion, depreciation and amortization 526,871 507,626 Accretion of asset retirement obligations 29,388 10,395 General and administrative 2,591,296 2,235,263 Total expenses 6,129,063 5,379,540 Costs and expenses (per BOE): Production taxes, transportation, and processing $ 5.66 $ 6.39 Lease operating expenses 33.08 27.87 Depreciation, depletion, and amortization expense 6.84 6.62 Accretion of asset retirement obligations 0.38 0.14 General and administrative 33.66 29.16 Net producing wells at period-end 472 342 32 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 three months ended September 30, 2025, our oil and natural gas sales decreased 16% from the three months ended September 30, 2024, excluding the effect of settled commodity derivatives, and a 2% increase in production volumes. Production volumes increased for the three months ended September 30, 2025 from the three months ended September 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. Production for the comparable periods is set forth in the following table: For the Three Months Ended September 30, 2025 2024 Production: Oil (MBbl) 68 67 Natural gas (MMcf) 53 58 Total (MBOE)(1) 77 77 Average daily production: Oil (Bbl) 741 746 Natural gas (Mcf) 575 647 Total (BOE)(1) 837 854 (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 $224,512 for the three months ended September 30, 2025, compared to a gain of $ 1,900,662 for the three months ended September 30, 2024. Lower commodity prices in the three months ended September 30, 2025, resulted in realized gains of $429,241 compared to realized losses of $ 107,969 for the three months ended September 30, 2024. For the three months ended September 30, 2025, unrealized losses were $653,753 compared to unrealized gains of $ 2,008,631 for the three months ended September 30, 2024. For the three months ended September 30, 2025, our average realized oil price per barrel after reflecting settled derivatives was $70.15 compared to $77.12 for the three months ended September 30, 2024. For the three months ended September 30, 2025, our settled derivatives increased our realized oil price per barrel by $6.30 compared to decreasing the price per barrel by $1.61 for the three months ended September 30, 2024. As of September 30, 2025, we ended the period with a $20,561 net derivative asset compared to a net asset of $106,397 as of December 31, 2024. Other Revenue Other revenue was $104,587 for the three months ended September 30, 2025, compared to $98,452 for the three months ended September 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. 33 Lease Operating Expenses Lease operating expenses were $2,545,969 for the three months ended September 30, 2025, compared to $ 2,136,732 for the three months ended September 30, 2024. On a per unit basis, production expenses increased 19% from $27.87 per BOE for the three months ended September 30, 2024, to $33.08 per BOE for the three months ended September 30, 2025. Production Taxes, Transportation and Processing We pay production taxes, transportation and processing costs based on realized oil and natural gas sales. Production taxes, transportation and processing costs were $435,539 for the three months ended September 30, 2025, compared to $489,524 for the three months ended September 30, 2024. As a percentage of oil and natural gas sales, these costs were 9.7% and 9% in the three months ended September 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 Depletion, depreciation and amortization (“DD&A”) was $526,871 for the three months ended September 30, 2025 compared to $507,626 for the three months ended September 30, 2024. DD&A was $6.84 per BOE for the three months ended September 30, 2025, compared to $6.62 per BOE for the three months ended September 30, 2024. The aggregate increase in DD&A expense for the three months ended September 30, 2025, compared to the three months ended September 30, 2024, was driven by the increase in the cost basis offset by a decrease in oil and gas production. Accretion of Asset Retirement Obligations Accretion expense was $29,388 for the three months ended September 30, 2025, compared to $10,395 for the three months ended September 30, 2024. Accretion expense was $0.38 per BOE for the three months ended September 30, 2025, compared to $0.14 per BOE for the three months ended September 30, 2024. The aggregate increase in accretion expense for the three months ended September 30, 2025, compared to the three months ended September 30, 2024, was driven by the addition of the South Justice field. General and Administrative General and administrative expenses were $2,591,296 for the three months ended September 30, 2025, compared to $2,235,263 for the three months ended September 30, 2024. The increase 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 $419,669 compared to $326,995 in the comparative period. 34 Interest Expense and amortization of financing costs Interest expense was $1,220,390 for the three months ended September 30, 2025, compared to $1,841,848 for the three months ended September 30, 2024. The decrease in interest expense is driven by the decreases in the Private Notes Payable and the Senior Secured Term Loan, along with the eventual settlement of the Senior Term Loan. During the three months ended September 30, 2025, the Company recorded $399,697 related to the amortization of financing costs compared to $507,701 for the three months ended 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. Change in fair value of forward purchase agreement The change in fair value of forward purchase agreement consisted of a gain of $981,337 for the three months ended September 30, 2024 related to the inputs used in our fair value estimate of the forward purchase agreement put option, primarily the decline in our stock price during the three months ended September 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 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 three months ended September 30, 2025. Change in fair value of warrant liabilities The change in fair value of warrant liabilities consisted of a loss of $137,911 for the three months ended 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 nine months ended September 30, 2025. Gain on extinguishment of liabilities The Company recognized a gain on extinguishment of liabilities of $1,846,684 during the three months ended September 30, 2025, primarily related to the settlement of the Senior Term Loan and other liabilities associated with the Company’s prior acquisition. Gain on sale of oil and gas properties The Company recognized a gain on the sale of oil and gas properties of $13,414,100 during the three months ended September 30, 2025, related to the sale of the 5% Horizontal ORRI and the Farmout Program. 35 Nine months ended September 30, 2025 Compared to nine months ended September 30, 2024 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. Nine Months Ended September 30, 2025 Nine Months Ended September 30, 2024 Revenues Crude oil $ 12,265,145 $ 15,132,363 Natural gas and natural gas liquids 339,838 396,670 Gain (loss) on derivative instruments, net 579,896 (180,063 ) Other revenue 327,208 359,270 Total revenues $ 13,512,087 15,708,240 Average sales prices: Oil (per Bbl) $ 65.88 $ 76.43 Effect on gain (loss) of settled oil derivatives on average price (per Bbl) 3.58 (2.56 ) Oil net of settled oil derivatives (per Bbl) 69.46 73.87 Natural gas (per Mcf) $ 3.09 $ 2.14 Realized price on a BOE basis excluding settled commodity derivatives $ 61.63 $ 67.86 Effect of gain (loss) on settled commodity derivatives on average price (per BOE) 3.26 (2.21 ) Realized price on a BOE basis including settled commodity derivatives $ 64.89 $ 65.65 Expenses Production taxes, transportation and processing 1,135,605 1,326,789 Lease operating 6,460,744 6,530,431 Depletion, depreciation and amortization 1,082,136 1,506,242 Accretion of asset retirement obligations 44,893 83,926 General and administrative 6,616,885 6,868,749 Total expenses 15,340,263 16,316,137 Costs and expenses (per BOE): Production taxes, transportation, and processing $ 5.55 $ 5.80 Lease operating expenses 31.59 28.54 Depreciation, depletion, and amortization expense 5.29 6.58 Accretion of asset retirement obligations 0.22 0.37 General and administrative 32.35 30.02 Net producing wells at period-end 472 342 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 nine months ended September 30, 2025, our oil and natural gas sales decreased 19% from the nine months ended September 30, 2024, excluding the effect of settled commodity derivatives, and a 11% decrease in production volumes. Production volumes decreased for the nine months ended September 30, 2025 from the nine months ended September 30, 2024 as a result of increased flaring of natural gas during the current period. 36 Production for the comparable periods is set forth in the following table: For the Nine Months Ended September 30, 2025 2024 Production: Oil (MBbl) 186 198 Natural gas (MMcf) 110 185 Total (MBOE)(1) 205 229 Average daily production: Oil (Bbl) 682 732 Natural gas (Mcf) 403 686 Total (BOE)(1) 749 846 (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 gain on derivative contracts of $579,896 for the nine months ended September 30, 2025, compared to a loss of $180,063 for the nine months ended September 30, 2024. Lower commodity prices in the nine months ended September 30, 2025, resulted in realized gains of $665,732 compared to realized losses of $506,571 for the nine months ended September 30, 2024. For the nine months ended September 30, 2025, unrealized losses were $85,836 compared to unrealized gains of $326,508 for the nine months ended September 30, 2024. For the nine months ended September 30, 2025, our average realized oil price per barrel after reflecting settled derivatives was $69.46 compared to $73.87 for the nine months ended September 30, 2024. For the nine months ended September 30, 2025, our settled derivatives increased our realized oil price per barrel by $3.58 compared to decreasing the price per barrel by $2.56 for the nine months ended September 30, 2024. As of September 30, 2025, we ended the period with a $20,561 net derivative asset compared to a net asset of $106,397 as of December 31, 2024. Other Revenue Other revenue was $327,208 for the nine months ended September 30, 2025, compared to $359,270 for the nine months ended September 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 Lease operating expenses were $6,460,744 for the nine months ended September 30, 2025, compared to $6,530,431 for the nine months ended September 30, 2024. On a per unit basis, production expenses increased 11% from $28.54 per BOE for the nine months ended September 30, 2024, to $31.59 per BOE for the nine months ended September 30, 2025. Production Taxes, Transportation and Processing We pay production taxes, transportation and processing costs based on realized oil and natural gas sales. Production taxes, transportation and processing costs were $1,135,605 for the nine months ended September 30, 2025, compared to $1,326,789 for the nine months ended September 30, 2024. As a percentage of oil and natural gas sales, these costs were 9.1% and 8.5% in the nine months ended September 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. 37 Depletion, Depreciation and Amortization Depletion, depreciation and amortization (“DD&A”) was $1,082,136 for the nine months ended September 30, 2025 compared to $1,506,242 for the nine months ended September 30, 2024. DD&A was $5.29 per BOE for the nine months ended September 30, 2025, compared to $6.58 per BOE for the nine months ended September 30, 2024. The aggregate increase in DD&A expense for the nine months ended September 30, 2025, compared to the nine months ended September 30, 2024, was driven by the increase in the cost basis offset by a decrease in oil and gas production. Accretion of Asset Retirement Obligations Accretion expense was $44,893 for the nine months ended September 30, 2025, compared to $83,926 for the nine months ended September 30, 2024. Accretion expense was $0.22 per BOE for the nine months ended September 30, 2025, compared to $0.37 per BOE for the nine months ended September 30, 2024. The aggregate increase in accretion expense for the nine months ended September 30, 2025, compared to the nine months ended September 30, 2024, was driven by changes in certain assumptions. General and Administrative General and administrative expenses were $6,616,885 for the nine months ended September 30, 2025, compared to $6,868,749 for the nine months ended September 30, 2024. The increase 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 $1,072,567 compared to $1,516,933 in the comparative period. Interest Expense and amortization of financing costs Interest expense was $4,643,174 for the nine months ended September 30, 2025, compared to $5,732,747 for the nine months ended September 30, 2024. The decrease in interest expense is driven by the decreases in the Private Notes Payable and the Senior Secured Term Loan, along with the eventual settlement of the Senior Term Loan. During the nine months ended September 30, 2025, the Company recorded $1,069,514 related to the amortization of financing costs compared to $1,982,958 for the nine months ended 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. Change in fair value of forward purchase agreement The change in fair value of forward purchase agreement consisted of a gain of $655,865 for the nine months ended September 30, 2024 related to the inputs used in our fair value estimate of the forward purchase agreement put option, primarily the decline in our stock price during the nine months ended September 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 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 nine months ended September 30, 2025. Change in fair value of warrant and convertible note liabilities The change in fair value of warrant liabilities consisted of a loss of $152,490 for the nine months ended September 30, 2025, compared to a loss of $484,799 for the nine months ended 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 nine months ended September 30, 2025. The change in fair value of convertible note liabilities consisted of a loss of $131,677 for the nine months ended September 30, 2025. Gain on extinguishment of liabilities The Company recognized a gain on extinguishment of liabilities of $2,146,285 during the nine months ended September 30, 2025, primarily related to the settlement of the Senior Term Loan, the exchange of certain notes payable and warrant liabilities for convertible note agreements, other liabilities associated with the Company’s prior acquisition. Gain on sale of oil and gas properties The Company recognized a gain on the sale of oil and gas properties of $13,414,100 during the nine months ended September 30, 2025, related to the sale of the 5% Horizontal ORRI and the Farmout Program. 38 Liquidity, Capital Resources and Going Concern Our main sources of liquidity have been internally generated cash flows from operations and credit facility borrowings. Our primary use of capital has been for the development of oil and gas properties and the return of initial invested capital to our owners. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position. As of September 30, 2025, we had outstanding debt of $4,425,000 of convertible notes payable and $1,248,062 from merchant cash advances. A total of $1,248,062 of this is due within one year. As of September 30, 2025, we had $875,604 of cash and cash equivalents on hand and had a working capital deficit of $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 $9,520,380 for the nine months ended September 30, 2025 and 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 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 $11,045,626 in cash proceeds related to the sale of 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. Cash Flows Sources and uses of cash for the nine months ended September, 2025 and 2024, are as follows: Nine Months Ended September 30, 2025 Nine Months Ended September 30, 2024 Net cash (used in) provided by operating activities $ (9,520,380 ) $ 3,346,362 Net cash provided by (used in) investing activities 28,387,926 (3,295,667 ) Net cash used in financing activities (20,963,500 ) (809,253 ) Net change in cash and cash equivalents $ (2,095,954 ) $ (758,558 ) Operating Activities The change in net cash flow used operating activities for the nine months ended September 30, 2025, as compared to 2024 is primarily due to decreased production volumes and a reduction in payable balances during the current period. Investing Activities Net cash used in investing activities for the nine months ended September 30, 2025 was primarily related to cash 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 nine months ended September 30, 2024 consisted primarily of $3,275,667 of cash paid for development costs of our reserves. 39 Financing Activities Net cash provided by financing activities during the nine months ended September 30, 2025 were primarily related to the sale of common stock under the Common Stock Purchase Agreement of $8,117,772 and proceeds of $1,676,300 from short term notes payable offset by repayments of the Senior Secured Term Loan of $22,215,898, repayment of the seller note of $7,000,000 and Private Notes Payable of $2,102,794. Cash flows used in financing activities for nine months ended September 30, 2024 were primarily related to repayments of the Senior Secured Term Loan of $2,945,312 and Private Notes Payable of $43,750, partially offset by $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 nine months ended September 30, 2024. Off-Balance Sheet Arrangements We did not have any off-balance sheet arrangements as of September 30, 2025. Contractual obligations We have contractual commitments under our 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 our Annual Report on its Form 10-K filed with the SEC on April 16, 2025 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 12 of notes to the consolidated annual 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. 40 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 interim unaudited consolidated financial statements. Asset Retirement Obligations We have significant obligations to remove tangible equipment and facilities and to restore the land at the end of crude oil and natural gas production operations. Our removal and restoration obligations are primarily associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, credit-adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations, a corresponding adjustment is generally made to the crude oil and natural gas property or other property and equipment balance. See Note 2 of notes to the interim unaudited 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 8 of notes to the consolidated financial statements. Derivative Instruments We use derivative financial instruments to mitigate its exposure to commodity price risk associated with oil prices. Our derivative financial instruments are recorded on the consolidated balance sheets as either an asset or a liability measured at fair value. We have elected not to apply hedge accounting for its existing derivative financial instruments, and as a result, we recognize the change in derivative fair value between reporting periods currently in its consolidated statements of operations. The fair value of our 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 3 for additional information about our derivative instruments. New Accounting Pronouncements The effects of new accounting pronouncements are discussed in Note 2 to the consolidated financial statements.