EON Resources Inc.
For the period ended Dec 31, 2025. Filed Sep 28, 2026.
View on SEC.govAbout this filing
A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2025 · Filed Sep 28, 2026
EONR$0.27+3.7%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2024-12-31; filed 2025-04-16.
0001213900-25-032248
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-K
Period ended 2025-12-31; filed 2026-09-28.
0001213900-26-103762
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 92 previous paragraphs and 91 current paragraphs.
50 unchanged; 26 reworded; 13 added; 15 removed; 1 previous and 2 current paragraphs rearranged.
Tables are not compared: 16 previous and 16 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (13)
Current report
Overview
Current report
Accretion expense was $46,426 as of December 31, 2025, compared to $144,988 as of December 31, 2024. Accretion expense was $0.17 per BOE for the year ended December 31, 2025, compared to $0.50 per BOE for the year ended December 31,2024.
Current report
General and administrative expenses were $12,080,450 as of December 31, 2025, compared to $10,381,095 as of December 31, 2024. The increase in general and administrative expenses is primarily due to increased legal and professional fees associated with the transactions closed during the current period, partially offset by decreased stock-based compensation in the current period of $1,067,140 compared to $2,778,991 in the comparative period.
Current report
Interest expense was $4,892,170 for the year ended of December 31, 2025, compared to $7,643,200 for the year ended December 31, 2024. The decrease in interest expense is driven by the decreases in the Private Notes Payable and the Senior Secured Term Loan, along with the eventual settlement of the Senior Term Loan.
Current report
Change in fair value of derivative liabilities
Current report
The change in fair value of derivative liabilities related to the changes in fair value of the embedded conversion option on convertible notes issued, and consisted of a loss of $2,070,278 as of December 31, 2025. The key inputs to the fair value of the derivative liability include our stock price, estimated equity volatility, estimated discount rate and the likelihood, timing and price of a potential dilutive offering.
Current report
The change in fair value of derivative liabilities, related party related to the estimated fair value of the Put Option Right, and consisted of a gain of $341,000 as of December 31, 2025, compared to a loss of $746,000 for the year ended December 31, 2024. The key inputs to the fair value of the Put Option Right estimate include our stock price, estimated tenure of the holder as CEO, and an estimated discount rate.
Current report
The Company recognized a gain on extinguishment of liabilities of $540,347 during the year ended December 31, 2025, primarily related to the settlement of the Senior Term Loan and other liabilities associated with the Company’s prior acquisition.
Current report
The change in net cash flow used in operating activities for the year ended December 31, 2025, as compared to 2024 is primarily due to decreased production volumes and market prices for crude oil.
Current report
Net cash provided by investing activities for the year ended December 31, 2025 was primarily related to cash proceeds from the sale of the of the 2025 ORRIs and Farmout Agreement for aggregate proceeds of $45,500,000, partially offset by the repurchase of the Pogo ORRI for $13,675,000 in cash, $6,563,949 in development costs for our reserves. Cash flows used in investing activities for the year ended December 31, 2024 consisted primarily of $3,555,062 of cash paid for development costs of our reserves.
Current report
Net cash used in financing activities during the year ended December 31, 2025 were primarily related to the sale of common stock under the Common Stock Purchase Agreement of $8,502,252, proceeds of $3,312,550 from short term notes payable and proceeds of $561,120 from issuance of convertible debt and proceeds of $200,000 from related party loans offset by repayments of the Senior Secured Term Loan and Seller Note of $29,215,898, and repayment of the short term notes payable of $3,572,179. Cash flows used in financing activities for year ended December 31, 2024 were primarily related to repayments of the Senior Secured Term Loan of $3,984,286, short term notes payable of $989,018 and related party notes payable of $62,750, partially offset by $2,628,334 in cash proceeds from sales of common stock under the Common Stock Purchase Agreement, $1,298,200 from the short-term notes payable, and an additional $450,000 in cash proceeds from the related party Notes Payable issued during the year ended December 31, 2024.
Current report
Derivative Instruments - Hedging
Current report
Derivative Instruments – Other Financial instruments
Removed paragraphs (15)
Previous report
Pogo Royalty Overriding Royalty Interest Transaction
Previous report
Effective July 1, 2023, the Predecessor transferred to Pogo Royalty, a related party, an assigned and undivided overriding royalty interest (“ORRI”) equal in amount to ten percent (10%) of Pogo Resources, LLC’s and LH Operating, LLC’s interest all oil, gas and minerals in, under and produced from each lease. The consideration received for the 10% ORRI was $10. Thus, a loss of $816,011 was recorded as a result of the conveyance during the period from January 1, 2023 to November 14, 2023 of the Predecessor. Additionally, because of this transaction, our reserve balance was decreased as well our current net production volumes and revenues. Additional details are discussed in Note 1 and Note 13 of notes to the consolidated financial statements.
Previous report
General and administrative expenses were $10,381,095 as of December 31, 2024 compared to $7,253,384 on a combined Successor and Predecessor basis for the year ended December 31, 2023. The increase for general and administrative expenses is primarily due to increased cost of outsourced legal, professional, and accounting services as a result of the transaction disclosed in Note 1 in the notes to the consolidated financial statements and the costs of being a public company, and includes stock-based compensation expense of $2,778,991 for the year ended December 31, 2024. The general and administrative expense total of $3,553,117 for the period from November 15, 2023 to December 31, 2023 for the Successor includes $1,500,000 from the 138,122 shares of Class A common stock issued to White Lion for the commitment fee on the Common Stock Purchase Agreement, $910,565 in stock-based compensation to certain Founders under the Founder Pledge Agreement, and $135,400 in other stock-based compensation.
Previous report
Acquisition costs
Previous report
There were no acquisition costs as of December 31, 2024, compared to $9,999,860 during the Successor period from November 15, 2023 to December 31, 2023, and included an aggregate of $7,854,660 in costs related to the Forward Purchase Agreement and the Non-Redemption Agreements, due diligence and broker fees related to closing the Purchase.
Previous report
Interest expense was $7,643,200 as of December 31, 2024, compared to $1,043,312 for the period from November 15, 2023 to December 31, 2023 (Successor), $1,834,208 for the period from January 1, 2023 to November 14, 2023 (Predecessor), The Successor period interest expense is driven by the Senior Secured Term loan entered into as part of the Closing, and the Private Notes Payable. The interest expense during the Predecessor period from January 1, 2023 to November 15, 2023 was primarily due to an increase in the average amount of the Predecessor’ revolving credit facility outstanding and an increase in the weighted average interest rate. The revolving credit facility was not assumed in the Acquisition.
Previous report
The Company recognized a gain on extinguishment of liabilities of $1,638,138 during the year ended December 31, 2024. In November 2024, the Company entered into a settlement agreement with the FPA Seller to fully release the Company from the terms of the FPA. We agreed to issue to the FPA Seller 450,000 restricted Class A Common shares which had a fair value of $450,000 based on the closing price of the Company’s common stock at the agreement date. The Company recognized a gain on settlement of the FPA liability of $82,998, which is included in Gain on Extinguishment of Liabilities on the Company’s consolidated statement of operations for the year ended December 31, 2024.
Previous report
The Company also recognized a gain of $1,720,000 related to the settlement of royalties payable and other claims with the Sellers. The Company recognized a loss on extinguishment of accounts payable of $76,200, and recognized a loss of $88,660 related to the exchange of certain notes payable and warrant liabilities for convertible note agreements.
Previous report
Loss on asset sales
Previous report
Loss on asset sales was $816,011 on a combined Successor and Predecessor basis for the year ended December 31, 2023, compared to $0 for the year ended December 31, 2024. The decrease was due to the loss that was recognized as a result of the conveyance of the 10% overriding royalty interest to Pogo Royalty in July 2023.
Previous report
The decrease in net cash flow provided by operating activities for the year ended December 31, 2024, as compared to 2023 on a combined Successor and Predecessor basis is primarily due to increased net loss as a result of decreased prices and production volumes, and higher general and administrative costs associated with public filings.
Previous report
Net cash used in investing activities for the year ended December 31, 2024 was primarily due to the development of crude oil and gas properties. Net cash provided by investing activities in the Successor period from November 15, 2023 to December 31, 2023 was primarily due to Trust Account withdrawals associated with the Closing in November 2023 of $49,362,479, partially offset by the cash paid to the Sellers of EON of $30,827,804 at the Closing, net of cash acquired. Cash flows used in investing activities in the Predecessor period ending November 14, 2023 consisted of $6,769,557 of cash paid for oil and gas property costs, primarily due to significant expenditures in the previous year to upgrade certain wells and meet compliance requirements.
Previous report
Net cash used in financing activities for the year ended December 31, 2024 was primarily due to repayments of long-term debt offset by the proceeds from the sale of common stock under the Common Stock Purchase Agreement. Net cash used by financing activities during the Successor period from November 15, 2023 to December 31, 2023 were primarily related to the redemptions of common stock of Public Shares at Closing of $44,737,839, partially offset by the net proceeds from the Senior Secured Term Loan of $27,191,008.
Previous report
Forward Purchase Agreement Valuation
Previous report
Derivative Instruments
Reworded paragraphs (26)
Previous wording
We are an independent oil and natural gas company based in Texas and formed in 2017 that is focused on the acquisition, development, exploration, production and divestiture of oil and natural gas properties in the Permian Basin. The Permian Basin is located in west Texas and southeastern New Mexico and is characterized by high oil and liquids-rich natural gas content, multiple vertical and horizontal target horizons, extensive production histories, long-lived reserves and historically high drilling success rates. our properties are in the Grayburg-Jackson Field in Eddy County, New Mexico, which is a sub-area of the Permian Basin. Pogo focuses primarily on production through waterflooding recovery methods.
Current wording
We are an independent oil and natural gas company based in Texas and formed in 2017 that is focused on the acquisition, development, exploration, production and divestiture of oil and natural gas properties in the Permian Basin. The Permian Basin is located in west Texas and southeastern New Mexico and is characterized by high oil and liquids-rich natural gas content, multiple vertical and horizontal target horizons, extensive production histories, long-lived reserves and historically high drilling success rates. Our properties are in the GJF in Eddy County, New Mexico, and SJF in Lea County, New Mexico which are both in the sub-area of the Permian Basin. LHO focuses primarily on production through waterflooding recovery methods.
Previous wording
The Company’s assets as mentioned above consist of contiguous leasehold positions of approximately 13,700 gross (13,700 net) acres with an average working interest of 100%. We operate 100% of the net acreage across the Company’s assets, all of which is net operated acreage of vertical wells with average depths of approximately 3,810 feet.
Current wording
Our assets as mentioned above consist of contiguous leasehold positions in the GJF of approximately 13,700 gross (13,700 net) acres with an average working interest of 100%. We operate 100% of the net acreage across the GJF, all of which is net operated acreage of vertical wells with average depths of approximately 3,810 feet. In addition, our SJF has contiguous leasehold positions of approximately 5,400 gross (5,400) acres with an average working interest of 94%. We operate 100% of the net acreage across the SJF assets, all of which is net operated acreage of vertical wells with average depths of approximately 6,000 feet.
Previous wording
Our average daily production for the year ended December 31, 2024, was 798 barrel of oil equivalent (“BOE”) per day, and for the year ended December 31, 2023, was 1,022 BOE per day. The decrease in production is due to an increase in well downtime, field conditions requiring certain enhancements, and the conveyance of the 10% Override royalty interest to Pogo Royalty.
Current wording
Our average daily net production for the year ended December 31, 2025 was 734 barrel of oil equivalent (“BOE”) per day. Our average daily net production for the year ended December 31, 2024, was 798 BOE per day. The decrease in production is due to an increase in well downtime, water injection flowlines that needed repair or replacement, increase in flaring of natural gas, and the conveyance of the 2025 ORRIs on September 9, 2025 with the recapitalization and Farmout funding.
Previous wording
The price at which our oil and natural gas production are sold typically reflects either a premium or discount to the New York Mercantile Exchange (“NYMEX”) benchmark price. Thus, our operating results are also affected by changes in the oil price differentials between the applicable benchmark and the sales prices we receive for our oil production. Our oil price differential to the NYMEX benchmark price during the years ended December 31, 2024 and 2023, was $(1.03) and $(4.95) per barrel, respectively. Our natural gas price differential during the years ended December 31, 2024 and 2023, was $0.08 and $(0.06) per one thousand cubic feet (“Mcf”), respectively. Fluctuations in our price differentials and realizations are due to several factors such as gathering and transportation costs, takeaway capacity relative to production levels, regional storage capacity, gain/loss on derivative contracts and seasonal refinery maintenance temporarily depressing demand.
Current wording
The price at which our oil and natural gas production are sold typically reflects either a premium or discount to the New York Mercantile Exchange (“NYMEX”) benchmark price. Thus, our operating results are also affected by changes in the oil price differentials between the applicable benchmark and the sales prices we receive for our oil production. Our oil price differential to the NYMEX benchmark price during the years ended December 31, 2025 and 2024, was $(1.53) and $(1.03) per barrel, respectively. Our natural gas price differential during the years ended December 31, 2025 and 2024, was $(1.64) and $0.08 per one thousand cubic feet (“Mcf”), respectively. Fluctuations in our price differentials and realizations are due to several factors such as gathering and transportation costs, takeaway capacity relative to production levels, regional storage capacity, gain/loss on derivative contracts and seasonal refinery maintenance temporarily depressing demand.
Previous wording
For the year ended December 31, 2024, the average NYMEX oil pricing was $76.55 per barrel of oil or 1% lower than the average NYMEX price per barrel for the year ended December 31, 2023. Our settled derivatives decreased our realized oil price per barrel by $1.91 and $3.63 in the years ended December 31, 2024, and 2023, respectively. Our average realized oil price per barrel after reflecting settled derivatives and location differentials was $73.61 for the year ended December 31, 2024 compared to $69.06 for the year ended December 31, 2023.
Current wording
For the year ended December 31, 2025, the average NYMEX oil pricing was $65.46 per barrel of oil or 14% lower than the average NYMEX price per barrel for the year ended December 31, 2024. Our settled derivatives increased our realized oil price per barrel by $2.89 in the year ended December 31, 2025, and decreased our realized oil price per barrel by $1.91 for the year ended December 31, 2024, respectively. Our average realized oil price per barrel after reflecting settled derivatives and location differentials was $66.82 for the year ended December 31, 2025 compared to $73.61 for the year ended December 31, 2024.
Previous wording
The average NYMEX natural gas pricing for the year ended December 31, 2024, was $2.19 per Mcf, or 14% lower than the average NYMEX price per Mcf for the year ended December 31, 2023.
Current wording
The average NYMEX natural gas pricing for the year ended December 31, 2025, was $3.53 per Mcf, or 61% higher than the average NYMEX price per Mcf for the year ended December 31, 2024.
Previous wording
For the year ended December 31, 2024, 86% and 14% of sales volumes from the assets were attributable to crude and natural gas, respectively. As of December 31, 2024, the company was continuing development of the Seven River waterflood interval. Further, as of December 31, 2024, the Company owned an interest in approximately 342 gross (342 net) producing wells.
Current wording
For the year ended December 31, 2025, 91% and 9% of production volumes from the assets were attributable to crude and natural gas, respectively. As of December 31, 2025, the Company was continuing development of the Seven Rivers waterflood interval and the SJF acquired in June 2025.
Previous wording
Our revenues vary from year to year primarily as a result of changes in realized commodity prices and production volumes. For the year ended December 31, 2024, our oil and natural gas sales decreased 15% from the year ended December 31, 2023 on a combined Successor and Predecessor basis, driven by a 28% decrease in production volumes offset by a 6% increase in realized prices, excluding the effect of settled commodity derivatives. The higher average price in the year ended December 31, 2024 compared to the combined year 2023, was driven by higher average NYMEX oil and natural gas prices during the first nine months of the year. Realized production from oil and gas properties decreased due to an increase in well downtime.
Current wording
Our revenues vary from year to year primarily as a result of changes in realized commodity prices and production volumes. For the year ended December 31, 2025, our oil and natural gas sales decreased 20% from the year ended December 31, 2024, driven by a 8% decrease in production volumes and a 13% decrease in realized prices, excluding the effect of settled commodity derivatives. The lower average price in the year ended December 31, 2025 compared to the year ending December 31, 2024, was driven by lower average NYMEX oil and natural gas prices during the year. Realized production from oil and gas properties decreased due to increased flaring of natural gas during the current period.
Previous wording
We recorded a loss on derivative contracts of $850,374 for the year ended December 31, 2024 compared to a gain of $392,765 on a combined Successor and Predecessor basis for the year ended December 31, 2023. Lower commodity prices in 2024, resulted in realized losses of $489,084 for the year ended December 31, 2024 compared to realized losses of $1,266,277 on a combined Successor and Predecessor basis for the year ended December 31, 2023. For the year ended December 31, 2024, our average realized oil price per barrel after reflecting settled derivatives was $73.61, compared to $73.82 on a combined Successor and Predecessor basis for the year ended December 31, 2023.
Current wording
We enter into commodity derivatives instruments to manage the price risk attributable to future oil production. We recorded a gain on derivative contracts of $663,010 for the year ended December 31, 2025, compared to a loss of $850,374 for the year ended December 31, 2024. Lower commodity prices in the year ended December 31, 2025, resulted in realized gains of $706,073 compared to realized losses of $489,084 for the year ended December 31, 2024. For the year ended December 31, 2025, unrealized losses were $43,063 compared to $361,290 for the year ended December 31, 2024.
Previous wording
As of December 31, 2024, we ended the period with a $106,397 net derivative asset compared to $467,687 as of December 31, 2023.
Current wording
As of December 31, 2025, we ended the period with a $63,334 net derivative asset compared to a net asset of $106,397 as of December 31, 2024.
Previous wording
Other revenue was $487,109 for the year ended December 31, 2024, compared to $571,189 on a combined Successor and Predecessor basis for the year ended December 31, 2023. The revenue is related to providing water services to a third party and the slight decrease is due to lower volumes in 2024 from supply line disruptions during the third quarter of 2024
Current wording
Other revenue was $383,196 for the year ended December 31, 2025 compared to $487,109 for year ended December 31, 2024. The revenue is related to providing water services to a third party. The contract is for one year starting on September 1, 2022, and has been renewed by mutual agreement.
Previous wording
Lease operating expenses were $8,614,080 for the year ended December 31,2024, compared to $10,146,119 on a combined Successor and Predecessor basis for the year ended December 31, 2023. On a per unit basis, production expenses increased 19% from $27.20 per BOE for the combined Successor and Predecessor year ended December 31, 2023, to $29.59 per BOE for the year ended December 31, 2024, due to increases in proactive maintenance activities, higher labor costs, and increased oil field service and supplies costs. Additionally, because of the conveyance of the 10% ORRI in July 2023, the net production volumes decreased, which increases the “per BOE” amounts.
Current wording
Lease operating expenses were $10,274,781 for the year ended December 31, 2025, compared to $8,614,080 for the year ended December 31, 2024. On a per unit basis, production expenses increased 30% from $29.59 per BOE for the year ended December 31, 2024, to $38.33 per BOE for the year ended December 31, 2025.
Previous wording
We pay production taxes, transportation and processing costs based on realized oil and natural gas sales. Production taxes, transportation and processing costs were $1,715,792 for the year ended December 31, 2024 compared to $2,343,862 on a combined Successor and Predecessor basis for the year ended December 31, 2023. As a percentage of oil and natural gas sales, these costs were 8.7% and 8.9% for the years ended December 31, 2024 and 2023 respectively. Production taxes, transportation, and processing as a percent of total oil and natural gas sales are consistent with historical trends.
Current wording
We pay production taxes, transportation and processing costs based on realized oil and natural gas sales. Production taxes, transportation and processing costs were $1,626,360 for the year ended December 31, 2025 compared to were $1,715,792 for the year ended December 31, 2024. As a percentage of oil and natural gas sales, these costs were 10.2% and 8.7% for the years ended December 31, 2025 and 2024 respectively. Production taxes, transportation, and processing as a percent of total oil and natural gas sales are consistent with historical trends.
Previous wording
Depletion, depreciation and amortization (“DD&A”) was $2,407,098 as of December 31, 2024, compared to $1,849,876 on a combined Successor and Predecessor basis for the year ended December 31, 2023. DD&A was $8.27 per BOE for the year ended December 31, 2024, compared to $4.53 per BOE on a combined Successor and Predecessor basis for the year ended December 31, 2023. The aggregate increase in DD&A expense for the year ended December 31, 2024 compared to 2023 was driven by a 48% increase in the DD&A rate per BOE, partially offset by a 28% decrease in production levels. The increase in the DD&A rate per BOE was driven by the increase in the oil and gas properties balance due to the development of the Seven Rivers waterflood interval and the decrease in the reserves balance due to the conveyance of the 10% overriding royalty interest to Royalty.
Current wording
Depletion, depreciation and amortization (“DD&A”) was $6,710,092 as of December 31, 2025, compared to $2,407,098 as of December 31, 2024. DD&A was $25.03 per BOE for the year ended December 31, 2025, compared to $8.27 per BOE for the year ended December 31, 2024. The aggregate increase in DD&A expense for the year ended December 31, 2025 compared to 2024 was driven by a 203% increase in the DD&A rate per BOE, partially offset by a 8% decrease in production levels. The increase in the DD&A rate per BOE was driven by the increase in the oil and gas properties balance due to the development of the Seven Rivers waterflood interval and the decrease in the reserves balance due to the net conveyance of the additional 5% overriding royalty interest to Virtus, along with a change in reserve classification from proved to probable.
Previous wording
Accretion expense was $144,988 as of December 31, 2024, compared to $859,102 on a combined Successor and Predecessor basis for the year ended December 31, 2023. Accretion expense was $0.50 per BOE for the year ended December 31, 2024, compared to $2.32 per BOE on a combined Successor and Predecessor basis for the year ended December 31, 2023. The aggregate decrease in accretion expense for the fiscal year ended December 31, 2024 compared to 2023 was driven by changes in certain assumptions, specifically the inflation factor and discount rate as a result of the acquisition date where we revised our estimates as part of its fair value estimates for the acquired business.
Current wording
The aggregate decrease in accretion expense for the year ended December 31, 2025, compared to the year ended December 31, 2024, was driven was driven by changes in certain assumptions.
Previous wording
Amortization of debt discount was $2,361,627 as of December 31, 2024 compared to $1,191,553 period from November 15, 2023 to December 31, 2023 (Successor), and attributable to deferred finance costs paid on the Senior Secured Term Loan, and discounts associated with the Private Notes Payable during 2023.
Current wording
During the year ended December 31, 2025, the Company recorded $1,475,191 related to the amortization of financing costs compared to $2,361,627 for the year ended December 31, 2024. These costs are attributable to deferred finance costs paid on the Senior Secured Term Loan, Merchant Cash Advances, convertible notes payable and discounts associated with the Private Notes Payable during 2023.
Previous wording
The change in fair value of forward purchase agreement consisted of a gain of $561,099 for the year ended December 31, 2024, for the Successor related to the inputs used in the Company’s fair value estimate of the FPA Put Option. The key inputs to the fair value estimate include the Company’s stock price, which declined during the Successor period, and the likelihood, timing and price of a potential dilutive offering.
Current wording
The change in fair value of forward purchase agreement consisted of a gain of $561,099 for the year ended December 31, 2024, related to the inputs used in our fair value estimate of the forward purchase agreement put option, primarily the decline in our stock price during the year ended December 31, 2024. The key inputs to the fair value estimate include our stock price, and the likelihood, timing and price of a potential dilutive offering. The forward purchase agreement put option was settled during the year ended December 31, 2024, and therefore no change in fair value was recorded in the year ended December 31, 2025.
Previous wording
The change in fair value of warrant liabilities consisted of a loss of $804,004 as of December 31, 2024, compared to a gain of $187,704 for the period from November 15, 2023 to December 31, 2023 for the Successor related to fluctuations in the trading price of the Company’s warrants, a portion of which are accounted for as liabilities due to the redemption provisions in those issued to Private Note holders. The Company also recognized a loss of $192,744 from the change in fair value of its convertible note liabilities during the year ended December 31, 2024.
Current wording
The change in fair value of warrant liabilities consisted of a loss of $152,490 as of December 31, 2025, compared to $804,004 as of December 31, 2024. The Company also recognized a loss of $131,677 from the change in fair value of its convertible note liabilities during the year ended December 31, 2025.
Previous wording
Our main sources of liquidity have been internally generated cash flows from operations, credit facility borrowings and equity line financing sales and issuances. Our primary use of capital has been for the development of oil and gas properties, payment to vendors, payment of debt obligations [and the return of initial invested capital to our founders]. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.
Current wording
Our main sources of liquidity have been internally generated cash flows from operations, credit facility borrowings and equity line financing sales and issuances. Our primary use of capital has been for the development of oil and gas properties, payment to vendors and payment of debt obligations. We continually monitor potential capital sources for opportunities to enhance liquidity or otherwise improve our financial position.
Previous wording
As of December 31, 2024, we had outstanding debt of $23,641,517 under our Senior Secured Term Loan, $15,000,000 under the Seller Promissory Note, $3,556,750 of outstanding private notes payable, and $948,982 from short term merchant loans. A total of $9,080,910 of this is due within one year. As of December 31, 2024, we had $2,971,558 of cash and cash equivalents on hand, of which approximately $2,600,000 is in an escrow account pursuant to the requirements of the Senior Secured Term Loan. At December 31, 2024 we had a working capital deficit of $31,213674. These conditions raise substantial doubt about our ability to continue as a going concern within one year after the date that the financial statements are issued.
Current wording
As of December 31, 2025, we had outstanding debt of $2,161,486 of convertible notes payable, $200,000 from related party notes payable and $1,517,337 from merchant cash advances. A total of $1,617,337 of this is due within one year. As of December 31, 2025, we had $375,036 of cash and cash equivalents on hand and had a working capital deficit of $21,814,454. These conditions raise substantial doubt about our ability to continue as a going concern within one year after the date that the financial statements are issued.
Previous wording
The Company had positive cash flow from operations of $3,700,686 for the year ended December 31, 2024. Additionally, management’s plans to alleviate this substantial doubt include improving profitability through streamlining costs, maintaining active hedge positions for its proven reserve production, and the issuance of additional shares of Class A common stock.
Current wording
The Company had negative cash flow from operations of $7,645,418 for the year ended December 31, 2025. Additionally, management’s plans to alleviate this substantial doubt include improving profitability through streamlining costs, maintaining active hedge positions for its proven reserve production, and the issuance of additional shares of Class A common stock.
Previous wording
We have a three-year equity line (ELOC) Common Stock Purchase Agreement with a maximum funding limit of $150,000,000 that can fund our operations and production growth, and be used to reduce liabilities. Through the date of this filing, we have received $6,992,906 in cash proceeds related to the sale of 7,000,000 shares of common stock under this agreement and expect to continue to utilize it to fund current operational needs. We cannot assure you, however, that any additional capital will be available to us on favorable terms or at all. Our capital expenditures could be curtailed if our cash flows decline from expected levels.
Current wording
We have a three-year equity line ELOC Purchase Agreement with a maximum funding limit of $150,000,000 that can fund our operations and production growth, and can be used to reduce liabilities. Through the date of this filing, we have received $11,130,586 in cash proceeds related to the sale of 17,000,000 shares of common stock under the ELOC Purchase Agreement and expect to continue to utilize it to fund current operational needs. We cannot assure you, however, that any additional capital will be available to us on favorable terms or at all. Our capital expenditures could be curtailed if our cash flows decline from expected levels.
Previous wording
As of December 31, 2024 and 202, the Company did not have any off-balance sheet arrangements, as defined in the rules and regulations of the Securities and Exchange Commission (SEC).
Current wording
As of December 31, 2025 and 2024, the Company did not have any off-balance sheet arrangements, as defined in the rules and regulations of the SEC.
Previous wording
We have contractual commitments under our Senior Secured Term Loan, the Seller Promissory Note and the Private Notes Payable which include periodic interest payments. See Note 5 to our interim condensed consolidated unaudited financial statements. We have contractual commitments that may require us to make payments upon future settlement of our commodity derivative contracts. See Note 4 to our interim condensed consolidated unaudited financial statements.
Current wording
We have contractual commitments under our Convertible Notes Payable which include periodic interest payments. See Note 5 to our consolidated financial statements. We have contractual commitments that may require us to make payments upon future settlement of our commodity derivative contracts. See Note 4 to our consolidated financial statements.
Previous wording
Our proved reserve information included in this filing as of December 31, 2024 and 2023, was prepared by independent petroleum engineers. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, proved reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify, positively or negatively, material revisions to the estimate of proved reserves.
Current wording
Our proved reserve information included in this filing as of December 31, 2025 was prepared by independent petroleum engineers covering 94% of our reserves as of December 31, 2025, while the remaining 6% were developed by our internal reserve engineers. Our proved reserve information included in this filing as of December 31, 2024 was prepared by independent petroleum engineers covering 100% of our reserves. Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, proved reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify, positively or negatively, material revisions to the estimate of proved reserves.
Previous wording
The Company has determined that the FPA Put Option, including the Maturity Consideration, within the Forward Purchase Agreement is (i) a freestanding financial instrument and (ii) a liability (i.e., an in-substance written put option). This liability was recorded as a liability at fair value on the consolidated balance sheet as of the reporting date in accordance with ASC 480. The fair value of the liability was estimated using a Monte-Carlo Simulation in a risk-neutral framework. Specifically, the future stock price is simulated assuming a Geometric Brownian Motion (“GBM”). For each simulated path, the forward purchase value is calculated based on the contractual terms and then discounted back to present. Finally, the value of the forward is calculated as the average present value over all simulated paths. The model also considered the likelihood of a dilutive offering of common stock.
Current wording
We have determined that the Put Option Right is a derivative liability required to be bifurcated from its host instrument. This liability was recorded as a liability at fair value on the consolidated balance sheet as of the reporting date in accordance with ASC 815. The fair value of the liability was estimated using a Monte-Carlo Simulation in a risk-neutral framework. Specifically, the future stock price is simulated assuming a Geometric Brownian Motion (“GBM”). For each simulated path, the forward purchase value is calculated based on the estimated term to exercise and then discounted back to present. Finally, the value of the Put Option Right is calculated as the average present value over all simulated paths.
Rearranged current paragraphs (2)
Current report — wording carried from elsewhere
For the year ended December 31, 2025, our average realized oil price per barrel after reflecting settled derivatives was $66.82 compared to $73.61 for the year ended December 31, 2024.
Current report — wording carried from elsewhere
We have also determined that conversion options within our convertible notes should be classified as derivative liabilities under ASC 815 and are required to be accounted for at fair value. The fair value of the liability was estimated using a Monte-Carlo Simulation in a risk-neutral framework. Specifically, the future stock price is simulated assuming a Geometric Brownian Motion (“GBM”). For each simulated path, the forward purchase value is calculated based on the estimated term to exercise and then discounted back to present. We estimate inputs for the fair value approach, including time to maturity, expected volatility, risk free rate and a continuous discount rate. The value of the embedded conversion options are calculated as the average present value over all simulated paths.
Rearranged previous paragraphs (1)
Previous report — wording carried elsewhere
We enter into commodity derivatives instruments to manage the price risk attributable to future oil production.