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

We are dependent upon a small number of significant customers for the majority of our production sales. The loss of those customers, if not replaced, could reduce our revenues and have a material adverse effect on our financial condition and results of operations.

We had two customers that each accounted for 10% or more of total reported revenues for the year ended December 31, 2025. The loss of these customers or any significant customer, should we be unable to replace them, could adversely affect our revenues and have a material adverse effect on our financial condition and results of operations. Also, if any significant customer reduces the volume it purchases from us, we could experience a temporary interruption in sales of, or may receive a lower price for, our production, or we could be required to shut in all or a portion of our production, any of which could cause our revenues and cash flows to decline and have a material adverse effect on our results of operations. For instance, in October 2024, Phillips 66 announced its plan to cease operations at its Los Angeles area refinery in the fourth quarter of 2025. Given that this refinery had historically made up all of our Beta sales, we had to seek out new customers in the area to replace the volume previously purchased by Phillips 66. Further, these risks may be greater in the future following the completion of several divestiture transactions in 2025, including the sale of our non-operated Eagle Ford assets in July 2025, our East Texas/North Louisiana assets in December 2025, and our Oklahoma assets in December 2025, as sales to these significant customers may constitute an even greater percentage of our total reported revenues in future periods. We cannot assure you that any of our customers will continue to do business with us or that we will continue to have access to suitably liquid markets for our future production. See “Item 1. Business — Operations — Marketing and Major Customers.”

Our properties are concentrated in a limited number of geographic locations and adverse developments, including potential difficulties in the marketing of oil, in such operating areas could adversely affect our business, financial condition, results of operations and cash flows.

As of December 31, 2025, following the completion of our divestitures, our properties are currently located in the Rockies and federal waters offshore Southern California. As a result, our business, financial condition, results of operations and cash flows may be disproportionately affected by adverse developments in these geographic areas, including regional events such as severe weather conditions, natural disasters, regulatory changes, infrastructure changes or local economic downturns. Additionally, increased competition, changes in the availability of services, equipment or the ability to attract and retain field personnel in these concentrated regions, could result in higher costs or operational delays. Any disruption, limitation or curtailment of operations in these areas, whether due to physical, regulatory or market-driven factors, or any potential difficulties in the marketing of our oil from such properties, could materially and adversely affect our overall performance.

The inability of our significant customers, vendors or other counterparties to meet their obligations to us may adversely affect our financial results.

We are subject to credit risk due to the concentration of our oil and natural gas receivables. The inability or failure of our significant customers, or any purchasers of our production, to meet their payment obligations to us or their insolvency or liquidation could have a material adverse effect on our results of operations. To the extent that purchasers of our production rely on access to the credit or equity markets to fund their operations, there could be an increased risk that those purchasers could default in their contractual obligations to us. If for any reason we were to determine that it was probable that some or all of the accounts receivable from any one or more of the purchasers of our production were uncollectible, we would recognize a charge to earnings of that period for the probable loss and could suffer a material reduction in our liquidity and cash flows.

Further, we are exposed to risks of loss in the event of nonperformance by our vendors and other counterparties. Some of our vendors and other counterparties may be highly leveraged and subject to their own operating and regulatory risks. Many of our vendors and other counterparties finance their activities through cash flow from operations, the incurrence of debt or the issuance of equity. The combination of reduction of cash flow resulting from declines in commodity prices and the lack of availability of debt or equity financing may result in a significant reduction in our vendors’ and other counterparties’ liquidity and ability to make payments or perform on their obligations to us. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with other parties. Any increase in the nonpayment or nonperformance by our vendors and/or counterparties could adversely affect our business, financial condition, results of operations and cash flows.

We are subject to, and in the future may be subject to additional complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

Our oil and natural gas development and production operations are also subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, worker health and safety aspects of our operations, or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations, including the acquisition of a permit before conducting regulated drilling activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands, seismically active areas and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly compliance measures or corrective actions. Further, the Incident (as defined below) or any similar future incidents may result in more stringent permitting obligations and regulation of our properties and other oil and gas activities, including at Beta and elsewhere, particularly relating to environmental, health and safety protection controls, oversight of oil and gas operations and required financial assurance. Regulatory or legislative action may impact the industry as a whole and could be directed specifically towards operators similarly situated to us, which could negatively impact our business. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, the issuance of orders limiting or prohibiting some or all of our operations. We may also experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and revenue. In addition, the long-term trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment. Thus, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations.

Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly owned or operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Moreover, public interest in the protection of the environment has increased in recent years. New laws and regulations continue to be enacted, particularly at the state level, resulting in increased costs of doing business and consequently affecting profitability. To the extent laws are enacted, or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.

Certain carbon dioxide purchase agreements are priced based on our counterparty’s ability to claim federal income tax credits which depend, in part, on our compliance with the requirements of such tax credits. If we are unable to comply with those requirements, or if Congress enacts new legislation, we will face increased payment obligations for carbon dioxide, which will negatively impact our economics.

Internal Revenue Code Section 45Q, and its accompanying Treasury Regulations provide, as relevant to our operations, a federal income tax credit for capturing of carbon oxides (“CO2”) from industrial processes that are used for enhanced oil recovery (the “Section 45Q Credit”). We purchase CO2 from counterparties that are eligible for the Section 45Q Credit provided we use the CO2 for enhanced oil recovery (“EOR”) in compliance with the Section 45Q Credit rules. We have negotiated certain CO2 purchase agreements to allow us to share in the value of the Section 45Q Credit in the form of reduced CO2 pricing.

The availability of the Section 45Q Credit, and associated reductions in our CO2 payments, require ongoing compliance by both us and our supplier with an evolving legal and regulatory regime. If Congress revises the Section 45Q Credit, including with retroactive effect, we, or our CO2 supplier may be unable to realize the Section 45Q Credit benefits. Even if Congress does not revise the Section 45Q Credit, it is possible that we are unable to comply with the existing or modified regulatory regimes. In both instances, we will incur higher CO2 costs, which will negatively impact our economics.

Additionally, if we are unable to utilize CO2 for EOR purposes consistent with the Section 45Q Credit requirements, or the CO2 that we purchase leaks from our EOR wells, we will have an indemnity obligation to our CO2 supplier, which will eliminate the savings to which we would otherwise be entitled.

While we have negotiated our CO2 purchase contracts consistent with the Section 45Q Credit requirements and are undertaking our EOR activities in a manner that we believe enables our CO2 supplier to be eligible for the Section 45Q Credit (and corresponding reduced CO2 pricing), there can be no assurances that the IRS will agree with our positions. Any successful challenge by the IRS would reduce or eliminate the Section 45Q Credit and associated cost savings from our reduced CO2 pricing.

The failure to replace our proved oil reserves could adversely affect our business, financial condition, results of operations, production and cash flows.

Producing oil reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil reserves and production and therefore, our cash flows, are highly dependent on our success in efficiently developing and exploiting our current reserves. Our production decline rates may be significantly higher than currently estimated if our wells do not produce as expected. Further, our decline rate may change when we drill additional wells or make acquisitions. We may not be able to develop, find or acquire additional reserves to replace our current and future production at economically acceptable terms, which would materially and adversely affect our business, financial condition and results of operations.

If we reduce our capital spending in an effort to conserve cash, this would likely result in production being lower than anticipated, and could result in reduced revenues, cash flows from operations and income. Further, if our revenues decrease, as a result of lower oil prices or for any other reason, we may not be able to obtain the capital necessary to sustain our operations.

Our business depends in part on pipelines, gathering systems and processing facilities owned by us or others. Any limitation in the availability of those facilities could interfere with our ability to market our oil production.

The marketability of our oil production depends in part on the availability, proximity and capacity of pipelines and other transportation methods, gathering systems and processing facilities owned by third parties. The amount of oil that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage or lack of contracted capacity on such systems. For example, our ability to produce and sell oil from the Beta properties will depend on the availability of the pipeline infrastructure between platforms as well as the San Pedro Bay Pipeline for delivery of that oil to shore, and any unavailability of that pipeline infrastructure or pipeline could cause us to shut in all or a portion of the production from the Beta properties for the length of such unavailability. Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided with only limited, if any, notice as to when these circumstances will arise and their duration. Any significant curtailment in gathering systems or transportation or processing facility capacity could reduce our ability to market our oil production and harm our business, financial condition, results of operations and cash flows.

Our offshore operations are subject to a variety of operating risks specific to the marine environment, such as a dependence on a limited number of electrical transmission lines, as well as capsizing, collisions and damage or loss from adverse weather conditions. Offshore activities are subject to more extensive governmental regulation than our other oil and natural gas activities. We are vulnerable to the risks associated with operating in the Pacific Outer Continental Shelf, including risks relating to:

We intend to maintain a portfolio of commodity derivative contracts covering at least 25%- 75%, depending on availability under the Revolving Credit Facility, of our estimated production from proved developed producing reserves over a one-year period at any given point in time. These commodity derivative contracts include natural gas, oil and NGL financial swaps, put options, costless collars, and three-way collars. The prices and quantities at which we enter into commodity derivative contracts covering our production in the future will be dependent upon oil and natural gas prices and price expectations, at the time we enter into these transactions, which may be substantially higher or lower than current or future oil and natural gas prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil, natural gas and NGL prices received for our future production. Many of the derivative contracts to which we will be a party will require us to make cash payments to the extent the applicable index exceeds a predetermined price, thereby limiting our ability to realize the benefit of increases in oil and NGL prices. If our actual production and sales for any period are less than our hedged production and sales for that period (including reductions in production due to operational delays) or if we are unable to perform our drilling activities as planned, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flow from our sale of the underlying physical commodity, which may materially impact our liquidity.

Under our Revolving Credit Facility, we are required to (i) maintain, as of the date of determination, a maximum total debt to EBITDAX ratio of 3.00 to 1.00, commencing with the fiscal quarter ending March 31, 2026, (ii) maintain a current ratio of not less than 1.00 to 1.00, and (iii) hedge at least 25%−75%, depending on availability under the Revolving Credit Facility, of our estimated production from total proved developed producing reserves. If we were to violate any of the covenants under our Revolving Credit Facility and were unable to obtain a waiver or amendment, it would be considered a default after the expiration of any applicable grace period. If we were in default under our Revolving Credit Facility, then the lenders may exercise certain remedies including, among others, declaring all borrowings outstanding thereunder, if any, immediately due and payable. This could adversely affect our operations and our ability to satisfy our obligations as they come due, because we might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our Revolving Credit Facility are secured by mortgages on not less than 90% of the PV-9 value of our oil and gas properties together with all or substantially all material midstream assets necessary to operate our proved, developed and producing oil and gas properties, and if we are unable to repay our indebtedness under our Revolving Credit Facility, the lenders could seek to foreclose on our assets.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase.

Our Revolving Credit Facility allows us to borrow in an amount up to the borrowing base, which is primarily based on the estimated value of our oil properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. The borrowing base is subject to redetermination on at least a semi-annual basis primarily based on an engineering report with respect to our estimated oil and NGL reserves, which takes into account the prevailing natural gas, oil and NGL prices at such time, as adjusted for the impact of our commodity derivative contracts. Accordingly, declining commodity prices may have an impact on the amount we can borrow, which could affect our cash flows and ability to execute our business plans. Any further reduction in the borrowing base may affect our business and financing activities, limit our flexibility and management’s discretion in operating our business, and increase the risk that we may default on our debt obligations. In addition, as hedges roll off, the borrowing base is subject to further reduction. Our Revolving Credit Facility requires us to repay any deficiency over a certain period or pledge additional oil and gas properties to eliminate such deficiency within 30 days of notice. If our outstanding borrowings exceed the borrowing base and we are unable to repay the deficiency or pledge additional oil and gas properties to eliminate such deficiency, our failure to repay any of the installments due related to the borrowing base deficiency would constitute an event of default under the Revolving Credit Facility and as such, the lenders could declare all outstanding principal and interest to be due and payable, could freeze our accounts, or foreclose against the assets securing the obligations owed under our Revolving Credit Facility.

Our assets have historically consisted primarily of producing oil and natural gas properties located in Oklahoma, the Rockies (“Bairoil”), federal waters offshore Southern California (“Beta”), East Texas/North Louisiana, and the Eagle Ford (Non-op). During 2025, we completed several divestiture transactions, including the sale of our non-operated Eagle Ford assets in July 2025, our East Texas/North Louisiana assets in December 2025 and our Oklahoma assets in December 2025. As of the date of this Annual Report, our remaining properties consist solely of Bairoil and Beta.

Reduction in Force

During the fourth quarter of 2025 and throughout the first quarter of 2026, certain employees were impacted by a workforce reduction resulting in the involuntary termination of 36 employees across the Company. The Company recorded $6.8 million of severance expense for the year ended December 31, 2025, which is included in “general and administrative expense” in the Company’s Consolidated Statement of Operations.

Amended Revolving Credit Facility

On December 31, 2025, OLLC entered into the Borrowing Base Redetermination, Commitment Increase and Second Amendment to Amended and Restated Credit Agreement (the “Second Amendment”), among OLLC, Amplify Acquisitionco LLC, the guarantors party thereto, the lenders party thereto and Citizens Bank, N.A., as administrative agent for the lenders. The Second Amendment amends the Amended and Restated Credit Agreement, dated July 31, 2023 (as amended, the “Credit Agreement”), to, among other things: (i) set the Borrowing Base to $25.0 million, with elected commitments of $15.0 million and (ii) extend the maturity date under the Credit Agreement to December 31, 2028. We had no amounts outstanding at December 31, 2025.

Revolution Purchase and Sale Agreement

On November 4, 2025, Amplify Oklahoma Operating LLC, a Delaware limited liability company and indirect, wholly owned subsidiary of the Company (“Amplify Oklahoma”), Magnify Energy Services LLC, a Delaware limited liability company and indirect, wholly owned subsidiary of the Company (“Magnify” and, together with Amplify Oklahoma, the “Revolution Sellers”) and OLLC, for certain limited purposes, entered into a purchase and sale agreement (the “Revolution Purchase and Sale Agreement”) with Revolution Resources III, LLC, a Delaware limited liability company (“Revolution”), pursuant to which the Revolution Sellers sold to Revolution certain assets of the Revolution Sellers, which include, among other things, the Revolution Sellers’ right, title and interest in and to certain specified oil and gas properties and equipment within or related to certain designated lands in Oklahoma (the “Revolution Asset Sale”) for a cash purchase price of $92.5 million, subject to estimated post-closing adjustments under the Revolution Purchase and Sale Agreement. The Revolution Asset Sale closed on December 29, 2025, with an effective date of October 1, 2025. We received net proceeds of $88.7 million from the Revolution Asset Sale. The proceeds from the divestiture were used to reduce borrowings under our Revolving Credit Facility. In connection with this transaction, we performed an assessment of the fair value of the net book value and determined that the assets were impaired, and as such, we recorded impairment expense of $34.0 million to write down those assets to the estimated purchase price less cost to sell.

EQV Purchase and Sale Agreement

On October 28, 2025, OLLC and Magnify (together with OLLC, the “EQV Sellers”), entered into a purchase and sale agreement (as subsequently amended, the “EQV Purchase and Sale Agreement”) with EQV Alpha LLC, a Delaware limited liability company (“Alpha”), pursuant to which the EQV Sellers sold to Alpha certain assets of the EQV Sellers, which include, among other things, the EQV Sellers’ right, title and interest in and to certain specified oil and gas properties and equipment within or related to certain designated lands in East Texas and Louisiana (the “EQV Asset Sale”) for a cash purchase price of $122.0 million, subject to estimated post-closing adjustments under the EQV Purchase and Sale Agreement. The EQV Asset Sale closed on December 23, 2025, with an effective date of October 1, 2025. We received net proceeds of $111.6 million from the EQV Asset Sale. The proceeds from the divestiture were used to reduce borrowings under our Revolving Credit Facility.

On October 2, 2025, the Company entered into a purchase and sale agreement to sell its remaining interest in certain units with rights in the Cotton Valley and Haynesville basins in Harrison County, Texas, generating $5.3 million in net proceeds from the transactions. The sale closed on October 24, 2025, with an effective date of October 1, 2025.

Other 2025 Developments

Other 2025 Divestitures

In July 2025, we closed a transaction to divest our non-operated Eagle Ford assets for a total purchase price of $23.0 million, excluding $1.9 million of final post-closing adjustments, resulting in a final adjusted purchase price of $21.1 million. In connection with this transaction, we performed an assessment of the fair value of the net book value and determined that the assets were impaired, and as such, we recorded impairment expense of $8.4 million to write down those assets to the estimated purchase price less cost to sell.

Throughout 2025, we had other divestitures where we sold certain rights and interests in the Cotton Valley and Haynesville basins generating approximately $7.8 million in net proceeds from such transactions.

Leadership Changes

On July 21, 2025, the Company, and Mr. Martyn Willsher, the Company’s former President, Chief Executive Officer and member of the Company’s board of directors (the “Board”), agreed that (i) Mr. Willsher’s roles as President and Chief Executive Officer of the Company and a member of the Board terminated effective July 22, 2025 (the “Transition Date”), and (ii) Mr. Willsher assumed the non-executive employee role of Special Advisor to the Company on the Transition Date.

In connection with the transition of Mr. Willsher’s role, the Company and Mr. Willsher entered into a Transition and Separation Agreement (the “Transition Agreement”), effective as of the Transition Date. Pursuant to the terms of the Transition Agreement, Mr. Willsher served as Special Advisor to the Company until December 31, 2025.

Appointment of Chief Executive Officer and Director

On July 21, 2025, the Board appointed Mr. Daniel Furbee, previously the Company’s Senior Vice President and Chief Operating Officer, to Chief Executive Officer and as a member of the Board, effective as of the Transition Date. In connection with Mr. Furbee’s appointment as Chief Executive Officer, Mr. Furbee and the Company entered into a performance-based restricted stock units award agreement.

Appointment of President and Chief Financial Officer

On July 21, 2025, the Board appointed Mr. James Frew, previously the Company’s Senior Vice President and Chief Financial Officer, to President and Chief Financial Officer, effective as of the Transition Date.

Appointment of Vice President and Chief Accounting Officer

On November 14, 2025, Mr. Eric Dulany and the Company mutually agreed Mr. Dulany’s tenure as Vice President and Chief Accounting Officer would end, effective immediately. Mr. Dulany’s departure did not result from any disagreement with the Company, the Company’s management or the Board. On November 14, 2025, the Board appointed Ms. Natasha France, to serve as Vice President and Chief Accounting Officer of the Company, effective immediately.

On April 25, 2025, pursuant to Section 8.1(a) of the Merger Agreement, the Company and the Acquired Companies entered into a mutual termination agreement (the “Termination Agreement”) to terminate the Merger Agreement (the “Termination”), effective immediately. As a result of the Termination Agreement, the Merger Agreement is of no further force and effect.

Factors Affecting the Comparability of the Historical Financial Results

As a result of the factors listed above, the historical results of operations and period-to-period comparisons of these results and certain financial data may not be comparable or indicative of future results.

For the year ended December 31, 2025 compared to the year ended December 31, 2024

Net income of $44.0 million compared to net income of $12.9 million was recorded for the year ended December 31, 2025 and 2024, respectively.

Share Repurchase Program

On August 6, 2026, the Company's board of directors approved a share repurchase program authorizing the repurchase of up to $15.0 million of Common Stock. Using recent prices, a fully executed program would represent approximately 10% of the Company's outstanding shares. Under the share repurchase program, repurchases may begin after market open on August 11, 2026 and continue through and including December 31, 2026.

Repurchases under the share repurchase program may be made from time to time through open market repurchases or through privately negotiated transactions subject to market conditions, applicable legal requirements, and other relevant factors. Open market repurchases may be structured to occur in accordance with the requirements of Rule 10b-18 under the Exchange Act. The Company may also, from time to time, enter into Rule 10b5-1 plans to facilitate repurchases of shares of its Common Stock under this authorization. The Company is not obligated under the share repurchase program to acquire any particular amount of Common Stock, and the Company may terminate or suspend the share repurchase program at any time. The timing and actual number of shares repurchased may depend on a variety of factors, including price, general business and market conditions, and alternative investment opportunities.

On April 30, 2026, the Bureau of Safety and Environmental Enforcement (“BSEE”) informed the Company that it had been approved for End-of-Life Royalty Relief for the Company’s interests in three Pacific Outer Continental Shelf blocks (P-300, P-0301, and P-0306), referred to as the Beta unit in the Beta Field located in federal waters approximately 11 miles offshore from the Port of Long Beach, California. The royalty relief is effective beginning May 1, 2026 for the Beta leases. On the Company’s two primary producing leases, the royalty rate was reduced from approximately 25% to 12.5%, and on the third lease, the royalty rate was reduced from 16.67% to 8.33%.

Royalty relief rates will be suspended in months in which the rolling 12-month weighted average NYMEX oil and Henry Hub gas price exceeds $79.65 per BOE, which represents a 25% premium to the average realized price recognized by the Company during the qualification period. Royalty relief will end in the event that the rolling 12-month weighted average commodity price exceed $79.65 per BOE, or if monthly production doubles the qualifying months’ average for 12 consecutive months.

General and administrative expenses were $7.0 million and $11.2 million for the three months ended June 30, 2026 and 2025, respectively. The change in general and administrative expenses was primarily related to (i) a decrease of $2.2 million in acquisition and divestiture costs; (ii) a decrease of $1.4 million for salaries and other payroll benefits, (iii) a decrease of $0.7 million in stock compensation expense, and (iv) a decrease of $0.4 million in legal expense, partially offset by (i) an increase of $0.5 million in bad debt expense and (ii) an increase of $0.7 million due to the elimination of COPAS overhead charges.

Net loss (gain) on commodity derivative instruments of ($9.0) million was recognized for the three months ended June 30, 2026, consisting of a $22.6 million increase in the fair value of open positions partially offset by $13.6 million of cash settlements paid on expired positions. Net gain on commodity derivative instruments of $22.2 million was recognized for the three months ended June 30, 2025, consisting of a $17.4 million increase in the fair value of open positions and $4.8 million of cash settlements received on expired positions.

Deferred income tax benefit (expense) was ($5.9) million and ($1.4) million for the three months ended June 30, 2026 and 2025, respectively. See additional information discussed in Note 17 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report.

For the Six Months Ended June 30, 2026 Compared to the Six Months Ended June 30, 2025

We reported a net loss of $20.8 million compared to net income of $0.5 million for the six months ended June 30, 2026 and 2025, respectively.

Oil, natural gas and NGL revenues were $89.8 million and $137.1 million for the six months ended June 30, 2026 and 2025, respectively. Average net production volumes were approximately 6.6 MBoe/d and 18.5 MBoe/d for the six months ended June 30, 2026 and 2025, respectively. The average realized sales prices were $75.03 per Boe and $40.96 per Boe for the six months ended June 30, 2026 and 2025, respectively. The decrease of $47.3 million in oil, natural gas and NGL revenue was primarily driven by the divestiture of our East Texas, Oklahoma and non-operated Eagle Ford assets in 2025. Oil revenues for our Beta and Bairoil assets were $89.9 million and $77.8 million for the six months ended June 30, 2026 and 2025, respectively. The change in oil revenue at Beta and Bairoil was primarily due to higher realized oil commodity prices, partially offset by lower volumes.

Other revenues were $0.3 million and $3.3 million for the six months ended June 30, 2026 and 2025, respectively. The decrease of $3.0 million in other revenue was primarily driven by the divestiture of our East Texas, Oklahoma and non-operated Eagle Ford assets in 2025. For the six months ended June 30, 2026, other revenues primarily consisted of pipeline transportation income. For the six months ended June 30, 2025, other revenues primarily consisted of service revenues of $2.0 million for Magnify and iodine sales of $1.2 million.

Lease operating expenses were $44.8 million and $76.0 million for the six months ended June 30, 2026 and 2025, respectively. The decrease of $31.2 million in lease operating expenses was primarily driven by the divestiture of our East Texas, Oklahoma and non-operated Eagle Ford assets in 2025. Lease operating expenses for Beta and Bairoil were $44.6 million and $54.5 million for the six months ended June 30, 2026 and 2025, respectively. At Beta, the decrease in lease operating expenses was due to lower base lease operating costs, partially offset by higher workovers. At Bairoil, the decrease in lease operating expenses was primarily driven by lower CO2 and electricity costs.

Gathering, processing and transportation expenses were $1.4 million and $9.0 million for the six months ended June 30, 2026 and 2025, respectively. The decrease of $7.6 million in gathering, processing and transportation expenses was primarily driven by the divestiture of our East Texas, Oklahoma and non-operated Eagle Ford assets in 2025. Gathering, processing and transportation expenses for Beta were $1.4 million and $1.5 million for the six months ended June 30, 2026 and 2025, respectively.

Taxes other than income were $5.4 million and $8.7 million for the six months ended June 30, 2026 and 2025, respectively. The decrease of $3.3 million in taxes other than income was primarily driven by the divestiture of our East Texas, Oklahoma and non-operated Eagle Ford assets in 2025. Taxes other than income at Beta and Bairoil were $5.4 million and $5.5 million for the six months ended June 30, 2026 and 2025, respectively.

DD&A expenses were $10.6 million and $18.3 million for the six months ended June 30, 2026 and 2025, respectively. The decrease of $7.7 million in DD&A expense was primarily driven by the divestiture of our East Texas, Oklahoma and non-operated Eagle Ford assets in 2025. DD&A expenses for Beta and Bairoil were $10.6 million and $8.4 million for the six months ended June 30, 2026 and 2025, respectively.

Impairment expense. No impairment expense was recorded for the six months ended June 30, 2026. The Company recorded impairment expense of $8.4 million for the six months ended June 30, 2025. The Company recognized an impairment expense to reduce the net book value of our non-operated Eagle Ford assets to fair value less costs to sell. See Note 4 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report for additional information.

General and administrative expenses were $15.9 million and $22.0 million for the six months ended June 30, 2026 and 2025, respectively. The change in general and administrative expenses was primarily related to (i) a decrease of $3.8 million in acquisition and divestiture costs, (ii) a decrease of $1.9 million for salaries and other payroll benefits, (iii) a decrease of $0.6 million in stock compensation expense, (iv) a decrease of $0.5 million in legal expense partially offset by (i) an increase of $0.3 million in severance expense, (ii) an increase of $1.3 million due to the elimination of COPAS overhead charges and (iii) an increase of $0.5 million in bad debt expense.

Net loss (gain) on commodity derivative instruments of $36.8 million was recognized for the six months ended June 30, 2026, consisting of a $20.8 million decrease in the fair value of open positions and $16.2 million of cash settlements paid on expired positions partially offset by $0.2 million of cash settlement received on terminated derivative instruments. A net gain on commodity derivative instruments of $7.8 million was recognized for the six months ended June 30, 2025, consisting of a $2.6 million increase in the fair value of open positions and $5.3 million of cash settlements received on expired positions.

Gain on sale of properties was $1.7 million and $7.8 million for the six months ended June 30, 2026 and 2025, respectively. The gain in 2025 primarily related to the sale of certain units with rights in the Haynesville basin in Harrison County, Texas. See Note 4 of the Notes to Unaudited Condensed Consolidated Financial Statements under “Item 1. Financial Statements” of this quarterly report for additional information.

Interest expense, net was $1.9 million and $7.1 million for the six months ended June 30, 2026 and 2025, respectively. The change was primarily related to the Company paying off all outstanding debt as of December 31, 2025. In 2026, the Company will continue to have interest expense associated with its surety bonds.

Current income tax benefit (expense). The Company had no current income tax benefit (expense) for the six months ended June 30, 2026 compared to ($0.5) million for the six months ended June 30, 2025. See additional information discussed in Note 17 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report.

Deferred income tax benefit (expense) was $5.7 million and $0.1 million for the six months ended June 30, 2026 and 2025, respectively. See additional information discussed in Note 17 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Financial Statements” of this quarterly report.

During 2026, the Company generated investing cash flows from the final post-closing adjustments related to its divested assets: $3.2 million of proceeds related to the East Texas divestiture and $0.5 million payment for the final post-closing adjustment for Oklahoma.