Amplify Energy Corp.

References

Amplify Energy Corp. (“Amplify Energy,” “Amplify,” the “Company,” “we,” “us,” “our,” or similar terms), is a publicly traded Delaware corporation, in which our common stock, par value of $0.01 per share (“Common Stock”), is listed on the NYSE under the symbol “AMPY.”

Amplify Energy is an independent oil and natural gas company engaged in the acquisition, development, exploitation and production of oil and natural gas properties. Our management evaluates performance based on one reportable business segment, as the economic environments are not different within the operation of our oil and natural gas properties. Our business activities are conducted through OLLC, our wholly owned subsidiary, and its wholly owned subsidiaries.

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, as discussed below, 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 a result of these divestitures, the oil and natural gas reserves presented herein reflect only properties owned as of December 31, 2025. As of the date of this Annual Report, our remaining properties consist solely of Bairoil and Beta.

As of the date of this Annual Report, the Company’s properties consist of operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells. As of December 31, 2025:

Recent Developments

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.

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.

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.

Termination of Contemplated Merger with Juniper Capital

On January 14, 2025, the Company entered into an Agreement and Plan of Merger, as subsequently amended (the “Merger Agreement”) with Amplify DJ Operating LLC, a Delaware limited liability company and indirect wholly owned subsidiary of the Company (“First Merger Sub”), Amplify PRB Operating LLC, a Delaware limited liability company and indirect wholly owned subsidiary of Amplify Energy (“Second Merger Sub”), North Peak Oil & Gas, LLC, a Delaware limited liability company (“NPOG”), Century Oil and Gas Sub-Holdings, LLC, a Delaware limited liability company (“COG” and, together with NPOG, the “Acquired Companies”), and, solely for the limited purposes set forth in the Merger Agreement, Juniper Capital Advisors, L.P. (“Juniper Capital”) and the Specified Company Entities set forth on Annex A thereto, pursuant to which, at the effective time of the Contemplated Mergers (as defined below), it was contemplated that (i) NPOG would merge with and into First Merger Sub, with NPOG surviving the merger as an indirect, wholly owned subsidiary of the Company and (ii) COG would merge with and into Second Merger Sub, with COG surviving the merger as an indirect, wholly owned subsidiary of the Company, in each case, subject to the terms and conditions of the Merger Agreement (clauses (i) and (ii), together, the “Contemplated Mergers”).

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.

Industry Trends

We continue to monitor the impact of the actions of the Organization of the Petroleum Exporting Countries and other large producing nations; the Russia-Ukraine conflict; conflicts or entanglements in the Middle East and South America; global inventories of oil and natural gas and the uncertainty associated with recovering oil demand; inflation and future monetary policy; and governmental policies aimed at transitioning towards lower carbon energy. The Russia-Ukraine conflict and conflicts or entanglements in the Middle East and South America continue to evolve, and the extent to which these events may impact our business, results of operations, financial condition and cash flows will depend on future developments, which are highly uncertain and cannot be predicted with confidence.

Properties

As discussed above, our assets have historically consisted primarily of producing oil and natural gas properties in Oklahoma, Bairoil, 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 a result of these divestitures, the oil and natural gas reserves presented herein reflect only properties owned as of December 31, 2025. As of the date of this Annual Report, our remaining properties consist solely of Bairoil and Beta.

We engaged Cawley, Gillespie and Associates, Inc. (“CG&A”), our independent reserve engineers, to prepare our reserves estimates for all of our proved reserves at December 31, 2025. Accordingly, the proved oil and natural gas reserves presented herein reflect only those reserves attributable to properties owned as of December 31, 2025 and exclude reserves associated with properties divested during 2025. The following table summarizes information, based on a reserve report prepared by CG&A (which we refer to as our “reserve report”), about our proved oil reserves by geographic region as of December 31, 2025, and our average net production for the three months ended December 31, 2025:

Our Areas of Operation

Beta

Approximately 64% of our estimated proved reserves as of December 31, 2025 and approximately 56% of our average daily net production for the three months ended December 31, 2025 were associated with the Beta field located in federal waters approximately 11 miles offshore from the Port of Long Beach, California. Our ownership in Beta consists of 100% of the working interests and 75.2% average net revenue interest in three Pacific Outer Continental Shelf lease blocks (P-0300, P-0301 and P-0306) (referred to as the “Beta Unit”) in the Beta field. The Beta properties contained 24.3 MMBbls of estimated net proved oil reserves as of December 31, 2025 based on our reserve report and generated average net production of 3.7 MBoe/d for the three months ended December 31, 2025. Oil and gas are produced from the Beta Unit via two production platforms, referred to as the Ellen and Eureka platforms, equipped with permanent drilling rigs and associated equipment. On a third platform, Elly, the oil, water and gas are separated, and the oil is prepared for sale, while the gas is utilized as fuel for power and the water is recycled back into the reservoir for pressure maintenance. Sales quality oil is then pumped from the Elly platform to the Beta pump station located onshore at the Port of Long Beach, California via a 16-inch diameter oil pipeline, which extends approximately 17.5 miles. Amplify Energy’s wholly owned subsidiary, San Pedro Bay Pipeline Company, owns and operates the pipeline system.

The following table summarizes production volumes from the Beta field for the period presented:

Bairoil

Approximately 36% of our estimated proved reserves as of December 31, 2025 and approximately 44% of our average daily net production for the three months ended December 31, 2025 were located in Bairoil. Our Bairoil properties include wells and properties primarily located in the Lost Soldier and Wertz fields in Wyoming at our Bairoil complex. Our Bairoil properties contained 13.7 MMBbls of estimated net proved oil and NGLs reserves as of December 31, 2025 based on our reserve report and generated average net production of 2.9 MBoe/d for the three months ended December 31, 2025.

The following table summarizes production volumes from Bairoil for the period presented:

Our Oil and Natural Gas Data

Our Reserves

*Internal Controls.*Our proved reserves were estimated at the well or unit level for reporting purposes by CG&A, our independent reserve engineers. We maintain internal evaluations of our reserves in a secure reserve engineering database. CG&A interacts with our internal petroleum engineers and geoscience professionals in each of our operating areas and with operating, accounting, and marketing employees to obtain the necessary data to prepare our proved reserves report. Reserves are reviewed and approved internally by our senior management on an annual basis and evaluated by our lender group on at least a semi-annual basis in connection with borrowing base redeterminations under our Revolving Credit Facility. Our reserve estimates are prepared by CG&A at least annually.

Our internal professional staff works closely with CG&A to ensure the integrity, accuracy and timeliness of data that is furnished to them in order to prepare the reserves report. All of the reserve information maintained in our secure reserve engineering database is provided to the external engineers. In addition, we provide CG&A with other pertinent data, such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria. We make all requested information, as well as our pertinent personnel, available to the external engineers as part of their preparation of our reserves.

Qualifications of Responsible Technical Persons

Internal Engineers. For the period covered by this Annual Report, Tony Lopez served as the technical person at the Company, primarily responsible for overseeing and providing oversight of the preparation of the reserves estimates with our third-party reserve engineers.

Mr. Lopez has over 20 years of corporate reserve reporting experience. Mr. Lopez joined the Company as Vice President of Corporate Reserves in June 2018 and for the period covered by this Annual Report has served as the Company’s Senior Vice President of Engineering & Exploitation. Prior to June 2018, Mr. Lopez was Vice President of Acquisitions and Engineering for EnerVest, Ltd., where he managed the corporate reserve reporting process and the financial planning & analysis department. Mr. Lopez is a graduate of West Virginia University and holds a B.S. in Petroleum and Natural Gas Engineering. Mr. Lopez is an active member of the Society of Petroleum Engineers.

*Cawley, Gillespie and Associates Inc.*CG&A is an independent oil and natural gas consulting firm. No director, officer, or key employee of CG&A has any financial ownership in us or any of our affiliates. CG&A’s compensation for the preparation of its report is not contingent upon the results obtained and reported. CG&A has not performed other work for us or any of our affiliates that would affect its objectivity. The estimates of our proved reserves presented in the CG&A reserve report were overseen by Todd Brooker.

Mr. Brooker became the President of CG&A in 2017 and has been an employee of CG&A since 1992. His responsibilities include reserve and economic evaluations, fair market valuations, field studies, pipeline resource studies and acquisition/divestiture analysis. His reserve reports are routinely used for public company SEC disclosures. Prior to joining CG&A, Mr. Brooker worked in Gulf of Mexico drilling and production engineering at Chevron Corporation. Mr. Brooker’s experience includes significant projects in both conventional and unconventional resources in every major U.S. producing basin and abroad, including oil and gas shale plays, coalbed methane fields, waterfloods and complex, faulted structures.

Mr. Brooker graduated with honors from the University of Texas at Austin in 1989 with a Bachelor of Science degree in Petroleum Engineering and is a registered Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.

Estimated Proved Reserves

The following table summarizes our estimated proved oil and natural gas reserves and related standardized measure of discounted future net cash flows attributable to our properties as of December 31, 2025, which are based on the prepared reserve report by CG&A, our independent reserve engineers. The oil and natural gas reserves and related standardized measure disclosures presented herein are based on properties owned as of December 31, 2025 and are prepared in accordance with SEC regulations.

The data in the table above represents estimates only. Oil and natural gas reserve engineering is inherently a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil and natural gas that are ultimately recovered.

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The 10% discount factor used to calculate standardized measure, which is required by the SEC and FASB, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate. For these reasons, neither standardized measure nor PV-10 should be construed as the fair value of our oil and natural gas reserves.

For a discussion of risks associated with internal reserve estimates, see “Item 1A. Risk Factors — Risks Related to Our Business — Our estimated reserves and future production rates are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our estimated reserves.”

Development of Proved Undeveloped Reserves

As of December 31, 2025, we had 13,475 MBoe of PUDs, comprised of 13,475 MBbls of oil. None of our PUDs as of December 31, 2025 are scheduled to be developed on a date more than five years from the date the reserves were initially booked as PUDs. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

For the year ended December 31, 2025, total PUDs increased by 2,719 MBoe. The increase includes 2,294.7 MBoe due to the addition of 4 Beta PUD locations. We also had transfers of (3,263.5) MBoe to proved developed reserves which included 4 Beta PUD, 4 East Texas PUD and 15 Eagle Ford PUDs. We sold the remaining Eagle Ford PUD locations of (451) MBoe. Other revisions consisted of 4,139.2 MBoe that were primarily related to updated Beta PUD performance and extended economic life.

Approximately 30.3% (3,263.5 MBoe) of our PUDs recorded as of December 31, 2024, were developed during the twelve months ended December 31, 2025. Total costs incurred to develop these PUDs were approximately $49.9 million. In total, we incurred total capital expenditures of approximately $36.1 million during fiscal year 2025 developing PUDs. Based on our current expectations of our cash flows, we believe that we can fund the drilling of our current PUD inventory and our expansions in the next five years from our cash flow from operations, cash on hand and borrowings under our Revolving Credit Facility. For a more detailed discussion of our liquidity position, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.”

Production, Revenue and Price History

For a description of our production, revenues, and average sales prices and per unit costs, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations.”

The following tables summarize our average net production, average unhedged sales prices by product and average lease operating expense per Boe by geographic region for the years ended December 31, 2025 and 2024, respectively:

Productive Wells

Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we own an interest and net wells are the sum of our fractional working interests owned in gross wells. The following table sets forth information relating to the productive wells in which we owned a working interest as of December 31, 2025.

Developed Acreage

Acreage related to royalty, overriding royalty and other similar interests is excluded from this summary. As of December 31, 2025, all of our leasehold acreage was held by production. The following table sets forth information as of December 31, 2025 relating to our leasehold acreage.

Undeveloped Acreage

As of December 31, 2025, we had no gross and net undeveloped acreage expiring over the next two years as all of our gross and net acreage is currently held by production.

Drilling Activities

Our drilling activities primarily consist of development wells. The following table sets forth information with respect to (i) wells drilled and completed during the periods indicated and (ii) wells drilled in a prior period but completed during the periods indicated. The information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value. At December 31, 2025, we had 0 gross (0 net) wells that were being developed.

Delivery Commitments

We have no commitments to deliver a fixed and determinable quantity of our oil production in the near future under our existing sales contracts.

Operations

General

As of December 31, 2025, the Company is the operator of record of properties containing 100% of our total estimated proved reserves. We design and manage the development, recompletion and/or workover operations, and supervise other operation and maintenance activities for all of the wells we operate. We do not own the drilling rigs used for drilling wells on our onshore properties; independent contractors provide all the equipment and personnel associated with these activities. Our Beta platforms have permanent drilling systems in place.

Marketing and Major Customers

The following individual customers each accounted for 10% or more of our total reported revenues for the period indicated:

The production sales agreements covering our properties contain customary terms and conditions for the oil and natural gas industry and provide for sales based on prevailing market prices. A majority of those agreements have terms that renew on a month-to-month basis until either party gives advance written notice of termination.

If we were to lose any one of our customers, the loss could temporarily delay production and sale of a portion of our oil and natural gas in the related producing region. If we were to lose any single customer, we believe we could identify a substitute customer to purchase the impacted production volumes. However, if one or more of our larger customers ceased purchasing oil or natural gas altogether and we were unable to replace them, the loss of any such customer could have a detrimental effect on our production volumes and revenues in general.

On October 1, 2025, our agreement with Phillips 66 terminated following Phillips 66’s closure of its Los Angeles‑area refinery. Historically, prior to the termination of this agreement, this refinery represented a significant portion of our sales to Phillips 66. Following the termination of this agreement, we have entered into agreements with other customers for the sale of our Beta crude oil.

Title to Properties

We believe that we have satisfactory title to all of our producing properties in accordance with industry standards. More thorough title investigations are customarily made before the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. Individual properties may be subject to burdens that we believe do not materially interfere with the use or affect the value of the properties. As is customary in the industry, in the case of undeveloped properties, often cursory investigation of record title is made at the time of lease acquisition. Burdens on properties may include customary royalty interests, liens incident to operating agreements and for current taxes, obligations or duties under applicable laws, development obligations under natural gas leases, or net profits interests.

Derivative Activities

We enter into commodity derivative contracts with unaffiliated third parties, generally lenders under our Revolving Credit Facility or their affiliates, to achieve more predictable cash flows and to reduce our exposure to fluctuations in oil and natural gas prices. We intend to enter into commodity derivative contracts at times and on terms desired 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 total proved developed producing reserves over a one-year period at any given point of time. We may, however, from time to time, hedge more or less than this approximate amount.

Periodically, we enter into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates (such as those in our Revolving Credit Facility) to fixed interest rates.

It is our policy to enter into derivative contracts only with creditworthy counterparties, which generally are financial institutions, deemed by management as competent and competitive market makers. Some of the lenders, or certain of their affiliates, under our Revolving Credit Facility are counterparties to our derivative contracts. We will continue to evaluate the benefit of employing derivatives in the future.

Competition

We operate in a highly competitive environment for acquiring properties, leasing acreage, contracting for drilling equipment and securing trained personnel. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. As a result, our competitors may be able to pay more for productive oil and natural gas properties and exploratory prospects, as well as evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional properties and to find and develop reserves will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry and many of our competitors have access to capital at a lower cost than that available to us.

Hydraulic Fracturing

As discussed above, 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. Prior to such divestitures, hydraulic fracturing was used as a means to maximize the productivity of almost every well that we drilled and completed, except in our offshore wells. Hydraulic fracturing had been a necessary part of the completion process because our properties had historically been dependent upon our ability to effectively fracture the producing formations in order to produce at economic rates. As of December 31, 2025, none of the remaining proved reserves required hydraulic fracturing.

We believe we have followed and continue to substantially follow, where required and consistent with the standards previously reported, applicable industry standard practices and legal and regulatory requirements for groundwater protection in our previous hydraulic fracturing operations, which are subject to supervision by state and federal regulators (including the U.S. Bureau of Land Management (the “BLM”) on federal acreage).

For information regarding existing and proposed governmental regulations regarding hydraulic fracturing and related environmental matters, see “— Environmental, Occupational Health and Safety Matters and Regulations — Hydraulic Fracturing.”

Insurance

In accordance with customary industry practice, we maintain insurance against many, but not all, potential losses or liabilities arising from our operations and at costs that we believe to be economic. We regularly review our risks of loss and the cost and availability of insurance and revise our insurance accordingly. Our insurance does not cover every potential risk associated with our operations, including the potential loss of significant revenues. We can provide no assurance that our coverage will adequately protect us against liability from all potential consequences, damages and losses. We currently have insurance policies that include the following:

We continuously monitor regulatory changes and comments and consider their impact on the insurance market, along with and our overall risk profile. As necessary, we will adjust our risk and insurance program to provide protection at a level we consider appropriate while weighing the cost of insurance against the potential and magnitude of disruption to our operations and cash flows. Changes in laws and regulations could lead to changes in underwriting standards, limitations on scope and amount of coverage, and higher premiums, including possible increases in liability caps for claims of damages from oil spills.

Environmental, Occupational Health and Safety Matters and Regulations

General

Our oil and natural gas development and production operations are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, occupational health and safety aspects of our operations, or otherwise relating to protection of the environment and natural resources. These laws and regulations impose numerous obligations applicable to our operations, including the acquisition of certain permits 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 U.S. Environmental Protection Agency (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 or corrective actions. 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, in certain jurisdictions, the long-term trend in environmental regulation has been to place more restrictions and limitations on activities that may affect the environment and 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 our own actions that were in compliance with all applicable laws at the time such 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, and the long-term trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, which may result in increased costs of doing business and consequently affect profitability. To the extent new or more stringent 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.

The following is a summary of the more significant existing environmental, occupational health and safety laws and regulations to which our business operations are subject and for which compliance may have a material adverse impact on our operations, capital expenditures, earnings or competitive position.

Offshore Operations

Our oil and gas operations associated with our Beta properties are conducted on offshore leases in federal waters, and those operations are regulated by agencies such as BOEM and BSEE, which have broad authority to regulate our oil and gas operations associated with our Beta properties.

BOEM is responsible for managing environmentally and economically responsible development of the nation’s offshore resources. Its functions include offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans, renewable energy development, and National Environmental Policy Act (“NEPA”) analysis and environmental review. Lessees must obtain BOEM approval for exploration, development and production plans prior to the commencement of offshore operations. BOEM generally requires that lessees have substantial net worth, post supplemental bonds or provide other acceptable assurances that the obligations will be met. In October 2020, BOEM and BSEE issued a proposed rule to clarify, streamline, and provide greater transparency to financial assurance requirements for the oil and gas industry, including streamlining the evaluation criteria for determining if and when additional security is required for Outer Continental Shelf (“OCS”) leases, pipeline rights-of-way and rights-of-use and easement (“RUE”) and revising the process for issuing decommissioning obligations for facilities on the OCS. Pursuant to prior Executive Order 13990, BOEM decided not to move forward with the BOEM-administered portions, and instead issued a new notice of proposed rulemaking to address the financial policy concerns. BSEE finalized the BSEE-related provisions, which became effective on May 18, 2023, to focus on clarifying decommissioning obligations of RUE grant holders and promulgate BSEE policy regarding the obligations of predecessors that must decommission their units. In April 2024, BOEM published a final rule, effective June 2024, which modified criteria for determining whether oil, gas, and sulfur lessees, RUE grant holders, and pipeline right-of-way grant holders are required to provide bonds or other financial assurance above what is currently required to ensure compliance with OCS obligations. The final rule also codified the use of the BSEE’s probabilistic estimates of decommissioning costs in setting the levels of demand for supplemental financial assurance, removed restrictive provisions for third-party guarantees and decommissioning accounts, and added new criteria for cancelling supplemental financial assurance. Litigation was filed challenging the BOEM 2024 rule, creating uncertainty regarding the finality of the BOEM 2024 rule requirements. On May 2, 2025, the U.S. Department of the Interior announced its intent to revise the BOEM 2024 rule and proceed with development of a new rule consistent with the 2020 proposed framework. In December 2025, the Western District Court of Louisiana issued a further stay of the litigation, pending BOEM’s issuance of a new rule.

BSEE is responsible for safety and environmental oversight of offshore oil and gas operations. Its functions include the development and enforcement of safety and environmental regulations, permitting offshore exploration, development and production, inspections, offshore regulatory programs, oil spill response and training and environmental compliance programs. BSEE regulations require offshore production facilities and pipelines located on the OCS to meet stringent engineering and construction specifications, and in August 2023 and August 2024 BSEE announced two final rules which added safety-related regulations concerning the design and operating procedures of these facilities and pipelines, including regulations to safeguard against or respond to well blowouts and other catastrophes and manage equipment used in high pressure high temperature environments. In August 2025, BSEE issued a final rule to align with the One Big Beautiful Bill Act, which clarified expectations for offshore commingling, production methods for well integrity, safety and ultimate recovery. BSEE regulations also restrict the flaring or venting of natural gas, prohibit the flaring of liquid hydrocarbons and govern the plugging and abandonment of wells located offshore and the installation and removal of all fixed drilling and production facilities.

BOEM and BSEE have adopted regulations providing for enforcement actions, including civil penalties and lease forfeiture or cancellation for failure to comply with regulatory requirements for offshore operations. If we fail to pay royalties or comply with safety and environmental regulations, BOEM and BSEE may require that our operations on the Beta properties be suspended or terminated, and we may be subject to civil or criminal liability, which may have a negative impact on our operations, capital expenditures, earnings or competitive position.

In addition to permits and approvals required by BOEM and BSEE, approvals and permits may be required from other agencies for the oil and gas operations associated with our Beta properties, such as the U.S. Coast Guard, the EPA, U.S. Department of Transportation, U. S. Army Corps of Engineers and the South Coast Air Quality Management District.

Hazardous Substances and Waste Handling

Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances, solid and hazardous wastes and petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict and, in some cases, joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also referred to as the Superfund law and comparable state laws, impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons deemed “responsible parties.” These persons include current owners or operators of the site where a release of hazardous substances occurred, prior owners or operators that owned or operated the site at the time of the release or disposal of hazardous substances and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to strict and joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. Despite the “petroleum exclusion” of Section 101(14) of CERCLA, which currently encompasses natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. Also, comparable state statutes may not contain a similar exemption for petroleum, and it is also not uncommon for neighboring landowners and other third parties to file common law-based claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In addition, we may have liability for releases of hazardous substances at our properties by prior owners or operators or other third parties.

The Oil Pollution Act of 1990 (“OPA”) is the primary federal law imposing oil spill liability. The OPA contains numerous requirements relating to the prevention of, and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. Under the OPA, strict, joint and several liability may be imposed on “responsible parties” for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters and natural resource damages resulting from oil spills into or upon navigable waters, adjoining shorelines or in the exclusive economic zone of the United States. A “responsible party” includes the owner or operator of an onshore facility. The OPA establishes a liability limit for onshore facilities, but these liability limits may not apply if: a spill is caused by a party’s gross negligence or willful misconduct; the spill resulted from violation of a federal safety, construction or operating regulation; or a party fails to report a spill or to cooperate fully in a cleanup. We are also subject to analogous state statutes that impose liabilities with respect to oil spills. For example, the California Department of Fish and Wildlife’s Office of Oil Spill Prevention and Response has adopted oil-spill prevention regulations that overlap with federal regulations.

We also generate solid wastes, including hazardous wastes, which are subject to the requirements of the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes. Although RCRA regulates both solid and hazardous wastes, it imposes stringent requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA’s hazardous waste regulations. These wastes, instead, are regulated under RCRA’s less stringent solid waste provisions, state laws or other federal laws. It is possible that these wastes, which could include wastes currently generated during our operations, could be designated as “hazardous wastes” in the future and, therefore, be subject to more rigorous and costly disposal requirements. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and gas exploration and production wastes as “hazardous wastes.” Any such changes, including to state programs, could result in an increase in our costs to manage and dispose of oil and gas waste, which could have a material adverse effect on our maintenance capital expenditures and operating expenses.

It is possible that our oil and natural gas operations may require us to manage naturally occurring radioactive materials (“NORM”). NORM are present in varying concentrations in sub-surface formations, including hydrocarbon reservoirs, and may become concentrated in scale, film and sludge in equipment that comes into contact with crude oil and natural gas production and processing streams. Some states have enacted regulations governing the handling, treatment, storage and disposal of NORM.

Administrative, civil and criminal penalties can be imposed for failure to comply with hazardous substance and waste handling requirements. We believe that we are in substantial compliance with the requirements of CERCLA, OPA, RCRA, and other applicable federal and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations required under such laws and regulations. Although we believe that the current costs of managing our hazardous substances and wastes as they are presently classified are reflected in our budget, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Water Discharges

The Federal Water Pollution Control Act (the “Clean Water Act”), the Safe Drinking Water Act (“SDWA”), the OPA and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including oil and hazardous substances, into navigable waters of the United States, as well as state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. These laws and regulations also prohibit certain activity in wetlands unless authorized by a permit issued by the U.S. Army Corps of Engineers (“Corps”). In June 2015, the EPA and the Corps issued a rule to revise the definition of “waters of the United States” (“WOTUS”) for all Clean Water Act programs, which never took effect before being replaced by the Navigable Waters Protection Rule (the “NWPR”) in April 2020. The NWPR was vacated by two separate federal district courts in late 2021. The definition of WOTUS was further impacted by the U.S. Supreme Court’s decision issued in May 2023 in Sackett v. EPA wherein the Court held that the jurisdiction of the Clean Water Act extends only to those adjacent wetlands that are indistinguishable from traditional navigable bodies of water due to a continuous surface connection and rejected the “significant nexus” test embraced in earlier jurisprudence. In September 2023, the EPA and the Corps published a direct-to-final rule redefining WOTUS to align with the decision in Sackett. The final rule eliminated the “significant nexus” test from consideration when determining federal jurisdiction and clarified that the Clean Water Act only extends to relatively permanent bodies of water and wetlands that have a continuous surface connection with such bodies of water. However, roughly half of the states and other plaintiffs are continuing to challenge the rule, and the EPA and the Corps are using the pre-2015 definition of WOTUS in these states while litigation continues. In November 2025, the Corps and the EPA issued a proposed rule revising the definition of WOTUS with the stated aim of conforming to the Supreme Court’s decision in Sackett and revising certain regulatory terms, such as “relatively permanent,” “tributary,” and “continuous surface connection”; a final rule is expected in early 2026, and litigation is highly likely following issuance of the final rule. As a result, substantial uncertainty exists with respect to future implementation of the September 2023 rule and the scope of CWA jurisdiction more generally.

The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of storm water or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits or specify other requirements for discharges or operations that may impact groundwater conditions. These same regulatory programs may also limit the total volume of water that can be discharged, hence limiting the rate of development and requiring us to incur compliance costs. Additionally, we are required to develop and implement spill prevention, control and countermeasure plans, in connection with on-site storage of significant quantities of oil.

These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. Additionally, obtaining permits has the potential to delay the development of oil projects. We maintain all required discharge permits necessary to conduct our operations and we believe we are in substantial compliance with their terms.

Hydraulic Fracturing

As discussed above, during 2025, we completed several divestiture transactions, including the sale of our non-operated Eagle Ford assets in July 2025, our East Texas/North Louisianna assets in December 2025 and our Oklahoma assets in December 2025. Prior to such divestitures, hydraulic fracturing had been used as a means to maximize the productivity of almost every well that we drilled and completed, except in our offshore wells. Hydraulic fracturing was historically a necessary part of the completion process because certain of our properties were historically dependent upon our ability to effectively fracture the producing formations in order to produce at economic rates. As of the date of this Annual Report, we are no longer engaged in any current hydraulic fracturing operations.

During the period in which we historically utilized hydraulic fracturing in our operations, we believe we followed, where required and consistent with then-existing standards previously reported, applicable industry standard practices and legal and regulatory requirements for groundwater protection in our previous hydraulic fracturing operations, which are subject to supervision by state and federal regulators (including the BLM on federal acreage).

Air Emissions

The federal Clean Air Act, as amended (“CAA”), and comparable state laws restrict the emission of air pollutants from many sources, including compressor stations, through the issuance of permits and the imposition of other requirements. The South Coast Air Quality Management District (“SCAQMD”) is a regulatory subdivision of the State of California and is responsible for air pollution control from stationary sources within Orange County and designated portions of Los Angeles, Riverside, and San Bernardino Counties. Our Beta properties and associated facilities are subject to regulation by the SCAQMD. Federal, SCAQMD, and other state laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants.

The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and modified and existing facilities may be required to obtain additional permits.

In November 2021, the EPA issued a proposed rule intended to establish standards for methane and volatile organic compounds, or VOCs, from new and modified oil and natural gas production and natural gas processing and transmission facilities. The proposed rule sought to make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that have never been regulated under the CAA (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities). In addition, the proposed rule sought to establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by EPA. In November 2022, the EPA issued a proposed rule supplementing the November 2021 proposed rule. Among other things, the November 2022 supplemental proposed rule removed an emissions monitoring exemption for small wellhead-only sites and created a new third-party monitoring program to flag large emissions events, referred to in the proposed rule as “super emitters”. The EPA announced a final rule in December 2023, later published in March 2024, which, among other things, requires the phase out of routine flaring of natural gas from new oil wells and routine leak monitoring at all well sites and compressor stations. Notably, the EPA updated the applicability date for Subparts OOOOb and OOOOc to December 6, 2022, meaning that sources constructed prior to that date will be considered existing sources with later compliance dates under state plans. The final rule gives states, along with federal tribes that wish to regulate existing sources, two years to develop and submit their plans for reducing methane from existing sources. However, in March 2025, the EPA announced its intention to reconsider the March 2024 rule, including Subparts OOOOb and OOOOc, with a final rule expected in or around July 2026. A subsequent rule finalized on November 26, 2025, gives states, along with federal tribes that wish to regulate existing sources, until January 2027 to develop and submit their plans for reducing methane emissions from existing sources. In December 2025, environmental groups filed a petition for review in the D.C. Circuit Court of Appeals challenging the EPA’s delay of the methane emissions rules.

Additionally, in 2016, the BLM finalized rules related to further controlling the venting and flaring of natural gas on BLM land, which was challenged by a group of states. In September 2018, the BLM published a final rule that revised the 2016 rules, which was again challenged by states and environmental groups. In April 2024, and later revised in November 2024, the BLM issued a final rule to reduce the waste of natural gas from venting, flaring, and leaks during oil and gas production activities on Federal and Indian leases. In January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development or use of domestic energy resources. Legal challenges to the 2024 rule from various states has been held in abeyance throughout 2025, as BLM considers rule revisions. Through a direct final rule published in December 2025, the BLM has extended compliance deadlines for key components of the 2024 rule. Consequently, future implementation and enforcement of the final 2024 EPA rule and the final 2024 BLM rule remain uncertain at this time.

We may be required to incur certain capital expenditures in the next few years for air pollution control equipment in connection with maintaining or obtaining operating permits addressing air emission related issues, which may have a material adverse effect on our operations. Obtaining permits also has the potential to delay the development of oil projects and increase our costs of development, which costs could be significant. We believe that we currently are in substantial compliance with all air emissions regulations and that we hold all necessary and valid construction and operating permits for our current operations.

Climate Change Regulation

At the international level, the United States joined the international community at the United Nations Framework Convention on Climate Change 21st Conference of the Parties (“COP21”) in Paris, France in 2015, which resulted in an agreement intended to nationally determine their contributions and set greenhouse gas (“GHG”) emission reduction goals every five years beginning in 2020. However, in January 2025, President Trump issued an executive order directing the immediate notice to the United Nations of the United States’ withdrawal from the Paris Agreement. The withdrawal became effective in January 2026. In January 2026, President Trump announced the United States will also withdraw from the UN Framework Convention on Climate Change. However, various state and local governments have publicly committed to furthering the goals of the Paris Agreement, and related initiatives are expected to continue. It is not possible at this time to predict how legislation or regulations that may be adopted to address climate change, methane and other GHG emissions may impact our business.

In August 2022, the prior Biden Administration signed into law the Inflation Reduction Act. The Inflation Reduction Act included a methane emissions reduction program that amended the CAA to include a Methane Emissions and Waste Reduction Incentive Program for petroleum and natural gas systems. This program required the EPA to impose a Waste Emissions Charge (“WEC”) on certain oil and gas sources that are already required to report under EPA’s Greenhouse Gas Reporting Program. To implement the program, in May 2024, the EPA finalized revisions to the Greenhouse Gas Reporting Program for petroleum and natural gas facilities. The emissions reported under the Greenhouse Gas Reporting Program were set as the basis for any payments under the Methane Emissions Reduction Program. However, petitions for reconsideration to the EPA are pending and litigation in the D.C. Circuit has commenced. In addition, EPA proposed on September 12, 2025 to eliminate or suspend Greenhouse Gas Reporting Program requirements for most industries, with final rules implementing the proposed rollback expected by mid-2026. In November 2024, the EPA finalized a regulation to implement the Inflation Reduction Act’s WEC. However, in January 2025, the Trump Administration issued an Executive Order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. In addition, in March 2025, President Trump signed Congress’ Joint Resolution of Disapproval of the WEC, and in May 2025, EPA issued a final rule to remove the WEC regulations from the Code of Federal Regulations. In July 2025, the One Big Beautiful Bill Act delayed the effective date of the WEC until 2034.

The 2007 case Massachusetts v. EPA held that GHGs are air pollutants covered by the Clean Air Act, and that EPA must determine whether certain GHG emissions may reasonably be anticipated to endanger public health or welfare. In December 2009, EPA issued a final rule stating that current and projected concentrations of carbon dioxide, methane and other GHGs endanger public health and welfare (“2009 Endangerment Finding”). The 2009 Endangerment Finding served as legal support for subsequent EPA Clean Air Act rulemakings that have significantly affected industry operational costs, including New Source Performance Standards and Existing Source Guidelines rules requiring technology investments to detect and reduce methane leaks and emissions from new and existing oil and gas infrastructure. In the 2022 Supreme Court case West Virginia v. EPA, the Court held that EPA lacked clear statutory authority under the Clean Air Act, absent specific and explicit authorization from Congress, to implement an EPA rulemaking that mandated a shift for electricity production from higher greenhouse gas emissions sources to lower emissions sources. In the 2024 Supreme Court case Loper Bright Enters. v. Raimondo, the Court held that courts must independently determine the best reading of a statute, rather than deferring to agency interpretations of ambiguous statutory language. On February 12, 2026, EPA issued a pre-publication copy of a final rule, submitted for publication in the Federal Register, rescinding the 2009 Endangerment Finding on the basis that the 2009 Endangerment Finding exceeded EPA authority, was not supported by specific and explicit authorization from Congress, and did not meet the best reading of the underlying Clean Air Act provision under the West Virginia and Loper Bright holdings. Litigation following the February 2026 final rule publication is expected, and the potential impact of the February 2026 final rule, potential subsequent revisions to existing emission standards, and the outcome of related litigation, including private nuisance litigation, remain uncertain and could affect our operations.

At the state level, California enacted legislation in October 2023 that will ultimately require certain companies that do business in California and exceed specified financial thresholds to publicly disclose certain climate-related information, including their Scopes 1, 2, and 3 GHG emissions, with third party assurance of such data, climate-related financial risks and related mitigation measures. The California Air Resources Board has proposed that initial reporting for scope 1 and 2 GHG emissions for fiscal year 2025 be due by August 10, 2026, with Scope 3 GHG emissions reporting required in 2027. These laws are subject to ongoing legal challenges and certain requirements are currently enjoined. It is unclear how the litigation process and additional legal developments will impact enforceability of these requirements and the timeline and cost of compliance. While we are still assessing the impact of these requirements, additional reporting obligations could cause us to incur increased costs.

While we are subject to certain federal GHG monitoring and reporting requirements, our operations are not currently adversely impacted by existing federal, state and local climate change initiatives. The adoption and implementation of any new regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we produce.

Moreover, any legislation or regulatory programs to reduce GHG emissions could increase the cost of consumption, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Incentives to conserve energy or use alternative energy sources as a means of addressing climate change could also reduce demand for the oil and natural gas we produce. However, the Supreme Court’s decision in Loper Bright Enterprises v. Raimondo to overrule Chevron U.S.A. Inc. v. Natural Resources Defense Council, Inc. ends the concept of general deference to regulatory agency interpretations of laws introduces new complexity for federal agencies and administration of climate change policy and regulatory programs, and in January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions that are unduly burdensome on the identification, development, or use of domestic energy resources. Consequently, future implementation and enforcement of federal climate change rules remain uncertain at this time.

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands are subject to NEPA. NEPA requires federal agencies, including the U.S. Departments of the Interior and Agriculture, to evaluate major federal actions having the potential to significantly impact the human environment. In the course of such evaluations, an agency evaluates the potential direct, indirect and cumulative impacts of a proposed project. If the proposed impacts are considered significant, the agency will prepare a detailed environmental impact statement that is made available for public review and comment. In July 2020, the White House’s Council on Environmental Quality (“CEQ”) published a final rule to amend the NEPA implementing regulations intended to streamline the environmental review process, including shortening the time for review as well as eliminating the requirement to evaluate cumulative impacts. The final rule required federal agencies to develop procedures consistent with the new rule within one year of the rule’s effective date (which was extended to two years in June 2021). In October 2021, the CEQ issued a notice of proposed rulemaking to amend the NEPA regulatory changes adopted in 2020 in two phases. Phase I of the CEQ’s proposed rulemaking process was finalized in April 2022, and generally restored provisions that were in effect prior to 2020. In May 2024, the CEQ finalized the Phase II rule that accelerates NEPA reviews while maintaining consideration of relevant environmental, environmental justice and climate change objectives. Further, the Infrastructure and Investment Jobs Act signed into law in November 2021 codified some of the July 2020 amendments in statutory text. These amendments must be implemented into each agency’s implementing regulations, and each of those individual rulemakings could be subject to legal challenge. Additionally, in June 2023, the Fiscal Responsibility Act of 2023 was signed into law, which includes important changes to NEPA to streamline the environmental review process. However, in January 2025, President Trump issued an executive order requiring CEQ to provide guidance on implementing NEPA and to propose rescinding CEQ’s NEPA regulations. The executive order also instructs federal agencies to adhere to only the relevant legislated requirements for environmental reviews and to prioritize efficiency and certainty over any other objectives in such reviews. In February 2025, CEQ sent an interim final rule to the White House Office of Management and Budget that would immediately withdraw the NEPA implementing regulations. In January 2026, CEQ formally repealed its NEPA implementing regulations. However, the repeal has left the July 2020, Phase I, and Phase II rules in place. This action may be subject to litigation. Congress is also considering legislation designed to streamline NEPA through the Standardizing Permitting and Expediting Economic Development Act (“SPEED Act”). The SPEED Act aims to redefine what qualifies as a “major Federal action” and impose stricter deadlines for NEPA review. Although the SPEED Act has passed the House of Representatives, final passage and implementation remains uncertain. The potential impact of further changes to the NEPA regulations and statutory text therefore remains uncertain and could have an effect on our operations.

Endangered Species Act and Migratory Bird Treaty Act

The federal ESA was established to protect endangered and threatened species and their habitat. If a species is listed as threatened or endangered pursuant to the ESA, restrictions may be imposed on activities adversely affecting that species or its habitat. The U.S. Fish and Wildlife Service (“FWS”) must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (“MBTA”), which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit. This prohibition covers most bird species in the U.S. In January 2021, the Department of the Interior finalized a rule limiting the application of the MBTA. However, the Department of the Interior revoked the rule in October 2021 and issued an advance notice of proposed rulemaking seeking comment on the Department’s plan to develop regulations that authorize incidental taking under certain prescribed conditions. The future of this rulemaking is uncertain. In April 2024, the U.S. FWS issued three final rules governing critical habitat designation and expanding protection options for species listed as threatened pursuant to the ESA. However, in April 2025, the U.S. Department of Interior issued a memo, M-37085, to repeal M-37065, which had previously declared that the MBTA prohibited both the intentional and incidental “take” of migratory birds. The memo restored M-37050, clarifying that only the intentional “take” of migratory birds is prohibited. Additionally, in April 2025, the FWS and National Marine Fisheries Service proposed to redefine “harm” to mean affirmative acts that are directed immediately and intentionally against a particular animal, excluding acts or omissions that indirectly cause injury. Additionally, in November 2025, the Trump Administration proposed several rules that would significantly alter ESA protections for plants and animals. One proposed rule would rescind a rule that automatically extends protections for endangered species to threatened species. Another proposed rule would change regulations for listing species as endangered or threatened as well as for designating critical habitats. Additionally, a third proposed rule would reinstate the framework for evaluating the benefits and cost of designating a critical habitat by considering factors like economic impact, impact on national security, and other relevant impacts. The FWS is expected to issue final rules in 2026. The designation of previously unidentified endangered or threatened species in areas where we operate could cause us to incur additional costs or become subject to operating delays, restrictions or bans. There is also increasing interest in nature-related matters beyond protected species, such as general biodiversity, which may similarly require us or our customers to incur costs or take other measures which may adversely impact our business or operations.

Occupational Safety and Health Act

We are also subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties. We believe that our operations are in substantial compliance with the OSHA requirements.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state and local authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden on our assets. Additionally, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the oil and natural gas industry with similar types, quantities and locations of production.

Legislation continues to be introduced in Congress, and the development of regulations continues in the U.S. Department of Homeland Security and other agencies concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations. Presently, it is not possible to accurately estimate the costs we could incur to comply with any such facility security laws or regulations, but such expenditures could be substantial.

Drilling and Production

Our operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states, and some counties and municipalities, in which we operate also regulate one or more of the following:

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction.

Sale and Transportation of Gas and Oil

The Federal Energy Regulatory Commission (“FERC”) has jurisdiction terms and conditions of service under which companies provide interstate transportation of gas, oil and other liquids by pipeline. The FERC does not regulate the sale of oil or petroleum products or the construction of oil or other liquids pipelines, but does regulate the rates and terms and conditions of service on oil and liquids pipelines.

The Beta properties include the San Pedro Bay Pipeline Company, which owns and operates an offshore crude oil pipeline. This pipeline is subject to regulation by the FERC under the Interstate Commerce Act and the Energy Policy Act of 1992. Tariff rates for liquids pipelines, which include both crude oil pipelines and refined products pipelines, must be just and reasonable and not unduly discriminatory. FERC regulations require that interstate oil pipeline transportation rates and terms of service be filed with the FERC and posted publicly. The FERC has established a formulaic methodology for oil and liquids pipelines to change their rates within prescribed ceiling levels that are tied to an inflation index. The FERC reviews the formula every five years. During the last review period, FERC set the index level in December 2020. Both pipelines and pipeline customers sought rehearing of the index level, and in January 2022, FERC issued a rehearing order setting a lower index price, effective July 1, 2021, of the producer price index for finished goods minus 0.21%. Pipelines challenged this decision and on July 26, 2024, the D.C. Circuit vacated the rehearing order. Subsequently, on September 17, 2024, FERC issued an order reinstating the index price of producer price index for finished goods plus 0.78%. Then, on October 17, 2024, FERC issued a supplemental notice of proposed rulemaking proposing to reduce the index price back to the producer price index for finished goods minus 0.21%; that proposed rule was withdrawn by FERC on November 20, 2025. On November 20, 2025, FERC issued a Notice of Proposed Rulemaking proposing to set the producer price index for finished goods at minus 1.42% as the index level for the five-year period commencing July 1, 2026. This proposed rule is now pending. The San Pedro Bay Pipeline Company uses the indexing methodology to change its rates.

Although the FERC does not have jurisdiction over the production of gas, the FERC exercises regulatory authority over wholesale sales of gas in interstate commerce through the issuance of blanket marketing certificates that authorize the wholesale sale of gas at market rates and the imposition of a code of conduct on blanket marketing certificate holders that regulate certain affiliate interactions. The FERC also has oversight of the performance of wholesale natural gas markets, including the authority to facilitate price transparency and to prevent market manipulation. In furtherance of this authority, the FERC imposed an annual reporting requirement on all industry participants, including otherwise non-jurisdictional entities, engaged in wholesale physical natural gas sales and purchases in excess of a minimum level. These agency actions have been intended to foster increased competition within all phases of the gas industry. To date, the FERC’s pro-competition policies have not materially affected our business or operations. Also, as discussed above, during 2025, we completed several divestiture transactions and as of the date of this Annual Report, and we are no longer engaged in the production and sale of natural gas.

The FERC and other federal agencies, the U.S. Congress or state legislative bodies and regulatory agencies may consider additional proposals or proceedings that might affect the gas or oil industries. We cannot predict when or if these proposals will become effective or any effect they may have on our operations. We do not believe, however, that any such proposal will affect us any differently than it would affect other gas or oil producers with which we compete.

The Outer Continental Shelf Lands Act requires that all pipelines operating on or across the OCS provide open access, non-discriminatory transportation service. BOEM/BSEE has established formal and informal complaint procedures for shippers that believe they have been denied open and non-discriminatory access to transportation on the OCS.

The U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (“PHMSA”) regulates the safety of all pipeline transportation in or affecting interstate or foreign commerce, including pipeline facilities on the OCS. The San Pedro Bay pipeline is subject to regulation by the PHMSA. PHMSA regularly updates its pipeline safety rules and recommendations. For example, on March 25, 2025, PHMSA published an advisory bulletin that stated PHMSA’s intent to encourage all regulated pipeline owners and operators to voluntarily adopt new safety management systems. PHMSA updates the maximum administrative civil penalties each year to account for inflation, and as of December 2025, the penalty limits are up to $272,926 per violation per day and up to $2,729,245 for a related series of violations. PHMSA has also issued a final rule applying safety regulations to certain rural low-stress hazardous liquid pipelines that were not covered previously by some of its safety regulations.

Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation.

Anti-Market Manipulation Laws and Regulations

The FERC, with respect to the purchase or sale of natural gas or the purchase or sale of transmission or transportation services subject to FERC jurisdiction, and the Federal Trade Commission (the “FTC”) with respect to petroleum and petroleum products, operating under various statutes, have each adopted anti-market manipulation regulations, which prohibit, among other things, fraud and price manipulation in the respective markets. These agencies hold substantial enforcement authority, including the ability to assess substantial civil penalties, to order repayment or disgorgement of profits and to recommend criminal penalties. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

Derivatives Regulation

Comprehensive financial reform legislation was signed into law by former President Obama on July 21, 2010 (the “Dodd-Frank Act”). This legislation called for the Commodities Futures Trading Commission (the “CFTC”) to regulate certain markets for derivative products, including over-the-counter derivatives. The CFTC has issued several new relevant regulations and rulemakings to implement the Dodd-Frank Act, the mandate to cause significant portions of derivatives markets to clear through clearinghouses, along with other mandated changes. While some of these rules have been finalized, some have not. As a result, the final form and timing of the implementation of the new regulatory regime affecting commodity derivatives remains uncertain.

In particular, on October 18, 2011, the CFTC adopted final rules under the Dodd-Frank Act establishing position limits for certain energy commodity futures and options contracts and economically equivalent swaps, futures and options. The CFTC’s final rules were challenged in court by two industry associations and were vacated and remanded by a federal district court. Subsequently, the CFTC proposed new rules in November 2013 and December 2016. In January 2020, the CFTC withdrew the 2013 and 2016 proposals. In January 2021 the CFTC issued a final rule on the matter, effective March 15, 2021. The final rule includes limits on positions in (1) certain “Core Referenced Futures Contracts,” including contracts for several energy commodities; (2) futures and options on futures that are directly or indirectly linked to the price of a Core Referenced Futures Contract, or to the same commodity for delivery at the same location as specified in that Core Referenced Futures Contract; and (3) economically equivalent swaps. The final rule also includes exemptions from position limits for bona fide hedging activities.

The Dodd-Frank Act and new, related regulations may prompt counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may become less predictable, which could adversely affect our ability to plan for and fund capital expenditures and to generate sufficient cash flow to pay quarterly distributions at current levels or at all. Our revenues could be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material, adverse effect on us, our financial condition and our results of operations. Our use of derivative financial instruments does not eliminate our exposure to fluctuations in commodity prices and interest rates and has in the past and could in the future result in financial losses or reduce our income.

Our sales of oil and natural gas are also subject to anti-manipulation and anti-disruptive practices authority under (i) the Commodity Exchange Act (the “CEA”), as amended by the Dodd-Frank Act, and regulations promulgated thereunder by the CFTC, and (ii) the Energy Independence and Security Act of 2007 (the “EISA”) and regulations promulgated thereunder by the FTC. The CEA, as amended by the Dodd-Frank Act, prohibits any person from using or employing any manipulative or deceptive device in connection with any swap, or a contract for sale of any commodity, or for future delivery on such commodity, in contravention of the CFTC’s rules and regulations. It also prohibits knowingly delivering or causing to be delivered false, misleading or inaccurate reports concerning market information or conditions that affect or tend to affect the price of any commodity. The FTC’s Petroleum Market Manipulation Rule, issued pursuant to EISA, prohibits fraudulent or deceptive conduct (including false or misleading statements of material fact) in connection with wholesale purchases or sales of crude oil or refined petroleum products. Under both the CEA and the EISA, fines for violations can be up to $1,000,000 per day per violation (subject to adjustment for inflation) and certain knowing or willful violations may also lead to a felony conviction.

Additional proposals and proceedings that may affect the crude oil and natural gas industry are pending before the U.S. Congress, federal agencies and the courts. The Company cannot predict the ultimate impact these proposals may have on its crude oil operations, but the Company does not expect any such action to affect the Company differently than it will affect other gas or oil producers with which we compete.

State Regulation

Various states regulate the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of natural gas resources. States may regulate rates of production and may establish maximum daily production allowable from natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but there can be no assurance that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.

Human Capital

On December 31, 2025, the Company had 184 employees, none of whom were represented by labor unions or covered by any collective bargaining agreement. We strive to create a high-performing culture and positive work environment that allows us to attract and retain a group of talented individuals who can foster the Company’s success. To attract and retain top talent, our human resources programs are designed to reward and incentivize our employees through competitive compensation practices, our commitment to employee health and safety, training and talent development and our commitment to inclusion.

Safety

Safety is our highest priority, and we are dedicated to the well-being of our employees, contractors, business partners, stakeholders and the environment. We promote safety with a robust health and safety program, which includes employee orientation and training, contractor management, risk assessment, hazard identification and mitigation, audits, incident reporting and investigation, and corrective and preventative action development.

In addition, we employ environmental, health and safety personnel at each of our asset locations, who provide in-person safety training and regular safety meetings. We also utilize learning management software to provide safety training on a variety of topics, and we contract with third-party technical experts to facilitate training on specialized topics that are unique to each of our areas of operation.

It is our policy to provide our employees with a safe and healthy workplace and to follow procedures aimed at safeguarding employees. We believe accident prevention and efficiency in production run hand-in-hand. Our internal Stop Work Authority empowers employees to pause operations so that an observed potential hazard can be eliminated or mitigated.

We are committed to maintaining a safe and healthy work environment by complying with state and federal regulations concerning the health and safety of our employees. Our employees are expected to demonstrate a cooperative spirit by working together to help us in this effort. As such, every employee is directly responsible for the proper care and use of Amplify property and equipment placed in their charge, either temporarily or on a regular basis.

Compensation

We operate in a highly competitive environment and have designed our compensation program to attract, retain and motivate talented and experienced individuals. Our compensation philosophy is designed to align the interests of our workforce with those of our stakeholders and to reward them for achieving the Company’s business and strategic objectives and driving shareholder value. We consider competitive market compensation paid by our peers and other companies comparable to us in size, geographic location and operations in order to ensure our compensation remains competitive and fulfills our goal of recruiting and retaining talented employees.

Training and Development

We are committed to the training and development of our employees. Employees are regularly provided training opportunities to develop skills in leadership, safety, and technical acumen, which bolsters our efforts in conducting business in a safe manner and with high ethical standards. Further, we believe that supporting our employees in achieving their career and development goals is a key element of our approach to attracting and retaining top talent. We encourage our employees to advance their knowledge and skills and to network with other professionals in order to pursue career advancement and potential future opportunities with the Company. Our employees are able to attend training seminars and off-site workshops or to join professional associations that will enable them to remain up to date on the latest changes and best practices in their respective fields.

Inclusion

We are committed to supporting an inclusive workplace and career development opportunities to attract and retain talented employees. As of December 31, 2025, approximately 56% of our total workforce self-identified as a racial or ethnic minority and approximately 18% self-identified as female. As of the same date, approximately 57% of the employees located in our corporate headquarters self-identified as a racial or ethnic minority and approximately 67% self-identified as female. It is our policy to prohibit discrimination and harassment of any type and afford equal employment opportunities to employees and applicants without regard to race, color, religion, sex, national origin, age, disability, genetic information, veteran status, or any other basis protected by federal, state or local law. Further, it is our policy to forbid retaliation against any individual who reports, claims, or makes a charge of discrimination or harassment, fraud, unethical conduct, or a violation of our Company policies. To sustain and promote an inclusive culture, we maintain a robust compliance program rooted in our Code of Business Conduct and Ethics and other Company policies, which provide policies and guidance on non-discrimination, anti-harassment, and equal employment opportunities. We require all employees to complete periodic training sessions on various aspects of our corporate policies through an annual acknowledgment and certification process.

Health and Wellness

We support our employees and their families by offering a robust package of health and welfare benefits, medical, dental, and vision insurance plans for employees and their families, life insurance and long-term disability plans, paid time off for holidays, vacation, sick leave, and other personal leave, and health and dependent care savings accounts. We also provide our employees with a 401(k) plan that includes a competitive company match, and employees have access to a variety of resources and services to help them plan for retirement.

In addition to these programs, we have several other programs designed to further promote the health and wellness of our employees, including, among others, an employee assistance program that offers counseling and referral services for a broad range of personal and family situations.

The success of our business is fundamentally connected to the safety and well-being of our employees. Our focus remains on providing a safe office environment for our employees while continuing to allow for remote work, hybrid work and flexible work schedules where feasible. With the support of the varying work arrangements and a geographically dispersed workforce, we continue to develop ways to best support our people.

Offices

Our principal executive office is located at 500 Dallas Street, Suite 1700, Houston, Texas 77002. Our main telephone number is (832) 219-9001.

Available Information

Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8–K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on our website atwww.amplifyenergy.com as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the SEC. Our website also includes our Code of Business Conduct and Ethics, Corporate Governance Guidelines and the charters of our audit committee, compensation committee and nominating & governance committee. The information contained on, or connected to, our website is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC.

The SEC maintains a website that contains reports, proxy and information statements, and other information regarding the Company at www.sec.gov.