Amplify Energy Corp.

Note 1. Organization and Basis of Presentation

General

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

The Company operates inone reportable segment engaged in the acquisition, development, exploitation and production of oil and natural gas properties. The Company’s management evaluates performance based onone reportable business segment as there are not different economic environments within the operation of our oil and natural gas properties.

The Company 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). The Company divested its assets in Oklahoma, East Texas/North Louisiana and the Eagle Ford (non-op) during the year ended December 31, 2025. See Note 4 for additional information related to the divestitures. The Company’s oil and natural gas properties were located in large, mature oil and natural gas reservoirs. The Company’s properties historically consisted primarily of operated and non-operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells.

As of the date of this 2025 Annual Report on Form 10-K, the Company properties consist of its Bairoil and Beta oil producing properties. The oil properties are located in mature oil reservoirs. As of December 31, 2025, we are the operator of record for properties containing 100% of our total estimated proved reserves.

Basis of Presentation

Material intercompany transactions and balances have been eliminated in preparation of the Company’s Consolidated Financial Statements. The accompanying Consolidated Financial Statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).

Amounts in the prior years consolidated financial statements are reclassified whenever necessary to conform to the current year’s presentation. Reclassification adjustments had no impact on prior year net income (loss) or shareholders’ equity.

Note 2. Summary of Significant Accounting Policies

Use of Estimates

The preparation of Consolidated Financial Statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Significant estimates include, but are not limited to, oil and natural gas reserves; depreciation, depletion and amortization of oil and natural gas properties; future cash flows from oil and natural gas properties; impairment of long-lived assets; fair value of derivatives; fair value of equity compensation; and asset retirement obligations.

Cash and Cash Equivalents

Cash and cash equivalents represent unrestricted cash on hand and all highly liquid investments with original contractual maturities of three months or less.

Concentrations of Credit Risk

Cash balances, accounts receivable, restricted investments and derivative financial instruments are financial instruments potentially subject to credit risk. Cash and cash equivalents are maintained in bank deposit accounts which, at times, may exceed the federally insured limits. Management periodically reviews and assesses the financial condition of the banks to mitigate the risk of loss. Various restricted investment accounts fund certain long-term contractual and regulatory asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Beta oil and gas properties. These restricted investments consist of money market deposit accounts which are held with credit-worthy financial institutions. Derivative financial instruments are generally executed with major financial institutions that expose us to market and credit risks and which may, at times, be concentrated with certain counterparties. The credit worthiness of the counterparties is subject to continual review. We rely upon netting arrangements with counterparties to reduce credit exposure.

Oil and natural gas are sold to a variety of purchasers, including intrastate and interstate pipelines or their marketing affiliates and independent marketing companies. Accounts receivable from joint operations are from a number of oil and natural gas companies, individuals and others who own interests in the properties operated by the Company. Generally, operators of crude oil and natural gas properties have the right to offset future revenues against unpaid charges related to operated wells, minimizing the credit risk associated with these receivables. An allowance for doubtful accounts is recorded after all reasonable efforts have been exhausted to collect or settle the amount owed. Any amounts outstanding longer than the contractual terms are considered past due. The Company recorded $2.9 million and $1.7 million, respectively, as an allowance for doubtful accounts at December 31, 2025 and 2024.

If the Company was to lose any one of its customers, the loss could temporarily delay the production and the sale of oil and natural gas in the related producing region. If it were to lose any single customer, the Company believes that a substitute customer to purchase the impacted production volumes could be identified.

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

Oil and Natural Gas Properties

Oil and natural gas exploration, development and production activities are accounted for in accordance with the successful efforts method of accounting. Under this method, costs of acquiring properties, costs of drilling successful exploration wells and development costs are capitalized. The costs of exploratory wells are initially capitalized, pending a determination of whether proved reserves have been found. At the completion of drilling activities, the costs of exploratory wells remain capitalized if a determination is made that proved reserves have been found. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense. In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a twelve-month period after drilling is complete. Exploration costs such as geological, geophysical, seismic costs and delay rental payments attributable to unproved locations are expensed as incurred.

As exploration and development work progresses and the reserves on these properties are proven, capitalized costs attributed to the properties are subject to depreciation and depletion. Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated field. Capitalized drilling and development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves.

Support equipment and facilities, which are primarily related to our Bairoil and Beta assets, are depreciated using the straight-line method generally based on estimated useful lives oftwelve totwenty-four years.

On the sale or retirement of a complete or partial unit of a proved property or pipeline and related facilities, the cost and related accumulated depreciation, depletion, and amortization are removed from the property accounts, and any gain or loss is recognized.

There wereno material capitalized exploratory drilling costs pending evaluation at December 31, 2025 and 2024.

Oil and Natural Gas Reserves

The estimates of proved oil and natural gas reserves utilized in the preparation of the Consolidated Financial Statements are estimated in accordance with the rules established by the SEC and the Financial Accounting Standards Board (“FASB”). These rules require that reserve estimates be prepared under existing economic and operating conditions using a trailing 12-month average price with no provision for price and cost escalations in future years except by contractual arrangements. The development of the Company’s oil and natural gas reserve quantities requires management to make significant estimates and assumptions related to the intent and ability to complete undeveloped proved reserves within a five-year development period, as prescribed by SEC guidelines. Additionally, none of the Company’s PUDs are scheduled to be developed on a date more than five years from the date the reserves were initially booked as PUD as prescribed by the SEC guidelines. PUDs are converted from undeveloped to developed as applicable wells begin production. We engaged Cawley, Gillespie and Associates, Inc. (“CG&A”), our independent reserve engineers, to prepare our reserves estimates for all of the Company’s estimated proved reserves at December 31, 2025 and 2024.

Reserve estimates are inherently imprecise. Accordingly, the estimates are expected to change as more current information becomes available. It is possible that, because of changes in market conditions or the inherent imprecision of reserve estimates, the estimates of future cash inflows, future gross revenues, the amount of oil and natural gas reserves, the remaining estimated lives of oil and natural gas properties, or any combination of the above may be increased or decreased. Increases in recoverable economic volumes generally reduce per unit depletion rates, while decreases in recoverable economic volumes generally increase per unit depletion rates.

Other Property & Equipment

Other property and equipment are stated at historical cost and is comprised primarily of vehicles, furniture, fixtures, office build-out cost and computer hardware and software. Depreciation of other property and equipment is calculated using the straight-line method generally based on estimated useful lives ofthree toseven years.

Restricted Investments

Restricted investment accounts fund certain long-term asset retirement obligations and collateralize certain regulatory bonds associated with the Beta oil and gas properties. These investments are classified as held-to-maturity and such investments are stated at amortized cost. Interest earned on these investments is included in interest expense, net in the Consolidated Statements of Operations. These restricted investments may consist of money market deposit accounts and U.S. Government securities. See Note 8 and Note 17 for additional information.

Debt Issuance Costs

Debt issuance costs are recorded in other long-term assets line item on the balance sheet and amortized over the term of the associated debt using the straight-line method, which generally approximates the effective yield method. Amortization expense, including write-off of debt issuance costs, for the years ended December 31, 2025 and 2024 was approximately $2.7 million and $1.2 million, respectively, as reflected in interest expense, net in the Consolidated Statements of Operations.

Impairments

Oil and natural gas properties including supporting equipment and facilities are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. This may be due to a downward revision of the reserve estimates, less than expected production, drilling results, higher operating and development costs, or lower commodity prices. The estimated undiscounted future net cash flows expected in connection with the property are compared to the carrying value of the property to determine if the carrying amount is recoverable. If the carrying value of the property exceeds its estimated undiscounted net future cash flows, the carrying amount of the property is reduced to its estimated fair value using Level 3 inputs. The factors used to determine fair value include, but are not limited to, estimates of future proved and probable reserves, commodity prices, production costs, and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties.

During the year, the Company recorded impairment charges related to certain oil and natural gas properties that were identified for sale in connection with our divestiture activities. In accordance with ASC 360, the Company evaluated these assets for recoverability once management committed to a plan to sell them. Based on this evaluation, the Company determined that the carrying amounts of the assets were not recoverable and exceeded their estimated fair values. Fair value was estimated using a discounted cash flow model that incorporated management’s best estimates of the expected sales prices, timing of disposal, and other market‑based assumptions available at the time of the assessment. The expected sales prices represented the primary input to the fair value determination, as they reflected the amounts the Company reasonably anticipated to receive in an orderly transaction between market participants.

As a result of this analysis, the Company recognized impairment charges to reduce the carrying values of the assets to their estimated fair values less costs to sell. The assets subject to impairment were subsequently sold during the year, and the recognized impairment charges aligned the carrying values with the expected economic outcomes of the sales. The Company recorded an impairment expense of $42.5 million for the year ended December 31, 2025. No impairment expense was recorded for the year ended December 31, 2024.

Unproved oil and natural gas properties are reviewed for impairment based on time or geologic factors. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage is also considered. When unproved property investments are deemed to be impaired, the expense is reported in impairment expense. No impairment expense related to the Company’s unproved properties was recorded for the years ended December 31, 2025 and 2024.

Asset Retirement Obligations

An asset retirement obligation associated with retiring long-lived assets is recognized as a liability on a discounted basis in the period in which the legal obligation is incurred and becomes determinable, with an equal amount capitalized as an addition to oil and natural gas properties, which is allocated to expense over the useful life of the asset. Generally, oil and gas producing companies incur such a liability upon acquiring or drilling a well. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value. Upon settlement of the liability, a gain or loss is recognized in net income (loss) to the extent the actual costs differ from the recorded liability. See Note 7 for further discussion of asset retirement obligations.

Revenue Recognition

The Company revenue is primarily derived from the sale of oil and natural gas production, as well as the sale of NGLs that are extracted from natural gas during processing. Revenue is recognized when the following five steps are completed: (1) identify the contract with the customer, (2) identify the performance obligation (promise) in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract, (5) recognize revenue when the reporting organization satisfies a performance obligation.

Revenue from the sale of oil and natural gas is recognized when title passes, net of royalties due to third parties. The performance obligation is the delivery of the commodity at a point in time. Prices for oil, natural gas and NGLs sales are negotiated based on index or spot price, distance from the well to pipeline, commodity quality and prevailing supply and demand conditions. To the extent actual quantities and values of oil, NGLs and natural gas are unavailable for a given reporting period because of timing or information not received from third parties, the expected sales volumes and price for those properties must be estimated.

Derivative Instruments

Commodity derivative financial instruments (e.g., swaps, collars and puts) are used to reduce the impact of natural gas and oil price fluctuations. Every derivative instrument is recorded on the balance sheet as either an asset or liability measured at its fair value. Changes in the derivative’s fair value are recognized in earnings as we have not elected hedge accounting for any of our derivative positions.

Income Tax

The Company is a corporation subject to federal and certain state income taxes.

The Company uses the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the tax basis of assets and liabilities and their reported amounts in the financial statements and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled.

In assessing the carrying value of the Company’s net deferred tax assets, it considers the realizability of its deferred tax assets each reporting period. The realization of any deferred tax asset is dependent upon the generation of future taxable income sufficient to demonstrate its ability to utilize the deferred tax asset in the period in which the temporary differences become deductible or in a future period prior to expiration. The Company considers all available evidence, including cumulative historical losses (defined as pre-tax earnings as adjusted for permanent tax adjustment), scheduled reversal of deferred tax liabilities, projected future taxable income and available tax planning strategies.

The Company recognizes a tax (expense) benefit from an uncertain tax position when it is more likely than not that the position will be sustained upon examination by taxing authorities, based on the technical merits of the position. The tax benefit recorded is equal to the largest amount that isgreater than 50% likely to be realized through effective settlement with a taxing authority. As of December 31, 2025, the Company has no uncertain tax positions.

Earnings (loss) Per Share

Basic and diluted earnings (loss) per share (“EPS”) is determined by dividing net income (loss) available to the common stockholders by the weighted average number of outstanding shares during the period. Diluted earnings (loss) per common share is calculated under the two-class method and the treasury stock method by dividing net income (loss) available to common stockholders by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. When a loss from continuing operations exists, all potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. See Note 11 for additional information.

Equity Compensation

The fair value of equity-classified awards (e.g., restricted common unit awards, restricted stock units or stock options) is amortized to earnings over the requisite service or vesting period. Compensation expense for liability-classified awards (e.g., phantom units awards) are recognized over the requisite service or vesting period of an award based on the fair value of the award re-measured at each reporting period. The Company currently has awards subject to performance criteria; such awards would vest when it is probable that the performance criteria will be met and the requisite service period has been met. Generally, no compensation expense is recognized for equity instruments that do not vest. See Note 12 for further information.

Lease Recognition

The FASB retained a dual model, requiring leases to be classified as either direct financing or operating leases. The classification will be based on criteria that are similar to the current lease accounting treatment. The Company is the lessee under various agreements for office space, warehouse, compressors, equipment, vehicles and surface rentals (right of use assets) that are currently accounted for as operating leases. See Note 13 for additional information regarding leases.

Loss of Production Income Insurance

The Company’s insurance coverage includes loss of production income (“LOPI”) insurance for our offshore properties. Proceeds from LOPI insurance claims are intended to partially offset the loss of revenue resulting from certain events that cause suspension of operations. When such event occurs, the Company files claims under its LOPI policy and recognizes LOPI in the period that insurers accept the claim and all uncertainty with respect to the receipt or amount of claim is resolved. The Company classifies LOPI within “Other revenues” in the Consolidated Statements of Operations.

Insurance Coverage

The Company recognizes an insurance receivable when collection of the receivable is deemed probable. Any recognition of an insurance receivable is recorded by crediting and offsetting the original charge. Any differential arising between the insurance recoveries and insurance receivables is recorded as a capitalized cost or as an expense, consistent with its original treatment.

New Accounting Pronouncements

Income Statement –Expense Disaggregation Disclosures. In November 2024, the FASB issued an accounting standard update which requires disaggregated disclosures of income statement expenses for public business entities. The guidance will require companies to disclose disaggregated information about specific natural expense categories underlying certain income statement expense line items that are considered relevant because they include one or more of the five natural expense categories, as applicable: (1) purchase of inventory, (2) employee compensation, (3) depreciation, (4) intangible asset amortization, and (5) depreciation, depletion and amortization (“DD&A”) recognized as part of oil and gas producing activities or other depletion expenses. The new guidance is effective for annual periods beginning after December 15, 2026 and interim periods within fiscal years beginning after December 31, 2027. The Company is currently evaluating the impact of this guidance on the Company’s financial disclosures. Adoption of the update will not impact the Company’s financial position, results of operations or liquidity.

Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Company's financial position, results of operations or cash flows.

Note 3. Revenues

Revenue from contracts with customers

Revenue is recognized when the following five steps are completed: (1) identify the contract with the customer, (2) identify the performance obligation (promise) in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract, (5) recognize revenue when the reporting organization satisfies a performance obligation.

The Company has determined that its contracts for the sale of crude oil, unprocessed natural gas, residue gas and NGLs contain monthly performance obligations to deliver product at locations specified in the contract. Control is transferred at the delivery location, at which point the performance obligation has been satisfied and revenue is recognized. Fees included in the contract that are incurred prior to control transfer are classified as gathering, processing and transportation and fees incurred after control transfers are included as a reduction to the transaction price. The transaction price at which revenue is recognized consists entirely of variable consideration based on quoted market prices less various fees and the quantity of volumes delivered.

Disaggregation of Revenue

The Company has identified three material revenue streams in its business: oil, natural gas and NGLs. The following table presents the Company’s revenues disaggregated by revenue stream.

Contract Balances

Under its sales contracts, the Company invoices customers once its performance obligations have been satisfied, at which point payment is unconditional. Accordingly, its contracts do not give rise to contract assets or liabilities. Accounts receivable attributable to the Company’s revenue contracts with customers were $23.0 million and $28.5 million at December 31, 2025 and 2024, respectively.

Transaction Price Allocated to Remaining Performance Obligations

For the Company’s contracts that have a contract term greater thanone year, the Company has utilized the practical expedient in ASC 606, which states that a company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under the Company’s contracts, each unit of product delivered to the customer represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. For the Company’s contracts that have a contract term ofone year or less, the Company has utilized the practical expedient in ASC 606, which states that a company is not required to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

Note 4. Acquisitions and Divestitures

2025 Divestitures

On November 4, 2025, Amplify Oklahoma Operating LLC, a Delaware limited liability company and indirect, wholly owned subsidiary of the Company (“Amplify Oklahoma”), Magnify (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. For the year ended December 31, 2025, the Company recorded a loss of $2.3 million in “(gain) loss on sale of properties” in the Company’s Consolidated Statement of Operations. The Company recognized an impairment expense of approximately $34.0 million for the year ended December 31, 2025 in connection with the divestiture. The proceeds from the Revolution Asset Sale were used to reduce borrowings under our Revolving Credit Facility. Upon the asset sale, the Company no longer holds any assets in Oklahoma. This disposition did not qualify as discontinued operation.

On October 28, 2025, OLLC and Magnify Energy Services LLC, a Delaware limited liability company and indirect, wholly owned subsidiary of the Company (“Magnify” and together with OLLC, the “EQV Sellers”), entered into a purchase and sale agreement (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 (each as defined in the EQV Purchase and Sale Agreement) 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. For the year ended December 31, 2025, the Company recorded a gain of $87.1 million in “(gain) loss on sale of properties” in the Company’s Consolidated Statement of Operations. The proceeds from the EQV Asset Sale were used to reduce borrowings under our Revolving Credit Facility. Upon the asset sale, the Company no longer holds any assets in East Texas/North Louisiana. This disposition did not qualify as discontinued operation.

Sale of Non-Operated Eagle Ford Assets

On July 1, 2025, OLLC entered into a definitive agreement (the “Purchase and Sale Agreement”) with Murphy Exploration & Production Company – USA, a Delaware corporation (“Buyer”), the existing operator of the majority of OLLC’s Assets (as defined in the Purchase and Sale Agreement), pursuant to which OLLC sold to Buyer all of OLLC’s Assets, which include, among other things, OLLC’s right, title and interest in and to certain specified oil and gas Properties, Contracts, Equipment and Production (each, as defined in the Purchase and Sale Agreement) within or related to certain designated lands in Karnes County, Texas, for an aggregate cash purchase price of $23.0 million, excluding $1.9 million final post-closing adjustments, resulting in a final adjusted purchase price of $21.1 million (the “ Eagle Ford Asset Sale”). The Eagle Ford Asset Sale closed simultaneously with the execution and delivery of the Purchase and Sale Agreement on July 1, 2025. The Purchase and Sale Agreement became effective as of June 15, 2025. For the year ended December 31, 2025, the Company recorded a gain of $1.2 million in “(gain) loss on sale of properties” in the Company’s Consolidated Statement of Operations. The Company recognized an impairment expense of approximately $8.4 million for the year ended December 31, 2025 in connection with the divestiture. Upon the asset sale, the Company no longer holds any assets in the Eagle Ford. This disposition did not qualify as discontinued operation.

On January 15, 2025, the Company sold 90% of its interest in certain units with rights in the Cotton Valley and Haynesville basins in Harrison County, Texas and purchased a 10% interest in adjacent acreage, generating $6.3 million in net proceeds from the transactions. These transactions also established an area of mutual interest with the counterparty covering 10,000 gross acres. The Company retained a 10% working interest in the units it divested and purchased a 10% working interest in the counterparty’s acreage. The net proceeds received from the purchase and sale transactions of $6.3 million, which is classified as a gain in the “(gain) loss on sale of properties” in the Company’s Consolidated Statement of Operations.

On May 1, 2025, the Company sold 90% of its interest inthree units with rights in the Haynesville basin in Panola and Shelby Counties, Texas to a third party. Amplify retained a 10% working interest in the units it divested. The net proceeds from the transaction of $1.5 million which is classified as a gain in the “(gain) loss on sale of properties” in the Company’s Consolidated Statement of Operations.

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 transaction, which is classified as a gain in the “(gain) loss on sale of properties” in the Company’s Consolidated Statement of Operations. The sale closed on October 24, 2025 and had an effective date of October 1, 2025.

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.

2024 Divestitures

During the year ended December 31, 2024, the Company sold certain rights, title and interest in assets located in East Texas to a third party. The Company recorded a gain of approximately $1.4 million, as reflected in the “(gain) loss on sale of properties" in the Consolidated Statements of Operations.

Acquisition and Divesture Expenses

Acquisition and divestiture related expenses for third-party transactions are included in general and administrative expense in the Consolidated Statements of Operations for the periods indicated below (in thousands):

Note 5. Fair Value Measurements of Financial Instruments

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at a specified measurement date. Fair value estimates are based on either (i) actual market data or (ii) assumptions that other market participants would use in pricing an asset or liability, including estimates of risk. A three-tier hierarchy has been established that classifies fair value amounts recognized or disclosed in the financial statements. The hierarchy considers fair value amounts based on observable inputs (Levels 1 and 2) to be more reliable and predictable than those based primarily on unobservable inputs (Level 3). The characteristics of fair value amounts classified within each level of the hierarchy are described as follows:

Level 1 — Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. An active market is one in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

**Level 2 —**Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. At December 31, 2025 and 2024, all of the derivative instruments reflected on the accompanying balance sheets were considered Level 2.

Level 3 — Measure based on prices or valuation models that require inputs that are both significant to the fair value measurement and are less observable from objective sources (i.e., supported by little or no market activity).

Assets and Liabilities Measured at Fair Value on a Recurring Basis

The carrying values of cash and cash equivalents (Level 1), accounts receivables, accounts payables (including accrued liabilities) and amounts outstanding under long-term debt agreements with variable rates included in the accompanying balance sheets approximated fair value at December 31, 2025 and 2024. The fair value estimates are based upon observable market data and are classified within Level 2 of the fair value hierarchy. These assets and liabilities are not presented in the following tables. See Note 9 for the estimated fair value of our outstanding fixed-rate debt.

The fair market values of the derivative financial instruments reflected on the balance sheets as of December 31, 2025 and 2024 were based on estimated forward commodity prices (including nonperformance risk). Nonperformance risk is the risk that the obligation related to the derivative instrument will not be fulfilled. Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement in its entirety. The significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at December 31, 2025 and 2024 for each of the fair value hierarchy levels:

See Note 6 for additional information regarding our derivative instruments.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are reported at fair value on a nonrecurring basis, as reflected on the balance sheets. The following methods and assumptions are used to estimate the fair values:

Note 6. Risk Management and Derivative Instruments

Derivative instruments are utilized to manage exposure to commodity price fluctuations and achieve a more predictable cash flow in connection with oil and natural gas sales from production. These transactions limit exposure to declines in prices but also limit the benefits that would be realized if prices increase.

Certain inherent business risks are associated with commodity and interest derivative contracts, including market risk and credit risk. Market risk is the risk that the price of natural gas or oil will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by the counterparty to a contract. 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 previous and current credit agreement are counterparties to our derivative contracts. While collateral is generally not required to be posted by counterparties, credit risk associated with derivative instruments is minimized by limiting exposure to any single counterparty and entering into derivative instruments only with creditworthy counterparties that are generally large financial institutions. Additionally, master netting agreements are used to mitigate risk of loss due to default with counterparties on derivative instruments. The Company enters into International Swaps and Derivatives Association Master Agreements (“ISDA Agreements”) with each of its counterparties. The terms of the ISDA Agreements provide the Company and each of its counterparties with rights of set-off upon the occurrence of defined acts of default by either the Company or its counterparty to a derivative, whereby the party not in default may set-off all liabilities owed to the defaulting party against all net derivative asset receivables from the defaulting party. See Note 9 for additional information regarding the Company’s Revolving Credit Facility.

Commodity Derivatives

A combination of commodity derivatives (e.g., floating-for-fixed swaps, put options, costless collars, and three-way collars) is used to manage exposure to commodity price volatility.

The Company enters into natural gas derivative contracts that are indexed to NYMEX Henry-Hub. The Company also enters into oil derivative contracts indexed to either NYMEX WTI or Inter-Continental Exchange (“ICE”) Brent. Its NGL derivative contracts are indexed to Oil Price Information Service Mont Belvieu.

In connection with the EQV Asset Sale as discussed in Note 4, the Company novated certain commodity derivative contracts to EQV Sellers pursuant to the EQV Purchase and Sale Agreement, which reduced the Company’s commodity derivative portfolio at December 31, 2025. The novated derivative contracts were recorded at fair value at the time of novation, and their value was reflected as an adjustment to the purchase price through the preliminary closing settlement statement.

Upon novation, the Company derecognized the derivative contracts from the consolidated balance sheets. The fair value of the novated derivatives was included in the loss (gain) on commodity derivative instruments recorded in the Company’s Consolidated Statements of Operations for the year ended December 31, 2025.

At December 31, 2025, the Company had the following open commodity positions:

Balance Sheet Presentation

The following table summarizes both: (i) the gross fair value of derivative instruments by the appropriate balance sheet classification even when the derivative instruments are subject to netting arrangements and qualify for net presentation in the balance sheet and (ii) the net recorded fair value as reflected on the balance sheet at December 31, 2025 and 2024. There wasno cash collateral received or pledged associated with its derivative instruments since all of the counterparties, or certain of their affiliates, to its derivative contracts are lenders under the Company’s Credit Agreement (as defined below).

(Gains) Losses on Derivatives

The Company does not designate derivative instruments as hedging instruments for accounting and financial reporting purposes. Accordingly, all gains and losses, including changes in the derivative instruments’ fair values, have been recorded in the accompanying statements of operations. The following table details the gains and losses related to derivative instruments for the periods indicated (in thousands):

Note 7. Asset Retirement Obligations

The Company’s asset retirement obligations primarily relate to the Company’s portion of future plugging and abandonment of wells and related facilities. The following table presents the changes in the asset retirement obligations for the years ended December 31, 2025 and 2024 (in thousands):

Note 8. Restricted Investments

Various restricted investment accounts fund certain long-term contractual and asset retirement obligations and collateralize certain regulatory bonds associated with the offshore Beta oil and gas properties. The components of the restricted investment balances are as follows:

Note 9. Long-Term Debt

The Company’s consolidated debt obligations consisted of the following at the dates indicated:

Amended and Restated Credit Agreement

On July 31, 2023, Amplify Energy Operating LLC (“OLLC”), a wholly owned subsidiary of the Company and Amplify Acquisitionco LLC (“Acquisitionco”), as the direct parent of OLLC and wholly owned subsidiary of the Company, entered into the Amended and Restated Credit Agreement (the “Credit Agreement”), providing for a senior secured reserve-based revolving credit facility (the “Revolving Credit Facility”). The Revolving Credit Facility is guaranteed by the Company and all of its material subsidiaries and secured by substantially all of its assets. The Revolving Credit Facility was originally set to mature on July 31, 2027, and is a replacement in full of the prior Revolving Credit Facility, by and among OLLC, Acquisitionco, the guarantors party thereto, the lenders party thereto and KeyBank National Association, as administrative agent.

On October 25, 2024, OLLC entered into the first amendment to the Revolving Credit Facility, which, among other things, (i) reduced the borrowing base under the Revolving Credit Facility from $150.0 million to $145.0 million, (ii) increased the aggregate elected commitments under the Revolving Credit Facility from $135.0 million to $145.0 million and (iii) amended certain interest rates applicable to loans under the Revolving Credit Facility.

On December 31, 2025, OLLC entered into the Borrowing Base Redetermination, Commitment Increase and Second Amendment to the 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 Credit Agreement, 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.

Certain key terms and conditions under the Revolving Credit Facility, as amended, include (but are not limited to):

The Company hadno loans outstanding under the Revolving Credit Facility as of December 31, 2025. The borrowing base under the facility is $25.0 million with elected commitments of $15.0 million at December 31, 2025. The Revolving Credit Facility borrowing base will be redetermined on a semi-annual basis based on an engineering report with respect to the Company’s estimated oil and NGL reserves, which will take into account the prevailing oil and NGL prices at such time, as adjusted for the impact of commodity derivative contracts. Unanimous approval by the lenders is required for any increase to the borrowing base.

Debt Compliance

As of December 31, 2025, the Company was in compliance with all the financial (current ratio and total leverage ratio) and non-financial covenants associated with the Company’s Revolving Credit Facility.

Weighted-Average Interest Rates

The following table presents the weighted-average interest rates paid on variable-rate debt obligations for the periods presented:

Letters of credit

At December 31, 2025, the Company hadno letters of credit outstanding.

Unamortized Deferred Financing Costs

Unamortized deferred financing costs associated with the Revolving Credit Facility was $1.0 million at December 31, 2025. The unamortized deferred financing costs are amortized over the remaining life of the Revolving Credit Facility using the straight-line method, which generally approximates the effective interest method.

For the year ended December 31, 2025, the Company wrote off $1.5 million of deferred financing cost.

Note 10. Equity (Deficit)

Equity Outstanding

The Company’s authorized capital stock includes 250,000,000 shares of common stock, $0.01 par value per share. The following table summarizes the changes in the number of outstanding common units and shares of common stock:

Note 11. Earnings (Loss) per Share

The following sets forth the calculation of earnings (loss) per share, or EPS, for the periods indicated (in thousands, except per share amounts):

Note 12. Equity-based Awards

In May 2021, the Company shareholders approved an Equity Incentive Plan (“2021 EIP”) in which the Legacy Amplify Management Incentive Plan (the “Legacy Amplify MIP”) and the Legacy Amplify 2017 Non-Employee Directors Compensation Plan (the “Legacy Amplify Non-Employee Directors Compensation Plan”) were replaced by the 2021 EIP and no further awards will be granted under the Legacy Amplify MIP or the Legacy Amplify Non-Employee Directors Compensation Plan.

On May 15, 2024, the Company’s shareholders approved the Amplify Energy Corp. 2024 Equity Incentive Plan (the “2024 EIP” and together with the 2021 EIP, the “EIP Plans”), which had previously been approved by the board of directors of the Company (the “Board”). No further awards will be granted under the prior 2021 EIP.

The 2024 EIP Plan provides for awards that can be granted in the form of nonqualified stock options, incentive stock options, restricted stock awards, restricted stock units, stock appreciation rights, performance awards, stock awards and other incentive awards. To the extent that an award granted under either of the EIP Plans is canceled, expired, forfeited, settled in cash or otherwise terminated without delivery of shares of common stock, the shares of Common Stock retained by or returned to the Company will be available for future awards under the 2024 EIP. Any shares that are tendered by a participant or withheld by the Company (i) in payment of the exercise, base or purchase price relating to a stock option or stock appreciation right under either of the EIP Plans, or (ii) to satisfy any taxes or tax withholding obligations with respect to a stock option or stock appreciation right under either of the EIP Plans, as applicable, will not be available for future awards under the 2024 EIP. Any shares that are withheld by the Company or tendered by a participant to satisfy tax withholding obligations associated with any award other than stock options or stock appreciation rights granted under the 2024 EIP will become available again for future awards under the 2024 EIP. The 2024 EIP is administered by the Board. At December 31, 2025, the Company had 626,673 shares remaining available for issuance under the 2024 EIP.

Restricted Stock Units

Restricted Stock Units with Service Vesting Condition

Restricted stock units with service vesting conditions (“TSUs”) are accounted for as equity-classified awards or liability-classified awards. The grant-date fair value is recognized as compensation cost on a straight-line basis over the requisite service period and forfeitures are accounted for as they occur. The Company considered its intent and ability to settle awards in cash or shares of stock in determining whether to classify the awards as equity or liability awards. Compensation costs for equity-classified awards are recorded as general and administrative expense. The fair value of liability-classified awards is determined on a quarterly basis beginning at the grant date until final vesting. Changes in the fair value of liability-classified awards are recorded to general administrative expense and are remeasured at fair value each reporting period.

In February 2024, the Company granted contingent cash-settlement awards in the form of TSUs (the “2024 TSUs”). In May 2024, the Company received shareholder approval of the 2024 EIP, which nullified the contingent cash settlement component for the 2024 TSUs. As of June 30, 2024, the 2024 TSUs were reclassified as equity awards. The compensation cost related to these awards is determined by the fair value of the award on the modification date. The 2024 TSUs will vest in substantially equal installments over athree-year period.

The unrecognized cost associated with TSUs was $4.1 million at December 31, 2025. The Company expects to recognize the unrecognized compensation cost for these awards over a weighted-average period of 1.6 years.

The following table summarizes information regarding the TSUs granted under the EIP Plans for the period presented:

Restricted Stock Units with Market and Service Vesting Conditions

Restricted stock units with market and service vesting conditions (“PSUs”) are accounted for as equity-classified awards or liability-classified awards. The grant-date fair value is recognized as compensation cost on a graded-vesting basis. The fair value of the awards is estimated on their grant dates using a Monte Carlo simulation.

The Company recognizes compensation cost over the requisite service or performance period. The Company accounts for forfeitures as they occur. Compensation costs are recorded as general and administrative expense. The unrecognized cost associated with these awards was $1.9 million at December 31, 2025. The Company expects to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 1.7 years.

2023 PSU Awards

The 2023 PSU awards are accounted for as equity-classified awards and were issued with athree-year vesting period beginning on the grant date and ending on the third anniversary of the grant date. Thethree-year performance period for the 2023 awards is January 1, 2023 through December 31, 2025. Vesting of PSUs can range from zero to 200% of the target units granted based on the Company’s relative total shareholder return as compared to the total shareholder return of the Company’s performance peer group over the applicable performance period.

2024 PSU Award

In February 2024, the Company granted contingent cash-settlement awards in the form of PSUs (the “2024 PSUs”). In May 2024, the Company received shareholder approval of the 2024 EIP, which nullified the contingent cash settlement component for the 2024 PSUs. As of June 30, 2024, the 2024 PSUs were reclassified as equity awards with athree-year vesting period. The compensation cost related to these awards is determined by the fair value of the award on the modification date. Thethree-year performance period for the 2024 PSUs is January 1, 2024 through December 31, 2026.

2025 PSU Awards

The 2025 PSU awards are accounted for as equity-classified awards and were issued with athree-year vesting period beginning on the grant date and ending on the third anniversary of the grant date. Thethree-year performance period for the 2025 awards is January 1, 2025 through December 31, 2027. Vesting of PRSUs can range from zero to 200% of the target units granted based on the Company’s relative total shareholder return as compared to the total shareholder return of the Company’s performance peer group over the applicable performance period.

In connection with Mr. Daniel Furbee’s appointment as Chief Executive Officer, he received a grant of 100,000 PSUs (the “Target PSUs”) on July 22, 2025. The Target PSUs are subject to a performance period that began on July 22, 2025 and ends on March 31, 2028 (the “Performance Period”). The Target PSUs will vest, subject to Mr. Furbee’s continued employment through the settlement date, as follows: (i)50% of the Target PSUs will vest if the 20-day volume-weighted average closing price (“VWAP”) of a share of Company common stock for the 20 consecutive trading days immediately preceding the end of the Performance Period equals at least $6.00 but less than $8.00, (ii)100% of the Target PSUs will vest if the 20-day VWAP of a share of Company common stock for the 20 consecutive trading days immediately preceding the end of the Performance Period equals at least $8.00, but less than $10.00, and (iii)200% of the Target PSUs will vest if the 20-day VWAP of a share of the Company’s common stock for the 20 consecutive trading days immediately preceding the end of the Performance Period equals at least $10.00, with linear interpolation to apply for actual performance achieved between the foregoing thresholds.

The below table reflects the ranges for the assumptions used in the Monte Carlo model for the 2025 and 2024 PSUs awards:

The following table summarizes information regarding the PSUs granted under the EIP Plans for the period presented:

Compensation Expense

The following table summarizes the amount of recognized compensation expense associated with these awards that are reflected in the accompanying statements of operations for the periods presented (in thousands):

Note 13. Leases

The Company enters into leases for office space, warehouse space and equipment in our corporate office and operating regions as well as vehicles, compressors and surface rentals related to our business operations. In addition, the Company has right-of-way leases to operate the San Pedro Bay Pipeline. For the year ended December 31, 2025, the Company leases qualify as operating leases and the Company did not have any existing or new leases qualifying as financing leases. Most of the Company’s leases, other than the Company’s corporate office lease, have an initial term and may be extended on a month-to-month basis after expiration of the initial term. Most of ourleases can be terminated with 30-day prior written notice. The majority of our month-to-month leases are not included as a lease liability in the Company’s balance sheet because continuation of the lease is not reasonably certain. Additionally, the Company elected the short-term practical expedient to exclude leases with a term of twelve months or less.

The Company corporate office lease does not provide an implicit rate. To determine the present value of the lease payments, the Company uses an incremental borrowing rate based on the information available at the inception date. To determine the incremental borrowing rate, the Company applied a portfolio approach based on the applicable lease terms and the current economic environment. The Company uses a reasonable market interest rate for the Company office equipment and vehicle leases.

For the year ended December 31, 2025 and 2024, the Company recognized approximately $2.1 million and $2.0 million, respectively, of costs relating to the operating leases in the Consolidated Statements of Operations.

Supplemental cash flow information related to the Company’s lease liabilities in included in the table below:

The following table presents the Company’s right-of-use assets and lease liabilities for the period presented:

The following table reflects the Company’s maturity analysis of the minimum lease payment obligations under non-cancelable operating leases with a remaining term in excess of one year (in thousands):

The weighted average remaining lease terms and discount rate for all of the Company’s operating leases for the period presented:

Note 14. Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows

Accrued Liabilities

Current accrued liabilities consisted of the following at the dates indicated (in thousands):

Accounts Receivable

Accounts receivable consisted of the following at the dates indicated (in thousands):

Supplemental Cash Flows

Supplemental cash flow for the periods presented (in thousands):

Note 15. Related Party Transactions

Related Party Agreements

There have beenno transactions between the Company and a related person in which the related person had a direct or indirect material interest for the years ended December 31, 2025 and 2024.

Note 16. Segment Reporting

The Company’s operations are all related to the exploration, development and production of oil and natural gas in the United States, from which the Company derives all of its revenues. The Company manages its business as a single reportable segment, as its operations are focused on assets with similar economic characteristics, production processes, types of purchasers, regulatory environment and customers which are consistent across the Company. Therefore, the Company aggregates its operating regions intoone reportable segment.

The Chief Operating Decision Maker (“CODM”) is the Company’s Chief Executive Officer, who reviews the financial information on a consolidated basis. The CODM uses consolidated net income to assess financial performance, allocating capital and other resources. The CODM uses consolidated net income in the annual budgeting and monthly forecasting process. Additionally, our CODM is regularly provided information on lease operating expense, gathering, processing and transportation and taxes other than income. Other segment items primarily consists of DD&A, accretion expense, general and administrative expense, pipeline incident loss, loss (gain) on commodity derivative, interest expense and income tax expense (benefit). Our significant segment expenses and other segment items are derived from and can be found within the Consolidated Statement of Operations.

The following table provides financial information with respect to the Company’s single reportable segment for the years ended December 31, 2025 and 2024:

Note 17. Commitments and Contingencies

Litigation and Environmental

We are involved in various lawsuits, claims, government investigations and other legal proceedings that arise in the usual conduct of our business. These claims or proceedings can involve various types of parties, including governments, regulatory agencies, competitors, customers, suppliers, service providers, licensees, employees or stockholders, among others. These matters may involve antitrust, securities, pricing, public utility and transportation rates, taxes, environmental, commercial, contractual rights, licensing obligations, health and safety matters, employment matters, regulatory compliance and permits relating to the operations of our various plants and facilities, among others.

We assess these matters to determine if a contingent liability should be recorded. We accrue for estimated exposures to the extent they are both probable and reasonably estimable based on then-available information.

Predicting the outcome of claims and litigation, and estimating related costs and exposure, involves substantial uncertainties that could cause actual costs to vary materially from estimates and accruals. Matters often develop over a long period of time and expectations can change as a result of new findings, rulings, appeals, settlements, legal or regulatory changes or other factors. If the assessment of relevant factors changes, estimates may change, and it is not possible to determine the final outcome of these matters.

Although the Company is insured against various risks to the extent the Company believes it is prudent, there is no assurance that the nature and amount of such insurance will be adequate, in every case, to indemnify it against liabilities arising from future legal proceedings.

Environmental costs for remediation are accrued based on estimates of known remediation requirements. Such accruals are based on management’s best estimate of the ultimate cost to remediate a site and are adjusted as further information and circumstances develop. Those estimates may change substantially depending on information about the nature and extent of contamination, appropriate remediation technologies and regulatory approvals. Expenditures to mitigate or prevent future environmental contamination are capitalized. Ongoing environmental compliance costs are charged to expense as incurred. In accruing for environmental remediation liabilities, costs of future expenditures for environmental remediation are not discounted to their present value, unless the amount and timing of the expenditures are fixed or reliably determinable. At December 31, 2025 and 2024, the Company hadno environmental reserves recorded.

Beta Pipeline Incident

In October 2021, the Company learned that a 4,000-foot section of the Company’s pipeline approximately four miles off the coast of Newport Beach, California had been displaced with a maximum lateral movement of approximately 105 feet and that the pipeline had a 13-inch split, running parallel to the pipe, leading to the release of approximately 588 barrels of oil (the “Incident”).

As previously disclosed, the Company reached resolutions regarding criminal and civil claims against it related to the Incident. The Company also reached resolutions related to civil claims the Company asserted against third parties related to the Incident. In addition, in December 2025, the Company paid $2.0 million pursuant to a settlement with PHMSA related to the Incident. Under the Oil Pollution Act of 1990, the Company’s pipeline was designated by the U.S. Coast Guard as the source of the oil discharge and therefore the Company is financially responsible for certain natural resource damages associated with the spill and certain costs determined by federal and state trustees engaged in a joint assessment of such natural resource damages. The Natural Resource Damage Assessment remains ongoing and therefore the extent, timing and cost related to such assessment are difficult to project. While the Company anticipates insurance will reimburse it for expenses related to the Natural Resource Damage Assessment, any potentially uncovered expenses may be material and could impact the Company’s business and results of operations and could put pressure on its liquidity position going forward.

While it remains possible that federal agencies may in the future commence investigations or proceedings or may initiate enforcement actions seeking penalties or other relief, outside of the Natural Resource Damage Assessment, Amplify Energy has resolved any such investigations, proceedings or actions initiated to date.

Total costs that the Company has incurred with respect to the Incident amount to approximately $202.4 million, which includes (i) response and remediation under the direction of the Unified Command, (ii) fines and penalties of $12.4 million resulting from the resolution of the federal and state of California matters, and (iii) certain legal fees.

On December 31, 2025, the Company no longer had an outstanding insurance receivable related to the pipeline incident loss and on December 31, 2024, the Company’s insurance receivables were $4.7 million. For the year ended December 31, 2025, the Company incurred legal fees, loss load and other non-reimbursable expenses of $2.4 million that are classified as “Pipeline Incident Loss” on the Company’s Consolidated Statements of Operations.

Sinking Fund Trust Agreement

Beta Operating Company, LLC, a wholly owned subsidiary, assumed an obligation with a third party to make payments into a sinking fund in connection with its 2009 acquisition of the Beta properties, the purpose of which is to provide funds adequate to decommission the portion of the San Pedro Bay Pipeline that lies within state waters and the surface facilities. Under the terms of the agreement, the operator of the properties is obligated to make monthly deposits into the sinking fund account in an amount equal to $0.25 per barrel of oil and other liquid hydrocarbon produced from the acquired working interest. Interest earned in the account stays in the account. The obligation to fund ceases when the aggregate value of the account reaches $4.3 million. As of December 31, 2025, the account balance included in restricted investments was approximately $4.6 million.

Supplemental Bond for Decommissioning Liabilities Trust Agreement

Beta Operating Company, LLC has an obligation with BOEM in connection with the 2009 acquisition of the Beta properties. The Company supports this obligation with $161.3 million in A-rated surety bonds.

Pursuant to these additional collateral requirements, on December 15, 2021, the Company entered intotwo escrow funding agreements, a federal escrow funding agreement and a state escrow funding agreement, with its surety providers to fund interest-bearing escrow accounts on a quarterly basis to reimburse and indemnify the surety providers for any claims arising under the surety bonds related to the decommissioning of our Beta properties. As long as we continue to comply with our obligations under such escrow agreements, the surety providers party thereto have agreed to stay requests of additional collateral in the form of cash or letters of credit, certificates of deposit or other similar forms of liquid collateral. If any such additional collateral were requested, such additional collateral may negatively impact the Company’s liquidity position.

In March 2024, the Company amended the federal escrow funding agreement to decrease the amount funded from $14.8 million per year to $8.0 million per year. There were no changes made to the state escrow funding agreement. The obligation ceases when the aggregate value of the account reaches $172.6 million. As of December 31, 2025, the Company has funded $35.6 million into the escrow accounts which is reflected in “Restricted Investments” on the Consolidated Balance Sheet. The table below outlines our funding commitment under these agreements at December 31, 2025 (in thousands):

The expense related to the surety bonds is recorded in interest expense in the Company Statement of Consolidated Operations.

Operating Leases

The Company enters into leases for compressors, surface rentals, office space, warehouse space and equipment in our corporate office and operating regions. For the years ended December 31, 2025 and 2024, the Company recognized $9.6 million and $10.7 million of rental cost, respectively.

See Note 13 for the minimum lease payment obligations under non-cancelable operating leases with a remaining term in excess of one year.

Purchase Commitments

At December 31, 2025, the Company had a CO 2 purchase commitment with a third party associated with its Bairoil properties. The price we will pay for CO 2 generally varies depending on the amount of CO 2 delivered and the price of oil. The table below outlines its purchase commitments under these contracts based on pricing at December 31, 2025 (in thousands):

Note 18. Income Tax

Amplify Energy is a corporation and, as a result, is subject to U.S. federal, state, and local income taxes.

On July 4, 2025, the U.S. enacted legislation referred to as the One Big Beautiful Bill(“OBBBA”), which contains certain significant changes to U.S. corporate income tax laws that are generally effective for tax years beginning after December 31, 2024. These changes include, but are not limited to, the restoration of immediate expensing for domestic research and experimental (“R&E”) expenses, the option to retroactively deduct certain previously capitalized R&E expenses, modifications to the business interest expense limitation, and the restoration of 100 percent bonus depreciation for qualified property placed in service after January 19, 2025. The impacts of the tax law changes from OBBBA are reflected in the Company’s 2025 income tax provision; however, the changes affect timing only and do not change the total tax provision for the year ended December 31, 2025.

The Company adopted improvements to income tax disclosure (ASU 2023-09) on January 1, 2025. The adoption of the guidance did not impact the Company's financial position, results of operations, or cash flows.

The components of income tax benefit (expense) are as follows:

The actual income tax benefit (expense) differs from the expected amount computed by applying the federal statutory corporate tax rate of 21% for the year ended December 31, 2025, presented in accordance with the prospectively adopted ASU 2023-09 guidance, was as follows:

The actual income tax benefit (expense) differs from the expected amount computed by applying the federal statutory corporate tax rate of 21% in 2024 in accordance with the guidance prior to the adoption of ASU 2023-09 was as follows:

The Company’s deferred income tax position reflects the net tax effects of the temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax reporting. Significant components of the deferred tax assets and liabilities are as follows (in thousands):

Net Operating Loss Carryforward. In connection with the merger with Midstates Petroleum Company in 2019, the Company was subject to IRC §382 loss limitations on pre-merger net operating loss (“NOL”) and tax attributes. As of December 31, 2025, the Company’s federal NOL carryforward of $790.8 million is subject to §382 loss limitations, of which $20.9 million will expire in 2037 and $769.9 million have no expiration. As of December 31, 2025, the Company has $149.7 million federal post-merger NOL carryforward. All post-merger NOLs are not subject to §382 loss limitations and do not expire.

As of December 31, 2025, the Company had approximately $88.9 million of state net operating loss carryovers which have different expirations dates starting in 2037.

Valuation Allowance. In assessing deferred tax assets, management considers new evidence, both positive and negative, that could affect its view of the future realization of deferred tax assets. The assessment considers all available information including, among other things, historical and forecasted taxable income and operating history, the scheduled reversal of deferred tax liabilities and available tax planning strategies. As of December 31, 2025, the Company hadthree years of cumulative book income. Furthermore, management determined that the Company’s ability to maintain long-term profitability despite near-term changes in commodity prices and capital and operating costs demonstrated that there is sufficient positive evidence to conclude that it is more likely than not that all net deferred tax assets are realizable.

*Uncertain Income Tax Position.*The Company must recognize the tax effects of any uncertain tax positions that the Company may adopt if the position taken by us is more likely than not sustainable based on its technical merits. For those benefits to be recognized, an income tax position must be more-likely-than-not to be sustained upon examination by taxing authorities. The Company hadno unrecognized tax benefits as of December 31, 2025.

*Tax Audits and Settlements.*The Company’s income tax years 2022 through 2024 remain open and subject to examination by the Internal Revenue Service (IRS). For state and local jurisdictions where the Company conducts operations, the Company’s 2021 through 2024 tax years remain open and subject to examination. In certain jurisdictions where the Company operates through more than one legal entity, each of which may have different open years subject to examination.

Note 19. Supplemental Oil and Gas Information (Unaudited)

Capitalized Costs Relating to Oil and Natural Gas Producing Activities

The total amount of capitalized costs relating to oil and natural gas producing activities and the total amount of related accumulated depreciation, depletion and amortization is as follows at the dates indicated.

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities

Costs incurred in property acquisition, exploration and development activities were as follows for the periods indicated:

Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves

As required by the FASB and SEC, the standardized measure of discounted future net cash flows presented below is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates and a discount factor of 10 percent to proved reserves. We do not believe the standardized measure provides a reliable estimate of the Company’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including first-day-of-the-month average prices, which represent discrete points in time and, therefore, may cause significant variability in cash flows from year to year as prices change.

Oil and Natural Gas Reserves

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves are those quantities of oil and natural gas that by analysis of geoscience and engineering data can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

We engaged CG&A to prepare our reserves estimates for all of our estimated proved reserves at December 31, 2025 and 2024. All proved reserves are located in the United States and all prices are held constant in accordance with SEC rules.

The weighted-average benchmark product prices used for valuing the reserves are based upon the average of the first-day-of-the-month price for each month within the period January through December of each year presented:

The following tables set forth estimates of the net reserves for the periods indicated:

Noteworthy amounts included in the categories of proved reserve changes in the above tables include:

A variety of methodologies are used to determine our proved reserve estimates. The principal methodologies employed are reservoir simulation, decline curve analysis, volumetric, material balance, advance production type curve matching, petro-physics/log analysis and analogy. Some combination of these methods is used to determine reserve estimates in substantially all of our fields.

The standardized measure of discounted future net cash flows is as follows:

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

The following is a summary of the changes in the standardized measure of discounted future net cash flows for the proved oil and natural gas reserves during each of the years in the two-year period presented: