Amplify Energy Corp

Note 1. Organization and Basis of Presentation

General

Amplify Energy Corp. (“Amplify Energy” 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 consist 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). Most of the Company’s oil and natural gas properties are located in large, mature oil and natural gas reservoirs. The Company’s properties consist primarily of operated and non-operated working interests in producing and undeveloped leasehold acreage and working interests in identified producing wells.

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 $1.7 million and $1.6 million, respectively, as an allowance for doubtful accounts at December 31, 2024 and 2023.

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, 2024 and 2023.

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, 2024 and 2023.

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 18 for additional information.

Debt Issuance Costs

Debt issuance costs are recorded in prepaid expenses and other current 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, 2024 and 2023 was approximately $1.2 million and $2.0 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. No impairment expense related to its proved properties was recorded for the years ended December 31, 2024 and 2023.

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, 2024 and 2023.

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, 2024, 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.

For the year ended December 31, 2023, the Company recognized LOPI insurance payments of $17.9 million from our Beta properties due to the Incident (as defined below). The Company’s LOPI insurance policy in effect at the time of the pipeline incident provided eighteen months of LOPI coverage. As such, the Company didnot recognize any LOPI insurance payments for the year ended December 31, 2024. See Note 17 for additional information regarding the pipeline incident.

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. See Note 17 for additional information regarding the pipeline incident.

New Accounting Pronouncements

Improvements to Income Tax Disclosure. In December 2023, the Federal Accounting Standards Board (“FASB”) issued an accounting standard update which requires that companies disclose the nature and magnitude of factors contributing to the difference between their effective tax rate and the statutory tax rate. The update will require companies to disclose specific categories in the rate reconciliation and provide additional information about items that meet a certain quantitative threshold. The new guidance is effective for annual periods beginning after December 15, 2024. 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.

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, 2024. 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 $28.5 million and $31.1 million at December 31, 2024 and 2023, 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

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

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.

Subsequent Events. On January 15, 2025, the Company announced that it entered into a definitive merger agreement with privately held Juniper Capital Advisors, L.P. (“Juniper”) to combine with certain Juniper portfolio companies that own substantial oil-weighted producing assets and significant leasehold interests in the Denver-Julesburg Basin and Powder River Basin. See Note 21 for additional information related to the Mergers (as defined below).

On January 15, 2025, the Company purchased and sold certain rights, title and interest in assets in East Texas from a third party, whereby the Company received net proceeds of $6.2 million.

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, 2024 and 2023, 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, 2024 and 2023. 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, 2024 and 2023 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, 2024 and December 31, 2023 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 natural gas and oil 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. As a result, had certain counterparties failed completely to perform according to the terms of the existing contracts, we would have the right to offset $6.6 million against amounts outstanding under our Revolving Credit Facility at December 31, 2024. 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.

At December 31, 2024, 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, 2024 and 2023. 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, 2024 and 2023 (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, OLLC 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 matures 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 (as amended, the “Prior Revolving Credit Facility”).

The aggregate principal amount of loans outstanding under the Revolving Credit Facility as of December 31, 2024, was $127.0 million. The borrowing base under the facility is $145.0 million with elected commitments of $145.0 million at December 31, 2024. 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, NGL, and natural gas reserves, which will take into account the prevailing oil, NGL and natural gas 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.

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

On October 25, 2024, OLLC entered into an 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. The next redetermination is expected in the spring of 2025.

Debt Compliance

As of December 31, 2024, 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, 2024, the Company hadno letters of credit outstanding.

Unamortized Deferred Financing Costs

Unamortized deferred financing costs associated with the Revolving Credit Facility was $3.3 million at December 31, 2024. 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.

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 a new Equity Incentive Plan (“EIP”) in which 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 EIP and no further awards will be allowed to 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”), which had previously been approved by the board of directors of the Company (the “Board”). No further awards will be granted under the prior Legacy Equity Incentive Plan (“EIP,” and together with the 2024 EIP, the “EIP Plans”).

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, 2024, the Company had 1,889,359 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 $5.5 million at December 31, 2024. The Company expects to recognize the unrecognized compensation cost for these awards over a weighted-average period of 1.8 years.

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

Restricted Stock Units with Market and Service Vesting Conditions

Restricted stock units with market and service vesting conditions (“PRSUs”) 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 $2.8 million at December 31, 2024. The Company expects to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 1.7 years.

2022 and 2023 PRSU Awards

The 2022 and 2023 PRSU 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 2022 awards is January 1, 2022 through December 31, 2024. Thethree-year performance period for the 2023 awards is January 1, 2023 through December 31, 2025. 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.

2024 PRSU Award

In February 2024, the Company granted contingent cash-settlement awards in the form of PRSUs (the “2024 PRSUs”). In May 2024, the Company received shareholder approval of the 2024 EIP, which nullified the contingent cash settlement component for the 2024 PRSUs. As of June 30, 2024, the 2024 PRSUs 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 PRSUs is January 1, 2024 through December 31, 2026.

The below table reflects the ranges for the assumptions used in the Monte Carlo model for the 2024 and 2023 PRSUs awards:

The following table summarizes information regarding the PRSUs granted under the EIP 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, 2024, 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, 2024 and 2023, the Company recognized approximately $2.0 million and $2.1 million, respectively, of costs relating to the operating leases in the Consolidated Statements of Operations.

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, 2024 and 2023.

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, 2024 and 2023:

Note 17. Beta Pipeline Incident

On October 2, 2021, contractors operating under the direction of Beta Operating Company, LLC, a subsidiary of the Company, observed an oil sheen on the water approximately four miles off the coast of Newport Beach, California (the “Incident”). Beta platform personnel were notified and promptly initiated the Company’s Oil Spill Response Plan. On October 3, 2021, a Unified Command, consisting of the Company, the U.S. Coast Guard and California Department of Fish and Wildlife’s Office of Spill Prevention and Response, was established to respond to the Incident.

On October 5, 2021, the Unified Command announced that reports from its contracted commercial divers and Remotely Operated Vehicle footage indicated that a 4,000-foot section of the Company’s pipeline 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. On October 14, 2021, the U.S. Coast Guard announced that it had a high degree of confidence the size of the release was approximately 588 barrels of oil. On October 16, 2021, the U.S. Coast Guard announced that it had identified the Mediterranean Shipping Company (DANIT) as a “vessel of interest” and its owner Dordellas Finance Corporation and operator Mediterranean Shipping Company, S.A. as parties in interest in connection with an anchor-dragging incident in January 2021 (the “Anchor Dragging Incident”), which occurred in close proximity to the Company’s pipeline, and that additional vessels of interest continued to be investigated. On November 19, 2021, the U.S. Coast Guard announced that it had identified the COSCO (Beijing) as another vessel involved in the Anchor Dragging Incident and named its owner Capetanissa Maritime Corporation of Liberia and its operator V.Ships Greece Ltd. as parties in interest. The cause, timing and details regarding the Incident remain under investigation.

At the height of the Incident response, the Company deployed over 1,800 personnel working under the guidance and at the direction of the Unified Command to aid in cleanup operations. As of October 14, 2021, all beaches that had been closed following the Incident have reopened. On February 2, 2022, the Unified Command announced that response and monitoring efforts have officially concluded for the Incident, and Unified Command would stand down as of such date. Amplify is grateful to its Unified Command partners for their collaboration and professionalism over the course of the response.

On April 10, 2023, the Company announced that it had received the required approvals from federal regulatory agencies to restart operations at the Beta Field. The pipeline has been operated in accordance with the restart procedures that were reviewed and approved by PHMSA.

As previously disclosed, the Company reached resolutions regarding criminal and civil claims against it related to the Incident. Certain obligations, as detailed in prior disclosures, are ongoing (including certain installment payments and probation terms under a federal plea agreement). The Company also reached resolutions related to civil claims the Company asserted against third parties related to the Incident.

Federal agencies may or have commenced investigations and proceedings and may initiate enforcement actions seeking penalties and other relief under the Clean Water Act and other statutes. Amplify continues to comply with all regulatory requirements and investigations. The outcomes of these investigations and the nature of any remedies pursued will depend on the discretion of the relevant authorities and may result in regulatory or other enforcement actions, as well as civil liability.

Under the Oil Pollution Act of 1990 (“OPA 90”), 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 remediation and for certain costs and economic damages as provided for in OPA 90, as well as 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 Company has completed processing covered claims under OPA 90. In addition, 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.

Based on presently enacted laws and regulations and currently available facts, the Company estimates that the total costs it has incurred or will incur with respect to the Incident to be approximately $190.0 million to $210.0 million, which includes (i) actual and projected response and remediation under the direction of the Unified Command, (ii) fines and penalties of $12.0 million resulting from the resolution of the federal and state of California matters discussed above, and (iii) certain legal fees.

The range of total costs is based on the Company’s assumptions regarding (i) settlement of costs associated with certain vendors for response and remediation expenses, (ii) resolution of certain third-party claims, excluding claims with respect to losses, which are not probable or reasonably estimable, and (iii) future claims and lawsuits. While the Company believes it has accurately reflected all probable and reasonably estimable costs incurred in the Company’s Unaudited Consolidated Statements of Operations, these estimates are subject to uncertainties associated with the underlying assumptions. For example, settlements with vendors for response and remediation expenses may be significantly higher or lower than the Company has currently estimated. Accordingly, as the Company’s assumptions and estimates may change in future periods based on future events, the Company can provide no assurance that total costs will not materially change in future periods.

The Company’s estimates do not include (i) the nature, extent and cost of future legal services that will be required in connection with all lawsuits, claims and other matters requiring legal or expert advice associated with the Incident, (ii) any lost revenue associated with the suspension of operations at Beta, (iii) any liabilities or costs that are not reasonably estimable at this time or that relate to contingencies where the Company currently regards the likelihood of loss as being only reasonably possible or remote and (iv) the costs associated with the permanent repair of the pipeline and the restart of the Beta operations.

In accordance with customary insurance practice, the Company maintains insurance policies, including loss of production income insurance, against many potential losses or liabilities arising from its operations and at costs that the Company believes to be economic. The Company regularly reviews its risk of loss and the cost and availability of insurance and revises its insurance accordingly. The Company’s insurance does not cover every potential risk associated with its operations and is subject to certain exclusions and deductibles. While the Company expects its insurance policies will cover a material portion of the total aggregate costs associated with the Incident, including but not limited to response and remediation expenses, defense costs and loss of revenue resulting from suspended operations, it can provide no assurance that its coverage will adequately protect it against liability from all potential consequences, damages and losses related to the Incident and such view and understanding is preliminary and subject to change.

On December 31, 2024 and December 31, 2023, the Company’s insurance receivables were $4.7 million and $3.6 million, respectively. Excluding the costs associated with the resolution of the federal and state matters discussed above, the year ended December 31, 2024, the Company incurred response and remediation expenses, legal fees, loss load and other non-reimbursable expenses of $8.0 million. Of these costs, the Company has received or expects that it is probable that it will receive, $4.1 million in insurance recoveries. The remaining amount of $3.9 million, which primarily relates to certain costs that are not expected to be recovered under an insurance policy, are classified as “Pipeline Incident Loss” on the Company’s Consolidated Statements of Operations.

Note 18. Commitments and Contingencies

Litigation and Environmental

As part of our normal business activities, we may be named as defendants in litigation and legal proceedings, including those arising from regulatory and environmental 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, 2024 and 2023, the Company hadno environmental reserves recorded.

Beta Pipeline Incident

Please refer to “Note 17. Beta Pipeline Incident” for details.

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, 2024, the account balance included in restricted investments was approximately $4.5 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, 2024, the Company has funded $25.4 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, 2024 (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, 2024 and 2023, the Company recognized $10.7 million and $10.3 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, 2024, 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, 2024 (in thousands):

Note 19. Income Tax

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

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% in 2024 and in 2023 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 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, 2024, the Company’s federal NOL carryforward of $794.2 million is subject to §382 loss limitations, of which $20.9 million will expire in 2037 and $773.3 million have no expiration. All post-merger NOLs are not subject to §382 loss limitations and do not expire.

As of December 31, 2024, the Company had approximately $422.9 million of state net operating loss carryovers, of which $393.7 million have no expiration period and the remaining will expire in varying amounts beginning 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, 2024, 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, 2024.

*Tax Audits and Settlements.*The Company’s income tax years 2021 through 2023 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 2020 through 2023 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 20. 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, 2024 and 2023. 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:

Note 21. Subsequent Events

On January 14, 2025, the Company entered into an Agreement and Plan of Merger (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 (“Second Merger Sub,” and together with First Merger Sub, the “Merger Subs”), 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, each, an “Acquired Company” and, collectively, the “Acquired Companies”), and, solely for the limited purposes set forth in the Merger Agreement (as defined below), Juniper and the Specified Company Entities set forth on Annex A thereto, pursuant to which, at the effective time of the Mergers (as defined below) (the “Effective Time”), (a) NPOG will merge with and into First Merger Sub, with NPOG surviving the merger as an indirect, wholly owned subsidiary of the Company and (b) COG will 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 (a) and (b), together, the “Mergers”).

Subject to the terms and conditions of the Merger Agreement, at the Effective Time, all of the issued and outstanding limited liability company interests of each of the Acquired Companies will automatically be converted into the right to receive, in the aggregate,26,729,315 validly issued, fully paid and nonassessable shares (the “Aggregate Merger Consideration”) of Amplify’s Common Stock. Following the Effective Time, the Company's existing stockholders and the Acquired Companies' existing equityholders are expected to own approximately 61% and 39%, respectively, of the combined company's outstanding equity.

Mr. Christopher W. Hamm will serve as Chairman of our Board, and Mr. Martyn Willsher will continue to serve as the Chief Executive Officer of the Company after the Effective Time. The Merger Agreement provides that the Board will consist of the following seven members: Martyn Willsher, Christopher W. Hamm, Deborah G. Adams, James E. Craddock, Vidisha Prasad, Edward Geiser and Josh Schmidt. Further, Josh Schmidt will be appointed as Chairman of the compensation committee of the Board, and Edward Geiser will be appointed as a member of the nominating and governance committee of the Board.

The Merger Agreement contains customary representations, warranties and covenants of the Company and the Acquired Companies, including covenants relating to the conduct of the business of both the Company and the Acquired Companies from the date of signing the Merger Agreement through closing of the Mergers (the “Closing”), obtaining the requisite approval of the stockholders of the Company and maintaining the listing of the Common Stock on the NYSE. Under the terms of the Merger Agreement, the Company has also agreed not to solicit from any person an acquisition proposal for the Company.

In connection with the Mergers, the Company will seek the approval of the Company’s stockholders with respect to the issuance of the Aggregate Merger Consideration in connection with the Closing (the “Stock Issuance Proposal”). The Board has agreed to recommend the approval of the Stock Issuance Proposal to our stockholders and to solicit proxies in support of the approval of the Stock Issuance Proposal at a meeting of the stockholders (the “Stockholders Meeting”) to be held for that purpose.

The Closing is subject to various customary closing conditions, including, among other things, (a) the receipt of approval of the Stock Issuance Proposal by the affirmative vote of at least a majority of the votes cast in person or represented by proxy at the Stockholders Meeting by the holders of Common Stock entitled to vote thereon (the “Amplify Stockholder Approval”), (b) the receipt of certain specified consents, and (c) the approval for listing by the NYSE for the shares of Common Stock to be issued in connection with the Mergers.

The Merger Agreement also provides each of the Company and the Acquired Companies with certain termination rights including, among other things, termination: (a) by the Acquired Companies or Amplify Energy if Amplify Energy fails to obtain the Amplify Stockholder Approval; (b) by Amplify Energy or the Acquired Companies, if Amplify Energy or either of the Acquired Companies breaches or fails to perform any of its or their respective representations, warranties or covenants in the Merger Agreement and such breach cannot be or is not timely cured in accordance with the terms of the Merger Agreement and such breach or failure to perform would cause the applicable closing condition not to be satisfied; (c) by the Acquired Companies, in the event the Board effects a Parent Change in Recommendation (as defined in the Merger Agreement) prior to the Amplify Stockholder Approval being obtained or if Amplify Energy is in violation of the covenant to not solicit alternative business combination proposals from third parties in any material respect; or (d) by Amplify Energy, if the Acquired Companies are in violation of the covenant to not solicit alternative business combination proposals from third parties in any material respect.

In the event that a Parent Alternative Proposal (as defined in the Merger Agreement) is publicly submitted or proposed to the Board prior to, and not withdrawn at the time of the Stockholders Meeting, the Merger Agreement is terminated by the Acquired Companies in accordance with clause (b) above or by either Amplify Energy or the Acquired Companies in accordance with clause (a) above or as a result of the failure to close the Mergers on or before July 14, 2025 (the “Outside Date”), and Amplify Energy enters into a definitive agreement with respect to, or consummates, a Parent Alternative Proposal within 12 months following termination of the Merger Agreement, Amplify Energy will be required to pay the Acquired Companies a termination fee of $8,500,000 (the “Amplify Termination Fee”). Amplify Energy will also be required to pay the Acquired Companies the Amplify Termination Fee in the event the Merger Agreement is terminated by the Acquired Companies in accordance with clause (c) above. In the event that Amplify Energy terminates the Merger Agreement in accordance with clause (d) above, the Acquired Companies will be required to (or will cause the Specified Company Entities to) pay Amplify Energy a termination fee of $5,500,000 (the “Acquired Companies’ Termination Fee”). If the Merger Agreement is terminated by any party in accordance with clause (a) or by the Acquired Companies in accordance with clause (b) above and the Amplify Termination Fee is not otherwise payable in accordance with the terms and conditions of the Merger Agreement, then Amplify Energy will be required to reimburse the Acquired Companies’ incurred expenses, up to a maximum aggregate amount of $800,000. If the Merger Agreement is terminated by Amplify Energy in accordance with clause (b) above and the Acquired Companies’ Termination Fee is not otherwise payable in accordance with the terms and conditions of the Merger Agreement, then the Acquired Companies will be required to (or will cause the Specified Company Entities to) reimburse Amplify Energy’s incurred expenses, up to a maximum aggregate amount of $1,250,000. In addition to the foregoing termination rights, the Merger Agreement may be terminated by either Amplify Energy or the Acquired Companies if the Mergers have not been consummated on or prior to the Outside Date or if a governmental entity issues a final, non-appealable order or decree permanently restraining, enjoining or prohibiting the Mergers. The parties may also mutually agree to terminate the Merger Agreement.

If the Board effects a Parent Change in Recommendation prior to the Stockholders Meeting, Amplify Energy will, unless the Acquired Companies terminate the Merger Agreement, be required to submit the approval of the Amplify Stock Issuance to a vote of Amplify Energy’s stockholders at the Stockholders Meeting notwithstanding the Parent Change in Recommendation. Neither Amplify Energy nor the Acquired Companies are able to terminate the Merger Agreement in order to accept an alternative business combination proposal.

The Merger Agreement provides that, during the period from the date of the Merger Agreement until the Effective Time, each of Amplify Energy and the Acquired Companies will be subject to certain restrictions on their ability to solicit or respond to alternative business combination proposals from third parties, to provide non-public information to third parties and to engage in discussions with third parties regarding alternative business combination proposals, subject to customary exceptions.

The Merger Agreement contains customary representations, warranties and covenants for a transaction of this nature. The Merger Agreement also contains customary pre-closing covenants, including the obligations of Amplify Energy and the Acquired Companies to conduct their respective businesses in the ordinary course, consistent with past practice, and to refrain from taking certain specified actions without the consent of the other party.