Amplify Energy (AMPY) 10-K6 Mar 242023 FY Annual reportFinancial data

Company Profile

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
Document and Entity Information - USD ($) $ in Millions	Dec. 31, 2023	Feb. 28, 2024	Jun. 30, 2023
Document and Entity Information
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
Document Transition Report	false
Entity File Number	001-35512
Entity Registrant Name	AMPLIFY ENERGY CORP.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	82-1326219
Entity Address, Address Line One	500 Dallas Street
Entity Address, Address Line Two	Suite 1700
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	832
Local Phone Number	219-9001
Title of 12(b) Security	Common Stock
Trading Symbol	AMPY
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	false
Document Financial Statement Error Correction [Flag]	false
Entity Shell Company	false
Entity Public Float			$ 213.3
Entity Common Stock, Shares Outstanding		39,470,258
Entity Central Index Key	0001533924
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY
Amendment Flag	false
Auditor Name	DELOITTE & TOUCHE LLP
Auditor Firm ID	34
Auditor Location	Houston, Texas
Documents Incorporated by Reference	Documents Incorporated By Reference :

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Current assets:
Cash and cash equivalents	$ 20,746
Accounts receivable, net (see Note 13)	39,096	$ 80,455
Short-term derivative instruments	17,669	0
Prepaid expenses and other current assets	20,672	18,789
Total current assets	98,183	99,244
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method	873,478	840,310
Support equipment and facilities	149,069	147,496
Other	10,359	9,648
Accumulated depreciation, depletion and amortization	(686,165)	(658,162)
Property and equipment, net	346,741	339,292
Long-term derivative instruments	9,405	0
Restricted investments	19,935	11,326
Operating lease - long term right-of-use asset	5,756	7,376
Deferred tax asset	253,796
Other long-term assets	3,858	2,240
Total assets	737,674	459,478
Current liabilities:
Accounts payable	23,616	38,414
Revenues payable	21,944	22,105
Accrued liabilities (see Note 13)	50,871	58,449
Short-term derivative instruments	0	20,884
Total current liabilities	96,431	139,852
Long-term debt (see Note 8)	115,000	190,000
Asset retirement obligations	122,001	114,614
Operating lease liability	5,090	6,567
Other long-term liabilities	8,116	13,010
Total liabilities	346,638	464,043
Commitments and contingencies (see Note 16)
Stockholders' equity (deficit):
Preferred stock, $0.01 par value: 50,000,000 shares authorized; no shares issued and outstanding at December 31, 2023 and December 31, 2022	0	0
Common stock, $0.01 par value: 250,000,000 shares authorized; 39,147,205 and 38,459,731 shares issued and outstanding at December 31, 2023 and December 31, 2022, respectively	393	386
Additional paid-in capital	435,095	432,251
Accumulated deficit	(44,452)	(437,202)
Total stockholders' equity (deficit)	391,036	(4,565)
Total liabilities and equity	$ 737,674	$ 459,478

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2023	Dec. 31, 2022
CONSOLIDATED BALANCE SHEETS
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized (in shares)	50,000,000	50,000,000
Preferred stock, shares issued (in shares)	0	0
Preferred stock, shares outstanding (in shares)	0	0
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	250,000,000	250,000,000
Common stock, shares issued (in shares)	39,147,205	38,459,731
Common stock, shares outstanding (in shares)	39,147,205	38,459,731

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Revenues:
Total revenues	$ 307,596	$ 458,456
Costs and expenses:
Lease operating expense	139,587	131,675
Gathering, processing and transportation	20,808	29,110
Taxes other than income	21,348	33,308
Depreciation, depletion and amortization	28,004	23,950
General and administrative expense	32,984	30,164
Accretion of asset retirement obligations	7,951	7,081
Loss (gain) on commodity derivative instruments	(40,343)	106,937
Pipeline incident loss	19,981	11,277
Pipeline incident settlement		12,000
Other, net	1,060	965
Total costs and expenses	231,380	386,467
Operating income (loss)	76,216	71,989
Other income (expense):
Interest expense, net	(17,719)	(14,101)
Litigation settlement (See Note 16)	84,875
Other income (expense)	399	98
Total other income (expense)	67,555	(14,003)
Income (loss) before income taxes	143,771	57,986
Income tax (expense) benefit - current	(4,817)	(111)
Income tax (expense) benefit - deferred	253,796
Net income (loss)	392,750	57,875
Allocation of net income (loss) to:
Net income (loss) available to common stockholders	375,151	55,147
Net income (loss) allocated to participating securities	17,599	2,728
Net Income (Loss)	$ 392,750	$ 57,875
Earnings (loss) per share: (See Note 10)
Basic earnings (loss) per share	$ 9.63	$ 1.44
Diluted earnings (loss) per share	$ 9.63	$ 1.44
Weighted average common shares outstanding:
Basic	38,961	38,351
Diluted	38,961	38,351
Oil and natural gas sales
Revenues:
Total revenues	$ 288,271	$ 407,761
Other revenues
Revenues:
Total revenues	$ 19,325	$ 50,695

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Cash flows from operating activities:
Net income (loss)	$ 392,750	$ 57,875
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	28,004	23,950
Loss (gain) on derivative instruments	(40,343)	106,002
Cash settlements (paid) received on expired derivative instruments	(8,273)	(147,926)
Cash settlements received (paid) on terminated derivative instruments	658
Deferred income tax expense (benefit)	(253,796)
Accretion of asset retirement obligations	7,951	7,081
Share-based compensation (see Note 11)	5,280	2,964
Settlement of asset retirement obligations	(1,236)	(923)
Amortization and write-off of deferred financing costs	1,980	649
Bad debt expense	98	1
Changes in operating assets and liabilities:
Accounts receivable	41,262	2,815
Prepaid expenses and other assets	(482)	(3,957)
Payables and accrued liabilities	(31,501)	13,812
Other	(762)	2,142
Net cash provided by operating activities	141,590	64,485
Cash flows from investing activities:
Additions to oil and gas properties	(30,667)	(34,814)
Additions to other property and equipment	(711)	(7)
Additions to restricted investments	(8,609)	(6,704)
Other	1,385
Net cash used in investing activities	(38,602)	(41,525)
Cash flows from financing activities:
Advances on Revolving Credit Facility	125,000	5,000
Payments on Revolving Credit Facility	(200,000)	(45,000)
Deferred financing costs	(4,813)	(1,196)
Shares withheld for taxes	(2,429)	(563)
Net cash used in financing activities	(82,242)	(41,759)
Net change in cash and cash equivalents	20,746	(18,799)
Cash and cash equivalents, beginning of period		$ 18,799
Cash and cash equivalents, end of period	$ 20,746

CONSOLIDATED STATEMENTS OF EQUI

CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Thousands	Common Stock	Warrants	Additional Paid-in Capital	Accumulated Earnings (Deficit)	Total
Balance at Dec. 31, 2021	$ 382	$ 4,788	$ 425,066	$ (495,077)	$ (64,841)
Net income (loss)	0	0	0	57,875	57,875
Share-based compensation expense	0	0	2,964	0	2,964
Expiration of warrants	0	(4,788)	4,788	0	0
Shares withheld for taxes	0	0	(563)	0	(563)
Other	4	0	(4)	0	0
Balance at Dec. 31, 2022	386	0	432,251	(437,202)	(4,565)
Net income (loss)	0	0	0	392,750	392,750
Share-based compensation expense	0	0	5,280	0	5,280
Shares withheld for taxes	0	0	(2,429)	0	(2,429)
Other	7	0	(7)	0	0
Balance at Dec. 31, 2023	$ 393	$ 0	$ 435,095	$ (44,452)	$ 391,036

Organization and Basis of Prese

Organization and Basis of Presentation	12 Months Ended
Organization and Basis of Presentation	Dec. 31, 2023
Organization and Basis of Presentation
Organization and Basis of Presentation	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 is listed on the NYSE under the symbol “AMPY.” The Company operates in one reportable segment engaged in the acquisition, development, exploitation and production of oil and natural gas properties. The Company’s management evaluates performance based on one 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.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
Summary of Significant Accounting Policies	Dec. 31, 2023
Summary of Significant Accounting Policies
Summary of Significant Accounting Policies	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 $1.6 million and $1.6 million, respectively, as an allowance for doubtful accounts at December 31, 2023 and 2022. 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: For the Year Ended December 31, 2023 2022 Major customers: HF Sinclair Corporation (formerly: Sinclair Oil & Gas Company) 24 % 23 % Southwest Energy LP 13 % 13 % Phillips 66 17 % n/a % Koch Energy Services, LLC n/a % 13 % 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 of twelve 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 were no material capitalized exploratory drilling costs pending evaluation at December 31, 2023 and 2022. 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, 2023 and 2022. 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 of three 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 Statement of Operations. These restricted investments may consist of money market deposit accounts and U.S. Government securities. See Note 7 and Note 16 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, 2023 and 2022 was approximately $2.0 million and $0.6 million, respectively, as reflected in interest expense, net in the Consolidated Statement 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, 2023 and 2022. 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, 2023 and 2022. 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 6 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 is greater than 50% likely to be realized through effective settlement with a taxing authority. We recognize interest and penalties accrued to unrecognized tax benefits in other income (expense) in our Consolidated Statement of Operations. Although we believe our assumptions, judgments and estimates are reasonable, changes in tax laws or our interpretation of tax laws and the resolution of any tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements. 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 10 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 11 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 12 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 Statement of Operations. For the year ended December 31, 2023 and 2022, the Company recognized LOPI insurance payments of $17.9 million and $50.2 million, respectively, 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. See Note 15 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 15 for additional information regarding the pipeline incident. New Accounting Pronouncements The Company has implemented all new accounting pronouncements that are in effect. These pronouncements did not have any material impact on the financial statements unless otherwise disclosed and the Company does not believe that there are any other new accounting pronouncements that have been issued by the FASB or other standards-setting bodies that are expected to have a material impact on the Company’s financial position, results of operations and cash flows.

Revenue

Revenue	12 Months Ended
Revenue	Dec. 31, 2023
Revenue
Revenue	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. For the Year Ended December 31, 2023 2022 (in thousands) Revenues Oil $ 205,663 $ 212,522 NGLs 29,432 47,398 Natural gas 53,176 147,841 Oil and natural gas sales $ 288,271 $ 407,761 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 $31.1 million and $35.1 million at December 31, 2023 and 2022, respectively. Transaction Price Allocated to Remaining Performance Obligations For the Company’s contracts that have a contract term greater than one 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 of one 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.

Fair Value Measurements of Fina

Fair Value Measurements of Financial Instruments	12 Months Ended
Fair Value Measurements of Financial Instruments	Dec. 31, 2023
Fair Value Measurements of Financial Instruments
Fair Value Measurements of Financial Instruments	Note 4. 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 — Level 2 — Level 3 — 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, 2023 and 2022. 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 8 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, 2023 and 2022 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, 2023 and December 31, 2022 for each of the fair value hierarchy levels: Fair Value Measurements at December 31, 2023 Significant Quoted Prices in Significant Other Unobservable Active Market Observable Inputs Inputs (Level 1) (Level 2) (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 39,439 $ — $ 39,439 Interest rate derivatives — — — — Total assets $ — $ 39,439 $ — $ 39,439 Liabilities: Commodity derivatives $ — $ 12,365 $ — $ 12,365 Interest rate derivatives — — — — Total liabilities $ — $ 12,365 $ — $ 12,365 Fair Value Measurements at December 31, 2022 Significant Quoted Prices in Significant Other Unobservable Active Market Observable Inputs Inputs (Level 1) (Level 2) (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 6,257 $ — $ 6,257 Interest rate derivatives — — — — Total assets $ — $ 6,257 $ — $ 6,257 Liabilities: Commodity derivatives $ — $ 27,141 $ — $ 27,141 Interest rate derivatives — — — — Total liabilities $ — $ 27,141 $ — $ 27,141 See Note 5 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: ● The fair value of asset retirement obligations (“AROs”) is based on discounted cash flow projections using numerous estimates, assumptions, and judgments regarding such factors as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate; and inflation rates. The initial fair value estimates are based on unobservable market data and are classified within Level 3 of the fair value hierarchy. See Note 6 for a summary of changes in AROs. ● If sufficient market data is not available, the determination of the fair values of proved and unproved properties acquired in transactions accounted for as business combinations are prepared by utilizing estimates of discounted cash flow projections. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves; (ii) future operating and development costs; (iii) future commodity prices; and (iv) a market-based weighted average cost of capital. The fair value of supporting equipment, such as plant assets, acquired in transactions accounted for as business combinations is commonly estimated using the depreciated replacement cost approach. ● Proved oil and natural gas properties are reviewed for impairment when events and circumstances indicate the carrying value of such properties may not be recoverable. The Company uses an income approach based on the discounted cash flow method, whereby the present value of expected future net cash flows are discounted by applying an appropriate discount rate, for purposes of placing a fair value on the assets. The future cash flows are based on management’s estimates for the future. The unobservable inputs used to determine fair value include, but are not limited to, estimates of proved reserves, estimates of probable reserves, future commodity prices, the timing of future production and capital expenditures and a discount rate commensurate with the risk reflective of the lives remaining for the respective oil and gas properties (some of which are Level 3 inputs within the fair value hierarchy). (i) No impairment expense on our proved oil and natural gas properties or support equipment was recorded for the year ended December 31, 2023 and 2022.

Risk Management and Derivative

Risk Management and Derivative Instruments	12 Months Ended
Risk Management and Derivative Instruments	Dec. 31, 2023
Risk Management and Derivative Instruments
Risk Management and Derivative Instruments	Note 5. 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 $20.6 million against amounts outstanding under our Revolving Credit Facility at December 31, 2023, reducing our maximum credit exposure to approximately $6.5 million. See Note 8 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, 2023, the Company had the following open commodity positions: 2024 2025 2026 Natural Gas Derivative Contracts: Fixed price swap contracts: Average monthly volume (MMBtu) 662,500 675,000 291,667 Weighted-average fixed price $ 3.72 $ 3.74 $ 3.72 Collar contracts: Two-way collars Average monthly volume (MMBtu) 627,083 500,000 291,667 Weighted-average floor price $ 3.43 $ 3.50 $ 3.50 Weighted-average ceiling price $ 4.32 $ 4.10 $ 4.10 Crude Oil Derivative Contracts: Fixed price swap contracts: Average monthly volume (Bbls) 61,333 53,000 30,917 Weighted-average fixed price $ 73.55 $ 70.68 $ 70.68 Collar contracts: Two-way collars Average monthly volume (Bbls) 102,000 59,500 — Weighted-average floor price $ 70.00 $ 70.00 $ — Weighted-average ceiling price $ 80.20 $ 80.20 $ — 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, 2023 and 2022. There was no 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). Asset Liability Asset Liability Derivatives Derivatives Derivatives Derivatives December 31, December 31, December 31, December 31, Type Balance Sheet Location 2023 2023 2022 2022 (In thousands) Commodity contracts Short-term derivative instruments $ 21,657 $ 3,988 $ 6,257 $ 27,141 Interest rate swaps Short-term derivative instruments — — — — Gross fair value 21,657 3,988 6,257 27,141 Netting arrangements (3,988) (3,988) (6,257) (6,257) Net recorded fair value Short-term derivative instruments $ 17,669 $ — $ — $ 20,884 Commodity contracts Long-term derivative instruments $ 17,782 $ 8,377 $ — $ — Interest rate swaps Long-term derivative instruments — — — — Gross fair value 17,782 8,377 — — Netting arrangements (8,377) (8,377) — — Net recorded fair value Long-term derivative instruments $ 9,405 $ — $ — $ — (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): For the Year Ended Statements of December 31, Operations Location 2023 2022 Commodity derivative contracts Loss (gain) on commodity derivatives $ (40,343) $ 106,937 (Gain) loss on interest rate derivatives Interest expense, net — (935)

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
Asset Retirement Obligations	Dec. 31, 2023
Asset Retirement Obligations
Asset Retirement Obligations	Note 6. 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, 2023 and 2022 (in thousands): For the Year Ended December 31, 2023 2022 Asset retirement obligations at beginning of period $ 116,438 $ 103,414 Liabilities added from acquisition or drilling 5 20 Liabilities settled (1,236) (923) Liabilities removed upon sale of wells — — Accretion expense 7,951 7,081 Revision of estimates 336 6,846 Asset retirement obligation at end of period 123,494 116,438 Less: Current portion 1,493 1,824 Asset retirement obligations - long-term portion $ 122,001 $ 114,614

Restricted Investments

Restricted Investments	12 Months Ended
Restricted Investments	Dec. 31, 2023
Restricted Investments
Restricted Investments	Note 7. 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: December 31, 2023 2022 (In thousands) BOEM platform abandonment (See Note 16) $ 15,509 $ 7,016 SPBPC Collateral: Contractual pipeline and surface facilities abandonment 4,426 4,310 Restricted investments $ 19,935 $ 11,326

Debt

Debt	12 Months Ended
Debt	Dec. 31, 2023
Debt
Debt	Note 8. Debt The Company’s consolidated debt obligations consisted of the following at the dates indicated: December 31, December 31, 2023 2022 (In thousands) Revolving Credit Facility (1) $ 115,000 $ 190,000 Total long-term debt $ 115,000 $ 190,000 (1) The carrying amount of the Company’s Revolving Credit Facility approximates fair value because the interest rates are variable and reflective of market rates. 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, 2023, was $115.0 million. The borrowing base under the facility is $150.0 million with elected commitments of $135.0 million. Consistent with the Prior Revolving Credit Facility, 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): ● A maturity date of July 31, 2027; ● The loans shall bear interest at a rate per annum equal to (i) adjusted SOFR or (ii) an adjusted base rate, plus an applicable margin based on a utilization ratio of the lesser of the borrowing base and the aggregate commitments. The applicable margin ranges from 2.00% to 3.00% for adjusted base rate borrowings, and 3.00% to 4.00% for adjusted SOFR borrowings; ● The unused commitments under the facility will accrue a commitment fee of 0.50% , payable quarterly in arrears; ● Certain financial covenants, including the maintenance of (i) a net debt leverage ratio not to exceed 3.00 to 1.00, determined as of the last day of each fiscal quarter for the four fiscal-quarter period then ending and (ii) a current ratio of not less than 1.00 to 1.00 , determined as of the last day of each fiscal quarter, in each case commencing with the fiscal quarter ending December 31, 2023; ● Certain events of default, including, without limitation: non-payment; breaches of representations and warranties; non-compliance with covenants or other agreements; cross-default to material indebtedness; judgments; change of control; and voluntary and involuntary bankruptcy; and ● Initial minimum hedging requirements covering 75% of the reasonably projected monthly production of hydrocarbons from proved developed producing reserves for the 24-month period following the effective date of the Revolving Credit Facility (the “First Period”) and (ii) 50% for the 12-month period immediately following the First Period. On October 19, 2023, OLLC completed the regularly scheduled semi-annual redetermination of its borrowing base, which was reaffirmed at $150.0 million with elected commitments of $135.0 million. The next redetermination is expected to occur in the second quarter of 2024. Debt Compliance As of December 31, 2023, 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: For the Year Ended December 31, 2023 2022 Revolving Credit Facility 9.35 % 5.36 % Letters of credit At December 31, 2023, the Company had no letters of credit outstanding. Unamortized Deferred Financing Costs Unamortized deferred financing costs associated with the Revolving Credit Facility was $4.4 million at December 31, 2023. 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, 2023, the Company wrote off $1.0 million of deferred financing costs in connection with the refinancing of the Revolving Credit Facility.

Equity (Deficit)

Equity (Deficit)	12 Months Ended
Equity (Deficit)	Dec. 31, 2023
Equity (Deficit)
Equity (Deficit)	Note 9. 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: Common Stock Balance, December 31, 2021 38,024,142 Issuance of common stock — Restricted stock units vested 534,834 Shares withheld for taxes (1) (99,245) Balance, December 31, 2022 38,459,731 Issuance of common stock — Restricted stock units vested 967,374 Shares withheld for taxes (1) (279,900) Balance, December 31, 2023 39,147,205 (1) Represents the net settlement on vesting of restricted stock to satisfy the tax withholding requirements. Warrants Legacy Amplify entered into a warrant agreement (the “Warrant Agreement”) with American Stock Transfer & Trust Company, LLC, as warrant agent (“AST”), pursuant to which Legacy Amplify issued warrants to purchase up to 2,173,913 shares of Legacy Amplify’s common stock (representing 8% of Legacy Amplify’s outstanding common stock on May 4, 2017, including shares of Legacy Amplify’s common stock issuable upon full exercise of the warrants, but excluding any common stock issuable under the Legacy Amplify’s Management Incentive Plan (the “Legacy Amplify MIP”), exercisable for a five year period commencing on May 4, 2017 at an exercise price of $42.60 per share. The warrants expired on May 4, 2022.

Earnings (Loss) per Share

Earnings (Loss) per Share	12 Months Ended
Earnings (Loss) per Share	Dec. 31, 2023
Earnings (Loss) per Share
Earnings (Loss) per Share	Note 10. 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): For the Year Ended December 31, 2023 2022 Net income (loss) $ 392,750 $ 57,875 Less: Net income allocated to participating securities 17,599 2,728 Basic and diluted earnings available to common stockholders $ 375,151 $ 55,147 Common shares: Common shares outstanding — basic 38,961 38,351 Dilutive effect of potential common shares — — Common shares outstanding — diluted 38,961 38,351 Net earnings (loss) per share: Basic $ 9.63 $ 1.44 Diluted $ 9.63 $ 1.44

Equity-based Awards

Equity-based Awards	12 Months Ended
Equity-based Awards	Dec. 31, 2023
Equity-based Awards
Equity-based Awards	Note 11. 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. EIP awards and Legacy Amplify MIP awards are 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 under the EIP or Legacy Amplify MIP is expired, forfeited or canceled for any reason without having been exercised in full, the unexercised award would then be available again for future grants under the EIP. The EIP is administered by the board of directors of the Company. At December 31, 2023, the Company had 857,177 shares remaining available for issuance under the 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. 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. Compensation costs are recorded as general and administrative expense. New director awards granted after the effectiveness of the EIP in May 2021 are reflected below within the TSUs awards table. The unrecognized cost associated with TSUs was $4.5 million at December 31, 2023. 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: Weighted- Average Grant- Number of Date Fair Value Units per Unit (1) TSUs outstanding at December 31, 2021 1,074,420 $ 3.66 Granted (2) 963,027 $ 4.05 Forfeited (52,485) $ 4.30 Vested (482,406) $ 3.85 TSUs outstanding at December 31, 2022 1,502,556 $ 3.82 Granted (3) 713,689 $ 8.07 Forfeited (72,095) $ 6.05 Vested (812,694) $ 4.16 TSUs outstanding at December 31, 2023 1,331,456 $ 5.77 (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. (2) The aggregate grant date fair value of TSUs issued for the year ended December 31, 2022 was $3.9 million based on a grant date market price ranging from $3.64 to $6.99 per share. (3) The aggregate grant date fair value of TSUs issued for the year ended December 31, 2023 was $5.8 million based on a grant date market price ranging from $6.52 to $8.91 per share. Restricted Stock Units with Market and Service Vesting Conditions Restricted stock units with market and service vesting conditions (“PSUs” or “PRSUs”) are accounted for as equity-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 $2.3 million at December 31, 2023. The Company expects to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 2.0 years. 2021 PRSU Awards The 2021 PRSU awards were issued collectively in separate tranches with individual performance periods beginning on January 1, 2021. For each of the performance periods, the awards will vest based on the percentage of the target PRSUs subject to the performance vesting condition, with 25% able to vest during the performance period of January 1, 2021 through December 31, 2021; 25% able to vest during the period January 1, 2021 through December 31, 2022 and 50% able to vest during the period of January 1, 2021 through December 31, 2023. 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. 2022 and 2023 PRSU Awards The 2022 and 2023 PRSU awards were issued with a three-year vesting period beginning on the grant date and ending on the third anniversary of the grant date. The three-year performance period for the 2022 awards is January 1, 2022 through December 31, 2024. The three-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. The below table reflects the ranges for the assumptions used in the Monte Carlo model for the 2022 and 2023 PRSUs awards: April 2023 February 2023 2022 Expected volatility 92.5 % 119.2 % 120.8 % Dividend yield 0.00 % 0.00 % 0.00 % Risk-free interest rate 3.78 % 3.74 % 1.38 % The following table summarizes information regarding the PSUs and PRSUs granted under the EIP for the period presented: Weighted- Average Grant- Number of Date Fair Value Units per Unit (1) PSUs and PRSUs outstanding at December 31, 2021 262,317 $ 2.14 Granted (2) 189,904 $ 6.20 Forfeited (22,614) $ 2.57 Vested (49,095) $ 1.24 PSUs and PRSUs outstanding at December 31, 2022 380,512 $ 4.28 Granted (3) 321,436 $ 10.59 Forfeited (144,567) $ 6.55 Vested (154,680) $ 2.20 PSUs and PRSUs outstanding at December 31, 2023 402,701 $ 9.31 (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. (2) The aggregate grant date fair value of PRSUs issued for the year ended December 31, 2022 was $1.2 million based on a calculated fair value price at $6.20 per share. (3) The aggregate grant date fair value of PRSUs issued for the year ended December 31, 2023 was $3.4 million based on a calculated fair value price ranging from $1.27 to $15.04 per share. 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): For the Year Ended December 31, 2023 2022 Equity classified awards TSUs $ 4,336 $ 2,648 PSUs and PRSUs 944 440 Board RSUs — 5 $ 5,280 $ 3,093

Leases

Leases	12 Months Ended
Leases	Dec. 31, 2023
Leases
Leases	Note 12. 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, 2023, 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 our leases 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, 2023 and 2022, the Company recognized approximately $2.1 million and $1.6 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: December 31, December 31, 2023 2022 (In thousands) Right-of-use asset $ 5,756 $ 7,376 Lease liabilities: Current lease liability 1,737 1,401 Long-term lease liability 5,090 6,567 Total lease liability $ 6,827 $ 7,968 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): Office and Leased vehicles warehouse and office leases equipment Total 2024 $ 1,417 $ 762 $ 2,179 2025 1,417 550 1,967 2026 1,197 64 1,261 2027 830 — 830 2028 and thereafter 1,786 — 1,786 Total lease payments 6,647 1,376 8,023 Less: interest 1,098 98 1,196 Present value of lease liabilities $ 5,549 $ 1,278 $ 6,827 The weighted average remaining lease terms and discount rate for all of the Company’s operating leases for the period presented: December 31, 2023 2022 Weighted average remaining lease term (years): Office and warehouse space 4.28 4.71 Vehicles 0.42 0.47 Office equipment 0.01 0.04 Weighted average discount rate: Office and warehouse space 5.22 % 4.87 % Vehicles 1.22 % 1.30 % Office equipment 0.07 % 0.11 %

Supplemental Disclosures to the

Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows	12 Months Ended
	Dec. 31, 2023
Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows
Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows	Note 13. 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): December 31, December 31, 2023 2022 Accrued lease operating expense $ 14,239 $ 11,226 Accrued liability - pipeline incident 9,331 20,832 Accrued liability - current portion of pipeline incident settlement 2,000 4,888 Accrued capital expenditures 8,019 2,714 Accrued general and administrative expense 5,335 4,943 Accrued production and ad valorem tax 3,502 4,675 Accrued commitment fee and other expense 2,626 5,824 Operating lease liability 1,737 1,401 Asset retirement obligations 1,493 1,824 Accrued interest payable 1,792 87 Other 797 35 Accrued liabilities $ 50,871 $ 58,449 Accounts Receivable Accounts receivable consisted of the following at the dates indicated (in thousands): December 31, December 31, 2023 2022 Oil and natural gas receivables $ 31,131 $ 35,083 Insurance receivable - pipeline incident 3,571 41,961 Joint interest owners and other 6,042 5,047 Total accounts receivable 40,744 82,091 Less: allowance for doubtful accounts (1,648) (1,636) Total accounts receivable, net $ 39,096 $ 80,455 Supplemental Cash Flows Supplemental cash flow for the periods presented (in thousands): For the Year Ended December 31, 2023 2022 Supplemental cash flows: Cash paid for interest, net of amounts capitalized $ 10,992 $ 11,209 Cash paid for taxes 5,773 93 Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities 6,786 1,012

Related Party Transactions

Related Party Transactions	12 Months Ended
Related Party Transactions	Dec. 31, 2023
Related Party Transactions
Related Party Transactions	Note 14. Related Party Transactions Related Party Agreements There have been no 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, 2023 and 2022.

Beta Pipeline Incident

Beta Pipeline Incident	12 Months Ended
Beta Pipeline Incident	Dec. 31, 2023
Beta Pipeline Incident
Beta Pipeline Incident	Note 15. 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, which was reviewed and approved by the Bureau of Safety and Environmental Enforcement’s (the “BSEE”) Oil Spill Preparedness Division within the United States Department of the Interior, and which included the required notifications of specified regulatory agencies. 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, which was below the previously reported maximum estimate of 3,134 barrels. 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. In response to the Incident, all operations were suspended and the pipeline was shut-in pending the Company’s receipt of the required regulatory approvals to restart operations. On October 4, 2021, the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), Office of Pipeline Safety issued a Corrective Action Order pursuant to 49 U.S.C. § 60112, which makes clear that no restart of the affected pipeline may occur until PHMSA has approved a written restart plan. On April 10, 2023, the Company announced that it has 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. On December 15, 2021, a federal grand jury in the Central District of California returned a federal criminal indictment against Amplify Energy Corp., Beta Operating Company, LLC, and San Pedro Bay Pipeline Company in connection with the Incident. The indictment alleges that the Company committed a misdemeanor violation of the federal Clean Water Act for negligently discharging oil into the contiguous zone of the United States. As previously disclosed, state authorities were conducting parallel criminal investigations. The Company has reached court-approved agreements to resolve all criminal matters stemming from the Incident. Specifically, on August 26, 2022, as part of the resolution with the United States, the Company agreed to plead guilty to one count of misdemeanor negligent discharge of oil in violation of the Clean Water Act. The Company will pay a fine of approximately $7.1 million in installments over a period of three years, serve a term of four years’ probation and reimburse governmental agencies approximately $5.8 million for their response to this event. Further, on September 8, 2022, as part of the resolution with the state of California, the Company agreed to enter a plea of No Contest to six misdemeanor charges. The Company will pay a fine in the amount of $4.9 million to be distributed among the state of California, including the State’s Fish and Game Preservation Fund, and Orange County. The Company will serve a one-year term of probation and has agreed to certain compliance enhancements to its operations. The Company is currently subject to a number of ongoing investigations related to the Incident by certain federal and state agencies. To date, the U.S. Coast Guard, the U.S. Bureau of Ocean Energy Management, the U.S. Department of Justice, PHMSA, the U.S. Department of the Interior Bureau of Safety and Environmental Enforcement, the National Transportation Safety Board, the California Department of Justice, the Orange County District Attorney, the Los Angeles County District Attorney, and the California Department of Fish & Wildlife have conducted or are conducting investigations or examinations of the Incident. On April 8, 2022, in light of the allegations raised in the December 15, 2021 federal indictment, the Company received a Show Cause Notice from the EPA asking the Company to provide information as to why it should not be suspended from participating in future federal contracting pursuant to 2 C.F.R. § 180.700(a), (c) and 2 C.F.R. § 180.800(a)(4). On April 22, 2022, the Company responded to the Show Cause Notice. On September 9, 2022, the EPA informed the Company’s counsel that the EPA has administratively closed the case at this time, and as such, the Company is no longer under a Show Cause Notice. On April 6, 2023, PHMSA provided the Company notice of PHMSA’s positions regarding “probable violations of the Pipeline Safety Regulations” in connection with the Incident; the Company has responded to that notice and is conferring with PHMSA about it. Other 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. The Company, Beta Operating Company, LLC, and San Pedro Bay Pipeline Company were named as defendants in a consolidated putative class action in the United States District Court for the Central District of California. Plaintiffs filed a consolidated class action complaint on January 28, 2022 and an amended complaint on March 21, 2022. Plaintiffs asserted claims against the Company, Beta Operating Company, LLC, San Pedro Bay Pipeline Company, MSC Mediterranean Shipping Company, Dordellas Finance Corp., the MSC Danit (proceeding in rem), Costamare Shipping Co. S.A., Capetanissa Maritime Corporation of Liberia, V.Ships Greece Ltd., and the COSCO Beijing (proceeding in rem). The Company filed a third-party complaint on February 28, 2022, an amended complaint on June 21, 2022, and second amended complaint on October 5, 2022. The Company sued the same shipping defendants as had Plaintiffs and added claims against the Marine Exchange, COSCO Shipping Lines Co. Ltd., COSCO (Cayman) Mercury Co. Ltd., Mediterranean Shipping Company S.r.l., and MSC Shipmanagement Limited. MSC Mediterranean Shipping Company, Dordellas Finance Corp., and Capetanissa Maritime Corporation of Liberia also filed petitions for limitations of liability under maritime law in the United States District Court for the Central District of California. The court consolidated the limitation actions into a single limitation action and also coordinated discovery between the consolidated limitation and the consolidated class actions. On April 17, 2023, the Court stayed the Limitation Action pending the documentation and approval of certain settlements expected to fully resolve the Limitation Action. The Limitation Action has subsequently been resolved. On August 25, 2022, the Company reached an agreement in principle with plaintiffs in the class action to resolve all civil claims against it and its subsidiaries. The settlement of $50.0 million, which also includes certain injunctive relief, will be funded under the Company’s insurance policies. The Court preliminarily approved the settlement on December 7, 2022 and granted final approval on April 24, 2023. On March 1, 2023, the Company announced that the vessels that struck and damaged the pipeline and their respective owners and operators agreed to pay the Company $96.5 million in a settlement. The Marine Exchange agreed to non-monetary terms as well. The overall resolution included subrogation claims by Amplify’s property damage and loss of production insurers, with Amplify ultimately receiving a net payment of approximately $85.0 million. The settlement resolves Amplify’s affirmative claims related to the Incident. As part of the settlement, Amplify has dismissed its legal claims against those parties. Under the 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 is currently processing covered claims under OPA 90 as expeditiously as possible. 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, 2023 and December 31, 2022, the Company’s insurance receivables were $3.6 million and $42.0 million, respectively. Excluding the costs associated with the resolution of the federal and state matters discussed above, the year ended December 31, 2023, the Company incurred response and remediation expenses and legal fees of $29.3 million. Of these costs, the Company has received or expects that it is probable that it will receive, $9.3 million in insurance recoveries. The remaining amount of $20.0 million, which primarily relates to certain legal 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. Additionally, for the year ended December 31, 2023 and 2022, the Company recognized $17.9 million and $50.2 million, respectively, related to approved LOPI insurance claims, which is classified as “Other Revenues” in the Company’s Consolidated Statement of Operations.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
Commitments and Contingencies	Dec. 31, 2023
Commitments and Contingencies.
Commitments and Contingencies	Note 16. 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, 2023 and 2022, the Company had no environmental reserves recorded. Beta Pipeline Incident Please refer to “Note 15. 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, 2023, the account balance included in restricted investments was approximately $4.4 million. Supplemental Bond for Decommissioning Liabilities Trust Agreement Beta Operating Company, LLC has an obligation with the 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 into two escrow funding agreements 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. The obligation ceases when the aggregate value of the account reaches $172.6 million. As of December 31, 2023, the Company has funded $15.2 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, 2023 (in thousands): Payment Due by Period Funding commitment Total 2024 2025 2026 2027 2028 Thereafter (1) Sinking fund payments $ 157,888 $ 15,789 $ 15,789 $ 15,789 $ 15,789 $ 15,789 $ 78,943 (1) The remaining payments will be made during the years of 2029 through 2033. 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, 2023 and 2022, the Company recognized $10.3 million and $8.7 million of rental cost, respectively. See Note 12 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, 2023, the Company had a CO 2 2 2 Payment or Settlement Due by Period Purchase commitment Total 2024 2025 2026 2027 2028 Thereafter CO 2 $ 7,907 $ 4,006 $ 3,901 $ — $ — $ — $ — Minimum Volume Commitment The Company had a long-term minimum volume commitment with a third party associated with a certain portion of its properties located in Oklahoma. The Company was party to a gathering and processing contract in Oklahoma, which included certain minimum NGL commitments. To the extent the Company did not deliver natural gas volumes in sufficient quantities to generate, when processed, the minimum levels of recovered NGLS, it was required to reimburse the counterparty an amount equal to the sum of the monthly shortfall, if any, multiplied by a fee. The commitment fee expense for the year ended December 31, 2023 and 2022, was approximately $0.3 million and $1.8 million, respectively. The minimum volume commitment for Oklahoma ended on June 30, 2023.

Income Taxes

Income Taxes	12 Months Ended
Income Taxes	Dec. 31, 2023
Income Taxes
Income Taxes	Note 17. 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: For the Year Ended December 31, 2023 2022 (In thousands) Current taxes: Federal $ (4,286) $ — State (531) (111) Total current income tax benefit (expense) (4,817) (111) Deferred taxes: Federal 232,351 — State 21,445 — Total deferred income tax benefit (expense) 253,796 — Total income tax benefit (expense) $ 248,979 $ (111) The actual income tax benefit (expense) differs from the expected amount computed by applying the federal statutory corporate tax rate of 21% in 2023 and in 2022 as follows: For the Year Ended December 31, 2023 2022 (In thousands) Expected tax benefit (expense) at federal statutory rate $ (30,192) $ (12,177) Changes in valuation allowances 284,927 12,267 Federal prior year adjustments — 1,673 Fines & penalties — (1,939) State income tax benefit (expense), net of federal benefit (2,430) (1,859) State rate change, net of federal benefit (2,541) 1,532 State prior year adjustment (380) (234) Other (405) 626 Total income tax benefit (expense) $ 248,979 $ (111) 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): December 31, 2023 2022 Deferred income tax assets: Property, plant & equipment $ 69,895 $ 82,152 Net operating loss carryforward 179,627 183,050 Derivatives — 4,800 Disallowed interest expense 5,580 7,467 Accrued liabilities 2,180 2,008 Other 4,093 7,103 Total deferred income tax assets: 261,375 286,580 Valuation allowance — (284,928) Net deferred income tax assets 261,375 1,652 Deferred income tax liabilities: Derivatives $ 6,319 $ — Other 1,260 1,652 Total deferred income tax liabilities 7,579 1,652 Net deferred income taxes $ 253,796 $ — Net Operating Loss Carryforward. As of December 31, 2023, the Company had approximately $432.0 million of state net operating loss carryovers, of which $401.5 million have no expiration period and the remaining will expire in varying amounts beginning in 2037. Valuation Allowance Uncertain Income Tax Position. Tax Audits and Settlements.

Supplemental Oil and Gas Inform

Supplemental Oil and Gas Information (Unaudited)	12 Months Ended
Supplemental Oil and Gas Information (Unaudited)	Dec. 31, 2023
Supplemental Oil and Gas Information (Unaudited)
Supplemental Oil and Gas Information (Unaudited)	Note 18. 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. December 31, 2023 2022 (In thousands) Evaluated oil and natural gas properties $ 873,478 $ 840,310 Support equipment and facilities 149,069 147,496 Accumulated depletion, depreciation, and amortization (676,573) (648,900) Total $ 345,974 $ 338,906 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: For the Year Ended December 31, 2023 2022 (In thousands) Property acquisition costs, proved $ — $ — Property acquisition costs, unproved — — Exploration — — Development 34,742 42,949 Total $ 34,742 $ 42,949 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, 2023 and 2022. 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: 2023 2022 Oil ($/Bbl): WTI (1) $ 78.22 $ 93.67 NGL ($/Bbl): WTI (1) $ 78.22 $ 93.67 Natural Gas ($/MMbtu): Henry Hub (2) $ 2.64 $ 6.36 (1) The weighted average WTI price was adjusted by lease for quality, transportation fees, and a regional price differential. (2) The weighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials. The following tables set forth estimates of the net reserves for the periods indicated: For the Year Ended December 31, 2023 Oil Gas NGLs Total (MBbls) (MMcf) (MBbls) (MBoe) Proved developed and undeveloped reserves: Beginning of year 47,868 312,792 24,026 124,027 Production (2,773) (20,297) (1,323) (7,479) Revision of previous estimates (4,017) (65,617) (3,518) (18,471) End of year 41,078 226,878 19,185 98,077 Proved developed reserves: Beginning of year 47,010 312,185 23,928 122,969 End of year 39,306 226,427 19,108 96,151 Proved undeveloped reserves: Beginning of year 858 607 98 1,058 End of year 1,772 451 77 1,926 For the Year Ended December 31, 2022 Oil Gas NGLs Total (MBbls) (MMcf) (MBbls) (MBoe) Proved developed and undeveloped reserves: Beginning of year 45,001 314,350 23,837 121,230 Production (2,327) (22,993) (1,389) (7,548) Revision of previous estimates 5,194 21,435 1,578 10,345 End of year 47,868 312,792 24,026 124,027 Proved developed reserves (1) : Beginning of period 43,857 309,794 23,574 119,063 End of period 47,010 312,185 23,928 122,969 Proved undeveloped reserves (2) : Beginning of period 1,144 4,556 263 2,167 End of period 858 607 98 1,058 (1) Our reserves related to our Beta properties were reclassified as proved developed non-producing at December 31, 2022. (2) Change to the Company’s development plan has resulted in removal of PUD locations in Oklahoma, Bairoil and Beta. Noteworthy amounts included in the categories of proved reserve changes in the above tables include: ● The 26.0 MMBoe decrease in reserves for the year ended December 31, 2023 is primarily due to production of 7.5 MMBoe, a 17.8 MMBoe decrease as a result of changes in commodity prices and 2.5 MMBoe decrease due to higher maintenance costs. This decrease was partially offset by the addition of 4 Beta PUD locations budgeted in 2024, which added 1.1 MMBoe and a positive technical revision of 0.7 MMBoe. ● The 2.8 MMBoe increase in reserves for the year ended December 31, 2022 is primarily due to 14.2 MMBoe increase as a result of changes in commodity prices. The Company also had a 4.1 MMBoe reduction due to higher maintenance costs and a 0.2 MMBoe upward technical revision. The Company had production of 7.5 MMBoe for the year ended December 31, 2022. 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: For the Year Ended December 31, 2023 2022 (In thousands) Future cash inflows $ 4,277,014 $ 7,373,499 Future production costs (1) (2,751,065) (3,824,348) Future development costs (1) (313,290) (309,188) Future income tax expense (203,770) (520,731) Future net cash flows for estimated timing of cash flows 1,008,889 2,719,232 10% annual discount for estimated timing of cash flows (382,759) (1,381,276) Standardized measure of discounted future net cash flows $ 626,130 $ 1,337,956 (1) For the years ended December 31, 2023 and 2022, onshore abandonment costs are included in future production cost and offshore abandonment costs are included in future development costs. 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: For the Year Ended December 31, 2023 2022 (In thousands) Beginning of year $ 1,337,956 $ 919,845 Changes in prices and costs (798,942) 856,545 Revisions of previous quantities (196,093) 59,216 Sale of oil and natural gas produced, net of production costs (106,469) (213,667) Net change in taxes 180,530 (311,412) Accretion of discount 164,937 91,985 Change in production rates and other 38,174 (57,484) Net changes in future development costs (3,669) (20,129) Previously estimated development costs incurred 9,706 13,057 End of year $ 626,130 $ 1,337,956

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2023
Summary of Significant Accounting Policies
General	General Amplify Energy Corp. (“Amplify Energy” or the “Company”), is a publicly traded Delaware corporation, in which our common stock is listed on the NYSE under the symbol “AMPY.” The Company operates in one reportable segment engaged in the acquisition, development, exploitation and production of oil and natural gas properties. The Company’s management evaluates performance based on one 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	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.
Use of Estimates	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 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	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 $1.6 million and $1.6 million, respectively, as an allowance for doubtful accounts at December 31, 2023 and 2022. 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: For the Year Ended December 31, 2023 2022 Major customers: HF Sinclair Corporation (formerly: Sinclair Oil & Gas Company) 24 % 23 % Southwest Energy LP 13 % 13 % Phillips 66 17 % n/a % Koch Energy Services, LLC n/a % 13 %
Oil and Natural Gas Properties	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 of twelve 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 were no material capitalized exploratory drilling costs pending evaluation at December 31, 2023 and 2022.
Oil and Natural Gas Reserves	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, 2023 and 2022. 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 & 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 of three
Restricted Investments	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 Statement of Operations. These restricted investments may consist of money market deposit accounts and U.S. Government securities. See Note 7 and Note 16 for additional information.
Debt Issuance Costs	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, 2023 and 2022 was approximately $2.0 million and $0.6 million, respectively, as reflected in interest expense, net in the Consolidated Statement of Operations.
Impairments	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, 2023 and 2022. 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, 2023 and 2022.
Asset Retirement Obligations	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 6 for further discussion of asset retirement obligations.
Revenue Recognition	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	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	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 is greater than 50% likely to be realized through effective settlement with a taxing authority. We recognize interest and penalties accrued to unrecognized tax benefits in other income (expense) in our Consolidated Statement of Operations. Although we believe our assumptions, judgments and estimates are reasonable, changes in tax laws or our interpretation of tax laws and the resolution of any tax audits could significantly impact the amounts provided for income taxes in our consolidated financial statements.
Earnings (loss) Per Share	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 10 for additional information.
Equity Compensation	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 11 for further information.
Lease Recognition	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 12 for additional information regarding leases.
Loss of Production Income Insurance	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 Statement of Operations. For the year ended December 31, 2023 and 2022, the Company recognized LOPI insurance payments of $17.9 million and $50.2 million, respectively, 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. See Note 15 for additional information regarding the pipeline incident.
Insurance Coverage	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 15 for additional information regarding the pipeline incident.
New Accounting Pronouncements	New Accounting Pronouncements The Company has implemented all new accounting pronouncements that are in effect. These pronouncements did not have any material impact on the financial statements unless otherwise disclosed and the Company does not believe that there are any other new accounting pronouncements that have been issued by the FASB or other standards-setting bodies that are expected to have a material impact on the Company’s financial position, results of operations and cash flows.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
Summary of Significant Accounting Policies (Tables)	Dec. 31, 2023
Summary of Significant Accounting Policies
Major Customers	The following individual customers each accounted for 10% or more of total reported revenues for the period indicated: For the Year Ended December 31, 2023 2022 Major customers: HF Sinclair Corporation (formerly: Sinclair Oil & Gas Company) 24 % 23 % Southwest Energy LP 13 % 13 % Phillips 66 17 % n/a % Koch Energy Services, LLC n/a % 13 %

Revenue (Tables)

Revenue (Tables)	12 Months Ended
Revenue (Tables)	Dec. 31, 2023
Revenue
Summary of Revenues Disaggregated	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. For the Year Ended December 31, 2023 2022 (in thousands) Revenues Oil $ 205,663 $ 212,522 NGLs 29,432 47,398 Natural gas 53,176 147,841 Oil and natural gas sales $ 288,271 $ 407,761

Fair Value Measurements of Fi_2

Fair Value Measurements of Financial Instruments (Tables)	12 Months Ended
Fair Value Measurements of Financial Instruments (Tables)	Dec. 31, 2023
Fair Value Measurements of Financial Instruments
Assets and Liabilities Measured at Fair Value on Recurring Basis	Fair Value Measurements at December 31, 2023 Significant Quoted Prices in Significant Other Unobservable Active Market Observable Inputs Inputs (Level 1) (Level 2) (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 39,439 $ — $ 39,439 Interest rate derivatives — — — — Total assets $ — $ 39,439 $ — $ 39,439 Liabilities: Commodity derivatives $ — $ 12,365 $ — $ 12,365 Interest rate derivatives — — — — Total liabilities $ — $ 12,365 $ — $ 12,365 Fair Value Measurements at December 31, 2022 Significant Quoted Prices in Significant Other Unobservable Active Market Observable Inputs Inputs (Level 1) (Level 2) (Level 3) Fair Value (In thousands) Assets: Commodity derivatives $ — $ 6,257 $ — $ 6,257 Interest rate derivatives — — — — Total assets $ — $ 6,257 $ — $ 6,257 Liabilities: Commodity derivatives $ — $ 27,141 $ — $ 27,141 Interest rate derivatives — — — — Total liabilities $ — $ 27,141 $ — $ 27,141

Risk Management and Derivativ_2

Risk Management and Derivative Instruments (Tables)	12 Months Ended
Risk Management and Derivative Instruments (Tables)	Dec. 31, 2023
Risk Management and Derivative Instruments
Open Commodity Positions	At December 31, 2023, the Company had the following open commodity positions: 2024 2025 2026 Natural Gas Derivative Contracts: Fixed price swap contracts: Average monthly volume (MMBtu) 662,500 675,000 291,667 Weighted-average fixed price $ 3.72 $ 3.74 $ 3.72 Collar contracts: Two-way collars Average monthly volume (MMBtu) 627,083 500,000 291,667 Weighted-average floor price $ 3.43 $ 3.50 $ 3.50 Weighted-average ceiling price $ 4.32 $ 4.10 $ 4.10 Crude Oil Derivative Contracts: Fixed price swap contracts: Average monthly volume (Bbls) 61,333 53,000 30,917 Weighted-average fixed price $ 73.55 $ 70.68 $ 70.68 Collar contracts: Two-way collars Average monthly volume (Bbls) 102,000 59,500 — Weighted-average floor price $ 70.00 $ 70.00 $ — Weighted-average ceiling price $ 80.20 $ 80.20 $ —
Gross Fair Value of Derivative Instruments by Appropriate Balance Sheet	Asset Liability Asset Liability Derivatives Derivatives Derivatives Derivatives December 31, December 31, December 31, December 31, Type Balance Sheet Location 2023 2023 2022 2022 (In thousands) Commodity contracts Short-term derivative instruments $ 21,657 $ 3,988 $ 6,257 $ 27,141 Interest rate swaps Short-term derivative instruments — — — — Gross fair value 21,657 3,988 6,257 27,141 Netting arrangements (3,988) (3,988) (6,257) (6,257) Net recorded fair value Short-term derivative instruments $ 17,669 $ — $ — $ 20,884 Commodity contracts Long-term derivative instruments $ 17,782 $ 8,377 $ — $ — Interest rate swaps Long-term derivative instruments — — — — Gross fair value 17,782 8,377 — — Netting arrangements (8,377) (8,377) — — Net recorded fair value Long-term derivative instruments $ 9,405 $ — $ — $ —
Unrealized and Realized Gains and Losses Related to Derivative Instruments	The following table details the gains and losses related to derivative instruments for the periods indicated (in thousands): For the Year Ended Statements of December 31, Operations Location 2023 2022 Commodity derivative contracts Loss (gain) on commodity derivatives $ (40,343) $ 106,937 (Gain) loss on interest rate derivatives Interest expense, net — (935)

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
Asset Retirement Obligations (Tables)	Dec. 31, 2023
Asset Retirement Obligations
Summary of changes in the asset retirement obligations	The following table presents the changes in the asset retirement obligations for the years ended December 31, 2023 and 2022 (in thousands): For the Year Ended December 31, 2023 2022 Asset retirement obligations at beginning of period $ 116,438 $ 103,414 Liabilities added from acquisition or drilling 5 20 Liabilities settled (1,236) (923) Liabilities removed upon sale of wells — — Accretion expense 7,951 7,081 Revision of estimates 336 6,846 Asset retirement obligation at end of period 123,494 116,438 Less: Current portion 1,493 1,824 Asset retirement obligations - long-term portion $ 122,001 $ 114,614

Restricted Investments (Tables)

Restricted Investments (Tables)	12 Months Ended
Restricted Investments (Tables)	Dec. 31, 2023
Restricted Investments
Summary of components of the restricted investment balances.	December 31, 2023 2022 (In thousands) BOEM platform abandonment (See Note 16) $ 15,509 $ 7,016 SPBPC Collateral: Contractual pipeline and surface facilities abandonment 4,426 4,310 Restricted investments $ 19,935 $ 11,326

Debt (Tables)

Debt (Tables)	12 Months Ended
Debt (Tables)	Dec. 31, 2023
Debt
Summary of consolidated debt obligations	December 31, December 31, 2023 2022 (In thousands) Revolving Credit Facility (1) $ 115,000 $ 190,000 Total long-term debt $ 115,000 $ 190,000 (1) The carrying amount of the Company’s Revolving Credit Facility approximates fair value because the interest rates are variable and reflective of market rates.
Summary of weighted-average interest rates paid on variable-rate debt obligations	For the Year Ended December 31, 2023 2022 Revolving Credit Facility 9.35 % 5.36 %

Equity (Deficit) (Tables)

Equity (Deficit) (Tables)	12 Months Ended
Equity (Deficit) (Tables)	Dec. 31, 2023
Equity (Deficit)
Summary of changes in the number of outstanding common units and shares of common stock	Common Stock Balance, December 31, 2021 38,024,142 Issuance of common stock — Restricted stock units vested 534,834 Shares withheld for taxes (1) (99,245) Balance, December 31, 2022 38,459,731 Issuance of common stock — Restricted stock units vested 967,374 Shares withheld for taxes (1) (279,900) Balance, December 31, 2023 39,147,205 (1) Represents the net settlement on vesting of restricted stock to satisfy the tax withholding requirements.

Earnings (Loss) per Share (Tabl

Earnings (Loss) per Share (Tables)	12 Months Ended
Earnings (Loss) per Share (Tables)	Dec. 31, 2023
Earnings (Loss) per Share
Schedule of calculation of 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): For the Year Ended December 31, 2023 2022 Net income (loss) $ 392,750 $ 57,875 Less: Net income allocated to participating securities 17,599 2,728 Basic and diluted earnings available to common stockholders $ 375,151 $ 55,147 Common shares: Common shares outstanding — basic 38,961 38,351 Dilutive effect of potential common shares — — Common shares outstanding — diluted 38,961 38,351 Net earnings (loss) per share: Basic $ 9.63 $ 1.44 Diluted $ 9.63 $ 1.44

Equity-based Awards (Tables)

Equity-based Awards (Tables)	12 Months Ended
Equity-based Awards (Tables)	Dec. 31, 2023
Equity-based Awards
Summary of Amount of Compensation Expense Recognized	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): For the Year Ended December 31, 2023 2022 Equity classified awards TSUs $ 4,336 $ 2,648 PSUs and PRSUs 944 440 Board RSUs — 5 $ 5,280 $ 3,093
TSUs
Equity-based Awards
Summary of Information Regarding Restricted Stock Unit Awards	Weighted- Average Grant- Number of Date Fair Value Units per Unit (1) TSUs outstanding at December 31, 2021 1,074,420 $ 3.66 Granted (2) 963,027 $ 4.05 Forfeited (52,485) $ 4.30 Vested (482,406) $ 3.85 TSUs outstanding at December 31, 2022 1,502,556 $ 3.82 Granted (3) 713,689 $ 8.07 Forfeited (72,095) $ 6.05 Vested (812,694) $ 4.16 TSUs outstanding at December 31, 2023 1,331,456 $ 5.77 (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. (2) The aggregate grant date fair value of TSUs issued for the year ended December 31, 2022 was $3.9 million based on a grant date market price ranging from $3.64 to $6.99 per share. (3) The aggregate grant date fair value of TSUs issued for the year ended December 31, 2023 was $5.8 million based on a grant date market price ranging from $6.52 to $8.91 per share.
PRSUs
Equity-based Awards
Ranges for the Assumptions Used in Monte Carlo Model for PRSUs Granted	April 2023 February 2023 2022 Expected volatility 92.5 % 119.2 % 120.8 % Dividend yield 0.00 % 0.00 % 0.00 % Risk-free interest rate 3.78 % 3.74 % 1.38 %
PSUs and PRSUs
Equity-based Awards
Summary of Information Regarding Restricted Stock Unit Awards	Weighted- Average Grant- Number of Date Fair Value Units per Unit (1) PSUs and PRSUs outstanding at December 31, 2021 262,317 $ 2.14 Granted (2) 189,904 $ 6.20 Forfeited (22,614) $ 2.57 Vested (49,095) $ 1.24 PSUs and PRSUs outstanding at December 31, 2022 380,512 $ 4.28 Granted (3) 321,436 $ 10.59 Forfeited (144,567) $ 6.55 Vested (154,680) $ 2.20 PSUs and PRSUs outstanding at December 31, 2023 402,701 $ 9.31 (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. (2) The aggregate grant date fair value of PRSUs issued for the year ended December 31, 2022 was $1.2 million based on a calculated fair value price at $6.20 per share. (3) The aggregate grant date fair value of PRSUs issued for the year ended December 31, 2023 was $3.4 million based on a calculated fair value price ranging from $1.27 to $15.04 per share.

Leases (Tables)

Leases (Tables)	12 Months Ended
Leases (Tables)	Dec. 31, 2023
Leases
Schedule of Right-of-Use Assets and Lease Liabilities	The following table presents the Company’s right-of-use assets and lease liabilities for the period presented: December 31, December 31, 2023 2022 (In thousands) Right-of-use asset $ 5,756 $ 7,376 Lease liabilities: Current lease liability 1,737 1,401 Long-term lease liability 5,090 6,567 Total lease liability $ 6,827 $ 7,968
Schedule of Maturity Analysis of Minimum Lease Payment Obligation Under Non-cancellable Operating Leases	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): Office and Leased vehicles warehouse and office leases equipment Total 2024 $ 1,417 $ 762 $ 2,179 2025 1,417 550 1,967 2026 1,197 64 1,261 2027 830 — 830 2028 and thereafter 1,786 — 1,786 Total lease payments 6,647 1,376 8,023 Less: interest 1,098 98 1,196 Present value of lease liabilities $ 5,549 $ 1,278 $ 6,827
Schedule of Weighted Average Remaining Lease Terms and Discount Rate of Operating Leases	December 31, 2023 2022 Weighted average remaining lease term (years): Office and warehouse space 4.28 4.71 Vehicles 0.42 0.47 Office equipment 0.01 0.04 Weighted average discount rate: Office and warehouse space 5.22 % 4.87 % Vehicles 1.22 % 1.30 % Office equipment 0.07 % 0.11 %

Supplemental Disclosures to t_2

Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows (Tables)	12 Months Ended
	Dec. 31, 2023
Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows
Summary of Current Accrued Liabilities	Current accrued liabilities consisted of the following at the dates indicated (in thousands): December 31, December 31, 2023 2022 Accrued lease operating expense $ 14,239 $ 11,226 Accrued liability - pipeline incident 9,331 20,832 Accrued liability - current portion of pipeline incident settlement 2,000 4,888 Accrued capital expenditures 8,019 2,714 Accrued general and administrative expense 5,335 4,943 Accrued production and ad valorem tax 3,502 4,675 Accrued commitment fee and other expense 2,626 5,824 Operating lease liability 1,737 1,401 Asset retirement obligations 1,493 1,824 Accrued interest payable 1,792 87 Other 797 35 Accrued liabilities $ 50,871 $ 58,449
Summary of accounts receivable	Accounts receivable consisted of the following at the dates indicated (in thousands): December 31, December 31, 2023 2022 Oil and natural gas receivables $ 31,131 $ 35,083 Insurance receivable - pipeline incident 3,571 41,961 Joint interest owners and other 6,042 5,047 Total accounts receivable 40,744 82,091 Less: allowance for doubtful accounts (1,648) (1,636) Total accounts receivable, net $ 39,096 $ 80,455
Summary of Supplemental Cash Flows	Supplemental cash flow for the periods presented (in thousands): For the Year Ended December 31, 2023 2022 Supplemental cash flows: Cash paid for interest, net of amounts capitalized $ 10,992 $ 11,209 Cash paid for taxes 5,773 93 Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities 6,786 1,012

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
Commitments and Contingencies (Tables)	Dec. 31, 2023
Commitments and Contingencies.
Schedule of funding commitment	The table below outlines our funding commitment under these agreements at December 31, 2023 (in thousands): Payment Due by Period Funding commitment Total 2024 2025 2026 2027 2028 Thereafter (1) Sinking fund payments $ 157,888 $ 15,789 $ 15,789 $ 15,789 $ 15,789 $ 15,789 $ 78,943 (1) The remaining payments will be made during the years of 2029 through 2033.
Purchase Commitments Under the Contracts	At December 31, 2023, the Company had a CO 2 2 2 Payment or Settlement Due by Period Purchase commitment Total 2024 2025 2026 2027 2028 Thereafter CO 2 $ 7,907 $ 4,006 $ 3,901 $ — $ — $ — $ —

Income Tax (Tables)

Income Tax (Tables)	12 Months Ended
Income Tax (Tables)	Dec. 31, 2023
Income Taxes
Components of Income Tax Expense (Benefit)	The components of income tax benefit (expense) are as follows: For the Year Ended December 31, 2023 2022 (In thousands) Current taxes: Federal $ (4,286) $ — State (531) (111) Total current income tax benefit (expense) (4,817) (111) Deferred taxes: Federal 232,351 — State 21,445 — Total deferred income tax benefit (expense) 253,796 — Total income tax benefit (expense) $ 248,979 $ (111)
Reconciliation of Income Tax Benefit (Provision)	The actual income tax benefit (expense) differs from the expected amount computed by applying the federal statutory corporate tax rate of 21% in 2023 and in 2022 as follows: For the Year Ended December 31, 2023 2022 (In thousands) Expected tax benefit (expense) at federal statutory rate $ (30,192) $ (12,177) Changes in valuation allowances 284,927 12,267 Federal prior year adjustments — 1,673 Fines & penalties — (1,939) State income tax benefit (expense), net of federal benefit (2,430) (1,859) State rate change, net of federal benefit (2,541) 1,532 State prior year adjustment (380) (234) Other (405) 626 Total income tax benefit (expense) $ 248,979 $ (111)
Components of Net Deferred Income Tax Liabilities	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): December 31, 2023 2022 Deferred income tax assets: Property, plant & equipment $ 69,895 $ 82,152 Net operating loss carryforward 179,627 183,050 Derivatives — 4,800 Disallowed interest expense 5,580 7,467 Accrued liabilities 2,180 2,008 Other 4,093 7,103 Total deferred income tax assets: 261,375 286,580 Valuation allowance — (284,928) Net deferred income tax assets 261,375 1,652 Deferred income tax liabilities: Derivatives $ 6,319 $ — Other 1,260 1,652 Total deferred income tax liabilities 7,579 1,652 Net deferred income taxes $ 253,796 $ —

Supplemental Oil and Gas Info_2

Supplemental Oil and Gas Information (Unaudited) (Tables)	12 Months Ended
Supplemental Oil and Gas Information (Unaudited) (Tables)	Dec. 31, 2023
Supplemental Oil and Gas Information (Unaudited)
Schedule of Capitalized Costs Relating to Oil and Natural Gas Producing Activities	December 31, 2023 2022 (In thousands) Evaluated oil and natural gas properties $ 873,478 $ 840,310 Support equipment and facilities 149,069 147,496 Accumulated depletion, depreciation, and amortization (676,573) (648,900) Total $ 345,974 $ 338,906
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities	For the Year Ended December 31, 2023 2022 (In thousands) Property acquisition costs, proved $ — $ — Property acquisition costs, unproved — — Exploration — — Development 34,742 42,949 Total $ 34,742 $ 42,949
Schedule of Product Prices Used for Valuing the Reserves	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: 2023 2022 Oil ($/Bbl): WTI (1) $ 78.22 $ 93.67 NGL ($/Bbl): WTI (1) $ 78.22 $ 93.67 Natural Gas ($/MMbtu): Henry Hub (2) $ 2.64 $ 6.36 (1) The weighted average WTI price was adjusted by lease for quality, transportation fees, and a regional price differential. (2) The weighted average Henry Hub price was adjusted by lease for energy content, compression charges, transportation fees, and regional price differentials.
Schedule of Net Reserves	For the Year Ended December 31, 2023 Oil Gas NGLs Total (MBbls) (MMcf) (MBbls) (MBoe) Proved developed and undeveloped reserves: Beginning of year 47,868 312,792 24,026 124,027 Production (2,773) (20,297) (1,323) (7,479) Revision of previous estimates (4,017) (65,617) (3,518) (18,471) End of year 41,078 226,878 19,185 98,077 Proved developed reserves: Beginning of year 47,010 312,185 23,928 122,969 End of year 39,306 226,427 19,108 96,151 Proved undeveloped reserves: Beginning of year 858 607 98 1,058 End of year 1,772 451 77 1,926 For the Year Ended December 31, 2022 Oil Gas NGLs Total (MBbls) (MMcf) (MBbls) (MBoe) Proved developed and undeveloped reserves: Beginning of year 45,001 314,350 23,837 121,230 Production (2,327) (22,993) (1,389) (7,548) Revision of previous estimates 5,194 21,435 1,578 10,345 End of year 47,868 312,792 24,026 124,027 Proved developed reserves (1) : Beginning of period 43,857 309,794 23,574 119,063 End of period 47,010 312,185 23,928 122,969 Proved undeveloped reserves (2) : Beginning of period 1,144 4,556 263 2,167 End of period 858 607 98 1,058 (1) Our reserves related to our Beta properties were reclassified as proved developed non-producing at December 31, 2022. (2) Change to the Company’s development plan has resulted in removal of PUD locations in Oklahoma, Bairoil and Beta.
Standardized Measure of Discounted Future Net Cash Flows	For the Year Ended December 31, 2023 2022 (In thousands) Future cash inflows $ 4,277,014 $ 7,373,499 Future production costs (1) (2,751,065) (3,824,348) Future development costs (1) (313,290) (309,188) Future income tax expense (203,770) (520,731) Future net cash flows for estimated timing of cash flows 1,008,889 2,719,232 10% annual discount for estimated timing of cash flows (382,759) (1,381,276) Standardized measure of discounted future net cash flows $ 626,130 $ 1,337,956 (1) For the years ended December 31, 2023 and 2022, onshore abandonment costs are included in future production cost and offshore abandonment costs are included in future development costs.
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves	For the Year Ended December 31, 2023 2022 (In thousands) Beginning of year $ 1,337,956 $ 919,845 Changes in prices and costs (798,942) 856,545 Revisions of previous quantities (196,093) 59,216 Sale of oil and natural gas produced, net of production costs (106,469) (213,667) Net change in taxes 180,530 (311,412) Accretion of discount 164,937 91,985 Change in production rates and other 38,174 (57,484) Net changes in future development costs (3,669) (20,129) Previously estimated development costs incurred 9,706 13,057 End of year $ 626,130 $ 1,337,956

Organization and Basis of Pre_2

Organization and Basis of Presentation (Detail)	12 Months Ended
Organization and Basis of Presentation (Detail)	Dec. 31, 2023 segment
Organization and Basis of Presentation
Number of reportable business segments	1

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Summary Of Significant Accounting Policies
Allowance for doubtful accounts	$ 1,648	$ 1,636
Capitalized exploratory drilling costs pending evaluation	0	0
Amortization expense including write-off of debt issuance costs	$ 2,000	600
Chance of tax benefit likely to be realized	greater than 50%
Beta Pipeline Incident [Member]
Summary Of Significant Accounting Policies
LOPI insurance payments recognized	$ 17,900	50,200
LOPI coverage period	18 months
Proved Developed and Producing Oil and Gas Properties
Summary Of Significant Accounting Policies
Impairment expense for proved/unproved properties	$ 0	0
Unproved oil and natural gas properties
Summary Of Significant Accounting Policies
Impairment expense for unproved leasehold costs	$ 0	$ 0
Minimum \| Other property & equipment
Summary Of Significant Accounting Policies
Estimated useful lives	3 years
Minimum \| Support Equipment and Facilities
Summary Of Significant Accounting Policies
Estimated useful lives	12 years
Maximum \| Other property & equipment
Summary Of Significant Accounting Policies
Estimated useful lives	7 years
Maximum \| Support Equipment and Facilities
Summary Of Significant Accounting Policies
Estimated useful lives	24 years

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Major Customers (Detail) - Customer concentration risk - Revenues	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
HF Sinclair Corporation (formerly: Sinclair Oil & Gas Company)
Significant Accounting Policies
Total Reported Revenues	24%	23%
Southwest Energy LP
Significant Accounting Policies
Total Reported Revenues	13%	13%
Phillips 66
Significant Accounting Policies
Total Reported Revenues	17%
Koch Energy Services LLC
Significant Accounting Policies
Total Reported Revenues		13%

Revenue - Summary of Revenues D

Revenue - Summary of Revenues Disaggregated (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Revenues:
Total revenues	$ 307,596	$ 458,456
Oil and natural gas sales
Revenues:
Total revenues	288,271	407,761
Oil
Revenues:
Total revenues	205,663	212,522
NGLs
Revenues:
Total revenues	29,432	47,398
Natural Gas
Revenues:
Total revenues	$ 53,176	$ 147,841

Revenue - Additional Informatio

Revenue - Additional Information (Detail) $ in Millions	12 Months Ended
Revenue - Additional Information (Detail) $ in Millions	Dec. 31, 2023 USD ($) item	Dec. 31, 2022 USD ($)
Revenue
Number of revenue streams \| item	3
Accounts receivable attributable to revenue from contracts with customers \| $	$ 31.1	$ 35.1
Revenue, Remaining Performance Obligation, Optional Exemption, Variable Consideration	true
Revenue, Remaining Performance Obligation, Optional Exemption, Performance Obligation	true

Fair Value Measurements of Fi_3

Fair Value Measurements of Financial Instruments - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - Fair Value - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis
Total assets	$ 39,439	$ 6,257
Total liabilities	12,365	27,141
Quoted Prices in Active Market (Level 1)
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis
Total assets	0	0
Total liabilities	0	0
Significant Other Observable Inputs (Level 2)
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis
Total assets	39,439	6,257
Total liabilities	12,365	27,141
Significant Unobservable Inputs (Level 3)
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis
Total assets	0	0
Total liabilities	0	0
Commodity derivatives
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis
Total assets	39,439	6,257
Total liabilities	12,365	27,141
Commodity derivatives \| Quoted Prices in Active Market (Level 1)
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis
Total assets	0	0
Total liabilities	0	0
Commodity derivatives \| Significant Other Observable Inputs (Level 2)
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis
Total assets	39,439	6,257
Total liabilities	12,365	27,141
Commodity derivatives \| Significant Unobservable Inputs (Level 3)
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis
Total assets	0	0
Total liabilities	0	0
Interest rate derivatives
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis
Total assets	0	0
Total liabilities	0	0
Interest rate derivatives \| Quoted Prices in Active Market (Level 1)
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis
Total assets	0	0
Total liabilities	0	0
Interest rate derivatives \| Significant Other Observable Inputs (Level 2)
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis
Total assets	0	0
Total liabilities	0	0
Interest rate derivatives \| Significant Unobservable Inputs (Level 3)
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis
Total assets	0	0
Total liabilities	$ 0	$ 0

Fair Value Measurements of Fi_4

Fair Value Measurements of Financial Instruments - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Proved Developed and Producing Oil and Gas Properties
Assets And Liabilities Carrying Value And Fair Value
Impairment expense	$ 0	$ 0

Risk Management and Derivativ_3

Risk Management and Derivative Instruments - Additional Information and Commodity Derivatives (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) MMBTU $ / bbl $ / MMBTU bbl
Revolving Credit Facility
Derivative
Revolving Credit Facility outstanding \| $	$ 20.6
Borrowing capacity \| $	$ 6.5
Natural gas derivative fixed price swaps 2024
Derivative
Average monthly volume (MMBtu) \| MMBTU	662,500
Weighted-average fixed price	3.72
Natural gas derivative two way collar contracts 2024
Derivative
Average monthly volume (MMBtu) \| MMBTU	627,083
Weighted-average floor price	3.43
Weighted-average ceiling price	4.32
Crude oil derivative fixed price swap 2024
Derivative
Average monthly volume (Bbls) \| bbl	61,333
Weighted-average fixed price \| $ / bbl	73.55
Crude oil derivative two way collars contracts 2024
Derivative
Average monthly volume (Bbls) \| bbl	102,000
Weighted-average floor price \| $ / bbl	70
Weighted-average ceiling price \| $ / bbl	80.20
Natural gas derivative fixed price swaps 2025
Derivative
Average monthly volume (MMBtu) \| MMBTU	675,000
Weighted-average fixed price	3.74
Natural gas derivative two way collar contracts 2025
Derivative
Average monthly volume (MMBtu) \| MMBTU	500,000
Weighted-average floor price	3.50
Weighted-average ceiling price	4.10
Crude oil derivative fixed price swap 2025
Derivative
Average monthly volume (Bbls) \| bbl	53,000
Weighted-average fixed price \| $ / bbl	70.68
Crude oil derivative two way collars contracts 2025
Derivative
Average monthly volume (Bbls) \| bbl	59,500
Weighted-average floor price \| $ / bbl	70
Weighted-average ceiling price \| $ / bbl	80.20
Natural gas derivative fixed price swaps 2026
Derivative
Average monthly volume (MMBtu) \| MMBTU	291,667
Weighted-average fixed price	3.72
Natural gas derivative two way collar contracts 2026
Derivative
Average monthly volume (MMBtu) \| MMBTU	291,667
Weighted-average floor price	3.50
Weighted-average ceiling price	4.10
Crude oil derivative fixed price swap 2026
Derivative
Average monthly volume (Bbls) \| bbl	30,917
Weighted-average fixed price \| $ / bbl	70.68

Risk Management and Derivativ_4

Risk Management and Derivative Instruments - Balance Sheet Presentation (Detail) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Derivative Instruments and Hedges, Assets
Cash collateral received	$ 0	$ 0
Net recorded fair value, Current assets	17,669	0
Net recorded fair value, Non-Current assets	9,405	0
Net recorded fair value, Current liabilities	0	20,884
Net recorded fair value, Non current liabilities	0	0
Short-term derivative instruments
Derivative Instruments and Hedges, Assets
Asset Derivatives, Gross fair value	21,657	6,257
Asset Derivatives, Netting arrangements	(3,988)	(6,257)
Liability Derivatives, Gross fair value	3,988	27,141
Liability Derivatives, Netting arrangements	(3,988)	(6,257)
Short-term derivative instruments \| Commodity derivatives
Derivative Instruments and Hedges, Assets
Asset Derivatives, Gross fair value	21,657	6,257
Liability Derivatives, Gross fair value	3,988	27,141
Short-term derivative instruments \| Interest rate swaps
Derivative Instruments and Hedges, Assets
Asset Derivatives, Gross fair value	0	0
Liability Derivatives, Gross fair value	0	0
Long-term derivative instruments
Derivative Instruments and Hedges, Assets
Asset Derivatives, Gross fair value	17,782	0
Asset Derivatives, Netting arrangements	(8,377)	0
Liability Derivatives, Gross fair value	8,377	0
Liability Derivatives, Netting arrangements	(8,377)	0
Long-term derivative instruments \| Commodity derivatives
Derivative Instruments and Hedges, Assets
Asset Derivatives, Gross fair value	17,782	0
Liability Derivatives, Gross fair value	8,377	0
Long-term derivative instruments \| Interest rate swaps
Derivative Instruments and Hedges, Assets
Asset Derivatives, Gross fair value	0	0
Liability Derivatives, Gross fair value	$ 0	$ 0

Risk Management and Derivativ_5

Risk Management and Derivative Instruments - (Gains) Losses on Derivatives (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Derivative Instruments Gain Loss [Line Items]
Loss (gain) on commodity derivative instruments	$ (40,343)	$ 106,937
Interest expense, net	(17,719)	(14,101)
Commodity derivative contracts
Derivative Instruments Gain Loss [Line Items]
Loss (gain) on commodity derivative instruments	(40,343)	106,937
(Gain) loss on interest rate derivatives
Derivative Instruments Gain Loss [Line Items]
Interest expense, net	$ 0	$ (935)

Asset Retirement Obligations -

Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Asset Retirement Obligations
Asset retirement obligations at beginning of period	$ 116,438	$ 103,414
Liabilities added from acquisition or drilling	5	20
Liabilities settled	(1,236)	(923)
Liabilities removed upon sale of wells	0	0
Accretion expense	7,951	7,081
Revision of estimates	336	6,846
Asset retirement obligation at end of period	123,494	116,438
Less: Current portion	1,493	1,824
Asset retirement obligations - long-term portion	$ 122,001	$ 114,614

Restricted Investments (Detail)

Restricted Investments (Detail) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Restricted Investments
Restricted investments	$ 19,935	$ 11,326
BOEM platform abandonment
Restricted Investments
Restricted investments	15,509	7,016
SPBPC Collateral contractual pipeline and surface facilities abandonment
Restricted Investments
Restricted investments	$ 4,426	$ 4,310

Debt - Consolidated debt obliga

Debt - Consolidated debt obligations (Detail) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Debt
Total long-term debt	$ 115,000	$ 190,000
Revolving Credit Facility
Debt
Revolving Credit Facility	$ 115,000	$ 190,000

Debt - Additional Information (

Debt - Additional Information (Detail) - USD ($) $ in Millions		12 Months Ended
	Jul. 31, 2023	Dec. 31, 2023	Oct. 19, 2023
Debt
Letters of credit outstanding		$ 0
Revolving Credit Facility
Debt
Borrowing capacity		6.5
Unamortized deferred financing costs		4.4
Successor Credit Facility
Debt
Deferred finance cost		1
New Revolving Credit Facility
Debt
Aggregate principal amount of loans outstanding		$ 115
Borrowing capacity	$ 150		$ 150
Elected commitments	$ 135		$ 135
Line of credit facility, unused capacity, commitment fee percentage	0.50%
Net debt leverage ratio	3%
New Revolving Credit Facility \| For 24-month period following the effective date of the Revolving Credit Facility
Debt
Debt instrument, percentage of hedging requirement of reasonably anticipated projected production of hydrocarbons	75%
New Revolving Credit Facility \| For 12-month period immediately following the First Period
Debt
Debt instrument, percentage of hedging requirement of reasonably anticipated projected production of hydrocarbons	50%
New Revolving Credit Facility \| Minimum
Debt
Current ratio	1%
New Revolving Credit Facility \| Maximum
Debt
Current ratio	1%
New Revolving Credit Facility \| Base rate \| Minimum
Debt
Debt instrument, basis spread on variable rate	2%
New Revolving Credit Facility \| Base rate \| Maximum
Debt
Debt instrument, basis spread on variable rate	3%
New Revolving Credit Facility \| SOFR \| Minimum
Debt
Debt instrument, basis spread on variable rate	3%
New Revolving Credit Facility \| SOFR \| Maximum
Debt
Debt instrument, basis spread on variable rate	4%

Debt - Weighted-Average Interes

Debt - Weighted-Average Interest Rates (Detail)	12 Months Ended
Debt - Weighted-Average Interest Rates (Detail)	Dec. 31, 2023	Dec. 31, 2022
Revolving Credit Facility
Debt
Revolving Credit Facility, Weighted-Average Interest Rates	9.35%	5.36%

Equity (Deficit) - Additional I

Equity (Deficit) - Additional Information (Detail) - $ / shares	May 04, 2017	Dec. 31, 2023	Dec. 31, 2022
Equity Outstanding
Common stock, shares authorized (in shares)		250,000,000	250,000,000
Common stock, par value (in dollars per share)		$ 0.01	$ 0.01
Warrants
Equity Outstanding
Warrant issued during period (in shares)	2,173,913
Percentage of common shares to be issued upon exercise of warrants	8%
Warrant life period	5 years
Warrant exercise price	$ 42.60

Equity (Deficit) - Summary of C

Equity (Deficit) - Summary of Changes in Common Stock (Detail) - shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Equity (Deficit)
Beginning balance	38,459,731
Ending balance	39,147,205	38,459,731
Common Stock
Equity (Deficit)
Beginning balance	38,459,731	38,024,142
Issuance of common stock	0	0
Restricted stock units vested	967,374	534,834
Shares withheld for taxes	(279,900)	(99,245)
Ending balance	39,147,205	38,459,731

Earnings (Loss) per Share (Deta

Earnings (Loss) per Share (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Earnings (Loss) per Share
Net income (loss)	$ 392,750	$ 57,875
Less: Net income allocated to participating securities	17,599	2,728
Net income (loss) available to common stockholders	$ 375,151	$ 55,147
Common shares:
Common shares outstanding - basic (in shares)	38,961	38,351
Common shares outstanding - diluted (in shares)	38,961	38,351
Basic (in dollars per shares)	$ 9.63	$ 1.44
Diluted (in dollars per shares)	$ 9.63	$ 1.44

Equity-based Awards - Additiona

Equity-based Awards - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) shares
PRSUs
Equity-based Awards
Fair value estimation method	The fair value of the awards is estimated on their grant dates using a Monte Carlo simulation
2022 and 2023 PRSU Awards
Equity-based Awards
Vesting period	3 years
Maximum \| 2021 PRSU Awards
Equity-based Awards
Percentage of Potential Payout	200%
Maximum \| 2022 and 2023 PRSU Awards
Equity-based Awards
Percentage of Potential Payout	200%
Minimum \| 2021 PRSU Awards
Equity-based Awards
Percentage of Potential Payout	0%
Minimum \| 2022 and 2023 PRSU Awards
Equity-based Awards
Percentage of Potential Payout	0%
EIP
Equity-based Awards
Shares available for future distribution (in shares) \| shares	857,177
TSUs
Equity-based Awards
Unrecognized compensation cost	$ 4.5
Weighted-average period of unrecognized compensation cost	1 year 9 months 18 days
PRSUs
Equity-based Awards
Unrecognized compensation cost	$ 2.3
Weighted-average period of unrecognized compensation cost	2 years
2021 PRSU Awards \| Share Based Compensation Award Tranche Three
Equity-based Awards
Stock units vesting percentage	50%
2021 PRSU Awards \| First Anniversary Vesting
Equity-based Awards
Stock units vesting percentage	25%
2021 PRSU Awards \| Second Anniversary Vesting
Equity-based Awards
Stock units vesting percentage	25%

Equity-based Awards - Summary o

Equity-based Awards - Summary of Information Regarding Restricted Stock Units (Detail) - $ / shares		12 Months Ended
		Dec. 31, 2023		Dec. 31, 2022
Restricted stock units \| TSUs
Equity-based Awards
Outstanding, Number of Units, Beginning Balance		1,502,556		1,074,420
Granted, Number of Units		713,689	[1]	963,027
Forfeited, Number of Units		(72,095)		(52,485)
Vested, Number of Units		(812,694)		(482,406)
Outstanding, Number of Units, Ending Balance		1,331,456		1,502,556
Outstanding, Weighted-Average Grant Date Fair Value per unit, Beginning balance	[2]	$ 3.82		$ 3.66
Granted, Weighted-Average Grant Date Fair Value per Unit	[2]	8.07	[1]	4.05
Forfeited, Weighted-Average Grant Date Fair Value per Unit	[2]	6.05		4.30
Vested, Weighted-Average Grant Date Fair Value per Unit	[2]	4.16		3.85
Outstanding, Weighted-Average Grant Date Fair Value per unit, Ending balance	[2]	$ 5.77		$ 3.82
Management Incentive Plan \| PSUs and PRSUs
Equity-based Awards
Outstanding, Number of Units, Beginning Balance		380,512		262,317
Granted, Number of Units		321,436		189,904
Forfeited, Number of Units		(144,567)		(22,614)
Vested, Number of Units		(154,680)		(49,095)
Outstanding, Number of Units, Ending Balance		402,701		380,512
Outstanding, Weighted-Average Grant Date Fair Value per unit, Beginning balance		$ 4.28		$ 2.14
Granted, Weighted-Average Grant Date Fair Value per Unit		10.59		6.20
Forfeited, Weighted-Average Grant Date Fair Value per Unit		6.55		2.57
Vested, Weighted-Average Grant Date Fair Value per Unit		2.20		1.24
Outstanding, Weighted-Average Grant Date Fair Value per unit, Ending balance		$ 9.31		$ 4.28

[1] The aggregate grant date fair value of TSUs issued for the year ended December 31, 2023 was $5.8 million based on a grant date market price ranging from $6.52 to $8.91 per share. Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.

Equity-based Awards - Summary_2

Equity-based Awards - Summary of Information Regarding Restricted Stock Units (Parenthetical) (Detail) - USD ($) $ / shares in Units, $ in Millions	Dec. 31, 2023	Dec. 31, 2022
TSUs
Equity-based Awards
Aggregate grant date fair value of restricted stock units issued	$ 5.8	$ 3.9
TSUs \| Minimum
Equity-based Awards
Grant Date Market Price	$ 6.52	$ 3.64
TSUs \| Maximum
Equity-based Awards
Grant Date Market Price	$ 8.91	$ 6.99
PRSUs
Equity-based Awards
Aggregate grant date fair value of restricted stock units issued	$ 3.4	$ 1.2
Calculated fair value price		$ 6.20
PRSUs \| Minimum
Equity-based Awards
Calculated fair value price	$ 1.27
PRSUs \| Maximum
Equity-based Awards
Calculated fair value price	$ 15.04

Equity-based Awards - Assumptio

Equity-based Awards - Assumptions Used in Monte Carlo Model (Detail) - PRSUs	1 Months Ended		12 Months Ended
	Apr. 30, 2023	Feb. 28, 2023	Dec. 31, 2022
Equity-based Awards
Expected volatility	92.50%	119.20%	120.80%
Dividend yield	0%	0%	0%
Risk-free interest rate	3.78%	3.74%	1.38%

Equity-based Awards - Summary_3

Equity-based Awards - Summary of Amount of Compensation Expense Recognized (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Equity-based Awards
Equity based compensation expense (benefit)	$ 5,280	$ 3,093
Restricted stock units
Equity-based Awards
Equity based compensation expense (benefit)	0	5
TSUs
Equity-based Awards
Equity based compensation expense (benefit)	4,336	2,648
PSUs and PRSUs
Equity-based Awards
Equity based compensation expense (benefit)	$ 944	$ 440

Leases - Additional Information

Leases - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Leases
Lease, option to terminate	leases can be terminated with 30-day prior written notice
Lease termination period with prior written notice	30 days
Operating lease costs	$ 2.1	$ 1.6

Leases - Schedule of Right-of-U

Leases - Schedule of Right-of-Use Assets and Lease Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Leases
Right-of-use asset	$ 5,756	$ 7,376
Current lease liability	1,737	1,401
Long-term lease liability	5,090	6,567
Total lease liability	$ 6,827	$ 7,968

Leases - Schedule of Maturity A

Leases - Schedule of Maturity Analysis of Minimum Lease Payment Obligation Under Non-cancellable Operating Leases (Detail) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Leases
2024	$ 2,179
2025	1,967
2026	1,261
2027	830
2028 and thereafter	1,786
Total lease payments	8,023
Less: interest	1,196
Present value of lease liabilities	6,827	$ 7,968
Office and warehouse leases
Leases
2024	1,417
2025	1,417
2026	1,197
2027	830
2028 and thereafter	1,786
Total lease payments	6,647
Less: interest	1,098
Present value of lease liabilities	5,549
Leased vehicles and office equipment
Leases
2024	762
2025	550
2026	64
2027	0
2028 and thereafter	0
Total lease payments	1,376
Less: interest	98
Present value of lease liabilities	$ 1,278

Leases - Schedule of Weighted A

Leases - Schedule of Weighted Average Remaining Lease Terms and Discount Rate of Operating Leases (Detail)	Dec. 31, 2023	Dec. 31, 2022
Office and warehouse leases
Leases
Weighted average remaining lease term	4 years 3 months 10 days	4 years 8 months 15 days
Weighted average discount rate	5.22%	4.87%
Vehicles
Leases
Weighted average remaining lease term	5 months 1 day	5 months 19 days
Weighted average discount rate	1.22%	1.30%
Office equipment
Leases
Weighted average remaining lease term	3 days	14 days
Weighted average discount rate	0.07%	0.11%

Supplemental Disclosures to t_3

Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows - Summary of Accrued Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows
Accrued liability - pipeline incident	$ 9,331	$ 20,832
Accrued lease operating expense	14,239	11,226
Accrued liability - current portion of pipeline incident settlement	2,000	4,888
Accrued capital expenditures	8,019	2,714
Accrued general and administrative expense	5,335	4,943
Accrued production and ad valorem tax	3,502	4,675
Accrued commitment fee and other expense	2,626	5,824
Operating lease liability	$ 1,737	$ 1,401
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Accrued liabilities	Accrued liabilities
Asset retirement obligations	$ 1,493	$ 1,824
Accrued interest payable	1,792	87
Other	797	35
Accrued liabilities	$ 50,871	$ 58,449

Supplemental Disclosures to t_4

Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows - Summary of Accounts Receivable (Detail) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows
Oil and natural gas receivables	$ 31,131	$ 35,083
Insurance receivable - pipeline incident	3,571	41,961
Joint interest owners and other	6,042	5,047
Total accounts receivable	40,744	82,091
Less: allowance for doubtful accounts	(1,648)	(1,636)
Total accounts receivable, net	$ 39,096	$ 80,455

Supplemental Disclosures to t_5

Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows - Summary of Supplemental Cash Flows (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized	$ 10,992	$ 11,209
Cash paid for taxes	5,773	93
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities	$ 6,786	$ 1,012

Related Party Transactions (Det

Related Party Transactions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Related Party Transactions
Significant transaction with related party	$ 0	$ 0

Beta Pipeline Incident (Details

Beta Pipeline Incident (Details) $ in Thousands					12 Months Ended
Beta Pipeline Incident (Details) $ in Thousands	Sep. 08, 2022 USD ($) item	Aug. 26, 2022 USD ($)	Aug. 25, 2022 USD ($)	Oct. 02, 2021 item	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Mar. 01, 2023 USD ($)	Oct. 14, 2021 bbl	Oct. 05, 2021 ft² item
Unusual or Infrequent Item, or Both [Line Items]
Amount agreed to be receivable in a settlement							$ 96,500
Approximate net payment receivable in a settlement							$ 85,000
Pipeline incident loss					$ 19,981	$ 11,277
Amount receivable					3,571	41,961
Beta Pipeline Incident
Unusual or Infrequent Item, or Both [Line Items]
Number of foot section of pipeline displaced with lateral movement \| item									4,000
Maximum lateral movement of pipeline identified \| ft²									105
Number of inch split running parallel to pipe \| item									13
Volume of oil expected to be released \| bbl								588
Maximum volume of oil previously estimated \| bbl								3,134
Number of deployed contractors working in cleanup operations \| item				1,800
Settlement amount			$ 50,000
Estimated aggregate costs					29,300
Fines and penalties					12,000
Costs probable of recovery					9,300
Pipeline incident loss					20,000
LOPI insurance payments recognized					17,900	50,200
Beta Pipeline Incident \| Accounts Receivable
Unusual or Infrequent Item, or Both [Line Items]
Amount receivable					3,600	42,000
LOPI insurance payments recognized					17,900	$ 50,200
Beta Pipeline Incident \| Minimum
Unusual or Infrequent Item, or Both [Line Items]
Estimated aggregate costs					190,000
Beta Pipeline Incident \| Maximum
Unusual or Infrequent Item, or Both [Line Items]
Estimated aggregate costs					$ 210,000
Beta Pipeline Incident \| Pending Litigation
Unusual or Infrequent Item, or Both [Line Items]
Estimated litigation liability	$ 4,900	$ 7,100
Reimbursement amount payable to government agencies		$ 5,800
Number of misdemeanor charges \| item	6
Probation period	1 year	4 years
Installment period		3 years
Beta Pipeline Incident \| CALIFORNIA
Unusual or Infrequent Item, or Both [Line Items]
Number of miles off the coast of beach \| item				4

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Details)		12 Months Ended
	Dec. 15, 2021 USD ($) agreement	Dec. 31, 2023 USD ($) $ / bbl	Dec. 31, 2022 USD ($)
Commitments and Contingencies Additional Textual [Abstract]
Remaining environmental accrued liability recorded		$ 0	$ 0
Obligatory monthly deposit into sinking fund account per barrel of oil \| $ / bbl		0.25
Number of escrow funding agreements \| agreement	2
Sinking fund account maximum value upon which obligation ceases	$ 172,600,000	$ 4,300,000
Beta's decommissioning obligations, cash		15,200,000
Beta's decommissioning obligations, full supported by surety bonds		161,300,000
Rent expense		10,300,000	8,700,000
Commitment fee expense		300,000	$ 1,800,000
SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member]
Commitments and Contingencies Additional Textual [Abstract]
Restricted Investment - decommissioning of offshore production facilities		$ 4,400,000

Commitments and Contingencies_2

Commitments and Contingencies - Funding Commitment (Details) - Sinking fund payments $ in Thousands	Dec. 31, 2023 USD ($)
Other Commitments [Line Items]
Total	$ 157,888
2024	15,789
2025	15,789
2026	15,789
2027	15,789
2028	15,789
Thereafter	$ 78,943

Commitments and Contingencies_3

Commitments and Contingencies - Purchase Commitments (Details) - CO2 Minimum Purchase Commitment $ in Thousands	Dec. 31, 2023 USD ($)
Recorded Unconditional Purchase Obligation [Line Items]
Total	$ 7,907
2024	4,006
2025	3,901
2026	0
2027	0
2028	0
Thereafter	$ 0

Income Tax - Components of Inco

Income Tax - Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Current taxes:
Federal	$ (4,286)
State	(531)	$ (111)
Total current income tax benefit (expense)	(4,817)	(111)
Deferred taxes:
Federal	232,351	0
State	21,445	0
Total deferred income tax benefit (expense)	253,796
Total income tax benefit (expense)	$ 248,979	$ (111)

Income Tax - Additional Informa

Income Tax - Additional Information (Details) - USD ($)	3 Months Ended	12 Months Ended
Income Tax - Additional Information (Details) - USD ($)	Mar. 31, 2023	Dec. 31, 2023	Dec. 31, 2022
Income Tax Disclosure [Line Items]
Statutory tax rate		21%	21%
Valuation Allowance			$ 284,928,000
Period of cumulative book income achieved	3 years
Valuation allowance released		$ 284,900,000
Unrecognized Tax Benefits		0
United States [Member]
Income Tax Disclosure [Line Items]
NOL carryforward subject to loss limitation		787,600,000
Operating loss expiration		20,600,000
Operating loss carryforwards not subject to expiration		767,000,000
State [Member]
Income Tax Disclosure [Line Items]
Operating loss carryforwards not subject to expiration		$ 401,500,000
Operating loss carryforwards expiration year		2037
Maximum \| State [Member]
Income Tax Disclosure [Line Items]
Net operating loss carryforwards		$ 432,000,000

Income Tax - Reconciliation of

Income Tax - Reconciliation of Income Tax Benefit (Provision) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Income Taxes
Expected tax benefit (expense) at federal statutory rate	$ (30,192)	$ (12,177)
Changes in valuation allowances	284,927	12,267
Federal prior year adjustments		1,673
Fines & penalties		(1,939)
State income tax benefit (expense), net of federal benefit	(2,430)	(1,859)
State rate change, net of federal benefit	(2,541)	1,532
State prior year adjustment	(380)	(234)
Other	(405)	626
Total income tax benefit (expense)	$ 248,979	$ (111)

Income Tax - Components of Net

Income Tax - Components of Net Deferred Income Tax (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Deferred income tax assets:
Property, plant & equipment	$ 69,895	$ 82,152
Net operating loss carryforward	179,627	183,050
Derivatives		4,800
Disallowed interest expense	5,580	7,467
Accrued liabilities	2,180	2,008
Other	4,093	7,103
Total deferred income tax assets	261,375	286,580
Valuation allowance		(284,928)
Net deferred income tax assets	261,375	1,652
Deferred income tax liabilities:
Derivatives	6,319	0
Other	1,260	1,652
Total deferred income tax liabilities	7,579	1,652
Net deferred income taxes	$ 253,796	$ 0

Supplemental Oil and Gas Info_3

Supplemental Oil and Gas Information (Unaudited) - Schedule of Capitalized Costs Relating to Oil and Natural Gas Producing Activities (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Supplemental Oil and Gas Information (Unaudited)
Evaluated oil and natural gas properties	$ 873,478	$ 840,310
Support equipment and facilities	149,069	147,496
Accumulated depletion, depreciation, and amortization	(676,573)	(648,900)
Total	$ 345,974	$ 338,906

Supplemental Oil and Gas Info_4

Supplemental Oil and Gas Information (Unaudited) - Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Supplemental Oil and Gas Information (Unaudited)
Property acquisition costs, proved	$ 0	$ 0
Property acquisition costs, unproved	0	0
Exploration	0	0
Development	34,742	42,949
Total	$ 34,742	$ 42,949

Supplemental Oil and Gas Info_5

Supplemental Oil and Gas Information (Unaudited) - Additional Information (Details)	12 Months Ended
	Dec. 31, 2023 MMBoe location	Dec. 31, 2022 MMBoe
Supplemental Oil and Gas Information (Unaudited)
Percent of discount factor to proved reserves	10%
Increase (reduction) in reserves	(26)	2.8
Upward price revisions in proved reserve		14.2
Proved developed and undeveloped reserves, decrease in production	7.5
Proved developed and undeveloped reserves, decrease in lease operating expense	2.5	4.1
Number of Beta PUD locations \| location	4
Proved reserve changes in location budget	1.1
Downward price revisions in proved reserve	17.8
Proved developed and undeveloped reserves, upward technical revision	0.7	0.2

Supplemental Oil and Gas Info_6

Supplemental Oil and Gas Information (Unaudited) - Schedule of Product Prices Used for Valuing the Reserves (Details) - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Oil
Supplemental Oil And Gas Reserve Information [Line Items]
Product prices for reserves	78.22	93.67
NGLs
Supplemental Oil And Gas Reserve Information [Line Items]
Product prices for reserves	78.22	93.67
Natural Gas
Supplemental Oil And Gas Reserve Information [Line Items]
Product prices for reserves	2.64	6.36

Supplemental Oil and Gas Info_7

Supplemental Oil and Gas Information (Unaudited) - Schedule of Net Reserves (Details)	12 Months Ended
	Dec. 31, 2023 MBbls MMcf	Dec. 31, 2022 MMcf MBbls
Oil
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year	47,868	45,001
Production	(2,773)	(2,327)
Revision of previous estimates	(4,017)	5,194
Proved developed and undeveloped reserves, End of year	41,078	47,868
Proved developed reserves, Beginning of year	47,010	43,857
Proved developed reserves, End of year	39,306	47,010
Proved undeveloped reserves, Beginning of year	858	1,144
Proved undeveloped reserves, End of year	1,772	858
Natural Gas
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year \| MMcf	312,792	314,350
Production \| MMcf	(20,297)	(22,993)
Revision of previous estimates \| MMcf	(65,617)	21,435
Proved developed and undeveloped reserves, End of year \| MMcf	226,878	312,792
Proved developed reserves, Beginning of year \| MMcf	312,185	309,794
Proved developed reserves, End of year \| MMcf	226,427	312,185
Proved undeveloped reserves, Beginning of year \| MMcf	607	4,556
Proved undeveloped reserves, End of year \| MMcf	451	607
NGLs
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year	24,026	23,837
Production	(1,323)	(1,389)
Revision of previous estimates	(3,518)	1,578
Proved developed and undeveloped reserves, End of year	19,185	24,026
Proved developed reserves, Beginning of year	23,928	23,574
Proved developed reserves, End of year	19,108	23,928
Proved undeveloped reserves, Beginning of year	98	263
Proved undeveloped reserves, End of year	77	98
Proved Reserves, Total
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year	124,027	121,230
Production	(7,479)	(7,548)
Revision of previous estimates	(18,471)	10,345
Proved developed and undeveloped reserves, End of year	98,077	124,027
Proved developed reserves, Beginning of year	122,969	119,063
Proved developed reserves, End of year	96,151	122,969
Proved undeveloped reserves, Beginning of year	1,058	2,167
Proved undeveloped reserves, End of year	1,926	1,058

Supplemental Oil and Gas Info_8

Supplemental Oil and Gas Information (Unaudited) -Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Supplemental Oil and Gas Information (Unaudited)
Future cash inflows	$ 4,277,014	$ 7,373,499
Future production costs	(2,751,065)	(3,824,348)
Future development costs	(313,290)	(309,188)
Future income tax expense	(203,770)	(520,731)
Future net cash flows for estimated timing of cash flows	1,008,889	2,719,232
10% annual discount for estimated timing of cash flows	(382,759)	(1,381,276)
Standardized measure of discounted future net cash flows	$ 626,130	$ 1,337,956	$ 919,845

Supplemental Oil and Gas Info_9

Supplemental Oil and Gas Information (Unaudited) - Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Supplemental Oil and Gas Information (Unaudited)
Beginning of year	$ 1,337,956	$ 919,845
Changes in prices and costs	(798,942)	856,545
Revisions of previous quantities	(196,093)	59,216
Sale of oil and natural gas produced, net of production costs	(106,469)	(213,667)
Net change in taxes	180,530	(311,412)
Accretion of discount	164,937	91,985
Change in production rates and other	38,174	(57,484)
Net changes in future development costs	(3,669)	(20,129)
Previously estimated development costs incurred	9,706	13,057
End of year	$ 626,130	$ 1,337,956

Pay vs Performance Disclosure

Pay vs Performance Disclosure - USD ($) $ in Thousands	12 Months Ended
Pay vs Performance Disclosure - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Pay vs Performance Disclosure
Net Income (Loss)	$ 392,750	$ 57,875

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
Insider Trading Arrangements	Dec. 31, 2023
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false