Amplify Energy (AMPY) 10-K9 Mar 232022 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, 2022	Feb. 28, 2023	Jun. 30, 2022
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
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
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Shell Company	false
Title of 12(b) Security	Common Stock
Trading Symbol	AMPY
Security Exchange Name	NYSE
Entity Common Stock, Shares Outstanding		38,710,696
Entity Central Index Key	0001533924
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
ICFR Auditor Attestation Flag	false
Auditor Name	DELOITTE & TOUCHE LLP
Auditor Firm ID	34
Auditor Location	Houston, Texas
Entity Public Float			$ 231.2
Documents Incorporated by Reference	Documents Incorporated By Reference :

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Current assets:
Cash and cash equivalents	$ 0	$ 18,799
Accounts receivable, net (see Note 13)	80,455	91,967
Prepaid expenses and other current assets	18,789	15,018
Total current assets	99,244	125,784
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method	840,310	799,532
Support equipment and facilities	147,496	145,324
Other	9,648	9,641
Accumulated depreciation, depletion and amortization	(658,162)	(634,212)
Property and equipment, net	339,292	320,285
Restricted investments	11,326	4,622
Operating lease - long term right-of-use asset	7,376	2,716
Other long-term assets	2,240	1,693
Total assets	459,478	455,100
Current liabilities:
Accounts payable	38,414	33,819
Revenues payable	22,105	20,374
Accrued liabilities (see Note 13)	58,449	57,826
Short-term derivative instruments	20,884	53,144
Total current liabilities	139,852	165,163
Long-term debt (see Note 8)	190,000	230,000
Asset retirement obligations	114,614	102,398
Long-term derivative instruments	0	9,664
Operating lease liability	6,567	2,017
Other long-term liabilities	13,010	10,699
Total liabilities	464,043	519,941
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, 2022 and December 31, 2021	0	0
Warrants, 2,173,913 warrants issued and outstanding at December 31, 2021	0	4,788
Common stock, $0.01 par value: 250,000,000 shares authorized; 38,459,731 and 38,024,142 shares issued and outstanding at December 31, 2022 and December 31, 2021, respectively	386	382
Additional paid-in capital	432,251	425,066
Accumulated deficit	(437,202)	(495,077)
Total stockholders' deficit	(4,565)	(64,841)
Total liabilities and equity	$ 459,478	$ 455,100

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2022	Dec. 31, 2021
CONSOLIDATED BALANCE SHEETS
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	50,000,000	50,000,000
Preferred stock, shares issued	0	0
Warrants issued		2,173,913
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	250,000,000	250,000,000
Common stock, shares issued	38,459,731	38,024,142

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Revenues:
Total revenues	$ 458,456	$ 342,916
Costs and expenses:
Lease operating expense	131,675	121,398
Gathering, processing and transportation	29,110	20,807
Taxes other than income	33,308	22,250
Depreciation, depletion and amortization	23,950	28,068
General and administrative expense	30,164	25,285
Accretion of asset retirement obligations	7,081	6,611
Loss (gain) on commodity derivative instruments	106,937	142,439
Pipeline incident loss	11,277	1,599
Pipeline incident settlement	12,000	0
Other, net	965	68
Total costs and expenses	386,467	368,525
Operating income (loss)	71,989	(25,609)
Other income (expense):
Interest expense, net	(14,101)	(12,099)
Gain on extinguishment of debt	0	5,516
Other income (expense)	98	128
Total other income (expense)	(14,003)	(6,455)
Income (loss) before reorganization items, net and income taxes	57,986	(32,064)
Reorganization items, net	0	(6)
Income tax expense	(111)	0
Net income (loss)	57,875	(32,070)
Allocation of net income (loss) to:
Net income (loss) available to common stockholders	55,147	(32,070)
Net income (loss) allocated to participating securities	2,728	0
Net income (loss) available to Amplify Energy Corp.	$ 57,875	$ (32,070)
Earnings (loss) per share: (See Note 10)
Basic earnings (loss) per share	$ 1.44	$ (0.84)
Diluted earnings (loss) per share	$ 1.44	$ (0.84)
Weighted average common shares outstanding:
Basic	38,351	37,959
Diluted	38,351	37,959
Oil and Natural Gas Sales [Member]
Revenues:
Total revenues	$ 407,761	$ 335,779
Other Revenues [Member]
Revenues:
Total revenues	$ 50,695	$ 7,137

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Cash flows from operating activities:
Net income (loss)	$ 57,875	$ (32,070)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	23,950	28,068
Loss (gain) on derivative instruments	106,002	142,223
Cash settlements (paid) received on expired derivative instruments	(147,926)	(90,214)
Gain on extinguishment of debt	0	(5,516)
Accretion of asset retirement obligations	7,081	6,611
Share-based compensation (see Note 11)	2,964	1,047
Settlement of asset retirement obligations	(923)	(296)
Amortization and write-off of deferred financing costs	649	626
Bad debt expense	1	95
Changes in operating assets and liabilities:
Accounts receivable	2,815	(61,172)
Prepaid expenses and other assets	(3,957)	296
Payables and accrued liabilities	13,812	73,655
Other	2,142	(384)
Net cash provided by operating activities	64,485	62,969
Cash flows from investing activities:
Additions to oil and gas properties	(34,814)	(29,294)
Additions to other property and equipment	(7)	(539)
Additions to restricted investments	(6,704)	1
Other	0	404
Net cash used in investing activities	(41,525)	(29,428)
Cash flows from financing activities:
Advances on revolving credit facility	5,000	0
Payments on revolving credit facility	(45,000)	(25,000)
Deferred financing costs	(1,196)	(25)
Shares withheld for taxes	(563)	(81)
Net cash used in financing activities	(41,759)	(25,106)
Net change in cash and cash equivalents	(18,799)	8,435
Cash and cash equivalents, beginning of period	18,799	10,364
Cash and cash equivalents, end of period	$ 0	$ 18,799

CONSOLIDATED STATEMENTS OF EQUI

CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Thousands	Common Stock [Member]	Warrant [Member]	Additional Paid In Capital [Member]	Accumulated Earnings (Deficit) [Member]	Total
Balance at Dec. 31, 2020	$ 378	$ 4,788	$ 424,104	$ (463,007)	$ (33,737)
Net income (loss)	0	0	0	(32,070)	(32,070)
Share-based compensation expense	0	0	1,047	0	1,047
Shares withheld for taxes	0	0	(81)	0	(81)
Other	4	0	(4)	0	0
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)

Organization and Basis of Prese

Organization and Basis of Presentation	12 Months Ended
Organization and Basis of Presentation	Dec. 31, 2022
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, federal waters offshore Southern California, East Texas/North Louisiana and the Eagle Ford. 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, 2022
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 proved 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; fair values of assets acquired and liabilities assumed in business combinations 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 Southern California 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 as an allowance for doubtful accounts at December 31, 2022 and 2021. 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, 2022 2021 Major customers: HF Sinclair Corporation (formerly: Sinclair Oil & Gas Company) 23 % 20 % Southwest Energy LP 13 % n/a % Koch Energy Services, LLC 13 % n/a % Phillips 66 n/a % 19 % ETC Texas Pipeline LTD n/a % 12 % 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 Wyoming and California 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 was no material capitalized exploratory drilling costs pending evaluation at December 31, 2022 and 2021. 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, 2022 and 2021. 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 offshore Southern California 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 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, 2022 and 2021 was approximately $0.6 million and $0.6 million, respectively. Impairments 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. 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, 2022 and 2021. 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, 2022 and 2021. 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. Net deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of deferred tax assets will not be realized. The valuation allowance serves to reduce the tax benefits recognized from the net deferred tax asset to an amount that is more likely than not to be realized based on the weight of all available evidence. The Company recognizes a tax 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, 2022 and 2021, the Company recognized LOPI insurance payments of $50.2 million and $6.7 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 provides 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.

Revenues

Revenues	12 Months Ended
Revenues	Dec. 31, 2022
Revenues
Revenues	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, 2022 2021 (in thousands) Revenues Oil $ 212,522 $ 212,486 NGLs $ 47,398 $ 40,899 Natural gas $ 147,841 $ 82,394 Oil and natural gas sales $ 407,761 $ 335,779 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 $35.1 million and $32.4 million at December 31, 2022 and 2021, 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, 2022
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, 2022 and 2021. 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, 2022 and 2021 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, 2022 and December 31, 2021 for each of the fair value hierarchy levels: 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 Fair Value Measurements at December 31, 2021 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 $ — $ 7,967 $ — $ 7,967 Interest rate derivatives — — — — Total assets $ — $ 7,967 $ — $ 7,967 Liabilities: Commodity derivatives $ — $ 70,152 $ — $ 70,152 Interest rate derivatives — 623 — 623 Total liabilities $ — $ 70,775 $ — $ 70,775 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 recorded for the year ended December 31, 2022 and 2021. ● 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. (i) No impairment expense on our unproved oil and natural gas properties recorded for the year ended December 31, 2022 and 2021.

Risk Management and Derivative

Risk Management and Derivative Instruments	12 Months Ended
Risk Management and Derivative Instruments	Dec. 31, 2022
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 provides 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. At December 31, 2022, after taking into effect netting arrangements, the Company had no counterparty exposure related to its derivative instruments. 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, 2022, the Company had the following open commodity positions: 2023 Natural Gas Derivative Contracts: Collar contracts: Two-way collars Average monthly volume (MMBtu) 1,160,000 Weighted-average floor price $ 3.49 Weighted-average ceiling price $ 5.92 Crude Oil Derivative Contracts: Fixed price swap contracts: Average monthly volume (Bbls) 55,000 Weighted-average fixed price $ 57.30 Collar contracts: Three-way collars Average monthly volume (Bbls) 30,000 Weighted-average ceiling price $ 67.15 Weighted-average floor price $ 55.00 Weighted-average sub-floor price $ 40.00 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, 2022 and 2021. There was no cash collateral received or pledged associated with its derivative instruments since most 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 2022 2022 2021 2021 (In thousands) Commodity contracts Short-term derivative instruments $ 6,257 $ 27,141 $ 4,804 $ 57,325 Interest rate swaps Short-term derivative instruments — — — 623 Gross fair value 6,257 27,141 4,804 57,948 Netting arrangements (6,257) (6,257) (4,804) (4,804) Net recorded fair value Short-term derivative instruments $ — $ 20,884 $ — $ 53,144 Commodity contracts Long-term derivative instruments $ — $ — $ 3,163 $ 12,827 Interest rate swaps Long-term derivative instruments — — — — Gross fair value — — 3,163 12,827 Netting arrangements — — (3,163) (3,163) Net recorded fair value Long-term derivative instruments $ — $ — $ — $ 9,664 (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 2022 2021 Commodity derivative contracts Loss (gain) on commodity derivatives $ 106,937 $ 142,439 (Gain) loss on interest rate derivatives Interest expense, net (935) (217)

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
Asset Retirement Obligations	Dec. 31, 2022
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, 2022 and 2021 (in thousands): For the Year Ended December 31, 2022 2021 Asset retirement obligations at beginning of period $ 103,414 $ 97,149 Liabilities added from acquisition or drilling 20 29 Liabilities settled (923) (296) Liabilities removed upon sale of wells — (113) Accretion expense 7,081 6,611 Revision of estimates 6,846 34 Asset retirement obligation at end of period 116,438 103,414 Less: Current portion 1,824 1,016 Asset retirement obligations - long-term portion $ 114,614 $ 102,398

Restricted Investments

Restricted Investments	12 Months Ended
Restricted Investments	Dec. 31, 2022
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 Southern California oil and gas properties. The components of the restricted investment balances are as follows: December 31, 2022 2021 (In thousands) BOEM platform abandonment (See Note 16) $ 7,016 $ 313 SPBPC Collateral: Contractual pipeline and surface facilities abandonment 4,310 4,309 Restricted investments $ 11,326 $ 4,622

Debt

Debt	12 Months Ended
Debt	Dec. 31, 2022
Debt
Debt	Note 8. Debt The Company’s consolidated debt obligations consisted of the following at the dates indicated: December 31, December 31, 2022 2021 (In thousands) Revolving Credit Facility (1) $ 190,000 $ 230,000 Total long-term debt $ 190,000 $ 230,000 (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. Revolving Credit Facility On November 2, 2018, OLLC and Amplify Acquisitionco, Inc. (“Acquistionco”) entered into a credit agreement (the “Credit Agreement”), providing for a reserve-based revolving credit facility (the “Revolving Credit Facility”), subject to a borrowing base of $210.0 million as of December 31, 2022, which is guaranteed by us and all of the Company’s current subsidiaries. The Credit Agreement matures on November 2, 2023. The borrowing base under the Company’s Credit Agreement is subject to redetermination on at least a semi-annual basis based on an engineering report with respect to its 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. The terms and conditions under the original Credit Agreement include (but are not limited to) the following: ● at OLLC’s option, borrowings under the Credit Agreement will bear interest at the base rate, LIBOR Market Index rate or LIBOR plus an applicable margin. Base rate loans bear interest at a rate per annum equal to the greatest of: (i) the federal funds effective rate plus 50 basis points, (ii) the rate of interest in effect for each day as publicly announced from time to time by the agent as its “prime rate”; and (iii) the adjusted LIBOR rate for a one-month interest period plus 100 basis points per annum. The applicable margin for base rate loans ranges from 100 to 200 basis points, and the applicable margin for LIBOR loans and LIBOR Market loans ranges from 200 to 300 basis points, in each case depending on the percentage of the borrowing base utilized; ● the obligations under the Revolving Credit Facility are secured by mortgages on not less than 85% of the PV-9 value of oil and gas properties (and at least 85% of the PV-9 value of the proved, developed and producing oil and gas properties) included in the determination of the borrowing base. OLLC and its other subsidiaries entered into a pledge and security agreement in favor of the agent for the secured parties, pursuant to which OLLC’s obligations under the Credit Agreement are secured by a first priority security interest in substantially all of our assets (subject to permitted liens). Additionally, the Company entered into a non-recourse pledge agreement in favor of the agent for the secured parties, pursuant to which OLLC’s obligations under the Credit Agreement are secured by a pledge and security interest of 100% of the equity interests held by the Company in Acquisitionco; ● 0.5% fee on unused line of credit; ● certain financial covenants, including the maintenance of (i) as of the date of determination, a maximum total debt to EBITDAX ratio of 4.00 to 1.00, and (ii) a current ratio of not less than 1.00 to 1.00; and ● 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. Borrowing Base Redetermination Agreement and Seventh Amendment On December 9, 2022, OLLC, entered into the Borrowing Base Redetermination Agreement and Seventh Amendment to Credit Agreement. The Seventh Amendment amends the Revolving Credit Facility, to, among other things: ● extend the maturity date from November 2, 2023 to May 31, 2024; ● reduce the borrowing base under the Revolving Credit Facility to $215.0 million; provided that, beginning on December 31, 2022, the borrowing base will be reduced by $5.0 million per month on the last calendar day of each month. The borrowing base, as reduced on each date pursuant to the foregoing sentence, shall remain in effect until otherwise redetermined or adjusted in accordance with the provisions of the Credit Agreement; ● adjust the minimum hedging requirements; ● reduce the maximum consolidated net leverage ratio (as defined in the Credit Agreement) requirement from 4.00 to 1.00 to 3.00 to 1.00; ● transition from London Inter-Bank Offered Rate to Secured Overnight Financing Rate based interest rates; and ● remove the Company’s ability to pay dividends through the maturity date. Borrowing Base Redetermination Agreement and Sixth Amendment On June 20, 2022, OLLC entered into the Borrowing Base Redetermination Agreement and Sixth Amendment to the Credit Agreement. The Sixth Amendment amends the Revolving Credit Facility to, among other things: ● terminate the automatic monthly reductions of the borrowing base; ● reaffirm the borrowing base under the Revolving Credit Facility at $225.0 million and; ● modify the affirmative hedging covenant. Borrowing Base Redetermination Agreement and Fifth Amendment On November 10, 2021, the Company completed its scheduled semi-annual borrowing base redetermination process, pursuant to which the borrowing base under the Revolving Credit Facility was reaffirmed at $245.0 million; provided that, beginning on February 28, 2022, the borrowing base will be reduced by $5.0 million per month on the last calendar day of each month until the next regularly scheduled redetermination, which is expected to occur in April 2022. Borrowing Base Redetermination On June 16, 2021, the Company completed its scheduled semi-annual borrowing base redetermination process, pursuant to which the borrowing base under the Revolving Credit Facility was decreased from $260.0 million to $245.0 million. In addition to the redetermination, the administrative agent under the Revolving Credit Facility agreement was changed from Bank of Montreal to KeyBank. Debt Compliance As of December 31, 2022, we were in compliance with all the financial (current ratio and total leverage ratio) and non-financial covenants associated with the Company’s Revolving Credit Facility. Paycheck Protection Program On April 24, 2020, the Company received a $5.5 million loan under the Paycheck Protection Program (the “PPP Loan”). The Paycheck Protection Program was established as part of the CARES Act to provide loans to qualifying businesses. The loans and accrued interest are potentially forgivable, provided that the borrower uses the loan proceeds for eligible purposes. The term of the Company’s PPP Loan was two years with an annual interest rate of 1% and no payments of principal or interest due during the six-month period beginning on the date of the PPP Loan. The Company applied for forgiveness of the amount due on the PPP Loan based on spending the loan proceeds on eligible expenses as defined by the statute. On June 22, 2021, KeyBank notified the Company that the PPP Loan had been approved for full and complete forgiveness by the Small Business Association. For the year ended December 31, 2021, the Company reported a gain on extinguishment of debt of $5.5 million for the PPP Loan forgiveness in the Consolidated Statements of Operations. 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, 2022 2021 Revolving Credit Facility 5.36 % 3.65 % Letters of credit At December 31, 2022, the Company had no letters of credit outstanding. Unamortized Deferred Financing Costs Unamortized deferred financing costs associated with the Revolving Credit Facility was $1.5 million at December 31, 2022. 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.

Equity (Deficit)

Equity (Deficit)	12 Months Ended
Equity (Deficit)	Dec. 31, 2022
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, 2020 37,663,509 Issuance of common stock — Restricted stock units vested 77,985 Bonus stock awards (1) 455,973 Shares withheld for taxes (2) (173,325) Balance, December 31, 2021 38,024,142 Issuance of common stock — Restricted stock units vested 534,834 Shares withheld for taxes (2) (99,245) Balance, December 31, 2022 38,459,731 (1) Reflects shares granted to certain executive officers and employees pursuant to the Company’s annual incentive bonus program. Shares were granted on February 12, 2021 at a grant price of $2.48 per share. (2) Represents the net settlement on vesting of restricted stock necessary to satisfy the minimum statutory 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, 2022
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, 2022 2021 Net income (loss) $ 57,875 $ (32,070) Less: Net income allocated to participating securities 2,728 — Basic and diluted earnings available to common stockholders $ 55,147 $ (32,070) Common shares: Common shares outstanding — basic 38,351 37,959 Dilutive effect of potential common shares — — Common shares outstanding — diluted 38,351 37,959 Net earnings (loss) per share: Basic $ 1.44 $ (0.84) Diluted $ 1.44 $ (0.84) Antidilutive warrants (1) — 2,174 (1) Amount represents warrants to purchase common stock that are excluded from the diluted net earnings per share calculations because of their antidilutive effect .

Equity-based Awards

Equity-based Awards	12 Months Ended
Equity-based Awards	Dec. 31, 2022
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, 2022, the Company had 1,570,403 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 $3.6 million at December 31, 2022. The Company expects to recognize the unrecognized compensation cost for these awards over a weighted-average period of 1.7 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, 2020 115,797 $ 4.47 Granted (2) 1,083,644 $ 3.65 Forfeited (52,601) $ 3.73 Vested (72,420) $ 4.74 TSUs outstanding at December 31, 2021 1,074,420 $ 3.66 Granted (3) 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 (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, 2021 was $4.0 million based on a grant date market price ranging from $3.52 to $4.66 per share. (3) 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. Restricted Stock Units with Market and Service Vesting Conditions Restricted stock units with market and service vesting conditions (“PSUs”) are accounted for as equity-classified awards. The grant-date fair value is recognized as compensation cost on a graded-vesting basis. As such, the Company recognizes compensation cost over the requisite service period for each separately vesting tranche of the award as though the award were, in substance, multiple awards. The Company accounts for forfeitures as they occur. Compensation costs are recorded as general and administrative expense. The unrecognized cost related to the PSUs was less than $0.1 million at December 31, 2022. The Company expects to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 0.6 years. The PSUs will vest based on the satisfaction of service and market vesting conditions with market vesting based on the Company’s achievement of certain share price targets. The PSUs are subject to service-based vesting such that 50% of the PSUs service vest on the applicable market vesting date and an additional 25% of the PSUs service vest on each of the first In the event of a qualifying termination, subject to certain conditions, (i) all PSUs that have satisfied the market vesting conditions will fully service vest, upon such termination, and (ii) if the termination occurs between the second and third anniversaries of the grant date, then PSUs that have not market vested as of the termination will market vest to the extent that the share targets (in each case, reduced by $0.25) are achieved as of such termination. Subject to the foregoing, any unvested PSUs will be forfeited upon termination of employment. A Monte Carlo simulation was used to determine the fair value of these awards at the grant date. The following table summarizes information regarding the PSUs granted under EIP for the period presented: Weighted- Average Grant- Number of Date Fair Value Units per Unit (1) PSUs outstanding at December 31, 2020 214,554 $ 2.36 Granted — $ — Forfeited (148,614) $ 2.13 Vested — $ — PSUs outstanding at December 31, 2021 65,940 $ 2.87 Granted — $ — Forfeited (22,614) $ 2.57 Vested — $ — PSUs & outstanding at December 31, 2022 43,326 $ 3.03 (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. Restricted Stock Units with Market Vesting Conditions The restricted stock units with performance-based vesting conditions (“PRSUs”) are accounted for as equity-classified awards. The grant-date fair value is recognized as compensation cost on a graded-vesting basis. As such, the Company recognizes compensation cost over the requisite service period for each separately vesting tranche of the award as though the award were, in substance, multiple awards. The Company accounts for forfeitures as they occur. Compensation costs are recorded as general and administrative expense. 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 performance period. The fair value of each PRSU award was estimated on their grant dates using a Monte Carlo simulation. The 2022 PRSUs were issued with a three-year vesting period beginning on the grant date and ending on the third anniversary of the grant date. The 2021 PRSUs awards were issued collectively in separate tranches with individual performances periods beginning in January 2021, 2022, and 2023 respectively. For each of the 2021 PRSUs awards the performance period, will vest based on the percentage of the target PRSUs subject to the performance vesting condition with 25% able to vest during the period January 1, 2021 through December 31, 2022; 25% able to vest during the period January 1, 2022 through December 31, 2022 and 50% able to vest during the period of January 1, 2023 through December 31, 2023. The unrecognized cost associated with the PRSUs was $0.9 million at December 31, 2022. The Company expects to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 2.0 years. The ranges for the assumptions used in the Monte Carlo model for the 2022 PRSUs granted are presented as follows: 2022 Expected volatility 120.8 % Dividend yield 0.00 % Risk-free interest rate 1.38 % The following table summarizes information regarding the PRSUs granted under the EIP for the period presented: Weighted- Average Grant- Number of Date Fair Value Units per Unit (1) PRSUs outstanding at December 31, 2020 — $ — Granted (2) 196,377 $ 1.94 Forfeited — $ — Vested — $ — PRSUs outstanding at December 31, 2021 196,377 $ 1.94 Granted (3) 189,904 $ 6.20 Forfeited — $ — Vested (49,095) $ 1.24 PRSUs outstanding at December 31, 2022 337,186 $ 4.44 (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, 2021 was $0.4 million based on a calculated fair value price ranging from $1.24 to $2.63 per share. (3) 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. 2017 Non-Employee Directors Compensation Plan As noted above, the Legacy Amplify Non-Employee Directors Compensation Plan was replaced by the EIP in May 2021. Any new director award granted after the implementation of the EIP is reflected above within our TSUs awards table. The Legacy Amplify Non-Employee Directors Compensation Plan awards were granted in the form of nonqualified stock options, restricted stock awards, restricted stock units, and other cash-based awards and stock-based awards. To the extent that an award under the Legacy Amplify Non-Employee Directors Compensation Plan is expired, forfeited or canceled for any reason without having been exercised in full, the unexercised award would then be available again for grant under the Legacy Amplify Non-Employee Directors Compensation Plan. Awards granted generally vest annually in three equal installments on each of the first three anniversaries of the grant date, subject to the grantee’s continued employment through each such vesting date. The restricted stock units with a service vesting condition (“Board RSUs”) granted 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. The following table summarizes information regarding the Board RSUs granted under the Director Compensation Plan for the period presented: Weighted- Average Grant- Number of Date Fair Value Units per Unit (1) Board RSUs outstanding at December 31, 2020 8,898 $ 5.12 Granted — $ — Forfeited — $ — Vested (5,565) $ 5.12 Board RSUs outstanding at December 31, 2021 3,333 $ 5.12 Granted — $ — Forfeited — $ — Vested (3,333) $ 5.12 Board RSUs outstanding at December 31, 2022 — $ — (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued. 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, 2022 2021 Equity classified awards TSUs $ 2,648 $ 1,541 PSUs and PRSUs 440 48 Board RSUs 5 16 $ 3,093 $ 1,605

Leases

Leases	12 Months Ended
Leases	Dec. 31, 2022
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 offshore Southern California pipeline right-of-way use agreements. For the year ended December 31, 2022, 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, 2022 and 2021, the Company recognized approximately $1.6 million and $2.7 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, 2022 2021 (In thousands) Right-of-use asset $ 7,376 $ 2,716 Lease liabilities: Current lease liability 1,401 777 Long-term lease liability 6,567 2,017 Total lease liability $ 7,968 $ 2,794 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 2023 $ 1,357 $ 860 $ 2,217 2024 1,357 651 2,008 2025 1,357 436 1,793 2026 1,140 — 1,140 2027 and thereafter 2,440 — 2,440 Total lease payments 7,651 1,947 9,598 Less: interest 1,459 171 1,630 Present value of lease liabilities $ 6,192 $ 1,776 $ 7,968 The weighted average remaining lease terms and discount rate for all of the Company’s operating leases for the period presented: December 31, 2022 2021 Weighted average remaining lease term (years): Office and warehouse space 4.71 3.51 Vehicles 0.47 0.37 Office equipment 0.04 — Weighted average discount rate: Office leases 4.87 % 2.95 % Vehicles 1.30 % 0.59 % Office equipment 0.11 % 0.02 %

Supplemental Disclosures to the

Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows	12 Months Ended
	Dec. 31, 2022
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, 2022 2021 Accrued liability - pipeline incident $ 20,832 $ 34,417 Accrued liability - current portion of pipeline incident settlement 4,888 — Accrued lease operating expense 11,226 9,271 Accrued commitment fee and other expense 5,824 2,882 Accrued production and ad valorem tax 4,675 3,277 Accrued general and administrative expense 4,943 4,555 Accrued capital expenditures 2,714 1,631 Operating lease liability 1,401 777 Asset retirement obligations 1,824 1,016 Other 122 — Accrued liabilities $ 58,449 $ 57,826 Accounts Receivable Accounts receivable consisted of the following at the dates indicated (in thousands): December 31, December 31, 2022 2021 Oil and natural gas receivables $ 35,083 $ 32,428 Insurance receivable - pipeline incident 41,961 49,098 Insurance receivable - LOPI — 6,667 Joint interest owners and other 5,047 5,409 Total accounts receivable 82,091 93,602 Less: allowance for doubtful accounts (1,636) (1,635) Total accounts receivable, net $ 80,455 $ 91,967 Supplemental Cash Flows Supplemental cash flow for the periods presented (in thousands): For the Year Ended December 31, 2022 2021 Supplemental cash flows: Cash paid for interest, net of amounts capitalized $ 11,209 $ 8,637 Cash paid for reorganization items, net — 6 Cash paid for taxes 93 — Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities 1,012 1,669

Related Party Transactions

Related Party Transactions	12 Months Ended
Related Party Transactions	Dec. 31, 2022
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, 2022 and 2021.

Southern California Pipeline In

Southern California Pipeline Incident	12 Months Ended
Southern California Pipeline Incident	Dec. 31, 2022
Southern California Pipeline Incident
Southern California Pipeline Incident	Note 15. Southern California 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 BSEE’s 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 our pipeline, and that additional vessels of interest continue 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 had reopened. On February 2, 2022, the Unified Command announced that response and monitoring efforts had officially concluded for the Incident, and Unified Command would stand down as of such date. Amplify remains grateful to its Unified Command partners for their collaboration and professionalism over the course of the response. In response to the Incident, all operations have been suspended and the pipeline has been shut-in until the Company receives the required regulatory approvals to restart operations. On October 4, 2021, the Pipeline and Hazardous Materials Safety Administration (PHMSA), Office of Pipeline Safety (OPS) issued a Corrective Action Order (CAO) 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. The Company is working expeditiously and cooperatively to comply with the requirements of the relevant agencies in order to gain any other regulatory approvals that are necessary to restart operations. Amplify has successfully completed pipeline repair operations and is awaiting approval by federal pipeline safety regulators to restart production. As a result of the uncertainties related to the regulatory approval process, the Company can provide no assurances as to whether and when, if at all, operations will restart at the Beta field. At present, no operations are underway in the Beta field. 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 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 U.S. Environmental Protection Agency (“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. 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 of Los Angeles-Long Beach Harbor (“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 have 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. The Court has set a trial for April 24, 2023 in the consolidated limitation action. 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. The final approval papers were submitted to the Court on January 25, 2023 and a final approval hearing is scheduled for April 24, 2023. Subsequent Events 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 $160.0 million to $170.0 million, which includes (i) actual and projected response and remediation under the direction of the Unified Command, (ii) estimated 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, 2022 and December 31, 2021, the Company’s insurance receivables were $42.0 million and $49.1 million, respectively. Excluding the costs associated with the resolution of the federal and state matters discussed above, the year ended December 31, 2022, the Company incurred response and remediation expenses and legal fees of $53.6 million. Of these costs, the Company has received or expects that it is probable that it will receive, $42.3 million in insurance recoveries. The remaining amount of $11.3 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, 2022 and 2021, the Company recognized $50.2 million and $6.7 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, 2022
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, 2022 and 2021, the Company had no environmental reserves recorded. Southern California Pipeline Incident The Company and certain of its subsidiaries are named defendants in a putative class action pending in the United States District Court for the Central District of California. The Company is also participating in a related claims process organized under the Oil Pollution Act of 1990, 33 U.S.C. § 2701 et seq. (“OPA 90”). Under OPA 90, a party alleged to be responsible for a discharge of oil is required to establish a claims process to pay for interim costs and damages as a result of the discharge. The OPA 90 claims process remains ongoing. 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, and the final agreement will be subject to court approval. The Court preliminarily approved the settlement on December 7, 2022. The final approval papers were submitted to the Court on January 25, 2023 and a final approval hearing is scheduled for April 24, 2023. On August 26, 2022, the Company reached an agreement with the United States government, which the court has approved, to resolve all federal criminal matters involving the Company and its subsidiaries stemming from Incident. 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. The Company also has agreed to implement certain compliance measures including installation of a new leak detection system and increased Remote Operated Vehicle inspections of the pipeline. As a result of this agreement, the Company’s Consolidated Statements of Operations for the year ended December 31, 2022 included $7.1 million in expenses classified as “Pipeline Incident Settlement.” As of December 31, 2022, the Company recorded $2.0 million in “Accrued liability−pipeline incident” and $3.1 million in “Other long-term liabilities” for the remaining payments related to this settlement on its Consolidated Balance Sheet. On September 8, 2022, the Company reached an agreement with the state of California to resolve all related state criminal matters. As part of the resolution with the state of California, which also has court approval, 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 also will serve a one-year term of probation and has agreed to certain compliance enhancements to its operations. As a result of this agreement, the Company’s Consolidated Statements of Operations for the year ended December 31, 2022 included $4.9 million in expenses classified as “Pipeline Incident Settlement.” As of December 31, 2022, the Company recorded $2.9 million in “Accrued liability−pipeline incident” for the remaining payments related to this settlement on its Consolidated Balance Sheet. Subsequent Events Future litigation may be necessary, among other things, to defend ourselves by determining the scope, enforceability, and validity of claims. The results of any current or future litigation cannot be predicted with certainty, and regardless of the outcome, litigation can have an adverse impact on us because of defense and settlement costs, diversion of management resources, and other factors. 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 Company properties in federal waters offshore Southern California, 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, 2022, the account balance included in restricted investments was approximately $4.3 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 and $7.0 million in cash at December 31, 2022. The Company’s existing bonding arrangements issued in connection with the decommissioning obligations related to our Beta properties contain additional collateral requirements pursuant to which we may be required to post collateral at any time, on demand, at the sureties’ sole discretion, which may negatively impact our liquidity position. 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. The table below outlines our funding commitment under these agreements at December 31, 2022 (in thousands): Payment Due by Period Funding commitment Total 2023 2024 2025 2026 2027 Thereafter (1) Sinking fund payments $ 165,913 $ 8,025 $ 15,789 $ 15,789 $ 15,789 $ 15,789 $ 94,732 (1) The remaining payments will be made during the years of 2028 through 2033. The expense related to the surety bonds is recorded in interest expense in the Company Statement of Consolidated Operations. Operating Leases We have leases for offshore Southern California pipeline right-of-way use as well as office space in our operating regions. We also lease equipment, compressors and incur surface rentals related to its business operations. For the years ended December 31, 2022 and 2021, the Company recognized $8.7 million and $7.6 million of rent expense, 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, 2022, the Company had a CO 2 2 2 Payment or Settlement Due by Period Purchase commitment Total 2023 2024 2025 2026 2027 Thereafter CO 2 $ 11,876 $ 3,851 $ 4,076 $ 3,949 $ — $ — $ — Minimum Volume Commitment At December 31, 2022, the Company has a long-term minimum volume commitment with a third party associated with a certain portion of its properties located in Oklahoma. The table below outlines the future payment commitments associated with the minimum volume commitment plus any applicable fee for not meeting the minimum volume commitment (in thousands): Payment or Settlement Due by Period (1) Total 2023 2024 2025 2026 2027 Thereafter Minimum volume commitment $ 3,243 $ 3,243 $ — $ — $ — $ — $ — (2) The amounts in the table do not reflect costs adjusted for inflation. The Company is party to a gathering and processing contract in Oklahoma, which includes certain minimum NGL commitments. To the extent the Company does not deliver natural gas volumes in sufficient quantities to generate, when processed, the minimum levels of recovered NGLS, it would be required to reimburse the counterparty an amount equal to the sum of the monthly shortfall, if any, multiplied by a fee. The Company is not meeting the minimum volume required under these contractual provisions. The commitment fee expense for the year ended December 31, 2022 and 2021, was approximately $1.8 million and $1.6 million, respectively. The minimum volume commitment for Oklahoma ends on June 30, 2023. The Company was a party to a gas purchase, gathering and processing contract in East Texas, which includes certain minimum gas commitments. The Company did not meet the minimum volume required under this contractual provision. The commitment fee expense for the year ended December 31, 2022 and 2021, was approximately $1.9 million and $2.0 million, respectively. The minimum volume commitment for East Texas ended on November 30, 2022.

Income Tax

Income Tax	12 Months Ended
Income Tax	Dec. 31, 2022
Income Tax
Income Tax	Note 17. Income Tax Amplify Energy is a corporation and, as a result, is subject to U.S. federal, state, and local income taxes. In August 2022, the President of the United States signed the Inflation Reduction Act (IRA), to respond to the high inflation and its economic effects. The enactment of the IRA did not impact the Company’s current year income tax provision. The components of income tax benefit (expense) are as follows: For the Year Ended December 31, 2022 2021 (In thousands) Current taxes: Federal $ — $ — State (111) — Total current income tax benefit (expense) (111) — Deferred taxes: Federal — — State — — Total deferred income tax benefit (expense) — — Total income tax benefit (expense) $ (111) $ — The actual income tax benefit (expense) differs from the expected amount computed by applying the federal statutory corporate tax rate of 21% in 2022 and in 2021 as follows: For the Year Ended December 31, 2022 2021 (In thousands) Expected tax benefit (expense) at federal statutory rate $ (12,177) $ 6,734 Changes in valuation allowances 12,267 3,192 Federal prior year adjustments 1,673 — Fines & penalties (1,939) — State income tax benefit (expense), net of federal benefit (1,859) 447 State rate change, net of federal benefit 1,532 (10,192) State prior year adjustment (234) (1,281) PPP loan forgiveness — 1,158 Other 626 (58) Total income tax benefit (expense) $ (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, 2022 2021 Deferred income tax assets: Property, plant & equipment $ 82,152 $ 94,439 Net operating loss carryforward 183,050 178,279 Derivatives 4,800 14,438 Disallowed interest expense 7,467 5,579 Accrued liabilities 2,008 1,592 Other 7,103 3,469 Total deferred income tax assets: 286,580 297,796 Valuation allowance (284,928) (297,195) Net deferred income tax assets 1,652 601 Deferred income tax liabilities: Derivatives $ — $ — Other 1,652 601 Total deferred income tax liabilities 1,652 601 Net deferred income taxes $ — $ — Net Operating Loss Carryforward As of December 31, 2022, the Company had approximately $453.7 million of state net operating loss carryovers, of which $399.5 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, 2022
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, 2022 2021 (In thousands) Evaluated oil and natural gas properties $ 840,310 $ 799,532 Support equipment and facilities 147,496 145,324 Accumulated depletion, depreciation, and amortization (648,900) (625,754) Total $ 338,906 $ 319,102 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, 2022 2021 (In thousands) Property acquisition costs, proved $ — $ 3 Property acquisition costs, unproved — — Exploration — — Development 42,949 27,478 Total $ 42,949 $ 27,481 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, 2022 and 2021. 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: 2022 2021 Oil ($/Bbl): WTI (1) $ 93.67 $ 66.56 NGL ($/Bbl): WTI (1) $ 93.67 $ 66.56 Natural Gas ($/MMbtu): Henry Hub (2) $ 6.36 $ 3.60 (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, 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 year 43,857 309,794 23,574 119,063 End of year 47,010 312,185 23,928 122,969 Proved undeveloped reserves: Beginning of year 1,144 4,556 263 2,167 End of year 858 607 98 1,058 (1) Our reserves related to our Beta properties are classified as proved developed non-producing at December 31, 2022. For the Year Ended December 31, 2021 Oil Gas NGLs Total (MBbls) (MMcf) (MBbls) (MBoe) Proved developed and undeveloped reserves: Beginning of year 46,676 274,139 21,484 113,849 Extensions and discoveries 746 4,283 215 1,674 Production (3,351) (23,808) (1,430) (8,747) Sale of minerals in place (3) (274) (12) (61) Revision of previous estimates 933 60,010 3,580 14,515 End of year 45,001 314,350 23,837 121,230 Proved developed reserves (1) : Beginning of period 35,613 252,218 19,009 96,658 End of period 43,857 309,794 23,574 119,063 Proved undeveloped reserves (2) : Beginning of period 11,063 21,921 2,475 17,191 End of period 1,144 4,556 263 2,167 (1) Our reserves related to our Beta properties were reclassified as proved developed non-producing at December 31, 2021. (2) Change to the Company’s development plan has resulted in removal of PUD locations in Oklahoma, Rockies and California. Noteworthy amounts included in the categories of proved reserve changes in the above tables include: ● 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. ● The 7.4 MMBoe increase in reserves for the year ended December 31, 2021 is primarily due to a 30.6 MMBoe increase as a result of changes in commodity pricing offset by a 16 MMBoe reduction due to removed PUD locations in Oklahoma, Rockies and California. The Company has shifted its resources to returning Beta to production and as a result has modified future PUD development plans. The Company also had 1.7 MMBoe of extension and discoveries primarily related to wells in progress at year end in Eagle Ford and East Texas, a 1.2 MMBoe reduction due to an increase in maintenance costs and a 0.9 MMBoe upward technical revision. 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, 2022 2021 (In thousands) Future cash inflows $ 7,373,499 $ 4,569,313 Future production costs (1) (3,824,348) (2,691,875) Future development costs (1) (309,188) (231,040) Future income tax expense (520,731) — Future net cash flows for estimated timing of cash flows 2,719,232 1,646,398 10% annual discount for estimated timing of cash flows (1,381,276) (726,553) Standardized measure of discounted future net cash flows $ 1,337,956 $ 919,845 (1) For the years ended December 31, 2022 and 2021, 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, 2022 2021 (In thousands) Beginning of year $ 919,845 $ 297,811 Changes in prices and costs 856,545 572,897 Net change in taxes (311,412) — Sale of oil and natural gas produced, net of production costs (213,667) (171,326) Accretion of discount 91,985 29,781 Change in production rates and other (57,484) (31,423) Net changes in future development costs (20,129) 113,546 Revisions of previous quantities 59,216 46,271 Previously estimated development costs incurred 13,057 45,298 Sale of minerals in place — (45) Extensions and discoveries — 17,035 End of year $ 1,337,956 $ 919,845

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2022
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, federal waters offshore Southern California, East Texas/North Louisiana and the Eagle Ford. 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 proved 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; fair values of assets acquired and liabilities assumed in business combinations 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 Southern California 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 as an allowance for doubtful accounts at December 31, 2022 and 2021. 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, 2022 2021 Major customers: HF Sinclair Corporation (formerly: Sinclair Oil & Gas Company) 23 % 20 % Southwest Energy LP 13 % n/a % Koch Energy Services, LLC 13 % n/a % Phillips 66 n/a % 19 % ETC Texas Pipeline LTD n/a % 12 %
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 Wyoming and California 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 was no material capitalized exploratory drilling costs pending evaluation at December 31, 2022 and 2021.
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, 2022 and 2021. 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 offshore Southern California 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 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, 2022 and 2021 was approximately $0.6 million and $0.6 million, respectively.
Impairments	Impairments 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. 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, 2022 and 2021. 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, 2022 and 2021.
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. Net deferred tax assets are reduced by a valuation allowance if, based on the weight of available evidence, it is more likely than not that some portion or all of deferred tax assets will not be realized. The valuation allowance serves to reduce the tax benefits recognized from the net deferred tax asset to an amount that is more likely than not to be realized based on the weight of all available evidence. The Company recognizes a tax 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, 2022 and 2021, the Company recognized LOPI insurance payments of $50.2 million and $6.7 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 provides 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, 2022
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, 2022 2021 Major customers: HF Sinclair Corporation (formerly: Sinclair Oil & Gas Company) 23 % 20 % Southwest Energy LP 13 % n/a % Koch Energy Services, LLC 13 % n/a % Phillips 66 n/a % 19 % ETC Texas Pipeline LTD n/a % 12 %

Revenues (Tables)

Revenues (Tables)	12 Months Ended
Revenues (Tables)	Dec. 31, 2022
Revenues
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, 2022 2021 (in thousands) Revenues Oil $ 212,522 $ 212,486 NGLs $ 47,398 $ 40,899 Natural gas $ 147,841 $ 82,394 Oil and natural gas sales $ 407,761 $ 335,779

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, 2022
Fair Value Measurements of Financial Instruments
Assets and Liabilities Measured at Fair Value on Recurring Basis	The following table presents the derivative assets and liabilities that are measured at fair value on a recurring basis at December 31, 2022 and December 31, 2021 for each of the fair value hierarchy levels: 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 Fair Value Measurements at December 31, 2021 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 $ — $ 7,967 $ — $ 7,967 Interest rate derivatives — — — — Total assets $ — $ 7,967 $ — $ 7,967 Liabilities: Commodity derivatives $ — $ 70,152 $ — $ 70,152 Interest rate derivatives — 623 — 623 Total liabilities $ — $ 70,775 $ — $ 70,775

Risk Management and Derivativ_2

Risk Management and Derivative Instruments (Tables)	12 Months Ended
Risk Management and Derivative Instruments (Tables)	Dec. 31, 2022
Risk Management and Derivative Instruments
Open Commodity Positions	At December 31, 2022, the Company had the following open commodity positions: 2023 Natural Gas Derivative Contracts: Collar contracts: Two-way collars Average monthly volume (MMBtu) 1,160,000 Weighted-average floor price $ 3.49 Weighted-average ceiling price $ 5.92 Crude Oil Derivative Contracts: Fixed price swap contracts: Average monthly volume (Bbls) 55,000 Weighted-average fixed price $ 57.30 Collar contracts: Three-way collars Average monthly volume (Bbls) 30,000 Weighted-average ceiling price $ 67.15 Weighted-average floor price $ 55.00 Weighted-average sub-floor price $ 40.00
Gross Fair Value of Derivative Instruments by Appropriate Balance Sheet	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, 2022 and 2021. There was no cash collateral received or pledged associated with its derivative instruments since most 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 2022 2022 2021 2021 (In thousands) Commodity contracts Short-term derivative instruments $ 6,257 $ 27,141 $ 4,804 $ 57,325 Interest rate swaps Short-term derivative instruments — — — 623 Gross fair value 6,257 27,141 4,804 57,948 Netting arrangements (6,257) (6,257) (4,804) (4,804) Net recorded fair value Short-term derivative instruments $ — $ 20,884 $ — $ 53,144 Commodity contracts Long-term derivative instruments $ — $ — $ 3,163 $ 12,827 Interest rate swaps Long-term derivative instruments — — — — Gross fair value — — 3,163 12,827 Netting arrangements — — (3,163) (3,163) Net recorded fair value Long-term derivative instruments $ — $ — $ — $ 9,664
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 2022 2021 Commodity derivative contracts Loss (gain) on commodity derivatives $ 106,937 $ 142,439 (Gain) loss on interest rate derivatives Interest expense, net (935) (217)

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
Asset Retirement Obligations (Tables)	Dec. 31, 2022
Asset Retirement Obligations
Summary of Changes in 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, 2022 and 2021 (in thousands): For the Year Ended December 31, 2022 2021 Asset retirement obligations at beginning of period $ 103,414 $ 97,149 Liabilities added from acquisition or drilling 20 29 Liabilities settled (923) (296) Liabilities removed upon sale of wells — (113) Accretion expense 7,081 6,611 Revision of estimates 6,846 34 Asset retirement obligation at end of period 116,438 103,414 Less: Current portion 1,824 1,016 Asset retirement obligations - long-term portion $ 114,614 $ 102,398

Restricted Investments (Tables)

Restricted Investments (Tables)	12 Months Ended
Restricted Investments (Tables)	Dec. 31, 2022
Restricted Investments
Restricted Investment Balances	December 31, 2022 2021 (In thousands) BOEM platform abandonment (See Note 16) $ 7,016 $ 313 SPBPC Collateral: Contractual pipeline and surface facilities abandonment 4,310 4,309 Restricted investments $ 11,326 $ 4,622

Debt (Tables)

Debt (Tables)	12 Months Ended
Debt (Tables)	Dec. 31, 2022
Debt
Consolidated Debt Obligations	The Company’s consolidated debt obligations consisted of the following at the dates indicated: December 31, December 31, 2022 2021 (In thousands) Revolving Credit Facility (1) $ 190,000 $ 230,000 Total long-term debt $ 190,000 $ 230,000 (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	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, 2022 2021 Revolving Credit Facility 5.36 % 3.65 %

Equity (Deficit) (Tables)

Equity (Deficit) (Tables)	12 Months Ended
Equity (Deficit) (Tables)	Dec. 31, 2022
Equity (Deficit)
Summary of Changes in Common Stock Issued	Common Stock Balance, December 31, 2020 37,663,509 Issuance of common stock — Restricted stock units vested 77,985 Bonus stock awards (1) 455,973 Shares withheld for taxes (2) (173,325) Balance, December 31, 2021 38,024,142 Issuance of common stock — Restricted stock units vested 534,834 Shares withheld for taxes (2) (99,245) Balance, December 31, 2022 38,459,731 (1) Reflects shares granted to certain executive officers and employees pursuant to the Company’s annual incentive bonus program. Shares were granted on February 12, 2021 at a grant price of $2.48 per share. (2) Represents the net settlement on vesting of restricted stock necessary to satisfy the minimum statutory tax withholding requirements.

Earnings (Loss) per Share (Tabl

Earnings (Loss) per Share (Tables)	12 Months Ended
Earnings (Loss) per Share (Tables)	Dec. 31, 2022
Earnings (Loss) per Share
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, 2022 2021 Net income (loss) $ 57,875 $ (32,070) Less: Net income allocated to participating securities 2,728 — Basic and diluted earnings available to common stockholders $ 55,147 $ (32,070) Common shares: Common shares outstanding — basic 38,351 37,959 Dilutive effect of potential common shares — — Common shares outstanding — diluted 38,351 37,959 Net earnings (loss) per share: Basic $ 1.44 $ (0.84) Diluted $ 1.44 $ (0.84) Antidilutive warrants (1) — 2,174 (1) Amount represents warrants to purchase common stock that are excluded from the diluted net earnings per share calculations because of their antidilutive effect .

Equity-based Awards (Tables)

Equity-based Awards (Tables)	12 Months Ended
Equity-based Awards (Tables)	Dec. 31, 2022
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
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, 2022 2021 Equity classified awards TSUs $ 2,648 $ 1,541 PSUs and PRSUs 440 48 Board RSUs 5 16 $ 3,093 $ 1,605
2017 Non-Employee Directors Compensation Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Summary of Information Regarding Restricted Stock Unit Awards	The following table summarizes information regarding the Board RSUs granted under the Director Compensation Plan for the period presented: Weighted- Average Grant- Number of Date Fair Value Units per Unit (1) Board RSUs outstanding at December 31, 2020 8,898 $ 5.12 Granted — $ — Forfeited — $ — Vested (5,565) $ 5.12 Board RSUs outstanding at December 31, 2021 3,333 $ 5.12 Granted — $ — Forfeited — $ — Vested (3,333) $ 5.12 Board RSUs outstanding at December 31, 2022 — $ — (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.
TSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Summary of Information Regarding Restricted Stock Unit Awards	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, 2020 115,797 $ 4.47 Granted (2) 1,083,644 $ 3.65 Forfeited (52,601) $ 3.73 Vested (72,420) $ 4.74 TSUs outstanding at December 31, 2021 1,074,420 $ 3.66 Granted (3) 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 (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, 2021 was $4.0 million based on a grant date market price ranging from $3.52 to $4.66 per share. (3) 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.
PSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Summary of Information Regarding Restricted Stock Unit Awards	The following table summarizes information regarding the PSUs granted under EIP for the period presented: Weighted- Average Grant- Number of Date Fair Value Units per Unit (1) PSUs outstanding at December 31, 2020 214,554 $ 2.36 Granted — $ — Forfeited (148,614) $ 2.13 Vested — $ — PSUs outstanding at December 31, 2021 65,940 $ 2.87 Granted — $ — Forfeited (22,614) $ 2.57 Vested — $ — PSUs & outstanding at December 31, 2022 43,326 $ 3.03 (1) Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.
PRSU [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Ranges for the Assumptions Used in Monte Carlo Model for PRSUs Granted	The ranges for the assumptions used in the Monte Carlo model for the 2022 PRSUs granted are presented as follows: 2022 Expected volatility 120.8 % Dividend yield 0.00 % Risk-free interest rate 1.38 %
Summary of Information Regarding Restricted Stock Unit Awards	The following table summarizes information regarding the PRSUs granted under the EIP for the period presented: Weighted- Average Grant- Number of Date Fair Value Units per Unit (1) PRSUs outstanding at December 31, 2020 — $ — Granted (2) 196,377 $ 1.94 Forfeited — $ — Vested — $ — PRSUs outstanding at December 31, 2021 196,377 $ 1.94 Granted (3) 189,904 $ 6.20 Forfeited — $ — Vested (49,095) $ 1.24 PRSUs outstanding at December 31, 2022 337,186 $ 4.44 (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, 2021 was $0.4 million based on a calculated fair value price ranging from $1.24 to $2.63 per share. (3) 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.

Leases (Tables)

Leases (Tables)	12 Months Ended
Leases (Tables)	Dec. 31, 2022
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, 2022 2021 (In thousands) Right-of-use asset $ 7,376 $ 2,716 Lease liabilities: Current lease liability 1,401 777 Long-term lease liability 6,567 2,017 Total lease liability $ 7,968 $ 2,794
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 2023 $ 1,357 $ 860 $ 2,217 2024 1,357 651 2,008 2025 1,357 436 1,793 2026 1,140 — 1,140 2027 and thereafter 2,440 — 2,440 Total lease payments 7,651 1,947 9,598 Less: interest 1,459 171 1,630 Present value of lease liabilities $ 6,192 $ 1,776 $ 7,968
Schedule of Weighted Average Remaining Lease Terms and Discount Rate of Operating Leases	The weighted average remaining lease terms and discount rate for all of the Company’s operating leases for the period presented: December 31, 2022 2021 Weighted average remaining lease term (years): Office and warehouse space 4.71 3.51 Vehicles 0.47 0.37 Office equipment 0.04 — Weighted average discount rate: Office leases 4.87 % 2.95 % Vehicles 1.30 % 0.59 % Office equipment 0.11 % 0.02 %

Supplemental Disclosures to t_2

Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022 2021 Accrued liability - pipeline incident $ 20,832 $ 34,417 Accrued liability - current portion of pipeline incident settlement 4,888 — Accrued lease operating expense 11,226 9,271 Accrued commitment fee and other expense 5,824 2,882 Accrued production and ad valorem tax 4,675 3,277 Accrued general and administrative expense 4,943 4,555 Accrued capital expenditures 2,714 1,631 Operating lease liability 1,401 777 Asset retirement obligations 1,824 1,016 Other 122 — Accrued liabilities $ 58,449 $ 57,826
Summary of accounts receivable	Accounts receivable consisted of the following at the dates indicated (in thousands): December 31, December 31, 2022 2021 Oil and natural gas receivables $ 35,083 $ 32,428 Insurance receivable - pipeline incident 41,961 49,098 Insurance receivable - LOPI — 6,667 Joint interest owners and other 5,047 5,409 Total accounts receivable 82,091 93,602 Less: allowance for doubtful accounts (1,636) (1,635) Total accounts receivable, net $ 80,455 $ 91,967
Summary of Supplemental Cash Flows	Supplemental cash flow for the periods presented (in thousands): For the Year Ended December 31, 2022 2021 Supplemental cash flows: Cash paid for interest, net of amounts capitalized $ 11,209 $ 8,637 Cash paid for reorganization items, net — 6 Cash paid for taxes 93 — Noncash investing and financing activities: Increase (decrease) in capital expenditures in payables and accrued liabilities 1,012 1,669

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
Commitments and Contingencies (Tables)	Dec. 31, 2022
Commitments And Contingencies.
Schedule of funding commitment	The table below outlines our funding commitment under these agreements at December 31, 2022 (in thousands): Payment Due by Period Funding commitment Total 2023 2024 2025 2026 2027 Thereafter (1) Sinking fund payments $ 165,913 $ 8,025 $ 15,789 $ 15,789 $ 15,789 $ 15,789 $ 94,732 (1) The remaining payments will be made during the years of 2028 through 2033.
Purchase Commitments Under the Contracts	At December 31, 2022, the Company had a CO 2 2 2 Payment or Settlement Due by Period Purchase commitment Total 2023 2024 2025 2026 2027 Thereafter CO 2 $ 11,876 $ 3,851 $ 4,076 $ 3,949 $ — $ — $ — At December 31, 2022, the Company has a long-term minimum volume commitment with a third party associated with a certain portion of its properties located in Oklahoma. The table below outlines the future payment commitments associated with the minimum volume commitment plus any applicable fee for not meeting the minimum volume commitment (in thousands): Payment or Settlement Due by Period (1) Total 2023 2024 2025 2026 2027 Thereafter Minimum volume commitment $ 3,243 $ 3,243 $ — $ — $ — $ — $ — (2) The amounts in the table do not reflect costs adjusted for inflation.

Income Tax (Tables)

Income Tax (Tables)	12 Months Ended
Income Tax (Tables)	Dec. 31, 2022
Income Tax
Components of Income Tax Expense (Benefit)	The components of income tax benefit (expense) are as follows: For the Year Ended December 31, 2022 2021 (In thousands) Current taxes: Federal $ — $ — State (111) — Total current income tax benefit (expense) (111) — Deferred taxes: Federal — — State — — Total deferred income tax benefit (expense) — — Total income tax benefit (expense) $ (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 2022 and in 2021 as follows: For the Year Ended December 31, 2022 2021 (In thousands) Expected tax benefit (expense) at federal statutory rate $ (12,177) $ 6,734 Changes in valuation allowances 12,267 3,192 Federal prior year adjustments 1,673 — Fines & penalties (1,939) — State income tax benefit (expense), net of federal benefit (1,859) 447 State rate change, net of federal benefit 1,532 (10,192) State prior year adjustment (234) (1,281) PPP loan forgiveness — 1,158 Other 626 (58) Total income tax benefit (expense) $ (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, 2022 2021 Deferred income tax assets: Property, plant & equipment $ 82,152 $ 94,439 Net operating loss carryforward 183,050 178,279 Derivatives 4,800 14,438 Disallowed interest expense 7,467 5,579 Accrued liabilities 2,008 1,592 Other 7,103 3,469 Total deferred income tax assets: 286,580 297,796 Valuation allowance (284,928) (297,195) Net deferred income tax assets 1,652 601 Deferred income tax liabilities: Derivatives $ — $ — Other 1,652 601 Total deferred income tax liabilities 1,652 601 Net deferred income taxes $ — $ —

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, 2022
Supplemental Oil and Gas Information (Unaudited)
Schedule of Capitalized Costs Relating to Oil and Natural Gas Producing Activities	December 31, 2022 2021 (In thousands) Evaluated oil and natural gas properties $ 840,310 $ 799,532 Support equipment and facilities 147,496 145,324 Accumulated depletion, depreciation, and amortization (648,900) (625,754) Total $ 338,906 $ 319,102
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities	For the Year Ended December 31, 2022 2021 (In thousands) Property acquisition costs, proved $ — $ 3 Property acquisition costs, unproved — — Exploration — — Development 42,949 27,478 Total $ 42,949 $ 27,481
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: 2022 2021 Oil ($/Bbl): WTI (1) $ 93.67 $ 66.56 NGL ($/Bbl): WTI (1) $ 93.67 $ 66.56 Natural Gas ($/MMbtu): Henry Hub (2) $ 6.36 $ 3.60 (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, 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 year 43,857 309,794 23,574 119,063 End of year 47,010 312,185 23,928 122,969 Proved undeveloped reserves: Beginning of year 1,144 4,556 263 2,167 End of year 858 607 98 1,058 (1) Our reserves related to our Beta properties are classified as proved developed non-producing at December 31, 2022. For the Year Ended December 31, 2021 Oil Gas NGLs Total (MBbls) (MMcf) (MBbls) (MBoe) Proved developed and undeveloped reserves: Beginning of year 46,676 274,139 21,484 113,849 Extensions and discoveries 746 4,283 215 1,674 Production (3,351) (23,808) (1,430) (8,747) Sale of minerals in place (3) (274) (12) (61) Revision of previous estimates 933 60,010 3,580 14,515 End of year 45,001 314,350 23,837 121,230 Proved developed reserves (1) : Beginning of period 35,613 252,218 19,009 96,658 End of period 43,857 309,794 23,574 119,063 Proved undeveloped reserves (2) : Beginning of period 11,063 21,921 2,475 17,191 End of period 1,144 4,556 263 2,167 (1) Our reserves related to our Beta properties were reclassified as proved developed non-producing at December 31, 2021. (2) Change to the Company’s development plan has resulted in removal of PUD locations in Oklahoma, Rockies and California.
Standardized Measure of Discounted Future Net Cash Flows	For the Year Ended December 31, 2022 2021 (In thousands) Future cash inflows $ 7,373,499 $ 4,569,313 Future production costs (1) (3,824,348) (2,691,875) Future development costs (1) (309,188) (231,040) Future income tax expense (520,731) — Future net cash flows for estimated timing of cash flows 2,719,232 1,646,398 10% annual discount for estimated timing of cash flows (1,381,276) (726,553) Standardized measure of discounted future net cash flows $ 1,337,956 $ 919,845 (1) For the years ended December 31, 2022 and 2021, 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, 2022 2021 (In thousands) Beginning of year $ 919,845 $ 297,811 Changes in prices and costs 856,545 572,897 Net change in taxes (311,412) — Sale of oil and natural gas produced, net of production costs (213,667) (171,326) Accretion of discount 91,985 29,781 Change in production rates and other (57,484) (31,423) Net changes in future development costs (20,129) 113,546 Revisions of previous quantities 59,216 46,271 Previously estimated development costs incurred 13,057 45,298 Sale of minerals in place — (45) Extensions and discoveries — 17,035 End of year $ 1,337,956 $ 919,845

Organization and Basis of Pre_2

Organization and Basis of Presentation - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2022 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, 2022	Dec. 31, 2021
Summary Of Significant Accounting Policies [Line Items]
Allowance for doubtful accounts	$ 1,636	$ 1,635
Capitalized exploratory drilling costs pending evaluation	0	0
Amortization expense including write-off of debt issuance costs	$ 600	600
Chance of tax benefit likely to be realized	greater than 50%
LOPI insurance payments recognized		6,667
Southern California Pipeline Incident and Oil Release
Summary Of Significant Accounting Policies [Line Items]
LOPI insurance payments recognized	$ 50,200	6,700
LOPI coverage period	18 months
Proved Developed And Producing Oil And Gas Properties [Member]
Summary Of Significant Accounting Policies [Line Items]
Impairment expense for proved/unproved properties	$ 0	0
Unproved Oil and Natural Gas Properties [Member]
Summary Of Significant Accounting Policies [Line Items]
Impairment expense for unproved leasehold costs	$ 0	$ 0
Minimum \| Other Property & Equipment [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives	3 years
Minimum \| Support Equipment and Facilities [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives	12 years
Maximum \| Other Property & Equipment [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives	7 years
Maximum \| Support Equipment and Facilities [Member]
Summary Of Significant Accounting Policies [Line Items]
Estimated useful lives	24 years

Summary of Significant Accoun_5

Summary of Significant Accounting Policies - Major Customers (Detail) - Customer Concentration Risk [Member] - Revenues [Member]	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Sinclair Oil & Gas Company [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues	23%	20%
Southwest Energy LP [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues	13%
Koch Energy Services LLC [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues	13%
Phillips 66 [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues		19%
ETC Texas Pipeline LTD [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues		12%

Revenues - Summary of Revenues

Revenues - Summary of Revenues Disaggregated (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Revenues:
Total revenues	$ 458,456	$ 342,916
Oil and Natural Gas Sales [Member]
Revenues:
Total revenues	407,761	335,779
Oil [Member]
Revenues:
Total revenues	212,522	212,486
NGLs [Member]
Revenues:
Total revenues	47,398	40,899
Natural Gas [Member]
Revenues:
Total revenues	$ 147,841	$ 82,394

Revenues - Additional Informati

Revenues - Additional Information (Detail) $ in Millions	12 Months Ended
Revenues - Additional Information (Detail) $ in Millions	Dec. 31, 2022 USD ($) item	Dec. 31, 2021 USD ($)
Revenues
Number of revenue streams \| item	3
Accounts receivable attributable to revenue from contracts with customers \| $	$ 35.1	$ 32.4
Revenue, Remaining Performance Obligation, Optional Exemption, Variable Consideration [true false]	true
Revenue, Remaining Performance Obligation, Optional Exemption, Performance Obligation [true false]	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 [Member] - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Total assets	$ 6,257	$ 7,967
Total liabilities	27,141	70,775
Quoted Prices in Active Market (Level 1) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Total assets	0	0
Total liabilities	0	0
Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Total assets	6,257	7,967
Total liabilities	27,141	70,775
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Total assets	0	0
Total liabilities	0	0
Commodity derivatives [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Total assets	6,257	7,967
Total liabilities	27,141	70,152
Commodity derivatives [Member] \| Quoted Prices in Active Market (Level 1) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Total assets	0	0
Total liabilities	0	0
Commodity derivatives [Member] \| Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Total assets	6,257	7,967
Total liabilities	27,141	70,152
Commodity derivatives [Member] \| Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Total assets	0	0
Total liabilities	0	0
Interest rate derivatives [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Total assets	0	0
Total liabilities	0	623
Interest rate derivatives [Member] \| Quoted Prices in Active Market (Level 1) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Total assets	0	0
Total liabilities	0	0
Interest rate derivatives [Member] \| Significant Other Observable Inputs (Level 2) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Total assets	0	0
Total liabilities	0	623
Interest rate derivatives [Member] \| Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
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 Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Proved Developed and Producing Oil and Gas Properties [Member]
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment expense	$ 0	$ 0
Unproved Properties [Member]
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment expense	$ 0	$ 0

Risk Management and Derivativ_3

Risk Management and Derivative Instruments - Open Commodity Positions (Detail)	12 Months Ended
	Dec. 31, 2022 MMBTU $ / MMBTU $ / bbl bbl
Natural Gas Derivative Two Way Collars Contracts 2023 [Member]
Derivative [Line Items]
Average monthly volume (MMBtu) \| MMBTU	1,160,000
Weighted-average floor price \| $ / MMBTU	3.49
Weighted-average ceiling price \| $ / MMBTU	5.92
Crude Oil Derivative Contracts Fixed Price Swap 2023 [Member]
Derivative [Line Items]
Average monthly volume (Bbls) \| bbl	55,000
Weighted-average fixed price	57.30
Crude Oil Derivative Three Way Collars Contracts 2023 [Member]
Derivative [Line Items]
Average monthly volume (Bbls) \| bbl	30,000
Weighted-average floor price	55
Weighted-average ceiling price	67.15
Weighted-average sub-floor price	40

Risk Management and Derivativ_4

Risk Management and Derivative Instruments - Gross Fair Value of Derivative Instruments by Appropriate Balance Sheet (Detail) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments and Hedges, Assets [Abstract]
Cash collateral received	$ 0
Net recorded fair value, Current assets	0	$ 0
Net recorded fair value, Non-Current assets	0	0
Net recorded fair value, Current liabilities	20,884	53,144
Net recorded fair value, Non current liabilities	0	9,664
Short-Term Derivative Instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	6,257	4,804
Asset Derivatives, Netting arrangements	(6,257)	(4,804)
Liability Derivatives, Gross fair value	27,141	57,948
Liability Derivatives, Netting arrangements	(6,257)	(4,804)
Short-Term Derivative Instruments [Member] \| Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	6,257	4,804
Liability Derivatives, Gross fair value	27,141	57,325
Short-Term Derivative Instruments [Member] \| Interest Rate Swaps [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	0	0
Liability Derivatives, Gross fair value	0	623
Long-Term Derivative Instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	0	3,163
Asset Derivatives, Netting arrangements	0	(3,163)
Liability Derivatives, Gross fair value	0	12,827
Liability Derivatives, Netting arrangements	0	(3,163)
Long-Term Derivative Instruments [Member] \| Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	0	3,163
Liability Derivatives, Gross fair value	0	12,827
Long-Term Derivative Instruments [Member] \| Interest Rate Swaps [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Gross fair value	0	0
Liability Derivatives, Gross fair value	$ 0	$ 0

Risk Management and Derivativ_5

Risk Management and Derivative Instruments - Unrealized and Realized Gains and Losses Related to Derivative Instruments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments Gain Loss [Line Items]
Loss (gain) on commodity derivative instruments	$ 106,937	$ 142,439
Interest expense, net	(14,101)	(12,099)
Commodity derivatives [Member]
Derivative Instruments Gain Loss [Line Items]
Loss (gain) on commodity derivative instruments	106,937	142,439
Interest Rate Swaps [Member]
Derivative Instruments Gain Loss [Line Items]
Interest expense, net	$ (935)	$ (217)

Asset Retirement Obligations -

Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligations
Asset retirement obligations at beginning of period	$ 103,414	$ 97,149
Liabilities added from acquisition or drilling	20	29
Liabilities settled	(923)	(296)
Liabilities removed upon sale of wells	0	(113)
Accretion expense	7,081	6,611
Revision of estimates	6,846	34
Asset retirement obligation at end of period	116,438	103,414
Less: Current Portion	1,824	1,016
Asset retirement obligations - long-term portion	$ 114,614	$ 102,398

Restricted Investments - Restri

Restricted Investments - Restricted Investment Balances (Detail) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Schedule Of Investments [Line Items]
Restricted investments	$ 11,326	$ 4,622
BOEM platform abandonment [Member]
Schedule Of Investments [Line Items]
Restricted investments	7,016	313
SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member]
Schedule Of Investments [Line Items]
Restricted investments	$ 4,310	$ 4,309

Debt - Consolidated Debt Obliga

Debt - Consolidated Debt Obligations (Detail) - USD ($) $ in Thousands		Dec. 31, 2022	Dec. 31, 2021
Line Of Credit Facility [Line Items]
Total long-term debt		$ 190,000	$ 230,000
Revolving Credit Facility [Member]
Line Of Credit Facility [Line Items]
Aggregate principal outstanding	[1]	$ 190,000	$ 230,000

[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.

Debt- Revolving Credit Facility

Debt- Revolving Credit Facility - Additional Information (Detail) - USD ($) $ in Millions				12 Months Ended
	Dec. 09, 2022	Nov. 10, 2021	Nov. 02, 2018	Dec. 31, 2022	Dec. 08, 2022	Jun. 20, 2022	Jun. 16, 2021	Jun. 15, 2021
Line Of Credit Facility [Line Items]
Letters of credit outstanding				$ 0
Revolving Credit Facility [Member]
Line Of Credit Facility [Line Items]
Borrowing base		$ 245		$ 210		$ 225	$ 245	$ 260
Maturity date				Nov. 02, 2023
LIBOR rate interest period			1 month
Unused line of credit, commitment fee percentage			0.50%
Amount of monthly reduction in borrowing base	$ 5	$ 5
Leverage ratio	3%				4%
Maximum borrowing capacity	$ 215
Revolving Credit Facility [Member] \| Amplify Acquisitionco Inc
Line Of Credit Facility [Line Items]
Pledge and security interest			100%
Revolving Credit Facility [Member] \| Minimum
Line Of Credit Facility [Line Items]
Current ratio			1%
Revolving Credit Facility [Member] \| Minimum \| Oil and Gas Properties [Member]
Line Of Credit Facility [Line Items]
Secured by percentage of mortgages			85%
Revolving Credit Facility [Member] \| Minimum \| Proved Developed And Producing Oil And Gas Properties [Member]
Line Of Credit Facility [Line Items]
Secured by percentage of mortgages			85%
Revolving Credit Facility [Member] \| Maximum
Line Of Credit Facility [Line Items]
Total debt to EBITDAX			4%
Revolving Credit Facility [Member] \| Federal Funds Effective Rate [Member]
Line Of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate			0.50%
Revolving Credit Facility [Member] \| LIBOR [Member]
Line Of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate			1%
Revolving Credit Facility [Member] \| LIBOR [Member] \| Minimum
Line Of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate			2%
Revolving Credit Facility [Member] \| LIBOR [Member] \| Maximum
Line Of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate			3%
Revolving Credit Facility [Member] \| Base Rate [Member] \| Minimum
Line Of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate			1%
Revolving Credit Facility [Member] \| Base Rate [Member] \| Maximum
Line Of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate			2%

Debt - Summary of Weighted-Aver

Debt - Summary of Weighted-Average Interest Rates Paid on Variable-Rate Debt Obligations (Detail)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Revolving Credit Facility [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates	5.36%	3.65%

Debt - Unamortized Deferred Fin

Debt - Unamortized Deferred Financing Costs - Additional Information (Detail) $ in Millions	Dec. 31, 2022 USD ($)
Successor Credit Facility [Member]
Line Of Credit Facility [Line Items]
Unamortized deferred financing costs	$ 1.5

Debt - Paycheck Protection Prog

Debt - Paycheck Protection Program - Additional Information (Detail) - USD ($) $ in Thousands		12 Months Ended
	Apr. 24, 2020	Dec. 31, 2022	Dec. 31, 2021
Debt
Loan amount received under paycheck protection plan	$ 5,500
Paycheck protection program loan of 2020, term	2 years
Paycheck protection program Loan of 2020, interest rate	1%
Paycheck protection program loan, principal or interest due next six months	$ 0
Gain on extinguishment of debt		$ 0	$ 5,516

Equity (Deficit)- Additional In

Equity (Deficit)- Additional Information (Detail) - $ / shares	May 04, 2017	Dec. 31, 2022	Dec. 31, 2021
Equity And Distributions [Line Items]
Common stock, shares authorized		250,000,000	250,000,000
Common stock, par value		$ 0.01	$ 0.01
Warrant [Member]
Equity And Distributions [Line Items]
Percentage of common shares to be issued upon exercise of warrants	8%
Warrant issued during period	2,173,913
Warrant life period	5 years
Warrant exercise price	$ 42.60

Equity (Deficit) - Summary of C

Equity (Deficit) - Summary of Changes in Number of Outstanding Common Stock (Detail) - Common Stock [Member] - shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Summary Of Changes In Number Of Outstanding Units Or Shares [Line Items]
Beginning balance	38,024,142	37,663,509
Issuance of common stock	0	0
Restricted stock units vested	534,834	77,985
Bonus stock awards		455,973
Shares withheld for taxes	(99,245)	(173,325)
Ending balance	38,459,731	38,024,142

Equity (Deficit) - Summary of_2

Equity (Deficit) - Summary of Changes in Number of Outstanding Common Units and Shares of Common Stock (Parenthetical) (Detail)	Feb. 12, 2021 $ / shares
Bonus Stock Awards [Member]
Summary Of Changes In Number Of Outstanding Units Or Shares [Line Items]
Shares grant price	$ 2.48

Earnings (Loss) per Share - Cal

Earnings (Loss) per Share - Calculation of Earnings (Loss) per Share (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021
Earnings Per Share [Line Items]
Net income (loss)		$ 57,875	$ (32,070)
Less: Net income allocated to participating securities		2,728	0
Basic and diluted earnings available to common stockholders		$ 55,147	$ (32,070)
Common shares:
Common shares outstanding - basic		38,351	37,959
Dilutive effect of potential common shares		0	0
Common shares outstanding - diluted		38,351	37,959
Basic		$ 1.44	$ (0.84)
Diluted		$ 1.44	$ (0.84)
Warrants [Member]
Common shares:
Antidilutive stock options or warrants	[1]	0	2,174

[1] Amount represents warrants to purchase common stock that are excluded from the diluted net earnings per share calculations because of their antidilutive effect

Equity-based Awards - Additiona

Equity-based Awards - Additional Information (Detail) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) installment $ / shares shares
TSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation cost	$ 3.6
Weighted-average period of unrecognized compensation cost	1 year 8 months 12 days
PSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation cost	$ 0.1
Weighted-average period of unrecognized compensation cost	7 months 6 days
Decrease in share targets \| $ / shares	$ 0.25
PSUs [Member] \| Market Vesting Date [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock units vesting percentage	50%
PSUs [Member] \| Share Based Compensation Award Tranche One [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock units vesting percentage	25%
PSUs [Member] \| Share Based Compensation Award Tranche Two [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock units vesting percentage	25%
PRSU [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation cost	$ 0.9
Weighted-average period of unrecognized compensation cost	2 years
PRSU [Member] \| Share Based Compensation Award Tranche One [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock units vesting percentage	25%
PRSU [Member] \| Share Based Compensation Award Tranche Two [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock units vesting percentage	25%
PRSU [Member] \| Share Based Compensation Award Tranche Three [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock units vesting percentage	50%
2017 Non-Employee Directors Compensation Plan [Member] \| Restricted Stock Units (RSUs) [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of vesting annually equal installments \| installment	3
Vesting date description	Awards granted generally vest annually in three equal installments on each of the first three anniversaries of the grant date, subject to the grantee’s continued employment through each such vesting date.
EIP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares available for future distribution (in shares) \| shares	1,570,403
PRSU [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
PRSU [Member] \| Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of Potential Payout	200%
PRSU [Member] \| Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of Potential Payout	0%

Equity-based Awards - Summary o

Equity-based Awards - Summary of Information Regarding Restricted Stock Unit Awards (Detail) - Legacy Amplify Management Incentive Plan [Member] - $ / shares		12 Months Ended
		Dec. 31, 2022		Dec. 31, 2021
TSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Number of Units, Beginning Balance		1,074,420		115,797
Granted, Number of Units		963,027	[1]	1,083,644	[2]
Forfeited, Number of Units		(52,485)		(52,601)
Vested, Number of Units		(482,406)		(72,420)
Outstanding, Number of Units, Ending Balance		1,502,556		1,074,420
Outstanding, Weighted-Average Grant Date Fair Value per unit, Beginning balance	[3]	$ 3.66		$ 4.47
Granted, Weighted-Average Grant Date Fair Value per Unit	[3]	4.05	[1]	3.65	[2]
Forfeited, Weighted-Average Grant Date Fair Value per Unit	[3]	4.30		3.73
Vested, Weighted-Average Grant Date Fair Value per Unit	[3]	3.85		4.74
Outstanding, Weighted-Average Grant Date Fair Value per unit, Ending balance	[3]	$ 3.82		$ 3.66
PSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Number of Units, Beginning Balance		65,940		214,554
Granted, Number of Units		0		0
Forfeited, Number of Units		(22,614)		(148,614)
Vested, Number of Units		0		0
Outstanding, Number of Units, Ending Balance		43,326		65,940
Outstanding, Weighted-Average Grant Date Fair Value per unit, Beginning balance	[3]	$ 2.87		$ 2.36
Granted, Weighted-Average Grant Date Fair Value per Unit	[3]	0		0
Forfeited, Weighted-Average Grant Date Fair Value per Unit	[3]	2.57		2.13
Vested, Weighted-Average Grant Date Fair Value per Unit	[3]	0		0
Outstanding, Weighted-Average Grant Date Fair Value per unit, Ending balance	[3]	$ 3.03		$ 2.87
PRSU [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Number of Units, Beginning Balance		196,377
Granted, Number of Units		189,904		196,377
Vested, Number of Units		(49,095)
Outstanding, Number of Units, Ending Balance		337,186		196,377
Outstanding, Weighted-Average Grant Date Fair Value per unit, Beginning balance		$ 1.94
Granted, Weighted-Average Grant Date Fair Value per Unit		6.20		$ 1.94
Vested, Weighted-Average Grant Date Fair Value per Unit		1.24
Outstanding, Weighted-Average Grant Date Fair Value per unit, Ending balance		$ 4.44		$ 1.94

[1] 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. The aggregate grant date fair value of TSUs issued for the year ended December 31, 2021 was $4.0 million based on a grant date market price ranging from $3.52 to $4.66 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 Unit Awards (Parenthetical) (Detail) - USD ($) $ / shares in Units, $ in Millions	Dec. 31, 2022	Dec. 31, 2021
TSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value of restricted stock units issued	$ 3.9	$ 4
TSUs [Member] \| Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant Date Market Price	$ 3.64	$ 3.52
TSUs [Member] \| Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant Date Market Price	$ 6.99	$ 4.66
PRSU [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value of restricted stock units issued	$ 1.2	$ 0.4
Calculated fair value price	$ 6.20
PRSU [Member] \| Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Calculated fair value price		$ 1.24
PRSU [Member] \| Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Calculated fair value price		$ 2.63

Equity-based Awards - Assumptio

Equity-based Awards - Assumptions Used in Monte Carlo Model (Detail) - PRSU [Member]	12 Months Ended
	Dec. 31, 2021
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Expected volatility	120.80%
Dividend yield	0%
Risk-free interest rate	1.38%

Equity-based Awards - Summary_3

Equity-based Awards - Summary of Information Regarding Restricted Stock Awards (Detail) - Restricted Stock Units (RSUs) [Member] - Two Thousand Seventeen Non Employee Directors Compensation Plan [Member] - $ / shares		12 Months Ended
		Dec. 31, 2022	Dec. 31, 2021
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Number of Units, Beginning Balance		3,333	8,898
Granted, Number of Units		0	0
Forfeited, Number of Units		0	0
Vested, Number of Units		(3,333)	(5,565)
Outstanding, Number of Units, Ending Balance		0	3,333
Outstanding, Weighted-Average Grant Date Fair Value per unit, Beginning balance	[1]	$ 5.12	$ 5.12
Granted, Weighted-Average Grant Date Fair Value per Unit	[1]	0	0
Forfeited, Weighted-Average Grant Date Fair Value per Unit	[1]	0	0
Vested, Weighted-Average Grant Date Fair Value per Unit	[1]	5.12	5.12
Outstanding, Weighted-Average Grant Date Fair Value per unit, Ending balance	[1]	$ 0	$ 5.12

[1] Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.

Equity-based Awards - Summary_4

Equity-based Awards - Summary of Amount of Compensation Expense Recognized (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)	$ 3,093	$ 1,605
Restricted Stock Units With Service Vesting Conditions [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)	2,648	1,541
Restricted Stock Units With Market And Service Vesting Conditions [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)	440	48
Restricted Stock Units R S U [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)	$ 5	$ 16

Leases - Additional Information

Leases - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
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	$ 1.6	$ 2.7

Leases - Schedule of Right-of-U

Leases - Schedule of Right-of-Use Assets and Lease Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Leases
Right-of-use asset	$ 7,376	$ 2,716
Current lease liability	1,401	777
Long-term lease liability	6,567	2,017
Total lease liability	$ 7,968	$ 2,794

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, 2022	Dec. 31, 2021
Lessee Lease Description [Line Items]
2023	$ 2,217
2024	2,008
2025	1,793
2026	1,140
2027 and thereafter	2,440
Total lease payments	9,598
Less: interest	1,630
Present value of lease liabilities	7,968	$ 2,794
Office and Warehouse Space [Member]
Lessee Lease Description [Line Items]
2023	1,357
2024	1,357
2025	1,357
2026	1,140
2027 and thereafter	2,440
Total lease payments	7,651
Less: interest	1,459
Present value of lease liabilities	6,192
Leased Vehicles and Office Equipment [Member]
Lessee Lease Description [Line Items]
2023	860
2024	651
2025	436
2026	0
2027 and thereafter	0
Total lease payments	1,947
Less: interest	171
Present value of lease liabilities	$ 1,776

Leases - Schedule of Weighted A

Leases - Schedule of Weighted Average Remaining Lease Terms and Discount Rate of Operating Leases (Detail)	Dec. 31, 2022	Dec. 31, 2021
Office and Warehouse Space [Member]
Lessee Lease Description [Line Items]
Weighted average remaining lease term	4 years 8 months 15 days	3 years 6 months 3 days
Office Leases [Member]
Lessee Lease Description [Line Items]
Weighted average discount rate	4.87%	2.95%
Vehicles [Member]
Lessee Lease Description [Line Items]
Weighted average remaining lease term	5 months 19 days	4 months 13 days
Weighted average discount rate	1.30%	0.59%
Office Equipment [Member]
Lessee Lease Description [Line Items]
Weighted average remaining lease term	14 days	0 years
Weighted average discount rate	0.11%	0.02%

Supplemental Disclosures to t_3

Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows - Summary of Current Accrued Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows
Accrued liability - pipeline incident	$ 20,832	$ 34,417
Accrued liability - current portion of pipeline incident settlement	4,888
Accrued lease operating expense	11,226	9,271
Accrued commitment fee and other expense	5,824	2,882
Accrued production and ad valorem tax	4,675	3,277
Accrued general and administrative expense	4,943	4,555
Accrued capital expenditures	2,714	1,631
Operating lease liability	$ 1,401	$ 777
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Accrued liabilities	Accrued liabilities
Accrued liabilities	$ 58,449	$ 57,826
Asset retirement obligations	1,824	$ 1,016
Other	$ 122

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, 2022	Dec. 31, 2021
Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows
Oil and natural gas receivables	$ 35,083	$ 32,428
Insurance receivable - pipeline incident	41,961	49,098
Insurance receivable - LOPI		6,667
Joint interest owners and other	5,047	5,409
Total accounts receivable	82,091	93,602
Less: allowance for doubtful accounts	(1,636)	(1,635)
Total accounts receivable, net	$ 80,455	$ 91,967

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, 2022	Dec. 31, 2021
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized	$ 11,209	$ 8,637
Cash paid for reorganization items, net	0	6
Cash paid for taxes	93
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities	$ 1,012	$ 1,669

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Related Party Transactions
Significant transaction with related party	$ 0	$ 0

Southern California Pipeline _2

Southern California Pipeline Incident (Details) $ in Thousands					12 Months Ended
	Sep. 08, 2022 USD ($) item	Aug. 26, 2022 USD ($)	Aug. 25, 2022 USD ($)	Oct. 02, 2021 item	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Mar. 01, 2023 USD ($)	Oct. 14, 2021 bbl	Oct. 05, 2021 ft² item
Unusual or Infrequent Item, or Both [Line Items]
Settlement amount			$ 50,000
Pipeline incident settlement					$ 12,000	$ 0
Pipeline incident loss					11,277	1,599
Amount receivable					41,961	49,098
LOPI insurance payments recognized						6,667
Subsequent Event
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
Southern California Pipeline Incident and Oil Release
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					53,600
Estimated fines and penalties					12,000
Costs probable of recovery					42,300
Pipeline incident loss					11,300
LOPI insurance payments recognized					50,200	6,700
Southern California Pipeline Incident and Oil Release \| Accounts Receivable
Unusual or Infrequent Item, or Both [Line Items]
Amount receivable					42,000	49,100
LOPI insurance payments recognized					50,200	$ 6,700
Southern California Pipeline Incident and Oil Release \| Minimum
Unusual or Infrequent Item, or Both [Line Items]
Estimated aggregate costs					160,000
Southern California Pipeline Incident and Oil Release \| Maximum
Unusual or Infrequent Item, or Both [Line Items]
Estimated aggregate costs					$ 170,000
Southern California Pipeline Incident and Oil Release \| Pending Litigation
Unusual or Infrequent Item, or Both [Line Items]
Estimated litigation liability	$ 4,900	$ 7,100
Installment period		3 years
Probation period	1 year	4 years
Reimbursement amount payable to government agencies		$ 5,800
Number of misdemeanor charges \| item	6
Southern California Pipeline Incident and Oil Release \| 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 (Detail)					12 Months Ended
	Sep. 08, 2022 USD ($) item	Aug. 26, 2022 USD ($)	Aug. 25, 2022 USD ($)	Dec. 15, 2021 USD ($) agreement	Dec. 31, 2022 USD ($) $ / bbl	Dec. 31, 2021 USD ($)	Mar. 01, 2023 USD ($)
Commitments and Contingencies Additional Textual [Abstract]
Remaining environmental accrued liability recorded					$ 0	$ 0
Settlement amount			$ 50,000,000
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					7,000,000
Beta's decommissioning obligations, full supported by surety bonds					161,300,000
Rent expense					8,700,000	7,600,000
Commitment fee expense					1,800,000	1,600,000
Commitment fee/expense					1,900,000	2,000,000
Pipeline incident settlement expense					12,000,000	$ 0
Accrued liability pipeline incident					4,888,000
Southern California Pipeline Incident and Oil Release
Commitments and Contingencies Additional Textual [Abstract]
Settlement amount			$ 50,000,000
Subsequent Event
Commitments and Contingencies Additional Textual [Abstract]
Amount agreed to be receivable in a settlement							$ 96,500,000
Approximate net payment receivable in a settlement							$ 85,000,000
Pending Litigation \| Southern California Pipeline Incident and Oil Release
Commitments and Contingencies Additional Textual [Abstract]
Estimated litigation liability	$ 4,900,000	$ 7,100,000
Installment period		3 years
Probation period	1 year	4 years
Reimbursement amount payable to government agencies		$ 5,800,000
Number of misdemeanor charges \| item	6
Pending Litigation \| Agreement with the United States government
Commitments and Contingencies Additional Textual [Abstract]
Estimated litigation liability		$ 7,100,000
Installment period		3 years
Probation period		4 years
Reimbursement amount payable to government agencies		$ 5,800,000
Pipeline incident settlement expense					7,100,000
Accrued liability pipeline incident					2,000,000
Pipeline incident settlement liability included in Other long-term liabilities					3,100,000
Pending Litigation \| Agreement with the State of California
Commitments and Contingencies Additional Textual [Abstract]
Estimated litigation liability	$ 4,900,000
Probation period	1 year
Pipeline incident settlement expense					4,900,000
Accrued liability pipeline incident					2,900,000
Number of misdemeanor charges \| item	6
SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member]
Commitments and Contingencies Additional Textual [Abstract]
Restricted Investment - decommissioning of offshore production facilities					$ 4,300,000

Commitments and Contingencies_2

Commitments and Contingencies - Other Commitments (Details) - Sinking fund payments $ in Thousands	Dec. 31, 2022 USD ($)
Other Commitments [Line Items]
Total	$ 165,913
2023	8,025
2024	15,789
2025	15,789
2026	15,789
2027	15,789
Thereafter	$ 94,732

Commitments and Contingencies_3

Commitments and Contingencies - Purchase Commitments Under the Contracts (Detail) $ in Thousands	Dec. 31, 2022 USD ($)
CO2 Minimum Purchase Commitment
Recorded Unconditional Purchase Obligation [Line Items]
Total	$ 11,876
2023	3,851
2024	4,076
2025	3,949
2026	0
2027	0
Thereafter	0
Minimum Volume Commitment
Recorded Unconditional Purchase Obligation [Line Items]
Total	3,243
2023	3,243
2024	0
2025	0
2026	0
2027	0
Thereafter	$ 0

Income Tax - Components of Inco

Income Tax - Components of Income Tax Expense (Benefit) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Current taxes:
Federal	$ 0	$ 0
State	(111)	0
Total current income tax benefit (expense)	(111)	0
Deferred taxes:
Federal	0	0
State	0	0
Total deferred income tax benefit (expense)	0	0
Total income tax benefit (expense)	$ (111)	$ 0

Income Tax - Additional Informa

Income Tax - Additional Information (Details) - USD ($)	12 Months Ended
Income Tax - Additional Information (Details) - USD ($)	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Line Items]
Statutory tax rate	21%	21%
Valuation Allowance	$ 284,928,000	$ 297,195,000
Unrecognized Tax Benefits	0
United States [Member]
Income Tax Disclosure [Line Items]
NOL carryforward subject to loss limitation	768,400,000
Operating loss expiration	20,600,000
Operating loss carryforwards not subject to expiration	747,800,000
Post merger operating loss Carry forwards	28,200,000
State [Member]
Income Tax Disclosure [Line Items]
Operating loss carryforwards not subject to expiration	$ 399,500,000
Operating loss carryforwards expiration year	2037
Maximum \| United States [Member]
Income Tax Disclosure [Line Items]
Net operating loss carryforwards	$ 796,600,000
Maximum \| State [Member]
Income Tax Disclosure [Line Items]
Net operating loss carryforwards	$ 453,700,000

Income Tax - Reconciliation of

Income Tax - Reconciliation of Income Tax Benefit (Provision) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Income Tax
Expected tax benefit (expense) at federal statutory rate	$ (12,177)	$ 6,734
Changes in valuation allowances	12,267	3,192
Federal prior year adjustments	1,673	0
Fines & penalties	(1,939)	0
State income tax benefit (expense), net of federal benefit	(1,859)	447
State rate change, net of federal benefit	1,532	(10,192)
State prior year adjustment	(234)	(1,281)
PPP loan forgiveness	0	1,158
Other	626	(58)
Total income tax benefit (expense)	$ (111)	$ 0

Income Tax - Components of Net

Income Tax - Components of Net Deferred Income Tax Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Deferred income tax assets:
Property, plant & equipment	$ 82,152	$ 94,439
Net operating loss carryforward	183,050	178,279
Derivatives	4,800	14,438
Disallowed interest expense	7,467	5,579
Accrued liabilities	2,008	1,592
Other	7,103	3,469
Total deferred income tax assets	286,580	297,796
Valuation allowance	(284,928)	(297,195)
Net deferred income tax assets	1,652	601
Deferred income tax liabilities:
Derivatives	0	0
Other	1,652	601
Total deferred income tax liabilities	1,652	601
Net deferred income taxes	$ 0	$ 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 (Detail) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Supplemental Oil and Gas Information (Unaudited)
Evaluated oil and natural gas properties	$ 840,310	$ 799,532
Support equipment and facilities	147,496	145,324
Accumulated depletion, depreciation, and amortization	(648,900)	(625,754)
Total	$ 338,906	$ 319,102

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 (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Supplemental Oil and Gas Information (Unaudited)
Property acquisition costs, proved	$ 0	$ 3
Property acquisition costs, unproved	0	0
Exploration	0	0
Development	42,949	27,478
Total	$ 42,949	$ 27,481

Supplemental Oil and Gas Info_5

Supplemental Oil and Gas Information (Unaudited) - Additional Information (Detail) - MMBoe	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Supplemental Oil and Gas Information (Unaudited)
Percent of discount factor to proved reserves	10%
Increase (reduction) in reserves	2.8	7.4
Upward price revisions in proved reserve	14.2	30.6
Proved developed and undeveloped reserves, decrease in production	7.5
Proved developed and undeveloped reserves, decrease in lease operating expense	4.1
Reduction due to removed PUD locations		16
Extensions, discoveries and additions related to wells in progress		1.7
Proved developed and undeveloped reserves, reduction due to increase in maintenance cost		1.2
Proved developed and undeveloped reserves, upward technical revision	0.2	0.9

Supplemental Oil and Gas Info_6

Supplemental Oil and Gas Information (Unaudited) - Schedule of Product Prices Used for Valuing the Reserves (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Oil Reserves [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Product prices for reserves	93.67	66.56
Natural Gas Liquids Reserves [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Product prices for reserves	93.67	66.56
Natural Gas Reserves [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Product prices for reserves	6.36	3.60

Supplemental Oil and Gas Info_7

Supplemental Oil and Gas Information (Unaudited) - Schedule of Net Reserves (Detail)	12 Months Ended
	Dec. 31, 2022 MBbls MMcf	Dec. 31, 2021 MMBoe MMcfe MBbls MMcf
Oil Reserves [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year	45,001	46,676
Extensions and discoveries		746
Production	(2,327)	(3,351)
Sale of minerals in place \| MMBoe		(3)
Revision of previous estimates	5,194	933
Proved developed and undeveloped reserves, End of year	47,868	45,001
Proved developed reserves, Beginning of year	43,857	35,613
Proved developed reserves, End of year	47,010	43,857
Proved undeveloped reserves, Beginning of year	1,144	11,063
Proved undeveloped reserves, End of year	858	1,144
Natural Gas Reserves [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year \| MMcf	314,350	274,139
Extensions and discoveries \| MMcf		4,283
Production \| MMcf	(22,993)	(23,808)
Sale of minerals in place \| MMcfe		(274)
Revision of previous estimates \| MMcf	21,435	60,010
Proved developed and undeveloped reserves, End of year \| MMcf	312,792	314,350
Proved developed reserves, Beginning of year \| MMcf	309,794	252,218
Proved developed reserves, End of year \| MMcf	312,185	309,794
Proved undeveloped reserves, Beginning of year \| MMcf	4,556	21,921
Proved undeveloped reserves, End of year \| MMcf	607	4,556
Natural Gas Liquids Reserves [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year	23,837	21,484
Extensions and discoveries		215
Production	(1,389)	(1,430)
Sale of minerals in place \| MMBoe		(12)
Revision of previous estimates	1,578	3,580
Proved developed and undeveloped reserves, End of year	24,026	23,837
Proved developed reserves, Beginning of year	23,574	19,009
Proved developed reserves, End of year	23,928	23,574
Proved undeveloped reserves, Beginning of year	263	2,475
Proved undeveloped reserves, End of year	98	263
Proved Reserves, Total
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year	121,230	113,849
Extensions and discoveries		1,674
Production	(7,548)	(8,747)
Sale of minerals in place \| MMBoe		(61)
Revision of previous estimates	10,345	14,515
Proved developed and undeveloped reserves, End of year	124,027	121,230
Proved developed reserves, Beginning of year	119,063	96,658
Proved developed reserves, End of year	122,969	119,063
Proved undeveloped reserves, Beginning of year	2,167	17,191
Proved undeveloped reserves, End of year	1,058	2,167

Supplemental Oil and Gas Info_8

Supplemental Oil and Gas Information (Unaudited) -Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Supplemental Oil and Gas Information (Unaudited)
Future cash inflows	$ 7,373,499	$ 4,569,313
Future production costs	(3,824,348)	(2,691,875)
Future development costs	(309,188)	(231,040)
Future income tax expense	(520,731)	0
Future net cash flows for estimated timing of cash flows	2,719,232	1,646,398
10% annual discount for estimated timing of cash flows	(1,381,276)	(726,553)
Standardized measure of discounted future net cash flows	$ 1,337,956	$ 919,845	$ 297,811

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 (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Supplemental Oil and Gas Information (Unaudited)
Beginning of year	$ 919,845	$ 297,811
Changes in prices and costs	856,545	572,897
Net change in taxes	(311,412)	0
Sale of oil and natural gas produced, net of production costs	(213,667)	(171,326)
Accretion of discount	91,985	29,781
Change in production rates and other	(57,484)	(31,423)
Net changes in future development costs	(20,129)	113,546
Revisions of previous quantities	59,216	46,271
Previously estimated development costs incurred	13,057	45,298
Sale of minerals in place	0	(45)
Extensions and discoveries	0	17,035
End of year	$ 1,337,956	$ 919,845