Amplify Energy (AMPY) 10-K 9 Mar 22 2021 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Feb. 28, 2022	Jun. 30, 2021
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Amendment Flag	false
Document Period End Date	Dec. 31, 2021
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	FY
Trading Symbol	AMPY
Entity Registrant Name	AMPLIFY ENERGY CORP.
Entity Central Index Key	0001533924
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Accelerated Filer
Entity Shell Company	false
Entity Small Business	true
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	false
Entity Tax Identification Number	82-1326219
Entity File Number	001-35512
Entity Incorporation, State or Country Code	DE
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
Security Exchange Name	NYSE
Title of 12(b) Security	Common Stock
Document Transition Report	false
Entity Interactive Data Current	Yes
Entity Common Stock, Shares Outstanding		38,064,214
Auditor Name	DELOITTE & TOUCHE LLP
Auditor Firm ID	34
Auditor Location	Houston, Texas
Entity Public Float			$ 140.4
Documents Incorporated by Reference	Documents Incorporated By Reference :

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Current assets:
Cash and cash equivalents	$ 18,799	$ 10,364
Accounts receivable, net (see Note 13)	91,967	30,901
Prepaid expenses and other current assets	15,018	15,572
Total current assets	125,784	56,837
Property and equipment, at cost:
Oil and natural gas properties, successful efforts method	799,532	775,167
Support equipment and facilities	145,324	142,208
Other	9,641	9,102
Accumulated depreciation, depletion and amortization	(634,212)	(609,231)
Property and equipment, net	320,285	317,246
Long-term derivative instruments	0	873
Restricted investments	4,622	4,623
Operating lease - long term right-of-use asset	2,716	2,500
Other long-term assets	1,693	2,680
Total assets	455,100	384,759
Current liabilities:
Accounts payable	33,819	798
Revenues payable	20,374	22,563
Accrued liabilities (see Note 13)	57,826	22,677
Short-term derivative instruments	53,144	10,824
Total current liabilities	165,163	56,862
Long-term debt (see Note 8)	230,000	260,516
Asset retirement obligations	102,398	96,725
Long-term derivative instruments	9,664	847
Operating lease liability	2,017	266
Other long-term liabilities	10,699	3,280
Total liabilities	519,941	418,496
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, 2021 and December 31, 2020	0	0
Warrants, 2,173,913 warrants issued and outstanding at December 31, 2021 and December 31, 2020	4,788	4,788
Common stock, $0.01 par value: 250,000,000 shares authorized; 38,024,142 and 37,663,509 shares issued and outstanding at December 31, 2021 and December 31, 2020, respectively	382	378
Additional paid-in capital	425,066	424,104
Accumulated deficit	(495,077)	(463,007)
Total stockholders' deficit	(64,841)	(33,737)
Total liabilities and equity	$ 455,100	$ 384,759

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2021	Dec. 31, 2020
Statement Of Financial Position [Abstract]
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	50,000,000	50,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Warrants issued	2,173,913	2,173,913
Warrants outstanding	2,173,913	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	38,024,142	37,663,509
Common stock, shares outstanding	38,024,142	37,663,509

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Revenues:
Total revenues	$ 342,916	$ 202,144
Costs and expenses:
Lease operating expense	121,398	119,708
Gathering, processing and transportation	20,807	20,547
Taxes other than income	22,250	12,944
Depreciation, depletion and amortization	28,068	40,268
Impairment expense	0	476,936
General and administrative expense	25,285	27,789
Accretion of asset retirement obligations	6,611	6,206
Loss (gain) on commodity derivative instruments	142,439	(60,671)
Pipeline incident loss	1,599	0
Other, net	68	306
Total costs and expenses	368,525	644,033
Operating loss	(25,609)	(441,889)
Other (expense) income:
Interest expense, net	(12,099)	(20,522)
Gain on extinguishment of debt	5,516	0
Inventory valuation adjustment	0	(1,003)
Other expense	128	65
Total other expense	(6,455)	(21,460)
Loss before reorganization items, net and income taxes	(32,064)	(463,349)
Reorganization items, net	(6)	(566)
Income tax expense	0	(115)
Net loss	(32,070)	(464,030)
Net (income) loss allocated to participating restricted stockholders	0	0
Net loss available to common stockholders	$ (32,070)	$ (464,030)
Loss per share: (See Note 10)
Basic loss per share	$ (0.84)	$ (12.34)
Diluted loss per share	$ (0.84)	$ (12.34)
Weighted average common shares outstanding:
Basic	37,959	37,612
Diluted	37,959	37,612
Oil and Natural Gas Sales [Member]
Revenues:
Total revenues	$ 335,779	$ 200,888
Other Revenues [Member]
Revenues:
Total revenues	$ 7,137	$ 1,256

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Cash flows from operating activities:
Net loss	$ (32,070)	$ (464,030)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	28,068	40,268
Impairment expense	0	476,936
Loss (gain) on derivative instruments	142,223	(56,628)
Cash settlements (paid) received on expired derivative instruments	(90,214)	61,135
Cash settlements received on terminated derivative instruments	0	17,977
Bad debt expense	95	294
Amortization and write-off of deferred financing costs	626	3,272
Gain on extinguishment of debt	(5,516)	0
Accretion of asset retirement obligations	6,611	6,206
Share-based compensation (see Note 11)	1,047	(112)
Settlement of asset retirement obligations	(296)	(327)
Changes in operating assets and liabilities:
Accounts receivable	(61,172)	1,950
Prepaid expenses and other assets	296	(2,334)
Payables and accrued liabilities	73,655	(9,803)
Other	(384)	(474)
Net cash provided by operating activities	62,969	74,330
Cash flows from investing activities:
Additions to oil and gas properties	(29,294)	(34,833)
Additions to other property and equipment	(539)	(1,057)
Additions to restricted investments	1	0
Other	404	0
Net cash used in investing activities	(29,428)	(35,890)
Cash flows from financing activities:
Advances on revolving credit facility	0	25,000
Payments on revolving credit facility	(25,000)	(55,000)
Proceeds from the paycheck protection program	0	5,516
Deferred financing costs	(25)	(115)
Dividends to stockholders	0	(3,786)
Shares withheld for taxes	(81)	(51)
Other	0	35
Net cash used in financing activities	(25,106)	(28,401)
Net change in cash and cash equivalents	8,435	10,039
Cash and cash equivalents, beginning of period	10,364	325
Cash and cash equivalents, end of period	$ 18,799	$ 10,364

CONSOLIDATED STATEMENTS OF EQUI

CONSOLIDATED STATEMENTS OF EQUITY - USD ($) $ in Thousands	Common Stock [Member]	Warrant [Member]	Additional Paid In Capital [Member]	Retained Earnings [Member]	Total
Balance at Dec. 31, 2019	$ 209	$ 4,790	$ 424,399	$ 4,809	$ 434,207
Net loss	0	0	0	(464,030)	(464,030)
Share-based compensation expense	0	0	(112)	0	(112)
Dividends	0	0	0	(3,786)	(3,786)
Expiration of warrants	0	(2)	2	0	0
Shares withheld for taxes	0	0	(51)	0	(51)
Other	169	0	(134)	0	35
Balance at Dec. 31, 2020	378	4,788	424,104	(463,007)	(33,737)
Net 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)

Organization and Basis of Prese

Organization and Basis of Presentation	12 Months Ended
	Dec. 31, 2021
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”). Market Conditions and COVID-19 In March 2020, the World Health Organization classified the outbreak of COVID 19 as a global pandemic. In attempting to control the spread of COVID 19, governments around the world imposed laws and regulations such as shelter-in-place orders, quarantines, executive orders and similar restrictions. As a result, the global economy suffered a significant slowdown and uncertainty, which in turn led to a precipitous decline in commodity prices in response to decreased demand. Beginning in the first quarter of 2021 and continuing throughout the year, commodity prices have recovered substantially, due in part to the accessibility of vaccines, reopening of economies after lockdowns, and general optimism concerning the spread and severity of new variants of COVID-19 and the economic recovery. Despite recent downward trends in the spread of COVID-19, particularly as vaccination rates have increased, new variants of COVID-19 have intermittently emerged and spread throughout the U.S. and globally causing further uncertainty. This continued uncertainty and/or the emergence of new COVID 19 variant, including vaccine resistant variant, may result in additional adverse impacts on our results of operations, cash flows and financial position. Paycheck Protection Program. Employee Retention Credit.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2021
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 and $1.5 million as an allowance for doubtful accounts at December 31, 2021 and 2020, respectively. 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, ​ ​ 2021 2020 ​ Major customers: ​ Sinclair Oil & Gas Company 20 % 21 % Phillips 66 19 % 23 % ETC Texas Pipeline LTD ​ 12 % n/a % BP America Production Company n/a % 17 % ​ 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 were no material capitalized exploratory drilling costs pending evaluation at December 31, 2021 and 2020. 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, 2021 and 2020. 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 is 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, 2021 and 2020 was approximately $0.6 million and $3.3 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 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 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 proved and 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. No impairment expense related to its proved properties was recorded for the year ended December 31, 2021. The Company recorded $427.6 million of impairment expense related to its proved properties for the year ended December 31, 2020. 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 year ended December 31, 2021. The Company recognized $49.3 million in impairment expense related to its unproved properties for the year ended December 31, 2020. For the year ended December 31, 2020 the impairment was related to expiring leases and the evaluation of qualitative and quantitative factors related to the current decline in commodity prices. Significant declines in commodity prices, further changes to the Company’s drilling or development plans, reduction of proved and probable reserve estimates, or increases in drilling or operating costs could result in other additional future impairments to proved and unproved oil and gas properties. 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. 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 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 no uncertainty exists with respect to the receipt or amount of claim proceeds. The Company classifies LOPI within “Other revenues” in the Consolidated Statement of Operations. For the period from October 2, 2021 through December 31, 2021, the Company recognized LOPI insurance payments of $6.7 million from our Beta properties due to the pipeline incident that occurred on October 2, 2021. 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 Income Taxes – Simplifying the Accounting for Income Taxes. No other accounting standards issued by the FASB or other standards-setting bodies are expected to have a material impact on the Company’s financial position, results of operations and cash flows.

Revenues

Revenues	12 Months Ended
	Dec. 31, 2021
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, ​ ​ 2021 2020 ​ ​ (in thousands) Revenues ​ ​ ​ Oil ​ $ 212,486 ​ $ 138,273 NGLs ​ $ 40,899 ​ $ 20,064 Natural gas ​ $ 82,394 ​ $ 42,551 Oil and natural gas sales ​ $ 335,779 ​ $ 200,888 ​ 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 $32.4 million and $25.6 million at December 31, 2021 and 2020, 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
	Dec. 31, 2021
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, 2021 and 2020. 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, 2021 and 2020 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, 2021 and December 31, 2020 for each of the fair value hierarchy levels: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value Measurements at December 31, 2021 Using ​ ​ ​ ​ ​ ​ 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 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value Measurements at December 31, 2020 Using ​ ​ ​ ​ ​ ​ 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 ​ $ — ​ $ 15,449 ​ $ — ​ $ 15,449 Interest rate derivatives ​ — ​ — ​ — ​ — Total assets ​ $ — ​ $ 15,449 ​ $ — ​ $ 15,449 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liabilities: ​ ​ ​ ​ Commodity derivatives ​ $ — ​ $ 23,495 ​ $ — ​ $ 23,495 Interest rate derivatives ​ — ​ 2,752 ​ — ​ 2,752 Total liabilities ​ $ — ​ $ 26,247 ​ $ — ​ $ 26,247 ​ 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, 2021. (ii) The Company recognized $427.6 million of impairment expense on our proved oil and natural gas properties for the year ended December 31, 2020. These impairments related to certain properties located in East Texas, the Rockies, offshore Southern California and the Eagle Ford. The estimated future cash flows expected from these properties were compared to their carrying values and determined to be unrecoverable primarily as a result of declining commodity prices. The impairments were due to a decline in the value of estimated proved reserves based on declining commodity prices. ● 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. (iii) No impairment expense on our unproved oil and natural gas properties recorded for the year ended December 31, 2021. (i) The Company recognized $49.3 million of impairment expense on unproved properties for the year ended December 31, 2020, which was related to expiring leases and the evaluation of qualitative and quantitative factors related to the current decline in commodity prices.

Risk Management and Derivative

Risk Management and Derivative Instruments	12 Months Ended
	Dec. 31, 2021
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, 2021, 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. In April 2020, the Company monetized a portion of its 2021 crude oil hedges for total cash proceeds of approximately $18.0 million. 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, 2021, the Company had the following open commodity positions: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 2023 Natural Gas Derivative Contracts: ​ ​ ​ Fixed price swap contracts: ​ ​ ​ Average monthly volume (MMBtu) ​ ​ 695,000 ​ — Weighted-average fixed price ​ $ 2.56 ​ $ — ​ ​ ​ ​ ​ ​ ​ Collar contracts: ​ ​ ​ ​ Two-way collars ​ ​ ​ ​ Average monthly volume (MMBtu) ​ 775,000 ​ 370,000 Weighted-average floor price ​ $ 2.56 ​ $ 2.63 Weighted-average ceiling price ​ $ 3.44 ​ $ 3.61 ​ ​ ​ ​ ​ ​ ​ Crude Oil Derivative Contracts: ​ ​ ​ ​ Fixed price swap contracts: ​ ​ ​ ​ Average monthly volume (Bbls) ​ 64,000 ​ 55,000 Weighted-average fixed price ​ $ 49.56 ​ $ 57.30 ​ ​ ​ ​ ​ ​ ​ Collar contracts: ​ ​ Two-way collars ​ ​ ​ ​ ​ ​ Average monthly volume (Bbls) ​ ​ 22,500 ​ ​ — Weighted-average floor price ​ $ 58.33 ​ $ — Weighted-average ceiling price ​ $ 67.42 ​ $ — ​ ​ ​ ​ ​ ​ ​ Three-way collars ​ ​ ​ ​ Average monthly volume (Bbls) ​ 89,000 ​ 30,000 Weighted-average ceiling price ​ $ 55.55 ​ $ 67.15 Weighted-average floor price ​ $ 42.92 ​ $ 55.00 Weighted-average sub-floor price ​ $ 32.58 ​ $ 40.00 ​ Interest Rate Swaps Periodically, the Company enters into interest rate swaps to mitigate exposure to market rate fluctuations by converting variable interest rates such as those in its credit agreement to fixed interest rates. At December 31, 2021, the Company had the following interest rate swaps open positions: ​ ​ ​ ​ ​ ​ ​ ​ 2022 Average Monthly Notional (in thousands) ​ $ 75,000 ​ Weighted-average fixed rate ​ 1.281 % Floating rate ​ 1 Month LIBOR ​ ​ 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, 2021 and 2020. 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). ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liability ​ ​ Liability ​ ​ ​ ​ Asset Derivatives ​ Derivatives ​ Asset Derivatives ​ Derivatives ​ ​ ​ ​ December 31, ​ December 31, ​ December 31, ​ December 31, Type Balance Sheet Location 2021 2021 2020 2020 ​ ​ ​ ​ (In thousands) Commodity contracts Short-term derivative instruments ​ $ 4,804 ​ $ 57,325 ​ $ 6,088 ​ $ 15,007 Interest rate swaps Short-term derivative instruments ​ — ​ 623 ​ — ​ 1,905 Gross fair value ​ ​ 4,804 ​ 57,948 ​ 6,088 ​ 16,912 Netting arrangements ​ ​ (4,804) ​ (4,804) ​ (6,088) ​ (6,088) Net recorded fair value Short-term derivative instruments ​ $ — ​ $ 53,144 ​ $ — ​ $ 10,824 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity contracts Long-term derivative instruments ​ $ 3,163 ​ $ 12,827 ​ $ 9,361 ​ $ 8,488 Interest rate swaps Long-term derivative instruments ​ — ​ — ​ — ​ 847 Gross fair value ​ ​ 3,163 ​ 12,827 ​ 9,361 ​ 9,335 Netting arrangements ​ ​ (3,163) ​ (3,163) ​ (8,488) ​ (8,488) Net recorded fair value Long-term derivative instruments ​ $ — ​ $ 9,664 ​ $ 873 ​ $ 847 ​ (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 ​ 2021 2020 Commodity derivative contracts Loss (gain) on commodity derivatives ​ $ 142,439 ​ $ (60,671) Loss (gain) on interest rate derivatives Interest expense, net ​ (217) ​ 4,044 ​

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2021
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, 2021 and 2020 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ For the Year Ended ​ ​ December 31, ​ ​ 2021 2020 Asset retirement obligations at beginning of period ​ $ 97,149 ​ $ 91,089 Liabilities added from acquisition or drilling ​ 29 ​ 79 Liabilities settled ​ (296) ​ (327) Liabilities removed upon sale of wells ​ (113) ​ — Accretion expense ​ 6,611 ​ 6,206 Revision of estimates ​ 34 ​ 102 Asset retirement obligation at end of period ​ 103,414 ​ 97,149 Less: Current portion ​ 1,016 ​ 424 Asset retirement obligations - long-term portion ​ $ 102,398 ​ $ 96,725 ​

Restricted Investments

Restricted Investments	12 Months Ended
	Dec. 31, 2021
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, ​ ​ 2021 2020 ​ ​ (In thousands) BOEM platform abandonment (See Note 16) ​ $ 313 ​ $ 313 ​ ​ ​ ​ ​ ​ ​ SPBPC Collateral: ​ ​ Contractual pipeline and surface facilities abandonment ​ 4,309 ​ 4,310 Restricted investments ​ $ 4,622 ​ $ 4,623 ​

Debt

Debt	12 Months Ended
	Dec. 31, 2021
Debt
Debt	Note 8. Debt The Company’s consolidated debt obligations consisted of the following at the dates indicated: ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2021 ​ 2020 ​ ​ (In thousands) Revolving Credit Facility (1) ​ $ 230,000 ​ $ 255,000 Paycheck Protection Program loan (2) ​ — ​ 5,516 Total long-term debt ​ $ 230,000 ​ $ 260,516 (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. (2) See below for additional information regarding the receipt and the forgiveness of the paycheck protection program loan. 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 $245.0 million as of December 31, 2021, 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 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. Borrowing Base Redetermination Agreement and Fourth Amendment On November 17, 2020, the Company entered into the Borrowing Base Redetermination Agreement and Fourth Amendment to Credit Agreement, among the Borrower, Amplify Acquisitionco LLC, a Delaware limited liability company, the guarantors party thereto, the lenders party thereto and Bank of Montreal, as administrative agent (the “Fourth Amendment”). The Fourth Amendment amended the parties’ existing Credit Agreement, to among other things: ● reaffirm the borrowing base under the Credit Agreement at $260.0 million; and ● modify the affirmative hedging covenant to include at least 65% and 45% hedge for calendar years 2021 and 2022 on a total proved developed producing reserves, respectively . The foregoing description of the Fourth Amendment is qualified in its entirety by reference to the Fourth Amendment, which is attached as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on November 18, 2020. Borrowing Base Redetermination Agreement and Third Amendment On June 12, 2020, the Company entered into the Borrowing Base Redetermination Agreement and Third Amendment to Credit Agreement, among the Borrower, Amplify Acquisitionco LLC, a Delaware limited liability company, the guarantors party thereto, the lenders party thereto and Bank of Montreal, as administrative agent (the “Third Amendment”). The Third Amendment amended the parties’ existing Credit Agreement, to among other things: ● reduce the borrowing base under the Credit Agreement from $450.0 million to $285.0 million, with monthly reductions of $5.0 million thereafter until the borrowing base is reduced to $260.0 million, effective November 1, 2020; ● increase the amount of first priority liens on all assets from at least 85% to 90% ; ● the applicable margin for LIBOR loans and LIBOR Market loans increased from 200 to 300 basis points to 250 to 350 basis points. ● suspend certain financial covenants for the quarter ended June 30, 2020 ; ● amend the definition of “Consolidated EBITDAX” in the Credit Agreement to decrease the limit of cash and cash equivalents permitted from $30.0 million to $25.0 million and increase the limit of transaction-related expense add-backs from $5.0 million to $20.0 million; ● increase the minimum hedging requirements to at least 30% - 60% of our estimated production from total proved developed producing reserves; ● incorporate a mandatory prepayment at times when cash and cash equivalents (as defined in the Credit Agreement) on hand exceed $25.0 million for five consecutive business days; and ● amend certain other covenants and provisions. The foregoing description of the Third Amendment is qualified in its entirety by reference to the Third Amendment, which is attached as Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on June 15, 2020. Debt Compliance As of December 31, 2021, 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, ​ 2021 ​ 2020 Revolving Credit Facility ​ 3.65 % 3.63 % ​ Letters of credit At December 31, 2021, the Company had no letters of credit outstanding. Unamortized Deferred Financing Costs Unamortized deferred financing costs associated with the Revolving Credit Facility was $1.0 million at December 31, 2021. The unamortized deferred financing costs are amortized over the remaining life of the Revolving Credit Facility using the straight-line method, which generally approximates the effective interest method. For the year ended December 31, 2020, the Company wrote-off $2.4 million of deferred financing costs in connection with the decrease in the Company’s borrowing base.

Equity (Deficit)

Equity (Deficit)	12 Months Ended
	Dec. 31, 2021
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, 2019 37,566,540 Issuance of common stock — Restricted stock units vested 132,237 Shares withheld for taxes (1) (35,268) Balance, December 31, 2020 37,663,509 Issuance of common stock — Restricted stock units vested 77,985 Bonus stock awards (2) ​ 455,973 Shares withheld for taxes (1) ​ (173,325) Balance, December 31, 2021 38,024,142 (1) Represents the net settlement on vesting of restricted stock necessary to satisfy the minimum statutory tax withholding requirements. (2) 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. 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), exercisable for a five year period commencing on May 4, 2017 at an exercise price of $42.60 per share. The warrants will expire on May 4, 2022. The fair values for the warrants upon issuance were estimated using the Black-Scholes option pricing model using the following assumptions: ​ ​ ​ ​ ​ ​ ​ Warrants Issued in ​ ​ Successor Period Risk-free interest rate ​ 2.06 % Dividend yield ​ — ​ Expected life (in years) ​ 5.0 ​ Expected volatility ​ 50.0 % Strike Price ​ $ 42.60 ​ Calculated fair value ​ $ 2.20 ​ ​ Cash Dividend Payment On March 3, 2020, the Company’s board of directors approved a dividend of $0.10 per share of outstanding common stock or $3.8 million in aggregate, which was paid on March 30, 2020, to stockholders of record at the close of business on March 16, 2020. The board of directors subsequently suspended quarterly dividends. Future dividends, if any, are subject to debt covenants under the Revolving Credit Facility and discretionary approval by the board of directors.

Earnings per Share

Earnings per Share	12 Months Ended
	Dec. 31, 2021
Earnings per Share
Earnings per Share	Note 10. Earnings 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, ​ ​ 2021 ​ 2020 Net loss ​ $ (32,070) ​ $ (464,030) Less: Net income allocated to participating restricted stockholders ​ — ​ — Basic and diluted earnings available to common stockholders ​ $ (32,070) ​ $ (464,030) ​ ​ ​ ​ ​ ​ ​ Common shares: ​ ​ Common shares outstanding — basic ​ 37,959 ​ 37,612 Dilutive effect of potential common shares ​ — ​ — Common shares outstanding — diluted ​ 37,959 ​ 37,612 ​ ​ ​ ​ ​ ​ ​ Net earnings (loss) per share: ​ ​ Basic ​ $ (0.84) ​ $ (12.34) Diluted ​ $ (0.84) ​ $ (12.34) Antidilutive warrants (1) ​ 2,174 ​ 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
	Dec. 31, 2021
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 Management Incentive Plan (the “Legacy Amplify MIP”) and the Legacy Amplify 2017 Non-Employee Directors Compensation Plan (the “Legacy Amplify Non-Employee Directors Compensation Plan”) were replaced by the 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, 2021, the Company had 2,789,054 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. The unrecognized cost associated with TSUs was $2.5 million at December 31, 2021. The Company expects to recognize the unrecognized compensation cost for these awards over a weighted-average period of 2.0 years. The following table summarizes information regarding the TSUs granted under the EIP and Legacy Amplify MIP for the period presented: ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted- ​ ​ ​ ​ Average Grant- ​ ​ Number of ​ Date Fair Value ​ ​ Units ​ per Unit (1) TSUs outstanding at December 31, 2019 291,370 ​ $ 5.18 Granted (2) 43,250 ​ $ 3.10 Forfeited (93,845) ​ $ 5.12 Vested (124,978) ​ $ 5.17 TSUs outstanding at December 31, 2020 115,797 ​ $ 4.47 Granted (3) 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 (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, 2020 was $0.1 million based on a grant date market price ranging from $0.54 to $6.61 per share. (3) 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. 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, 2021. The Company expects to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 1.2 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 and the Legacy Amplify MIP for the period presented: ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted- ​ ​ ​ ​ Average Grant- ​ ​ Number of ​ Date Fair Value ​ ​ Units ​ per Unit (1) PSUs outstanding at December 31, 2019 305,893 ​ $ 2.15 Granted (2) 43,250 ​ $ 3.03 Forfeited (134,589) ​ $ 2.11 Vested — ​ $ — 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 (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 PSUs issued for the year ended December 31, 2020 was $0.1 million based on a calculated fair value price ranging from $2.46 to $3.66 per share. 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. The PRSUs are issued collectively in separate tranches with individual performances periods beginning in January 2021, 2022, and 2023 respectively. For each of the performance periods the awards will vest based on the percentage of the target PRSUs subject to the performance vesting condition with 25% able to vest during the period January 1, 2021 through December 31, 2021; 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. 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 unrecognized cost associated with the PRSUs was $0.2 million at December 31, 2021. The Company expects to recognize the unrecognized compensation cost for these awards over a weighted-average period of approximately 1.8 years. The ranges for the assumptions used in the Monte Carlo model for the PRSUs granted are presented as follows: ​ ​ ​ ​ ​ ​ 2021 ​ Expected volatility ​ 119.6 % Dividend yield ​ 0.00 % Risk-free interest rate ​ 0.31 % ​ The following table summarizes information regarding the PRSUs granted under the EIP and Legacy Amplify MIP 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 (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. 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. 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 unrecognized cost associated with Board RSUs was less than $0.1 million at December 31, 2021. The Company expects to recognize the unrecognized compensation cost for these awards over a weighted-average period of 0.3 years. 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, 2019 16,157 ​ $ 5.12 Granted — ​ $ — Forfeited — ​ $ — Vested (7,259) ​ $ 5.12 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 (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, ​ ​ 2021 ​ 2020 Equity classified awards ​ ​ ​ ​ TSUs ​ $ 1,541 ​ $ 267 PSUs ​ (130) ​ 98 Board RSUs ​ 16 ​ 19 PRSUs ​ ​ 178 ​ ​ — ​ ​ $ 1,605 ​ $ 384 ​

Leases

Leases	12 Months Ended
	Dec. 31, 2021
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, 2021, 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, 2021 and 2020, the Company recognized approximately $2.7 million and $2.4 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, ​ ​ 2021 ​ 2020 ​ ​ (In thousands) Right-of-use asset ​ $ 2,716 ​ $ 2,500 ​ ​ ​ ​ ​ ​ ​ Lease liabilities: ​ ​ Current lease liability ​ 777 ​ 2,258 Long-term lease liability ​ 2,017 ​ 266 Total lease liability ​ $ 2,794 ​ $ 2,524 ​ 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 2022 ​ $ 597 ​ $ 262 ​ $ 859 2023 ​ ​ 502 ​ ​ 240 ​ ​ 742 2024 ​ ​ 517 ​ ​ 32 ​ ​ 549 2025 ​ ​ 532 ​ ​ — ​ ​ 532 2026 and thereafter ​ 317 ​ — ​ 317 Total lease payments ​ 2,465 ​ 534 ​ 2,999 Less: interest ​ 186 ​ 19 ​ 205 Present value of lease liabilities ​ $ 2,279 ​ $ 515 ​ $ 2,794 ​ The weighted average remaining lease terms and discount rate for all of the Company’s operating leases for the period presented: ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2021 ​ 2020 Weighted average remaining lease term (years): ​ ​ Office and warehouse space 3.51 0.74 ​ Vehicles 0.37 0.34 ​ Office equipment — 0.04 ​ Weighted average discount rate: ​ ​ ​ Office leases 2.95 % 3.41 % Vehicles 0.59 % 0.96 % Office equipment 0.02 % 0.17 % ​

Supplemental Disclosures to the

Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows	12 Months Ended
	Dec. 31, 2021
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, ​ ​ 2021 ​ 2020 Accrued liability - pipeline incident ​ $ 34,417 ​ $ — Accrued lease operating expense ​ ​ 9,271 ​ ​ 8,978 Accrued general and administrative expense ​ 4,555 ​ 3,349 Accrued production and ad valorem tax ​ 3,277 ​ 2,601 Accrued commitment fee and other expense ​ 2,882 ​ 4,404 Accrued capital expenditures ​ ​ 1,631 ​ ​ 173 Asset retirement obligations ​ 1,016 ​ 424 Operating lease liability ​ ​ 777 ​ ​ 2,258 Accrued current income taxes ​ — ​ 110 Other ​ — ​ 380 Accrued liabilities ​ $ 57,826 ​ $ 22,677 ​ Accounts Receivable Accounts receivable consisted of the following at the dates indicated (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2021 ​ 2020 Oil and natural gas receivables ​ $ 32,428 ​ $ 25,640 Insurance receivable - pipeline incident ​ ​ 55,765 ​ ​ — Joint interest owners and other ​ ​ 5,409 ​ ​ 6,801 Total accounts receivable ​ 93,602 ​ 32,441 Less: allowance for doubtful accounts ​ (1,635) ​ (1,540) Total accounts receivable, net ​ 91,967 ​ 30,901 ​ Supplemental Cash Flows Supplemental cash flow for the periods presented (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ For the Year Ended ​ ​ December 31, ​ ​ 2021 ​ 2020 Supplemental cash flows: ​ ​ ​ ​ Cash paid for interest, net of amounts capitalized ​ $ 8,637 ​ $ 10,331 Cash paid for reorganization items, net 6 ​ 566 Cash paid for taxes — ​ 85 ​ ​ ​ ​ ​ ​ ​ Noncash investing and financing activities: ​ ​ ​ Increase (decrease) in capital expenditures in payables and accrued liabilities 1,669 ​ (5,343) ​

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2021
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, 2021 and 2020. Secondary Public Offering of Common Stock for Selling Stockholders On December 11, 2020, certain selling stockholders of the Company (the “Selling Stockholders”), Roth Capital Partners, LLC (the “Underwriter”) and the Company entered into an underwriting agreement, pursuant to which the Selling Stockholders agreed to sell to the Underwriter, and the Underwriter agreed to purchase from the Selling Stockholders, subject to and upon the terms and conditions set forth therein, an aggregate of 8,548,485 shares of Common Stock. The offering closed on December 15, 2020. The Company did not receive any proceeds from the sale of shares of Common Stock in the offering. The offering was made pursuant to effective shelf registration statements (File No. 333-233677, effective October 11, 2019, and 333-215602, effective May 1, 2018) and prospectuses filed by the Company with the SEC. The offering of these securities was made only by means of a prospectus and prospectus supplement.

Southern California Pipeline In

Southern California Pipeline Incident	12 Months Ended
	Dec. 31, 2021
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, 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 are currently under investigation and any information regarding the Incident is preliminary. At the height of the Incident response, the Company deployed over 1,800 personnel working under the guidance and at the direction of the Unified Command to aid in cleanup operations. As of October 14, 2021, all beaches that had been closed following the Incident have reopened. On February 2, 2022, the Unified Command announced that response and monitoring efforts have officially concluded for the Incident, and Unified Command would stand down as of such date. Amplify is grateful to its Unified Command partners for their collaboration and professionalism over the course of the response. In response to the Incident, all operations have been suspended and the pipeline has been shut-in until the Company receives the required regulatory approvals to begin 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. Additionally, the California Coastal Commission has requested approval from the Office of Coastal Management for the National Oceanic and Atmospheric Association to conduct a Coastal Zone Management Act consistency review of the U.S. Army Corps of Engineers Nationwide Permit (NWP) 12 application for the proposed permanent repair permit. The Company is working expeditiously and cooperatively to comply with the requirements of the relevant agencies in order to gain such approvals and any other regulatory approvals that are necessary to permanently repair the pipeline and restart operations. As a result of the uncertainties related to the permitting and regulatory approval process, we can provide no assurances as to whether and when, if at all, we will be able to restart operations at the Beta field. At present, no operations are underway in the Beta field. 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, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration, 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 are conducting investigations or examinations of the Incident. Other federal agencies may or have commenced investigations and proceedings, and federal agencies such as the U.S. Environmental Protection Agency 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 and criminal liability. 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. The United States Attorney’s Office for the Central District of California has stated that its investigation of the Incident and related matters is ongoing. State authorities are conducting parallel criminal investigations as well. The Company is continuing to cooperate with these federal and state investigations. The outcome of these investigations is uncertain, including whether they will result in additional criminal charges. The Company and certain of its subsidiaries have been named as defendants in approximately 14 putative class action lawsuits, which have been consolidated into a single consolidated action in the United States District Court for the Central District of California. In the consolidated action, Plaintiffs filed an amended class action complaint on January 28, 2022. The amended complaint asserted claims against us and MSC Mediterranean Shipping Company, Dordellas Finance Corp., Costamare Shipping Co. S.A., and Capetanissa Maritime Corporation of Liberia. Resolution of the consolidated case may take considerable time, and it is not possible at this time to estimate our potential liability resulting from these actions. Under the Oil Pollution Act of 1990, 33 U.S.C. S 2701 et seq. (“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. The Company currently estimates that the total costs it has incurred or will incur with respect to the Incident related to (i) actual and projected response and remediation expenses incurred under the direction of the Unified Command and (ii) estimates for certain legal fees, to be approximately $90.0 million to $110.0 million. These estimates consider currently available facts and presently enacted laws and regulations. The Company has made assumptions regarding (i) the probable and estimable amounts expected to be settled with certain vendors for response and remediation expenses and (ii) the resolution of certain third-party claims, excluding claims with respect to losses, which are not probable and reasonably estimable, and (iii) future claims and lawsuits. 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 future costs associated with the permanent repair of the pipeline and the restart of the Beta operations. The Company believes it has accrued adequate amounts for all probable and reasonably estimable costs; however, this estimate is subject to uncertainties associated with the assumptions that it has made. For example, settlements with vendors for response and remediation expenses could turn out to be significantly higher or lower than the Company has estimated. Accordingly, as the Company’s assumptions and estimates may change in future periods based on future events and total costs may materially increase; therefore, the Company can provide no assurance that it will not have to accrue significant additional costs in future period with respect to the Incident. 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. As of December 31, 2021, the Company has incurred total aggregate gross costs of $99.0 million, of which the Company has received or believes that it is probable that it will receive $97.4 million in insurance recoveries. The Company’s net charge of $1.6 million, which is classified as “Pipeline Incident Loss” in the Company’s Consolidated Statements of Operations, reflects insurance deductibles and legal costs incurred to date that are not currently expected to be recovered under an insurance policy. Through December 31, 2021, the Company had collected $48.3 million out of approximate $97.4 million of costs that the Company believe are probable of recovery from insurance carriers, net of deductibles. Therefore as of December 31, 2021, the Company had a receivable of approximately $49.1 million for the portion of costs that the Company believe is probable of recovery from insurance, net of deductibles and amounts collected during 2021. Subsequent to December 31, 2021, for the period January 1, 2022 through March 1, 2022, the Company received insurance cost recoveries of $22.1 million. Additionally, during 2021, the Company recognized $6.7 million related to approved LOPI insurance claims, which is classified as “Other Revenues” in the Company’s Consolidated Statement of Operations. Subsequent to December 31, 2021, for the period January 1, 2022 through March 1, 2022, the Company received the entire LOPI insurance claim settlement of $6.7 million.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2021
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, 2021 and 2020, the Company had no environmental reserves recorded. Southern California Pipeline Incident As of February 11, 2022, 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 plaintiffs seek unspecified monetary damages and certain forms of injunctive relief. We are also participating in a related claims process organized under the Oil Pollution Act of 1990, 33 U.S.C. S 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 at a preliminary stage. 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. Application for Final Decree On April 30, 2018, the Legacy Amplify debtors filed with the Bankruptcy Court a motion for a final decree and entry of an order closing the Chapter 11 cases with respect to each of the Legacy Amplify debtors other than (i) San Pedro Bay Pipeline Company, Ch. 11 Case No. 17-30249, (ii) Rise Energy Beta, LLC, Ch. 11 Case No. 17-30250, and (iii) Beta Operating Company, LLC, Ch. 11 Case No. 17-30253, (collectively, the “Closing Debtors”). On May 30, 2018, the Bankruptcy Court entered the final decree closing the Chapter 11 cases of the Closing Debtors. On August 24, 2020, the Legacy Amplify debtors filed with the Bankruptcy Court a motion for a final decree closing the remaining Chapter 11 cases with respect to (i) San Pedro Bay Pipeline Company, Ch. 11 Case No. 17-30249, (ii) Rise Energy Beta, LLC, Ch. 11 Case No. 17-30250, and (iii) Beta Operating Company, LLC, Ch. 11 Case No. 17-30253. On September 15, 2020, the Bankruptcy Court entered the final decree closing the remaining Chapter 11 cases. Accordingly, certain expenses, gains and losses that were realized or incurred in the bankruptcy proceedings are recorded in “reorganization items, net” on the Company’s Consolidated Statement of Operations. Sinking Fund Trust Agreement Beta Operating Company, LLC, a wholly owned subsidiary, assumed an obligation with a third party to make payments into a sinking fund in connection with its 2009 acquisition of the 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, 2021, the account balance included in restricted investments was approximately $4.3 million. Supplemental Bond for Decommissioning Liabilities Trust Agreement Beta 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 $0.3 million in cash at December 31, 2021. 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, 2021 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Payment Due by Period Funding commitment ​ Total 2022 2023 2024 2025 2026 Thereafter (1) Sinking fund payments ​ $ 172,601 ​ $ 6,688 ​ $ 8,025 ​ $ 15,789 ​ $ 15,789 ​ $ 15,789 ​ $ 110,521 (1) The remaining payments will be made during the years of 2027 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, 2021 and 2020, the Company recognized $7.6 million and $8.3 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, 2021, the Company had a CO 2 2 2 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Payment or Settlement Due by Period Purchase commitment ​ Total 2022 2023 2024 2025 2026 Thereafter CO 2 ​ $ 3,975 ​ $ 3,975 ​ $ — ​ $ — ​ $ — ​ $ — ​ $ — ​ Minimum Volume Commitment At December 31, 2021, the Company had long-term minimum volume commitments with third parties associated with a certain portion of its properties located in Oklahoma and East Texas. 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 2022 2023 2024 2025 2026 Thereafter Minimum volume commitment ​ $ 15,196 ​ $ 12,283 ​ $ 2,913 ​ $ — ​ $ — ​ $ — ​ $ — (2) The amounts in the table do not reflect costs adjusted for inflation. The Company is party to a gas purchase, 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, 2021 and 2020, was approximately $1.6 million and $2.1 million. The minimum volume commitment for Oklahoma ends on June 30, 2023. The Company is party to a gas purchase, gathering and processing contract in East Texas, which includes certain minimum gas commitments. The Company is not meeting the minimum volume required under this contractual provision. The commitment fee expense for the year ended December 31, 2021 and 2020, was approximately $2.0 million and $1.8 million, respectively. The minimum volume commitment for East Texas ends on November 30, 2022.

Income Tax

Income Tax	12 Months Ended
	Dec. 31, 2021
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. On March 11, 2021, the President of the United States signed the ARP Act, to respond to the COVID-19 emergency and address its economic effects. Additionally, the President signed the Infrastructure Investment and Jobs Act “IIJ Act” on November 15, 2021 to authorize funds for Federal-aid highways, highway safety programs, and transit programs, and for other purposes. The enactment of the ARP Act and IIJ Act did not result in any material impact on the Company’s current year income tax provision. The components of income tax benefit (expense) are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ For the Year Ended ​ ​ December 31, ​ ​ 2021 2020 ​ ​ (In thousands) Current taxes: ​ ​ Federal ​ $ — ​ $ (5) State ​ — ​ (110) Total current income tax benefit (expense) ​ — ​ (115) Deferred taxes: ​ ​ Federal ​ — ​ — State ​ — ​ — Total deferred income tax benefit (expense) ​ — ​ — Total income tax benefit (expense) ​ $ — ​ $ (115) ​ The actual income tax benefit (expense) differs from the expected amount computed by applying the federal statutory corporate tax rate of 21% in 2021 and in 2020 as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ For the Year Ended ​ ​ December 31, ​ ​ 2021 2020 ​ ​ (In thousands) Expected tax benefit (expense) at federal statutory rate ​ $ 6,734 ​ $ 97,423 State income tax benefit (expense), net of federal benefit ​ 447 ​ 6,189 Non-deductible expenses ​ (64) ​ (45) Changes in valuation allowances ​ 3,192 ​ (110,445) State rate change, net of federal benefit ​ (10,192) ​ 6,100 State prior year adjustment ​ ​ (1,281) ​ ​ — Non-cash compensation ​ 8 ​ (137) PPP loan forgiveness ​ ​ 1,158 ​ ​ — Other ​ (2) ​ 800 Total income tax benefit (expense) ​ $ — ​ $ (115) ​ The Company’s deferred 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, ​ ​ 2021 ​ 2020 Deferred income tax assets: ​ ​ Property, Plant & Equipment ​ $ 94,439 ​ $ 115,695 Net operating loss carryforward ​ 178,279 ​ 174,479 Derivatives ​ 14,438 ​ 2,448 Disallowed interest expense ​ 5,579 ​ 5,388 Accrued liabilities ​ 1,592 ​ 1,226 Other ​ 3,469 ​ 1,717 Total deferred income tax assets: ​ 297,796 ​ 300,953 Valuation allowance ​ (297,195) ​ (300,386) Net deferred income tax assets ​ 601 ​ 567 ​ ​ ​ ​ ​ ​ ​ Deferred income tax liabilities: ​ ​ Derivatives ​ $ — ​ $ — Other ​ 601 ​ 567 Total deferred income tax liabilities ​ 601 ​ 567 ​ ​ ​ ​ ​ ​ ​ Net deferred income tax liabilities ​ $ — ​ $ — ​ As of December 31, 2021, the Company had approximately $777.6 million of federal net operating loss (“NOL”) carryovers, of which $757.0 million have no expiration date and the remaining will expire in year 2037. In connection with the merger with Midstates in 2019, the Company is subject to IRC §382 loss limitation on pre-merger NOL and tax attributes. The amount of 2021 federal NOL carryover generated post-merger, and not subject to §382 loss limitation, is $32.2 million. As of December 31, 2021, the Company had approximately $429.8 million of state net operating loss carryovers, of which $376.3 million have no expiration period, and the remaining will expire in varying amounts beginning in 2037. In assessing deferred tax assets, the Company considers whether a valuation allowance should be recorded for some or all of the deferred tax assets which may not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which the temporary differences become deductible. Among other items, the Company considers the scheduled reversal of deferred tax liabilities, projected future taxable income and available tax planning strategies. A valuation allowance is established against deferred tax assets for which management believes realization is considered to be more likely than not that all of the deferred tax assets will not be realized. As of December 31, 2021, a valuation allowance of $297.2 million had been recorded, which is an increase to the valuation allowance of $3.2 million from the prior year. Uncertain Income Tax Position. Tax Audits and Settlements.

Supplemental Oil and Gas Inform

Supplemental Oil and Gas Information (Unaudited)	12 Months Ended
	Dec. 31, 2021
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, ​ ​ 2021 ​ 2020 ​ ​ (In thousands) Evaluated oil and natural gas properties ​ $ 799,532 ​ $ 775,167 Support equipment and facilities ​ 145,324 ​ 142,208 Accumulated depletion, depreciation, and amortization ​ (625,754) ​ (602,861) Total ​ $ 319,102 ​ $ 314,514 ​ 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, ​ ​ 2021 ​ 2020 ​ ​ (In thousands) Property acquisition costs, proved ​ $ 3 ​ $ 42 Property acquisition costs, unproved ​ — ​ (49,307) Exploration ​ — ​ — Development ​ 27,478 ​ 29,543 Total ​ $ 27,481 ​ $ (19,722) ​ 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, 2021 and 2020. 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: ​ ​ ​ ​ ​ ​ ​ ​ ​ 2021 2020 Oil ($/Bbl): ​ ​ WTI (1) ​ $ 66.56 ​ $ 39.57 ​ ​ ​ ​ ​ ​ ​ NGL ($/Bbl): ​ ​ WTI (1) ​ $ 66.56 ​ $ 39.57 ​ ​ ​ ​ ​ ​ ​ Natural Gas ($/MMbtu): ​ ​ Henry Hub (2) ​ $ 3.60 ​ $ 1.99 (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, 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 year 35,613 252,218 19,009 96,658 End of year 43,857 309,794 23,574 119,063 ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved undeveloped reserves (2): Beginning of year 11,063 21,921 2,475 17,191 End of year 1,144 4,556 263 2,167 (1) Our reserves related to our Beta properties have been 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. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ For the Year Ended December 31, 2020 ​ ​ Oil ​ Gas ​ NGLs ​ Total ​ ​ (MBbls) ​ (MMcf) ​ (MBbls) ​ (MBoe) Proved developed and undeveloped reserves: Beginning of period 70,772 377,869 29,252 163,002 Extensions and discoveries 291 655 61 461 Production (3,887) (27,473) (1,725) (10,190) Revision of previous estimates (20,500) (76,912) (6,104) (39,424) End of period 46,676 274,139 21,484 113,849 ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved developed reserves: Beginning of period 53,476 320,731 23,646 130,577 End of period 35,613 252,218 19,009 96,658 ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved undeveloped reserves: ​ Beginning of period 17,296 57,138 5,606 32,425 End of period 11,063 21,921 2,475 17,191 ​ Noteworthy amounts included in the categories of proved reserve changes in the above tables include: ● 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. ● The 49.2 MMBoe reduction in reserves for the year ended December 31, 2020 is primarily due to a 50.1 MMBoe downward pricing revision as a result of changes in commodity pricing, partially offset by a 4.5 MMBoe upward revision due to lower maintenance costs, a 2.4 MMBoe upward revision due to Special Case Royalty Relief on our offshore Southern California assets and a 3.7 MMBoe upward technical revision. Additionally, the Company added 0.46 MMBoe during the year ended December 31, 2020 due to extensions and discoveries. 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, ​ 2021 2020 ​ ​ (In thousands) Future cash inflows ​ $ 4,569,313 ​ $ 2,410,260 Future production costs (1) ​ (2,691,875) ​ (1,589,945) Future development costs (1) ​ (231,040) ​ (375,146) Future income tax expense ​ — ​ — Future net cash flows for estimated timing of cash flows ​ 1,646,398 ​ 445,169 10% annual discount for estimated timing of cash flows ​ (726,553) ​ (147,358) Standardized measure of discounted future net cash flows ​ $ 919,845 ​ $ 297,811 (1) For the year ended December 31, 2021 and 2020, 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, ​ ​ 2021 2020 ​ ​ (In thousands) Beginning of year ​ $ 297,811 ​ $ 916,561 Sale of oil and natural gas produced, net of production costs ​ (171,326) ​ (47,687) Sale of minerals in place ​ (45) ​ — Extensions and discoveries ​ 17,035 ​ 3,687 Changes in prices and costs ​ 572,897 ​ (548,429) Previously estimated development costs incurred ​ 45,298 ​ 49,144 Net changes in future development costs ​ 113,546 ​ 89,997 Revisions of previous quantities ​ 46,271 ​ (150,245) Accretion of discount ​ 29,781 ​ 91,657 Change in production rates and other ​ (31,423) ​ (106,874) End of year ​ $ 919,845 ​ $ 297,811 ​

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2021
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”).
Market Conditions and COVID-19	Market Conditions and COVID-19 In March 2020, the World Health Organization classified the outbreak of COVID 19 as a global pandemic. In attempting to control the spread of COVID 19, governments around the world imposed laws and regulations such as shelter-in-place orders, quarantines, executive orders and similar restrictions. As a result, the global economy suffered a significant slowdown and uncertainty, which in turn led to a precipitous decline in commodity prices in response to decreased demand. Beginning in the first quarter of 2021 and continuing throughout the year, commodity prices have recovered substantially, due in part to the accessibility of vaccines, reopening of economies after lockdowns, and general optimism concerning the spread and severity of new variants of COVID-19 and the economic recovery. Despite recent downward trends in the spread of COVID-19, particularly as vaccination rates have increased, new variants of COVID-19 have intermittently emerged and spread throughout the U.S. and globally causing further uncertainty. This continued uncertainty and/or the emergence of new COVID 19 variant, including vaccine resistant variant, may result in additional adverse impacts on our results of operations, cash flows and financial position. Paycheck Protection Program.
Employee Retention Credit	Employee Retention Credit.
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 and $1.5 million as an allowance for doubtful accounts at December 31, 2021 and 2020, respectively. 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, ​ ​ 2021 2020 ​ Major customers: ​ Sinclair Oil & Gas Company 20 % 21 % Phillips 66 19 % 23 % ETC Texas Pipeline LTD ​ 12 % n/a % BP America Production Company n/a % 17 %
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 were no material capitalized exploratory drilling costs pending evaluation at December 31, 2021 and 2020.
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, 2021 and 2020. 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 is 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, 2021 and 2020 was approximately $0.6 million and $3.3 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 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 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 proved and 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. No impairment expense related to its proved properties was recorded for the year ended December 31, 2021. The Company recorded $427.6 million of impairment expense related to its proved properties for the year ended December 31, 2020. 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 year ended December 31, 2021. The Company recognized $49.3 million in impairment expense related to its unproved properties for the year ended December 31, 2020. For the year ended December 31, 2020 the impairment was related to expiring leases and the evaluation of qualitative and quantitative factors related to the current decline in commodity prices. Significant declines in commodity prices, further changes to the Company’s drilling or development plans, reduction of proved and probable reserve estimates, or increases in drilling or operating costs could result in other additional future impairments to proved and unproved oil and gas properties.
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. 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 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 no uncertainty exists with respect to the receipt or amount of claim proceeds. The Company classifies LOPI within “Other revenues” in the Consolidated Statement of Operations. For the period from October 2, 2021 through December 31, 2021, the Company recognized LOPI insurance payments of $6.7 million from our Beta properties due to the pipeline incident that occurred on October 2, 2021. 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 Income Taxes – Simplifying the Accounting for Income Taxes. No other accounting standards issued by the FASB or other standards-setting bodies 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
	Dec. 31, 2021
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, ​ ​ 2021 2020 ​ Major customers: ​ Sinclair Oil & Gas Company 20 % 21 % Phillips 66 19 % 23 % ETC Texas Pipeline LTD ​ 12 % n/a % BP America Production Company n/a % 17 %

Revenues (Tables)

Revenues (Tables)	12 Months Ended
	Dec. 31, 2021
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, ​ ​ 2021 2020 ​ ​ (in thousands) Revenues ​ ​ ​ Oil ​ $ 212,486 ​ $ 138,273 NGLs ​ $ 40,899 ​ $ 20,064 Natural gas ​ $ 82,394 ​ $ 42,551 Oil and natural gas sales ​ $ 335,779 ​ $ 200,888

Fair Value Measurements of Fi_2

Fair Value Measurements of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 and December 31, 2020 for each of the fair value hierarchy levels: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value Measurements at December 31, 2021 Using ​ ​ ​ ​ ​ ​ 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 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value Measurements at December 31, 2020 Using ​ ​ ​ ​ ​ ​ 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 ​ $ — ​ $ 15,449 ​ $ — ​ $ 15,449 Interest rate derivatives ​ — ​ — ​ — ​ — Total assets ​ $ — ​ $ 15,449 ​ $ — ​ $ 15,449 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liabilities: ​ ​ ​ ​ Commodity derivatives ​ $ — ​ $ 23,495 ​ $ — ​ $ 23,495 Interest rate derivatives ​ — ​ 2,752 ​ — ​ 2,752 Total liabilities ​ $ — ​ $ 26,247 ​ $ — ​ $ 26,247

Risk Management and Derivativ_2

Risk Management and Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2021
Risk Management and Derivative Instruments
Open Commodity Positions	At December 31, 2021, the Company had the following open commodity positions: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 2023 Natural Gas Derivative Contracts: ​ ​ ​ Fixed price swap contracts: ​ ​ ​ Average monthly volume (MMBtu) ​ ​ 695,000 ​ — Weighted-average fixed price ​ $ 2.56 ​ $ — ​ ​ ​ ​ ​ ​ ​ Collar contracts: ​ ​ ​ ​ Two-way collars ​ ​ ​ ​ Average monthly volume (MMBtu) ​ 775,000 ​ 370,000 Weighted-average floor price ​ $ 2.56 ​ $ 2.63 Weighted-average ceiling price ​ $ 3.44 ​ $ 3.61 ​ ​ ​ ​ ​ ​ ​ Crude Oil Derivative Contracts: ​ ​ ​ ​ Fixed price swap contracts: ​ ​ ​ ​ Average monthly volume (Bbls) ​ 64,000 ​ 55,000 Weighted-average fixed price ​ $ 49.56 ​ $ 57.30 ​ ​ ​ ​ ​ ​ ​ Collar contracts: ​ ​ Two-way collars ​ ​ ​ ​ ​ ​ Average monthly volume (Bbls) ​ ​ 22,500 ​ ​ — Weighted-average floor price ​ $ 58.33 ​ $ — Weighted-average ceiling price ​ $ 67.42 ​ $ — ​ ​ ​ ​ ​ ​ ​ Three-way collars ​ ​ ​ ​ Average monthly volume (Bbls) ​ 89,000 ​ 30,000 Weighted-average ceiling price ​ $ 55.55 ​ $ 67.15 Weighted-average floor price ​ $ 42.92 ​ $ 55.00 Weighted-average sub-floor price ​ $ 32.58 ​ $ 40.00
Interest Rate Swap Open Positions	​ ​ ​ ​ ​ ​ ​ ​ 2022 Average Monthly Notional (in thousands) ​ $ 75,000 ​ Weighted-average fixed rate ​ 1.281 % Floating rate ​ 1 Month LIBOR ​
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, 2021 and 2020. 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). ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Liability ​ ​ Liability ​ ​ ​ ​ Asset Derivatives ​ Derivatives ​ Asset Derivatives ​ Derivatives ​ ​ ​ ​ December 31, ​ December 31, ​ December 31, ​ December 31, Type Balance Sheet Location 2021 2021 2020 2020 ​ ​ ​ ​ (In thousands) Commodity contracts Short-term derivative instruments ​ $ 4,804 ​ $ 57,325 ​ $ 6,088 ​ $ 15,007 Interest rate swaps Short-term derivative instruments ​ — ​ 623 ​ — ​ 1,905 Gross fair value ​ ​ 4,804 ​ 57,948 ​ 6,088 ​ 16,912 Netting arrangements ​ ​ (4,804) ​ (4,804) ​ (6,088) ​ (6,088) Net recorded fair value Short-term derivative instruments ​ $ — ​ $ 53,144 ​ $ — ​ $ 10,824 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Commodity contracts Long-term derivative instruments ​ $ 3,163 ​ $ 12,827 ​ $ 9,361 ​ $ 8,488 Interest rate swaps Long-term derivative instruments ​ — ​ — ​ — ​ 847 Gross fair value ​ ​ 3,163 ​ 12,827 ​ 9,361 ​ 9,335 Netting arrangements ​ ​ (3,163) ​ (3,163) ​ (8,488) ​ (8,488) Net recorded fair value Long-term derivative instruments ​ $ — ​ $ 9,664 ​ $ 873 ​ $ 847
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 ​ 2021 2020 Commodity derivative contracts Loss (gain) on commodity derivatives ​ $ 142,439 ​ $ (60,671) Loss (gain) on interest rate derivatives Interest expense, net ​ (217) ​ 4,044

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2021
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, 2021 and 2020 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ For the Year Ended ​ ​ December 31, ​ ​ 2021 2020 Asset retirement obligations at beginning of period ​ $ 97,149 ​ $ 91,089 Liabilities added from acquisition or drilling ​ 29 ​ 79 Liabilities settled ​ (296) ​ (327) Liabilities removed upon sale of wells ​ (113) ​ — Accretion expense ​ 6,611 ​ 6,206 Revision of estimates ​ 34 ​ 102 Asset retirement obligation at end of period ​ 103,414 ​ 97,149 Less: Current portion ​ 1,016 ​ 424 Asset retirement obligations - long-term portion ​ $ 102,398 ​ $ 96,725

Restricted Investments (Tables)

Restricted Investments (Tables)	12 Months Ended
	Dec. 31, 2021
Restricted Investments
Restricted Investment Balances	​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2021 2020 ​ ​ (In thousands) BOEM platform abandonment (See Note 16) ​ $ 313 ​ $ 313 ​ ​ ​ ​ ​ ​ ​ SPBPC Collateral: ​ ​ Contractual pipeline and surface facilities abandonment ​ 4,309 ​ 4,310 Restricted investments ​ $ 4,622 ​ $ 4,623

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2021
Debt
Consolidated Debt Obligations	The Company’s consolidated debt obligations consisted of the following at the dates indicated: ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2021 ​ 2020 ​ ​ (In thousands) Revolving Credit Facility (1) ​ $ 230,000 ​ $ 255,000 Paycheck Protection Program loan (2) ​ — ​ 5,516 Total long-term debt ​ $ 230,000 ​ $ 260,516 (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. (2) See below for additional information regarding the receipt and the forgiveness of the paycheck protection program loan.
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, ​ 2021 ​ 2020 Revolving Credit Facility ​ 3.65 % 3.63 %

Equity (Deficit) (Tables)

Equity (Deficit) (Tables)	12 Months Ended
	Dec. 31, 2021
Equity And Distributions [Line Items]
Summary of Changes in Common Stock Issued	​ ​ ​ ​ ​ Common Stock Balance, December 31, 2019 37,566,540 Issuance of common stock — Restricted stock units vested 132,237 Shares withheld for taxes (1) (35,268) Balance, December 31, 2020 37,663,509 Issuance of common stock — Restricted stock units vested 77,985 Bonus stock awards (2) ​ 455,973 Shares withheld for taxes (1) ​ (173,325) Balance, December 31, 2021 38,024,142 (1) Represents the net settlement on vesting of restricted stock necessary to satisfy the minimum statutory tax withholding requirements. (2) 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.
Warrant [Member]
Equity And Distributions [Line Items]
Summary of Assumptions used to Estimate the Fair Value	​ ​ ​ ​ ​ ​ ​ Warrants Issued in ​ ​ Successor Period Risk-free interest rate ​ 2.06 % Dividend yield ​ — ​ Expected life (in years) ​ 5.0 ​ Expected volatility ​ 50.0 % Strike Price ​ $ 42.60 ​ Calculated fair value ​ $ 2.20 ​

Earnings per Share (Tables)

Earnings per Share (Tables)	12 Months Ended
	Dec. 31, 2021
Earnings 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, ​ ​ 2021 ​ 2020 Net loss ​ $ (32,070) ​ $ (464,030) Less: Net income allocated to participating restricted stockholders ​ — ​ — Basic and diluted earnings available to common stockholders ​ $ (32,070) ​ $ (464,030) ​ ​ ​ ​ ​ ​ ​ Common shares: ​ ​ Common shares outstanding — basic ​ 37,959 ​ 37,612 Dilutive effect of potential common shares ​ — ​ — Common shares outstanding — diluted ​ 37,959 ​ 37,612 ​ ​ ​ ​ ​ ​ ​ Net earnings (loss) per share: ​ ​ Basic ​ $ (0.84) ​ $ (12.34) Diluted ​ $ (0.84) ​ $ (12.34) Antidilutive warrants (1) ​ 2,174 ​ 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
	Dec. 31, 2021
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, ​ ​ 2021 ​ 2020 Equity classified awards ​ ​ ​ ​ TSUs ​ $ 1,541 ​ $ 267 PSUs ​ (130) ​ 98 Board RSUs ​ 16 ​ 19 PRSUs ​ ​ 178 ​ ​ — ​ ​ $ 1,605 ​ $ 384
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, 2019 16,157 ​ $ 5.12 Granted — ​ $ — Forfeited — ​ $ — Vested (7,259) ​ $ 5.12 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 (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 and Legacy Amplify MIP for the period presented: ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted- ​ ​ ​ ​ Average Grant- ​ ​ Number of ​ Date Fair Value ​ ​ Units ​ per Unit (1) TSUs outstanding at December 31, 2019 291,370 ​ $ 5.18 Granted (2) 43,250 ​ $ 3.10 Forfeited (93,845) ​ $ 5.12 Vested (124,978) ​ $ 5.17 TSUs outstanding at December 31, 2020 115,797 ​ $ 4.47 Granted (3) 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 (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, 2020 was $0.1 million based on a grant date market price ranging from $0.54 to $6.61 per share. (3) 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.
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 and the Legacy Amplify MIP for the period presented: ​ ​ ​ ​ ​ ​ ​ ​ ​ Weighted- ​ ​ ​ ​ Average Grant- ​ ​ Number of ​ Date Fair Value ​ ​ Units ​ per Unit (1) PSUs outstanding at December 31, 2019 305,893 ​ $ 2.15 Granted (2) 43,250 ​ $ 3.03 Forfeited (134,589) ​ $ 2.11 Vested — ​ $ — 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 (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 PSUs issued for the year ended December 31, 2020 was $0.1 million based on a calculated fair value price ranging from $2.46 to $3.66 per share.
PRSU [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 PRSUs granted under the EIP and Legacy Amplify MIP 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 (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.
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 PRSUs granted are presented as follows: ​ ​ ​ ​ ​ ​ 2021 ​ Expected volatility ​ 119.6 % Dividend yield ​ 0.00 % Risk-free interest rate ​ 0.31 %

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2021
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, ​ ​ 2021 ​ 2020 ​ ​ (In thousands) Right-of-use asset ​ $ 2,716 ​ $ 2,500 ​ ​ ​ ​ ​ ​ ​ Lease liabilities: ​ ​ Current lease liability ​ 777 ​ 2,258 Long-term lease liability ​ 2,017 ​ 266 Total lease liability ​ $ 2,794 ​ $ 2,524
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 2022 ​ $ 597 ​ $ 262 ​ $ 859 2023 ​ ​ 502 ​ ​ 240 ​ ​ 742 2024 ​ ​ 517 ​ ​ 32 ​ ​ 549 2025 ​ ​ 532 ​ ​ — ​ ​ 532 2026 and thereafter ​ 317 ​ — ​ 317 Total lease payments ​ 2,465 ​ 534 ​ 2,999 Less: interest ​ 186 ​ 19 ​ 205 Present value of lease liabilities ​ $ 2,279 ​ $ 515 ​ $ 2,794
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, ​ ​ 2021 ​ 2020 Weighted average remaining lease term (years): ​ ​ Office and warehouse space 3.51 0.74 ​ Vehicles 0.37 0.34 ​ Office equipment — 0.04 ​ Weighted average discount rate: ​ ​ ​ Office leases 2.95 % 3.41 % Vehicles 0.59 % 0.96 % Office equipment 0.02 % 0.17 %

Supplemental Disclosures to t_2

Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows (Tables)	12 Months Ended
	Dec. 31, 2021
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, ​ ​ 2021 ​ 2020 Accrued liability - pipeline incident ​ $ 34,417 ​ $ — Accrued lease operating expense ​ ​ 9,271 ​ ​ 8,978 Accrued general and administrative expense ​ 4,555 ​ 3,349 Accrued production and ad valorem tax ​ 3,277 ​ 2,601 Accrued commitment fee and other expense ​ 2,882 ​ 4,404 Accrued capital expenditures ​ ​ 1,631 ​ ​ 173 Asset retirement obligations ​ 1,016 ​ 424 Operating lease liability ​ ​ 777 ​ ​ 2,258 Accrued current income taxes ​ — ​ 110 Other ​ — ​ 380 Accrued liabilities ​ $ 57,826 ​ $ 22,677
Summary of accounts receivable	Accounts receivable consisted of the following at the dates indicated (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2021 ​ 2020 Oil and natural gas receivables ​ $ 32,428 ​ $ 25,640 Insurance receivable - pipeline incident ​ ​ 55,765 ​ ​ — Joint interest owners and other ​ ​ 5,409 ​ ​ 6,801 Total accounts receivable ​ 93,602 ​ 32,441 Less: allowance for doubtful accounts ​ (1,635) ​ (1,540) Total accounts receivable, net ​ 91,967 ​ 30,901
Summary of Supplemental Cash Flows	Supplemental cash flow for the periods presented (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ For the Year Ended ​ ​ December 31, ​ ​ 2021 ​ 2020 Supplemental cash flows: ​ ​ ​ ​ Cash paid for interest, net of amounts capitalized ​ $ 8,637 ​ $ 10,331 Cash paid for reorganization items, net 6 ​ 566 Cash paid for taxes — ​ 85 ​ ​ ​ ​ ​ ​ ​ Noncash investing and financing activities: ​ ​ ​ Increase (decrease) in capital expenditures in payables and accrued liabilities 1,669 ​ (5,343)

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2021
Commitments And Contingencies.
Schedule of funding commitment	The table below outlines our funding commitment under these agreements at December 31, 2021 (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Payment Due by Period Funding commitment ​ Total 2022 2023 2024 2025 2026 Thereafter (1) Sinking fund payments ​ $ 172,601 ​ $ 6,688 ​ $ 8,025 ​ $ 15,789 ​ $ 15,789 ​ $ 15,789 ​ $ 110,521 (1) The remaining payments will be made during the years of 2027 through 2033.
Purchase Commitments Under the Contracts	At December 31, 2021, the Company had a CO 2 2 2 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Payment or Settlement Due by Period Purchase commitment ​ Total 2022 2023 2024 2025 2026 Thereafter CO 2 ​ $ 3,975 ​ $ 3,975 ​ $ — ​ $ — ​ $ — ​ $ — ​ $ — At December 31, 2021, the Company had long-term minimum volume commitments with third parties associated with a certain portion of its properties located in Oklahoma and East Texas. 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 2022 2023 2024 2025 2026 Thereafter Minimum volume commitment ​ $ 15,196 ​ $ 12,283 ​ $ 2,913 ​ $ — ​ $ — ​ $ — ​ $ — (2) The amounts in the table do not reflect costs adjusted for inflation.

Income Tax (Tables)

Income Tax (Tables)	12 Months Ended
	Dec. 31, 2021
Income Tax
Components of Income Tax Expense (Benefit)	The components of income tax benefit (expense) are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ For the Year Ended ​ ​ December 31, ​ ​ 2021 2020 ​ ​ (In thousands) Current taxes: ​ ​ Federal ​ $ — ​ $ (5) State ​ — ​ (110) Total current income tax benefit (expense) ​ — ​ (115) Deferred taxes: ​ ​ Federal ​ — ​ — State ​ — ​ — Total deferred income tax benefit (expense) ​ — ​ — Total income tax benefit (expense) ​ $ — ​ $ (115)
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 2021 and in 2020 as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ For the Year Ended ​ ​ December 31, ​ ​ 2021 2020 ​ ​ (In thousands) Expected tax benefit (expense) at federal statutory rate ​ $ 6,734 ​ $ 97,423 State income tax benefit (expense), net of federal benefit ​ 447 ​ 6,189 Non-deductible expenses ​ (64) ​ (45) Changes in valuation allowances ​ 3,192 ​ (110,445) State rate change, net of federal benefit ​ (10,192) ​ 6,100 State prior year adjustment ​ ​ (1,281) ​ ​ — Non-cash compensation ​ 8 ​ (137) PPP loan forgiveness ​ ​ 1,158 ​ ​ — Other ​ (2) ​ 800 Total income tax benefit (expense) ​ $ — ​ $ (115)
Components of Net Deferred Income Tax Liabilities	The Company’s deferred 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, ​ ​ 2021 ​ 2020 Deferred income tax assets: ​ ​ Property, Plant & Equipment ​ $ 94,439 ​ $ 115,695 Net operating loss carryforward ​ 178,279 ​ 174,479 Derivatives ​ 14,438 ​ 2,448 Disallowed interest expense ​ 5,579 ​ 5,388 Accrued liabilities ​ 1,592 ​ 1,226 Other ​ 3,469 ​ 1,717 Total deferred income tax assets: ​ 297,796 ​ 300,953 Valuation allowance ​ (297,195) ​ (300,386) Net deferred income tax assets ​ 601 ​ 567 ​ ​ ​ ​ ​ ​ ​ Deferred income tax liabilities: ​ ​ Derivatives ​ $ — ​ $ — Other ​ 601 ​ 567 Total deferred income tax liabilities ​ 601 ​ 567 ​ ​ ​ ​ ​ ​ ​ Net deferred income tax liabilities ​ $ — ​ $ —

Supplemental Oil and Gas Info_2

Supplemental Oil and Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2021
Supplemental Oil and Gas Information (Unaudited)
Schedule of Capitalized Costs Relating to Oil and Natural Gas Producing Activities	​ ​ ​ ​ ​ ​ ​ ​ ​ December 31, ​ ​ 2021 ​ 2020 ​ ​ (In thousands) Evaluated oil and natural gas properties ​ $ 799,532 ​ $ 775,167 Support equipment and facilities ​ 145,324 ​ 142,208 Accumulated depletion, depreciation, and amortization ​ (625,754) ​ (602,861) Total ​ $ 319,102 ​ $ 314,514
Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development Activities	​ ​ ​ ​ ​ ​ ​ ​ ​ For the Year Ended ​ ​ December 31, ​ ​ 2021 ​ 2020 ​ ​ (In thousands) Property acquisition costs, proved ​ $ 3 ​ $ 42 Property acquisition costs, unproved ​ — ​ (49,307) Exploration ​ — ​ — Development ​ 27,478 ​ 29,543 Total ​ $ 27,481 ​ $ (19,722)
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: ​ ​ ​ ​ ​ ​ ​ ​ ​ 2021 2020 Oil ($/Bbl): ​ ​ WTI (1) ​ $ 66.56 ​ $ 39.57 ​ ​ ​ ​ ​ ​ ​ NGL ($/Bbl): ​ ​ WTI (1) ​ $ 66.56 ​ $ 39.57 ​ ​ ​ ​ ​ ​ ​ Natural Gas ($/MMbtu): ​ ​ Henry Hub (2) ​ $ 3.60 ​ $ 1.99 (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, 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 year 35,613 252,218 19,009 96,658 End of year 43,857 309,794 23,574 119,063 ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved undeveloped reserves (2): Beginning of year 11,063 21,921 2,475 17,191 End of year 1,144 4,556 263 2,167 (1) Our reserves related to our Beta properties have been 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. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ For the Year Ended December 31, 2020 ​ ​ Oil ​ Gas ​ NGLs ​ Total ​ ​ (MBbls) ​ (MMcf) ​ (MBbls) ​ (MBoe) Proved developed and undeveloped reserves: Beginning of period 70,772 377,869 29,252 163,002 Extensions and discoveries 291 655 61 461 Production (3,887) (27,473) (1,725) (10,190) Revision of previous estimates (20,500) (76,912) (6,104) (39,424) End of period 46,676 274,139 21,484 113,849 ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved developed reserves: Beginning of period 53,476 320,731 23,646 130,577 End of period 35,613 252,218 19,009 96,658 ​ ​ ​ ​ ​ ​ ​ ​ ​ Proved undeveloped reserves: ​ Beginning of period 17,296 57,138 5,606 32,425 End of period 11,063 21,921 2,475 17,191
Standardized Measure of Discounted Future Net Cash Flows	​ ​ ​ ​ ​ ​ ​ ​ ​ For the Year Ended ​ ​ December 31, ​ 2021 2020 ​ ​ (In thousands) Future cash inflows ​ $ 4,569,313 ​ $ 2,410,260 Future production costs (1) ​ (2,691,875) ​ (1,589,945) Future development costs (1) ​ (231,040) ​ (375,146) Future income tax expense ​ — ​ — Future net cash flows for estimated timing of cash flows ​ 1,646,398 ​ 445,169 10% annual discount for estimated timing of cash flows ​ (726,553) ​ (147,358) Standardized measure of discounted future net cash flows ​ $ 919,845 ​ $ 297,811 (1) For the year ended December 31, 2021 and 2020, 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, ​ ​ 2021 2020 ​ ​ (In thousands) Beginning of year ​ $ 297,811 ​ $ 916,561 Sale of oil and natural gas produced, net of production costs ​ (171,326) ​ (47,687) Sale of minerals in place ​ (45) ​ — Extensions and discoveries ​ 17,035 ​ 3,687 Changes in prices and costs ​ 572,897 ​ (548,429) Previously estimated development costs incurred ​ 45,298 ​ 49,144 Net changes in future development costs ​ 113,546 ​ 89,997 Revisions of previous quantities ​ 46,271 ​ (150,245) Accretion of discount ​ 29,781 ​ 91,657 Change in production rates and other ​ (31,423) ​ (106,874) End of year ​ $ 919,845 ​ $ 297,811

Organization and Basis of Pre_2

Organization and Basis of Presentation - Additional Information (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2021USD ($)segment	Dec. 31, 2020USD ($)
Consolidation And Basis Of Presentation [Line Items]
Number of reportable business segments | segment	1
Gain on extinguishment of debt	$ 5,516	$ 0
Percentage of employee retention	70.00%
Maximum qualified wages	$ 10,000
Maximum tax credit claimed	7,000
Employee retention credit	2,800
General and Administrative Expense [Member]
Consolidation And Basis Of Presentation [Line Items]
Employee retention credit	800
Operating Lease Expense [Member]
Consolidation And Basis Of Presentation [Line Items]
Employee retention credit	$ 2,000

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Summary Of Significant Accounting Policies [Line Items]
Allowance for doubtful accounts	$ 1,635	$ 1,540
Capitalized exploratory drilling costs pending evaluation	0	0
Amortization expense including write-off of debt issuance costs	600	3,300
Impairment expense for proved/unproved properties	$ 0	476,936
Chance of tax benefit likely to be realized	greater than 50%
Southern California Pipeline Incident and Oil Release
Summary Of Significant Accounting Policies [Line Items]
LOPI insurance payments recognized	$ 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	427,600
Unproved Oil and Natural Gas Properties [Member]
Summary Of Significant Accounting Policies [Line Items]
Impairment expense for unproved leasehold costs	$ 0	$ 49,300
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, 2021	Dec. 31, 2020
Sinclair Oil & Gas Company [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues	20.00%	21.00%
Phillips 66 [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues	19.00%	23.00%
ETC Texas Pipeline LTD [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues	12.00%
BP America Production Company [Member]
Significant Accounting Policies [Line Items]
Total Reported Revenues		17.00%

Revenues - Summary of Revenues

Revenues - Summary of Revenues Disaggregated (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Revenues:
Total revenues	$ 342,916	$ 202,144
Oil and Natural Gas Sales [Member]
Revenues:
Total revenues	335,779	200,888
Oil [Member]
Revenues:
Total revenues	212,486	138,273
NGLs [Member]
Revenues:
Total revenues	40,899	20,064
Natural Gas [Member]
Revenues:
Total revenues	$ 82,394	$ 42,551

Revenues - Additional Informati

Revenues - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)item	Dec. 31, 2020USD ($)
Revenues
Number of revenue streams | item	3
Accounts receivable attributable to revenue from contracts with customers | $	$ 32.4	$ 25.6
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, 2021	Dec. 31, 2020
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Total assets	$ 7,967	$ 15,449
Total liabilities	70,775	26,247
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	7,967	15,449
Total liabilities	70,775	26,247
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	7,967	15,449
Total liabilities	70,152	23,495
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	7,967	15,449
Total liabilities	70,152	23,495
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	623	2,752
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	623	2,752
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 Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment expense	$ 0	$ 476,936
Proved Developed and Producing Oil and Gas Properties [Member]
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment expense	0	427,600
Unproved Properties [Member]
Assets And Liabilities Carrying Value And Fair Value [Line Items]
Impairment expense	$ 0	$ 49,300

Risk Management and Derivativ_3

Risk Management and Derivative Instruments - Additional Information (Detail) $ in Millions	1 Months Ended
	Apr. 30, 2020USD ($)
Fair Value Measurements of Financial Instruments
Derivative Cash Received On Hedge	$ 18

Risk Management and Derivativ_4

Risk Management and Derivative Instruments - Open Commodity Positions (Detail)	12 Months Ended
	Dec. 31, 2021MMBTU$ / bbl$ / MMBTUbbl
Natural Gas Derivative Contracts Fixed Price Swap 2022 [Member]
Derivative [Line Items]
Average monthly volume (MMBtu) | MMBTU	695,000
Weighted-average fixed price | $ / MMBTU	2.56
Natural Gas Derivative Two Way Collars Contracts 2022 [Member]
Derivative [Line Items]
Average monthly volume (MMBtu) | MMBTU	775,000
Weighted-average floor price | $ / MMBTU	2.56
Weighted-average ceiling price | $ / MMBTU	3.44
Crude Oil Derivative Contracts Fixed Price Swap 2022 [Member]
Derivative [Line Items]
Average monthly volume (Bbls) | bbl	64,000
Weighted-average fixed price	49.56
Crude Oil Derivative Two Way Collars Contracts 2022 [Member]
Derivative [Line Items]
Average monthly volume (Bbls) | bbl	22,500
Weighted-average floor price	58.33
Weighted-average ceiling price	67.42
Crude Oil Derivative Three Way Collars Contracts 2022 [Member]
Derivative [Line Items]
Average monthly volume (Bbls) | bbl	89,000
Weighted-average floor price	42.92
Weighted-average ceiling price	55.55
Weighted-average sub-floor price	32.58
Natural Gas Derivative Contracts Fixed Price Swap 2023 [Member]
Derivative [Line Items]
Average monthly volume (MMBtu) | MMBTU	0
Weighted-average fixed price | $ / MMBTU	0
Natural Gas Derivative Two Way Collars Contracts 2023 [Member]
Derivative [Line Items]
Average monthly volume (MMBtu) | MMBTU	370,000
Weighted-average floor price | $ / MMBTU	2.63
Weighted-average ceiling price | $ / MMBTU	3.61
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 Two Way Collars Contracts 2023 [Member]
Derivative [Line Items]
Average monthly volume (Bbls) | bbl	0
Weighted-average floor price	0
Weighted-average ceiling price	0
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_5

Risk Management and Derivative Instruments - Interest Rate Swap Open Positions (Detail) - Interest Rate Swap Open Position 2022 [Member] $ in Thousands	12 Months Ended
	Dec. 31, 2021USD ($)
Derivative [Line Items]
Average Monthly Notional (in thousands)	$ 75,000
Weighted-average fixed rate	1.281%
Floating rate	1 Month LIBOR

Risk Management and Derivativ_6

Risk Management and Derivative Instruments - Gross Fair Value of Derivative Instruments by Appropriate Balance Sheet (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Derivative Instruments and Hedges, Assets [Abstract]
Asset Derivatives, Net recorded fair value	$ 0	$ 873
Liability Derivatives, Net recorded fair value	53,144	10,824
Liability Derivatives, Net recorded fair value	9,664	847
Short-Term Derivative Instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Total assets	4,804	6,088
Asset Derivatives, Netting arrangements	(4,804)	(6,088)
Asset Derivatives, Net recorded fair value	0	0
Liability Derivatives, Gross fair value	57,948	16,912
Liability Derivatives, Netting arrangements	(4,804)	(6,088)
Liability Derivatives, Net recorded fair value	53,144	10,824
Short-Term Derivative Instruments [Member] | Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Total assets	4,804	6,088
Liability Derivatives, Gross fair value	57,325	15,007
Short-Term Derivative Instruments [Member] | Interest Rate Swaps [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Total assets	0	0
Liability Derivatives, Gross fair value	623	1,905
Long-Term Derivative Instruments [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Total assets	3,163	9,361
Asset Derivatives, Netting arrangements	(3,163)	(8,488)
Asset Derivatives, Net recorded fair value	0	873
Liability Derivatives, Gross fair value	12,827	9,335
Liability Derivatives, Netting arrangements	(3,163)	(8,488)
Liability Derivatives, Net recorded fair value	9,664	847
Long-Term Derivative Instruments [Member] | Commodity derivatives [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Total assets	3,163	9,361
Liability Derivatives, Gross fair value	12,827	8,488
Long-Term Derivative Instruments [Member] | Interest Rate Swaps [Member]
Derivative Instruments and Hedges, Assets [Abstract]
Total assets	0	0
Liability Derivatives, Gross fair value	$ 0	$ 847

Risk Management and Derivativ_7

Risk Management and Derivative Instruments - Unrealized and Realized Gains and Losses Related to Derivative Instruments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Derivative Instruments Gain Loss [Line Items]
Loss (gain) on commodity derivative instruments	$ 142,439	$ (60,671)
Interest expense, net	(12,099)	(20,522)
Commodity derivatives [Member]
Derivative Instruments Gain Loss [Line Items]
Loss (gain) on commodity derivative instruments	142,439	(60,671)
Interest Rate Swaps [Member]
Derivative Instruments Gain Loss [Line Items]
Interest expense, net	$ (217)	$ 4,044

Asset Retirement Obligations -

Asset Retirement Obligations - Summary of Changes in Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligations
Asset retirement obligations at beginning of period	$ 97,149	$ 91,089
Liabilities added from acquisition or drilling	29	79
Liabilities settled	(296)	(327)
Liabilities removed upon sale of wells	(113)	0
Accretion expense	6,611	6,206
Revision of estimates	34	102
Asset retirement obligation at end of period	103,414	97,149
Less: Current Portion	1,016	424
Asset retirement obligations - long-term portion	$ 102,398	$ 96,725

Restricted Investments - Restri

Restricted Investments - Restricted Investment Balances (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Schedule Of Investments [Line Items]
Restricted investments	$ 4,622	$ 4,623
BOEM platform abandonment [Member]
Schedule Of Investments [Line Items]
Restricted investments	313	313
SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member]
Schedule Of Investments [Line Items]
Restricted investments	$ 4,309	$ 4,310

Debt - Consolidated Debt Obliga

Debt - Consolidated Debt Obligations (Detail) - USD ($) $ in Thousands		Apr. 24, 2020	Dec. 31, 2021		Dec. 31, 2020
Line Of Credit Facility [Line Items]
Paycheck Protection Program loan		$ 5,500	$ 0	[1]	$ 5,516	[1]
Total long-term debt			230,000		260,516
Revolving Credit Facility [Member]
Line Of Credit Facility [Line Items]
Aggregate principal outstanding	[2]		$ 230,000		$ 255,000
[1]	See below for additional information regarding the receipt and the forgiveness of the paycheck protection program loan.
[2]	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 - Credit Facility - Additi

Debt - Credit Facility - Additional Information (Detail) - USD ($)	Nov. 10, 2021	Nov. 17, 2020	Jun. 12, 2020	Nov. 02, 2018	Nov. 02, 2018	Dec. 31, 2021	Dec. 31, 2022	Jun. 16, 2021	Jun. 15, 2021	Nov. 01, 2020
Line Of Credit Facility [Line Items]
Letters of credit outstanding						$ 0
Revolving Credit Facility [Member]
Line Of Credit Facility [Line Items]
Borrowing base	$ 245,000,000	$ 260,000,000				$ 245,000,000		$ 245,000,000	$ 260,000,000	$ 260,000,000
Maturity date						Nov. 2, 2023
LIBOR rate interest period					1 month
Unused line of credit, commitment fee percentage					0.50%
Debt Instrument, Covenant Description		modify the affirmative hedging covenant to include at least 65% and 45% hedge for calendar years 2021 and 2022 on a total proved developed producing reserves, respectively
Cash and cash equivalents on hand, Threshold amount						$ 25,000,000
Cash and cash equivalent threshold amount, Number of days						5
Monthly reduction of line of credit facility current borrowing capacity						$ 5,000,000
Line of credit facility, covenant terms						suspend certain financial covenants for the quarter ended June 30, 2020
Amount of monthly reduction in borrowing base	$ 5,000,000
Revolving Credit Facility [Member] | Amplify Acquisitionco Inc
Line Of Credit Facility [Line Items]
Pledge and security interest				100.00%	100.00%
Revolving Credit Facility [Member] | Minimum
Line Of Credit Facility [Line Items]
Borrowing base						$ 285,000,000
Current ratio				1.00%	1.00%
Hedging Liabilities Noncurrent						65.00%
Increase in percentage of priority lien assets						85.00%
Line of credit facility decrease limit of cash and cash equivalents						$ 30,000,000
Line of credit facility increase limit of transaction-related expense add-backs						$ 5,000,000
Revolving Credit Facility [Member] | Minimum | Scenario Forecast [Member]
Line Of Credit Facility [Line Items]
Hedging Liabilities Noncurrent							45.00%
Revolving Credit Facility [Member] | Minimum | Oil and Gas Properties [Member]
Line Of Credit Facility [Line Items]
Secured by percentage of mortgages				85.00%	85.00%
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				85.00%	85.00%
Hedging Liabilities Noncurrent						30.00%
Revolving Credit Facility [Member] | Maximum
Line Of Credit Facility [Line Items]
Borrowing base						$ 450,000,000
Total debt to EBITDAX				4.00%	4.00%
Increase in percentage of priority lien assets						90.00%
Line of credit facility decrease limit of cash and cash equivalents						$ 25,000,000
Line of credit facility increase limit of transaction-related expense add-backs						$ 20,000,000
Revolving Credit Facility [Member] | Maximum | Proved Developed And Producing Oil And Gas Properties [Member]
Line Of Credit Facility [Line Items]
Hedging Liabilities Noncurrent						60.00%
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					1.00%
Revolving Credit Facility [Member] | LIBOR [Member] | Minimum
Line Of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate			2.50%	2.00%	2.00%
Revolving Credit Facility [Member] | LIBOR [Member] | Maximum
Line Of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate			3.50%	3.00%	3.00%
Revolving Credit Facility [Member] | Base Rate [Member] | Minimum
Line Of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate					1.00%
Revolving Credit Facility [Member] | Base Rate [Member] | Maximum
Line Of Credit Facility [Line Items]
Debt instrument, basis spread on variable rate					2.00%

Debt - Paycheck Protection Prog

Debt - Paycheck Protection Program - Additional Information (Detail) - USD ($) $ in Thousands	Apr. 24, 2020	Dec. 31, 2021		Dec. 31, 2020
Debt
Loan amount received under paycheck protection plan	$ 5,500	$ 0	[1]	$ 5,516	[1]
Paycheck protection program loan of 2020, term	2 years
Paycheck protection program Loan of 2020, interest rate	1.00%
Paycheck protection program loan, principal or interest due next six months	$ 0
Gain on extinguishment of debt		$ 5,516		$ 0
[1]	See below for additional information regarding the receipt and the forgiveness of the paycheck protection program loan.

Debt - Summary of Weighted-Aver

Debt - Summary of Weighted-Average Interest Rates Paid on Variable-Rate Debt Obligations (Detail)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Revolving Credit Facility [Member]
Line Of Credit Facility [Line Items]
Revolving credit facility, weighted-average interest rates	3.65%	3.63%

Debt - Unamortized Deferred Fin

Debt - Unamortized Deferred Financing Costs - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Line Of Credit Facility [Line Items]
Amortization and write-off of deferred financing costs	$ 626	$ 3,272
Successor Credit Facility [Member]
Line Of Credit Facility [Line Items]
Unamortized deferred financing costs	1,000
Revolving Credit Facility [Member]
Line Of Credit Facility [Line Items]
Amortization and write-off of deferred financing costs	$ 2,400

Equity (Deficit)- Additional In

Equity (Deficit)- Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	Mar. 03, 2020	May 04, 2017	Dec. 31, 2021	Dec. 31, 2020
Equity And Distributions [Line Items]
Common stock, shares authorized			250,000,000	250,000,000
Common stock, par value			$ 0.01	$ 0.01
Dividend declared date	Mar. 3, 2020
Dividends declared per share	$ 0.10
Dividends paid	$ 3.8
Dividend payable record date	Mar. 16, 2020
Warrant [Member]
Equity And Distributions [Line Items]
Percentage of common shares to be issued upon exercise of warrants		8.00%
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 Units and Shares of Common Stock (Detail) - shares		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020
Summary Of Changes In Number Of Outstanding Units Or Shares [Line Items]
Beginning balance		37,663,509
Ending balance		38,024,142	37,663,509
Common Stock [Member]
Summary Of Changes In Number Of Outstanding Units Or Shares [Line Items]
Beginning balance		37,663,509	37,566,540
Issuance of common stock		0	0
Restricted stock units vested		77,985	132,237
Bonus stock awards	[1]	455,973
Shares withheld for taxes	[2]	(173,325)	(35,268)
Ending balance		38,024,142	37,663,509
[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.

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

Equity (Deficit) - Summary of A

Equity (Deficit) - Summary of Assumptions used to Estimate the Fair Value (Detail) - Warrant [Member]	12 Months Ended
	Dec. 31, 2021$ / shares
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Calculated fair value	$ 2.20
Risk-free Interest Rate [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Fair values of warrants, measurement input	2.06
Dividend Yield [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Fair values of warrants, measurement input	0
Expected Life [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Fair values of warrants, measurement input	5 years
Expected Volatility [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Fair values of warrants, measurement input	50
Strike Price [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Fair values of warrants, measurement input	42.60

Earnings per Share - Calculatio

Earnings per Share - Calculation of Earnings (Loss) per Share (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020
Earnings Per Share [Line Items]
Net loss		$ (32,070)	$ (464,030)
Less: Net income allocated to participating restricted stockholders		0	0
Basic and diluted earnings available to common stockholders		$ (32,070)	$ (464,030)
Common shares:
Common shares outstanding - basic		37,959	37,612
Dilutive effect of potential common shares		0	0
Common shares outstanding - diluted		37,959	37,612
Basic		$ (0.84)	$ (12.34)
Diluted		$ (0.84)	$ (12.34)
Warrants [Member]
Common shares:
Antidilutive stock options or warrants	[1]	2,174	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, 2021USD ($)installment$ / sharesshares
TSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation cost	$ 2.5
Weighted-average period of unrecognized compensation cost	2 years
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	1 year 2 months 12 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	50.00%
PSUs [Member] | Share Based Compensation Award Tranche One [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock units vesting percentage	25.00%
PSUs [Member] | Share Based Compensation Award Tranche Two [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock units vesting percentage	25.00%
PRSU [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation cost	$ 0.2
Weighted-average period of unrecognized compensation cost	1 year 9 months 18 days
Fair value estimation method	The fair value of each PRSU award was estimated on their grant dates using a Monte Carlo simulation.
PRSU [Member] | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of Potential Payout	200.00%
PRSU [Member] | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Percentage of Potential Payout	0.00%
PRSU [Member] | Share Based Compensation Award Tranche One [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock units vesting percentage	25.00%
PRSU [Member] | Share Based Compensation Award Tranche Two [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock units vesting percentage	25.00%
PRSU [Member] | Share Based Compensation Award Tranche Three [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock units vesting percentage	50.00%
2017 Non-Employee Directors Compensation Plan [Member] | Restricted Stock Units (RSUs) [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Weighted-average period of unrecognized compensation cost	3 months 18 days
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.
2017 Non-Employee Directors Compensation Plan [Member] | Restricted Stock Units (RSUs) [Member] | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation cost	$ 0.1
EIP [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Shares available for future distribution (in shares) | shares	2,789,054

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, 2021		Dec. 31, 2020
TSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Number of Units, Beginning Balance		115,797		291,370
Granted, Number of Units		1,083,644	[1]	43,250	[2]
Forfeited, Number of Units		(52,601)		(93,845)
Vested, Number of Units		(72,420)		(124,978)
Outstanding, Number of Units, Ending Balance		1,074,420		115,797
Outstanding, Weighted-Average Grant Date Fair Value per unit, Beginning balance	[3]	$ 4.47		$ 5.18
Granted, Weighted-Average Grant Date Fair Value per Unit	[3]	3.65	[1]	3.10	[2]
Forfeited, Weighted-Average Grant Date Fair Value per Unit	[3]	3.73		5.12
Vested, Weighted-Average Grant Date Fair Value per Unit	[3]	4.74		5.17
Outstanding, Weighted-Average Grant Date Fair Value per unit, Ending balance	[3]	$ 3.66		$ 4.47
PSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Number of Units, Beginning Balance		214,554		305,893
Granted, Number of Units		0		43,250	[4]
Forfeited, Number of Units		(148,614)		(134,589)
Vested, Number of Units		0		0
Outstanding, Number of Units, Ending Balance		65,940		214,554
Outstanding, Weighted-Average Grant Date Fair Value per unit, Beginning balance	[3]	$ 2.36		$ 2.15
Granted, Weighted-Average Grant Date Fair Value per Unit	[3]	0		3.03	[4]
Forfeited, Weighted-Average Grant Date Fair Value per Unit	[3]	2.13		2.11
Vested, Weighted-Average Grant Date Fair Value per Unit	[3]	0		0
Outstanding, Weighted-Average Grant Date Fair Value per unit, Ending balance	[3]	$ 2.87		$ 2.36
PRSU [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Granted, Number of Units		196,377
Outstanding, Number of Units, Ending Balance		196,377
Granted, Weighted-Average Grant Date Fair Value per Unit		$ 1.94
Outstanding, Weighted-Average Grant Date Fair Value per unit, Ending balance		$ 1.94
[1]	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.
[2]	The aggregate grant date fair value of TSUs issued for the year ended December 31, 2020 was $0.1 million based on a grant date market price ranging from $0.54 to $6.61 per share.
[3]	Determined by dividing the aggregate grant date fair value of awards by the number of awards issued.
[4]	The aggregate grant date fair value of PSUs issued for the year ended December 31, 2020 was $0.1 million based on a calculated fair value price ranging from $2.46 to $3.66 per share.

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, 2021	Dec. 31, 2020
TSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value of restricted stock units issued	$ 4	$ 0.1
TSUs [Member] | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant Date Market Price	$ 3.52	$ 0.54
TSUs [Member] | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Grant Date Market Price	$ 4.66	$ 6.61
PSUs [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value of restricted stock units issued		$ 0.1
PSUs [Member] | Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Calculated fair value price		$ 2.46
PSUs [Member] | Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Calculated fair value price		$ 3.66
PRSU [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Aggregate grant date fair value of restricted stock units issued		$ 0.4
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	119.60%
Dividend yield	0.00%
Risk-free interest rate	0.31%

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, 2021	Dec. 31, 2020
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Outstanding, Number of Units, Beginning Balance		8,898	16,157
Granted, Number of Units		0	0
Forfeited, Number of Units		0	0
Vested, Number of Units		(5,565)	(7,259)
Outstanding, Number of Units, Ending Balance		3,333	8,898
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]	$ 5.12	$ 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, 2021	Dec. 31, 2020
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)	$ 1,605	$ 384
Restricted Stock Units With Service Vesting Conditions [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)	1,541	267
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)	(130)	98
Restricted Stock Units R S U [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)	16	19
PRSU [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity based compensation expense (benefit)	$ 178	$ 0

Leases - Additional Information

Leases - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Leases
Lease, option to terminate	leases can be terminated with 30-day prior written notice
Lease termination period with prior written notice	30 days
Operating lease costs	$ 2.7	$ 2.4

Leases - Schedule of Right-of-U

Leases - Schedule of Right-of-Use Assets and Lease Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Leases
Right-of-use asset	$ 2,716	$ 2,500
Current lease liability	777	2,258
Long-term lease liability	2,017	266
Total lease liability	$ 2,794	$ 2,524

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, 2021	Dec. 31, 2020
Lessee Lease Description [Line Items]
2022	$ 859
2023	742
2024	549
2025	532
2026 and thereafter	317
Total lease payments	2,999
Less: interest	205
Present value of lease liabilities	2,794	$ 2,524
Office and Warehouse Space [Member]
Lessee Lease Description [Line Items]
2022	597
2023	502
2024	517
2025	532
2026 and thereafter	317
Total lease payments	2,465
Less: interest	186
Present value of lease liabilities	2,279
Leased Vehicles and Office Equipment [Member]
Lessee Lease Description [Line Items]
2022	262
2023	240
2024	32
2025	0
2026 and thereafter	0
Total lease payments	534
Less: interest	19
Present value of lease liabilities	$ 515

Leases - Schedule of Weighted A

Leases - Schedule of Weighted Average Remaining Lease Terms and Discount Rate of Operating Leases (Detail)	Dec. 31, 2021	Dec. 31, 2020
Office and Warehouse Space [Member]
Lessee Lease Description [Line Items]
Weighted average remaining lease term	3 years 6 months 3 days	8 months 26 days
Office Leases [Member]
Lessee Lease Description [Line Items]
Weighted average discount rate	2.95%	3.41%
Vehicles [Member]
Lessee Lease Description [Line Items]
Weighted average remaining lease term	4 months 13 days	4 months 2 days
Weighted average discount rate	0.59%	0.96%
Office Equipment [Member]
Lessee Lease Description [Line Items]
Weighted average remaining lease term	0 years	14 days
Weighted average discount rate	0.02%	0.17%

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, 2021	Dec. 31, 2020
Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows
Accrued liability - pipeline incident	$ 34,417
Accrued lease operating expense	9,271	$ 8,978
Accrued general and administrative expense	4,555	3,349
Accrued production and ad valorem tax	3,277	2,601
Accrued commitment fee and other expense	2,882	4,404
Accrued capital expenditures	1,631	173
Asset retirement obligations	1,016	424
Operating lease liability	$ 777	$ 2,258
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Accrued liabilities	Accrued liabilities
Accrued current income taxes	$ 0	$ 110
Other	0	380
Accrued liabilities	$ 57,826	$ 22,677

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, 2021	Dec. 31, 2020
Supplemental Disclosures to the Consolidated Balance Sheet and Condensed Statement of Cash Flows
Oil and natural gas receivables	$ 32,428	$ 25,640
Insurance receivable - pipeline incident	55,765
Joint interest owners and other	5,409	6,801
Total accounts receivable	93,602	32,441
Less: allowance for doubtful accounts	(1,635)	(1,540)
Total accounts receivable, net	$ 91,967	$ 30,901

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, 2021	Dec. 31, 2020
Supplemental cash flows:
Cash paid for interest, net of amounts capitalized	$ 8,637	$ 10,331
Cash paid for reorganization items, net	6	566
Cash paid for taxes	0	85
Noncash investing and financing activities:
Increase (decrease) in capital expenditures in payables and accrued liabilities	$ 1,669	$ (5,343)

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail) - USD ($) $ in Thousands	Dec. 11, 2020	Dec. 31, 2021	Dec. 31, 2020
Related Party Transactions
Significant transaction with related party		$ 0	$ 0
Underwriters option to purchase additional shares from selling stockholders	8,548,485
Proceeds from issuance of common stock	$ 0

Southern California Pipeline _2

Southern California Pipeline Incident (Details) $ in Thousands	Oct. 02, 2021item	Mar. 01, 2022USD ($)	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Nov. 05, 2021item	Oct. 14, 2021bbl	Oct. 05, 2021ft²item
Unusual or Infrequent Item, or Both [Line Items]
Pipeline incident loss			$ 1,599	$ 0
Amount receivable			55,765
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
Estimated aggregate costs			99,000
Pipeline incident loss			1,600
Amount received as reimbursement by insurance carriers			48,300
Costs probable of recovery			97,400
LOPI insurance payments recognized			6,700
Southern California Pipeline Incident and Oil Release | Subsequent Event
Unusual or Infrequent Item, or Both [Line Items]
Insurance cost recoveries		$ 22,100
LOPI claim settlement		$ 6,700
Southern California Pipeline Incident and Oil Release | Accounts Receivable
Unusual or Infrequent Item, or Both [Line Items]
Amount receivable			49,100
LOPI insurance payments recognized			6,700
Southern California Pipeline Incident and Oil Release | Minimum
Unusual or Infrequent Item, or Both [Line Items]
Estimated aggregate costs			90,000
Southern California Pipeline Incident and Oil Release | Maximum
Unusual or Infrequent Item, or Both [Line Items]
Estimated aggregate costs			$ 110,000
Southern California Pipeline Incident and Oil Release | Pending Litigation
Unusual or Infrequent Item, or Both [Line Items]
Number of putative class action suit filed | item					14
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) $ in Millions	Dec. 15, 2021USD ($)agreement	Dec. 31, 2021USD ($)$ / bbl	Dec. 31, 2020USD ($)	Nov. 05, 2021item
Commitments and Contingencies Additional Textual [Abstract]
Remaining environmental accrued liability recorded		$ 0	$ 0
Obligatory monthly deposit into sinking fund account per barrel of oil | $ / bbl		0.25
Number of escrow funding agreements | agreement	2
Sinking fund account maximum value upon which obligation ceases	$ 172.6	$ 4.3
Beta's decommissioning obligations, cash		0.3
Beta's decommissioning obligations, full supported by surety bonds		161.3
Rent expense		7.6	8.3
Commitment fee expense		1.6	2.1
Commitment fee/expense		2	$ 1.8
Pending Litigation | Southern California Pipeline Incident and Oil Release
Commitments and Contingencies Additional Textual [Abstract]
Number of putative class action suit filed | item				14
SPBPC Collateral Contractual pipeline and surface facilities abandonment [Member]
Commitments and Contingencies Additional Textual [Abstract]
Restricted Investment - decommissioning of offshore production facilities		$ 4.3

Commitments and Contingencies_2

Commitments and Contingencies - Other Commitments (Details) - Sinking fund payments $ in Thousands	Dec. 31, 2021USD ($)
Other Commitments [Line Items]
Total	$ 172,601
2022	6,688
2023	8,025
2024	15,789
2025	15,789
2026	15,789
Thereafter	$ 110,521

Commitments and Contingencies_3

Commitments and Contingencies - Purchase Commitments Under the Contracts (Detail) $ in Thousands	Dec. 31, 2021USD ($)
CO2 Minimum Purchase Commitment
Recorded Unconditional Purchase Obligation [Line Items]
Total	$ 3,975
2022	3,975
2023	0
2024	0
2025	0
2026	0
Thereafter	0
Minimum Volume Commitment
Recorded Unconditional Purchase Obligation [Line Items]
Total	15,196
2022	12,283
2023	2,913
2024	0
2025	0
2026	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, 2021	Dec. 31, 2020
Current taxes:
Federal	$ 0	$ (5)
State	0	(110)
Total current income tax benefit (expense)	0	(115)
Deferred taxes:
Federal	0	0
State	0	0
Total deferred income tax benefit (expense)	0	0
Total income tax benefit (expense)	$ 0	$ (115)

Income Tax - Additional Informa

Income Tax - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Income Tax Disclosure [Line Items]
Statutory tax rate	21.00%	21.00%
Valuation Allowance	$ 297,195,000	$ 300,386,000
Increase to valuation allowance	3,200,000
Unrecognized Tax Benefits	0
United States [Member]
Income Tax Disclosure [Line Items]
Operating loss carryforwards not subject to expiration	$ 757,000,000
Operating loss carryforwards expiration year	2037
Post merger operating loss Carry forwards	$ 32,200,000
State [Member]
Income Tax Disclosure [Line Items]
Operating loss carryforwards not subject to expiration	$ 376,300,000
Operating loss carryforwards expiration year	2037
Maximum | United States [Member]
Income Tax Disclosure [Line Items]
Net operating loss carryforwards	$ 777,600,000
Maximum | State [Member]
Income Tax Disclosure [Line Items]
Net operating loss carryforwards	$ 429,800,000

Income Tax - Reconciliation of

Income Tax - Reconciliation of Income Tax Benefit (Provision) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Income Tax
Expected tax benefit (expense) at federal statutory rate	$ 6,734	$ 97,423
State income tax benefit (expense), net of federal benefit	447	6,189
Non-deductible expenses	(64)	(45)
Changes in valuation allowances	3,192	(110,445)
State rate change, net of federal benefit	(10,192)	6,100
State prior year adjustment	(1,281)	0
Non-cash compensation	8	(137)
PPP loan forgiveness	1,158	0
Other	(2)	800
Total income tax benefit (expense)	$ 0	$ (115)

Income Tax - Components of Net

Income Tax - Components of Net Deferred Income Tax Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Deferred income tax assets:
Property, Plant & Equipment	$ 94,439	$ 115,695
Net operating loss carryforward	178,279	174,479
Derivatives	14,438	2,448
Disallowed interest expense	5,579	5,388
Accrued liabilities	1,592	1,226
Other	3,469	1,717
Total deferred income tax assets	297,796	300,953
Valuation allowance	(297,195)	(300,386)
Net deferred income tax assets	601	567
Deferred income tax liabilities:
Derivatives	0	0
Other	601	567
Total deferred income tax liabilities	601	567
Net deferred income tax liabilities	$ 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, 2021	Dec. 31, 2020
Supplemental Oil and Gas Information (Unaudited)
Evaluated oil and natural gas properties	$ 799,532	$ 775,167
Support equipment and facilities	145,324	142,208
Accumulated depletion, depreciation, and amortization	(625,754)	(602,861)
Total	$ 319,102	$ 314,514

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, 2021	Dec. 31, 2020
Supplemental Oil and Gas Information (Unaudited)
Property acquisition costs, proved	$ 3	$ 42
Property acquisition costs, unproved	0	(49,307)
Exploration	0	0
Development	27,478	29,543
Total	$ (27,481)	$ (19,722)

Supplemental Oil and Gas Info_5

Supplemental Oil and Gas Information (Unaudited) - Additional Information (Detail) - MMBoe	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Supplemental Oil and Gas Information (Unaudited)
Percent of discount factor to proved reserves	10.00%
Increase (reduction) in reserves	7.4	(49.2)
Upward price revisions in proved reserve	30.6
Downward price revisions in proved reserve		50.1
Reduction due to removed PUD locations	16
Extensions, discoveries and additions related to wells in progress	1.7
Upward revision due to lower maintenance cost		4.5
Extensions and discoveries		0.46
Proved developed and undeveloped reserves, reduction due to increase in maintenance cost	1.2
Proved developed and undeveloped reserves, upward technical revision	0.9	3.7
Proved developed and undeveloped reserve, upward revision due to special royalty relief		2.4

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, 2021	Dec. 31, 2020
Oil Reserves [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Product prices for reserves	66.56	39.57
Natural Gas Liquids Reserves [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Product prices for reserves	66.56	39.57
Natural Gas Reserves [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Product prices for reserves	3.60	1.99

Supplemental Oil and Gas Info_7

Supplemental Oil and Gas Information (Unaudited) - Schedule of Net Reserves (Detail)	12 Months Ended
	Dec. 31, 2021MMBoeMMcfeMBblsMMcf	Dec. 31, 2020MBblsMMcf
Oil Reserves [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year	46,676	70,772
Extensions and discoveries	746	291
Production	(3,351)	(3,887)
Sale of minerals in place | MMBoe	(3)
Revision of previous estimates	933	(20,500)
Proved developed and undeveloped reserves, End of year	45,001	46,676
Proved developed reserves, Beginning of year	35,613	53,476
Proved developed reserves, End of year	43,857	35,613
Proved undeveloped reserves, Beginning of year	11,063	17,296
Proved undeveloped reserves, End of year	1,144	11,063
Natural Gas Reserves [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year | MMcf	274,139	377,869
Extensions and discoveries | MMcf	4,283	655
Production | MMcf	(23,808)	(27,473)
Sale of minerals in place | MMcfe	(274)
Revision of previous estimates | MMcf	60,010	(76,912)
Proved developed and undeveloped reserves, End of year | MMcf	314,350	274,139
Proved developed reserves, Beginning of year | MMcf	252,218	320,731
Proved developed reserves, End of year | MMcf	309,794	252,218
Proved undeveloped reserves, Beginning of year | MMcf	21,921	57,138
Proved undeveloped reserves, End of year | MMcf	4,556	21,921
Natural Gas Liquids Reserves [Member]
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year	21,484	29,252
Extensions and discoveries	215	61
Production	(1,430)	(1,725)
Sale of minerals in place | MMBoe	(12)
Revision of previous estimates	3,580	(6,104)
Proved developed and undeveloped reserves, End of year	23,837	21,484
Proved developed reserves, Beginning of year	19,009	23,646
Proved developed reserves, End of year	23,574	19,009
Proved undeveloped reserves, Beginning of year	2,475	5,606
Proved undeveloped reserves, End of year	263	2,475
Proved Reserves, Total
Supplemental Oil And Gas Reserve Information [Line Items]
Proved developed and undeveloped reserves, Beginning of year	113,849	163,002
Extensions and discoveries	1,674	461
Production	(8,747)	(10,190)
Sale of minerals in place | MMBoe	(61)
Revision of previous estimates	14,515	(39,424)
Proved developed and undeveloped reserves, End of year	121,230	113,849
Proved developed reserves, Beginning of year	96,658	130,577
Proved developed reserves, End of year	119,063	96,658
Proved undeveloped reserves, Beginning of year	17,191	32,425
Proved undeveloped reserves, End of year	2,167	17,191

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, 2021	Dec. 31, 2020	Dec. 31, 2019
Supplemental Oil and Gas Information (Unaudited)
Future cash inflows	$ 4,569,313	$ 2,410,260
Future production costs	(2,691,875)	(1,589,945)
Future development costs	(231,040)	(375,146)
Future income tax expense	0	0
Future net cash flows for estimated timing of cash flows	1,646,398	445,169
10% annual discount for estimated timing of cash flows	(726,553)	(147,358)
Standardized measure of discounted future net cash flows	$ 919,845	$ 297,811	$ 916,561

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, 2021	Dec. 31, 2020
Supplemental Oil and Gas Information (Unaudited)
Beginning of year	$ 297,811	$ 916,561
Sale of oil and natural gas produced, net of production costs	(171,326)	(47,687)
Sale of minerals in place	(45)	0
Extensions and discoveries	17,035	3,687
Changes in prices and costs	572,897	(548,429)
Previously estimated development costs incurred	45,298	49,144
Net changes in future development costs	113,546	89,997
Revisions of previous quantities	46,271	(150,245)
Accretion of discount	29,781	91,657
Change in production rates and other	(31,423)	(106,874)
End of year	$ 919,845	$ 297,811