Exhibit 23.1

Consent of Independent Auditors

We consent to the incorporation by reference in Registration Statement Nos. 333-231925, 333-248754, 333-255489 and 333-265589 on Form S-3 and Registration Statement Nos. 333-225058 and 333-256554 on Form S-8 of Talos Energy Inc. of our report dated February 28, 2022, relating to the consolidated financial statements of EnVen Energy Corporation and subsidiaries as of December 31, 2021 and 2020 and for the years ended December 31, 2021, 2020 and 2019 appearing in this Current Report on Form 8-K/A of Talos Energy Inc.

Houston, Texas

April 12, 2023

Exhibit 23.2

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

As independent petroleum engineers, we hereby consent to the incorporation by reference into or inclusion in this Current Report on Form 8-K/A (including any amendments or supplements thereto, related appendices, and financial statements) (this “Current Report”) of Talos Energy Inc. (the “Company”) of our firm’s reserves report dated December 16, 2022, prepared for the Company as of December 16, 2022. The December 16 report sets forth the reserves and future revenue, as of December 31, 2021, to the EnVen Energy Ventures, LLC interest in certain oil and gas properties located in federal waters in the Gulf of Mexico. We hereby further consent to all references to our firm or such letters included in or incorporated by reference into this Current Report.

Houston, Texas

April 11, 2023

Exhibit 99.1

Report of Independent Auditors

To the Stockholders and the Board of Directors of EnVen Energy Corporation

Opinion

We have audited the consolidated financial statements of EnVen Energy Corporation and subsidiaries (the Company), which comprise the consolidated balance sheets as of December 31, 2021 and 2020, and the related consolidated statements of operations, comprehensive (loss) income, changes in equity and cash flows for the years ended December 31, 2021, 2020 and 2019, and the related notes (collectively referred to as the “financial statements”).

In our opinion, the accompanying financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2021 and 2020, and the results of its operations and its cash flows for the years ended December 31, 2021, 2020 and 2019 in accordance with accounting principles generally accepted in the United States of America.

Basis for Opinion

We conducted our audits in accordance with auditing standards generally accepted in the United States of America (GAAS). Our responsibilities under those standards are further described in the Auditor’s Responsibilities for the Audit of the Financial Statements section of our report. We are required to be independent of the Company and to meet our other ethical responsibilities in accordance with the relevant ethical requirements relating to our audits. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Adoption of Accounting Standards Update (ASU) 2020-06, Debt – Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging – Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity (ASU 2020-06)

As discussed in Note 1 to the financial statements, in 2021 the Company adopted new accounting guidance, which revised the accounting for convertible debt and convertible preferred stock by removing the requirements to separately present certain conversion features in equity and eliminates the accounting model for beneficial conversion features, as a result of the adoption of the amendments to the Financial Accounting Standards Board (FASB) Accounting Standards Codification resulting from ASU 2020-06. Our opinion is not modified with respect to this matter.

Responsibilities of Management for the Financial Statements

Management is responsible for the preparation and fair presentation of the financial statements in accordance with accounting principles generally accepted in the United States of America, and for the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of material misstatement, whether due to fraud or error.

In preparing the financial statements, management is required to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the Company’s ability to continue as a going concern for one year after the date that the financial statements are available to be issued.

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Auditor’s Responsibilities for the Audit of the Financial Statements

Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free of material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance but is not absolute assurance and therefore is not a guarantee that an audit conducted in accordance with GAAS will always detect a material misstatement when it exists. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control. Misstatements are considered material if there is a substantial likelihood that, individually or in the aggregate, they would influence the judgment made by a reasonable user based on the financial statements.

In performing an audit in accordance with GAAS, we:

We are required to communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit, significant audit findings, and certain internal control-related matters that we identified during the audit.

/s/ Ernst & Young LLP

Houston, Texas

February 28, 2022

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ENVEN ENERGY CORPORATION AND SUBSIDIARIES

Consolidated Balance Sheets

(In thousands, except share amounts)

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The accompanying notes are an integral part of these consolidated financial statements.

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ENVEN ENERGY CORPORATION AND SUBSIDIARIES

Consolidated Statements of Operations

(In thousands)

The accompanying notes are an integral part of these consolidated financial statements.

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ENVEN ENERGY CORPORATION AND SUBSIDIARIES

Consolidated Statements of Comprehensive (Loss) Income

(In thousands)

The accompanying notes are an integral part of these consolidated financial statements.

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ENVEN ENERGY CORPORATION AND SUBSIDIARIES

Consolidated Statement of Changes in Equity

(In thousands, except share amounts)

The accompanying notes are an integral part of these consolidated financial statements.

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ENVEN ENERGY CORPORATION AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(In thousands)

The accompanying notes are an integral part of these consolidated financial statements.

Refer to Note 17—Supplemental Cash Flow Information for supplemental cash flow disclosures.

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ENVEN ENERGY CORPORATION AND SUBSIDIARIES

Notes to Consolidated Financial Statements

Note 1—Organization and Basis of Presentation

EnVen Energy Corporation (individually or together with its subsidiaries, the “Company”) is an independent oil and natural gas company engaged in the development, exploitation, exploration, and acquisition of primarily crude oil properties in the deepwater region of the United States (“U.S.”) Gulf of Mexico. The Company focuses on developing operated, deepwater assets that it believes have untapped, lower-risk drill bit opportunities and will provide strong cash flow and significant production potential. This strategy allows the Company to benefit from the favorable geologic and economic characteristics of the deepwater U.S. Gulf of Mexico fields.

Organization

On October 30, 2015, Energy Ventures GoM Holdings, LLC entered into an agreement to sell 13,732,925 units in a private offering, at a price of $10.00 per unit, to selected institutional investors (the “2015 Equity Offering”). Prior to the closing of the 2015 Equity Offering, the then existing members of Energy Ventures GoM Holdings, LLC contributed 100% of their limited liability company units (the “limited liability interest”) in Energy Ventures GoM LLC (“EnVen GoM”) to a newly formed limited liability company, EnVen Equity Holdings, LLC (“EnVen Equity Holdings”). Therefore, the members of EnVen Equity Holdings indirectly owned 100% of the limited liability interest of EnVen GoM. Following this transaction and also prior to the closing of the 2015 Equity Offering, Energy Ventures GoM Holdings, LLC was converted from a limited liability company to a Delaware corporation and renamed EnVen Energy Corporation. Further, at the time of the 2015 Equity Offering, the Company also entered into a Tax Receivable Agreement (“TRA”) with EnVen Equity Holdings. Refer to Note 10—Related Party Transactions for a further discussion of the Redemption Rights and the TRA.

As specified in the EnVen GoM Second Amended and Restated Limited Liability Company Agreement (the “EnVen GoM LLC Agreement”), the members of EnVen Equity Holdings could have, at any time, required EnVen GoM to repurchase all or any number of its limited liability interest of EnVen GoM for consideration equal to one share of the Company’s $0.001 par value per share (“Class A Common Stock”) per unit of the limited liability interest of EnVen GoM. However, with approval from the Company’s board of directors (the “Board”), the Company could satisfy the obligation by exercising an option to purchase the limited liability interest of EnVen GoM for a cash price equal to the fair value of one share of its Class A Common Stock or by issuing newly issued shares of its Class A Common Stock (collectively, the “Redemption Rights”).

In April 2021, EnVen Equity Holdings exercised its Redemption Rights with respect to all of its limited liability interests of EnVen GoM. Pursuant to the terms of the EnVen GoM LLC Agreement, the Company then elected to settle the Redemption Rights through a direct exchange of such common units for 3,333,333 newly issued shares of its Class A Common Stock and cancelled the associated 3,333,333 shares of its $0.001 par value Class B common stock (“Class B Common Stock”) (collectively, the “Class B Common Stock Conversion”). Concurrent with the Class B Common Stock Conversion, the Company and EnVen Equity Holdings agreed to terminate the TRA for a $7.0 million cash payment to EnVen Equity Holdings (the “TRA Settlement”). As a result of these transactions, EnVen Equity Holdings no longer holds any limited liability interests of EnVen GoM and no longer holds any shares of Company’s Class B Common Stock. The Company accounted for these transactions as an adjustment to its Stockholders’ equity during the second quarter of 2021.

Basis of Presentation and Consolidation

The accompanying consolidated financial statements as of and for the years ended December 31, 2021, 2020 and 2019 are prepared in accordance with accounting principles generally accepted in the U.S. (“GAAP”) and include the accounts for the Company and entities in which it has control. All significant intercompany balances and transactions have been eliminated.

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Prior to the Class B Common Stock Conversion, discussed above, the Company owned the majority interest (approximately 90.5% and 89.8% as of December 31, 2020 and 2019, respectively) of and controlled its subsidiary, EnVen GoM; therefore, the majority interest in EnVen GoM was reflected as a consolidated subsidiary in the accompanying consolidated financial statements as of December 31, 2020 and 2019. The remaining ownership interest (approximately 9.5% and 10.2% as of December 31, 2020 and 2019, respectively) not held by the Company (the “Non-controlling interest”) was included in the accompanying consolidated financial statements as Non-controlling interest. Following the consummation of the Class B Common Stock Conversion in April 2021, the Company owns and controls 100% of its subsidiary EnVen GoM; therefore, as of April 30, 2021, it no longer reports a Non-controlling interest on its consolidated balance sheet. Refer to Note 9 - Stockholders’ Equity for a further discussion of the Non-controlling interest prior to the Class B Common Stock Conversion.

Use of Estimates

The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities as of the date of the financial statements, the reported amounts of revenues and expenses during the reporting periods and the reported amounts of proved oil and natural gas reserves. Management believes its estimates and assumptions to be reasonable under the circumstances. Certain estimates and assumptions are inherently unpredictable and actual results could differ from those estimates.

Recently Adopted Accounting Standards

Current Expected Credit Losses—ASU No. 2016-13

In June 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13, Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (“ASU 2016-13”), which changes how entities account for credit losses for most financial assets and certain other instruments which are not measured at fair value through net income and will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. For public and non-public entities, ASU 2016-13, including all of its amendments, is effective for interim and annual periods beginning after December 15, 2019 and 2020, respectively, using a modified retrospective approach and early adoption is permitted.

The Company elected to early adopt ASU 2016-13, effective January 1, 2020, resulting in a cumulative effect adjustment of $0.6 million to its Accumulated deficit balance and $0.1 million to its Non-controlling interest balance related to the estimated credit losses for its notes receivable for certain acquired P&A obligations (the “P&A Notes Receivable”). Upon entering into the P&A Notes Receivable, the Company recorded the P&A Notes Receivable at their present value using estimated imputed interest rates and the related carrying values of the notes receivable are accreted, with the accretion recognized to Interest income and other on the accompanying consolidated statements of operations based on the expected timing of the completion of the P&A obligations. The Company estimates the current expected credit losses related to its P&A Notes Receivable using the probability of default method based on the long-term credit ratings of the counterparties of the notes, which are currently considered “investment grade.” Additionally, the Company has elected to estimate the credit losses on the various components, the originally discounted principal and accreted interest, included in the amortized basis of the P&A Notes Receivable on a combined basis. The Company records the change in the current estimated credit losses related to its P&A Notes Receivable into Interest income and other on the accompanying consolidated statements of operations and presents the P&A Note Receivable net of the related cumulative estimated credit losses on the accompanying consolidated balance sheets.

The Company estimates the current expected credit losses related to its short-term receivables using an aging method based on historical loss data that, if warranted, is adjusted for asset-specific considerations and current

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economic conditions. Upon adoption, the Company analyzed the aging of its short-term oil, natural gas, and NGL revenue, production handling agreements revenue, and joint interest and other accounts receivables and its derivative settlement receivables and determined that it did not need to record an adjustment for credit loss related to those short-term receivables because the credit losses have historically been immaterial. The Company will continue to review the aging of these short-term receivables on a quarterly basis and if necessary, could record an allowance in future periods.

Overall, the adoption of ASU 2016-13 did not have a material impact on the Company’s consolidated financial statements.

Income Taxes—ASU No. 2019-12

In December 2019, the FASB issued ASU No. 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes (“ASU 2019-12”), which is intended to simplify various aspects related to accounting for income taxes by removing certain exceptions to the general principles in Topic 740 and clarifying and amending existing guidance to promote more consistent application. For public entities, ASU 2019-12 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020. For non-public entities, ASU 2019-12 is effective for fiscal years beginning after December 15, 2022 and interim periods within fiscal years beginning after December 15, 2022. The Company has elected to early adopt ASU 2019-12, effective January 1, 2020.

The amendments in ASU 2019-12 eliminate several legacy exceptions the Company was subject to in Topic 740. Specifically, the standard eliminates the legacy exception relating to the allocation of income tax expense or benefit for the year to continuing operations, discontinued operations, other comprehensive (loss) income, and other charges or credits recorded directly to shareholders’ equity. ASU 2019-12 requires that the new intraperiod tax allocation guidance be applied prospectively in the period of adoption. The adoption of this standard did not impact the Company’s prior year financial statements or its income tax provision for the years ended December 31, 2021, 2020, or 2019.

Convertible Debt and Preferred Stock—ASU No. 2020-06

In August 2020, the FASB issued ASU No. 2020-06, Debt – Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging – Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity (“ASU 2020- 06”), which simplifies the accounting for convertible debt and convertible preferred stock by removing the requirements to separately present certain conversion features in equity and eliminates the accounting model for beneficial conversion features. In addition, the amendments in the ASU simplify the guidance in Accounting Standards Codification (“ASC”) Subtopic 815-40, Derivatives and Hedging: Contracts in Entity’s Own Equity, by removing certain criteria that must be satisfied in order to classify a contract as equity.

For public entities, ASU 2020-06 is effective for fiscal years beginning after December 15, 2021, including interim periods within those fiscal years. For non-public entities, ASU 2020-06 is effective for fiscal years beginning after December 15, 2023, including interim periods within those fiscal years. Early adoption is permitted for fiscal years beginning after December 15, 2020, including interim periods within those fiscal years. An entity can only adopt the guidance as of the beginning of its annual fiscal year and can do so through either a modified retrospective method of transition or a fully retrospective method of transition.

The Company elected to early adopt ASU 2020-06, effective January 1, 2021, using the modified retrospective method of transition, eliminating the accounting model for the beneficial conversion feature related to the paid-in-kind dividends of its Series A convertible perpetual preferred stock (“Series A Preferred Stock”), which is classified in the stockholders’ equity section of the accompanying consolidated balance sheets as the shares are not mandatorily redeemable nor do they contain an unconditional conversion obligation. The holders of the

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Series A Preferred Stock are entitled to receive quarterly dividends of $0.45 per Series A Preferred Stock share, at the election of the Company’s Board, in cash or in shares of the Series A Preferred Stock (“PIK Shares”). Prior to the adoption of this ASU, at the end of each reporting period or when PIK Share dividends were declared, the Company would evaluate if there was a beneficial conversion feature related to the PIK Share dividends of its Series A Preferred Stock by comparing the fair value of its Class A Common Stock to the original issue price of $12.00 per share. If the fair value of the Company’s Class A Common Stock was above the original issue price of $12.00 per share, it would record the difference as a beneficial conversion feature associated with its PIK Share dividends and reflect that amount as part of the Series A preferred stock dividends line item on the accompanying consolidated statements of operations. Until the adoption of ASU 2020-06, the Company evaluated if a beneficial conversion existed on a quarterly basis; however, it has not recognized a beneficial conversion feature related to the PIK Share dividends of its Series A Preferred Stock since 2019. Refer to Note 9 - Stockholders’ Equity for a full description of the Company’s Series A Preferred Stock.

To reflect the adoption of ASU 2020-06, the Company has recorded a cumulative effect adjustment of $28.3 million to its Additional paid-in capital and Accumulated deficit balances as of January 1, 2021 to reverse the beneficial conversion feature associated with its Series A Preferred Stock PIK Share dividends outstanding as of January 1, 2021. Additionally, with the adoption of the ASU, the Company is no longer required to include the disclosures required for the beneficial conversion feature in the notes of its consolidated financial statements.

Note 2—Summary of Significant Accounting Policies

Cash and Cash Equivalents

The Company considers all highly liquid investments with an initial maturity of three months or less to be cash and cash equivalents.

Restricted Cash

Restricted cash primarily consists of amounts held in escrow for future P&A obligations in connection with past acquisitions. Pursuant to the purchase agreements, the Company was required to deposit funds in to escrow accounts to use for future P&A obligation costs assumed in the acquisitions. These escrow accounts are fully funded as of October 2021. Refer to Note 14—Commitments and Contingencies for a further discussion of those requirements.

Additionally, prior to the amendment of the first lien senior secured revolving credit facility (the “Revolving Credit Facility”) agreement in April 2021, the Company was required to provide the full outstanding letter of credit amount of $3.6 million in cash to the banks to fulfill a cash security requirement to collateralize its letters of credit, which was recorded as Restricted cash on the consolidated balance sheet as of December 31, 2020. The cash security requirement was removed as part of the Revolving Credit Facility agreement amendment, therefore, the banks have released the previously provided cash required to collateralize its letters of credit back to the Company. Refer to Note 8—Long-term Debt for a further discussion of the Company’s Revolving Credit Facility.

Accounts Receivable

Oil, natural gas, and NGL revenue receivable consists of uncollateralized accrued oil, natural gas, and NGL revenue due under normal trade terms, generally requiring payment within 30 days of production. Joint interest and other receivables consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date and, at times, receivables from the counterparties to the Company’s derivative contracts. In the Company’s capacity as operator, it incurs drilling, operating, and P&A costs that are billed to its partners based on their respective working interests. For receivables from joint interest owners, the Company typically has the ability to withhold revenue distributions to recover any unpaid joint operations billings that are past due.

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The Company estimates the current expected credit losses related to its short-term receivables using an aging method based on historical loss data that, if warranted, is adjusted for asset-specific considerations and current economic conditions. Upon the adoption of ASU 2016-13 effective January 1, 2020, the Company analyzed the aging of its short-term oil, natural gas, and NGL revenue, production handling agreements revenue, and joint interest and other accounts receivables and its derivative settlement receivables and determined that it did not need to record an adjustment for credit loss related to those short-term receivables because the credit losses have historically been immaterial. Further, the Company has determined that no allowance is necessary as of December 31, 2021, 2020 and 2019. The Company will continue to review the aging of these short-term receivables on a quarterly basis and if necessary, could record an allowance in future periods.

Oil and Natural Gas Properties

The Company follows the full cost method of accounting for oil and natural gas activities and capitalizes all the costs associated with the acquisition, exploration, and development of oil and natural gas properties. Capitalized costs include lease acquisitions, geological and geophysical work, delay rentals, costs of drilling, completing, and equipping oil and natural gas wells, whether successful or unsuccessful, and other directly related costs.

The capitalized costs of proved oil and natural gas properties, net of accumulated DD&A plus estimated future development costs related to proved oil and natural gas reserves and estimated future P&A costs are amortized on a unit of production method over the estimated productive life of the proved reserves, which is reflected as DD&A on the accompanying consolidated statements of operations. DD&A related to oil and natural gas properties for the years ended December 31, 2021, 2020 and 2019 was $155.5 million, $170.3 million and $178.5 million, respectively.

Costs related to nonproducing leasehold, geological and geophysical costs associated with unproved acreage, and exploration drilling costs represent investments in unproved properties. Additionally, for any significant capital projects with a development period exceeding six months, the Company will capitalize a portion of its interest expense while the activities are in progress to bring the unproved assets to their intended use. The capitalized interest is added to the cost of the underlying property and treated in the same manner as the underlying asset. All of these costs are excluded from the depreciable base until management determines the existence of proved oil and natural gas reserves on the respective property or the costs are impaired. At least quarterly, the Company reviews its investments in unproved properties individually to determine if the costs should be reclassified and included as a part of the depreciable base. Refer to Note 6—Property and Equipment, net for further information related to the Company’s oil and natural gas properties.

The following table presents the costs of unproved properties excluded from the Company’s depreciable base as of December 31, 2021 and the periods such costs were incurred:

Under the full cost method of accounting, the Company performs the full cost ceiling test at the end of each reporting period. Per the full cost ceiling test, net capitalized costs less deferred income taxes are limited to the

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present value of estimated future net cash flows from proved oil and natural gas reserves computed using the unweighted arithmetic average of the first-day-of-the-month historical price, net of applicable differentials, for each month within the previous 12-month period discounted at 10%, plus the lower of cost or fair market value of unevaluated properties, excluding cash flows related to estimated abandonment costs associated with developed properties (the “ceiling limitation”). If the net capitalized costs exceed the ceiling limitation, the Company would recognize a non-cash impairment expense equal to the excess of the net capitalized costs over the ceiling limitation. The Company did not recognize an impairment of oil and natural gas properties for the years ended December 31, 2021, 2020 and 2019.

Other Property and Equipment

Other property and equipment primarily consists of computer hardware and software, furniture, fixtures, and the Company’s undivided interest in an aircraft, which are depreciated using the straight line method over their estimated useful lives ranging from 2 to 5 years.

Other Well Equipment Inventory

Other well equipment inventory represents the cost of equipment the Company intends to use in its oil and natural gas drilling and development activities, such as drilling pipe, tubulars and certain wellhead equipment. When this inventory is supplied to wells, the cost of the inventory will be capitalized into oil and natural gas properties, and if such property is jointly owned, the proportionate costs will be reimbursed by third-party participants. The Company states its inventory at the lower of cost or net realizable value.

Derivative Instruments

The Company utilizes commodity derivative instruments to reduce its exposure to crude oil and natural gas price volatility for a portion of its estimated production from its proved, developed, producing oil and natural gas properties. The fair values of the Company’s derivative instruments are measured on a recurring basis using a third-party industry-standard pricing model. Refer to Note 5—Fair Value Measurements for a further discussion of the fair value of the Company’s derivative instruments.

The Company has not designated any of its derivative instruments as hedges for accounting purposes; therefore, the aggregate net gains and losses resulting from changes in the fair values of its outstanding derivatives, the settlement of derivative instruments, and any net proceeds or payments related to the early termination of derivative contracts during the period are recognized as net gain or loss on derivatives, as applicable, in the consolidated statements of operations. The Company typically has numerous hedge positions that span several time periods and often result in both fair value derivative asset and liability positions held with that counterparty, therefore, it has elected to net its derivative instrument fair values executed with the same counterparty, pursuant to the International Swaps and Derivatives Association, Inc. (“ISDA”) master agreements, which provide for the net settlement over the term of the contract and in the event of the default or termination of the contract. Refer to Note 4—Derivative Instruments for a discussion of the Company’s outstanding derivative instruments.

Prepaid Expenses and Other Current Assets

The Company’s prepaid expenses and other current assets primarily includes premiums paid to surety companies for its supplemental and performance bonds. These bond premiums are amortized over the life of the surety bonds into Interest expense on the accompanying consolidated statements of operations. As of December 31, 2021 and 2020, the Company’s prepaid balances for its surety bond premiums were $7.7 million and $8.2 million, respectively. Refer to Note 14—Commitments and Contingencies for a further discussion of the Company’s surety bond premiums. Additionally, the Company’s prepaid expenses and other current assets also includes balances related to its commercial insurance packages, which are amortized into LOE over the life of the policy. As of December 31, 2021 and 2020 the Company’s prepaid balances for its commercial insurance packages were $2.2 million and $2.3 million, respectively.

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Notes Receivable, net

The Company holds two notes receivables which consist of commitments from the sellers of oil and natural gas properties, acquired by the Company, related to the costs associated with its performance of the assumed P&A obligations (the “P&A Notes Receivable”). As of December 31, 2021, both of the P&A Notes Receivable have fully accreted to their principal amounts and are presented as such, net of the related cumulative estimated credit losses, on the accompanying consolidated balance sheet. As of December 31, 2020, the P&A Notes Receivable were recorded at their present values using estimated imputed interest rates of 8.0% and 12.0%, net of the related cumulative estimated credit losses, on the accompanying consolidated balance sheet.

Subsequent to the adoption of ASU 2016-13, discussed above, the Company records the change in the current estimated credit losses related to its P&A Notes Receivable into Interest income and other on the accompanying consolidated statements of operations and presents the P&A Note Receivable net of the related cumulative estimated credit losses on the accompanying consolidated balance sheets Refer to Note 14—Commitments and Contingencies for a further discussion of the Company’s outstanding notes receivable.

Notes Payable

The Company has in the past entered into notes payable agreements to purchase certain items or services used in its daily operations. The Company records the fair value of the total principal and interest payments as a note payable utilizing an effective interest rate and amortizes the discount over the term of the agreement. If the agreement requires an upfront consideration payment and installment payments, the Company will record the fair value of the installment payments as a note payable at the effective interest rate stated in the agreement and will amortize the discount over the term of the installment period. If the agreement does not state an effective interest rate, the Company will estimate the imputed rate of interest at the time the note is recognized. Refer to Note 14—Commitments and Contingencies for a discussion of the Company’s outstanding notes payable.

11.00% Senior Notes due 2023

On February 15, 2018, the Company completed the private offering of its $325.0 million aggregate principal amount 11.0% senior secured second lien notes due 2023 (the “2023 Notes”). The 2023 Notes indenture contained certain put and call features that were analyzed at the time of issuance in accordance with ASC Topic 815, Derivatives and Hedging. The Company determined that one of these features was an embedded derivative, which would typically require bifurcation. Due to this embedded derivative feature, the Company elected to account for the 2023 Notes and all of its features using the fair value option; therefore, the 2023 Notes were recorded at their fair value on the consolidated balance sheet as of December 31, 2020. Throughout the fourth quarter of 2020, the Company repurchased $48.2 million principal amount of its 2023 Notes and then in April of 2021, as part of the 2021 Refinancing Transactions described further below, the Company redeemed the remaining $276.8 million principal amount of its outstanding 2023 Notes. Refer to Note 8—Long-term Debt for a discussion of the 2021 Refinancing Transactions.

Prior to the redemption of the 2023 Notes in April 2021, the Company recorded the changes in the fair value of the 2023 Notes in accordance with ASU No. 2016-01, Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities (“ASU 2016-01”). Therefore, the change in the fair value of the 2023 Notes attributable to the change in the base market rate was recorded as a component of Gain (loss) on fair value of 11.00% Senior Notes due 2023 on the Company’s consolidated statements of operations and the remainder of the change was attributable to instrument-specific credit risk and was recognized separately as Other comprehensive (loss) income, net on the consolidated statements of comprehensive (loss) income. The Company had elected to use the U.S. Treasury bond rate as its benchmark interest rate to determine the change in the fair value attributable to instrument-specific credit risk, therefore, it compared the change in the fair value of the 2023 Notes to the change in the fair value of the U.S. Treasury bonds based on the interpolated yields of the U.S. Treasury bonds with maturities which coincided with the

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maturity date of the 2023 Notes. The change in the U.S. Treasury bond rate was attributable as the base market rate change and the remainder of the change was attributable to instrument-specific credit risk, which was separately recognized as Other comprehensive (loss) income, net. Refer to Note 8—Long-term Debt for a further discussion of the Company’s 2023 Notes.

Leases

The Company capitalizes its operating leases as right-of-use (“ROU”) assets and lease liabilities on the accompanying consolidated balance sheets and recognizes the fixed minimum lease costs for its operating leases on a straight-line basis over the lease term in accordance with ASC Topic 842, Leases (“ASC 842”). The Company does not recognize leases with initial lease terms less than or equal to 12 months on the balance sheet and only includes those short-term leases as part of its lease-related disclosures. Additionally, the Company does not include any of its variable lease costs in the calculation of its ROU assets and lease liabilities, as none of the variable costs are based on an index or rate. Instead, all of the variable costs are based on the performance of the leased asset or the level of use of other non-lease components due to the election of the practical expedient to not separate the lease and non-lease components when measuring lease payments.

The Company makes certain assumptions and judgments when determining its ROU assets and lease liabilities. When determining whether a contract contains a lease, the Company considers whether there is an identified asset that is physically distinct, whether the supplier has substantive substitution rights, whether the Company has the right to obtain substantially all of the economic benefits from the use of the asset, and whether it has the right to control the asset. Certain of the Company’s leases include one or more options to renew the lease, with renewal terms that can extend the lease term for additional years. When determining if renewals should be included in the lease term to be recognized, the Company utilizes the reasonably certain threshold, therefore, certain of the leases included in the calculation of its ROU assets and lease liabilities include optional renewal periods for which it is not contractually obligated. Additionally, the Company must estimate its incremental borrowing rate when the implicit rate is not stated in the lease agreement and cannot be readily determined. As of December 31, 2021, none of the Company’s active leases contain purchase or termination options that are reasonably certain to be exercised.

The Company has several operating leases for office space and IT Equipment used in its daily operations, for which it records the related lease costs as G&A expenses on the accompanying consolidated statements of operations. Additionally, the Company enters into drilling rig operating contracts with third parties to support its drilling activities. The scope of ASC 842 does not include leases to explore or use minerals, oil, natural gas, and similar non-regenerative resources; therefore, the Company’s oil and natural gas leases are excluded, but the equipment used to explore for natural resources, which includes drilling rigs, marine vessels, and other equipment used in the exploration and development of oil and natural gas assets are included in the scope of ASC 842.

In accordance with the full cost method of accounting for oil and natural gas properties, the Company capitalizes the portion of its lease costs which relate to its drilling rig operating leases as part of its oil and natural gas property balance. In lease agreements where the Company is the designated operator per a joint operations arrangement, any related ROU assets and lease liabilities are calculated using the gross payment amount rather than the net amounts based on its working interest in the related property. However, when the costs are incurred, the Company only recognizes its share of the drilling rig operating lease costs in its consolidated financial statements. Refer to Note 15—Leases for a further discussion of the Company’s leases.

Asset Retirement Obligations

The Company’s oil and natural gas properties include estimates of future expenditures to P&A wells, pipelines, platforms, and other related facilities after the reserves have been depleted. The Company recognizes the present value of the asset retirement obligation costs as a liability when it is incurred and an increase to its capitalized oil

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and natural gas properties. The capitalized asset retirement obligation costs are depleted over the productive lives of the oil and natural gas properties while the asset retirement obligation liability is accreted to the expected settlement value over the productive lives of the oil and natural gas properties. Upon settlement, the difference between the recorded liability amount and the amount of costs incurred is recognized as an adjustment to the capitalized cost of oil and natural gas properties.

The determination of future asset retirement obligations requires estimates of the future costs of removal and restoration, productive lives of the oil and natural gas properties based on reserve estimates, and future inflation rates. Estimated costs consider historical experience, third-party estimates, and government regulatory requirements but do not consider salvage values. These costs could be subject to revisions in subsequent years due to changes in regulatory requirements, the estimated P&A cost, and the estimated timing of the oil and natural gas property retirement. In subsequent periods, if the estimate of the asset retirement obligation liability changes, the Company records an adjustment to both the asset retirement obligation liability and the oil and natural gas property carrying value. Additionally, the Company estimates the credit-risk adjusted discount rate, which is applied to the future inflated P&A costs to determine the discounted present value which is recognized as the initial liability. The determined credit-risk adjusted discount rate is also subsequently applied to accrete the liability. Refer to Note 7—Asset Retirement Obligations for further information related to the Company’s asset retirement obligations.

Series A Preferred Stock

The Company’s Series A Preferred Stock is classified in the stockholders’ equity section of the accompanying consolidated balance sheets as the shares are not mandatorily redeemable nor do they contain an unconditional conversion obligation. The holders of the Series A Preferred Stock are entitled to receive quarterly dividends of $0.45 per Series A Preferred Stock share, at the election of the Company’s Board, in cash or in PIK Shares. Since the Board has the option to pay the dividends in cash or in PIK Shares, the PIK Share dividends are deemed discretionary and are recorded at the declaration date at their stated rate (rather than at fair value) as a reduction to Net (loss) income to determine Net (loss) income attributable to EnVen Energy Corporation Class A common stockholders on the accompanying consolidated statements of operations.

As discussed above in Recently Adopted Accounting Standards, prior to the adoption of ASU 2020-06 on January 1, 2021, at the end of each reporting period or when PIK Share dividends were declared, the Company would evaluate if there was a beneficial conversion feature related to the PIK Share dividends of its Series A Preferred Stock. Although the Company has historically evaluated if a beneficial conversion exists on a quarterly basis, it has not recorded a beneficial conversion feature related to the PIK Share dividends of its Series A Preferred Stock since 2019 due to changes in the fair value of the its Class A Common Stock. Refer to Note 9 - Stockholders’ Equity for a further discussion of the Company’s Series A Preferred Stock.

Commitments and Contingencies

Liabilities for loss contingencies arising from claims, assessments, litigation, fines, penalties, and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred. Refer to Note 14—Commitments and Contingencies for a further discussion of the Company’s commitments and contingencies as of December 31, 2021.

Revenue Recognition

The Company recognizes the sales of oil, natural gas, and NGLs at the point that control of the product is transferred to the customer and production handling revenue is recognized over time as the Company performs on the service contract.

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The Company records revenue in the month production is delivered to the purchaser and invoices revenue by calendar month based on volumes at contractually based rates with payment typically required 30 days after the end of the production month. As a result, at the end of each month when the performance obligation is satisfied, the Company is required to estimate the variable consideration using the amount of production delivered to the purchaser and the price that will be received for the sale of the product. Additionally, the Company has made an accounting election to exclude certain qualifying taxes collected from customers and remitted to governmental authorities from its reported revenues and is presenting those amounts as a component of operating expense in the accompanying consolidated statements of operations. The amounts due from purchasers are accrued in oil, natural gas, and NGL revenue accounts receivable on the accompanying consolidated balance sheets. The Company records the differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Additionally, the Company has determined that product returns or refunds are very rare and will account for them as they occur, and it generally provides no warranty other than the implicit promise that goods delivered are free of liens and encumbrances and meet the agreed upon specification.

Oil revenue contracts. The majority of the Company’s oil revenue contracts are structured so that the Company delivers oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title, and risk of loss of the product. Generally, under these arrangements, the Company collects a price net of transportation incurred by the purchaser. The Company concluded that the corresponding transportation deductions related to these arrangements are part of the overall transaction price and records those deductions as a reduction to revenue rather than an expense.

However, in certain arrangements, the Company pays a third-party to transport the product to a contractually agreed-upon delivery point at which time the purchaser takes custody, title, and risk of loss of the product and receives a specified index price from the purchaser with no deduction. In this scenario, the Company recognizes revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third-party transportation costs are recorded as a component of operating expense in the accompanying consolidated statements of operations.

Natural gas and NGLs revenue contracts. Under the Company’s natural gas processing contracts, the Company delivers natural gas to a processing entity at the wellhead or the inlet of the processing entity’s system. In these contracts, the Company may elect to take residue gas and/or NGLs in-kind at the tailgate of the processing plant and subsequently market the product. Through the marketing process, the Company delivers the product to the purchaser at a contractually agreed-upon delivery point and receives a specified index price from the purchaser. This purchaser can be the natural gas processor or the processor can market the product on the Company’s behalf to a third-party purchaser. In both scenarios, the Company concluded it is the principal in the transaction as control of the product remains with the Company throughout the process. The Company recognizes revenue when control transfers to the ultimate purchaser at the delivery point based on the index price received from the purchaser. Any fees paid to the processor are considered to be for a distinct service with an identifiable benefit that is sufficiently separable. The gathering, processing, and compression fees attributable to the gas processing contract, as well as any transportation fees incurred to deliver the product to the purchaser, are presented as a component of operating expense in the accompanying consolidated statements of operations.

Production handling services contracts. The Company’s production handling service contracts are negotiated in situations where it has a significant working interest in a platform with excess capacity to process and handle produced oil and natural gas. The Company provides processing services to customers with nearby property interests who wish to utilize its excess processing capacity for their production. In certain situations, the Company will also provide services for the operation of the producer’s satellite subsea system. Under these contracts, the Company receives fees for volumes delivered by the customer and processed by the Company. The nature of production handling services is inherently output based on volumes processed and the Company recognizes revenue over time using the output method. Refer to Note 14—Commitments and Contingencies for a further discussion of the Company’s performance obligations related to its production handling services contracts.

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General and Administrative Expenses

G&A expenses consist of overhead, including salaries, incentive compensation, benefits for the Company’s corporate staff, costs of maintaining its headquarters, and costs of managing its production and development operations. The Company records a certain portion of its salaries, wages, and benefits as LOE when they are directly attributable to maintaining the production of its operated oil and natural gas properties. For oil and natural gas properties for which the Company is the operator, it reduces G&A expenses for reimbursements received from other working interest owners for the portion of costs and allowable overhead incurred during the drilling and production phases of the property. G&A expenses also include software fees and audit, legal compliance, and other professional service fees. Additionally, the Company could be subject to legal actions and claims arising in the ordinary course of business, which, if considered probable and reasonably estimable, would require a contingent liability to be recorded as G&A expense.

Stock-based Compensation

The Company recognizes stock-based compensation expense related to its Restricted Stock and stock options based on their fair value on the date of the grant. The Company’s Restricted Stock does not have any post-vesting restrictions; therefore, the fair value of each share on the grant date is determined based on the per share fair value of the Company’s Class A Common Stock on a minority, non-marketable basis. The estimates of the fair value of the Company’s Class A Common Stock are highly complex and subjective, incorporating significant judgments and estimates in the fair value assumptions. Refer to Note 5—Fair Value Measurements for discussion of the fair value of the Company’s Class A Common Stock. The fair value of the stock options granted was estimated on the date of the grant using the Black-Scholes option pricing model.

The Company recognizes compensation expense related to time-based Restricted Stock and stock options using the straight-line method over the requisite service period during which the employee or board member is required to provide services in exchange for the award in accordance with ASC Topic 718, Compensation—Stock Compensation. Compensation expense related to performance-based Restricted Stock is only recognized when the performance condition is deemed probable of occurring and, if necessary, is adjusted based on the probability of the level of achievement of the performance metric. The Company has elected to not estimate the forfeiture rate of its Restricted Stock or stock options in its initial calculation of compensation expense, but instead will adjust compensation expense for forfeitures as they occur. Refer to Note 11—Stock-based Compensation for a further discussion of the Company’s Restricted Stock and stock options.

Income Taxes

The Company accounts for income taxes using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to temporary differences between the financial statement carrying amounts of the assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are calculated by applying the existing tax laws and rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period that includes the enactment date.

A valuation allowance for deferred tax assets, including net operating loss carryforwards, is recognized when it is more likely than not that all or some portion of the benefit from the deferred tax asset will not be realized. To assess that likelihood, the Company uses estimates and judgment regarding its future taxable income, considering the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include the Company’s current financial position, actual and forecasted results of operations, and tax planning strategies, as well as the current and forecasted business economics of the oil and natural gas industry. The Company assesses all available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. A valuation allowance is provided for deferred tax assets if it is more likely than not that these items will not be

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realized. The effects of a change in the valuation allowance due to changes in circumstances and judgements about the realizability of the related deferred tax asset are included in income from continuing operations. Refer to Note 16—Income Taxes for a further discussion of the Company’s income tax provision.

Note 3—Acquisitions of Oil and Natural Gas Properties

On May 20, 2021, the Company completed the acquisition of an incremental 35% working interest in the U.S. Gulf of Mexico Atwater Valley 574, 575, and 618 (“Neptune”) field from BHP Billiton Petroleum (Deepwater) Inc. and BHP Billiton Petroleum (GOM) Inc. (collectively, “BHP”) with an effective date of July 1, 2020 (collectively, the “Neptune Acquisition”). The Neptune Acquisition was consummated pursuant to a Purchase and Sale Agreement executed on April 6, 2021 and accounted for as an asset acquisition in accordance with ASC Topic 805, Business Combinations. Prior to the acquisition, the Company held a 30% working interest in the Neptune field and following the close of the acquisition, it holds a 65% working interest in the Neptune field. Additionally, the Company became the operator of the Neptune field on August 1, 2021. Per the agreement, the Company did not provide any cash consideration for the Neptune Acquisition, but assumed BHP’s portion of the future P&A obligations associated with the Neptune field. Upon the final settlement of the acquisition, BHP agreed to pay the Company $8.6 million for the Neptune Acquisition, inclusive of customary closing adjustments and net of transaction related costs. Due to the timing of the final settlement, the Company has received $8.2 million of the total consideration in cash as of December 31, 2021, which is reflected in the Net cash used in investing activities section on the consolidated statement of cash flows for the year ended December 31, 2021. The remaining amount was received in January 2022, therefore, it is reflected as non-cash investing activity for the year ended December 31, 2021 in Note 17—Supplemental Cash Flow Information.

The following table presents the allocation of the total consideration to the assets acquired and liabilities assumed, based on their relative fair values, on May 20, 2021:

Refer to Note 5—Fair Value Measurements for a further discussion of the fair value measurements of the assets acquired and liabilities assumed in the Neptune Acquisition.

Note 4—Derivative Instruments

The Company utilizes commodity derivative instruments to reduce its exposure to crude oil and natural gas price volatility for a portion of its estimated production from its proved, developed, producing oil and natural gas properties. The Company has entered into various derivative contracts with major financial institutions, which, as of December 31, 2021, settle monthly through the first quarter of 2023.

The Company’s crude oil and natural gas derivative instruments consist of various instruments based on its hedging strategy, including financially settled crude oil and natural gas call options, put options, and swaps (including basis swaps), or combinations of these arrangements, which are described below.

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Additionally, the Company may purchase volumetrically offsetting derivative instruments in order to mitigate its exposure against additional commodity price volatility before the settlement date of certain outstanding derivative contracts.

The Company had the following outstanding crude oil derivative contracts, which are indexed to NYMEX WTI, in place as of December 31, 2021:

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The Company had the following outstanding natural gas derivative contracts, which are indexed to NYMEX HH, in place as of December 31, 2021:

The Company recognizes all of its derivative instruments at fair value as assets or liabilities on the accompanying consolidated balance sheets. The Company has not designated any of its derivative instruments as hedges for accounting purposes; therefore, the aggregate net gains and losses resulting from changes in the fair values of its outstanding derivatives, the settlement of derivative instruments, and any net proceeds or payments related to the early termination of derivative contracts during the period are recognized in (Loss) gain on derivatives, net in the accompanying consolidated statements of operations.

The Company typically has numerous hedge positions that span several time periods and often result in both fair value derivative asset and liability positions held with that counterparty. The Company has elected to net its derivative instrument fair values executed with the same counterparty, pursuant to the ISDA master agreements, which provide for the net settlement over the term of the contract and in the event of the default or termination of the contract.

In some cases, the Company might agree to pay a premium on certain of its option derivative contracts. The Company could agree to pay the premium upfront, in which case the premium payment is recorded as a derivative asset. The value of the premium is considered in the underlying derivative fair value and is adjusted in subsequent periods through (Loss) gain on derivatives, net in the accompanying consolidated statements of operations. Alternatively, the Company could defer the payment of the premium until the month the applicable derivative contract settles, in which case it recognizes the deferred premium obligation net against the derivative

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instruments fair value asset or liability, pursuant to the ISDA master netting agreements described above. In the period the derivative contract settles, the Company recognizes the deferred premium obligation in (Loss) gain on derivatives, net in the accompanying consolidated statements of operations.

The following tables present the gross and net fair values of the Company’s derivative instruments, net of any applicable deferred premium obligations recorded on the accompanying consolidated balance sheets:

As of December 31, 2021 and 2020, the fair values of the Company’s derivatives are presented net of deferred premium obligations of $7.5 million and $6.4 million, respectively.

The following table presents the components of (Loss) gain on derivatives, net reflected on the accompanying consolidated statements of operations and cash flows for the periods indicated. Total cash (paid) received for derivative settlements, net reflects the gains or losses on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price for those contracts. Any proceeds or payments related to the early termination of derivative contracts, any upfront premiums paid for new derivative contracts during the period, and any cash premium payments associated with derivative contracts settled during the period are included in the total cash (paid) received for derivative settlements, net. Total non-cash loss on derivatives, net represents the changes in the fair values of derivative instruments outstanding at the end of the period and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period.

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For the year ended December 31, 2021, total cash (paid) received for derivative settlements, net includes deferred premium obligations paid for crude oil derivative contracts of $7.7 million and natural gas derivative contracts of $2.4 million. For the year ended December 31, 2020, total cash (paid) received for derivative settlements, net includes deferred premium obligations paid for crude oil derivative contracts of $6.6 million. Additionally, for the year ended December 31, 2020, total cash (paid) received for derivative settlements, net includes $4.7 million of monetization costs received from counterparties for the early termination of certain oil derivative contracts before their contract settlement dates. For the year ended December 31, 2019, total cash (paid) received for derivative settlements, net includes deferred premium obligations paid for crude oil derivative contracts of $14.1 million.

Note 5—Fair Value Measurements

Certain of the Company’s assets and liabilities are carried at fair value and measured either on a recurring or non-recurring basis. The Company’s fair value measurements are based either on actual market data or assumptions that other market participants would use in pricing an asset or liability in an orderly transaction, using the valuation hierarchy prescribed by GAAP.

The GAAP valuation hierarchy categorizes assets and liabilities measured at fair value into one of three levels depending on the observability of inputs used to determine fair value. The three levels of the fair value hierarchy are as follows:

The classification of an asset or liability within the fair value hierarchy is based on the lowest level input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement of an asset or liability requires judgment and may affect the valuation of the fair value asset or liability and its placement within the fair value hierarchy. There have been no transfers between fair value hierarchy levels.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Commodity derivative contracts. The fair values of the Company’s derivative instruments are measured on a recurring basis using a third-party industry-standard pricing model that considers various inputs such as quoted forward commodity prices, discount rates, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant data. These significant inputs are observable in the current market or can be corroborated by observable active market data and are therefore considered Level 2 inputs within the fair value hierarchy.

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11.00% Senior Notes due 2023. At the time of the issuance of the 2023 Notes, the Company elected to account for the 2023 Notes and all of its features using the fair value option; therefore, the 2023 Notes were recorded at their fair value on the consolidated balance sheet as of December 31, 2020. In April, as part of the 2021 Refinancing Transactions, described further below, the Company redeemed the total $276.8 million principal amount of its outstanding 2023 Notes. Refer to Note 8—Long-term Debt for a discussion of the Company’s 2023 Notes. Prior to the redemption, the fair value of the Company’s 2023 Notes was measured on a recurring basis and based on unadjusted quoted prices for the liability in an active market, which is considered a Level 1 input.

The following tables present the Company’s assets and liabilities which are measured at fair value on a recurring basis as of December 31, 2021 and 2020 using the fair value hierarchy:

Fair Value of Other Financial Instruments

Cash and cash equivalents, restricted cash, accounts receivable, and accounts payable. The carrying amounts of the Company’s cash and cash equivalents, restricted cash, accounts receivable, and accounts payable approximate fair value due to the highly liquid or short-term nature of these instruments.

11.75% Senior Notes due 2026. The Company’s 11.75% senior secured second lien notes due 2026 (the “2026 Notes”) are presented on the consolidated balance sheet as of December 31, 2021 at their carrying value of $275.5 million, which is net of the unamortized discount and deferred financing costs. Refer to Note 8—Long-term Debt for a discussion of the Company’s 2026 Notes. The fair value of the aggregate principal amount outstanding of the 2026 Notes is $296.2 million as of December 31, 2021, and is estimated based on unadjusted quoted prices for the liability in an active market, which is considered a Level 1 input.

Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis

Acquisition-related assets and liabilities. The fair values of assets acquired and liabilities assumed in an acquisition are measured on a non-recurring basis on the acquisition date using a discounted cash flow model. The significant inputs used in the discounted cash flow model include estimates relating to oil and natural gas reserves, future commodity prices, the timing of developing the assets, future operating costs, a credit-risk adjusted discount rate, and other relevant data. These significant inputs are based on unobservable market data and are therefore considered Level 3 inputs within the fair value hierarchy. Refer to Note 3—Acquisitions of Oil and Natural Gas Properties for a further discussion of the Company’s acquisitions.

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Asset retirement obligations. The fair values of any additions to the Company’s asset retirement obligations are measured on a non-recurring basis at the time those obligations are incurred or acquired using a discounted cash flow model. The significant inputs used in the discounted cash flow model include estimates relating to the future P&A settlement timing and costs, a credit-risk adjusted discount rate, and inflation rates. These significant inputs are based on unobservable market data and are therefore considered Level 3 inputs within the fair value hierarchy. Refer to Note 7—Asset Retirement Obligations for a further discussion of the Company’s asset retirement obligations.

Class A Common Stock. The per share fair value of the Company’s Class A Common Stock is estimated on a non-recurring basis. In the second, third, and fourth quarters of 2021, the Company’s Board elected to pay the quarterly Series A Preferred Stock dividends in cash rather than issuing PIK Shares, as they were historically paid, and subsequently changed the valuation model used in determining the fair value of its Class A Common Stock from an option pricing model (“OPM”) to a Monte Carlo simulation model. The Monte Carlo simulation model uses assumptions regarding multiple projections of the Company’s share price paths and must be repeated numerous times to achieve a probabilistic assessment. Both the Monte Carlo model and the OPM estimate the per share fair value of the Company’s Class A Common Stock on a minority, marketable basis, and apply a discount for lack of marketability to account for the illiquidity of the Company’s Class A Common Stock. Both models allocate the Company’s total equity value to the various classes of equity in its capital structure, treating any outstanding shares of the Class A Common Stock, Class B Common Stock, and Series A Preferred Stock as options on the entity’s enterprise value and capturing the option-like characteristics of common stock for entities whose common stock is a small portion of the total capital structure.

The significant inputs used in the Monte Carlo model and the OPM include the timing and probabilities of potential liquidity event dates, equity volatilities, risk-free rates, and an estimate of the Company’s total equity value. A discounted cash flow model is utilized to calculate the total equity fair value by present valuing risk-adjusted future expected cash flows primarily associated with the Company’s oil and natural gas asset reserves. The assumed timing and probabilities of potential liquidity event dates are based on management’s estimates. As there is currently no active market for the Company’s Class A Common Stock, the expected equity volatility is determined using the historical volatility of a publicly traded set of peer companies. The risk-free interest rates utilized are based on the interpolated yields of the U.S. Treasury bonds with maturities that commensurate the timing of potential liquidity event dates. These significant inputs are based on sensitive unobservable market data and are therefore considered Level 3 inputs within the fair value hierarchy.

As of December 31, 2021, the Company’s Monte Carlo valuation model assumed a weighted-average risk-free interest rate of 0.3% and a weighted-average expected stock price volatility rate of 75.0%. As of December 31, 2020, the Company’s OPM valuation assumed a weighted-average risk-free interest rate of 0.2% and a weighted-average expected stock price volatility rate of 80.0%. Historically, the Company has not declared or paid Class A Common Stock cash dividends, nor is it probable that it will do so in the future, therefore, there was no dividend yield included in the OPM.

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Note 6—Property and Equipment, net

The Company’s property and equipment, net consist of the following for the periods indicated:

During each of the years ended December 31, 2021 and 2020, the Company recognized $0.9 million of G&A expenses directly allocable to capital exploratory activities, which were initially capitalized to unproved oil and natural gas properties. Additionally, during the years ended December 31, 2021 and 2020, the Company capitalized $2.3 million and $1.3 million, respectively, of interest expense to unproved oil and natural gas properties related to certain significant long-term exploratory projects. Refer to Note 19—Supplemental Oil and Natural Gas Disclosures (Unaudited) for a summary of the Company’s costs incurred related to its oil and natural gas properties.

Note 7—Asset Retirement Obligations

The following table presents the change in the Company’s asset retirement obligations for the periods indicated:

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For the years ended December 31, 2021 and 2020, the revisions of previous estimates to the Company’s asset retirement obligation balances are attributable to changes in estimated cash flows and the planned timing of P&A activities.

Note 8—Long-term Debt

The Company’s outstanding long-term debt balances consist of the following for the periods indicated:

The following table presents the components of Interest expense reflected on the accompanying consolidated statements of operations for the periods indicated: