Talos Energy 8K Other Events | TALO 12 Apr 23

Exhibit 99.1

ENVEN ENERGY CORPORATION AND SUBSIDIARIES

Financial Statements and Supplementary Data


Table of Contents	Page
Report of Independent Auditors		2
Consolidated Balance Sheets as of December 31, 2022 and 2021		3
Consolidated Statements of Operations for the Years Ended December 31, 2022 and 2021		5
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2022 and 2021		6
Consolidated Statement of Changes in Equity for the Years Ended December 31, 2022 and 2021		7
Consolidated Statements of Cash Flows for the Years Ended December 31, 2022 and 2021		8
Notes to Consolidated Financial Statements		10
Note 1 - Organization and Basis of Presentation		10
Note 2 - Summary of Significant Accounting Policies		11
Note 3 - Acquisitions of Oil and Natural Gas Properties		16
Note 4 - Derivative Instruments		17
Note 5 - Fair Value Measurements		20
Note 6 - Property and Equipment, net		21
Note 7 - Asset Retirement Obligations		22
Note 8 - Long-term Debt		22
Note 9 - Stockholders’ Equity		25
Note 10 - Related Party Transactions		26
Note 11 - Stock-based Compensation		27
Note 12 - Employee Benefit Plan		29
Note 13 - Concentrations of Risk		30
Note 14 - Commitments and Contingencies		30
Note 15 - Leases		32
Note 16 - Income Taxes		33
Note 17 - Supplemental Cash Flow Information		35
Note 18 - Subsequent Events		35
Note 19 - Supplemental Oil and Natural Gas Disclosures (Unaudited)		36

Report of Independent Auditors

To the Stockholders and the Board of Directors of Talos Energy Inc.

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, 2022 and 2021, and the related consolidated statements of operations, comprehensive income (loss), changes in equity and cash flows for the years then ended, 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, 2022 and 2021, and the results of its operations and its cash flows for the years then ended 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.

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.

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:

•

Exercise professional judgment and maintain professional skepticism throughout the audit.

•

Identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, and design and perform audit procedures responsive to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements.

•

Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control. Accordingly, no such opinion is expressed.

•

Evaluate the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluate the overall presentation of the financial statements.

•

Conclude whether, in our judgment, 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 a reasonable period of time.

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

April 11, 2023

ENVEN ENERGY CORPORATION AND SUBSIDIARIES

Consolidated Balance Sheets

(In thousands, except share amounts)


	December 31, 2022			December 31, 2021
Assets:
Current assets:
Cash and cash equivalents	$	175,947		$	88,930
Accounts receivable:
Oil, natural gas, and NGL revenue		47,345			56,323
Joint interest and other		25,596			11,961
Prepaid expenses and other current assets		7,924			11,426
Prepaid income tax		6,175			—

Total current assets		262,987			168,640
Property and equipment:
Oil and natural gas properties, full cost method, including $98,448 and $94,462 of unevaluated properties not being amortized as of December 31, 2022 and 2021, respectively		2,007,446			1,832,679
Other property and equipment		8,545			8,545
Less: accumulated depreciation, depletion, and amortization		(1,223,809	)		(1,074,368	)

Property and equipment, net		792,182			766,856
Restricted cash		100,651			100,695
Notes receivable, net		65,137			65,089
Right-of-use assets		18,912			21,662
Other well equipment inventory		14,687			11,408
Other non-current assets		3,437			4,540

Total assets	$	1,257,993		$	1,138,890

Liabilities and Stockholders’ Equity:
Current liabilities:
Accounts payable	$	29,042		$	21,487
Revenue and royalties payable		15,458			17,508
Accrued liabilities		53,201			58,905
Asset retirement obligations		8,390			24,935
11.75% Senior Notes due 2026, net		27,136			27,045
Lease liabilities		3,516			4,233
Derivative liabilities		6,515			77,551
Notes payable		—			4,413
Income tax payable		—			2,740
Other current liabilities		4,141			2,199

Total current liabilities		147,399			241,016
Asset retirement obligations, less current portion		384,075			323,351
11.75% Senior Notes due 2026, net, less current portion		221,333			248,469
Lease liabilities, less current portion		13,278			14,895
Derivative liabilities		156			2,391
Deferred tax liability		1,637			—
Other non-current liabilities		17,498			15,344

Total liabilities	$	785,376		$	845,466
Commitments and contingencies (Note 14)
Stockholders’ equity:
Series A convertible perpetual preferred stock, $0.001 par value, 25,000,000 shares authorized and 14,949,771 shares issued and outstanding as of December 31, 2022 and 2021	$	15		$	15

ENVEN ENERGY CORPORATION AND SUBSIDIARIES

Consolidated Balance Sheets

(In thousands, except share amounts)


	December 31, 2022		December 31, 2021
Class A common stock, $0.001 par value, 200,000,000 shares authorized and 21,551,777 and 20,840,432 shares issued and outstanding as of December 31, 2022 and 2021, respectively		22		21
Additional paid-in capital		400,686		394,474
Retained earnings (accumulated deficit)		71,894		(101,086	)

Total stockholders’ equity		472,617		293,424

Total liabilities and stockholders’ equity	$	1,257,993	$	1,138,890

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

ENVEN ENERGY CORPORATION AND SUBSIDIARIES

Consolidated Statements of Operations

(In thousands)


	Year Ended December 31,
	2022			2021

Revenues:
Oil, natural gas, and NGL revenue	$	703,235		$	508,901
Production handling and other income		27,505			21,390

Total revenues		730,740			530,291

Operating expenses:
Lease operating expenses		81,394			79,789
Workover, repair, and maintenance expenses		24,302			23,027
Transportation, gathering, and processing costs		8,939			7,261
Depreciation, depletion, and amortization		149,441			156,745
Accretion of asset retirement obligations		26,901			27,541
General and administrative expenses		78,562			75,601

Total operating expenses		369,539			369,964

Operating income		361,201			160,327

Other (expenses) income:
Loss on derivatives, net		(93,229	)		(171,917	)
Interest expense		(46,446	)		(47,165	)
Loss on extinguishment of long-term debt		—			(11,419	)
Gain on fair value of 11.00% Senior Notes due 2023		—			16,589
Other income		5,203			2,790

Total other expenses		(134,472	)		(211,122	)

Income (loss) before income taxes		226,729			(50,795	)

Income tax expense		26,841			11,307

Net income (loss)		199,888			(62,102	)

Net loss attributable to non-controlling interest		—			(4,744	)

Net income (loss) attributable to EnVen Energy Corporation		199,888			(57,358	)
Series A preferred stock dividends		(26,908	)		(28,583	)

Net income (loss) attributable to EnVen Energy Corporation Class A common stockholders	$	172,980		$	(85,941	)

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

ENVEN ENERGY CORPORATION AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income (Loss)

(In thousands)


	Year Ended December 31,
	2022		2021

Net income (loss)	$	199,888	$	(62,102	)
Other comprehensive loss, net:
Credit risk adjustment on 11.00% Senior Notes due 2023 before reclassification, net of deferred income tax benefit of $2.2 million for the year ended December 31, 2021		—		(23,571	)
Amount reclassified from accumulated other comprehensive income		—		(5,035	)

Total comprehensive income (loss), net		199,888		(90,708	)

Less: comprehensive loss attributable to non-controlling interest		—		(10,339	)

Comprehensive income (loss) attributable to EnVen Energy Corporation	$	199,888	$	(80,369	)

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

ENVEN ENERGY CORPORATION AND SUBSIDIARIES

Consolidated Statement of Changes in Equity

(In thousands, except share amounts)


	Series A preferred stock				Class A common stock					Class B common stock
	Shares		Amount		Shares			Amount		Shares			Amount			Additional paid-in capital			Accumulated other comprehensive income			Retained earnings (accumulated deficit)			Total stockholders’ equity			Non-controlling interest			Total equity
January 1, 2021 balance		14,409,417	$	14		17,329,667		$	17		3,333,333		$	3		$	382,819		$	23,011		$	(43,412	)	$	362,452		$	38,202		$	400,654
Issuance of Class A common stock related to stock-based compensation		—		—		450,469			1		—			—			(1	)		—			—			—			—			—
Tax payments related to stock-based compensation		—		—		(141,632	)		—		—			—			(1,213	)		—			—			(1,213	)		—			(1,213	)
Stock-based compensation		—		—		—			—		—			—			11,190			—			—			11,190			—			11,190
Repurchase of Class A common stock		—		—		(131,405	)		—		—			—			(1,950	)		—			—			(1,950	)		—			(1,950	)
Series A preferred stock dividends		540,354		1		—			—		—			—			6,483			—			(28,583	)		(22,099	)		—			(22,099	)
Change in ownership due to Series A preferred stock dividends		—		—		—			—		—			—			828			—			—			828			(828	)		—
Conversion of Class B common stock and settlement of the Tax Receivable Agreement, inclusive of tax impact		—		—		3,333,333			3		(3,333,333	)		(3	)		24,585			—			—			24,585			(27,035	)		(2,450	)
Cumulative effect of ASU 2020-06 accounting change		—		—		—			—		—			—			(28,267	)		—			28,267			—			—			—
Other comprehensive loss, net of tax		—		—		—			—		—			—			—			(23,011	)		—			(23,011	)		(5,595	)		(28,606	)
Net loss		—		—		—			—		—			—			—			—			(57,358	)		(57,358	)		(4,744	)		(62,102	)

December 31, 2021 balance		14,949,771	$	15		20,840,432		$	21		—		$	—		$	394,474		$	—		$	(101,086	)	$	293,424		$	—		$	293,424
Issuance of Class A common stock related to stock-based compensation		—		—		1,265,141			1		—			—			(1	)		—			—			—			—			—
Tax payments related to stock-based compensation		—		—		(463,121	)		—		—			—			(11,508	)		—			—			(11,508	)		—			(11,508	)
Stock-based compensation		—		—		—			—		—			—			20,068			—			—			20,068			—			20,068
Repurchase of Class A common stock		—		—		(90,675	)		—		—			—			(2,347	)		—			—			(2,347	)		—			(2,347	)
Series A preferred stock dividends		—		—		—			—		—			—			—			—			(26,908	)		(26,908	)		—			(26,908	)
Net income		—		—		—			—		—			—			—			—			199,888			199,888			—			199,888

December 31, 2022 balance		14,949,771	$	15		21,551,777		$	22		—		$	—		$	400,686		$	—		$	71,894		$	472,617		$	—		$	472,617

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

ENVEN ENERGY CORPORATION AND SUBSIDIARIES

Consolidated Statements of Cash Flows

(In thousands)


	Year Ended December 31,
	2022			2021

Cash flows from operating activities:
Net income (loss)	$	199,888		$	(62,102	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization		149,441			156,745
Accretion of asset retirement obligations		26,901			27,541
Stock-based compensation		20,068			11,190
Excess tax benefit (deficit) from stock-based compensation		1,456			(424	)
Amortization of debt discount and deferred financing costs		4,246			3,429
Loss on extinguishment of long-term debt		—			11,419
Gain on fair value of 11.00% Senior Notes due 2023		—			(16,589	)
Loss on derivatives, net		93,229			171,917
Cash paid for derivative settlements, net		(166,500	)		(111,262	)
Deferred income taxes		1,637			(5,098	)
Other non-cash items		148			(1,891	)
Changes in operating assets and liabilities:
Accounts receivable		(5,121	)		(14,655	)
Income tax		(10,371	)		20,495
Prepaid expenses and other current assets		3,568			4,026
Other well equipment inventory		(3,279	)		(5,670	)
Accounts payable		7,555			(23,847	)
Revenue and royalties payable		(2,050	)		7,800
Accrued liabilities		(14,513	)		16,163
Settlement of asset retirement obligations		(24,059	)		(10,781	)
Other liabilities		2,213			15,712

Net cash provided by operating activities	$	284,457		$	194,118

Cash flows from investing activities:
Purchases of property, equipment, and other capital expenditures	$	(122,114	)	$	(92,996	)
Net cash received for the acquisition of proved oil and natural gas properties		464			8,169
Acquisitions of unevaluated oil and natural gas properties		(658	)		(6,546	)

Net cash used in investing activities	$	(122,308	)	$	(91,373	)

Cash flows from financing activities:
Payment of Series A preferred stock dividends	$	(26,908	)	$	(22,099	)
Payment for the repurchase of Class A common stock		(2,347	)		(1,950	)
Tax payments related to stock-based compensation		(11,508	)		(1,213	)
Payment for the settlement of the tax receivable agreement		—			(7,000	)
Payments on notes payable		(4,413	)		(8,519	)
Repayment of long-term debt		(30,000	)		(291,816	)
Premium paid for the early termination of long-term debt		—			(11,419	)
Proceeds from the issuance of long-term debt		—			295,700
Payment of debt issue and deferred financing costs		—			(10,292	)

Net cash used in financing activities	$	(75,176	)	$	(58,608	)

Net increase in cash, cash equivalents, and restricted cash	$	86,973		$	44,137
Cash, cash equivalents, and restricted cash - beginning of period	$	189,625		$	145,488

Cash, cash equivalents, and restricted cash - end of period	$	276,598		$	189,625

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.

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.

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 Class A common stock $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”). Refer to Note 10 - Related Party Transactions for a full discussion of the TRA and 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. Refer to Note 9 - Stockholders’ Equity for a further discussion of these transactions.

Talos Merger Agreement

On September 21, 2022, the Company and Talos Energy Inc. (“Talos”) announced that they entered into an Agreement and Plan of Merger (the “Talos Merger Agreement”), pursuant to which Talos would acquire all of the outstanding equity interest in the Company in a stock and cash transaction. Under the terms of the Talos Merger Agreement, the Company’s shareholders would receive an aggregate of 43,800,000 shares of Talos common stock and an aggregate of approximately $212.5 million in cash (subject to certain adjustments) (the “Talos Merger”).

Pursuant to the Talos Merger Agreement, immediately prior to the closing of the merger, all outstanding shares of the Company’s Series A convertible perpetual preferred stock (“Series A Preferred Stock”) will automatically convert into shares of the Company’s Class A Common Stock, per the Series A Preferred Stock certificate of designation (“COD”), as amended in connection with the Talos Merger Agreement on September 21, 2022. Additionally, immediately prior to the closing of the merger, all of the time-based and performance-based Restricted Stock shares issued and outstanding will vest into shares of the Company’s Class A Common Stock. The Talos Merger Agreement also addresses the treatment of the Company’s stock options. Refer to Note 9—Stockholders’ Equity for a further discussion of the Company’s Series A Preferred Stock and to Note 11 - Stock-based Compensation for a further discussion of the Company’s time-based and performance-based Restricted Stock and stock options.

On January 11, 2023, Talos announced that the Securities Exchange Commission (“SEC”) had declared its Registration Statement on Form S-4 related to the merger as effective and on February 8, 2023, Talos stockholders approved certain matters relating to the merger at a special meeting of the stockholders. Additionally, the Company obtained the written consents required from its shareholders to approve the merger. The transaction closed on February 13, 2023. Refer to Note 18 - Subsequent Events for a further discussion.

Basis of Presentation and Consolidation

The accompanying consolidated financial statements as of and for the years ended December 31, 2022 and 2021 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 intercompany balances and transactions have been eliminated.

Prior to the Class B Common Stock Conversion in April 2021, discussed above, the Company owned the majority interest 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. The remaining ownership interest not held by the Company 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 and 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

In August 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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.

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 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 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 were fully funded as of October 2021. Refer to Note 14 - Commitments and Contingencies for a further discussion of those requirements.

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 development, exploration, 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.

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 No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments 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, 2022 and 2021. 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, 2022 and 2021 was $148.2 million and $155.5 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 basis subject to DD&A 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 basis subject to DD&A. 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 basis subject to DD&A as of December 31, 2022 and the periods such costs were incurred:


			Year Ended December 31,
	Total		2022		2021		2020		2019 & Prior ⁽¹⁾
	(In thousands)
Acquisition costs	$	36,341	$	658	$	667	$	10,596	$	24,420
Exploration costs ⁽²⁾		62,107		6,808		4,144		16,919		34,236

Total costs	$	98,448	$	7,466	$	4,811	$	27,515	$	58,656

⁽¹⁾	None of the acquisition or exploration costs presented were incurred prior to 2018.

⁽²⁾	The Company’s exploration costs incurred for the years ended December 31, 2022, 2021, and 2020 includes capitalized interest of $2.4 million, $2.3 million, and $1.3 million, respectively, related to certain significant long-term exploratory projects.

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 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, 2022 and 2021.

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 exploration 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, 2022 and 2021, the Company’s prepaid balances for its surety bond premiums were $2.0 million and $7.7 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, 2022 and 2021, the Company’s prepaid balances for its commercial insurance packages were $2.6 million and $2.2 million, respectively.

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, 2022 and 2021, both of the P&A Notes Receivable have fully accreted to their principal amounts of $65.1 million and are presented as such, net of related cumulative estimated credit losses, on the accompanying consolidated balance sheets.

The Company estimates any current expected credit losses related to its P&A Notes Receivable on a combined amortized basis 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.” The Company records any changes in the current estimated credit losses related to its P&A Notes Receivable as part of Other income on the accompanying consolidated statements of operations. Refer to Note 14 - Commitments and Contingencies for a further discussion of the Company’s outstanding notes receivable.

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 could 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, 2022, 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.

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 or assumed and an increase to its capitalized oil 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 by issuing 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 income (loss) to determine Net income (loss) attributable to EnVen Energy Corporation Class A common stockholders on the accompanying consolidated statements of operations. 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, 2022.

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.

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.

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, 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 complex and subjective, incorporating 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 to reflect material changes in the probability or achievement level of the 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 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 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 received $8.2 million of the total consideration in cash during the year ended December 31, 2021 and the remaining amount was received in January 2022. The net cash received for the Neptune Acquisition is reflected in the Net cash used in investing activities section on the consolidated statements of cash flows for the years ended December 31, 2022 and 2021.

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:


	(In thousands)
Proved oil and natural gas properties	$	5,831
Asset retirement obligations		(14,464	)

Allocated total consideration	$	(8,633	)

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. Based on the Company’s hedging strategy, it has various crude oil and natural gas derivative contracts with multiple major financial institutions, which could consist of any of the instruments described below.

•

Swaps: The Company receives a fixed price and pays a variable market price to the counterparty for contracted commodity volumes over specified time periods. From time to time, the Company may enter into basis swaps or WTI NYMEX roll swaps to provide additional protection against the variability of other pricing components.

•

Call Options: A sold call option gives the counterparty the right, but not the obligation, to purchase the underlying commodity volumes from the Company at a specified price (“strike/ceiling price”) over a specified time period. At settlement, if the market price is above the fixed ceiling price of the sold call option, the Company pays the counterparty the difference. In a purchased call option, if the market price settles above the fixed ceiling price of the purchased call option, the Company will receive the difference from the counterparty. If the market price settles below the fixed ceiling price of the sold or purchased call option, no payment is due from either party.

•

Purchased Put Options: A purchased put option gives the Company the right, but not the obligation, to sell the underlying commodity volumes to the counterparty at a specified price (“strike/floor price”) over a specified time period. At settlement, if the market price is below the fixed floor price of the purchased put option, the counterparty pays the Company the difference. If the market price settles above the fixed floor price of the purchased put option, no payment is due from either party.

•

Put Spreads: A put spread is a combination of a sold put option and a purchased put option. At settlement, if the market price is below the sold put option strike price, the Company receives the difference between the two strike prices from the counterparty. If the market price settles below the purchased put option strike price but above the sold put option strike price, the Company receives the difference between the purchased put option strike price and the market price from the counterparty. If the market price settles above the purchased put option strike price, no payment is due from either party.

•

Collars: A collar contains a purchased put option (“fixed floor price”) and a sold call option (“fixed ceiling price”). At settlement, if the market price is below the fixed floor price, the Company receives the difference between the fixed floor price and the market price from the counterparty. If the market price settles above the fixed ceiling price, the Company pays the counterparty the difference between the market price and the fixed ceiling price. If the market price settles between the fixed floor price and fixed ceiling price, no payments are due from either party.

•

Three-way Collars: A three-way collar combines a sold call option (“fixed ceiling price”), a purchased put option (“fixed floor price”), and a sold put option (“fixed subfloor price”). At settlement, if the market price settles above the fixed subfloor price but below the fixed floor price, the Company receives the difference between the fixed floor price and the market price from the counterparty. If the market price settles below the fixed subfloor price, the Company receives the market price plus the difference between the fixed subfloor price and the fixed floor price from the counterparty. If the market price settles above the fixed ceiling price, the Company pays the counterparty the difference between the fixed ceiling price and the market price. If the market price settles between the fixed floor price and fixed ceiling price, no payments are due from either party.

As of December 31, 2022, the Company had the following outstanding crude oil and natural gas derivative contracts in place, which settle monthly and are indexed to NYMEX WTI and NYMEX HH, respectively:


	Settling Through December 31, 2023		Settling Through December 31, 2024
Crude Oil Swaps:
Notional volume (Bbls)		90,000		—
Weighted average price ($/Bbl)	$	62.00	$	—
Crude Oil Collars:
Notional volume (Bbls)		772,500		—
Weighted average floor price ($/Bbl)	$	59.17	$	—
Weighted average ceiling price ($/Bbl)	$	85.08	$	—
Crude Oil Three-way Collars:
Notional volume (Bbls)		3,079,000		291,200
Weighted average sub-floor price ($/Bbl)	$	50.22	$	57.27
Weighted average floor price ($/Bbl)	$	63.44	$	70.00
Weighted average ceiling price ($/Bbl)	$	106.34	$	98.01
Natural Gas Purchased Calls:
Notional volume (MMBtus)		590,000		—
Weighted average price ($/MMBtu)	$	6.00	$	—
Natural Gas Three-way Collars:
Notional volume (MMBtus)		590,000		—
Weighted average sub-floor price ($/MMBtu)	$	2.50	$	—
Weighted average floor price ($/MMBtu)	$	3.00	$	—
Weighted average ceiling price ($/MMBtu)	$	5.00	$	—

Additionally, the Company may enter into diesel swap derivative contracts to hedge against variability in cash flows associated with the purchase of diesel fuel used in its production and drilling activities. Under these diesel derivative swap contracts, the Company pays a fixed price to the counterparty for contracted commodity volumes over specified time periods. All of the Company’s outstanding diesel swap derivative contracts settled prior to December 31, 2022.

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 as part of the Loss on derivatives, net on 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 on derivatives, net on 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 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 on derivatives, net on 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:


	December 31, 2022
	Gross Amounts Recognized			Gross Amounts Offset on the Consolidated Balance Sheet			Net Amounts Presented on the Consolidated Balance Sheet
	(In thousands)
Current assets	$	14,124		$	(14,124	)	$	—
Long-term assets		2,691			(2,691	)		—
Current liabilities		(20,639	)		14,124			(6,515	)
Long-term liabilities	$	(2,847	)	$	2,691		$	(156	)


	December 31, 2021
	Gross Amounts Recognized			Gross Amounts Offset on the Consolidated Balance Sheet			Net Amounts Presented on the Consolidated Balance Sheet
	(In thousands)
Current assets	$	5,205		$	(5,205	)	$	—
Long-term assets		2,206			(2,206	)		—
Current liabilities		(82,756	)		5,205			(77,551	)
Long-term liabilities	$	(4,597	)	$	2,206		$	(2,391	)

As of December 31, 2022 and 2021, the fair values of the Company’s derivatives are presented net of deferred premium obligations of $0.7 million and $7.5 million, respectively.

The following table presents the components of Loss on derivatives, net reflected on the accompanying consolidated statements of operations and cash flows for the periods indicated. Total cash paid for derivative settlements, net reflects the net losses or gains 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 for derivative settlements, net. Total non-cash gain (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 losses or gains on derivative contracts that matured during the period.


	Year Ended December 31,
	2022			2021
	(In thousands)
Cash (paid) received for derivative settlements, net:
Crude oil	$	(164,719	)	$	(106,828	)
Natural gas		(2,396	)		(4,434	)
Diesel		615			—

Total cash paid for derivative settlements, net		(166,500	)		(111,262	)
Non-cash gain (loss) on derivatives:
Crude oil		72,657			(59,961	)
Natural gas		614			(694	)
Total non-cash gain (loss) on derivatives, net		73,271			(60,655	)

Loss on derivatives, net	$	(93,229	)	$	(171,917	)

For the year ended December 31, 2022, total cash paid for derivative settlements, net includes deferred premium obligations paid for crude oil derivative contracts of $7.7 million and deferred premium obligations paid for natural gas derivative contracts of $1.2 million. Additionally, for the year ended December 31, 2022, the total cash paid for natural gas derivative settlements, net includes payments of $0.8 million to unwind certain natural gas derivative contracts before their settlement dates. For the year ended December 31, 2021, total cash paid for derivative settlements, net includes deferred premium obligations paid for crude oil derivative contracts of $7.7 million and deferred premium obligations paid for natural gas derivative contracts of $2.4 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:

•

Level 1: Unadjusted quoted prices for identical assets or liabilities in active markets.

•

Level 2: Observable inputs other than Level 1 inputs. These include: quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets which are not active, or inputs that are corroborated by observable active market data.

•

Level 3: Unobservable inputs for which little or no market data exists.

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.

The following tables present the Company’s commodity derivative contract assets and liabilities, which are measured at fair value on a recurring basis, as of December 31, 2022 and 2021, using the fair value hierarchy:


	Fair Value Measurement as of December 31, 2022
	Total			Level 1		Level 2			Level 3

	(In thousands)
Assets:
Commodity derivative contracts	$	16,815		$	—	$	16,815		$	—
Liabilities:
Commodity derivative contracts	$	(23,486	)	$	—	$	(23,486	)	$	—


	Fair Value Measurement as of December 31, 2021
	Total			Level 1		Level 2			Level 3

	(In thousands)
Assets:
Commodity derivative contracts	$	7,411		$	—	$	7,411		$	—
Liabilities:
Commodity derivative contracts	$	(87,353	)	$	—	$	(87,353	)	$	—

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 sheets as of December 31, 2022 and 2021 at their carrying values of $248.5 million and $275.5 million, respectively, 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. As of December 31, 2022 and 2021, the fair value of the aggregate principal amount outstanding of the 2026 Notes was $266.3 million and $296.2 million, respectively. The fair value of the 2026 Notes is estimated based on the 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.

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 assumed 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 using a Monte Carlo simulation model, which uses assumptions regarding multiple projections of the Company’s share price paths and must be repeated numerous times to achieve a probabilistic assessment. The Monte Carlo model estimates the per share fair value of the Company’s Class A Common Stock on a minority, marketable basis, and applies a discount for lack of marketability to account for the illiquidity of the Company’s Class A Common Stock. The model allocates the Company’s total equity value to the various classes of equity in its capital structure, treating all outstanding shares of the Class A 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 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, 2022, the Company’s Monte Carlo valuation model assumed a risk-free interest rate of 1.61% and an expected stock price volatility rate of 65.0%. 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%. These significant inputs are based on sensitive unobservable market data and are therefore considered Level 3 inputs within the fair value hierarchy.

Note 6 - Property and Equipment, net

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


	December 31, 2022			December 31, 2021

	(In thousands)
Proved oil and natural gas properties	$	1,908,998		$	1,738,217
Less: accumulated depreciation, depletion, and amortization		(1,216,698	)		(1,068,467	)

Proved oil and natural gas properties, net		692,300			669,750
Unproved oil and natural gas properties		98,448			94,462

Total oil and natural gas properties, net		790,748			764,212

Other property and equipment		8,545			8,545
Less: accumulated depreciation		(7,111	)		(5,901	)

Total other property and equipment, net		1,434			2,644

Total property and equipment, net	$	792,182		$	766,856

During each of the years ended December 31, 2022 and 2021, 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, 2022 and 2021, the Company capitalized $2.4 million and $2.3 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:


	December 31, 2022			December 31, 2021

	(In thousands)
Asset retirement obligations at the beginning of the period	$	348,286		$	299,674
Liabilities settled		(17,154	)		(10,040	)
Liabilities incurred		1,474			13
Liabilities acquired ⁽¹⁾		—			14,464
Revisions of previous estimates		32,958			16,634
Accretion expense		26,901			27,541

Asset retirement obligations at the end of the period		392,465			348,286
Less: current portion of asset retirement obligations		(8,390	)		(24,935	)

Asset retirement obligations, less current portion at the end of the period	$	384,075		$	323,351

⁽¹⁾	All of the asset retirement obligation liabilities acquired during the year ended December 31, 2021 relate to the Neptune Acquisition, refer to Note 3 - Acquisitions of Oil and Natural Gas Properties for a further discussion.

For the years ended December 31, 2022 and 2021, 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:


	December 31, 2022			December 31, 2021

	(In thousands)
11.75% Senior Notes due 2026 ⁽¹⁾	$	257,500		$	287,500
Less: unamortized discount and deferred financing costs		(9,031	)		(11,986	)

11.75% Senior Notes due 2026, net		248,469			275,514
Less: current portion of 11.75% Senior Notes due 2026, net ⁽²⁾		(27,136	)		(27,045	)

Long-term portion of 11.75% Senior Notes due 2026, net	$	221,333		$	248,469

⁽¹⁾	The Company redeemed $15.0 million of its 2026 Notes outstanding principal amount at par value on October 15, 2021, April 15, 2022, and October 15, 2022 as required per the 2026 Notes indenture.

⁽²⁾	As of December 31, 2022 and 2021, the current portion of the 11.75% Senior Notes due 2026 is presented net of the next twelve months of the unamortized discount and deferred financing costs.

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


	Year Ended December 31,
	2022			2021

	(In thousands)
Interest expense on 11.75% Senior Notes due 2026	$	32,166		$	24,810
Amortization of discount and deferred financing costs related to 11.75% Senior Notes due 2026		2,955			2,127
Interest expense on 11.00% Senior Notes due 2023		—			8,980
Amortization of deferred financing costs related to the Revolving Credit Facility		1,291			1,302
Fees associated with the Revolving Credit Facility		1,091			1,045
Amortization of surety bond premiums		10,675			10,657
Other interest expense		666			580
Less: capitalized interest		(2,398	)		(2,336	)

Total interest expense	$	46,446		$	47,165

Revolving Credit Facility

In 2014, the Company entered into an agreement with a syndicate of banks and established the first lien senior secured revolving credit facility (the “Revolving Credit Facility”), which is secured by substantially all of the Company’s assets on a first lien basis. The Revolving Credit Facility has a maximum line of credit of $500.0 million and the borrowing base is subject to a semi-annual redetermination, based on an assessment of the value of the Company’s proved reserves as determined by a reserve report. In April 2021, the Company amended certain terms of the Revolving Credit Facility agreement and extended the maturity date to January 26, 2024, established a revised borrowing base of $165.0 million, reduced the aggregate committed amounts thereunder to $165.0 million, and modified applicable interest rates. As part of the semi-annual redeterminations, in November 2021, the Revolving Credit Facility borrowing base was increased to $200.0 million and in June 2022, the Revolving Credit Facility borrowing base and aggregated committed amounts were increased to $250.0 million and $200.0 million, respectively.

As of December 31, 2022 and 2021, the Revolving Credit Facility remained undrawn and the Company had $3.6 million in outstanding letters of credit to collateralize its oil and natural gas transportation agreements and P&A obligations, resulting in $196.4 million and $161.4 million, respectively, of availability under its Revolving Credit Facility, including its outstanding letters of credit.

Borrowings under the Revolving Credit Facility, as amended, bear interest at one of the following rates, as selected by the Company: (i) the bank’s prime rate in effect, adjusted by an applicable margin of 2.0%–4.5%; or (ii) the Secured Overnight Financing Rate, adjusted by an applicable margin of 3.0%–5.5%. Per the agreement, the Company may elect to convert its outstanding borrowings to a different type and interest rate.

The agreement governing the Revolving Credit Facility contains certain covenants, including maximum ratios of total funded and secured debt to EBITDAX, and a minimum ratio of current assets to current liabilities. The Company’s ability to declare and pay dividends and other restricted payments under its amended Revolving Credit Facility agreement is subject to its compliance with additional incurrence covenants, the Company maintaining a required amount of availability under its Revolving Credit Facility, as well as the absence of any defaults by the Company under its Revolving Credit Facility. Other restrictive covenants include, but are not limited to, limitations on the Company’s ability to incur indebtedness, make loans or investments, enter into certain hedging agreements, materially change its business, or undergo a change of control.

Additionally, the Revolving Credit Facility agreement contains certain requirements relating to the Company’s hedging of its proved, developed, and producing reserves, which are defined in the agreement as reasonably projected production from proved, developed, and producing reserves. The Revolving Credit Facility agreement limits the Company’s derivative contracts with delivery risk to 85% of the reasonably projected production from its proved, developed, producing reserves in December through July (“non-wind months”) and 70% of the reasonably projected production from its proved, developed, producing reserves in August through November (“wind months”).

The Revolving Credit Facility agreement also contains a minimum hedging requirement, which was amended as part of the semi-annual redetermination in November 2021. Per the agreement, as amended, if the Company’s leverage ratio is below a defined threshold on the minimum hedging test dates of March 15th and September 15th of each year (the “Minimum Hedging Test Date”), it is required to hedge a minimum of 50% of the reasonably projected production from its proved, developed, producing reserves, on a Boe basis, for the first twelve months following the Minimum Hedging Test Date. If the Company’s leverage ratio is above the defined threshold on the Minimum Hedging Test Date, then the minimum hedging requirements change to 70% of the reasonably projected production from its proved, developed, producing reserves, on a Boe basis, for the first twelve months and 50% of the reasonably projected production from its proved, developed, producing reserves, on a Boe basis, for months 13 through 18 following the Minimum Hedging Test Date.

As of December 31, 2022, the Company is in compliance with all of the covenants and hedging requirements contained in its Revolving Credit Facility agreement.

On February 13, 2023, in connection with the consummation of the transactions contemplated by the Talos Merger Agreement, described in Note 1 - Organization and Basis of Presentation—Talos Merger Agreement, the Revolving Credit Facility was terminated.

11.75% Senior Notes due 2026

On April 15, 2021, the Company completed the private offering of its $302.5 million aggregate principal amount 2026 Notes, which resulted in net proceeds of $288.4 million, net of the original issuance discount of $6.8 million and underwriter and other third-party offering costs of $7.3 million. The 2026 Notes were issued by EnVen GoM and co-issued by EnVen GoM’s wholly-owned subsidiary, EnVen Finance Corporation, and are initially guaranteed by the Company and its domestic subsidiaries which guarantee the Revolving Credit Facility. The 2026 Notes and the related guarantees are secured by second-priority liens on the Company’s and the guarantors’ assets that secure all of the indebtedness under the Revolving Credit Facility, subject to certain exceptions. The 2026 Notes will mature on April 15, 2026 and interest accrues from April 15, 2021, the date of issuance, and is to be paid semi-annually in cash in arrears on April 15th and October 15th of each year, beginning October 15, 2021. The Company amortizes the 2026 Notes discount and deferred financing costs into Interest expense on the accompanying consolidated statements of operations over the term of the 2026 Notes using the interest method with an effective interest rate of 13.3%. Additionally, per the 2026 Notes indenture, the Company is required to redeem $15.0 million of the principal amount outstanding at par value on April 15th and October 15th of each year, beginning October 15, 2021. In accordance with ASC Topic 210, Balance Sheet, the Company classifies the portion of the 2026 Notes, net of the unamortized discount and deferred financing costs, which will be paid within the next twelve months as a current liability on its consolidated balance sheets.

The indenture governing the 2026 Notes also contains certain covenants, which are customary with respect to non-investment grade debt securities, including limitations on the Company’s ability to incur and guarantee additional indebtedness, repay, redeem, or repurchase certain debt and capital stock, issue certain preferred stock or similar equity securities, pay dividends or make other distributions on capital stock, enter into certain types of transactions with affiliates, make loans or investments, and make other restricted payments. Additionally, certain covenants restrict the Company’s subsidiaries’ ability to pay dividends, create liens, and sell certain assets. As of December 31, 2022, the Company is in compliance with all of the debt covenants contained in the indenture governing the 2026 Notes.

In connection with the consummation of the transactions contemplated by the Talos Merger Agreement, described in Note 1—Organization and Basis of Presentation—Talos Merger Agreement, Talos Production Inc. (“Talos Production”) and certain of its subsidiaries entered into a supplemental indenture to the 2026 Notes indenture which, among other things, provides for the assumption of the indebtedness in respect of the 2026 Notes by Talos Production, as well as guarantees of such indebtedness by certain subsidiaries of Talos Production, as contemplated by the terms of the indenture governing the 2026 Notes.

11.00% Senior Notes due 2023

On February 15, 2018, the Company completed the private offering of its $325.0 million aggregate principal amount 11.00% senior secured second lien notes due 2023 (the “2023 Notes”), resulting in net proceeds of $317.0 million, after deducting initial purchaser fees and offering expenses of $8.0 million. The 2023 Notes were issued by EnVen GoM and co-issued by EnVen GoM’s wholly-owned subsidiary, EnVen Finance Corporation and were initially guaranteed by the Company and its domestic subsidiaries which guaranteed the Revolving Credit Facility. The 2023 Notes and the related guarantees were secured by second-priority liens on the Company’s and the guarantors’ assets that secured all of the indebtedness under the Revolving Credit Facility, subject to certain exceptions. The 2023 Notes were set to mature on February 15, 2023 and interest accrued from February 15, 2018, the date of issuance, and was paid semi-annually in cash in arrears on February 15th and August 15th of each year, beginning August 15, 2018. As of the date of issuance and until the 2023 Notes were redeemed, the Company was in compliance with all of the debt covenants contained in the indenture governing the 2023 Notes.

Throughout the fourth quarter of 2020, the Company paid $41.3 million to repurchase $48.2 million principal amount of its 2023 Notes, including $1.3 million in accrued interest. In April 2021, the Company redeemed the remaining $276.8 million principal amount of its outstanding 2023 Notes, which included paying $5.2 million of accrued interest. Additionally, upon redemption, the Company paid a call premium of $11.4 million, which is recognized as Loss on extinguishment of long-term debt on the accompanying consolidated statement of operations for the year ended December 31, 2021 and reflects the difference between the par value and the redemption price of the 2023 Notes.

At the time of the 2023 Notes issuance, the Company analyzed the put and call features contained in the 2023 Notes indenture in accordance with ASC Topic 815, Derivatives and Hedging and determined that one of these features was an embedded derivative. The Company then elected to account for the 2023 Notes and all of its features using the fair value option instead of bifurcating the derivative; therefore, it recorded the 2023 Notes at fair value on its balance sheet and all subsequent changes in the fair value were recorded in accordance with ASU No. 2016-01, Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities. 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 on fair value of 11.00% Senior Notes due 2023 on the Company’s consolidated statement of operations and the remainder of the change was attributable to instrument-specific credit risk and was recognized separately as Other comprehensive income (loss), net on the consolidated statement of comprehensive income (loss). 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 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 income (loss), net.

Additionally, ASC Topic 470-50, Modifications and Extinguishment of Debt specifies that if the Company extinguishes debt that is recorded using the fair value option then the net carrying amount of the extinguished debt should equal its fair value at the date of the redemption and any related gains or losses that have been recognized separately in Other comprehensive income (loss) should be reclassified to Net income (loss) upon extinguishment. Therefore, at the time of the redemption, the Company recorded the outstanding amount of the 2023 Notes at their fair value and allocated the change in fair value between the change in the base market rate and the change attributable to instrument-specific credit risk. The Company then reclassified the Accumulated other comprehensive income associated with the 2023 Notes of $5.0 million to its consolidated statement of operations for the year ended December 31, 2021 as a component of Gain on fair value of 11.00% Senior Notes due 2023. Additionally, the Gain on fair value of 11.00% Senior Notes due 2023 recognized for the year ended December 31, 2021 includes the reversal of $11.4 million of losses previously recognized to account for the changes in the base market rate of the 2023 Notes. Overall, during the year ended December 31, 2021, the Company recognized $16.6 million as Gain on fair value of 11.00% Senior Notes due 2023 and $23.0 million as Other comprehensive income (loss), net of $5.6 million attributable to non-controlling interest.

Note 9 - Stockholders’ Equity

Prior to the 2015 Equity Offering, as discussed in Note 1—Organization and Basis of Presentation—Organization, the Company amended its certificate of incorporation to authorize the issuance of 275,000,000 shares of capital stock consisting of 200,000,000 shares of Class A Common Stock, 50,000,000 shares of Class B Common Stock, and 25,000,000 shares of Series A Preferred Stock.

Additionally, as part of the 2015 Equity Offering, the Company issued Series A and Series B Warrants, which were exercisable at any time into 2,000,000 shares of Class A Common Stock. None of these warrants were exercised before they expired on November 6, 2020.

Class A & Class B Common Stock

As discussed in Note 1—Organization and Basis of Presentation—Organization, 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 interest in EnVen GoM to a newly formed limited liability company, EnVen Equity Holdings. 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. Concurrently, the Company issued 3,333,333 shares of its Class B Common Stock to the owners of EnVen Equity Holdings.

In April 2021, EnVen Equity Holdings exercised its Redemption Rights, discussed above in Note 1—Organization and Basis of Presentation—Organization, 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 Class B Common Stock, resulting in the Class B Common Stock Conversion. As a result, 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.

Prior to the Class B Common Stock Conversion, the Company owned the majority interest 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 and the Non-controlling interest not held by the Company was included in the accompanying consolidated financial statements as Non-controlling interest. The Non-controlling interest percentage was based on the proportionate amount of the Company’s Class B Common Stock outstanding to the total shares outstanding, inclusive of its Class A Common Stock, Series A Preferred Stock, and the PIK Share dividends; therefore, it changed if and when shares of Class A Common Stock, Series A Preferred Stock, and PIK Share dividends were issued. EnVen GoM was considered a variable interest entity for which the Company was the primary beneficiary, as it was the sole managing member of EnVen GoM and had the power to direct the activities most significant to EnVen GoM’s economic performance, as well as the obligation to absorb losses and receive benefits that were potentially significant. 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.

Excluding Class A Common Stock shares issued as part of the Class B Conversion discussed above, during the years ended December 31, 2022 and 2021, the Company only issued Class A Common Stock shares as part of its employee incentive award plan. Additionally, during the years ended December 31, 2022 and 2021, the Company repurchased and retired 90,675 shares and 131,405 shares of vested Restricted Stock, respectively, from current employees. Refer to Note 11—Stock-based Compensation for a further discussion.

Series A Preferred Stock

On December 30, 2016, the Board designated 9,867,930 shares of the Company’s authorized and unissued shares of preferred stock with a par value of $0.001 per share as Series A Preferred Stock. The Company subsequently issued the Series A Preferred Stock to investors for $12.00 per share in conjunction with funding the acquisition of certain oil and natural gas properties.

The Series A Preferred Stock COD provides the holders certain rights and preferential privileges not available to the holders of other classes of the Company’s stock. In June 2021, the Company executed an amendment to the Series A Preferred Stock COD to reflect certain administrative changes. In conjunction with the amendment, the Company paid a $1.9 million consent fee to the Series A Preferred Stock holders, which is presented as a component of Net cash used in financing activities on the consolidated statement of cash flows for the year ended December 31, 2021. The Series A Preferred Stock COD was further amended on September 21, 2022 in connection with the Talos Merger Agreement to enable the automatic conversion of the Series A Preferred Stock in connection with a business combination with the consent of a super majority of the Series A Preferred Stock holders. The Series A Preferred Stock COD amendments did not change the nature or fair value of the Series A Preferred Stock.

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. The Series A Preferred Stock dividends are cumulative from the issue date and are payable in arrears beginning on December 31, 2016. In the first quarter of 2021, the Company paid the quarterly Series A Preferred Stock dividends by issuing PIK Shares. However, in the second, third, and fourth quarters of 2021 and throughout all of 2022, the Company’s Board elected to pay the dividends in cash rather than issuing PIK Shares, which is presented as a component of Net cash used in financing activities on the consolidated statements of cash flows for the years ended December 31, 2022 and 2021.

The holders of the Series A Preferred Stock are entitled to one vote per share of Class A Common Stock, on an as-converted basis, on all matters to be voted on by the Company’s shareholders. The Series A Preferred Stock COD also contains several conversion and redemption features including upon the consummation of a qualified initial public offering (as defined in the COD). Additionally, the holders of the Series A Preferred Stock are entitled to receive a cash liquidation preference in the event of a liquidation, dissolution or other winding up of the affairs of the Company, including the consolidation or merger of the Company or the sale of all or substantially all of the assets of the Company, equal to the greater of either: (i) $24.00 per outstanding share, excluding any previously issued PIK Share dividends, plus accrued and unpaid dividends, or (ii) $12.00 per outstanding share, inclusive of any previously issued PIK Share dividends, plus accrued and unpaid dividends.

As discussed in Note 18 - Subsequent Events, pursuant to the Talos Merger Agreement, immediately prior to the closing of the merger on February 13, 2023, all outstanding shares of the Company’s Series A Preferred Stock automatically converted into shares of the Company’s Class A Common Stock, per the Series A Preferred Stock COD.

Note 10 - Related Party Transactions

Bain Capital Credit

As of December 31, 2022, entities affiliated with Bain Capital Credit (“Bain”) held 45.3% of the Company’s Class A Common Stock and Series A Preferred Stock and three members of the Company’s Board are affiliated with Bain. Additionally, as of December 31, 2022, Adage Capital Management, L.P. (“Adage”) held 15.3% of the Company’s Class A Common Stock and Series A Preferred Stock.

In April 2021, the Company issued the 2026 Notes and used the net proceeds to redeem the remaining principal amount of its outstanding 2023 Notes. At the date of issuance, an entity affiliated with Bain purchased 8.3% of the Company’s 2026 Notes and prior to the redemption, an entity affiliated with Bain held 13.3% of the 2023 Notes. Additionally, at the date of issuance, Adage purchased 3.3% of the 2026 Notes and certain members of management purchased less than 1% of the 2026 Notes.

In connection with the Talos Merger Agreement, Bain, Adage, and certain other equity investors holding a majority of the outstanding shares of the Company’s Class A Common Stock and Series A Preferred Stock (collectively, the “EnVen Supporting Stockholders”) entered into several agreements with the Company and Talos (the “EnVen Support Agreements”). Pursuant to the EnVen Support Agreements, the EnVen Supporting Stockholders have agreed, among other things, to vote all shares of the Company’s Class A Common Stock and Series A Preferred Stock beneficially owned by such equity holders (i) in favor of approving the Talos Merger Agreement, the Talos Merger, and the conversion of the Company’s Series A Preferred Stock (as specified in the Talos Merger Agreement) and (ii) against any Acquisition Proposal (as defined in the Talos Merger Agreement) with respect to the Company and any other action, proposal, transaction, or agreement that could reasonably be expected to impede, interfere with, delay, postpone, or materially and adversely affect the Talos Merger.

In addition, concurrently with signing the Talos Merger Agreement, the Company has entered into Indemnity Agreements with certain former holders of equity interests of EnVen Equity Holdings, providing for indemnification for certain expenses, interest, and penalties relating to applicable tax audits.

Tax Receivable Agreement

As discussed in Note 1—Organization and Basis of Presentation—Organization, in connection with the 2015 Equity Offering, the members of EnVen Equity Holdings indirectly owned the limited liability interests of EnVen GoM and as specified in the EnVen GoM LLC Agreement had the ability to exercise their Redemption Rights at any time. Additionally, at the time of the 2015 Equity Offering, the Company also entered into a TRA with EnVen Equity Holdings. Pursuant to the TRA, the Company would be required to remit 85% of the cash tax savings, determined on a with-and-without basis, to EnVen Equity Holdings should it convert its limited liability interest of EnVen GoM into shares of the Company’s Class A Common Stock or if payments were accelerated pursuant to the terms of the TRA. The Company had the right to terminate the TRA early, in which case it would be required to make an immediate payment equal to the present value of the anticipated future tax benefits subject to the TRA, calculated based on certain assumptions and deemed events as set forth in the TRA. The TRA remained in effect until (i) EnVen Equity Holdings or any successor holders exchanged all of its limited liability interest of EnVen GoM pursuant to the Redemption Rights, discussed above, and the payment of all amounts required to be paid under the TRA and (ii) the TRA was terminated pursuant to its terms.

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 the Class B Common Stock Conversion transaction, as discussed in Note 1—Organization and Basis of Presentation—Organization. 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, which was paid in April of 2021. Therefore, the Company has no future liability associated with the TRA and has recorded the TRA Settlement as an adjustment to its Stockholders’ equity.

Note 11 - Stock-based Compensation

Incentive Award Plan

The Company has established the EnVen Energy Corporation and Energy Ventures GoM LLC 2015 Incentive Award Plan (the “2015 Incentive Plan”) which authorizes the granting of Restricted Stock, stock options, performance bonuses, and other incentive awards to eligible employees, consultants, and members of its Board. Pursuant to the 2015 Incentive Plan, the Company was authorized to award up to 2,583,301 shares of its Class A Common Stock. On December 13, 2018, the Company amended the 2015 Incentive Plan (“2015 Incentive Plan Amendment”) and all of the awards granted on or after December 13, 2018 will be granted under the 2015 Incentive Plan Amendment. Pursuant to the 2015 Incentive Plan Amendment, the Company is authorized to award up to 2,720,000 shares of its Class A Common Stock. As of December 31, 2022, the Company had 544,191 shares of its Class A Common Stock available for grant under the 2015 Incentive Plan Amendment and all incentive awards granted to date have been to employees or members of its Board.

Restricted Stock Awards and Units

The Company awards time-based and performance-based non-qualified Restricted Stock subject to the terms, restrictions, and vesting requirements defined in the restricted stock agreements. Additionally, the Company has employment agreements with certain employees with varying terms that provide for, among other things, the accelerated vesting of all non-vested equity awards upon the (i) retirement after the eligible age of 65 or (ii) termination of employment without cause (the “Accelerated Vesting Conditions”).

The Company’s Restricted Stock does not have any post-vesting restrictions, therefore, the fair value of each share of Restricted Stock on the date of the grant is determined based on the per share fair value of its Class A Common Stock on a minority, non-marketable basis. The per share fair value of the Company’s Class A Common Stock is estimated at the grant date of the shares. Refer to Note 5—Fair Value Measurements for a discussion of the fair value of the Company’s Class A Common Stock. The Monte Carlo valuations for the Restricted Stock granted during the years ended December 31, 2022 and 2021 assumed weighted-average risk-free interest rates of 1.61% and 0.3%, respectively, and weighted-average expected stock price volatility rates of 65.0% and 75.0%, respectively.

During the years ended December 31, 2022 and 2021, the aggregate fair value of the vested Restricted Stock was $31.5 million and $3.9 million, respectively, and the Company withheld 463,121 shares and 141,632 shares, respectively, of the vested Restricted Stock on behalf of the Restricted Stock holders to satisfy the related tax withholding obligations. Any shares withheld in connection with such tax withholdings will be available for new grants. Additionally, during the years ended December 31, 2022 and 2021, the Company repurchased and retired 90,675 shares and 131,405 shares of vested Restricted Stock, respectively, from current employees and members of its Board for $2.3 million and $2.0 million, respectively, the estimated aggregate fair value of the vested Restricted Stock on the dates of the repurchases. These repurchased shares are not available for new grants.

Time-based Restricted Stock

The Company awards time-based non-qualified Restricted Stock subject to the terms, restrictions, and vesting requirements defined in the restricted stock agreements. Time-based Restricted Stock contains a vesting period subject to the Restricted Stock holder continuing employment or service and generally vests in installments over a period of three years.

The Company recognizes compensation expense related to time-based Restricted Stock on a straight-line basis over the requisite service period based on the fair value of the Restricted Stock on the grant date. In accordance with ASC Topic 718, Compensation—Stock Compensation, for the time-based Restricted Stock subject to Accelerated Vesting Conditions, as discussed above, the Company considers the accelerated vesting when determining the requisite service period over which to recognize the compensation expense and utilizes the lesser of the stated service period or the period in which the Restricted Stock holder is no longer required to continue employment or service.

The following table presents the Company’s time-based Restricted Stock activity for the periods indicated:


	Time-based Restricted Stock			Weighted Average Grant Date Fair Value

Year ended December 31, 2021:
Non-vested at the beginning of the period		693,484		$	13.14
Granted		434,616		$	13.98
Vested		(354,706	)	$	14.45
Forfeitures		(14,129	)	$	12.42

Non-vested at the end of the period		759,265		$	12.82

Year ended December 31, 2022:
Non-vested at the beginning of the period		759,265		$	12.82
Granted		295,898		$	32.45
Vested		(374,519	)	$	13.69
Forfeitures		(7,815	)	$	20.40

Non-vested at the end of the period		672,829		$	20.89

During the years ended December 31, 2022 and 2021, the Company recognized compensation expense related to time-based Restricted Stock of $7.5 million and $5.1 million, respectively. As of December 31, 2022, there was $5.5 million of unrecognized compensation expense related to time-based Restricted Stock, with a weighted average remaining vesting period of 1.3 years.

As discussed in Note 18 - Subsequent Events, pursuant to the Talos Merger Agreement, immediately prior to the closing of the merger on February 13, 2023, all of the time-based Restricted Stock shares issued and outstanding vested into shares of the Company’s Class A Common Stock.

Performance-based Restricted Stock

The Company awards performance-based non-qualified Restricted Stock subject to the terms, restrictions, and vesting requirements defined in the restricted stock agreements. Performance-based Restricted Stock vests only if the Company achieves certain performance goals during a predetermined performance period and depending on the performance metric, the vesting of certain performance-based Restricted Stock is subject to the Restricted Stock holder fulfilling varying employment conditions. On a quarterly basis, the Company assesses the likelihood that the performance conditions associated with its performance-based Restricted Stock will be achieved and the expected level of achievement. When the level of a performance metric is determined, the Company considers any difference between the number of awards associated with the maximum and the actual performance level as canceled. Additionally, the Company considers any unvested performance-based Restricted Stock remaining at the end of any predetermined performance period as canceled.

The Company only begins recognizing compensation expense related to its performance-based Restricted Stock at the time the performance condition is deemed probable of occurring. Once the performance condition is deemed probable of occurring, the Company recognizes the compensation expense related to those performance-based Restricted Stock shares on a straight-line basis over the stated performance period based on the fair value of the Restricted Stock on the grant date. If necessary, the Company may adjust the compensation expense related to performance-based Restricted Stock to reflect material changes in the probability or achievement level of the metric. For the performance-based Restricted Stock subject to Accelerated Vesting Conditions, as noted above, the Company considers the accelerated vesting when determining the requisite service period over which to recognize the compensation expense and utilizes the lesser of the stated performance period or the period in which the Restricted Stock holder is no longer required to continue employment or service.

The following table presents the Company’s performance-based Restricted Stock activity for the periods indicated:


	Performance-based Restricted Stock			Weighted Average Grant Date Fair Value

Year ended December 31, 2021:
Non-vested at the beginning of the period		893,074		$	12.37
Granted		528,317		$	13.46
Vested		(95,763	)	$	8.72
Forfeitures		(25,715	)	$	14.48
Canceled		(223,507	)	$	8.72

Non-vested at the end of the period		1,076,406		$	13.51

Year ended December 31, 2022:
Non-vested at the beginning of the period		1,076,406		$	13.51
Granted		479,195		$	32.45
Vested		(890,622	)	$	21.78
Forfeitures		(10,925	)	$	22.01
Canceled		(145,334	)	$	12.18

Non-vested at the end of the period		508,720		$	16.84

A portion of the performance-based Restricted Stock granted will vest based on the achievement of certain performance metrics in future years. As of December 31, 2022, the performance metrics associated with 310,514 shares, net of forfeitures, issued in May 2021 and March 2022 have not been established; therefore, the Company cannot yet determine the grant date or the fair value of these shares and is considering the shares as issued, but not yet granted. During the year ended December 31, 2022, the baseline for a performance metric associated with 251,940 shares of performance-based Restricted Stock issued in June 2020 and May 2021 was finalized, as a result, these shares are considered granted, at their maximum performance level, during the year ended December 31, 2022 and are presented as such in the table above.

During the year ended December 31, 2022, the Company determined that certain performance metrics associated with some of its performance-based Restricted Stock are probable to be met. As a result, the Company recognized $12.5 million in compensation expense during the year ended December 31, 2022. During the year ended December 31, 2021, the Company recognized $6.1 million in compensation expense related to certain performance-based Restricted Stock.

As of December 31, 2022, there is $8.6 million of unrecognized compensation expense related to the Company’s non-vested performance-based Restricted Stock shares, which have a weighted average term of 3.3 years. Additionally, as discussed above, the performance metrics for certain of the performance-based Restricted Stock issued in May 2021 and March 2022 have not been established; therefore, the Company cannot yet determine the grant date or the related fair value and compensation expense associated with those performance-based shares.

As discussed in Note 18—Subsequent Events, pursuant to the Talos Merger Agreement, immediately prior to the closing of the merger on February 13, 2023, all of the performance-based Restricted Stock shares issued and outstanding vested into shares of the Company’s Class A Common Stock.

Stock Options

The Company had previously awarded non-qualified stock options, which represent the right to purchase its Class A Common Stock at a specified price (“Stock Options”). The Company did not grant any Stock Options during the years ended December 31, 2022 and 2021 and as of January 1, and December 31, 2022, all of the 682,650 outstanding Stock Options were vested and exercisable. As of December 31, 2022, all of the Company’s outstanding Stock Options have an exercise price of $10.00 and a weighted average remaining contractual term of 2.9 years. The Company has recognized all of the compensation expense related to its Stock Options prior to 2020.

As discussed in Note 1—Organization and Basis of Presentation—Talos Merger Agreement, the Talos Merger Agreement also addresses the treatment of the Company’s stock options. Prior to the closing of the merger, all of the outstanding Stock Options were exercised at $10.00 a share and the proceeds from the exercise were included in the cash received by the Company’s shareholders upon the closing of the merger on February 13, 2023.

Note 12 - Employee Benefit Plan

Defined-Contribution Plan

The Company has a qualified, contributory 401(k) savings plan for all eligible employees. Eligible employees may contribute up to 90% of gross compensation, up to the limits set by the Internal Revenue Service, into the plan and the Company can make matching contributions or can contribute discretionary amounts, at their determination at the end of each year. During the years ended December 31, 2022 and 2021, the Company contributed $1.2 million and $1.1 million, respectively, to the defined contribution plan.

Note 13 - Concentrations of Risk

Major Customers

During the years ended December 31, 2022 and 2021, Shell Offshore Inc. accounted for approximately 86.0% and 85.2%, respectively, of the Company’s total revenues and was the only purchaser to account for more than 10% of the Company’s total revenue during those periods. However, based on the adequate number of potential other purchasers, the Company does not believe that the loss of any major customer would have a significant effect on its results of operations or financial position.

Accounts Receivable

The Company does not require its oil and natural gas purchasers to post collateral and an inability or failure of any its significant customers to meet their obligations or their insolvency or liquidation could adversely affect its financial results. The Company evaluates the credit standing of its oil and natural gas purchasers as it deems appropriate under the circumstances, which may include reviewing a purchaser’s credit rating, latest financial information, their historical payment record, the financial ability of the purchaser’s parent company to make payment if the purchaser cannot, and undertaking the due diligence necessary to determine credit terms and credit limits.

Derivative Instruments

The Company’s use of derivative instruments exposes it to the risk that its derivative counterparties will be unable to meet their commitments under the arrangements. The Company manages this risk by using multiple counterparties, all of which are registered swap dealers that have an “investment grade” credit rating. Additionally, the Company continually monitors the creditworthiness of its derivative counterparties to determine if any credit risk adjustment is necessary to the fair values of its derivative instruments or if any nonperformance risk exists. Since all of the Company’s derivative counterparties are large financial institutions with investment-grade credit ratings, the Company believes it does not have any significant credit risk associated with its counterparties and does not currently anticipate any nonperformance from its counterparties.

Note 14 - Commitments and Contingencies

Revenue Performance Obligations

Oil and natural gas production sales contracts. All of the Company’s oil and natural gas production sales contracts are short-term in nature with a contract term of one year or less. As such, the Company has elected to utilize the practical expedient within ASC Topic 606, Revenue from Contracts with Customers (“ASC 606”) exempting it from the disclosure of the transaction price allocated to the remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Additionally, under the Company’s oil and natural gas production sales contracts, each unit of product represents a separate wholly unsatisfied performance obligation for which the variable payment relates specifically to the efforts to satisfy that performance obligation and allocating the variable consideration is consistent with the allocation objective. Therefore, the disclosure of the transaction price allocated to the remaining performance obligations for these contracts is not required under ASC 606-10-32-40.

Production handling service contracts. All of the Company’s production handling service contracts are long-term in nature with a contract term of one year or more. The transaction price for the Company’s production handling service contracts is comprised of both fixed and variable consideration, which are received monthly as the distinct service is provided. The fixed consideration typically relates to monthly minimum fees, production system operation fees, or infrastructure access fees. The variable consideration may include operating and production handling fees which are based on either contractual rates for units of production serviced or a proportionate expense fee.

As of December 31, 2022, the Company had approximately $29.5 million of remaining performance obligations related to the fixed consideration of its production handling service contracts with expected durations of less than half a year to 11 years. During the years ended December 31, 2022 and 2021, The Company recognized $2.7 million and $1.7 million, respectively, of revenue related to the fixed consideration of its production handling service contracts performance obligations. The Company expects to recognize approximately $2.8 million, $2.7 million, and $2.7 million of the remaining fixed consideration performance obligations as revenue annually over the next three years and the remaining amount allocated to those performance obligations ratably over the following 8.1 years.

Asset Retirement Obligations

Future P&A obligation escrows. Pursuant to purchase agreements executed in December 2015 and February 2016, the Company was required to deposit approximately $100.0 million into escrow accounts to use for future P&A obligation costs assumed in the acquisitions. In December 2015, the Company deposited approximately $30.0 million into escrow to fully fund one of the P&A obligations and funded the remaining $70.0 million obligation by depositing a percentage of net revenues from the acquired properties into a separate escrow account, on a quarterly basis, beginning in January 2017 until October 2021. As of October 2021, the escrow accounts were fully funded and the Company has no remaining future funding obligations. As of December 31, 2022 and 2021, these escrow accounts have a combined balance of $100.7 million, inclusive of interest earned to date, and are reflected as Restricted cash on the consolidated balance sheets.

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 Company records any changes in the current estimated credit losses related to its P&A Notes Receivable as part of Other income on the accompanying consolidated statements of operations. As of December 31, 2022 and 2021, both of the P&A Notes Receivable have fully accreted to their principal amounts of $65.1 million and are presented as such, net of related cumulative estimated credit losses, on the accompanying consolidated balance sheets. During the years ended December 31, 2022 and 2021, the Company recognized interest income of less than $0.1 million and $2.6 million, respectively.

Other obligations. The Bureau of Ocean Management and certain third-parties require the Company to post supplemental and performance bonds as a means to ensure its decommissioning obligations, such as the plugging of wells, the removal of platforms and other offshore facilities, the abandonment of offshore pipelines, and the clearing of the seafloor of obstructions. If needed, the Company may enter into arrangements with surety companies who provide such bonds on its behalf. In exchange, the Company pays an annual premium to the surety for its financial strength to extend the credit. These surety bond premiums are recognized in Prepaid expenses and other current assets on the accompanying consolidated balance sheets and are amortized over the life of the surety bonds into Interest expense on the accompanying consolidated statements of operations. During the years ended December 31, 2022 and 2021, the Company paid $5.6 million and $12.9 million, respectively, for surety bond premiums. Additionally, during each of the years ended December 31, 2022 and 2021, the Company amortized $10.7 million of the premiums into Interest expense on the accompanying consolidated statements of operations.

Notes Payable

On December 30, 2019, the Company entered into a financing agreement for payments due under a licensing agreement for seismic data, paying an initial installment of $3.0 million in the first quarter of 2020, and agreeing to pay eight quarterly installments of $2.2 million beginning on July 1, 2020 through April 1, 2022, at an imputed interest rate of 4.75%. Per the agreement, the Company paid $8.9 million of the notes payable balance during the year ended December 31, 2021 and as of December 31, 2021, the outstanding balance of this note payable was $4.4 million which is reflected as a current note payable on the accompanying consolidated balance sheet. The Company paid the remaining $4.4 million notes payable balance during the year ended December 31, 2022, which included the final installment on April 1, 2022, resulting in a zero balance as of December 31, 2022.

Legal Proceedings

From time to time, the Company could be subject to legal actions and claims arising in the ordinary course of business. It is the opinion of management that the outcome of these matters will not have a material adverse effect on the Company’s financial position or results of operations.

In June 2019, David M. Dunwoody, Jr., former President of the Company, filed a lawsuit against the Company in Texas District Court alleging that the circumstances of his resignation constituted “Good Reason” under his employment agreement dated as of November 6, 2015 (the “Employment Agreement”), and entitled him to the severance payments and benefits as set forth in his Employment Agreement for a resignation for “Good Reason.” In September 2021, the trial court entered a judgment of $12.4 million in favor of Mr. Dunwoody, inclusive of Mr. Dunwoody’s legal fees and interest, which the Company has recorded as a non-current liability on its consolidated balance sheets as of December 31, 2022 and 2021. The Company has appealed the judgment, as it disagrees with many of the trial court’s rulings and does not agree with Mr. Dunwoody’s assertion that he had “Good Reason” to resign from his employment. The Company expects the appellate process to continue for the foreseeable future.

In July 2019, the Company filed a lawsuit against Mr. Dunwoody in Delaware Chancery Court for breach of fiduciary duty and equitable fraud relating to Mr. Dunwoody’s conduct while he was President of the Company. In January 2020, the Company filed an amended complaint that added claims against Oilfield Pipe of Texas, LLC for aiding and abetting Mr. Dunwoody’s breach of his fiduciary duty and equitable fraud. The Delaware Chancery Court has scheduled the trial for July 2023. The Company may recognize additional liabilities and expenses in future periods related to this litigation with Mr. Dunwoody.

Note 15 - Leases

Office space and information technology equipment leases. The Company has several operating leases for office space and information technology equipment (“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.

The following table presents the components of the Company’s office space and IT Equipment operating lease costs during the periods indicated:


	Year Ended December 31,
	2022		2021

	(In thousands)
Office space and IT equipment operating lease costs	$	2,873	$	2,896
Variable office space and IT equipment operating lease costs		1,562		1,461

Total office space and IT equipment operating lease costs ⁽¹⁾	$	4,435	$	4,357

⁽¹⁾	None of the total office space and IT equipment operating lease costs incurred during the years ended December 31, 2022 and 2021 relate to short-term leases.

During the years ended December 31, 2022 and 2021, the Company made cash payments related to its office space and IT Equipment leases of $4.0 million and $3.8 million, respectively, which are included in its cash flows from operating activities on the accompanying consolidated statements of cash flows.

Drilling rig operating leases. 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.

The following table presents the components of the Company’s drilling rig operating leases capitalized during the periods indicated:


	Year Ended December 31,
	2022		2021

	(In thousands)
Drilling rig operating lease costs	$	12,556	$	11,717
Variable drilling rig operating lease costs		1,726		1,427

Total drilling rig operating lease costs ⁽¹⁾	$	14,282	$	13,144

⁽¹⁾

None of the total drilling rig operating lease costs incurred during the years ended December 31, 2022 and 2021 relate to short-term leases; however, the total drilling rig operating lease costs for the current period are not indicative of the Company’s current or future lease costs and obligations, as it routinely enters into short-term drilling rigs contracts to support its drilling activities. As of December 31, 2022, the Company’s short-term lease obligations were approximately $23.7 million, however, this short-term lease was cancelled early in 2023 without any penalty or cancellation costs.

Additionally, during the year ended December 31, 2021, the Company recognized $0.5 million of drilling rig operating lease costs related to P&A costs. The Company did not recognize any drilling rig operating lease costs related to P&A costs during the year ended December 31, 2022.

During the years ended December 31, 2022 and 2021, the Company made cash payments of $19.0 million and $19.8 million, respectively, related to its drilling rig operating lease costs, $15.3 million and $14.2 million, respectively, of which are included in its cash flows from investing activities on the accompanying consolidated statements of cash flows.

Total lease liabilities. As of December 31, 2022, the Company had total lease liabilities of $16.8 million on the accompanying consolidated balance sheet. To determine the present value of its future lease payments as of December 31, 2022, the Company applied a weighted average incremental borrowing rate of 5.5% and a weighted average remaining lease term of 7.0 years. During the year ended December 31, 2022, the Company recognized an additional $15.7 million in both ROU asset and lease liabilities.

As of December 31, 2022, the Company’s lease liabilities consisted of the following:


	(In thousands)
Future lease payments due:
January 1, 2023 through December 31, 2023	$	4,229
January 1, 2024 through December 31, 2024		2,272
January 1, 2025 through December 31, 2025		2,138
January 1, 2026 through December 31, 2026		2,179
January 1, 2027 through December 31, 2027		2,222
Thereafter		6,924

Total future lease payments ⁽¹⁾		19,964

Less: present value discount		(3,170	)

Total lease liabilities as of December 31, 2022	$	16,794

⁽¹⁾

As of December 31, 2022, total future lease payments include payments of $17.8 million, $1.9 million, and $0.3 million for office space, drilling rigs, and IT equipment, respectively. Payments for drilling rigs are presented on a gross basis and do not reflect the Company’s net proportionate share of such amounts, as the Company will bill other joint interest owners for their working interest share of such costs. The Company’s share of the drilling rig costs are generally capitalized as part of its oil and natural gas property balance.

Note 16 - Income Taxes

Following the consummation of the Class B Common Stock Conversion in April 2021, as discussed in Note 1—Organization and Basis of Presentation—Organization, the Company now files a consolidated tax return reporting 100% of the activity of its subsidiary, EnVen GoM, which is treated as a partnership for U.S. income tax purposes. Deferred taxes related to EnVen’s investment in EnVen GoM are recorded based upon the difference between the financial statement basis of the Company’s consolidated investment in EnVen GoM and the Company’s outside tax basis in its consolidated interest in EnVen GoM. Following the consummation of the Class B Common Stock Conversion in April 2021, as the Company consolidates its financial statements, the financial statement basis in EnVen GoM is generally equal to the net equity of EnVen GoM. The Company’s outside tax basis in EnVen GoM is computed as the sum of the Company’s contributions to EnVen GoM plus its share of allocable items of EnVen GoM taxable income less its share of allocable items of EnVen GoM tax deductions, losses, non-deductible expenses, and distributions.

For the years ended December 31, 2022 and 2021, the Company had income tax expense of $26.8 million and $11.3 million, respectively. The Company’s provision for income taxes is comprised of the following items for the periods indicated:


	Year Ended December 31,
	2022		2021
	(In thousands)
Current income tax expense:
United States federal	$	24,303	$	13,965
Louisiana		901		472

Total current income tax expense		25,204		14,437
Deferred income tax expense (benefit):
United States federal		1,637		(3,130	)

Total deferred income tax expense (benefit)		1,637		(3,130	)

Total income tax expense	$	26,841	$	11,307

The difference in the Company’s income tax provision calculations using its effective rate rates of 11.8% and 22.3% for the years ended December 31, 2022 and 2021, respectively, from the amounts calculated by applying the U.S. federal income tax rate of 21% to its pretax income from continuing operations were due to the following items for the periods indicated:


	Year Ended December 31,
	2022			2021

	(In thousands, except percentages)
Expected tax expense (benefit) provision	$	47,791		$	(10,667	)
Increase (decrease) in income taxes resulting from:
Permanent differences		2,232			765
State income taxes		711			373
Excess tax (benefit) expense from stock-based compensation		(1,456	)		424
Changes in the valuation allowance		(22,437	)		22,269
Adjustments for non-controlling interest		—			996
Reclassification of a stranded deferred tax balance⁽¹⁾		—			(3,130	)
Return to provision and other adjustments		—			277

Income tax expense	$	26,841		$	11,307

Effective tax rate		11.8	%		22.3	%

⁽¹⁾

During the year ended December 31, 2021, the Company recorded a deferred income tax benefit of $3.1 million for the recognition of a stranded deferred tax balance in Accumulated other comprehensive income associated with the credit risk adjustment on its 2023 Notes, which were repurchased in April 2021. Refer to Note 8—Long-term Debt for a further discussion of the 2023 Notes.

The components of the Company’s net deferred tax asset and liability were as follows for the periods indicated:


	December 31, 2022			December 31, 2021

	(In thousands)
Deferred tax asset:
Investment in partnership	$	—		$	22,269

Net deferred tax asset		—			22,269
Valuation allowance		—			(22,269	)

Deferred tax asset, net of valuation allowance	$	—		$	—

Deferred tax liability:
Investment in partnership	$	(1,637	)	$	—

Net deferred tax liability		(1,637	)		—

Deferred tax liability	$	(1,637	)	$	—

For the year ending December 31, 2021, the Company presents its Other comprehensive loss net of a deferred income tax benefit of $2.2 million. Additionally, the Company presents the Class B Common Stock Conversion and TRA Settlement transactions on its consolidated statement of changes in equity for the year ending December 31, 2021 net of a deferred income tax benefit of $4.5 million.

The 2019 through 2022 tax years remain open to examination by the tax jurisdictions in which the Company is subject to tax. The statute of limitations with respect to the U.S. federal and state income tax returns of the Company for the year ended December 31, 2018 and prior are closed (except to the extent any net operating loss carryovers are used in open years). Additionally, the Joint Committee on Taxation is in the process of reviewing the net operating loss carryback return for the year 2020.

Note 17 - Supplemental Cash Flow Information

The following table presents a reconciliation of cash, cash equivalents, and restricted cash reported on the accompanying consolidated statements of cash flows for the periods indicated:


	December 31,
	2022		2021		2020
	(In thousands)
Cash and cash equivalents	$	175,947	$	88,930	$	56,009
Restricted cash⁽¹⁾		100,651		100,695		89,479

Total cash, cash equivalents, and restricted cash	$	276,598	$	189,625	$	145,488

⁽¹⁾Restricted cash primarily consists of cash held in escrow for future P&A obligations, refer to Note 14—Commitments and Contingencies for a discussion of the restricted cash balances related to certain of the Company’s P&A obligations.

The following table presents non-cash investing and financing activities and the supplemental disclosure relating to cash paid for interest and income taxes during the periods indicated:


	Year Ended December 31,
	2022			2021

	(In thousands)
Non-cash investing and financing activities:
Expenditures for property and equipment in accrued liabilities and non-current liabilities	$	10,692		$	(640	)
Expenditures for unevaluated oil and natural gas leases in accrued liabilities		—			(5,879	)
Neptune Acquisition closing adjustments⁽¹⁾		464			(464	)
Changes in asset retirement obligations		34,432			31,111
Lease cost property additions		(34	)		(18	)
Series A preferred stock dividends - paid-in-kind⁽²⁾		—			(6,484	)
Series A preferred stock dividends - beneficial conversion feature ⁽³⁾		—			28,267
Supplemental disclosure:
Interest paid on debt, net of amounts capitalized	$	31,498		$	37,160
Income taxes paid ⁽⁴⁾		34,100			1,950

⁽¹⁾	Reflects the final settlement payment from BHP received in January 2022 for the Neptune Acquisition. Refer to Note 3 - Acquisitions of Oil and Natural Gas Properties for a further discussion.

⁽²⁾	In the first quarter of 2021, the Company paid the quarterly Series A Preferred Stock dividends by issuing PIK Shares. However, in the second, third, and fourth quarters of 2021 and throughout all of 2022, the Company’s Board elected to pay the dividends in cash rather than issuing PIK Shares.

⁽³⁾

Reflects the cumulative effect adjustment for the adoption ASU 2020-06 to reverse the beneficial conversion feature associated with the Company’s Series A Preferred Stock PIK Share dividends outstanding as of January 1, 2021. Refer to Note 1 - Organization and Basis of PresentationRecently Adopted Accounting Standards for a further discussion.

⁽⁴⁾	During the year ended December 31, 2022, the Company made estimated tax payments of $32.7 million in accordance with the U.S. Internal Revenue Code and its current tax projections.

Note 18 - Subsequent Events

As discussed in Note 1—Organization and Basis of Presentation—Talos Merger Agreement, on January 11, 2023, Talos announced that the SEC had declared its Registration Statement on Form S-4 related to the merger as effective and on February 8, 2023, Talos stockholders approved certain matters relating to the merger at a special meeting of the stockholders. Additionally, the Company obtained the written consents required from its shareholders to approve the merger. The transaction closed on February 13, 2023.

Pursuant to the Talos Merger Agreement, immediately prior to the closing of the merger, all outstanding shares of the Company’s Series A Preferred Stock automatically converted into shares of the Company’s Class A Common Stock and all of the time-based and performance-based Restricted Stock shares issued and outstanding vested into shares of the Company’s Class A Common Stock. Refer to Note 9—Stockholders’ Equity for a further discussion of the Company’s Series A Preferred Stock and to Note 11—Stock-based Compensation for a further discussion of the Company’s time-based and performance-based Restricted Stock.

Additionally, the Revolving Credit Facility was terminated upon the closing on the transaction on February 13, 2023. Further, Talos Production and certain of its subsidiaries entered into a supplemental indenture to the 2026 Notes which, among other things, provides for the assumption of the indebtedness in respect of the 2026 Notes by Talos Production. Refer to Note 8—Long-term Debt for a further discussion of the Company’s Revolving Credit Facility and 2026 Notes.

The Company has evaluated subsequent events from the balance sheet date as of December 31, 2022 through April 11, 2023, the date at which these consolidated financial statements were available to be issued and has determined there are no other events to disclose.

Note 19 - Supplemental Oil and Natural Gas Disclosures (Unaudited)

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration, and Development Activities

The following table presents the costs incurred in oil and natural gas acquisition, exploration, and development activities for the periods indicated:


	Year Ended December 31,
	2022		2021

	(In thousands)
Property acquisition costs:
Proved properties	$	—	$	5,831
Unproved properties, not subject to amortization		658		667

Total property acquisition costs		658		6,498
Exploration costs		6,871		4,401
Development costs		167,238		103,435

Total costs incurred	$	174,767	$	114,334

For the year ended December 31, 2022, the Company’s development costs incurred include $41.3 million of asset retirement obligations costs, revisions, and liabilities incurred. For the year ended December 31, 2021, the Company’s development costs incurred include $17.4 million of asset retirement obligations costs, revisions, and liabilities incurred. All of the Company’s proved property acquisition costs incurred for the year ended December 31, 2021 relate to the Neptune Acquisition and include $14.5 million of asset retirement obligations costs assumed in the acquisition, refer to Note 3—Acquisitions of Oil and Natural Gas Properties for a further discussion. Additionally, during the years ended December 31, 2022 and 2021, the Company capitalized $2.4 million and $2.3 million, respectively, of interest expense to unproved oil and natural gas properties related to certain significant long-term exploratory projects.

Proved Reserves

Proved reserves are those quantities of oil and natural gas, which, 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. There are numerous uncertainties inherent in estimating the quantities of proved oil and natural gas reserves and periodic revisions to estimated reserves and future cash flows may be necessary as a result of numerous factors, including reservoir performance, new drilling, oil, natural gas, and NGL prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas ultimately recovered or reserve quantities reported by other entities.

The Company’s reserve estimates as of December 31, 2022 and 2021, are based on reserve reports prepared by Netherland, Sewell & Associates, Inc. in accordance with the rules and regulations of the SEC in Regulation S-X, Rule 4-10. All of the Company’s proved reserves presented below are located in the U.S. Gulf of Mexico. The Company’s estimated proved reserves and the related net revenues and Standardized Measure were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December (“SEC Prices”). For the years ended December 31, 2022 and 2021, SEC Prices used in the calculations were $94.14 per Bbl and $66.55 per Bbl, respectively, for oil and NGL volumes and $6.36 per Bbl and $3.60 per MMBtu, respectively, for natural gas volumes. The SEC Prices for oil and NGL volumes are adjusted by field for quality, transportation fees, and market differentials and the SEC Prices for natural gas volumes are adjusted by field for energy content, transportation fees, and market differentials. These prices are held constant throughout the lives of the oil and natural gas properties. For proved reserves as of December 31, 2022 and 2021, the average SEC Prices adjusted for the differentials, as discussed above, weighted by production over the remaining lives of the oil and natural gas properties were $90.30 per Bbl and $64.58 per Bbl, respectively, for oil volumes and $8.42 per Mcf and $4.95 per Mcf, respectively, for natural gas volumes.

The following table presents the quantities of the Company’s estimated proved, proved developed, and proved undeveloped oil, natural gas, and NGL reserves and the changes in the quantities of estimated proved oil, natural gas, and NGL reserves for the periods indicated:


	Oil (MBbl)			Natural Gas (MMcf)			NGLs (MBbl)			Total (MBoe)
Proved reserves as of January 1, 2021		36,332			34,426			1,010			43,080
Revisions of previous estimates		10,935			12,618			110			13,148
Extensions and discoveries		915			577			40			1,051
Purchases of reserves		1,591			387			29			1,685
Production		(7,177	)		(7,005	)		(209	)		(8,554	)

Proved reserves as of December 31, 2021		42,596			41,003			980			50,410
Revisions of previous estimates		4,113			195			340			4,485
Extensions and discoveries		2,502			1,710			109			2,896
Production		(7,049	)		(5,921	)		(308	)		(8,344	)

Proved reserves as of December 31, 2022		42,162			36,987			1,121			49,447

Proved developed reserves:
January 1, 2021		29,876			29,977			779			35,651
December 31, 2021		36,281			36,930			854			43,290
December 31, 2022		34,468			25,717			1,036			39,790
Proved undeveloped reserves:
January 1, 2021		6,456			4,449			231			7,429
December 31, 2021		6,315			4,073			126			7,120
December 31, 2022		7,694			11,270			85			9,657

During the year ended December 31, 2022, the Company’s estimated proved reserves decreased approximately 1.0 MMBoe, primarily due to 8.3 MMBoe of production during the year ended December 31, 2022. This decrease was largely offset with positive revisions of 4.5 MMBoe, which were primarily driven by upward proved developed producing performance revisions at its core operated fields, as well as positive price revisions due to increased SEC Prices used in the determination of proved reserves at December 31, 2022 compared to December 31, 2021 and 2.9 MMBoe of additional estimated proved reserves from extensions and discoveries as a result of its successful drilling activities at its operated Lobster field and non-operated Spruance field.

During the year ended December 31, 2021, the Company added 7.3 MMBoe of estimated proved reserves, primarily due to positive revisions of 13.1 MMBoe, which include upward proved developed producing performance revisions of 6.2 MMBoe at several of its fields, as well as positive price revisions of 6.9 MMBoe due to increased SEC prices used in the estimation of proved reserves at December 31, 2021 compared to December 31, 2020. The Company also had 1.1 MMBoe of additional estimated proved reserves from extensions and discoveries as a result of its successful drilling activities at its operated Lobster field and 1.7 MMBoe of additional estimated proved reserves from the Neptune Acquisition completed in May 2021. These increases were partially offset by 8.6 MMBoe of production during the year ended December 31, 2021.

Standardized Measure of Discounted Future Net Cash Flows

The Standardized Measure is the present value, discounted at 10%, of future net cash flows from estimated proved reserves calculated using the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December (with consideration of price changes only to the extent provided by contractual arrangements). The estimated future net cash flows are reduced by projected future development, P&A, and production (excluding DD&A and any impairments of oil and natural gas properties) costs and estimated future income tax expenses.

Although the Company’s estimates of total proved reserves, development costs, and production rates were based on the best available information, the development and production of the oil and natural gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred, and production quantities may vary significantly from those used. Therefore, the Standardized Measure should not be considered to represent the Company’s estimate of the expected revenues or the fair value of its proved oil, natural gas, and NGL reserves.

The following table presents the Standardized Measure relating to the Company’s estimated proved oil and natural gas reserves for the periods indicated:


	Year Ended December 31,
	2022			2021

	(In thousands)
Future cash inflows	$	4,172,745		$	2,982,723
Future production costs		(999,608	)		(731,167	)
Future development and abandonment costs		(524,314	)		(440,282	)
Future income taxes		(521,708	)		(336,047	)

Future net cash flows		2,127,115			1,475,227
10% annual discount for estimated timing of cash flows		(500,588	)		(334,792	)

Standardized Measure	$	1,626,527		$	1,140,435

The following table presents the changes in the Standardized Measure relating to the Company’s estimated proved oil and natural gas reserves for the periods indicated:


	Year Ended December 31,
	2022			2021

	(In thousands)
Standardized Measure at the beginning of the period	$	1,140,435		$	420,896
Net change in sales prices and production costs related to future production		734,853			784,528
Changes in estimated future development and abandonment costs		(10,620	)		15,807
Sales and transfers of oil and natural gas produced, net of production costs		(588,601	)		(398,819	)
Extensions, discoveries, and other additions, net of future production and development costs		184,936			50,261
Purchases of reserves		—			3,972
Revisions of previous quantity estimates		198,557			404,430
Development and abandonment costs incurred during the period		8,866			31,540
Accretion of discount		139,678			50,071
Net change in income taxes		(131,681	)		(176,522	)
Changes in production rates, timing, and other		(49,896	)		(45,729	)

Net increase in Standardized Measure		486,092			719,539

Standardized Measure at the end of the period	$	1,626,527		$	1,140,435

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