10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

☑ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2023

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number 001-38497

 

Talos Energy Inc.

(Exact name of Registrant as specified in its Charter)

Delaware	82-3532642
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
333 Clay Street, Suite 3300 Houston, TX	77002
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (713) 328-3000

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Trading Symbol(s)	Name of Each Exchange on Which Registered
Common Stock	TALO	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☑ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ☐ No ☑

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☑	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☑

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, based on the closing price of the shares of common stock on the New York Stock Exchange on June 30, 2023, was $1,493,763,437.

The number of shares of registrant’s Common Stock outstanding as of February 21, 2024 was 158,632,597.

Portions of the registrant’s definitive proxy statement relating to the 2024 Annual Meeting of Stockholders are incorporated by reference into Part III of this report.

TABLE OF CONTENTS

		Page
GLOSSARY		3
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		5
SUMMARY RISK FACTORS		7
	PART I
Items 1 and 2.	Business and Properties	9
Item 1A.	Risk Factors	33
Item 1B.	Unresolved Staff Comments	58
Item 1C.	Cybersecurity	58
Item 3.	Legal Proceedings	59
Item 4.	Mine Safety Disclosures	60
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases Of Equity Securities	61
Item 6.	[Reserved]	62
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	63
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	80
Item 8.	Financial Statements and Supplementary Data	81
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	81
Item 9A.	Controls and Procedures	81
Item 9B.	Other Information	82
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	82
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	83
Item 11.	Executive Compensation	83
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	83
Item 13.	Certain Relationships and Related Transactions, and Director Independence	83
Item 14.	Principal Accounting Fees and Services	83
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	84
Item 16.	Form 10-K Summary	88

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GLOSSARY

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and natural gas industry:

Barrel or Bbl — One stock tank barrel, or 42 United States gallons liquid volume.

Boe — One barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate.

BOEM — Bureau of Ocean Energy Management.

BSEE — Bureau of Safety and Environmental Enforcement.

Boepd — Barrels of oil equivalent per day.

Btu — British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water one degree Fahrenheit.

CCS — Carbon capture and sequestration.

CO2 — Carbon dioxide.

Completion — The installation of permanent equipment for the production of oil or natural gas.

Deepwater — Water depths of more than 600 feet.

Developed acres — The number of acres that are allocated or assignable to producing wells or wells capable of production.

Field — An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.

GAAP — Accounting principles generally accepted in the United States of America.

Gross acres or gross wells — The total acres or wells in which the Company owns a working interest.

MBbls — One thousand barrels of crude oil or other liquid hydrocarbons.

MBblpd — One thousand barrels of crude oil or other liquid hydrocarbons per day.

MBoe — One thousand barrels of oil equivalent.

MBoepd — One thousand barrels of oil equivalent per day.

Mcf — One thousand cubic feet of natural gas.

Mcfpd — One thousand cubic feet of natural gas per day.

MMBoe — One million barrels of oil equivalent.

MMBtu — One million British thermal units.

MMcf — One million cubic feet of natural gas.

MMcfpd — One million cubic feet of natural gas per day.

Net acres or net wells — The sum of the fractional working interests the Company owns in gross acres or gross wells.

NGL — Natural gas liquid. Hydrocarbons which can be extracted from wet natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs consist primarily of ethane, propane, butane and natural gasoline.

NYMEX — The New York Mercantile Exchange.

NYMEX Henry Hub — Henry Hub is the major exchange for pricing natural gas futures on the New York Mercantile Exchange. It is frequently referred to as the Henry Hub index.

OPEC — Organization of Petroleum Exporting Countries.

Productive well — A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Proved developed reserves — In general, proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. The SEC provides a complete definition of developed oil and gas reserves in Rule 4-10(a)(6) of Regulation S-X.

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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. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Proved undeveloped reserves — In general, proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. The SEC provides a complete definition of undeveloped oil and gas reserves in Rule 4-10(a)(31) of Regulation S-X.

PV-10 — The present value of estimated future revenues, discounted at 10% annually, to be generated from the production of proved reserves determined in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to (i) non-property related expenses such as general and administrative expenses, derivatives, debt service and future income tax expense or (ii) depreciation depletion and amortization expense.

SEC — The U.S. Securities and Exchange Commission.

SEC pricing — The unweighted average first-day-of-the-month commodity price for crude oil or natural gas for each month within the 12-month period prior to the end of the reporting period, adjusted by lease for market differentials (quality, transportation, fees, energy content, and regional price differentials). The SEC provides a complete definition of prices in “Modernization of Oil and Gas Reporting” (Final Rule, Release Nos. 33-8995; 34-59192).

Shelf — Water depths of up to 600 feet.

Standardized Measure — The present value of estimated future net revenue to be generated from the production of proved reserves, determined in accordance with the rules, regulations or standards established by the SEC and the Financial Accounting Standards Board (using prices and costs in effect as of the date of estimation), less future development, production and income tax expenses, and discounted at 10% per annum to reflect the timing of future net revenue.

Undeveloped acreage — Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves.

Working interest — The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

WTI or West Texas Intermediate — A light crude oil produced in the United States with an American Petroleum Institute gravity of approximately 38-40 and the sulfur content is approximately 0.3%.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this Annual Report on Form 10-K (this “Annual Report”) includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Annual Report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Annual Report, the words “will,” “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “forecast,” “may,” “objective,” “plan” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. Forward-looking statements may include statements about:

•business strategy;

•recoverable resources, reserves and prospective storage resources;

•drilling prospects, inventories, projects and programs;

•our ability to replace the reserves that we produce through drilling and property acquisitions;

•financial strategy, liquidity and capital required for our development program and other capital expenditures;

•realized oil and natural gas prices;

•risks related to the pending and future mergers and acquisitions, such as the acquisition of QuarterNorth Energy Inc. (“QuarterNorth,” and such transaction, the “QuarterNorth Acquisition”), including the risk that we may fail to complete such transaction on the terms contemplated or at all, and/or to realize the expected benefits of any such transaction;

•timing and amount of future production of oil, natural gas and NGLs;

•our hedging strategy and results;

•future drilling and low carbon solutions plans;

•availability of pipeline connections on economic terms;

•competition, government regulations and legislative and political developments;

•our ability to obtain permits and governmental approvals;

•pending legal, governmental or environmental matters;

•our marketing of oil, natural gas and NGLs;

•our integration of acquisitions, including the QuarterNorth Acquisition, and future performance of the combined company;

•future leasehold or business acquisitions on desired terms;

•costs of developing properties;

•general economic conditions, including the impact of continued inflation and associated changes in monetary policy;

•political and economic conditions and events in foreign oil, natural gas and NGL producing countries and acts of terrorism or sabotage;

•credit markets;

•volatility in the political, legal and regulatory environments ahead of the upcoming domestic and foreign presidential elections;

•estimates of future income taxes;

•our estimates and forecasts of the timing, number, profitability and other results of wells we expect to drill and other exploration activities;

•the success of our low carbon solutions business, including as a result of any development opportunities, permitting, access to capital to finance such opportunities, the timing and amount of revenues therefrom and potential future customers;

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•the uncertainty inherent in estimating subsurface storage resources in our low carbon solutions projects;

•our ongoing strategy with respect to our Zama asset;

•uncertainty regarding our future operating results and our future revenues and expenses;

•impact of new accounting pronouncements on earnings in future periods; and

•plans, objectives, expectations and intentions contained in this Annual Report that are not historical.

We caution you that these forward-looking statements are subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility; global demand for oil and natural gas; the ability or willingness of OPEC and other state-controlled oil companies (“OPEC Plus”) to set and maintain oil production levels and the impact of any such actions; the lack of a resolution to the war in Ukraine and increasing hostilities in the Middle East, and their impact on commodity markets; the impact of any pandemic and governmental measures related thereto; lack of transportation and storage capacity as a result of oversupply, government and regulations; the effect of a possible U.S. government shutdown and resulting impact on economic conditions and delays in regulatory and permitting approvals; lack of availability of drilling and production equipment and services; adverse weather events, including tropical storms, hurricanes, winter storms and loop currents; cybersecurity threats; sustained inflation and the impact of central bank policy in response thereto; environmental risks; failure to find, acquire or gain access to other discoveries and prospects or to successfully develop and produce from our current discoveries and prospects; geologic risk; drilling and other operating risks; well control risk; regulatory changes; the uncertainty inherent in estimating reserves and in projecting future rates of production; cash flow and access to capital; the timing of development expenditures; potential adverse reactions or competitive responses to our acquisitions and other transactions; the possibility that the anticipated benefits of our acquisitions are not realized when expected or at all, including as a result of the impact of, or problems arising from, the integration of acquired assets and operations, risks associated with permitting for—and access to capital to finance—our CCS opportunities; and the other risks discussed in Part I, Item 1A. Risk Factors which are included herein.

Reserve engineering is a process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify upward or downward revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

Should one or more of the risks or uncertainties described herein occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Annual Report.

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SUMMARY RISK FACTORS

•Oil and natural gas prices are volatile. Stagnation or declines in commodity prices may adversely affect our financial condition and results of operations, cash flows, access to the capital markets and available borrowings under our Bank Credit Facility and our ability to grow.

•Future exploration and drilling results are uncertain and involve substantial costs.

•Our production, revenue and cash flow from operating activities are derived from assets that are concentrated in a single geographic region, making us vulnerable to risks associated with operating in one geographic area.

•Production periods or relatively short reserve lives for U.S. Gulf of Mexico properties may subject us to higher reserve replacement needs and may impair our ability to reduce production during periods of low oil and natural gas prices.

•Our actual recovery of reserves may substantially differ from our proved reserve estimates.

•Our acreage must be drilled before lease expirations in order to hold the acreage by production. If commodity prices become depressed for an extended period of time, it might not be economical for us to drill sufficient wells in order to hold acreage, which could result in the expiry of a portion of our acreage, which could have an adverse effect on our business.

•The marketability of our production depends mostly upon the availability, proximity and capacity of oil and natural gas gathering systems, pipelines and processing facilities.

•Inflationary issues and associated changes in monetary policy may result in increases to the cost of our goods, services and personnel, which in turn could cause our capital expenditures and operating costs to rise.

•We may be unable to pursue our CCS business, either wholly or in significant measure, which could have a material adverse effect on our business, results of operations and financial condition.

•Our inability to benefit from Section 45Q tax credits could materially reduce our ability to develop CCS projects and, as a result, may adversely impact our business, results of operations and financial condition.

•We may be unable to provide the financial assurances in the amounts and under the time periods required by BOEM if it submits future demands to cover our decommissioning obligations. If in the future BOEM issues orders to provide additional financial assurances and we fail to comply with such future orders, BOEM could elect to take actions that would materially adversely impact our operations and our properties, including commencing proceedings to suspend our operations or cancel our associated federal offshore leases.

•Our business could be negatively affected by security threats, including cybersecurity threats, terrorist attacks and other disruptions.

•Global geopolitical tensions may create heightened volatility in oil, gas and NGL prices and could adversely affect our business, financial condition and results of operations.

•We may not be in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves from our non-operated properties.

•Hedging transactions may limit our potential gains.

•Our operations may incur substantial liabilities to comply with environmental laws and regulations as well as legal requirements applicable to marine life and endangered and threatened species.

•Additional drilling laws, regulations, executive orders and other regulatory initiatives that restrict, delay or prohibit oil and natural gas exploration, development and production activities or access to locations where such activities may occur could have a material adverse effect on our business, financial condition or results of operations.

•Our oil and gas operations are subject to various international, foreign and U.S. federal, state and local governmental regulations that materially affect our operations.

•If we are forced to shut-in production, we will likely incur greater costs to bring the associated production back online, and will be unable to predict the production levels of such wells once brought back online.

•We may experience significant shut-ins and losses of production due to the effects of events outside of our control, including tropical storms and hurricanes in the U.S. Gulf of Mexico and in the shallow waters off the coast of Mexico and epidemics, outbreaks or other public health events.

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•We are upgrading our accounting system to a more recent version and, if this upgraded version proves ineffective or we experience difficulties with the migration, we may be unable to timely or accurately prepare financial reports.

•Our debt level and the covenants in our current or future agreements governing our debt, including our Bank Credit Facility, and the indentures governing our New Senior Notes, could negatively impact our financial condition, results of operations and business prospects. Our failure to comply with these covenants could result in the acceleration of our outstanding indebtedness.

•A financial crisis may impact our business and financial condition and may adversely impact our ability to obtain funding under our Bank Credit Facility or in the capital markets.

•We require substantial capital expenditures to conduct our operations and replace our production, and we may be unable to obtain needed financing on satisfactory terms necessary to fund our planned capital expenditures.

•We are a holding company that has no material assets other than our ownership of the equity interests of Talos Production Inc. Accordingly, we are dependent upon distributions from Talos Production Inc. to pay taxes, cover our corporate and other overhead expenses and pay dividends, if any, on our common stock.

•Our estimates of future asset retirement obligations may vary significantly from period to period and unanticipated decommissioning costs could materially adversely affect our current and future financial position and results of operations.

•We may not realize the anticipated benefits from our current and future acquisitions, and we may be unable to successfully integrate future acquisitions.

•Our current and future acquisitions could expose us to potentially significant liabilities, including P&A liabilities.

•Resolution of litigation could materially affect our financial position and results of operations.

•The interests of the Slim Family and its affiliates may differ from the interests of our other stockholders.

•We may not consummate the QuarterNorth Acquisition on the terms currently contemplated or at all.

•The failure to successfully integrate our business and operations with QuarterNorth in the expected time frame may adversely affect our future results.

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Part I

Items 1 and 2. Business and Properties

Overview

As used in this Annual Report and unless otherwise indicated or the context otherwise requires, references to “we,” “us,” “our,” “Talos Energy Inc.,” “Talos” and the “Company” refer to Talos Energy Inc. and its consolidated subsidiaries.

We are a publicly traded Delaware corporation and our common stock is listed on the New York Stock Exchange under the symbol “TALO.”

We are a technically driven independent exploration and production company focused on safely and efficiently maximizing long-term value through our operations, currently in the United States (“U.S.”) and offshore Mexico both through oil and gas exploration and production (“Upstream”) and the development of low carbon solutions opportunities. We leverage decades of technical and offshore operational expertise in the acquisition, exploration and development of assets in key geological trends that are present in many offshore basins around the world. We are also utilizing our expertise to develop CCS projects to help reduce industrial emissions along the coast of the U.S. Gulf of Mexico (“Gulf Coast”).

We combine our technical experience in geology, geophysics and engineering with innovative resource evaluation techniques and seismic imaging expertise to discover new resources. We rely on our operational experience to optimize our assets’ production and reserve recovery, safely and responsibly. Finally, we leverage our commercial and corporate management experience to most effectively allocate our capital to balance risk and reward, grow our business and maximize long-term stockholder value.

Business Strategy

We intend to increase stockholder value by growing our Upstream reserves, production, cash flow and future growth opportunities in a capital efficient manner while also exploring CCS opportunities. Our deep technical expertise and extensive physical operating experience also allows us to successfully manage our Upstream business and consistently make attractive acquisitions. We believe these same core competencies can be utilized to develop large-scale decarbonization projects to reduce industrial emissions.

Upstream Strategy

We maintain a large and diverse in-house technical staff focused on geology, geophysics, engineering and other technical disciplines, providing many decades of exploration and production experience in the key resource trends in which we focus. Our significant library of seismic data resources, which focuses on the U.S. Gulf of Mexico and offshore Mexico, allows our technical team to apply proprietary seismic reprocessing techniques to evaluate or re-evaluate potential resources across our asset portfolio. We also maintain deep in-house experience across our offshore operations, production operations, safety, facilities and business development teams.

Our strategic business development activities allow us to consistently identify and evaluate new opportunities through a wide range of potential avenues, including government lease sales, joint ventures and acquisitions, among others. Our proven track record of success through organic drilling opportunities frequently attracts potential drilling partners in projects that we operate, while in non-operated projects we leverage our core competencies to independently identify the best investment opportunities, review partner-proposed projects and be a value-added contributor. Our asset acquisition strategy is primarily focused on assets with a geological setting that can benefit from our ability to use our seismic database and technical expertise to re-evaluate and improve the acquired properties. Specifically, our acquisition focus areas target a variety of potential situations and sellers that are currently available in offshore basins, including single asset acquisitions, consolidation of private companies and broader asset package transactions. We seek to actively participate in government lease sales to identify and acquire attractive leasehold acreage, which in many cases has not been evaluated with the latest reprocessed seismic data, resulting in an opportunity for us to identify previously unknown drilling prospects.

We have historically focused our operations in the U.S. Gulf of Mexico because of our deep experience and technical expertise in the basin, which maintains favorable geologic and economic conditions, including multiple geologic trends, comprehensive geologic and geophysical seismic databases, extensive infrastructure and an attractive asset acquisition market. Our asset footprint, which includes operational control of several key shallow and Deepwater facilities, allows us to invest in a diverse set of opportunities ranging from in-field development to high impact exploration projects while optimizing our facilities to lower incremental operating costs structures. We also believe our operated infrastructure can be attractive to other operators looking for a host facility for their subsea tie-back projects, which allows us either to be involved in new investment opportunities or to offset the operating cost of these facilities.

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Utilizing our core competencies in conjunction with a robust and active business development effort allows us to use the following strategies to increase stockholder value:

•Continuously Optimizing our Existing Asset Base — We benefit from our proven ability to enhance and extend the life of existing projects within our portfolio. Investments in optimization projects across our asset base aim to stabilize and improve the profile of producing assets by increasing recovery, production and cash flow with typically relatively low investment capital and risk. These projects allow for subsequent investment opportunities in exploitation and exploration projects.

•Conducting Development and Near-Field Projects In and Around Our Existing Asset Footprint — We undertake asset development and exploitation drilling projects in close proximity to our existing assets as well as facilities that we either own or have access to. These projects leverage ongoing operations and existing technical knowledge of the area, often coupled with recent proprietary seismic reprocessing evaluations to provide attractive incremental investment opportunities to grow reserves, production and cash flow in well-understood areas.

•Engaging in Exploration Activities to Grow our Asset Base and Potentially Unlock Significant New Resources — We conduct exploration drilling activities across our acreage set with risk-weighted investments that could establish significant new reserves and production. These projects are intended to optimize risk and reward across our portfolio of prospective drilling opportunities by finding and developing previously undiscovered resources along existing or emerging geological trends with the most efficient deployment of capital. When successful, exploration drilling activities can organically generate material new assets for the Company.

•Utilizing Acquisitions and Other Business Development Activities to Expand our Asset Base, Opportunity Set and Value Creation Potential — We rely on our commercial and business development activities to expand our asset base through the acquisition or optimization of additional or existing properties, respectively. Commercial and business development provides a key avenue to create additional value from the acquisition of undervalued properties where we can apply our technical and operational competencies to generate upside. Additionally, we utilize business development to acquire new leaseholds, enter new projects and increase or decrease working interests in various existing projects to optimize capital planning and our targeted risk/return profile for varying business conditions. Acquisition opportunities in our basin and, more broadly, in the offshore exploration and production segment in other basins around the world, are numerous and span a wide range of lifecycle stages, sizes and geographic variables. We expect to continue utilizing acquisitions and business development to grow our business in a manner that preserves a strong and healthy credit profile as well as a diverse and high-quality asset base.

•Maintaining Safety, Sustainability and Corporate Responsibility as Key Principles for Operations Across All Areas of our Business — We are focused on maintaining high standards of safety, environmental responsibility and corporate citizenship across all elements of our business. We closely monitor safety performance and consistently take steps to improve our performance. We strive to execute our business plan while simultaneously minimizing our environmental footprint, including emissions, potential spills and other impacts. Production from the Gulf of Mexico continues to provide some of the lowest greenhouse gas (“GHG”) emissions intensity due to the nature of subsea wells and established offshore pipeline and we continue to strive to lower our GHG emissions. Finally, we aim to be a good corporate citizen in the regions and communities where we operate.

Low Carbon Solutions Strategy

Our CCS business is operated through our Talos Low Carbon Solutions (“TLCS”) subsidiary. TLCS intends to leverage its experience and technical expertise along the Gulf Coast, including subsurface engineering expertise, seismic interpretation capabilities, operations experience along the Gulf Coast and a solid track record of safety and environmentally responsible operations. The Gulf Coast is a critical industrial region with a large emissions footprint, while the underlying conventional geology in the area is believed to be ideal for carbon sequestration. TLCS intends to provide decarbonization solutions to assist industrial partners with carbon emissions capture, transportation and injection into sequestration sites in the region.

Upstream Properties

United States Gulf of Mexico

Our area of focus in the United States is the Gulf of Mexico Deepwater. Our strategy is concentrated in areas characterized by clearly defined infrastructure, well-known production history and geological well control, which reduces operational and investment risk.

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We believe our Deepwater operations in the U.S. Gulf of Mexico provide significant potential growth opportunities through our drilling program. Through our technical approach of starting with known hydrocarbon systems and applying modern seismic reprocessing techniques, we have generated a substantial inventory of Deepwater prospects that we believe are capable of delivering production growth. We primarily focus our exploitation and exploration efforts around our existing infrastructure. This subsea tie-back strategy allows for better project economics and shorter periods between discovery and production as compared to design, construction and installation of a new facility following a discovery.

As of December 31, 2023, our core areas in the United States are summarized in the illustration below:

 

The following table sets forth a summary of certain key 2023 information regarding our core areas in the United States:

	Estimated Proved Reserves
	MBoe		% Oil			% Natural Gas			% NGLs			% Proved Developed			Net Production (MBoe)		% Operated
Green Canyon		41,342		75	%		17	%		8	%		82	%		7,807		88	%
Mississippi Canyon		87,183		77	%		15	%		8	%		91	%		11,608		71	%
Shelf & Gulf Coast		24,241		51	%		42	%		7	%		75	%		4,780		60	%
Total United States		152,766		73	%		20	%		7	%		86	%		24,195		74	%

Green Canyon — Green Canyon is a Deepwater region in the Central U.S. Gulf of Mexico and is a key focus area both industry-wide and for our exploration activities. We operate several production facilities in the region including Green Canyon 18, Lobster, Prince, Neptune, and Brutus/ Glider facilities. Additionally, we have a floating production unit, the Helix Producer I (“HP-I”), that is leased from Helix Energy Solutions Group, Inc. (“Helix”).

Mississippi Canyon — Mississippi Canyon is a Deepwater region in the eastern portion of the Central U.S. Gulf of Mexico with a track record of prolific production and ongoing exploration success that continues to unlock new resources. We operate several production facilities in the region including Pompano, Amberjack, Ram Powell, Cognac and our non-operated Delta House. We are active as both an operator and non-operating partner in numerous development projects and producing fields.

Shelf and Gulf Coast — The U.S. Gulf of Mexico Shelf (the “Shelf”) and Gulf Coast area spans an enormous geographical area across the basin and provides diverse production from numerous operated production facilities. The Shelf area is a producing region of the basin with attractive redevelopment and recovery enhancement opportunities.

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Mexico

As of December 31, 2023, our area of focus in Mexico is the Block 7, Zama Unit Area segment located within the Sureste Basin, a prolific proven hydrocarbon province, in the shallow waters off the coast of Mexico’s Tabasco state. Such area is illustrated below:

 

Block 7 — On July 15, 2015, a Talos-led consortium was awarded Block 7 (“Block 7 Consortium”) with a term of thirty years, starting in September 2015, and extendable for two additional five-year periods. The Company’s participation interest in Block 7 is 35% and we are the operator. The Block 7 Consortium made a significant discovery in Block 7 after drilling the Zama-1 in 2017, less than two years after signing a production sharing contract (“PSC”) for the block with Mexico's upstream oil and gas regulator, the National Hydrocarbon Commission (“CNH”). Subsequent to the Zama-1 discovery, we drilled three additional wells to further appraise the discovery.

Upon conclusion of the three well appraisal program, we determined that the Zama Field likely extended into a nearby offshore block owned by Petróleos Mexicanos (“PEMEX”). The Block 7 Consortium and PEMEX engaged a third-party reservoir engineering firm to evaluate initial tract participation within the Zama reservoir and concluded that the Block 7 Consortium holds 49.6% of the gross interest in the Zama Field and PEMEX holds 50.4%, which resulted in us holding a 17.35% interest in the unitized Zama Field. Mexico’s Secretaría de Energía (“SENER”) has designated PEMEX as the operator of the Zama unit.

The Zama Unit Development Plan was submitted by PEMEX to CNH for formal approval in March 2023 and was approved in June 2023. Modifications to the development plan were approved by CNH in February 2024 due to a revised timeline for infrastructure development activities. Additionally, an Integrated Project Team (“IPT”) comprised of individuals from all four Zama Unit Holders has been established to manage the development and operation of Zama going forward. The IPT is designed to provide technical, operational and execution expertise, leveraging the talents from each of the Zama Unit Holders. The IPT will report to the Zama Unit Operating Committee, which includes representatives from each of the companies. We will co-lead the planning, drilling, construction, and completion of all Zama wells and co-lead the planning, execution, and delivery of Zama’s offshore infrastructure. Additionally, we will co-lead the project management office.

On September 27, 2023, we sold a 49.9% interest in Talos Energy Mexico 7, S. de R.L. de C.V. (“Talos Mexico”), a wholly owned subsidiary of the Company to Zamajal, S.A. de C.V., a wholly owned subsidiary of Grupo Carso. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures and Note 7 — Equity Method Investments for additional information.

12

Carbon Capture & Sequestration

TLCS is leveraging decades of experience with conventional geology and Gulf Coast operations to pursue the development of future CCS projects. Project opportunities are actively being evaluated along the Gulf Coast. TLCS intends to identify, lease, mature and operate future CCS project opportunities and the associated sequestration sites. Areas of development are illustrated below as of December 31, 2023:

 

Bayou Bend CCS — On March 11, 2022, Bayou Bend CCS LLC (“Bayou Bend”) executed definitive lease documentation with the Texas General Land Office, formalizing the Jefferson County carbon sequestration site located in state waters offshore Jefferson County, Texas, near the Beaumont and Port Arthur, Texas industrial corridor. Chevron U.S.A Inc. (“Chevron”), which owns a 50% membership interest in Bayou Bend, became the operator effective March 1, 2023. During March 2023, Bayou Bend expanded its storage footprint through the acquisition of onshore acreage in Chambers and Jefferson Counties, Texas located within the Houston Ship Channel, Beaumont and Port Arthur regions. Equinor ASA acquired a 25% membership interest in August 2023. As of December 31, 2023, we own a 25% membership interest in Bayou Bend. For additional information on Bayou Bend, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Equity Method Investments.

Harvest Bend CCS (formerly River Bend CCS) — In February 2022, Harvest Bend CCS LLC (“Harvest Bend”) executed two agreements to lease acreage along the Mississippi River industrial corridor for a future CCS project. The agreements, which contained right of first refusal provisions on additional acreage, will allow for sequestration sites near existing pipeline infrastructure that may be used for the project. A separate right of first refusal agreement on incremental acreage was also executed in September 2023. In October 2023, Harvest Bend executed an additional agreement to lease acreage along the Mississippi River industrial corridor and two EPA Class VI permits were filed. In November 2023, seven additional agreements were conveyed to Harvest Bend from another wholly owned TLCS subsidiary that had nearby acreage. In December 2023, Harvest Bend became a multi-member limited liability company and entered into an operating agreement with a TLCS subsidiary to be operator. As of December 31, 2023, we own a 65% membership interest in Harvest Bend and an affiliate of Storegga Limited owns the remaining equity interest. For additional information on Harvest Bend, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Equity Method Investments.

Coastal Bend CCS — Pursuant to an option agreement with the Port of Corpus Christi Authority (“PCCA”) executed in February 2022, TLCS and Howard Energy Partners (“HEP”) began pursuing commercial CCS opportunities on-site at the PCCA. On March 17, 2023, Coastal Bend CCS LLC (“Coastal Bend”) became a multi-member limited liability company. As of December 31, 2023, we own a 50% membership interest in Coastal Bend. For additional information on Coastal Bend, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Equity Method Investments.

13

Summary of Reserves

The following table summarizes our estimated proved reserves which are all located in the United States:

	Oil (MBbls)		Natural Gas (MMcf)		NGL (MBbls)		MBoe		Standardized Measure (in thousands)		PV -10 (in thousands)
Consolidated Entities:
December 31, 2023
Proved developed producing		75,132		90,279		6,440		96,619			$	2,911,256
Proved developed non-producing		23,093		51,544		3,517		35,200				388,794
Total proved developed		98,225		141,823		9,957		131,819				3,300,050
Proved undeveloped		12,590		38,048		2,016		20,947				198,768
Total proved		110,815		179,871		11,973		152,766	$	3,043,488	$	3,498,818
December 31, 2022
Proved developed producing		63,049		103,245		6,194		86,451			$	3,935,208
Proved developed non-producing		17,236		58,482		3,121		30,104				661,882
Total proved developed		80,285		161,727		9,315		116,555				4,597,090
Proved undeveloped		10,774		57,824		3,613		24,024				584,009
Total proved		91,059		219,551		12,928		140,579	$	4,368,448	$	5,181,099
December 31, 2021
Proved developed producing		70,183		108,238		7,426		95,649			$	3,073,168
Proved developed non-producing		23,237		78,204		4,366		40,637				599,010
Total proved developed		93,420		186,442		11,792		136,286				3,672,178
Proved undeveloped		14,344		49,911		2,643		25,306				253,819
Total proved		107,764		236,353		14,435		161,592	$	3,440,611	$	3,925,997

Reconciliation of Standardized Measure to PV-10

PV-10 is a non-GAAP financial measure and differs from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10%. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies without regard to the specific tax characteristics of such entities. We use this measure when assessing the potential return on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 measure and the standardized measure of discounted future net cash flows do not purport to represent the fair value of our oil and natural gas reserves.

The following table provides a reconciliation of the standardized measure of discounted future net cash flows to PV-10 of our proved reserves (in thousands):

	Year Ended December 31,
	2023		2022		2021
Consolidated Entities:
Standardized measure	$	3,043,488	$	4,368,448	$	3,440,611
Present value of future income taxes discounted at 10%		455,330		812,651		485,386
PV-10 (Non-GAAP)	$	3,498,818	$	5,181,099	$	3,925,997

14

Changes in Proved Developed Reserves

The following table discloses our estimated changes in proved developed reserves:

	Oil, Natural Gas and NGLs
	(MBoe)
Consolidated Entities:
Proved developed reserves at December 31, 2022		116,555
Changes during the year:
Production		(24,195	)
Revisions of previous estimates		(14,251	)
Additions		1,322
Acquired		42,684
Conversion to proved developed		9,704
Total proved developed reserves changes		15,264
Proved developed reserves at December 31, 2023		131,819

Our proved developed reserves at December 31, 2023 increased by 15.3 MMBoe, or 13% primarily due to:

Revisions of Previous Estimates — There was a decrease of 14.3 MMBoe from revisions of previous estimates. The revisions were primarily due to a 9.2 MMBoe decrease in reserve volumes due to the decrease in SEC Pricing of $17.47 per Bbl of oil and $4.05 per Mcf of natural gas and an additional decrease in the Phoenix field located in the Green Canyon core area due to well performance.

Acquired — Acquired proved developed reserves of 42.7 MMBoe are attributable to the acquisition of EnVen Energy Corporation (“EnVen,” and such acquisition, the “EnVen Acquisition”) located primarily in the Green Canyon and Mississippi Canyon core areas. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.

Development of Proved Undeveloped Reserves

The following table discloses our estimated proved undeveloped (“PUD”) reserve activities:

	Oil, Natural Gas and NGLs			Future Development Costs
	(MBoe)			(in thousands)
Consolidated Entities:
Proved undeveloped reserves at December 31, 2022		24,024		$	478,511
Changes during the year:
Extensions and discoveries		4,040			29,624
Revisions of previous estimates		(3,831	)		(176,869	)
Acquired		6,418			141,651
Conversion to proved developed		(9,704	)		(188,161	)
Total proved undeveloped reserves changes		(3,077	)		(193,755	)
Proved undeveloped reserves at December 31, 2023		20,947		$	284,756

Our PUD reserves at December 31, 2023 decreased by 3.1 MMBoe, or 13% primarily due to:

Extensions and Discoveries — Extensions and discoveries of 4.0 MMBoe are primarily attributable to the Brutus Field located in the Green Canyon core area.

Revisions of Previous Estimates — Downward revisions of 3.8 MMBoe are primarily due to a decrease of 3.2 MMBoe from the removal of a natural gas weighted opportunity in the Mississippi Canyon core area as a result of the change in the natural gas commodity environment.

Acquired — Acquired proved undeveloped reserves of 6.4 MMBoe are attributable to the EnVen Acquisition located primarily in the Green Canyon and Mississippi Canyon core areas. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.

Conversion to Proved Developed — Conversions of 9.7 MMBoe are attributable to successful drilling of our wells Venice and Lime Rock, which tie back to our Ram Powell facility as well as our MC 28 Mt. Hunter well in the Pompano Field, which are all located in the Mississippi core area.

15

We annually review all PUD reserves to ensure an appropriate plan for development exists. Our PUD reserves are required to be converted to proved developed reserves within five years of the date they are first booked as PUD reserves, unless the reserves are associated with an existing producing zone. Future development costs associated with our PUD reserves at December 31, 2023 totaled approximately $284.8 million, of which $131.0 million, $77.5 million and $76.2 million is attributable to our Mississippi Canyon, Green Canyon and Shelf and Gulf Coast core areas, respectively. When considering capital expenditures associated with other exploration projects and abandonment obligations, we expect to fund the development of PUD reserves using cash flows from operations and, if needed, availability under the Company’s senior reserve-based revolving credit facility (the “Bank Credit Facility”), in each future annual period prior to the five year expiration. Our 2024 drilling program includes development of PUD reserves, and the conversion rate may not be uniform due to obligatory wells, newly acquired PUD reserves and production performance targets.

Internal Controls over Reserve Estimates and Reserve Estimation Procedures

At December 31, 2023, 2022 and 2021, proved oil, natural gas and NGL reserves attributable to our net interests in oil and natural gas properties were estimated and compiled for reporting purposes by our reservoir engineers and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers and geologists, as described in further detail below.

Our policies regarding internal controls over the determination of reserves estimates require reserves quantities, reserves categorization, future producing rates, future net revenue and the present value of such future net revenue prepared using the definitions set forth in Regulation S-X, Rule 4-10(a) and subsequent SEC staff interpretations and guidance. These internal controls, which are intended to ensure reliability of our reserves estimations, include, but are not limited to, the following:

•reserve information, as well as models used to estimate such reserves, is stored on secure database applications to which only authorized personnel are given access rights consistent with their assigned job function;

•a comparison of historical expenses is made to the lease operating costs in the reserve database;

•internal reserves estimates are reviewed by well and by area by our reservoir engineers. A variance analysis by well to the previous year-end reserve report is performed;

•reserve estimates are reviewed and approved by certain members of senior management, including our President and Chief Executive Officer;

•our management requires that the independent petroleum engineers and geologists and our reserve quantities and calculation of the net present value of the reserves, collectively, vary by no more than 10% in the aggregate, in accordance with Society of Petroleum Evaluation Engineers (“SPEE”) auditing standards;

•data is transferred to NSAI through a secure file transfer protocol site; and

•material reserve variances are discussed among NSAI, as applicable, our internal reservoir engineers and our Director of Reserves to ensure the best estimate of remaining reserves.

Because these estimates depend on many assumptions, any or all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil, natural gas and NGLs that are ultimately recovered.

During the reserves audit, NSAI did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil, natural gas and NGL production, well test data, historical costs of operation and development, product prices or any agreements relating to current and future operations of the fields and sales of production. However, if in the course of the examination something came to the attention of NSAI that brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data. When compared on a well by well basis, some of our estimates are greater and some are less than the estimates of NSAI. Given the inherent uncertainties and judgments that go into estimating proved reserves, differences between internal and external estimates are to be expected. NSAI determined that its estimates of reserves have been prepared in accordance with the definitions and regulations of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions, consistent with the definition in Rule 4-10(a)(24) of Regulation S-X. NSAI issued unqualified audit opinions on our reserves as of December 31, 2023, 2022 and 2021 based upon its evaluations. NSAI concluded that our estimates of reserves were, in the aggregate, reasonable and have been prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the SPEE. The 2023 NSAI report is filed as Exhibit 99.1 to this Annual Report.

16

Technologies Used in Reserve Estimation

The SEC’s reserves rules allow the use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil, natural gas and/or NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our internal reservoir engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the estimates of our reserves is a function of:

•the quality and quantity of available data and the engineering and geological interpretation of that data;

•estimates regarding the amount and timing of future operating costs, development costs and workovers, all of which may vary considerably from actual results;

•future prices of oil, natural gas and NGLs, which may vary considerably from those mandated by the SEC; and

•the judgment of the persons preparing the estimates.

Qualifications of Primary Internal Engineer

Our Director of Reserves is the technical person primarily responsible for overseeing the preparation of our internal reserve estimates and for coordinating reserve audits conducted by NSAI. He has over 48 years of industry experience with positions of increasing responsibility, including 40 years as a reserves evaluator or manager. His further professional qualifications include a State of Texas Professional Engineering License, extensive internal and external reserve training and asset evaluation. In addition, he is an active participant in industry reserve seminars and professional industry groups, and has been a member of the Society of Petroleum Engineers for over 48 years. He reports directly to our Vice President of Corporate Development.

Drilling Activity

The following table sets forth our drilling activity:

	Exploratory and Appraisal Wells												Development Wells
	Productive(1)				Dry(2)				Total				Productive(1)				Dry(2)				Total				Total
	Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net		Gross		Net
Consolidated Entities:
Year Ended December 31, 2023
United States		3.0		1.3		5.0		2.1		8.0		3.4		7.0		3.0		—		—		7.0		3.0		15.0		6.4
Mexico		—		—		—		—		—		—		—		—		—		—		—		—		—		—
Total		3.0		1.3		5.0		2.1		8.0		3.4		7.0		3.0		—		—		7.0		3.0		15.0		6.4
Year Ended December 31, 2022
United States		—		—		1.0		1.0		1.0		1.0		6.0		2.8		—		—		6.0		2.8		7.0		3.8
Mexico		—		—		—		—		—		—		—		—		—		—		—		—		—		—
Total		—		—		1.0		1.0		1.0		1.0		6.0		2.8		—		—		6.0		2.8		7.0		3.8
Year Ended December 31, 2021
United States		—		—		2.0		1.5		2.0		1.5		5.0		2.4		—		—		5.0		2.4		7.0		3.9
Mexico		—		—		—		—		—		—		—		—		—		—		—		—		—		—
Total		—		—		2.0		1.5		2.0		1.5		5.0		2.4		—		—		5.0		2.4		7.0		3.9
Equity Method Investees:
Year Ended December 31, 2023
Mexico		—		—		—		—		—		—		—		—		—		—		—		—		—		—

(1)A productive well is an exploratory or development well found to be capable of producing either oil or natural gas in sufficient quantities to justify completion as an oil or natural gas producing well. Productive wells are included in the table in the year they were determined to be productive, as opposed to the year the well was drilled.

(2)A dry well is an exploratory or development well that is not a productive well. Dry wells are included in the table in the year they were determined not to be productive, as opposed to the year the well was drilled.

17

As of December 31, 2023, we had wells actively drilling or completing and wells suspended or awaiting completion, as follows:

	Actively Drilling or Completing								Wells Suspended or Waiting on Completion
	Exploratory				Development				Exploratory				Development
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
Consolidated Entities:
United States		—		—		—		—		1.0		0.5		1.0		0.1
Equity Method Investees:
Mexico		—		—		—		—		4.0		0.4		—		—

Productive Wells

The number of our productive wells is as follows for the year ended December 31, 2023:

	Gross		Net
Consolidated Entities:
Crude oil		259.0		191.3
Natural gas		76.0		37.7
Total(1)		335.0		229.0

(1)Includes 8.0 gross and 7.1 net wells with dual completions.

Acreage

Gross and net developed and undeveloped acreage is as follows for the year ended December 31, 2023:

	Developed Acres				Undeveloped Acres				Total Acres
	Gross		Net		Gross		Net		Gross		Net
Consolidated Entities:
United States:
Deepwater		362,000		186,247		592,712		368,238		954,712		554,485
Shelf		261,929		175,775		53,572		33,088		315,501		208,863
Total United States		623,929		362,022		646,284		401,326		1,270,213		763,348
Equity Method Investees:
Mexico(1)		—		—		3,261		572		3,261		572

(1)Gross acreage for Mexico represents the gross acreage in Block 7, which Talos Mexico has a 35% participation interest. We hold a 50.1% equity interest in Talos Mexico. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Equity Method Investments for additional information.

Undeveloped acreage is considered to be leased acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether or not such acreage contains proved reserves. Included within undeveloped acreage are leased acres (held by production under the terms of a lease) that are not within the spacing unit containing, or acreage assigned to, the productive well holding such lease. The terms of our leases on undeveloped acreage as of December 31, 2023 are scheduled to expire as shown in the table below (the terms of which may be extended by drilling and production operations):

	Consolidated Entities				Equity Method Investees
	Gross		Net		Gross		Net
2024		94,043		45,873		—		—
2025		85,046		60,921		—		—
2026		74,880		58,473		—		—
2027		92,160		44,086		—		—
2028		17,280		4,367		—		—
2029 and beyond		282,875		187,606		3,261		572
Total		646,284		401,326		3,261		572

18

Crude Oil, Natural Gas and NGL Production, Prices and Production Costs

Our production volumes, average sales prices and average production costs are as follows:

	Year Ended December 31,
	2023			2022			2021
Consolidated Entities:
Production Volumes:
Crude oil (MBbls)		18,062			14,561			16,159
Natural gas (MMcf)		26,194			32,215			32,795
NGLs (MBbls)		1,767			1,793			1,875
Total (MBoe)		24,195			21,723			23,500
Percent of MBoe from crude oil		75	%		67	%		69	%
Average Sales Price (including commodity derivatives):
Crude oil (per Bbl)	$	73.59		$	68.40		$	49.67
Natural gas (per Mcf)	$	3.32		$	5.30		$	3.11
NGLs (per Bbl)	$	18.18		$	33.20		$	26.54
Average (per Boe)	$	59.86		$	56.46		$	40.61
Average Sales Price (excluding commodity derivatives):
Crude oil (per Bbl)	$	75.17		$	93.75		$	65.86
Natural gas (per Mcf)	$	2.60		$	7.06		$	3.98
NGLs (per Bbl)	$	18.18		$	33.20		$	26.54
Average (per Boe)	$	60.26		$	76.05		$	52.96
Average Lease Operating Expense (per Boe)	$	16.10		$	14.18		$	12.07

Expenditures and Costs Incurred

For information on property development, exploration and acquisition costs, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 16 — Supplemental Oil and Gas Disclosures (Unaudited).

Title to Properties

We believe that we have satisfactory title to our oil and natural gas properties in accordance with generally accepted industry standards. Individual properties may be subject to burdens such as royalties, overriding royalties, and carried, net profits, working and other outstanding interests customary in the industry. In addition, interests may be subject to obligations or duties under applicable laws or burdens such as production payments, ordinary course liens incidental to operating agreements and for current taxes and development obligations under oil and natural gas leases. As is customary in the industry in the case of undeveloped properties, often limited investigation of record title is made at the time of acquisition. Title search investigations are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties. To the extent title opinions or other investigations reflect defects affecting such undeveloped properties, we are typically responsible for curing any such title defects at our expense.

Commodity Price Risks and Price Risk Management Activities

Production from our properties is marketed using methods that are consistent with industry practices. Sales prices for oil and natural gas production are negotiated based on factors normally considered in the industry, such as an index or spot price, price regulations, distance from the well to the pipeline, commodity quality and prevailing supply and demand conditions. We enter into derivative contracts on our oil and natural gas production primarily to stabilize cash flows and reduce the risk and financial impact of downward commodity price movements on commodity sales. For additional information regarding our commodity price risk and commodity derivative instruments, see Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Significant Customers

Oil and natural gas companies spend capital on exploration, drilling and production operations expenditures, the amount of which is generally dependent on the prevailing view of future oil and natural gas prices which are subject to many external factors which may contribute to significant volatility in future prices. We market the majority of our oil, natural gas and NGL production from the properties we operate and those we do not operate. Our customers consist primarily of major oil and gas companies, well-established oil and pipeline companies and independent oil and natural gas producers and suppliers. We perform ongoing credit evaluations of our customers and provide allowances for probable credit losses when necessary. For the year ended December 31, 2023, 54% and 21% of our oil, natural gas and NGL revenues were attributable to Shell Trading (US) Company and Valero Energy Corporation, respectively, which are the customers that individually represented 10% or more of our oil, natural gas and NGL revenues.

19

Competitive Conditions

The oil and natural gas business is highly competitive in the exploration for and acquisition of reserves, the acquisition of oil and natural gas leases, equipment and personnel required to find and produce reserves and in the gathering and marketing of oil, natural gas and NGLs. We compete with large integrated oil and natural gas companies as well as independent exploration and production companies. Certain of our competitors may have significantly more financial or other resources available to them. In addition, certain of the larger integrated companies may be better able to respond to industry changes, including price fluctuation, oil and natural gas demand and governmental regulations.

However, we believe our high quality oil-weighted production base, proven expertise in utilizing seismic technology to identify, evaluate and develop exploitation and exploration opportunities, balanced mix of assets in the U.S. Gulf of Mexico deep and shallow waters and significant operating control give us a strong competitive position relative to many of our competitors.

Seasonality of Business

Weather conditions affect the demand for, and prices of, oil and natural gas. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of the results that may be realized on an annual basis. Generally, but not always, the demand for gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers may impact general seasonal changes in demand.

Insurance Matters

Our oil and natural gas operations are subject to risks incident to the operation of oil and gas wells, including, but not limited to, uncontrolled flows of oil, gas, brine or well fluids into the environment, blowouts, cratering, mechanical difficulties, fires, explosions or other physical damage, pollution or other risks, any of which could result in substantial losses to us. In addition, our oil and natural gas properties are located in the U.S. Gulf of Mexico, which makes us more vulnerable to tropical storms, loop currents and hurricanes. These hazards can cause personal injury or loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and the suspension of operations. Damages arising from such occurrences may result in lawsuits asserting large claims. Insurance may not be sufficient or effective under all circumstances or against all hazards to which we may be subject. A successful claim for which we are not fully insured could have a material adverse effect on our financial condition, results of operations and cash flow. Although we obtain insurance against some of these risks, we cannot insure against all possible losses. As a result, any damage or loss not covered by insurance could have a material adverse effect on our financial condition, results of operations and cash flow.

We have insurance policies to cover some of our risk of loss associated with our operations, and we maintain the amount of insurance we believe is prudent. However, not all of our business activities can be insured at the levels we desire because of either limited market availability or unfavorable economics (limited coverage for the underlying cost).

Our general property damage insurance provides varying ranges of coverage based upon several factors, including well counts and the cost of replacement facilities. Our general liability insurance program provides a limit of $500.0 million for each occurrence and in the aggregate, and includes varying deductibles. Our Oil Pollution Act insurance is subject to a maximum of up to $150.0 million for each occurrence and in the aggregate, including a $100,000 retention. Coverage is provided for damage to our assets resulting from a named U.S. Gulf of Mexico windstorm; however, such coverage is subject to a maximum of $250.0 million per named windstorm and in the aggregate, and is also subject to a maximum of $15.0 million per occurrence retention dependent on location. We separately maintain an operators extra expense policy with additional coverage for an amount up to $500.0 million for U.S. Gulf of Mexico Deepwater drilling wells, $150.0 million for U.S. Gulf of Mexico Shelf drilling wells, $75.0 million for U.S. Gulf of Mexico producing and shut-in wells, $75.0 million for drilling and workover in inland waters and $25.0 million for drilling and workover in onshore fields that would cover costs involved in making a well safe after a blow-out or getting the well under control; re-drilling a well to the depth reached prior to the well being out of control or blown out; costs for plugging and abandoning the well; and costs for clean-up and containment and for damages caused by contamination and pollution. For our Mexico insurance policies, we maintain $250.0 million in operators extra expense coverage for operations and $500.0 million per occurrence and aggregate limit for general liability.

We may increase or decrease insurance coverage around our key strategic assets, including potentially purchasing catastrophic bond instruments. A portion of our highest value assets, which are located in the Phoenix Field, produce through the HP-I floating production system, which has the capability to disconnect and move away in the event of a storm, mitigating the risk of property damage.

We customarily have reciprocal agreements with our customers and vendors in which each contracting party is responsible for its respective personnel for liability related to work performed for us. Under these agreements, we generally are indemnified against third party claims related to the injury or death of our customers’ or vendors’ personnel, subject to the application of various states’ laws.

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Government Regulation

Exploration and development and the production and sale of oil, natural gas and NGLs are subject to extensive federal, state, local and foreign laws and regulations. An overview of these legal requirements is set forth below. Historically, our compliance with existing requirements has not had a material adverse effect on our financial position, results of operations or cash flows. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Because such laws and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of compliance. Although the regulatory burden increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect others in our industry with similar types, quantities and locations of production.

General Overview — Our oil and natural gas operations and CCS projects are subject to various federal, state, local and foreign laws and regulations. Generally speaking, these regulations relate to matters that include, but are not limited to:

•location of wells;

•size of drilling and spacing units or proration units;

•number of wells that may be drilled in a unit;

•unitization or pooling of oil and natural gas properties;

•drilling and casing of wells;

•issuance of permits in connection with exploration, drilling and production and CCS activities;

•well production;

•spill prevention plans;

•protection of private and public surface and ground water supplies;

•emissions permitting or limitations;

•protection of marine life and endangered species;

•use, transportation, storage and disposal of fluids and materials incidental to oil and natural gas operations;

•surface usage and the restoration of properties upon which wells have been drilled;

•calculation and disbursement of royalty payments and production taxes;

•requirements for the posting of supplemental bonds or providing other forms of financial assurance for the plugging and abandonment of wells located in the U.S. Gulf of Mexico and offshore Mexico and, following cessation of operations, the removal or appropriate abandonment of all production facilities, structures and pipelines in those areas (“P&A” or “decommissioning” obligations);

•performance of P&A obligations; and

•transportation of production.

Outer Continental Shelf (“OCS”) Regulation — Our operations on federal oil and natural gas leases in the U.S. Gulf of Mexico are subject to extensive regulation by BSEE, BOEM and the Office of Natural Resources Revenue (“ONRR”) under the purview of the U.S. Department of the Interior (“DOI”). Federal leases are awarded by BOEM based on competitive bidding with relatively standardized lease terms and require compliance with detailed BSEE and BOEM regulations and orders issued pursuant to various federal laws, including the federal Outer Continental Shelf Lands Act (“OCSLA”). For offshore operations, lessees must obtain BOEM approval for exploration, development and production plans prior to the commencement of their operations. In addition to permits required from other agencies such as the U.S. Environmental Protection Agency (“EPA”), lessees must obtain a permit from BSEE prior to the commencement of drilling and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, P&A of wells on the OCS, calculation of and valuation of production related to royalty payments, and decommissioning of facilities, structures and pipelines.

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U.S. federal offshore oil and gas leasing and permitting practices have been subject to numerous challenges, delays, and moratoriums over the last three years which has curtailed our ability to seek additional new federal leases and may continue to delay or prevent us from bidding and obtaining new federal leases. Additionally, in response to a November 2021 report from the DOI on federal oil and gas leasing and permitting practices, the Inflation Reduction Act of 2022 (the “IRA 2022”) increased onshore royalty rates to 16.7% and offshore royalty rates to no less than 16.7% but not more than 18.8% for the next ten years, thereby ensuring the full value of the leased tracts are captured. The extent to which the Biden Administration will act upon the DOI report’s other recommendations cannot be predicted at this time, but any additional action may cause delay or prevent us from obtaining new federal leases.

In January 2023, BOEM released its final environmental impact statement for Lease Sales 259 and 261 and, in March 2023, announced the results of Lease Sale 259, in which we were the high bidder on four offshore blocks, and were awarded leases on all four blocks. BOEM held Lease Sale 261 on December 20, 2023, in which we were the high bidder on thirteen offshore blocks and were awarded four leases as of February 16, 2024. As BOEM is still in its bid evaluation process, we are awaiting BOEM’s award decisions on our remaining high bids. Any reduction in the size or number of offshore blocks designated by BOEM for future leasing activities, as well as delays in BOEM awarding leases to operators either as a result of NEPA-related days or legal challenges to BOEM leasing decisions, has the potential to materially and adversely affect our business and results of operations.

Laws and regulations related to our business continually evolve and change depending on the political climate, but generally our business has experienced increased safety and environmental restrictions and permitting and performance requirements during our existence. Our operations are currently subject to rigorous standards relating to the design, operation and maintenance of blow-out preventers, real-time monitoring of Deepwater, high temperature, high pressure drilling activities, and enhanced reporting requirements.

The Biden Administration has taken a number of actions to adopt more stringent safety, permitting and performance requirements. For example, on August 23, 2023, BSEE published a final well control rule for drilling, workover, completion and decommissioning operations, revising the 2019 rule and increasing the requirements for blowout preventer systems (“BOPs”) and other well control and operations requirements. The final rule requires, among other things, that BOPs are always able to close and seal the wellbore to the well’s maximum anticipated surface pressure, failure analysis and investigations start within 90 days of an incident, failure data is reported to both a designated third party and BSEE, and independent third-party qualifications are submitted to BSEE with associated permit applications. Compliance with Biden Administration legislative, executive and regulatory actions or any other legal initiatives that impact oil and natural gas exploration, development and production activities on the OCS could result in significant costs, including increased capital expenditures and operating costs, and could adversely impact our business. Our failure to comply with legal requirements under the OCSLA, our lease or applicable regulations may ultimately result in BOEM canceling one or more of our leases, which such cancellation could adversely affect our financial condition and operations.

Furthermore, tropical storms, loop current, hurricanes and other adverse weather conditions in the U.S. Gulf of Mexico can have a significant impact on oil and natural gas operations and can result in suspended operations and significant damage to key infrastructure and extensive pollution. In an effort to reduce the potential for future damage, BOEM and BSEE have periodically issued guidance aimed at improving platform survivability by taking into account environmental and oceanic conditions in the design of platforms and related structures. More stringent, requirements could be proposed or finalized in the future, which could increase our operating costs and/or capital expenditures.

In addition, in order to cover the various decommissioning obligations of lessees on the OCS, BOEM generally requires that lessees post some form of acceptable financial assurances that such obligations will be met, such as surety bonds. The cost of such bonds or other financial assurance can be substantial, and we can provide no assurance that we can continue to obtain bonds or other surety in all cases. BOEM requires that lessees demonstrate financial strength and reliability according to its regulations and provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities on the OCS.

There has been substantial uncertainty with respect to BOEM’s financial assurance requirements in recent years and BSEE’s approach to predecessor liability for decommissioning obligations. In April 2023, BSEE published its Final Rule entitled, “Risk Management, Financial Assurance, and Loss Prevention – Decommissioning Activities and Obligations,” wherein BSEE clarified decommissioning responsibilities for RUE grant holders and formalized BSEE’s policies regarding performance by predecessors ordered to decommission OCS facilities. The final rule withdraws a rule proposed during the Trump Administration that sought to amend BSEE’s regulations requiring the agency to proceed in reverse chronological order against predecessor lessees, owners of operating rights and grant holders when requiring such entities to perform their accrued decommissioning obligations upon failure to perform by current lessees, owners, or holders. Under the final rule, BSEE may issue an order to predecessors to perform accrued decommissioning obligations, including beginning maintenance and monitoring within thirty days, designating an operator for decommissioning within ninety days, and submitting a decommissioning plan within one hundred fifty days.

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In addition, in June 2023, BOEM published a proposed rule that, if adopted as initially proposed, would substantially revise the supplemental financial assurance requirements applicable to offshore oil and gas operations. The proposed rule would change the current criteria used to determine whether OCS lease and grant holders are required to secure supplemental financial assurance. The proposed rule would no longer use the current 5-point test in determining whether an OCS lessee or grant holder is required to obtain supplemental financial assurance and instead proposes a simplified test: (1) the credit rating of the lessee and, where applicable, (2) the ratio of the value of proved oil and gas reserves of the lease to the estimated decommissioning liability associated with the reserves. Under the proposed rule, BOEM would no longer consider or rely upon the financial strength of predecessors in determining whether, or how much, supplemental financial assurance should be provided by current lessees and grant holders. BOEM would not require supplemental financial assurance above the base bond requirements in three cases: (1) where a lessee has an investment grade credit rating (i.e., a credit rating from a Nationally Recognized Statistical Ratings Organizations, or NRSRO, that is greater than or equal to either BBB- from S&P or Baa3 from Moody’s, or its equivalent, or a proxy credit rating greater than or equal to either BBB- or Baa3, as determined by the Regional Director and based upon a company’s audited financial information with an accompanying auditor’s certificate); (2) where there are multiple co-lessees on a lease and any one of those lessees meets the credit rating threshold; and (3) for any lease on which all lessees are rated below investment grade, where the value of the lease’s proved oil and gas reserves is at least three times that of the estimated decommissioning cost estimate. BOEM proposes to phase in compliance with the new requirements over a three-year period. The extended public comment period closed on September 7, 2023, and BOEM is reviewing the comments received. At this time, we cannot predict whether BOEM will adopt the final rule in its current form or at all, the timing for any final decision, or whether any changes will result from the public notice and comment process, but will continue to monitor this rulemaking. According to the Fall 2023 Unified Agenda, the final rule is expected in the second quarter of 2024.

Separately, in August 2021, BOEM published a Note to Stakeholders detailing an expansion of its supplemental financial assurance requirements currently applicable to all sole liability properties and now to certain high-risk, non-sole liability properties; namely, those properties that are inactive, where production end-of-life is fewer than five years, or with damaged infrastructure irrespective of the remaining property life of the surrounding producing assets. BOEM has stated it will prioritize non-sole liability properties where it believes that the current owner does not meet applicable requirements related to financial strength and has no co-owners or predecessors that are financially strong, as determined by BOEM.

The future cost of compliance with respect to supplemental bonding, including the obligations imposed on us, whether as current or predecessor lessee or grant holder in respect of any new, more stringent, NTLs or final rules on supplemental bonding published by BOEM under the Biden Administration, could materially and adversely affect our financial condition, cash flows and results of operations. Moreover, BOEM has the right to issue liability orders in the future, including if it determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities.

Regulation in Shallow Waters Off the Coast of Mexico — Our oil and gas operations in shallow waters off the coast of Mexico’s Tabasco state are subject to regulation by SENER, the CNH and other Mexican regulatory bodies. The CNH is responsible for, among other things, overseeing the tender procedures for awarding contracts for the exploration and production of oil and natural gas in Mexican waters, managing and supervising contracts that have been awarded, and approving exploration and production plans. The PSC that the Block 7 Consortium entered into for the development of this acreage contains terms that impose on us the duty to comply with various laws and regulations. These laws and regulations govern, among other things, the exploration and exploitation of hydrocarbons (including certain national content requirements), the treatment, conveyance, marketing, transport and storage of petroleum, and requirements for industrial safety, operational security, and facility decommissioning. Failure to comply can result in the imposition of monetary penalties, revocation of permits, rescission of the PSC, suspension of operations, and ordered decommissioning of offshore facilities and systems. The laws and regulations governing activities in the Mexican energy sector were significantly reformed in 2013, and the legal regulatory framework continues to evolve as SENER, the CNH and other Mexican regulatory bodies issue new regulations and guidance. Such regulations are subject to change, and it is possible that SENER, the CNH or other Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs and/or capital expenditures for operations in Mexican offshore shallow waters.

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Hydrocarbon Export Regulation in Mexico — Our oil and gas operations in shallow waters off the coast of Mexico’s Tabasco state are subject to regulation by SENER. Such regulations are subject to change, and it is possible that the Mexican National Agency of Industrial Safety and Environmental Protection of the Hydrocarbons Sector (“ASEA”) or other Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs and/or capital expenditures for operations in Mexican offshore waters. For example, in December 2020, SENER published regulations affecting the granting of permits for the import and export of hydrocarbons. These regulations imposed additional constraints on permit applicants, and granted SENER more discretion in issuing, modifying, and revoking those permits. Previously, such permits would have had a term of 20 years – the December 2020 regulations limit terms to 5 years, restrict extensions and add new requirements. Subsequently, in May 2021, the Mexican government amended its federal Hydrocarbons Law in a manner that is anticipated to be beneficial to PEMEX, but have an adverse impact on privately-held oil and gas energy companies including by way of example, (i) authorizing SENER and the Mexican Energy Regulatory Commission (the “CRE”) to suspend or revoke hydrocarbon permits if there is imminent danger to national security, energy security or the national economy; (ii) allowing the government to temporarily occupy the facilities of hydrocarbon permit-holders to safeguard the national interest and hand over the operation of such facilities to State-owned entities, such as PEMEX; and (iii) allowing for denial by default of applications for new permits of private companies if the authorities do not respond within 90 days. Also in May 2021, the Mexican government made a second amendment to its Hydrocarbons Law, which such amendment halts the CRE’s power to enforce asymmetric regulation in the hydrocarbon, petroleum products and petrochemical markets, which regulation obligates PEMEX to comply with certain obligations that effectively limits its market position relative to its competitors. Amparo actions are being pursued in local courts in response to these legal changes and, as interim measures, court actions suspended the December 2020 regulations in March 2021, partially suspended portions of the first amendment to the Hydrocarbons Law (such suspension including the authorization to temporarily occupy facilities of permit-holders) in May 2021 and suspended the second amendment to the Hydrocarbons Law in May 2021.

Environmental and Occupational Safety and Health Regulations

We are subject to various federal, state, local and foreign regulations concerning occupational safety and health as well as the discharge of materials into, and the protection of, the environment. Environmental laws and regulations relate to, among other things:

•assessing the environmental impact of seismic acquisition, drilling or construction activities;

•the generation, storage, transportation and disposal of waste materials;

•the emission of certain gases into the atmosphere;

•the monitoring, abandonment, reclamation and remediation of well and other sites, including sites of former operations;

•various environmental permitting requirements, such as permits for wastewater discharges;

•the development of emergency response and spill contingency plans;

•specific operating criteria addressing worker protection; and

•protection of private and public surface and ground water supplies.

Based on regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to the protection of the environment and safety and health compliance have increased over the years and it is possible such expenses will continue to increase in the future. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters, and the cost of compliance could be significant. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations, natural resource damages or the issuance of injunctive relief (including orders to cease operations). Both onshore and offshore drilling in certain areas has been opposed by environmental groups and, in certain areas, has been restricted. Additionally, President Biden has made climate change arising from GHG emissions a priority under his administration. Some environmental laws and regulations may impose strict liability, which could subject us to liability for conduct that was lawful at the time it occurred or conduct or conditions caused by prior operators or third parties. To the extent laws are enacted or other governmental action is taken that prohibits or restricts onshore or offshore drilling or imposes environmental protection requirements that result in increased costs to the oil and gas industry in general, our business and financial results could be adversely affected.

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We expect to continue making expenditures on a regular basis relating to environmental compliance. We maintain insurance coverage for spills, pollution and certain other environmental risks, although we are not fully insured against all such risks. Our insurance coverage provides for the reimbursement to us of certain costs incurred for the containment and clean-up of materials that may be suddenly and accidentally released in the course of our operations, but such insurance does not fully insure against pollution and similar environmental risks. We do not anticipate that we will be required under current environmental laws and regulations to expend amounts that will have a material adverse effect on our consolidated financial position or our results of operations. However, since environmental costs and liabilities are inherent in our operations and in the operations of companies engaged in similar businesses, and since regulatory requirements frequently change and may become more stringent under the Biden Administration including in respect of GHG emissions, there can be no assurance that material costs and liabilities will not be incurred in the future. Such costs may result in increased costs of operations and acquisitions and decreased production.

Water Discharges — Our discharges into waters of the United States are limited by the federal Clean Water Act, as amended (“CWA”), and analogous state laws. The CWA prohibits any discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States, except in compliance with permits issued by federal and state governmental agencies. These discharge permits also include monitoring and reporting obligations. Failure to comply with the CWA, including discharge limits set by permits issued pursuant to the CWA, may also result in administrative, civil or criminal enforcement actions. Violations of the CWA can result in suspension, debarment or the imposition of statutory disability, each of which prevents companies and individuals from participating in government contracts and receiving some non-procurement government benefits. The CWA also requires the preparation of oil spill response plans and spill prevention, control and countermeasure plans.

Oil Pollution Act — The Oil Pollution Act of 1990, as amended (“OPA”), holds owners and operators of offshore oil production or handling facilities, including the lessee or permittee of the area where an offshore facility is located, strictly liable for the costs of removing oil discharged into waters of the United States and for certain damages from such spills. OPA assigns joint and several strict liability, without regard to fault, to each liable party for all containment and oil removal costs and a variety of public and private damages including, but not limited to, the costs of responding to a release of oil, natural resource damages and economic damages suffered by persons adversely affected by an oil spill. Although defenses exist to the liability imposed by OPA, they are limited. OPA’s damages liability cap is currently $167.8 million; however, a party cannot take advantage of liability limits if a spill was caused by gross negligence or willful misconduct, resulted from violation of a federal safety, construction or operating regulation, or if the party failed to report a spill or cooperate fully in the clean-up. OPA also requires responsible parties to maintain evidence of financial responsibility in prescribed amounts. OPA currently requires a minimum financial responsibility demonstration of between $35 million to $150 million, based on a worst case oil spill discharge volume, for companies operating on the OCS, although BOEM may increase this amount in certain situations, but in no event greater than $150 million. From time to time, the United States Congress has proposed, but not adopted, amendments to OPA raising the financial responsibility requirements. If OPA is amended to increase the minimum level of financial responsibility, we may experience difficulty in providing financial assurances sufficient to comply with this requirement. We cannot predict at this time whether OPA will be amended or whether the level of financial responsibility required for companies operating on the OCS will be increased. In any event, if an oil discharge or substantial threat of discharge were to occur, we may be liable for costs and damages, which costs and liabilities could be material to our results of operations and financial position.

National Environmental Policy Act — The National Environmental Policy Act, as amended (“NEPA”), requires federal agencies, including the DOI, to consider the impacts their actions have on the human environment, and to prepare detailed statements for major federal actions having the potential to significantly impact the environment. These requirements can lead to additional costs and delays in permitting for operators as the DOI or its bureaus may need to prepare Environmental Assessments (“EA”) and more detailed Environmental Impact Statements (“EIS”) in support of its leasing and other activities that have the potential to significantly affect the quality of the environment. If the EA indicates that no significant impact is likely, then the agency can release a finding of no significant impact and carry on with the proposed action. Otherwise, the agency must then conduct a full-scale EIS. In July 2020, the Council on Environmental Quality (“CEQ”) under former President Trump’s Administration published a final rule modifying the NEPA including, among other things, establishing a time limit of two years for preparation of EIS statements and one year for the preparation of EAs, and also eliminating the responsibility to consider cumulative effects of a project. While the July 2020 rule modifying NEPA was subject to litigation in several federal district courts, the CEQ, under the Biden Administration, announced in October 2021, that it intended to make three significant changes to the 2020 final rule, including authorizing agencies to consider direct, indirect and cumulative effects of major federal actions including upstream and downstream GHG emissions impacts of fossil fuel projects, allowing agencies to determine the purpose and need of a project, which allows consideration of less-harmful alternatives, and affording agencies greater flexibility in crafting their own NEPA procedures, consistent with CEQ regulations, so as to meet the agencies’ and public’s needs.

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To that end, in April 2022, the CEQ issued a final rule in line with the proposed changes, a move considered as “Phase I” of the Biden Administration’s two-phased approach to modifying the NEPA. On July 28, 2023, the CEQ announced a “Phase 2” Notice of Proposed Rulemaking, the “Bipartisan Permitting Reform Implementation Rule,” which revises the implementing regulations of the procedural provisions of NEPA and implements the amendments to NEPA included in the June 3, 2023, Fiscal Responsibility Act of 2023. The public comment period for the proposed rule closed on September 29, 2023, and the final rule is expected in the second quarter of 2024. Additionally, in January 2023, the CEQ released guidance to assist federal agencies in assessing the GHG emissions and climate change effects of their proposed actions under NEPA. The CEQ’s interim guidance, effective upon publication, encourages agencies to consider, among other things, effects from upstream and downstream GHG emissions of fossil fuel projects and, in many cases, use estimates of the social costs of GHG emissions when communicating those findings to the public. The NEPA process involves public input through comment. These comments, as well as the agency’s analysis of the proposed project, can result in changes to the nature of a proposed project, such as by limiting the scope of the project or requiring resource-specific mitigation. The adequacy of the agency’s NEPA process can be challenged in federal court by process participants. This process may result in delaying the permitting and development of projects, and result in increased costs.

Endangered Species Act — The Endangered Species Act, as amended (“ESA”), restricts activities that may affect federally identified endangered and threatened species or their habitats. Additionally, the Migratory Bird Treaty Act, as amended (“MBTA”), implements various treaties and conventions between the United States and certain other nations for the protection of migratory birds. Under the MBTA, the taking, killing or possessing of migratory birds is unlawful without a permit. The U.S. Fish and Wildlife Service (“FWS”) under former President Trump issued a final rule on January 7, 2021, which notably clarifies that criminal liability under the MBTA will apply only to actions “directed at” migratory birds, its nests or its eggs; however, in October 2021, the FWS under the Biden Administration revoked the Trump Administration’s rule on incidental take and published an advanced notice of proposed rulemaking to codify a general prohibition on incidental take while establishing a process to regulate or permit exceptions to such a prohibition. On February 9, 2023, the FWS published a proposed rule that revised the requirements for an incidental take permit application. A final rule is scheduled for release in the first quarter of 2024. The Marine Mammal Protection Act, as amended (“MMPA”), similarly prohibits the taking of marine mammals without authorization. Additionally, the FWS may make determinations on the listing of species as threatened or endangered under the ESA and litigation with respect to the listing or non-listing of certain species may result in more fulsome protections for non-protected or lesser-protected species. We conduct operations on oil and natural gas leases in areas where certain species that are protected by the ESA, MBTA and MMPA are known to exist and where other species that could potentially be protected under these statutes are known to exist. The FWS or the National Marine Fisheries Service (“NMFS”) may designate critical habitat that it believes is necessary for survival of a threatened or endangered species. A critical habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit access to protected areas for oil and natural gas development. For example, in April 2019, the NMFS listed the Rice’s whale, determined to be a subspecies of the Bryde’s whale, as endangered under the ESA. On July 24, 2023, NMFS proposed to designate approximately 28,270.65 square miles of the Gulf of Mexico as critical habitat for the Rice’s whale. NMFS is currently reviewing comments and is expected to issue a final critical habitat designation for the Rice’s whale in 2024. These statutes may result in operating restrictions or a temporary, seasonal or permanent ban in affected areas. Consequently, the designation of new species or their critical habitat for protection under the ESA, MBTA, and MMPA could adversely affect our business and results of operations and increase our operating costs.

Hazardous Substances and Waste Management — The Resource Conservation and Recovery Act, as amended (“RCRA”), generally regulates the disposal of solid and hazardous wastes and imposes certain environmental cleanup obligations. Although RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy,” the EPA and state agencies may regulate these wastes as solid wastes. However, it is possible that certain oil and natural gas drilling and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Any future loss of the RCRA exclusion for drilling fluids, produced waters and related wastes could result in increased costs to manage and dispose of generated wastes. Also, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous waste.

Comprehensive Environmental Response, Compensation and Liability Act — The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on persons that are considered to have contributed to the release of a “hazardous substance” into the environment. Such “responsible persons” may be subject to joint and several liability under CERCLA for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Further, it is not uncommon for coastal landowners or other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

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Air Emissions — The Clean Air Act, as amended (“CAA”), and comparable state statutes restrict the emission of air pollutants and affect both onshore and offshore oil and natural gas operations. New facilities may be required to obtain separate construction and operating permits before construction work can begin or operations may start, and existing facilities may be required to incur capital costs in order to remain in compliance. Also, the EPA has developed, and continues to develop, more stringent regulations governing emissions of toxic air pollutants and is considering the regulation of additional air pollutants and air pollutant parameters. For example, in 2015, the EPA under the Obama Administration issued a final rule under the CAA, making the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone more stringent. The EPA is currently reconsidering a prior decision to retain the 2015 ozone standard. Any revision to the NAAQS and state implementation of the same could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits and result in increased expenditures for pollution control equipment, the costs of which could be significant.

Worker Health and Safety — The Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes regulate the protection of the health and safety of workers. The OSHA hazard communication standard requires maintenance of information about hazardous materials used or produced in operations and provision of such information to employees. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties.

Climate Change —The threat of climate change continues to attract considerable public, governmental and scientific attention in the United States and in foreign countries. President Biden has made action on climate change a priority of his administration’s agenda and laws such as the IRA 2022 advance numerous climate-related objectives. Additionally, numerous proposals have been made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHG as well as to restrict or eliminate such future emissions. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG emissions reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, the EPA has adopted regulations under the existing CAA that, among other things, impose pre-construction and operating permit requirements on certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources and implement New Source Performance Standards directing the reduction of methane from certain new, modified or reconstructed facilities in the oil and natural gas sector. Compliance with these rules or others could result in increased compliance costs on our operations.

On December 2, 2023, the EPA published its final rule establishing more stringent methane rules for new, modified, and reconstructed facilities, known as Quad Ob, as well as standards for existing sources for the first time ever, known as Quad Qc. Under the final rules, states have two years to prepare and submit their plans to impose methane emission controls on existing sources. The presumptive standards established under the final rule are generally the same for both new and existing sources and include enhanced leak detection survey requirements using optical gas imaging and other advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions, reduction of emissions by 95% through capture and control systems, zero-emission requirements for certain devices, and the establishment of a “super emitter” response program that would allow third parties to make reports to EPA of large methane emission events, triggering certain investigation and repair requirements. Fines and penalties for violations of these rules can be substantial. It is likely, however, that the final rule and its requirements will be subject to legal challenges, so we are unable to predict at this time the scope of any final regulatory requirements and the expected cost to comply with such requirements. Any increase in regulatory scope and oversight may increase compliance expenditure or mitigation costs for our operations.

At the international level, there exists the United Nations-sponsored “Paris Agreement,” which is a non-binding agreement among participating nations to limit their GHG emissions through individually-determined emissions reduction goals every five years after 2020. President Biden announced in April 2021 a new, more rigorous nationally determined emissions reduction level of 50-52% reduction from 2005 levels in economy-wide net GHG emissions by 2030. Subsequent climate conferences have resulted in pledges by the United States and others to monitor, report and reduce methane emissions (including all feasible reductions for the energy sector) and calls for accelerated efforts toward the phase out of inefficient fossil fuel subsidies. Most recently, at the 28th Conference of the Parties (“COP28”), participants signed onto an agreement to transition “away from fossil fuels in energy systems in a just, orderly and equitable manner” and increase renewable energy capacity so as to achieve net zero by 2050, although no timeline for doing so was set. The impacts of these orders, pledges and agreements, and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement and subsequent climate conferences or other international conventions cannot be predicted at this time and it is unclear what additional initiatives may be adopted or implemented that may have a negative impact on our financial condition.

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Governmental, scientific and public concern over the threat of climate change arising from GHG emissions has resulted in increasing federal political risk regarding climate change. In the United States, President Biden has issued several executive orders calling for more expansive action to address climate change and limit new oil and gas operations on federal lands and waters. See Part I, Items 1 and 2. Business and Properties — Government Regulation — Outer Continental Shelf (“OCS”) Regulation for more information. Other actions that could be pursued by the Biden Administration include more restrictive requirements for the establishment of pipeline infrastructure or the permitting of liquified natural gas (“LNG”) export facilities, as well as more stringent emissions standards for oil and gas facilities. For example, on January 26, 2024, President Biden announced a temporary pause on pending decisions on new exports of LNG to countries that the United States does not have free trade agreements with, pending Department of Energy review of the underlying analyses for authorizations. The pause is intended to provide time to integrate certain considerations, including potential energy cost increases for consumers and manufacturers and the latest assessment of the impact of GHG emissions, to ensure adequate safeguards against health risks are in place. Additionally, the IRA 2022 was signed into law in August 2022, and contains hundreds of billions of dollars in incentives for the development of renewable energy, clean fuels, electric vehicles and supporting infrastructure, and carbon capture and sequestration, among other provisions. These incentives could further accelerate the transition of the United States’ economy away from the use of fossil fuels toward lower- or zero-carbon emissions alternatives. The IRA 2022 also imposes the first ever federal fee on the GHG emissions through a methane emissions charge. Litigation risks are also increasing, as a number of cities, local governments and other plaintiffs have sought to bring suit against oil and natural gas companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors or customers by failing to adequately disclose those impacts. We are not currently a defendant in any of these lawsuits but could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.

Additionally, our access to capital may be impacted by climate change policies. Stockholders and bondholders currently invested in fossil fuel energy companies such as ours, but concerned about the potential effects of climate change, may elect in the future to shift some or all of their investments into non-fossil fuel energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices that favor “clean” power sources, such as wind and solar, making those sources more attractive, and some of them may elect not to provide funding for fossil fuel energy companies. Many of the largest U.S. banks have made “net zero” carbon emission commitments and have announced that they will be assessing financed emissions across their portfolios and taking steps to quantify and reduce those emissions. At COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. These and other developments in the financial sector could lead to some lenders restricting access to capital for or divesting from certain industries or companies, including the oil and natural gas sector, or requiring that borrowers take additional steps to reduce their GHG emissions. Additionally, there is the possibility that financial institutions will be required to adopt policies that limit funding to fossil fuel energy companies.

In late 2020, the Federal Reserve announced that it had joined the Network for Greening the Financial System (“NGFS”), a consortium of financial regulators focused on addressing climate-related risks in the financial sector, and, in September 2022, announced that six of the U.S. largest banks will participate in a pilot climate scenario analysis exercise to enhance the ability of firms and supervisors to measure and manage climate-related financial risk. The Federal Reserve released its pilot exercise in January 2023 which is designed to analyze the impact of both physical and transition risks related to climate change on specific assets of the banks’ portfolios. In October 2023, the Federal Reserve, Office of the Comptroller of the Currency and the Federal Deposit Insurance Corporation (the “FDIC”) released a finalized set of principles guiding financial institutions with $100 billion or more in assets on the management of physical and transition risks associated with climate change. While we cannot predict what additional developments may arise from these various activities, a material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for exploration, development, production, transportation, and processing activities, which could impact our business and operations. Separately, the SEC released a proposed rule in March 2022 that would establish a framework for the reporting of climate risks, targets and metrics. A final rule is anticipated to be released in the second quarter of 2024. The SEC has also announced that it is scrutinizing existing climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege that an issuer’s existing climate disclosures are misleading, deceptive or deficient. Such agency action could also increase the potential for private litigation. Relatedly, California has enacted new laws requiring additional disclosure with respect to certain climate-related risks and GHG emission reduction claims. Non-compliance with these new laws may result in the imposition of substantial fines or penalties. Other states are considering similar laws. Any new laws or regulations imposing more stringent requirements on our business related to the disclosure of climate related risks may result in reputation harms among certain stakeholders if they disagree with our approach to mitigating climate-related risks, increased compliance costs resulting from the development of any disclosures, and increased costs of and restrictions on access to capital to the extent we do not meet any climate-related expectations or requirements of financial institutions.

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Finally, some scientists have concluded that increasing concentrations of GHG emissions in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other extreme climatic events, as well as chronic shifts in temperature and precipitation patterns. Our offshore operations are particularly at risk from severe climatic events, which have the potential to cause physical damage to our assets and thus could have an adverse effect on our exploration and production operations. Additionally, changing meteorological conditions, particularly temperature, may result in changes to the amount, timing, or location of demand for energy or the products we produce. While our consideration of changing weather conditions and inclusion of safety factors in design is intended to reduce the uncertainties that climate change and other events may potentially introduce, our ability to mitigate the adverse impacts of these events depends in part on the effectiveness of our facilities and our disaster preparedness and response and business continuity planning, which may not have considered or be prepared for every eventuality.

Environmental Regulation in Shallow Waters Off the Coast of Mexico — Our oil and gas operations in shallow waters off the coast of Mexico’s Tabasco state are subject to regulation by the ASEA. We must obtain ASEA-issued permits and comply with ASEA regulations governing hydrocarbon activities, including requirements for environmental impact and risk assessments, industrial safety, waste management, water and air emissions, operational security and facility decommissioning. Failure to comply with applicable laws and regulations can result in the imposition of monetary penalties, revocation of permits, suspension of operations and ordered decommissioning of offshore facilities and systems. The laws and regulations governing the protection of health, safety and the environment from activities in the Mexican energy sector are relatively new, having been significantly reformed following the establishment of ASEA in 2014 as a result of federal constitutional amendments approved in 2013, and the legal regulatory framework continues to evolve as ASEA and other Mexican regulatory bodies issue new regulations and guidance. Such regulations are subject to change, and it is possible that ASEA or other Mexican regulatory bodies may impose new or revised requirements that could increase our environmental compliance-related operating costs and/or capital expenditures for operations in Mexican offshore shallow waters.

For example, in May 2020, the ASEA published the Industrial Safety, Operational Safety and Environmental Protection Guidelines for the Closing, Dismantling and Abandonment of Hydrocarbons Sector Facilities (the “Dismantling Guidelines”). The Dismantling Guidelines are mandatory for all hydrocarbon sector facilities that perform dismantling, abandonment and closing of hydrocarbon sector activities. The Dismantling Guidelines set out several obligations in terms of safety, reporting and risk, including establishing a closing, dismantling and/or abandonment activities program for each of the relevant phases. Additionally, during the fourth quarter of 2021, ASEA announced its implementation of a “Popular Denunciation System” that will utilize an internet-based platform to allow persons, organizations and companies to anonymously report complaints against entities and companies operating in Mexico, including in respect of safety and environmental incidents such as, for example, hydrocarbon spills and pollution events. We anticipate that ASEA will conduct investigations to substantiate the incidents identified in the new reporting system.

Under the Block 7 PSC, we are jointly and severally liable for the performance of all obligations under the PSC, including exploration, appraisal, extraction and abandonment activities and compliance with all environmental regulations, and failure to perform such obligations could result in contractual rescission of the PSC.

Federal Regulation of Sales and Transportation of Natural Gas — Our sales of natural gas are affected directly or indirectly by the availability, terms and cost of natural gas transportation. The prices and terms for access to pipeline transportation of natural gas are subject to extensive federal and state regulation. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”) and by regulations and orders promulgated under the NGA and/or NGPA by the Federal Energy Regulatory Commission (“FERC”). In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by the United States Congress and by FERC regulations. However, certain offshore gathering and transportation services we rely upon are subject to limited FERC regulation and are regulated by the states.

Pursuant to authority delegated to it by the Energy Policy Act of 2005 (“EPAct 2005”), FERC promulgated anti-manipulation regulations establishing violation enforcement mechanisms that make it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to the jurisdiction of FERC to (i) use or employ any device, scheme or artifice to defraud, (ii) make any untrue statement of a material fact or to omit to state a material fact necessary in order to make the statements made, in the light of the circumstances under which they were made, not misleading or (iii) engage in any act, practice or course of business that operates or would operate as a fraud or deceit upon any entity. The EPAct 2005 also amended the NGA and the NGPA to give FERC authority to impose civil penalties for violations of these statutes and regulations, up to $1,544,521 per violation, per day for 2024 (this amount is adjusted annually for inflation). FERC may also order disgorgement of profits and corrective action. The anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of natural gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction, which includes annual reporting requirements for entities that purchase or sell a certain volume of natural gas in a given calendar year. We believe, however, that neither the EPAct 2005 nor the regulations promulgated by FERC as a result of the EPAct 2005 will affect us in a way that materially differs from the way they affect other natural gas producers, gatherers and marketers with which we compete.

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Our sales of oil and natural gas are also subject to market manipulation and anti-disruptive requirements under the Commodity Exchange Act (“CEA”) as amended by the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”), and regulations promulgated thereunder by the U.S. Commodity Futures Trading Commission (the “CFTC”). The CFTC prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity.

The current statutory and regulatory framework governing interstate natural gas transactions is subject to change in the future, and the nature of such changes is impossible to predict. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by the United States Congress, the applicable federal agencies, or the various state legislatures, and what effect, if any, the proposals might have on our operations. The natural gas industry historically has been very heavily regulated. In the past, the federal government regulated the prices at which natural gas could be sold. Since 1978, various federal laws have been enacted that have resulted in the complete removal of all price and non-price controls for sales of domestic natural gas sold in “first sales,” which include all of our sales of our own production. However, we are subject to reporting requirements imposed by FERC. There is always some risk, however, that the United States Congress may reenact price controls in the future. Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines or impose additional reporting or other requirements upon our operations, and we cannot predict what future action FERC will take. Therefore, there is no assurance that the current regulatory approach recently pursued by FERC and the United States Congress will continue. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete.

Federal Regulation of Sales and Transportation of Crude Oil — FERC regulates the interstate pipeline of crude oil, petroleum products and other liquids, such as NGLs. Our sales of crude oil and condensate are currently not regulated and are made at negotiated prices. There is always some risk, however, that the United States Congress may reenact crude oil, petroleum products and NGL price controls in the future. We cannot predict whether new legislation to regulate crude oil, or the prices charged for crude oil might be proposed, what proposals, if any, might actually be enacted by the United States Congress or the various state legislatures and what effect, if any, the proposals might have on our operations. Additionally, such sales may be subject to certain state, and potentially federal, reporting requirements.

Our ability to transport and sell such products is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act (“ICA”), and intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. Certain regulations implemented by FERC in recent years and certain pending rulemaking and other proceedings could result in an increase in the cost of transportation service on certain petroleum products pipelines. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other crude oil and condensate producers with which we compete.

Further, interstate and intrastate common carrier oil pipelines must provide service on a non-discriminatory basis. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to other crude oil and condensate producers with which we compete.

We own an undivided interest in a pipeline that extends from South Pass Block 89 in federal waters, offshore Louisiana, to the West Delta Receiving Station in Venice, Louisiana. Although the pipeline is subject to FERC jurisdiction under the ICA, FERC has granted us a temporary waiver of the filing and reporting requirements. If the facts upon which the waiver was granted change materially, we are required to inform FERC, which may result in revocation of the waiver. If conditions change such that the pipeline no longer qualifies for a waiver, we may be subject to regulation by FERC of the rates, terms and conditions of service on the pipeline; however, these burdens generally would not affect us any differently or to any greater or lesser extent than they affect others in our industry with similar pipelines.

FERC also implements the OCSLA pertaining to transportation and pipeline issues, which requires that all pipelines operating on or across the OCS provide nondiscriminatory transportation service. We own and operate pipelines that are located in the OCS and are subject to the non-discrimination requirements in the OCSLA.

Human Capital

We have experienced significant growth in our workforce since our formation as a private equity backed start-up company with six (6) original employees in 2012 to a NYSE publicly listed company with approximately 600 employees as of December 31, 2023. Our approach to human capital management has adapted as we have matured as a company and continues to evolve as we grow our business. We strive to manage our employees in a way that supports our business strategy, underscores our entrepreneurial spirit and promotes employee development.

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Policies — Our Code of Business Conduct and Ethics addresses our commitment to providing equal opportunities in employment without regard to race, color, gender identity or expression, religion, age, national origin, citizenship status, military service or reserve or veteran status, sexual orientation, or disability. We make employment and compensation decisions based on a person’s ability to perform the tasks required by their position.

Our Human Rights Policy embodies key tenets which we expect all individuals involved in our operations to follow, such as respect for human rights; freedom of association and collective bargaining; freedom of religion, opinion, and assembly; maintaining a safe and healthy workplace; the prohibition of forced labor; prevention of human trafficking and child labor; right to a living wage; and open communication to report violations to the appropriate individuals.

Each of our Code of Business Conduct and Ethics and Human Rights Policy is overseen at the highest level by our Board of Directors (our “Board” or “Board of Directors”).

Please refer to https://www.talosenergy.com/investor-relations/Corporate-Governance-New on our website for additional information regarding our corporate policies. The policies referenced herein, and the information contained on or accessible through our website, are not incorporated by reference herein or otherwise made a part of this Annual Report or any of our other filings with the SEC.

Oversight and Management — The Company's executive leadership team, with oversight from various committees of the Board, sets the Company's human capital management philosophy and goals with the support of the human resources function which administers the Company's workforce programs.

The Compensation Committee of our Board (the “Compensation Committee”) provides oversight, subject to Board approval, of the Company’s executive compensation program, the annual incentive plan (“AIP”), the long-term incentive plan, and the overall budget for non-executive compensation. In addition, the Compensation Committee evaluates material risks related to the Company’s compensation policies and practices. The Compensation Committee also periodically assesses the Company’s compensation programs related to all employees.

The Nominating & Governance Committee of our Board (the “NGC”) reviews succession planning for the Chief Executive Officer position, monitors and reviews the development and progression of potential successors and consults with the Chief Executive Officer on senior management succession planning. The NGC reviews with management the Company’s executive succession risks.

The Safety, Sustainability and Corporate Responsibility Committee of our Board (the “SSCR Committee”) reviews the Company’s strategies, policies and procedures related to material safety matters, and reviews the Company’s major operational risks, environmental, health and safety risks, climate change and other sustainability risks, social and human capital risks, including the welfare of employees in the workplace, and the Company’s safety statistics, such as the Total Recordable Incident Rate and Significant Injury or Fatality Rate.

At the corporate level, the Vice President of Human Resources, together with our executive leadership team, is responsible for our workforce management policies and programs, reporting directly to our President and Chief Executive Officer (“CEO”), and providing regular updates to the Compensation, NCG, and SSCR Committees on human capital matters. Our President and CEO and other executive officers are accessible to all employees through town hall meetings where our President and CEO discusses corporate matters and other topics pertinent to employees, answers questions and receives employee feedback.

Workforce Composition — As of December 31, 2023, we employed approximately 600 employees located primarily in Texas, Louisiana and Mexico, approximately 320 (53%) of which are employed in our offshore operations and seven (7) of which are Mexican nationals. In addition, we supplement our workforce with independent contractors and consultants to perform various offshore and corporate services. None of our employees are represented by labor unions or covered by any collective bargaining agreement.

Safety — “Embody Integrity and Safety” is a core value and our number one priority in the operation of our business. Our focus on safety starts at the top with our Board of Directors, our President and CEO, our Executive Vice President and Head of Operations, who is directly responsible for all safety initiatives, and our Vice President of HSE, Regulatory and Compliance, who is dedicated exclusively to health, safety, and environmental matters. Workforce safety is also a key focus within our enterprise risk management assessment. Our Safety and Environmental Management System includes a stringent “Stop Work Authority” which empowers all employees and contractors to stop work immediately for any safety or environmental concern without fear of retaliation or intimidation. In addition, our behavior-based safety program and our “Keystones to Saving Lives” program are core components for effective pre-work planning and maintaining a safety-focused culture. We seek to reinforce our safety-first mindset by linking employees’ compensation to safety performance through our annual bonus plan. Offshore employees are eligible to receive an additional quarterly safety bonus based on safety results at our offshore facilities. Please refer to our 2023 Sustainability Report posted on our website for information regarding our safety governance, programs and performance.

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Recruitment, Development and Leadership Training — We take a broad approach to recruiting top talent, utilizing online recruiting platforms, referrals, universities and colleges, internships and professional recruiters to access a skilled candidate pool. We encourage employee development through an interactive performance management process to provide feedback and growth opportunities that enable employees to advance their careers and support Talos’s strategic business goals. In 2022, we launched the Leadership Development Program available to all employees with the goal of fostering dynamic and engaged leaders. In 2023, approximately 200 employees participated in this leadership training. We also reimburse for outside training and tuition for approved higher education in further support of developing our employees.

Compensation and Benefits — Our success is based on our financial performance and operational results, and we believe that our compensation program is an important driver of these goals. Our program is designed to tie compensation to corporate and individual performance and align the interests of our employees with those of our stockholders. All full-time employees are eligible for our AIP focused on attaining financial, operational and strategic goals. We also utilize long-term incentive awards to motivate and retain key talent. Please refer to the section entitled “Compensation Discussion and Analysis” in our Definitive Proxy Statement on Form DEF 14A filed with the SEC on April 5, 2023, for further compensation information on our executive compensation program and philosophy.

We also seek to attract and retain employees by offering a broad array of health and welfare benefit programs designed to meet the needs of a varied workforce. In addition, we offer matching contributions to 401(k) accounts, a company health savings account contribution, subsidized counseling, legal and financial support, a subsidy for health & fitness memberships, paid time off and leave of absence, and a work-from-home program. We also began offering a mental health plan in 2023 to support employees and their families’ mental well-being. In 2024, we expect to open an employee health clinic in our corporate offices to provide easy access for basic health needs.

Social Investment — We support our employees and the communities where we live and work through active corporate philanthropic efforts. Our employee-led community committee supports outreach programs, fundraising efforts, and community involvement events to benefit charitable organizations. In addition, we (i) provide an annual allowance to every employee that can be donated to a charitable organization of their choice, (ii) match funds raised by community committee events, (iii) budget for corporate contributions to charitable organizations and (iv) provide a paid volunteer day off for each employee each year.

Available Information

We make our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, all amendments to those reports, and all other information filed with or furnished to the SEC available, free of charge, through our website, https://www.talosenergy.com, as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. The filings are also available by accessing the SEC’s website at https://www.sec.gov.

We voluntarily publish annual sustainability reports which are available free of charge on our corporate website at: https://www.talosenergy.com/sustainability/. Information included in these sustainability reports is not incorporated into this Annual Report or in any other report or document we file with the SEC.

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Item 1A. Risk Factors

Certain factors may have a material adverse effect on our business, financial condition, and results of operations. You should consider carefully the risks and uncertainties described below, in addition to other information contained in this Annual Report, including our Consolidated Financial Statements and related notes. The risks and uncertainties described below are not the only ones we face. Additional risks and uncertainties that we are unaware of, or that we currently believe are not material, may also become important factors that adversely affect our business. If any of the following risks actually occur, our business, financial condition, results of operations and future prospects could be materially and adversely affected. In that event, the trading price of our common stock could decline, and you could lose part or all of your investment.

Risks Related to our Business and the Oil and Natural Gas Industry

Oil and natural gas prices are volatile. Stagnation or declines in commodity prices may adversely affect our financial condition and results of operations, cash flows, access to the capital markets and available borrowings under our Bank Credit Facility and our ability to grow.

Our revenues, cash flows, profitability and future rate of growth substantially depend upon the market prices of oil and natural gas. Prices affect our cash flows available for capital expenditures and our ability to access funds under our Bank Credit Facility and through the capital markets. The amount available for borrowing under our Bank Credit Facility is subject to a borrowing base, which is determined by the lenders taking into account our estimated proved reserves and is subject to periodic redeterminations based on pricing models to be determined by the lenders at such time. Further, because we use the full cost method of accounting for our oil and gas operations, we perform a ceiling test each quarter, and the risk that we are required to write-down the carrying value of oil and natural gas properties increases when oil and natural gas prices are low or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated proved reserves or our undeveloped property values, or if estimated future development costs increase. Volatility in commodity prices, poor conditions in the global economic markets and other factors could cause us to record additional write-downs of our oil and natural gas properties and other assets in the future, and incur additional charges against future earnings. Any required write-downs or impairments could materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

In addition, significant or extended price declines may also adversely affect the amount of oil and natural gas that we can economically produce. A reduction in production and/or the prices we receive for our production could result in a shortfall in our expected cash flows and require us to reduce our capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively impact our ability to replace our production and our future rate of growth.

The markets for oil and natural gas have been volatile historically and are likely to remain volatile in the future. For example, during the period January 1, 2021 through December 31, 2023, the daily NYMEX WTI crude oil price per Bbl ranged from a low of $47.47 to a high of $123.64, and the daily NYMEX Henry Hub natural gas price per MMBtu ranged from a low of $1.74 to a high of $23.86. Subsequent to December 31, 2023, NYMEX WTI crude oil and NYMEX Henry Hub natural gas prices recorded daily lows of $70.62 per Bbl and $1.61 per MMBtu, respectively.

The prices we receive for our oil and natural gas depend upon many factors beyond our control, including, among others:

•changes in domestic and global supply of and demand for oil and natural gas;

•market uncertainty;

•level of consumer product demands;

•the cost of exploring for, developing and producing oil and natural gas;

•changes in climate, weather and natural disasters such as hurricanes and other adverse climatic conditions;

•the impact of applicable market differentials, including those relating to quality, transportation, fees, energy content and regional pricing;

•domestic and foreign governmental actions, regulations and taxes;

•price and availability of alternative fuels and competing forms of energy;

•political and economic conditions in oil and natural gas producing regions, particularly in the Middle East, Russia, South America and Africa;

•armed conflicts and hostilities such as Russia’s ongoing war in Ukraine and increasing hostilities in Israel and the Middle East;

•the occurrence or threat of epidemic or pandemic diseases and other public health events;

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•actions by OPEC Plus and other significant producers and governments relating to oil and natural gas price and production controls;

•volatility in the political, legal and regulatory environments ahead of the upcoming U.S. and Mexico presidential elections;

•U.S. and foreign supply of oil and natural gas;

•price and quantity of oil and natural gas imports and exports;

•the level of global oil and natural gas exploration and production and inventories;

•localized supply and demand fundamentals and transportation availability;

•infrastructure availability and constraints such as capacity of processing, gathering, storage and transportation facilities;

•speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;

•price and availability of competitors’ supplies of oil and natural gas;

•technological advances affecting energy consumption; and

•overall economic conditions worldwide.

These factors make it very difficult to predict future commodity price movements with any certainty. Substantially all of our oil and natural gas sales are made in the spot market or pursuant to contracts based on spot market prices and are not long-term fixed price contracts. Further, oil prices and natural gas prices do not necessarily fluctuate in direct relation to each other. Because oil, natural gas and NGLs accounted for approximately 73%, 20%, and 7%, respectively, of our estimated proved reserves as of December 31, 2023, and approximately 75%, 18%, and 7%, respectively, of our 2023 production on an MBoe basis, our financial results are sensitive to movements in oil, natural gas and NGL prices.

Future exploration and drilling results are uncertain and involve substantial costs.

Drilling for oil and natural gas involves numerous risks including the risk that we may not encounter commercially productive reservoirs. The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

•unexpected drilling conditions;

•pressure or irregularities in formations;

•equipment failures or accidents;

•inflation in exploration and drilling costs;

•fires, explosions, blowouts or surface cratering;

•lack of, or disruption in, access to infrastructure and transportation;

•lack of available skilled labor; and

•shortages or delays in the availability of services or delivery of equipment.

Our production, revenue and cash flow from operating activities are derived from assets that are concentrated in a single geographic region, making us vulnerable to risks associated with operating in one geographic area.

We currently operate in a concentrated geographic region, in the U.S. Gulf of Mexico and in the shallow waters off the coast of Mexico. As such, the success and profitability of our operations may be disproportionately exposed to the effect of regional conditions such as:

•severe weather, such as hurricanes, winter storms, loop currents, tornadoes and other adverse climatic conditions;

•changes in state or regional laws and regulations affecting our operations (including regulations that may, in certain circumstances, impose strict liability for pollution damage or require posting substantial bonds to address decommissioning and P&A costs) and interruption or termination of operations by governmental authorities based on environmental, safety or other considerations;

•local price fluctuations and other regional supply and demand factors, including availability of gathering, pipeline, transportation and storage capacity constraints;

•production delays or decreases in the region;

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•limited potential customers;

•infrastructure capacity and availability of rigs, equipment, oil field services, supplies and labor;

•changes in the status of pipelines that we depend on for transportation of our production to the marketplace;

•changes in guidelines issued by BOEM related to financial assurance requirements to cover decommissioning obligations for operations on the OCS; and/or

•changes imposed as a result of litigation or by a new presidential administration or by Congress in the United States that may result in added restrictions and delays or prohibitions in offshore oil and natural gas exploration and production activities, including with respect to leasing, permitting, site development or operation in federal waters or hydraulic fracturing.

Because all or a number of our properties could experience many of the same conditions at the same time, these conditions may have a relatively greater impact on our results of operations than they might have on other producers who have properties over a wider geographic area.

Production periods or relatively short reserve lives for U.S. Gulf of Mexico properties may subject us to higher reserve replacement needs and may impair our ability to reduce production during periods of low oil and natural gas prices.

Substantially all of our operations are in the U.S. Gulf of Mexico. As a result, our reserve replacement needs from new prospects may be greater than those of other companies with longer-life reserves in other producing areas. Our future oil and natural gas production is highly dependent upon finding and/or acquiring additional reserves at a unit cost that is sustainable at prevailing commodity prices.

Exploring for, developing or acquiring reserves is capital intensive and uncertain. We may not be able to economically find, develop or acquire additional reserves or make the necessary capital investments if our cash flows from operations decline or external sources of capital become limited or unavailable. Our need to generate revenues to fund ongoing capital commitments and/or repay debt may limit our ability to slow or shut-in production from producing wells during periods of low prices for oil and natural gas. We cannot assure you that our future exploitation, exploration, development and acquisition activities will result in additional proved reserves or that we will be able to drill productive wells at acceptable costs. Further, current market conditions may adversely impact our ability to obtain financing to fund acquisitions, and further lower the level of activity and depressed values in the oil and natural gas property sales market.

Our actual recovery of reserves may substantially differ from our proved reserve estimates.

Reserve estimation is a subjective and complex process that requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data to estimate volumes to be recovered from underground accumulations of oil and natural gas that cannot be directly measured. These estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Our interpretations of the rules governing the estimation of proved reserves could differ from the interpretation of staff members of regulatory authorities resulting in estimates that could be challenged by these authorities.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves will most likely vary from those estimated. Any significant variance in these factors could materially affect the estimated quantities and present value of reserves. Our properties may also be susceptible to hydrocarbon drainage from production by other operators on adjacent properties. In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development, prevailing oil and natural gas prices and other factors, many of which are beyond our control. See Part I, Items 1 and 2. Business and Properties—Summary of Reserves for further discussion on 2023 changes in estimates of our proved reserves.

You should not assume that any present value of future net cash flows from our proved reserves represents the market value of our estimated oil and natural gas reserves. We base the estimated discounted future net cash flows from our proved reserves at December 31, 2023 on historical 12-month average prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues are affected by factors such as:

•the amount and timing of capital expenditures and decommissioning costs;

•the rate and timing of production;

•changes in governmental legislation, regulations or taxation;

•volume, pricing and duration of our oil and natural gas hedging contracts;

•supply of and demand for oil and natural gas;

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•actual prices we receive for oil and natural gas; and

•our actual operating costs in producing oil and natural gas.

The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties affects the timing of actual future net cash flows from reserves, and thus their actual present value. In addition, the 10% discount factor that we use to calculate the net present value of future net revenues and cash flows may not necessarily be the most appropriate discount factor based on our cost of capital in effect from time to time and the risks associated with our business and the oil and natural gas industry in general.

At December 31, 2023, approximately 14% of our estimated proved reserves (by volume) were undeveloped and approximately 23% were non-producing. Any or all of our PUD or proved developed non-producing reserves may not be ultimately developed or produced. Furthermore, any or all of our undeveloped and developed non-producing reserves may not be ultimately produced during the time periods we plan or at the costs we budget, which could result in the write-off of previously recognized reserves. Recovery of undeveloped reserves generally requires significant capital expenditures and successful drilling or waterflood operations. Our reserve estimates include the assumptions that we incur capital expenditures to develop these undeveloped reserves and the actual costs and results associated with these properties may not be as estimated. Any material inaccuracies in these reserve estimates or underlying assumptions materially affects the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.

Our acreage must be drilled before lease expirations in order to hold the acreage by production. If commodity prices become depressed for an extended period of time, it might not be economical for us to drill sufficient wells in order to hold acreage, which could result in the expiry of a portion of our acreage, which could have an adverse effect on our business.

Our leases may expire unless production is established as required by leases covering undeveloped acres. Our drilling plans for areas not held by production are subject to change based upon various factors. As of December 31, 2023, approximately 53% of our net acreage was undeveloped acres. See Part I, Items 1 and 2. Business and Properties—Acreage for further discussion. Many of these factors are beyond our control, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. On the acreage that we do not operate, we have less control over the timing of drilling, and therefore there is additional risk of expirations occurring in those acreages.

The marketability of our production depends mostly upon the availability, proximity and capacity of oil and natural gas gathering systems, pipelines and processing facilities.

The marketability of our production depends upon the availability, proximity, operation and capacity of oil and natural gas gathering systems, pipelines and processing facilities. The lack of availability or capacity of this infrastructure could result in the shut-in of producing wells or delays or discontinuance of development plans for our properties. The disruption of these gathering systems, pipelines and processing facilities due to maintenance and/or weather could negatively impact our ability to market and deliver our products. Federal, state, and local regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand could adversely affect our ability to produce and market our oil and natural gas. If market factors change dramatically, the financial impact could be substantial. The availability of markets and the volatility of product prices are beyond our control and represent a significant risk.

Inflationary issues and associated changes in monetary policy may result in increases to the cost of our goods, services and personnel, which in turn could cause our capital expenditures and operating costs to rise.

The U.S. inflation rate steadily rose in 2021 and into 2022 before eventually declining throughout 2023. These inflationary pressures resulted in increases to the costs of our goods, services and personnel, which in turn, caused our capital expenditures and operating costs to rise. The U.S. Federal Reserve (the “Fed”) and other central banks increased interest rates multiple times in 2022 and 2023 in an effort to curb inflationary pressure on the costs of goods and services across the U.S. and globally. While the Fed indicated in December 2023 that it may reduce benchmark interest rates in 2024, the continuation of elevated rates could have the effects of raising the cost of capital and depressing economic growth, either of which—or the combination thereof—could hurt the financial and operating results of our business.

Higher crude oil and natural gas prices may cause the costs of materials and services to continue to rise. We cannot predict any future trends in the rate of inflation or the monetary policies in response thereto.

We may be unable to pursue our CCS business, either wholly or in significant measure, which could have a material adverse effect on our business, results of operations and financial condition.

The successful development of our CCS projects is dependent on various economic, regulatory, operational and technical factors. The failure to satisfy, wholly or in significant measure, any of such factors could have a material adverse impact on our business, results of operations and financial condition.

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Risks related to our CCS business include but are not limited to:

•the uncertainty of evolving government regulations;

•adequate capital financing to develop our projects;

•the availability of necessary infrastructure, equipment, services and skilled personnel to develop our CCS business;

•sufficient infrastructure to capture CO2 at the source, and transport it to CCS sites;

•the availability, applicability and adequacy of various federal and state incentive programs related to CCS projects;

•the availability and cost of acquiring necessary federal and state permits, including permits applicable to subsurface injection, and air emissions or impacts to environmental, natural, historic or cultural resources resulting from the construction and operation of a CCS facility;

•our ability to maintain adequate financial assurances to cover the cost of corrective action, injection well plugging, post injection site care and site closure, and emergency and remedial response;

•public and political opinion regarding CCS development in local communities;

•locating suitable sources of anthropogenic CO2;

•obtaining sufficient quantities of CO2 from, and entering into suitable agreements with, emitters on terms that are acceptable and economical to us; and

•complex recordkeeping and GHG emissions/sequestration accounting which may increase our costs.

The availability and applicability of various federal financial incentives related to our projects is uncertain and there is no assurance that if available, such incentives would be adequate for our CCS project needs or that such incentives will continue to be available in the future.

Additionally, successful development of CCS projects in the United States requires us to comply with stringent and varied regulatory schemes requiring permits applicable to subsurface injection of CO2 for geologic sequestration. Moreover, as operator for two of our CCS projects, we must demonstrate and maintain levels of financial assurance sufficient to cover the cost of corrective action, injection well plugging, post injection site care and site closure, and emergency and remedial response. As carbon management represents an emerging sector, regulations may evolve rapidly and unpredictably, which could impact the feasibility of one or more of our anticipated projects. There is no assurance that we will be successful in obtaining sufficient federal and state permits or adequate levels of financial assurance for one or more of our CCS projects or that permits can be obtained on a timely basis, whether due to difficulty with the technical demonstrations required to obtain such permits, public opposition or otherwise. Separately, CCS projects are also subject to additional permits and approvals unrelated to subsurface injection from various U.S. federal and state agencies, such as for air emissions or impacts to environmental, natural, historic or cultural resources resulting from the construction and operation of a CCS facility. To the extent regulatory requirements are imposed, are increased or more stringently enforced, we may incur additional costs in the development of our CCS projects, which costs may be material or may render any one or more of our projects uneconomic.

CCS projects also require satisfying certain operational factors, such as locating a suitable source of anthropogenic CO2 and reaching suitable agreements to capture that CO2. Such agreements are complex and may involve allocation of not only fees but also various credits, incentives and environmental attributes associated with the sequestration of CO2. Not all emission sources produce sufficiently large quantities of pure or relatively pure streams of CO2, or have installed equipment to capture such CO2, so as to be usable in one or more of our CCS projects. As a result, we may not be able to obtain sufficient quantities of CO2 from emitters on terms that are acceptable to us, and the failure to do so may have a material impact on our ability to execute our CCS strategy. Additionally, development of successful CCS projects will require infrastructure to transport CO2 between the source and our CCS sites. In project areas with existing CO2 transportation pipelines, this may require reaching an agreement on CO2 transportation with operators of CO2 pipelines within the regions in which we operate. Inability to reach a suitable agreement may render a project uneconomic or impracticable.

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Separately, if no CO2 pipelines exist in proposed project areas, or if existing pipelines do not extend to one or more of our project sites, we may be required to convert existing pipelines, or build new CO2 pipelines or lateral connections, which may be subject to various environmental and other permitting requirements to include increased regulation from U.S. federal and state agencies, as well as third party easements, which may render one or more projects uneconomical. We will also need to build the required equipment on a timely basis and at a cost that is economically viable. Additionally, complex recordkeeping and GHG emissions/sequestration accounting may be required in connection with one or more of our projects, which may increase the costs of such operations. Different methodologies may be required for various regulatory and non-regulatory accounts regarding GHG emissions/sequestration at one or more of our projects, including but not limited to, compliance with the EPA’s mandatory Greenhouse Gas Reporting Program. Furthermore, as CCS may be viewed as a pathway to the continued use of fossil fuels, notwithstanding that CO2 emissions are intended to be captured, there may be organized opposition to CCS, including as it relates to our projects.

We can provide no assurance that we will be able to execute our CCS business strategy in the future. Any failure by us to achieve such expectations in whole or any significant measure could have a material adverse effect on our business, results of operations and financial condition.

Our inability to benefit from Section 45Q tax credits could materially reduce our ability to develop CCS projects and, as a result, may adversely impact our business, results of operations and financial condition.

The successful development of our CCS projects is dependent upon our ability to benefit from certain financial and tax incentives available with respect to CCS projects. The development of CCS projects is incentivized by tax credits provided under Section 45Q of the Internal Revenue Code of 1986, as amended (such credits, “Section 45Q tax credits”), which provides a tax credit for qualified CO2 that is captured using carbon capture equipment and disposed of in secure geological storage. The amount of Section 45Q tax credits from which we may benefit is dependent upon our ability to satisfy certain wage and apprenticeship requirements, which we cannot assure you that we will satisfy. With respect to the first five tax years a qualifying CCS project is in service, but not beyond December 31, 2032, we may elect a “direct pay” option with respect to available Section 45Q tax credits to efficiently monetize their value (i.e., we may receive a payment for the tax credits through a tax refund as if there had been an overpayment of taxes). Following the period in which the direct pay election is available and for the remaining period in which the applicable Section 45Q tax credits are otherwise available, we may elect to transfer the Section 45Q tax credits to unrelated taxpayers. We cannot assure you that we will be able to efficiently monetize Section 45Q tax credits that are transferred to unrelated taxpayers. We will benefit from Section 45Q tax credits only if we satisfy the applicable statutory and regulatory requirements for obtaining the Section 45Q tax credits, including that we own carbon capture equipment that captures qualified CO2 that we physically or contractually capture and securely store, or if another party that owns carbon capture equipment elects to pass through Section 45Q tax credits to us, that we dispose of the qualified CO2 in secure storage. If we are unable to satisfy such statutory and regulatory requirements or otherwise qualify for or obtain the Section 45Q tax credits, our CCS projects may no longer be economically viable and may not be completed. We cannot assure you that we will be successful in satisfying such requirements or otherwise qualifying for or obtaining the Section 45Q tax credits currently available or that we will be able to effectively benefit from such tax credits. Section 45Q tax credits are also subject to recapture with respect to any CO2 that ceases to be disposed of in secure storage, which recapture is treated as an increase in tax liability for the year in which the recapture occurs. The recapture period for Section 45Q tax credits is limited to a 3-year lookback period preceding the date that sequestered CO2 escapes from its secure storage.

Additionally, the availability of Section 45Q tax credits may be reduced, modified or eliminated as a matter of legislative or regulatory policy. There can be no assurance that Section 45Q tax credits will not be reduced, modified or eliminated in the future, including as a result of any change in presidential administration as a result of the 2024 U.S. presidential election. Any such reduction, modification or elimination of Section 45Q tax credits, or our inability to otherwise benefit from Section 45Q tax credits, could materially reduce our ability to develop CCS projects and, as a result, may adversely impact our business, results of operations and financial condition. Even if we are able to benefit from Section 45Q tax credits, we may determine that additional financial incentives are required for our CCS projects to be economically viable. If such additional incentives do not emerge, we may not be able to achieve an economic return from our CCS business or, alternatively, the construction or operation of our CCS projects may be substantially delayed, unprofitable or otherwise infeasible.

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We may be unable to provide the financial assurances in the amounts and under the time periods required by BOEM if it submits future demands to cover our decommissioning obligations. If in the future BOEM issues orders to provide additional financial assurances and we fail to comply with such future orders, BOEM could elect to take actions that would materially adversely impact our operations and our properties, including commencing proceedings to suspend our operations or cancel our associated federal offshore leases.

BOEM requires that lessees demonstrate financial strength and reliability according to its regulations or provide acceptable financial assurances to assure satisfaction of lease obligations, including decommissioning activities on the OCS. In 2016, BOEM under the Obama Administration had sought to implement more stringent and costly standards under the existing federal financial assurance requirements through issuance and implementation of the 2016 NTL, but the Trump Administration first suspended, and then in 2020 rescinded, the implementation of the 2016 NTL. Following the effectiveness of the 2016 NTL, we received orders from BOEM in late 2016 directing us to provide additional financial assurance in material amounts relating to our OCS properties. We entered into discussions with BOEM regarding the requested additional financial security and submitted a proposed tailored plan (applicable to our sole and non-sole liability properties) for the posting of additional financial security to the agency for review. However, as the Trump Administration rescinded the 2016 NTL, BOEM withdrew the previously issued orders under the 2016 NTL.

In August 2021, BOEM published a Note to Stakeholders detailing an expansion of its supplemental financial assurance requirements currently applicable to all sole liability properties and now to certain high-risk, non-sole liability properties; namely, those properties that are inactive, where production end-of-life is fewer than five years, or with damaged infrastructure irrespective of the remaining property life of the surrounding producing assets. BOEM has stated it will prioritize non-sole liability properties where it believes that the current owner does not meet applicable requirements related to financial strength and has no co-owners or predecessors that are financially strong, as determined by BOEM. In connection with this Note to Stakeholders, BOEM initially assessed the required financial assurance for our sole liability properties as approximately $70 million. However, following the opportunity to review BOEM’s sole liability assessment, we were able to reduce the financial assurance required to approximately $37.7 million. The bonds covering this amount were posted in 2021. Notwithstanding the above, BOEM, now under the Biden Administration, could, in the future, continue to make new demands for additional financial assurances in material amounts relating to the decommissioning of our OCS properties. BOEM may reject our proposals to satisfy any such additional financial assurance coverage and make demands that exceed our capabilities.

If we fail to comply with the current or future orders of BOEM to provide additional surety bonds or other financial assurances, BOEM could commence enforcement proceedings or take other remedial action, including assessing civil penalties, suspending operations or production, or initiating procedures to cancel leases associated with our noncompliance, which, if upheld, would have a material adverse effect on our business, properties, results of operations and financial condition. BOEM has the right to issue financial assurance orders in the future, including if it determines there is a substantial risk of nonperformance of the current interest holder’s decommissioning liabilities and the Biden Administration may elect to pursue more stringent supplemental bonding requirements.

In the event that BOEM finalizes new regulations similar to or more stringent than the 2016 NTL, such as BOEM’s June 2023 proposed rule that substantially revises the supplemental financial assurance requirements applicable to offshore oil and gas operations, the surety bond market has very limited capacity to provide additional financial assurance and we therefore may not be able to procure and provide the financial assurance required by such new regulations. Moreover, the implementation of such new regulations could result in sureties seeking additional collateral to support existing or future bonds, such as cash or letters of credit, and we cannot provide assurance that we will be able to satisfy collateral demands for such bonds to comply with supplemental bonding requirements of BOEM. If we are required to provide collateral in the form of cash or letters of credit, our liquidity position could be negatively impacted and we may be required to seek alternative financing. To the extent we are unable to secure adequate financing, we may be forced to reduce our capital expenditures. All of these factors may make it more difficult for us to obtain the financial assurances required by BOEM to conduct operations on the OCS. These and other changes to BOEM bonding and financial assurance requirements could result in increased costs on our operations, reduced cash flows if unable to comply and consequently have a material adverse effect on our business and results of operations.

See Part I, Items 1 and 2. Business and Properties — Government Regulation — Outer Continental Shelf (“OCS”) Regulation for more discussion on orders and regulatory initiatives impacting the oil and natural gas industry on the OCS.

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Our business could be negatively affected by security threats, including cybersecurity threats, terrorist attacks and other disruptions.

As an oil and gas producer, we have various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable, threats to the security of our facilities and infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. The potential for such security threats subjects our operations to increased risks that could have a material adverse effect on our business. In particular, the implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls are sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information and corruption of data. These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability.

The U.S. government has issued warnings that U.S. energy assets may be the future targets of terrorist organizations. These developments subject our operations to increased risks. Any future terrorist attack at our facilities, or those of our purchasers or vendors, could have a material adverse effect on our financial condition and operations.

Global geopolitical tensions may create heightened volatility in oil, gas and NGL prices and could adversely affect our business, financial condition and results of operations.

Our oil and gas activities are subject to numerous geopolitical and economic risks, uncertainties (including but not limited to changes, sometimes frequent or marked, in energy policies or the personnel administering them), expropriation of property, cancellation or modification of contract rights, changes in laws and policies governing operations of foreign-based companies, unilateral renegotiation of contracts by governmental entities, redefinition of international boundaries or boundary disputes, foreign exchange restrictions, currency fluctuations, royalty and tax increases, and other risks arising out of governmental sovereignty over the areas in which our operations are conducted, as well as risks of loss due to acts of terrorism, piracy, disease, illegal cartel activities and other political risks, including tension and confrontations among political parties. The upcoming presidential election in the U.S., the expected change in presidential administration in Mexico, the extended war between Russia and Ukraine and increasing hostilities in the Middle East may cause prolonged uncertainty and volatility in commodity prices.

Mexico’s most recent presidential election was held in July 2018. Presidential reelection is not permitted in Mexico. President Andrés Manuel López Obrador, took office on December 1, 2018, and his successor is due to be elected in June of 2024. At this time we cannot predict what changes (if any) will result from this change in administration. Political events in Mexico could adversely affect economic conditions and/or the oil and gas industry and, by extension, our results of operations and financial position.

On February 24, 2022, Russian military forces invaded Ukraine, and sustained war and continued and prolonged disruption in the region is likely.

Russia’s recognition of two separatist republics in the Donetsk and Luhansk regions of Ukraine and subsequent military action against Ukraine have led to an unprecedented expansion of sanction programs imposed by the U.S., the European Union, the United Kingdom, Canada, Switzerland, Japan and other countries against Russia, Belarus, the Crimea Region of Ukraine, the so-called Donetsk People’s Republic and the so-called Luhansk People’s Republic, including, among others:

•blocking sanctions against some of the largest state-owned and private Russian financial institutions (and their subsequent removal from the Society for Worldwide Interbank Financial Telecommunication payment system) and certain Russian businesses, some of which have significant financial and trade ties to the European Union;

•blocking sanctions against Russian and Belarusian individuals, including the Russian President, other politicians and those with government connections or involved in Russian military activities; and

•blocking of Russia’s foreign currency reserves as well as expansion of sectoral sanctions and export and trade restrictions, limitations on investments and access to capital markets and bans on various Russian imports.

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In retaliation against new international sanctions and as part of measures to stabilize and support the volatile Russian financial and currency markets, the Russian authorities also imposed significant currency control measures aimed at restricting the outflow of foreign currency and capital from Russia, imposed various restrictions on transacting with non-Russian parties, banned exports of various products and other economic and financial restrictions. The situation is rapidly evolving as a result of the war in Ukraine, and the U.S., the European Union, the United Kingdom and other countries may implement additional sanctions, export controls or other measures against Russia, Belarus and other countries, regions, officials, individuals or industries in the respective territories. Such sanctions and other measures, as well as the existing and potential further responses from Russia or other countries to such sanctions, tensions and military actions, could adversely affect the global economy and financial markets and could adversely affect our business, financial condition and results of operations.

We are actively monitoring the situation in Ukraine and assessing its impact on our business, including our business partners and customers. To date we have not experienced any material interruptions in our infrastructure, supplies, technology systems or networks needed to support our operations. We have no way to predict the progress or outcome of the war in Ukraine or its impacts in Ukraine, Russia or Belarus as the war, and any resulting government reactions, are rapidly developing and beyond our control. Continued hostilities, or any significant increases in the extent and duration of the military action, sanctions and resulting market disruptions — or any meaningful escalation in the objectives thereof or the methods used by the combatants to achieve such objectives —could be significant and could potentially have substantial impact on the global economy and our business for an unknown period of time.

Alternatively, a cessation of hostilities as a result of a negotiated withdrawal or otherwise—particularly if coupled with an easing of international sanctions — could cause commodity prices to decline in a manner that would reduce the revenues we receive for our oil and gas production. During the first quarter of 2022, we experienced an increase in commodity prices as sanctions imposed on Russia severely limited the access of Russian oil and gas producers to international markets. In the months that followed, commodity prices subsequently decreased and remained stagnant during the second half of 2022. If the military action concludes and the related sanctions are dropped, commodity prices could significantly decrease. Any of the above mentioned factors could affect our business, financial condition and results of operations.

Additionally, on October 7, 2023, Hamas, a U.S.-designated terrorist organization, launched a series of coordinated attacks from the Gaza Strip onto Israel. On October 8, 2023, Israel formally declared war on Hamas, and the armed conflict is ongoing as of the date of this filing. Hostilities between Israel and Hamas have escalated and involved surrounding countries in the Middle East. Iranian-backed groups have launched attacks on U.S. military bases and assets in Syria, Iraq, and Jordan, and have targeted international shipping in the Red Sea. After three American troops were killed in a drone attack by an Iran-backed militant group, the U.S. launched retaliatory strikes on multiple sites in Iraq and Syria used by Iranian forces and Iran-backed militants. U.S. and British forces then launched a series of strikes on Houthi targets in Yemen in response to continuing attacks on shipping in the Red Sea and Gulf of Aden. Although the length, impact and outcome of the military conflicts between Ukraine and Russia and Israel and Hamas, respectively, are highly unpredictable, these conflicts could lead to significant market and other disruptions, including significant volatility in commodity prices and supply of energy resources, instability in financial markets, supply chain interruptions, political and social instability and other material and adverse effects on macroeconomic conditions. It is not possible at this time to predict or determine the ultimate consequence of these regional conflicts. These conflicts and their broader impacts could adversely affect our business, financial condition and results of operations and the global economy.

We may not be in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves from our non-operated properties.

As we carry out our drilling program, we may not serve as operator of all planned wells. For example, in March 2022, the final UR from SENER regarding the development of the Zama Field in offshore Mexico, affirmed the appointment of PEMEX as operator of the unit, despite our discovery of the Zama Field in 2017 and subsequent operatorship. We may have limited ability to exercise influence over the operations of some non-operated properties and their associated costs. Our dependence on the operator and other working interest owners, and our limited ability to influence operations and associated costs of properties operated by others, could prevent the realization of anticipated results in drilling or acquisition activities. The success and timing of development and exploitation activities on properties operated by others depends upon a number of factors that could be largely outside of our control, including:

•the timing and amount of capital expenditures;

•the availability of suitable offshore drilling rigs, drilling equipment, support vessels, production and transportation infrastructure and qualified operating personnel;

•the operator’s expertise and financial resources;

•approval of other participants in drilling wells;

•risk of other non-operator’s failure to pay its share of costs, which may require us to pay our proportionate share of the defaulting party’s share of costs;

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•selection of technology;

•the rate of production of the reserves; and

•the timing and cost of P&A operations.

In addition, with respect to oil and natural gas projects that we do not operate, we have limited influence over operations, including limited control over the maintenance of safety and environmental standards. The operators of those properties may, depending on the terms of the applicable joint operating agreement:

•refuse to initiate exploration or development projects;

•initiate exploration or development projects on a slower or faster schedule than we would prefer;

•delay the pace of exploratory drilling or development; and/or

•drill more wells or build more facilities on a project than we can afford, whether on a cash basis or through financing, which may limit our participation in those projects or limit the percentage of our revenues from those projects.

The occurrence of any of the foregoing events could have a material adverse effect on our anticipated exploration and development activities.

Hedging transactions may limit our potential gains.

In order to manage our exposure to price risks in the marketing of our oil, natural gas and NGLs, we periodically enter into oil, natural gas and NGL price hedging arrangements with respect to a portion of our expected production. These arrangements may include futures contracts on the NYMEX. While intended to reduce the effects of volatile oil and natural gas prices, such transactions, depending on the hedging instrument used, may limit our potential gains if oil and natural gas prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

•our production is less than expected or is shut-in for extended periods due to hurricanes or other factors;

•there is a widening of price differentials between delivery points for our production and the delivery point to be assumed in the hedge arrangement;

•the counterparties to our futures contracts fails to perform the contracts;

•a sudden, unexpected event materially impacts oil or natural gas prices; or

•we are unable to market our production in a manner contemplated when entering into the hedge contract.

Our outstanding commodity derivative instruments are with certain lenders or affiliates of the lenders under our Bank Credit Facility. Our derivative agreements with the lenders are secured by the security documents executed by the parties under the Bank Credit Facility. Future collateral requirements for our commodity hedging activities are uncertain and depend on the arrangements we negotiate with the counterparty and the volatility of oil and natural gas prices and market conditions.

Our operations may incur substantial liabilities to comply with environmental laws and regulations as well as legal requirements applicable to marine life and endangered and threatened species.

Our oil and natural gas operations in the United States and Mexico are subject to stringent federal, state and/or local laws and regulations relating to the release or disposal of materials into the environment or otherwise relating to environmental protection. These laws and regulations require permits or other approvals before drilling or other regulated activity commences; restrict the types, quantities and concentration of substances that can be released into the environment in connection with drilling and production activities; limit or prohibit exploration or drilling activities on certain lands lying within protected areas or that may affect certain wildlife, including marine species and endangered and threatened species and impose substantial liabilities for pollution resulting from our operations. Additionally, the threat of climate change continues to be a heightened area of focus and regulatory and disclosure requirements in the United States. For example, in March 2022, the SEC proposed rules which could require additional disclosure of climate change-related information, including, among other things, climate change risk management; short-medium-and long-term climate-related financial risks; and reporting Scope1, Scope2 and (for certain companies) Scope3 emissions. The SEC’s proposed climate disclosure rules have not yet been finalized, but implementation of the rules as proposed could impose additional costly and time-consuming requirements on our business. For additional information about government regulation related to environmental and worker safety matters, please see Part I, Items 1 and 2. Business and Properties — Government Regulation — Environmental and Occupational Safety and Health Regulations. Any regulatory developments that impact, curtail or increase the cost of our oil and natural gas exploration and production activities on the OCS could have a material adverse effect on our business, results of operations and financial condition.

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Additional drilling laws, regulations, executive orders and other regulatory initiatives that restrict, delay or prohibit oil and natural gas exploration, development and production activities or access to locations where such activities may occur could have a material adverse effect on our business, financial condition or results of operations.

The Biden Administration has taken a number of actions that may result in stricter environmental, health and safety standards applicable to our operations and those of the oil and gas industry more generally. The Biden Administration issued the “Executive Order on Tackling the Climate Crisis at Home and Abroad” on January 27, 2021 (the “Climate Change Executive Order”). This executive order directed the Secretary of the Interior to halt indefinitely new oil and natural gas leases on federal lands and offshore waters pending completion of a review by the Secretary of the Interior of federal oil and gas permitting and leasing practices in light of the Biden Administration’s concerns regarding the impact of these activities on the environment and climate. The Secretary of the Interior completed its review of permitting and leasing practices in November 2021 and issued a report recommending, among other things, an increase in royalty rates and financial assurance requirements. However, litigation concerning the Climate Change Executive Order’s pause on new oil and gas leases is ongoing. In June 2021, the U.S. District Court for the Western District of Louisiana issued a nationwide preliminary injunction barring the Biden Administration from implementing the pause in new federal oil and gas leases, an injunction which was made permanent in August 2022. This effectively halts implementation of the leasing suspension with respect to those lease sales canceled or postponed prior to March 24, 2021. In November 2021, the Biden Administration conducted Lease Sale 257 and various industry participants submitted bids for leases in the Gulf of Mexico; however, on January 27, 2022, in litigation brought by Friends of the Earth and other plaintiffs, the U.S. District Court for the District of Columbia vacated Lease Sale 257 and the related agency decision making process, finding that BOEM failed to consider the impact on foreign greenhouse gas emissions if Lease Sale 257 was not held and the court determined that this failure was a violation of the NEPA. In September 2022, BOEM announced that it was reinstating Lease Sale 257 results in line with congressional direction in the IRA 2022. In addition, there is increasing uncertainty regarding the near-term future of Gulf of Mexico lease sales. These lease sales are conducted pursuant to Five-Year Leasing Programs under the Outer Continental Shelf Lands Act. The most recent Five-Year Leasing Program expired on June 30, 2022 and on July 1, 2022, BOEM released a proposed program for 2023 through 2028. The proposed program, which was subject to public comment through October 6, 2022, proposes no more than ten potential lease sales in the Gulf of Mexico. On September 29, 2023, the proposed final program for 2024-2029 was published and includes a maximum of three potential oil and gas lease sales in the Gulf of Mexico scheduled to be held in years 2025, 2027 and 2029. The Secretary of the Interior approved the 2024-2029 program via a combined decision memo and Record of Decision. It is likely, however, that the new Five-Year Leasing Program will be subject to heightened environmental review. It is also possible that the program could be delayed by opposing lawsuits that were filed on February 12, 2024 by the American Petroleum Institute and by Earthjustice representing multiple environmental groups both of which are challenging BOEM’s actions. Future actions taken by the Biden Administration to limit the availability of new oil and gas leases on the OCS would adversely impact the offshore oil and gas industry and impact demand for our products.

Over the past decade, BSEE and BOEM, primarily under the Obama Administration, have imposed new and more stringent permitting procedures and regulatory safety and performance requirements for new wells to be drilled in federal waters. While actions by BSEE or BOEM under the Trump Administration sought to mitigate or delay certain of those more rigorous standards, the Biden Administration could reconsider rules and regulatory initiatives implemented under the previous administration and replace them with more stringent requirements and also provide more rigorous enforcement of existing regulatory requirements. For example, in August 2023, BSEE published a final rule, effective October 23, 2023, to clarify and modify certain blowout preventer system requirements. The rule requires, among other things, that the blowout preventer system is able to close and seal the wellbore at all times to the wells maximum kick tolerance design limits and includes more stringent requirements for failure reporting. Compliance with any added or more stringent regulatory requirements or enforcement initiatives and existing environmental and spill regulations, together with uncertainties or inconsistencies in decisions and rulings by governmental agencies and delays in the processing and approval of drilling permits and exploration, development, oil spill response and decommissioning plans could result in difficult and more costly actions and adversely affect or delay new drilling and ongoing development efforts. Moreover, governmental agencies under the Biden Administration may continue evaluating aspects of safety and operational performance in the U. S. Gulf of Mexico that may result in new, more restrictive requirements.

These regulatory actions, or any new laws, executive orders, regulations or other legal or enforcement initiatives, that impose increased costs or more stringent operational standards could delay or disrupt our operations, result in increased supplemental bonding and associated costs, and limit activities in certain areas, or cause us to incur penalties, fines, or shut-in production at one or more of our facilities or result in suspension or cancellation of leases. Also, if material spill incidents were to occur in the future, the United States or other countries where such an event may occur could elect to issue directives to temporarily cease drilling activities and, in any event, may from time to time issue further safety and environmental laws and regulations regarding offshore oil and natural gas exploration and development, any of which could have a material adverse effect on our business. We cannot predict with any certainty the full impact of any new laws or regulations on our drilling and production operations or on the cost or availability of insurance to cover some or all of the risks associated with such operations.

See Part I, Items 1 and 2. Business and Properties — Government Regulation — Outer Continental Shelf (“OCS”) Regulation for more discussion on orders and regulatory initiatives impacting the oil and natural gas industry on the OCS.

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Our oil and gas operations are subject to various international, foreign and U.S. federal, state and local governmental regulations that materially affect our operations.

Our oil and gas operations are subject to various international, foreign and U.S. federal, state and local laws and regulations. These laws and regulations may be changed in response to economic or political conditions. Regulated matters include: permits for exploration, development and production operations; limitations on our drilling activities in environmentally sensitive areas, such as marine habitats, and restrictions on the way we can discharge materials and/or GHG emissions into the environment; bonds or other financial responsibility requirements to cover drilling contingencies, well P&A and other decommissioning costs; reports concerning operations, the spacing of wells and unitization and pooling of properties; regulations regarding the rate, terms and conditions of transportation service or the price, terms, and conditions related to the purchase and sale of oil and natural gas; and taxation. Failure to comply with these laws and regulations can result in the assessment of administrative, civil or criminal penalties, the issuance of remedial obligations and the imposition of injunctions limiting or prohibiting certain of our operations. In addition, because we hold federal leases, the federal government requires that we comply with numerous additional regulations applicable to government contractors.

The SENER has promulgated guidelines to establish procedures for conducting the unitization of shared reservoirs and approving the terms and conditions of unitization and unit operating agreements, as well as the authority to direct parties holding rights in a potentially shared reservoir to appraise and potentially form a unit for development of such reservoir.

If we are forced to shut-in production, we will likely incur greater costs to bring the associated production back online, and will be unable to predict the production levels of such wells once brought back online.

If we are forced to shut-in production, we will likely incur greater costs to bring the associated production back online. Cost increases necessary to bring the associated wells back online may be significant enough that such wells would become uneconomic at low commodity price levels, which may lead to decreases in our proved reserve estimates and potential impairments and associated charges to our earnings. If we are able to bring wells back online, there is no assurance that such wells will be as productive following recommencement as they were prior to being shut-in. Any shut-in or curtailment of the oil, natural gas and NGLs produced from our fields could adversely affect our financial condition and results of operations.

We may experience significant shut-ins and losses of production due to the effects of events outside of our control, including tropical storms and hurricanes in the U.S. Gulf of Mexico and in the shallow waters off the coast of Mexico and epidemics, outbreaks or other public health events.

Our production is primarily associated with our properties in the U.S. Gulf of Mexico and in the shallow waters off the coast of Mexico. Accordingly, if the level of production from these properties substantially declines, it could have a material adverse effect on our overall production level and our revenue. We are particularly vulnerable to significant risk from hurricanes, tropical storms, loop currents and other adverse weather conditions in the U.S. Gulf of Mexico. We are unable to predict what impact future incidents might have on our future results of operations and production.

Epidemics, pandemics, outbreaks or other public health events that are outside of our control could significantly disrupt our operations and adversely affect our financial condition. The global or national outbreak of an illness or other communicable disease, or any other public health crisis, such as COVID-19, may cause disruptions to our business and operational plans, which may include (i) shortages of employees, (ii) unavailability of contractors or subcontractors, (iii) interruption of supplies from third parties upon which we rely, (iv) recommendations of, or restrictions imposed by government and health authorities, including quarantines, to address an outbreak and (v) restrictions that we and our contractors, subcontractors and our customers impose, including facility shutdowns, to ensure the safety of employees.

We are not insured against all of the operating risks to which our business is exposed.

In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We insure some, but not all, of our properties from operational loss-related events. We have insurance policies that include coverage for general liability, physical damage to our oil and gas properties, operational control of well, named U.S. Gulf of Mexico windstorm, oil pollution, construction risk, workers’ compensation and employers’ liability and other coverage. Our insurance coverage includes deductibles that have to be met prior to recovery, as well as sub-limits or self-insurance. Additionally, our insurance is subject to exclusions and limitations, and there is no assurance that such coverage will adequately protect us against liability from all potential consequences, damages or losses. See Part I, Items 1 and 2. Business and Properties – Insurance Matters for more information on our insurance coverage.

An operational or hurricane or other adverse weather-related event may cause damage or liability in excess of our coverage that might severely impact our financial position. We may be liable for damages from an event relating to a project in which we own a non-operating working interest. Such events may also cause a significant interruption to our business, which might also severely impact our financial position. We may experience production interruptions for which we do not have production interruption insurance.

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We reevaluate the purchase of insurance, policy limits and terms annually. Future insurance coverage for our industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable, and we may elect to maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations in the U.S. Gulf of Mexico, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.

Our actual production could differ materially from our forecasts.

From time to time, we may provide forecasts of expected quantities of future oil and gas production. These forecasts are based on a number of estimates, including expectations of production from existing wells. In addition, our forecasts may assume that none of the risks associated with our oil and natural gas operations summarized in this section would occur, such as facility or equipment malfunctions, adverse weather effects, adverse resolutions to disputes relating to operatorships or significant declines in commodity prices or material increases in costs, which could make certain production uneconomical.

Our operations are subject to numerous risks of oil and natural gas drilling and production activities.

Oil and gas drilling and production activities are subject to numerous risks, including the risk that no commercially productive oil or natural gas reserves are found. The cost of drilling and completing wells is often uncertain. To the extent we drill additional wells in the U.S. Gulf of Mexico Deepwater and/or in the Gulf Coast deep shelf, our drilling activities increase capital cost. In addition, the geological complexity of the areas in which we have oil and natural gas operations make it more difficult for us to sustain the historical rates of drilling success. Oil and natural gas drilling and production activities may be shortened, delayed or cancelled as a result of a variety of factors, many of which are beyond our control. These factors include:

•unexpected drilling conditions;

•pressure or irregularities in formations;

•equipment failures or accidents;

•hurricanes and other adverse weather conditions;

•shortages in experienced labor; and

•shortages or delays in the delivery of equipment.

The prevailing prices of oil and natural gas also affect the cost of and the demand for drilling rigs, production equipment and related services. We cannot assure you that the wells we drill will be productive or that we will recover all or any portion of our investment. Drilling for oil and natural gas may be unprofitable. Drilling activities can result in dry holes and wells that are productive but do not produce sufficient cash flows to recoup drilling costs.

In addition, an oil spill on or related to our properties and operations could expose us to joint and several strict liability, without regard to fault, under applicable law for containment and oil removal costs and a variety of public and private damages, including, but not limited to, the costs of responding to a release of oil, natural resource damages and economic damages suffered by persons adversely affected by an oil spill. If an oil discharge or substantial threat of discharge were to occur, we could be liable for costs and damages, which costs and damages could be material to our results of operations and financial position.

We have an interest in Deepwater fields and may attempt to pursue additional operational activity in the future and acquire additional fields and leases in the Deepwaters of the U.S. Gulf of Mexico. Exploration for oil or natural gas in the Deepwaters of the U.S. Gulf of Mexico generally involves greater operational and financial risks than exploration in the shallower waters of the U.S. Gulf of Mexico conventional shelf. Deepwater drilling generally requires more time and more advanced drilling technologies, involving a higher risk of technological failure and usually higher drilling costs. For example, the drilling of Deepwater wells requires specific types of drilling rigs with significantly higher day rates and limited availability as compared to the rigs used in shallower water. Deepwater wells often use subsea completion techniques with subsea trees tied back to host production facilities with flow lines. The installation of these subsea trees and flow lines requires substantial time and the use of advanced remote installation mechanics. These operations may encounter mechanical difficulties and equipment failures that could result in cost overruns. Furthermore, the Deepwater operations generally lack the physical and oilfield service infrastructure present in the shallower waters of the U.S. Gulf of Mexico conventional shelf. As a result, a considerable amount of time may elapse between a Deepwater discovery and the marketing of the associated oil or natural gas, increasing both the financial and operational risk involved with these operations. Because of the lack and high cost of infrastructure, some reserve discoveries in the Deepwater may never be produced economically.

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If any of these industry operating risks occur, we could have substantial losses. Substantial losses may be caused by injury or loss of life, severe damage to or destruction of property, natural resources and equipment, pollution or other environmental damage, clean-up responsibilities, regulatory investigation and penalties, suspension of operations and production and repairs to resume operations. Any of these industry operating risks could have a material adverse effect on our business, results of operations and financial condition.

Competition within our industry may adversely affect our operations. Many of our competitors are larger and have more available financial resources.

The oil and gas industry is highly competitive, and many companies in our industry are larger and have substantially greater financial resources than we do. We compete with these companies for oil and natural gas leases and other properties; equipment and personnel; and marketing our product to end-users. Such competition can significantly increase costs and the availability of resources available to us, which could provide larger companies a competitive advantage. Larger competitors may also be able to more easily attract and retain experienced personnel. In addition, larger competitors may be better able to respond and adapt to adverse economic and industry conditions, including price fluctuations, reduced oil and gas demand, political changes and current and future governmental regulations and taxation.

Competitors may be able to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Competitors may also be able to outbid us for acquisitions, productive oil and gas properties and exploratory prospects. Further, our competitors may be able to expend greater resources on the existing and changing technologies to gain competitive advantages. If we are unable to compete successfully in the future, our future revenues and growth may be diminished or restricted.

The loss of our larger customers could materially reduce our revenue and materially adversely affect our business, financial condition and results of operations.

We have a limited number of customers that provide a substantial portion of our revenue. The loss of our larger customers, including Shell Trading (US) Company and Valero Energy Corporation, could adversely affect our current and future revenue, and could have a material adverse effect on our business, financial condition and results of operations. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies for additional information.

The loss of key personnel could adversely affect our ability to operate.

Our industry has lost a significant number of experienced professionals over the years due to its cyclical nature, which is attributable, among other reasons, to the volatility in commodity prices. Our operations are dependent upon key management and technical personnel. We cannot assure you that individuals will remain with us for the immediate or foreseeable future. The unexpected loss of the services of one or more of these individuals could have an adverse effect on us and our operations.

In addition, our exploration, production and decommissioning activities require personnel with specialized skills and experience. As a result, our ability to remain productive and profitable depends upon our ability to employ and retain skilled workers. Our ability to expand operations depends in part on our ability to increase the size of our skilled labor force, including geologists and geophysicists, field operations managers and engineers, to handle all aspects of our exploration, production and decommissioning activities. The demand for skilled workers in our industry is high, and the supply is limited. A significant increase in the wages paid by competing employers or the unionization of our U.S. Gulf of Mexico employees could result in a reduction of our labor force, increases in the wage rates that we will have to pay, or both. If either of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.

We have operations in multiple jurisdictions, including jurisdictions in which the tax laws, their interpretation or their administration may change. As a result, our tax obligations and related filings are complex and subject to change, and our after-tax profitability could be lower than anticipated. Additionally, future tax legislative or regulatory changes in the United States, Mexico or any other jurisdiction in which we operate or have subsidiaries could result in changes to the taxation of our income and operations, which could also adversely impact our after-tax profitability.

We are subject to income, withholding and other taxes in the United States on a worldwide basis and in numerous state, local and foreign jurisdictions with respect to our income, operations and subsidiaries in those jurisdictions. Our after-tax profitability could be affected by numerous factors, including the availability of tax credits, exemptions, refunds (including refunds of value added taxes) and other benefits to reduce our tax liabilities, changes in the relative amount of our earnings subject to tax in the various jurisdictions in which we operate or have subsidiaries, the potential expansion of our business into or otherwise becoming subject to tax in additional jurisdictions, changes to our existing business structure and operations, the extent of our intercompany transactions and the extent to which taxing authorities in the relevant jurisdictions respect those intercompany transactions.

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Our after-tax profitability may also be affected by changes in the relevant tax laws and tax rates, regulations, administrative practices and principles, judicial decisions, and interpretations, in each case, possibly with retroactive effect. From time to time, federal and state level legislation in the United States has been proposed that would, if enacted into law, make significant changes to tax laws, including to certain key U.S. federal and state income tax provisions currently available to oil and natural gas exploration and development companies. Such proposed legislative changes have included, but have not been limited to, (i) the elimination of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) an extension of the amortization period for certain geological and geophysical expenditures, (iv) the elimination of certain other tax deductions and relief previously available to oil and natural gas companies, and (v) an increase in the U.S. federal income tax rate applicable to corporations (such as us). U.S. states in which we operate or own assets may also impose new or increased taxes or fees on oil and natural gas extraction. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. Additionally, the Multilateral Convention to Implement Tax Treaty Related Measures to Prevent Base Erosion and Profit Shifting (the “Multilateral Instrument”) has entered into force among the jurisdictions that have ratified it, although the United States has not yet become a signatory to the Multilateral Instrument. Such proposed legislative changes and ratification of the Multilateral Instrument in the jurisdictions in which we operate could result in further changes to our global taxation. Additionally, Mexico has enacted tax reform legislation, and a majority of the provisions became effective on January 1, 2020. These tax reforms provided for new and complex provisions that significantly change how Mexico tax entities and operations and are subject to further legislative change and administrative guidance and interpretation, which may differ from our interpretation. Future tax legislative or regulatory changes in the United States, Mexico or in any other jurisdictions in which we operate now or in the future could also adversely impact our after-tax profitability.

Our Mexican operations are subject to certain offshore regulatory and environmental laws and regulations promulgated by Mexico.

Our oil and gas operations in shallow waters off the coast of Mexico’s Tabasco state are subject to regulation by the SENER, the CNH and other Mexican regulatory bodies. The laws and regulations governing activities in the Mexican energy sector have undergone significant reformation over the past decade, and the legal regulatory framework continues to evolve as SENER, the CNH and other Mexican regulatory bodies issue new regulations and guidance. Such regulations are subject to change, and it is possible that SENER, the CNH or other Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs and/or capital expenditures for operations in Mexican offshore waters. See Part I, Items 1 and 2. Business and Properties — Government Regulation — Regulation in Shallow Waters Off the Coast of Mexico and Part I, Items 1 and 2. Business and Properties — Government Regulation — Hydrocarbon Export Regulation in Mexico for additional disclosure relating to the legal requirements imposed by SENER, CNH or other Mexican regulatory bodies to which we may be subject in the pursuit of our operations.

In addition, our oil and gas operations in shallow waters off the coast of Mexico’s Tabasco state are subject to regulation by the ASEA. The laws and regulations governing the protection of health, safety and the environment from activities in the Mexican energy sector are also relatively new, having been significantly reformed in 2013 and 2014, and the legal regulatory framework continues to evolve as ASEA and other Mexican regulatory bodies issue new regulations and guidance. Such regulations are subject to change, and it is possible that ASEA or other Mexican regulatory bodies may impose new or revised requirements that could increase our operating costs and/or capital expenditures for operations in Mexican offshore waters. See Part I, Items 1 and 2. Business and Properties — Environmental and Occupational Safety and Health Regulations — Environmental Regulation in Shallow Waters Off the Coast of Mexico for additional disclosure relating to the legal requirements imposed by ASEA or other Mexican regulatory bodies to which we may be subject in the pursuit of our operations. The permit holders must comply with requirements relating to insurance, facility construction and design, law compliance, and risk analysis scenarios.

Under the Block 7 PSC, we are also jointly and severally liable for the performance of all obligations under the PSC, including exploration, appraisal, extraction and abandonment activities and compliance with all environmental regulations, and failure to perform such obligations could result in contractual rescission of the PSC.

Three-dimensional seismic interpretation does not guarantee that hydrocarbons are present or if present, produce in economic quantities.

We rely on 3D seismic studies to assist us with assessing prospective drilling opportunities on our properties, as well as on properties that we may acquire. Such seismic studies are merely an interpretive tool and do not necessarily guarantee that hydrocarbons are present or, if present, produce in economic quantities, and seismic indications of hydrocarbon saturation are generally not reliable indicators of productive reservoir rock. These limitations of 3D seismic data may impact our drilling and operational results, and consequently our financial condition.

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We may be exposed to liabilities under the U.S. Foreign Corrupt Practices Act.

We are subject to the U.S. Foreign Corrupt Practices Act (the “FCPA”) and other laws that prohibit improper payments or offers of payments to foreign governments and their officials and political parties for the purpose of obtaining or retaining business. We may do business in the future in countries and regions in which we may face, directly or indirectly, corrupt demands by officials, tribal or insurgent organizations or private entities. Thus, we face the risk of unauthorized payments or offers of payments by one of our employees or consultants, given that these parties may not always be subject to our control. Our existing safeguards and any future improvements may prove to be less than effective, and our employees and consultants may engage in conduct for which we might be held responsible.

Under the Block 7 PSC with the CNH, we work as a consortium with our partners. Violations of the FCPA, by any consortium partner, may result in severe criminal or civil sanctions, and we may be subject to other liabilities, which could negatively affect our business, operating results and financial condition. In addition, the CNH has the authority to rescind the PSC if these violations occur.

Our operations are subject to various risks arising out of the threat of climate change that could result in increased operating costs, limit the areas in which oil and natural gas production may occur and reduce demand for the crude oil and natural gas that we produce.

Climate change continues to attract considerable public, political and scientific attention both domestically and abroad. For example, the IRA 2022 contains significant financial incentives for the development of renewable energy, alternative fuels, supporting infrastructure and carbon capture and sequestration and imposes the first ever federal fee on the emission of greenhouse gases through a methane emissions charge generated from sources in the onshore petroleum and natural gas production categories. Beginning in 2024, the methane emissions charge is set at $900 per ton of methane, and is expected to increase to $1,200 in 2025, and $1,500 in 2026 and each year after. Such additional fees could significantly impact our operating costs. Further, the incentives offered for various clean energy industries could further accelerate the transition of the economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives. These regulatory changes could ultimately decrease demand for crude oil and natural gas, increase our compliance and operating costs and consequently adversely affect our business.

Numerous other executive actions and legislative and regulatory initiatives have been enacted or may be anticipated, such as cap-and-trade programs, carbon taxes, GHG emissions reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. Further, regulations or legal actions are likely at the state, regional or international levels of government to monitor and limit existing GHG emissions as well as to restrict or eliminate such future emissions. Additionally, the threat of climate change has resulted in increasing political, litigation and financial risks associated with the production of fossil fuels and GHG emissions. See Part I, Items 1 and 2. Business and Properties — Environmental and Occupational Safety and Health Regulations — Climate Change for additional disclosure relating to risks arising out of the threat of climate change.

The adoption of legislation or regulatory programs to reduce or eliminate future GHG emissions could require us to incur significant operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce or eliminate future GHG emissions could have an adverse effect on our business, financial condition and results of operations. Also, political, financial and litigation risks may result in our restricting or canceling production activities or impairing the ability to continue to operate in an economic manner. Further, if any such effects of climate changes were to occur, they could have an adverse effect on our financial condition and results of operations.

Increasing attention to environmental, social and governance matters may impact our business.

Increasing attention to climate change and societal expectations on companies to address climate change and substitute energy sources for fossil fuels may result in increased costs, reduced demand for our products and our services and the products and services of our customers, reduced profits, increased compliance measures, investigations and litigation, and negative impacts on our stock price and access to capital markets.

Moreover, while we endeavor to publish transparent sustainability reports, the voluntary disclosures therein are sometimes based on assumptions and calculations that may or may not be representative of actual or forecasted risks or events, including the costs associated therewith. Such assumptions and calculations are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many environmental, social and governance (“ESG”) matters.

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The Board’s SSCR Committee is the primary committee responsible for overseeing and managing our ESG initiatives. Our Director of ESG is responsible for driving our sustainability initiatives, engaging with stakeholders, benchmarking our ESG data, and evaluating potential and emerging ESG drivers. We note, however, that our governance structure may not be able to adequately identify or manage ESG-related risks and opportunities, which may include failing to achieve our GHG emissions targets or other ESG-related aspirational goals, including but not limited to as a result of unforeseen costs or technical difficulties associated with achieving such goals. Moreover, given the evolving nature of GHG emissions accounting methodologies and climate science, it is possible that factors outside of our control could give rise to the need to restate or revise our emissions intensity reduction goals, cause us to miss them altogether, or limit the impact of success of achieving our goals. Additionally, to the extent we meet such targets, they may be achieved through various contractual arrangements, including the purchase of various credits or offsets that may be deemed to mitigate our ESG impact instead of actual changes in our ESG performance. However, we cannot guarantee that there will be sufficient offsets available for purchase given the increased demand from numerous businesses implementing net zero goals, or that the offsets we do purchase will successfully achieve the emissions reductions they represent.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. We and other companies in our industry publish sustainability reports that are made available to investors. Such ratings and reports are used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings may lead to increased negative investor sentiment toward us and to the diversion of investment to other industries which could have a negative impact on our stock price and/or our access to and costs of capital. Additionally, certain institutional lenders may decide not to provide funding to us based on ESG concerns, which could adversely affect our financial condition and access to capital for potential growth projects. To the extent ESG matters negatively impact our reputation, we may also be unable to compete as effectively to recruit or retain employees, which may adversely affect our operations.

Furthermore, public statements with respect to ESG matters, such as emissions reduction goals, other environmental targets, or other commitments addressing certain social issues, are becoming increasingly subject to heightened scrutiny from public and governmental authorities related to the risk of potential “greenwashing,” (i.e., misleading information or false claims overstating potential ESG benefits). For example, in March 2021, the SEC established the Climate and ESG Task Force in the Division of Enforcement to identify and address potential ESG-related misconduct, including greenwashing. Certain non-governmental organizations and other private actors have also filed lawsuits under various securities and consumer protection laws alleging that certain ESG statements, emission reduction claims, approaches to accounting for GHG emissions reductions, or other ESG-related goals or standards were misleading, false, or otherwise deceptive. As a result, we may face increased litigation risk from private parties and governmental authorities related to our ESG efforts. In addition, any alleged claims of greenwashing against us or others in our industry may lead to further negative sentiment and diversion of investments. Additionally, we could face increasing costs as we attempt to comply with and navigate further regulatory ESG-related focus and scrutiny.

A change in the jurisdictional characterization of our FERC-jurisdictional pipelines, tribal or local regulatory agencies or a change in policy by those agencies may result in increased regulation of such asset, which may cause our revenues to decline and operating expenses to increase or delay or increase the cost of expansion projects.

One of our subsidiaries owns an oil pipeline that extends from South Pass Block 89 in federal waters, offshore Louisiana, to the West Delta Receiving Station in Venice, Louisiana. This subsidiary has previously been granted a waiver of certain portions of the ICA and related regulations by the FERC. However, if the pipeline’s circumstances change, the FERC could, either at the request of other entities or on its own initiative, assert that such pipeline no longer qualifies for a waiver. In the event that the FERC determines the pipeline no longer qualified for a waiver, we would likely be required to file a tariff with the FERC, provide a cost justification for the transportation charge and provide service to all potential shippers without undue discrimination. Such a change in the jurisdictional status of transportation on this pipeline could adversely affect our results of operations. Please also see Part I, Items 1 and 2 Business and Properties — Environmental and Occupational Safety and Health Regulations — Federal Regulation of Sales and Transportation of Crude Oil for more information.

We are upgrading our accounting system to a more recent version and, if this upgraded version proves ineffective or we experience difficulties with the migration, we may be unable to timely or accurately prepare financial reports.

We are in the process of upgrading our accounting systems. Any problems or delays associated with the implementation of our accounting platform or the failure to complete such implementation on a timely basis could adversely affect our ability to report financial information as our company grows, including the filing of our quarterly or annual reports with the SEC on a timely and accurate basis. After converting from prior systems and processes, we may discover data integrity problems or other issues that, if not corrected, could impact our business or financial results.

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Risks Related to our Capital Structure and Ownership of our Common Stock

Our debt level and the covenants in our current or future agreements governing our debt, including our Bank Credit Facility, and the indentures governing our New Senior Notes, could negatively impact our financial condition, results of operations and business prospects. Our failure to comply with these covenants could result in the acceleration of our outstanding indebtedness.

The terms of the agreements governing our debt impose significant restrictions on our ability to take a number of actions that we may otherwise desire to take, including:

•incurring additional debt;

•paying dividends on stock, redeeming stock or redeeming subordinated debt;

•making investments;

•creating liens on our assets;

•selling assets;

•guaranteeing other indebtedness;

•entering into agreements that restrict dividends from our subsidiaries to us;

•merging, consolidating or transferring all or substantially all of our assets;

•hedging future production; and

•entering into transactions with affiliates.

Our level of indebtedness, and the covenants contained in the agreements governing our debt, including the Bank Credit Facility, the indentures for each of Talos Production Inc.’s (the “Issuer”) 9.000% Second-Priority Senior Secured Notes due 2029 (the “9.000% Notes”) and 9.375% Second-Priority Senior Secured Notes due 2031 (the “9.375% Notes,” and together, with the 9.000% Notes, our “New Senior Notes”), have important consequences on our operations, including:

•requiring that we dedicate a substantial portion of our cash flow from operating activities to required payments on debt, thereby reducing the availability of cash flow for working capital, capital expenditures, and other general business activities;

•limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and other general business activities;

•limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

•detracting from our ability to successfully withstand a downturn in our business or the economy generally;

•placing us at a competitive disadvantage against other less leveraged competitors; and

•making us vulnerable to increases in interest rates because debt under our Bank Credit Facility is at variable rates.

See Part II. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Significant Developments — Debt Offering for additional information on the issuance of the New Senior Notes.

We may be required to repay all or a portion of our debt on an accelerated basis in certain circumstances. If we fail to comply with the covenants and other restrictions in the agreements governing our debt, it could lead to an event of default and the acceleration of repayment of outstanding debt. Our ability to comply with these covenants and other restrictions may be affected by events beyond our control, including prevailing economic and financial conditions. Sustained low oil and natural gas prices have a material and adverse effect on our liquidity position. Our cash flow is highly dependent on the prices we receive for oil and natural gas.

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We depend on our Bank Credit Facility for a portion of our future capital needs. We are required to comply with certain debt covenants and certain financial ratios under the Bank Credit Facility. Our borrowing base under the Bank Credit Facility, which is redetermined semi-annually, is based on an amount established by the lenders after their evaluation of our proved oil and natural gas reserve values. Such borrowing base determines the amount which is available under our Bank Credit Facility. If, due to a redetermination of our borrowing base, our outstanding borrowings plus outstanding letters of credit exceed our redetermined borrowing base (referred to as a borrowing base deficiency), we could be required to repay such borrowing base deficiency. Our Bank Credit Facility allows us to cure a borrowing base deficiency through any combination of the following actions: (i) repay amounts outstanding sufficient to cure the borrowing base deficiency within 30 days after the existence of such deficiency; (ii) add additional oil and gas properties acceptable to the banks to the borrowing base and take such actions necessary to grant the banks a mortgage in such oil and gas properties within 30 days after the existence of such deficiency; (iii) pay the deficiency in four equal monthly installments with the first installment due within 30 days after the existence of such deficiency or (iv) any combination of the above. We are required to elect one of the foregoing options within 10 days after the existence of such deficiency.

We may not have sufficient funds to make such repayments. If we do not repay our debt out of cash on hand, we could attempt to restructure or refinance such debt, reduce or delay investments and capital expenditures, sell assets, or repay such debt with the proceeds from an equity offering. We cannot assure you that we will be able to generate sufficient cash flows from operating activities to pay the interest on our debt or that future borrowings, equity financings or proceeds from the sale of assets are available to pay or refinance such debt. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of our debt, including our Bank Credit Facility and the respective indentures for our New Senior Notes, may also prohibit us from taking such actions. Factors that affect our ability to raise cash through offerings of our capital stock, a refinancing of our debt or a sale of assets include financial market conditions and our market value and operating performance at the time of such offerings, refinancing or sale of assets. We cannot assure you that any such offerings, restructuring, refinancing or sale of assets would be successfully completed.

A financial crisis may impact our business and financial condition and may adversely impact our ability to obtain funding under our Bank Credit Facility or in the capital markets.

We use our cash flows from operating activities and borrowings under our Bank Credit Facility to fund our capital expenditures, and we rely on the capital markets and asset monetization transactions to provide us with additional capital for large or exceptional transactions. As such, we may not be able to access adequate funding under our Bank Credit Facility as a result of (i) a decrease in our borrowing base due to the outcome of a borrowing base redetermination or a breach or default under our Bank Credit Facility, including a breach of a financial covenant or (ii) an unwillingness or inability on the part of our lending counterparties to meet their funding obligations.

We may also face limitations on our ability to access the debt and equity capital markets and complete asset sales, increased counterparty credit risk on our derivatives contracts and requirements by our contractual counterparties to post collateral guaranteeing performance. Events involving limited liquidity, defaults, non-performance or other adverse developments that affect financial institutions, transactional counterparties or other companies in the financial services industry or the financial services industry generally, or concerns or rumors about any events of these kinds or other similar risks, have in the past and may in the future lead to market-wide liquidity problems. Most recently, on May 1, 2023, First Republic was closed by the California Department of Financial Protection and Innovation (“DFPI”), which appointed the FDIC as receiver. The FDIC sold First Republic’s deposits and most of its assets to JPMorgan Chase Bank, N.A. On March 10, 2023, Silicon Valley Bank (“SVB”) was closed by the DFPI, which appointed the FDIC as receiver. Similarly, on March 12, 2023, Signature Bank and Silvergate Capital Corp. were each swept into receivership. Although a statement by the Department of the Treasury, the Fed and the FDIC indicated that all depositors of SVB would have access to all of their money after only one business day of closure, including funds held in uninsured deposit accounts, borrowers under credit agreements, letters of credit and certain other financial instruments with SVB, Signature Bank or any other financial institution that is placed into receivership by the FDIC may be unable to access undrawn amounts thereunder. Access to funding sources and other credit arrangements could be significantly impaired by factors that affect the financial services industry or economy in general.

In addition, from time to time, we could be required to, or we or our affiliates may seek to, retire or purchase our outstanding debt through cash purchases and/or exchanges for equity or debt, open-market purchases, privately negotiated transactions or other transactions. Such debt repurchase or exchange transactions, if any, will be upon such terms and at such prices as we may determine and will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. Such transactions may give rise to taxable cancellation of indebtedness income (to the extent the fair market value of the property exchanged, or the amount of cash paid to acquire the outstanding debt, is less than the adjusted issue price of the outstanding debt) and adversely impact our ability to deduct interest expenses in respect of our debt against our taxable income in the future. This could result in a current or future tax liability, which could adversely affect our financial condition and cash flows.

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We require substantial capital expenditures to conduct our operations and replace our production, and we may be unable to obtain needed financing on satisfactory terms necessary to fund our planned capital expenditures.

We spend a substantial amount of capital for the acquisition, exploration, exploitation, development, and production of oil and natural gas reserves. We fund our capital expenditures primarily through operating cash flows, cash on hand and borrowings under our Bank Credit Facility, if necessary. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil and natural gas prices, actual drilling results, the availability of drilling rigs and other services and equipment and regulatory, technological and competitive developments. A further reduction in commodity prices may result in a further decrease in our actual capital expenditures, which would negatively impact our ability to grow production.

Our cash flow from operations and access to capital is subject to a number of variables, including:

•our proved reserves;

•the level of hydrocarbons we are able to produce from our wells;

•the prices at which our production is sold;

•our ability to acquire, locate and produce new reserves; and

•our ability to borrow under our Bank Credit Facility.

If low oil and natural gas prices, operating difficulties, declines in reserves or other factors, many of which are beyond our control, cause our revenues, cash flows from operating activities, and the borrowing base under our Bank Credit Facility to decrease, we may be limited in our ability to fund the capital necessary to complete our capital expenditure program. After utilizing our available sources of financing, we may be forced to raise additional debt or equity proceeds to fund such capital expenditures. We cannot be sure that additional debt or equity financing will be available, and we cannot be sure that cash flows provided by operations will be sufficient to meet these requirements. For example, the ability of oil and gas companies to access the equity and high yield debt markets has been, and continues to be, significantly limited.

We are a holding company that has no material assets other than our ownership of the equity interests of Talos Production Inc. Accordingly, we are dependent upon distributions from Talos Production Inc. to pay taxes, cover our corporate and other overhead expenses and pay dividends, if any, on our common stock.

We are a holding company that has no material assets other than our ownership of the equity interests of Talos Production Inc. We have no independent means of generating revenue. To the extent Talos Production Inc. has available cash, we will cause Talos Production Inc. to make distributions of cash to us, directly and indirectly through our wholly owned subsidiaries, to pay taxes, cover our corporate and other overhead expenses and pay dividends, if any, on our common stock. As we have never declared or paid any cash dividends on our common stock, we anticipate that any available cash, other than the cash distributed to us to pay taxes and cover our corporate and other overhead expenses, will be retained by Talos Production Inc. to satisfy its operational and other cash needs. Accordingly, we do not anticipate paying any cash dividends on our common stock in the foreseeable future. Although we do not expect to pay dividends on our common stock, if our Board of Directors decides to do so in the future, our ability to do so may be limited to the extent Talos Production Inc. is limited in its ability to make distributions to us, including the significant restrictions the agreements governing Talos Production Inc.’s debt impose on the ability of Talos Production Inc. to make distributions and other payments to us. To the extent that we need funds and Talos Production Inc. is restricted from making such distributions under applicable law or regulation or under the terms of our financing agreements, or is otherwise unable to provide such funds, it could materially adversely affect our liquidity and financial condition. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt — Limitation on Restricted Payments Including Dividends for additional information.

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Our estimates of future asset retirement obligations may vary significantly from period to period and unanticipated decommissioning costs could materially adversely affect our current and future financial position and results of operations.

We are required to record a liability for the discounted present value of our asset retirement obligations to plug and abandon inactive, non-producing wells, to remove inactive or damaged platforms, facilities and equipment, and to restore the land or seabed at the end of oil and natural gas operations. These costs are typically considerably more expensive for offshore operations as compared to most land-based operations due to increased regulatory scrutiny and the logistical issues associated with working in waters of various depths. Estimating future restoration and removal costs in the U.S. Gulf of Mexico is especially difficult because most of the removal obligations may be many years in the future, regulatory requirements are subject to change or more restrictive interpretation, and asset removal technologies are constantly evolving, which may result in additional or increased or decreased costs. As a result, we may significantly increase or decrease our estimated asset retirement obligations in future periods. For example, because we operate in the U.S. Gulf of Mexico, platforms, facilities and equipment are subject to damage or destruction as a result of hurricanes and other adverse weather conditions. The estimated costs to plug and abandon a well or dismantle a platform can change dramatically if the host platform from which the work was anticipated to be performed is damaged or toppled rather than structurally intact. Accordingly, our estimates of future asset retirement obligations could differ dramatically from what we may ultimately incur as a result of damage from a hurricane or other natural disaster. Also, a sustained lower commodity price environment may cause our non-operator partners to be unable to pay their share of costs, which may require us to pay our proportionate share of the defaulting party’s share of costs.

We have divested, as assignor, various leases, wells and facilities located in the U.S. Gulf of Mexico where the purchasers, as assignees, typically assume all abandonment obligations acquired. Certain of these counterparties in these divestiture transactions or third parties in existing leases have filed for bankruptcy protection or undergone associated reorganizations and may not be able to perform required abandonment obligations. Under certain circumstances, regulations or federal laws such as the OCSLA could impose joint and several strict liability and require predecessor assignors, such as us, to assume such obligations. As of December 31, 2023, we have accrued $3.3 million and $12.3 million in obligations reflected as “Other current liabilities” and “Other long-term liabilities”, respectively, on the Consolidated Balance Sheets. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies and Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 14 — Commitments and Contingencies for more information.

We may not realize the anticipated benefits from our current and future acquisitions, and we may be unable to successfully integrate future acquisitions.

Our growth strategy will, in part, rely on acquisitions. We have to plan and manage acquisitions effectively to achieve revenue growth and maintain profitability in our evolving market. We expect to grow in the future by expanding the exploitation and development of our existing assets, in addition to growing through targeted acquisitions in the U.S. Gulf of Mexico or in other basins. We may not realize all of the anticipated benefits from our future acquisitions, such as increased earnings, cost savings and revenue enhancements, for various reasons, including difficulties integrating operations and personnel, higher than expected acquisition and operating costs or other difficulties, inexperience with operating in new geographic regions, unknown liabilities, inaccurate reserve estimates and fluctuations in market prices. In particular, this risk arises in the context of the pending QuarterNorth Acquisition, which is expected to close in the first quarter of 2024.

In addition, integrating acquired businesses and properties involves a number of special risks and unforeseen difficulties can arise in integrating operations and systems and in retaining and assimilating employees. These difficulties include, among other things:

•operating a larger organization;

•coordinating geographically disparate organizations, systems and facilities;

•integrating corporate, technological and administrative functions;

•diverting management’s attention from regular business concerns;

•diverting financial resources away from existing operations;

•increasing our indebtedness; and

•incurring potential environmental or regulatory liabilities and title problems.

Any of these or other similar risks could lead to potential adverse short-term or long-term effects on our operating results. The process of integrating our operations could cause an interruption of, or loss of momentum in, the activities of our business. Members of our management may be required to devote considerable amounts of time to this integration process, which decreases the time they have to manage our business. If our management is not able to effectively manage the integration process, or if any business activities are interrupted as a result of the integration process, our business could suffer.

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Our current and future acquisitions could expose us to potentially significant liabilities, including P&A liabilities.

We expect that future acquisitions will contribute to our growth. In connection with potential future acquisitions, we may only be able to perform limited due diligence.

Successful acquisitions of oil and natural gas properties require an assessment of a number of factors, including estimates of recoverable reserves, the timing of recovering reserves, exploration potential, future oil and natural gas prices, operating costs and potential environmental, regulatory and other liabilities, including P&A liabilities. Such assessments are inexact and may not disclose all material issues or liabilities. In connection with our assessments, we perform a review of the acquired properties. However, such a review may not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities.

There may be threatened, contemplated, asserted or other claims against the acquired assets related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations. We may be successful in obtaining contractual indemnification for preclosing liabilities, including environmental liabilities, but we expect that we will generally acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. In addition, even if we are able to obtain such indemnification from the sellers, these indemnification obligations usually expire over time and could potentially expose us to unindemnified liabilities, which could materially adversely affect our production, revenues and results of operations.

Resolution of litigation could materially affect our financial position and results of operations.

Resolution of litigation could materially affect our financial position and results of operations. To the extent that potential exposure to liability is not covered by insurance or insurance coverage is inadequate, we may incur losses that could be material to our financial position or results of operations in future periods.

The corporate opportunity provisions in our Second Amended and Restated Certificate of Incorporation could enable others to benefit from corporate opportunities that might not otherwise be available to us.

Subject to the limitations of applicable law, our Second Amended and Restated Certificate of Incorporation, among other things:

•permits us to enter into transactions with entities in which one or more of our officers or directors are financially or otherwise interested;

•permits our officers or directors who are also officers, directors, employees, managing directors, or other affiliate of a Principal Stockholder (as defined in the Second Amended and Restated Certificate of Incorporation) to conduct business that competes with us and to make investments in any kind of property in which we may make investments; and

•provides that if any of our officers or directors who is also an officer, director, employee, managing director or other affiliate of the Principal Stockholders becomes aware of a potential business opportunity, transaction or other matter (other than one expressly offered to that director or officer in writing solely in his or her capacity as an director or officer of us), that director or officer will have no duty to communicate or offer that opportunity to us, and will be permitted to communicate or offer that opportunity to any other entity or individual and that director or officer will not be deemed to have acted in a manner inconsistent with his or her fiduciary duty to us or our stockholders.

Any of our directors may vote upon any contract or any other transaction between us and any affiliated corporation without regard to the fact that such person is also a director or officer of such affiliated corporation.

These provisions create the possibility that a corporate opportunity that would otherwise be available to us may be used for the benefit of others.

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Our Second Amended and Restated Certificate of Incorporation designates the Court of Chancery of the State of Delaware and, to the extent enforceable, the federal district courts of the United States of America as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.

Our Second Amended and Restated Certificate of Incorporation provides that, unless we consent in writing to the selection of an alternative forum, the sole and exclusive forum for (i) any derivative action or proceeding brought on our or our stockholders’ behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our current or former directors, officers, employees, agents and stockholders to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the DGCL, our Second Amended and Restated Certificate of Incorporation or our Second Amended and Restated Bylaws, (iv) any action as to which the DGCL confers jurisdiction to the Court of Chancery of the State of Delaware, or (v) any other action asserting a claim that is governed by the internal affairs doctrine shall be the Court of Chancery of the State of Delaware. Our Second Amended and Restated Certificate of Incorporation also provides that, to the fullest extent permitted by applicable law, the federal district courts of the U.S. are the exclusive forum for resolving any complaint asserting a cause of action arising under the Securities Act, subject to and contingent upon a final adjudication in the State of Delaware of the enforceability of such exclusive forum provision. Section 22 of the Securities Act creates concurrent jurisdiction for federal and state courts with respect to suits brought to enforce a duty or liability created by the Securities Act or the rules and regulations thereunder. Accordingly, both state and federal courts have jurisdiction to entertain claims under the Securities Act.

Notwithstanding the foregoing, the exclusive forum provision does not apply to suits brought to enforce any liability or duty created by the Exchange Act or any other claim for which the federal courts have exclusive jurisdiction. Section 27 of the Exchange Act creates exclusive federal jurisdiction over all suits brought to enforce any duty or liability created by the Exchange Act or the rules and regulations thereunder. Any person or entity purchasing or otherwise acquiring an interest in any shares of our capital stock shall be deemed to have notice of and to have consented to the forum provisions in our Second Amended and Restated Certificate of Incorporation.

These choice-of-forum provisions may limit a stockholder’s ability to bring a claim in a judicial forum that he, she or it believes to be favorable for disputes with us or our directors, officers or other employees, which may discourage such lawsuits. Alternatively, if a court were to find these provisions of our Second Amended and Restated Certificate of Incorporation inapplicable or unenforceable with respect to one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could materially adversely affect our business, financial condition and results of operations and result in a diversion of the time and resources of our management and board of directors.

While the Delaware courts have determined that choice of forum provisions of this type are facially valid, uncertainty exists as to whether a court would enforce such provision, and as such, a stockholder may nevertheless seek to bring a claim in a venue other than those designated in our exclusive forum provision. In such instance, to the extent applicable, we would expect to vigorously assert the validity and enforceability of our exclusive forum provision. This may require additional costs associated with resolving such action in other jurisdictions and there can be no assurance that the provisions will be enforced by a court in those other jurisdictions.

Future sales, or the perception of future sales, by us or our existing stockholders in the public market could cause the market price for our common stock to decline.

The sale of substantial amounts of shares of our common stock in the public market, or the perception that such sales could occur, could harm the prevailing market price of shares of our common stock. These sales, or the possibility that these sales may occur, also might make it more difficult for us to sell equity securities in the future at a time and at a price that we deem appropriate.

Certain holders of our common stock, including certain former stockholders of EnVen, are entitled to rights with respect to registration of approximately 17.9 million shares of our common stock (representing approximately 11.3% of the outstanding shares of our common stock as of February 21, 2024) under the Securities Act pursuant to certain registration rights agreements. In addition, we intend to enter into a registration rights agreement in connection with the QuarterNorth Acquisition, which will become effective at the closing, which will grant registration rights to approximately 24.8 million shares of our common stock (representing approximately 13.5% of the outstanding shares of our common stock immediately following the closing of the acquisition. If these holders of our common stock, by exercising their registration rights, sell a large number of shares, the market price for our common stock could be adversely affected.

The interests of the Slim Family and its affiliates may differ from the interests of our other stockholders.

As of February 21, 2024, an entity controlled by the Carlos Slim Helu and his family members (collectively, the “Slim Family”) beneficially owned and possessed voting power approximately 21.9% of our common stock.

The Slim Family has significant influence over matters submitted to stockholders for approval, including changes in capital structure, transactions requiring stockholder approval under Delaware law, and corporate governance. The Slim Family may have different interests than other holders of our common stock and may make decisions adverse to your interests.

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Among other things, the Slim Family’s concentration of voting power could delay or defer a sale of us that many of our other stockholders support. This concentration of voting power could discourage a potential investor from seeking to acquire our common stock and, as a result, might harm the market price of our common stock.

Risks Related to the QuarterNorth Acquisition and our Integration of QuarterNorth Into our Business

The market price for our common stock following the closing of the QuarterNorth Acquisition may be affected by factors different from those that historically have affected or currently affect our common stock.

Our financial position may differ from our financial position before the completion of the QuarterNorth Acquisition, and the results of operations of the combined company may be affected by some factors that are different from those currently affecting our results of operations. Accordingly, the market price and performance of our common stock is likely to be different from the performance of our common stock in the absence of the QuarterNorth Acquisition. In addition, general fluctuations in stock markets could have a material adverse effect on the market for, or liquidity of, our common stock, regardless of our actual operating performance.

Our stockholders, as of immediately prior to the QuarterNorth Acquisition, will have reduced ownership in the combined company after closing of the transaction.

Based on the number of shares of common stock outstanding immediately following the closing of the QuarterNorth Acquisition, our existing stockholders would own approximately 86.5% of the outstanding shares of the combined company and QuarterNorth’s existing members would own approximately 13.5% of the outstanding shares of the combined company. As a result, our current stockholders will have less influence on the policies of the combined company than they currently have following the closing of the QuarterNorth Acquisition.

We may not consummate the QuarterNorth Acquisition on the terms currently contemplated or at all.

We may not consummate the QuarterNorth Acquisition, which is subject to the satisfaction of customary closing conditions. Many of the conditions to completion of the QuarterNorth Acquisition are not within either our or QuarterNorth’s control, and neither we nor QuarterNorth can predict when, or if, these conditions will be satisfied. If any of these conditions are not satisfied or waived prior to the outside date, it is possible that the QuarterNorth Acquisition may be terminated. Although we have agreed with QuarterNorth to use reasonable best efforts, subject to certain limitations, to promptly complete the QuarterNorth Acquisition, these and other conditions to the completion of the QuarterNorth Acquisition may fail to be satisfied. In addition, satisfying the conditions to and completion of the QuarterNorth Acquisition may take longer, and could cost more, and require additional borrowings, than we currently expect. There can be no assurance that such conditions will be satisfied or that the QuarterNorth Acquisition will be consummated on the terms currently contemplated or at all. If additional borrowings are required to consummate the QuarterNorth Acquisition, our total debt and leverage will be greater than currently anticipated, and our availability under our Bank Credit Facility will be reduced by a corresponding amount. If we fail to complete the QuarterNorth Acquisition, our management will have broad discretion in the use of proceeds from the January Equity Offering (as defined herein), and may use such proceeds in ways in which you do not approve.

Failure to complete the QuarterNorth Acquisition could negatively impact our stock price and have a material adverse effect on our results of operations, cash flows and financial position.

If the QuarterNorth Acquisition is not completed for any reason, including as a result of failure to obtain all requisite regulatory approvals, we may be materially adversely affected and, without realizing any of the benefits of having completed the acquisition, we would be subject to a number of risks, including the following:

•we may experience negative reactions from the financial markets, including negative impacts on our stock price;

•we may experience negative reactions from our customers, distributors, suppliers, vendors, landlords, joint venture partners and other business partners;

•we will still be required to pay certain significant costs relating to the acquisition, such as legal, accounting, financial advisor and printing fees;

•QuarterNorth may be entitled to receive the full amount of the deposit pursuant to the Agreement and Plan of Merger, dated as of January 13, 2024, by and among the Company, QuarterNorth, Compass Star Merger Sub Inc. and the Equityholder Representatives named therein (the “QuarterNorth Merger Agreement”);

•the QuarterNorth Merger Agreement places certain restrictions on our conduct pursuant to the terms thereof, which may delay or prevent us from undertaking business opportunities that, absent the QuarterNorth Merger Agreement, may have been pursued;

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•matters relating to the acquisition (including integration planning) require substantial commitments of time and resources by our management, which may have resulted in the distraction of our management from ongoing business operations and pursuing other opportunities that could have been beneficial to us; and

•litigation related to any failure to complete the acquisition or related to any enforcement proceeding commenced against us to perform our obligations pursuant to the QuarterNorth Merger Agreement.

If the QuarterNorth Acquisition is not completed, the risks described above may materialize and they may have a material adverse effect on our results of operations, cash flows, financial position and stock price.

Future sales or issuances of our common stock could have a negative impact on our common stock price.

If holders of our common stock, by exercising registration rights or otherwise, sell a large number of shares, the market price for our common stock could be adversely affected. It is possible that some QuarterNorth shareholders will decide to sell some or all of the shares of our common stock that they received as consideration in the QuarterNorth Acquisition. Shortly after the closing of the QuarterNorth Acquisition, we are obligated to file a registration statement covering the resale of potentially all of the shares issued to the QuarterNorth shareholders. In addition, in connection with the closing of the QuarterNorth Acquisition, we will enter into a registration rights agreement with certain QuarterNorth shareholders, pursuant to which we will grant such holders certain demand, “piggy-back” registration rights with respect to shares of our common stock received by such holders in the acquisition, subject to a lock-up period of 60 days following the closing.

Following the closing of the QuarterNorth Acquisition, the QuarterNorth shareholders will collectively own 24.8 million shares of our common stock, representing approximately 13.5% of the outstanding shares of our common stock after the closing of that acquisition. We expect that at least a majority of those shares will be subject to the lock-up period.

Any disposition by a significant stockholder of our common stock, including by one of the RRA Holders, or the perception in the market that such dispositions could occur, may cause the price of our common stock to fall. Any such decline could impair the combined company’s ability to raise capital through future sales of our common stock. Further, our common stock may not qualify for investment indices and any such failure may discourage new investors from investing in our common stock.

Our and QuarterNorth’s business relationships may be subject to disruption due to uncertainty associated with the QuarterNorth Acquisition, which could have a material adverse effect on the results of operations, cash flows and financial position of us pending and following the closing of the QuarterNorth Acquisition.

Parties with which we or QuarterNorth do business may experience uncertainty associated with the QuarterNorth Acquisition, including with respect to current or future business relationships with us following the closing of the QuarterNorth Acquisition. Our and QuarterNorth’s business relationship may be subject to disruption as customers, distributors, suppliers, vendors, landlords, joint venture partners and other business partners may attempt to delay or defer entering into new business relationships, negotiate changes in existing business relationships or consider entering into business relationships with parties other than us or QuarterNorth following the QuarterNorth Acquisition. These disruptions could have a material and adverse effect on the results of operations, cash flows and financial position of us, regardless of whether the QuarterNorth Acquisition is completed, as well as a material and adverse effect on our ability to realize the expected benefits of the QuarterNorth Acquisition.

The QuarterNorth Merger Agreement subjects us to restrictions on our business activities prior to the Effective Time.

The QuarterNorth Merger Agreement subjects us to restrictions on our business activities prior to the closing of the QuarterNorth Acquisition (the “Effective Time”). The QuarterNorth Merger Agreement obligates each of us and QuarterNorth to generally conduct our businesses in the ordinary course until the Effective Time and to use commercially reasonable efforts to preserve intact our present business organizations. Additionally, the QuarterNorth Merger Agreement restricts us and QuarterNorth from certain other actions prior to the Effective Time, including, among other things, (i) amending our respective organizational documents, (ii) issuing, selling, pledging, disposing of or encumbering any of our respective securities and (iii) merging, consolidating, combining or amalgamating with any person or acquiring any assets or incurring indebtedness in excess of certain monetary thresholds.

These restrictions could prevent us from pursuing certain business opportunities that arise prior to the Effective Time.

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The failure to successfully integrate our business and operations with QuarterNorth in the expected time frame may adversely affect our future results.

The integration process of our business with those of QuarterNorth could result in the loss of key employees, customers, providers, vendors or business partners, the disruption of each company’s or all companies’ ongoing businesses, inconsistencies in standards, controls, procedures and policies, potential unknown liabilities and unforeseen expenses, delays, or regulatory conditions or higher than expected integration costs and an overall post-completion integration process that takes longer than originally anticipated. Specifically, the following issues, among others, must be addressed in integrating the operations in order to realize the anticipated benefits of the QuarterNorth Acquisition:

•combining the companies’ operations and corporate functions and the resulting difficulties associated with managing a larger, more complex, integrated business;

•combining our business with QuarterNorth in a manner that permits the combined company to achieve any cost savings or operating synergies anticipated to result from the QuarterNorth Acquisition;

•reducing the additional and unforeseen expenses such that integration costs are not more than anticipated;

•minimizing the loss of key employees;

•identifying and eliminating redundant functions and assets;

•maintaining existing agreements with customers, providers and vendors or business partners and avoiding delays in entering into new agreements with prospective customers, providers and vendors or business partners; and

•consolidating the companies’ operating, administrative and information technology infrastructure.

In addition, at times the attention of certain members of our management and resources may be focused on the integration of the businesses of the companies and diverted from day-to-day business operations or other opportunities that may have been beneficial to us, which may disrupt our ongoing business.

Item 1B. Unresolved Staff Comments

None.

Item 1C. Cybersecurity

Assessing, Identifying and Managing Cybersecurity Risks — We strive to align our cybersecurity operating model with the National Institute of Standards and Technology (“NIST”) Cybersecurity Framework to enhance our ability to protect, detect, respond, and recover from potential cybersecurity threats. Our cybersecurity team actively works to assess, identify and manage risks in our information systems in order to protect the confidentiality, integrity and availability of our digital infrastructure. The cybersecurity team meets regularly to evaluate potential threats, discuss best practices and identify new solutions to help mitigate cyber risks.

We engage third-party service providers to conduct evaluations of our cybersecurity controls through penetration testing, independent audits and consulting on best practices to address existing and new challenges. These evaluations include testing the design and operational effectiveness of our cybersecurity controls. To further enhance the capabilities of our internal systems, we utilize third-party vendors to provide extended coverage of our information technology and operational technology environments. We also share and receive threat intelligence with companies in the energy sector, government agencies, information sharing and analysis centers and cybersecurity associations in order to monitor and address developments in the cybersecurity environment.

To serve as an additional protection from outside threats, we also seek to prepare our employees and contractors about cybersecurity risks through training, simulated phishing exercises and awareness campaigns. We have implemented software and processes to help identify and evaluate risks from cybersecurity threats associated with third-party service vendors. In the event of a cybersecurity incident deemed to have a moderate or higher business impact, we have an incident response plan to notify senior leadership and to address how to contain the incident, mitigate the impact, and restore normal operations efficiently.

Cybersecurity Risk Assessment — We have integrated cybersecurity risk management into our broader Enterprise Risk Management (“ERM”) framework to promote a company-wide culture of cybersecurity risk management. Our ERM framework is designed to identify and prioritize company-wide risks, including cybersecurity threats, and integrate mitigation measures into our business, operational and capital structure planning activities. The purpose of the ERM framework is to enable the Board and executive leadership to (1) align risk management with strategic objectives, (2) identify risks, including cybersecurity risks, throughout the organization, (3) assess and prioritize risks that could impact the Company’s operational and strategic objectives, (4) develop and monitor risk mitigation initiatives, and (5) report and assess material risks, mitigation strategies and progress to the Board and/or its applicable committees. Cybersecurity risk is reviewed by a cross-functional, management-level ERM Steering Committee as part of the Company’s overall enterprise risk management program.

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Board of Directors’ Oversight of Risks from Cybersecurity Threats — The Board of Directors is aware of the importance of managing risks associated with cybersecurity threats. The Audit Committee has been delegated responsibility by the Board for overseeing the Company’s overall enterprise risk management program, including cybersecurity risk. The Audit Committee receives reports at least quarterly from the Director of Information Technology regarding cybersecurity matters, which may include, among other things, the results of cybersecurity audits, cybersecurity maturity assessments, other information technology matters, risk mitigation strategies, data protection and progress on initiatives. The Audit Committee Chair is responsible for reporting key cybersecurity issues regarding current and potential material cybersecurity threats and our risk mitigation response strategies to the Board. To further inform our Board and management on emerging cybersecurity issues, we periodically engage third-party cybersecurity experts to report to the Audit Committee, other directors, and management, as applicable, on topics that may include, among other things, the latest cybersecurity trends, new technologies, evolving threats in the marketplace, proposed initiatives, legislation, and reporting standards.

Management’s Role in Assessing and Managing Cybersecurity Threats — Our information technology team is responsible for assessing, identifying and managing cybersecurity risks. Top cybersecurity risks are also integrated into our overall ERM framework and overseen at the management level by the ERM Steering Committee. Our Director of Information Technology, who reports directly to the Chief Financial Officer (“CFO”) and Senior Vice President and is a member of the ERM Steering Committee, is responsible for our efforts to comply with applicable cybersecurity standards, establish cybersecurity protocols and protect the integrity, confidentiality and availability of our information technology infrastructure. Technology and cybersecurity policy decisions are made by our Director of Information Technology in consultation with our CFO and Senior Vice President. In addition, our Director of Information Technology has a direct line of communication with our President and CEO and Executive Vice President and General Counsel as needed. Our Director of Information Technology has over 20 years of experience in cybersecurity, holds a Master of Science in Cybersecurity from the University of Houston and is a Certified Information Systems Security Professional and a Boardroom Certified Qualified Technology Expert.

Impact of Risks from Cybersecurity Threats — As of the date of this Annual Report, we are not aware of previous cybersecurity incidents that have materially affected or are reasonably likely to materially affect the Company, although the Company regularly experiences cybersecurity incidents that are not deemed material to our operations. Examples of cybersecurity threats we face include incidents common to most companies in the energy industry, such as phishing, business email compromise, ransomware and denial-of-service, as well as attacks from more advanced sources, including nation state actors, that target companies in the energy industry. Our customers, suppliers, subcontractors and joint venture partners face similar cybersecurity threats, and a cybersecurity incident impacting us or any of these entities could materially adversely disrupt our operations, including our drilling operations, and affect our performance and results of operations. We acknowledge that cybersecurity threats are continually evolving, and the possibility of future cybersecurity incidents remains. Please see Part I, Item 1A. “Risk Factors — Risks Related to our Business and the Oil and Natural Gas Industry — Our business could be negatively affected by security threats, including cybersecurity threats, terrorist attacks and other disruptions.”

Item 3. Legal Proceedings

We are named as a party in certain lawsuits and regulatory proceedings arising in the ordinary course of business. We do not expect that these matters, individually or in the aggregate, will have a material adverse effect on our financial condition.

In June 2019, David M. Dunwoody, Jr., former President of EnVen, filed a lawsuit against EnVen in Texas District Court alleging that the circumstances of his resignation entitled him to the severance payments and benefits under his employment agreement dated as of November 6, 2015 as a resignation for “Good Reason.” In September 2021, the trial court entered a judgment in favor of Mr. Dunwoody, inclusive of Mr. Dunwoody’s legal fees and interest. EnVen filed a Notice of Appeal in December 2021. In April 2023, the appellate court affirmed the trial court’s judgment. The Company filed a petition for review with the Texas Supreme Court on August 2, 2023, which was denied on January 26, 2024. As of December 31, 2023, the Company has recorded $14.3 million as “Other current liabilities” on the Condensed Consolidated Balance Sheets related to the litigation.

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On November 11, 2013, two lawsuits were filed, and on November 12, 2013, a third lawsuit was filed, against Stone Energy Corporation (“Stone”) and other named co-defendants, by the Parish of Jefferson (“Jefferson Parish”), on behalf of Jefferson Parish and the State of Louisiana, in the 24th Judicial District Court for the Parish of Jefferson, State of Louisiana, alleging violations of the State and Local Coastal Resources Management Act of 1978, as amended, and the applicable regulations, rules, orders and ordinances thereunder (collectively, the “CRMA”), relating to certain of the defendants’ alleged oil and gas operations in Jefferson Parish, and seeking to recover alleged unspecified damages to the Jefferson Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Jefferson Parish Coastal Zone and related costs and attorney’s fees. In March and April 2016, the Louisiana Attorney General and the Louisiana Department of Natural Resources, respectively, intervened in the three lawsuits. In connection with Stone’s filing of bankruptcy in December 2016, Jefferson Parish dismissed its claims against Stone in these three lawsuits without prejudice to refiling; the claims of the Louisiana Attorney General and the Louisiana Department of Natural Resources were not similarly dismissed. In 2018, the Jefferson Parish lawsuits were removed to the United States District Court for the Eastern District of Louisiana. The plaintiffs moved to remand the lawsuit to the state courts. Plaintiffs’ motions to remand were submitted to the state court for decision in two of the lawsuits on February 15, 2023. Plaintiffs filed motions to remand, which the District Court granted, remanding the lawsuits back to the 24th Judicial District Court for the Parish of Jefferson. Defendants who removed the Jefferson Parish lawsuits have filed notices of appeal providing notice that they intend to appeal the District Court’s orders granting Plaintiffs’ motion to remand.

On November 8, 2013, a lawsuit was filed against Stone and other named co-defendants by the Parish of Plaquemines (“Plaquemines Parish”), on behalf of Plaquemines Parish and the State of Louisiana, in the 25th Judicial District Court for the Parish of Plaquemines, State of Louisiana, alleging violations of the CRMA, relating to certain of the defendants’ alleged oil and gas operations in Plaquemines Parish, and seeking to recover alleged unspecified damages to the Plaquemines Parish Coastal Zone and remedies, including unspecified monetary damages and declaratory relief, restoration of the Plaquemines Parish Coastal Zone, and related costs and attorney’s fees. In March and April 2016, the Louisiana Attorney General and the Louisiana Department of Natural Resources, respectively, intervened in the lawsuit. In connection with Stone’s filing of bankruptcy in December 2016, Plaquemines Parish dismissed its claims against Stone without prejudice to refiling; the claims of the Louisiana Attorney General and the Louisiana Department of Natural Resources were not similarly dismissed. In state court, the Plaquemines Parish lawsuit was stayed pending the conclusion of trials in five other cases, also filed in Plaquemines Parish and alleging violations of the CRMA, but not involving Stone. However, in 2018, the Plaquemines Parish lawsuit was removed to the United States District Court for the Eastern District of Louisiana. The plaintiffs have moved to remand the lawsuit to the state courts, but the case was administratively closed in federal court pending the appeal of another case, also filed in Plaquemines Parish and alleging violations of the CRMA, but not involving Stone. That appeal was resolved by the United States Court of Appeals for the Fifth Circuit on December 15, 2022, and on December, 22, 2022, plaintiffs filed a motion in federal court to re-open the lawsuit. The United States Court of Appeals for the Fifth Circuit has not yet ruled on the plaintiffs’ motion to re-open. Plaintiffs filed motions to remand, which the District Court granted. However, the District Court also granted Defendants’ motion to stay the remand order pending appeal. That appeal is currently pending before the United States Court of Appeals for the Fifth Circuit.

Legal proceedings are subject to substantial uncertainties concerning the outcome of material factual and legal issues relating to the litigation. Accordingly, we cannot currently predict the manner and timing of the resolution of some of these matters and may be unable to estimate a range of possible losses or any minimum loss from such matters. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 14 — Commitments and Contingencies for more information.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuers Purchases of Equity Securities

Market for Common Stock

Our common stock is listed on the NYSE under the symbol “TALO”.

Holders of Record

Pursuant to the records of our transfer agent, as of February 21, 2024, there were approximately 180 holders of record of our common stock.

Dividends

We have never declared or paid any cash dividends on our common stock, and we anticipate that any available cash, other than the cash distributed to us to pay taxes and cover our corporate and other overhead expenses, will be retained by Talos Production Inc. to satisfy its operational and other cash needs. Accordingly, we do not anticipate paying any cash dividends on our common stock in the foreseeable future. Although we do not expect to pay dividends on our common stock, if our Board of Directors decides to do so in the future, our ability to do so may be limited to the extent Talos Production Inc. is limited in its ability to make distributions to us, including the significant restrictions that the agreements governing Talos Production Inc.’s debt impose on the ability of Talos Production Inc. to make distributions and other payments to us. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt — Limitation on Restricted Payments Including Dividends for additional information.

Securities Authorized for Issuance Under Equity Compensation Plans

See Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters for information regarding securities authorized for issuance under equity compensation plans.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Our Board of Directors authorized a stock repurchase program on March 20, 2023 with an approved limit of $100.0 million and no set term limits. Repurchases may be made from time to time in the open market, in a privately negotiated transaction, or by such other means as will comply with applicable state and federal securities laws. The timing of any repurchases under the share repurchase program will depend on market conditions, contractual limitations and other considerations. The program may be extended, modified, suspended or discontinued at any time, and does not obligate the Company to repurchase any dollar amount or number of shares. There were no shares of common stock repurchased during the three months ended December 31, 2023. As of December 31, 2023, there is $52.5 million remaining under the authorized program.

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Stockholder Return Performance Presentation

The following graph is included in accordance with the SEC’s executive compensation disclosure rules. This historic stock price performance is not necessarily indicative of future stock performance. The graph compares the change in the cumulative total return of our common stock, the Dow Jones U.S. Exploration and Production Index, and the S&P 500 Index for December 31, 2018 through December 31, 2023. The graph assumes that $100 was invested in our common stock and each index on December 31, 2018 and that dividends were reinvested.

 

	2018		2019		2020		2021		2022		2023
Talos Energy Inc.	$	100	$	185	$	50	$	60	$	116	$	87
S&P 500 Index	$	100	$	131	$	156	$	200	$	164	$	207
Dow Jones U.S. Exploration & Production Index	$	100	$	110	$	74	$	131	$	208	$	216

The performance graph and the information contained in this section is not “soliciting material,” is being “furnished” not “filed” with the SEC and is not to be incorporated by reference into any of our filings under the Securities Act or the Exchange Act whether made before or after the date hereof and irrespective of any general incorporation language contained in such filing.

Item 6. [Reserved]

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations is based on, and should be read in conjunction with our Consolidated Financial Statements and the Notes to Consolidated Financial Statements set forth in Part IV, Item 15. Exhibits and Financial Statement Schedules; Part I, Items 1 and 2. Business and Properties; Part I, Item 1A. Risk Factors; and Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk. This discussion and analysis contains forward-looking statements that involve risk and uncertainties. Actual results may differ materially from those anticipated in these forward-looking statements.

This section of this Annual Report generally discusses 2023 and 2022 items and year-to-year comparisons between 2023 and 2022. Discussions of 2021 items and year-to-year comparisons between 2022 and 2021 that are not included in this Annual Report can be found in “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of the Company’s Annual Report on Form 10-K for the year ended December 31, 2022 filed with the SEC.

Our Business

We are a technically driven independent exploration and production company focused on safely and efficiently maximizing long-term value through our operations, currently in the U.S. and offshore Mexico both through Upstream and the development of low carbon solutions opportunities. We leverage decades of technical and offshore operational expertise in the acquisition, exploration and development of assets in key geological trends that are present in many offshore basins around the world. We are also utilizing our expertise to develop CCS projects to help reduce industrial emissions along the coast of the U.S. Gulf of Mexico.

We have historically focused our operations in the U.S. Gulf of Mexico because of our deep experience and technical expertise in the basin, which maintains favorable geologic and economic conditions, including multiple reservoir formations, comprehensive geologic and geophysical databases, extensive infrastructure and an attractive and robust asset acquisition market. Additionally, we have access to state-of-the-art three-dimensional seismic data, some of which is aided by new and enhanced reprocessing techniques that have not been previously applied to our current acreage position. We use our broad regional seismic database and our reprocessing efforts to generate a large and expanding inventory of high-quality prospects, which we believe greatly improves our development and exploration success. The application of our extensive seismic database, coupled with our ability to effectively reprocess this seismic data, allows us to both optimize our organic drilling program and better evaluate a wide range of business development opportunities, including acquisitions and collaborative arrangement opportunities, among others.

Outlook

We operate within an industry sector directly impacted by the energy transition. The energy transition will require both significant new investments in low-carbon energies and continued use of traditional hydrocarbons to meet the expected energy demand of an expanding global economy.

Our historical focus in the Gulf of Mexico results in an asset profile that differentiates us from the typical shale-driven onshore exploration and production companies. We are continuing to build operational scale. We expect that the QuarterNorth Acquisition, discussed below, will add scale to our business both in terms of production and operated infrastructure, while also diversifying our production across a broader asset base. While we are currently a pure play Gulf of Mexico company, diversification outside of our existing operational areas is always a possibility.

Oil and gas prices are expected to remain relatively stable in 2024. However, geopolitical tensions may contribute to hydrocarbon price volatility. For now, it looks like inflation will return to normal without a recession. Future changes to the benchmark interest rate remain uncertain. However, a modest reduction to the benchmark interest rate is the most likely scenario for 2024. We expect to scale back planned capital expenditures in 2024 compared to 2023. We remain exposed to increasing regulatory scrutiny and potential operational disruptions from weather-related events in the Gulf of Mexico. The limited scope of BOEM's 2024-2029 offshore oil and gas leasing program is disappointing to offshore producers. However, we have the ability to increase our acreage inventory through exchanges and mergers and acquisitions.

Significant Developments

The following encompasses significant developments since the filing of our Annual Report on Form 10-K for the year ended December 31, 2022:

QuarterNorth Acquisition — On January 13, 2024, we executed the QuarterNorth Merger Agreement to acquire QuarterNorth, a privately-held U.S Gulf of Mexico exploration and production company. The QuarterNorth Acquisition is expected to close during the first quarter of 2024. Consideration for the QuarterNorth Acquisition consists of (i) approximately $964.9 million in cash, (ii) the amount of net unrestricted cash of QuarterNorth as of December 31, 2023 and (iii) 24.8 million shares of the Company’s common stock.

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Equity Offering — On January 22, 2024, we closed an upsized firm commitment underwritten public offering (the “January Equity Offering”) of 34,500,000 shares of our common stock, resulting in net proceeds to us of approximately $388.5 million, after deducting underwriting discounts and commissions and before estimated offering expenses. We intend to use the net proceeds from the January Equity Offering to fund a portion of the cash consideration for the QuarterNorth Acquisition. However, the QuarterNorth Acquisition remains subject to certain conditions to closing. Pending the use of the proceeds of the January Equity Offering as described above, we may temporarily use all or a portion of such proceeds to reduce the borrowings outstanding under our Bank Credit Facility. In the event that the QuarterNorth Acquisition is not completed, the proceeds from the January Equity Offering will be used for general corporate purposes.

Debt Offering — On February 7, 2024, Talos Production, Inc. issued in an upsized offering (the “Debt Offering”) $1,250.0 million in aggregate principal amount of second-priority senior secured notes, consisting of $625.0 million aggregate principal amount of 9.000% second-priority senior secured notes due 2029 (the “9.000% Notes”) and $625.0 million aggregate principal amount of 9.375% second-priority senior secured notes due 2031 (the “9.375% Notes” and, together with the 9.000% Notes, the “New Senior Notes”), in a private offering to eligible purchasers that is exempt from registration under the Securities Act. The New Senior Notes were issued pursuant to an indenture governing the 9.000% Notes (the “9.000% Notes Indenture”) and an indenture governing the 9.375% Notes (the “9.375% Notes Indenture” and, together with the 9.000% Notes Indenture, the “Indentures”), each dated as of February 7, 2024 and by and among the Company, Talos Production Inc., the subsidiary guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent. The New Senior Notes rank equally in right of payment with all existing and future senior obligations of the issuer and the guarantors thereto. The issuance of the New Senior Notes on February 7, 2024, resulted in $1,250.0 million gross proceeds. The net proceeds from the Debt Offering (i) are expected to fund a portion of the cash consideration for the pending QuarterNorth Acquisition as discussed above, (ii) funded the redemption (the “Redemptions”) of all of the outstanding 11.75% Notes (defined below) and 12.00% Notes (defined below) (the “Senior Notes”), and (iii) paid premiums, fees and expenses related to the Redemptions and the issuance of the New Senior Notes. We intend to use any remaining net proceeds for general corporate purposes, which may include the repayment of a portion of the outstanding borrowings under the Bank Credit Facility.

An aggregate of $340 million principal amount of the New Senior Notes will be subject to a “special mandatory redemption” in the event that the transactions contemplated by the QuarterNorth Merger Agreement are not consummated on or before May 31, 2024 (or up to September 30, 2024 solely in the event the parties require additional time to satisfy certain requirements under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, pursuant to the terms of the QuarterNorth Merger Agreement), or if we notify the trustee of the New Senior Notes that we will not pursue the consummation of the QuarterNorth Acquisition.

Mexico Divestiture — On September 27, 2023, we sold a 49.9% interest in Talos Energy Mexico 7, S. de R.L. de C.V., a wholly owned subsidiary of the Company, to Zamajal, S.A. de C.V., a wholly owned subsidiary of Grupo Carso (the “Mexico Divestiture”). See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.

Common Stock Repurchase Program — On March 20, 2023, we announced that our Board of Directors approved a $100.0 million common stock repurchase program. As of December 31, 2023, we have repurchased 3.4 million shares for a total of $47.5 million resulting in $52.5 million remaining under the authorized program. All repurchased shares are held in treasury.

Factors Affecting the Comparability of our Financial Condition and Results of Operations

The following items affect the comparability of our financial condition and results of operations for periods presented herein and could potentially continue to affect our future financial condition and results of operations.

EnVen Acquisition — On February 13, 2023, we acquired EnVen Energy Corporation (“EnVen”), a private operator in the Deepwater U.S. Gulf of Mexico (the “EnVen Acquisition”). See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.

Planned Downtime — We are vulnerable to downtime events impacting the transportation, gathering and processing of production. We produce the Phoenix Field through the HP-I that is operated by Helix. Helix is required to disconnect and dry-dock the HP-I every two to three years for inspection as required by the U.S. Coast Guard, during which time we are unable to produce the Phoenix Field.

During the year ended December 31, 2022, Helix dry-docked the HP-I. After conducting sea trials, production resumed in mid-September, resulting in a total shut-in period of 41 days. The shut-in resulted in an estimated deferred production of approximately 1.6 MBoepd for the year ended December 31, 2022, based on production rates prior to the shut-in. The next dry-dock is scheduled for the first half of 2024 with a projected shut-in period of approximately 55 days.

During the year ended December 31, 2022, we experienced approximately 26 days of planned third-party downtime due to maintenance of the Shell Odyssey Pipeline, which carries our production primarily from our Ram Powell Field, Main Pass 288 Field and non-operated Delta House facility. Production resumed in October 2022. We estimate the shut-in resulted in deferred production of approximately 0.7 MBoepd for the year ended December 31, 2022, based on production rates prior to the shut-in.

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Eugene Island Pipeline System — During the first quarter of 2022, we experienced approximately 40 days of unplanned third-party downtime due to maintenance of the Eugene Island Pipeline System, which carries our production from the Phoenix Field and Green Canyon 18 Field. For the year ended December 31, 2022, we estimate the shut-in has resulted in deferred production of approximately 1.2 MBoepd based on production rates prior to the shut-in.

Known Trends and Uncertainties

Volatility in Oil, Natural Gas and NGL Prices — Historically, the markets for oil and natural gas have been volatile. Oil, natural gas and NGL prices are subject to wide fluctuations in supply and demand. Our revenue, profitability, access to capital and future rate of growth depends upon the price we receive for our sales of oil, natural gas and NGL production.

During January 1, 2023 through December 31, 2023, the daily spot prices for NYMEX WTI crude oil ranged from a high of $93.67 per Bbl to a low of $66.61 per Bbl and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $3.78 per MMBtu to a low of $1.74 per MMBtu. Although we cannot predict the occurrence of events that may affect future commodity prices or the degree to which these prices will be affected, the prices for any commodity that we produce will generally approximate current market prices in the geographic region of production. We hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 6 — Financial Instruments for more additional information regarding our commodity derivative positions as of December 31, 2023.

The U.S. Energy Information Administration (“EIA”) published its February 2024 Short-Term Energy Outlook on February 6, 2024. The EIA expects natural gas prices to average $2.65 per MMBtu in 2024, and rise to an average of $2.94 per MMBtu in 2025, up from an average of $2.54 per MMBtu in 2023. Prices are expected to increase because of slowing growth in natural gas production and increasing U.S. liquefied natural gas exports, particularly in 2025 following the addition of new export capacity in late 2024. However, the EIA expects upward price pressures to be limited by relatively flat consumption of natural gas in the electric power sector and persistently high inventories. The EIA also expects the NYMEX WTI spot price will average $77.68 per Bbl in 2024 and then fall to $74.98 per Bbl in 2025 when it expects production growth will slightly outpace demand growth, allowing inventories to build modestly and place some downward pressure on crude oil prices. Recent developments in the Middle East increase the risk for supply disruptions over the EIA forecast, which could result in higher and more volatile prices than the EIA currently forecast. Heightened tensions around the critical Red Sea shipping channel and other developments in the Middle East have added upward price pressure since early December 2023 and have the potential to disrupt global oil trade flows and drive up global oil prices further should they escalate or persist.

Inflation of Cost of Goods, Services and Personnel — Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increase, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices do. In addition, the U.S. inflation rate began increasing in 2021, peaked in the middle of 2022 and began to gradually decline in the second half of 2022. These inflationary pressures may also result in increases to the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise. Sustained levels of high inflation could likely cause the Fed and other central banks to further increase interest rates, which could have the effects of raising the cost of capital and depressing economic growth, either or both of which could hurt our business. In 2022 and 2023, the Fed raised its benchmark interest rate 11 times. The latest interest rate hike in July 2023 increased the federal funds rate to a range of 5.25%-5.50%, its highest level since 2001. The Fed wants inflation to return to its 2% goal over time, and even though inflation is declining, it is still high in absolute terms. Future changes to the benchmark interest rate remain uncertain.

Impairment of Oil and Natural Gas Properties — Under the full cost method of accounting, the “ceiling test” under SEC rules and regulations specifies that evaluated and unevaluated properties’ capitalized costs, less accumulated amortization and related deferred income taxes (the “Full Cost Pool”), should be compared to a formulaic limitation (the “Ceiling”) each quarter on a country-by-country basis. If the Full Cost Pool exceeds the Ceiling, an impairment must be recorded. During 2023, 2022 and 2021 our ceiling test computations for our U.S. oil and gas properties did not result in a write down. At December 31, 2023, the Company’s ceiling test computation was based on SEC pricing of $78.56 per Bbl of oil, $2.75 per Mcf of natural gas and $18.77 per Bbl of NGLs.

If the unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the period beginning January 1, 2023 and ending December 1, 2023 used in the determination of the SEC pricing was 10% lower, resulting in $70.73 per Bbl of oil, $2.48 per Mcf of natural gas and $16.89 per Bbl of NGLs, while all other factors remained constant, our oil and natural gas properties would have been impaired by $321.9 million.

There is a significant degree of uncertainty with the assumptions used to estimate the present value of future net cash flows from estimated production of proved oil and gas reserves due to, but not limited to the risk factors referred to in Part I, Item 1A. “Risk Factors.” The discounted present value of our proved reserves is a major component of the Ceiling calculation. Any decrease in pricing, negative change in price differentials, or increase in capital or operating costs could negatively impact the estimated future discounted net cash flows related to our proved oil and natural gas properties.

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BOEM Bonding Requirements — In 2016, BOEM issued the 2016 NTL, which bolstered supplemental bonding requirements for offshore oil and gas lessees. The 2016 NTL was first paused under the Trump Administration, and then in 2020, rescinded by BOEM. In October 2020, BOEM pursued a proposed rule published jointly with the BSEE that sought to clarify and provide greater transparency to decommissioning and related financial assurance requirements imposed on oil and gas lessees (record title owners), sublessees (operating rights owners) and RUE and ROW grant holders conducting operations on the federal OCS. The DOI under the Biden Administration elected to separate BOEM and BSEE portions of the supplemental bonding requirements.

In April 2023, BSEE published its Final Rule entitled, “Risk Management, Financial Assurance, and Loss Prevention – Decommissioning Activities and Obligations,” wherein BSEE clarified decommissioning responsibilities for RUE grant holders and formalized BSEE’s policies regarding performance by predecessors ordered to decommission OCS facilities. The final rule withdraws the proposal in the October 2020 proposed rule to amend BSEE’s regulations requiring the agency to proceed in reverse chronological order against predecessor lessees, owners of operating rights and grant holders when requiring such entities to perform their accrued decommissioning obligations upon failure to perform by current lessees, owners, or holders. Under the final rule, BSEE may issue an order to predecessors to perform accrued decommissioning obligations, including beginning maintenance and monitoring within thirty days, designating an operator for decommissioning within ninety days, and submitting a decommissioning plan within one hundred fifty days.

On June 29, 2023, BOEM published a proposed rule that, if adopted as initially proposed, would substantially revise the supplemental financial assurance requirements applicable to offshore oil and gas operations. The proposed rule would change the current criteria used to determine whether OCS lease and grant holders are required to secure supplemental financial assurance. The proposed rule would no longer use the current 5-point test in determining whether an OCS lessee or grant holder is required to obtain supplemental financial assurance and instead proposes a simplified test: (1) the credit rating of the lessee and, where applicable, (2) the ratio of the value of proved oil and gas reserves of the lease to the estimated decommissioning liability associated with the reserves. Under the proposed rule, BOEM would no longer consider or rely upon the financial strength of predecessors in determining whether, or how much, supplemental financial assurance should be provided by current lessees and grant holders. BOEM would not require supplemental financial assurance above the base bond requirements in three cases: (1) where a lessee has an investment grade credit rating (i.e., a credit rating from a Nationally Recognized Statistical Ratings Organizations, or NRSRO, that is greater than or equal to either BBB- from S&P or Baa3 from Moody’s, or its equivalent, or a proxy credit rating greater than or equal to either BBB- or Baa3, as determined by the Regional Director and based upon a company’s audited financial information with an accompanying auditor’s certificate); (2) where there are multiple co-lessees on a lease and any one of those lessees meets the credit rating threshold; and (3) for any lease on which all lessees are rated below investment grade, where the value of the lease’s proved oil and gas reserves is at least three times that of the estimated decommissioning cost estimate. BOEM proposes to phase in compliance with the new requirements over a three-year period. The extended public comment period closed on September 7, 2023, and BOEM is reviewing the comments received. At this time, we cannot predict whether BOEM will adopt the final rule in its current form or at all, the timing for any final decision, or whether any changes will result from the public notice and comment process, but will continue to monitor this rulemaking.

Moreover, BOEM has the right to issue liability orders in the future, including if it determines there is a substantial risk of nonperformance of the current interest holder’s decommissioning obligations. In August 2021, BOEM published a Note to Stakeholders detailing an expansion of its supplemental financial assurance requirements to certain high-risk, non-sole liability properties; namely, those properties that are inactive, where production end-of-life is fewer than five years, or with damaged infrastructure irrespective of the remaining property life of the surrounding producing assets. BOEM has stated it will prioritize non-sole liability properties where it believes that the current owner does not meet applicable requirements related to financial strength and has no co-owners or predecessors that are financially strong, as determined by BOEM. We may be unable to provide the financial assurances in the amounts and under the time periods required by BOEM if it submits future demands to cover our decommissioning obligations. If in the future BOEM issues orders to provide additional financial assurances and we fail to comply with such future orders, BOEM could elect to take actions that would materially adversely impact our operations and our properties, including commencing proceedings to suspend our production and other operations or cancel our applicable federal offshore leases. Our ability to obtain adequate supplemental financial assurance (pursuant to a final BOEM rule that is substantially consistent with the June 2023 proposed rule or otherwise), including the future cost of compliance with respect to supplemental bonding, could materially and adversely affect our liquidity, financial condition, cash flows, business, properties and results of operations.

Deepwater Operations — We have interests in Deepwater fields in the U.S. Gulf of Mexico. Operations in Deepwater can result in increased operational risks as has been demonstrated by the Deepwater Horizon disaster in 2010. Despite technological advances since this disaster, liabilities for environmental losses, personal injury and loss of life and significant regulatory fines in the event of a disaster could be well in excess of insured amounts and result in significant current losses on our statements of operations as well as going concern issues.

Oil Spill Response Plan — We maintain a Regional Oil Spill Response Plan that defines our response requirements, procedures and remediation plans in the event we have an oil spill. Oil spill response plans are generally approved by the BSEE bi-annually, except when changes are required, in which case revised plans are required to be submitted for approval at the time changes are made. Additionally, these plans are tested and drills are conducted periodically at all levels.

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Hurricanes, Tropical Storms and Loop Currents — Since our operations are in the U.S. Gulf of Mexico, we are particularly vulnerable to the effects of hurricanes, tropical storms and loop currents on production and capital projects. Significant impacts could include reductions and/or deferrals of future oil and natural gas production and revenues and increased lease operating expenses for evacuations and repairs.

Five-Year Offshore Oil and Gas Leasing Program Update — Under the OCSLA, as amended, BOEM within the DOI must prepare and maintain forward-looking five-year plans—referred to by BOEM as national programs or five-year programs—to schedule proposed oil and gas lease sales on the U.S. Outer Continental Shelf. On May 11, 2022, the DOI cancelled two lease auctions in the Gulf of Mexico, Lease Sales 259 and 261 included in the 2017-2022 national program that was developed under the Obama Administration, which expired on June 30, 2022. The DOI cited “conflicting court rulings” as the primary reason for not holding the two Gulf of Mexico lease sales. The IRA, which President Biden signed into law on August 16, 2022, reinstated Lease Sale 257 held in November 2021, and required the DOI to both accept all valid high bids received in Lease Sale 257 and issue leases to the high bidders. We were one of the most active bidders in Lease Sale 257 and we were the high bidder on ten (10) blocks and awarded leases on nine (9) blocks. In January 2023, BOEM released its final environmental impact statement for Lease Sales 259 and 261 and, in March 2023, announced the results of Lease Sale 259, in which we were the high bidder on four offshore blocks, and were awarded leases on all four blocks. Lease Sale 261 was scheduled to be held on November 8, 2023, pursuant to a September 21, 2023 court order from the United States District Court for the Western District of Louisiana, as amended by a September 25, 2023 court order from the United States Court of Appeals for the Fifth Circuit. However, on October 26, 2023, the United States Court of Appeals for the Fifth Circuit stayed its and the District Court’s ruling, scheduling oral arguments for November 13, 2023. On November 2, 2023, BOEM announced the postponement of Lease Sale 261 as a result of the United States Court of Appeals for the Fifth Circuit’s October 26, 2023 order. Pursuant to the United States Court of Appeals for the Fifth Circuit’s November 14, 2023 order, BOEM held Lease Sale 261 on December 20, 2023, in which we were the high bidder on thirteen offshore blocks and were awarded four leases as of February 16, 2024. As BOEM is still in its bid evaluation, we are awaiting BOEM’s award decisions on our remaining high bids.

BOEM’s development of a new five-year national program typically takes place over several years, during which successive drafts of the program are published for review and comment. At the end of the process, the Secretary of the Interior must submit the Proposed Final Program (“PFP”) to the President and to Congress for a period of at least 60 days, after which the program may be approved by the Secretary of the Interior and may take effect with no further regulatory or legislative action.

BOEM took the first formal step in pursuit of a new five-year national program in January 2018 by releasing a Draft Proposed Program. The OCSLA and its implementing regulations call for two subsequent drafts, a Proposed Program (“PP”), which is open for public comment for a period of at least 90 days, and then a PFP, which is submitted to Congress and the President for 60 days before implementation. These later program stages also are accompanied by publication of a draft and final Programmatic Environmental Impact Statement (“PEIS”), with a period for public comment on the draft PEIS. The PP and a draft PEIS for the 2023-2028 five-year period were published in the Federal Register on July 8, 2022, with a 90-day comment period. The PP included no more than ten potential lease sales in the Gulf of Mexico. On September 29, 2023, the PFP for 2024-2029 was published and includes a maximum of three potential oil and gas lease sales in the Gulf of Mexico scheduled to be held in years 2025, 2027 and 2029. On December 14, 2023, the Secretary of the Interior approved the final program in a combined decision memo and Record of Decision and the final program is set to become effective on July 1, 2024.

How We Evaluate Our Operations

We use a variety of financial and operational metrics to assess the performance of our oil and natural gas operations, including:

•production volumes;

•realized prices on the sale of oil, natural gas and NGLs, including the effect of our commodity derivative contracts;

•lease operating expenses;

•capital expenditures; and

•Adjusted EBITDA, which is discussed under “—Supplemental Non-GAAP Measure” below.

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Basis of Presentation

Sources of Revenues

Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs, that are extracted from our natural gas during processing. Our oil, natural gas and NGL revenues do not include the effects of derivatives, which are reported in “Price risk management activities income (expense)” on our Consolidated Statements of Operations. The following table presents a breakout of each revenue component:

	Year Ended December 31,
	2023			2022			2021
Oil		93	%		83	%		86	%
Natural gas		5	%		14	%		10	%
NGL		2	%		4	%		4	%

Our revenues may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

Realized Prices on the Sale of Oil, Natural Gas and NGLs — The NYMEX WTI prompt month oil settlement price is a widely used benchmark in the pricing of domestic oil in the United States. The actual prices we realize from the sale of oil differ from the quoted NYMEX WTI price as a result of quality and location differentials. For example, the prices we realize on the oil we produce are affected by the Gulf of Mexico Basin’s proximity to U.S. Gulf Coast refineries and the quality of the oil production sold in Eugene Island Crude, Louisiana Light Sweet Crude and Heavy Louisiana Sweet Crude markets.

The NYMEX Henry Hub price of natural gas is a widely used benchmark for the pricing of natural gas in the United States. The actual prices we realize from the sale of natural gas differ from the quoted NYMEX Henry Hub price as a result of quality and location differentials. Currently, the sales points of our gas production are generally within close proximity to the Henry Hub which creates a minimal differential in the prices we receive for our production versus average Henry Hub prices.

In the past, oil and natural gas prices have been extremely volatile, and we expect this volatility to continue, as indicated in the table below, which provides the high, low and average prices for NYMEX WTI and NYMEX Henry Hub monthly contract prices as well as our average realized oil, natural gas, and NGL sales prices for the periods indicated.

	Year Ended December 31,
	2023			2022			2021
Oil:
NYMEX WTI high per Bbl	$	89.43		$	114.84		$	81.48
NYMEX WTI low per Bbl	$	70.25		$	76.44		$	52.01
Average NYMEX WTI per Bbl	$	77.63		$	94.79		$	67.99
Average oil sales price per Bbl (including commodity derivatives)	$	73.59		$	68.40		$	49.67
Average oil sales price per Bbl (excluding commodity derivatives)	$	75.17		$	93.75		$	65.86
Natural Gas:
NYMEX Henry Hub high per MMBtu	$	3.27		$	8.81		$	5.51
NYMEX Henry Hub low per MMBtu	$	2.14		$	4.38		$	2.62
Average NYMEX Henry Hub per MMBtu	$	2.54		$	6.42		$	3.91
Average natural gas sales price per Mcf (including commodity derivatives)	$	3.32		$	5.30		$	3.11
Average natural gas sales price per Mcf (excluding commodity derivatives)	$	2.60		$	7.06		$	3.98
NGLs:
NGL realized price as a % of average NYMEX WTI		23	%		35	%		39	%

To achieve more predictable cash flow, and to reduce exposure to adverse fluctuations in commodity prices, we enter into commodity derivative arrangements for a portion of our anticipated production. By removing a significant portion of price volatility associated with our anticipated production, we believe it will mitigate, but not eliminate, the potential negative effects of reductions in oil and natural gas prices on our cash flow from operations for those periods. However, our price risk management activity may also reduce our ability to benefit from increases in prices. We will sustain losses to the extent our commodity derivatives contract prices are lower than market prices and, conversely, we will sustain gains to the extent our commodity derivatives contract prices are higher than market prices.

We will continue to use commodity derivative instruments to manage commodity price risk in the future. Our hedging strategy and future hedging transactions will be determined in accordance with both our Bank Credit Facility and Hedging Policy and may be different from what we have done on a historical basis.

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Expenses

Lease Operating Expense — Lease operating expense consists of the daily costs incurred to bring oil, natural gas and NGLs out of the underground formation and to the market, together with the daily costs incurred to maintain our producing properties. Expenses for direct labor, insurance, a portion of the HP-I lease, materials and supplies, rental and third party costs comprise the most significant portion of our lease operating expense. It further consists of costs associated with major remedial operations on completed wells to restore, maintain or improve the well’s production. Because the amount of workover and maintenance expense is closely correlated to the levels of workover activity, which is not regularly scheduled, workover and maintenance expense is not necessarily comparable from period-to-period. There is a reduction in our lease operating expenses for production handling fees related to certain reimbursements for costs from certain third parties.

Production Taxes — Production taxes consist of severance taxes levied by the Louisiana Department of Revenue on production of oil and natural gas from land or water bottoms within the boundaries of the state of Louisiana.

Depreciation, Depletion and Amortization expense — Depreciation, depletion and amortization expense is the expensing of the capitalized costs incurred to acquire, explore and develop oil and natural gas reserves. We use the full cost method of accounting for oil and natural gas activities. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies for further discussion.

Accretion Expense — We have obligations associated with the retirement of our oil and natural gas wells and related infrastructure. We have obligations to plug wells when production on those wells is exhausted, when we no longer plan to use them or when we abandon them. We accrue a liability with respect to these obligations based on our estimate of the timing and amount to replace, remove or retire the associated assets. Accretion of the liability is recognized for changes in the value of the liability as a result of the passage of time over the estimated productive life of the related assets as the discounted liabilities are accreted to their expected settlement values.

General and Administrative Expense — General and administrative expense generally consists of costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production operations, bad debt expense, equity-based compensation expense, audit and other fees for professional services and legal compliance.

Interest Expense — We finance a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our Bank Credit Facility and term-based debt. As a result, we incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. Interest includes interest incurred under our debt agreements, the amortization of deferred financing costs (including origination and amendment fees), commitment fees, imputed interest on our capital lease, performance bond premiums and annual agency fees. Interest expense is net of capitalized interest on expenditures made in connection with exploratory projects that are not subject to current amortization.

Price Risk Management Activities — We utilize commodity derivative instruments to reduce our exposure to fluctuations in the price of oil and natural gas. We recognize gains and losses associated with our open commodity derivative contracts as commodity prices and the associated fair value of our commodity derivative contracts change. The commodity derivative contracts we have in place are not designated as hedges for accounting purposes. Consequently, these commodity derivative contracts are marked-to-market each quarter with fair value gains and losses recognized currently as a gain or loss in our results of operations. Cash flow is only impacted to the extent the actual settlements under the contracts result in making a payment to or receiving a payment from the counterparty.

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Results of Operations

Revenues

The information below provides a discussion of, and an analysis of significant variance in, our oil, natural gas and NGL revenues, production volumes and sales prices (in thousands, except per unit data):

	Year Ended December 31,
	2023		2022		Change
Revenues:
Oil	$	1,357,732	$	1,365,148	$	(7,416	)
Natural gas		68,034		227,306		(159,272	)
NGL		32,120		59,526		(27,406	)
Total revenues	$	1,457,886	$	1,651,980	$	(194,094	)
Production Volumes:
Oil (MBbls)		18,062		14,561		3,501
Natural gas (MMcf)		26,194		32,215		(6,021	)
NGL (MBbls)		1,767		1,793		(26	)
Total production volume (MBoe)		24,195		21,723		2,472
Daily Production Volumes by Product:
Oil (MBblpd)		49.5		39.9		9.6
Natural gas (MMcfpd)		71.8		88.3		(16.5	)
NGL (MBblpd)		4.8		4.9		(0.1	)
Total production volume (MBoepd)		66.3		59.5		6.8
Average Sale Price per Unit:
Oil (per Bbl)	$	75.17	$	93.75	$	(18.58	)
Natural gas (per Mcf)	$	2.60	$	7.06	$	(4.46	)
NGL (per Bbl)	$	18.18	$	33.20	$	(15.02	)
Price per Boe	$	60.26	$	76.05	$	(15.79	)
Price per Boe (including realized commodity derivatives)	$	59.86	$	56.46	$	3.40

The information below provides an analysis of the change in our oil, natural gas and NGL revenues in our Upstream Segment, due to changes in sales prices and production volumes (in thousands):

	Price			Volume			Total
Revenues:
Oil	$	(335,635	)	$	328,219		$	(7,416	)
Natural gas		(116,764	)		(42,508	)		(159,272	)
NGL		(26,543	)		(863	)		(27,406	)
Total revenues	$	(478,942	)	$	284,848		$	(194,094	)

Volumetric Analysis — Production volumes increased by 6.8 MBoepd to 66.3 MBoepd for the year ended December 31, 2023. The increase was primarily due to 17.6 MBoepd in production from the oil and natural gas assets acquired in the EnVen Acquisition. Additionally, production volumes increased due to the third party downtime for the HP-I dry-dock in our Phoenix Field, the Eugene Island Pipeline System shut-in primarily impacting HP-I and Green Canyon 18 Field and the Shell Odyssey Pipeline shut-in primarily impacting our Ram Powell Field, Main Pass 288 Field and non-operated Delta House facility, which resulted in 3.5 MBoepd of deferred production during 2022. These increases were partially offset by a decrease of 13.4 MBoepd due to well performance and natural production declines primarily in our Phoenix Field, Green Canyon 18 Field and Pompano Field.

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Operating Expenses

Lease Operating Expense

The following table highlights lease operating expense items in total and on a cost per Boe production basis to our Upstream Segment. The information below provides the financial results and an analysis of significant variances in these results (in thousands, except per Boe data):

	Year Ended December 31,
	2023		2022
Lease operating expenses	$	389,621	$	308,092
Lease operating expenses per Boe	$	16.10	$	14.18

Total lease operating expenses for the year ended December 31, 2023 increased by approximately $81.5 million, or 26%. The increase is primarily related to lease operating expenses of $86.8 million incurred in connection with assets acquired from the EnVen Acquisition. Additionally, there was a $11.3 million decrease in production handling fees related to reimbursements for costs from certain third parties related to our historical operations. This increase was partially offset by a $17.1 million decrease in facility and workover expense related to repairs and maintenance at the Phoenix Field compared to the same period in 2022.

Depreciation, Depletion and Amortization

The following table highlights depreciation, depletion and amortization items. The information below provides the financial results and an analysis of significant variances in these results (in thousands):

	Year Ended December 31,
	2023		2022
Depreciation, depletion and amortization	$	663,534	$	414,630

Depreciation, depletion and amortization expense for the year ended December 31, 2023 increased by approximately $248.9 million, or 60%. This increase was primarily due to an increase of $8.28 per Boe, or 44% in the depletion rate on our proved oil and natural gas properties due to an increase in our proved properties and related production primarily related to the assets acquired as part of the EnVen Acquisition, which resulted in $176.3 million of additional depletion. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures” for further discussion on the EnVen Acquisition. Additionally, the depletion rate increased due to the extension of the HP-I lease during the fourth quarter of 2022. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 5 — Leases for additional information on the HP-I lease extension.

General and Administrative Expense

The following table highlights general and administrative expense items in total and on a cost per Boe production basis for the Upstream Segment. The information below provides the financial results and an analysis of significant variances in these results (in thousands, except per Boe data):

	Year Ended December 31,
	2023		2022
Upstream Segment	$	139,026	$	82,979
CCS Segment		11,922		10,240
Unallocated corporate		7,545		6,535
Total general and administrative expense	$	158,493	$	99,754
Upstream general and administrative expense per Boe	$	5.75	$	3.82

General and administrative expense for the year ended December 31, 2023, increased by approximately $58.7 million, or 59%. This increase was primarily related to higher Upstream Segment transaction costs for the closing and continued integration of the EnVen Acquisition of $31.4 million or $1.26 per Boe. The Upstream Segment also had an increase in legal fees of $5.1 million or $0.21 per Boe due to the Dunwoody litigation assumed as part of the EnVen Acquisition. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 14 — Commitments and Contingencies for further discussion. Additionally, there was an increase in payroll expense due to additional employee headcount primarily related to the EnVen Acquisition. These increases were partially offset by a decrease in non-cash equity-based compensation of $3.0 million, primarily due to a forfeiture during the third quarter of 2023.

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Miscellaneous

The following table highlights miscellaneous items in total. The information below provides the financial results and an analysis of significant variances in these results (in thousands):

	Year Ended December 31,
	2023			2022
Accretion expense	$	86,152		$	55,995
Other operating (income) expense	$	(52,155	)	$	33,902
Interest expense	$	173,145		$	125,498
Price risk management activities (income) expense	$	(80,928	)	$	272,191
Equity method investment (income) expense	$	(3,209	)	$	(14,222	)
Other (income) expense	$	(12,371	)	$	(31,800	)
Income tax (benefit) expense	$	(60,597	)	$	2,537

Accretion Expense — During the year ended December 31, 2023, we recorded $86.2 million of accretion expense compared to $56.0 million during the year ended December 31, 2022. The change is primarily the result of the increase in accretion associated with the asset retirement obligations assumed as part of the EnVen Acquisition. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for further discussion.

Other Operating (Income) Expense — During the year ended December 31, 2023, we recognized a gain of $66.2 million on the Mexico Divestiture. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for further discussion. This gain was partially offset by $11.9 million of estimated decommissioning obligations primarily as a result of unrelated parties or counterparties that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. During the year ended December 31, 2022, we recorded $31.6 million of estimated decommissioning obligations. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 14 — Commitments and Contingencies.

Interest Expense — During the year ended December 31, 2023, we recorded $173.1 million of interest expense compared to $125.5 million during the year ended December 31, 2022. The change is primarily a result of the increase in interest associated with the 11.75% Notes assumed as part of the EnVen Acquisition. Additionally, there was an increase in interest associated with the Bank Credit Facility due to increased interest rates and average borrowings when compared to the same period in 2022. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt.

Price Risk Management Activities — Price risk management activities for year ended December 31, 2023 resulted in a decrease of approximately $353.1 million, or 130%. The income of $80.9 million for the year ended December 31, 2023 consisted of $90.4 million in non-cash gains from the increase in the fair value of our open derivative contracts offset by $9.5 million in cash settlement losses. The expense of $272.2 million for the year ended December 31, 2022 consisted of $425.6 million in cash settlement losses and $153.4 million in non-cash gains from the increase in the fair value of our open derivative contracts.

These unrealized gains and losses on open derivative contracts relate to production for future periods; however, changes in the fair value of all of our open derivative contracts are recorded as a gain or loss on our Consolidated Statements of Operations at the end of each month. As a result of the derivative contracts we have on our anticipated production volumes through December 2025, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 6 — Financial Instruments for additional information.

Equity Method Investment Income — During the year ended December 31, 2023, we recorded $12.1 million of equity losses offset by an $8.6 million gain on the funding of the capital carry of our investment in Bayou Bend by Chevron. During the year ended December 31, 2022, we recorded a $13.9 million gain on the partial sale and $1.4 million gain on the funding of the capital carry of our equity method investment in Bayou Bend offset by equity losses of $1.1 million. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Equity Method Investments for additional information.

Other (Income) Expense — During the year ended December 31, 2022, we recorded a $27.5 million gain as a result of the settlement agreement to resolve a previously pending litigation that was filed in October 2017 that is further discussed in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 14 — Commitments and Contingencies. This was partially offset by a $1.6 million loss on extinguishment of debt as a result of the redemption of the 12.00% Notes further discussed in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt.

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Income Tax Benefit (Expense) — During the year ended December 31, 2023, we recorded $60.6 million of income tax benefit compared to $2.5 million of income tax expense during the year ended December 31, 2022, primarily due to a non-cash tax benefit of $106.8 million related to the release of the valuation allowance for our deferred tax assets partially offset with an income tax expense of $31.1 million related to current year activity inclusive of permanent differences for the year ended December 31, 2023. The realization of our deferred tax asset depends on recognition of sufficient future taxable income in specific tax jurisdictions in which temporary differences or net operating losses relate. In assessing the need for a valuation allowance, we consider whether it is more likely than not that some portion of the deferred tax assets will not be realized. See additional information on the valuation allowance as described in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 11 — Income Taxes.

Commitments and Contingencies

For a further discussion of our commitments and contingencies, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 14 — Commitments and Contingencies. Additionally, we are party to lawsuits arising in the ordinary course of our business. We cannot predict the outcome of any such lawsuit with certainty, but our management believes it is remote that any such pending or threatened lawsuit will have a material adverse impact on our financial condition. See Part I, Item 3. Legal Proceedings for additional information.

Due to the nature of our business, we are, from time-to-time, involved in other routine litigation or subject to disputes or claims related to business activities, including workers’ compensation claims, employment related disputes and civil penalties by regulators. In the opinion of our management, none of these other pending litigations, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations. See Part I, Item 3. Legal Proceedings for additional information.

Supplemental Non-GAAP Measure

EBITDA and Adjusted EBITDA

“EBITDA” and “Adjusted EBITDA” are non-GAAP financial measures used to provide management and investors with (i) additional information to evaluate, with certain adjustments, items required or permitted in calculating covenant compliance under our debt agreements, (ii) important supplemental indicators of the operational performance of our business, (iii) additional criteria for evaluating our performance relative to our peers and (iv) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. EBITDA and Adjusted EBITDA have limitations as analytical tools and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP or as alternatives to net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP.

We define these as the following:

•EBITDA — Net income (loss) plus interest expense, income tax expense (benefit), depreciation, depletion and amortization, and accretion expense.

•Adjusted EBITDA — EBITDA plus non-cash write-down of oil and natural gas properties, transaction and other (income) expenses, decommissioning obligations, the net change in the fair value of derivatives (mark to market effect, net of cash settlements and premiums related to these derivatives), (gain) loss on debt extinguishment, non-cash write-down of other well equipment and non-cash equity-based compensation expense.

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The following table presents a reconciliation of the GAAP financial measure of net income (loss) to Adjusted EBITDA for each of the periods indicated (in thousands):

	Year Ended December 31,
	2023			2022			2021
Net income (loss)	$	187,332		$	381,915		$	(182,952	)
Interest expense		173,145			125,498			133,138
Income tax expense (benefit)		(60,597	)		2,537			(1,635	)
Depreciation, depletion and amortization		663,534			414,630			395,994
Accretion expense		86,152			55,995			58,129
EBITDA		1,049,566			980,575			402,674
Write-down of oil and natural gas properties		—			—			18,123
Transaction and other (income) expense(1)		(33,295	)		(34,513	)		5,886
Decommissioning obligations(2)		11,879			31,558			21,055
Derivative fair value (gain) loss(3)		(80,928	)		272,191			419,077
Net cash received (paid) on settled derivative instruments(3)		(9,457	)		(425,559	)		(290,164	)
(Gain) loss on debt extinguishment		—			1,569			13,225
Non-cash write-down of other well equipment		—			—			5,606
Non-cash equity-based compensation expense		12,953			15,953			10,992
Adjusted EBITDA	$	950,718		$	841,774		$	606,474

(1)Transaction expenses include $40.4 million and $9.0 million in costs related to the EnVen Acquisition, inclusive of $25.3 million and nil in severance expenses for the years ended December 31, 2023 and 2022, respectively. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures and Note 10 — Employee Benefit Plans and Share-Based Compensation. Other income (expense) includes restructuring expenses, cost saving initiatives and other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the year ended December 31, 2023, the amount includes a $66.2 million gain on the Mexico Divestiture. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures. The amount includes a gain on the funding of the capital carry of our investment in Bayou Bend by Chevron of $8.6 million and $1.4 million for the year ended December 31, 2023 and 2022, respectively. Additionally, it includes a $13.9 million gain on the partial sale of our investment in Bayou Bend to Chevron for the year ended December 31, 2022. See further discussion in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 7 — Equity Method Investments. For the year ended December 31, 2022, the amount includes $27.5 million gain as a result of the settlement agreement to resolve previously pending litigation that was filed in October 2017 that is further discussed in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 14 — Commitments and Contingencies.

(2)Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 14 — Commitments and Contingencies for additional information on decommissioning obligations.

(3)The adjustments for the derivative fair value (gains) losses and net cash receipts (payments) on settled commodity derivative instruments have the effect of adjusting net loss for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because we do not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled.

Liquidity and Capital Resources

Our primary sources of liquidity are cash generated by our operations and borrowings under our Bank Credit Facility. Our primary uses of cash are for capital expenditures, working capital, debt service, share repurchases and for general corporate purposes. The cost of borrowing under our Bank Credit Facility has increased. By raising its federal funds rate, the Fed is making it more expensive to borrow money. Our working capital deficit has decreased since December 31, 2022 primarily due to a decrease of $61.1 million in liabilities from price risk management activities and an increase of $11.1 million in assets from price risk management activities. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 6 — Financial Instruments for additional information. As of December 31, 2023, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $787.9 million.

We fund drilling, completions and development activities primarily through operating cash flows, cash on hand and through borrowings under the Bank Credit Facility, if necessary. Historically, we have funded significant acquisitions with the issuance of senior notes, borrowings under the Bank Credit Facility and through additional equity issuances. We occasionally adjust our capital budget in response to changing operating cash flow forecasts and market conditions, including the prices of oil, natural gas and NGLs, acquisition opportunities and the results of our exploration and development activities. We are continuing to explore a capital raise to finance the accelerated growth of our CCS segment.

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Capital Expenditures — The following is a table of our capital expenditures, excluding acquisitions, for the year ended December 31, 2023 (in thousands):

U.S. drilling & completions	$	447,254
Mexico appraisal & exploration		291
Asset management(1)		83,970
Seismic and G&G, land, capitalized G&A and other		64,955
Total Upstream capital expenditures		596,470
Plugging & abandonment		86,615
Decommissioning obligations settled(2)		50,584
Total Upstream		733,669
Investment in CCS		40,961
Total	$	774,630

(1)Asset management consists of capital expenditures for development-related
activities primarily associated with recompletions and improvements to our facilities and infrastructure.

(2)Settlement of decommissioning obligations as a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 14 — Commitments and Contingencies for additional information on decommissioning obligations.

Based on our current level of operations and available cash, we believe our cash flows from operations, combined with availability under the Bank Credit Facility, provide sufficient liquidity to fund our board approved 2024 Upstream capital spending program of $565.0 million to $595.0 million and plugging & abandonment and decommissioning obligations of $90.0 million to $100.0 million. However, our ability to (i) generate sufficient cash flows from operations or obtain future borrowings under the Bank Credit Facility, and (ii) repay or refinance any of our indebtedness on commercially reasonable terms or at all for any potential future acquisitions, joint ventures or other similar transactions, depends on operating and economic conditions, some of which are beyond our control. To the extent possible, we have attempted to mitigate certain of these risks (e.g. by entering into oil and natural gas derivative contracts to reduce the financial impact of downward commodity price movements on a substantial portion of our anticipated production), but we could be required to, or we or our affiliates may from time to time, take additional future actions on an opportunistic basis. To address further changes in the financial and/or commodity markets, future actions may include, without limitation, issuing debt, including secured debt, or issuing equity to directly or independently repurchase or refinance our outstanding indebtedness.

Common Stock Repurchase Program — Our Board of Directors authorized a stock repurchase program on March 20, 2023 with an approved limit of $100.0 million and no set term limits. In March and June of 2023, we repurchased 1.9 million shares for $26.6 million and 1.5 million shares for $20.9 million, respectively. As of December 31, 2023, there is $52.5 million remaining under the authorized program. All repurchased shares are held in treasury.

Repurchases may be made from time to time in the open market, in privately negotiated transactions, or by such other means as will comply with applicable state and federal securities laws. The timing of any repurchases under the share repurchase program will depend on market conditions, contractual limitations and other considerations. The program may be extended, modified, suspended or discontinued at any time, and does not obligate the Company to repurchase any dollar amount or number of shares.

The IRA 2022 provides for, among other things, the imposition of a new 1% U.S. federal excise tax on certain repurchases of stock by publicly traded U.S. corporations such as us after December 31, 2022. Accordingly, the excise tax applies to our share repurchase program. The excise tax payment is non-deductible for income tax purposes. Subject to certain exceptions and adjustments, the excise tax equals 1% of the fair market value of the stock repurchased by a corporation during the applicable tax year. The repurchase amount subject to the excise tax is generally reduced by the fair market value of any stock issued by a corporation during a taxable year, including the fair market value of any stock issued or provided to employees of a corporation or employees of certain of its subsidiaries. The current federal administration has proposed increasing the excise tax amount from 1% to 4%; however, it is unclear whether such a change in the amount of the excise tax will be enacted and, if enacted, how soon any change can take effect. We do not anticipate paying any excise tax in 2023 based on the fair market value of the stock issuance in connection to the EnVen Acquisition.

Overview of Cash Flow Activities — The following table summarizes cash flows provided by (used in) by type of activity, for the following periods (in thousands):

	Year Ended December 31,
	2023			2022
Operating activities	$	519,069		$	709,739
Investing activities	$	(512,626	)	$	(311,977	)
Financing activities	$	85,411		$	(423,469	)

Operating Activities — Net cash provided by operating activities decreased $190.7 million in 2023 compared to 2022 primarily attributable to a decrease in revenues combined with an increase in lease operating expense of $275.6 million.

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Investing Activities — Net Cash used in investing activities increased $200.6 million in 2023 compared to 2022 primarily due to an increase in capital expenditures of $238.3 million. The capital expenditure budget for 2023 included projects related to the EnVen Acquisition. Additionally, we had an increase in contributions to equity method investees of $27.2 million and investment in intangibles of $12.4 million. This was offset by cash proceeds of $74.9 million from the Mexico Divestiture. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information.

Financing Activities — Net cash used in financing activities increased $508.9 million in 2023 compared to 2022. We had net borrowings from the Bank Credit Facility of $200.0 million for the year ended December 31, 2023 due to the funding of the EnVen Acquisition, working capital needs and capital expenditures. We had net repayments of $375.0 million during the same period in 2022 due to a management goal to reduce our leverage ratio coupled with a commodity price environment that supported debt repayments to achieve such goal. See Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 3 — Acquisitions and Divestitures for additional information on the EnVen Acquisition. We repurchased $47.5 million of our common stock through our share repurchase program during the year ended December 31, 2023. See the subsection entitled “— Common Stock Repurchase Program” for additional information. Additionally, there was an increase in redemption of senior notes of $11.8 million and deferred financing costs of $11.6 million in each case when compared to the same period in 2022. For additional details on our debt, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt.

Overview of Debt Instruments

Financing Arrangements — As of December 31, 2023, total debt, net of discount and deferred financing costs, was approximately $1,025.7 million, comprised of our $866.0 million aggregate principal amount of the 12.00% Notes and 11.75% Notes (as defined herein) and $200.0 million outstanding under our Bank Credit Facility. We were in compliance with all debt covenants at December 31, 2023. For additional details on our debt, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt.

Bank Credit Facility – matures March 2027 — We maintain a Bank Credit Facility with a syndicate of financial institutions. The Bank Credit Facility provides for determination of the borrowing base based on our proved producing reserves and a portion of our proved undeveloped reserves. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter each year. For additional details on our Bank Credit Facility, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt.

12.00% Second-Priority Senior Secured Notes—due January 2026 — The 12.00% Notes were issued pursuant to an indenture dated January 4, 2021 and the first supplemental indenture dated January 14, 2021 between Talos Energy Inc. (the “Parent Guarantor”); Talos Production Inc. (the “Issuer”); the Subsidiary Guarantors (defined below); and Wilmington Trust, National Association, as trustee and collateral agent. The 12.00% Notes rank pari passu in right of payment and constitute a single class of securities for all purposes under the indentures. The 12.00% Notes were secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 12.00% Notes were scheduled to mature on January 15, 2026 and had interest payable semi-annually each January 15 and July 15. We made an interest payment of $38.3 million on January 16, 2024. For additional details on the 12.00% Notes, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt.

On January 23, 2024, we issued a conditional notice to redeem in full the 12.00% Notes at a redemption price of 103.000% of the principal amount thereof, plus accrued and unpaid interest to, but excluding, the redemption date, in accordance with the 12.00% Notes indenture. The 12.00% Notes were redeemed on February 7, 2024 for $662.4 million utilizing the net proceeds from the Debt Offering.

11.75% Senior Secured Second Lien Notes—due April 2026 — On February 13, 2023, in conjunction with the closing of the EnVen Acquisition, the Company assumed EnVen’s 11.75% Senior Secured Second Lien Notes due 2026 (the “11.75% Notes”) with a principal amount of $257.5 million. The 11.75% Notes were scheduled to mature on April 15, 2026 and interest accrued and was paid semi-annually in cash in arrears on April 15th and October 15th of each year. The 11.75% Notes were secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The indenture governing the 11.75% Notes required the redemption of $15.0 million of the principal amount outstanding at par value on April 15th and October 15th of each year. For additional details on the 11.75% Notes, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt.

On January 26, 2024, we issued a conditional notice to redeem in full the 11.75% Notes at a redemption price of 102.938% of the principal amount thereof, plus accrued and unpaid interest to, but excluding, the redemption date, in accordance with the 11.75% Notes indenture. We irrevocably deposited funds with the trustee sufficient to satisfy and discharge the 11.75% Notes indenture and the 11.75% Notes until redeemed on April 15, 2024 with the funds deposited with the trustee and elected to satisfy and discharge the 11.75% Notes indenture in accordance with its terms and the 11.75% Notes trustee acknowledged such discharge and satisfaction. We deposited $247.5 million with the trustee on February 7, 2024 utilizing the net proceeds from the Debt Offering.

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9.000% Second-Priority Senior Secured Notes—due February 2029 — The 9.000% Notes were issued pursuant to the 9.000% Notes indenture. The 9.000% Notes rank pari passu in right of payment and constitute a single class of securities for all purposes under the indenture. The 9.000% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 9.000% Notes mature on February 1, 2029 and have interest payable semi-annually each February 1 and August 1.

9.375% Second-Priority Senior Secured Notes—due February 2031 — The 9.375% Notes were issued pursuant to the 9.375% Notes indenture. The 9.375% Notes rank pari passu in right of payment and constitute a single class of securities for all purposes under the indenture. The 9.375% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 9.375% Notes mature on February 1, 2031 and have interest payable semi-annually each February 1 and August 1.

Guarantor Financial Information — We own no operating assets and have no operations independent of our subsidiaries. The 12.00% Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by the Parent Guarantor and on a second-priority senior secured basis by each of the Issuer’s present and future direct or indirect wholly owned material restricted subsidiaries that guarantees the Issuer’s Bank Credit Facility (collectively, the “Subsidiary Guarantors” and, together with the Parent Guarantor, the “Guarantors”). Our non-domestic subsidiaries (other than Talos International Holdings SCS) and our unrestricted CCS domestic subsidiaries (the “Non-Guarantors”) are 100% owned by us but do not guarantee the 12.00% Notes.

In lieu of providing separate financial statements for the Issuer and the Guarantors, we have presented the accompanying supplemental summarized combined balance sheet and statement of operations information for the Issuer and the Guarantors on a combined basis after elimination of intercompany transactions and amounts related to investment in any subsidiary that is a Non-Guarantor.

The following table presents the balance sheet information for the respective periods (in thousands):

	Year Ended December 31,
	2023		2022
Current assets	$	409,112	$	344,525
Non-current assets		4,352,102		2,571,254
Total assets	$	4,761,214	$	2,915,779
Current liabilities	$	577,587	$	599,669
Non-current liabilities		2,082,543		1,285,992
Talos Energy Inc. stockholdersʼ equity		2,101,084		1,030,118
Total liabilities and stockholdersʼ equity	$	4,761,214	$	2,915,779

The following table presents the income statement information (in thousands):

	Year Ended December 31, 2023
Revenues	$	1,457,886
Costs and expenses		(1,258,327	)
Net income (loss)	$	199,559

Material Cash Requirements — We are party to various contractual obligations. Some of these obligations may be reflected in our accompanying Consolidated Financial Statements, while other obligations, such as certain operating leases and capital commitments, are not reflected on our accompanying Consolidated Financial Statements.

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The following table and discussion summarizes our material cash requirements from known contractual obligations as of December 31, 2023 (in thousands):

	2024		2025		2026		2027		2028		Thereafter		Total(5)
Long-term financing obligations:
Debt principal	$	30,000	$	30,000	$	806,041	$	200,000	$	—	$	—	$	1,066,041
Debt interest		123,084		119,559		68,975		5,152		—		—		316,770
Vessel commitments(1)		13,216		—		—		—		—		—		13,216
Derivative liabilities		7,305		795		—		—		—		—		8,100
Operating lease obligations		4,748		4,716		4,803		4,708		4,610		4,584		28,169
Finance lease(2)		19,336		—		—		—		—		—		19,336
Purchase obligations(3)		3,083		—		—		—		—		—		3,083
Other commitments(4)		3,991		327		—		—		—		—		4,318
Total contractual obligations(5)	$	204,763	$	155,397	$	879,819	$	209,860	$	4,610	$	4,584	$	1,459,033

(1)Includes vessel commitments we will utilize for certain Deepwater well intervention, drilling operations and decommissioning activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by us will be billed for their working interest share of such costs.

(2)Lease agreement for the HP-I floating production facility in the Phoenix Field.

(3)Includes committed purchase orders to execute planned future drilling activities.

(4)Includes commitments associated with our CCS Segment relating to an equity funding obligation and payments required under a sequestration agreement.

(5)This table does not include our estimated discounted liability for dismantlement, abandonment and restoration costs of oil and natural gas properties of $897.2 million as of December 31, 2023. For additional information regarding these liabilities, please see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 9 — Asset Retirement Obligations. Additionally, this table does not include liabilities associated with our decommissioning obligations. For additional information regarding our decommissioning obligations, please see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 14 — Commitment and Contingencies.

Debt principal of $638.5 million associated with the 12.00% Notes reflected in the table above was redeemed on February 7, 2024 from proceeds from the Debt Offering. There was $191.8 million of interest reflected in the table above associated with the 12.00% Notes. Debt principal of $227.5 million associated with the 11.75% Notes reflected in the table above will be redeemed on April 15, 2024 from proceeds from the Debt Offering. There was $58.0 million of interest reflected in the table above associated with the 11.75% Notes. The New Senior Notes have an aggregate principal amount of $1,250.0 million with interest of $688.9 million over the life of the New Senior Notes.

Performance Obligations — As of December 31, 2023, we had secured performance bonds totaling $1.4 billion primarily related to plugging and abandonment of wells and removal of facilities in the U.S. Gulf of Mexico and certain obligations under the PSCs with Mexico from third party sureties. Additionally, we had secured letters of credit issued under our Bank Credit Facility totaling $10.8 million. Letters of credit that are outstanding reduce the available revolving credit commitments. See the subsection entitled “— Known Trends and Uncertainties — BOEM Bonding Requirements” for additional information on the future cost of compliance with respect to BOEM supplemental bonding requirements that could have a material adverse effect on our business, properties, results of operations and financial condition.

For additional information about certain of our obligations and contingencies, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 14 — Commitments and Contingencies.

Critical Accounting Policies and Estimates

The preparation of financial statements in conformity with GAAP requires our management to make estimates and assumptions that affect the reported amount of assets, liabilities, revenue and expense, and the disclosures of contingent assets and liabilities. We consider our critical accounting estimates to be those estimates that require complex or subjective judgment in the application of the accounting policy and that could significantly impact our financial results based on changes in those judgments. Changes in facts and circumstances may result in revised estimates and actual results may differ materially from those estimates. Our management has identified the following critical accounting estimates. Our significant accounting policies are described in Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 2 — Summary of Significant Accounting Policies.

Proved Reserve Estimates — We account for our oil and natural gas producing activities using the full cost method of accounting, which is dependent on the estimation of proved reserves to determine the rate at which we record depletion on our oil and natural gas properties and whether the value of our evaluated oil and natural gas properties is permanently impaired based on the quarterly full cost ceiling impairment test.

We estimate our proved oil, natural gas and NGL reserves in accordance with the guidelines established by the SEC. Proved oil, natural gas and NGL reserves are those quantities of oil, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible in future periods from known reservoirs and under existing economic conditions, operating methods and governmental regulations. Prices are determined using SEC pricing.

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Our estimates of proved reserves are made using available geological and reservoir data, as well as production performance data. The estimates of proved reserves are reviewed annually by internal reservoir engineers and revised, either upward or downward, as warranted by additional data. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental restrictions. Decreases in price, for example, may cause a reduction in some proved reserves due to reaching economic limits at an earlier projected date. A material adverse change in the estimated volumes of proved reserves could have a negative impact on depreciation, depletion and amortization or could result in property impairments.

The depletion of our proved oil and natural gas properties is calculated using the unit-of-production method based on proved oil and gas reserves. If the proved reserves used had been a 10 percent lower, depreciation, depletion and amortization in the three months ended December 31, 2023 would have increased by an estimated $19.4 million. Furthermore, the Company’s capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10%, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. Downward revisions of previous reserve quantity estimates accounted for approximately $484.4 million of the standardized measure of our total reserves from December 31, 2022 to December 31, 2023. The Company’s ceiling test computations did not result in a write-down of its U.S. oil and natural gas properties during the years ended December 31, 2023, 2022 and 2021.

Asset Retirement Obligations — The Company has obligations associated with the retirement of its oil and natural gas wells and related infrastructure. The Company has obligations to plug wells when production on those wells is exhausted, when the Company no longer plans to use them or when the Company abandons them. The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount to replace, remove or retire the associated assets.

In estimating the liability associated with its asset retirement obligations, the Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate. Changes in estimate in the table below represent changes to the expected amount and timing of payments to settle its asset retirement obligations. Typically, these changes result from obtaining new information about the timing of its obligations to plug and abandon oil and natural gas wells and the costs to do so. After initial recording, the liability is increased for the passage of time, with the increase being reflected as “Accretion expense” on the Company’s Consolidated Statements of Operations. If the Company incurs an amount different from the amount accrued for asset retirement obligations, the Company recognizes the difference as an adjustment to proved properties.

Income Taxes — Our provision for income taxes includes U.S. state and federal and foreign taxes. We record our federal income taxes in accordance with accounting for income taxes under GAAP which results in the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the book carrying amounts and the tax basis of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized. As of December 31, 2023, we believe it is more likely than not that some or all of the benefits from our state deferred tax assets will not be realized and reduced the state deferred tax assets by a valuation allowance.

We apply significant judgment in evaluating our tax positions and estimating our provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The actual outcome of these future tax consequences could differ significantly from our estimates, which could impact our financial position, results of operations and cash flows.

We also account for uncertainty in income taxes recognized in the financial statements in accordance with GAAP by prescribing a recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. Authoritative guidance for accounting for uncertainty in income taxes requires that we recognize the financial statement benefit of a tax position only after determining that the relevant tax authority would more likely than not sustain the position following an audit. For tax positions meeting the more likely than not threshold, the amount recognized in the financial statements is the largest benefit that has a greater than 50% likelihood of being realized upon ultimate settlement with the relevant tax authority.

Determination of Fair Value in Business Combinations — We account for business combinations under the acquisition method of accounting. Accordingly, we recognize amounts for identifiable assets acquired and liabilities assumed equal to their estimated acquisition date fair values. The amount of goodwill or bargain purchase gain recognized, if any, is determined based on the consideration transferred compared to the acquisition date amounts of the identifiable net assets acquired.

We make various assumptions in estimating the fair values of assets acquired and liabilities assumed. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. The most significant assumptions relate to the estimated fair values of proved and unproved oil and natural gas properties.

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The fair value of proved and oil natural gas properties as of the acquisition date are based on estimated proved oil, natural gas and NGL reserves and related discounted future net cash flows. Significant inputs to the valuation include estimates of future production volumes, future operating and development costs, future commodity prices, and a weighted average cost of capital discount rate. When estimating the fair value of proved and unproved properties, additional risk adjustments are applied to proved developed non-producing, proved undeveloped, probable and possible reserves to reflect the relative uncertainty of each reserve class.

The estimates used in determining fair values are based on assumptions believed to be reasonable but which are inherently uncertain. Accordingly, actual results may differ from the projected results used to determine fair value. Historically there has been significant volatility in oil, natural gas and NGL prices and estimates of such future prices are inherently imprecise. Additionally, the actual timing of the production could be different than the projection. Cash flows realized later in the projection period are less valuable than those realized earlier due to the time value of money. A higher discount rate decreases the net present value of cash flows.

Recently Adopted Accounting Standards

None.

Recently Issued Accounting Standards

Information on Recently Issued Accounting Standards that could potentially impact our consolidated financial statements and related disclosures is incorporated by reference to Part IV, Item 15. Exhibit and Financial Statement Schedules — Note 1 — Organization, Nature of Business and Basis of Presentation.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

We are currently exposed to market risk in two areas: commodity prices and, to a lesser extent, interest rate risk. Our risk management activities involve the use of derivative financial instruments to mitigate the impact of market price risk exposures primarily related to our oil and natural gas production.

We are subject to a minimum hedging requirement under our Bank Credit Facility for each calendar month on a six-full fiscal quarter rolling basis. For any quarter occurring during the first four forward fiscal quarters, we are required to hedge a minimum of 50% of our reasonably anticipated projected production from proved developed producing reserves from the semi-annual reserves report delivered to the administrative agent of our Bank Credit Facility, adjusted to 45% in July and November and 25% in August, September and October. For the fifth and sixth forward fiscal quarters, if the Consolidated Total Debt to EBITDAX Ratio (as defined in the Bank Credit Facility) is greater than or equal to 1.00 to 1.00, then we are required to hedge a minimum of 25%, adjusted to 20% in August, September and October.

All derivatives are recorded on the Consolidated Balance Sheets at fair value with settlements of such contracts and changes in the unrealized fair value recorded as “Price risk management activities income (expense)” on the Consolidated Statements of Operations in each period.

Commodity Price Risks

Oil and natural gas prices can fluctuate significantly and have a direct impact on our revenues, earnings and cash flow. During year ended December 31, 2023, our average oil price realizations after the effect of derivatives increased 8% to $73.59 per Bbl from $68.40 per Bbl in the comparable 2022 period. Our average natural gas price realizations after the effect of derivatives decreased 37% during the year ended December 31, 2023 to $3.32 per Mcf from $5.30 per Mcf in the comparable 2022 period.

Price Risk Management Activities

We have attempted to mitigate commodity price risk and stabilize cash flows associated with our forecasted sales of oil and natural gas production through the use of oil and natural gas swaps. These contracts will impact our earnings as the fair value of these derivatives changes. Our derivatives will not mitigate all of the commodity price risks of our forecasted sales of oil and natural gas production and, as a result, we will be subject to commodity price risks on our remaining forecasted production.

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We had commodity derivative instruments in place to reduce the price risk associated with future production of 9,833 MBbls of crude oil and 15,515 MMBtu of natural gas at December 31, 2023, with a net derivative asset position of $45.6 million. For additional information regarding our commodity derivative instruments, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 6 — Financial Instruments, included elsewhere in this Annual Report. The table below presents the hypothetical sensitivity of our commodity price risk management activities to changes in fair values arising from immediate selected potential changes in oil and natural gas prices at December 31, 2023 (in thousands):

			Oil and Natural Gas Derivatives
			Ten Percent Increase						Ten Percent Decrease
	Fair Value		Fair Value			Change			Fair Value		Change
Price impact(1)	$	45,603	$	(21,481	)	$	(67,084	)	$	113,601	$	67,998

(1)Presents the hypothetical sensitivity of our commodity price risk management activities to changes in fair values arising from changes in oil and natural gas prices.

Variable Interest Rate Risks

We had total debt outstanding of $1,066.0 million at December 31, 2023, before unamortized original issue discount and deferred financing costs. Of this, $866.0 million aggregate principal was from our 12.00% Notes and 11.75% Notes, which bears interest at a fixed rate. The remaining $200.0 million is from outstanding borrowings under our Bank Credit Facility with variable interest rates. We are subject to the risk of changes in interest rates under our Bank Credit Facility. In addition, the terms of our Bank Credit Facility require us to pay higher interest rates as we utilize a larger percentage of our available borrowing base. We manage our interest rate exposure by maintaining a combination of fixed and variable rate debt and monitoring the effect of market changes in interest rates. As of December 31, 2023, our interest rate risk exposure is mitigated as a result of fixed interest rates on 81% of our debt. The all-in interest rate on our variable rate debt at December 31, 2023 was 8.26%, which includes a spread of 2.85% based on the utilization rate of our Bank Credit Facility, and a secured overnight financing rate (”SOFR”) of 5.41%. A 10% change in the SOFR rate on this variable rate debt balance at December 31, 2023 would change interest expense for the year ended December 31, 2023 by approximately $1.1 million. For additional information regarding the borrowing base utilization percentage associated with our Bank Credit Facility, see Part IV, Item 15. Exhibits and Financial Statement Schedules — Note 8 — Debt, included elsewhere in this Annual Report.

Item 8. Financial Statements and Supplementary Data

See the Consolidated Financial Statements and Report of Independent Registered Public Accounting Firm as of December 31, 2023 and 2022 and for the years ended December 31, 2023, 2022 and 2021, included in Part IV, Item 15. Exhibits and Financial Statements Schedules.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our chief executive officer and chief financial officer, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a- 15(e) and 15d- 15(e) under the Exchange Act) as of the end of the period covered by this Annual Report. Based on such evaluation, our chief executive officer and chief financial officer have concluded that as of December 31, 2023, our disclosure controls and procedures are designed at a reasonable assurance level and are effective to provide reasonable assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of SEC, and that such information is accumulated and communicated to our management, including our chief executive officer and chief financial officer, as appropriate, to allow timely decisions regarding required disclosures.

Management’s Annual Report on Internal Control over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Exchange Act. Management conducted an assessment of the effectiveness of our internal control over financial reporting based on the criteria set forth in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based on the assessment, management has concluded that its internal control over financial reporting was effective as of December 31, 2023 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with GAAP. Our independent registered public accounting firm, Ernst & Young LLP, has issued an audit report with respect to our internal control over financial reporting, which is included in this Annual Report.

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Changes in Internal Control over Financial Reporting

There were no changes in our internal controls over financial reporting identified in management's evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the fourth quarter of 2023 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

During the three months ended December 31, 2023, no director or officer of the Company adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspection

Not applicable.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information required by this item is incorporated by reference to our Proxy Statement for the 2024 Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2023.

Our Board of Directors has adopted a Code of Business Conduct and Ethics applicable to all officers, directors and employees, which is available on our website (www.talosenergy.com) under “Corporate Governance” within the “Investors” tab. We intend to satisfy the disclosure requirement under Item 5.05 of Form 8-K regarding amendment to, or waiver from, a provision of our Code of Business Conduct and Ethics by posting such information on the website address and location specified above.

Item 11. Executive Compensation

The information required by this item is incorporated by reference to our Proxy Statement for the 2024 Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2023.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The information required by this item is incorporated by reference to our Proxy Statement for the 2024 Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2023.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required by this item is incorporated by reference to our Proxy Statement for the 2024 Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2023.

Item 14. Principal Accounting Fees and Services

The information required by this item is incorporated by reference to our Proxy Statement for the 2024 Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2023.

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PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)The following documents are filed as part of this Annual Report:

(1)Financial Statements:

Refer to the Index to Consolidated Financial Statements on page F-1 for a list of all financial statements filed as part of this Annual Report on Form 10-K.

(2)Financial Statement Schedules:

Other than as stated on the Index to Consolidated Financial Statements on page F-1 with respect to Schedule I, financial statement schedules have been omitted because they are either not material, not required, not applicable or the information required to be presented is included in our Consolidated Financial Statements and related notes.

(3)Exhibits:

Exhibit Number	Description
2.1#	Agreement and Plan of Merger, dated as of September 21, 2022, by and among Talos Energy Inc., Talos Production Inc., Tide Merger Sub I Inc., Tide Merger Sub II LLC, Tide Merger Sub III LLC, BCC Enven Investments, L.P. and EnVen Energy Corporation (incorporated by reference to Exhibit 2.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on September 22, 2022).
2.2#	Agreement and Plan of Merger, dated as of January 13, 2024, by and among Talos Energy Inc., QuarterNorth Energy Inc., Compass Star Merger Sub Inc. and the Equityholder Representatives named therein (incorporated by reference to Exhibit 2.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 16, 2024).
3.1	Second Amended and Restated Certificate of Incorporation of Talos Energy Inc. (incorporated by reference to Exhibit 3.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023).
3.2	Second Amended and Restated Bylaws of Talos Energy Inc. (incorporated by reference to Exhibit 3.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023).
4.1	Indenture, dated as of January 4, 2021, by and among Talos Production Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee and as collateral agent (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 8, 2021).
4.2	Form of Stock Certificate for Common Stock of Talos Energy Inc. (incorporated by reference to Exhibit 4.2 to Talos Energy Inc.’s Amendment No. 1 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on February 9, 2018).
4.3	First Supplemental Indenture, dated as of January 14, 2021, by and among Talos Production Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee and as collateral agent (incorporated by reference to Exhibit 4.3 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 14, 2021).
4.4	Indenture, dated as of February 7, 2024, and by and among Talos Production Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee, pursuant to which the 2029 Notes were issued. (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 7, 2024).
4.5	Indenture, dated as of February 7, 2024, and by and among Talos Production Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee, pursuant to which the 2031 Notes were issued. (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 7, 2024).
4.6	Form of 12.00% Second-Priority Senior Secured Note due 2026 (included as Exhibit A to Exhibit 4.6 hereto) (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 8, 2021).
4.7	Form of 9.000% Second-Priority Senior Secured Note due 2029 (included as Exhibit A to Exhibit 4.4 hereto) (incorporated by reference to Exhibit 4.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 7, 2024).

84

4.8	Form of 9.375% Second-Priority Senior Secured Note due 2031 (included as Exhibit A in Exhibit 4.5 hereto) (incorporated by reference to Exhibit 4.4 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 7, 2024).
4.9	Registration Rights Agreement, dated as of January 4, 2021, by and among Talos Production Inc., the Guarantors named therein and J.P. Morgan Securities LLC, as representative of the initial purchasers of the 2026 Notes (incorporated by reference to Exhibit 4.3 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 8, 2021).
4.10	Registration Rights Agreement, dated as of January 14, 2021, by and among Talos Production Inc., the Guarantors named therein and J.P. Morgan Securities LLC, as representative of the initial purchasers of the 2026 Notes (incorporated by reference to Exhibit 4.4 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 14, 2021).
4.11	Registration Rights Agreement, dated September 21, 2022, by and among Talos Energy Inc. and the Persons listed on Schedule A thereto (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on September 22, 2022).
4.12	Description of Registrant’s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (incorporated by reference to Exhibit 4.10 to Talos Energy Inc.’s Form 10-K (File No. 001-38497) filed with the SEC on March 1, 2023).
4.13	Second Supplemental Indenture, dated as of October 27, 2022, among Talos Production Inc., the Guarantors named therein and Wilmington Trust National Association, as trustee and as collateral agent (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on October 28, 2022).
4.14	Indenture, dated as of April 15, 2021, by and among Energy Ventures GoM LLC, EnVen Finance Corporation, Talos Production Inc. (as successor in interest to EnVen Energy Corporation), the other guarantors party thereto and Wilmington Trust, National Association, as trustee and as collateral agent (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023).
4.15	Second Supplemental Indenture, dated as of February 13, 2023, among Talos Production Inc., each of the other guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent (incorporated by reference to Exhibit 4.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023).
4.16	Third Supplemental Indenture, dated as of February 13, 2023, among Talos Production Inc., Energy Ventures GoM LLC, EnVen Finance Corporation, each of the other guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent (incorporated by reference to Exhibit 4.4 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023).
10.1	Credit Agreement, dated as of May 10, 2018, by and among Talos Production LLC, as borrower, Talos Energy Inc., as holdings, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders named therein (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 8-K12B/A filed with the SEC on July 18, 2018).
10.2	Intercreditor Agreement, dated as of May 10, 2018, between JPMorgan Chase Bank, N.A., as First Lien Agent, and Wilmington Trust, National Association, as Second Lien Agent (incorporated by reference to Exhibit 10.3 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).
10.3†	Offer Letter between Talos Energy Inc. and Shannon Young, dated as of April 13, 2019 (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K filed with the SEC on April 24, 2019).
10.4†	Offer Letter between Talos Energy Inc. and Robert D. Abendschein, dated as of December 26, 2019 (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 23, 2020).
10.5†	Employment Agreement, dated as of February 3, 2012, by and between Talos Energy Operating Company LLC and Timothy S. Duncan (incorporated by reference to Exhibit 10.10 to Talos Energy Inc.’s Amendment No. 3 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on March 30, 2018).
10.6†	Employment Agreement, dated as of February 3, 2012, by and between Talos Energy Operating Company LLC and John A. Parker (incorporated by reference to Exhibit 10.12 to Talos Energy Inc.’s Amendment No. 3 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on March 30, 2018).
10.7†	Employment Agreement, dated as of August 30, 2013, by and between Talos Energy Operating Company LLC and William S. Moss III (incorporated by reference to Exhibit 10.14 to Talos Energy Inc.’s Amendment No. 3 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on March 30, 2018).

85

10.8†	Separation and Release Agreement by and between the Company and Robert D. Abendschein, effective December 26, 2023 (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 29, 2023).
10.9†	Talos Energy Inc. Long Term Incentive Plan (incorporated by reference to Exhibit 10.4 to Talos Energy Inc.’s Form 8-K12B filed with the SEC on May 16, 2018).
10.10†	Talos Energy Inc. 2021 Long Term Incentive Plan (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 6, 2021).
10.11	Contract for the Exploration and Extraction of Hydrocarbons under Production Sharing Modality (Contract Area 7), dated as of September 4, 2015, by and among the National Hydrocarbons Commission, Sierra O&G Exploración y Producción, S. de R.L. de C.V., Talos Energy Offshore México 7, S. de R.L. de C.V. and Premier Oil Exploration and Production Mexico, S.A. de C.V. (incorporated by reference to Exhibit 10.9 to Talos Energy Inc.’s Amendment No. 4 to the Registration Statement on Form S-4 (File No. 333-222341) filed with the SEC on April 4, 2018).
10.12†*	Form of Indemnification Agreement (Directors and Officers).
10.13†	Form of Restricted Stock Unit Grant Notice and Restricted Stock Agreement (Directors) (incorporated by reference to Exhibit 10.20 to Talos Energy Inc.’s Form 10-Q filed with the SEC on August 9, 2018).
10.14†	Form of Talos Energy Inc. Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Directors) (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 6, 2021).
10.15†	Form of Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Executives) (incorporated by reference to Exhibit 10.32 to Talos Energy Inc.’s Registration Statement on Form S-4 (File No. 333-227362) filed with the SEC on September 14, 2018)
10.16†	Form of Talos Energy Inc. 2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Executives) (incorporated by reference to Exhibit 10.3 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 6, 2021).
10.17†	Form of Talos Energy Inc. 2021 Long Term Incentive Plan Performance Share Unit Grant Notice and Performance Share Unit Agreement (Executives) (incorporated by reference to Exhibit 10.4 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 6, 2021).
10.18†	Form of Talos Energy Inc. 2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Directors) (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on November 3, 2021).
10.19†	Form of Talos Energy Inc. 2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Executives) (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 5, 2022).
10.20†	Form of Talos Energy Inc. 2021 Long Term Incentive Plan Performance Share Unit Grant Notice and Performance Share Unit Agreement (Executives) (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 5, 2022).
10.21†	Form of Performance Share Unit Cancellation and Release Agreement (incorporated by reference to Exhibit 10.3 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 5, 2022).
10.22†	Talos Energy Operating Company LLC Amended and Restated Executive Severance Plan (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on March 2, 2020).
10.23†	Form of Participation Agreement pursuant to Talos Energy Operating Company LLC Amended and Restated Executive Severance Plan (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on October 26, 2020).
10.24†	Talos Energy Inc. 2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Directors) (incorporated by reference to Exhibit 10.5 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on May 9, 2023).

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10.25	Joinder, First Amendment to Credit Agreement, and Borrowing Base Reaffirmation Agreement, dated as of July 3, 2019, by and among Talos Energy Inc., as holdings, Talos Production LLC, as borrower, each other credit party, JPMorgan Chase Bank, N.A., as administrative agent, each issuing bank, the swingline lender, and the lenders (including the new lenders) party thereto (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K filed with the SEC on July 10, 2019).
10.26	Joinder, Commitment Increase Agreement, Second Amendment to Credit Agreement, Borrowing Base Redetermination Agreement, and Amendment to Other Credit Documents, dated as of December 10, 2019, by and among Talos Energy Inc., as holdings, Talos Production Inc., as borrower, each other credit party, JPMorgan Chase Bank, N.A., as administrative agent, each issuing bank, the swingline lender, and the lenders (including the new lenders) party thereto (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 16, 2019).
10.27	Third Amendment to Credit Agreement and Borrowing Base Redetermination Agreement, dated as of June 19, 2020, by and among Talos Energy Inc., as holdings, Talos Production Inc., as borrower, each other credit party, JPMorgan Chase Bank, N.A., as administrative agent, each issuing bank, the swing line lender, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on June 25, 2020).
10.28	Borrowing Base Redetermination Agreement and Sixth Amendment to Credit Agreement, dated as of June 22, 2021, by and among Talos Energy Inc., as holdings, Talos Production Inc., as borrower, each other credit party thereto, JPMorgan Chase Bank, N.A., as administrative agent, each issuing bank, the swingline lender and the lenders party thereto (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on June 23, 2021).
10.29	Incremental Agreement, Borrowing Base Redetermination Agreement and Seventh Amendment to Credit Agreement, dated as of December 21, 2021, by and among Talos Energy Inc., as holdings, Talos Production Inc., as borrower, each other credit party thereto, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto. (incorporated by reference to Exhibit 10.45 to Talos Energy Inc.’s Form 10-K (File No. 001-38497) filed with the SEC on February 25, 2022).
10.30	Borrowing Base Redetermination Agreement and Eighth Amendment to Credit Agreement, dated as of May 4, 2022, by and among Talos Energy Inc., as holdings, Talos Production Inc., as borrower, each other credit party thereto, JPMorgan Chase Bank, N.A., as administrative agent, each issuing bank, the swingline lender and the lenders party thereto. (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on August 05, 2022).
10.31	Incremental Agreement of Increasing Lenders, dated as of May 4, 2022, by and among DNB Capital LLC and Mizuho Bank, Ltd, as increasing lender, Talos Production Inc., as borrower, Talos Energy Inc., as holdings, JPMorgan Chase Bank, N.A., as administrative agent, swingline lender and issuing bank and Natixis, New York Branch, as issuing bank.(incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 10-Q (File No. 001-38497) filed with the SEC on August 05, 2022).
10.32	Incremental Agreement and Ninth Amendment to Credit Agreement, dated as of December 23, 2022, among Talos Energy Inc., Talos Production Inc., each other Credit Party, JPMorgan Chase Bank, N.A., as Administrative Agent, each Issuing Bank, the Swingline Lender and each of the Lenders (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on December 27, 2022).
10.33*	Tenth Amendment to Credit Agreement, dated January 13, 2024, by and among Talos Energy Inc., as Holdings and a Guarantor, Talos Production Inc., as the Borrower, the other Guarantors party thereto, JPMorgan Chase, N.A., as the Administrative Agent, and the Lenders party thereto.
10.34#	Form of QuarterNorth Support Agreement, by and among QuarterNorth Energy Inc., Talos Energy Inc. and the other parties thereto (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 16, 2024).
21.1*	List of Subsidiaries of Talos Energy Inc.
22.1*	List of Subsidiary Guarantors and Issuers of Guaranteed Securities.
23.1*	Consent of Ernst & Young LLP.
23.2*	Consent of Netherland, Sewell & Associates, Inc.
24.1*	Powers of Attorney (included on signature pages of this Part IV).

87

31.1*	Certification of Chief Executive Officer of Talos Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer of Talos Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1**	Certification of Chief Executive Officer and Chief Financial Officer of Talos Energy Inc. pursuant to 18 U.S.C. § 1350, as adopted pursuant to the Sarbanes-Oxley Act of 2002.
97.1*	Talos Energy Inc. Executive Compensation Clawback Policy, effective November 15, 2023.
99.1*	Netherland, Sewell & Associates, Inc. reserve report for Talos Energy Inc. as of December 31, 2023.
101.INS*	Inline XBRL Instance.
101.SCH*	Inline XBRL Taxonomy Extension Schema.
101.CAL*	Inline XBRL Taxonomy Extension Calculation.
101.DEF*	Inline XBRL Taxonomy Extension Definition.
101.LAB*	Inline XBRL Taxonomy Extension Label.
101.PRE*	Inline XBRL Taxonomy Extension Presentation.
104*	Cover Page Interactive Data File – The cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

*	Filed herewith.
**	Furnished herewith.
†	Identifies management contracts and compensatory plans or arrangements.
#	Certain schedules, annexes or exhibits have been omitted pursuant to Item 601(a)(5) of Regulation S-K, but will be furnished supplementally to the SEC upon request.

Item 16. Form 10-K Summary

None.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		TALOS ENERGY INC.
Date:	February 28, 2024	By:	/s/ Sergio L. Maiworm, Jr.
			Sergio L. Maiworm, Jr.
			Chief Financial Officer and Senior Vice President

POWER OF ATTORNEY

KNOW ALL PERSONS BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints Timothy S. Duncan and Sergio L. Maiworm, Jr., and each of them, as his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this report, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in connection therewith, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming that all said attorneys-in-fact and agents, or any of them or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Timothy S. Duncan	Chief Executive Officer	February 28, 2024
Timothy S. Duncan	(Principal Executive Officer, Director)
/s/ Sergio L. Maiworm, Jr.	Chief Financial Officer	February 28, 2024
Sergio L. Maiworm, Jr.	(Principal Financial Officer, Authorized Signatory)
/s/ Gregory Babcock	Chief Accounting Officer	February 28, 2024
Gregory Babcock	(Principal Accounting Officer, Authorized Signatory)
/s/ Paula R. Glover	Director	February 28, 2024
Paula R. Glover
/s/ Neal P. Goldman	Director	February 28, 2024
Neal P. Goldman
/s/ John “Brad” Juneau	Director	February 28, 2024
John “Brad” Juneau
/s/ Donald R. Kendall, Jr.	Director	February 28, 2024
Donald R. Kendall, Jr.
/s/ Richard Sherrill	Director	February 28, 2024
Richard Sherrill
/s/ Charles M. Sledge	Director	February 28, 2024
Charles M. Sledge
/s/ Shandell Szabo	Director	February 28, 2024
Shandell Szabo

89

Index to Consolidated Financial Statements

Reports of Independent Registered Public Accounting Firm (PCAOB ID 42)	F-2
Consolidated Balance Sheets as of December 31, 2023 and 2022	F-6
Consolidated Statements of Operations for the years ended December 31, 2023, 2022 and 2021	F-7
Consolidated Statements of Changes in Stockholders’ Equity for the years ended December 31, 2023, 2022 and 2021	F-8
Consolidated Statements of Cash Flows for the years ended December 31, 2023, 2022 and 2021	F-9
Notes to Consolidated Financial Statements	F-10
Note 1 — Organization, Nature of Business and Basis of Presentation	F-10
Note 2 — Summary of Significant Accounting Policies	F-10
Note 3 — Acquisitions and Divestitures	F-16
Note 4 — Property, Plant and Equipment	F-18
Note 5 — Leases	F-19
Note 6 — Financial Instruments	F-21
Note 7 — Equity Method Investments	F-23
Note 8 — Debt	F-24
Note 9 — Asset Retirement Obligations	F-28
Note 10 — Employee Benefit Plans and Share-Based Compensation	F-28
Note 11 — Income Taxes	F-31
Note 12 — Income (Loss) Per Share	F-33
Note 13 — Related Party Transactions	F-34
Note 14 — Commitments and Contingencies	F-35
Note 15 — Segment Information	F-37
Note 16 — Supplemental Oil and Gas Disclosures (Unaudited)	F-39
Note 17 — Subsequent Events	F-42
Schedule to Consolidated Financial Statements	F-43
Schedule I — Condensed Financial Information of Registrant	F-43

F-1

Report of Independent Registered Public Accounting Firm

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

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Talos Energy Inc. (the Company) as of December 31, 2023 and 2022, the related consolidated statements of operations, changes in stockholders' equity and cash flows for each of the three years in the period ended December 31, 2023, and the related notes and the financial statement schedule listed in Item 15(a) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 28, 2024 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of the critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matters or on the accounts or disclosures to which it relates.

Depreciation, depletion and amortization of proved oil and gas properties.

Description of the Matter

As described in Note 2 to the consolidated financial statements, the Company follows the full cost method of accounting for its oil and gas properties. Depreciation, depletion and amortization (“DD&A”) of the cost of proved oil and gas properties is calculated using the unit-of-production method based on proved oil and gas reserves, as estimated by the Company’s internal reservoir engineers. Proved oil and gas reserves are prepared using standard geological and engineering methods generally recognized in the petroleum industry based on evaluations of estimated in-place hydrocarbon volumes using financial and non-financial inputs. Judgment is required by the Company’s internal reservoir engineers in evaluating geological and engineering data when estimating oil and gas reserves. Estimating reserves also requires the selection and evaluation of inputs, including historical production, future oil and gas price assumptions, future operating and capital costs assumptions, among others. Because of the complexity involved in estimating oil and gas reserves, management engaged independent petroleum engineers to audit the proved oil and gas reserve estimates prepared by the Company’s internal reservoir engineers for all properties as of December 31, 2023. Auditing the Company’s DD&A expense calculation is complex because of the use of the work of the internal reservoir engineers and independent petroleum engineers and the evaluation of management’s determination of the inputs described above used by the engineers in estimating proved oil and gas reserves.

F-2

How We Addressed the Matter in Our Audit	We obtained an understanding, evaluated the design, and tested the operating effectiveness of the Company’s controls that address the risks of material misstatement relating to the DD&A expense calculation, including management’s controls over the completeness and accuracy of the financial data provided to the engineers for use in estimating oil and gas reserves. Our audit procedures included, among others, evaluating the professional qualifications and objectivity of the Company’s internal reservoir engineers responsible for overseeing the preparation of the reserve estimates and the independent petroleum engineers used to audit the proved oil and gas reserve estimates. On a sample basis, we tested the completeness and accuracy of the financial data used in the estimation of proved oil and gas reserves by agreeing significant inputs to source documentation, where available, and assessing the inputs for reasonableness based on review of corroborative evidence and consideration of any contrary evidence. Additionally, we performed analytic and lookback procedures on select inputs into the oil and gas reserve estimate. Finally, we tested that the DD&A expense calculations are based on the appropriate proved oil and gas reserve balances from the Company’s reserve report.
	Evaluation of the fair value measurement of oil and gas properties acquired in the EnVen Energy Corporation business combination
Description of the Matter	As described in Note 3 to the consolidated financial statements, the Company executed a merger agreement to acquire EnVen Energy Corporation for net consideration of approximately $1.0 billion. The transaction was accounted for as a business combination. The Company applied a discounted cash flow method to estimate the fair value of the proved and unproved oil and gas properties acquired. Significant judgment is required by the Company’s internal reservoir engineers in evaluating geological and engineering data when estimating oil and gas reserves. Significant inputs to the valuation of proved and unproved oil and gas properties include estimates of future oil and gas price assumption and production profiles of reserve estimates, reserve category risk adjustment factors and discount rate using a market-based weighted average cost of capital. Auditing the Company’s determination of the fair value of the proved and unproved oil and gas properties acquired was complex due to the significant estimation required by management of reserves associated with the acquired assets and the sensitivity of the significant assumptions used in determining the fair value. In evaluating the reasonableness of management’s estimates and assumptions used, the audit testing procedures performed required a high degree of auditor judgment and additional effort, including involving internal specialists.
How We Addressed the Matter in Our Audit	We obtained an understanding, evaluated the design and tested the operating effectiveness of the Company’s internal controls over its process to estimate the fair value of the acquired proved and unproved oil and gas properties, including management’s review of the significant assumptions used as inputs to the fair value calculations. To test the estimated fair value of the acquired proved and unproved oil and gas properties, our audit procedures included, among others, evaluating the significant assumptions used and testing the completeness and accuracy of the underlying data supporting the significant assumptions. For example, we compared and assessed certain significant assumptions to current industry or third-party data for reasonableness. We also performed sensitivity analyses of significant assumptions, to evaluate the extent of their impact to the fair value calculation. In addition, we involved our valuation specialists to assist with certain significant assumptions included in the fair value estimate. Furthermore, we evaluated the professional qualifications and objectivity of the third-party valuation specialist engaged by the Company to prepare the fair value of the acquired proved and unproved oil and gas properties.
	Asset Retirement Obligations
Description of the Matter	As described in Note 2 and 9 of the consolidated financial statements, the Company records a liability for the Asset Retirement Obligation at fair value in the period in which it is incurred. The retirement obligations are periodically adjusted to reflect changes in the expected cash flows resulting from revisions to the estimates of either the timing or amount of the retirement costs. Due to the complexity involved in estimating the expected cash outflows, management used a specialist to estimate the expected cash outflows for the Company’s asset retirement obligation as of December 31, 2023.

F-3

Auditing management’s accounting for retirement obligations was especially challenging, as significant judgment is required by the Company in determining the obligation. The significant judgment was primarily related to the inherent estimation uncertainty relating to the expected cash outflows extent of future asset retirement activities and the ultimate productive life of the properties.

How We Addressed the Matter in Our Audit

We obtained an understanding, evaluated the design, and tested the operating effectiveness of the controls over the Company’s accounting for asset retirement obligation, including the controls over management’s review of the significant assumptions described above. To test the asset retirement obligation, among other procedures, we evaluated the methodology, tested the significant assumptions described above and tested the completeness and accuracy of the underlying data used by the Company in estimating the expected cashflows. To assess the estimates of asset retirement activities and cash flows, we evaluated significant changes from the prior estimate, verified consistency between the timing of asset retirement activities and projected productive life of the properties, verified cost rates against third-party information or internal cost records and recalculated management’s estimate. We involved our asset retirement specialists to assist in our evaluation of the expected cash outflows for asset retirement obligation.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2010.

Houston, Texas

February 28, 2024

F-4

Report of Independent Registered Public Accounting Firm

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

Opinion on Internal Control Over Financial Reporting

We have audited Talos Energy Inc.’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Talos Energy Inc. (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2023 and 2022, the related consolidated statements of operations, changes in stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2023, and the related notes and the financial statement schedule listed in Item 15(a) (collectively referred to as the consolidated financial statements”) and our report dated February 28, 2024 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Report of Management on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Houston, Texas

February 28, 2024

F-5

TALOS ENERGY INC.

CONSOLIDATED BALANCE SHEETS

(In thousands, except share amounts)

	Year Ended December 31,
	2023			2022
ASSETS
Current assets:
Cash and cash equivalents	$	33,637		$	44,145
Accounts receivable:
Trade, net		178,977			150,598
Joint interest, net		79,337			54,697
Other, net		19,296			6,684
Assets from price risk management activities		36,152			25,029
Prepaid assets		64,387			84,759
Other current assets		10,389			1,917
Total current assets		422,175			367,829
Property and equipment:
Proved properties		7,906,295			5,964,340
Unproved properties, not subject to amortization		268,315			154,783
Other property and equipment		34,027			30,691
Total property and equipment		8,208,637			6,149,814
Accumulated depreciation, depletion and amortization		(4,168,328	)		(3,506,539	)
Total property and equipment, net		4,040,309			2,643,275
Other long-term assets:
Restricted cash		102,362			—
Assets from price risk management activities		17,551			7,854
Equity method investments		146,049			1,745
Other well equipment		54,277			25,541
Notes receivable, net		16,207			—
Operating lease assets		11,418			5,903
Other assets		5,961			6,479
Total assets	$	4,816,309		$	3,058,626
LIABILITIES AND STOCKHOLDERSʼ EQUITY
Current liabilities:
Accounts payable	$	84,193		$	128,174
Accrued liabilities		227,690			219,769
Accrued royalties		55,051			52,215
Current portion of long-term debt		33,060			—
Current portion of asset retirement obligations		77,581			39,888
Liabilities from price risk management activities		7,305			68,370
Accrued interest payable		42,300			36,340
Current portion of operating lease liabilities		2,666			1,943
Other current liabilities		48,769			60,359
Total current liabilities		578,615			607,058
Long-term liabilities:
Long-term debt		992,614			585,340
Asset retirement obligations		819,645			501,773
Liabilities from price risk management activities		795			7,872
Operating lease liabilities		18,211			14,855
Other long-term liabilities		251,278			176,152
Total liabilities		2,661,158			1,893,050
Commitments and contingencies (Note 14)
Stockholdersʼ equity:
Preferred stock; $0.01 par value; 30,000,000 shares authorized and zero shares issued or outstanding as of December 31, 2023 and 2022, respectively		—			—
Common stock; $0.01 par value; 270,000,000 shares authorized; 127,480,361 and 82,570,328 shares issued as of December 31, 2023 and 2022, respectively		1,275			826
Additional paid-in capital		2,549,097			1,699,799
Accumulated deficit		(347,717	)		(535,049	)
Treasury stock, at cost; 3,400,000 and zero shares as of December 31, 2023 and 2022, respectively		(47,504	)		—
Total stockholdersʼ equity		2,155,151			1,165,576
Total liabilities and stockholdersʼ equity	$	4,816,309		$	3,058,626

See accompanying notes.

F-6

TALOS ENERGY INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except share amounts)

	Year Ended December 31,
	2023			2022			2021
Revenues:
Oil	$	1,357,732		$	1,365,148		$	1,064,161
Natural gas		68,034			227,306			130,616
NGL		32,120			59,526			49,763
Total revenues		1,457,886			1,651,980			1,244,540
Operating expenses:
Lease operating expense		389,621			308,092			283,601
Production taxes		2,451			3,488			3,363
Depreciation, depletion and amortization		663,534			414,630			395,994
Write-down of oil and natural gas properties		—			—			18,123
Accretion expense		86,152			55,995			58,129
General and administrative expense		158,493			99,754			78,677
Other operating (income) expense		(52,155	)		33,902			32,037
Total operating expenses		1,248,096			915,861			869,924
Operating income (expense)		209,790			736,119			374,616
Interest expense		(173,145	)		(125,498	)		(133,138	)
Price risk management activities income (expense)		80,928			(272,191	)		(419,077	)
Equity method investment income (expense)		(3,209	)		14,222			—
Other income (expense)		12,371			31,800			(6,988	)
Net income (loss) before income taxes		126,735			384,452			(184,587	)
Income tax benefit (expense)		60,597			(2,537	)		1,635
Net income (loss)	$	187,332		$	381,915		$	(182,952	)
Net income (loss) per common share:
Basic	$	1.56		$	4.63		$	(2.24	)
Diluted	$	1.55		$	4.56		$	(2.24	)
Weighted average common shares outstanding:
Basic		119,894			82,454			81,769
Diluted		120,752			83,683			81,769

See accompanying notes.

F-7

TALOS ENERGY INC.

CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY

(In thousands, except share amounts)

	Common Stock				Additional Paid-In			Accumulated			Treasury Stock					Total Stockholdersʼ
	Shares Issued		Par Value		Capital			Deficit			Shares		Amount			Equity
Balance at December 31, 2020		81,279,989	$	813	$	1,659,800		$	(734,012	)		—	$	—		$	926,601
Equity-based compensation		—		—		20,165			—			—		—			20,165
Equity-based compensation tax withholdings		—		—		(3,161	)		—			—		—			(3,161	)
Equity-based compensation stock issuances		601,488		6		(6	)		—			—		—			—
Net income (loss)		—		—		—			(182,952	)		—		—			(182,952	)
Balance at December 31, 2021		81,881,477		819		1,676,798			(916,964	)		—		—			760,653
Equity-based compensation		—		—		27,611			—			—		—			27,611
Equity-based compensation tax withholdings		—		—		(4,603	)		—			—		—			(4,603	)
Equity-based compensation stock issuances		688,851		7		(7	)		—			—		—			—
Net income (loss)		—		—		—			381,915			—		—			381,915
Balance at December 31, 2022		82,570,328		826		1,699,799			(535,049	)		—		—			1,165,576
Equity-based compensation		—		—		25,008			—			—		—			25,008
Equity-based compensation tax withholdings		—		—		(7,459	)		—			—		—			(7,459	)
Equity-based compensation stock issuances		1,110,143		11		(11	)		—			—		—			—
Issuance of common stock for acquisition (Note 3)		43,799,890		438		831,760			—			—		—			832,198
Purchase of treasury stock		—		—		—			—			3,400,000		(47,504	)		(47,504	)
Net income (loss)		—		—		—			187,332			—		—			187,332
Balance at December 31, 2023		127,480,361	$	1,275	$	2,549,097		$	(347,717	)		3,400,000	$	(47,504	)	$	2,155,151

See accompanying notes.

F-8

TALOS ENERGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2023			2022			2021
Cash flows from operating activities:
Net income (loss)	$	187,332		$	381,915		$	(182,952	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion, amortization and accretion expense		749,686			470,625			454,123
Write-down of oil and natural gas properties and other well equipment		—			—			23,729
Amortization of discount, premium and deferred financing costs		15,039			14,379			13,382
Equity-based compensation expense		12,953			15,953			10,992
Price risk management activities (income) expense		(80,928	)		272,191			419,077
Net cash received (paid) on settled derivative instruments		(9,457	)		(425,559	)		(290,164	)
Equity method investment (income) expense		3,209			(14,222	)		—
Loss (gain) on extinguishment of debt		—			1,569			13,225
Settlement of asset retirement obligations		(86,615	)		(69,596	)		(67,988	)
Gain (loss) on sale of assets		(66,115	)		303			(687	)
Changes in operating assets and liabilities:
Accounts receivable		20,352			14,927			(35,396	)
Other current assets		7,066			(36,545	)		(18,901	)
Accounts payable		(60,401	)		24,258			(6,261	)
Other current liabilities		(96,960	)		73,531			64,800
Other non-current assets and liabilities, net		(76,092	)		(13,990	)		14,409
Net cash provided by (used in) operating activities		519,069			709,739			411,388
Cash flows from investing activities:
Exploration, development and other capital expenditures		(561,434	)		(323,164	)		(293,331	)
Proceeds from (cash paid for) acquisitions, net of cash acquired		17,617			(3,500	)		(5,399	)
Proceeds from (cash paid for) sale of property and equipment, net		73,004			1,937			4,983
Contributions to equity method investees		(29,447	)		(2,250	)		—
Investment in intangible assets		(12,366	)		—			—
Proceeds from sale of equity method investment		—			15,000			—
Net cash provided by (used in) investing activities		(512,626	)		(311,977	)		(293,747	)
Cash flows from financing activities:
Issuance of senior notes		—			—			600,500
Redemption of senior notes		(30,000	)		(18,184	)		(356,803	)
Proceeds from Bank Credit Facility		825,000			85,000			100,000
Repayment of Bank Credit Facility		(625,000	)		(460,000	)		(365,000	)
Deferred financing costs		(11,775	)		(189	)		(27,833	)
Other deferred payments		(1,545	)		—			(7,921	)
Payments of finance lease		(16,306	)		(25,493	)		(21,804	)
Purchase of treasury stock		(47,504	)		—			—
Employee stock awards tax withholdings		(7,459	)		(4,603	)		(3,161	)
Net cash provided by (used in) financing activities		85,411			(423,469	)		(82,022	)
Net increase (decrease) in cash, cash equivalents and restricted cash		91,854			(25,707	)		35,619
Cash, cash equivalents and restricted cash:
Balance, beginning of period		44,145			69,852			34,233
Balance, end of period	$	135,999		$	44,145		$	69,852
Supplemental non-cash transactions:
Capital expenditures included in accounts payable and accrued liabilities	$	114,972		$	105,773		$	45,761
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	130,313		$	91,809		$	68,891

See accompanying notes.

F-9

TALOS ENERGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2023

Note 1 — Organization, Nature of Business and Basis of Presentation

Organization and Nature of Business

Talos Energy Inc. (the “Parent Company”) is a Delaware corporation originally incorporated on November 14, 2017. The Parent Company conducts all business operations through its operating subsidiaries, owns no operating assets and has no material operations, cash flows or liabilities independent of its subsidiaries. The Parent Company’s common stock is traded on The New York Stock Exchange under the ticker symbol “TALO.”

The Parent Company (including its subsidiaries, collectively “Talos” or the “Company”) is a technically driven independent exploration and production company focused on safely and efficiently maximizing long-term value through its operations, currently in the United States (“U.S.”) and offshore Mexico both through upstream oil and gas exploration and production and the development of low carbon solutions opportunities. The Company leverages decades of technical and offshore operational expertise in the acquisition, exploration and development of assets in key geological trends that are present in many offshore basins around the world. The Company is also utilizing its expertise to develop CCS projects to help reduce industrial emissions along the coast of the U.S. Gulf of Mexico.

Basis of Presentation and Consolidation

The Consolidated Financial Statements have been prepared in accordance with GAAP and include the accounts of the Parent Company and entities in which the Parent Company holds a controlling financial interest. Both majority-owned subsidiaries and any variable interest entity in which the Parent Company is the primary beneficiary are consolidated. All intercompany transactions have been eliminated. All adjustments are of a normal, recurring nature and are necessary to fairly present the financial position, results of operations and cash flows for the periods reflected herein.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities 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. Actual results could differ from those estimates.

Segments

The Company has two operating segments: (i) exploration and production of oil, natural gas and NGLs (“Upstream Segment”) and (ii) CCS (“CCS Segment”). The Upstream Segment is the Company’s only reportable segment. The legal entities included in the CCS Segment have been designated as unrestricted, non-guarantor subsidiaries of the Company for purposes of the Bank Credit Facility (as defined in Note 2 — Summary of Significant Accounting Policies) and indenture governing the senior notes. See additional information in Note 15 — Segment Information.

Recently Issued Accounting Standards

Segment Reporting — In November 2023, the Financial Accounting Standards Board (“FASB”) issued an update to the required disclosures for segment reporting. The update is intended to improve reportable segment disclosures, primarily through enhanced disclosures about significant segment expenses. The update will require public entities to disclose significant segment expenses that are regularly provided to the chief operating decision maker and included within segment profit and loss. The update is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024 on a retrospective basis. Early adoption is permitted. The Company is currently evaluating the effect of this update on the Company’s disclosures.

Tax Disclosures — In December 2023, the FASB issued an update which expands disclosures in an entity’s income tax rate reconciliation table and regarding cash taxes paid both in the U.S. and foreign jurisdictions. The update is effective for annual periods beginning after December 15, 2024 on a prospective basis. However, retrospective application in all periods presented is permitted. The Company is currently evaluating the effect of this update on the Company’s disclosures.

Note 2 — Summary of Significant Accounting Policies

Overview of Significant Accounting Policies

Cash and Cash Equivalents — The Company presents cash as “Cash and cash equivalents” on the Company’s Consolidated Balance Sheets. The Company considers all cash, money market funds and highly liquid investments with an original maturity of three months or less as cash and cash equivalents. Cash and cash equivalents are carried at cost, which approximates fair value.

F-10

Accounts Receivable and Allowance for Expected Credit Losses — Accounts receivable are stated at the historical carrying amount net of an allowance for expected credit losses. At each reporting period, the recoverability of material receivables is assessed using historical data, current market conditions and reasonable and supported forecasts of future economic conditions to determine their expected collectability. A loss-rate methodology is used to estimate the allowance for expected credit losses to be accrued on material receivables to reflect the net amount to be collected. As of December 31, 2023 and 2022, the Company had allowances of $8.8 million and $10.7 million, respectively, presented net in accounts receivable on the Consolidated Balance Sheets.

Price Risk Management Activities — The Company uses commodity price derivatives to manage fluctuating oil and natural gas market risks. The Company periodically enters into commodity derivative contracts, which may require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes.

Commodity derivatives are recorded on the Consolidated Balance Sheets at fair value with settlements of such contracts and changes in the unrealized fair value recorded in earnings each period. Realized gains and losses on the settlement of commodity derivatives and changes in their unrealized gains and losses are reported in “Price risk management activities income (expense)” on the Consolidated Statements of Operations. The Company classifies cash flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows are considered an integral part of the Company’s oil and natural gas operations, they are classified as cash flows from operating activities. The Company does not enter into derivative agreements for trading or other speculative purposes.

The commodity derivative’s fair value reflects the Company’s best estimate with priority based upon exchange or over-the-counter quotations. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, the Company then utilizes other valuation techniques or models to estimate market values. These modeling techniques require the Company to make estimations of future prices, price correlation, market volatility and liquidity. The Company’s actual results may differ from its estimates, and these differences can be favorable or unfavorable.

Prepaid Assets — Prepaid assets primarily represent prepaid subscriptions, insurance, progress payments for well equipment and deposits with the Office of Natural Resources Revenue (“ONRR”). The progress payments made for well equipment relate to long lead time items which the Company has not taken title to as of period end. The deposits with ONRR represent the Company’s estimated federal royalties payable within thirty days of the production date. On a monthly basis, the Company adjusts the deposit based on actual royalty payments remitted to the ONRR.

Accounting for Oil and Natural Gas Activities — The Company follows the full cost method of accounting for oil and natural gas exploration and development activities. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the internal costs directly related to acquisition, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and assessed for impairment on a quarterly basis through a ceiling test calculation as discussed below.

Capitalized costs associated with proved reserves are amortized on a country-by-country basis over the life of the total proved reserves using the unit of production method, computed quarterly. Conversely, capitalized costs associated with unproved properties and related geological and geophysical costs, exploration wells currently drilling and capitalized interest are initially excluded from the amortizable base. The Company transfers unproved property costs into the amortizable base when properties are determined to have proved reserves or when the Company has completed an unproved properties evaluation resulting in an impairment. The Company evaluates each of these unproved properties individually for impairment at least annually. Additionally, the amortizable base includes future development costs, dismantlement, restoration and abandonment costs, net of estimated salvage values, and geological and geophysical costs incurred that cannot be associated with specific unproved properties or prospects in which the Company owns a direct interest. The Company capitalizes overhead costs that are directly related to exploration, acquisition and development activities.

The Company’s capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10%, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. Generally, any costs in excess of the ceiling are recognized as a non-cash “Write-down of oil and natural gas properties” on the Consolidated Statements of Operations and an increase to “Accumulated depreciation, depletion and amortization” on the Company’s Consolidated Balance Sheets. The expense may not be reversed in future periods, even though higher oil, natural gas and NGL prices may subsequently increase the ceiling. The Company performs this ceiling test calculation each quarter. In accordance with the SEC rules and regulations, the Company utilizes SEC Pricing when performing the ceiling test. The Company also holds prices and costs constant over the life of the reserves, even though actual prices and costs of oil and natural gas are often volatile and may change from period to period.

F-11

Under the full cost method of accounting for oil and natural gas operations, assets whose costs are currently being depreciated, depleted or amortized are assets in use in the earnings activities of the enterprise and do not qualify for capitalization of interest cost. Investments in unproved properties for which exploration and development activities are in progress and other major development projects that are not being currently depreciated, depleted or amortized are assets qualifying for capitalization of interest costs.

When the Company sells or conveys interests in oil and natural gas properties, the Company reduces its oil and natural gas reserves for the amount attributable to the sold or conveyed interest. The Company treats sales proceeds on non-significant sales as reductions to the cost of the Company’s oil and natural gas properties. The Company does not recognize a gain or loss on sales of oil and natural gas properties, unless those sales would significantly alter the relationship between capitalized costs and proved reserves.

Other Property and Equipment — Other property and equipment is recorded at cost and consists primarily of leasehold improvements, office furniture and fixtures and computer hardware. Acquisitions and betterments are capitalized; maintenance and repairs are expensed as incurred. Depreciation is provided using the straight-line method over estimated useful lives of three to ten years.

Restricted Cash — Any cash that is legally restricted from use is classified as restricted cash. If the purpose of restricted cash relates to acquiring a long-term asset, liquidating a long-term liability, or is otherwise unavailable for a period longer than one year from the balance sheet date, the restricted cash is included in other long-term assets. Otherwise, restricted cash is included in other current assets in the Consolidated Balance Sheets. The Company acquired funds held in escrow to be used for future plugging and abandonment (“P&A”) obligations assumed through the EnVen Acquisition (as defined in Note 3 — Acquisitions and Divestitures). These escrow accounts required deposits of approximately $100.0 million, which was fully funded by EnVen (as defined in Note 3 — Acquisitions and Divestitures) prior to the consummation of the acquisition. This is reflected as “Restricted Cash” within “Other long-term assets” on the Consolidated Balance Sheets.

Equity Method Investments — The Company generally accounts for investments under the equity method of accounting when it exercises significant influence over the entity’s operating and financial policies but does not hold a controlling financial interest in the entity. The voting percentage that is presumed to provide an investor with the required level of influence necessary to apply the equity method of accounting varies depending on the nature of the investee. For investments in common stock, in-substance common stock, a limited liability company or partnership that does not maintain specific ownership accounts for each investor, a voting percentage of 20% or more is generally presumed to demonstrate significant influence. For investments in a limited partnership or unincorporated joint venture and a limited liability company or partnership that maintains a specific ownership account for each investor, a voting percentage of 3-5% or more is generally presumed to demonstrate significant influence. Equity method accounting for interests in limited partnerships is generally appropriate unless the interest is so minor that the investor has virtually no influence (less than 3%).

In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for the Company’s proportionate share of earnings, losses, contributions and distributions. Investments accounted for using the equity method are reflected as “Equity method investments” on the Consolidated Balance Sheets. The equity in earnings of an investee is reflected in “Equity method investment income (expense)” on the Consolidated Statement of Operations. The gain or loss from the full or partial sale of an equity method investment is presented in the same line item in which the Company reports the equity in earnings of the investee.

The Company assesses equity method investments for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred if the loss is deemed to be other-than-temporary. When the loss is deemed to be other-than-temporary, the carrying value of the equity method investment is written down to fair value. The impairment charge is included as a component of the Company’s share of the earning or losses of the investee. No impairment charges have been recorded during the years ended December 31, 2023, 2022 and 2021.

Other Well Equipment — Other well equipment primarily represents the cost of equipment to be used in the Company’s oil and natural gas drilling and development activities such as drilling pipe, tubulars and certain wellhead equipment. When well equipment is supplied to wells, the cost is capitalized in oil and gas properties, and if such property is jointly owned, the proportionate costs will be reimbursed by third party participants.

Notes Receivable, net — The Company holds two notes receivable with an aggregate face value of $66.2 million acquired by the Company as part of the EnVen Acquisition (as defined herein), which consist of commitments from the sellers of oil and natural gas properties related to the costs associated with P&A obligations (the “P&A Notes Receivable”). The P&A Notes Receivable are recorded at a discounted value, being accreted to their principal amounts and presented as such, net of related cumulative estimated credit losses, on the accompanying Consolidated Balance Sheets. The Company estimates the current expected credit losses related to its P&A Notes Receivable using the probability of default method based on the long-term credit ratings of the counterparties of the notes, which are currently considered “investment grade.”

F-12

Leases — At inception, contracts are reviewed to determine whether the agreement contains a lease. To the extent an arrangement is determined to include a lease, it is classified as either an operating or a finance lease, which dictates the pattern of expense recognition in the income statement. Operating leases are reflected as “Operating lease assets,” “Current portion of operating lease liabilities” and “Operating lease liabilities” on the Consolidated Balance Sheets. Finance leases are included in “Property and equipment,” “Other current liabilities” and “Other long-term liabilities” on the Consolidated Balance Sheets.

A right-of-use (“ROU”) asset representing our right to use an underlying asset for the lease term and a lease liability representing our obligation to make lease payments arising from the lease are recognized on the Consolidated Balance Sheets for all leases, regardless of classification. The ROU asset is initially measured as the present value of the lease liability adjusted for any payments made prior to lease commencement, including any initial direct costs incurred and incentives received. Lease liabilities are initially measured at the present value of future minimum lease payments, excluding variable lease payments, over the lease term. As most of our leases do not provide an implicit rate, the Company generally uses an incremental borrowing rate based on the estimated rate of interest for collateralized borrowing over a similar term of the lease payments at commencement date.

The Company has elected to account for lease and non-lease components in its contracts as a single lease component for all asset classes except for our leased floating production vessel class. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. The Company has elected, as an accounting policy, not to record leases with terms of twelve months or less (i.e., short-term) on the Consolidated Balance Sheets. See Note 5 — Leases for additional information.

Debt Issuance Costs — The Company presents debt issuance costs associated with revolving line-of-credit arrangements as a reduction of the carrying value of long-term debt.

Asset Retirement Obligations — The Company has obligations associated with the retirement of its oil and natural gas wells and related infrastructure. The Company has obligations to plug wells when production on those wells is exhausted, when the Company no longer plans to use them or when the Company abandons them. The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount to replace, remove or retire the associated assets.

In estimating the liability associated with its asset retirement obligations, the Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate. Changes in estimate represent changes to the expected amount and timing of payments to settle its asset retirement obligations. Typically, these changes result from obtaining new information about the timing of its obligations to plug and abandon oil and natural gas wells and the costs to do so. After initial recording, the liability is increased for the passage of time, with the increase being reflected as “Accretion expense” on the Company’s Consolidated Statements of Operations. If the Company incurs an amount different from the amount accrued for asset retirement obligations, the Company recognizes the difference as an adjustment to proved properties.

Decommissioning Obligations — Certain counterparties in divestiture transactions or third parties in existing leases that have filed for bankruptcy protection or undergone associated reorganizations may not be able to perform required abandonment obligations. The Company may be held jointly and severally liable for the decommissioning of various facilities and related wells. The Company accrues losses associated with decommissioning obligations when such losses are probable and reasonably estimable. When there is a range of possible outcomes, the amount accrued is the most likely outcome within the range. If no single outcome within the range is more likely than the others, the minimum amount in the range is accrued. These accruals may be adjusted as additional information becomes available. In addition, when decommissioning obligations are reasonably possible, the Company discloses an estimate for a possible loss or range of loss (or a statement that such an estimate cannot be reasonably made). See Note 14 — Commitments & Contingencies for additional information.

Share-Based Compensation — Certain of the Company’s employees participate in its equity-based compensation plan. The Company measures all employee equity-based compensation awards at fair value on the date awards are granted to its employees.

The fair value of the stock-based awards is determined at the date of grant and is not remeasured for awards classified as equity unless the award is modified. Liability classified awards are remeasured at each reporting period. The Company records share-based compensation, net of actual forfeitures, for the restricted stock units (“RSUs”) and performance share units (“PSUs”) in “General and administrative expense” on the Consolidated Statements of Operations, net of amounts capitalized to oil and gas properties. See Note 10 — Employee Benefits Plans and Share-Based Compensation for additional information.

RSUs — Share-based compensation is based on the market price of the Company’s common stock on the grant date and recognized over the requisite service period using the straight-line method.

F-13

PSUs with Market Based Conditions — Share-based compensation is based on the grant date fair value determined using a Monte Carlo valuation model for awards with a market condition and recognized over the requisite service period using the straight-line method. Estimates used in the Monte Carlo valuation model are considered highly-complex and subjective. The number of shares of common stock issuable upon vesting ranges from zero to 200% of the number of PSUs granted based on the Company’s total shareholder return (“TSR”). Share-based compensation related to PSUs with a market condition are recognized as the requisite service period is fulfilled, even if the market condition is not achieved.

PSUs with Performance Based Conditions — Share-based compensation is based on the market price of the Company’s common stock on the grant date and recognized over the requisite service period using the straight-line method for awards with a performance condition. The Company recognizes compensation cost for awards with performance conditions if and when the Company concludes that it is probable that the performance condition will be achieved. The Company reassesses the probability of vesting at each reporting period for awards with performance conditions and adjusts compensation cost based on its probability assessment. The Company recognizes a cumulative catch-up adjustment for such changes in its probability assessment in subsequent reporting periods, using the grant date fair value of the award whose terms reflect the updated probable performance condition (which could be either a reversal or increase in expense). The number of shares of common stock issuable upon vesting ranges from zero to 200% of the number of PSUs granted based on a metric associated with the Company’s own operations or activities.

Revenue Recognition — Revenues are recorded based from the sale of oil, natural gas and NGL quantities sold to purchasers. The Company records revenues from the sale of oil, natural gas and NGLs based on quantities of production sold to purchasers under short-term contracts (less than twelve months) at market prices when delivery to the customer has occurred, title has transferred, prices are fixed and determinable and collection is reasonably assured. This occurs when production has been delivered to a pipeline or when a barge lifting has occurred. The Company recognizes transportation costs as a component of lease operating expense when it is the shipper of the product. Each unit of product typically represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Production Handling Fees — The Company presents certain reimbursements for costs from certain third parties as a reduction of “Lease operating expense” on the Consolidated Statements of Operations.

ONRR Federal Royalty Refund — Included within “Other operating (income) expense” on the Consolidated Statements of Operations is income from the Company’s multi-year federal royalty refund claim from the ONRR. The Company records income when a refund is filed and its collection is reasonably assured.

Income Taxes — The Company records current income taxes based on estimates of current taxable income and provides for deferred income taxes to reflect estimated future income tax payments and receipts. The impact to changes in tax laws are recorded in the period the change is enacted. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. The Company classifies all deferred tax assets and liabilities, along with any related valuation allowance, as long-term on the Consolidated Balance Sheets.

The realization of deferred tax assets depends on recognition of sufficient future taxable income during periods in which those temporary differences are deductible. The Company reduces deferred tax assets by a valuation allowance when, based on estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The deferred tax asset estimates are subject to revision, either up or down, in future periods based on new facts or circumstances. In evaluating the Company’s valuation allowances, the Company considers cumulative book losses, the reversal of existing temporary differences, the existence of taxable income in carryback years, tax planning strategies and future taxable income for each of its taxable jurisdictions, the latter two of which involve the exercise of significant judgment. Changes to the Company’s valuation allowances could materially impact its results of operations.

The Company’s policy is to classify interest and penalties associated with underpayment of income taxes as “Interest expense” and “General and administrative expense” on the Consolidated Statements of Operations, respectively.

Income (Loss) Per Share — Basic net income per common share (“EPS”) is computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted EPS includes the impact of RSUs, PSUs and outstanding warrants. See Note 12 — Income (Loss) Per Share for additional information.

Fair Value Measure of Financial Instruments — Financial instruments generally consist of cash and cash equivalents, accounts receivable, commodity derivatives, accounts payable and debt. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to the highly liquid nature of these instruments.

F-14

Current fair value accounting standards define fair value, establish a consistent framework for measuring fair value and stipulate the related disclosure requirements for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis. These standards also clarify fair value is an exit price, presenting the amount that would be received to sell an asset or paid to transfer a liability, in an orderly transaction between market participants. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value depending on the degree to which they are observable as follows:

•Level 1 – Inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

•Level 2 – Inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial statement.

•Level 3 – Inputs to the valuation methodology are unobservable (little or no market data), which require the reporting entity to develop its own assumptions and are significant to the fair value measurement.

Assets and liabilities measured at fair value are based on one or more of three valuation techniques. The valuation techniques are as follows:

•Market Approach – Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.

•Cost Approach – Amount that would be required to replace the service capacity of an asset (replacement cost).

•Income Approach – Techniques to convert expected future cash flows to a single present value amount based on market expectations (including present value techniques, option-pricing and excess earnings models).

Authoritative guidance on financial instruments requires certain fair value disclosures to be presented. The estimated fair value amounts have been determined using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

Variable Interest Entities — Upon inception of a contractual agreement, the Parent Company performs an assessment to determine whether the arrangement contains a variable interest in a legal entity and whether that legal entity is a variable interest Entity (“VIE”). The Parent Company assesses all aspects of its interests in an entity and uses judgment when determining if it is the primary beneficiary. The primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. Other qualitative factors that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. A reassessment of the primary beneficiary conclusion is conducted when there are changes in the facts and circumstances related to a VIE. See Note 7 — Equity Method Investments for additional information.

Concentration of Credit Risk

Consisting principally of cash and cash equivalents, accounts receivable and commodity derivatives, the Company is subject to concentrated financial instruments credit risk.

Cash and cash equivalents balances are maintained in financial institutions, which at times, exceed federally insured limits. The Company monitors the financial condition of these institutions and has not experienced losses on these accounts.

Commodity derivatives are entered into with registered swap dealers, all of which participate in the Company’s senior reserve-based revolving credit facility (the “Bank Credit Facility”). The Company monitors the financial condition of these institutions and has not experienced losses due to counterparty default on these instruments.

The Company markets the majority of its oil and natural gas production, and substantially all of its revenues are attributable to the U.S. The majority of the Company’s oil, natural gas and NGL production is sold to customers under short-term (less than 12 months) contracts at market-based prices. The Company’s customers consist primarily of major oil and natural gas companies, well-established oil and pipeline companies and independent oil and gas producers and suppliers. The Company performs ongoing credit evaluations of its customers and provide allowances for probable credit losses when necessary.

F-15

The percent of consolidated revenue of major customers, those whose total represented 10% or more of the Company’s oil, natural gas and NGL revenues, was as follows:

	Year Ended December 31,
	2023			2022			2021
Shell Trading (US) Company		54	%		44	%		45	%
Valero Energy Corporation		21	%		23	%	**
Chevron Products Company	**				11	%		29	%

** Less than 10%

The loss of a major customer could have material adverse effect on the Company in the short term. However, the Company believes it would be able to obtain other customers to market its oil, natural gas and NGL production.

Cash, Cash Equivalents and Restricted Cash

The following table provides a reconciliation of the amount of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheets to the total of the same such amounts shown in the Consolidated Statement of Cash Flows (in thousands):

	Year Ended December 31,
	2023		2022
Cash and cash equivalents	$	33,637	$	44,145
Restricted cash included in Other long-term assets		102,362		—
Total cash, cash equivalent and restricted cash	$	135,999	$	44,145

Note 3 — Acquisitions and Divestitures

Business Combinations

Acquisitions qualifying as business combinations are accounted for under the acquisition method of accounting, which requires, among other items, that assets acquired and liabilities assumed be recognized on the Consolidated Balance Sheets at their fair values as of the acquisition date.

EnVen Acquisition — On September 21, 2022, the Company executed a merger agreement to acquire EnVen Energy Corporation (“EnVen”), a private operator in the Deepwater U.S. Gulf of Mexico (the “EnVen Acquisition,” and such agreement, the “EnVen Merger Agreement”). On February 13, 2023, the Company completed the EnVen Acquisition for consideration consisting of (i) $207.3 million in cash, (ii) 43.8 million shares of the Company’s common stock valued at $832.2 million and (iii) the effective settlement of an accounts receivable balance of $8.4 million. No gain or loss was recognized on settlement as the payable was effectively settled at the recorded amount. The cash payment was partially funded with borrowings under the Bank Credit Facility.

The following table summarizes the purchase price (in thousands except share and per share data):

Talos common stock		43,799,890
Talos common stock price per share(1)	$	19.00
Common stock value	$	832,198
Cash consideration	$	207,313
Settlement of preexisting relationship	$	8,388
Total purchase price	$	1,047,899

(1)Represents the closing price of the Company’s common stock on February 13, 2023, the date of the closing of the EnVen Acquisition.

F-16

The following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed based on their fair values on February 13, 2023 (in thousands):

Current assets	$	243,571
Property and equipment		1,455,347
Other long-term assets:
Restricted cash		100,753
Notes receivable, net		14,844
Other long-term assets		48,899
Current liabilities:
Current portion of long-term debt		(33,234	)
Current portion of asset retirement obligations		(7,079	)
Other current liabilities		(124,347	)
Long-term liabilities:
Long-term debt		(233,836	)
Asset retirement obligations		(251,779	)
Deferred tax liabilities		(150,264	)
Other long-term liabilities		(14,976	)
Allocated purchase price	$	1,047,899

The fair values determined for accounts receivable, accounts payable and other current assets and most current liabilities were equivalent to the carrying value due to their short-term nature. Assumed debt was valued based on observable market prices.

The fair value of proved oil and natural gas properties as of the acquisition date is based on estimated proved oil, natural gas and NGL reserves and related discounted future net cash flows incorporating market participant assumptions. Significant inputs to the valuation include estimates of future production volumes, future operating and development costs, future commodity prices, and a weighted average cost of capital discount rate. When estimating the fair value of proved and unproved properties, additional risk adjustments were applied to proved developed non-producing, proved undeveloped, probable and possible reserves to reflect the relative uncertainty of each reserve class. These inputs are classified as Level 3 unobservable inputs, including the underlying commodity price assumptions which are based on the five-year NYMEX forward strip prices, escalated for inflation thereafter, and adjusted for price differentials.

The fair value of asset retirement obligations is determined by calculating the present value of estimated future cash flows related to the liabilities. The Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate.

The Company incurred approximately $21.8 million of acquisition-related costs in connection with the EnVen Acquisition exclusive of severance expense, of which $12.8 million was recognized during the year ended December 31, 2023 and $9.0 million was recognized during the year ended December 31, 2022 and reflected in general and administrative expense on the Consolidated Statements of Operations. Additionally, the Company incurred $25.3 million in severance expense in connection with the EnVen Acquisition for the year ended December 31, 2023. See Note 10 — Employee Benefit Plans and Share-Based Compensation for additional discussion.

The following table presents revenue and net income (loss) attributable to the EnVen Acquisition for the period from February 13, 2023 to December 31, 2023 (in thousands):

	Year Ended December 31, 2023
Revenue	$	423,624
Net income (loss)	$	85,622

F-17

Pro Forma Financial Information (Unaudited) — The following supplemental pro forma financial information (in thousands, except per common share amounts), presents the consolidated results of operations for the years ended December 31, 2023 and 2022 as if the EnVen Acquisition had occurred on January 1, 2022. The unaudited pro forma information was derived from historical statements of operations of the Company and EnVen adjusted to include (i) depletion expense applied to the adjusted basis of the oil and natural gas properties acquired, (ii) interest expense to reflect borrowings under the Bank Credit Facility and to adjust the amortization of the premium of the 11.75% Notes (as defined in Note 8 — Debt), (iii) general and administrative expense adjusted for transaction related costs incurred (including severance), (iv) other income (expense) to adjust the accretion of the discount on the P&A Notes Receivable and (v) weighted average basic and diluted shares of common stock outstanding from the issuance of 43.8 million shares of common stock to EnVen. Supplemental pro forma earnings for the year ended December 31, 2022 were adjusted to include $65.1 million of general and administrative expenses, of which $16.3 million were incurred during the year ended December 31, 2022. Supplemental pro forma earnings for the year ended December 31, 2023 were adjusted to exclude $65.1 million of general and administrative expenses. This information does not purport to be indicative of results of operations that would have occurred had the EnVen Acquisition occurred on January 1, 2022, nor is such information indicative of any expected future results of operations (in thousands, except for the per share data).

	Year Ended December 31,
	2023		2022
Revenue	$	1,509,929	$	2,355,215
Net income (loss)	$	217,537	$	425,995
Basic net income (loss) per common share	$	1.74	$	3.37
Diluted net income (loss) per common share	$	1.73	$	3.34

Subsequent Event

QuarterNorth Acquisition — On January 13, 2024, the Company executed a merger agreement to acquire QuarterNorth Energy Inc. (“QuarterNorth,” and such acquisition, the “QuarterNorth Acquisition”), a privately-held U.S. Gulf of Mexico exploration and production company. The QuarterNorth Acquisition is expected to close during the first quarter of 2024. Consideration for the QuarterNorth Acquisition primarily consists of (i) approximately $964.9 million in cash, (ii) the amount of net unrestricted cash of QuarterNorth as of December 31, 2023 and (iii) 24.8 million shares of the Company’s common stock.

Divestiture

Mexico Divestiture — On September 27, 2023, the Company closed the sale of a 49.9% equity interest in its subsidiary, Talos Energy Mexico 7, S. de R.L. de C.V. (“Talos Mexico”) to Zamajal, S.A. de C.V., a wholly owned subsidiary of Grupo Carso, for $74.9 million in cash consideration with an additional $49.9 million contingent on first oil production from the Zama Field (the “Mexico Divestiture”). The contingent consideration will be recognized when regular commercial production from the Zama Field becomes probable. Talos Mexico, through its wholly owned subsidiary, holds a 17.4% unitized interest in the Zama Field.

As a result of the Mexico Divestiture, Talos Mexico was deconsolidated on September 27, 2023 and is now accounted for as an equity method investment. Total assets derecognized included $112.3 million of unproved properties associated with exploration and appraisal activities in Block 7 located in the shallow waters off the coast of Mexico’s Tabasco state. The fair value of the Company’s retained equity method investment in Talos Mexico was $107.6 million. The determination of fair value was based on the implied fair value of Talos Mexico. The implied fair value of Talos Mexico was based on the transaction price of the Mexico Divestiture, which was an orderly transaction between market participants. A gain of $66.2 million was recognized on the Mexico Divestiture during the year ended December 31, 2023 which is included in “Other operating (income) expense” on the Consolidated Statements of Operations.

Note 4 — Property, Plant and Equipment

Proved Properties

The Company’s interests in oil and natural gas proved properties are located in the United States, primarily in the Gulf of Mexico deep and shallow waters. During 2023, 2022 and 2021, the Company’s ceiling test computations did not result in a write-down of its U.S. oil and natural gas properties. At December 31, 2023, its ceiling test computation was based on SEC pricing of $78.56 per Bbl of oil, $2.75 per Mcf of natural gas and $18.77 per Bbl of NGLs.

Unproved Properties

Unproved capitalized costs of oil and natural gas properties excluded from amortization relate to unevaluated properties associated with acquisitions, leases awarded in the U.S. Gulf of Mexico federal lease sales, certain geological and geophysical costs, expenditures associated with certain exploratory wells in progress and capitalized interest.

F-18

During the year ended December 31, 2023, the Company derecognized $112.3 million of unproved properties associated with the exploration and appraisal activities in Block 7 located in the shallow waters off the coast of Mexico’s Tabasco state. See Note 3 — Acquisitions and Divestitures for additional discussion.

During the year ended December 31, 2021, the Company’s evaluation of unproved property located offshore Mexico resulted in a non-cash impairment of $18.1 million presented as “Write-down of oil and natural gas properties” on the Consolidated Statements of Operations. The non-cash impairment was primarily attributable to the Company’s operations in offshore Mexico in Block 31 associated with the Company’s non-consent of the proposed appraisal plan during the fourth quarter of 2021.

The following table sets forth a summary of the Company’s oil and natural gas property costs not being amortized at December 31, 2023, by the year in which such costs were incurred (in thousands):

			Year Ended December 31,
	Total		2023		2022		2021		2020 and Prior
Acquisition United States	$	249,799	$	229,216	$	—	$	—	$	20,583
Exploration United States		18,516		10,108		1,299		2,295		4,814
Total unproved properties, not subject to amortization	$	268,315	$	239,324	$	1,299	$	2,295	$	25,397

The excluded costs will be included in the amortization base as properties are evaluated and proved reserves are established or impairment is determined. The unproved costs will be excluded from the amortization base until the Company has made a determination as to the existence of proved reserves. The Company currently estimates these costs will be transferred to the amortization base over eight years.

Note 5 — Leases

The Company has operating leases principally for office space, drilling rigs, compressors and other equipment necessary to support the Company’s operations. Additionally, the Company has a finance lease related to the use of the Helix Producer I (the “HP-I”), a dynamically positioned floating production facility that interconnects with the Phoenix Field through a production buoy. The HP-I is utilized in the Company’s oil and natural gas development activities and the ROU asset was capitalized and included in proved property and depleted as part of the full cost pool. Once items are included in the full cost pool, they are indistinguishable from other proved properties. The capitalized costs within the full cost pool are amortized over the life of the total proved reserves using the unit-of-production method, computed quarterly. Costs associated with the Company’s leases are either expensed or capitalized depending on how the underlying asset is utilized.

In November 2022, the Company exercised its option to extend the lease of the HP-I through June 1, 2024. The extension resulted in a remeasurement of the lease liability to $166.3 million and corresponding adjustment to proved property.

The lease costs described below are presented on a gross basis and do not represent the Company’s net proportionate share of such amounts. A portion of these costs have been or may be billed to other working interest owners. The Company’s share of these costs is included in property and equipment, lease operating expense or general and administrative expense, as applicable. The components of lease costs were as follows (in thousands):

	Year Ended December 31,
	2023			2022		2021
Finance lease cost - interest on lease liabilities	$	14,476		$	7,558	$	11,453
Operating lease cost, excluding short-term leases(1)		4,883			2,281		2,706
Short-term lease cost(2)		117,132			55,072		38,472
Variable lease cost(3)		2,888			1,450		1,356
Variable and fixed sublease income		(482	)		—		—
Total lease cost	$	138,897		$	66,361	$	53,987

(1)Operating lease cost reflect a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis.

(2)Short-term lease costs are reported at gross amounts and primarily represent costs incurred for drilling rigs, most of which are short-term contracts not recognized as a ROU asset and lease liability on the Consolidated Balance Sheets.

(3)Variable lease costs primarily represent differences between minimum payment obligations and actual operating charges incurred by the Company related to its long-term leases.

F-19

The present value of the fixed lease payments recorded as the Company’s ROU asset and liability, adjusted for initial direct costs and incentives were as follows (in thousands):

	Year Ended December 31,
	2023		2022
Operating leases:
Operating lease assets	$	11,418	$	5,903
Current portion of operating lease liabilities	$	2,666	$	1,943
Operating lease liabilities		18,211		14,855
Total operating lease liabilities	$	20,877	$	16,798
Finance leases:
Proved properties	$	166,261	$	166,261
Other current liabilities	$	17,834	$	16,306
Other long-term liabilities		131,230		149,064
Total finance lease liabilities	$	149,064	$	165,370

The table below presents the lease maturity by year as of December 31, 2023 (in thousands). Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the Consolidated Balance Sheets.

	Operating Leases			Finance Leases
2024	$	4,748		$	30,782
2025		4,716			30,782
2026		4,803			30,782
2027		4,708			30,782
2028		4,610			30,782
Thereafter		4,584			43,608
Total lease payments	$	28,169		$	197,518
Imputed interest		(7,292	)		(48,454	)
Total lease liabilities	$	20,877		$	149,064

The table below presents the weighted average remaining lease term and discount rate related to leases:

	Year Ended December 31,
	2023			2022			2021
Weighted average remaining lease term:
Operating leases	5.9 years			6.4 years			7.4 years
Finance leases	6.4 years			7.4 years			1.4 years
Weighted average discount rate:
Operating leases		10.8	%		11.8	%		11.9	%
Finance leases		9.2	%		9.2	%		21.9	%

The table below presents the supplemental cash flow information related to leases (in thousands):

	Year Ended December 31,
	2023			2022		2021
Operating cash outflow from finance leases	$	14,476		$	7,181	$	11,453
Operating cash outflow from operating leases	$	6,318		$	3,722	$	3,864
ROU assets obtained in exchange for new finance lease liabilities	$	—		$	166,261	$	—
ROU assets obtained in exchange for new operating lease liabilities(1)	$	12,971		$	474	$	1,020
Remeasurement of lease liability arising from modification of ROU asset(2)	$	(5,124	)	$	—	$	—

(1)See EnVen Acquisition in Note 3 — Acquisitions and Divestitures.

(2)Lease termination accounted for as a lease modification based on the modified lease term. The termination did not take effect contemporaneously with the effective date of the modification.

F-20

Note 6 — Financial Instruments

As of December 31, 2023 and 2022, the carrying amounts of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximate their fair values because they are highly liquid or due to the short-term nature of these instruments.

Debt Instruments

The following table presents the carrying amounts, net of discount and deferred financing costs, and estimated fair values of the Company’s debt instruments (in thousands):

	December 31, 2023				December 31, 2022
	Carrying Amount		Fair Value		Carrying Amount			Fair Value
12.00% Second-Priority Senior Secured Notes – due January 2026	$	601,353	$	655,130	$	590,132		$	674,542
11.75% Senior Secured Second Lien Notes – due April 2026	$	234,221	$	233,410	$	—		$	—
Bank Credit Facility – matures March 2027	$	190,100	$	200,000	$	(4,792	)	$	—

The carrying value of the senior notes are adjusted for discount, premium and deferred financing costs. Fair value is estimated (representing a Level 1 fair value measurement) using quoted secondary market trading prices and, where such prices are not available, other observable (Level 2) inputs are used such as quoted prices for similar liabilities in the active markets.

The carrying amount of the Company’s bank credit facility, as amended and restated (the “Bank Credit Facility”), is presented net of deferred financing costs. The fair value of the Bank Credit Facility is estimated based on the outstanding borrowings under the Bank Credit Facility since it is secured by the Company’s reserves and the interest rates are variable and reflective of market rates (representing a Level 2 fair value measurement).

Oil and Natural Gas Derivatives

The Company attempts to mitigate a portion of its commodity price risk and stabilize cash flows associated with sales of oil and natural gas production. The Company is currently utilizing oil and natural gas swaps and costless collars. Swaps are contracts where the Company either receives or pays depending on whether the oil or natural gas floating market price is above or below the contracted fixed price. Costless collars consist of a purchased put option and a sold call option with no net premiums paid to or received from counterparties. Typical collar contracts require payments by the Company if the NYMEX average closing price is above the ceiling price or payments to the Company if the NYMEX average closing price is below the floor price.

In connection with the EnVen Acquisition, the Company assumed oil and natural gas collar contracts that combine a two-way collar with a short put that holds an exercise price below the floor price (“three-way collar”). In these contracts, when the NYMEX average closing price is below the floor price, the Company receives the difference between the NYMEX average closing price and the floor price, capped at the difference between the floor price and the short put price.

The following table presents the impact that derivatives, not designated as hedging instruments, had on its Consolidated Statements of Operations (in thousands):

	Year Ended December 31,
	2023			2022			2021
Net cash received (paid) on settled derivative instruments	$	(9,457	)	$	(425,559	)	$	(290,164	)
Unrealized gain (loss)(1)		90,385			153,368			(128,913	)
Price risk management activities income (expense)	$	80,928		$	(272,191	)	$	(419,077	)

(1)Includes $1.4 million gain from the unrealized derivative instruments acquired from the EnVen Acquisition for the year ended December 31, 2023.

The following tables reflect the contracted average daily volumes and weighted average prices under the terms of the Company's derivative contracts as of December 31, 2023:

Swap Contracts
Production Period	Settlement Index	Volumes		Swap Price
Crude oil:		(Bbls)		(per Bbl)
January 2024 – December 2024	NYMEX WTI CMA		16,859	$	74.30
January 2025 – December 2025	NYMEX WTI CMA		7,734	$	73.80
Natural gas:		(MMBtu)		(per MMBtu)
January 2024 – December 2024	NYMEX Henry Hub		18,716	$	3.41
January 2025 – December 2025	NYMEX Henry Hub		13,712	$	3.92

F-21

Two-Way Collar Contracts
Production Period	Settlement Index	Volumes		Floor Price		Ceiling Price
Crude oil:		(Bbls)		(per Bbl)		(per Bbl)
January 2024 – December 2024	NYMEX WTI CMA		1,497	$	70.00	$	79.32
Natural gas:		(MMBtu)		(per MMBtu)		(per MMBtu)
January 2024 – December 2024	NYMEX Henry Hub		10,000	$	4.00	$	6.90

Three-Way Collar Contracts
Production Period	Settlement Index	Volumes		Short Put Price		Floor Price		Ceiling Price
Crude oil:		(Bbls)		(per Bbl)		(per Bbl)		(per Bbl)
January 2024 – March 2024	NYMEX WTI CMA		3,200	$	57.27	$	70.00	$	98.01

The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands):

	December 31, 2023
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas derivatives	$	—	$	53,703		$	—	$	53,703
Liabilities:
Oil and natural gas derivatives		—		(8,100	)		—		(8,100	)
Total net asset (liability)	$	—	$	45,603		$	—	$	45,603

	December 31, 2022
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas derivatives	$	—	$	32,883		$	—	$	32,883
Liabilities:
Oil and natural gas derivatives		—		(76,242	)		—		(76,242	)
Total net asset (liability)	$	—	$	(43,359	)	$	—	$	(43,359	)

Financial Statement Presentation

Derivatives are classified as either current or non-current assets or liabilities based on their anticipated settlement dates. Although the Company has master netting arrangements with its counterparties, the Company presents its derivative financial instruments on a gross basis in its Consolidated Balance Sheets. The following table presents the fair value of derivative financial instruments as well as the potential effect of netting arrangements on the Company's recognized derivative asset and liability amounts (in thousands):

	December 31, 2023				December 31, 2022
	Assets		Liabilities		Assets		Liabilities
Oil and natural gas derivatives:
Current	$	36,152	$	7,305	$	25,029	$	68,370
Non-current		17,551		795		7,854		7,872
Total gross amounts presented on balance sheet		53,703		8,100		32,883		76,242
Less: Gross amounts not offset on the balance sheet		8,100		8,100		32,883		32,883
Net amounts	$	45,603	$	—	$	—	$	43,359

Credit Risk

The Company is subject to the risk of loss on its financial instruments as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. The Company has entered into International Swaps and Derivative Association agreements with counterparties to mitigate this risk. The Company also maintains credit policies with regard to its counterparties to minimize overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the regular monitoring of counterparties’ credit exposures; (iii) the use of contract language that affords the Company netting or set off opportunities to mitigate exposure risk; and (iv) potentially requiring counterparties to post cash collateral, parent guarantees, or letters of credit to minimize credit risk. The Company’s assets and liabilities from commodity price risk management activities at December 31, 2023 represent derivative instruments from nine counterparties; all of which are registered swap dealers that have an “investment grade” (minimum Standard & Poor’s rating of BBB- or better) credit rating, and eight of which are parties under the Company’s Bank Credit Facility. The Company enters into derivatives directly with these counterparties and, subject to the terms of the Company’s Bank Credit Facility, is not required to post collateral or other securities for credit risk in relation to the derivative activities. Had the Company’s counterparties failed to perform under existing commodity derivative contracts the maximum loss at December 31, 2023 would have been $45.6 million.

F-22

Note 7 — Equity Method Investments

The following table presents the Company’s investments in unconsolidated affiliates by segment for the periods indicated below. The Company accounts for these investments using the equity method of accounting.

	Ownership Interest at			Year Ended December 31,
	December 31, 2023			2023		2022
Upstream:
Talos Energy Mexico 7, S. de R.L. de C.V		50.1	%	$	107,259	$	—
SP 49 Pipeline LLC		33.3	%		861		374
CCS:
Bayou Bend CCS LLC		25.0	%		28,183		1,371
Harvest Bend CCS LLC		65.0	%		9,746		—
Coastal Bend CCS LLC		50.0	%		—		—
Total Equity Method Investments				$	146,049	$	1,745

Talos Energy Mexico 7, S. de R.L. de C.V.

See Note 3 – Acquisitions and Divestitures for additional information on the deconsolidation of Talos Mexico. There is $66.0 million positive basis difference related to this investment, which will be amortized on a units of production method once regular commercial production from the Zama Field commences.

Bayou Bend CCS LLC

On March 8, 2022, the Company made a $2.3 million cash contribution for a 50% membership interest in Bayou Bend CCS LLC (“Bayou Bend”). Bayou Bend has a CCS site that is in the early stages of development located offshore Jefferson County, Texas, near the Beaumont and Port Arthur, Texas industrial corridor. In May 2022, the Company sold a 25% membership interest to Chevron U.S.A. Inc. (“Chevron”) for upfront cash consideration of $15.0 million. The Company recognized a $13.9 million gain on the partial sale of its investment in Bayou Bend during the year ended December 31, 2022, which is included in “Equity method investment income (expense)” on the Consolidated Statement of Operations. Chevron also agreed to fund up to $10.0 million of contributions to Bayou Bend on the Company’s behalf, which was fully funded by the first quarter of 2023. The Bayou Bend investment was increased with an offsetting gain as the capital carry was funded by Chevron. The Company recognized an $8.6 million and $1.4 million gain during the years ended December 31, 2023 and 2022, respectively, on the funding of the capital carry of its investment in Bayou Bend. This gain is included in “Equity method investment income (expense)” on the Consolidated Statements of Operations.

Effective March 1, 2023, Chevron became the operator of Bayou Bend. During March 2023, Bayou Bend expanded its storage footprint through the acquisition of onshore acreage in Chambers and Jefferson Counties, Texas located within the Houston Ship Channel, Beaumont and Port Arthur region.

VIE Disclosures

VIE and Primary Beneficiary Determination — Talos Mexico, Bayou Bend, Harvest Bend CCS LLC (“Harvest Bend”), and Coastal Bend CCS LLC (“Coastal Bend”) were each determined to be a VIE. Neither Talos Mexico, Bayou Bend, Harvest Bend, nor Coastal Bend had sufficient equity at risk to finance their respective activities without additional subordinated financial support. The Company is not the primary beneficiary of these VIE’s due to the governance structure of these entities. The most significant activities of these entities are jointly controlled by the owners. The level of the Company’s economic interest in Harvest Bend is not indicative of the amount of power held.

Financings — All of the Company’s VIE’s have historically been funded through equity contributions from owners.

Maximum Exposure — The Company’s maximum exposure to loss as result of its involvement with VIE’s is the carrying amount of each investment.

Nature of Risks — Talos Mexico holds a working interest in the unitized Zama Field. In March 2023, Petróleos Mexicanos submitted the Zama Unit Development Plan (“UDP”) to Mexico’s governmental agency for approval and the UDP received approved in June 2023. An Integrated Project Team (“IPT”) was formed in March 2023 to pool the talents and competencies of all companies participating in the development of the Zama Field. The IPT reports to the Zama Unit Operating Committee, which includes representatives from each of the participating companies. Final Investment Decision (“FID”) is expected following completion and final review of the front-end engineering and design (“FEED”), project financing and final approvals. Achieving FID is a crucial stage and marks the beginning of the engineering and construction stage, where project contractors proceed with procuring material and beginning the construction. Availability of equipment and unexpected construction hurdles could delay the start of oil and gas production. Even though an IPT exists, teamwork could remain a challenge. There is also a risk that the project will not be completed within the budget and timeline, which ultimately could have an adverse impact on the net present value of the project.

F-23

The successful development of our CCS projects is dependent on various economic, regulatory, operational and technical factors. The failure to satisfy, wholly or in a significant measure, any of such factors could have a material adverse impact on the Company’s business, results of operations and financial condition. For example, successful development of CCS projects in the United States requires compliance with stringent and varied regulatory schemes including obtaining Class VI well permits that are applicable to subsurface injection of CO2 for geologic sequestration. Locating a suitable source of anthropogenic CO2 and reaching suitable agreements to capture that CO2 is crucial. Infrastructure to transport CO2 between the source and CCS project sites is also required. In project areas with existing CO2 transportation pipelines, reaching an agreement on CO2 transportation with operators of such pipelines will be necessary. Inability to reach a suitable agreement may render a project uneconomic or impracticable. Separately, if no CO2 pipelines exist in proposed project areas, or if existing pipelines do not extend to one or more of the Company’s project sites, conversion of existing pipelines or construction of new pipelines or lateral connections will be required, which may render one or more projects uneconomic. Given the capital-intensive nature of CCS projects, project finance plays a critical role in accelerating the development of the Company’s projects. If the Company is unable to obtain acceptable financing for its CCS projects, then it could result in significant delays in the development and construction of such projects. Lastly, the development of CCS projects is incentivized by tax credits provided under Section 45Q of the Internal Revenue Code of 1986, as amended. The Company’s inability to benefit from such tax credits could prevent the development of the Company’s projects.

Note 8 — Debt

A summary of the detail comprising the Company’s debt and the related book values for the respective periods presented is as follows (in thousands):

	Year Ended December 31,
	2023			2022
12.00% Second-Priority Senior Secured Notes – due January 2026	$	638,541		$	638,541
11.75% Senior Secured Second Lien Notes – due April 2026		227,500			—
Bank Credit Facility – matures March 2027		200,000			—
Total debt, before discount, premium and deferred financing cost		1,066,041			638,541
Unamortized discount, premium and deferred financing cost, net		(40,367	)		(53,201	)
Total debt		1,025,674			585,340
Less: Current portion of long-term debt		33,060			—
Long-term debt	$	992,614		$	585,340

12.00% Second-Priority Senior Secured Notes

The 12.00% Second-Priority Senior Secured Notes due 2026 (the “12.00% Notes”) were issued pursuant to an indenture dated January 4, 2021 and the first supplemental indenture dated January 14, 2021 between the Parent Company (the “Parent Guarantor”), Talos Production Inc. (the “Issuer”), and certain of the Issuer's subsidiaries (the “Subsidiary Guarantors” and, together with the Parent Guarantor, the “Guarantors”) and Wilmington Trust, National Association, as trustee and collateral agent. The 12.00% Notes rank pari passu in right of payment and constitute a single class of securities for all purposes under the indentures. The 12.00% Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by the Parent Guarantor and on a second-priority senior secured basis by each of the Subsidiary Guarantors and will be unconditionally guaranteed on the same basis by certain of the Issuer’s future subsidiaries. The 12.00% Notes are secured on a second-priority basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 12.00% Notes mature January 15, 2026 and have interest payable semi-annually each January 15 and July 15.

The Company may redeem all or a portion of the 12.00% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest if redeemed during the period commencing on January 15 of the years set forth below:

Period	Redemption Price
2023		106.000	%
2024		103.000	%
2025 and thereafter		100.000	%

The indenture governing the 12.00% Notes applies certain limitations on the Company’s ability and the ability of its subsidiaries to, among other things, (i) incur, assume or guarantee additional indebtedness or issue certain convertible or redeemable equity securities; (ii) create liens to secure indebtedness; (iii) pay distributions on equity interests, repurchase equity securities or redeem junior lien, unsecured or subordinated indebtedness; (iv) make investments; (v) restrict distributions, loans or other asset transfers from Talos Production Inc.’s restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of Talos Production Inc.’s properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiliates. The 12.00% Notes contain customary quarterly and annual reporting, financial and administrative covenants. The Company was in compliance with all debt covenants at December 31, 2023.

F-24

The Issuer initiated a notes consent solicitation on October 21, 2022, to obtain the requisite holders’ consent to certain amendments to the indenture governing the Issuer’s 12.00% Notes to permit the incurrence of indebtedness in respect of the 11.75% Senior Secured Second Lien Notes due 2026 of EnVen (the “Notes Consent Solicitation”). The Notes Consent Solicitation expired on October 27, 2022, with holders of 95.8% of the aggregate principal amount of the 12.00% Notes outstanding consenting. As a result, the Issuer entered into a second supplemental indenture to the base indenture on October 27, 2022, which became effective upon its execution. The Issuer offered holders of the 12.00% Notes consideration equal to 50 basis points times the principal amount of the 12.00% Notes held by such consenting holder (“Consent Fee”). On February 13, 2023, the Issuer paid the Consent Fee of approximately $3.1 million in the aggregate in connection with the EnVen Acquisition.

During the year ended December 31, 2022, the Company repurchased $11.5 million of the 12.00% Notes. The debt repurchases resulted in a loss on extinguishment of debt for the year ended December 31, 2022 of $1.6 million, which is presented as “Other income (expense)” on the Consolidated Statements of Operations.

Subsequent Event — On January 23, 2024, the Company issued a conditional notice to redeem in full the 12.00% Notes at a redemption price of 103.00% of the principal amount thereof, plus accrued and unpaid interest to, but excluding, the redemption date, in accordance with the 12.00% Notes indenture. The 12.00% Notes were redeemed on February 7, 2024 for $662.4 million utilizing the net proceeds from the Debt Offering (as defined below).

11.75% Senior Secured Second Lien Notes

On February 13, 2023, in conjunction with the closing of the EnVen Acquisition, the Company assumed EnVen’s 11.75% Senior Secured Second Lien Notes due 2026 (the “11.75% Notes”) with a principal amount of $257.5 million. The 11.75% Notes mature on April 15, 2026 and interest accrues and is to be paid semi-annually in cash in arrears on April 15th and October 15th of each year. The indenture governing the 11.75% Notes requires the redemption of $15.0 million of the principal amount outstanding at par value on April 15th and October 15th of each year.

The Company may redeem all or a portion of the 11.75% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest if redeemed during the period commencing on February 15 of the years set forth below:

Period	Redemption Price
2023		105.875	%
2024		102.938	%
2025 and thereafter		100.000	%

The 11.75% Notes are governed by an indenture by and among Energy Ventures GoM LLC, EnVen Finance Corporation as co-issuers, the guarantors party thereto and Wilmington Trust, National Association as trustee and collateral agent, dated as of April 15, 2021 (“11.75% Notes Indenture”). Talos Production Inc. and certain of its subsidiaries entered into a supplemental indenture to the 11.75% Notes Indenture which, inter alia, provides for the assumption of the indebtedness in respect of the 11.75% Notes by Talos Production Inc., as well as guarantees of such indebtedness by certain subsidiaries of Talos Production Inc., as contemplated by the terms of the 11.75% Notes Indenture.

The 11.75% Notes Indenture 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 Talos Production Inc. subsidiaries’ ability to pay dividends, create liens, and sell certain assets.

Subsequent Event — On January 26, 2024, the Company issued a conditional notice to redeem in full the 11.75% Notes at a redemption price of 102.938% of the principal amount thereof, plus accrued and unpaid interest to, but excluding, the redemption date, in accordance with the 11.75% Notes Indenture. The Company irrevocably deposited funds with the trustee sufficient to satisfy and discharge the 11.75% Notes Indenture and the 11.75% Notes until redeemed on April 15, 2024 with the funds deposited with the trustee and elected to satisfy and discharge the 11.75% Notes Indenture in accordance with its terms and the 11.75% Notes trustee acknowledged such discharge and satisfaction. The Company deposited $247.5 million with the trustee on February 7, 2024 utilizing the net proceeds from the Debt Offering.

11.00% Second-Priority Senior Secured Notes

On January 13, 2021, the Company redeemed $347.3 million aggregate principal amount of the 11.00% Second-Priority Senior Secured Notes due 2022 (the “11.00% Notes”) at 102.75% plus accrued and unpaid interest using the proceeds from the issuance of the 12.00% Notes. The debt redemption resulted in a loss on extinguishment of debt of $13.2 million for the year ended December 31, 2021, which is included in “Other income (expense)” on the Consolidated Statements of Operations.

F-25

7.50% Senior Notes

The 7.50% Senior Notes due 2022 matured on May 31, 2022 and were redeemed at an aggregate principal of $6.1 million plus accrued and unpaid interest.

Bank Credit Facility

The Company maintains a Bank Credit Facility with a syndicate of financial institutions. The Bank Credit Facility provides for the determination of the borrowing base based on the Company’s proved producing reserves and a portion of the Company's proved undeveloped reserves. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter of each year. On December 23, 2022, the Company entered into the Incremental Agreement and Ninth Amendment to Credit Agreement (the “Ninth Amendment”). The Ninth Amendment, among other things, (i) extended the maturity date of the Bank Credit Facility from November 12, 2024 to March 31, 2027, (ii) increased the borrowing base from $1.1 billion to $1.5 billion and (iii) increased commitments from $806.3 million to $965.0 million, in each case went into effect upon the closing of the EnVen Acquisition and the occurrence of certain events related thereto. On June 9, 2023, the borrowing base decreased from $1.5 billion to $1.1 billion and commitments were reaffirmed at $965.0 million as part of the biannual determination.

The Bank Credit Facility no longer bears interest at the applicable London InterBank Offered Rate plus the applicable margin. Interest under the Bank Credit Facility accrues at the Company’s option either at an alternate base rate (“ABR”) plus the applicable margin (“ABR Loans”), an adjusted term secured overnight financing rate (“SOFR”) plus the applicable margin (“Term Benchmark Loans”) or adjusted daily simple SOFR plus the applicable margin (“RFR Loans”). The ABR is based on the greater of (a) the prime rate, (b) a federal funds rate plus 0.5% or (c) the adjusted term SOFR for a one-month interest period plus 1.00%. The adjusted term SOFR is equal to the term SOFR for each applicable tenor (e.g., one-month, three-months, six-months, and twelve-months) calculated and published by the CME Group Inc. plus 0.10%. The adjusted daily simple SOFR is equal to the overnight SOFR calculated and published by the Federal Reserve Bank of New York plus 0.10%. In addition, the Company is obligated to pay a commitment fee on the unutilized portion of the commitments. The pricing grid below shows the applicable margin for Term Benchmark Loans, RFR Loans and ABR Loans as well as the commitment fee rate, in each case based upon the applicable borrowing base utilization percentage:

Borrowing Base Utilization Percentage	Utilization	Term Benchmark Loans and RFR Loans	ABR Loans	Commitment Fee Rate
Level 1	< 25%	2.75%	1.75%	0.38%
Level 2	≥ 25% < 50%	3.00%	2.00%	0.38%
Level 3	≥ 50% < 75%	3.25%	2.25%	0.50%
Level 4	≥ 75% < 90%	3.50%	2.50%	0.50%
Level 5	≥ 90%	3.75%	2.75%	0.50%

The Bank Credit Facility has certain debt covenants, the most restrictive of which is that the Company must maintain a Consolidated Total Debt to EBITDAX Ratio (as defined in the Bank Credit Facility) of no greater than 3.00 to 1.00 calculated each quarter utilizing the most recent twelve months to determine EBITDAX. The Company must also maintain a current ratio no less than 1.00 to 1.00 each quarter. Under the Bank Credit Facility, unutilized commitments are included in current assets in the current ratio calculation. The Bank Credit Facility is secured by, among other things, mortgages covering at least 85.0% of the oil and natural gas assets of the Company. The Bank Credit Facility is fully and unconditionally guaranteed by the Company and certain of its wholly-owned subsidiaries.

As of December 31, 2023, the Company's borrowing base was $1,075.0 million with total commitments of $965.0 million. Additionally, no more than $250.0 million of the Company’s borrowing base can be used as letters of credit with current commitments at $150.0 million. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Bank Credit Facility. The Company was in compliance with all debt covenants at December 31, 2023. As of December 31, 2023, the Company had outstanding borrowings at a weighted average interest rate of 8.26%. See Note 14 — Commitments and Contingencies for the amount of letters of credit issued under the Bank Credit Facility as of December 31, 2023.

Subsequent Event — On January 13, 2024, the Company entered into the Tenth Amendment to Credit Agreement (the “Tenth Amendment”). The Tenth Amendment, among other things, (i) permits the incurrence of additional indebtedness in order to fund the QuarterNorth Acquisition, with such indebtedness excluded from any reduction of the borrowing base that would otherwise result from such incurrence, and (ii) reaffirms the borrowing base at $1.1 billion effective upon closing of the QuarterNorth Acquisition.

F-26

Limitation on Restricted Payments Including Dividends

The Company has not historically declared or paid any cash dividends on its capital stock. However, to the extent the Company determines in the future that it may be appropriate to pay a special dividend or initiate a quarterly dividend program, the Company’s ability to pay any such dividends to its stockholders may be limited to the extent its consolidated subsidiaries are limited in their ability to make distributions to the Parent Company, including the significant restrictions that the agreements governing the Company’s debt impose on the ability of its consolidated subsidiaries to make distributions and other payments to the Parent Company. With respect to entities accounted for under the equity method, the Company’s primary equity method investee as of December 31, 2023 did not have any undistributed earnings.

The Bank Credit Facility contains restrictions on the ability of Talos Production Inc. to transfer funds to the Parent Company in the form of cash dividends, loans or advances. The Bank Credit Facility restricts distributions and other payments to the Parent Company, subject to certain baskets and other exceptions described therein including the payment of operating expense incurred in the ordinary course of business and for income taxes attributable to its ownership in Talos Production Inc. Under the Bank Credit Facility, general distributions and other restricted payments may be made to the Company so long as after giving pro forma effect to the making of any such restricted payment (i) no default or event of default has occurred and is continuing; (ii) available commitments exceed 25% of the then effective loan limit; (iii) the pro forma current ratio of 1.0 to 1.0 is satisfied; and (iv) either (A) the Consolidated Total Debt to EBITDAX Ratio (as defined in the Bank Credit Facility) is not greater than 1.75 to 1.00 and the aggregate amount of such restricted payments does not exceed the Available Free Cash Flow Amount (as defined in the Bank Credit Facility) at the time made or (B) the Consolidated Total Debt to EBITDAX Ratio is not greater than 1.00 to 1.00.

In addition, the indenture governing the 12.00% Notes restricts the Company’s consolidated subsidiaries from, directly or indirectly, among other things, declaring or paying any dividend on account of their equity securities, subject to certain limited exceptions described in the indenture. Such exceptions include, among other things, if (i) no default has occurred or would occur as a result thereof, (ii) immediately after giving effect to such transaction on a pro forma basis, the issuer could incur $1.00 of additional indebtedness in compliance with a fixed charge coverage ratio of 2.25 to 1.00, (iii) the ratio of the issuer’s total debt to EBITDA ratio is not greater than 3.00 to 1.00, and (iii) if payments pursuant to such transaction, together with the aggregate amount of certain other restricted payments, is less than the cumulative credit permitted under the indenture.

The indenture governing the 11.75% Notes contains a similar restriction on the Company and its consolidated subsidiaries’ ability to declare or pay dividends, subject to exceptions which include, among other things, (i) subject to no default or event of default having occurred or continuing, dividends in an aggregate amount not to exceed the greater of $25 million and 2.5% of Adjusted Consolidated Net Tangible Assets, (ii) dividends or distributions to any parent company to make payments, in lieu of issuing fractional shares in connection with share dividends, share splits, reverse share splits, mergers, consolidations, amalgamations or other business combinations and in connection with the exercise of warrants, options or other securities convertible into or exchangeable for equity interests of the Company.

At December 31, 2023, restricted net assets of the Company’s consolidated subsidiaries exceeded 25%.

Subsequent Event — Debt Offering

On February 7, 2024, the Company closed an upsized offering (the “Debt Offering”) for the sale of $1,250.0 million in aggregate principal amount of second-priority senior secured notes, consisting of $625.0 million aggregate principal amount of second-priority senior secured notes due 2029 and $625.0 million aggregate principal amount of second-priority senior secured notes due 2031 (collectively, the “New Senior Notes”), in a private offering to eligible purchasers that is exempt from registration under the Securities Act. The net proceeds from the Debt Offering (i) are expected to fund a portion of the cash consideration for the pending QuarterNorth Acquisition, (ii) funded the redemption of all of the outstanding 12.00% Notes and all of the outstanding 11.75% Notes discussed above (the “Redemptions”), and (iii) paid premiums, fees and expenses related to the Redemptions and the issuance of the New Senior Notes. The Company intends to use any remaining net proceeds for general corporate purposes, which may include the repayment of a portion of the outstanding borrowings under the Bank Credit Facility.

An aggregate of $340.0 million principal amount of the New Senior Notes will be subject to a “special mandatory redemption” in the event that the transactions contemplated by the QuarterNorth Merger Agreement are not consummated on or before May 31, 2024 (or up to September 30, 2024 solely in the event the parties require additional time to satisfy certain requirements under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, pursuant to the terms of the QuarterNorth Merger Agreement), or if we notify the trustee of the New Senior Notes that we will not pursue the consummation of the QuarterNorth Acquisition.

F-27

Note 9 — Asset Retirement Obligations

The asset retirement obligations included in the Consolidated Balance Sheets in current and non-current liabilities, and the changes in that liability were as follows (in thousands):

	Year Ended December 31,
	2023			2022
Balance, beginning of period	$	541,661		$	434,006
Obligations assumed(1)		258,858			—
Obligations incurred		14,199			1,140
Obligations settled		(86,615	)		(69,596	)
Obligations divested		(19,448	)		(1,572	)
Accretion expense		86,152			55,995
Changes in estimate(2)		102,419			121,688
Balance, end of period	$	897,226		$	541,661
Less: Current portion		77,581			39,888
Long-term portion	$	819,645		$	501,773

(1)Assumed in connection with the EnVen Acquisition. See further discussion in Note 3 — Acquisitions and Divestitures.

(2)Changes in estimate were primarily due to an increase in estimated service costs. Additionally, increases for the year ended December 31, 2023 due to the acceleration of estimated settlement date.

At December 31, 2023, the Company has (1) restricted cash of $102.4 million inclusive of interest earned to date, held in escrow and (2) the P&A Notes Receivable with an aggregate face value of $66.2 million to settle future asset retirement obligations. These assets are discussed in Note 2 — Summary of Significant Accounting Policies.

Note 10 — Employee Benefits Plans and Share-Based Compensation

EnVen Acquisition Severance

The following table summarizes severance accrual activity in connection with the EnVen Acquisition included in “Other current liabilities” and “Other long-term liabilities” on the Consolidated Balance Sheets as of December 31, 2023 (in thousands):

Severance accrual at December 31, 2022	$	—
Accrual additions		25,348
Benefit payments		(19,054	)
Severance accrual at December 31, 2023		6,294
Less: Current portion at December 31, 2023		6,190
Long-term portion at December 31, 2023	$	104

The above table includes involuntary termination benefits that are being provided pursuant to a one-time benefit arrangement that is being spread over the future service period through the termination date. Involuntary termination benefits are also being provided pursuant to contractual termination benefits required by the terms of existing employee agreements. Pursuant to the EnVen Merger Agreement, a rabbi trust was established and funded with $14.5 million at closing to pay a portion of future severance benefits associated with the contractual termination benefits. As of December 31, 2023, the rabbi trust held $3.7 million in assets of which $3.3 million and $0.4 million are included in “Other current assets” and “Other assets,” respectively, on the Consolidated Balance Sheets and both of which are included in the severance accrual at December 31, 2023 listed above. The assets of the rabbi trust are available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Severance costs are reflected in “General and administrative expense” on the Consolidated Statement of Operations.

Long Term Incentive Plans

On May 11, 2021, the Company’s stockholders approved the Talos Energy Inc. 2021 Long Term Incentive Plan (the “2021 LTIP”), which had previously been approved by the board of directors of the Company. No further awards will be granted under the Talos Energy Inc. Long Term Incentive Plan (the “2018 LTIP”) (together with the 2021 LTIP, the “LTIP Plans”).

The 2021 LTIP provides for potential grants of: (i) incentive stock options qualified as such under U.S. federal income tax laws (“ISOs”), (ii) stock options that do not qualify as ISOs (together with ISOs, “Options”), (iii) stock appreciation rights, (iv) restricted stock awards, (v) RSUs, (vi) awards of vested stock, (vii) dividend equivalents, (viii) other share-based or cash awards and (ix) substitute awards. Employees, non-employee directors and consultants of the Company and its affiliates are eligible to receive awards under the 2021 LTIP. The 2021 LTIP authorizes the Company to grant awards of up to 8,639,415 shares of the Company’s common stock, subject to the share counting and share recycling provisions of the 2021 LTIP.

F-28

Restricted Stock Units – Employees — RSUs granted to employees under the LTIP Plans primarily vest ratably over an approximate three year period subject to such employee’s continued service through each vesting date. Upon vesting, each RSU represents a contingent right to receive one share of common stock. The total unrecognized share-based compensation expense related to these RSUs at December 31, 2023 was approximately $19.0 million, which is expected to be recognized over a weighted average period of 1.7 years.

Restricted Stock Units – Non-employee Directors — RSUs granted to non-employee directors under the LTIP Plans vested approximately one year following the date of grant, subject to such non-employee director’s continued service through the vesting date. Upon vesting, these RSUs represent a contingent right to receive one share of common stock for each RSU for 60%, and cash for the remaining 40%. The total unrecognized share-based compensation expense related to these RSUs at December 31, 2023 was approximately $0.1 million, which is expected to be recognized over a weighted average period of 0.2 years. Of the unrecognized share-based compensation expense, $0.1 million relates to liability awards and will be subsequently remeasured at each reporting period.

The following table summarizes RSU activity:

	Restricted Stock Units			Weighted Average Grant Date Fair Value
Unvested RSUs at December 31, 2020		1,652,988		$	13.73
Granted		1,102,038		$	13.11
Vested		(669,832	)	$	15.01
Forfeited		(101,995	)	$	12.46
Unvested RSUs at December 31, 2021		1,983,199		$	13.02
Granted		2,297,465		$	13.23
Vested		(967,269	)	$	14.14
Forfeited		(97,891	)	$	14.34
Unvested RSUs at December 31, 2022(1)		3,215,504		$	12.79
Granted		1,154,541		$	16.24
Vested		(1,730,959	)	$	11.97
Forfeited		(332,725	)	$	14.52
Unvested RSUs at December 31, 2023(1)		2,306,361		$	14.89

(1)As of December 31, 2023 and 2022, 26,975 and 25,257, respectively, of the unvested RSUs were accounted for as liability awards in “Accrued liabilities” on the Consolidated Balance Sheet.

The Company considers its intent and ability to settle awards in cash or shares in determining whether to classify the awards as equity or as a liability. Certain awards granted during the year ended December 31, 2021 were originally classified as liability awards; however, these awards became equity-classified awards upon stockholder approval of the 2021 LTIP. The aggregate amount of compensation cost related to these awards is determined by the fair value of the award on the modification date.

Performance Share Units – Employees — PSUs granted to employees under the LTIP Plans represent the contingent right to receive one share of common stock. However, the number of shares of common stock issuable upon vesting ranges from zero to 200% of the target number of PSUs granted. The total unrecognized share-based compensation expense related to these PSUs at December 31, 2023 was approximately $8.7 million, which is expected to be recognized over a weighted average period of 1.7 years.

F-29

The following table summarizes PSU activity:

	Performance Share Units			Weighted Average Grant Date Fair Value
Unvested PSUs at December 31, 2020		834,172		$	25.46
Granted		586,995		$	18.96
Vested		(391,308	)	$	39.43
Forfeited		(14,400	)	$	18.48
Unvested PSUs at December 31, 2021		1,015,459		$	16.41
Granted(1)		629,666		$	23.73
Vested(2)		(14,474	)	$	13.05
Forfeited		(16,486	)	$	17.48
Cancelled		(975,564	)	$	16.42
Unvested PSUs at December 31, 2022		638,601		$	23.66
Granted(3)		595,394		$	18.76
Forfeited		(217,346	)	$	21.28
Unvested PSUs at December 31, 2023		1,016,649		$	21.30

(1)There were 314,833 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute total shareholder return (“TSR”) over a three-year performance period. An additional 314,833 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2022 drill program over a three-year performance period.

(2)The performance period for the relative TSR awards ended on December 31, 2022. The payout on these awards was 0% based on actual performance over the performance period as certified by the Compensation Committee of the Company’s Board of Directors in early 2023. Since these awards were legally forfeited they will again be available for new awards under the recycling provisions of the 2021 LTIP.

(3)There were 297,697 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute TSR over a three-year performance period. An additional 297,697 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2023 drill program over a three-year performance period.

Certain awards granted during the year ended December 31, 2021 were originally classified as liability awards; however, these awards became equity-classified awards upon stockholder approval of the 2021 LTIP. The following table summarizes the assumptions used in the Monte Carlo simulations to calculate the fair value of the relative or absolute TSR PSUs granted and modified at the date indicated:

	2023									2022						2021
	Grant			Grant			Grant			Grant			Grant			Modification			Grant
	December 1			July 1			March 5			September 20			March 5			May 11			March 8
Expected term (in years)		2.1			2.5			2.8			2.3			2.8			2.6			2.8
Expected volatility		61.9	%		66.2	%		73.1	%		74.3	%		82.2	%		80.9	%		78.3	%
Risk-free interest rate		4.4	%		4.6	%		4.5	%		3.9	%		1.6	%		0.3	%		0.3	%
Dividend yield		—	%		—	%		—	%		—	%		—	%		—	%		—	%
Fair value (in thousands)	$	12		$	173		$	6,165		$	621		$	8,668		$	9,715		$	11,129

Modification — During March 2022, the outstanding PSUs held by certain executive officers that were awarded in 2020 and 2021 were cancelled and, in connection with this cancellation, 1,147,352 of RSUs were granted (the “Retention RSUs”). The Retention RSUs will vest ratably each year over two years, generally contingent upon continued employment through each such date. The cancellation of the PSUs along with the concurrent grant of the Retention RSUs are accounted for as a modification. The incremental cost of $9.7 million will be recognized prospectively over the modified requisite service period. Additionally, the remaining unrecognized grant or modification date fair value of the original PSUs will be recognized over the original remaining requisite service period.

Share-based Compensation Costs

Share-based compensation costs associated with RSUs, PSUs and other awards are reflected as “General and administrative expense” on the Consolidated Statements of Operations, net amounts capitalized to “Proved Properties” on the Consolidated Balance Sheets. Because of the non-cash nature of share-based compensation, the expensed portion of share-based compensation is added back to net income in arriving at “Net cash provided by operating activities” on the Consolidated Statements of Cash Flows.

The following table presents the amount of costs expensed and capitalized (in thousands):

	Year Ended December 31,
	2023		2022		2021
Share-based compensation costs	$	25,236	$	28,280	$	20,560
Less: Amounts capitalized to oil and gas properties		12,283		12,327		9,568
Total share-based compensation expense	$	12,953	$	15,953	$	10,992

F-30

Note 11 — Income Taxes

Income Tax Expense (Benefit)

The components of income tax expense (benefit) were as follows (in thousands):

	Year Ended December 31,
	2023			2022		2021
Current income tax expense (benefit):
United States	$	76		$	1,375	$	(5	)
Mexico		31			432		(993	)
Total current income tax expense (benefit)	$	107		$	1,807	$	(998	)
Deferred income tax expense (benefit):
United States	$	(60,704	)	$	659	$	(1,067	)
Mexico		—			71		430
Total deferred income tax expense (benefit)	$	(60,704	)	$	730	$	(637	)
Total income tax expense (benefit)	$	(60,597	)	$	2,537	$	(1,635	)

A reconciliation of income tax expense (benefit) computed at the U.S. federal statutory tax rate to the Company’s income tax expense (benefit) is as follows (in thousands, except percentages):

	Year Ended December 31,
	2023			2022			2021
Income tax expense (benefit) at the federal statutory tax rate	$	26,614		$	80,735		$	(38,763	)
State income taxes		1,748			1,591			(674	)
Impact of foreign operations		13,539			15,657			(11,920	)
Effect of change in state rate		—			—			2,008
Prior year taxes		1,184			(2,920	)		486
Change in valuation allowance		(106,815	)		(96,537	)		45,547
Other permanent differences		3,133			4,011			1,681
Total income tax expense (benefit)	$	(60,597	)	$	2,537		$	(1,635	)
Effective tax rate		(47.81	)%		0.66	%		0.89	%

The Company’s effective tax rate for the year ended December 31, 2023 differed from the federal statutory rate of 21.0% primarily due to a non-cash tax benefit of $106.8 million related to the release of the valuation allowance for its deferred tax assets offset with permanent differences and state income tax expense.

The Company’s effective tax rate for the years ended December 31, 2022 and 2021 differed from the federal statutory rate of 21.0% primarily due to recording a full valuation allowance against its federal, state and foreign deferred tax assets.

F-31

Deferred Tax Assets and Liabilities

Net deferred tax assets (liabilities) reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of deferred tax assets and liabilities were as follows (in thousands):

	Year Ended December 31,
	2023			2022
Deferred tax assets:
Federal net operating loss	$	147,252		$	159,257
Foreign tax loss carryforward		509			44,462
State net operating loss		24,840			24,787
Tax credits		107			107
Interest expense carryforward		46,414			23,262
Asset retirement obligations		190,248			115,848
Derivatives		—			9,273
Other well equipment		1,317			1,891
Accrued bonus		5,050			5,863
Share-based compensation		5,172			5,296
Operating lease liabilities		4,427			3,669
Finance lease liabilities		31,607			32,559
Other		3,383			7,142
Total deferred tax assets		460,326			433,416
Valuation allowance		(23,697	)		(129,105	)
Total deferred tax assets, net	$	436,629		$	304,311
Deferred tax liabilities:
Oil and gas properties	$	512,918		$	302,602
Operating lease assets		2,421			1,323
Derivatives		9,670			—
Prepaid		3,847			2,530
Total deferred tax liabilities		528,856			306,455
Net deferred tax liability	$	(92,227	)	$	(2,144	)

Net Operating Loss

The table below presents the details of the Company’s net operating loss carryovers as of December 31, 2023 (in thousands):

	Amount		Expiration Year
Federal net operating losses	$	452,393	2035 - 2037
Federal net operating losses	$	248,807	Unlimited
Foreign tax loss carryforward	$	1,696	2025 - 2032
State net operating losses	$	125,958	2025 - 2037
State net operating losses	$	277,930	Unlimited

As of December 31, 2023, the Company had U.S. federal net operating loss carryforwards (“NOLs”) of approximately $701.2 million, all of which are subject to limitation under Section 382 of the IRC. IRC Section 382 provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, against future U.S. taxable income in the event of a change in ownership. If not utilized, such carryforwards would begin to expire at the end of 2035.

Valuation Allowance

The Company recorded a valuation allowance of $23.7 million and $129.1 million as of December 31, 2023 and 2022, respectively. Deferred income tax assets and liabilities are recorded related to NOLs and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions and income in the future. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or NOLs relate.

In assessing the need for a valuation allowance, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized using available positive and negative evidence, including future reversals of temporary differences, tax-planning strategies and future taxable income, to estimate whether sufficient future taxable income will be generated to permit use of deferred tax assets. A significant piece of objective negative evidence evaluated is the cumulative loss incurred over recent years. Such objective negative evidence limits the Company’s ability to consider other subjective positive evidence.

F-32

At December 31, 2022, the Company maintained a valuation allowance related to federal, state and foreign deferred tax assets, as there was insufficient positive evidence to overcome the substantial negative evidence of being in a cumulative loss position. At December 31, 2023, the Company is no longer in a cumulative loss position and reached the conclusion that it is appropriate to release the valuation allowance against its federal deferred tax assets due to the sustained positive operating performance and the availability of expected future taxable income. The Company’s remaining valuation allowance primarily relates to various state operating loss carryforwards.

Uncertain Tax Positions

The table below sets forth the beginning and ending balance of the total amount of unrecognized tax benefits. None of the unrecognized benefits would impact the effective tax rate if recognized. While amounts could change during the next 12 months, the Company does not anticipate having a material impact on its financial statements.

Balances in the uncertain tax positions are as follows (in thousands):

	Year Ended December 31,
	2023		2022		2021
Total unrecognized tax benefits, beginning balance	$	835	$	696	$	648
Increases in unrecognized tax benefits as a result of:
Tax positions taken during a prior period		154		100		21
Tax positions taken during the current period		—		39		27
Total unrecognized tax benefits, ending balance	$	989	$	835	$	696

The Company recognizes interest and penalties related to uncertain tax positions as “Interest Expense” and “General and administrative expense” on the Consolidated Statements of Operations, respectively.

Years Open to Examination

The 2020 through 2023 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 income tax returns of the Company for years ending on or before December 31, 2019 are closed, except to the extent of any NOL carryover balance.

EnVen Acquisition

On February 13, 2023, the Company completed the EnVen Acquisition, which is further discussed in Note 3 —Acquisitions and Divestitures. The Company recognized a net deferred tax liability of $150.3 million in its purchase price allocation as of the acquisition date to reflect differences between tax basis and the fair value of EnVen’s assets acquired and liabilities assumed. The deferred tax balance is based on preliminary calculations and on information available to management at the time such estimates were made.

Note 12 — Income (Loss) Per Share

Basic earnings per common share is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted earnings per common share includes the impact of RSUs, PSUs and outstanding warrants. The warrants expired unexercised on February 28, 2021.

The following table presents the computation of the Company’s basic and diluted income (loss) per share were as follows (in thousands, except for the per share amounts):

	Year Ended December 31,
	2023		2022		2021
Net income (loss)	$	187,332	$	381,915	$	(182,952	)
Weighted average common shares outstanding — basic		119,894		82,454		81,769
Dilutive effect of securities		858		1,229		—
Weighted average common shares outstanding — diluted		120,752		83,683		81,769
Net income (loss) per common share:
Basic	$	1.56	$	4.63	$	(2.24	)
Diluted	$	1.55	$	4.56	$	(2.24	)
Anti-dilutive potentially issuable securities excluded from diluted common shares		1,353		865		1,709

F-33

Note 13 — Related Party Transactions

Apollo Funds and Riverstone Funds

On February 3, 2012, Talos Energy LLC completed a transaction with funds and other alternative investment vehicles managed by Apollo Management VII, L.P. and Apollo Commodities Management, L.P., with respect to Series I (“Apollo Funds”), and entities controlled by or affiliated with Riverstone Energy Partners V, L.P. (“Riverstone Funds”) and members of management pursuant to which the Talos Energy LLC received a private equity capital commitment. On January 3, 2022, the Apollo Funds ceased being a beneficial owner of more than five percent of the Company’s common stock. On July 5, 2023, the Riverstone Funds ceased being a beneficial owner of more than five percent of the Company’s common stock.

Whistler Acquisition Settlement

On August 31, 2018, the Company acquired Whistler Energy II, LLC from Whistler Energy II Holdco, LLC, an affiliate of the Apollo Funds. A settlement agreement related to a dispute regarding the decommissioning obligation of a Deepwater well was executed in September 2021. For the year ended December 31, 2021, the Company recognized a $4.4 million gain resulting from the settlement which is reflected in “Other income (expense)” on the Company’s Consolidated Statements of Operations.

Registration Rights Agreements

2018 Registration Rights Agreement — On May 10, 2018, the Company entered into a registration rights agreement (the “2018 Registration Rights Agreement”) with certain of the Apollo Funds and the Riverstone Funds, certain funds controlled by Franklin Advisers, Inc. (“Franklin”) and certain clients of MacKay Shields LLC (“MacKay Shields”), relating to the registered resale of the Company’s common stock owned by such parties on such date. Subsequently, the 2018 Registration Rights Agreement was amended to add additional affiliates of the Riverstone Funds as parties to the agreement and provide such parties with customary registration rights with respect to the Company’s Series A Convertible Preferred Stock issued to these parties at the closing of an acquisition on February 28, 2020.

The 2018 Registration Rights Agreement provided that registration rights would terminate with respect to Franklin and MacKay Shields in the event that either Franklin or MacKay Shields ceased to beneficially own 5% or more of the then outstanding shares of the Company’s common stock. Additionally, the 2018 Registration Rights Agreement provided that registration rights would otherwise terminate at such time as there were no registrable securities outstanding. The 2018 Registration Rights Agreement terminated on July 5, 2023 as there were no registrable securities outstanding.

The Company agreed to bear all of the expenses incurred in connection with any offer and sale, while the selling stockholders will be responsible for paying underwriting fees, discounts and selling commissions. The Company incurred fees of nil, nil, and $0.7 million for the fiscal years ended December 31, 2023, 2022 and 2021, respectively.

2022 Registration Rights Agreement — In connection with the Company’s entry into the EnVen Merger Agreement on September 21, 2022 to acquire EnVen, the Company entered into a registration rights agreement (the “2022 Registration Rights Agreement”) with Adage Capital Partners, L.P. (“Adage”) and affiliated entities of Bain Capital, LP (“Bain”). Pursuant to the 2022 Registration Rights Agreement, the Company grants to Adage and Bain certain demand, “piggy-back” and shelf registration rights with respect to the shares of the Company’s common stock to be received by such entities in the EnVen Acquisition, subject to certain customary thresholds and conditions. Adage and Bain held approximately 2.3% and 12.2%, respectively, of the Company’s outstanding shares of common stock as of December 31, 2023 based on SEC beneficial ownership reports filed by each of Adage and Bain.

Additionally, the Company agreed to pay certain expenses of the parties incurred in connection with the exercise of their rights under such agreement and to indemnify them for certain securities law matters in connection with any registration statement filed pursuant thereto. The Company did not incur any fees for the fiscal year ended December 31, 2023.

Amended and Restated Stockholders’ Agreement and Related Agreements

On May 10, 2018, the Company entered into a Stockholders’ Agreement (the “Stockholders’ Agreement”) by and among the Company and the other parties thereto. On February 24, 2020, the Company and the other parties thereto amended the Stockholders’ Agreement to, among other things, add additional affiliates of the Riverstone Funds (or one or more of its designated affiliates) as parties to the Stockholders’ Agreement and provided ownership of the Series A Convertible Preferred Stock would, prior to the conversion thereof on March 20, 2020, count towards certain stock ownership requirements on an as converted basis to retain the Riverstone Funds rights to nominate directors to the board of directors.

On March 29, 2022, the Company and other parties thereto, entered into the Amended and Restated Stockholders’ Agreement, in connection with the termination of the Apollo Funds’ rights thereunder and the resignation of certain members of the Company's Board of Directors (the “Amended and Restated Stockholders’ Agreement”). The Amended and Restated Stockholders’ Agreement, among other things, (i) terminated the rights of the Apollo Funds under the Stockholders’ Agreement and (ii) eliminated the requirement that the board of directors consist of ten members.

F-34

In connection with the closing of the EnVen Acquisition, the Company and the Riverstone Funds terminated the Amended and Restated Stockholders’ Agreement and Mr. Robert M. Tichio resigned from the Company’s Board of Directors pursuant to a shareholder support agreement dated as of September 21, 2022 requiring the Riverstone Funds to, among other things, approve the EnVen Merger Agreement and the proposed business combination. In connection with the termination of the Amended and Restated Stockholders’ Agreement, the Company and the Riverstone Funds entered into a letter agreement, dated February 13, 2023, pursuant to which the parties thereto agreed to execute and deliver such additional documents and take all such further action as may be reasonably necessary to cause the Amended and Restated Stockholders’ Agreement to be terminated without any further force and effect.

Legal Fees

The Company has engaged the law firm Vinson & Elkins L.L.P. (“V&E”) to provide legal services. An immediate family member of William S. Moss III, the Company’s Executive Vice President and General Counsel and one of its executive officers, is a partner at V&E. For the years ended December 31, 2023, 2022 and 2021, the Company incurred fees of approximately $3.3 million, $4.8 million, and $3.1 million, respectively, of which $0.8 million, $1.3 million, and $0.2 million were payable at each respective balance sheet date for legal services performed by V&E.

Slim Family

Carlos Slim Helú, Carlos Slim Domit, Marco Antonio Slim Domit, Patrick Slim Domit, María Soumaya Slim Domit, Vanessa Paola Slim Domit and Johanna Monique Slim Domit (collectively, the “Slim Family”) are beneficiaries of a Mexican trust which in turn owns all of the outstanding voting securities of Control Empresarial de Capitales S.A. de C.V. (“Control Empresarial” together with the Slim Family, the “Slim Family Office”). Control Empresarial, a sociedad anónima de capital variable organized under the laws of the United Mexican States, is a holding company with portfolio investments in various companies. Control Empresarial and the Slim Family became related parties on November 7, 2023 when they accumulated greater than ten percent of the Company’s outstanding shares of common stock. Control Empresarial held approximately 12.2% of the Company’s outstanding shares of common stock as of December 31, 2023 based on SEC beneficial ownership reports filed by Control Empresarial. The Slim Family own a majority stake in Grupo Carso, which indirectly has an ownership interest in Talos Mexico. See Note 3 – Acquisitions and Divestitures for additional information. The Company had no related party receivable from affiliates of the Slim Family as of December 31, 2023.

Subsequent Event — In connection with the January Equity Offering (defined below), Control Empresarial increased their holding to approximately 21.9% of the Company’s outstanding shares of common stock as of the closing of the January Equity Offering based on SEC beneficial ownership reports filed by Control Empresarial. See Note 17 – Subsequent Events for additional information.

In connection with the Debt Offering in February 2024, the Company consummated a firm commitment debt offering consisting of $1,250.0 million in aggregate principal amount of second-priority senior secured notes in a private offering to eligible purchasers that was exempt from registration under the Securities Act. In connection with the Debt Offering, and after expressing a non-binding indication of interest after commencement of the offering, entities and/or persons related to the Slim Family Office purchased an aggregate principal amount of $312.5 million of such notes from the initial purchasers of such offering. In connection with such transaction, the Company expects to pay Inbursa, a banking institution controlled by the Slim Family Office an advisory fee of approximately $2.7 million. See Note 8 – Debt for additional information regarding the Debt Offering.

Equity Method Investments

The Company had a $5.5 million related party receivable from various equity method investments as of December 31, 2023. This is reflected as “Other, net” within “Accounts Receivable” on the Consolidated Balance Sheets. See Note 7 – Equity Method Investments for additional information on the Company’s equity method investments.

Note 14 — Commitments and Contingencies

Legal Proceedings and Other Contingencies

From time to time, the Company is involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of business in jurisdictions in which the Company does business. Although the outcome of these matters cannot be predicted with certainty, the Company’s management believes none of these matters, either individually or in the aggregate, would have a material effect upon the Company’s financial position; however, an unfavorable outcome could have a material adverse effect on the Company’s results from operations for a specific interim period or year.

On March 23, 2022, the Company entered into a settlement agreement to receive $27.5 million to resolve previously pending litigation, which was filed on October 23, 2017, against a third-party supplier related to quality issues. As part of the settlement agreement, the Company released all of its claims in the litigation. The settlement is reflected as “Other income (expense)” on the Consolidated Statements of Operations.

F-35

In June 2019, David M. Dunwoody, Jr., former President of EnVen, filed a lawsuit against EnVen in Texas District Court alleging that the circumstances of his resignation entitled him to the severance payments and benefits under his employment agreement dated as of November 6, 2015 as a resignation for “Good Reason.” In September 2021, the trial court entered a judgment in favor or Mr. Dunwoody, inclusive of Mr. Dunwoody’s legal fees and interest. EnVen filed a Notice of Appeal in December 2021. The litigation was assumed as part of the EnVen Acquisition. In April 2023, the appellate court affirmed the trial court’s judgment. The Company filed a petition for review with the Texas Supreme Court on August 2, 2023, which was denied on January 26, 2024. As Of December 31, 2023, the Company has recorded $14.3 million as “Other current liabilities” on the Consolidated Balance Sheets related to the litigation.

Performance Obligations

Regulations with respect to the Company's operations govern, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells, removal of facilities in the U.S. Gulf of Mexico and certain obligations under the production sharing contracts with Mexico.

As of December 31, 2023, the Company had secured performance bonds from third party sureties totaling $1.4 billion. The cost of securing these bonds is reflected as “Interest expense” on the Consolidated Statements of Operations. Additionally, as of December 31, 2023, the Company had secured letters of credit issued under its Bank Credit Facility totaling $10.8 million. Letters of credit that are outstanding reduce the available revolving credit commitments. See Note 8 — Debt for further information on the Bank Credit Facility.

The table below summarizes the Company’s total minimum commitments associated with vessel commitments, purchase obligations and other miscellaneous commitments as of December 31, 2023 (in thousands):

	2024		2025		2026		2027		Thereafter		Total
Vessel Commitments(1)	$	13,216	$	—	$	—	$	—	$	—	$	13,216
Committed purchase orders(2)		3,083		—		—		—		—		3,083
Other commitments(3)		3,991		327		—		—		—		4,318
Total	$	20,290	$	327	$	—	$	—	$	—	$	20,617

(1)Includes vessel commitments the Company will utilize for certain Deepwater well intervention, drilling operations and decommissioning activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs.

(2)Includes committed purchase orders to execute planned future drilling activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs.

(3)Includes commitments associated with the Company’s CCS Segment relating to an equity funding obligation and payments required under a sequestration agreement.

Decommissioning Obligations

The Company, as a co-lessee or predecessor-in-interest in oil and natural gas leases located in the U.S. Gulf of Mexico, is in the chain of title with unrelated third parties either directly or by virtue of divestiture of certain oil and natural gas assets previously owned and assigned by our subsidiaries. Certain counterparties in these divestiture transactions or third parties in existing leases have filed for bankruptcy protection or undergone associated reorganizations and may not be able to perform required abandonment obligations. Regulations or federal laws could require the Company to assume such obligations. The Company reflects such costs as “Other operating (income) expense” on the Consolidated Statements of Operations.

The decommissioning obligations included are in the Consolidated Balance Sheets as “Other current liabilities” and “Other long-term liabilities”, and the changes in that liability were as follows (in thousands):

	Year Ended December 31,
	2023			2022			2021
Balance, beginning of period	$	54,269		$	24,336		$	—
Additions		266			8,900			21,056
Changes in estimate		11,613			22,658			—
Reimbursements due from third parties		—			—			3,280
Settlements		(50,584	)		(1,625	)		—
Balance, end of period	$	15,564		$	54,269		$	24,336
Less: Current portion		3,280			42,069			3,756
Long-term portion	$	12,284		$	12,200		$	20,580

F-36

Although it is reasonably possible that the Company could receive state or federal decommissioning orders in the future or be notified of defaulting third parties in existing leases, the Company cannot predict with certainty, if, how or when such orders or notices will be resolved or estimate a possible loss or range of loss that may result from such orders. However, the Company could incur judgments, enter into settlements or revise its opinion regarding the outcome of certain notices or matters, and such developments could have a material adverse effect on its results of operations in the period in which the amounts are accrued and its cash flows in the period in which the amounts are paid.

Note 15 — Segment Information

The Company’s operations are managed through two operating segments: (i) Upstream Segment and (ii) CCS Segment. The Upstream Segment is the Company’s only reportable segment. The Company’s chief operating decision-maker (“CODM”) is the President and Chief Executive Officer, who reviews operating results to make decisions about allocating resources and assessing performance for the entire company. A reportable segment is an operating segment that meets materiality thresholds. The 10% test, as prescribed by the segment reporting accounting guidance, are based on the reported measures of revenue, profit, and assets that are used by the CODM to assess performance and allocate resources. The CCS Segment currently does not meet any of the reportable segment quantitative thresholds. The profit or loss metric used to evaluate segment performance is Adjusted EBITDA, which is defined by the Company as net income (loss) plus interest expense; income tax expense (benefit); depreciation, depletion, and amortization; accretion expense; non-cash write-down of oil and natural gas properties; transaction and other (income) expenses; decommissioning obligations; the net change in the fair value of derivatives (mark to market effect, net of cash settlements and premiums related to these derivatives); (gain) loss on debt extinguishment; non-cash write-down of other well equipment; and non-cash equity-based compensation expense.

Corporate general and administrative expense include certain shared costs such as finance, accounting, tax, human resources, information technology and legal costs that are not directly attributable to each of operating segment. A portion of these expenses are allocated based on the percentage of employees dedicated to each operating segment. The remaining expenses are included in the reconciliation of reportable segment Adjusted EBITDA to consolidated pre-tax net income (loss) as an unallocated corporate general and administrative expense. The accounting policies of the segments are the same as those described in the summary of significant accounting policies.

The Company’s CODM does not review assets by segment as part of the financial information provided and therefore, no asset information is provided in the table below.

The following table presents selected segment information for the periods indicated (in thousands):

	Upstream		All Other(1)			Total
Revenues from External Customers:
Year Ended December 31, 2023	$	1,457,886	$	—		$	1,457,886
Year Ended December 31, 2022		1,651,980		—			1,651,980
Year Ended December 31, 2021		1,244,540		—			1,244,540
Equity in the Net Income (Loss) of Investees Accounted for by the Equity Method:
Year Ended December 31, 2023	$	120	$	(12,228	)	$	(12,108	)
Year Ended December 31, 2022		101		(1,166	)		(1,065	)
Year Ended December 31, 2021		—		—			—
Adjusted EBITDA:
Year Ended December 31, 2023	$	979,729	$	(22,883	)	$	956,846
Year Ended December 31, 2022	$	859,840	$	(12,786	)		847,054
Year Ended December 31, 2021		615,798		(4,782	)		611,016
Segment Expenditures:
Year Ended December 31, 2023	$	733,669	$	40,961		$	774,630
Year Ended December 31, 2022		452,674		2,778			455,452
Year Ended December 31, 2021		338,822		—			338,822

(1)The CCS Segment is included in the “All Other” category. The CCS Segment is an emerging business in the start-up phase of operations and the business that does not currently generate any revenues. The CCS Segment’s business activities are conducted through both wholly owned subsidiaries and equity method investments with industry partners. Equity method investments is a business strategy that enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed.

F-37

Reconciliations

The following table presents the reconciliations of Adjusted EBITDA to the Company’s consolidated totals (in thousands):

	Year Ended December 31,
	2023			2022			2021
Adjusted EBITDA:
Total for reportable segments	$	979,729		$	859,840		$	615,798
All other		(22,883	)		(12,786	)		(4,782	)
Unallocated corporate general and administrative expense		(6,128	)		(5,280	)		(4,542	)
Interest expense		(173,145	)		(125,498	)		(133,138	)
Depreciation, depletion and amortization		(663,534	)		(414,630	)		(395,994	)
Accretion expense		(86,152	)		(55,995	)		(58,129	)
Write-down of oil and natural gas properties		—			—			(18,123	)
Transaction and other (income) expenses(1)		33,295			34,513			(5,886	)
Decommissioning obligations(2)		(11,879	)		(31,558	)		(21,055	)
Derivative fair value gain (loss) (3)		80,928			(272,191	)		(419,077	)
Net cash (received) paid on settled derivative instruments (3)		9,457			425,559			290,164
Gain (loss) on extinguishment of debt		—			(1,569	)		(13,225	)
Non-cash write-down of other well equipment		—			—			(5,606	)
Non-cash equity-based compensation expense		(12,953	)		(15,953	)		(10,992	)
Income (loss) before income taxes	$	126,735		$	384,452		$	(184,587	)

(1)Transaction expenses includes $40.4 million and $9.0 million in costs related to the EnVen Acquisition, inclusive of $25.3 million and nil in severance expense for the years ended December 31, 2023 and 2022, respectively. See further discussion in Note 3 — Acquisition and Divestitures and Note 10 — Employee Benefits Plans and Share-Based Compensation. Other income (expense) includes other miscellaneous income and expenses that the Company does not view as a meaningful indicator of its operating performance. For the year ended December 31, 2023, the amount includes a $66.2 million gain on the Mexico Divestiture. See further discussion in Note 3 — Acquisitions and Divestitures. The amount includes a gain on the funding of the capital carry of the Company’s investment in Bayou Bend by Chevron of $8.6 million and $1.4 million for the year ended December 31, 2023 and 2022, respectively. Additionally, it includes a $13.9 million gain on the partial sale of its investment in Bayou Bend to Chevron for the year ended December 31, 2022. See further discussion in Note 7 — Equity Method Investments. For the year ended December 31, 2022, the amount includes $27.5 million gain as a result of the settlement agreement to resolve previously pending litigation that was filed in October 2017 that is further discussed in Note 14 — Commitments and Contingencies.

(2)Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Note 14 — Commitments and Contingencies for additional information on decommissioning obligations.

(3)The adjustments for the derivative fair value (gains) losses and net cash receipts (payments) on settled commodity derivative instruments have the effect of adjusting net loss for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because the Company does not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled.

The following table presents the reconciliation of Segment Expenditures to the Company’s consolidated totals (in thousands):

	Year Ended December 31,
	2023			2022			2021
Segment Expenditures:
Total reportable segments	$	733,669		$	452,674		$	338,822
All other		40,961			2,778			—
Change in capital expenditures included in accounts payable and accrued liabilities		(9,199	)		(60,011	)		28,258
Plugging & abandonment		(86,615	)		(69,596	)		(67,988	)
Decommissioning obligations settled		(50,584	)		(1,625	)		—
Investment in CCS intangibles and equity method investees		(40,946	)		(2,778	)		—
Other deferred payments		(1,545	)		—			(7,921	)
Insurance recovery proceeds		2,802			—			—
Non-cash well equipment transfers		(27,731	)		(6	)		1,086
Other		622			1,728			1,074
Exploration, development and other capital expenditures	$	561,434		$	323,164		$	293,331

F-38

Note 16 — Supplemental Oil and Gas Disclosures (Unaudited)

Capitalized Costs

Aggregate amounts of capitalized costs relating to oil, natural gas and NGL activities and the aggregate amount of related accumulated depletion and amortization as of the dates indicated are presented below (in thousands):

	Year Ended December 31,
	2023		2022		2021
Consolidated Entities:
Proved properties	$	7,906,295	$	5,964,340	$	5,232,480
Unproved oil and gas properties, not subject to amortization(1)		268,315		154,783		219,055
Total oil and gas properties		8,174,610		6,119,123		5,451,535
Less: Accumulated depletion		4,143,491		3,484,590		3,072,907
Net capitalized costs	$	4,031,119	$	2,634,533	$	2,378,628
Depletion and amortization rate (Per Boe)	$	27.23	$	18.95	$	16.71
Company's Share of Equity Investees:
Unproved oil and gas properties, not subject to amortization	$	56,579	$	—	$	—

(1)Amount includes $111.4 million and $110.3 million of unproved properties, not subject to amortization, related to the Company’s operations in offshore Mexico for the years ended December 31, 2022 and 2021, respectively.

Included in the depletable basis of proved oil and gas properties is the estimate of the Company’s proportionate share of asset retirement costs relating to these properties which are also reflected as “Asset retirement obligations” on the accompanying Consolidated Balance Sheets. See Note 9 — Asset Retirement Obligations for additional information.

Costs Incurred for Property Acquisition, Exploration and Development Activities

The following table reflects the costs incurred in oil, natural gas and NGL property acquisition, exploration and development activities during the years indicated (in thousands). Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to estimates during the year.

	Year Ended December 31,
	2023		2022		2021
Consolidated Entities:
Property acquisition costs:
Proved properties	$	951,703	$	—	$	210
Unproved properties, not subject to amortization		249,688		2,221		—
Total property acquisition costs		1,201,391		2,221		210
Exploration costs(1)		161,296		125,889		23,844
Development costs		805,148		541,512		245,058
Total costs incurred	$	2,167,835	$	669,622	$	269,112
Company's Share of Equity Investees:
Exploration costs	$	290	$	—	$	—

(1)Amount includes nil, $1.2 million and $6.6 million of exploration costs related to the Company’s operations in offshore Mexico for the years ended December 31, 2023, 2022 and 2021, respectively.

Estimated Quantities of Proved Oil, Natural Gas and NGL Reserves

The Company employs full-time experienced reserve engineers and geologists who are responsible for determining proved reserves in compliance with SEC guidelines. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The reserve data in the following tables only represent estimates and should not be construed as being exact. Engineering reserve estimates were prepared based upon interpretation of production performance data and subsurface information obtained from the drilling of existing wells. The Company’s Director of Reserves, internal reservoir engineers and geologists analyzed and prepared reserve estimates on all oil and natural gas fields. All of the Company’s proved oil, natural gas and NGL reserves are located in the U.S. Gulf of Mexico.

At December 31, 2023, 2022 and 2021, 100% of proved oil, natural gas and NGL reserves attributable to all of the Company’s oil and natural gas properties were estimated and compiled for reporting purposes by the Company’s reservoir engineers and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers and geologists.

F-39

The following table presents the Company’s estimated proved reserves at its net ownership interest:

	Oil (MBbls)			Gas (MMcf)			NGL (MBbls)			Oil Equivalent (MBoe)
Consolidated Entities:
Total proved reserves at December 31, 2020		109,307			257,208			10,858			163,033
Revision of previous estimates		13,619			8,979			5,137			20,252
Production		(16,159	)		(32,795	)		(1,875	)		(23,500	)
Extensions and discoveries		997			2,961			315			1,806
Total proved reserves at December 31, 2021		107,764			236,353			14,435			161,591
Revision of previous estimates		(5,625	)		(8,302	)		(2,002	)		(9,010	)
Production		(14,561	)		(32,215	)		(1,793	)		(21,723	)
Sales of reserves		(158	)		(7,625	)		—			(1,429	)
Extensions and discoveries		3,639			31,340			2,288			11,150
Total proved reserves at December 31, 2022		91,059			219,551			12,928			140,579
Revision of previous estimates		(6,308	)		(62,946	)		(1,283	)		(18,082	)
Production		(18,062	)		(26,194	)		(1,767	)		(24,195	)
Purchases of reserves		41,871			36,690			1,116			49,102
Extensions and discoveries		2,255			12,770			979			5,362
Total proved reserves at December 31, 2023		110,815			179,871			11,973			152,766
Total Proved Developed Reserves as of:
December 31, 2021		93,420			186,442			11,792			136,286
December 31, 2022		80,285			161,727			9,315			116,555
December 31, 2023		98,225			141,823			9,957			131,819
Total Proved Undeveloped Reserves as of:
December 31, 2021		14,344			49,911			2,643			25,305
December 31, 2022		10,774			57,824			3,613			24,024
December 31, 2023		12,590			38,048			2,016			20,947

During 2023, proved reserves increased by 12.2 MMBoe primarily due to a purchases of reserves of 49.1 MMBoe in connection with the EnVen Acquisition and 5.4 MMBoe of estimated proved reserves from extensions and discoveries primarily from evaluations of the Brutus Field in the Green Canyon core area. This increase was partially offset by a decrease of 24.2 MMBoe of production and a decrease of 18.1 MMBoe from revisions of previous estimates. The revisions were primarily due to a 13.5 MMBoe decrease in reserve volumes due to the decrease in SEC Pricing of $17.47 per Bbl of oil and $4.05 per Mcf of natural gas and an additional decrease in the Phoenix Field in the Green Canyon core area due to well performance.

During 2022, proved reserves decreased by 21.0 MMBoe primarily due to a decrease of 21.7 MMBoe of production. Additionally, there was a decrease of 9.0 MMBoe primarily due to timing of development of certain PUD locations to move beyond five years at the Phoenix Field in the Green Canyon core area and sales of reserves of 1.4 MMBoe primarily related to the Brushy Creek Field in the Shelf and Gulf Coast area. The decrease was partially offset by 11.2 MMBoe of estimated proved reserves from extensions and discoveries primarily from evaluations of the Pompano Field and the Ram Powell Field located in the Mississippi Canyon core area.

During 2021, proved reserves decreased by 1.4 MMBoe primarily due to a decrease of 23.5 MMBoe of production. The decrease was partially offset by revision to previous estimates of 20.3 MMBoe due to increase in commodity prices as well as 1.8 MMBoe of estimated proved reserves from extensions and discoveries primarily from an evaluation of Crown and Anchor Field located in the Mississippi Canyon core area.

F-40

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves

The following table reflects the standardized measure of discounted future net cash flows relating to the Company’s interest in proved oil, natural gas and NGL reserves (in thousands):

	Year Ended December 31,
	2023			2022			2021
Consolidated Entities:
Future cash inflows	$	9,425,055		$	10,674,896		$	8,496,005
Future costs:
Production		(3,090,491	)		(1,906,752	)		(1,868,818	)
Development and abandonment		(2,358,368	)		(1,873,453	)		(1,422,507	)
Future net cash flows before income taxes		3,976,196			6,894,691			5,204,680
Future income tax expense		(589,413	)		(1,114,409	)		(676,778	)
Future net cash flows after income taxes		3,386,783			5,780,282			4,527,902
Discount at 10% annual rate		(343,295	)		(1,411,834	)		(1,087,291	)
Standardized measure of discounted future net cash flows	$	3,043,488		$	4,368,448		$	3,440,611

Future cash inflows are computed by applying SEC Pricing to year-end quantities of proved reserves. The discounted future cash flow estimates do not include the effects of derivative instruments. See the following table for SEC Pricing used in determining the standardized measure:

	Year Ended December 31,
	2023		2022		2021
Oil price per Bbl	$	78.56	$	96.03	$	67.14
Natural gas price per Mcf	$	2.75	$	6.80	$	3.71
NGL price per Bbl	$	18.77	$	33.89	$	26.62

Future net cash flows are discounted at the prescribed rate of 10%. Actual future net cash flows may vary considerably from these estimates. Although the Company’s estimates of total proved reserves, development and abandonment costs and production rates were based on the best information available, the development and production of oil and gas reserves may not occur in the periods assumed. All estimated costs to settle asset retirement obligations associated with the Company’s proved reserves have been included in their calculation of development and abandonment of the standardized measure of discounted future net cash flows for each period presented. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, such estimated future net cash flow computations should not be considered to represent the Company’s estimate of the expected revenues or the current value of existing proved reserves.

Changes in Standardized Measure of Discounted Future Net Cash Flows

Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved oil, natural gas and NGL reserves are as follows (in thousands):

	Year Ended December 31,
	2023			2022			2021
Consolidated Entities:
Standardized measure, beginning of year	$	4,368,448		$	3,440,611		$	1,904,934
Sales and transfers of oil, net gas and NGLs produced during the period		(1,065,814	)		(1,340,400	)		(957,576	)
Net change in prices and production costs		(2,835,125	)		2,388,442			2,049,980
Changes in estimated future development and abandonment costs		(19,877	)		(84,391	)		(57,876	)
Previously estimated development and abandonment costs incurred		202,503			20,107			69,125
Accretion of discount		518,110			392,600			199,849
Net change in income taxes		357,321			(327,265	)		(391,834	)
Purchases of reserves		2,033,852			—			—
Sales of reserves		—			(5,218	)		—
Extensions and discoveries		90,244			202,239			45,485
Net change due to revision in quantity estimates		(484,423	)		(255,743	)		426,357
Changes in production rates (timing) and other		(121,751	)		(62,534	)		152,167
Standardized measure, end of year	$	3,043,488		$	4,368,448		$	3,440,611

F-41

Note 17 — Subsequent Events

QuarterNorth Acquisition

For additional Information, see the following:

•Note 3 — Acquisitions and Divestitures

•Note 8 — Debt

•Note 13 — Related Party Transactions

Equity Offering

On January 22, 2024, the Company closed an upsized underwritten public offering (the “January Equity Offering”) of 34.5 million shares of the Company’s common stock, resulting in net proceeds to the Company of approximately $388.5 million, after deducting underwriting discounts and commissions and before estimated offering expenses. The Company intends to use the net proceeds from the January Equity Offering to fund a portion of the cash consideration for the QuarterNorth Acquisition. However, the QuarterNorth Acquisition remains subject to certain conditions to closing. Pending the use of the proceeds of the January Equity Offering as described above, the Company may temporarily use all or a portion of such proceeds to reduce the borrowings outstanding under the Company’s Bank Credit Facility. In the event that the QuarterNorth Acquisition is not completed, the proceeds from the January Equity Offering will be used for general corporate purposes.

F-42

Schedule I. Condensed Financial Information of Registrant

TALOS ENERGY INC. (PARENT ONLY)

BALANCE SHEETS

(In thousands, except share amounts)

	Year Ended December 31,
	2023			2022
ASSETS
Current assets:
Accounts receivable:
Other, net	$	100		$	—
Prepaid assets		221			169
Other current assets		19			36
Total current assets		340			205
Other long-term assets:
Investments in subsidiaries		2,246,908			1,168,053
Total assets	$	2,247,248		$	1,168,258
LIABILITIES AND STOCKHOLDERSʼ EQUITY
Current liabilities:
Accounts payable	$	316		$	249
Accrued liabilities		705			728
Other current liabilities		124			62
Total current liabilities		1,145			1,039
Long-term liabilities:
Other long-term liabilities		90,952			1,643
Total liabilities		92,097			2,682
Commitments and contingencies
Stockholdersʼ equity:
Preferred stock; $0.01 par value; 30,000,000 shares authorized and zero shares issued or outstanding as of December 31, 2023 and 2022, respectively		—			—
Common stock; $0.01 par value; 270,000,000 shares authorized; 127,480,361 and 82,570,328 shares issued as of December 31, 2023 and 2022, respectively		1,275			826
Additional paid-in capital		2,549,097			1,699,799
Accumulated deficit		(347,717	)		(535,049	)
Treasury stock, at cost; 3,400,000 and zero shares as of December 31, 2023 and 2022, respectively		(47,504	)		—
Total stockholdersʼ equity		2,155,151			1,165,576
Total liabilities and stockholdersʼ equity	$	2,247,248		$	1,168,258

See accompanying notes.

F-43

TALOS ENERGY INC. (PARENT ONLY)

STATEMENTS OF OPERATIONS

(In thousands)

	Year Ended December 31,
	2023			2022			2021
Revenues:
Oil	$	—		$	—		$	—
Natural gas		—			—			—
NGL		—			—			—
Total revenues		—			—			—
Operating expenses:
Lease operating expense		—			—			—
Production taxes		—			—			—
Depreciation, depletion and amortization		—			—			—
Accretion expense		—			—			—
General and administrative expense	$	2,708		$	2,145		$	1,322
Other operating (income) expense		—			—			—
Total operating expenses		2,708			2,145			1,322
Operating income (expense)		(2,708	)		(2,145	)		(1,322	)
Interest expense		—			—			(5	)
Price risk management activities income (expense)		—			—			—
Equity method investment income (expense)		—			—			—
Other income (expense)		(1	)		(1	)		(2	)
Equity earnings (loss) from subsidiaries		128,888			385,968			(180,548	)
Net income (loss) before income taxes		126,179			383,822			(181,877	)
Income tax benefit (expense)		61,153			(1,907	)		(1,075	)
Net income (loss)	$	187,332		$	381,915		$	(182,952	)

See accompanying notes.

F-44

TALOS ENERGY INC. (PARENT ONLY)

STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2023			2022			2021
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	(1,836	)	$	(809	)	$	(876	)
Cash flows from investing activities:
Distributions from subsidiaries		49,340			809			879
Contributions to subsidiaries		—			—			(3	)
Net cash provided by (used in) investing activities		49,340			809			876
Cash flows from financing activities:
Purchase of treasury stock		(47,504	)		—			—
Net cash provided (used in) by financing activities		(47,504	)		—			—
Net increase (decrease) in cash and cash equivalents		—			—			—
Cash and cash equivalents:
Balance, beginning of period		—			—			—
Balance, end of period	$	—		$	—		$	—

See accompanying notes.

F-45

TALOS ENERGY INC. (PARENT ONLY)

NOTES TO CONDENSED FINANCIAL STATEMENTS

December 31, 2023

Note 1 — Basis of Presentation

Pursuant to the rules and regulations of the SEC, the parent only condensed financial information of Talos Energy, Inc. do not reflect all of the information and notes normally included with financial statements prepared in accordance with GAAP. Therefore, these condensed financial statements should be read in conjunction with the consolidated financial statements and related notes included under Part IV, Item 15. Exhibits and Financial Statement Schedules in this Annual Report.

F- 46

EX-10.12

Exhibit 10.12

FORM OF INDEMNIFICATION AGREEMENT

This Indemnification Agreement (“Agreement”) is made as of by and between Talos Energy Inc., a Delaware corporation (the “Company”), and (“Indemnitee”). This Agreement supersedes and replaces any and all previous Agreements between the Company and Indemnitee covering the subject matter of this Agreement.

RECITALS

WHEREAS, highly competent persons have become more reluctant to serve publicly-held corporations as directors, officers or in other capacities unless they are provided with adequate protection through insurance or adequate indemnification against inordinate risks of claims and actions against them arising out of their service to and activities on behalf of the corporation;

WHEREAS, directors, officers, and other persons in service to corporations or business enterprises are being increasingly subjected to expensive and time-consuming litigation relating to, among other things, matters that traditionally would have been brought only against the Company or business enterprise itself;

WHEREAS, the Board of Directors of the Company (the “Board”) has determined that, in order to attract and retain qualified individuals, the Company will attempt to maintain on an ongoing basis, at its sole expense, liability insurance to protect persons serving the Company and its subsidiaries from certain liabilities. Although the furnishing of such insurance has been a customary and widespread practice among United States-based corporations and other business enterprises, the Company believes that, given current market conditions and trends, such insurance may be available to it in the future only at higher premiums and with more exclusions;

WHEREAS, the Second Amended and Restated Certificate of Incorporation of the Company (the “Certificate of Incorporation”) and the Second Amended and Restated Bylaws of the Company (the “Bylaws”) require indemnification of the officers and directors of the Company. Indemnitee may also be entitled to indemnification pursuant to the General Corporation Law of the State of Delaware (the “DGCL”). The Certificate of Incorporation, Bylaws and the DGCL expressly provide that the indemnification provisions set forth therein are not exclusive, and thereby contemplate that contracts may be entered into between the Company and members of the board of directors, officers and other persons with respect to indemnification;

WHEREAS, the uncertainties relating to such insurance and to indemnification have increased the difficulty of attracting and retaining such persons;

WHEREAS, the Board has determined that the increased difficulty in attracting and retaining such persons is detrimental to the best interests of the Company and its stockholders and that the Company should act to assure such persons that there will be increased certainty of such protection in the future;

WHEREAS, it is reasonable, prudent and necessary for the Company contractually to obligate itself to indemnify, and to advance expenses on behalf of, such persons to the fullest extent permitted by applicable law so that they will serve or continue to serve the Company free from undue concern that they will not be so indemnified;

WHEREAS, this Agreement is a supplement to and in furtherance of the Certificate of Incorporation, Bylaws and any resolutions adopted pursuant thereto, and shall not be deemed a substitute therefor, nor to diminish or abrogate any rights of Indemnitee thereunder;

WHEREAS, Indemnitee does not regard the protection available under the Certificate of Incorporation, Bylaws and insurance as adequate in the present circumstances, and may not be willing to serve as an officer or director without adequate protection, and the Company desires Indemnitee to serve in such capacity. Indemnitee is willing to serve, continue to serve and to take on additional service for or on behalf of the Company on the condition that he be so indemnified; and

NOW, THEREFORE, in consideration of the premises and the covenants contained herein, the Company and Indemnitee do hereby covenant and agree as follows:

Section 1. Services to the Company. Indemnitee agrees to serve as a director, officer, employee and/or agent of the Company. Indemnitee may at any time and for any reason resign from such position (subject to any other contractual obligation or any obligation imposed by operation of law). This Agreement shall not be deemed an employment contract between the Company (or any of its subsidiaries or any Enterprise) and Indemnitee. Indemnitee specifically acknowledges that Indemnitee’s employment with the Company (or any of its subsidiaries or any Enterprise), if any, is at will, and the Indemnitee may be discharged at any time for any

Exhibit 10.12

reason, with or without cause, except as may be otherwise provided in any written employment contract between Indemnitee and the Company (or any of its subsidiaries or any Enterprise), other applicable formal severance policies duly adopted by the Board, or, with respect to service as a director or officer of the Company, by the Certificate of Incorporation, the Company’s Bylaws, and the DGCL. The foregoing notwithstanding, this Agreement shall continue in force after Indemnitee has ceased to serve as a director, officer, employee and/or agent of the Company, as provided in Section 16 hereof.

Section 2. Definitions. As used in this Agreement:

(a) References to “agent” shall mean any person who is or was a director, officer, or employee of the Company or a subsidiary of the Company or other person authorized by the Company to act for the Company, to include such person serving in such capacity as a director, officer, employee, fiduciary or other official of another corporation, partnership, limited liability company, joint venture, trust or other enterprise at the request of, for the convenience of, or to represent the interests of the Company or a subsidiary of the Company.

(b) A “Change in Control” shall be deemed to have the meaning set forth, as of the date hereof, in the Talos Energy Inc. Long Term Incentive Plan.

For purposes of this Section 2(b), the following terms shall have the following meanings:

(A) “Exchange Act” shall mean the Securities Exchange Act of 1934, as amended from time to time.

(B) “Person” shall have the meaning as set forth in Sections 13(d) and 14(d) of the Exchange Act; provided, however, that Person shall exclude (i) the Company, (ii) any trustee or other fiduciary holding securities under an employee benefit plan of the Company, and (iii) any corporation owned, directly or indirectly, by the stockholders of the Company in substantially the same proportions as their ownership of stock of the Company.

(C) “Beneficial Owner” shall have the meaning given to such term in Rule 13d-3 under the Exchange Act; provided, however, that Beneficial Owner shall exclude any Person otherwise becoming a Beneficial Owner by reason of the stockholders of the Company approving a merger of the Company with another entity.

(c) “Corporate Status” describes the status of a person who is or was a director, officer, employee or agent of the Company or of any other corporation, limited liability company, partnership or joint venture, trust or other enterprise which such person is or was serving at the request of the Company.

(d) “Disinterested Director” means a director of the Company who is not and was not a party to the Proceeding in respect of which indemnification is sought by Indemnitee.

(e) “Enterprise” shall mean the Company and any other corporation, limited liability company, partnership, joint venture, trust or other enterprise of which Indemnitee is or was serving at the request of the Company as a director, officer, employee, agent or fiduciary.

(f) “Expenses” shall include all reasonable attorneys’ fees, retainers, court costs, transcript costs, fees of experts, witness fees, travel expenses, duplicating costs, printing and binding costs, telephone charges, postage, delivery service fees, any federal, state, local or foreign taxes imposed on Indemnitee as a result of the actual or deemed receipt of any payments under this Agreement, ERISA excise taxes and penalties, and all other disbursements or expenses of the types customarily incurred in connection with prosecuting, defending, preparing to prosecute or defend, investigating, being or preparing to be a witness in, or otherwise participating in, a Proceeding. Expenses also shall include (i) Expenses incurred in connection with any appeal resulting from any Proceeding, including without limitation the premium, security for, and other costs relating to any cost bond, supersedeas bond, or other appeal bond or its equivalent, and (ii) for purposes of Section 14(d) only, Expenses incurred by Indemnitee in connection with the interpretation, enforcement or defense of Indemnitee’s rights under this Agreement, by litigation or otherwise. Expenses, however, shall not include amounts paid in settlement by Indemnitee or the amount of judgments or fines against Indemnitee.

(g) “Indemnity Obligations” shall mean all obligations of the Company to Indemnitee under this Agreement, including the Company’s obligations to provide indemnification to Indemnitee and advance Expenses to Indemnitee under this Agreement.

(h) “Independent Counsel” means a law firm, or a member of a law firm, in each case, that is a nationally or internationally recognized law firm that is experienced in matters of corporation law, has adequate personnel and other resources to diligently perform its duties described herein, and neither presently is, nor in the past five years has been, retained to represent: (i) the Company or Indemnitee in any matter material to either such party (other than with respect to matters concerning the Indemnitee

Exhibit 10.12

under this Agreement, or of other indemnitees under similar indemnification agreements), or (ii) any other party to the Proceeding giving rise to a claim for indemnification hereunder. Notwithstanding the foregoing, the term “Independent Counsel” shall not include any person who, under the applicable standards of professional conduct then prevailing, would have a conflict of interest in representing either the Company or Indemnitee in an action to determine Indemnitee’s rights under this Agreement. The Company agrees to pay the reasonable fees and expenses of the Independent Counsel referred to above and to fully indemnify such counsel against any and all Expenses, claims, liabilities and damages arising out of or relating to this Agreement or its engagement pursuant hereto.

(i) The term “Proceeding” shall include any threatened, pending or completed action, suit, arbitration, alternate dispute resolution mechanism, investigation, inquiry, administrative hearing or any other actual, threatened or completed proceeding, whether brought in the right of the Company or otherwise and whether of a civil, criminal, administrative, legislative, or investigative (formal or informal) nature, including any appeal therefrom, in which Indemnitee was, is or will be involved as a party, potential party, non-party witness or otherwise by reason of the fact that Indemnitee is or was a director or officer of the Company, by reason of any action taken by him or of any action on his part while acting pursuant to his Corporate Status, or by reason of the fact that he is or was serving at the request of the Company as a director, officer, employee, agent or fiduciary of another corporation, partnership, joint venture, trust or other Enterprise, in each case whether or not serving in such capacity at the time any liability or Expense is incurred for which indemnification, reimbursement, or advancement of Expenses can be provided under this Agreement; including any Proceeding pending on or before the date of this Agreement. If the Indemnitee believes in good faith that a given situation may lead to or culminate in the institution of a Proceeding, this shall be considered a Proceeding under this paragraph.

(j) “Losses” means any and all Expenses, damages, losses, liabilities, judgments, fines, penalties (whether civil, criminal or other), amounts paid or payable in settlement, including any interest, assessments and all other charges paid or payable in connection with investigating, defending, being a witness in or participating in (including on appeal), or preparing to defend, be a witness or participate in, any Claim.

(k) Reference to “other enterprise” shall include employee benefit plans; references to “fines” shall include any excise tax assessed with respect to any employee benefit plan; references to “serving at the request of the Company” shall include any service as a director, officer, employee or agent of the Company which imposes duties on, or involves services by, such director, officer, employee or agent with respect to an employee benefit plan, its participants or beneficiaries; and a person who acted in good faith and in a manner he reasonably believed to be in the best interests of the participants and beneficiaries of an employee benefit plan shall be deemed to have acted in manner “not opposed to the best interests of the Company” as referred to in this Agreement.

Section 3. Indemnity in Third-Party Proceedings. The Company shall indemnify and hold harmless Indemnitee to the fullest extent permitted by applicable law from and against all Losses and Expenses suffered or reasonably incurred by Indemnitee or on Indemnitee’s behalf in connection with any Proceeding, other than a Proceeding by or in the right of the Company to procure a judgment in its favor, which is provided for in Section 4. Pursuant to this Section 3, Indemnitee shall be indemnified to the fullest extent permitted by applicable law against all Losses actually and reasonably incurred by Indemnitee or on his behalf in connection with such Proceeding or any claim, issue or matter therein, if Indemnitee acted in good faith and in a manner he reasonably believed to be in or not opposed to the best interests of the Company and, in the case of a criminal proceeding had no reasonable cause to believe that his conduct was unlawful.

Section 4. Indemnity in Proceedings by or in the Right of the Company. The Company shall indemnify Indemnitee to the fullest extent permitted by applicable law from and against all Losses and Expenses suffered or incurred by Indemnitee or on Indemnitee’s behalf in connection with any Proceeding brought by or in the right of the Company to procure a judgment in its favor, or any claim, issue or matter therein. No indemnification for Expenses shall be made under this Section 4 in respect of any claim, issue or matter as to which Indemnitee shall have been finally adjudged by a court to be liable to the Company, unless and only to the extent that the Delaware Court of Chancery or any court in which the Proceeding was brought shall determine upon application that, despite the adjudication of liability but in view of all the circumstances of the case, Indemnitee is fairly and reasonably entitled to indemnification.

Section 5. Indemnification for Expenses of a Party Who is Wholly or Partly Successful. Notwithstanding any other provisions of this Agreement, to the fullest extent permitted by applicable law and to the extent that Indemnitee is a party to (or a participant in) and is successful, on the merits or otherwise, in any Proceeding or in defense of any claim, issue or matter therein, in whole or in part, the Company shall indemnify Indemnitee against all Expenses actually and reasonably incurred by him in connection therewith. If Indemnitee is not wholly successful in such Proceeding but is successful, on the merits or otherwise, as to one or more but less than all claims, issues or matters in such Proceeding, the Company shall indemnify Indemnitee against all Expenses actually and reasonably incurred by him or on his behalf in connection with or related to each successfully resolved claim, issue or matter to the fullest extent

Exhibit 10.12

permitted by law. For purposes of this Section and without limitation, the termination of any claim, issue or matter in such a Proceeding by dismissal, with or without prejudice, shall be deemed to be a successful result as to such claim, issue or matter.

Section 6. Indemnification For Expenses of a Witness. Notwithstanding any other provision of this Agreement, to the fullest extent permitted by applicable law and to the extent that Indemnitee is, by reason of his Corporate Status, a witness or otherwise asked to participate in any Proceeding to which Indemnitee is not a party, he shall be indemnified against all Expenses actually and reasonably incurred by him or on his behalf in connection therewith.

Section 7. Partial Indemnification. If Indemnitee is entitled under any provision of this Agreement to indemnification by the Company for some or a portion of Expenses, but not, however, for the total amount thereof, the Company shall nevertheless indemnify Indemnitee for the portion thereof to which Indemnitee is entitled.

Section 8. Additional Indemnification.

(a) Notwithstanding any limitation in Sections 3, 4, or 5, the Company shall indemnify Indemnitee to the fullest extent permitted by applicable law if Indemnitee is a party to or threatened to be made a party to any Proceeding (including a Proceeding by or in the right of the Company to procure a judgment in its favor) against all Losses actually and reasonably incurred by Indemnitee in connection with the Proceeding.

(b) For purposes of Section 8(a), the meaning of the phrase “to the fullest extent permitted by applicable law” shall include, but not be limited to:

(i) to the fullest extent permitted by the provision of the DGCL that authorizes or contemplates additional indemnification by agreement, or the corresponding provision of any amendment to or replacement of the DGCL, and

(ii) to the fullest extent authorized or permitted by any amendments to or replacements of the DGCL adopted after the date of this Agreement that increase the extent to which a corporation may indemnify its officers and directors.

Section 9. Exclusions. Notwithstanding any provision in this Agreement, the Company shall not be obligated under this Agreement to make any indemnity in connection with any claim made against Indemnitee:

(a) for which payment has actually been made to or on behalf of Indemnitee under any insurance policy or other indemnity provision, except with respect to any excess beyond the amount paid under any insurance policy or other indemnity provision; or

(b) for (i) an accounting of profits made from the purchase and sale (or sale and purchase) by Indemnitee of securities of the Company within the meaning of Section 16(b) of the Exchange Act (as defined in Section 2(b) hereof) or similar provisions of state statutory law or common law, or (ii) any reimbursement of the Company by the Indemnitee of any bonus or other incentive-based or equity-based compensation or of any profits realized by the Indemnitee from the sale of securities of the Company, as required in each case under the Exchange Act (including any such reimbursements that arise from an accounting restatement of the Company pursuant to Section 304 of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”), or the payment to the Company of profits arising from the purchase and sale by Indemnitee of securities in violation of Section 306 of the Sarbanes-Oxley Act);

(c) to the extent that a final decision by a court of competent jurisdiction determines that such indemnification is prohibited by applicable law; or

(d) except as provided in Section 14(d) of this Agreement, in connection with any Proceeding (or any part of any Proceeding) initiated by Indemnitee, including any Proceeding (or any part of any Proceeding) initiated by Indemnitee against the Company or its directors, officers, employees or other indemnitees, unless (i) the Board authorized the Proceeding (or any part of any Proceeding) prior to its initiation or (ii) the Company provides the indemnification, in its sole discretion, pursuant to the powers vested in the Company under applicable law.

Section 10. Advances of Expenses. Notwithstanding any provision of this Agreement to the contrary (other than Section 14(d)), the Company shall advance, to the extent not prohibited by law, the Expenses incurred by Indemnitee in connection with any Proceeding (or any part of any Proceeding) not initiated by Indemnitee, and such advancement shall be made within thirty (30) days after the receipt by the Company of a statement or statements requesting such advances from time to time, whether prior to or after final disposition of any Proceeding. Such statement or statements shall reasonably evidence the Expenses incurred by Indemnitee and shall include or be preceded or accompanied by a written undertaking by or on behalf of Indemnitee to repay any Expenses advanced

Exhibit 10.12

if it shall ultimately be determined that Indemnitee is not entitled to be indemnified against such Expenses. Advances and undertaking to repay shall be unsecured and interest free. Advances shall be made without regard to Indemnitee’s ability to repay the Expenses and without regard to Indemnitee’s ultimate entitlement to indemnification under the other provisions of this Agreement. In accordance with Section 14(d), advances shall include any and all reasonable Expenses incurred pursuing an action to enforce this right of advancement, including Expenses incurred preparing and forwarding statements to the Company to support the advances claimed. This Section 10 shall not apply to any claim made by Indemnitee for which indemnity is excluded pursuant to Sections 9(a), (b) and (d).

Section 11. Procedure for Notification and Defense of Claim.

(a) Indemnitee shall notify the Company in writing of any matter with respect to which Indemnitee intends to seek indemnification or advancement of Expenses hereunder as soon as reasonably practicable following the receipt by Indemnitee of written notice thereof. The written notification to the Company shall include a description of the nature of the Proceeding and the facts underlying the Proceeding. To obtain indemnification under this Agreement, Indemnitee shall submit to the Company a written request, including therein or therewith such documentation and information as is reasonably available to Indemnitee and is reasonably necessary to determine whether and to what extent Indemnitee is entitled to indemnification following the final disposition of such Proceeding. The omission by Indemnitee to notify the Company hereunder will not relieve the Company from any liability which it may have to Indemnitee hereunder or otherwise than under this Agreement, except to the extent, and only to the extent, that the Company was materially and adversely prejudiced by such failure or delay. The Secretary of the Company shall, promptly upon receipt of such a request for indemnification, advise the Board in writing that Indemnitee has requested indemnification.

(b) The Company will be entitled to participate in the Proceeding at its own expense and, except as otherwise provided below, to the extent the Company so wishes, it may assume the defense thereof with counsel reasonably satisfactory to Indemnitee. After notice from the Company to Indemnitee of its election to assume the defense of any such matter with respect to which Indemnitee intends to seek indemnification, the Company shall not be liable to Indemnitee under this Agreement or otherwise for any Expenses subsequently incurred by Indemnitee in connection with Indemnitee’s defense of such matter other than reasonable costs of investigation or as otherwise provided below. Indemnitee shall have the right to employ its own legal counsel in such matter with respect to which Indemnitee intends to seek indemnification, but all Expenses related to such counsel incurred after notice from the Company of its assumption of the defense shall be at Indemnitee’s own expense; provided, however, that if (i) Indemnitee’s employment of its own legal counsel has been authorized by the Company, (ii) Indemnitee’s legal counsel has reasonably determined that there may be a conflict of interest between Indemnitee and the Company in the defense of such matter, (iii) after a Change in Control, Indemnitee’s employment of its own counsel has been approved by the Independent Counsel or (iv) the Company shall not in fact have employed counsel to assume the defense of such matter, then Indemnitee shall be entitled to retain its own separate counsel (but not more than one law firm plus, if applicable, local counsel in respect of any such matter) and all Expenses related to such separate counsel shall be borne by the Company subject to the terms and conditions set forth herein.

Section 12. Procedure Upon Application for Indemnification.

(a) Upon written request by Indemnitee for indemnification pursuant to Section 11(a), a determination, if required by applicable law, with respect to Indemnitee’s entitlement thereto shall be made in the specific case: (i) if a Change in Control shall have occurred, by Independent Counsel in a written opinion to the Board, a copy of which shall be delivered to Indemnitee; or (ii) if a Change in Control shall not have occurred, (A) by a majority vote of the Disinterested Directors, even though less than a quorum of the Board, (B) by a committee of Disinterested Directors designated by a majority vote of the Disinterested Directors, even though less than a quorum of the Board, (C) if there are no such Disinterested Directors or, if such Disinterested Directors so direct, by Independent Counsel in a written opinion to the Board, a copy of which shall be delivered to Indemnitee or (D) if so directed by the Board, by the stockholders of the Company; and, if it is so determined that Indemnitee is entitled to indemnification, payment to Indemnitee shall be made within ten (10) days after such determination. Indemnitee shall cooperate with the person, persons or entity making such determination with respect to Indemnitee’s entitlement to indemnification, including providing to such person, persons or entity upon reasonable advance request any documentation or information which is not privileged or otherwise protected from disclosure and which is reasonably available to Indemnitee and reasonably necessary to such determination. Any costs or Expenses (including attorneys’ fees and disbursements) incurred by Indemnitee in so cooperating with the person, persons or entity making such determination shall be borne by the Company (irrespective of the determination as to Indemnitee’s entitlement to indemnification) and the Company hereby indemnifies and agrees to hold Indemnitee harmless therefrom.

(b) In the event the determination of entitlement to indemnification is to be made by Independent Counsel pursuant to Section 12(a) hereof, the Independent Counsel shall be selected as provided in this Section 12(b). The Independent Counsel shall be selected by the Board, and the Company shall give written notice to Indemnitee advising him of the identity of the Independent Counsel so selected. Indemnitee may, within ten (10) days after such written notice of selection shall have been given, deliver to the

Exhibit 10.12

Company a written objection to such selection; provided, however, that such objection may be asserted only on the ground that the Independent Counsel so selected does not meet the requirements of “Independent Counsel” as defined in Section 2 of this Agreement, and the objection shall set forth with particularity the factual basis of such assertion. Absent a proper and timely objection, the person so selected shall act as Independent Counsel. If such written objection is so made and substantiated, the Independent Counsel so selected may not serve as Independent Counsel unless and until such objection is withdrawn or a court has determined that such objection is without merit. If, within twenty (20) days after the later of submission by Indemnitee of a written request for indemnification pursuant to Section 11(a) hereof and the final disposition of the Proceeding, no Independent Counsel shall have been selected and not objected to, either the Company or Indemnitee may petition a court of competent jurisdiction for resolution of any objection which shall have been made by the Indemnitee to the selection of Independent Counsel and/or for the appointment as Independent Counsel of a person selected by the Court or by such other person as the Court shall designate, and the person with respect to whom all objections are so resolved or the person so appointed shall act as Independent Counsel under Section 12(a) hereof. The determination made by the Independent Counsel shall be valid, binding and enforceable against both parties subject to the rights to challenge such determination as set forth in Section 14 hereof.

Section 13. Presumptions and Effect of Certain Proceedings.

(a) In making a determination with respect to entitlement to indemnification hereunder, the person or persons or entity making such determination shall, to the fullest extent not prohibited by law, presume that Indemnitee is entitled to indemnification under this Agreement if Indemnitee has submitted a request for indemnification in accordance with Section 11(a) of this Agreement, and the Company shall, to the fullest extent not prohibited by law, have the burden of proof to overcome that presumption in connection with the making by any person, persons or entity of any determination contrary to that presumption. Neither the failure of the Company (including by its directors or independent legal counsel) to have made a determination prior to the commencement of any action pursuant to this Agreement that indemnification is proper in the circumstances because Indemnitee has met the applicable standard of conduct, nor an actual determination by the Company (including by its directors or independent legal counsel) that Indemnitee has not met such applicable standard of conduct, shall be a defense to the action or create a presumption that Indemnitee has not met the applicable standard of conduct.

(b) Subject to Section 14(e), if the person, persons or entity empowered or selected under Section 12 of this Agreement to determine whether Indemnitee is entitled to indemnification shall not have made a determination within sixty (60) days after receipt by the Company of the request therefor, the requisite determination of entitlement to indemnification shall, to the fullest extent not prohibited by law, be deemed to have been made and Indemnitee shall be entitled to such indemnification, absent (i) a misstatement by Indemnitee of a material fact, or an omission of a material fact necessary to make Indemnitee’s statement not materially misleading, in connection with the request for indemnification, or (ii) a prohibition of such indemnification under applicable law; provided, however, that such 60-day period may be extended for a reasonable time, not to exceed an additional thirty (30) days, if the person, persons or entity making the determination with respect to entitlement to indemnification in good faith requires such additional time for the obtaining or evaluating of documentation and/or information relating thereto; and provided, further, that the foregoing provisions of this Section 13(b) shall not apply (i) if the determination of entitlement to indemnification is to be made by the stockholders pursuant to Section 12(a) of this Agreement and if (A) within fifteen (15) days after receipt by the Company of the request for such determination the Board has resolved to submit such determination to the stockholders for their consideration at an annual meeting thereof to be held within seventy-five (75) days after such receipt and such determination is made thereat, or (B) a special meeting of stockholders is called within fifteen (15) days after such receipt for the purpose of making such determination, such meeting is held for such purpose within sixty (60) days after having been so called and such determination is made thereat, or (ii) if the determination of entitlement to indemnification is to be made by Independent Counsel pursuant to Section 12(a) of this Agreement.

(c) The termination of any Proceeding or of any claim, issue or matter therein, by judgment, order, settlement or conviction, or upon a plea of nolo contendere or its equivalent, shall not (except as otherwise expressly provided in this Agreement) of itself adversely affect the right of Indemnitee to indemnification or create a presumption that Indemnitee did not act in good faith and in a manner which he reasonably believed to be in or not opposed to the best interests of the Company or, with respect to any criminal Proceeding, that Indemnitee had reasonable cause to believe that his conduct was unlawful.

(d) Reliance as Safe Harbor. For purposes of any determination of good faith, Indemnitee shall be deemed to have acted in good faith if Indemnitee’s action is based on the records or books of account of the Enterprise, including financial statements, or on information supplied to Indemnitee by the officers of the Enterprise in the course of their duties, or on the advice of legal counsel for the Enterprise or on information or records given or reports made to the Enterprise by an independent certified public accountant or by an appraiser or other expert selected with the reasonable care by the Enterprise. The provisions of this Section 13(d) shall not be deemed to be exclusive or to limit in any way the other circumstances in which the Indemnitee may be deemed to have met the applicable standard of conduct set forth in this Agreement.

Exhibit 10.12

(e) Actions of Others. The knowledge and/or actions, or failure to act, of any director, officer, agent or employee of the Enterprise shall not be imputed to Indemnitee for purposes of determining the right to indemnification under this Agreement.

Section 14. Remedies of Indemnitee.

(a) Subject to Section 14(e), in the event that (i) a determination is made pursuant to Section 12(a) of this Agreement that Indemnitee is not entitled to indemnification under this Agreement, (ii) advancement of Expenses is not timely made pursuant to Section 10 of this Agreement, (iii) no determination of entitlement to indemnification shall have been made by the Board pursuant to Section 12(a) of this Agreement within ninety (90) days after receipt by the Company of the request for indemnification, (iv) payment of indemnification is not made pursuant to Section 5, 6 or 7 or the last sentence of Section 12(a) of this Agreement within ten (10) days after receipt by the Company of a written request therefor, (v) payment of indemnification pursuant to Sections 3, 4 or 8 of this Agreement is not made within ten (10) days after a determination has been made that Indemnitee is entitled to indemnification, or (vi) in the event that the Company or any other person takes or threatens to take any action to declare this Agreement void or unenforceable, or institutes any litigation or other action or Proceeding designed to deny, or to recover from, the Indemnitee the benefits provided or intended to be provided to the Indemnitee hereunder, Indemnitee shall be entitled to an adjudication by a court as to whether Indemnitee is entitled to such indemnification or advancement of Expenses. Alternatively, Indemnitee, at his option, may seek an award in arbitration to be conducted by a single arbitrator pursuant to the Commercial Arbitration Rules of the American Arbitration Association. Indemnitee shall commence such proceeding seeking an adjudication or award in arbitration within 180 days following the date on which Indemnitee first has the right to commence such proceeding pursuant to this Section 14(a); provided, however, that the foregoing clause shall not apply in respect of a proceeding brought by Indemnitee to enforce his rights under Section 5 of this Agreement. The Company shall not oppose Indemnitee’s right to seek any such adjudication or award in arbitration.

(b) In the event that a determination shall have been made pursuant to Section 12(a) of this Agreement that Indemnitee is not entitled to indemnification, any judicial proceeding or arbitration commenced pursuant to this Section 14 shall be conducted in all respects as a de novo trial, or arbitration, on the merits and Indemnitee shall not be prejudiced by reason of that adverse determination. In any judicial proceeding or arbitration commenced pursuant to this Section 14 the Company shall have the burden of proving Indemnitee is not entitled to indemnification or advancement of Expenses, as the case may be.

(c) If a determination shall have been made pursuant to Section 12(a) of this Agreement that Indemnitee is entitled to indemnification, the Company shall be bound by such determination in any judicial proceeding or arbitration commenced pursuant to this Section 14, absent (i) a misstatement by Indemnitee of a material fact, or an omission of a material fact necessary to make Indemnitee’s statement not materially misleading, in connection with the request for indemnification, or (ii) a prohibition of such indemnification under applicable law.

(d) The Company shall, to the fullest extent not prohibited by law, be precluded from asserting in any judicial proceeding or arbitration commenced pursuant to this Section 14 that the procedures and presumptions of this Agreement are not valid, binding and enforceable and shall stipulate in any such court or before any such arbitrator that the Company is bound by all the provisions of this Agreement. It is the intent of the Company that, to the fullest extent permitted by law, the Indemnitee not be required to incur legal fees or other Expenses associated with the interpretation, enforcement or defense of Indemnitee’s rights under this Agreement by litigation or otherwise because the cost and expense thereof would substantially detract from the benefits intended to be extended to the Indemnitee hereunder. The Company shall, to the fullest extent permitted by law, indemnify Indemnitee against any and all Expenses and, if requested by Indemnitee, shall (within ten (10) days after receipt by the Company of a written request therefor) advance, to the extent not prohibited by law, such Expenses to Indemnitee, which are incurred by Indemnitee in connection with any action brought by Indemnitee for indemnification or advance of Expenses from the Company under this Agreement or under any directors’ and officers’ liability insurance policies maintained by the Company if, in the case of indemnification, Indemnitee is wholly successful on the underlying claims; if Indemnitee is not wholly successful on the underlying claims, then such indemnification shall be only to the extent Indemnitee is successful on such underlying claims or otherwise as permitted by law, whichever is greater.

(e) Notwithstanding anything in this Agreement to the contrary, no determination as to entitlement of Indemnitee to indemnification under this Agreement shall be required to be made prior to the final disposition of the Proceeding.

Section 15. Non-exclusivity; Survival of Rights; Insurance; Subrogation.

(a) The rights of indemnification and to receive advancement of Expenses as provided by this Agreement shall not be deemed exclusive of any other rights to which Indemnitee may at any time be entitled under applicable law, the Certificate of Incorporation, the Bylaws, any agreement, a vote of stockholders or a resolution of directors, or otherwise. No amendment, alteration or repeal of this Agreement or of any provision hereof shall limit or restrict any right of Indemnitee under this Agreement in respect of

Exhibit 10.12

any action taken or omitted by such Indemnitee in his Corporate Status prior to such amendment, alteration or repeal. To the extent that a change in Delaware law, whether by statute or judicial decision, permits greater indemnification or advancement of Expenses than would be afforded currently under the Bylaws, Certificate of Incorporation, and this Agreement, it is the intent of the parties hereto that Indemnitee shall enjoy by this Agreement the greater benefits so afforded by such change. No right or remedy herein conferred is intended to be exclusive of any other right or remedy, and every other right and remedy shall be cumulative and in addition to every other right and remedy given hereunder or now or hereafter existing at law or in equity or otherwise. The assertion or employment of any right or remedy hereunder, or otherwise, shall not prevent the concurrent assertion or employment of any other right or remedy.

(b) The Company hereby acknowledges that Indemnitee may have certain rights to indemnification, advancement and insurance provided by one or more Persons with whom or which Indemnitee may be associated (including, without limitation, any Sponsor Entity) (collectively, the “Alternative Indemnitors”). The Company hereby acknowledges and agrees that (i) the Company shall be the indemnitor of first resort with respect to any Proceeding, Expense, Loss or matter that is the subject of the Indemnity Obligations, (ii) the Company shall be primarily liable for all Indemnity Obligations and any indemnification and/or advanced expenses afforded to Indemnitee in respect of any Proceeding, Expense, Loss or matter that is the subject of Indemnity Obligations, whether created by applicable law, organizational or constituent documents, contract (including this Agreement) or otherwise, (iii) any obligation of any Alternative Indemnitors to indemnify Indemnitee or advance Expenses or Losses to Indemnitee in respect of any Proceeding shall be secondary to the obligations of the Company hereunder, (iv) the Company shall be required to indemnify Indemnitee and advance Expenses or Losses to Indemnitee hereunder to the fullest extent provided herein without regard to any rights Indemnitee may have against any Alternative Indemnitors or insurer of any such Person and (v) the Company irrevocably waives, relinquishes and releases any Alternative Indemnitors from any claim of contribution, subrogation or any other recovery of any kind in respect of amounts paid by the Company hereunder. In the event any Alternative Indemnitors or their insurers advances or extinguishes any liability or loss which is the subject of any Indemnity Obligation owed by the Company or payable under any Company insurance policy, the payor shall have a right of contribution and/or subrogation against the Company or its insurer or insurers for all amounts so paid which would otherwise be payable by the Company or its insurer or insurers under this Agreement. In no event will payment of an Indemnity Obligation by any Alternative Indemnitor or their insurers affect the obligations of the Company hereunder.

(c) To the extent that the Company maintains an insurance policy or policies providing liability insurance for directors, officers, employees, or agents of the Enterprise, Indemnitee shall be covered by such policy or policies in accordance with its or their terms to the maximum extent of the coverage available for any such director, officer, employee or agent under such policy or policies. If, at the time of the receipt of a notice of a claim pursuant to the terms hereof, the Company has director and officer liability insurance in effect, the Company shall give prompt notice of such claim or of the commencement of a Proceeding, as the case may be, to the insurers in accordance with the procedures set forth in the respective policies. The Company shall thereafter take all necessary or desirable action to cause such insurers to pay, on behalf of the Indemnitee, all amounts payable as a result of such Proceeding in accordance with the terms of such policies.

(d) In the event of any payment under this Agreement, the Company shall be subrogated to the extent of such payment to all of the rights of recovery of Indemnitee, subject to Section 15(b) above. The Indemnitee shall execute all papers required and take all action necessary to secure such rights, including execution of such documents as are necessary to enable the Company to bring suit to enforce such rights.

(e) The Company shall not be liable under this Agreement to make any payment of amounts otherwise indemnifiable (or for which advancement is provided hereunder) hereunder if and to the extent that Indemnitee has otherwise actually received such payment under any insurance policy, contract, agreement or otherwise.

(f) The Company’s obligation to indemnify or advance Expenses hereunder to Indemnitee who is or was serving at the request of the Company as a director, officer, employee or agent of any other corporation, limited liability company, partnership, joint venture, trust, employee benefit plan or other enterprise shall be reduced by any amount Indemnitee has actually received as indemnification or advancement of Expenses from such other corporation, limited liability company, partnership, joint venture, trust or other enterprise.

Section 16. Duration of Agreement. This Agreement shall continue during the period Indemnitee serves as a director or officer of the Company or as a director, officer, trustee, partner, manager, managing member, fiduciary, employee or agent of any other corporation, partnership, joint venture, trust, employee benefit plan or other enterprise which Indemnitee serves at the request of the Company and shall continue thereafter so long as Indemnitee shall be subject to any possible Proceeding, Expense, Loss or matter that is the subject of Indemnity Obligations (including any rights of appeal thereto and any Proceeding commenced by Indemnitee pursuant this Agreement) by reason of such Indemnitee’s position, whether or not Indemnitee is acting in any such capacity at the time

Exhibit 10.12

any liability or expense is incurred for which indemnification or advancement can be provided under this Agreement. This Agreement shall be binding upon the Company and its successors and assigns and shall inure to the benefit of Indemnitee and his heirs, executors and administrators. The Company shall require and cause any successor, and any direct or indirect parent of any successor, whether direct or indirect by purchase, merger, consolidation or otherwise, to all, substantially all or a substantial part, of the business and/or assets of the Company, by written agreement in form and substance satisfactory to Indemnitee, expressly to assume and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform if no such succession had taken place. This Agreement shall not be deemed an employment contract between the Company (or any of its subsidiaries or any other Enterprise) and Indemnitee. Indemnitee specifically acknowledges that Indemnitee’s employment with the Company (or any of its subsidiaries or any other Enterprise), if any, is at will, and Indemnitee may be discharged at any time for any reason, with or without cause, except as may be otherwise provided in any written employment contract between Indemnitee and the Company (or any of its subsidiaries or any other Enterprise), other applicable formal severance policies duly adopted by the Board, or, with respect to service as a director of the Company, by the Certificate of Incorporation, the Bylaws or the DGCL.

Section 17. Severability. If any provision or provisions of this Agreement shall be held to be invalid, illegal or unenforceable for any reason whatsoever: (a) the validity, legality and enforceability of the remaining provisions of this Agreement (including without limitation, each portion of any Section of this Agreement containing any such provision held to be invalid, illegal or unenforceable, that is not itself invalid, illegal or unenforceable) shall not in any way be affected or impaired thereby and shall remain enforceable to the fullest extent permitted by law; (b) such provision or provisions shall be deemed reformed to the extent necessary to conform to applicable law and to give the maximum effect to the intent of the parties hereto; and (c) to the fullest extent possible, the provisions of this Agreement (including, without limitation, each portion of any Section of this Agreement containing any such provision held to be invalid, illegal or unenforceable, that is not itself invalid, illegal or unenforceable) shall be construed so as to give effect to the intent manifested thereby.

Section 18. Enforcement; Third Party Beneficiaries.

(a) The Company expressly confirms and agrees that it has entered into this Agreement and assumed the obligations imposed on it hereby in order to induce Indemnitee to serve as a director or officer of the Company, and the Company acknowledges that Indemnitee is relying upon this Agreement in serving as a director or officer of the Company.

(b) This Agreement constitutes the entire agreement between the parties hereto with respect to the subject matter hereof and supersedes all prior agreements and understandings, oral, written and implied, between the parties hereto with respect to the subject matter hereof; provided, however, that this Agreement is a supplement to and in furtherance of the Certificate of Incorporation, the Bylaws and applicable law, and shall not be deemed a substitute therefor, nor to diminish or abrogate any rights of Indemnitee thereunder

Section 19. Mutual Acknowledgment. Both the Company and Indemnitee acknowledge that in certain instances, federal law or public policy may override applicable state law and prohibit the Company from indemnifying its directors and officers under this Agreement or otherwise. For example, the Company and Indemnitee acknowledge that the Securities and Exchange Commission (the “SEC”) has taken the position that indemnification is not permissible for liabilities arising under certain federal securities laws, and federal legislation prohibits indemnification for certain ERISA violations. Indemnitee understands and acknowledges that the Company has undertaken or may be required in the future to undertake with the SEC to submit the question of indemnification to a court in certain circumstances for a determination of the Company’s right under public policy to indemnify Indemnitee.

Section 20. Modification and Waiver. No supplement, modification or amendment of this Agreement shall be binding unless executed in writing by the parties hereto. No waiver of any of the provisions of this Agreement shall be deemed or shall constitute a waiver of any other provisions of this Agreement nor shall any waiver constitute a continuing waiver;

Section 21. Notice by Indemnitee. Indemnitee agrees promptly to notify the Company in writing upon being served with any summons, citation, subpoena, complaint, indictment, information or other document relating to any Proceeding or matter which may be subject to indemnification or advancement of Expenses covered hereunder. The failure of Indemnitee to so notify the Company shall not relieve the Company of any obligation which it may have to the Indemnitee under this Agreement or otherwise.

Section 22. Notices. All notices, requests, demands and other communications under this Agreement shall be in writing and shall be deemed to have been duly given if (a) delivered by hand and receipted for by the party to whom said notice or other communication shall have been directed, (b) mailed by certified or registered mail with postage prepaid, on the third business day after the date on which it is so mailed, (c) mailed by reputable overnight courier and receipted for by the party to whom said notice or other communication shall have been directed or (d) sent by facsimile transmission, with receipt of oral confirmation that such transmission has been received:

Exhibit 10.12

(a) If to Indemnitee, at the address indicated on the signature page of this Agreement, or such other address as Indemnitee shall provide to the Company.

(b) If to the Company to

Talos Energy Inc.

333 Clay Street, Suite 3300

Houston, TX 77002

Attn: General Counsel

or to any other address as may have been furnished to Indemnitee by the Company.

Section 23. Contribution. To the fullest extent permissible under applicable law, if the indemnification provided for in this Agreement is unavailable in whole or part to Indemnitee for any reason whatsoever, the Company, in lieu of indemnifying Indemnitee, shall contribute to the amount incurred by Indemnitee, whether for judgments, fines, penalties, excise taxes, amounts paid or to be paid in settlement and/or for Expenses, in connection with any claim relating to an indemnifiable event under this Agreement, in such proportion as is deemed fair and reasonable in light of all of the circumstances of such Proceeding in order to reflect (i) the relative benefits received by the Company and Indemnitee as a result of the event(s) and/or transaction(s) giving cause to such Proceeding; and/or (ii) the relative fault of the Company (and its directors, officers, employees and agents) and Indemnitee in connection with such event(s) and/or transaction(s).

Section 24. Applicable Law and Consent to Jurisdiction. This Agreement and the legal relations among the parties shall be governed by, and construed and enforced in accordance with, the laws of the State of Delaware, without regard to its conflict of laws rules. Except with respect to any arbitration commenced by Indemnitee pursuant to Section 14(a) of this Agreement, the Company and Indemnitee hereby irrevocably and unconditionally (i) agree that any action or proceeding arising out of or in connection with this Agreement shall be brought only in the Chancery Court of the State of Delaware (the “Delaware Court”), and not in any other state or federal court in the United States of America or any court in any other country, (ii) consent to submit to the exclusive jurisdiction of the Delaware Court for purposes of any action or proceeding arising out of or in connection with this Agreement, (iii) appoint, to the extent such party is not otherwise subject to service of process in the State of Delaware, irrevocably RL&F Service Corp., One Rodney Square, 10th Floor, 10th and King Streets, Wilmington, Delaware 19801 as its agent in the State of Delaware as such party’s agent for acceptance of legal process in connection with any such action or proceeding against such party with the same legal force and validity as if served upon such party personally within the State of Delaware, (iv) waive any objection to the laying of venue of any such action or proceeding in the Delaware Court, and (v) waive, and agree not to plead or to make, any claim that any such action or proceeding brought in the Delaware Court has been brought in an improper or inconvenient forum.

Section 25. Identical Counterparts. This Agreement may be executed in one or more counterparts, each of which shall for all purposes be deemed to be an original but all of which together shall constitute one and the same Agreement. Only one such counterpart signed by the party against whom enforceability is sought needs to be produced to evidence the existence of this Agreement.

Section 26. Miscellaneous. Use of the masculine pronoun shall be deemed to include usage of the feminine pronoun where appropriate. The headings of this Agreement are inserted for convenience only and shall not be deemed to constitute part of this Agreement or to affect the construction thereof.

[Signature Page Follows]

Exhibit 10.12

IN WITNESS WHEREOF, the parties have caused this Agreement to be signed as of the day and year first above written.

TALOS ENERGY INC.	INDEMNITEE
By:	By:
Name:	Name:
Title:	Address:

[Signature Page to Talos Energy Inc. Indemnification Agreement]

EX-10.33

Exhibit 10.33

Execution Version

TENTH AMENDMENT
TO CREDIT AGREEMENT

THIS TENTH AMENDMENT TO CREDIT AGREEMENT (this “Amendment”), dated as of January 13, 2024 is among TALOS ENERGY INC., a Delaware corporation (“Holdings”), TALOS PRODUCTION INC., a Delaware corporation (as successor-by-conversion to Talos Production LLC, a Delaware limited liability company) and a direct or indirect Subsidiary of Holdings (the “Borrower”), each other Credit Party, JPMORGAN CHASE BANK, N.A., as the Administrative Agent (the “Administrative Agent”), and each Lender party hereto.

WITNESSETH:

WHEREAS, reference is made to that certain Credit Agreement, dated as of May 10, 2018, among Holdings, the Borrower, the Administrative Agent, the Issuing Banks, the Lenders party thereto, and the other Persons from time to time party thereto (as amended, supplemented, waived or otherwise modified from time to time prior to the date hereof, the “Existing Credit Agreement”; and the Existing Credit Agreement, as amended hereby upon the occurrence (but only if it shall occur) of the Amendment Effective Date, the “Credit Agreement”); and

WHEREAS, the Borrower has informed the Administrative Agent, the Issuing Banks and the Lenders that QuarterNorth Energy Inc., a Delaware corporation (the “Target”), the Borrower and certain of its Affiliates entered that certain Agreement and Plan of Merger dated as of January 13, 2024 (the “Acquisition Agreement”), pursuant to which, after giving effect to a series of transactions, the Borrower shall acquire the Equity Interests of the Target (such acquisition, the “Acquisition”); and

WHEREAS, in connection with the Acquisition, the consideration to be paid by the Borrower shall consist of one or more of the issuance of Equity Interests of Holdings, cash proceeds received by the Borrower from substantially concurrent equity contributions or issuance of new Equity Interests, new junior lien Indebtedness, or one or more Borrowings under the Credit Agreement, or cash-on-hand available to the Borrower at such time; and

WHEREAS, the Borrower has provided to the Administrative Agent and the Lenders a reserve report dated as of September 30, 2023 (the “QuarterNorth Acquisition Reserve Report”), with respect to the Oil and Gas Properties to be acquired by the Borrower as a result of the Acquisition; and

WHEREAS, each of Holdings and the Borrower desires to amend the Existing Credit Agreement on the terms and subject to the conditions set forth herein; and

WHEREAS, Section 13.1 of the Existing Credit Agreement provides that Holdings, the Borrower, the Issuing Banks and the Lenders may amend the Existing Credit Agreement and the other Credit Documents in accordance with the provisions thereof;

NOW, THEREFORE, in consideration of the foregoing premises and the mutual agreements set forth herein, the parties hereto agree as follows:

Section 1.Definitions. Unless otherwise defined in this Amendment, each capitalized term used in this Amendment has the meaning assigned to such term in the Existing Credit Agreement.

Section 2.Borrowing Base Redetermination; Total Commitment.

1

(a)If the Amendment Effective Date occurs, then on the Amendment Effective Date, the Borrower and the Lenders party hereto agree that (i) the Borrowing Base shall be, and hereby is, maintained at $1,075,000,000 until such time as the Borrowing Base is redetermined or otherwise adjusted pursuant to the terms of the Credit Agreement and (ii) the Total Commitment is, and shall remain, $965,000,000.

(b)Both the Borrower, on the one hand, and the Administrative Agent and the Lenders, on the other hand, agree that the redetermination of the Borrowing Base pursuant to Section 2(a) hereof shall constitute the Scheduled Redetermination of the Borrowing Base for the fall of 2023 and shall not constitute an Interim Redetermination of the Borrowing Base pursuant to Section 2.14(b) of the Credit Agreement.

(c)Unless otherwise agreed or waived in writing by the Administrative Agent and each Lender, the Borrower hereby covenants and agrees that it shall not initiate an Incremental Increase pursuant to Section 2.16 of the Credit Agreement, or otherwise request an increase of the Total Commitment, until the earlier of (i) the date on which the next Scheduled Redetermination occurs pursuant to the terms of the Credit Agreement or (ii) the first date on which each of the post-closing covenants set forth in Section 7 have been satisfied.

Section 3.Amendments to Existing Credit Agreement. If the Amendment Effective Date occurs, then on the Amendment Effective Date, the body of the Existing Credit Agreement (but, for the avoidance of doubt, not the exhibits orschedules) is hereby amended by deleting the stricken text (indicated textually in the same manner as the following example: stricken text) and by inserting the double-underlined text (indicated textually in the same manner as the following example: double-underlined text) as set forth in the Credit Agreement attached as Exhibit A hereto;

Section 4.Representations and Warranties, Etc. To induce the Administrative Agent, the Lenders and Issuing Banks to enter into this Amendment, the Borrower and Holdings represent and warrant to the Administrative Agent, the Issuing Banks and the Lenders that on and as of the Amendment Effective Date:

(a)each representation and warranty made by any Credit Party contained in the Existing Credit Agreement or in the other Credit Documents is true and correct in all material respects (except for representations and warranties that are qualified by a materiality qualifier, which shall be true and correct in all respects) with the same effect as though such representations and warranties had been made on and as of the Amendment Effective Date, except where such representations and warranties expressly relate to an earlier date, in which case such representations and warranties shall have been true and correct in all material respects (except for representations and warranties that are qualified by a materiality qualifier, which shall be true and correct in all respects) as of such earlier date;

(b)each Credit Party executing this Amendment has the corporate or other organizational power and authority to execute, deliver and carry out the terms and provisions of this Amendment and has taken all necessary corporate or other organizational action to authorize the execution, delivery and performance of this Amendment;

(c)the Existing Credit Agreement and each other Credit Document constitutes the legal, valid and binding obligation of such Credit Party enforceable in accordance with its terms, subject to the effects of bankruptcy, insolvency, fraudulent conveyance, reorganization and other similar laws relating to or affecting creditors’ rights generally and general principles of equity (whether considered in a proceeding in equity or law); and

2

(d)no Default, Event of Default or Borrowing Base Deficiency exists under the Existing Credit Agreement or any of the other Credit Documents.

Section 5.Ratification; Reaffirmation of Security Documents.

(a)Each of Holdings, the Borrower and each other Credit Party hereby ratifies and confirms, on and as of the Amendment Effective Date, (i) the covenants and agreements contained in each Credit Document to which it is a party, including, in each case, as such covenants and agreements may be modified by this Amendment and the transactions contemplated thereby and (ii) all of the Obligations under the Existing Credit Agreement and the other Credit Documents.

(b)Each of Holdings, the Borrower and each other Credit Party (i) reaffirms the terms of and its obligations (and the security interests granted by it) under each Security Document, and agrees that each such Security Document will continue in full force and effect to secure the Obligations as the same may be amended, supplemented, or otherwise modified from time to time and (ii) acknowledges, represents, warrants and agrees that the Liens and security interests granted by it pursuant to the Security Documents are valid and subsisting and create a security interest to secure the Obligations.

Section 6.Effectiveness. This Amendment shall become effective (the “Amendment Effective Date”) upon receipt by the Administrative Agent of executed counterparts of this Amendment from Holdings, the Borrower, each other Credit Party, the Administrative Agent, and the Lenders constituting at least the Required Lenders.

Section 7.Post-Closing Covenant and Consummation of the Acquisition. The Borrower hereby covenants and agrees that, concurrently with the consummation of the Acquisition (the “Acquisition Date”):

(a)Resolutions; Organizational Documents; Secretary’s Certificates. The Administrative Agent shall receive, in the case of the Target and each of its Subsidiaries (each a “New Credit Party”, and collectively, the “New Credit Parties”), each of the items referred to in subclauses (i), (ii) and (iii) below:

(i)the certificate or articles of incorporation, certificate of limited partnership or certificate of formation, including all amendments thereto, of each New Credit Party, in each case, certified as of a recent date by the Secretary of State (or other similar official) of the jurisdiction of its organization, and a certificate as to the continued existence and good standing (to the extent such concept or a similar concept exists under the laws of such jurisdiction) of each such New Credit Party as of a recent date from such Secretary of State (or other similar official);

(ii)a certificate of the Secretary, an Assistant Secretary or similar officer of each New Credit Party dated the Acquisition Date and certifying:

(A)that either (x) attached thereto is a true and complete copy of the bylaws, partnership agreement, limited liability company agreement or other equivalent governing documents, as applicable, of such New Credit Party as in effect on the Acquisition Date or (y) no amendments, supplements or modifications have been made to such New Credit Party’s bylaws, partnership agreement, limited liability company agreement or other equivalent governing documents since the date on which such New Credit Party most recently delivered a certified copy of such New Credit Party’s bylaws, partnership agreement, limited liability company agreement or other equivalent governing documents to the Administrative Agent,

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(B)that attached thereto is a true and complete copy of resolutions duly adopted by the board of directors (or managing general partner, managing member or equivalent) of such New Credit Party authorizing the execution, delivery and performance of each Credit Document to which such person is a party and that such resolutions have not been modified, rescinded or amended since the date of their adoption and are in full force and effect on the Acquisition Date,

(C)that the certificate or articles of incorporation, certificate of limited partnership, articles of incorporation or certificate of formation of such New Credit Party has not been amended since the date of their certification by the Secretary of State (or other similar official) of the jurisdiction of its organization as described in subclause (i) above, and

(D)as to the absence of any pending proceeding for the dissolution or liquidation of such Credit Party; and

(iii)a certificate as to the incumbency and specimen signature of each officer authorized to execute any Credit Document or any other document delivered in connection herewith or therewith on behalf of such New Credit Party (and including the incumbency and specimen signatures of each officer providing the certificate delivered pursuant to subclause (ii) above).

(b)Termination of QuarterNorth Credit Agreements. The Administrative Agent shall be reasonably satisfied that concurrently with (or prior to) the Acquisition Date, the Target shall have repaid in full all outstanding “Loans” and other “Obligations” outstanding under (i) that certain Third Amended and Restated First Lien Term Loan Agreement dated as of August 27, 2021 by and among the Target, QuarterNorth Energy Holding Inc., Goldman Sachs Bank USA and the other lenders party thereto, as such agreement may be amended, restated, supplemented or otherwise modified from time to time (the “QuarterNorth Credit Agreement”) and (ii) that certain Second Term Loan Agreement dated as of August 27, 2021 by and among the Target, QuarterNorth Energy Holding Inc., Cantor Fitzgerald Securities and the other lenders party thereto, as such agreement may be amended, restated, supplemented or otherwise modified from time to time (the “QuarterNorth 2L Credit Agreement”), and the QuarterNorth Credit Agreement, the QuarterNorth 2L Credit Agreement, and all other “Loan Documents” (as defined in the QuarterNorth Credit Agreement and QuarterNorth 2L Credit Agreement, respectively), including the commitments of the lenders and the letter of credit issuers thereunder to extend credit, shall be terminated, and all Liens securing such “Loans” and other “Obligations” shall have been released.

(c)Notice of Borrowing. If the Borrower intends to use the proceeds of any Borrowings to consummate the Acquisition (or for any other purpose permitted by the Credit Agreement) on the Acquisition Date, the Administrative Agent shall receive a Notice of Borrowing in accordance with Section 2.3 of the Credit Agreement with respect to any such Borrowings.

(d)Certificate Regarding Consummation of Acquisition. The Administrative Agent shall receive a certificate of an Authorized Officer of the Borrower certifying that (i) the Acquisition has been consummated, or concurrently with the Acquisition Date (including after giving effect to the application of the proceeds of any Borrowings to be made on the Acquisition Date, if any), will be consummated, in all material respects in accordance with the terms of the Acquisition Agreement, without giving effect to any modification, consent or waiver thereto that is materially adverse to the interests of the Administrative Agent, the Collateral Agent, the Lenders or the Issuing Banks (each, in their capacities as such) without the consent of each of the Administrative Agent, the Collateral Agent, the Lenders and the Issuing Banks, (ii) both before and after giving effect to the consummation of the Acquisition and the transactions

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contemplated thereby and by this Amendment, each representation and warranty made by any Credit Party contained in the Credit Agreement or in the other Credit Documents is true and correct in all material respects (except for representations and warranties that are qualified by a materiality qualifier, which shall be true and correct in all respects) with the same effect as though such representations and warranties had been made on and as of the Acquisition Date, except where such representations and warranties expressly relate to an earlier date, in which case such representations and warranties shall have been true and correct in all material respects (except for representations and warranties that are qualified by a materiality qualifier, which shall be true and correct in all respects) as of such earlier date and (iii) both before and after giving effect to the consummation of the Acquisition and the transactions contemplated thereby and by this Amendment, no Default, Event of Default or Borrowing Base Deficiency exists under the Credit Agreement or any of the other Credit Documents.

(e)Title. The Credit Parties shall deliver to the Administrative Agent satisfactory title information with respect to Oil and Gas Properties of the Credit Parties constituting Proved Reserves evaluated in the most recently delivered Reserve Report comprising, together with title information previously delivered to the Administrative Agent, at least 85% of the PV-10 of such Proved Reserves on a pro-forma consolidated basis.

(f)Lien Searches. The Administrative Agent shall receive (i) customary UCC lien search results with respect to the New Credit Parties in their respective jurisdictions of formation and (ii) county-level real property search results for the counties in which the Oil and Gas Properties of the New Credit Parties constituting Proved Reserves evaluated in the QuarterNorth Acquisition Reserve Report (the “QuarterNorth Oil & Gas Properties”) are located.

(g)Additional Guarantors, Grantors and Collateral.

(i)New Credit Parties. The Collateral Agent shall receive from an Authorized Officer of each New Credit Party (A) an executed and delivered supplement to the Guarantee, substantially in the form of Exhibit I thereto, pursuant to which such New Credit Party shall become a Guarantor, (B) an executed and delivered supplement to the Collateral Agreement, substantially in the form of Exhibit I thereto, pursuant to which such Subsidiary shall become a grantor and a pledgor thereunder, and (C) an executed and delivered joinder to the Intercompany Note.

(ii)Pledge of Target Equity Interests and Indebtedness. The Collateral Agent shall receive from an Authorized Officer of the Borrower (A) an executed and delivered supplement to the Collateral Agreement, substantially in the form of Exhibit I thereto, pursuant to which the Borrower shall, subject to any applicable limitations set forth in the Collateral Agreement, pledge (i) all of the Equity Interests (other than any Excluded Equity Interests) of the Target and (ii) except with respect to intercompany Indebtedness, all evidences of Indebtedness for borrowed money in a principal amount in excess of $20,000,000 (individually) that is owing to the Borrower or any Guarantor (which shall be evidenced by a promissory note) and (B) all certificates, if any, representing such securities pledged under the Collateral Agreement pursuant to this subclause (ii), accompanied by instruments of transfer and/or undated powers endorsed in blank.

(iii)Mortgages.

(A)The Collateral Agent shall receive Mortgages and any ancillary documents required by any local jurisdiction for the recordation of such Mortgages (including, but not limited to, tax petitions, supporting affidavits, or orders), executed and delivered by a duly Authorized Officer of each applicable Credit Party in sufficient counterparts for the prompt

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recordation thereof, encumbering the same QuarterNorth Oil & Gas Properties that are, or will be, encumbered as of the Acquisition Date to secure the QuarterNorth Acquisition Debt.

(B)The Collateral Agent shall receive Mortgages and any ancillary documents required by any local jurisdiction for the recordation of such Mortgages (including, but not limited to, tax petitions, supporting affidavits, or orders), executed and delivered by a duly Authorized Officer of each applicable Credit Party in sufficient counterparts for the prompt recordation thereof, together with the PV-10 of the Mortgaged Properties that were encumbered by a previously delivered Mortgage, sufficient to satisfy the Collateral Coverage Minimum (after giving effect to the consummation of the QuarterNorth Acquisition and any Mortgages delivered pursuant to Section 7(g)(iii)(A) above).

(iv)Financing Statements. All Uniform Commercial Code or other applicable personal property and financing statements reasonably requested by the Collateral Agent to be filed, registered or recorded to create the Liens intended to be created by any Security Document and perfect such Liens to the extent required by, and with the priority required by, such Security Document shall be delivered to the Collateral Agent for filing, registration or recording and none of the Collateral shall be subject to any other pledges, security interests or mortgages, except for Liens permitted under Section 10.2 of the Credit Agreement.

(h)Intercreditor Agreement. The Administrative Agent shall receive a written notice from the Borrower designating the QuarterNorth Acquisition Debt as an additional “Second Lien Facility” under (and as defined in) the Intercreditor Agreement and a joinder agreement to the Intercreditor Agreement (or other appropriate acknowledgment or amendment documentation) in form and substance reasonable acceptable to the Administrative Agent executed and delivered by the representative(s) of any QuarterNorth Acquisition Debt as Second Lien Obligations, in each case, in accordance with the Intercreditor Agreement.

(i)Legal Opinion. The Administrative Agent shall receive a written opinion of (i) Vinson & Elkins LLP, counsel to the Borrower and the New Credit Parties, and (ii) local counsel in each jurisdiction where a Mortgage delivered pursuant to Section 7(g)(iii) of this Amendment is expected to be recorded to perfect first priority Liens on any QuarterNorth Oil & Gas Properties, in each case (A) dated as of the Acquisition Date, (B) addressed to the Administrative Agent, the Collateral Agent, the Lenders and each Issuing Bank and (C) in form and substance reasonably satisfactory to the Administrative Agent. The Borrower and the other Credit Parties hereby instruct such counsels to deliver such legal opinions.

(j)Know Your Customer. The Administrative Agent and the Lenders shall have received, at least three (3) Business Days prior to the Acquisition Date, all documentation and other information about the New Credit Parties as has been reasonably requested in writing at least five (5) Business Days prior to the Acquisition Date by the Administrative Agent and the Lenders that they reasonably determine is required by regulatory authorities under applicable “know your customer” and anti-money laundering rules and regulations, including without limitation the PATRIOT Act.

(k)Fees and Expenses. The Borrower shall make payment of all fees and expenses due and owing under the Credit Agreement and under any separate fee letter entered into by the Borrower (or one or more of its Affiliates) and the Administrative Agent (or one or more of its Affiliates).

The Administrative Agent shall notify the Borrower and the Lenders of the Acquisition Date and the satisfaction of the covenants required by this Section 7, and such notice shall be conclusive and binding.

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Section 8.Post-Acquisition Covenants. The Borrower hereby covenants and agrees that, within 60 days following the Acquisition Date

(a)Title. The Administrative Agent shall receive satisfactory title information with respect to the QuarterNorth Oil & Gas Properties comprising at least 85% of the PV‑10 of all such QuarterNorth Oil & Gas Properties.

(b)Mortgages. The Collateral Agent shall receive Mortgages and any ancillary documents required by any local jurisdiction for the recordation of such Mortgages (including, but not limited to, tax petitions, supporting affidavits, or orders), executed and delivered by a duly Authorized Officer of each applicable Credit Party in sufficient counterparts for the prompt recordation thereof, encumbering the greater of (i) 85% of the PV-10 of all of the QuarterNorth Oil & Gas Properties and (ii) the same QuarterNorth Oil & Gas Properties that are, or will be, encumbered as of such date to secure the QuarterNorth Acquisition Debt.

(c)Legal Opinion. The Administrative Agent shall receive a written opinion of (i) Vinson & Elkins LLP, counsel to the Borrower and the New Credit Parties, and (ii) local counsel in each jurisdiction where a Mortgage delivered pursuant to Section 8(b) of this Amendment is expected to be recorded to perfect first priority Liens on any QuarterNorth Oil & Gas Properties, in each case (A) dated as of the date of such Mortgage(s), (B) addressed to the Administrative Agent, the Collateral Agent, the Lenders and each Issuing Bank and (C) in form and substance reasonably satisfactory to the Administrative Agent. The Borrower and the other Credit Parties hereby instruct such counsels to deliver such legal opinions.

Section 9.Counterparts. This Amendment may be executed by one or more of the parties to this Amendment on any number of separate counterparts (including by facsimile or other electronic transmission, i.e. a “pdf” or a “tif”), and all of said counterparts taken together shall be deemed to constitute one and the same instrument. A set of the copies of this Amendment signed by all the parties shall be lodged with the Borrower and the Administrative Agent.

Section 10.Severability. Any provision of this Amendment that is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

Section 11.Integration. This Amendment and the other Credit Documents represent the agreement of the Borrower, the Guarantors, the Collateral Agent, the Administrative Agent and the Lenders with respect to the subject matter hereof and thereof, and there are no promises, undertakings, representations or warranties by the Borrower, the Guarantors, the Collateral Agent, the Administrative Agent or any Lender relative to subject matter hereof not expressly set forth or referred to herein or in the other Credit Documents.

Section 12.GOVERNING LAW. THIS AMENDMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK.

Section 13.Successors and Assigns. This Amendment shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted under the Existing Credit Agreement and the Credit Agreement, as applicable (including any Affiliate of each Issuing Bank that issues any Letter of Credit).

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Section 14.Miscellaneous. (a) On and after the Amendment Effective Date, each reference in each Credit Document to “the Credit Agreement”, “thereunder”, “thereof” or words of like import referring to the Credit Agreement shall mean and be a reference to the Credit Agreement as amended, waived or otherwise modified by this Amendment and (b) this Amendment is a Credit Document executed pursuant to the Existing Credit Agreement and the Credit Agreement, as applicable, and shall (unless otherwise expressly indicated therein) be construed, administered and applied in accordance with the terms and provisions of the Existing Credit Agreement and the Credit Agreement, as applicable.

(Remainder of Page Left Intentionally Blank)

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IN WITNESS WHEREOF, each of the parties hereto has caused a counterpart of this Amendment to be duly executed and delivered as of the Amendment Effective Date.

TALOS ENERGY INC.,

as Holdings

By: /s/ Sergio Maiworm

Name: Sergio Maiworm

Title: Chief Financial Officer and Senior Vice President

TALOS PRODUCTION INC.,

as the Borrower

By: /s/ Sergio Maiworm

Name: Sergio Maiworm

Title: Chief Financial Officer and Senior Vice President

Signature Page to Tenth Amendment to Credit Agreement

TALOS ERT LLC,

TALOS ENERGY PHOENIX LLC,

TALOS ENERGY OFFSHORE LLC,

TALOS GULF COAST LLC,

TALOS GULF COAST OFFSHORE LLC,

TALOS GULF COAST ONSHORE LLC,

ANRP (TALOS DC), LLC,

CKB PETROLEUM, LLC,

TALOS PETROLEUM LLC,

STONE ENERGY HOLDING, L.L.C.,

TALOS RESOURCES LLC,

TALOS ENERGY HOLDINGS LLC,

TALOS ENERGY LLC,

TALOS ENERGY OPERATING COMPANY LLC,

TALOS PRODUCTION FINANCE INC.,

TALOS ENERGY INTERNATIONAL LLC and

TALOS OIL AND GAS LLC,

TALOS EXPLORATION LLC,

TALOS THIRD COAST LLC,

TALOS ENERGY VENTURES GOM LLC,

TALOS ENERGY CORPORATION SUB LLC,

TALOS ENERGY VENTURES HOLDING, LLC,

TALOS FINANCE CORPORATION,

TALOS ENERGY VENTURES, LLC

as Credit Parties

By: /s/ Sergio Maiworm

Name: Sergio Maiworm

Title: Chief Financial Officer and Senior Vice President

Talos International Holdings SCS, a limited partnership (société en commandite simple), having its registered office address at 6, rue Eugène Ruppert, L-2453 Luxembourg and registered with the RCS Luxembourg under number B 240.942 acting by its general partner, ANRP (Talos DC), LLC, itself represented by:

By: /s/ Sergio Maiworm

Name: Sergio Maiworm

Title: Chief Financial Officer and Senior Vice President

Signature Page to Tenth Amendment to Credit Agreement

JPMORGAN CHASE BANK, N.A., as Administrative Agent and as a Lender

By: /s/ Jason R. Williams

Name: Jason R. Williams

Title: Authorized Officer

Signature Page to Tenth Amendment to Credit Agreement

DNB Capital LLC,

as a Lender

By: /s/ Kevin Utsey

Name: Kevin Utsey

Title: Senior Vice President

By: /s/ George Philippopoulous

Name: George Philippopoulous

Title: Senior Vice President

Capital One, National Association,

as a Lender

By: /s/ Jason Groll

Name: Jason Groll

Title: Vice President

Keybank National Association,

as a Lender

By: /s/ George McKean

Name: George McKean

Title: Senior Vice President

Societe Generale,

as a Lender

By: /s/ Eric Kim

Name: Eric Kim

Title: Managing Director

CITIBANK, N.A.,

as a Lender

By: /s/ Jeff Ard

Name: Jeff Ard

Title: Vice President

Signature Page to Tenth Amendment to Credit Agreement

Mizuho Bank, Ltd.,

as a Lender

By: /s/ Edward Sacks

Name: Edward Sacks

Title: Executive Director

Regions Bank,

as a Lender

By: /s/ David Valentine

Name: David Valentine

Title: Managing Director

Goldman Sachs Bank USA,

as a Lender

By: /s/ Piryankush Goswami

Name: Piryankush Goswami

Title: Authorized Signatory

Morgan Stanley Senior Funding, Inc.,

as a Lender

By: /s/ Rikin Pandya

Name: Rikin Pandya

Title: Vice President

Signature Page to Tenth Amendment to Credit Agreement

Exhibit ATO TENTH AMENDMENT TO CREDIT AGREEMENT

ADDED TEXT SHOWN UNDERSCORED

DELETED TEXT SHOWN STRIKETHROUGH

CREDIT AGREEMENT

Dated as of May 10, 2018

among

TALOS ENERGY, INC.,
as Holdings,

TALOS PRODUCTION INC.,
as successor-by-conversion to Talos Production LLC,
as the Borrower,

The Several Lenders
from Time to Time Parties Hereto,

JPMORGAN CHASE BANK, N.A.,
as Administrative Agent, Collateral Agent, and Swingline Lender

JPMORGAN CHASE BANK, N.A., DNB BANK ASA, NEW YORK BRANCH, CAPITAL
ONE, NATIONAL ASSOCIATION, KEYBANK NATIONAL ASSOCIATION and
MIZUHO BANK, LTD.,
as Issuing Banks

and

JPMORGAN CHASE BANK, N.A., DNB MARKETS, INC., CAPITAL ONE, NATIONAL
ASSOCIATION, KEYBANC CAPITAL MARKETS INC., SOCIÉTÉ GÉNÉRALE,
CITIBANK, N.A. and MIZUHO BANK, LTD.,
as Lead Arrangers

DNB MARKETS, INC., CAPITAL ONE, NATIONAL ASSOCIATION, KEYBANC
CAPITAL MARKETS INC., SOCIÉTÉ GÉNÉRALE, CITIBANK, N.A. and
MIZUHO BANK, LTD.,
as Syndication Agents

REGIONS BANK,
as Documentation Agent

_____________________________

JPMORGAN CHASE BANK, N.A., DNB MARKETS, INC., CAPITAL ONE, NATIONAL
ASSOCIATION, KEYBANC CAPITAL MARKETS INC., and SOCIÉTÉ GÉNÉRALE,
as Joint Bookrunners

_____________________________

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Table of Contents

Page

SECTION 1. Definitions 3

1.1 Defined Terms 3

1.2 Other Interpretive Provisions 71

1.3 Accounting Terms 71

1.4 Rounding 72

1.5 References to Agreements, Laws, Etc. 7372

1.6 Times of Day 72

1.7 Timing of Payment or Performance 72

1.8 Currency Equivalents Generally 73

1.9 Classification of Loans and Borrowings 73

1.10 Interest Rates; Benchmark Notification 74

1.11 Letter of Credit Amounts 74

1.12 Divisions 7574

SECTION 2. Amount and Terms of Credit 75

2.1 Commitments 75

2.2 Minimum Amount of Each Borrowing; Maximum Number of Borrowings 76

2.3 Notice of Borrowing 7776

2.4 Disbursement of Funds 7877

2.5 Repayment of Loans; Evidence of Debt 7978

2.6 Conversions and Continuations 79

2.7 Pro Rata Borrowings 80

2.8 Interest 8180

2.9 Interest Periods 81

2.10 Increased Costs 82

2.11 Compensation 83

2.12 Change of Lending Office 84

2.13 Notice of Certain Costs 84

2.14 Borrowing Base 8584

2.15 Defaulting Lenders 89

2.16 Increase of Total Commitment 9291

2.17 [Intentionally Omitted] 92

2.18 Alternate Rate of Interest 9392

SECTION 3. Letters of Credit 94

3.1 Letters of Credit 94

3.2 Letter of Credit Applications 9796

3.3 Letter of Credit Participations 9897

3.4 Agreement to Repay Letter of Credit Drawings 99

3.5 Increased Costs 102101

3.6 New or Successor Issuing Bank 103102

3.7 Role of Issuing Bank 104103

3.8 Cash Collateral 105104

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3.9 Existing Letters of Credit 105

3.10 Applicability of ISP and UCP 106105

3.11 Conflict with Issuer Documents 106105

3.12 Letters of Credit Issued for Restricted Subsidiaries 106105

3.13 Alternate Currency 106105

SECTION 4. Fees; Commitment 105

4.1 Fees 105

4.2 Voluntary Reduction of Commitments 106

4.3 Mandatory Termination of Commitments 108107

SECTION 5. Payments 107

5.1 Voluntary Prepayments 107

5.2 Mandatory Prepayments 109108

5.3 Method and Place of Payment 111110

5.4 Net Payments 112111

5.5 Computations of Interest and Fees 116115

5.6 Limit on Rate of Interest 116115

SECTION 6. Conditions Precedent to Initial Borrowing 117116

SECTION 7. Conditions Precedent to All Subsequent Credit Events 120

SECTION 8. Representations, Warranties and Agreements 122121

8.1 Corporate Status 121

8.2 Corporate Power and Authority; Enforceability 123121

8.3 No Violation 123122

8.4 Litigation 123122

8.5 Margin Regulations 123122

8.6 Governmental Approvals 123122

8.7 Investment Company Act 124122

8.8 True and Complete Disclosure 124122

8.9 Financial Condition; Financial Statements 124123

8.10 Tax Matters 125123

8.11 Compliance with ERISA 125124

8.12 Subsidiaries 126125

8.13 Intellectual Property 126125

8.14 Environmental Laws 126125

8.15 Properties 127125

8.16 Solvency 127126

8.17 Insurance 128126

8.18 Deposit Accounts; Securities Accounts; Commodities Accounts 128126

8.19 Creation of Liens 128126

8.20 Hedge Transactions 128127

8.21 Patriot Act; Sanctions; Anti-Corruption; Anti-Money Laundering 128127

8.22 No Material Adverse Effect 129127

8.23 Foreign Corrupt Practices Act 129127

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8.24 Direct Benefit 129128

8.25 Plan Assets; Prohibited Transactions 129128

8.26 Affected Financial Institutions 129128

SECTION 9. Affirmative Covenants 129128

9.1 Information Covenants 130128

9.2 Books, Records and Inspections 135133

9.3 Maintenance of Insurance 136134

9.4 Payment of Taxes 136135

9.5 Consolidated Corporate Franchises 136135

9.6 Compliance with Statutes, Regulations, Etc. 136135

9.7 ERISA 137135

9.8 Maintenance of Properties 138136

9.9 Transactions with Affiliates 138137

9.10 End of Fiscal Years; Fiscal Quarters 140138

9.11 Additional Guarantors, Grantors and Collateral 140139

9.12 Use of Proceeds 142141

9.13 Further Assurances 143141

9.14 Reserve Reports 144142

9.15 Title Information 145143

9.16 Change in Business 146144

9.17 Holdings and Intermediate Entity Covenant 146145

9.18 Keepwell 147145

9.19 Minimum Hedge Covenant 148146

9.20 Separateness 148146

SECTION 10. Negative Covenants 148146

10.1 Limitation on Indebtedness 148146

10.2 Limitation on Liens 154153

10.3 Limitation on Fundamental Changes 158156

10.4 Limitation on Sale of Assets 160158

10.5 Limitation on Investments 162161

10.6 Limitation on Restricted Payments 166164

10.7 Limitations on Debt Payments and Amendments 170168

10.8 Negative Pledge Agreements 171170

10.9 Limitation on Subsidiary Distributions 173172

10.10 Hedge Transactions 175173

10.11 Financial Performance Ratios 177175

10. 12 Accounts 177175

10.13 Sanctions 177176

10.14 Amendments to Organizational Documents 177176

SECTION 11. Events of Default 178176

11.1 Payments 178176

11.2 Representations, Etc. 178176

11.3 Covenants 178176

11.4 Default Under Other Agreements 178177

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11.5 Bankruptcy, Etc. 179177

11.6 ERISA 179178

11.7 Guarantee 180178

11.8 Security Document 180178

11.9 Judgments 180178

11.10 Change of Control 180179

11.11 Application of Proceeds 181179

11.12 Equity Cure 182180

SECTION 12. The Agents 183182

12.1 Appointment 183182

12.2 Delegation of Duties 184182

12.3 Exculpatory Provisions 184183

12.4 Reliance by Agents 185183

12.5 Notice of Default 186184

12.6 Acknowledgements of Lenders and Issuing Banks 186184

12.7 Indemnification 188186

12.8 Agents in Its Individual Capacities 189187

12.9 Successor Agents 189187

12.10 Withholding Tax 190188

12.11 Security Documents and Collateral Agent under Security Documents and Guarantee 190189

12.12 Right to Realize on Collateral and Enforce Guarantee 191189

12.13 Administrative Agent May File Proofs of Claim 192191

12.14 Certain ERISA Matters 193191

SECTION 13. Miscellaneous 195193

13.1 Amendments, Waivers and Releases 195193

13.2 Notices; Posting of Communications 197195

13.3 No Waiver; Cumulative Remedies 200198

13.4 Survival of Representations and Warranties 200198

13.5 Expenses; Limitation of Liability; Indemnification 200198

13.6 Successors and Assigns; Participations and Assignments 202200

13.7 Replacements of Lenders under Certain Circumstances 209207

13.8 Adjustments; Set-off 210208

13.9 Counterparts; Electronic Execution 211209

13.10 Severability 212210

13.11 Integration 212210

13.12 GOVERNING LAW 213210

13.13 Submission to Jurisdiction; Waivers 213211

13.14 Acknowledgments 214212

13.15 WAIVERS OF JURY TRIAL 215213

13.16 Confidentiality 215213

13.17 Release of Collateral and Guarantee Obligations 216214

13.18 USA PATRIOT Act 217215

13.19 Payments Set Aside 217215

13.20 Reinstatement 218215

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13.21 Disposition of Proceeds 218216

13.22 Collateral Matters; Hedge Agreements 218216

13.23 Agency of the Borrower for the Other Credit Parties 218216

13.24 Acknowledgement and Consent to Bail-In of Affected Financial
Institutions 219216

13.25 Acknowledgement Regarding Any Supported QFCs 219217

13.26 Judgment Currency 220218

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EXHIBITS

Exhibit A Form of Reserve Report Certificate

Exhibit B Form of Notice of Borrowing

Exhibit C Form of Guarantee

Exhibit D Forms of Mortgage/Deed of Trust (Texas and Louisiana)

Exhibit E Form of Collateral Agreement

Exhibit F Form of Intercreditor Agreement

Exhibit G Form of Assignment and Acceptance

Exhibit H-1 Form of Promissory Note (Loan)

Exhibit H-2 Form of Promissory Note (Swingline Loan)

Exhibit I Form of Intercompany Note

Exhibit J Form of Solvency Certificate

Exhibit K Form of Non-Bank Tax Certificate

Exhibit L Form of Notice of Conversion or Continuation

Exhibit M Form of Prepayment Notice

SCHEDULES

Schedule 1.1(a) Commitments

Schedule 1.1(b) Excluded Equity Interests

Schedule 1.1(c) Excluded Subsidiaries

Schedule 1.1(d) Existing Letters of Credit

Schedule 1.1(e) Closing Date Subsidiary Guarantors

Schedule 1.1(f) Closing Date Hedge Banks

Schedule 1.1(g) [Intentionally Omitted]

Schedule 1.1(h) Maximum LC Commitments

Schedule 1.1(i) Excluded Accounts

Schedule 6(b) Local Counsels

Schedule 8.4 Litigation

Schedule 8.12 Subsidiaries

Schedule 8.18 Deposit Accounts; Securities Accounts; Commodities Accounts

Schedule 8.20 Closing Date Hedge Transactions

Schedule 9.9 Closing Date Affiliate Transactions

Schedule 9.13(b) Further Assurances

Schedule 10.1 Closing Date Indebtedness

Schedule 10.2(d) Closing Date Liens

Schedule 10.4(i) Scheduled Dispositions

Schedule 10.5(d) Closing Date Investments

Schedule 10.8 Closing Date Negative Pledge Agreements

Schedule 13.2 Notice Addresses

Schedule 13.22 Legacy Hedge Transactions

7

CREDIT AGREEMENT, dated as of May 10, 2018, among TALOS ENERGY, INC., a Delaware corporation (“Holdings”), TALOS PRODUCTION INC., a Delaware corporation (as successor-by-conversion to Talos Production LLC, a Delaware limited liability company) and a wholly owned subsidiary of Holdings (the “Borrower”), the banks, financial institutions and other lending institutions from time to time parties as lenders hereto (each a “Lender” and, collectively, the “Lenders”), JPMORGAN CHASE BANK, N.A., as administrative agent and collateral agent for the Lenders and as the swing line lender, and each Issuing Bank from time to time party hereto.

WHEREAS, the Borrower, as borrower, and Holdings, as parent holding company, heretofore entered into that certain Credit Agreement dated as of February 6, 2013, with Toronto Dominion (Texas) LLC, as administrative agent, collateral agent and swingline lender, Citibank, N.A., and The Toronto-Dominion Bank, New York Branch, as letter of credit issuing banks, and the other banks and financial institutions party thereto (as amended, supplemented or otherwise modified from time to time prior to the date hereof, the “Existing Talos Credit Agreement”), pursuant to which the Borrower incurred certain Indebtedness as loans or reimbursement obligations in respect of letters of credit issued for its benefit or the benefit of one or more of its Restricted Subsidiaries;

WHEREAS, pursuant to that certain Transaction Agreement, dated as of November 21, 2017 (together with all exhibits and schedules thereto, and as amended, supplemented or otherwise modified from time to time, the “Transaction Agreement”), by and among Stone Energy Corporation, a Delaware corporation (“Stone Energy”), Sailfish Energy Holdings Corporation, a Delaware corporation, Sailfish Merger Sub Corporation, a Delaware corporation, Talos Energy LLC, a Delaware limited liability company (“Existing Talos Energy”) and the Borrower, Stone Energy will undergo a reorganization pursuant to which (x) Sailfish Merger Sub Corporation will merge with and into Stone Energy, with Stone Energy as the surviving corporation and a direct wholly owned subsidiary of Sailfish Energy Holdings Corporation; (y) each outstanding share of Stone Energy’s common stock will be converted into the right to receive one share of common stock of Sailfish Energy Holdings Corporation, (z) Sailfish Energy Holdings Corporation will be named “Talos Energy, Inc.” (“New Talos Energy”); through a series of contributions by the direct and indirect owners of all of the equity interests in Borrower, New Talos Energy will receive 100% of the equity interests of Borrower, which at that time will own 100% of the equity interests in Existing Talos Energy, and the contributing parties will receive common stock of New Talos Energy (the transaction described in the foregoing clauses (i) and (ii), herein collectively the “Corporate Reorganization and Merger Transactions”), certain Affiliates of the Sponsors will contribute all outstanding senior unsecured notes issued by the Borrower and Talos Production Finance Inc., in exchange for common stock in New Talos Energy, the Borrower and Stone Energy will offer to exchange their respective second lien notes for second lien notes (the “2018 Junior Lien Notes”) of the Borrower (the “2018 Junior Lien Note Exchange”), and any holders of the existing second lien notes of Stone Energy that accept the exchange offer will execute and deliver an indenture supplement approving certain amendments and modifications to the indenture governing any such existing second lien notes of Stone Energy that remain outstanding after giving effect to the 2018 Junior Lien Note Exchange (the transactions described in the foregoing clauses (i) through (v), collectively, the “Transactions”);

WHEREAS, Stone Energy, as borrower, heretofore entered into, that certain Fifth Amended and Restated Credit agreement, dated as of March 1, 2017, by and among Stone Energy, Bank of America, N.A., as administrative agent and issuing bank, and the lenders and other persons party thereto (as amended, supplemented or otherwise modified from time to time prior to the date hereof, the “Existing Stone Credit Agreement” and together with the Existing Talos Credit Agreement, the “Existing Credit Agreements”), pursuant to which Stone Energy incurred certain Indebtedness as loans or reimbursement obligations in respect of letters of credit issued for its benefit or the benefit of one or more of its restricted subsidiaries;

WHEREAS, in connection with the foregoing, the Borrower has requested that on the Closing Date, the Lenders provide Loans to the Borrower (but subject to compliance with Section 6(q) regarding minimum remaining Availability) (the “Closing Date Loans”) and at any time and from time to time after the Closing Date, the Lenders provide Loans to the Borrower subject to the Available Commitment, the Borrower has requested that each Issuing Bank issue Letters of Credit (subject to the Available Commitment) at any time and from time to time prior to the L/C Maturity Date (including on the Closing Date to back stop and/or replace any Existing Letter of Credit (subject to the Available Commitment)), in an aggregate Stated Amount at any time outstanding not in excess of $200,000,000, and the Borrower has requested that the Swingline Lender extend credit in the form of Swingline Loans (subject to the Available Commitment) at any time and from time to time prior to the Swingline Maturity Date, in an aggregate principal amount at any time outstanding not in excess of $10,000,000;

WHEREAS, the net proceeds of the Closing Date Loans will be used on the Closing Date to consummate the Transactions, pay Transaction Expenses and repay the Indebtedness outstanding under each of the Existing Credit Agreements outstanding on the Closing Date;

WHEREAS, following the Closing Date, the proceeds of the Loans will be used by the Borrower for the acquisition, development and exploration of Oil and Gas Properties and for working capital and other general corporate purposes of the Borrower and its Restricted Subsidiaries (including Permitted Acquisitions) and to make dividends and distributions to the holders of the Borrower’s Equity Interests (to the extent permitted under this Agreement), and the Letters of Credit will be used by the Borrower and its Restricted Subsidiaries for general corporate purposes, including to secure any surety and bonding requirements and to support deposits required under purchase agreements pursuant to which the Borrower or its Restricted Subsidiaries may acquire Oil and Gas Properties and other assets,;

WHEREAS, the Lenders, the Swingline Lender and the Issuing Banks are willing to make available to the Borrower such revolving credit, swingline and letter of credit facilities upon the terms and subject to the conditions set forth herein; and

NOW, THEREFORE, in consideration of the premises and the covenants and agreements contained herein, the parties hereto hereby agree as follows:

Section 1.Definitions.

1.1Defined Terms.

As used herein, the following terms shall have the meanings specified below:

“ABR” when used in reference to any Loan or Borrowing, refers to whether such Loan, or the Loans comprising such Borrowing, bear interest at a rate determined by reference to the Alternate Base Rate.

“Additional Lender” shall have the meaning provided in Section 2.16(a).

“Adjusted Consolidated Net Tangible Assets” shall mean (without duplication), as of the date of determination, the remainder of:

(a)the sum of:

(i)estimated discounted future net revenues from Proved Reserves of the Borrower and its Restricted Subsidiaries calculated in accordance with SEC guidelines before any provincial,

territorial, state, federal or foreign income taxes, as estimated by the Borrower in a reserve report prepared as of the end of the Borrower’s most recently completed fiscal year for which audited financial statements are available, as increased by, as of the date of determination, the estimated discounted future net revenues from (A) estimated Proved Reserves acquired since such year end, which Proved Reserves were not reflected in such year-end reserve report, and (B) estimated oil and gas reserves attributable to upward revisions of estimates of Proved Reserves (including the impact to discounted future net revenues related to development costs previously estimated in the last year-end reserve report, but only to the extent such costs were actually incurred since the date of the last year-end reserve report) since such year-end due to exploration, development, exploitation or other activities, increased by the accretion of discount from the date of the last year-end reserve report to the date of determination, and decreased by, as of the date of determination, the estimated discounted future net revenues from (C) estimated Proved Reserves included in the last year-end reserve report that shall have been produced or disposed of since such year-end, and (D) estimated oil and gas reserves included therein that are subsequently removed from the Proved Reserves of the Borrower and its Restricted Subsidiaries as so calculated due to downward revisions of estimates of Proved Reserves since such year-end due to changes in geological conditions or other factors which would, in accordance with standard industry practice, cause such revisions, provided, that (x) in the case of such year-end reserve report and any adjustments since such year-end pursuant to clauses (A), (B) and (D), the estimated discounted future net revenues from Proved Reserves shall be determined in their entirety using oil, gas and other hydrocarbon prices and costs that are either (1) calculated in accordance with the SEC guidelines and, with respect to such adjustments under clauses (A), (B) or (D), calculated with such prices and costs as if the end of the most recent fiscal quarter preceding the date of determination for which such information is available to the Borrower were year-end or (2) if the Borrower so elects at any time, calculated in accordance with the foregoing clause (1), except that when pricing of future net revenues of Proved Reserves under the SEC guidelines is not based on a contract price and is instead based upon benchmark, market or posted pricing, the pricing for each month of estimated future production from such Proved Reserves not subject to contract pricing shall be based upon NYMEX (or successor) published forward prices for the most comparable hydrocarbon commodity applicable to such production month (adjusted for energy content, quality and basis differentials (such basis differential being the relevant NYMEX (or successor) published forward basis differential or, if such NYMEX (or successor) forward basis differential is unavailable, as estimated in good faith by the Borrower based on historical basis differential (before any state or federal or other income tax)) and giving application to the last sentence of such definition hereto), as such forward prices are published as of the year-end date of such reserve report or, with respect to post-year-end adjustments under clauses (A), (B) or (D), the last day of the most recent fiscal quarter preceding the date of determination, (y) the pricing of estimated Proved Reserves that have been produced or disposed since year-end as set forth in clause (C) shall be based upon the applicable pricing elected for the prior year-end reserve report as provided in clause (x), and (z) in each case as estimated by or under the supervision of the chief engineer of the Borrower or a Restricted Subsidiary or by any Approved Petroleum Engineer;

(ii)the capitalized costs that are attributable to Oil and Gas Properties of the Borrower and its Restricted Subsidiaries to which no Proved Reserves are attributable, based on the Borrower’s books and records as of a date no earlier than the date of the Borrower’s latest annual or quarterly consolidated financial statements;

(iii)the Net Working Capital on a date no earlier than the date of the Borrower’s latest annual or quarterly consolidated financial statements;

(iv)assets related to commodity risk management activities less liabilities related to commodity risk management activities, in each case to the extent that such assets and liabilities arise in the ordinary course of the Oil and Gas Business, provided that such net value shall not be less than zero; and

(v)the greater of (A) the net book value of other tangible assets (including, without limitation, investments in unconsolidated Restricted Subsidiaries and mineral rights held under lease or other contractual arrangement) of the Borrower and its Restricted Subsidiaries, as of a date no earlier than the date of the Borrower’s latest annual or quarterly consolidated financial statements, and (B) the Fair Market Value, as estimated by the Borrower, of other tangible assets (including, without limitation, investments in unconsolidated Restricted Subsidiaries and mineral rights held under lease or other contractual arrangement) of the Borrower and its Restricted Subsidiaries, as of a date no earlier than the date of the Borrower’s latest audited consolidated financial statements (it being understood that the Borrower shall not be required to obtain any appraisal of any assets); minus

(b)the sum of:

(i)any amount included in (a)(i) through (a)(v) above that is attributable to minority interests;

(ii)any net gas balancing liabilities of the Borrower and its Restricted Subsidiaries reflected in the Borrower’s latest audited consolidated financial statements;

(iii)to the extent included in (a)(i) above, the estimated discounted future net revenues, calculated in accordance with the SEC guidelines (utilizing the prices and costs as provided in (a)(i)), attributable to reserves that are required to be delivered to third parties to fully satisfy the obligations of the Borrower and its Restricted Subsidiaries with respect to Volumetric Production Payments (determined, if applicable, using the schedules specified with respect thereto); and

(iv)to the extent included in (a)(i) above, the estimated discounted future net revenues, calculated in accordance with SEC guidelines (utilizing prices and costs as provided in (a)(i)), attributable to reserves subject to Dollar- Denominated Production Payments that, based on the estimates of production and price assumptions included in determining the estimated discounted future net revenues specified in (a)(i) above, would be necessary to fully satisfy the payment obligations of the Borrower and its Restricted Subsidiaries with respect to Dollar-Denominated Production Payments (determined, if applicable, using the schedules specified with respect thereto).

If the Borrower changes its method of accounting from the full cost method of accounting to the successful efforts or a similar method, “Adjusted Consolidated Net Tangible Assets” will continue to be calculated as if the Borrower were still using the full cost method of accounting.

“Adjusted Daily Simple SOFR” means an interest rate per annum equal to (c) the Daily Simple SOFR, plus (d) 0.10%; provided that if the Adjusted Daily Simple SOFR Rate as so determined would be less than the Floor, such rate shall be deemed to be equal to the Floor for the purposes of this Agreement.

“Adjusted Term SOFR Rate” means, for any Interest Period, an interest rate per annum equal to (e) the Term SOFR Rate for such Interest Period, plus (f) 0.10%; provided that if the Adjusted Term SOFR Rate as so determined would be less than the Floor, such rate shall be deemed to be equal to the Floor for the purposes of this Agreement.

“Adjusted Total Commitment” shall mean, at any time, the Total Commitment less the aggregate amount of Commitments of all Defaulting Lenders.

“Administrative Agent” shall mean JPMorgan Chase Bank, N.A. (or any of its designated branch offices or affiliates), as the administrative agent for the Lenders under this Agreement and the other Credit Documents, or any successor administrative agent appointed in accordance with the provisions of Section 12.9.

“Administrative Agent’s Office” shall mean the Administrative Agent’s address and, as appropriate, account as set forth on Schedule 13.2, or such other address or account as the Administrative Agent may from time to time notify in writing to the Borrower and the Lenders.

“Administrative Questionnaire” shall mean, for each Lender, an administrative questionnaire in a form approved by the Administrative Agent.

“Affected Financial Institution” means (g) any EEA Financial Institution or (h) any UK Financial Institution.

“Affiliate” shall mean, with respect to any Person, any other Person directly or indirectly controlling, controlled by, or under direct or indirect common control with such Person. A Person shall be deemed to control another Person if such Person possesses, directly or indirectly, the power to direct or cause the direction of the management and policies of such other Person, whether through the ownership of voting securities, by contract or otherwise. “Controlling” (“controlling”) and “controlled” shall have meanings correlative thereto.

“Affiliated Institutional Lender” shall mean any investment fund managed or advised by Affiliates of a Co-Investor that is a bona fide debt fund and that extends credit or buys loans in the ordinary course of business.

“Affiliated Lender” shall mean a Lender that is a Co-Investor or any Affiliate thereof (other than Holdings, any other Subsidiary of Holdings, the Borrower or any Affiliated Institutional Lender).

“Agents” shall mean the Administrative Agent and the Collateral Agent.

“Agreed Currencies” shall mean Dollars and each Alternate Currency.

“Agreement” shall mean this Credit Agreement, as amended, restated, supplemented or otherwise modified from time to time.

“Alternate Base Rate” means, for any day, a rate per annum equal to the greatest of (i) the Prime Rate in effect on such day, (j) the NYFRB Rate in effect on such day plus ½ of 1% and (k) the Adjusted Term SOFR Rate for a one month Interest Period as published two U.S. Government Securities Business Days prior to such day (or if such day is not a U.S. Government Securities Business Day, the immediately preceding U.S. Government Securities Business Day) plus 1%; provided that for the purpose of this definition, the Adjusted Term SOFR Rate for any day shall be based on the Term SOFR Reference Rate at approximately 5:00 a.m. Chicago time on such day (or any amended publication time for the Term SOFR Reference Rate, as specified by the CME Term SOFR Administrator in the Term SOFR Reference Rate methodology). Any change in the Alternate Base Rate due to a change in the Prime Rate, the NYFRB Rate or the Adjusted Term SOFR Rate shall be effective from and including the effective date of such change in the Prime Rate, the NYFRB Rate or the Adjusted Term SOFR Rate, respectively. If the Alternate Base Rate is being used as an alternate rate of interest pursuant to Section 2.18 (for the avoidance of doubt, only until the Benchmark Replacement has been determined

pursuant to Section 2.18(b)), then the Alternate Base Rate shall be the greater of clauses (a) and (b) above and shall be determined without reference to clause (c) above. For the avoidance of doubt, if the Alternate Base Rate as determined pursuant to the foregoing would be less than 1.00%, such rate shall be deemed to be 1.00% for purposes of this Agreement.

“Alternate Currency” shall mean, with respect to any Letter of Credit, Euro and any other currency agreed to by the Administrative Agent and the Issuing Banks; provided that each such currency is a lawful currency that is readily available, freely transferable and not restricted and able to be converted into Dollars.

“Alternate Currency Letter of Credit” shall mean any Letter of Credit denominated in an Alternate Currency.

“Ancillary Document” has the meaning assigned to it in Section 13.9.

“Anti-Corruption Laws” shall mean all laws, rules, and regulations of any jurisdiction applicable to the Borrower or any of its Subsidiaries from time to time concerning or relating to bribery or corruption.

“Anti-Money Laundering Laws” shall mean all laws, rules, and regulations of any jurisdiction applicable to the Borrower or any of its Subsidiaries from time to time concerning or relating to money laundering.

“Applicable Margin” shall mean, for any day, with respect to any ABR Loan, any Term Benchmark Loan, any RFR Loan or Commitment Fees, as the case may be, the rate per annum set forth in the grid below based upon the Utilization Percentage in effect on such day:

Utilization Grid

Utilization Percentage	X < 25%	≥ 25 % X	≥ 50 % X	≥ 75% X
		< 50 %	< 75 %	< 90%	X ≥ 90%
Term Benchmark Loans and RFR Loans	2.75%	3.00%	3.25%	3.50%	3.75%
ABR Loans	1.75%	2.00%	2.25%	2.50%	2.75%
Commitment Fee Rate	0.375%	0.375%	0.50%	0.50%	0.50%

Each change in the Commitment Fee Rate or Applicable Margin shall apply during the period commencing on the effective date of such change and ending on the date immediately preceding the effective date of the next such change.

“Applicable Period” shall mean, for the fiscal quarter ending March 31, 2021, and each fiscal quarter ending thereafter, the four fiscal quarter period ending as of the last day of such fiscal quarter.

“Approved Fund” shall mean any Fund that is administered or managed by (l) a Lender, (m) an Affiliate of a Lender or (n) an entity or an Affiliate of an entity that administers or manages a Lender.

“Approved Petroleum Engineers” shall mean (o) Netherland, Sewell & Associates, Inc., (p) Ryder Scott Company, L.P., (q) DeGolyer and MacNaughton, (r) Cawley, Gillespie & Associates, Inc., and (s) at the Borrower’s option, any other independent petroleum engineers selected by the Borrower and reasonably acceptable to the Administrative Agent.

“Assignment and Acceptance” shall mean an assignment and acceptance substantially in the form of Exhibit G or such other form (including electronic records generated by the use of an electronic platform) as may be approved by the Administrative Agent.

“Authorized Officer” shall mean as to any Person, the President, the Chief Executive Officer, the Chief Financial Officer, the Chief Operating Officer, the Treasurer, the Assistant or Vice Treasurer, the Vice President-Finance, the General Counsel and any manager, managing member or general partner, in each case, of such Person, and any other senior officer designated as such in writing to the Administrative Agent by such Person. Any document delivered hereunder that is signed by an Authorized Officer shall be conclusively presumed to have been authorized by all necessary corporate, limited liability company, partnership and/or other action on the part of the Borrower or any other Credit Party and such Authorized Officer shall be conclusively presumed to have acted on behalf of such Person.

“Auto-Extension Letter of Credit” shall have the meaning provided in Section 3.2(b).

“Available Commitment” shall mean, at any time, (t) the Loan Limit at such time minus (u) the aggregate Total Exposures of all Lenders at such time.

“Available Free Cash Flow Amount” shall mean, as of any date of determination, the result of (v) Free Cash Flow for the Applicable Period most recently ended for which a certificate has been delivered pursuant to Section 9.1(l)minus(w) the aggregate amount of all Restricted Payments made in reliance on Section 10.6(i) (if any) during the most recently completed Free Cash Flow Usage Period and since the date on which a certificate has been most recently delivered pursuant to Section 9.1(l)minus(x) the aggregate amount of all Investments made in reliance on Section 10.5(i) (if any) during the most recently completed Free Cash Flow Usage Period and since the date on which a certificate has been most recently delivered pursuant to Section 9.1(l)minus(y) the aggregate amount of all prepayments, repurchases, redemptions or defeasances paid in reliance on Section 10.7(a) (if any) during the most recently completed Free Cash Flow Usage Period and since the date on which a certificate has been most recently delivered pursuant to Section 9.1(l).

“Available Tenor” means, as of any date of determination and with respect to the then-current Benchmark, as applicable, any tenor for such Benchmark (or component thereof) or payment period for interest calculated with reference to such Benchmark (or component thereof), as applicable, that is or may be used for determining the length of an Interest Period for any term rate or otherwise, for determining any frequency of making payments of interest calculated pursuant to this Agreement as of such date and not including, for the avoidance of doubt, any tenor for such Benchmark that is then-removed from the definition of “Interest Period” pursuant to clause (e) of Section 2.18.

“Bail-In Action” means the exercise of any Write-Down and Conversion Powers by the applicable Resolution Authority in respect of any liability of an Affected Financial Institution.

“Bail-In Legislation” means (z) with respect to any EEA Member Country implementing Article 55 of Directive 2014/59/EU of the European Parliament and of the Council of the European Union, the implementing law, regulation, rule or requirement for such EEA Member Country from time to time which is described in the EU Bail-In Legislation Schedule and (aa) with respect to the United Kingdom, Part I of the United Kingdom Banking Act 2009 (as amended from time to time) and any other law, regulation, rule or requirement applicable in the United Kingdom relating to the resolution of unsound or failing banks, investment firms or other financial institutions or their affiliates (other than through liquidation, administration or other insolvency proceedings).

“Bank Price Deck” shall mean the Administrative Agent’s forward curve for each of oil, natural gas and other Hydrocarbons, as applicable, furnished to the Borrower by the Administrative Agent from time to time in accordance with the terms of this Agreement.

“Bankruptcy Code” shall have the meaning provided in Section 11.5.

“Benchmark” means, initially, with respect to any (bb) RFR Loan, the Daily Simple SOFR or (cc) Term Benchmark Loan, the Term SOFR Rate; provided that if a Benchmark Transition Event and the related Benchmark Replacement Date have occurred with respect to the Daily Simple SOFR or Term SOFR Rate, as applicable, or the then-current Benchmark, then “Benchmark” means the applicable Benchmark Replacement to the extent that such Benchmark Replacement has replaced such prior benchmark rate pursuant to clause (b) of Section 2.18.

“Benchmark Replacement” means, for any Available Tenor, the sum of: (dd) the alternate benchmark rate that has been selected by the Administrative Agent and the Borrower as the replacement for the then-current Benchmark for the applicable Corresponding Tenor giving due consideration to (i) any selection or recommendation of a replacement benchmark rate or the mechanism for determining such a rate by the Relevant Governmental Body or (ii) any evolving or then-prevailing market convention for determining a benchmark rate as a replacement for the then-current Benchmark for dollar-denominated syndicated credit facilities at such time in the United States and (ee) the related Benchmark Replacement Adjustment. If the Benchmark Replacement as determined pursuant to the above would be less than the Floor, the Benchmark Replacement will be deemed to be the Floor for the purposes of this Agreement and the other Credit Documents.

“Benchmark Replacement Adjustment” means, with respect to any replacement of the then-current Benchmark with an Unadjusted Benchmark Replacement for any applicable Interest Period and Available Tenor for any setting of such Unadjusted Benchmark Replacement, the spread adjustment, or method for calculating or determining such spread adjustment (which may be a positive or negative value or zero) that has been selected by the Administrative Agent and the Borrower for the applicable Corresponding Tenor giving due consideration to (i) any selection or recommendation of a spread adjustment, or method for calculating or determining such spread adjustment, for the replacement of such Benchmark with the applicable Unadjusted Benchmark Replacement by the Relevant Governmental Body on the applicable Benchmark Replacement Date and/or (ff) any evolving or then-prevailing market convention for determining a spread adjustment, or method for calculating or determining such spread adjustment, for the replacement of such Benchmark with the applicable Unadjusted Benchmark Replacement for dollar-denominated syndicated credit facilities at such time.

“Benchmark Replacement Conforming Changes” means, with respect to any Benchmark Replacement and/or any Term Benchmark Revolving Loan, any technical, administrative or operational changes (including changes to the definition of “Alternate Base Rate,” the definition of “Business Day,” the definition of “U.S. Government Securities Business Day,” the definition of “Interest Period,” timing and frequency of determining rates and making payments of interest, timing of borrowing requests or prepayment, conversion or continuation notices, length of lookback periods, the applicability of breakage provisions, and other technical, administrative or operational matters) that the Administrative Agent decides may be appropriate to reflect the adoption and implementation of such Benchmark and to permit the administration thereof by the Administrative Agent in a manner substantially consistent with market practice (or, if the Administrative Agent decides that adoption of any portion of such market practice is not administratively feasible or if the Administrative Agent determines that no market practice for the administration of such Benchmark exists, in such other manner of administration as the Administrative Agent decides is reasonably necessary in connection with the administration of this Agreement and the other Credit Documents).

“Benchmark Replacement Date” means, with respect to any Benchmark, the earlier to occur of the following events with respect to such then-current Benchmark:

(1)in the case of clause (1) or (2) of the definition of “Benchmark Transition Event,” the later of (a) the date of the public statement or publication of information referenced therein and (b) the date on which the administrator of such Benchmark (or the published component used in the calculation thereof) permanently or indefinitely ceases to provide all Available Tenors of such Benchmark (or such component thereof); or

(2)in the case of clause (3) of the definition of “Benchmark Transition Event,” the first date on which such Benchmark (or the published component used in the calculation thereof) has been determined and announced by the regulatory supervisor for the administrator of such Benchmark (or such component thereof) to be no longer representative; provided, that such non-representativeness will be determined by reference to the most recent statement or publication referenced in such clause (3) and even if any Available Tenor of such Benchmark (or such component thereof) continues to be provided on such date.

For the avoidance of doubt, (i) if the event giving rise to the Benchmark Replacement Date occurs on the same day as, but earlier than, the Reference Time in respect of any determination, the Benchmark Replacement Date will be deemed to have occurred prior to the Reference Time for such determination and (ii) the “Benchmark Replacement Date” will be deemed to have occurred in the case of clause (1) or (2) with respect to any Benchmark upon the occurrence of the applicable event or events set forth therein with respect to all then-current Available Tenors of such Benchmark (or the published component used in the calculation thereof).

“Benchmark Transition Event” means, with respect to any Benchmark, the occurrence of one or more of the following events with respect to such then-current Benchmark:

(3)a public statement or publication of information by or on behalf of the administrator of such Benchmark (or the published component used in the calculation thereof) announcing that such administrator has ceased or will cease to provide all Available Tenors of such Benchmark (or such component thereof), permanently or indefinitely, provided that, at the time of such statement or publication, there is no successor administrator that will continue to provide any Available Tenor of such Benchmark (or such component thereof);

(4)a public statement or publication of information by the regulatory supervisor for the administrator of such Benchmark (or the published component used in the calculation thereof), the Federal Reserve Board, the NYFRB, the CME Term SOFR Administrator, an insolvency official with jurisdiction over the administrator for such Benchmark (or such component), a resolution authority with jurisdiction over the administrator for such Benchmark (or such component) or a court or an entity with similar insolvency or resolution authority over the administrator for such Benchmark (or such component), in each case, which states that the administrator of such Benchmark (or such component) has ceased or will cease to provide all Available Tenors of such Benchmark (or such component thereof) permanently or indefinitely, provided that, at the time of such statement or publication, there is no successor administrator that will continue to provide any Available Tenor of such Benchmark (or such component thereof); or

(5)a public statement or publication of information by the regulatory supervisor for the administrator of such Benchmark (or the published component used in the calculation thereof)

announcing that all Available Tenors of such Benchmark (or such component thereof) are no longer, or as of a specified future date will no longer be, representative.

For the avoidance of doubt, a “Benchmark Transition Event” will be deemed to have occurred with respect to any Benchmark if a public statement or publication of information set forth above has occurred with respect to each then-current Available Tenor of such Benchmark (or the published component used in the calculation thereof).

“Benchmark Unavailability Period” means, with respect to any Benchmark, the period (if any) (x) beginning at the time that a Benchmark Replacement Date pursuant to clauses (1) or (2) of that definition has occurred if, at such time, no Benchmark Replacement has replaced such then-current Benchmark for all purposes hereunder and under any Credit Document in accordance with Section 2.18 and (y) ending at the time that a Benchmark Replacement has replaced such then-current Benchmark for all purposes hereunder and under any Credit Document in accordance with Section 2.18.

“Beneficial Ownership Certification” means a certification regarding beneficial ownership or control as required by the Beneficial Ownership Regulation.

“Beneficial Ownership Regulation” means 31 C.F.R. § 1010.230.

“benefited Lender” shall have the meaning provided in Section 13.8.

“BHC Act Affiliate” of a party means an “affiliate” (as such term is defined under, and interpreted in accordance with, 12 U.S.C. 1841(k)) of such party.

“Board” shall mean the Board of Governors of the Federal Reserve System of the United States (or any successor).

“Board of Directors” shall mean, as to any Person, the board of directors or other governing body of such Person, or if such Person is owned or managed by a single entity, the board of directors or other governing body of such entity.

“Borrower” shall have the meaning provided in the introductory paragraph hereto.

“Borrowing” shall mean the incurrence of one Type of Loan on a given date (or resulting from conversions on a given date) having, in the case of Term Benchmark Loans, the same Interest Period.

“Borrowing Base” shall mean, at any time, an amount equal to the amount determined in accordance with Section 2.14, as the same may be adjusted from time to time pursuant to the provisions thereof.

“Borrowing Base Adjustment Provisions” shall mean Sections 2.14(e), (f), (g) and (h), and any other provision in this Agreement that adjusts (as opposed to redetermines) the amount of the Borrowing Base.

“Borrowing Base Deficiency” occurs if, at any time, the aggregate Total Exposure of all Lenders exceeds the Borrowing Base then in effect. The amount of the Borrowing Base Deficiency is the amount by which the Total Exposure of all Lenders exceeds the Borrowing Base then in effect.

“Borrowing Base Properties” shall mean the Oil and Gas Properties of the Credit Parties included in the Initial Reserve Report and thereafter in the Reserve Report most recently delivered pursuant to

Section 9.14, together with the Hydrocarbon Interests on which such Oil and Gas Properties are located or to which such Oil and Gas Properties are attributed.

“Borrowing Base Required Lenders” shall mean, at any date, (z) Non-Defaulting Lenders having or holding 100% of the Adjusted Total Commitment at such date or (aa) if the Total Commitment has been terminated, Lenders having or holding 100% of the outstanding principal amount of the Loans, the Swingline Exposure and Letter of Credit Exposure (excluding the Loans, Swingline Exposure and Letter of Credit Exposure of Defaulting Lenders) in the aggregate at such date.

“Borrowing Base Value” shall mean, with respect to any Oil and Gas Property of evaluated in the determination of the Borrowing Base or any Hedge Transaction in respect of commodities, the value attributed to such asset in connection with the most recent determination of the Borrowing Base (which Borrowing Base was approved by the Borrowing Base Required Lenders or the Required Lenders, as applicable, in accordance with Section 2.14).

“Budget” shall have the meaning provided in Section 9.1(k).

“Business Day” means, any day (other than a Saturday or a Sunday) on which banks are open for business in New York City; provided that, in addition to the foregoing, a Business Day shall be (bb) in relation to RFR Loans and any interest rate settings, fundings, disbursements, settlements or payments of any such RFR Loan, or any other dealings of such RFR Loan and (cc) in relation to Loans referencing the Adjusted Term SOFR Rate and any interest rate settings, fundings, disbursements, settlements or payments of any such Loans referencing the Adjusted Term SOFR Rate or any other dealings of such Loans referencing the Adjusted Term SOFR Rate, any such day that is only a U.S. Government Securities Business Day.

“Capital Lease” shall mean, as applied to any Person, any lease of any property (whether real, personal or mixed) by that Person as lessee that, in conformity with GAAP, is, or is required to be, accounted for as a capital lease on the balance sheet of that Person; provided that leases that are recharacterized as Capital Leases due to a change in GAAP after January 1, 2017 shall not be treated as Capital Leases for any purpose under this Agreement but shall instead be treated as they would have been in accordance with GAAP as in effect on January 1, 2017.

“Capitalized Lease Obligations” shall mean, as applied to any Person, all obligations under Capital Leases of such Person or any of its Restricted Subsidiaries, in each case taken at the amount thereof accounted for as liabilities in accordance with GAAP; provided that obligations that are recharacterized as Capitalized Lease Obligations due to a change in GAAP after January 1, 2017 shall not be treated as Capitalized Lease Obligations for any purpose under this Agreement but shall instead be treated as they would have been in accordance with GAAP as in effect on January 1, 2017.

“Capitalized Software Expenditures” shall mean, for any period, the aggregate of all expenditures (whether paid in cash or accrued as liabilities) by a person during such period in respect of licensed or purchased software or internally developed software and software enhancements that, in accordance with GAAP, are or are required to be reflected as capitalized costs on the consolidated balance sheet of such Person and its subsidiaries.

“Cash Collateral” shall have the meaning provided in Section 3.8.

“Cash Collateralize” shall have the meaning provided in Section 3.8(c).

“Cash Management Agreement” shall mean any agreement entered into from time to time by the Borrower or any of the Borrower’s Restricted Subsidiaries in connection with cash management services for collections, other Cash Management Services and for operating, payroll and trust accounts of such Person, including automatic clearing house services, controlled disbursement services, electronic funds transfer services, lockbox services, stop payment services and wire transfer services.

“Cash Management Bank” shall mean any Person that either (dd) is at the time it provides Cash Management Services or (ee) becomes at any time after it has provided any Cash Management Services for which the Borrower or any Restricted Subsidiary has, as of such time, continuing obligations in connection with, or in respect of, any Cash Management Services, a Lender or an Agent or an Affiliate of a Lender or an Agent.

“Cash Management Obligations” shall mean obligations owed by the Borrower or any Restricted Subsidiary to any Cash Management Bank in connection with, or in respect of, any Cash Management Services.

“Cash Management Services” shall mean (ff) commercial credit cards, merchant card services, purchase or debit cards, including non-card e-payables services, (gg) treasury management services (including controlled disbursement, overdraft, automated clearing house fund transfer services, return items and interstate depository network services) and (hh) any other demand deposit or operating account relationships or other cash management services, including any Cash Management Agreement.

“Castex Acquisition” means that certain acquisition consummated pursuant to the terms of the Castex PSA.

“Castex Acquisition Conditions” means each of the following conditions in connection with the consummation of the Castex Acquisition:

(ii)Acquisition Certificate. The Administrative Agent shall have received a certificate, reasonably satisfactory to the Administrative Agent in all respects, of an Authorized Officer of the Borrower (i) certifying that the Castex Acquisition shall constitute a Permitted Acquisition, (ii) certifying that the Borrower has acquired (or with the proceeds of the applicable Borrowing shall acquire) all or substantially all, but in any event not less than 95% of the PV-10, of the Oil and Gas Properties included in the Castex Acquisition Reserve Report, all conditions to the obligations of the parties set forth in the Castex PSA shall have been satisfied or waived (or with the application of the proceeds of the applicable Borrowing shall be satisfied or waived), and no provision thereof shall have been waived, amended, supplemented or otherwise modified to the extent such waiver, amendment, supplement or other modification would reasonably be expected to materially adversely affect the Administrative Agent, the Collateral Agent or the Lenders (except as otherwise agreed by the Administrative Agent, the Collateral Agent and the Lenders), (iii) identifying the Oil and Gas Properties that have not been acquired pursuant to the Castex PSA, (iv) attaching lien releases delivered in connection with the Castex PSA (or certifying that the assets subject to the Castex PSA were not, prior to the Castex Acquisition, subject to any liens), (v) certifying as to the final purchase price paid under the Castex PSA after giving effect to all adjustments as of the closing date for such acquisition, and specifying, by category, the amount of such adjustment, (vi) certifying that attached thereto are true and complete executed copies of the conveyance documents from the applicable seller to Borrower and (vii) certifying that attached thereto is a true and complete executed copy of the Castex PSA, together with all amendments thereto, pursuant to which the Borrower has acquired the applicable Oil and Gas Properties (or certifying that the previously delivered Castex PSA has not been amended or modified in any way since the Third Amendment Effective Date);

(jj)Verification of Collateral Coverage. The Borrower shall have delivered to the Administrative Agent appropriate documentation evidencing that the Collateral Coverage Minimum is satisfied as of the date of consummation of the Castex PSA or additional Mortgages, executed and delivered by a duly Authorized Officer of the applicable Restricted Subsidiary in sufficient counterparts for the prompt recordation thereof, encumbering Mortgaged Properties that constitute Borrowing Base Properties evaluated, collectively, in the Castex Acquisition Reserve Report and the Spring 2020 Reserve Report having a PV-10, together with the PV-10 of the Mortgaged Properties that remain encumbered by a previously delivered Mortgage, sufficient to satisfy the Collateral Coverage Minimum;

(kk)Legal Opinion. To the extent a new Mortgage is required to be delivered by clause (b) above, the Borrower shall deliver to the Administrative Agent a written opinion of local counsel in any jurisdictions where such Mortgage will be recorded to perfect first priority Liens on any Borrowing Base Properties, which shall be (i) addressed to the Administrative Agent, the Collateral Agent, the Lenders and each Issuing Bank and (ii) in form and substance reasonably satisfactory to the Administrative Agent; and

(ll)Title Compliance. The Borrower shall deliver to the Administrative Agent satisfactory title information with respect to Oil and Gas Properties of the Borrower and its Restricted Subsidiaries comprising, together with title information previously delivered to the Administrative Agent, at least 85% of the PV-10 of all of the Proved Reserves evaluated, collectively, in the Castex Acquisition Reserve Report and the Spring 2020 Reserve Report.

“Castex Acquisition Outside Date” means the earlier of (mm) August 31, 2020 (or such later date as agreed to by the Administrative Agent in its reasonable discretion) and (nn) the date on which the Castex Acquisition is terminated (whether in accordance with the Castex PSA, or otherwise) or otherwise abandoned.

“Castex Acquisition Reserve Report” means the reserve report dated as of April 1, 2020, with respect to the Oil and Gas Properties to be acquired pursuant to the Castex Acquisition.

“Castex PSA” means that certain Purchase and Sale Agreement executed on June 19, 2020, pursuant to which the Borrower, as buyer, will acquire certain Oil and Gas Properties from Castex Energy Partners, LLC, a Delaware limited liability company and Castex Offshore, Inc., a Texas corporation, collectively as sellers.

“Casualty Event” shall mean, with respect to any property or asset, (oo) any damage to, destruction of, or other casualty or loss involving, any such property or asset or (pp) any seizure, condemnation, confiscation or taking under the power of eminent domain of, or any requisition of title or use of, or relating to, or any similar event in respect of, any such property or asset.

“CFC” shall mean a “controlled foreign corporation” within the meaning of Section 957 of the Code.

“Change in Law” shall mean, after the Closing Date (or, with respect to any Lender, such later date on which such Lender becomes a party to this Agreement), (qq) the adoption of, or the taking effect of, any law, treaty, order, policy, rule or regulation, (rr) any change in any law, treaty, order, policy, rule or regulation or in the administrative, interpretation, implementation or application thereof by any Governmental Authority or (ss) compliance by any Lender with any guideline, request, directive or order enacted or promulgated by any central bank or other governmental or quasi-governmental authority (whether or not having the force of law); provided that notwithstanding anything herein to the contrary, (x) the Dodd-Frank Wall Street Reform and

Consumer Protection Act and all requests, rules, guidelines or directives thereunder or issued in connection therewith or in the implementation thereof and (y) all requests, rules, guidelines or directives promulgated by the Bank for International Settlements, the Basel Committee on Banking Supervision (or any successor or similar authority) or the United States or foreign regulatory authorities, in each case pursuant to Basel III, shall be deemed to be included as a Change in Law regardless of the date adopted, enacted, promulgated or implemented.

“Change of Control” shall mean and be deemed to have occurred if:

(tt)any Person or group (within the meaning of the Securities Exchange Act of 1934 and the rules of the SEC thereunder as in effect on the date hereof) other than Permitted Holders acquires the ownership, directly or indirectly, beneficially or of record, of Equity Interests representing more than the greater of 35% and the percentage beneficially owned by the Permitted Holders of the aggregate ordinary voting power represented by the issued and outstanding Equity Interests of Holdings;

(uu)during any period of twelve (12) consecutive months, a majority of the seats (other than vacant seats) on the Board of Directors of Holdings shall be occupied by individuals who were not (i) nominated by the Board of Directors of Holdings or a Permitted Holder, (ii) appointed by directors so nominated or (iii) appointed by a Permitted Holder;

(vv)Holdings shall at any time cease to own, directly or indirectly through one or more Intermediate Entities, 100% of the Equity Interests of the Borrower; or

(ww)a “Change of Control” (as defined in (i) the Junior Lien Indenture, the EnVen Notes Indenture or, any indenture or credit agreement in respect of any QuarterNorth Acquisition Debt, orany indenture or credit agreement in respect of any Permitted Incremental Junior Lien Debt, (ii) any indenture or credit agreement in respect of Permitted Additional Debt that constitutes Material Indebtedness, or (iii) any indenture or credit agreement in respect of any Permitted Refinancing Indebtedness with respect to the Junior Lien Indenture, the EnVen Notes Indenture, any indenture or credit agreement in respect of any QuarterNorth Acquisition Debt, or any indenture or credit agreement in respect of any Permitted Incremental Junior Lien Debt that constitutes Material Indebtedness) shall have occurred.

“Closing Date” shall mean May 10, 2018.

“Closing Date Loans” shall have the meaning provided in the recitals to this Agreement.

“Closing Date Reserve Report” shall mean one or more reserve reports prepared as of December 31, 2017, by one or more Approved Petroleum Engineers with respect to (xx) the Proved Reserves of the Borrower and its Restricted Domestic Subsidiaries and (yy) the Proved Reserves of Stone Energy and its Subsidiaries.

“CME Term SOFR Administrator” means CME Group Benchmark Administration Limited as administrator of the forward-looking term Secured Overnight Financing Rate (SOFR) (or a successor administrator).

“Code” shall mean the Internal Revenue Code of 1986, as amended from time to time.

“Co-Investors” shall mean (zz) the Sponsors, (aaa) any other investors party to that certain Second Amended and Restated Limited Liability Company Agreement of Talos Energy LLC, dated effective June 7, 2012 (as amended from time to time to the date hereof), disclosed to the Lead Arrangers on or prior to the

Closing Date, (bbb) Franklin, (ccc) MacKay and (ddd) the respective Affiliates of the investors described in clauses 0, 0, and 0 (but excluding in each case any of their respective operating portfolio companies).

“Collateral” shall have the meaning provided for such term in each of the Security Documents and shall include any and all assets securing or intended to secure any or all of the Obligations; provided that with respect to any Mortgages, “Collateral,” as defined herein, shall include “Mortgaged Property” as defined therein.

“Collateral Agent” shall mean JPMorgan Chase Bank, N.A., as collateral agent under the Security Documents, or any successor collateral agent appointed in accordance with the provisions of Section 12.9.

“Collateral Agreement” shall mean the Collateral Agreement of even date herewith by and among the Borrower, the other grantors party thereto and the Collateral Agent, for the benefit of the Secured Parties, substantially in the form of Exhibit E hereto.

“Collateral Coverage Minimum” shall mean that the Mortgaged Properties shall comprise at least 85% of the PV-10 of the Credit Parties’ total Proved Reserves and at least 85% of the PV-10 of the Credit Parties’ total Proved Developed Producing Reserves, in each case, included in the most recent Reserve Report delivered pursuant to Section 9.14 (and, if not included in the most recent Reserve Report, the Oil and Gas Properties included in the EnVenQuarterNorth Acquisition Reserve Report (if the QuarterNorth Acquisition has been consummated)).

“Commitment” shall mean, (eee) with respect to each Lender that is a Lender on the Ninth Amendment Implementation Date, the amount set forth opposite such Lender’s name on Schedule 1.1(a) as such Lender’s “Commitment” and (fff) in the case of any Lender that becomes a Lender after the Ninth Amendment Implementation Date, the amount specified as such Lender’s “Commitment” in the Assignment and Acceptance pursuant to which such Lender assumed a portion of the Total Commitment or in the Incremental Agreement pursuant to which such Lender joined this Agreement and made its initial Commitment, in each case as the same may be increased, decreased or otherwise adjusted from time to time pursuant to terms of this Agreement.

“Commitment Fee” shall have the meaning provided in Section 4.1(a).

“Commitment Fee Rate” shall mean, for any day, with respect to the Available Commitment on such day, the applicable rate per annum set forth next to the row heading “Commitment Fee Rate” in the definition of “Applicable Margin” and based upon the Utilization Percentage in effect on such day.

“Commitment Percentage” shall mean, at any time, for each Lender, the percentage obtained by dividing (ggg) such Lender’s Commitment at such time by (hhh) the amount of the Total Commitment at such time; provided that at any time when the Total Commitment shall have been terminated, each Lender’s Commitment Percentage shall be the percentage obtained by dividing (i) such Lender’s Total Exposure at such time by (ii) the aggregate Total Exposures of all Lenders at such time.

“Commodity Exchange Act” shall mean the Commodity Exchange Act (7 U.S.C. § 1 et seq.), as amended from time to time, and any successor statute, and any regulations promulgated thereunder.

“Confidential Information” shall have the meaning provided in Section 13.16.

“Connection Income Taxes” shall mean Other Connection Taxes that are imposed on or measured by net income (however denominated) or that are franchise Taxes or branch profits Taxes.

“Consolidated Current Assets” means, as of any date of determination, the current assets of the Borrower and its Restricted Subsidiaries determined on a consolidated basis in accordance with GAAP, plus, to the extent not already included therein, all Available Commitments as of such date; provided that for purposes of this definition, current assets shall exclude non-cash assets required to be included in consolidated current assets of the Borrower and its Restricted Subsidiaries as a result of the application of Accounting Standards Codifications 815, 842 or 410.

“Consolidated Current Liabilities” means, as of any date of determination, the current liabilities of the Borrower and its Restricted Subsidiaries determined on a consolidated basis in accordance with GAAP, minus, to the extent included therein, the current portion of long-term Indebtedness outstanding under this Agreement; provided that for purposes of this definition, current liabilities shall exclude non-cash liabilities required to be included in consolidated current liabilities of the Borrower and its Restricted Subsidiaries as a result of the application of Accounting Standards Codifications 815, 842 or 410, but shall expressly include any unpaid liabilities for cash charges or payments that have been incurred as a result of the termination of any Hedge Transaction.

“Consolidated Net Income” shall mean, with respect to any Person for any period, the aggregate of the Net Income of such Person and its subsidiaries for such period, on a consolidated basis; provided, however, that, without duplication,

(iii)any net after tax extraordinary, nonrecurring or unusual gains or losses or income or expense or charge (less all fees and expenses relating thereto) including any severance, relocation, operating expenses directly attributable to the implementation of cost savings initiatives, any expenses related to any reconstruction, decommissioning, recommissioning or reconfiguration of fixed assets for alternative uses, fees, expenses or charges relating to facilities closing costs, curtailments or modifications to pension and post-retirement employee benefit plans, excess pension charges, acquisition integration costs, facilities opening costs, project start-up costs, signing, retention or completion bonuses, and expenses or charges related to any offering of Equity Interests or debt securities of the Borrower, Holdings or any Parent Entity, any Investment, acquisition, Disposition, recapitalization or issuance, repayment, refinancing, amendment or modification of Indebtedness (in each case, whether or not successful), and any fees, expenses, charges or change in control payments related to the Transactions (including any Transaction Expenses incurred before, on or after the Closing Date), in each case, shall be excluded,

(iv)any net after tax income or loss from Disposed of, abandoned, transferred, closed or discontinued operations or fixed assets and any net after tax gain or loss on disposal of Disposed of, abandoned, transferred, closed or discontinued operations or fixed assets shall be excluded,

(v)any net after tax gain or loss (less all fees and expenses or charges relating thereto) attributable to business Dispositions or asset Dispositions other than in the ordinary course of business (as determined in good faith by the management of the Borrower) shall be excluded,

(vi)any net after tax income or loss (less all fees and expenses or charges relating thereto) attributable to the early extinguishment of Indebtedness, Hedge Transactions or other derivative instruments shall be excluded,

(vii)(A) the Net Income for such period of any Person that is not a subsidiary of such Person, or is a Restricted Foreign Subsidiary or an Unrestricted Subsidiary or that is accounted for by the equity method of accounting, shall be included only to the extent of the amount of dividends or distributions or other payments paid in cash (or to the extent converted into cash) to the referent Person or a subsidiary thereof (other than a Restricted Foreign Subsidiary or an Unrestricted Subsidiary of such referent Person) in respect of such period and (B) the Net Income for such period shall include any ordinary course dividend, distribution or other payment in cash (or to the extent converted into cash) received by the referent Person or a subsidiary thereof (other than a Restricted Foreign Subsidiary or an Unrestricted Subsidiary of such referent Person) from any Person in excess of, but without duplication of, the amounts included in subclause (v),

(viii)the cumulative effect of a change in accounting principles during such period shall be excluded,

(ix)effects of purchase accounting adjustments (including the effects of such adjustments pushed down to such Person and its Subsidiaries) in component amounts required or permitted by GAAP, resulting from the application of purchase accounting or the amortization or write-off of any amounts thereof, net of taxes, shall be excluded,

(x)any impairment charges or asset write-offs, in each case pursuant to GAAP, and the amortization of intangibles arising pursuant to GAAP, and any impairment charges, asset write-offs or write-down, including ceiling test write-downs, on Oil and Gas Properties under GAAP or SEC guidelines shall be excluded,

(xi)any noncash compensation charge or expenses realized or resulting from stock option plans, employee benefit plans or post-employment benefit plans, or grants or sales of stock, stock appreciation or similar rights, stock options, restricted stock, preferred stock or other rights shall be excluded,

(xii)accruals and reserves that are established or adjusted within twelve months after the Closing Date and that are so required to be established or adjusted in accordance with GAAP or as a result of adoption or modification of accounting policies shall be excluded,

(xiii)non-cash gains, losses, income and expenses resulting from fair value accounting required by the applicable standard under GAAP and related interpretations shall be excluded,

(xiv)any currency translation gains and losses related to currency remeasurements of Indebtedness shall be excluded,

(xv)(i) the non-cash portion of “straight-line” rent expense shall be excluded and (ii) the cash portion of “straight-line” rent expense which exceeds the amount expensed in respect of such rent expense shall be included,

(xvi)(a) to the extent covered by insurance and actually reimbursed, or, so long as such Person has made a determination that there exists reasonable evidence that such amount will in fact be reimbursed by the insurer and only to the extent that such amount is (i) not denied by the applicable carrier in writing within 180 days and (ii) in fact reimbursed within 365 days of the date of such evidence (with a deduction for any amount so added back to the extent not so reimbursed within 365 days), expenses with respect to liability or casualty events or business interruption shall be excluded and (b) amounts estimated

in good faith to be received from insurance in respect of lost revenues or earnings in respect of liability or casualty events or business interruption shall be included (with a deduction for amounts actually received up to such estimated amount to the extent included in Net Income in a future period),

(xvii)without duplication, an amount equal to the amount of distributions actually made to any parent or equity holder of such Person in respect of such period in accordance with Section 10.6(f)(i) shall be included as though such amounts had been paid as income taxes directly by such person for such period, and

(xviii)non-cash charges for deferred tax asset valuation allowances shall be excluded (except to the extent reversing a previously recognized increase to net income).

“Consolidated Total Assets” shall mean, as of any date of determination, the amount that would, in conformity with GAAP, be set forth opposite the caption “total assets” (or any like caption) on a consolidated balance sheet of the Borrower and the Restricted Domestic Subsidiaries, without giving effect to any amortization of the amount of intangible assets since the Closing Date, calculated on a pro forma basis after giving effect to any subsequent acquisition or Disposition of a Person or business.

“Consolidated Total Debt” shall mean, as of any date of determination, (iii) the sum of (without duplication) all Indebtedness (other than letters of credit or bank guarantees, to the extent undrawn) consisting of Capital Lease Obligations, Indebtedness for borrowed money, Disqualified Stock and any earn-outs (if such earn-outs constitute liabilities on the balance sheet of such Person in accordance with GAAP) of the Borrower and the Restricted Subsidiaries on such date determined on a consolidated basis in accordance with GAAP minus (jjj) the aggregate amount of Unrestricted Cash subject to a Control Agreement on such date up to (but not exceeding) $50,000,000.

“Consolidated Total Debt to EBITDAX Ratio” shall mean, as of any date of determination, the ratio of (kkk) Consolidated Total Debt as of the last day of the most recent Test Period to (lll) EBITDAX for such Test Period; provided that the Consolidated Total Debt to EBITDAX Ratio shall be determined for the relevant Test Period on a Pro Forma Basis.

“Contractual Requirement” shall have the meaning provided in Section 8.3.

“Control Agreement” shall mean a control agreement or other similar agreement by and among an Agent, a Credit Party and the depositary bank, securities intermediary or commodities intermediary, as applicable, in form and substance reasonably satisfactory to the Collateral Agent, in order to give the Collateral Agent “control” (within the meaning set forth in Section 9-104) of the UCC) of such account.

“Corresponding Tenor” with respect to any Available Tenor means, as applicable, either a tenor (including overnight) or an interest payment period having approximately the same length (disregarding business day adjustment) as such Available Tenor.

“Covered Entity” means any of the following:

(i)a “covered entity” as that term is defined in, and interpreted in accordance with, 12 C.F.R. § 252.82(b);

(ii)a “covered bank” as that term is defined in, and interpreted in accordance with, 12 C.F.R. § 47.3(b); or

(iii)a “covered FSI” as that term is defined in, and interpreted in accordance with, 12 C.F.R. § 382.2(b).

“Covered Party” has the meaning assigned to it in Section 13.25.

“Credit Documents” shall mean this Agreement, the Guarantee, the Security Documents, each Letter of Credit, any promissory notes issued by the Borrower under this Agreement, any Incremental Agreement and any Intercreditor Agreement with respect to the Facility entered into on or after the Closing Date to which the Collateral Agent is party.

“Credit Event” shall mean and include the making (but not the conversion or continuation) of a Loan and the issuance of a Letter of Credit.

“Credit Party” shall mean each of the Borrower and the Guarantors.

“Cure Amount” shall have the meaning provided in Section 11.12(a).

“Cure Deadline” shall have the meaning provided in Section 11.12(a).

“Cure Right” shall have the meaning provided in Section 11.12(a).

“Current Ratio” shall mean, as of any date of determination, the ratio of (mmm) Consolidated Current Assets as of the last day of the most recent Test Period ended on or prior to such date of determination to (nnn) Consolidated Current Liabilities as of the last day of such Test Period.

“Daily Simple SOFR” means, for any day (a “SOFR Rate Day”), a rate per annum equal to SOFR for the day (such day “SOFR Determination Date”) that is five (5) U.S. Government Securities Business Day prior to (ooo) if such SOFR Rate Day is a U.S. Government Securities Business Day, such SOFR Rate Day or (ppp) if such SOFR Rate Day is not a U.S. Government Securities Business Day, the U.S. Government Securities Business Day immediately preceding such SOFR Rate Day, in each case, as such SOFR is published by the SOFR Administrator on the SOFR Administrator’s Website. Any change in Daily Simple SOFR due to a change in SOFR shall be effective from and including the effective date of such change in SOFR without notice to the Borrower.

“Default” shall mean any event, act or condition that with notice or lapse of time, or both, would constitute an Event of Default.

“Default Rate” shall have the meaning provided in Section 2.8(d).

“Default Right” has the meaning assigned to that term in, and shall be interpreted in accordance with, 12 C.F.R. §§ 252.81, 47.2 or 382.1, as applicable.

“Defaulting Lender” shall mean any Lender whose acts or failures to act, whether directly or indirectly, cause it to meet any part of the definition of “Lender Default”.

“Disposition” shall have the meaning provided in Section 10.4.

“Dispose” or “Disposed of” shall have a correlative meaning to the defined term of “Disposition”.

“Disqualified Stock” shall mean, with respect to any Person, any Equity Interests of such Person that, by its terms, or by the terms of any security into which it is convertible or for which it is putable or exchangeable, or upon the happening of any event, matures or is mandatorily redeemable (other than solely for Qualified Equity Interests), other than as a result of a change of control or asset sale, pursuant to a sinking fund obligation or otherwise, or is redeemable at the option of the holder thereof (other than as a result of a change of control or asset sale to the extent the terms of such Equity Interests provide that such Equity Interests shall not be required to be repurchased or redeemed until the Maturity Date as in effect at the time of issuance has occurred or such repurchase or redemption is otherwise permitted by this Agreement (including as a result of a waiver hereunder)), in whole or in part, in each case prior to the date that is 180 days after the Maturity Date hereunder as in effect at the time of issuance; provided that, if such Equity Interests are issued to any plan for the benefit of employees of the Borrower or its Subsidiaries or by any such plan to such employees, such Equity Interests shall not constitute Disqualified Stock solely because it may be required to be repurchased by the Borrower or its Subsidiaries in order to satisfy applicable statutory or regulatory obligations; provided, further, that any Equity Interests held by any future, present or former employee, director, manager or consultant of the Borrower, any of its Subsidiaries or any of its Parent Entities or any other entity in which the Borrower or a Restricted Subsidiary has an Investment and is designated in good faith as an “affiliate” by the board of directors or managers of the Borrower, in each case pursuant to any equity holders’ agreement, management equity plan or stock incentive plan or any other management or employee benefit plan or agreement shall not constitute Disqualified Stock solely because it may be required to be repurchased by the Borrower or its Subsidiaries.

“Distressed Person” shall have the meaning provided in the definition of “Lender-Related Distress Event”.

“Dollar-Denominated Production Payments” shall mean production payment obligations recorded as liabilities in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Dollar Equivalent” shall mean, at the time of determination thereof, (qqq) if an amount is expressed in Dollars, such amount, (rrr) if an amount is expressed in an Alternate Currency, the equivalent of such amount in Dollars determined by using the rate of exchange for the purchase of the Dollars with the Alternate Currency last provided (either by publication or otherwise provided to the Administrative Agent) by Reuters on the Business Day (New York City time) immediately preceding the date of determination or if such service ceases to be available or ceases to provide a rate of exchange for the purchase of dollars with the Alternate Currency, as provided by such other publicly available information service which provides that rate of exchange at such time in place of Reuters chosen by the Administrative Agent in its sole discretion (or if such service ceases to be available or ceases to provide such rate of exchange, the equivalent of such amount in Dollars as determined by the Administrative Agent using any method of determination it deems appropriate in its sole discretion).

“Dollars”, “dollars” and “$” shall mean dollars in lawful currency of the United States of America.

“Domestic Subsidiary” shall mean each Subsidiary of the Borrower that is organized under the laws of the United States or any state thereof, or the District of Columbia.

“Drawing” shall have the meaning provided in Section 3.4(b).

“EBITDAX” shall mean, with respect to the Borrower and the Restricted Domestic Subsidiaries on a consolidated basis for any period, the Consolidated Net Income of the Borrower and the Restricted Domestic Subsidiaries for such period plus (sss) the sum of (in each case without duplication and to the

extent the respective amounts described in subclauses (i) through (xii) of this clause 0 are otherwise deducted (and not added back) in arriving at such Consolidated Net Income for the respective period for which EBITDAX is being determined):

(i)provision for Taxes based on income, profits or capital of the Borrower and the Restricted Domestic Subsidiaries for such period, including, without limitation, state, franchise and similar taxes and foreign withholding taxes (including penalties and interest related to taxes or arising from tax examinations),

(ii)Interest Expense (and to the extent not included in Interest Expense, (x) solely to the extent deducted from Consolidated Net Income, all cash dividend payments (excluding items eliminated in consolidation) on any series of preferred stock or Disqualified Stock and (y) costs of surety bonds in connection with financing activities and costs and expenses in connection with surety and bonding requirements) of the Borrower and the Restricted Domestic Subsidiaries for such period (net of interest income of the Borrower and the Restricted Domestic Subsidiaries for such period),

(iii)depreciation, depletion and amortization expenses of the Borrower and the Restricted Domestic Subsidiaries for such period including, the amortization of intangible assets, deferred financing fees and Capitalized Software Expenditures, accretion on asset retirement obligations in accordance with ASC 410 Asset Retirement and Environmental Obligations and amortization of unrecognized prior service costs and actuarial gains and losses related to pensions and other post-employment benefits,

(iv)business optimization expenses and other restructuring charges or reserves (which, for the avoidance of doubt, shall include, without limitation, the effect of inventory optimization programs, facility closure, facility consolidations, retention, severance, systems establishment costs, contract termination costs, future lease commitments and excess pension charges),

(v)any other non-cash charges; provided that, for purposes of this subclause (v), any non-cash charges or losses shall be treated as cash charges or losses in any subsequent period during which cash disbursements attributable thereto are made (but excluding, for the avoidance of doubt, amortization of a prepaid cash item that was paid in a prior period),

(vi)the amount of management, consulting, monitoring, transaction and advisory fees and related expenses paid to the Sponsors and any other Co-Investor (or any accruals related to such fees and related expenses) during such period to the extent permitted under Section 9.9(j),

(vii)any costs or expense incurred pursuant to any management equity plan or stock option plan or any other management or employee benefit plan or agreement or any stock subscription or shareholder agreement, to the extent that such cost or expenses are funded with cash proceeds contributed to the capital of the Borrower or a Subsidiary Guarantor or net cash proceeds of an issuance of Equity Interests of the Borrower (other than Disqualified Stock),

(viii)any deductions (less any additions) attributable to minority interests except, in each case, to the extent of cash paid or received,

(ix)the amount of any loss attributable to a new plant or facility, until the date that is 12 months after the date of completing construction of or acquiring such plant or facility, as the case may be; provided that (A) such losses are reasonably identifiable and factually supportable and certified by a

responsible officer of the Borrower and (B) losses attributable to such plant or facility after 12 months from the date of completing such construction of or acquiring such plant or facility, as the case may be, shall not be included in this clause (ix),

(x)exploration expenses or costs (to the extent the Borrower adopts the successful efforts method of accounting),

(xi)with respect to any joint venture that is not a Restricted Domestic Subsidiary and solely to the extent relating to any net income referred to in clause (v) of the definition of “Consolidated Net Income”, an amount equal to the proportion of those items described in clauses (i) and (ii) above relating to such joint venture corresponding to the Borrower’s and the Restricted Domestic Subsidiaries’ proportionate share of such joint venture’s Consolidated Net Income (determined as if such joint venture were a Restricted Domestic Subsidiary), and

(xii)one-time costs associated with commencing Public Company Compliance;

minus(ttt) the sum of (without duplication and to the extent the amounts described in this clause (b) increased such Consolidated Net Income for the respective period for which EBITDAX is being determined) non-cash items increasing Consolidated Net Income of the Borrower and the Restricted Domestic Subsidiaries for such period (but excluding any such items (A) in respect of which cash was received in a prior period or will be received in a future period or (B) which represent the reversal of any accrual of, or cash reserve for, anticipated cash charges that reduced EBITDAX in any prior period).

Notwithstanding anything to the contrary contained herein and subject to adjustments as provided under clause (a)(x) above and other adjustments permitted hereunder with respect to acquisitions, Dispositions, and other transactions occurring following the Closing Date and pursuant to the definition of “Pro Forma Basis”, EBITDAX for any period of four-consecutive fiscal quarters ending on or before September 30, 2018, such amounts shall be annualized (i) for the fiscal quarter ending March 31, 2018, by taking EBITDAX for the fiscal quarter ending March 31, 2018, and multiplying it by four (4); (ii) for the fiscal quarter ending June 30, 2018, by taking EBITDAX for the two fiscal quarters ending June 30, 2018 and multiplying it by two (2); and (iii) for the fiscal quarter ending September 30, 2018, by taking EBITDAX for the three (3) fiscal quarters ending September 30, 2018, and multiplying it by four (4) and dividing it by three (3). EBITDAX will be deemed to be $140,000,000 for the fiscal quarter ended March 31, 2018.

Notwithstanding the foregoing, the aggregate amount of add-backs made pursuant to subclause (iv) above and the aggregate amount of operating expense reductions and other operating improvements, synergies or cost savings reasonably expected to result from the Transactions that are included in EBITDAX in any four-fiscal-quarter period shall not exceed 15% of EBITDAX (prior to giving effect to such add-backs) for such period.

“EEA Financial Institution” shall mean (uuu) any credit institution or investment firm established in any EEA Member Country that is subject to the supervision of an EEA Resolution Authority, (vvv) any entity established in an EEA Member Country that is a parent of an institution described in clause 0 of this definition, or (www) any financial institution established in an EEA Member Country that is a subsidiary of an institution described in clauses 0 or 0 of this definition and is subject to consolidated supervision with its parent;

“EEA Member Country” shall mean any of the member states of the European Union, Iceland, Liechtenstein, and Norway.

“EEA Resolution Authority” shall mean any public administrative authority or any person entrusted with public administrative authority of any EEA Member Country (including any delegee) having responsibility for the resolution of any EEA Financial Institution.

“Electronic Signature” means an electronic sound, symbol, or process attached to, or associated with, a contract or other record and adopted by a Person with the intent to sign, authenticate or accept such contract or record.

“Engineering Reports” shall have the meaning provided in Section 2.14(c).

“EnVen” shall mean EnVen Energy Corporation, a Delaware corporation.

“EnVen Merger” shall mean the consummation of the transactions described in the EnVen Merger Agreement, pursuant to which EnVen merged with and into the Borrower, with the Borrower as the surviving entity.

“EnVen Merger Agreement” shall mean that certain Agreement and Plan of Merger dated as of September 21, 2022, among Holdings, the Borrower, EnVen and the other parties thereto.

“EnVen Notes” shall mean EnVen’s 11.750% Notes due 2026 issued pursuant to the EnVen Notes Indenture in aggregate principal amount of $258,000,000 as of the Ninth Amendment Effective Date, as such aggregate principal amount shall be reduced from time to time in accordance with the terms thereof or the EnVen Notes Indenture.

“EnVen Notes Indenture” shall mean the Indenture, dated as of April 15, 2021, under which the EnVen Notes were issued, among Energy Ventures GoM LLC, as issuer, EnVen Finance Corporation, as co-issuer, the guarantors party thereto and Wilmington Trust, National Association (or any successor), as trustee and collateral agent, as amended, restated, supplemented or otherwise modified from time to time in accordance with the requirements thereof and of this Agreement.

“EnVen Reserve Report” shall have the meaning provided in the Ninth Amendment.

“Environmental Claims” shall mean any and all actions, suits, orders, decrees, demands, demand letters, claims, liens, notices of noncompliance, restrictions on use, operations or transferability, violation or potential responsibility or investigation (other than internal reports prepared by or on behalf of the Borrower or any of the Subsidiaries (xxx) in the ordinary course of such Person’s business or (yyy) as required in connection with a financing transaction or an acquisition or disposition of real estate) or proceedings arising under or based upon any Environmental Law or any permit issued, or any approval given, under any such Environmental Law (hereinafter, “Claims”), including, without limitation, (i) any and all Claims by governmental or regulatory authorities for enforcement, cleanup, removal, response, remedial or other actions or damages pursuant to any applicable Environmental Law and (ii) any and all Claims by any third party seeking damages, contribution, indemnification, cost recovery, compensation or injunctive relief relating to the presence, release or threatened release of Hazardous Materials or arising from alleged injury or threat of injury to health or safety (to the extent relating to human exposure to Hazardous Materials), or the environment including, without limitation, ambient air, surface water, groundwater, land surface and subsurface strata and natural resources such as wetlands.

“Environmental Law” shall mean any applicable Federal, state, foreign or local statute, law, rule, regulation, ordinance, code and rule of common law now or hereafter in effect and in each case as amended, and any binding judicial or administrative interpretation thereof, including any binding judicial or

administrative order, consent decree or judgment, relating to the protection of the environment, including, without limitation, ambient air, surface water, groundwater, land surface and subsurface strata and natural resources such as wetlands, or human health or safety (to the extent relating to human exposure to Hazardous Materials), or Hazardous Materials.

“Equity Interests” of any person shall mean any and all shares, interests, rights to purchase or otherwise acquire, warrants, options, participations or other equivalents of or interests in (however designated) equity or ownership of such person, including any preferred stock, any limited or general partnership interest and any limited liability company membership interest, and any securities or other rights or interests convertible into or exchangeable for any of the foregoing.

“ERISA” shall mean the Employee Retirement Income Security Act of 1974, as amended from time to time. Section references to ERISA are to ERISA as in effect on the Closing Date and any subsequent provisions of ERISA amendatory thereof, supplemental thereto or substituted therefor.

“ERISA Affiliate” shall mean each person (as defined in Section 3(9) of ERISA) that together with the Borrower would be deemed to be a “single employer” within the meaning of Section 414(b) or (c) of the Code or, solely for purposes of Section 302 of ERISA and Section 412 of the Code, is treated as a single employer under Section 414 of the Code.

“EU Bail-In Legislation Schedule” shall mean the EU Bail-In Legislation Schedule published by the Loan Market Association (or any successor person), as in effect from time to time.

“Euro” and “€” shall mean the lawful single currency unit of the Participating Member States.

“Event of Default” shall have the meaning provided in Section 11.

“Excess Cash” means, at any time, the aggregate amount of all cash and Permitted Investments of the Borrower and the Restricted Subsidiaries (other than Excluded Cash) in excess of $125,000,000.

“Exchange Act” shall mean the Securities Exchange Act of 1934, as amended, and the rules and regulations promulgated thereunder.

“Exchange Rate” shall mean on any day with respect to any currency (other than Dollars), the applicable currency exchange rate determined by reference to clauses (a) and (b) of the definition of “Dollar Equivalent” in this Agreement.

“Excluded Accounts” shall mean (zzz) each account all or substantially all of the deposits in which consist of amounts utilized to fund payroll, employee benefit or tax obligations of the Borrower and its Subsidiaries, (aaaa) fiduciary accounts, (bbbb) each account listed on Schedule 1.1(i) and (cccc) other accounts so long as the aggregate average daily maximum balance in any such other account over a 30-day period does not at any time exceed $1,000,000; provided that the aggregate daily maximum balance for all such bank accounts excluded pursuant to this clause 0 on any day shall not exceed $5,000,000; provided that in no event shall any of the principal operating or collection accounts (including any accounts into which any purchaser remits the proceeds for the sale of Hydrocarbons or Oil and Gas Properties) of the Borrower or any other Credit Party constitute an Excluded Account.

“Excluded Cash” means (dddd) any cash to be used to pay obligations of the Borrower and the Restricted Subsidiaries then due and owing to unaffiliated third parties generally for which the Borrower or any Restricted Subsidiary has issued checks or has initiated wires or ACH transfers (or will issue checks or initiate wires or ACH transfers within five (5) Business Days) in order to pay such obligations and (eeee) any cash set aside (including cash held in suspense or trust accounts) (i) to make or pay payroll, employee wage and benefit payments and trust and fiduciary obligations and similar obligations, (ii) in collateral accounts with respect to Letters of Credit, (iii) for the payment of taxes of the Borrower and the Restricted Subsidiaries due and payable within the existing fiscal quarter, and (iv) for royalty obligations, working interest obligations, and production payments, in each case owing to third parties.

“Excluded Equity Interests” shall mean (ffff) any Equity Interests with respect to that, in the reasonable judgment of the Administrative Agent and the Borrower evidenced in writing delivered to the Agent, the cost or other consequences of pledging such Equity Interests in favor of the Secured Parties under the Security Documents shall be excessive in view of the benefits to be obtained by the Secured Parties therefrom, (gggg) solely in the case of any pledge of Equity Interests of any Foreign Subsidiary or FSHCO (in each case, that is owned directly by the Borrower or a Guarantor) to secure the Obligations, any Equity Interest that is Voting Stock of such Foreign Subsidiary or FSHCO in excess of 65% of the outstanding Equity Interests of such class, (hhhh) any Equity Interests to the extent the pledge thereof would be prohibited by any Requirement of Law, (iiii) in the case of (i) any Equity Interests of any Subsidiary to the extent the pledge of such Equity Interests is prohibited by Contractual Requirements or (ii) any Equity Interests of any Subsidiary that is not a Wholly owned Subsidiary at the time such Subsidiary becomes a Subsidiary, any Equity Interests of each such Subsidiary described in clause 0 or 0 to the extent (A) that a pledge thereof to secure the Obligations is prohibited by any applicable Contractual Requirement (other than customary non-assignment provisions that are ineffective under the Uniform Commercial Code or other applicable Requirements of Law), (B) any Contractual Requirement prohibits such a pledge without the consent of any other party; provided that this clause 0 shall not apply if (1) such other party is a Credit Party or a Wholly owned Subsidiary or (2) consent has been obtained to consummate such pledge (it being understood that the foregoing shall not be deemed to obligate the Borrower or any Subsidiary to obtain any such consent) and for so long as such Contractual Requirement or replacement or renewal thereof is in effect, or (C) a pledge thereof to secure the Obligations would give any other party (other than a Credit Party or a Wholly owned Subsidiary) to any Contractual Requirement governing such Equity Interests the right to terminate its obligations thereunder (other than customary non-assignment provisions that are ineffective under the Uniform Commercial Code or other applicable Requirement of Law), (jjjj) the Equity Interests of any Immaterial Subsidiary and any Unrestricted Subsidiary, (kkkk) the Equity Interests of any Subsidiary of a Foreign Subsidiary, (llll) any Equity Interests of any Subsidiary to the extent that the pledge of such Equity Interests would result in material adverse tax consequences to the Borrower or any Subsidiary as reasonably determined by the Borrower in consultation with the Administrative Agent, and (mmmm) any Equity Interests set forth on Schedule 1.1(b) that have been identified on or prior to the Closing Date in writing to the Administrative Agent by an Authorized Officer of the Borrower and agreed to by the Administrative Agent.

“Excluded Hedge Obligation” shall mean, with respect to any Credit Party, any Swap Obligation if, and to the extent that, all or a portion of the liability of such Credit Party with respect to, or the grant by such Credit Party of a security interest to secure, such Swap Obligation (or any Guarantee thereof or other agreement or undertaking agreeing to guaranty, repay, indemnify or otherwise be liable therefor) is or becomes illegal under the Commodity Exchange Act or any rule, regulation or order of the Commodity Futures Trading Commission (or the application or official interpretation of any thereof) by virtue of such Credit Party’s failure for any reason to constitute an “eligible contract participant” as defined in the Commodity Exchange Act and the regulations thereunder at the time the guaranty obligation or other liability of such Credit Party or the grant of such security interest becomes or would become effective with respect to such Swap Obligation. If a

Swap Obligation arises under a master agreement governing more than one swap, such exclusion shall apply only to the portion of such Swap Obligation that is attributable to swaps for which such guaranty obligation or other liability or security interest is or becomes illegal.

“Excluded Subsidiary” shall mean (nnnn) each Domestic Subsidiary listed on Schedule 1.1(c) and each future Domestic Subsidiary, in each case, for so long as any such Subsidiary does not constitute a Material Subsidiary, (oooo) each Domestic Subsidiary that is not a Wholly owned Subsidiary (for so long as such Subsidiary remains a non wholly owned Restricted Subsidiary), (pppp) each Domestic Subsidiary that is prohibited by any applicable Contractual Requirement (but only to the extent such Contractual Requirement is not entered into in contemplation of such prohibition) from guaranteeing or granting Liens to secure the Obligations at the time such Subsidiary becomes a Restricted Subsidiary (and for so long as such restriction or any replacement or renewal thereof is in effect) and each Domestic Subsidiary that is prohibited by any applicable Requirement of Law from guaranteeing or granting Liens to secure the Obligations (and for so long as such restriction or any replacement or renewal thereof is in effect) or that would require consent, approval, license or authorization of a Governmental Authority to guarantee or grant Liens to secure the Obligations (unless such consent, approval, license or authorization has been received), (qqqq) any Foreign Subsidiary, (rrrr) any Domestic Subsidiary (i) that owns no material assets (directly or through its Subsidiaries) other than equity interests of one or more Foreign Subsidiaries that are CFCs or (ii) that is a direct or indirect Subsidiary of a Foreign Subsidiary, (ssss) each other Domestic Subsidiary acquired pursuant to a Permitted Acquisition financed with Indebtedness of the type incurred pursuant to Section 10.1(k) and would be permitted by the proviso contained in subclause (C) of Section 10.1(k) and each Restricted Subsidiary thereof that guarantees such Indebtedness to the extent and so long as the financing documentation relating to such Permitted Acquisition to which such Restricted Subsidiary is a party prohibits such Restricted Subsidiary from guaranteeing or granting a Lien on any of its assets to secure the Obligations, (tttt) any other Domestic Subsidiary with respect to which, (x) in the reasonable judgment of the Administrative Agent (and acknowledged in writing by the Administrative Agent) and the Borrower, the cost or other consequences of providing a Guarantee of or granting Liens to secure the Obligations shall be excessive in view of the benefits to be obtained by the Lenders therefrom or (y) providing such a Guarantee or granting such Liens would result in material adverse tax consequences as reasonably determined by the Borrower in consultation with the Administrative Agent, and (uuuu) each Unrestricted Subsidiary.

“Excluded Taxes” shall mean, with respect to the Administrative Agent, any Lender or any other recipient of any payment to be made by or on account of any obligation of any Credit Party hereunder or under any other Credit Document, (i) Taxes imposed on or measured by its overall net income or branch profits (however denominated, and including (for the avoidance of doubt) any backup withholding in respect thereof under Section 3406 of the Code or any similar provision of state, local or foreign law), and franchise (and similar) Taxes, in each case, (a) imposed on it by a jurisdiction (including any political subdivision thereof) as a result of such recipient being organized in, having its principal office in, or in the case of any Lender, having its applicable lending office in, such jurisdiction, or (b) that are Other Connection Taxes, (ii) U.S. federal withholding Tax imposed on any payment by or on account of any obligation of any Credit Party hereunder or under any other Credit Document that is required to be imposed on amounts payable to a Lender (other than to the extent such Lender is an assignee pursuant to a request by the Borrower under Section 13.7) pursuant to laws in force at the time such Lender becomes a party hereto (or designates a new lending office), except to the extent that such Lender (or its assignor, if any) was entitled, immediately prior to the designation of a new lending office (or assignment), to receive additional amounts or indemnification payments from any Credit Party with respect to such withholding Tax pursuant to Section 5.4, (iii) any withholding Tax imposed on any payment by or on account of any obligation of any Credit Party hereunder or under any other Credit Document that is attributable to the Administrative Agent’s, any Lender’s or any other recipient’s failure to comply with Section 5.4(d) or (e) or (iv) any Tax imposed under FATCA.

“Existing Letters of Credit” shall mean each letter of credit existing on the Closing Date and identified on Schedule 1.1(d) and any amendments, extensions and renewals thereof.

“Existing Talos Energy” shall have the meaning provided in the recitals to this Agreement.

“Facility” shall mean this Agreement and the Commitments and the extensions of credit made hereunder.

“Fair Market Value” shall mean, with respect to any asset or group of assets on any date of determination, the value of the consideration obtainable in a Disposition of such asset at such date of determination assuming a Disposition by a willing seller to a willing purchaser dealing at arm’s length and arranged in an orderly manner over a reasonable period of time having regard to the nature and characteristics of such asset, as determined by the Borrower in good faith.

“FATCA” shall mean Sections 1471 through 1474 of the Code, as of the date of this Agreement (or any amended or successor version that is substantively comparable and not materially more onerous to comply with), any current or future regulations or official interpretations thereof, any agreement entered into pursuant to Section 1471(b)(1) of the Code and any fiscal or regulatory legislation, rules or practices adopted pursuant to any intergovernmental agreement, treaty or convention among Governmental Authorities and implementing such Sections of the Code.

“Federal Funds Effective Rate” shall mean, for any day, the rate calculated by the NYFRB based on such day’s federal funds transactions by depositary institutions, as determined in such manner as shall be set forth on the NYFRB’s Website from time to time, and published on the next succeeding Business Day by the NYFRB as the effective federal funds rate; provided that if the Federal Funds Effective Rate as so determined would be less than 0.00%, such rate shall be deemed to be 0.00% for the purposes of this Agreement.

“Financial Officer” of any Person shall mean the Chief Financial Officer, principal accounting officer, Treasurer or Assistant Treasurer of such Person.

“Financial Performance Covenant” shall mean, as the context may require, either or both of the covenants of the Borrower set forth in Section 10.11.

“First Amendment” shall mean that certain Joinder, First Amendment to Credit Agreement, and Borrowing Base Reaffirmation Agreement dated as of July 3, 2019, by and among Holdings, the Borrower, each other Credit Party, the Administrative Agent, each Issuing Bank, the Swingline Lender and the Lenders party thereto.

“First Amendment Effective Date” shall mean the first date on which all conditions precedent set forth in Section 8 of the First Amendment shall have been satisfied.

“Floor” means the benchmark rate floor, if any, provided in this Agreement initially (as of the execution of this Agreement, the modification, amendment or renewal of this Agreement or otherwise) with respect to the Adjusted Term SOFR Rate or the Adjusted Daily Simple SOFR, as applicable. For the avoidance of doubt the initial Floor for each of Adjusted Term SOFR Rate or the Adjusted Daily Simple SOFR shall be 0.00%.

“Foreign Plan” shall mean any employee benefit plan, program, policy, arrangement or agreement maintained or contributed to by the Borrower or any of its Subsidiaries with respect to employees employed outside the United States.

“Foreign Subsidiary” shall mean each Subsidiary of the Borrower that is not a Domestic Subsidiary.

“Fourth Amendment” means the Fourth Amendment to Credit Agreement and Borrowing Base Redetermination Agreement, dated as of December 7, 2020, among Holdings, the Borrower, the Administrative Agent and the other Persons party thereto.

“Fourth Amendment Effective Date” means the “Effective Date” as defined in the Fourth Amendment.

“Franklin” shall mean Franklin Advisers, Inc., as investment manager on behalf of certain funds and accounts.

“Free Cash Flow” shall mean, as of any date of determination, the result of (vvvv) EBITDAX for the Applicable Period for which a certificate has been delivered pursuant to Section 9.1(a), minus(wwww) the sum, without duplication, of the following cash expenses or cash charges to the extent added back in the calculation of EBITDAX for such period: (i) Interest Expense, (ii) Taxes based on income, profits or capital, (iii) exploration expenses or costs, including plugging and abandonment expenses and (iv) to the extent not included in the foregoing, any other cash expense or cash charge that otherwise served to increase EBITDAX for such period, minus(xxxx) to the extent not already reducing EBITDAX for such period, the sum, without duplication, of (i) capital expenditures, (ii) Investments made in cash or cash equivalents in reliance on clauses (c), 10.5(g), (h), (l), (n), (q), (t), (y) or (z) of Section 10.5, (iii) Restricted Payments made in cash or cash equivalents in reliance on clauses (b), (e), (f), (g) or (j) of Section 10.6, and (iv) cash principal payments in respect of any Indebtedness for borrowed money (other than the Obligations and any prepayments, repurchases, redemptions or defeasances paid under Section 10.7(a)) that cannot be reborrowed pursuant to the terms of such Indebtedness, in each case, incurred or made by the Borrower and its Restricted Subsidiaries during such period, and (yyyy)minus the increase (or plus the decrease) in working capital from the last day immediately prior to the Applicable Period for which EBITDAX is calculated pursuant to the foregoing clause 0.

“Free Cash Flow Usage Period” shall mean (zzzz) for each fiscal quarter ending March 31, 2021, June 30, 2021, September 30, 2021 or December 31, 2021, the respective period (x) commencing on the date on which the Borrower delivered its financial statements in accordance with Section 9.1(a) or (b), as applicable, for the fiscal quarters ending, March 31, 2020, June 30, 2020, September 30, 2020 and December 31, 2020, and (y) ending on (but not including) the date on which the Borrower has delivered the Available Free Cash Flow Amount certificate to the Administrative Agent in accordance with Section 9.1(l) for the fiscal quarter ending March 31, 2021, June 30, 2021, September 30, 2021, and December 31, 2021, and (aaaaa) for each fiscal quarter ending March 31, 2022, and thereafter, each period commencing on the date on which the Borrower has delivered the Available Free Cash Flow Amount certificate to the Administrative Agent in accordance with Section 9.1(l) for the fourth most recently ended fiscal quarter and ending on (but not including) the date on which the Borrower has delivered the Available Free Cash Flow Amount certificate to the Administrative Agent in accordance with Section 9.1(l) for the most recently ended fiscal quarter.

“Fronting Fee” shall have the meaning provided in Section 4.1(c).

“FSHCO” shall mean any Domestic Subsidiary that owns (directly or through its Subsidiaries) no material assets other than the Equity Interests of one or more Foreign Subsidiaries that are CFCs.

“Fund” shall mean any Person (other than a natural person) that is (or will be) engaged in making, purchasing, holding or otherwise investing in commercial loans and similar extensions of credit in the ordinary course.

“GAAP” shall mean generally accepted accounting principles in the United States of America, as in effect from time to time.

“Governmental Authority” shall mean any nation, sovereign or government, any state, province, territory or other political subdivision thereof, and any entity or authority exercising executive, legislative, judicial, taxing, regulatory or administrative functions of or pertaining to government, including a central bank or stock exchange (including any supra-national bodies such as the European Union or the European Central Bank).

“Granting Lender” shall have the meaning provided in Section 13.6(g).

“Guarantee” shall mean the Guarantee made by any Guarantor in favor of the Collateral Agent for the benefit of the Secured Parties, substantially in the form of Exhibit C.

“Guarantee Obligations” shall mean, as to any Person, any obligation of such Person guaranteeing or intended to guarantee any Indebtedness of any other Person (the “primary obligor”) in any manner, whether directly or indirectly, including any obligation of such Person, whether or not contingent, (bbbbb) to purchase any such Indebtedness or any property constituting direct or indirect security therefor, (ccccc) to advance or supply funds (i) for the purchase or payment of any such Indebtedness or (ii) to maintain working capital or equity capital of the primary obligor or otherwise to maintain financial condition or liquidity of the primary obligor so as to enable the primary obligor to pay such Indebtedness, (ddddd) to purchase property, securities or services primarily for the purpose of assuring the owner of any such Indebtedness of the ability of the primary obligor to make payment of such Indebtedness or (eeeee) otherwise to assure or hold harmless the owner of such Indebtedness against loss in respect thereof; provided, however, that the term “Guarantee Obligations” shall not include endorsements of instruments for deposit or collection in the ordinary course of business or customary and reasonable indemnity obligations in effect on the Closing Date or entered into in connection with any acquisition or Disposition of assets permitted under this Agreement (other than such obligations with respect to Indebtedness). The amount of any Guarantee Obligation shall be deemed to be an amount equal to the stated or determinable amount of the Indebtedness in respect of which such Guarantee Obligation is made or, if not stated or determinable, the maximum reasonably anticipated liability in respect thereof (made using the assumption that such Person is required to perform thereunder) as determined by such Person in good faith.

“Guarantors” shall mean Holdings, each Intermediate Entity and each Domestic Subsidiary listed on Schedule 1.1(e) and each other Domestic Subsidiary (other than an Excluded Subsidiary) that becomes a party to the Guarantee after the Closing Date pursuant to Section 9.11 or otherwise.

“Hazardous Materials” shall mean (fffff) any petroleum or petroleum products, natural gas or natural gas liquids, radioactive materials, friable asbestos or asbestos containing materials, urea formaldehyde foam insulation, transformers or other equipment that contain dielectric fluid containing regulated levels of polychlorinated biphenyls, and radon gas, (ggggg) any chemicals, materials or substances defined as or included in the definition of “hazardous substances”, “hazardous waste”, “hazardous materials”, “extremely hazardous waste”, “restricted hazardous waste”, “toxic substances”, “toxic pollutants”, “contaminants”, or “pollutants”, or words of

similar import, under any applicable Environmental Law and (hhhhh) any other chemical, material or substance that is prohibited, limited or regulated by any Environmental Law.

“Hedge Agreements” shall mean (iiiii) any and all rate swap transactions, basis swaps, credit derivative transactions, forward rate transactions, commodity swaps, commodity options, forward commodity contracts, future contracts, equity or equity index swaps or options, bond or bond price or bond index swaps or options or forward bond or forward bond price or forward bond index transactions, interest rate options, forward foreign exchange transactions, cap transactions, floor transactions, collar transactions, credit spread transaction, repurchase transaction, reserve repurchase transaction, securities lending transaction, weather index transaction, spot contracts, currency swap transactions, cross-currency rate swap transactions, currency options, fixed-price physical delivery contracts, whether or not exchange traded, or any other similar transactions or any combination of any of the foregoing (including any options to enter into any of the foregoing), whether or not any such transaction is governed by or subject to any master agreement, and (jjjjj) any and all transactions of any kind, and the related confirmations, which are subject to the terms and conditions of, or governed by, any form of master agreement published by the International Swaps and Derivatives Association, Inc., any International Foreign Exchange Master Agreement or any other master agreement (any such master agreement, together with any related schedules, a “Master Agreement”), including any such obligations or liabilities under any Master Agreement. Notwithstanding the foregoing, agreements or obligations to physically sell any commodity at any index-based price shall not be considered Hedge Agreements or Hedging Obligations, respectively.

“Hedge Bank” shall mean (kkkkk) any Person (other than the Borrower or any of its Subsidiaries) that (x) at the time it enters into a Hedge Transaction is a Lender or Agent or an Affiliate of a Lender or Agent, or (y) at any time after it enters into a Hedge Transaction it becomes a Lender or Agent or an Affiliate of a Lender or Agent or (lllll) with respect to any Hedge Transaction that is in effect on the Closing Date, any Person (other than the Borrower or any of its Subsidiaries) that (x) is a Lender or Agent or an Affiliate of a Lender or Agent on the Closing Date or (y) is listed on Schedule 1.1(f) (and, in the case of this clause (y), any Affiliate of such Person).

“Hedge Transaction” shall mean any trade or other transaction entered into by a Person under a Hedge Agreement.

“Hedging Condition” shall mean the circumstance that, as of the date that is 60 days following the Closing Date, the Borrower shall have delivered to the Administrative Agent reasonably satisfactory evidence demonstrating that the Credit Parties have entered into Hedge Transactions with approved counterparties with respect to not less than 50% of the quarterly projected production of oil and natural gas, calculated separately, from Proved Developed Producing Reserves included in the Initial Reserve Report for each quarter during the period of twenty-four (24) consecutive months immediately following the Closing Date at prices acceptable to the Administrative Agent.

“Hedging Obligations” shall mean, with respect to any Person, the obligations of such Person under Hedge Transactions other than Excluded Hedge Obligations.

“Highest Lawful Rate” shall mean, with respect to each Lender, the maximum nonusurious interest rate, if any, that at any time or from time to time may be contracted for, taken, reserved, charged or received on the Loans under laws applicable to such Lender that are presently in effect or, to the extent allowed by law, under such applicable laws that may hereafter be in effect and that allow a higher maximum nonusurious interest rate than applicable laws allow as of the date hereof.

“Historical Financial Statements” shall mean (mmmmm) the audited consolidated balance sheets of the Borrower and its consolidated Subsidiaries as of December 31, 2017, and the related audited statements of income and comprehensive income, statements of changes in shareholders’ equity and statements of cash flows for each of the fiscal years in the three-year period ended December 31, 2017, (nnnnn) the draft unaudited interim consolidated balance sheets of the Borrower and its consolidated Subsidiaries as of March 31, 2018, and the related statement of income and comprehensive income, statement of changes in shareholders’ equity and statement of cash flows for each of the fiscal quarters ended March 31, 2018, and comparable financial statements for the comparable period of the prior year, each of which may be presented without commentary, footnotes or other explanatory information, (ooooo) the audited consolidated balance sheets of Stone Energy and its consolidated Subsidiaries as of December 31, 2017, and (ppppp) the unaudited interim consolidated balance sheets of Stone Energy and its consolidated Subsidiaries as of as of March 31, 2018, and the related statement of income and comprehensive income, statement of changes in shareholders’ equity and statement of cash flows for each of the fiscal quarters ended March 31, 2018, and comparable financial statements for the comparable period of the prior year.

“Holdings” shall have the meaning provided in the recitals to this Agreement.

“Hydrocarbon Interests” shall mean all rights, titles, interests and estates now or hereafter acquired in and to oil and gas leases, oil, gas and mineral leases, or other liquid or gaseous hydrocarbon leases, mineral fee interests, overriding royalty and royalty interests, net profit interests and production payment interests, including any reserved or residual interests of whatever nature.

“Hydrocarbons” shall mean oil, gas, casinghead gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all products refined or separated therefrom.

“IBA” shall have the meaning provided in Section 1.10.

“Immaterial Subsidiary” shall mean any Subsidiary that is not a Material Subsidiary.

“Increasing Lender” shall have the meaning provided in Section 2.16.

“Incremental Agreement” shall have the meaning provided in Section 2.16.

“Incremental Increase” shall have the meaning provided in Section 2.16.

“Indebtedness” of any Person shall mean, if and to the extent (other than with respect to clause 0 below) the same would constitute indebtedness or a liability in accordance with GAAP, without duplication, (qqqqq) all indebtedness of such Person for borrowed money, (rrrrr) all obligations of such Person evidenced by bonds, debentures, notes, loan agreements or other similar instruments, (sssss) the deferred purchase price of assets or services that in accordance with GAAP would be required to be shown as a liability on the balance sheet of such Person (other than (i) any earn-out obligation until such obligation becomes a liability on the balance sheet of such Person in accordance with GAAP and (ii) obligations resulting under firm transportation contracts or take or pay contracts entered into in the ordinary course of business), (ttttt) the face amount of all letters of credit issued for the account of such Person and, without duplication, all drafts drawn thereunder, (uuuuu) the principal component of all Capitalized Lease Obligations of such Person, (vvvvv) net Hedging Obligations of such Person, (wwwww) all indebtedness (excluding prepaid interest thereon) of any other Person secured by any Lien on any property owned by such Person, whether or not such Indebtedness has been assumed by such Person, (xxxxx) the amount of all obligations of such Person with respect to the redemption, repayment or other repurchase in respect of Disqualified Stock (excluding accrued dividends that have not increased the liquidation preference of such

Disqualified Stock), (yyyyy) the undischarged balance of any production payment created by such Person or for the creation of which such Person directly or indirectly received payment and (zzzzz) without duplication, all Guarantee Obligations of such Person; provided that Indebtedness shall not include (i) trade and other ordinary-course payables and accrued expenses arising in the ordinary course of business, (ii) deferred or prepaid revenues, (iii) purchase price holdbacks in respect of a portion of the purchase price of an asset to satisfy warranty or other unperformed obligations of the respective seller, (iv) in the case of the Borrower and its Restricted Subsidiaries, (A) all intercompany Indebtedness having a term not exceeding 364 days (inclusive of any roll-over or extensions of terms) and made in the ordinary course of business and (B) intercompany liabilities in connection with the cash management, tax and accounting operations of the Borrower and the Restricted Subsidiaries, (v) obligations under the Transaction Agreement and any other agreements or instruments contemplated thereby, in each case, as amended, restated supplemented or otherwise modified from time to time, (vi) Production Payments and Reserve Sales, (vii) obligations in respect of surety and bonding requirements of the Borrower and the Restricted Subsidiaries, (viii) in-kind obligations relating to net oil, natural gas liquids or natural gas balancing positions arising in the ordinary course of business and (ix) any obligation in respect of a farm-in agreement or similar arrangement whereby such Person agrees to pay all or a share of the drilling, completion or other expenses of an exploratory or development well (which agreement may be subject to a maximum payment obligation, after which expenses are shared in accordance with the working or participation interest therein or in accordance with the agreement of the parties) or perform the drilling, completion or other operation on such well in exchange for an ownership interest in an oil or gas property.

For purposes hereof, the amount of any net Hedging Obligations on any date shall be deemed to be the Swap Termination Value thereof as of such date. The amount of Indebtedness of any Person for purposes of clause 0 above shall be deemed to be equal to the lesser of (x) the aggregate unpaid amount of such Indebtedness and (xi) the Fair Market Value of the property encumbered thereby as determined by such Person in good faith.

“Indemnified Liabilities” shall have the meaning provided in Section 13.5(a).

“Indemnified Taxes” shall mean all Taxes imposed on or with respect to or measured by, any payment by or on account of any obligation of any Credit Party hereunder or under any other Credit Document other than (aaaaaa) Excluded Taxes and (bbbbbb) Other Taxes.

“Indemnitee” shall mean each of the Administrative Agent, the Collateral Agent, each Lead Arranger, each Syndication Agent, each Documentation Agent, each Issuing Bank and each Lender, and each Related Party of the foregoing Persons.

“Industry Investment” shall mean Investments and/or expenditures made in the ordinary course of, and of a nature that is or shall have become customary in, the Oil and Gas Business as a means of actively engaging therein through agreements, transactions, interests or arrangements that permit one to share risks or costs, comply with regulatory requirements regarding local ownership or satisfy other objectives customarily achieved through the conduct of Oil and Gas Business jointly with third parties, including: (cccccc) ownership interests (directly or through equity) in oil and gas properties or gathering, transportation, processing, or related systems; and (dddddd) Investments and/or expenditures in the form of or pursuant to operating agreements, processing agreements, farm-in agreements, farm-out agreements, development agreements, area of mutual interest agreements, unitization agreements, pooling arrangements, joint bidding agreements, service contracts, joint venture agreements, partnership agreements (whether general or limited), and other similar agreements (including for limited liability companies) with third parties.

“Ineligible Institution” shall mean, subject to the provisions of Section 13.6(i), the persons identified in writing to the Administrative Agent by the Borrower on or prior to the Closing Date, which list may be updated from time to time after the Closing Date with the consent of the Administrative Agent (not to be unreasonably withheld or delayed) to add any operational competitors of the Borrower.

“Information” shall have the meaning provided in Section 8.8(a).

“Initial Reserve Report” shall mean, collectively, the reserve reports (eeeeee) prepared as of April 1, 2017 by the Borrower with respect to the Proved Reserves of the Borrower and its Restricted Domestic Subsidiaries and (ffffff) prepared by Netherland, Sewell & Associates, Inc. with respect to the Proved Reserves of Stone Energy and its Subsidiaries, as adjusted by the Borrower and reviewed by Netherland, Sewell, & Associates, Inc. on August 9, 2017.

“Intercompany Note” shall mean the Intercompany Subordinated Note, dated as of the Closing Date, substantially in the form of Exhibit I executed by the Borrower and each Subsidiary of the Borrower.

“Intercreditor Agreement” shall mean an intercreditor agreement substantially in the form of Exhibit F hereto, or another intercreditor agreement that is not materially less favorable to the Lenders than such form of intercreditor agreement, between the Collateral Agent and one or more collateral agents or representatives for the holders of any Junior Liens.

“Interest Expense” shall mean, with respect to any Person for any period, the sum of (gggggg) gross interest expense of such Person for such period on a consolidated basis (including (i) the amortization of debt discounts, (ii) the amortization of all fees (including fees with respect to any Hedge Transactions) payable in connection with the incurrence of Indebtedness to the extent included in interest expense and (iii) the portion of any payments or accruals with respect to Capitalized Lease Obligations allocable to interest expense) and (hhhhhh) capitalized interest of such Person. For purposes of the foregoing, gross interest expense shall be determined after giving effect to any net payments made or received and costs incurred by the Borrower and the Restricted Domestic Subsidiaries with respect to any interest rate Hedge Transactions, and interest on a Capitalized Lease Obligation shall be deemed to accrue at an interest rate reasonably determined by the Borrower to be the rate of interest implicit in such Capitalized Lease Obligation in accordance with GAAP.

“Interest Payment Date” means (iiiiii) with respect to any ABR Loan, the last day of each March, June, September and December and the Maturity Date, (jjjjjj) with respect to any RFR Loan, (A) each date that is on the numerically corresponding day in each calendar month that is one month after the Borrowing of such Loan (or, if there is no such numerically corresponding day in such month, then the last day of such month) and (B) the Maturity Date, (kkkkkk) with respect to any Term Benchmark Loan, the last day of each Interest Period applicable to the Borrowing of which such Loan is a part and, in the case of a Term Benchmark Borrowing with an Interest Period of more than three months’ duration, each day prior to the last day of such Interest Period that occurs at intervals of three months’ duration after the first day of such Interest Period, and the Maturity Date and (llllll) with respect to any Swingline Loan, the day that such Loan is required to be repaid and the Maturity Date.

“Interest Period” means with respect to any Term Benchmark Borrowing, the period commencing on the date of such Borrowing and ending on the numerically corresponding day in the calendar month that is one, three or six months thereafter (in each case, subject to the availability for the Benchmark applicable to the relevant Loan or Commitment), as the Borrower may elect; provided, that (mmmmmm) if any Interest Period would end on a day other than a Business Day, such Interest Period shall be extended to the next succeeding Business Day unless such next succeeding Business Day would fall in the next calendar month, in which case

such Interest Period shall end on the next preceding Business Day, (nnnnnn) any Interest Period that commences on the last Business Day of a calendar month (or on a day for which there is no numerically corresponding day in the last calendar month of such Interest Period) shall end on the last Business Day of the last calendar month of such Interest Period and (oooooo) no tenor that has been removed from this definition pursuant to Section 2.18(e) shall be available for specification in such Notice of Borrowing or Notice of Conversion or Continuation. For purposes hereof, the date of a Borrowing initially shall be the date on which such Borrowing is made and thereafter shall be the effective date of the most recent conversion or continuation of such Borrowing

“Interim Redetermination” shall have the meaning provided in Section 2.14.

“Interim Redetermination Date” shall mean the date on which a Borrowing Base that has been redetermined pursuant to an Interim Redetermination becomes effective as provided in Section 2.14.

“Intermediate Entity” shall mean each Legacy Blocker Entity and each other Person (if any) that both (pppppp) is owned directly or indirectly by Holdings and (qqqqqq) directly or indirectly owns any Equity Interests of the Borrower.

“Investment” shall have the meaning provided in Section 10.5.

“ISDA Definitions” means the 2006 ISDA Definitions published by the International Swaps and Derivatives Association, Inc. or any successor thereto, as amended or supplemented from time to time, or any successor definitional booklet for interest rate derivatives published from time to time by the International Swaps and Derivatives Association, Inc. or such successor thereto.

“ISP” shall mean, with respect to any Letter of Credit, the “International Standby Practices 1998” published by the Institute of International Banking Law & Practice (or such later version thereof as may be in effect at the time of issuance).

“Issuer Documents” shall mean, with respect to any Letter of Credit, the Letter of Credit Application and any other document, agreement and instrument entered into by the applicable Issuing Bank and the Borrower (or any Restricted Subsidiary) or in favor of the applicable Issuing Bank and relating to such Letter of Credit.

“Issuing Bank” shall mean (rrrrrr) JPMorgan Chase Bank, N.A. or any of its Affiliates, DNB Bank ASA, New York Branch or any of its Affiliates, Capital One, National Association or any of its Affiliates, KeyBank National Association or any of its Affiliates, and Mizuho Bank, Ltd. or any of its Affiliates, or any replacement or successor appointed pursuant to Section 3.6, (ssssss) if requested by the Borrower and reasonably acceptable to the Administrative Agent, any other Person that is a Lender at the time of such request and who accepts such appointment (it being understood that, if any such Person ceases to be a Lender hereunder, such Person will remain an Issuing Bank with respect to any Letter of Credit issued by such Person that remained outstanding as of the date such Person ceased to be a Lender), and (tttttt) solely with respect to any letter of credit issued for the benefit of EnVen or any of its Subsidiaries prior to the Ninth Amendment Implementation Date that is identified on a schedule delivered to the Administrative Agent on or before the Ninth Amendment Implementation Date, the issuer of such letter of credit. If the Borrower requests any Issuing Bank to issue a Letter of Credit, such Issuing Bank may, in its discretion, arrange for such Letter of Credit to be issued by any of its Affiliates or any Lender, and in each such case, the term “Issuing Bank” shall include any such Affiliate or Lender with respect to Letters of Credit issued by such Affiliate or Lender. References herein and in the other Credit Documents to an Issuing Bank shall be deemed to refer to the Issuing Bank in respect of the applicable Letter of Credit or to all Issuing Banks, as the context requires.

“Joint Bookrunner” shall mean each of JPMorgan Chase Bank, N.A., DNB Markets, Inc., Capital One, National Association, KeyBanc Capital Markets Inc., and Société Générale, each in its capacity as joint bookrunner in respect of the Facility.

“Junior Lien Indenture” shall mean that certain Indenture dated as of January 4, 2021 under which the Junior Lien Notes were issued, by and among the Borrower, as issuer, the Subsidiary Guarantors party thereto from time to time and the trustee and collateral agent named therein, as amended, restated, supplemented or otherwise modified from time to time in accordance with the requirements thereof and of this Agreement.

“Junior Lien Notes” shall mean the Borrower’s 12.00% Second-Priority Senior Secured Notes due 2026 in aggregate principal amount of $650,000,000, issued pursuant to the Junior Lien Indenture, as amended, restated, supplemented or otherwise modified from time to time in accordance with the requirements thereof and of this Agreement.

“Junior Liens” shall mean Liens on the Collateral (other than Liens securing the Obligations) securing the Junior Lien Notes, the EnVen Notes, any QuarterNorth Acquisition Debt or any Permitted Incremental Junior Lien Debt, in each case that are subordinated to the Liens granted under the Credit Documents pursuant to an Intercreditor Agreement (it being understood that Junior Liens are not required to be pari passu with other Junior Liens, and that Indebtedness secured by Junior Liens may have Liens that are senior in priority to, or pari passu with, or junior in priority to, other Liens constituting Junior Liens).

“L/C Borrowing” shall mean an extension of credit resulting from a drawing under any Letter of Credit that has not been reimbursed on the date when made or refinanced as a Borrowing. All L/C Borrowings shall be denominated in Dollars.

“L/C Maturity Date” shall mean the date that is five (5) Business Days prior to the Maturity Date.

“L/C Obligations” shall mean, as at any date of determination, the aggregate amount available to be drawn under all outstanding Letters of Credit plus the aggregate of all Unpaid Drawings, including all L/C Borrowings. For all purposes of this Agreement, if on any date of determination a Letter of Credit has expired by its terms but any amount may still be drawn thereunder by reason of the operation of Rule 3.14 of the ISP, such Letter of Credit shall be deemed to be “outstanding” in the amount so remaining available to be drawn.

“L/C Participant” shall have the meaning provided in Section 3.3(a).

“L/C Participation” shall have the meaning provided in Section 3.3(a).

“Lead Arranger” shall mean each of JPMorgan Chase Bank, N.A., DNB Markets, Inc., Capital One, National Association, KeyBanc Capital Markets Inc., Société Générale, Citibank, N.A., and Mizuho Bank, Ltd., each in its capacity as a lead arranger in respect of the Facility.

“Legacy Blocker Entity” shall mean each of AIF VII (Talos DC), LLC, ANRP (Talos DC), LLC, AP Overseas Talos Holdings (DC I), LLC, AP Overseas Talos Holdings (DC II), LLC, AP Overseas Talos Holdings (DC III), LLC, AP Overseas Talos Holdings (DC IV), LLC, New Talos Sub Inc., and Riverstone V Non-U.S. Talos Corp, each of which is organized under the laws of the state of Delaware.

“Legacy Hedge Transactions” shall mean each Hedge Transaction specifically listed on Schedule 13.22 entered into by the Borrower or any of its Subsidiaries or Stone Energy or any of its Subsidiaries,

in each case, prior to the consummation of the Corporate Reorganization and Merger Transactions that remain in effect on the Closing Date.

“Lender” shall have the meaning provided in the preamble to this Agreement. Unless the context otherwise requires, the term “Lender” includes the Swingline Lender.

“Lender Default” shall mean (uuuuuu) the refusal or failure of any Lender to make available its portion of any incurrence of Loans or participations in Letters of Credit or Swingline Loans, which refusal or failure is not cured within two (2) Business Days after the date of such refusal or failure, unless such Lender notifies the Administrative Agent in writing that such refusal or failure is the result of such Lender’s good faith determination that a condition precedent to funding (specifically identified and including the particular default, if any) has not been satisfied; (vvvvvv) the failure of any Lender to pay over to the Administrative Agent, any Issuing Bank, any Swingline Lender or any other Lender any other amount required to be paid by it hereunder within two (2) Business Days of the date when due, unless the subject of a good faith dispute; (wwwwww) a Lender has notified the Borrower or the Administrative Agent that it does not intend or expect to comply with any of its funding obligations or has made a public statement to that effect with respect to its funding obligations under the Facility (unless such writing or public statement indicates that such position is based on such Lender’s good faith determination that a condition precedent (specifically identified and including the particular default, if any) to funding a loan under this Agreement cannot be satisfied), (xxxxxx) the failure by a Lender to confirm in a manner reasonably satisfactory to the Administrative Agent that it will comply with its obligations under the Facility, which failure is not cured after the date of such failure (provided that such Lender shall cease to be a Defaulting Lender pursuant to this clause (d) upon receipt of such written confirmation by the Administrative Agent and the Borrower), (yyyyyy) a Distressed Person has admitted in writing that it is insolvent or such Distressed Person becomes subject to a Lender-Related Distress Event or (zzzzzz) a Lender or any Person that directly or indirectly controls such Lender, as the case may be, is or becomes the subject of a Bail-In Action.

“Lender-Related Distress Event” shall mean, with respect to any Lender, that such Lender or any Person that directly or indirectly controls such Lender (each, a “Distressed Person”), as the case may be, is or becomes subject to a voluntary or involuntary case with respect to such Distressed Person under any debt relief law, or a custodian, conservator, receiver or similar official is appointed for such Distressed Person or any substantial part of such Distressed Person’s assets, or such Distressed Person or any Person that directly or indirectly controls such Distressed Person is subject to a forced liquidation, or such Distressed Person makes a general assignment for the benefit of creditors or is otherwise adjudicated as, or determined by any Governmental Authority having regulatory authority over such Distressed Person or its assets to be, insolvent or bankrupt or such Distressed Person becomes or has a parent company become the subject of a Bail-In Action; provided that a Lender-Related Distress Event shall not be deemed to have occurred solely by virtue of (aaaaaaa) the ownership or acquisition of any equity interests in any Lender or any Person that directly or indirectly controls such Lender by a Governmental Authority or an instrumentality thereof so long as such ownership interest does not result in or provide such Lender with immunity from the jurisdiction of courts within the United States or from the enforcement of judgments or writs of attachment on its assets or permit such Lender (or such Governmental Authority) to reject, repudiate, disavow or disaffirm any contracts or agreements made with such Lender or (bbbbbbb) an undisclosed administration pursuant to the laws of the Netherlands.

“Letter of Credit” shall have the meaning provided in Section 3.1 and shall include the Existing Letters of Credit, any Alternate Currency Letters of Credit, and any letter of credit issued for the benefit of EnVen or any of its Subsidiaries prior to the Ninth Amendment Implementation Date that is identified on a schedule delivered to the Administrative Agent on or before the Ninth Amendment Implementation Date and that

has been issued by a letter of credit issuer that is (or has become) an Issuing Bank hereunder as of the Ninth Amendment Implementation Date.

“Letter of Credit Application” shall have the meaning provided in Section 3.2.

“Letter of Credit Commitment” shall mean $250,000,000, as the same may be reduced from time to time pursuant to Section 3.1 or, with the consent of the Administrative Agent and the Issuing Banks, increased from time to time (or the equivalent thereof in an Alternate Currency).

“Letter of Credit Exposure” shall mean, with respect to any Lender, at any time, the sum of (ccccccc) the principal amount of any Unpaid Drawings in respect of which such Lender has made (or is required to have made) payments to the applicable Issuing Bank pursuant to Section 3.4(a) at such time (calculated, in the case of Alternate Currency Letters of Credit, based on the Dollar Equivalent thereof) and (ddddddd) such Lender’s Commitment Percentage of the Letters of Credit Outstanding at such time (excluding the portion thereof consisting of Unpaid Drawings in respect of which the Lenders have made (or are required to have made) payments to the applicable Issuing Bank pursuant to Section 3.4(a)) minus the amount of cash or deposit account balances held by the Administrative Agent to Cash Collateralize outstanding Letters of Credit and Unpaid Drawings under Section 3.8. For all purposes of this Agreement, if on any date of determination a Letter of Credit has expired by its terms but any amount may still be drawn thereunder by reason of the operation of Article 29(a) of the Uniform Customs and Practice for Documentary Credits, International Chamber of Commerce Publication No. 600 (or such later version thereof as may be in effect at the applicable time) or Rule 3.13 or Rule 3.14 of the International Standby Practices, International Chamber of Commerce Publication No. 590 (or such later version thereof as may be in effect at the applicable time) or similar terms in the governing rules or laws or of the Letter of Credit itself, or if compliant documents have been presented but not yet honored, such Letter of Credit shall be deemed to be “outstanding” and “undrawn” in the amount so remaining available to be paid, and the obligations of the Borrower and each Lender shall remain in full force and effect until the Issuing Banks and the Lenders shall have no further obligations to make any payments or disbursements under any circumstances with respect to any Letter of Credit.

“Letter of Credit Fee” shall have the meaning provided in Section 4.1(b).

“Letters of Credit Outstanding” shall mean, at any time, the sum of, without duplication, (eeeeeee) the aggregate Stated Amount of all outstanding Letters of Credit and (fffffff) the aggregate principal amount of all Unpaid Drawings in respect of all Letters of Credit.

“Liabilities” means any losses, claims (including intraparty claims), demands, damages or liabilities of any kind.

“Lien” shall mean, with respect to any asset, (ggggggg) any mortgage, preferred mortgage, deed of trust, lien, notice of claim of lien, hypothecation, pledge, charge, security interest or similar encumbrance in or on such asset, (hhhhhhh) the interest of a vendor or a lessor under any conditional sale agreement, capital lease or title retention agreement (or any financing lease having substantially the same economic effect as any of the foregoing) relating to such asset or (iiiiiii) Production Payments and Reserve Sales and the like payable out of Oil and Gas Properties; provided that in no event shall an operating lease be deemed to be a Lien.

“Liquidity” shall mean, as of any date of determination, the sum of (jjjjjjj) the Available Commitment on such date and (kkkkkkk) the aggregate amount of Unrestricted Cash of the Borrower and the Restricted Subsidiaries at such date, less the amount of any Borrowing Base Deficiency existing on such date of determination.

“Loan” shall have the meaning provided in Section 2.1(a).

“Loan Limit” shall mean, at any time, the lesser of (lllllll) the Total Commitment at such time and (mmmmmmm) the Borrowing Base at such time (including as it may be reduced pursuant to the Borrowing Base Adjustment Provisions).

“MacKay” shall mean MacKay Shields, LLC, as investment manager on behalf of certain clients.

“Majority Lenders” shall mean, at any date, (nnnnnnn) Non-Defaulting Lenders having or holding more than fifty percent (50.0%) of the Adjusted Total Commitment at such date, or (ooooooo) if the Total Commitment has been terminated or for the purposes of acceleration pursuant to Section 11, Non-Defaulting Lenders having or holding a majority of the outstanding principal amount of the Loans, the Swingline Exposure and Letter of Credit Exposure (excluding the Loans, Swingline Exposure and Letter of Credit Exposure of Defaulting Lenders) in the aggregate at such date.

“Mandatory Borrowing” shall have the meaning provided in Section 2.1(c).

“Material Adverse Effect” shall mean a circumstance or condition affecting the business, assets, operations, properties or financial condition of the Borrower and the Subsidiaries, taken as a whole, that would, individually or in the aggregate, materially adversely affect (ppppppp) the ability of the Borrower and the other Credit Parties, taken as a whole, to perform their payment obligations under this Agreement or any of the other Credit Documents or (qqqqqqq) the rights and remedies of the Agents and the Lenders under this Agreement or under any of the other Credit Documents.

“Material Indebtedness” shall mean Indebtedness (other than Loans and Letters of Credit) of any one or more of the Borrower or any Restricted Subsidiary in an aggregate principal amount exceeding $50,000,000.

“Material Subsidiary” shall mean, at any date of determination, each Restricted Domestic Subsidiary of the Borrower (rrrrrrr) whose Total Assets (when combined with the assets of such Subsidiary’s Domestic Subsidiaries, after eliminating intercompany obligations) at the last day of the Test Period were equal to or greater than 5% of the Consolidated Total Assets of the Borrower and the Restricted Domestic Subsidiaries at such date or (sssssss) whose revenues (when combined with the revenues of such Subsidiary’s Domestic Subsidiaries, after eliminating intercompany obligations) during such Test Period were equal to or greater than 5% of the consolidated revenues of the Borrower and the Restricted Domestic Subsidiaries for such period, in each case determined in accordance with GAAP; provided that if, at any time and from time to time after the Closing Date, Restricted Domestic Subsidiaries that are not Material Subsidiaries have, in the aggregate, (i) Total Assets (when combined with the assets of such Subsidiary’s Domestic Subsidiaries, after eliminating intercompany obligations) at the last day of such Test Period equal to or greater than 10.0% of the Consolidated Total Assets of the Borrower and the Restricted Domestic Subsidiaries at such date or (ii) revenues (when combined with the revenues of such Subsidiary’s Domestic Subsidiaries, after eliminating intercompany obligations) during such Test Period equal to or greater than 10.0% of the consolidated revenues of the Borrower and the Restricted Domestic Subsidiaries for such period, in each case determined in accordance with GAAP, then the Borrower shall, on the date on which financial statements for such quarter are delivered pursuant to this Agreement, designate in writing to the Administrative Agent one or more of such Restricted Domestic Subsidiaries as “Material Subsidiaries” such that foregoing 10% threshold shall no longer be exceeded after giving effect to the designation of such Restricted Domestic Subsidiaries.

“Maturity Date” shall mean the earlier of (iii) March 31, 2027 and (iv) the 91st day prior to the earliest stated maturity date of any of the Junior Lien Notes (or any Permitted Refinancing Indebtedness with respect thereto) or any QuarterNorth Acquisition Debt (or any Permitted Refinancing Indebtedness with respect thereto), if such Junior Lien Notes or such QuarterNorth Acquisition Debt (or such Permitted Refinancing Indebtedness) have not been refinanced, redeemed, or repaid in full on prior to such 91st day.

“Maximum Incremental Junior Lien Debt Amount” shall mean, as of any date of determination, an amount equal to (ttttttt) $1,208,000,000 minus(uuuuuuu) the aggregate outstanding principal amount of Indebtedness permitted by Section 10.1(b) as of such date, minus(vvvvvvv) the aggregate outstanding principal amount of Indebtedness permitted by Section 10.1(c) as of such date.

“Maximum LC Commitment” shall mean with respect to each Issuing Bank the amount set forth opposite such Issuing Bank’s name in Schedule 1.1(h) hereto, as such Schedule 1.1(h) may be amended or modified from time to time by the Borrower, each Issuing Bank affected by such amendment or modification thereto and by the Administrative Agent.

“Minimum Borrowing Amount” shall mean, with respect to any Borrowing of Loans, $500,000 (or, if less, the entire remaining Commitments at the time of such Borrowing).

“Minimum Hedging Compliance Date” is defined in Section 9.19.

“Minimum Quarterly Hedged Volume” shall mean, as of any date of determination and with respect to each fiscal quarter that occurs in the six (6) fiscal quarter period described in the definition of “Monthly Hedged Volume Component”, the sum of the Monthly Hedged Volume Components for each month in such fiscal quarter.

“Minority Investment” shall mean any Person (other than a Subsidiary) in which the Borrower or any Restricted Subsidiary owns Equity Interests.

“Moody’s” shall mean Moody’s Investors Service, Inc. or any successor by merger or consolidation to its business.

“Monthly Hedged Volume Component” shall mean (wwwwwww) for any month occurring during the first four (4) full fiscal quarters following a Minimum Hedging Compliance Date, (i) the total reasonably anticipated projected production of oil and natural gas, calculated separately, from the Credit Parties’ Proved Developed Producing Reserves evaluated in the Reserve Report most recently delivered to the Administrative Agent for such month multiplied by (ii)(A) with respect to the months of August, September or October in any such fiscal quarter, 25%, (B) with respect to the months of July or November in any such fiscal quarter, 45%, and (C) with respect to any other month, 50%, and (xxxxxxx) if the Consolidated Total Debt to EBITDAX Ratio as of the last day of any Minimum Hedging Compliance Date is greater than or equal to 1.00 to 1.00, for any month occurring during the fifth (5th) and sixth (6th) full fiscal quarters following such Minimum Hedging Compliance Date, (i) the total reasonably anticipated projected production of oil and natural gas, calculated separately, from the Credit Parties’ Proved Developed Producing Reserves evaluated in the Reserve Report most recently delivered to the Administrative Agent for such month multiplied by (ii)(A) with respect to the months of August, September or October in any such fiscal quarter, 20% or (B) with respect to any other month, 25%.

“Mortgage” shall mean a mortgage or a deed of trust, deed to secure debt, trust deed, assignment of as-extracted collateral, fixture filing or other security document entered into by the owner of a Mortgaged Property and the Collateral Agent for the benefit of the Secured Parties in respect of that Mortgaged

Property, which may be substantially in the form of Exhibit D (with such changes thereto as may be necessary to account for local law matters) or otherwise in such form as agreed between the Borrower and the Collateral Agent.

“Mortgaged Property” shall mean the Oil and Gas Properties and other assets appertaining thereto that are encumbered by a Mortgage and such other Oil and Gas Properties and other assets appertaining thereto with respect to which a Mortgage is required to be granted pursuant to Section 6 or Section 9.11; provided that, notwithstanding any provision in any Mortgage to the contrary, in no event shall any Building (as defined in the applicable Flood Insurance Regulation) or Manufactured (Mobile) Home (as defined in the applicable Flood Insurance Regulation) located on the Mortgaged Properties (as defined in the applicable Mortgage) within an area having special flood hazards and in which flood insurance is available under the National Flood Insurance Act of 1968 be included in the definition of “Mortgaged Property” or “Mortgaged Properties” and no such Building or Manufactured (Mobile) Home shall be encumbered by any Mortgage. As used herein, “Flood Insurance Regulations” shall mean (yyyyyyy) the National Flood Insurance Act of 1968 as now or hereafter in effect or any successor statute thereto, (zzzzzzz) the Flood Disaster Protection Act of 1973 as now or hereafter in effect or any successor statue thereto, (aaaaaaaa) the National Flood Insurance Reform Act of 1994 (amending 42 USC 4001, et seq.), as the same may be amended or recodified from time to time, and (bbbbbbbb) the Flood Insurance Reform Act of 2004 and any regulations promulgated thereunder.

“Multiemployer Plan” shall mean a Plan that is a multiemployer plan as defined in Section 4001(a)(3) of ERISA.

“Net Income” shall mean, with respect to any Person, the net income (loss) of such Person, determined in accordance with GAAP and before any reduction in respect of preferred stock dividends.

“Net Working Capital” shall mean (cccccccc) all current assets of the Borrower and its Restricted Domestic Subsidiaries, except current assets from commodity price risk management activities arising in the ordinary course of the Oil and Gas Business, less(dddddddd) all current liabilities of the Borrower and its Restricted Domestic Subsidiaries, except current liabilities (i) associated with asset retirement obligations relating to Oil and Gas Properties, (ii) included in Indebtedness and (iii) any current liabilities from commodity price risk management activities arising in the ordinary course of the Oil and Gas Business, in each case as set forth in the consolidated financial statements of the Borrower prepared in accordance with GAAP.

“New Borrowing Base Notice” shall have the meaning provided in Section 2.14(d).

“New Facility” shall mean each plant or facility that is either a new plant or facility or an expansion of an existing plant or facility owned by the Borrower or its Restricted Subsidiaries that receives a certificate of completion or occupancy and all relevant licenses, and in fact commences operations.

“New Talos Energy” shall have the meaning provided in the recitals to this Agreement.

“Ninth Amendment” shall mean that certain Incremental Agreement and Ninth Amendment to Credit Agreement dated as of December 23, 2022, by and among Holdings, the Borrower, each other Credit Party, the Administrative Agent, the Issuing Banks, the Swingline Lender and the Lenders.

“Ninth Amendment Effective Date” shall mean the first date on which all conditions precedent to the effectiveness of the Ninth Amendment shall have been satisfied.

“Ninth Amendment Implementation Date” shall mean the first date on which all conditions precedent set forth in Section 9 of the Ninth Amendment shall have been satisfied (or waived in accordance with provisions thereof).

“Non-Consenting Lender” shall have the meaning provided in Section 13.7(b).

“Non-Defaulting Lender” shall mean and include each Lender other than a Defaulting Lender.

“Non-Extension Notice Date” shall have the meaning provided in Section 3.2(b).

“Non-U.S. Lender” shall mean any Lender (eeeeeeee) that is not disregarded as separate from its owner for U.S. federal income tax purposes and that is not a “United States person” as defined by Section 7701(a)(30) of the Code. or (ffffffff) that is disregarded as separate from its owner for U.S. federal income tax purposes and whose regarded owner is not a “United States person” as defined by Section 7701(a)(30) of the Code.

“Notice of Borrowing” shall mean a request of the Borrower in accordance with the terms of Section 2.3(a) and substantially in the form of Exhibit B or such other form as shall be approved by the Administrative Agent (acting reasonably).

“Notice of Conversion or Continuation” shall have the meaning provided in Section 2.6(a).

“NYFRB” means the Federal Reserve Bank of New York.

“NYFRB’s Website” means the website of the NYFRB at http://www.newyorkfed.org, or any successor source.

“NYFRB Rate” means, for any day, the greater of (gggggggg) the Federal Funds Effective Rate in effect on such day and (hhhhhhhh) the Overnight Bank Funding Rate in effect on such day (or for any day that is not a Business Day, for the immediately preceding Business Day); provided that if none of such rates are published for any day that is a Business Day, the term “NYFRB Rate” means the rate for a federal funds transaction quoted at 11:00 a.m. on such day received by the Administrative Agent from a federal funds broker of recognized standing selected by it; provided, further, that if any of the aforesaid rates as so determined be less than 0.00%, such rate shall be deemed to be 0.00% for purposes of this Agreement.

“NYMEX” shall mean the New York Mercantile Exchange.

“Obligations” shall mean all advances to, and debts, liabilities, obligations, covenants and duties of, any Credit Party arising under any Credit Document or otherwise with respect to any Loan or Letter of Credit or under any Secured Cash Management Agreement or Secured Hedge Transaction, in each case, entered into with the Borrower or any of its Restricted Subsidiaries, whether direct or indirect (including those acquired by assumption), absolute or contingent, due or to become due, now existing or hereafter arising and including interest and fees that accrue after the commencement by or against any Credit Party or any Affiliate thereof in any proceeding under any bankruptcy or insolvency law naming such Person as the debtor in such proceeding, regardless of whether such interest and fees are allowed claims in such proceeding. Without limiting the generality of the foregoing, the Obligations of the Credit Parties under the Credit Documents (and any of their Restricted Subsidiaries to the extent they have obligations under the Credit Documents) include the obligation (including Guarantee Obligations) to pay principal, interest, charges, expenses, fees, attorney costs, indemnities and other amounts payable by any Credit Party under any Credit Document. Notwithstanding the foregoing, (iiiiiiii) the

obligations of the Borrower or any Restricted Subsidiary under any Secured Hedge Transaction and under any Secured Cash Management Agreement shall be secured and guaranteed pursuant to the Security Documents and the Guarantee only to the extent that, and for so long as, the other Obligations are so secured and guaranteed, (jjjjjjjj) any release of Collateral or Guarantors effected in the manner permitted by this Agreement (including as this Agreement may be amended or waived in accordance with the terms hereof) and the other Credit Documents shall not require the consent of the holders of Hedging Obligations under Secured Hedge Transactions or of the holders of Cash Management Obligations under Secured Cash Management Agreements and (kkkkkkkk) solely with respect to any Credit Party that is not an “eligible contract participant” under the Commodity Exchange Act, Excluded Hedge Obligations of such Credit Party shall in any event be excluded from “Obligations” owing by such Credit Party.

“Oil and Gas Business” shall mean:

(llllllll)the business of acquiring, exploring, exploiting, developing, producing, operating and disposing of interests in oil, natural gas, natural gas liquids, liquefied natural gas and other Hydrocarbons and mineral properties or products produced in association with any of the foregoing;

(mmmmmmmm)the business of gathering, marketing, distributing, treating, processing, storing, refining, selling and transporting of any production from such interests or properties and products produced in association therewith and the marketing of oil, natural gas, other Hydrocarbons and minerals obtained from unrelated Persons;

(nnnnnnnn)any business related to the development of technology or infrastructure relating to (i) renewable energy generation, including geothermal energy, to the extent related to, in areas adjacent to, or otherwise accretive to the value of the offshore Oil and Gas Properties of the Credit Parties, and (ii) carbon storage and mitigation;

(oooooooo)any business relating to oil field sales and service; and

(pppppppp)any business or activity relating to, arising from, or necessary, appropriate, incidental or ancillary to the activities described in the foregoing clauses (a) through (d) of this definition.

“Oil and Gas Properties” shall mean (qqqqqqqq) Hydrocarbon Interests, (rrrrrrrr) the properties now or hereafter pooled or unitized with Hydrocarbon Interests, (ssssssss) all presently existing or future unitization, pooling agreements and declarations of pooled units and the units created thereby (including all units created under orders, regulations and rules of any Governmental Authority) that may affect all or any portion of the Hydrocarbon Interests, (tttttttt) all operating agreements, contracts and other agreements, including production sharing contracts and agreements, that relate to any of the Hydrocarbon Interests or the production, sale, purchase, exchange or processing of Hydrocarbons from or attributable to such Hydrocarbon Interests, (uuuuuuuu) all Hydrocarbons in and under and that may be produced and saved or attributable to the Hydrocarbon Interests, including all oil in tanks, and all rents, issues, profits, proceeds, products, revenues and other incomes from or attributable to the Hydrocarbon Interests, (vvvvvvvv) all tenements, hereditaments, appurtenances and properties in any manner appertaining, belonging, affixed or incidental to the Hydrocarbon Interests and (wwwwwwww) all properties, rights, titles, interests and estates described or referred to above, including any and all property, real or personal, now owned or hereafter acquired and situated upon, used, held for use or useful in connection with the operating, working or development of any of such Hydrocarbon Interests or property (excluding drilling rigs, automotive equipment, rental equipment or other personal property which may be on such premises for the purpose of drilling a well or for other similar temporary uses) and including any and all oil wells, gas wells, injection wells or other wells, buildings, structures, fuel separators, liquid extraction plants, plant compressors, pumps, pumping units, field gathering systems, gas

processing plants and pipeline systems and any related infrastructure to any thereof, tanks and tank batteries, fixtures, valves, fittings, machinery and parts, engines, boilers, meters, apparatus, equipment, appliances, tools, implements, cables, wires, towers, casing, tubing and rods, surface leases, rights-of-way, easements and servitudes together with all additions, substitutions, replacements, accessions and attachments to any and all of the foregoing.

“Ongoing Hedges” shall have the meaning provided in Section 10.10(a).

“Other Currency” shall have the meaning provided in Section 3.13.

“Other Connection Taxes” shall mean, with respect to any Recipient, Taxes imposed as a result of a present or former connection between such Recipient and the jurisdiction imposing such Tax (other than connections arising from such Recipient having executed, delivered, become a party to, performed its obligations under, received payments under, received or perfected a security interest under, engaged in any other transaction pursuant to or enforced any Credit Document, or sold or assigned an interest in any Loan, Letter of Credit or Credit Document).

“Other Taxes” shall mean any and all present or future stamp, registration, documentary, intangible, recording, filing or any other excise, property or similar Taxes (including interest, fines, penalties, additions to tax and related, reasonable, out-of-pocket expenses with regard thereto) arising from any payment made hereunder or made under any other Credit Document or from the execution or delivery of, registration or enforcement of, consummation or administration of, or otherwise with respect to, this Agreement or any other Credit Document; provided that such term shall not include any of the foregoing Taxes (xxxxxxxx) that result from an assignment, grant of a participation pursuant to Section 13.6(c) or transfer or assignment to or designation of a new lending office or other office for receiving payments under any Credit Document (“Assignment Taxes”) that are Other Connection Taxes, except to the extent that any such action described in this proviso is requested or required by the Borrower, or (yyyyyyyy) that are Excluded Taxes.

“Outstanding Aggregate Junior Lien Debt Amount” shall mean the aggregate amount of the outstanding principal amounts of Indebtedness permitted by Sections 10.1(b), 10.1(c), and 10.1(bb).

“Overnight Bank Funding Rate” means, for any day, the rate comprised of both overnight federal funds and overnight eurodollar transactions denominated in Dollars by U.S.‑managed banking offices of depository institutions, as such composite rate shall be determined by the NYFRB as set forth on the NYFRB’s Website from time to time, and published on the next succeeding Business Day by the NYFRB as an overnight bank funding rate.

“Overnight Rate” means, for any day, (zzzzzzzz) with respect to any amount denominated in Dollars, the NYFRB Rate and (aaaaaaaaa) with respect to any amount denominated in an Alternate Currency, an overnight rate determined by the Administrative Agent or the Issuing Banks, as the case may be, in accordance with banking industry rules on interbank compensation.

“Parent Entity” shall mean any Person that is a direct or indirect parent company (which may be organized as a partnership) of Holdings and/or the Borrower, as applicable.

“Participant” shall have the meaning provided in Section 13.6(c).

“Participant Register” shall have the meaning provided in Section 13.6(c).

“Participating Member States” shall mean, together, each member state of the European Union that adopts or has adopted the Euro as its lawful currency in accordance with legislation of the European Union relating to the Economic and Monetary Union (as amended or re-enacted from time to time).

“Patriot Act” shall have the meaning provided in Section 13.18.

“PBGC” shall mean the Pension Benefit Guaranty Corporation established pursuant to Section 4002 of ERISA, or any successor thereto.

“Pension Act” shall mean the Pension Protection Act of 2006, as it presently exists or as it may be amended from time to time.

“Permitted Acquisition” shall mean the non-hostile acquisition, by merger or otherwise, by the Borrower or any of the Restricted Subsidiaries of assets (including any assets constituting a business unit, line of business or division) or Equity Interests, so long as (bbbbbbbbb) such acquisition and all transactions related thereto shall be consummated in all material respects in accordance with Requirements of Law; (ccccccccc) if such acquisition involves the acquisition of Equity Interests of a Person that upon such acquisition would become a Subsidiary, such acquisition shall result in the issuer of such Equity Interests becoming a Restricted Subsidiary and, to the extent required by Section 9.11, a Guarantor; (ddddddddd) such acquisition shall result in the Collateral Agent, for the benefit of the Secured Parties, being granted a security interest in any Equity Interests or any assets so acquired to the extent required by Section 9.11; (eeeeeeeee) after giving effect to such acquisition, no Default or Event of Default shall have occurred and be continuing; (fffffffff) after giving effect to such acquisition, the Borrower and its Restricted Subsidiaries shall be in compliance with Section 9.16; and (ggggggggg) the Borrower shall be in Pro Forma Compliance after giving effect to such acquisition (including any Indebtedness assumed or permitted to exist pursuant to Section 10.1(k)).

“Permitted Acquisition Consideration” shall mean in connection with any Permitted Acquisition, the aggregate amount (as valued at the Fair Market Value of such Permitted Acquisition at the time such Permitted Acquisition is made) of, without duplication: (hhhhhhhhh) the purchase consideration paid or payable in cash for such Permitted Acquisition, whether payable at or prior to the consummation of such Permitted Acquisition or deferred for payment at any future time, whether or not any such future payment is subject to the occurrence of any contingency, and including any and all payments representing the purchase price and any assumptions of Indebtedness and/or Guarantee Obligations, “earn-outs” and other agreements to make any payment the amount of which is, or the terms of payment of which are, in any respect subject to or contingent upon the revenues, income, cash flow or profits (or the like) of any Person or business and (iiiiiiiii) the aggregate amount of Indebtedness incurred or assumed in connection with such Permitted Acquisition;provided, in each case, that any such future payment that is subject to a contingency shall be considered Permitted Acquisition Consideration only to the extent of the reserve, if any, required under GAAP (as determined at the time of the consummation of such Permitted Acquisition) to be established in respect thereof for the Borrower or its Restricted Subsidiaries.

“Permitted Additional Debt” shall mean any unsecured senior, unsecured senior subordinated or unsecured subordinated Indebtedness issued by the Borrower or a Guarantor, (jjjjjjjjj) the terms of which do not provide for any scheduled repayment, mandatory redemption or sinking fund obligation prior to the 180th day after the Maturity Date as in effect on the date of determination (other than customary offers to purchase upon a change of control, asset sale or casualty or condemnation event and customary acceleration rights after an event of default), (kkkkkkkkk) the covenants, events of default, guarantees and other terms of which (other than interest rate, fees, funding discounts and redemption or prepayment premiums and other pricing terms determined by the Borrower to be “market” rates, fees, discounts and premiums and other terms at the time of issuance or incurrence of any such Indebtedness), taken as a whole, are determined by the Borrower to be “market” terms on the date of

issuance or incurrence and in any event are not materially adverse to the interests of the Lenders, taken as a whole, relative to the terms of the Senior Unsecured Notes Indenture, taken as a whole, and do not require the maintenance or achievement of any financial performance standards other than as a condition to taking specified actions; provided that a certificate of an Authorized Officer of the Borrower delivered to the Administrative Agent at least three (3) Business Days prior to the incurrence or issuance of such Indebtedness, together with a reasonably detailed description of the material terms and conditions of such Indebtedness or drafts of the documentation relating thereto, stating that the Borrower has determined in good faith that such terms and conditions satisfy the relevant criteria set forth above, as applicable, shall be conclusive evidence that such terms and conditions satisfy such relevant standard, (lllllllll) if such Indebtedness is subordinated in right of payment to the Obligations, the terms of such Indebtedness provide for customary subordination of such Indebtedness to the Obligations and (mmmmmmmmm) no Subsidiary of the Borrower (other than a Guarantor) is an obligor under such Indebtedness.

“Permitted Holders” shall mean (nnnnnnnnn) the Co-Investors and (ooooooooo) officers, directors, employees and other members of management of the Borrower (or any of its Parent Entities) or any of its Restricted Subsidiaries who are or become holders of Equity Interests of the Borrower (or any Parent Entity).

“Permitted Incremental Junior Lien Debt” shall mean any Indebtedness permitted under Section 10.1(bb).

“Permitted Investments” shall mean:

(ppppppppp)securities issued or unconditionally guaranteed by the United States government or any agency or instrumentality thereof, in each case having maturities and/or reset dates of not more than 24 months from the date of acquisition thereof;

(qqqqqqqqq)securities issued by any state, territory or commonwealth of the United States of America or any political subdivision of any such state, territory or commonwealth or any public instrumentality thereof or any political subdivision of any such state, territory or commonwealth or any public instrumentality thereof having maturities of not more than 24 months from the date of acquisition thereof and, at the time of acquisition, having an investment grade rating generally obtainable from either S&P or Moody’s (or, if at any time neither S&P nor Moody’s shall be rating such obligations, then from another nationally-recognized rating service);

(rrrrrrrrr)commercial paper maturing no more than 12 months after the date of acquisition thereof and, at the time of acquisition, having a rating of at least A-2 or P-2 from either S&P or Moody’s (or, if at any time neither S&P nor Moody’s shall be rating such obligations, an equivalent rating from another nationally-recognized rating service);

(sssssssss)time deposits with, or certificates of deposit or bankers’ acceptances maturing no more than two years after the date of acquisition thereof issued by, any Lender or any other bank or trust company having combined capital, surplus and undivided profits of not less than $500,000,000 in the case of domestic banks and $100,000,000 (or the Dollar equivalent thereof) in the case of foreign banks;

(ttttttttt)repurchase agreements with a term of not more than 180 days for underlying securities of the type described in clauses (a), (b) and (d) above entered into with any bank meeting the qualifications specified in clause (d) above or securities dealers of recognized national standing;

(uuuuuuuuu)marketable short-term money market and similar funds (i) either having assets in excess of $500,000,000 or (ii) having a rating of at least A-2 or P-2 from either S&P or Moody’s (or, if at any time

neither S&P nor Moody’s shall be rating such obligations, an equivalent rating from another nationally-recognized rating service);

(vvvvvvvvv)shares of investment companies that are registered under the Investment Company Act of 1940 and substantially all the investments of which are one or more of the types of securities described in clauses (a) through (f) above; and

(wwwwwwwww)in the case of Investments by any Restricted Foreign Subsidiary or Investments made in a country outside the United States of America, other customarily utilized high-quality Investments in the country where such Restricted Foreign Subsidiary is located or in which such Investment is made.

“Permitted Liens” shall mean:

(xxxxxxxxx)Liens for taxes, assessments or governmental charges or claims not yet overdue for a period of more than 30 days or that are being contested in good faith and by appropriate proceedings for which appropriate reserves have been established to the extent required by and in accordance with GAAP (or in the case of any Foreign Subsidiary, the comparable accounting principles in the relevant jurisdiction), or for property taxes on property that the Borrower or one of its Subsidiaries has determined to abandon if the sole recourse for such tax, assessment, charge or claim is to such property;

(yyyyyyyyy)Liens in respect of property or assets of the Borrower or any of the Restricted Subsidiaries imposed by law, such as landlords’, vendors’, suppliers’, carriers’, warehousemen’s, repairmen’s, construction contractors’, workers’ and mechanics’ Liens and other similar Liens arising in the ordinary course of business or incident to the exploration, development, operation or maintenance of Oil and Gas Properties, in each case so long as such Liens arise in the ordinary course of business and do not individually or in the aggregate have a Material Adverse Effect;

(zzzzzzzzz)Liens arising from judgments or decrees in circumstances not constituting an Event of Default under Section 11.9;

(aaaaaaaaaa)Liens incurred or pledges or deposits made in connection with workers’ compensation, unemployment insurance and other types of social security, old age pension, public liability obligations or similar legislation, and deposits securing liabilities to insurance carriers under insurance or self-insurance arrangements in respect of such obligations, or to secure (or secure the Liens securing) liability for reimbursement or indemnification obligations of (including obligations in respect of letters of credit or bank guarantees for the benefit of) insurance carriers providing property, casualty or liability insurance to the Borrower or any Subsidiary;

(bbbbbbbbbb)deposits and other Liens securing (or securing the bonds or similar instruments securing) the performance of tenders, statutory obligations, plugging and abandonment obligations, surety, stay, customs and appeal bonds, bids, leases, government contracts, trade contracts, performance and return-of-money bonds and other similar obligations (including cash, cash equivalents and letters of credit issued in lieu of such bonds or to support the issuance thereof) incurred in the ordinary course of business, including those incurred to secure health, safety and environmental obligations in the ordinary course of business, to secure any surety and bonding requirements or otherwise constituting Investments permitted by Section 10.5;

(cccccccccc)ground leases, subleases, licenses or sublicenses in respect of real property on which facilities owned or leased by the Borrower or any of its Restricted Subsidiaries are located;

(dddddddddd)easements, rights-of-way, licenses, restrictions (including zoning restrictions), title defects, exceptions, deficiencies or irregularities in title, encroachments, protrusions, servitudes, permits, conditions and covenants and other similar charges or encumbrances (including in any rights-of-way or other property of the Borrower or its Restricted Subsidiaries for the purpose of roads, pipelines, transmission lines, transportation lines, distribution lines for the removal of gas, oil or other minerals or timber, and other like purposes, or for joint or common use of real estate, rights of way, facilities and equipment) not interfering in any material respect with the business of the Borrower and its Restricted Subsidiaries, taken as a whole and, to the extent reasonably agreed by the Administrative Agent, any exception on the title reports issued in connection with any Borrowing Base Property;

(eeeeeeeeee)(i) any interest or title of a lessor, sublessor, licensor or sublicensor under any lease, liens reserved in oil, gas or other Hydrocarbons, minerals, leases for bonus, royalty or rental payments and for compliance with the terms of such lease and (ii) any interest or title of a lessor, sublessor, licensor or sublicensor or secured by a lessor’s, sublessor’s, licensor’s or sublicensor’s interest under any lease, sublease, license or sublicense entered into by the Borrower or any Restricted Subsidiary in the ordinary course of business or otherwise permitted by this Agreement;

(ffffffffff)Liens in favor of customs and revenue authorities arising as a matter of law to secure payment of customs duties in connection with the importation of goods;

(gggggggggg)Liens on goods or inventory the purchase, shipment or storage price of which is financed by a documentary letter of credit or bankers’ acceptance issued for the account of the Borrower or any of its Restricted Subsidiaries; provided that such Lien secures only the obligations of the Borrower or such Restricted Subsidiaries in respect of such letter of credit or bankers’ acceptance to the extent permitted under Section 10.1;

(hhhhhhhhhh)leases, licenses, subleases or sublicenses granted to others not interfering in any material respect with the business of the Borrower and its Restricted Subsidiaries, taken as a whole;

(iiiiiiiiii)Liens arising from precautionary Uniform Commercial Code financing statement or similar filings made in respect of operating leases entered into by the Borrower or any of its Restricted Subsidiaries;

(jjjjjjjjjj)Liens created in the ordinary course of business in favor of banks and other financial institutions over credit balances of any bank accounts of the Borrower and the Restricted Subsidiaries held at such banks or financial institutions, as the case may be, to facilitate the operation of cash pooling and/or interest set-off arrangements in respect of such bank accounts in the ordinary course of business;

(kkkkkkkkkk)Liens which arise in the ordinary course of business under operating agreements, joint venture agreements, oil and gas partnership agreements, oil and gas leases, farm-out agreements, farm-in agreements, division orders, contracts for the sale, transportation or exchange of oil and natural gas, unitization and pooling declarations and agreements, area of mutual interest agreements, overriding royalty agreements, marketing agreements, processing agreements, net profits agreements, development agreements, gas balancing or deferred production agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, seismic or other geophysical permits or agreements, and other agreements that are usual or customary in the oil and gas business and are for claims which are not delinquent or that are being contested in good faith and by appropriate proceedings for which appropriate reserves have been established to the extent required by and in accordance with GAAP; provided that any such Lien referred to in this clause does not materially impair the use of the property

covered by such Lien for the purposes for which such property is held by the Borrower or any Restricted Subsidiary;

(llllllllll)Liens on pipelines and pipeline facilities that arise by operation of law or other like Liens arising by operation of law in the ordinary course of business and incident to the exploration, development, operation and maintenance of Oil and Gas Properties, each of which is in respect of obligations that do not constitute Indebtedness for borrowed money and are not yet overdue for a period of more than 30 days or which are being contested in good faith by appropriate action and for which adequate reserves have been maintained in accordance with GAAP; and

(mmmmmmmmmm)any zoning or similar law or right reserved to or vested in any Governmental Authority to control or regulate the use of any real property that does not materially interfere with the ordinary conduct of the business of the Borrower and its Restricted Subsidiaries, taken as a whole.

“Permitted Refinancing Indebtedness” shall mean, with respect to any Indebtedness (the “Refinanced Indebtedness”), any Indebtedness issued or incurred in exchange for, or the net proceeds of which are used to modify, extend, refinance, renew, replace or refund (collectively to “Refinance” or a “Refinancing” or “Refinanced”), such Refinanced Indebtedness (or previous refinancing thereof constituting Permitted Refinancing Indebtedness); provided that (A) the principal amount (or accreted value, if applicable) of any such Permitted Refinancing Indebtedness does not exceed the principal amount (or accreted value, if applicable) of the Refinanced Indebtedness outstanding immediately prior to such Refinancing except by an amount equal to the unpaid accrued interest and premium thereon plus other amounts paid and fees and expenses incurred in connection with such Refinancing plus an amount equal to any existing commitment unutilized and letters of credit undrawn thereunder, (B) if the Indebtedness being Refinanced is (x) Indebtedness permitted by Section 10.1(b), 10.1(c) or, 10.1(bb), or 10.1(cc), such Indebtedness is not guaranteed by anany direct or contingent obligor other than a Credit Party, or (y) permitted by Section 10.1(i), 10.1(k) or 10.1(l), the direct and contingent obligors with respect to such Permitted Refinancing Indebtedness immediately prior to such Refinancing are not changed as a result of such Refinancing (except that a Credit Party may be added as an additional obligor), (C) other than with respect to a Refinancing in respect of Indebtedness permitted pursuant to Section 10.1(h), such Permitted Refinancing Indebtedness shall have a final maturity date equal to or later than the final maturity date of, and has a Weighted Average Life to Maturity equal to or greater than the Weighted Average Life to Maturity of, the Refinanced Indebtedness, and (D) if the Indebtedness being Refinanced is Indebtedness permitted by Section 10.1(b), 10.1(c), 10.1(i), 10.1(k), 10.1(l), 10.1(p), or 10.1(bb)or 10.1(cc)such Refinanced Indebtedness contains terms, taken as a whole, at least as favorable to the Credit Parties as market terms for issuers of similar size and credit quality given the then prevailing market conditions as determined by the Administrative Agent.

“Person” shall mean any individual, partnership, joint venture, firm, corporation, limited liability company, association, trust or other enterprise or any Governmental Authority.

“Petroleum Industry Standards” shall mean the Definitions for Oil and Gas Reserves promulgated by the Society of Petroleum Engineers (or any generally recognized successor) as in effect at the time in question.

“Plan” shall mean any of (nnnnnnnnnn) an “employee benefit plan” (as defined in Section 3(3) of ERISA) that is subject to Title I of ERISA, (oooooooooo) a “plan” as defined in Section 4975 of the Code to which Section 4975 of the Code applies, and (pppppppppp) any Person whose assets include (for purposes of the Plan Asset Regulations or otherwise for purposes of Title I of ERISA or Section 4975 of the Code) the assets of any such “employee benefit plan” or “plan”.

“Plan Asset Regulations” shall mean 29 CFR § 2510.3-101 et seq., as modified by Section 3(42) of ERISA, as amended from time to time.

“Prime Rate” shall mean the rate of interest last quoted by The Wall Street Journal as the “Prime Rate” in the U.S. or, if The Wall Street Journal ceases to quote such rate, the highest per annum interest rate published by the Board in Federal Reserve Statistical Release H.15 (519) (Selected Interest Rates) as the “bank prime loan” rate or, if such rate is no longer quoted therein, any similar rate quoted therein (as determined by the Administrative Agent) or any similar release by the Board (as determined by the Administrative Agent). Each change in the Prime Rate shall be effective from and including the date such change is publicly announced or quoted as being effective.

“Pro Forma Basis” shall mean, as to any Person, for any events as described below that occur subsequent to the commencement of a period for which the financial effect of such events is being calculated, and giving effect to the events for which such calculation is being made, such calculation as will give pro forma effect to such events as if such events occurred on the first day of the four consecutive fiscal quarter period ended on or before the occurrence of such event (the “Reference Period”): (i) in making any determination of EBITDAX, effect shall be given to any Disposition, any acquisition, Investment, capital expenditure, construction, repair, replacement, improvement, development, disposition, merger, amalgamation, consolidation (including the Transactions or any similar transaction or transactions not otherwise permitted under Section 10.3 or Section 10.5 that require a waiver or consent of the Majority Lenders and such waiver or consent has been obtained), any dividend, distribution or other similar payment, any designation of any Restricted Subsidiary as an Unrestricted Subsidiary and any Subsidiary Redesignation, and any restructurings of the business of the Borrower or any Restricted Subsidiary that the Borrower or any of the Restricted Subsidiaries has determined to make and/or made and are expected to have a continuing impact and are factually supportable, that would include cost savings resulting from head count reduction, closure of facilities and similar operational and other cost savings, which adjustments the Borrower determines are reasonable as set forth in a certificate of a Financial Officer of the Borrower (the foregoing, together with any transactions related thereto or in connection therewith, the “relevant transactions”), in each case that occurred during the Reference Period (or, in the case of determinations made pursuant to the definition of the term “Pro Forma Compliance” or pursuant to Sections 10.1, 10.2, 10.5, 10.6 and 10.7 occurring during the Reference Period or thereafter and through and including the date upon which the respective Permitted Acquisition or relevant transaction is consummated), (ii) in making any determination on a Pro Forma Basis, (x) all Indebtedness (including Indebtedness issued, incurred or assumed as a result of, or to finance, any relevant transactions and for which the financial effect is being calculated, whether incurred under this Agreement or otherwise, but excluding normal fluctuations in revolving Indebtedness incurred for working capital purposes) issued, incurred, assumed or permanently repaid during the Reference Period (or, in the case of determinations made pursuant to the definition of the term “Pro Forma Compliance” or pursuant to Sections 10.1, 10.2, 10.5, 10.6 and 10.7, occurring during the Reference Period or thereafter and through and including the date upon which the respective Permitted Acquisition or relevant transaction is consummated) shall be deemed to have been issued, incurred, assumed or permanently repaid at the beginning of such period, (y) Interest Expense of such person attributable to interest on any Indebtedness, for which pro forma effect is being given as provided in preceding clause (x), bearing floating interest rates shall be computed on a pro forma basis as if the rates that would have been in effect during the period for which pro forma effect is being given had been actually in effect during such periods, and (z) with respect to each New Facility that commences operations and records not less than one full fiscal quarter’s operations during the Reference Period, the operating results of such New Facility shall be annualized on a straight line basis during such period, and (iii)(A) any Subsidiary Redesignation then being designated, effect shall be given to such Subsidiary Redesignation and all other Subsidiary Redesignations after the first day of the relevant Reference Period and on or prior to the date of the respective Subsidiary Redesignation then being designated, collectively, and (B) any designation of a Restricted Subsidiary as an

Unrestricted Subsidiary, effect shall be given to such designation and all other designations of Restricted Subsidiaries as Unrestricted Subsidiaries after the first day of the relevant Reference Period and on or prior to the date of the then applicable designation of a Restricted Subsidiary as an Unrestricted Subsidiary, collectively.

Pro forma calculations made pursuant to the definition of the term “Pro Forma Basis” shall be determined in good faith by a Financial Officer of the Borrower and may include, for any fiscal period ending on or prior to the third anniversary of any relevant pro forma event (but not for any fiscal period ending after such third anniversary), adjustments to reflect operating expense reductions and other operating improvements, synergies or cost savings reasonably expected to result from such relevant pro forma event (including, to the extent applicable, the Transactions).

For purposes of this definition, any amount in a currency other than Dollars will be converted to Dollars based on the average exchange rate for such currency for the most recent twelve month period immediately prior to the date of determination in a manner consistent with that used in calculating EBITDAX for the applicable period.

“Pro Forma Compliance” shall mean, at any date of determination, that the Borrower and the Restricted Subsidiaries shall be in compliance, on a Pro Forma Basis after giving effect on a Pro Forma Basis to the relevant transactions (including the assumption, the issuance, incurrence and permanent repayment of Indebtedness), with each Financial Performance Covenant recomputed as at the last day of the most recently ended fiscal quarter of the Borrower and the Restricted Subsidiaries for which the financial statements and certificates required pursuant to Section 9.1(a) or Section 9.1(b) have been or were required to have been delivered.

“Proceeding” means any claim, litigation, investigation, action, suit, arbitration or administrative, judicial or regulatory action or proceeding in any jurisdiction.

“Production Payments and Reserve Sales” shall mean the grant or transfer by the Borrower or any of its Restricted Subsidiaries to any Person of a royalty, overriding royalty, net profits interest, production payment (whether volumetric or dollar-denominated), partnership or other interest in Oil and Gas Properties, reserves or the right to receive all or a portion of the production or the proceeds from the sale of production attributable to such properties where the holder of such interest has recourse solely to such production or proceeds of production, subject to the obligation of the grantor or transferor to operate and maintain, or cause the subject interests to be operated and maintained, in a reasonably prudent manner or other customary standard or subject to the obligation of the grantor or transferor to indemnify for environmental, title or other matters customary in the Oil and Gas Business, including any such grants or transfers.

“Proposed Acquisition” shall have the meaning provided in Section 10.10(a).

“Proposed Borrowing Base” shall have the meaning provided in Section 2.14(c)(i).

“Proposed Borrowing Base Notice” shall have the meaning provided in Section 2.14(c)(ii).

“Proved Developed Non-Producing Reserves” shall mean oil and gas reserves that, in accordance with Petroleum Industry Standards, are classified as both “Proved Reserves” and “Developed Non-Producing Reserves.”

“Proved Developed Producing Reserves” shall mean oil and gas reserves that, in accordance with Petroleum Industry Standards, are classified as both “Proved Reserves” and “Developed Producing Reserves.”

“Proved Developed Reserves” shall mean oil and gas reserves that, in accordance with Petroleum Industry Standards, are classified as both “Proved Reserves” and one of the following: (qqqqqqqqqq) “Developed Producing Reserves” or (rrrrrrrrrr) “Developed Non-Producing Reserves.”

“Proved Reserves” shall mean oil and gas reserves that, in accordance with Petroleum Industry Standards, are classified as both “Proved Reserves” and one of the following: (ssssssssss) “Developed Producing Reserves”, (tttttttttt) “Developed Non-Producing Reserves” or (uuuuuuuuuu) “Undeveloped Reserves”.

“PTE” shall mean a prohibited transaction class exemption issued by the U.S. Department of Labor, as any such exemption may be amended from time to time.

“Public Company Compliance” shall mean compliance with the requirements of the Sarbanes-Oxley Act of 2002 and the rules and regulations promulgated in connection therewith, the provisions of the Securities Act and the Exchange Act, and the rules of national securities exchange listed companies (in each case, as applicable to companies with equity or debt securities held by the public), including procuring directors’ and officers’ insurance, legal and other professional fees, and listing fees.

“PV-10” shall mean, with respect to any Proved Reserves expected to be produced from any Borrowing Base Properties, the net present value, discounted at 10% per annum, of the future net revenues expected to accrue to the Borrower’s and the Credit Parties’ collective interests in such reserves during the remaining expected economic lives of such reserves, calculated in accordance with the most recent Bank Price Deck provided to the Borrower by the Administrative Agent pursuant to Section 2.14(i).

“QFC” has the meaning assigned to the term “qualified financial contract” in, and shall be interpreted in accordance with, 12 U.S.C. 5390(c)(8)(D).

“QFC Credit Support” has the meaning assigned to it in Section 13.25.

“Qualified ECP Guarantor” shall mean, in respect of any Secured Hedge Transaction, each Credit Party that has total assets exceeding $10,000,000 at the time such Secured Hedge Transaction is incurred or such other person as constitutes an “eligible contract participant” under the Commodity Exchange Act.

“Qualified Equity Interests” shall mean any Equity Interests of Holdings or the Borrower or any Parent Entity other than Disqualified Stock.

“QuarterNorth” shall mean QuarterNorth Energy Inc., a Delaware corporation.

“QuarterNorth Acquisition” shall mean the consummation of the transactions described in the QuarterNorth Acquisition Agreement, pursuant to which the Borrower shall acquire the Equity Interests of QuarterNorth.

“QuarterNorth Acquisition Agreement” shall mean that certain Agreement and Plan of Merger dated as of January 13, 2024, among QuarterNorth, Holdings, Compass Star Merger Sub Inc., a Delaware corporation and an indirect wholly-owned subsidiary of Holdings, and Michael T. Dane and Thomas R. Lamme,

in their collective capacity as the representatives of the Company Stockholders and Equity Award Holders (each as defined therein).

“QuarterNorth Acquisition Debt” shall mean any Indebtedness permitted under Section 10.1(cc).

“QuarterNorth Reserve Report” shall have the meaning provided in the Tenth Amendment.

“Recipient” means (vvvvvvvvvv) the Administrative Agent, (wwwwwwwwww) any Lender and (xxxxxxxxxx) any Issuing Bank, as applicable.

“Redetermination Date” shall mean, with respect to any Scheduled Redetermination or any Interim Redetermination, the date that the redetermined Borrowing Base related thereto becomes effective pursuant to Section 2.14(d).

“Reference Time” with respect to any setting of the then-current Benchmark means (yyyyyyyyyy) if such Benchmark is the Term SOFR Rate, 5:00 a.m. (Chicago time) on the day that is two U.S. Government Securities Business Days preceding the date of such setting, (zzzzzzzzzz) if such Benchmark is Daily Simple SOFR, then four Business Days prior to such setting, or (aaaaaaaaaaa) if such Benchmark is none of the Term SOFR Rate or Daily Simple SOFR, the time determined by the Administrative Agent in its reasonable discretion.

“Refinance” shall have the meaning provided in the definition of “Permitted Refinancing Indebtedness.”

“Register” shall have the meaning provided in Section 13.6(b)(iv).

“Regulation T” shall mean Regulation T of the Board as from time to time in effect and any successor to all or a portion thereof establishing margin requirements.

“Regulation U” shall mean Regulation U of the Board as from time to time in effect and any successor to all or a portion thereof establishing margin requirements.

“Regulation X” shall mean Regulation X of the Board as from time to time in effect and any successor to all or a portion thereof establishing margin requirements.

“Reimbursement Date” shall have the meaning provided in Section 3.4(a).

“Related Parties” shall mean, with respect to any specified Person, such Person’s Affiliates and the directors, officers, employees, agents, advisors, representatives and members of such Person or such Person’s Affiliates and any Person that possesses, directly or indirectly, the power to direct or cause the direction of the management or policies of such Person, whether through the ability to exercise voting power, by contract or otherwise.

“Relevant Governmental Body” means, the Federal Reserve Board and/or the NYFRB, as applicable, or a committee officially endorsed or convened by the Federal Reserve Board and/or the NYFRB or, in each case, any successor thereto.

“Relevant Rate” means (bbbbbbbbbbb) with respect to any Term Benchmark Borrowing, the Adjusted Term SOFR Rate or (ccccccccccc) with respect to any RFR Borrowing, the Adjusted Daily Simple SOFR, as applicable.

“Reportable Event” shall mean an event described in Section 4043 of ERISA and the regulations thereunder, other than any event as to which the 30-day notice period has been waived.

“Required Cash Collateral Amount” shall have the meaning provided in Section 3.8(c).

“Required Lenders” shall mean, at any date, (ddddddddddd) Non-Defaulting Lenders having or holding at least 66-⅔% of the Adjusted Total Commitment at such date or (eeeeeeeeeee) if the Total Commitment has been terminated, Non-Defaulting Lenders having or holding at least 66-⅔% of the outstanding principal amount of the Loans, the Swingline Exposure and Letter of Credit Exposure (excluding the Loans, Swingline Exposure and Letter of Credit Exposure of Defaulting Lenders) in the aggregate at such date.

“Requirement of Law” shall mean, as to any Person, any law, treaty, rule, regulation, statute, order, ordinance, decree, judgment, consent decree, writ, injunction, settlement agreement or governmental requirement enacted, promulgated or imposed or entered into or agreed by any Governmental Authority, in each case applicable to or binding upon such Person or any of its property or assets or to which such Person or any of its property or assets is subject.

“Reserve Report” shall mean the Initial Reserve Report and any other subsequent report, in form and substance reasonably satisfactory to the Administrative Agent, setting forth, as of a date not earlier than December 31, 2017, in the case of the first Scheduled Redetermination on June 30, 2018, and on each June 30th or December 31st thereafter (or such other date in the event of certain Interim Redeterminations) the Proved Reserves and the Proved Developed Reserves attributable to the Borrowing Base Properties of the Borrower and the Credit Parties, together with a projection of the rate of production and future net revenues, operating expenses (including production taxes and ad valorem expenses) and capital expenditures with respect thereto as of such date, based upon the most recent Bank Price Deck provided to the Borrower by the Administrative Agent pursuant to Section 2.14(i); provided that in connection with any Interim Redeterminations of the Borrowing Base pursuant to the last sentence of Section 2.14(b), (i.e., as a result of the Borrower having acquired Oil and Gas Properties with Proved Reserves that are to be Borrowing Base Properties having a PV-10 (calculated at the time of acquisition) in excess of 10% of the Borrowing Base in effect immediately prior to such acquisition), the Borrower shall be required, for purposes of updating the Reserve Report, to set forth only such additional Proved Reserves and related information as are the subject of such acquisition.

“Reserve Report Certificate” shall mean a certificate of an Authorized Officer in substantially the form of Exhibit A certifying as to the matters set forth in Section 9.14(c) (or such other form reasonably acceptable to the Administrative Agent).

“Resolution Authority” means an EEA Resolution Authority or, with respect to any UK Financial Institution, a UK Resolution Authority.

“Restricted Domestic Subsidiary” shall mean a Domestic Subsidiary that is a Restricted Subsidiary.

“Restricted Foreign Subsidiary” shall mean a Foreign Subsidiary that is a Restricted Subsidiary.

“Restricted Payments” shall have the meaning provided in Section 10.6.

“Restricted Subsidiary” shall mean any Subsidiary of the Borrower other than an Unrestricted Subsidiary.

“Reuters” means, as applicable, Thomson Reuters Corp., Refinitiv, or any successor thereto.

“Revaluation Date” shall mean, with respect to any Alternate Currency Letter of Credit, each of the following: (fffffffffff) each date of issuance of an Alternate Currency Letter of Credit, (ggggggggggg) each date of an amendment of any Alternate Currency Letter of Credit having the effect of increasing the amount thereof (solely with respect to the increased amount), (hhhhhhhhhhh) each date of any payment by an Issuing Bank under any Alternate Currency Letter of Credit, and (iiiiiiiiiii) such additional dates as the Administrative Agent or the applicable Issuing Bank shall determine or the Majority Lenders shall require.

“RFR Borrowing” means, as to any Borrowing, the RFR Loans comprising such Borrowing.

“RFR Loan” means a Loan that bears interest at a rate based on the Adjusted Daily Simple SOFR.

“S&P” shall mean Standard & Poor’s Ratings Services or any successor by merger or consolidation to its business.

“Sanctioned Country” shall mean, at any time, a country, region or territory which is itself the subject or target of any Sanctions (as of May 4, 2022, the so-called Donetsk People’s Republic, the so-called Luhansk People’s Republic, the Crimea Region of Ukraine, Cuba, Iran, North Korea and Syria).

“Sanctioned Person” shall mean, at any time, (jjjjjjjjjjj) any Person listed in any Sanctions-related list of designated Persons maintained by the Office of Foreign Assets Control of the U.S. Department of the Treasury, the U.S. Department of State, or by the United Nations Security Council, the European Union, any European Union member state, Her Majesty’s Treasury of the United Kingdom, or other relevant sanctions authority, (kkkkkkkkkkk) any Person operating, organized or resident in a Sanctioned Country, (lllllllllll) any Person owned or controlled by any such Person or Persons described in the foregoing clauses 0 or 0, or (mmmmmmmmmmm) any Person otherwise subject to any Sanctions.

“Sanctions” shall mean all economic or financial sanctions or trade embargoes imposed, administered or enforced from time to time by (nnnnnnnnnnn) the U.S. government, including those administered by the Office of Foreign Assets Control of the U.S. Department of the Treasury or the U.S. Department of State or (ooooooooooo) the United Nations Security Council, the European Union, any European Union member state, Her Majesty’s Treasury of the United Kingdom, or other relevant sanctions authority.

“Scheduled Dispositions” shall have the meaning provided in Section 10.4(i).

“Scheduled Redetermination” shall have the meaning provided in Section 2.14(b).

“Scheduled Redetermination Date” shall mean the date on which a Borrowing Base that has been redetermined pursuant to a Scheduled Redetermination becomes effective as provided in Section 2.14.

“SEC” shall mean the Securities and Exchange Commission or any successor thereto.

“Second Amendment” shall mean that certain Joinder, Commitment Increase Agreement, Second Amendment to Credit Agreement, Borrowing Base Redetermination Agreement, and Amendment to other

Credit Documents dated as of December 10, 2019, by and among Holdings, the Borrower, each other Credit Party, the Administrative Agent, each Issuing Bank, the Swingline Lender and the Lenders party thereto.

“Second Amendment Effective Date” shall mean the first date on which all conditions precedent set forth in Section 10 of the Second Amendment shall have been satisfied.

“Section 9.1 Financials” shall mean the financial statements delivered, or required to be delivered, pursuant to Section 9.1(a) or (b), together with the accompanying Authorized Officer’s certificate delivered, or required to be delivered, pursuant to Section 9.1(c).

“Secured Cash Management Agreement” shall mean any agreement related to Cash Management Services by and between the Borrower or any of its Restricted Subsidiaries and any Cash Management Bank that is secured by the Security Documents in accordance with the documents related to any such Cash Management Services among the Borrower and the applicable Cash Management Bank.

“Secured Hedge Transaction” shall mean any Hedge Transaction by and between the Borrower or any of its Restricted Subsidiaries and any Hedge Bank that is secured that is secured by the Security Documents in accordance with the Hedge Agreement related to any such Hedge Transaction among the Borrower or any of its Restricted Subsidiaries and the applicable Hedge Bank and any Legacy Hedge Transaction.

“Secured Parties” shall mean, collectively, the Administrative Agent, the Collateral Agent, each Issuing Bank, each Lender, each Hedge Bank that is party to any Secured Hedge Transaction, each Cash Management Bank that is a party to any Secured Cash Management Agreement and each sub-agent pursuant to Section 12.2 appointed by the Administrative Agent with respect to matters relating to the Credit Documents or by the Collateral Agent with respect to matters relating to any Security Document.

“Securities Act” shall mean the Securities Act of 1933, as amended, and the rules and regulations promulgated thereunder.

“Security Documents” shall mean, collectively, (ppppppppppp) the Collateral Agreement, (qqqqqqqqqqq) the Mortgages, (rrrrrrrrrrr) the Control Agreements, and (sssssssssss) each other security agreement or other instrument or document executed and delivered pursuant to Section 9.11 or 9.13 or pursuant to any other such Security Documents or otherwise to secure or perfect the security interest in any or all of the Obligations.

“Senior Unsecured Notes Indenture” shall mean the Indenture, dated as of February 6, 2013, under which the Senior Unsecured Notes were issued, among the Borrower and certain of the Subsidiaries party thereto and the trustee named therein from time to time, as amended, restated, supplemented or otherwise modified from time to time in accordance with the requirements thereof and of this Agreement.

“Sixth Amendment” shall mean that certain Borrowing Base Redetermination Agreement and Sixth Amendment to Credit Agreement dated as of June 22, 2021, by and among Holdings, the Borrower, each other Credit Party, the Administrative Agent, each Issuing Bank party thereto, the Swingline Lender and the Lenders party thereto.

“Sixth Amendment Effective Date” shall mean the first date on which all conditions precedent set forth in Section 8 of the Sixth Amendment shall have been satisfied.

“SOFR” means a rate equal to the secured overnight financing rate as administered by the SOFR Administrator.

“SOFR Administrator” means the NYFRB (or a successor administrator of the secured overnight financing rate).

“SOFR Administrator’s Website” means the NYFRB’s Website, currently at http://www.newyorkfed.org, or any successor source for the secured overnight financing rate identified as such by the SOFR Administrator from time to time.

“SOFR Determination Date” has the meaning specified in the definition of “Daily Simple SOFR”.

“SOFR Rate Day” has the meaning specified in the definition of “Daily Simple SOFR”.

“Solvent” shall mean, with respect to any Person, that as of the Closing Date, (ttttttttttt) the fair value of the assets of such Person and its Subsidiaries on a consolidated basis, at a fair valuation, will exceed the debts and liabilities, direct, subordinated, contingent or otherwise, of such Person and its Subsidiaries on a consolidated basis; (uuuuuuuuuuu) the present fair saleable value of the property of such Person and its Subsidiaries on a consolidated basis will be greater than the amount that will be required to pay the probable liability of such Person and its Subsidiaries on a consolidated basis on their debts and other liabilities, direct, subordinated, contingent or otherwise, as such debts and other liabilities become absolute and matured; (vvvvvvvvvvv) such Person and its Subsidiaries on a consolidated basis will be able to pay their debts and liabilities, direct, subordinated, contingent or otherwise, as such debts and liabilities become absolute and matured; and (wwwwwwwwwww) such Person and its Subsidiaries on a consolidated basis will not have unreasonably small capital with which to conduct the businesses in which they are engaged as such businesses are now conducted and are proposed to be conducted following the Closing Date.

“Specified Subsidiary” shall mean, at any date of determination any Restricted Subsidiary (xxxxxxxxxxx) whose Total Assets at the last day of the applicable Test Period were equal to or greater than 15% of the Consolidated Total Assets of the Borrower and the Restricted Domestic Subsidiaries at such date, or (yyyyyyyyyyy) whose revenues during such Test Period were equal to or greater than 15% of the consolidated revenues of the Borrower and the Restricted Subsidiaries for such period, in each case determined in accordance with GAAP.

“Sponsors” shall mean (zzzzzzzzzzz) Apollo Global Management, LLC, (aaaaaaaaaaaa) Riverstone Holdings, LLC, and (bbbbbbbbbbbb) the respective Affiliates of the Persons described in the foregoing clauses 0 and 0, excluding in each case any of their respective operating portfolio companies.

“Spring 2020 Reserve Report” means that certain Reserve Report prepared as of February 7, 2020.

“SPV” shall have the meaning provided in Section 13.6(g).

“Stated Amount” of any Letter of Credit shall mean the maximum amount from time to time available to be drawn thereunder (calculated, in the case of Alternate Currency Letters of Credit, based on the Dollar Equivalent thereof), determined without regard to whether any conditions to drawing could then be met.

“Stone Energy” shall have the meaning provided in the recitals to this Agreement.

“Stone Energy Notes” shall mean the $6,060,218 in aggregate principal amount of Stone Energy’s 7.5% Notes due 2022 issued pursuant to the Stone Energy Notes Indenture that remain outstanding as of the Closing Date after giving effect to the 2018 Junior Lien Note Exchanges.

“Stone Energy Notes Indenture” shall mean the Indenture, dated as of February 28, 2017, under which the Stone Energy Notes were issued, among the Stone Energy and certain of its Subsidiaries party thereto and the trustee named therein from time to time, as amended, restated, supplemented or otherwise modified from time to time in accordance with the requirements thereof and of this Agreement.

“Subagent” shall have the meaning provided in Section 12.2.

“Subsidiary” of any Person shall mean and include (cccccccccccc) any corporation more than 50% of whose Equity Interests of any class or classes having by the terms thereof ordinary voting power to elect a majority of the directors of such corporation (irrespective of whether or not at the time Equity Interests of any class or classes of such corporation shall have or might have voting power by reason of the happening of any contingency) is at the time owned by such Person directly or indirectly through Subsidiaries and (dddddddddddd) any limited liability company, partnership, association, joint venture or other entity of which such Person directly or indirectly through Subsidiaries has more than a 50% equity interest at the time. Unless otherwise expressly provided, all references herein to a “Subsidiary” shall mean a Subsidiary of the Borrower.

“Subsidiary Guarantor” shall mean each Subsidiary that is a Guarantor.

“Subsidiary Redesignation” shall have the meaning provided in the definition of “Unrestricted Subsidiary” contained in this Section 1.1.

“Successor Borrower” shall have the meaning provided in Section 10.3(a).

“Supported QFC” has the meaning assigned to it in Section 13.25.

“Swap Obligation” shall mean, with respect to any Guarantor, any obligation to pay or perform under any agreement, contract or transaction that constitutes a “swap” within the meaning of Section 1a(47) of the Commodity Exchange Act.

“Swap Termination Value” shall mean, in respect of any one or more Hedge Transactions, after taking into account the effect of any legally enforceable netting agreement relating to such Hedge Transactions, (eeeeeeeeeeee) for any date on or after the date such Hedge Transactions have been closed out and termination value(s) determined in accordance therewith, such termination value(s), and (ffffffffffff) for any date prior to the date referenced in clause 0, the amount(s) determined as the mark-to-market value(s) for such Hedge Transactions, as determined based upon one or more mid-market or other readily available quotations provided by any recognized dealer in such Hedge Transactions (which may include a Lender or any Affiliate of a Lender).

“Swingline Commitment” shall mean the obligation of the Swingline Lender to make Swingline Loans pursuant to Section 2.1 in an aggregate principal amount at any one time outstanding not to exceed $10,000,000.

“Swingline Exposure” shall mean at any time the aggregate principal amount at such time of all outstanding Swingline Loans. The Swingline Exposure of any Lender at any time shall equal the sum of (gggggggggggg) its Commitment Percentage of the aggregate principal amount of all Swingline Loans outstanding at such time (excluding, in the case of any Lender that is a Swingline Lender, Swingline Loans made by it that are outstanding at such time to the extent that the other Lenders shall not have funded their participations in such Swingline Loans), adjusted to give effect to any reallocation under Section 2.15 of the Swingline Exposure of Defaulting Lenders in effect at such time, and (hhhhhhhhhhhh) in the case of any Lender that is a Swingline Lender, the aggregate principal

amount of all Swingline Loans made by such Lender outstanding at such time, less the amount of participations funded by the other Lenders in such Swingline Loans.

“Swingline Lender” shall mean JPMorgan Chase Bank, N.A., in its capacity as the lender of Swingline Loans hereunder.

“Swingline Loan” shall have the meaning provided in Section 2.1(b). All Swingline Loans shall be denominated in Dollars.

“Swingline Maturity Date” shall mean, with respect to any Swingline Loan, the date that is five (5) Business Days prior to the Maturity Date.

“Taxes” shall mean any and all present or future taxes, duties, levies, imposts, assessments, deductions, withholdings or other similar charges imposed by any Governmental Authority whether computed on a separate, consolidated, unitary, combined or other basis and any interest, fines, penalties or additions to tax with respect to the foregoing.

“Tenth Amendment” shall mean that certain Tenth Amendment to Credit Agreement dated as of January 13, 2024, by and among Holdings, the Borrower, each other Credit Party, the Administrative Agent, and the Lenders party thereto.

“Tenth Amendment Effective Date” shall mean the first date on which all conditions precedent to the effectiveness of the Tenth Amendment shall have been satisfied.

“Term Benchmark” when used in reference to any Loan or Borrowing, refers to whether such Loan, or the Loans comprising such Borrowing, are bearing interest at a rate determined by reference to the Adjusted Term SOFR Rate, other than pursuant to clause 0 of the definition of “Alternate Base Rate”.

“Termination Date” shall mean the earlier to occur of (iiiiiiiiiiii) the Maturity Date and (jjjjjjjjjjjj) the date on which the Total Commitment shall have terminated (whether by acceleration or otherwise).

“Term SOFR Determination Day” has the meaning assigned to it under the definition of Term SOFR Reference Rate.

“Term SOFR Rate” means, with respect to any Term Benchmark Borrowing and for any tenor comparable to the applicable Interest Period, the Term SOFR Reference Rate at approximately 5:00 a.m., Chicago time, two U.S. Government Securities Business Days prior to the commencement of such tenor comparable to the applicable Interest Period, as such rate is published by the CME Term SOFR Administrator.

“Term SOFR Reference Rate” means, for any day and time (such day, the “Term SOFR Determination Day”), with respect to any Term Benchmark Borrowing denominated in Dollars and for any tenor comparable to the applicable Interest Period, the rate per annum published by the CME Term SOFR Administrator and identified by the Administrative Agent as the forward-looking term rate based on SOFR. If by 5:00 pm (New York City time) on such Term SOFR Determination Day, the “Term SOFR Reference Rate” for the applicable tenor has not been published by the CME Term SOFR Administrator and a Benchmark Replacement Date with respect to the Term SOFR Rate has not occurred, then, so long as such day is otherwise a U.S. Government Securities Business Day, the Term SOFR Reference Rate for such Term SOFR Determination Day will be the Term SOFR Reference Rate as published in respect of the first preceding U.S. Government Securities Business Day for which such Term SOFR Reference Rate was published by the CME Term SOFR Administrator, so long

as such first preceding U.S. Government Securities Business Day is not more than five (5) U.S. Government Securities Business Days prior to such Term SOFR Determination Day.

“Test Period” shall mean, as of any date of determination, the four consecutive fiscal quarters of the Borrower then last ended and for which Section 9.1 Financials have been delivered to the Administrative Agent.

“Third Amendment” means the Third Amendment to Credit Agreement and Borrowing Base Redetermination Agreement, dated as of June 19, 2020, among Holdings, the Borrower, the Administrative Agent and the other Persons party thereto.

“Third Amendment Effective Date” means the “Effective Date” as defined in the Third Amendment.

“Total Assets” shall mean, as of any date of determination with respect to any Person, the amount that would, in conformity with GAAP, be set forth opposite the caption “total assets” (or any like caption) on a balance sheet of such Person at such date.

“Total Commitment” shall mean, at any time, the sum of the Commitments of the Lenders at such time. The Total Commitment as of the Ninth Amendment Implementation Date is $965,000,000.

“Total Exposure” shall mean, with respect to any Lender at any time, the sum of (kkkkkkkkkkkk) the aggregate principal amount of the Loans of such Lender then outstanding, (llllllllllll) such Lender’s Letter of Credit Exposure at such time and (mmmmmmmmmmmm) such Lender’s Swingline Exposure at such time.

“Transaction Expenses” shall mean any fees or expenses incurred or paid by the Borrower or any of its Subsidiaries or any of their Affiliates (including the Co-Investors) in connection with the Transactions, this Agreement and the other Credit Documents, the Transaction Agreement, the 2018 Junior Lien Notes, and the transactions contemplated hereby and thereby.

“Transaction Agreement” shall have the meaning provided in the recitals to this Agreement.

“Transactions” shall have the meaning provided in the recitals to this Agreement.

“Transferee” shall have the meaning provided in Section 13.6(e).

“Type” when used in reference to any Loan or Borrowing, refers to whether the rate of interest on such Loan, or on the Loans comprising such Borrowing, is determined by reference to the Adjusted Term SOFR Rate, the Alternate Base Rate or the Adjusted Daily Simple SOFR.

“UCC” shall mean the Uniform Commercial Code of the State of New York or of any other state the laws of which are required to be applied in connection with the perfection of security interests in any Collateral.

“UK Financial Institutions” means any BRRD Undertaking (as such term is defined under the PRA Rulebook (as amended form time to time) promulgated by the United Kingdom Prudential Regulation Authority) or any person falling within IFPRU 11.6 of the FCA Handbook (as amended from time to time) promulgated by the United Kingdom Financial Conduct Authority, which includes certain credit institutions and investment firms, and certain affiliates of such credit institutions or investment firms.

“UK Resolution Authority” means the Bank of England or any other public administrative authority having responsibility for the resolution of any UK Financial Institution.

“Unadjusted Benchmark Replacement” means the applicable Benchmark Replacement excluding the related Benchmark Replacement Adjustment.

“Unfunded Current Liability” of any Plan shall mean the amount, if any, by which the Accumulated Benefit Obligation (as defined under Statement of Financial Accounting Standards No. 87 (“SFAS 87”)) under the Plan as of the close of its most recent plan year, determined in accordance with SFAS 87 as in effect on the date hereof, exceeds the Fair Market Value of the assets allocable thereto.

“Uniform Customs” shall mean, with respect to any Letter of Credit, the Uniform Customs and Practice for Documentary Credits as approved by the International Chamber of Commerce, commencing on July 1, 2007 (or such later version thereof as may be in effect at the time of issuance).

“Unpaid Drawing” shall have the meaning provided in Section 3.4(a).

“Unrestricted Cash” shall mean cash or cash equivalents of the Borrower or any of its Restricted Subsidiaries that would not appear as “restricted” on a consolidated balance sheet of the Borrower or any of its Restricted Subsidiaries.

“Unrestricted Subsidiary” shall mean (nnnnnnnnnnnn) any Subsidiary of the Borrower that is formed or acquired after the Closing Date if, at such time or promptly thereafter, the Borrower designates such Subsidiary as an “Unrestricted Subsidiary” in a written notice to the Administrative Agent, (oooooooooooo) any Restricted Subsidiary designated as an Unrestricted Subsidiary by the Borrower in a written notice to the Administrative Agent; provided that in the case of each of 0 and 0, (i) such designation shall be deemed to be an Investment (or reduction in an outstanding Investment, in the case of a designation of an Unrestricted Subsidiary as a Restricted Subsidiary) on the date of such designation in an amount equal to the Fair Market Value of the Borrower’s investment therein on such date and such designation shall be permitted only to the extent such Investment is permitted under Section 10.5 on the date of such designation, (ii) in the case of clause 0, such designation shall be deemed to be a Disposition pursuant to which the provisions of Section 2.14(g) will apply to the extent contemplated thereby and (iii) no Default or Event of Default would result from such designation immediately after giving effect thereto and (pppppppppppp) each Subsidiary of an Unrestricted Subsidiary. No Subsidiary may be designated as an Unrestricted Subsidiary if, after such designation, it would be a “Restricted Subsidiary” for the purpose of the Junior Lien Notes, the EnVen Notes, any QuarterNorth Acquisition Debt, any Permitted Incremental Junior Lien Debt, any Permitted Additional Debt or any Permitted Refinancing Indebtedness in respect of any of the foregoing. The Borrower may, by written notice to the Administrative Agent, re- designate any Unrestricted Subsidiary as a Restricted Subsidiary (each, a “Subsidiary Redesignation”), and thereafter, such Subsidiary shall no longer constitute an Unrestricted Subsidiary, but only if (A) to the extent such Subsidiary has outstanding Indebtedness on the date of such designation, immediately after giving effect to such designation, the Borrower shall be in Pro Forma Compliance and (B) no Default or Event of Default would result from such Subsidiary Redesignation.

“U.S. Government Securities Business Day” means any day except for (qqqqqqqqqqqq) a Saturday, (rrrrrrrrrrrr) a Sunday or (ssssssssssss) a day on which the Securities Industry and Financial Markets Association recommends that the fixed income departments of its members be closed for the entire day for purposes of trading in United States government securities.

“U.S. Lender” shall mean any Lender other than a Non-U.S. Lender.

“U.S. Special Resolution Regime” has the meaning assigned to it in Section 13.25.

“Utilization Percentage” shall mean, as of any day, the fraction expressed as a percentage, the numerator of which is the sum of the aggregate Total Exposures of all Lenders on such day, and the denominator of which is the Loan Limit in effect on such day.

“Volumetric Production Payments” shall mean production payment obligations recorded as deferred revenue in accordance with GAAP, together with all undertakings and obligations in connection therewith.

“Voting Stock” shall mean, with respect to any Person, such Person’s Equity Interests having the right to vote for the election of directors of such Person under ordinary circumstances.

“Weighted Average Life to Maturity” shall mean, when applied to any Indebtedness at any date, the number of years obtained by dividing: (tttttttttttt) the sum of the products obtained by multiplying (i) the amount of each then remaining installment, sinking fund, serial maturity or other required payments of principal, including payment at final maturity, in respect thereof, by (ii) the number of years (calculated to the nearest one-twelfth) that will elapse between such date and the making of such payment; by (uuuuuuuuuuuu) the then outstanding principal amount of such Indebtedness.

“Whitney Term Loan Documents” shall mean (vvvvvvvvvvvv) that certain Commercial Business Loan Agreement for Term Loan, dated November 20, 2015, between Whitney Bank and Stone Energy Corporation, (wwwwwwwwwwww) that certain Commercial Note, dated November 20, 2015 by Stone Energy Corporation in favor of Whitney Bank, (xxxxxxxxxxxx) that certain Multiple Indebtedness Mortgage, Pledge of Leases and Rents and Security Agreement by Stone Energy Corporation and (yyyyyyyyyyyy) any other documents, instruments, or similar agreements entered into in connection with any of the foregoing.

“Wholly owned Subsidiary” of any person shall mean a subsidiary of such person, all of the Equity Interests of which (other than directors’ qualifying shares or nominee or other similar shares required pursuant to applicable law) are owned by such person or another Wholly owned Subsidiary of such person.

“Write-Down and Conversion Powers” means, (zzzzzzzzzzzz) with respect to any EEA Resolution Authority, the write-down and conversion powers of such EEA Resolution Authority from time to time under the Bail-In Legislation for the applicable EEA Member Country, which write-down and conversion powers are described in the EU Bail-In Legislation Schedule, and (aaaaaaaaaaaaa) with respect to the United Kingdom, any powers of the applicable Resolution Authority under the Bail-In Legislation to cancel, reduce, modify or change the form of a liability of any UK Financial Institution or any contract or instrument under which that liability arises, to convert all or part of that liability into shares, securities or obligations of that person or any other person, to provide that any such contract or instrument is to have effect as if a right had been exercised under it or to suspend any obligation in respect of that liability or any of the powers under that Bail-In Legislation that are related to or ancillary to any of those powers.

1.2Other Interpretive Provisions. With reference to this Agreement and each other Credit Document, unless otherwise specified herein or in such other Credit Document:

(a)The meanings of defined terms are equally applicable to the singular and plural forms of the defined terms.

(b)The words “herein”, “hereto”, “hereof” and “hereunder” and words of similar import when used in any Credit Document shall refer to such Credit Document as a whole and not to any particular provision thereof.

(c)Article, Section, Exhibit and Schedule references are to the Credit Document in which such reference appears.

(d)The term “including” is by way of example and not limitation.

(e)The term “documents” includes any and all instruments, documents, agreements, certificates, notices, reports, financial statements and other writings, however evidenced, whether in physical or electronic form.

(f)In the computation of periods of time from a specified date to a later specified date, the word “from” means “from and including”; the words “to” and “until” each mean “to but excluding”; and the word “through” means “to and including”.

(g)Section headings herein and in the other Credit Documents are included for convenience of reference only and shall not affect the interpretation of this Agreement or any other Credit Document.

(h)Any reference to any Person shall be constructed to include such Person’s successors or assigns (subject to any restrictions on assignment set forth herein) and, in the case of any Governmental Authority, any other Governmental Authority that shall have succeeded to any or all of the functions thereof.

(i)Whenever the context may require, any pronoun shall include the corresponding masculine, feminine and neuter forms.

(j)The word “will” shall be construed to have the same meaning as the word “shall”.

(k)The words “asset” and “property” shall be construed to have the same meaning and effect and to refer to any and all tangible and intangible assets and properties, including cash, securities, accounts and contract rights.

1.3Accounting Terms. All accounting terms not specifically or completely defined herein shall be construed in conformity with, and all financial data (including financial ratios and other financial calculations) required to be submitted pursuant to this Agreement shall be prepared in conformity with, GAAP applied in a manner consistent with that used in preparing the Section 9.1 Financials, except as otherwise specifically prescribed herein; provided, however, that if the Borrower notifies the Administrative Agent that the Borrower requests an amendment to any provision hereof to eliminate the effect of any change occurring after the Closing Date in GAAP or in the application thereof on the operation of such provision (or if the Administrative Agent notifies the Borrower that the Required Lenders request an amendment to any provision hereof for such purpose), regardless of whether any such notice is given before or after such change in GAAP or in the application thereof, then such provision shall be interpreted on the basis of GAAP as in effect and applied immediately before such change shall have become effective until such notice shall have been withdrawn or such provision amended in accordance herewith. Notwithstanding any other provision contained herein, all terms of an accounting or financial nature used herein shall be construed, and all computations of amounts and ratios referred to herein shall be made, without giving effect to (a) any election under Financial Accounting Standards Board Accounting Standards Codification 825 (or any other Financial Accounting Standard having a similar result or effect) to value any Indebtedness or other liabilities of the Borrower or any Subsidiary at “fair value”, as defined therein and (b)

any treatment of Indebtedness under Accounting Standards Codification 470-20 or 2015-03 (or any other Accounting Standards Codification or Financial Accounting Standard having a similar result or effect) to value any such Indebtedness in a reduced or bifurcated manner as described therein, and such Indebtedness shall at all times be valued at the full stated principal amount thereof. Notwithstanding anything to the contrary contained in Section 1.3 or in the definition of “Capital Lease Obligations,” any change in accounting for leases pursuant to GAAP resulting from the adoption of Financial Accounting Standards Board Accounting Standards Update No. 2016-02, Leases (Topic 842) (“FAS 842”), to the extent such adoption would require treating any lease (or similar arrangement conveying the right to use) as a capital lease where such lease (or similar arrangement) would not have been required to be so treated under GAAP as in effect on December 31, 2015, such lease shall not be considered a capital lease, and all calculations and deliverables under this Agreement or any other Credit Document shall be made or delivered, as applicable, in accordance therewith.

1.4Rounding. Any financial ratios required to be maintained or complied with by the Borrower pursuant to this Agreement (or required to be satisfied in order for a specific action to be permitted under this Agreement) shall be calculated by dividing the appropriate component by the other component, carrying the result to one place more than the number of places by which such ratio is expressed herein and rounding the result up or down to the nearest number (with a rounding-up if there is no nearest number).

1.5References to Agreements, Laws, Etc. Unless otherwise expressly provided herein, (a) references to organizational documents, agreements (including the Credit Documents) and other Contractual Requirements shall be deemed to include all subsequent amendments, restatements, amendment and restatements, extensions, supplements and other modifications thereto, but only to the extent that such amendments, restatements, amendment and restatements, extensions, supplements and other modifications are permitted by any Credit Document and (b) references to any Requirement of Law shall include all statutory and regulatory provisions consolidating, amending, replacing, supplementing or interpreting such Requirement of Law.

1.6Times of Day. Unless otherwise specified, all references herein to times of day shall be references to New York City (daylight saving or standard, as applicable).

1.71.7 Timing of Payment or Performance. When the payment of any obligation or the performance of any covenant, duty or obligation is stated to be due or performance required on a day which is not a Business Day, the date of such payment (other than as described in Section 2.9) or performance shall extend to the immediately succeeding Business Day.

1.8Currency Equivalents Generally.

(a)For purposes of any determination under Section 9, Section 10 (other than Section 10.11) or Section 11 or any determination under any other provision of this Agreement requiring the use of a current exchange rate, all amounts incurred, outstanding or proposed to be incurred or outstanding in currencies other than Dollars shall be translated into Dollars at the Exchange Rate then in effect on the date of such determination; provided, however, that (w) the Administrative Agent shall determine the Exchange Rate as of each Revaluation Date to be used for calculating Dollar Equivalent amounts of Alternate Currency Letters of Credit. Such Exchange Rate shall become effective as of such Revaluation Date and shall be the Exchange Rate employed in converting any amounts between Dollars and each Alternate Currency until the next Revaluation Date to occur, (x) for purposes of determining compliance with Section 10 with respect to the amount of any Indebtedness, Investment, Disposition, Restricted Payment or payment under Section 10.7 in a currency other than Dollars, no Default or Event of Default shall be deemed to have occurred solely as a result of changes in rates of exchange occurring after the time such Indebtedness or Investment is incurred or Disposition, Restricted Payment or payment under Section 10.7 is made, (y) for purposes of determining compliance with any Dollar-denominated restriction on the

incurrence of Indebtedness, if such Indebtedness is incurred to Refinance other Indebtedness denominated in a foreign currency, and such Refinancing would cause the applicable Dollar-denominated restriction to be exceeded if calculated at the relevant currency exchange rate in effect on the date of such Refinancing, such Dollar-denominated restriction shall be deemed not to have been exceeded so long as the principal amount of such Refinanced Indebtedness does not exceed the principal amount of such Indebtedness being Refinanced and (z) for the avoidance of doubt, the foregoing provisions of this Section 1.8 shall otherwise apply to such Sections, including with respect to determining whether any Indebtedness or Investment may be incurred or Disposition, Restricted Payment or payment under Section 10.7 may be made at any time under such Sections. For purposes of Section 10.11, amounts in currencies other than Dollars shall be translated into Dollars at the applicable exchange rates used in preparing the most recently delivered financial statements pursuant to Section 9.1(a) or (b).

(b)Wherever in this Agreement in connection with an Alternate Currency Letter of Credit, an amount, such as a required minimum or multiple amount, is expressed in Dollars, such amount shall be the Dollar Equivalent of such Dollar amount (rounded to the nearest unit of such Alternate Currency, with 0.5 of a unit being rounded upward), as determined by the Administrative Agent.

(c)Each provision of this Agreement shall be subject to such reasonable changes of construction as the Administrative Agent may from time to time specify with the Borrower’s consent (such consent not to be unreasonably withheld) to appropriately reflect a change in currency of any country and any relevant market conventions or practices relating to such change in currency.

1.9Classification of Loans and Borrowings. For purposes of this Agreement, Loans may be classified and referred to by Type (e.g., a “Term Benchmark Loan” or an “RFR Loan”). Borrowings also may be classified and referred to by Type (e.g., a “Term Benchmark Borrowing” or an “RFR Borrowing”).

1.10Interest Rates; Benchmark Notification. The interest rate on a Loan denominated in dollars may be derived from an interest rate benchmark that may be discontinued or is, or may in the future become, the subject of regulatory reform. Upon the occurrence of a Benchmark Transition Event, Section 2.18(b) provides a mechanism for determining an alternative rate of interest. The Administrative Agent does not warrant or accept any responsibility for, and shall not have any liability with respect to, the administration, submission, performance or any other matter related to any interest rate used in this Agreement, or with respect to any alternative or successor rate thereto, or replacement rate thereof, including without limitation, whether the composition or characteristics of any such alternative, successor or replacement reference rate will be similar to, or produce the same value or economic equivalence of, the existing interest rate being replaced or have the same volume or liquidity as did any existing interest rate prior to its discontinuance or unavailability. The Administrative Agent and its affiliates and/or other related entities may engage in transactions that affect the calculation of any interest rate used in this Agreement or any alternative, successor or alternative rate (including any Benchmark Replacement) and/or any relevant adjustments thereto, in each case, in a manner adverse to the Borrower. The Administrative Agent may select information sources or services in its reasonable discretion to ascertain any interest rate used in this Agreement, any component thereof, or rates referenced in the definition thereof, in each case pursuant to the terms of this Agreement, and shall have no liability to the Borrower, any Lender or any other person or entity for damages of any kind, including direct or indirect, special, punitive, incidental or consequential damages, costs, losses or expenses (whether in tort, contract or otherwise and whether at law or in equity), for any error or calculation of any such rate (or component thereof) provided by any such information source or service.

1.11Letter of Credit Amounts. Unless otherwise specified herein, the amount of a Letter of Credit at any time shall be deemed to be the Dollar Equivalent of the stated amount of such Letter of Credit available to be drawn at such time; provided that with respect to any Letter of Credit that, by its terms, provides for one or more automatic increases in the available amount thereof, the amount of such Letter of Credit shall be deemed to be the Dollar Equivalent of the maximum amount of such Letter of Credit after giving effect to all such increases, whether or not such maximum amount is available to be drawn at such time.

1.12Divisions. For all purposes under the Credit Documents, in connection with any division or plan of division under Delaware law (or any comparable event under a different jurisdiction’s laws): (a) if any asset, right, obligation or liability of any Person becomes the asset, right, obligation or liability of a different Person, then it shall be deemed to have been transferred from the original Person to the subsequent Person, and (b) if any new Person comes into existence, such new Person shall be deemed to have been organized and acquired on the first date of its existence by the holders of its Equity Interests at such time.

Section 2.Amount and Terms of Credit

2.1Commitments.

(a)(i) Subject to and upon the terms and conditions herein set forth, each Lender severally, but not jointly, agrees to make a loan or loans denominated in Dollars (each a “Loan” and, collectively, the “Loans”) to the Borrower, which Loans (A) shall be made at any time and from time to time on and after the Closing Date and prior to the Termination Date, (B) may, at the option of the Borrower, be incurred and maintained as, and/or converted into, ABR Loans , Term Benchmark Loans or RFR Loans; provided that all Loans made by each of the Lenders pursuant to the same Borrowing shall, unless otherwise specifically provided herein, consist entirely of Loans of the same Type, (C) may be repaid and reborrowed in accordance with the provisions hereof, (D) shall not, for any Lender at any time, after giving effect thereto and to the application of the proceeds thereof, result in such Lender’s Total Exposure at such time exceeding such Lender’s Commitment Percentage at such time of the Loan Limit and (E) shall not, after giving effect thereto and to the application of the proceeds thereof, result in the aggregate amount of all Lenders’ Total Exposures at such time exceeding the Loan Limit.

(ii)Each Lender may at its option make any Loan by causing any domestic or foreign branch or Affiliate of such Lender to make such Loan, provided that (A) any exercise of such option shall not affect the obligation of the Borrower to repay such Loan and (B) in exercising such option, such Lender shall use its reasonable efforts to minimize any increased costs to the Borrower resulting therefrom (which obligation of the Lender shall not require it to take, or refrain from taking, actions that it determines would result in increased costs for which it will not be compensated hereunder or that it determines would be otherwise disadvantageous to it and in the event of such request for costs for which compensation is provided under this Agreement, the provisions of Section 2.10 shall apply).

(b)Subject to and upon the terms and conditions herein set forth, the Swingline Lender in its individual capacity agrees, at any time and from time to time on and after the Closing Date and prior to the Swingline Maturity Date, to make a loan or loans (each a “Swingline Loan” and, collectively, the “Swingline Loans”) to the Borrower in Dollars, which Swingline Loans (i) shall be ABR Loans, (ii) shall have the benefit of the provisions of Section 2.1(c), (iii) shall not exceed at any time outstanding the Swingline Commitment, (iv) shall not, after giving effect thereto and to the application of the proceeds thereof, result at any time in the aggregate amount of the Lenders’ Total Exposure at such time exceeding the Total Commitment then in effect and (v) may be repaid and reborrowed in accordance with the provisions hereof. Each outstanding Swingline

Loan shall be repaid in full on the earlier of (A) 15 Business Days after such Swingline Loan is initially borrowed and (B) the Swingline Maturity Date. The Swingline Lender shall not make any Swingline Loan after receiving a written notice from the Borrower, the Administrative Agent or any Lender stating that an Event of Default exists and is continuing until such time as the Swingline Lender shall have received written notice of (1) rescission of all such notices from the party or parties originally delivering such notice or (2) the waiver of such Event of Default in accordance with the provisions of Section 13.1.

(c)On any Business Day, the Swingline Lender may, in its sole discretion, give notice to each Lender that all then-outstanding Swingline Loans shall be funded with a Borrowing of Loans, in which case Loans constituting ABR Loans (each such Borrowing, a “Mandatory Borrowing”) shall be made on the immediately succeeding Business Day by each Lender pro rata based on each Lender’s Commitment Percentage, and the proceeds thereof shall be applied directly to the Swingline Lender to repay the Swingline Lender for such outstanding Swingline Loans. Each Lender hereby irrevocably agrees to make such Loans upon one Business Days’ notice pursuant to each Mandatory Borrowing in the amount and in the manner specified in the preceding sentence and on the date specified to it in writing by the Swingline Lender notwithstanding (i) that the amount of the Mandatory Borrowing may not comply with the minimum amount for each Borrowing specified in Section 2.2, (ii) whether any conditions specified in Section 7 are then satisfied, (iii) whether a Default or an Event of Default has occurred and is continuing, (iv) the date of such Mandatory Borrowing or (v) any reduction in the Total Commitment after any such Swingline Loans were made. In the event that, in the sole judgment of the Swingline Lender, any Mandatory Borrowing cannot for any reason be made on the date otherwise required above (including as a result of the commencement of a proceeding under the Bankruptcy Code in respect of the Borrower), each Lender hereby agrees that it shall forthwith purchase from the Swingline Lender (without recourse or warranty) such participation of the outstanding Swingline Loans as shall be necessary to cause the Lenders to share in such Swingline Loans ratably based upon their respective Commitment Percentages; provided that all principal and interest payable on such Swingline Loans shall be for the account of the Swingline Lender until the date the respective participation is purchased and, to the extent attributable to the purchased participation, shall be payable to such Lender purchasing same from and after such date of purchase.

2.2Minimum Amount of Each Borrowing; Maximum Number of Borrowings. The aggregate principal amount of each Borrowing shall be in a minimum amount of at least the Minimum Borrowing Amount for such Type of Loans and in a multiple of $100,000 in excess thereof and Swingline Loans shall be in a minimum amount of $100,000 and in a multiple of $10,000 in excess thereof (except that Mandatory Borrowings shall be made in the amounts required by Section 2.1(c) and Loans to reimburse the applicable Issuing Bank with respect to any Unpaid Drawing shall be made in the amounts required by Section 3.3 or Section 3.4, as applicable). More than one Borrowing may be incurred on any date; provided, that at no time shall there be outstanding more than ten Borrowings of Term Benchmark Loans or RFR Loans under this Agreement.

2.3Notice of Borrowing.

(a)Whenever the Borrower desires to incur Loans (other than Swingline Loans, Mandatory Borrowings or borrowings to repay Unpaid Drawings), the Borrower shall give the Administrative Agent at the Administrative Agent’s Office, (i) prior to 1:00 p.m. (New York City time) at least three (3) U.S. Government Securities Business Days’ prior written notice (or telephonic notice promptly confirmed in writing) of each Borrowing of Loans if such Loans are to be initially Term Benchmark Loans, (ii) prior to 1:00 p.m. (New York City time) at least five (5) U.S. Government Securities Business Days’ prior written notice in the case of a Borrowing of Loans if such Loans are to be initially RFR Loans and (iii) written notice (or telephonic notice promptly confirmed in writing) prior to 12:00 p.m. (New York City time) on the date of each Borrowing of Loans that are to be ABR Loans. Such notice (together with each notice of a Borrowing of Swingline Loans pursuant to

Section 2.3(b), a “Notice of Borrowing”) shall specify (A) the aggregate principal amount of the Loans to be made pursuant to such Borrowing, (B) the date of the Borrowing (which shall be a Business Day) and (C) whether the respective Borrowing shall consist of ABR Loans, Term Benchmark Loans, and/or RFR Loans (if no election as to the Type of Borrowing is specified, the Borrower shall be deemed to have requested an ABR Borrowing) and, if Term Benchmark Loans, the Interest Period to be initially applicable thereto (provided that if no Interest Period is selected, the Borrower shall be deemed to have selected an Interest Period of one month’s duration). The Administrative Agent shall promptly give each Lender written notice (or telephonic notice promptly confirmed in writing) of each proposed Borrowing of Loans, of such Lender’s Commitment Percentage thereof and of the other matters covered by the related Notice of Borrowing.

(b)Whenever the Borrower desires to incur Swingline Loans hereunder, it shall give the Administrative Agent written notice (or telephonic notice promptly confirmed in writing) of each Borrowing of Swingline Loans prior to 1:00 p.m. (New York City time) on the date of such Borrowing. Each such notice shall specify (i) the aggregate principal amount of the Swingline Loans to be made pursuant to such Borrowing and (ii) the date of Borrowing (which shall be a Business Day). The Administrative Agent shall promptly give the Swingline Lender written notice (or telephonic notice promptly confirmed in writing) of each proposed Borrowing of Swingline Loans and of the other matters covered by the related Notice of Borrowing.

(c)Mandatory Borrowings shall be made upon the notice specified in Section 2.1(c), with the Borrower irrevocably agreeing, by its incurrence of any Swingline Loan, to the making of Mandatory Borrowings as set forth in such Section.

(d)Borrowings to reimburse Unpaid Drawings shall be made upon the notice specified in Section 3.4(a).

(e)Without in any way limiting the obligation of the Borrower to confirm in writing any notice it may give hereunder by telephone, the Administrative Agent may act prior to receipt of written confirmation without liability upon the basis of such telephonic notice believed by the Administrative Agent in good faith to be from an Authorized Officer of the Borrower.

2.4Disbursement of Funds.

(a)No later than 2:00 p.m. (New York City time) on the date specified in each Notice of Borrowing (including Mandatory Borrowings), each Lender will make available its pro rata portion of each Borrowing requested to be made on such date in the manner provided below; provided that on the Closing Date, such funds shall be made available by 10:00 a.m. (New York City time) or such earlier time as may be agreed among the Lenders, the Borrower and the Administrative Agent for the purpose of consummating the Transactions; provided, further, that all Swingline Loans shall be made available in the full amount thereof by the Swingline Lender no later than 3:30 p.m. (New York City time) on the date requested.

(b)Each Lender shall make available all amounts it is to fund to the Borrower under any Borrowing in immediately available funds to the Administrative Agent at the Administrative Agent’s Office in Dollars, and the Administrative Agent will (except in the case of Mandatory Borrowings and Borrowings to repay Unpaid Drawings) make available to the Borrower, by depositing or wiring to an account as designated by the Borrower in the Borrowing Notice to the Administrative Agent the aggregate of the amounts so made available in Dollars. Unless the Administrative Agent shall have been notified by any Lender prior to the date of any such Borrowing (or, with respect to an ABR Loan, the date of such Borrowing prior to 1:00 p.m. (New York City time)) that such Lender does not intend to make available to the Administrative Agent its portion of the Borrowing or Borrowings to be made on such date, the Administrative Agent may assume that such Lender has made such

amount available to the Administrative Agent on such date of Borrowing, and the Administrative Agent, in reliance upon such assumption, may (in its sole discretion and without any obligation to do so) make available to the Borrower a corresponding amount. If such corresponding amount is not in fact made available to the Administrative Agent by such Lender and the Administrative Agent has made available such amount to the Borrower, the Administrative Agent shall be entitled to recover such corresponding amount from such Lender. If such Lender does not pay such corresponding amount forthwith upon the Administrative Agent’s demand therefor the Administrative Agent shall promptly notify the Borrower and the Borrower shall immediately pay such corresponding amount to the Administrative Agent in Dollars. The Administrative Agent shall also be entitled to recover from such Lender or the Borrower, as the case may be, interest on such corresponding amount in respect of each day from the date such corresponding amount was made available by the Administrative Agent to the Borrower to the date such corresponding amount is recovered by the Administrative Agent, at a rate per annum equal to (i) if paid by such Lender, the Overnight Rate or (ii) if paid by the Borrower, the then-applicable rate of interest or fees, calculated in accordance with Section 2.8, for the respective Loans.

(c)Nothing in this Section 2.4 shall be deemed to relieve any Lender from its obligation to fulfill its commitments hereunder or to prejudice any rights that the Borrower may have against any Lender as a result of any default by such Lender hereunder (it being understood, however, that no Lender shall be responsible for the failure of any other Lender to fulfill its commitments hereunder).

2.5Repayment of Loans; Evidence of Debt.

(a)The Borrower hereby promises to pay to the Administrative Agent, for the benefit of the applicable Lenders, (i) on the Maturity Date, the then outstanding Loans, (ii) [intentionally omitted] and (iii) on the Swingline Maturity Date, the then outstanding Swingline Loans.

(b)Each Lender shall maintain in accordance with its usual practice an account or accounts evidencing the indebtedness of the Borrower to the appropriate lending office of such Lender resulting from each Loan made by such lending office from time to time, including the amounts of principal and interest payable and paid to such lending office from time to time under this Agreement.

(c)The Administrative Agent, on behalf of the Borrower, shall maintain the Register pursuant to Section 13.6(b), and a subaccount for each Lender, in which Register and subaccounts (taken together) shall be recorded (i) the amount of each Loan made hereunder (whether such Loan is a Swingline Loan), the Type of each Loan made and the Interest Period applicable thereto, (ii) the amount of any principal or interest due and payable or to become due and payable from the Borrower to each Lender or the Swingline Lender hereunder and (iii) the amount of any sum received by the Administrative Agent hereunder from the Borrower and each Lender’s share thereof.

(d)The entries made in the Register and accounts and subaccounts maintained pursuant to clauses (b) and (c) of this Section 2.5 shall, to the extent permitted by applicable Requirements of Law, be prima facie evidence of the existence and amounts of the obligations of the Borrower therein recorded; provided, however, that the failure of any Lender or the Administrative Agent to maintain such account, such Register or such subaccount, as applicable, or any error therein, shall not in any manner affect the obligation of the Borrower to repay (with applicable interest) the Loans made to the Borrower by such Lender in accordance with the terms of this Agreement.

(e)Any Lender may request that Loans made by it be evidenced by a promissory note substantially in the form of Exhibit H-1 hereto. In such event, the Borrower shall execute and deliver to such Lender a promissory note payable to such Lender (or, if requested by such Lender, to such Lender and its

registered assigns). Thereafter, the Loans evidenced by such promissory note and interest thereon shall at all times (including after assignment pursuant to Section 13.6) be represented by one or more promissory notes in such form payable to the payee named therein (or, if such promissory note is a registered note, to such payee and its registered assigns).

2.6Conversions and Continuations.

(a)Subject to the penultimate sentence of this clause (a), (i) the Borrower shall have the option on any Business Day to convert all or a portion equal to at least the Minimum Borrowing Amount (and in multiples of $100,000 in excess thereof) of the outstanding principal amount of Loans of one Type into a Borrowing or Borrowings of another Type and (ii) the Borrower shall have the option on any Business Day to continue the outstanding principal amount of any Term Benchmark Loans as Term Benchmark Loans for an additional Interest Period; provided that (A) no partial conversion of Term Benchmark Loans shall reduce the outstanding principal amount of Term Benchmark Loans made pursuant to a single Borrowing to less than the Minimum Borrowing Amount, (B) ABR Loans may not be converted into Term Benchmark Loans if an Event of Default is in existence on the date of the conversion and the Administrative Agent has or the Majority Lenders have determined in its or their sole discretion not to permit such conversion, (C) Term Benchmark Loans may not be continued as Term Benchmark Loans for an additional Interest Period if an Event of Default is in existence on the date of the proposed continuation and the Administrative Agent has or the Majority Lenders have determined in its or their sole discretion not to permit such continuation, (D) RFR Loans may not be continued as RFR Loans if an Event of Default is in existence on the Interest Payment Date applicable to such RFR Loan and the Administrative Agent has or the Majority Lenders have determined in its or their sole discretion not to permit such continuation and (E) Borrowings resulting from conversions pursuant to this Section 2.6 shall be limited in number as provided in Section 2.2. Each such conversion or continuation shall be effected by the Borrower by giving the Administrative Agent at the Administrative Agent’s Office prior to 1:00 p.m. (New York City time) (1) at least three Business Days’, in the case of a continuation of or conversion to Term Benchmark Loans, (2) at least five Business Days’ in the case of a continuation of or conversion to RFR Loans, or (3) on the date of conversion, in the case of a conversion into ABR Loans, prior written notice (or telephonic notice promptly confirmed in writing) substantially in the form attached hereto as Exhibit L (each, a “Notice of Conversion or Continuation”) specifying the Loans to be so converted or continued, the Type of Loans to be converted into or continued and, if such Loans are to be converted into or continued as Term Benchmark Loans or an RFR Borrowing, the Interest Period to be initially applicable thereto (if no Interest Period is selected, the Borrower shall be deemed to have selected an Interest Period of one month’s duration). The Administrative Agent shall give each applicable Lender notice as promptly as practicable of any such proposed conversion or continuation affecting any of its Loans.

(b)If upon the expiration of any Interest Period in respect of Term Benchmark Loans, the Borrower has failed to elect a new Interest Period to be applicable thereto as provided in clause (a) of this Section 2.6 above, the Borrower shall be deemed to have elected an Interest Period of one month, effective as of the expiration date of such current Interest Period. Notwithstanding any contrary provision hereof, if any Event of Default is in existence at the time of any proposed continuation of any Term Benchmark Loans or RFR Loans and the Administrative Agent has or the Majority Lenders have determined in its or their sole discretion not to permit such continuation, such Term Benchmark Loans shall be automatically converted on the last day of the current Interest Period and RFR Loans shall be automatically converted on the applicable Interest Payment Date, in either case, so long as the Event of Default is continuing on such date, into ABR Loans.

2.7Pro Rata Borrowings. Each Borrowing of Loans under this Agreement shall be made by the Lenders pro rata on the basis of their then applicable Commitment Percentages. It is understood that (a) no Lender shall be responsible for any default by any other Lender in its obligation to make Loans hereunder and that each

Lender severally but not jointly shall be obligated to make the Loans provided to be made by it hereunder, regardless of the failure of any other Lender to fulfill its commitments hereunder and (b) failure by a Lender to perform any of its obligations under any of the Credit Documents shall not release any Person from performance of its obligation under any Credit Document.

2.8Interest.

(a)The unpaid principal amount of each ABR Loan shall bear interest from the date of the Borrowing thereof until maturity (whether by acceleration or otherwise) at a rate per annum that shall at all times be the Applicable Margin plus the Alternate Base Rate, in each case, in effect from time to time.

(b)The unpaid principal amount of each Term Benchmark Loan shall bear interest from the date of the Borrowing thereof until maturity thereof (whether by acceleration or otherwise) at a rate per annum that shall at all times be the Applicable Margin plus the Adjusted Term SOFR Rate, in each case, in effect from time to time.

(c)The unpaid principal amount of each RFR Loan shall bear interest from the date of the Borrowing thereof until maturity (whether by acceleration or otherwise) at a rate per annum that shall at all times be the Applicable Margin plus the Adjusted Daily Simple SOFR rate, in each case, in effect from time to time.

(d)If all or a portion of (i) the principal amount of any Loan or (ii) any interest payable thereon shall not be paid when due (whether at stated maturity, by acceleration including as a result of the occurrence of an Event of Default of the type specified in Section 11.5, or otherwise), such overdue amount shall bear interest at a rate per annum that is (the “Default Rate”) (A) in the case of overdue principal, the rate that would otherwise be applicable thereto plus 2% or (B) in the case of any overdue interest, to the extent permitted by applicable Requirements of Law, the rate described in Section 2.8(a)plus 2% from the date of such non-payment to the date on which such amount is paid in full (after as well as before judgment).

(e)Interest on each Loan shall accrue from and including the date of any Borrowing to but excluding the date of any repayment thereof and shall be payable in Dollars; provided that any Loan that is repaid on the same date on which it is made shall bear interest for one day. Except as provided below, interest on each Loan shall be payable in arrears on each Interest Payment Date, on the date of any prepayment (on the amount prepaid), and after maturity, on demand.

(f)All computations of interest hereunder shall be made in accordance with Section 5.5.

(g)The Administrative Agent, upon determining the interest rate for any Borrowing of Term Benchmark Loans, shall promptly notify the Borrower and the relevant Lenders thereof. Each such determination shall, absent clearly demonstrable error, be final and conclusive and binding on all parties hereto.

2.9Interest Periods. At the time the Borrower gives a Notice of Borrowing or Notice of Conversion or Continuation in respect of the making of, or conversion into or continuation as, a Borrowing of Term Benchmark Loans in accordance with Section 2.6(a), the Borrower shall give the Administrative Agent written notice (or telephonic notice promptly confirmed in writing) of the Interest Period applicable to such Borrowing, which Interest Period shall, at the option of the Borrower be (i) a one-, three- or six-month period requested by the Borrower.

Notwithstanding anything to the contrary contained above:

(a)the initial Interest Period for any Borrowing of Term Benchmark Loans shall commence on the date of such Borrowing (including the date of any conversion from a Borrowing of ABR Loans) and each Interest Period occurring thereafter in respect of such Borrowing shall commence on the day on which the next preceding Interest Period expires;

(b)if any Interest Period relating to a Borrowing of Term Benchmark Loans begins on the last Business Day of a calendar month or begins on a day for which there is no numerically corresponding day in the calendar month at the end of such Interest Period, such Interest Period shall end on the last Business Day of the calendar month at the end of such Interest Period;

(c)if any Interest Period would otherwise expire on a day that is not a Business Day, such Interest Period shall expire on the next succeeding Business Day; provided that, if any Interest Period in respect of a Term Benchmark Loan would otherwise expire on a day that is not a Business Day, but is a day of the month after which no further Business Day occurs in such month, such Interest Period shall expire on the next preceding Business Day; and

(d)the Borrower shall not be entitled to elect any Interest Period in respect of any Term Benchmark Loan if such Interest Period would extend beyond the Maturity Date.

2.10Increased Costs.

(a)If any Change in Law shall:

(i)impose, modify or deem applicable any reserve, special deposit, liquidity or similar requirement (including any compulsory loan requirement, insurance charge or other assessment) against assets of, deposits with or for the account of, or credit extended by, any Lender or Issuing Bank;

(ii)impose on any Lender or Issuing Bank or the applicable offshore interbank market any other condition, cost or expense (other than Taxes) affecting this Agreement or Loans made by such Lender or any Letter of Credit or participation therein; or

(iii)subject any Recipient to any Taxes (other than (A) Indemnified Taxes, (B) Taxes described in clause (ii) of the definition of Excluded Taxes and (C) Connection Income Taxes) on its loans, loan principal, letters of credit, commitments, or other obligations, or its deposits, reserves, other liabilities or capital attributable thereto;

and the result of any of the foregoing shall be to increase the cost to such Lender or such other Recipient of making, continuing, converting or maintaining any Loan (or of maintaining its obligation to make any such Loan) or to increase the cost to such Lender, such Issuing Bank or such other Recipient of participating in, issuing or maintaining any Letter of Credit or to reduce the amount of any sum received or receivable by such Lender, such Issuing Bank or such other Recipient hereunder (whether of principal, interest or otherwise), then the Borrower will pay to such Lender, such Issuing Bank or such other Recipient, as the case may be, such additional amount or amounts as will compensate such Lender, such Issuing Bank or such other Recipient, as the case may be, for such additional costs incurred or reduction suffered.

(b)If any Lender or Issuing Bank determines that any Change in Law regarding capital or liquidity requirements has or would have the effect of reducing the rate of return on such Lender’s or the Issuing Bank’s capital or on the capital of such Lender’s or Issuing Bank’s holding company, if any, as a consequence of

this Agreement or the Loans made by, or participations in Letters of Credit held by, such Lender, or the Letters of Credit issued by such Issuing Bank, to a level below that which such Lender or Issuing Bank or such Lender’s or Issuing Bank’s holding company could have achieved but for such Change in Law (taking into consideration such Lender’s or Issuing Bank’s policies and the policies of such Lender’s or Issuing Bank’s holding company with respect to capital adequacy and liquidity), then from time to time the Borrower will pay to such Lender or Issuing Bank, as the case may be, such additional amount or amounts as will compensate such Lender or Issuing Bank or such Lender’s or Issuing Bank’s holding company for any such reduction suffered.

(c)A certificate of a Lender or Issuing Bank setting forth the amount or amounts necessary to compensate such Lender or Issuing Bank or its holding company, as the case may be, as specified in paragraph (a) or (b) of this Section shall be delivered to the Borrower and shall be conclusive absent manifest error. The Borrower shall pay such Lender or Issuing Bank, as the case may be, the amount shown as due on any such certificate within 10 days after receipt thereof.

(d)Failure or delay on the part of any Lender or Issuing Bank to demand compensation pursuant to this Section shall not constitute a waiver of such Lender’s or Issuing Bank’s right to demand such compensation; provided that the Borrower shall not be required to compensate a Lender or Issuing Bank pursuant to this Section for any increased costs or reductions incurred more than 270 days prior to the date that such Lender or Issuing Bank, as the case may be, notifies the Borrower of the Change in Law giving rise to such increased costs or reductions and of such Lender’s or Issuing Bank’s intention to claim compensation therefor; provided further that, if the Change in Law giving rise to such increased costs or reductions is retroactive, then the 270-day period referred to above shall be extended to include the period of retroactive effect thereof.

2.11Compensation.

(a)With respect to Loans that are not RFR Loans, if (i) any payment of principal of any Term Benchmark Loan is made by the Borrower to or for the account of a Lender other than on the last day of the Interest Period for such Term Benchmark Loan as a result of a payment or conversion pursuant to Section 2.5, 2.6, 2.10, 2.18, 5.1, 5.2 or 13.7, as a result of acceleration of the maturity of the Loans pursuant to Section 11 or for any other reason, (ii) any Borrowing of Term Benchmark Loans is not made on the date specified in a Notice of Borrowing, (iii) any ABR Loan is not converted into a Term Benchmark Loan on the date specified in a Notice of Conversion or Continuation, (iv) any Term Benchmark Loan is not continued as a Term Benchmark Loan on the date specified in a Notice of Conversion or Continuation, or (v) any prepayment of principal of any Term Benchmark Loan is not made as a result of a withdrawn notice of prepayment pursuant to Section 5.1 or 5.2, the Borrower shall after the Borrower’s receipt of a written request by such Lender (which request shall set forth in reasonable detail the basis for requesting such amount), pay to the Administrative Agent (within fifteen days after such request) for the account of such Lender any amounts required to compensate such Lender for any additional losses, costs or expenses that such Lender may reasonably incur as a result of such payment, failure to convert, failure to continue or failure to prepay, including any loss, cost or expense (excluding loss of anticipated profits) actually incurred by reason of the liquidation or reemployment of deposits or other funds acquired by any Lender to fund or maintain such Term Benchmark Loan.

(b)With respect to RFR Loans, in the event of (i) the payment of any principal of any RFR Loan other than on the Interest Payment Date applicable thereto (including as a result of an Event of Default or an optional or mandatory prepayment of Loans), (ii) the failure to borrow or prepay any RFR Loan on the date specified in any notice delivered pursuant hereto (regardless of whether such notice may be revoked hereunder and is revoked in accordance herewith) or (iii) the assignment of any RFR Loan other than on the Interest Payment Date applicable thereto as a result of a request by the Borrower, then, in any such event, the Borrower shall

compensate each Lender for the loss, cost and expense attributable to such event. A certificate of any Lender setting forth any amount or amounts that such Lender is entitled to receive pursuant to this Section shall be delivered to the Borrower and shall be conclusive absent manifest error. The Borrower shall pay such Lender the amount shown as due on any such certificate within ten (10) days after receipt thereof.

2.12Change of Lending Office. Each Lender agrees that, upon the occurrence of any event giving rise to the operation of Section 2.10, 3.5 or 5.4 with respect to such Lender, it will, if requested by the Borrower use reasonable efforts (subject to overall policy considerations of such Lender) to designate another lending office for any Loans affected by such event; provided that such designation does not cause such Lender or its lending office to suffer any economic, legal or regulatory disadvantage, with the object of avoiding the consequence of the event giving rise to the operation of any such Section. Nothing in this Section 2.12 shall affect or postpone any of the obligations of the Borrower or the right of any Lender provided in Section 2.10, 3.5 or 5.4.

2.13Notice of Certain Costs. Notwithstanding anything in this Agreement to the contrary, to the extent any notice required by Section 2.10, 2.11, 3.5 or 5.4 is given by any Lender more than 180 days after such Lender has knowledge (or should have had knowledge) of the occurrence of the event giving rise to the additional cost, reduction in amounts, loss, tax or other additional amounts described in such Sections, such Lender shall not be entitled to compensation under Section 2.10, 2.11, 3.5 or 5.4, as the case may be, for any such amounts incurred or accruing prior to the 181st day prior to the giving of such notice to the Borrower; provided that if the circumstance giving rise to such claim is retroactive, then such 180-day period referred to above shall be extended to include the period of retroactive effect thereof.

2.14Borrowing Base.

(a)Initial Borrowing Base. For the period from and including the Ninth Amendment Implementation Date to but excluding the first Redetermination Date thereafter, the amount of the Borrowing Base shall be $1,500,000,000. Notwithstanding the foregoing, the Borrowing Base amount may be subject to further adjustments from time to time pursuant to the Borrowing Base Adjustment Provisions.

(b)Scheduled and Interim Redeterminations. The Borrowing Base shall be redetermined semi-annually in accordance with this Section 2.14 (a “Scheduled Redetermination”), and, subject to Section 2.14(d), such redetermined Borrowing Base shall become effective and applicable to the Borrower, the Administrative Agent, the Issuing Banks and the Lenders on or about June 1, 2018 and on or about each April 30th and October 31st of each year thereafter (or, in each case, as promptly as possible thereafter). In addition, at any time after the first Scheduled Redetermination date of June 1, 2018, each of the Borrower, by notifying the Administrative Agent thereof not more than one time between any two Scheduled Redeterminations, and the Administrative Agent, at its discretion or at the direction of the Required Lenders, by notifying the Borrower thereof, not more than one time between any two consecutive Scheduled Redeterminations, in each case, may elect to cause the Borrowing Base to be redetermined between Scheduled Redeterminations (an “Interim Redetermination”) in accordance with this Section 2.14; provided that the Required Lenders may also direct the Administrative Agent to initiate an Interim Redetermination in the event that the Hedging Condition is not satisfied (in which case, such Interim Redetermination shall not count as the one Interim Redetermination otherwise permitted to be initiated pursuant to this Section 2.14(b) by the Administrative Agent or the Required Lenders). In addition to, and not including and/or limited by the annual Interim Redeterminations allowed above, the Borrower may, by notifying the Administrative Agent thereof, at any time between Scheduled Redeterminations, request additional Interim Redeterminations of the Borrowing Base in the event it acquires Oil and Gas Properties with Proved Reserves that are to be Borrowing Base Properties having a PV-10 (calculated at the time of acquisition) in excess of 10% of the Borrowing Base in effect immediately prior to such acquisition.

(c)Scheduled and Interim Redetermination Procedure.

(i)Each Scheduled Redetermination and each Interim Redetermination shall be effectuated as follows: Upon receipt by the Administrative Agent of (A) the Reserve Report and the Reserve Report Certificate, and (B) such other reports, data and supplemental information, including the information provided pursuant to Section 9.14(c), as may, from time to time, be reasonably requested by the Required Lenders (the Reserve Report, such Reserve Report Certificate and such other reports, data and supplemental information being the “Engineering Reports”), the Administrative Agent shall evaluate the information contained in the Engineering Reports and shall in good faith propose a new Borrowing Base (the “Proposed Borrowing Base”) based upon such information and such other information (including the status of title information with respect to the Borrowing Base Properties as described in the Engineering Reports and the existence of any Hedge Transactions or any other Indebtedness) as the Administrative Agent deems appropriate in good faith in accordance with its usual and customary oil and gas lending criteria as they exist at the particular time (as determined by the Administrative Agent in its sole discretion).

(ii)The Administrative Agent shall notify the Borrower and the Lenders of the Proposed Borrowing Base (the “Proposed Borrowing Base Notice”):

(A)in the case of a Scheduled Redetermination, (1) if the Administrative Agent shall have received the Engineering Reports required to be delivered by the Borrower pursuant to Sections 9.14(a) and (c) in a timely manner, then on or before May 15, 2018 in the case of the first Scheduled Redetermination, and each April 15th and October 15th (commencing October 15, 2018) of such year following the date of delivery or (2) if the Administrative Agent shall not have received the Engineering Reports required to be delivered by the Borrower pursuant to Sections 9.14(a) and (c) in a timely manner, then promptly after the Administrative Agent has received complete Engineering Reports from the Borrower and has had a reasonable opportunity to determine the Proposed Borrowing Base in accordance with Section 2.14(c)(i); and

(B)in the case of an Interim Redetermination, promptly, and in any event, within 15 days after the Administrative Agent has received the required Engineering Reports.

(iii)Any Proposed Borrowing Base that would increase the Borrowing Base then in effect must be approved or deemed to have been approved by the Borrowing Base Required Lenders in good faith in accordance with their respective usual and customary oil and gas lending criteria as they exist at the particular time as provided in this Section 2.14(c)(iii) and any Proposed Borrowing Base that would decrease or maintain the Borrowing Base then in effect must be approved or be deemed to have been approved by Lenders constituting at least the Required Lenders in good faith in accordance with their respective usual and customary oil and gas lending criteria as they exist at the particular time as provided in this Section 2.14(c)(iii). Upon receipt of the Proposed Borrowing Base Notice, each Lender shall have 15 days to agree with the Proposed Borrowing Base or disagree with the Proposed Borrowing Base by proposing an alternate Borrowing Base. If at the end of such 15-day period, any Lender has not communicated its approval or disapproval in writing to the Administrative Agent, such silence shall be deemed to be an approval of the Proposed Borrowing Base. If, at the end of such 15-day period, the Borrowing

Base Required Lenders, in the case of a Proposed Borrowing Base that would increase the Borrowing Base then in effect, or the Required Lenders, in the case of a Proposed Borrowing Base that would decrease or maintain the Borrowing Base then in effect, have approved or deemed to have approved, as aforesaid, then the Proposed Borrowing Base shall become the new Borrowing Base, effective on the date specified in Section 2.14(d). If, however, at the end of such 15-day period, the Borrowing Base Required Lenders or the Required Lenders, as applicable, have not approved or deemed to have approved, as aforesaid, then the Administrative Agent shall promptly thereafter poll the Lenders to ascertain the highest Borrowing Base then acceptable to the Borrowing Base Required Lenders (in the case of any increase to the Borrowing Base) or a number of Lenders sufficient to constitute the Required Lenders (in any other case) and such amount shall become the new Borrowing Base, effective on the date specified in Section 2.14(d). It is expressly understood that the Administrative Agent and Lenders have no obligation to designate the Borrowing Base at any particular amount, except in the exercise of their discretion, whether in relation to the Total Commitment, or otherwise, and no Lender shall be required to increase its Commitment amount under this Agreement in connection with an increase in the Borrowing Base.

(d)Effectiveness of a Redetermined Borrowing Base. Subject to Section 2.14(h), after a redetermined Borrowing Base is approved or is deemed to have been approved by the Borrowing Base Required Lenders or the Required Lenders, as applicable, pursuant to Section 2.14(c)(iii), the Administrative Agent shall promptly thereafter notify the Borrower and the Lenders of the amount of the redetermined Borrowing Base (the “New Borrowing Base Notice”), and such amount shall become the new Borrowing Base, effective and applicable to the Borrower, the Administrative Agent, the Issuing Banks and the Lenders:

(i)in the case of a Scheduled Redetermination, on June 1, 2018, with respect to the first Scheduled Redetermination, and thereafter (A) if the Administrative Agent shall have received the Engineering Reports required to be delivered by the Borrower pursuant to Sections 9.14(a) and (c) in a timely and complete manner, or on the April 30th or October 31st, as applicable, following such notice, or (B) if the Administrative Agent shall not have received the Engineering Reports required to be delivered by the Borrower pursuant to Sections 9.14(a) and (c) in a timely and complete manner, then on the Business Day next succeeding delivery of such New Borrowing Base Notice; and

(ii)in the case of an Interim Redetermination, on the Business Day next succeeding delivery of such New Borrowing Base Notice.

Subject to Section 2.14(h), such amount shall then become the Borrowing Base until the next Scheduled Redetermination Date, the next Interim Redetermination Date or the next adjustment to the Borrowing Base pursuant to the Borrowing Base Adjustment Provisions, whichever occurs first. Notwithstanding the foregoing, no Scheduled Redetermination or Interim Redetermination shall become effective until the New Borrowing Base Notice related thereto is received by the Borrower.

(e)Reduction of Borrowing Base Upon Incurrence of Permitted Additional Debt. Upon the issuance or incurrence of any Permitted Incremental Junior Lien Debt or any Permitted Additional Debt (other than (x) any Permitted Incremental Junior Lien Debt or Permitted Additional Debt, in either case, incurred by the Borrower the proceeds of which are used by the Borrower to consummate the QuarterNorth Acquisition and to pay any fees, underwriting discounts, premiums and other costs and expenses incurred in connection with the foregoing, and (y) Indebtedness constituting Permitted Refinancing Indebtedness incurred to Refinance such Indebtedness or previously incurred Permitted Incremental Junior Lien Debt or previously incurred Permitted

Additional Debt, but only to the extent that the aggregate principal amount of Permitted Refinancing Indebtedness incurred to Refinance such Indebtedness does not result in an increase in the principal amount thereof above the principal amount originally incurred or issued up to the original principal amount of the Refinanced Indebtedness), the Borrowing Base then in effect shall be reduced by an amount equal to the product of 0.25 multiplied by the stated principal amount of such Indebtedness (without regard to any original issue discount plus an amount equal to the unpaid accrued interest and premium thereon plus other amounts paid and fees and expenses incurred in connection with such Refinancing plus an amount equal to any existing commitment unutilized and letters of credit undrawn thereunder), and the Borrowing Base as so reduced shall become the new Borrowing Base immediately upon the date of such issuance or incurrence, effective and applicable to the Borrower, the Administrative Agent, the Issuing Banks and the Lenders on such date until the next redetermination or modification thereof hereunder.

(f)Reduction of Borrowing Base Upon Termination of Hedge Positions. If the Borrower or any Restricted Subsidiary shall terminate or create any off-setting positions in respect of any commodity hedge positions (whether evidenced by a floor, put or Hedge Transaction) upon which (i) the Lenders relied in determining the Borrowing Base and (ii) the Borrowing Base Value of such terminated and/or offsetting positions (after taking into account any other Hedge Transaction, entered into prior to or contemporaneously with the taking of such actions) exceeds 5% of the then-effective Borrowing Base (or, when aggregated with Dispositions of Oil and Gas Properties or Equity Interests in any Restricted Subsidiary or Minority Investment owning Oil and Gas Properties, 7.5% of the then-effective Borrowing Base), then, the Required Lenders shall have the right to adjust the Borrowing Base in an amount equal to the Borrowing Base Value, if any, attributable to such terminated or off-setting hedge positions in the calculation of the then-effective Borrowing Base and (if the Required Lenders in fact make any such adjustment) the Administrative Agent shall promptly notify the Borrower in writing of the Borrowing Base Value, if any, attributable to such hedge positions in the calculation of the then-effective Borrowing Base and upon receipt of such notice, the Borrowing Base shall be simultaneously reduced by such amount.

(g)Reduction of Borrowing Base Upon Asset Dispositions. If (i) the Borrower or any of the other Credit Parties Disposes of Oil and Gas Properties or Disposes of any Equity Interests in any Restricted Subsidiary or Minority Investment owning Oil and Gas Properties and none of the foregoing Dispositions is a Scheduled Disposition, (ii) such Disposition described in clause (i) involves Borrowing Base Properties included in the most recently delivered Reserve Report and (iii) the aggregate Borrowing Base Value of all such Borrowing Base Properties Disposed of (except in connection with a Scheduled Disposition) since the later of (A) the last Scheduled Redetermination Date and (B) the last adjustment of the Borrowing Base made pursuant to this Section 2.14(g) exceeds 500 of the then-effective Borrowing Base (or, when aggregated with all terminations or creations of any off-setting positions in respect of any commodity hedge positions, 7.500 of the then-effective Borrowing Base), then, no later than two Business Days’ after the Administrative Agent has received the notice of the consummation of any such Disposition required to be delivered by the Borrower pursuant to Section 10.4(b), the Required Lenders shall have the right to adjust the Borrowing Base in an amount equal to the Borrowing Base Value, if any, attributable to such Disposed of Borrowing Base Properties in the calculation of the then-effective Borrowing Base and, if the Required Lenders in fact make any such adjustment, the Administrative Agent shall promptly notify the Borrower in writing of the Borrowing Base Value, if any, attributable to such Disposed of Borrowing Base Properties in the calculation of the then-effective Borrowing Base and upon receipt of such notice, the Borrowing Base shall be simultaneously reduced by such amount.

(h)Borrower’s Right to Elect Reduced Borrowing Base. Within three Business Days of its receipt of a New Borrowing Base Notice, the Borrower may provide written notice to the Administrative Agent and the Lenders that specifies for the period from the effective date of the New Borrowing Base Notice until the

next succeeding Scheduled Redetermination Date, the Borrowing Base will be a lesser amount than the amount set forth in such New Borrowing Base Notice, whereupon such specified lesser amount will become the new Borrowing Base. The Borrower’s notice under this Section 2.14(h) shall be irrevocable, but without prejudice to its rights to initiate Interim Redeterminations.

(i)Administrative Agent Data. The Administrative Agent hereby agrees to provide, promptly, and in any event within three Business Days, following its receipt of a request by the Borrower, an updated Bank Price Deck. In addition, the Administrative Agent and the Lenders agree, upon request, to meet with the Borrower to discuss their evaluation of the reservoir engineering of the Oil and Gas Properties included in the Reserve Report and their respective methodologies for valuing such properties and the other factors considered in calculating the Borrowing Base.

2.15Defaulting Lenders. Notwithstanding any provision of this Agreement to the contrary, if any Lender becomes a Defaulting Lender, then the following provisions shall apply for so long as such Lender is a Defaulting Lender:

(a)Commitment Fees shall cease to accrue on the unfunded portion of the Commitment of such Defaulting Lender pursuant to Section 4.1(a);

(b)The Commitment and Total Exposure of such Defaulting Lender shall not be included in determining whether all Lenders, the Majority Lenders or the Required Lenders or Borrowing Base Required Lenders have taken or may take any action hereunder (including any consent to any amendment or waiver pursuant to Section 13.1); provided that (i) any waiver, amendment or modification requiring the consent of all Lenders pursuant to Section 13.1 (other than Section 13.1(J)) or requiring the consent of each affected Lender pursuant to Section 13.1(A) or (I) shall require the consent of such Defaulting Lender (which for the avoidance of doubt would include any change to the Maturity Date applicable to such Defaulting Lender, decreasing or forgiving any principal or interest due to such Defaulting Lender, any decrease of any interest rate applicable to Loans made by such Defaulting Lender (other than the waiving of post-default interest rates) and any increase in such Defaulting Lender’s Commitment) and (ii) any redetermination, whether an increase, decrease or affirmation, of the Borrowing Base shall occur without the participation of a Defaulting Lender, but the Commitment (i.e., the Commitment Percentage of the Borrowing Base) of a Defaulting Lender may not be increased without the consent of such Defaulting Lender;

(c)If any Swingline Exposure or Letter of Credit Exposure exists at the time a Lender becomes a Defaulting Lender, then all or any part of such Swingline Exposure and Letter of Credit Exposure of such Defaulting Lender will, subject to the limitation in the first proviso below, automatically be reallocated (effective on the day such Lender becomes a Defaulting Lender) among the Non-Defaulting Lenders pro rata in accordance with their respective Commitment Percentages; provided that (i) each Non-Defaulting Lender’s Total Exposure may not in any event exceed the Commitment Percentage of the Loan Limit of such Non-Defaulting Lender as in effect at the time of such reallocation and (ii) neither such reallocation nor any payment by a Non-Defaulting Lender pursuant thereto will constitute a waiver or release of any claim the Borrower, the Administrative Agent, the Issuing Banks or any other Lender may have against such Defaulting Lender or cause such Defaulting Lender to be a Non-Defaulting Lender, to the extent that all or any portion (the “unreallocated portion”) of the Defaulting Lender’s Swingline Exposure or Letter of Credit Exposure cannot, or can only partially, be so reallocated to Non-Defaulting Lenders, whether by reason of the first proviso in Section 2.15(c)(i) or otherwise, the Borrower shall within two Business Days following notice by the Administrative Agent (x) first, prepay such Swingline Exposure and (y) second, Cash Collateralize for the benefit of the applicable Issuing Bank only the Borrower’s obligations corresponding to such Defaulting Lender’s Letter of Credit Exposure (after giving effect to any partial reallocation

pursuant to clause (i) above), in accordance with the procedures set forth in Section 3.8 for so long as such Letter of Credit Exposure is outstanding, if the Borrower Cash Collateralizes any portion of such Defaulting Lender’s Letter of Credit Exposure pursuant to this Section 2.15(c), the Borrower shall not be required to pay any fees to such Defaulting Lender pursuant to Section 4.1(b) with respect to such Defaulting Lender’s Letter of Credit Exposure during the period such Defaulting Lender’s Letter of Credit Exposure is Cash Collateralized, if the Letter of Credit Exposure of the Non-Defaulting Lenders is reallocated pursuant to this Section 2.15(c), then the Letter of Credit Fees payable for the account of the Lenders pursuant to Section 4.1(b) shall be adjusted in accordance with such Non-Defaulting Lenders’ Commitment Percentages and the Borrower shall not be required to pay any Swingline Loan fees (if any) or Letter of Credit Fees to the Defaulting Lender pursuant to Section 4.1(b) with respect to such Defaulting Lender’s Letter of Credit Exposure during the period that such Defaulting Lender’s Letter of Credit Exposure is reallocated, or if any Defaulting Lender’s Letter of Credit Exposure is neither Cash Collateralized nor reallocated pursuant to this Section 2.15(c), then, without prejudice to any rights or remedies of any Issuing Bank or any Lender hereunder, all Letter of Credit Fees payable under Section 4.1(b) with respect to such Defaulting Lender’s Letter of Credit Exposure shall be payable to such Issuing Bank until such Letter of Credit Exposure is Cash Collateralized and/or reallocated;

(d)So long as any Lender is a Defaulting Lender, the Swingline Lender shall not be required to fund any Swingline Loan and no Issuing Bank will be required to issue any new Letter of Credit or amend any outstanding Letter of Credit to increase the Stated Amount thereof, alter the drawing terms thereunder or extend the expiry date thereof, unless each Issuing Bank is reasonably satisfied that any exposure that would result from the exposure to such Defaulting Lender is eliminated or fully covered by the Commitments of the Non-Defaulting Lenders or by Cash Collateralization or a combination thereof in accordance with clause (c) above or otherwise in a manner reasonably satisfactory to such Issuing Bank, and participating interests in any such newly issued or increased Letter of Credit or newly made Swingline Loan shall be allocated among Non-Defaulting Lenders in a manner consistent with Section 2.15(c)(i) (and Defaulting Lenders shall not participate therein); and

(e)If the Borrower, the Administrative Agent, the Swingline Lender and each Issuing Bank agree in writing in their discretion that a Lender that is a Defaulting Lender should no longer be deemed to be a Defaulting Lender, the Administrative Agent will so notify the parties hereto, whereupon, as of the effective date specified in such notice and subject to any conditions set forth therein, such Lender will cease to be a Defaulting Lender and will be a Non-Defaulting Lender and any applicable Cash Collateral shall be promptly returned to the Borrower and any Letter of Credit Exposure of such Lender reallocated pursuant to Section 2.15(c) shall be reallocated back to such Lender; provided that, except to the extent otherwise expressly agreed by the affected parties, no change hereunder from Defaulting Lender to Non-Defaulting Lender will constitute a waiver or release of any claim of any party hereunder arising from such Lender’s having been a Defaulting Lender.

(f)Any payment of principal, interest, fees or other amounts received by the Administrative Agent for the account of that Defaulting Lender (whether voluntary or mandatory, at maturity, pursuant to Section 11 or otherwise, and including any amounts made available to the Administrative Agent by that Defaulting Lender pursuant to Section 13.8), shall be applied at such time or times as may be determined by the Administrative Agent as follows: first, to the payment of any amounts owing by that Defaulting Lender to the Administrative Agent hereunder; second, to the payment on a pro rata basis of any amounts owing by that Defaulting Lender to each Issuing Bank and the Swingline Lender hereunder; third, as the Borrower may request (so long as no Default or Event of Default exists), to the funding of any Loan in respect of which that Defaulting Lender has failed to fund its portion thereof as required by this Agreement, as determined by the Administrative Agent; fourth, if so determined by the Administrative Agent and the Borrower, to be held in a non-interest bearing deposit account and released in order to satisfy obligations of that Defaulting Lender to fund Loans under this Agreement; fifth, to the payment of any amounts owing to the Lenders, each Issuing Bank or the Swingline Lender as a result of

any judgment of a court of competent jurisdiction obtained by any Lender, such Issuing Bank or the Swingline Lender against that Defaulting Lender as a result of that Defaulting Lender’s breach of its obligations under this Agreement; sixth, so long as no Default or Event of Default exists, to the payment of any amounts owing to the Borrower as a result of any judgment of a court of competent jurisdiction obtained by the Borrower against that Defaulting Lender as a result of that Defaulting Lender’s breach of its obligations under this Agreement; and seventh, to that Defaulting Lender or as otherwise directed by a court of competent jurisdiction; provided that if such payment is a payment of the principal amount of any Loans or Unpaid Drawings, such payment shall be applied solely to pay the relevant Loans of, and Unpaid Drawings owed to, the relevant non-Defaulting Lenders on a pro rata basis prior to being applied in the manner set forth in this Section 2.15(f). Any payments, prepayments or other amounts paid or payable to a Defaulting Lender that are applied (or held) to pay amounts owed by a Defaulting Lender or to post Cash Collateral pursuant to Section 3.8 shall be deemed paid to and redirected by that Defaulting Lender, and each Lender irrevocably consents hereto.

2.16Increase of Total Commitment.

(a)Subject to the conditions set forth in Section 2.16(b), the Borrower may increase the Total Commitment then in effect (any such increase an “Incremental Increase”) by increasing the Commitment of a Lender (an “Increasing Lender”) or by causing a Person that at such time is not a Lender to become a Lender (an “Additional Lender”).

(b)Any increase in the Total Commitment shall be subject to the following additional conditions:

(i)such increase shall not be less than $25,000,000 (and increments of $1,000,000 above that minimum) unless the Administrative Agent otherwise consents, and no such increase shall be permitted if after giving effect thereto the Total Commitment would exceed the lesser of (A) $1,500,000,000 and (B) the Borrowing Base then in effect (after giving effect to any concurrent increase in the Borrower Base);

(ii)neither an Event of Default nor a Borrowing Base Deficiency shall have occurred and be continuing after giving effect to such increase;

(iii)no Lender’s Commitment may be increased without the consent of such Lender;

(iv)the Administrative Agent, the Swingline Lender and each Issuing Bank must consent to the increase in Commitments of an Increasing Lender and the addition of any Additional Lender, in each case, such consent not to be unreasonably withheld or delayed;

(v)the maturity date of such increase shall be the same as the Maturity Date;

(vi)the increase shall be on the exact same terms and pursuant to the exact same documentation applicable to this Agreement (other than with respect to any arrangement, structuring, upfront or other fees or discounts payable in connection with such Incremental Increase) (provided that the Applicable Margin of the Facility may be increased to be consistent with that for such Incremental Increases).

For the avoidance of doubt, any such Incremental Increase shall not require any mandatory prepayment or commitment reduction prior to the Maturity Date.

(c)Any increase in the Total Commitment shall be implemented using customary documentation (any such documentation, an “Incremental Agreement”).

2.17[Intentionally Omitted].

2.18Alternate Rate of Interest.

(a)Subject to clauses (b), (c), (d), (e) and (f) of this Section 2.18, if:

(i)the Administrative Agent determines (which determination shall be conclusive absent manifest error) (A) prior to the commencement of any Interest Period for a Term Benchmark Borrowing, that adequate and reasonable means do not exist for ascertaining the Adjusted Term SOFR Rate (including because the Term SOFR Reference Rate is not available or published on a current basis), for such Interest Period or (B) at any time, that adequate and reasonable means do not exist for ascertaining the applicable Adjusted Daily Simple SOFR or Daily Simple SOFR; or

(ii)the Administrative Agent is advised by the Required Lenders that (A) prior to the commencement of any Interest Period for a Term Benchmark Borrowing, the Adjusted Term SOFR Rate for such Interest Period will not adequately and fairly reflect the cost to such Lenders (or Lender) of making or maintaining their Loans (or its Loan) included in such Borrowing for such Interest Period or (B) at any time, Adjusted Daily Simple SOFR will not adequately and fairly reflect the cost to such Lenders (or Lender) of making or maintaining their Loans (or its Loan) included in such Borrowing;

then the Administrative Agent shall give notice thereof to the Borrower and the Lenders by telephone, telecopy or electronic mail as promptly as practicable thereafter and, until (x) the Administrative Agent notifies the Borrower and the Lenders that the circumstances giving rise to such notice no longer exist with respect to the relevant Benchmark and (y) the Borrower delivers a new Notice of Conversion or Continuation in accordance with the terms of Section 2.6 or a new Notice of Borrowing in accordance with the terms of Section 2.3, (1) any Notice of Conversion or Continuation that requests the conversion of any Revolving Borrowing to, or continuation of any Revolving Borrowing as, a Term Benchmark Borrowing and any Notice of Borrowing that requests a Term Benchmark Revolving Borrowing shall instead be deemed to be an Notice of Conversion or Continuation or a Notice of Borrowing, as applicable, for (x) an RFR Borrowing so long as the Adjusted Daily Simple SOFR is not also the subject of Section 2.18(a)(i) or (ii) above or (y) an ABR Borrowing if the Adjusted Daily Simple SOFR also is the subject of Section 2.18(a)(i) or (ii) above and (2) any Notice of Borrowing that requests an RFR Borrowing shall instead be deemed to be a Notice of Borrowing, as applicable, for an ABR Borrowing; provided that if the circumstances giving rise to such notice affect only one Type of Borrowings, then all other Types of Borrowings shall be permitted. Furthermore, if any Term Benchmark Loan or RFR Loan is outstanding on the date of the Borrower’s receipt of the notice from the Administrative Agent referred to in this Section 2.18(a) with respect to a Relevant Rate applicable to such Term Benchmark Loan or RFR Loan, then until (x) the Administrative Agent notifies the Borrower and the Lenders that the circumstances giving rise to such notice no longer exist with respect to the relevant Benchmark and (y) the Borrower delivers a new Notice of Conversion or Continuation in accordance with the terms of Section 2.6 or a new Notice of Borrowing in accordance with the terms of Section 2.3, (a) any Term Benchmark Loan shall on the last day of the Interest Period applicable to such Loan, be converted by the Administrative Agent to, and shall constitute, (x) an RFR Borrowing so long as the Adjusted Daily Simple SOFR is not also the subject of Section 2.18(a)(i) or (ii) above or (y) an ABR Loan if the Adjusted Daily Simple SOFR also is the subject of Section 2.18(a)(i) or (ii) above, on such day, and (b) any RFR Loan shall on and from such day be converted by the Administrative Agent to, and shall constitute an ABR Loan.

(b)Notwithstanding anything to the contrary herein or in any other Credit Document, if a Benchmark Transition Event and its related Benchmark Replacement Date have occurred prior to the Reference Time in respect of any setting of the then-current Benchmark, then such Benchmark Replacement will replace such Benchmark for all purposes hereunder and under any Credit Document in respect of any Benchmark setting at or after 5:00 p.m. (New York City time) on the fifth (5th) Business Day after the date notice of such Benchmark Replacement is provided to the Lenders without any amendment to, or further action or consent of any other party to, this Agreement or any other Credit Document so long as the Administrative Agent has not received, by such time, written notice of objection to such Benchmark Replacement from Lenders comprising the Required Lenders.

(c)Notwithstanding anything to the contrary herein or in any other Credit Document, the Administrative Agent will have the right to make Benchmark Replacement Conforming Changes from time to time and, notwithstanding anything to the contrary herein or in any other Credit Document, any amendments implementing such Benchmark Replacement Conforming Changes will become effective without any further action or consent of any other party to this Agreement or any other Credit Document.

(d)The Administrative Agent will promptly notify the Borrower and the Lenders of (i) any occurrence of a Benchmark Transition Event, (ii) the implementation of any Benchmark Replacement, (iii) the effectiveness of any Benchmark Replacement Conforming Changes, (iv) the removal or reinstatement of any tenor of a Benchmark pursuant to clause (e) below and (v) the commencement or conclusion of any Benchmark Unavailability Period. Any determination, decision or election that may be made by the Administrative Agent or, if applicable, any Lender (or group of Lenders) pursuant to this Section 2.18, including any determination with respect to a tenor, rate or adjustment or of the occurrence or non-occurrence of an event, circumstance or date and any decision to take or refrain from taking any action or any selection, will be conclusive and binding absent manifest error and may be made in its or their sole discretion and without consent from any other party to this Agreement or any other Credit Document, except, in each case, as expressly required pursuant to this Section 2.18.

(e)Notwithstanding anything to the contrary herein or in any other Credit Document, at any time (including in connection with the implementation of a Benchmark Replacement), (i) if the then-current Benchmark is a term rate (including the Term SOFR Rate) and either (A) any tenor for such Benchmark is not displayed on a screen or other information service that publishes such rate from time to time as selected by the Administrative Agent in its reasonable discretion or (B) the regulatory supervisor for the administrator of such Benchmark has provided a public statement or publication of information announcing that any tenor for such Benchmark is or will be no longer representative, then the Administrative Agent may modify the definition of “Interest Period” for any Benchmark settings at or after such time to remove such unavailable or non-representative tenor and (ii) if a tenor that was removed pursuant to clause (i) above either (A) is subsequently displayed on a screen or information service for a Benchmark (including a Benchmark Replacement) or (B) is not, or is no longer, subject to an announcement that it is or will no longer be representative for a Benchmark (including a Benchmark Replacement), then the Administrative Agent may modify the definition of “Interest Period” for all Benchmark settings at or after such time to reinstate such previously removed tenor.

(f)Upon the Borrower’s receipt of notice of the commencement of a Benchmark Unavailability Period, the Borrower may revoke any request for a Term Benchmark Borrowing or RFR Borrowing of, conversion to or continuation of Term Benchmark Loans to be made, converted or continued during any Benchmark Unavailability Period and, failing that, the Borrower will be deemed to have converted any request for a Term Benchmark Borrowing into a request for a Borrowing of or conversion to (A) an RFR Borrowing so long as the Adjusted Daily Simple SOFR is not the subject of a Benchmark Transition Event or (B) an ABR Borrowing if the Adjusted Daily Simple SOFR is the subject of a Benchmark Transition Event. During any

Benchmark Unavailability Period or at any time that a tenor for the then-current Benchmark is not an Available Tenor, the component of ABR based upon the then-current Benchmark or such tenor for such Benchmark, as applicable, will not be used in any determination of ABR. Furthermore, if any Term Benchmark Loan or RFR Loan is outstanding on the date of the Borrower’s receipt of notice of the commencement of a Benchmark Unavailability Period with respect to a Relevant Rate applicable to such Term Benchmark Loan or RFR Loan, then until such time as a Benchmark Replacement is implemented pursuant to this Section 2.18, (1) any Term Benchmark Loan shall on the last day of the Interest Period applicable to such Loan, be converted by the Administrative Agent to, and shall constitute, (x) an RFR Borrowing so long as the Adjusted Daily Simple SOFR is not the subject of a Benchmark Transition Event or (y) an ABR Loan if the Adjusted Daily Simple SOFR is the subject of a Benchmark Transition Event, on such day and (2) any RFR Loan shall on and from such day be converted by the Administrative Agent to, and shall constitute an ABR Loan.

Section 3.Letters of Credit

3.1Letters of Credit.

(a)Subject to and upon the terms and conditions herein set forth, at any time and from time to time on and after the Closing Date and prior to the L/C Maturity Date, each Issuing Bank, severally and not jointly, agrees, in reliance upon the agreements of the Lenders set forth in this Section 3, to issue upon the request of the Borrower and for the direct or indirect benefit of the Borrower and the Restricted Subsidiaries, a letter of credit or letters of credit (the “Letters of Credit” and each, a “Letter of Credit”) denominated in any Agreed Currency in such form and with such Issuer Documents as may be approved by the applicable Issuing Bank in its reasonable discretion; provided that the Borrower shall be a co-applicant of, and jointly and severally liable with respect to, each Letter of Credit issued for the account of a Restricted Subsidiary.

(b)Notwithstanding the foregoing, (i) no Letter of Credit shall be issued the Stated Amount of which, when added to the Letters of Credit Outstanding at such time, would exceed the Letter of Credit Commitment then in effect, (ii) no Letter of Credit shall be issued the Stated Amount of which would cause the aggregate amount of all Lenders’ Total Exposures at such time to exceed the Loan Limit then in effect, (iii) each Letter of Credit shall have an expiration date occurring no later than one year after the date of issuance or such longer period of time as may be agreed by the applicable Issuing Bank, unless otherwise agreed upon by the Administrative Agent and the applicable Issuing Bank or as provided under Section 3.2(b); provided that any Letter of Credit may provide for automatic renewal thereof for additional periods of up to 12 months or such longer period of time as may be agreed upon by the applicable Issuing Bank, subject to the provisions of Section 3.2(b); provided, further, that in no event shall such expiration date occur later than the L/C Maturity Date unless arrangements which are reasonably satisfactory to the applicable Issuing Bank to Cash Collateralize (or backstop) such Letter of Credit have been made (and, in any event, no Lender shall have any obligation to fund any L/C Participation if respect of any Unpaid Drawing after the L/C Maturity Date), (iv) no Alternate Currency Letter of Credit shall be issued unless (A) the Administrative Agent and the applicable Issuing Bank agree to such issuance of such Alternate Currency Letter of Credit (it being understood that there shall be no obligation to so agree) and (B) after giving effect thereto, the aggregate amount of the Letter of Credit Exposure with respect to all Alternate Currency Letters of Credit would not exceed $20,000,000, (v) no Letter of Credit shall be issued if it would be illegal under any applicable Requirement of Law for the beneficiary of the Letter of Credit to have a Letter of Credit issued in its favor, (vi) no Letter of Credit shall be issued by an Issuing Bank after it has received a written notice from any Credit Party or the Administrative Agent or the Majority Lenders stating that a Default or Event of Default has occurred and is continuing until such time as such Issuing Bank shall have received a written notice (A) of rescission of such notice from the party or parties originally delivering such notice, (B) of the waiver of such Default or Event of Default in accordance with the provisions of Section 13.1 or (C) that such Default or

Event of Default is no longer continuing, (vii) no Issuing Bank shall have an obligation to issue a Letter of Credit in a Stated Amount that, when added to the Letters of Credit Outstandings of Letters of Credit issued by such Issuing Bank, would exceed such Issuing Bank’s Maximum LC Commitment, (viii) any order, judgment or decree of any Governmental Authority or arbitrator shall by its terms purport to enjoin or restrain such Issuing Bank from issuing such Letter of Credit, or request that such Issuing Bank refrain from issuing such Letter of Credit, or any law applicable to such Issuing Bank shall prohibit the issuance of letters of credit generally or such Letter of Credit in particular or any such order, judgment or decree, or law shall impose upon such Issuing Bank with respect to such Letter of Credit any restriction, reserve or capital or liquidity requirement (for which such Issuing Bank is not otherwise compensated hereunder) not in effect on the Closing Date, or shall impose upon such Issuing Bank any unreimbursed loss, cost or expense that was not applicable on the Closing Date and that such Issuing Bank in good faith deems material to it, and (ix) no Issuing Bank shall have an obligation to issue a Letter of Credit the proceeds of which would be available to any Person in any manner that would result in a violation of one or more policies of such Issuing Bank applicable to letters of credit generally. In no event shall more than twenty (20) Letters of Credit be issued and outstanding at any time unless otherwise approved in writing by the Administrative Agent.

(c)Upon at least one Business Day’s prior written notice (or telephonic notice promptly confirmed in writing) to the Administrative Agent and the applicable Issuing Bank (which notice the Administrative Agent shall promptly transmit to each of the applicable Lenders), the Borrower shall have the right, on any day, permanently to terminate or reduce the Letter of Credit Commitment in whole or in part; provided that, after giving effect to such termination or reduction, the Letters of Credit Outstanding shall not exceed the Letter of Credit Commitment.

(d)Notwithstanding anything herein to the contrary, no Issuing Bank shall have an obligation hereunder to issue, and no Issuing Bank shall issue, any Letter of Credit the proceeds of which would be made available to any Person (i) to fund any activity or business of or with any Sanctioned Person, or in any country or territory that, at the time of such funding, is the subject of any Sanctions or (ii) in any manner that would result in a violation of any Sanctions by any party to this Agreement.

3.2Letter of Credit Applications.

(a)Whenever the Borrower desires that a Letter of Credit be issued, amended or renewed for its account on its own behalf, or on behalf of its Restricted Subsidiaries, the Borrower shall hand deliver or telecopy (or transmit by electronic communication, if arrangements for doing so have been approved by the applicable Issuing Bank) to the applicable Issuing Bank and the Administrative Agent a Letter of Credit application, amendment request or any such document as may be approved by the applicable Issuing Bank (each, a “Letter of Credit Application”). Upon receipt of any Letter of Credit Application or amendment request, (i) in the case of Letters of Credit denominated in Dollars, (A) the applicable Issuing Bank will use its best efforts to process such Letter of Credit Application on the Business Day on which such Letter of Credit Application is received, provided that such Letter of Credit Application is received no later than 12:00 p.m. (New York City time) on such Business Day, or (B) otherwise, the first Business Day next succeeding receipt of such Letter of Credit Application, and (ii) in the case of Letters of Credit denominated in an Alternate Currency, (A) the applicable Issuing Bank will use its best efforts to process such Letter of Credit Application on the second Business Day after the day on which such Letter of Credit Application is received, or (B) otherwise, the fifth Business Day after the day on which such Letter of Credit Application is received. In addition, as a condition to any such Letter of Credit issuance, the Borrower shall have entered into a continuing agreement (or other letter of credit agreement) for the issuance of letters of credit and/or shall submit a letter of credit application, in each case, as required by the respective Issuing Bank and using such Issuing Bank’s standard form (each, a “Letter of

Credit Agreement”). In the event of any conflict between the terms and conditions of this Agreement and the terms and conditions of any Letter of Credit Agreement, the terms and conditions of this Agreement shall control.

(b)If the Borrower so requests in any applicable Letter of Credit Application, the applicable Issuing Bank may, in its sole and absolute discretion, agree to issue a Letter of Credit that has automatic extension provisions (each, an “Auto-Extension Letter of Credit”); provided that any such Auto-Extension Letter of Credit must permit such Issuing Bank to prevent any such extension at least once in each 12-month period (commencing with the date of issuance of such Letter of Credit) by giving prior notice to the beneficiary thereof not later than a day (the “Non-Extension Notice Date”) in each such 12-month period to be agreed upon at the time such Letter of Credit is issued. Unless otherwise directed by the applicable Issuing Bank, the Borrower shall not be required to make a specific request to such Issuing Bank for any such extension. Once an Auto-Extension Letter of Credit has been issued, the Lenders shall be deemed to have authorized (but may not require) the applicable Issuing Bank to permit the extension of such Letter of Credit at any time to an expiry date not later than the L/C Maturity Date; provided, however, that such Issuing Bank shall not permit any such extension if (i) such Issuing Bank has determined that it would not be permitted, or would have no obligation, at such time to issue such Letter of Credit in its revised form (as extended) under the terms hereof (by reason of the provisions of clause (b) of Section 3.1 or otherwise), or (ii) it has received notice (which may be by telephone or in writing) on or before the day that is five Business Days before the Non-Extension Notice Date (A) from the Administrative Agent that the Majority Lenders have elected not to permit such extension or (B) from the Administrative Agent, any Lender or the Borrower that one or more of the applicable conditions specified in Section 7 are not then satisfied, and in each such case directing such Issuing Bank not to permit such extension.

(c)Each Issuing Bank (other than the Administrative Agent or any of its Affiliates) shall, at least once each week, provide the Administrative Agent with a list of all Letters of Credit issued by it that are outstanding at such time; provided that, upon written request from the Administrative Agent, such Issuing Bank shall thereafter notify the Administrative Agent in writing on each Business Day of all Letters of Credit issued on the prior Business Day by such Issuing Bank; provided further that the notification requirements of this Section 3.2(c) shall not apply with respect to any Existing Letter of Credit.

(d)The making of each Letter of Credit Request shall be deemed to be a representation and warranty by the Borrower that the Letter of Credit may be issued in accordance with, and will not violate the requirements of, Section 3.1(b).

3.3Letter of Credit Participations.

(a)Immediately upon the issuance by an Issuing Bank of any Letter of Credit (and on the Closing Date, with respect to the Existing Letters of Credit) or an amendment by an Issuing Bank to a Letter of Credit increasing the amount thereof, such Issuing Bank shall be deemed to have sold and transferred to each Lender (each such Lender, in its capacity under this Section 3.3, an “L/C Participant”), and each such L/C Participant shall be deemed irrevocably and unconditionally to have purchased and received from such Issuing Bank, without recourse or warranty, an undivided interest and participation (each an “L/C Participation”), to the extent of such L/C Participant’s Commitment Percentage, in each Letter of Credit, each substitute therefor, each drawing made thereunder and the obligations of the Borrower under this Agreement with respect thereto, and any security therefor or guaranty pertaining thereto.

(b)In determining whether to pay under any Letter of Credit, the relevant Issuing Bank shall have no obligation relative to the L/C Participants other than to confirm that (i) any documents required to be delivered under such Letter of Credit have been delivered, (ii) such Issuing Bank has examined the documents with reasonable care and (iii) the documents appear to comply on their face with the requirements of such Letter

of Credit. Any action taken or omitted to be taken by the relevant Issuing Bank under or in connection with any Letter of Credit issued by it, if taken or omitted in the absence of gross negligence or willful misconduct, shall not create for such Issuing Bank any resulting liability.

(c)In the event that an Issuing Bank makes any payment under any Letter of Credit issued by it and the Borrower shall not have repaid such amount (calculated, in the case of Alternate Currency Letters of Credit, based on the Dollar Equivalent thereof) in full to such Issuing Bank pursuant to Section 3.4(a), such Issuing Bank shall promptly notify the Administrative Agent and each L/C Participant of such failure, and each such L/C Participant shall promptly and unconditionally pay to the Administrative Agent for the account of such Issuing Bank, the amount of such L/C Participant’s Commitment Percentage of such unreimbursed payment in Dollars and in immediately available funds; provided, however, that no L/C Participant shall be obligated to pay to the Administrative Agent for the account of such Issuing Bank its Commitment Percentage of such unreimbursed amount arising from any wrongful payment made by such Issuing Bank under any such Letter of Credit as a result of acts or omissions constituting willful misconduct or gross negligence on the part of such Issuing Bank. Each L/C Participant shall make available to the Administrative Agent for the account of the relevant Issuing Bank such L/C Participant’s Commitment Percentage of the amount of such payment no later than 1:00 p.m. (New York City time) on the first Business Day after the date notified by such Issuing Bank in immediately available funds. If and to the extent such L/C Participant shall not have so made its Commitment Percentage of the amount of such payment available to the Administrative Agent for the account of the relevant Issuing Bank, such L/C Participant agrees to pay to the Administrative Agent for the account of such Issuing Bank, forthwith on demand, such amount, together with interest thereon for each day from such date until the date such amount is paid to the Administrative Agent for the account of such Issuing Bank at a rate per annum equal to the Overnight Rate from time to time then in effect, plus any administrative, processing or similar fees customarily charged by such Issuing Bank in connection with the foregoing. The failure of any L/C Participant to make available to the Administrative Agent for the account of any Issuing Bank its Commitment Percentage of any payment under any Letter of Credit shall not relieve any other L/C Participant of its obligation hereunder to make available to the Administrative Agent for the account of such Issuing Bank its Commitment Percentage of any payment under such Letter of Credit on the date required, as specified above, but no L/C Participant shall be responsible for the failure of any other L/C Participant to make available to the Administrative Agent such other L/C Participant’s Commitment Percentage of any such payment.

(d)Whenever an Issuing Bank receives a payment in respect of an unpaid reimbursement obligation as to which the Administrative Agent has received for the account of such Issuing Bank any payments from the L/C Participants pursuant to clause (c) above, such Issuing Bank shall pay to the Administrative Agent and the Administrative Agent shall promptly pay to each L/C Participant that has paid its Commitment Percentage of such reimbursement obligation, in Dollars and in immediately available funds, an amount equal to such L/C Participant’s share (based upon the proportionate aggregate amount originally funded by such L/C Participant to the aggregate amount funded by all L/C Participants) of the principal amount so paid in respect of such reimbursement obligation and interest thereon accruing after the purchase of the respective L/C Participations at the Overnight Bank Funding Rate.

(e)The obligations of the L/C Participants to make payments to the Administrative Agent for the account of an Issuing Bank with respect to Letters of Credit shall be irrevocable and not subject to counterclaim, set-off or other defense or any other qualification or exception whatsoever and shall be made in accordance with the terms and conditions of this Agreement under all circumstances, including under any of the following circumstances:

(i)any lack of validity or enforceability of this Agreement or any of the other Credit Documents;

(ii)the existence of any claim, set-off, defense or other right that the Borrower may have at any time against a beneficiary named in a Letter of Credit, any transferee of any Letter of Credit (or any Person for whom any such transferee may be acting), the Administrative Agent, any Issuing Bank, any Lender or other Person, whether in connection with this Agreement, any Letter of Credit, the transactions contemplated herein or any unrelated transactions (including any underlying transaction between the Borrower and the beneficiary named in any such Letter of Credit);

(iii)any draft, certificate or any other document presented under any Letter of Credit proving to be forged, fraudulent, invalid or insufficient in any respect or any statement therein being untrue or inaccurate in any respect;

(iv)the surrender or impairment of any security for the performance or observance of any of the terms of any of the Credit Documents;

(v)the occurrence of any Default or Event of Default; or

(vi)any adverse change in the relevant exchange rates or in the availability of the relevant Alternate Currency to the Borrower or any Subsidiary or in the relevant currency markets generally;

provided, however, that no L/C Participant shall be obligated to pay to the Administrative Agent for the account of any Issuing Bank its Commitment Percentage of any unreimbursed amount arising from any wrongful payment made by such Issuing Bank under a Letter of Credit as a result of acts or omissions constituting willful misconduct or gross negligence on the part of such Issuing Bank.

3.4Agreement to Repay Letter of Credit Drawings.

(a)The Borrower hereby agrees to reimburse the relevant Issuing Bank by making payment in Dollars or, in the case of Alternate Currency Letters of Credit, in the applicable Alternate Currency to such Issuing Bank or to the Administrative Agent for the account of such Issuing Bank (whether with its own funds or with proceeds of the Loans) in immediately available funds, for any payment or disbursement made by such Issuing Bank under any Letter of Credit issued by it (each such amount so paid until reimbursed, an “Unpaid Drawing” (calculated, in the case of Alternate Currency Letters of Credit, based on the Dollar Equivalent thereof)) (i) within one Business Day of the date of such payment or disbursement if such Issuing Bank provides notice to the Borrower of such payment or disbursement prior to 11:00 a.m. (New York City time) on such next succeeding Business Day (from the date of such payment or disbursement) or (ii) if such notice is received after such time, on the next Business Day following the date of receipt of such notice (such required date for reimbursement under clause (i) or (ii), as applicable, on such Business Day (the “Reimbursement Date”)), with interest on the amount so paid or disbursed by such Issuing Bank, from and including the date of such payment or disbursement to but excluding the Reimbursement Date, at the per annum rate for each day equal to the rate described in Section 2.8(a); provided that, notwithstanding anything contained in this Agreement to the contrary, with respect to any Letter of Credit, (A) unless the Borrower shall have notified the Administrative Agent and such Issuing Bank prior to 11:00 a.m. (New York City time) on the Reimbursement Date that the Borrower intends to reimburse such Issuing Bank for the amount of such drawing with funds other than the proceeds of Loans, the Borrower shall be deemed to have given a Notice of Borrowing requesting that the Lenders make Loans (which shall be

ABR Loans) on the Reimbursement Date in an amount equal to the amount at such drawing (calculated, in the case of Alternate Currency Letters of Credit, based on the Dollar Equivalent thereof), and (B) the Administrative Agent shall promptly notify each L/C Participant of such drawing and the amount of its Loan to be made in respect thereof, and each L/C Participant shall be irrevocably obligated to make a Loan to the Borrower in the manner deemed to have been requested in the amount of its Commitment Percentage of the applicable Unpaid Drawing by 12:00 noon (New York City time) on such Reimbursement Date by making the amount of such Loan available to the Administrative Agent. Such Loans made in respect of such Unpaid Drawing on such Reimbursement Date shall be made without regard to the Minimum Borrowing Amount and without regard to the satisfaction of the conditions set forth in Section 7. The Administrative Agent shall use the proceeds of such Loans solely for purpose of reimbursing the relevant Issuing Bank for the related Unpaid Drawing. In the event that the Borrower fails to Cash Collateralize any Letter of Credit that is outstanding on the L/C Maturity Date, the full amount of the Letters of Credit Outstanding in respect of such Letter of Credit shall be deemed to be an Unpaid Drawing subject to the provisions of this Section 3.4 except that such Issuing Bank shall hold the proceeds received from the Lenders as contemplated above as cash collateral for such Letter of Credit to reimburse any Drawing under such Letter of Credit and shall use such proceeds first, to reimburse itself for any Drawings made in respect of such Letter of Credit following the L/C Maturity Date, second, to the extent such Letter of Credit expires or is returned undrawn while any such cash collateral remains, to the repayment of obligations in respect of any Loans that have not paid at such time and third, to the Borrower or as otherwise directed by a court of competent jurisdiction. Nothing in this Section 3.4(a) shall affect the Borrower’s obligation to repay all outstanding Loans when due in accordance with the terms of this Agreement.

(b)The obligations of the Borrower under this Section 3.4 to reimburse the relevant Issuing Bank with respect to Unpaid Drawings (including, in each case, interest thereon) shall be absolute, unconditional and irrevocable, and shall be performed strictly in accordance with the terms of this Agreement under any and all circumstances and irrespective of any set-off, counterclaim or defense to payment that the Borrower or any other Person may have or have had against such Issuing Bank, the Administrative Agent or any Lender (including in its capacity as an L/C Participant), including any defense based upon (i) the failure of any drawing under a Letter of Credit (each a “Drawing”) to conform to the terms of the Letter of Credit, (ii) any non-application or misapplication by the beneficiary of the proceeds of such Drawing, (iii) any lack of validity or enforceability of any Letter of Credit or this Agreement, or any term or provision therein, (iv) any draft or other document presented under a Letter of Credit proving to be forged, fraudulent or invalid in any respect or any statement therein being untrue or inaccurate in any respect, (v) payment by the respective Issuing Bank under a Letter of Credit against presentation of a draft or other document that does not comply with the terms of such letter of Credit, or (vi) any other event or circumstance whatsoever, whether or not similar to any of the foregoing, that might, but for the provisions of this Section, constitute a legal or equitable discharge of, or provide a right of setoff against, the Borrower’s obligations hereunder. None of the Administrative Agent, the Lenders or any Issuing Bank, nor any of their respective Related Parties, shall have any liability or responsibility by reason of or in connection with the issuance or transfer of any Letter of Credit or any payment or failure to make any payment thereunder (irrespective of any of the circumstances referred to in the preceding sentence), or any error, omission, interruption, loss or delay in transmission or delivery of any draft, document, notice or other communication under or relating to any Letter of Credit (including any document required to make a drawing thereunder), any error in interpretation of technical terms, any error in translation or any consequence arising from causes beyond the control of the respective Issuing Bank provided that the foregoing shall not be construed to excuse the relevant Issuing Bank from liability to the Borrower to the extent of any direct damages (as opposed to special, indirect, consequential or punitive damages, claims in respect of which are hereby waived by the Borrower to the extent permitted by applicable law) suffered by the Borrower that are caused by such Issuing Bank’s failure to exercise care when determining whether drafts and other documents presented under a Letter of Credit comply with the terms thereof. The parties hereto expressly agree that, in the absence of gross negligence or willful misconduct on the part of an

Issuing Bank (as finally determined by a court of competent jurisdiction), such Issuing Bank shall be deemed to have exercised care in each such determination. In furtherance of the foregoing and without limiting the generality thereof, the parties hereto agree that, with respect to documents presented which appear on their face to be in substantial compliance with the terms of a Letter of Credit, the Issuing Bank that issued such Letter of Credit may in its sole discretion, either accept or make payment upon such documents without responsibility for further investigation, regardless of any notice or information to the contrary, or refuse to accept and make payment upon such documents if such documents are not in strict compliance with the terms of such Letter of Credit.

3.5Increased Costs.

(a)If any Change in Law shall either (i) impose, modify or deem applicable any reserve, special deposit, liquidity, or similar requirement (including any compulsory loan requirement, insurance charge or other assessment) against assets of, deposits with or for the account of, or credit extended by, any Issuing Bank or any L/C Participant, (ii) impose on any Issuing Bank, any L/C Participant or the London interbank market, any other conditions, costs or expenses (other than Taxes) affecting this Agreement or any Letter of Credit or L/C Participant’s L/C Participation therein, or (iii) subject any Issuing Bank or any L/C Participant to any Taxes (other than (A) Indemnified Taxes, (B) Taxes described in clauses (i) and (iii) of the definition of Excluded Taxes and (C) Connection Income Taxes) on its letters of credit, commitments, or other obligations, or its deposits, reserves, other liabilities or capital attributable thereto, and the result of any of the foregoing is to increase the cost to such Issuing Bank or such L/C Participant of issuing, maintaining or participating in any Letter of Credit, or to reduce the amount of any sum received or receivable by such Issuing Bank or such L/C Participant hereunder (whether of principal, interest or otherwise), then the Borrower shall pay to such Issuing Bank or such L/C Participant such additional amount or amounts as will compensate such Issuing Bank or such L/C Participant for such increased cost or reduction suffered.

(b)If, after the Closing Date, any Change in Law relating to capital adequacy or liquidity requirements of any Issuing Bank or L/C Participant or compliance by any Issuing Bank, L/C Participant, or its parent with any Change in Law relating to capital adequacy or liquidity requirements occurring after the Closing Date, has or would have the effect of reducing the rate of return on such Issuing Bank’s, L/C Participant’s, or its parent’s capital or assets as a consequence of such Issuing Bank’s or L/C Participant’s commitments or obligations hereunder to a level below that which such Issuing Bank, L/C Participant or its parent could have achieved but for such Change in Law (taking into consideration such Issuing Bank’s, L/C Participant’s, or its parent’s policies with respect to capital adequacy or liquidity requirements), then from time to time, promptly after written demand by such Issuing Bank or L/C Participant (with a copy to the Administrative Agent), the Borrower shall pay to such Issuing Bank or L/C Participant such additional amount or amounts as will compensate such Issuing Bank, L/C Participant, or its parent for such reduction, it being understood and agreed, however, that an Issuing Bank, L/C Participant or its parent shall not be entitled to such compensation as a result of such Issuing Bank’s or L/C Participant’s compliance with, or pursuant to any request or directive to comply with, any applicable Requirement of Law as in effect on the Closing Date (except as otherwise set forth in the definition of Change in Law).

(c)Each Issuing Bank or L/C Participant, upon determining in good faith that any additional amounts will be payable pursuant to this Section 3.5, will give prompt written notice thereof to the Borrower, which notice shall set forth in reasonable detail the basis of the calculation of such additional amounts and shall be conclusive absent manifest error. The Borrower shall pay such Issuing Bank or L/C Participant the amount shown on any such certificate within ten (10) days after receipt thereof, although the failure of any Issuing Bank or L/C Participant to give any such notice shall not, subject to Section 2.13, release or diminish the Borrower’s obligations to pay additional amounts pursuant to this Section 3.5 upon receipt of such notice.

3.6New or Successor Issuing Bank.

(a)Any Issuing Bank may resign as an Issuing Bank upon 30 days’ prior written notice to the Administrative Agent, the Lenders and the Borrower; provided that no Issuing Bank may resign without the prior consent of the Borrower so long as it (or one of its Affiliates) is also a Lender hereunder. The Borrower may replace any Issuing Bank for any reason upon written notice to such Issuing Bank and the Administrative Agent and may add Issuing Banks at any time upon notice by the Borrower to the Administrative Agent. If an Issuing Bank shall resign or be replaced, or if the Borrower shall decide to add a new Issuing Bank under this Agreement, then the Borrower may appoint from among the Lenders a successor issuer of Letters of Credit or a new Issuing Bank, as the case may be, or, with the consent of the Administrative Agent (such consent not to be unreasonably withheld) and such new Issuing Bank, another successor or new issuer of Letters of Credit, whereupon such successor issuer shall succeed to the rights, powers and duties of the replaced or resigning Issuing Bank under this Agreement and the other Credit Documents, or such new issuer of Letters of Credit shall be granted the rights, powers and duties of an Issuing Bank hereunder, and the term “Issuing Bank” shall mean such successor or such new issuer of Letters of Credit effective upon such appointment. The acceptance of any appointment as an Issuing Bank hereunder whether as a successor issuer or new issuer of Letters of Credit in accordance with this Agreement, shall be evidenced by an agreement entered into by such new or successor issuer of Letters of Credit, in a form reasonably satisfactory to the Borrower and the Administrative Agent and, from and after the effective date of such agreement, such new or successor issuer of Letters of Credit shall become an “Issuing Bank” hereunder. After the resignation or replacement of an Issuing Bank hereunder, the resigning or replaced Issuing Bank shall remain a party hereto and shall continue to have all the rights and obligations of an Issuing Bank under this Agreement and the other Credit Documents with respect to Letters of Credit issued by it prior to such resignation or replacement, but shall not be required to issue additional Letters of Credit. In connection with any resignation or replacement pursuant to this clause (a) (but, in case of any such resignation, only to the extent that a successor issuer of Letters of Credit shall have been appointed), either (i) the Borrower, the resigning or replaced Issuing Bank and the successor issuer of Letters of Credit shall arrange to have any outstanding Letters of Credit issued by the resigning or replaced Issuing Bank replaced with Letters of Credit issued by the successor issuer of Letters of Credit or (ii) the Borrower shall cause the successor issuer of Letters of Credit, if such successor issuer is reasonably satisfactory to the replaced or resigning Issuing Bank, to issue “back-stop” Letters of Credit naming the resigning or replaced Issuing Bank as beneficiary for each outstanding Letter of Credit issued by the resigning or replaced Issuing Bank, which new Letters of Credit shall have a Stated Amount equal to the Letters of Credit being back-stopped and the sole requirement for drawing on such new Letters of Credit shall be a drawing on the corresponding back-stopped Letters of Credit. After any resigning or replaced Issuing Bank’s resignation or replacement as Issuing Bank, the provisions of this Agreement relating to an Issuing Bank shall inure to its benefit as to any actions taken or omitted to be taken by it (A) while it was an Issuing Bank under this Agreement or (B) at any time with respect to Letters of Credit issued by such Issuing Bank.

(b)To the extent that there are, at the time of any resignation or replacement as set forth in clause (a) above, any outstanding Letters of Credit, nothing herein shall be deemed to impact or impair any rights and obligations of any of the parties hereto with respect to such outstanding Letters of Credit (including any obligations related to the payment of fees or the reimbursement or funding of amounts drawn), except that the Borrower, the resigning or replaced Issuing Bank and the successor issuer of Letters of Credit shall have the obligations regarding outstanding Letters of Credit described in clause (a) above.

3.7Role of Issuing Bank. Each Lender and the Borrower agree that, in paying any drawing under a Letter of Credit, no Issuing Bank shall have any responsibility to obtain any document (other than any sight draft, certificates and documents expressly required by the Letter of Credit) or to ascertain or inquire as to the validity or accuracy of any such document or the authority of the Person executing or delivering any such document. None

of the Issuing Banks, the Administrative Agent, any of their respective affiliates nor any correspondent, participant or assignee of any Issuing Bank shall be liable to any Lender for (a) any action taken or omitted in connection herewith at the request or with the approval of the Majority Lenders, (b) any action taken or omitted in the absence of gross negligence or willful misconduct or (c) the due execution, effectiveness, validity or enforceability of any document or instrument related to any Letter of Credit or Issuer Document. The Borrower hereby assumes all risks of the acts or omissions of any beneficiary or transferee with respect to its use of any Letter of Credit; provided that this assumption is not intended to, and shall not, preclude the Borrower’s pursuing such rights and remedies as it may have against the beneficiary or transferee at law or under any other agreement. None of the Issuing Banks, the Administrative Agent, any of their respective affiliates nor any correspondent, participant or assignee of any Issuing Bank shall be liable or responsible for any of the matters described in Section 3.3(e); provided that anything in such Section to the contrary notwithstanding, the Borrower may have a claim against an Issuing Bank, and such Issuing Bank may be liable to the Borrower, to the extent, but only to the extent, of any direct, as opposed to consequential or exemplary, damages suffered by the Borrower which the Borrower proves were caused by such Issuing Bank’s willful misconduct or gross negligence or such Issuing Bank’s unlawful failure to pay under any Letter of Credit after the presentation to it by the beneficiary of a sight draft and certificate(s) strictly complying with the terms and conditions of a Letter of Credit. In furtherance and not in limitation of the foregoing, any Issuing Bank may accept documents that appear on their face to be in order, without responsibility for further investigation, regardless of any notice or information to the contrary, and no Issuing Bank shall be responsible for the validity or sufficiency of any instrument transferring or assigning or purporting to transfer or assign a Letter of Credit or the rights or benefits thereunder or proceeds thereof, in whole or in part, which may prove to be invalid or ineffective for any reason.

3.8Cash Collateral.

(a)Upon the request of the Majority Lenders if, as of the L/C Maturity Date, there are any Letters of Credit Outstanding, the Borrower shall immediately Cash Collateralize the then Letters of Credit Outstanding.

(b)If any Event of Default shall occur and be continuing, the Majority Lenders may require that the L/C Obligations be Cash Collateralized; provided that, upon the occurrence of an Event of Default referred to in Section 11.5 with respect to the Borrower, the Borrower shall immediately Cash Collateralize the Letters of Credit then outstanding and no notice or request by or consent from the Majority Lenders shall be required.

(c)For purposes of this Agreement, “Cash Collateralize” shall mean to (i) pledge and deposit with or deliver to the Administrative Agent, for the benefit of the Issuing Banks and the Lenders, as collateral for the L/C Obligations, cash or deposit account balances in an amount equal to the amount in the applicable currencies of the Letters of Credit Outstanding required to be Cash Collateralized (the “Required Cash Collateral Amount”) or (ii) if the relevant Issuing Bank benefiting from such collateral shall agree in its reasonable discretion, other forms of credit support (including any backstop letter of credit) in a face amount equal to 105% of the Required Cash Collateral Amount from an issuer reasonably satisfactory to such Issuing Bank, in each case under clause (i) and (ii) above pursuant to documentation in form and substance reasonably satisfactory to the Administrative Agent and the relevant Issuing Bank (which documents are hereby consented to by the Lenders). Derivatives of such term, including “Cash Collateral”, have corresponding meanings. The Borrower hereby grants to the Administrative Agent, for the benefit of the Issuing Banks and the L/C Participants, a security interest in all such cash, deposit accounts and all balances therein and all proceeds of the foregoing. Such Cash Collateral shall be maintained in blocked, interest bearing deposit accounts established by and in the name of the Borrower, subject at all times, in each case, to a Control Agreement.

3.9Existing Letters of Credit. Subject to the terms and conditions hereof, each Existing Letter of Credit that is outstanding on the Closing Date, listed on Schedule 1.1(d) shall, effective as of the Closing Date and without any further action by the Borrower, be continued as a Letter of Credit hereunder and from and after the Closing Date shall be deemed a Letter of Credit for all purposes hereof and shall be subject to and governed by the terms and conditions hereof.

3.10Applicability of ISP and UCP. Unless otherwise expressly agreed to by the relevant Issuing Bank and the Borrower when a Letter of Credit is issued, (a) the rules of the ISP or the Uniform Customs and Practice for Documentary Credits shall apply to each standby Letter of Credit and (b) the rules of the Uniform Customs and Practice for Documentary Credits, as most recently published by the International Chamber of Commerce at the time of issuance, shall apply to each commercial Letter of Credit.

3.11Conflict with Issuer Documents. In the event of any conflict between the terms hereof and the terms of any Issuer Document, the terms hereof shall control.

3.12Letters of Credit Issued for Restricted Subsidiaries. Notwithstanding that a Letter of Credit issued or outstanding hereunder is in support of any obligations of, or is for the account of, a Restricted Subsidiary, the Borrower shall be obligated to reimburse the relevant Issuing Bank hereunder for any and all drawings under such Letter of Credit. The Borrower hereby acknowledges that the issuance of Letters of Credit for the account of Restricted Subsidiaries inures to the benefit of the Borrower, and that the Borrower’s business derives substantial benefits from the businesses of such Restricted Subsidiaries.

3.13Alternate Currency. If any amounts received or owing hereunder in connection with Alternate Currency Letters of Credit are paid in a currency other than the applicable Alternate Currency (the “Other Currency”), the applicable Issuing Bank may convert (actually or notionally) such Other Currency into the applicable Alternate Currency and such conversion shall be effected at the Exchange Rate for the time being for obtaining such Alternate Currency and the Borrower shall indemnify such Issuing Bank on demand in respect of any resulting loss in respect of such conversion. The Borrower waives any right it may have in any jurisdiction to pay any amount under this Section 3.13 in a currency or currency unit other than that in which it is expressed to be payable.

Section 4.Fees; Commitments.

4.1Fees.

(a)The Borrower agrees to pay to the Administrative Agent in Dollars, for the account of each Lender (in each case pro rata according to the respective Commitment Percentages of the Lenders), a commitment fee (the “Commitment Fee”) for each day from the Closing Date until but excluding the Termination Date. Each Commitment Fee shall be payable by the Borrower (i) quarterly in arrears on the fifteenth (15th) day immediately following the last day of each March, June, September and December (for the three-month period (or portion thereof) ended on such day for which no payment has been received) and (ii) on the Termination Date (for the period ended on such date for which no payment has been received pursuant to clause (i) above), and shall be computed for each day during such period at a rate per annum equal to the Commitment Fee Rate in effect on such day on the Available Commitment (assuming for this purpose that there is no reference to “Swingline Exposure” in the definition of Total Exposure) in effect on such day.

(b)The Borrower agrees to pay to the Administrative Agent in Dollars for the account of the Lenders pro rata on the basis of their respective Letter of Credit Exposure, a fee in respect of each Letter of Credit (the “Letter of Credit Fee”), for the period from the date of issuance of such Letter of Credit until the termination

or expiration date of such Letter of Credit computed at the per annum rate for each day equal to the Applicable Margin for Term Benchmark Loans on the average daily Stated Amount of such Letter of Credit. Such Letter of Credit Fees shall be due and payable (i) quarterly in arrears on the last Business Day of each March, June, September and December and (ii) on the Termination Date (for the period for which no payment has been received pursuant to clause (i) above).

(c)The Borrower agrees to pay directly to each Issuing Bank a fee in respect of each Letter of Credit issued by it (the “Fronting Fee”), for the period from the date of issuance of such Letter of Credit to the termination or expiration date of such Letter of Credit, computed at the rate for each day equal to 0.125% per annum (or such other amount as may be agreed in a separate writing between the Borrower and the relevant Issuing Bank) on the average daily Stated Amount of such Letter of Credit (or at such other rate per annum as agreed in writing between the Borrower and the relevant Issuing Bank). Such Fronting Fees shall be due and payable by the Borrower (i) quarterly in arrears on the last Business Day of each March, June, September and December and (ii) on the Termination Date (for the period for which no payment has been received pursuant to clause (i) above).

(d)The Borrower agrees to pay directly to each Issuing Bank upon each issuance of, drawing under, and/or amendment of, a Letter of Credit issued by it such amount as the relevant Issuing Bank and the Borrower shall have agreed upon for issuances of, drawings under or amendments of, letters of credit issued by it.

(e)The Borrower agrees to pay to the Administrative Agent the administrative agent fees in the amounts and on the dates as set forth in writing from time to time between the Administrative Agent and the Borrower.

4.2Voluntary Reduction of Commitments.

(a)Upon at least two Business Days’ prior written notice (or telephonic notice promptly confirmed in writing) to the Administrative Agent at the Administrative Agent’s Office (which notice the Administrative Agent shall promptly transmit to each of the Lenders), the Borrower shall have the right, without premium or penalty, on any day, permanently to terminate or reduce the Commitments, in whole or in part; provided that (i) any such termination or reduction shall apply proportionately and permanently to reduce the Commitments of each of the Lenders, provided that (x) after giving effect to any such reduction and to the repayment of any Loans made on such date, the Total Exposure of any such Lender does not exceed the Commitment of such Lender and (y) for the avoidance of doubt, any such repayment of Loans contemplated by the preceding clause shall be made in compliance with the requirements of Section 5.3(a) with respect to the ratable allocation of payments hereunder, (ii) any partial reduction pursuant to this Section 4.2 shall be in the amount of at least $500,000 and in multiples of $100,000 in excess thereof and (iii) after giving effect to such termination or reduction and to any prepayments of Loans or cancellation or Cash Collateralization of Letters of Credit made on the date thereof in accordance with this Agreement, the aggregate amount of the Lenders’ Total Exposures shall not exceed the Loan Limit.

(b)The Borrower may terminate the unused amount of the Commitment of a Defaulting Lender upon not less than two (2) Business Days’ prior notice to the Administrative Agent (which will promptly notify the Lenders thereof), and in such event the provisions of Section 2.15(f) will apply to all amounts thereafter paid by the Borrower for the account of such Defaulting Lender under this Agreement (whether on account of principal, interest, fees, indemnity or other amounts), provided that such termination will not be deemed to be a waiver or release of any claim the Borrower, the Administrative Agent, any Issuing Bank, the Swingline Lender or any Lender may have against such Defaulting Lender.

4.3Mandatory Termination of Commitments.

(a)The Total Commitment shall terminate at 5:00 p.m. (New York City time) on the Termination Date.

(b)The Swingline Commitment shall terminate at 5:00 p.m. (New York City time) on the earlier of (x) the Swingline Maturity Date and (y) the Termination Date.

(c)If any reduction in the Borrowing Base pursuant to any provision of Section 2.14 would result in the Borrowing Base being less than the Total Commitment, then each Lender’s Commitment shall be automatically and permanently reduced, without premium or penalty, contemporaneously with such reduction in the Borrowing Base by such Lender’s pro rata amount by which the Borrowing Base is less than the Total Commitment (and concurrently with, and effective on, the effective date of such Borrowing Base reduction, (i)Schedule 1.1(a) and the Register shall each be amended to reflect the decrease in the Total Commitment and the Commitment of each Lender and (ii) the Administrative Agent shall promptly distribute to the Borrower, each Issuing Bank and each Lender the revised Schedule 1.1(a)). Any termination or reduction of the Total Commitment and each Lender’s Commitment shall be permanent and shall not be reinstated automatically upon any subsequent increase in the Borrowing Base (if any); provided, however, that the Total Commitment may be increased pursuant to the provisions of Section 2.16.

Section 5.Payments.

5.1Voluntary Prepayments. The Borrower shall have the right to prepay Loans and Swingline Loans, in each case, without premium or penalty, in whole or in part from time to time on the following terms and conditions:

(a)the Borrower shall give the Administrative Agent at the Administrative Agent’s Office written notice substantially in the form of Exhibit M hereto (or telephonic notice promptly confirmed in writing in such form) of its intent to make such prepayment, the amount of such prepayment and (in the case of Term Benchmark Loans) the specific Borrowing(s) being prepaid, which notice shall be given by the Borrower no later than 1:00 p.m. (New York City time) (i) in the case of Term Benchmark Loans, three U.S. Government Securities Business Days prior, (ii) in the case of RFR Loans, five U.S. Government Securities Business Days prior, and (iii) in the case of ABR Loans on the date of such prepayment and shall promptly be transmitted by the Administrative Agent to each of the Lenders;

(b)each partial prepayment of (i) Term Benchmark Loans and RFR Loans shall be in a minimum amount of $500,000 and in multiples of $100,000 in excess thereof, and (ii) any ABR Loans shall be in a minimum amount of $500,000 and in multiples of $100,000 in excess thereof; provided that no partial prepayment of Term Benchmark Loans made pursuant to a single Borrowing shall reduce the outstanding Term Benchmark Loans made pursuant to such Borrowing to an amount less than the applicable Minimum Borrowing Amount for such Term Benchmark Loans; and

(c)any prepayment of Term Benchmark Loans pursuant to this Section 5.1 on any day other than the last day of an Interest Period applicable thereto shall be subject to compliance by the Borrower with the applicable provisions of Section 2.11.

Each such notice shall specify the date and amount of such prepayment and the Type of Loans to be prepaid. At the Borrower’s election in connection with any prepayment pursuant to this Section 5.1, such prepayment shall not be applied to any Loans of a Defaulting Lender.

5.2Mandatory Prepayments.

(a)Repayment following Optional Reduction of Commitments. If, after giving effect to any termination or reduction of the Commitments pursuant to Section 4.2(a), the aggregate Total Exposures of all Lenders exceeds the Loan Limit (as reduced), then the Borrower shall on the same Business Day (i) prepay the Swingline Loans and, after all Swingline Loans have been paid in full, the remaining Loans on the date of such termination or reduction in an aggregate principal amount equal to such excess and (ii) if any excess remains after prepaying all of the Loans as a result of any Letter of Credit Exposure, pay to the Administrative Agent on behalf of the Issuing Banks and the L/C Participants an amount in cash or otherwise Cash Collateralize an amount equal to such excess as provided in Section 3.8.

(b)Repayment of Loans Following Redetermination or Adjustment of Borrowing Base.

(i)Upon any redetermination of the Borrowing Base in accordance with Section 2.14(b), if the aggregate Total Exposures of all Lenders exceeds the redetermined Borrowing Base, then the Borrower shall, within ten (10) Business Days after its receipt of a New Borrowing Base Notice indicating such Borrowing Base Deficiency, inform the Administrative Agent of the Borrower’s election to: (A) within 30 days following such election prepay the Loans in an aggregate principal amount equal to such excess, (B) prepay the Loans in four equal monthly installments, commencing on the 30th day following such election with each payment being equal to l/4th of the aggregate principal amount of such excess, (C) within 30 days following such election, provide additional Collateral in the form of additional Oil and Gas Properties not evaluated in the most recently delivered Reserve Report or other Collateral reasonably acceptable to the Administrative Agent having a Borrowing Base Value (as proposed by the Administrative Agent and approved by the Required Lenders in good faith in accordance with their respective usual and customary oil and gas lending criteria as they exist at the particular time) sufficient, after giving effect to any other actions taken pursuant to this Section 5.2(b)(i) to eliminate any such excess or (D) undertake a combination of clauses (A), (B) and (C); provided that if, because of Letter of Credit Exposure, a Borrowing Base Deficiency remains after prepaying all of the Loans, the Borrower shall Cash Collateralize such remaining Borrowing Base Deficiency as provided in Section 3.8; provided further, that all payments required to be made pursuant to this Section 5.2(b)(i) must be made on or prior to the Termination Date.

(ii)Upon any adjustment to the Borrowing Base pursuant to the Borrowing Base Adjustment Provisions, if the aggregate Total Exposures of all Lenders exceeds the Borrowing Base, as adjusted, then the Borrower shall (A) prepay the Loans in an aggregate principal amount equal to such excess and (B) if any excess remains after prepaying all of the Loans as a result of any Letter of Credit Exposure, Cash Collateralize such excess as provided in Section 3.8. The Borrower shall be obligated to make such prepayment and/or deposit of cash collateral no later than two (2) Business Days following the date it receives written notice from the Administrative Agent of the adjustment of the Borrowing Base and the resulting Borrowing Base Deficiency; provided that all payments required to be made pursuant to this clause must be made on or prior to the Termination Date.

(c)Repayment of Loans With Excess Cash.

(i)Upon the occurrence of and during the continuation of an Event of Default, on each Business Day the Borrower shall immediately prepay the Loans with all Excess Cash.

(ii)Unless required more frequently pursuant to Section 5.2(c)(i), if the Borrower and its Restricted Subsidiaries have any Excess Cash outstanding on the last Business Day of any week, the Borrower shall prepay the Loans on such last Business Day of the week in an amount equal to or greater than the amount of such Excess Cash.

(d)Application to Loans. With respect to each prepayment of Loans elected under Section 5.1 or required by Section 5.2, the Borrower may designate (i) the Types of Loans that are to be prepaid and the specific Borrowing(s) being repaid and (ii) the Loans to be prepaid; provided that (A) each prepayment of any Loans made pursuant to a Borrowing shall be applied pro rata among such Loans and (B) notwithstanding the provisions of the preceding clause (A), no prepayment of Loans shall be applied to the Loans of any Defaulting Lender unless otherwise agreed to in writing by the Borrower. In the absence of a designation by the Borrower as described in the preceding sentence, the Administrative Agent shall, subject to the above, make such designation in its reasonable discretion with a view, but no obligation, to minimize breakage costs owing under Section 2.11.

(e)Term Benchmark Interest Periods. In lieu of making any payment pursuant to this Section 5.2 in respect of any Term Benchmark Loan, other than on the last day of the Interest Period therefor so long as no Event of Default shall have occurred and be continuing, the Borrower at its option may deposit, on behalf of the Borrower, with the Administrative Agent an amount equal to the amount of the Term Benchmark Loan to be prepaid and such Term Benchmark Loan shall be repaid on the last day of the Interest Period therefor in the required amount. Such deposit shall be held by the Administrative Agent in a corporate time deposit account established on terms reasonably satisfactory to the Administrative Agent, earning interest at the then customary rate for accounts of such type. The Borrower hereby grants to the Administrative Agent, for the benefit of the Lenders, a security interest in all such cash, deposit accounts and all balances therein and all proceeds of the foregoing. Such deposit shall constitute cash collateral for the Term Benchmark Loans to be so prepaid; provided that the Borrower may at any time direct that such deposit be applied to make the applicable payment required pursuant to this Section 5.2.

(f)Application of Proceeds. The application of proceeds pursuant to this Section 5.2 shall not reduce the aggregate amount of Commitments under the Facility and amounts prepaid may be reborrowed subject to the Available Commitment.

5.3Method and Place of Payment.

(a)All payments under this Agreement shall be made by the Borrower without set-off, counterclaim or deduction of any kind. Unless otherwise specifically provided herein, all such payments shall be made to the Administrative Agent for the ratable account of the Lenders entitled thereto or the Issuing Banks or the Swingline Lender entitled thereto, as the case may be, not later than 2:00 p.m. (New York City time), in each case, on the date when due and shall be made in immediately available funds at the Administrative Agent’s Office or at such other office as the Administrative Agent shall specify for such purpose by notice to the Borrower, it being understood that written or facsimile notice by the Borrower to the Administrative Agent to make a payment from the funds in the Borrower’s account at the Administrative Agent’s Office shall constitute the making of such payment to the extent of such funds held in such account. All repayments or prepayments of any Loans (whether of principal, interest or otherwise) hereunder and all other payments under each Credit Document shall be made in Dollars. The Administrative Agent will thereafter cause to be distributed on the same day (if payment was actually received by the Administrative Agent prior to 2:00 p.m. (New York City time) or, otherwise, on the next Business Day in the sole discretion of the Administrative Agent) like funds relating to the payment of principal or interest or fees ratably to the Lenders or the Issuing Banks, as applicable, entitled thereto.

(b)For purposes of computing interest or fees, any payments under this Agreement that are made later than 2:00 p.m. (New York City time) shall be deemed to have been made on the next succeeding Business Day in the sole discretion of the Administrative Agent. Whenever any payment to be made hereunder shall be stated to be due on a day that is not a Business Day, the due date thereof shall be extended to the next succeeding Business Day and, with respect to payments of principal, interest shall be payable during such extension at the applicable rate in effect immediately prior to such extension.

5.4Net Payments.

(a)Any and all payments made by or on behalf of the Borrower or any Guarantor under this Agreement or any other Credit Document shall be made free and clear of, and without deduction or withholding for or on account of, any Taxes; provided that if the Borrower, any Guarantor, the Administrative Agent or any other applicable withholding agent shall be required by applicable Requirements of Law to deduct or withhold any Taxes from such payments, then (i) the applicable withholding agent shall make such deductions or withholdings as are reasonably determined by the applicable withholding agent to be required by any applicable Requirement of Law, (ii) the applicable withholding agent shall timely pay the full amount deducted or withheld to the relevant Governmental Authority within the time allowed and in accordance with applicable Requirements of Law, and (iii) to the extent withholding or deduction is required to be made on account of Indemnified Taxes or Other Taxes, the sum payable by the Borrower or such Guarantor shall be increased as necessary so that after all required deductions and withholdings have been made (including deductions or withholdings applicable to additional sums payable under this Section 5.4) the Administrative Agent, the Collateral Agent, or the applicable Issuing Bank or Lender, as the case may be, receives an amount equal to the sum it would have received had no such deductions or withholdings been made. Whenever any Indemnified Taxes or Other Taxes are payable by the Borrower or such Guarantor, as promptly as possible thereafter, the Borrower or Guarantor shall send to the Administrative Agent for its own account or for the account of such Issuing Bank or Lender, as the case may be, a certified copy of an official receipt (or other evidence acceptable to such Issuing Bank or Lender, acting reasonably) received by the Borrower or such Guarantor showing payment thereof. Without duplication, after any payment of Taxes by any Credit Party or the Administrative Agent to a Governmental Authority as provided in this Section 5.4, the Borrower shall deliver to the Administrative Agent or the Administrative Agent shall deliver to the Borrower, as the case may be, a copy of a receipt issued by such Governmental Authority evidencing such payment, a copy of any return required by laws to report such payment or other evidence of such payment reasonably satisfactory to the Borrower or the Administrative Agent, as the case may be.

(b)The Borrower shall timely pay and shall indemnify and hold harmless the Administrative Agent, the Collateral Agent and each Lender with regard to any Other Taxes (whether or not such Other Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority).

(c)The Borrower shall indemnify and hold harmless the Administrative Agent, the Collateral Agent and each Lender within 15 Business Days after written demand therefor, for the full amount of any Indemnified Taxes or Other Taxes imposed on the Administrative Agent, the Collateral Agent or such Lender, as the case may be (including Indemnified Taxes or Other Taxes imposed or asserted on or attributable to amounts payable under this Section 5.4), and any reasonable expenses arising therefrom or with respect thereto, whether or not such Indemnified Taxes or Other Taxes were correctly or legally imposed or asserted by the relevant Governmental Authority. A certificate setting forth in reasonable detail the basis and calculation of the amount of such payment or liability delivered to the Borrower by a Lender, the Administrative Agent or the Collateral Agent (as applicable) on its own behalf or on behalf of a Lender shall be conclusive absent manifest error.

(d)Each Lender shall deliver to the Borrower and the Administrative Agent, at such time or times reasonably requested by the Borrower or the Administrative Agent, such properly completed and executed documentation prescribed by applicable law and such other reasonably requested information as will permit the Borrower or the Administrative Agent, as the case may be, to determine (i) whether or not any payments made hereunder or under any other Credit Document are subject to Taxes, (ii) if applicable, the required rate of withholding or deduction, and (iii) such Lender’s entitlement to any available exemption from, or reduction of, applicable Taxes in respect of any payments to be made to such Lender by any Credit Party pursuant to any Credit Document or otherwise to establish such Lender’s status for withholding tax purposes in the applicable jurisdiction. In addition, any Lender, if requested by the Borrower or the Administrative Agent, shall deliver such other documentation prescribed by applicable law or reasonably requested by the Borrower or the Administrative Agent as will enable the Borrower or the Administrative Agent to determine whether or not such Lender is subject to backup withholding or information reporting requirements.

(e)Without limiting the generality of Section 5.4(d), each Non-U.S. Lender with respect to any Loan made to the Borrower shall, to the extent it is legally eligible to do so:

(i)deliver to the Borrower and the Administrative Agent, prior to the date on which the first payment to the Non-U.S. Lender is due hereunder, two copies of (A) in the case of a Non-U.S. Lender claiming exemption from U.S. federal withholding tax under Section 871(h) or 881(c) of the Code with respect to payments of “portfolio interest”, United States Internal Revenue Service Form W-8BEN (or any applicable successor form) (together with a certificate (substantially in the form of Exhibit K hereto) representing that such Non-U.S. Lender is not a bank for purposes of Section 881(c) of the Code, is not a “10-percent shareholder” (within the meaning of Section 871(h) (3)(B) of the Code) of the Borrower, is not a CFC related to the Borrower (within the meaning of Section 864(d)(4) of the Code) and the interest payments in question are not effectively connected with the conduct by such Lender of a trade or business within the United States), (B) Internal Revenue Service Form W-8BEN or Form W-8ECI (or any applicable successor form), in each case properly completed and duly executed by such Non-U.S. Lender claiming complete exemption from, or reduced rate of, U.S. federal withholding tax on payments by the Borrower under this Agreement, (C) Internal Revenue Service Form W-8IMY (or any applicable successor form) and all necessary attachments (including the forms described in clauses (A) and (B) above, provided that if the Non-U.S. Lender is a partnership, and one or more of the partners is claiming portfolio interest treatment, the Non-Bank Tax Certificate substantially in the form of Exhibit K may be provided by such Non-U.S. Lender on behalf of such partners) or (D) any other form prescribed by applicable law as a basis for claiming exemption from or a reduction in United States federal withholding tax duly completed together with such supplementary documentation as may be prescribed by applicable law to permit the Borrower to determine the withholding or deduction required to be made; and

(ii)deliver to the Borrower and the Administrative Agent two further copies of any such form or certification (or any applicable successor form) on or before the date that any such form or certification expires or becomes obsolete or invalid, after the occurrence of any event requiring a change in the most recent form previously delivered by it to the Borrower and the Administrative Agent, and from time to time thereafter if reasonably requested by the Borrower or the Administrative Agent.

Any Non-U.S. Lender that becomes legally ineligible to update any form or certification previously delivered shall promptly notify the Borrower and the Administrative Agent in writing of such Non-U.S. Lender’s inability to do so.

Each Person that shall become a Participant pursuant to Section 13.6 or a Lender pursuant to Section 13.6 shall, upon the effectiveness of the related transfer, be required to provide all the forms and statements required pursuant to this Section 5.4(e); provided that in the case of a Participant such Participant shall furnish all such required forms and statements to the Person from which the related participation shall have been purchased.

In addition, to the extent it is legally eligible to do so, each Agent shall deliver to the Borrower (x)(I) prior to the date on which the first payment by the Borrower is due hereunder or (II) prior to the first date on or after the date on which such Agent becomes a successor Agent pursuant to Section 12.9 on which payment by the Borrower is due hereunder, as applicable, two copies of a properly completed and executed IRS Form W-9 certifying its exemption from U.S. Federal backup withholding or a properly completed and executed applicable IRS Form W-8 certifying its non-U.S. status and its entitlement to any treaty benefits, and (y) on or before the date on which any such previously delivered documentation expires or becomes obsolete or invalid, after the occurrence of any event requiring a change in the most recent documentation previously delivered by it to the Borrower, and from time to time if reasonably requested by the Borrower, two further copies of such documentation.

(f)If any Lender, any Issuing Bank, the Administrative Agent or the Collateral Agent, as applicable, determines, in its sole discretion, that it had received a refund of an Indemnified Tax or Other Tax for which a payment has been made by the Borrower or any Guarantor pursuant to this Agreement or any other Credit Document, which refund in the good faith judgment of such Lender, such Issuing Bank, the Administrative Agent or the Collateral Agent, as the case may be, is attributable to such payment made by the Borrower or any Guarantor, then the Lender, the Issuing Bank, the Administrative Agent or the Collateral Agent, as the case may be, shall reimburse the Borrower or such Guarantor for such amount (net of all reasonable out-of-pocket expenses of such Lender, such Issuing Bank, the Administrative Agent or the Collateral Agent, as the case may be, and without interest other than any interest received thereon from the relevant Governmental Authority with respect to such refund) as the Lender, the Issuing Bank, the Administrative Agent or the Collateral Agent, as the case may be, determines in its sole discretion to be the proportion of the refund as will leave it, after such reimbursement, in no better or worse position (taking into account expenses or any taxes imposed on the refund) than it would have been in if the payment had not been required; provided that the Borrower or such Guarantor, upon the request of the Lender, the Issuing Bank, the Administrative Agent or the Collateral Agent, agrees to repay the amount paid over to the Borrower or such Guarantor (plus any penalties, interest or other charges imposed by the relevant Governmental Authority) to the Lender, the Issuing Bank, the Administrative Agent or the Collateral Agent in the event the Lender, the Issuing Bank, the Administrative Agent or the Collateral Agent is required to repay such refund to such Governmental Authority. In such event, such Lender, such Issuing Bank, the Administrative Agent or the Collateral Agent, as the case may be, shall, at the Borrower’s request, provide the Borrower with a copy of any notice of assessment or other evidence of the requirement to repay such refund received from the relevant Governmental Authority (provided that such Lender, such Issuing Bank, the Administrative Agent or the Collateral Agent may delete any information therein that it deems confidential). A Lender, an Issuing Bank, the Administrative Agent or the Collateral Agent shall claim any refund that it determines is available to it, unless it concludes in its sole discretion that it would be adversely affected by making such a claim. No Lender nor any Issuing Bank nor the Administrative Agent nor the Collateral Agent shall be obliged to make available its tax returns (or any other information relating to its taxes that it deems confidential) to any Credit Party in connection with this clause (f) or any other provision of this Section 5.4.

(g)If the Borrower determines that a reasonable basis exists for contesting an Indemnified Tax or Other Tax for which a Credit Party has paid additional amounts or indemnification payments, each Lender or Agent, as the case may be, shall use reasonable efforts to cooperate with the Borrower as the Borrower may reasonably request in challenging such Tax. The Borrower shall indemnify and hold each Lender and Agent harmless against any out-of- pocket expenses incurred by such Person in connection with any request made by the Borrower pursuant to this Section 5.4(g). Nothing in this Section 5.4(g) shall obligate any Lender or Agent to take any action that such Person, in its sole judgment, determines may result in a material detriment to such Person.

(h)Each U.S. Lender shall deliver to the Borrower and the Administrative Agent two Internal Revenue Service Forms W-9 (or substitute or successor form), properly completed and duly executed, certifying that such U.S. Lender is exempt from United States federal backup withholding (i) on or prior to the Closing Date (or on or prior to the date it becomes a party to this Agreement), (ii) on or before the date that such form expires or becomes obsolete or invalid, (iii) after the occurrence of a change in the U.S. Lender’s circumstances requiring a change in the most recent form previously delivered by it to the Borrower and the Administrative Agent, and (iv) from time to time thereafter if reasonably requested by the Borrower or the Administrative Agent. Any U.S. Lender that becomes legally ineligible to update any form or certification previously delivered shall promptly notify the Borrower and the Administrative Agent in writing of such U.S. Lender’s inability to do so.

(i)If a payment made to any Lender or any Agent under this Agreement or any other Credit Document would be subject to U.S. federal withholding tax imposed by FATCA if such Lender or such Agent were to fail to comply with the applicable reporting requirements of FATCA (including those contained in Section 1471(b) or 1472(b) of the Code, as applicable), such Lender or such Agent shall deliver to the Borrower and the Administrative Agent at the time or times prescribed by law and at such time or times reasonably requested by the Borrower or the Administrative Agent such documentation prescribed by applicable law (including as prescribed by Section 1471(b)(3)(C)(i) of the Code) and such additional documentation reasonably requested by the Borrower or the Administrative Agent as may be necessary for the Borrower and the Administrative Agent to comply with their obligations under FATCA, to determine whether such Lender has or has not complied with such Lender’s obligations under FATCA or to determine the amount, if any, to deduct and withhold from such payment. Solely for purposes of this Section 5.4(i), “FATCA” shall include any amendments made to FATCA after the date of this Agreement.

(j)For the avoidance of doubt, for purposes of this Section 5.4, the term “Lender” includes any Issuing Bank and any Swingline Lender.

(k)The agreements in this Section 5.4 shall survive the termination of this Agreement and the payment of the Loans and all other amounts payable hereunder.

5.5Computations of Interest and Fees.

(a)Except as provided in the next succeeding sentence, Interest on all Loans shall be calculated on the basis of a 360-day year for the actual days elapsed. Interest on ABR Loans in respect of which the rate of interest is calculated on the basis of the Prime Rate shall be calculated on the basis of a 365- (or 366-, as the case may be) day year for the actual days elapsed. All interest hereunder on any Loan shall be computed on a daily basis based upon the outstanding principal amount of such Loan as of the applicable date of determination. A determination of the applicable Alternate Base Rate, Adjusted Term SOFR Rate, Term SOFR Rate, Adjusted Daily Simple SOFR or Daily Simple SOFR shall be determined by the Administrative Agent, and such determination shall be conclusive absent manifest error.

(b)Fees and the average daily Stated Amount of Letters of Credit shall be calculated on the basis of a 360-day year for the actual days elapsed.

5.6Limit on Rate of Interest.

(a)No Payment Shall Exceed Lawful Rate. Notwithstanding any other term of this Agreement, the Borrower shall not be obligated to pay any interest or other amounts under or in connection with this Agreement or otherwise in respect to any of the Obligations in excess of the amount or rate permitted under or consistent with any applicable law, rule or regulation.

(b)Payment at Highest Lawful Rate. If the Borrower is not obliged to make a payment that it would otherwise be required to make, as a result of Section 5.6(a), the Borrower shall make such payment to the maximum extent permitted by or consistent with applicable laws, rules and regulations.

(c)Adjustment if Any Payment Exceeds Lawful Rate. If any provision of this Agreement or any of the other Credit Documents would obligate the Borrower or any other Credit Party to make any payment of interest or other amount payable to any Lender in an amount or calculated at a rate that would be prohibited by any applicable Requirement of Law, then notwithstanding such provision, such amount or rate shall be deemed to have been adjusted with retroactive effect to the maximum amount or rate of interest, as the case may be, as would not be so prohibited by applicable Requirements of Law, such adjustment to be effected, to the extent necessary, by reducing the amount or rate of interest required to be paid by the Borrower to the affected Lender under Section 2.8.

(d)Rebate of Excess Interest. Notwithstanding the foregoing, and after giving effect to all adjustments contemplated thereby, if any Lender shall have received from the Borrower an amount in excess of the maximum permitted by any applicable Requirement of Law, then the Borrower shall be entitled, by notice in writing to the Administrative Agent to obtain reimbursement from that Lender in an amount equal to such excess, and pending such reimbursement, such amount shall be deemed to be an amount payable by that Lender to the Borrower.

Section 6.Conditions Precedent to Initial Borrowing.

The initial Borrowing under this Agreement is subject to the satisfaction of the following conditions precedent, except as otherwise agreed or waived pursuant to Section 13.1.

(a)The Administrative Agent (or its counsel) shall have received from each party hereto either (i) a counterpart of this Agreement signed on behalf of such party or (ii) written evidence satisfactory to the Administrative Agent (which may include telecopy transmission of a signed signature page of this Agreement) that such party has signed a counterpart of this Agreement.

(b)The Administrative Agent shall have received, on behalf of itself and the Secured Parties on the Closing Date, a written opinion of (i) Vinson & Elkins LLP, counsel to the Credit Parties, and (ii) each local counsel specified on Schedule 6(b), in each case (A) dated the Closing Date, (B) addressed to the Administrative Agent, the Collateral Agent, the Lenders and each Issuing Bank and (C) in form and substance reasonably satisfactory to the Administrative Agent. The Borrower, the other Credit Parties and the Administrative Agent hereby instruct such counsels to deliver such legal opinions.

(c)The Administrative Agent shall have received, in the case of each Credit Party, each of the items referred to in subclauses (i), (ii) and (iii) below:

(i)a copy of the certificate or articles of incorporation, certificate of limited partnership or certificate of formation, including all amendments thereto, of each Credit Party, in each case, certified as of a recent date by the Secretary of State (or other similar official) of the jurisdiction of its organization, and a certificate as to the good standing (to the extent such concept or a similar concept exists under the laws of such jurisdiction) of each such Credit Party as of a recent date from such Secretary of State (or other similar official);

(ii)a certificate of the Secretary or Assistant Secretary or similar officer of each Credit Party dated the Closing Date and certifying:

(A)that attached thereto is a true and complete copy of the bylaws (or partnership agreement, limited liability company agreement or other equivalent governing documents) of such Credit Party as in effect on the Closing Date and at all times immediately prior to and after the date of the resolutions described in clause (B) below,

(B)that attached thereto is a true and complete copy of resolutions duly adopted by the board of directors (or managing general partner, managing member or equivalent) of such Credit Party authorizing the execution, delivery and performance of the Credit Documents to which such person is a party and, in the case of the Borrower, the borrowings hereunder, and that such resolutions have not been modified, rescinded or amended and are in full force and effect on the Closing Date,

(C)that the certificate or articles of incorporation, certificate of limited partnership, articles of incorporation or certificate of formation of such Credit Party has not been amended since the date of the last amendment thereto disclosed pursuant to subclause (i) above,

(D)as to the incumbency and specimen signature of each officer executing any Credit Document or any other document delivered in connection herewith on behalf of such Credit Party, and

(E)as to the absence of any pending proceeding for the dissolution or liquidation of such Credit Party; and

(iii)a certificate of a director or an officer as to the incumbency and specimen signature of the Secretary or Assistant Secretary or similar officer executing the certificate pursuant to subclause (ii) above.

(d)The Guarantee shall be in full force and effect.

(e)Except for any items referred to on Schedule 9.13(b):

(i)The Collateral Agreement, all other Security Documents and other documents and instruments, including Uniform Commercial Code or other applicable personal property and financing statements, reasonably requested by the Collateral Agent to be filed, registered or recorded to create the Liens intended to be created by any Security Document and perfect such Liens to the extent required by, and with the priority required by, such Security Document shall have been delivered to the Collateral Agent for filing, registration or recording and none of the

Collateral shall be subject to any other pledges, security interests or mortgages, except for Liens permitted under Section 10.2.

(ii)All Equity Interests of the Borrower and all Equity Interests of each Material Subsidiary directly owned by the Borrower or any Subsidiary Guarantor, in each case as of the Closing Date, shall have been pledged pursuant to the Collateral Agreement (except that such Credit Parties shall not be required to pledge any Excluded Equity Interests) and the Collateral Agent shall have received all certificates, if any, representing such securities pledged under the Collateral Agreement, accompanied by instruments of transfer and/or undated powers endorsed in blank.

(iii)Except with respect to intercompany Indebtedness, all evidences of Indebtedness for borrowed money in a principal amount in excess of $10,000,000 (individually) that is owing to the Borrower or any Subsidiary Guarantor shall be evidenced by a promissory note and shall have been pledged pursuant to the Collateral Agreement, and the Collateral Agent shall have received all such promissory notes, together with undated instruments of transfer with respect thereto endorsed in blank.

(iv)All Indebtedness of the Borrower and each of the Restricted Subsidiaries that is owing to any Credit Party shall be evidenced by the Intercompany Note, which shall be executed and delivered by the Borrower and each of the Restricted Subsidiaries and shall have been pledged pursuant to the Collateral Agreement, and the Collateral Agent shall have received such Intercompany Note, together with undated instruments of transfer with respect thereto endorsed in blank.

(f)Each of the Corporate Reorganization and Merger Transactions, the 2018 Junior Lien Note Exchange and each other transaction contemplated under the Transaction Agreement, shall have been consummated, or substantially simultaneously with the initial Borrowing under this Agreement, will be consummated, in all material respects in accordance with the terms of the Transaction Agreement, without giving effect to any modification, consent or waiver thereto that is materially adverse to the interests of the Administrative Agent, the Collateral Agent or the Lenders (in their capacities as such) without the consent of each of the Administrative Agent, the Collateral Agent and the Lenders.

(g)[Intentionally Blank.]

(h)The Administrative Agent shall have received (i) true, correct and complete copies of the Historical Financial Statements, (ii) a pro forma balance sheet as of December 31, 2017, for the Borrower and its Restricted Subsidiaries after giving effect to the Transactions, and (iii) a pro forma capitalization table of the Borrower and its Restricted Subsidiaries after giving effect to the Transactions.

(i)On the Closing Date, the Administrative Agent shall have received a solvency certificate substantially in the form of Exhibit J hereto and signed by a Financial Officer of the Borrower.

(j)The Agents shall have received all fees payable thereto or to any Lender (including any agent and arranger in respect of this Facility) on or prior to the Closing Date and, to the extent invoiced at least three (3) Business Days prior to the Closing Date, all other amounts due and payable pursuant to the Credit Documents on or prior to the Closing Date, including, to the extent invoiced, reimbursement or payment of all reasonable out-of-pocket expenses (including reasonable fees, charges and disbursements of Mayer Brown LLP) required to be reimbursed or paid by the Credit Parties hereunder or under any Credit Document.

(k)The Administrative Agent and the Lenders shall have received, at least three (3) Business Days prior to the Closing Date, all documentation and other information about the Borrower and the Guarantors as has been reasonably requested in writing at least five (5) Business Days prior to the Closing Date by the Administrative Agent and the Lenders that they reasonably determine is required by regulatory authorities under applicable “know your customer” and anti-money laundering rules and regulations, including without limitation the PATRIOT Act.

(l)Since December 31, 2017, no change, event, circumstance, development, state of facts, or condition shall have occurred (or existed, as applicable) that would, individually or in the aggregate, be reasonably expected to have a Material Adverse Effect.

(m)The Administrative Agent and each of the Lenders shall have received the Initial Reserve Report and the Closing Date Reserve Report.

(n)The Administrative Agent shall have received, in the case of a Borrowing, a Borrowing Request as required by Section 2.3(a)(i) or, in the case of a Letter of Credit extension, the applicable Issuing Bank and the Administrative Agent shall have received a Letter of Credit Application as required by Section 3.2(a).

(o)The Administrative Agent shall have received the Intercreditor Agreement executed and delivered by the Borrower, each Subsidiary Guarantor, and each other representative of the 2018 Junior Lien Notes.

(p)The Administrative Agent shall have received Mortgages, executed and delivered by a duly Authorized Officer of the applicable Credit Parties in sufficient counterparts for the prompt recordation thereof, encumbering Mortgaged Properties that constitute Borrowing Base Properties evaluated in the Initial Reserve Report having a PV-10 sufficient to satisfy the Collateral Coverage Minimum.

(q)After giving effect to all Loans to be made and Letters of Credit to be issued hereunder and the consummation of the Transactions on the date of the initial Credit Event, Availability shall be not less than $300,000,000.

(r)The Administrative Agent shall have received (i) customary UCC lien search results with respect to the Borrower and the other Credit Parties in their respective jurisdictions of formation and (ii) county-level real property search results for the counties in which the Borrowing Base Properties are located.

(s)No litigation by any Person or Governmental Authority shall be pending or threatened (i) with respect to the Transaction Agreement or the Transactions contemplated therein, this Agreement or any Credit Document or (ii) that the Administrative Agent shall determine has had, or could reasonably be expected to have, a Material Adverse Effect or materially and adversely affect this Agreement or the Collateral.

(t)The Administrative Agent shall be reasonably satisfied with the environmental condition of the Borrowing Base Properties.

(u)The Administrative Agent shall have received satisfactory title information with respect to Oil and Gas Properties of the Borrower and its Restricted Subsidiaries (including Stone Energy and its Subsidiaries) comprising at least 85% of the PV‑10 of all of the Proved Reserves evaluated in the Initial Reserve Report.

(v)The Administrative Agent shall have received copies of insurance certificates, if applicable, evidencing the insurance required to be maintained by the Borrower and the Subsidiaries pursuant to Section 9.3, each of which shall name the Secured Parties as additional insureds on any such liability insurance and name the Collateral Agent as additional loss payee under any such property insurance, in each case in form and substance reasonably satisfactory to the Administrative Agent.

(w)The Administrative Agent shall have received the schedule of Hedge Transactions described in Section 8.20 prepared as of a reasonably recent date (not exceeding ten (10) Business Days prior to the Closing Date).

(x)After giving effect to the Transactions, none of Holdings, the Borrower or its or their Restricted Subsidiaries shall have any outstanding Indebtedness or preferred Equity Interests other than (i) the Loans and Letters of Credit, (ii) the 2018 Junior Lien Notes, (iii) the Stone Energy Notes, and (iv) other Indebtedness permitted under Section 10.1.

(y)The Administrative Agent shall have received duly executed mortgage releases and terminations, terminations of any financing statements and terminations of control agreements, with respect to any and all Liens, in each case, encumbering the properties or assets (including Oil and Gas Properties) of the Borrower or its Restricted Subsidiaries (including Stone Energy and its Subsidiaries), including, without limitation, any mortgages, financing statements, control agreements and other security documents securing the Existing Credit Agreements, except to the extent any such Lien constitutes a Permitted Lien.

(z)The Administrative Agent and the Lenders shall have completed with satisfactory results all other business, legal, environmental, tax, financial and accounting due diligence with respect to the Borrower and its Restricted Subsidiaries, Stone Energy and its Subsidiaries and the Transactions.

The Administrative Agent shall notify the Borrower, the Issuing Banks and the Lenders of the Closing Date, and such notice shall be conclusive and binding. Notwithstanding the foregoing, the obligations of the Lenders to make Loans and of the Issuing Banks to issue Letters of Credit hereunder shall not become effective unless each of the foregoing conditions is satisfied (or waived pursuant to Section 13.1) at or prior to 11:59 p.m., New York City time, on May 31, 2018 (and, in the event such conditions are not so satisfied or waived, the Commitments shall terminate at such time).

Section 7.Conditions Precedent to All Subsequent Credit Events.

The agreement of each Lender to make any Loan requested to be made by it (including on the Closing Date) (excluding Mandatory Borrowings and Loans required to be made by the Lenders in respect of Unpaid Drawings pursuant to Sections 3.3 and 3.4), and the obligation of any Issuing Bank to issue Letters of Credit on any date (other than any Existing Letter of Credit) after the Closing Date, is subject to the satisfaction of the following conditions precedent:

(a)At the time of each such Credit Event and also after giving effect thereto, (i) no Default or Event of Default shall have occurred and be continuing and (ii) all representations and warranties made by any Credit Party contained herein or in the other Credit Documents shall be true and correct in all material respects (or, with respect to any such representations and warranties already qualified by materiality, Material Adverse Effect or a similar qualification, in all respects) with the same effect as though such representations and warranties had been made on and as of the date of such Credit Event (except where such representations and warranties expressly relate to an earlier date, in which case such representations and warranties shall have been true and correct in all material respects (or, if already qualified by materiality, in all respects) as of such earlier date).

(b)Prior to the making of each Loan (other than any Loan made pursuant to Section 3.4(a)) and each Swingline Loan, the Administrative Agent shall have received a Notice of Borrowing (whether in writing or by telephone) meeting the requirements of Section 2.3(a).

(c)Prior to the issuance of each Letter of Credit (other than any Existing Letter of Credit), the Administrative Agent and the applicable Issuing Bank shall have received a Letter of Credit Application meeting the requirements of Section 3.2(a).

(d)No Excess Cash. At the time of each Borrowing and also after giving effect thereto, the Borrower and the Restricted Subsidiaries, taken as a whole, shall not have any Excess Cash. No Borrowing shall, after giving pro forma effect to any intended use of proceeds in the ordinary course of business, be in an amount that would trigger a mandatory prepayment under Section 5.2(c). Any Notice of Borrowing delivered by the Borrower shall include a certification (i) as to the intended use of proceeds from such Borrowing and (ii) that the conditions set forth in this Section 7(d) shall be satisfied (A) as of the date of such Notice of Borrowing and (B) after giving effect to the requested Borrowing.

The acceptance of the benefits of each Credit Event after the Closing Date shall constitute a representation and warranty by each Credit Party to each of the Lenders that all the applicable conditions specified in Section 7 above have been satisfied as of that time.

Section 8.Representations, Warranties and Agreements

In order to induce the Lenders to enter into this Agreement, to make the Loans and issue or participate in Letters of Credit as provided for herein, each of Holdings and the Borrower makes, on the date of each Credit Event, the following representations and warranties to, and agreements with, the Lenders, all of which shall survive the execution and delivery of this Agreement and the making of the Loans and the issuance of the Letters of Credit:

8.1Corporate Status. Each of the Borrower, each Guarantor and each Material Subsidiary (a) is a duly organized and validly existing corporation or other entity in good standing (or, if applicable in a foreign jurisdiction, enjoys the equivalent status under the laws of such jurisdiction of organization outside the United States) under the laws of the jurisdiction of its organization and has the corporate or other organizational power and authority to own its property and assets and to transact its business as now conducted and (b) has duly qualified and is authorized to do business and is in good standing (if applicable) in all jurisdictions where it is required to be so qualified, except where the failure to be so qualified would not reasonably be expected to have a Material Adverse Effect.

8.2Corporate Power and Authority; Enforceability. Each Credit Party has the corporate or other organizational power and authority to execute, deliver and carry out the terms and provisions of the Credit Documents to which it is a party and has taken all necessary corporate or other organizational action to authorize the execution, delivery and performance of the Credit Documents to which it is a party. Each Credit Party has duly executed and delivered each Credit Document to which it is a party and each such Credit Document constitutes the legal, valid and binding obligation of such Credit Party enforceable in accordance with its terms, subject to the effects of bankruptcy, insolvency, fraudulent conveyance, reorganization and other similar laws relating to or affecting creditors’ rights generally and general principles of equity (whether considered in a proceeding in equity or law).

8.3No Violation. None of the execution, delivery or performance by any Credit Party of the Credit Documents to which it is a party or the compliance with the terms and provisions thereof will contravene any

Requirement of Law except to the extent such contravention would not reasonably be expected to result in a Material Adverse Effect, result in any breach of any of the terms, covenants, conditions or provisions of, or constitute a default under, or result in the creation or imposition of (or the obligation to create or impose) any Lien upon any of the property or assets of such Credit Party or any of the Restricted Subsidiaries (other than Liens created under the Credit Documents and Liens permitted hereunder) pursuant to the terms of any indenture, loan agreement, lease agreement, mortgage, deed of trust, agreement or other instrument to which such Credit Party or any of the Restricted Subsidiaries is a party or by which it or any of its property or assets is bound (any such term, covenant, condition or provision, a “Contractual Requirement”) except to the extent such breach, default or Lien that would not reasonably be expected to result in a Material Adverse Effect or violate any provision of the certificate of incorporation, by-laws or other organizational documents of such Credit Party or any of the Restricted Subsidiaries.

8.4Litigation. Except as set forth on Schedule 8.4, there are no actions, suits or proceedings (including Environmental Claims) pending or, to the knowledge of either Holdings or the Borrower, threatened with respect to Holdings, the Borrower or any of its Restricted Subsidiaries that would reasonably be expected to result in a Material Adverse Effect.

8.5Margin Regulations. Neither the making of any Loan hereunder nor the use of the proceeds thereof will violate the provisions of Regulation T, Regulation U or Regulation X of the Board.

8.6Governmental Approvals. The execution, delivery and performance of each Credit Document do not require any consent or approval of, registration or filing with, or other action by, any Governmental Authority, except for (a) such as have been obtained or made and are in full force and effect, (b) filings and recordings in respect of the Liens created pursuant to the Security Documents and (c) such consents, approvals, registrations, filings or actions the failure of which to obtain or make would not reasonably be expected to have a Material Adverse Effect.

8.7Investment Company Act. No Credit Party is required to be registered as an “investment company” within the meaning of the Investment Company Act of 1940, as amended.

8.8True and Complete Disclosure.

(a)All written information (other than the Budget, estimates and information of a general economic nature or general industry nature) (the “Information”) concerning Holdings, the Intermediate Entities, the Borrower, the Subsidiaries, the Transactions and any other transactions contemplated hereby included in the Information Memorandum or otherwise prepared by or on behalf of the foregoing or their representatives and made available to any Lenders or the Administrative Agent in connection with the Transactions or the other transactions contemplated hereby, when taken as a whole, was true and correct in all material respects, as of the date such Information was furnished to the Lenders and as of the Closing Date (with respect to Information provided prior to the Closing Date) and did not, taken as a whole, contain any untrue statement of a material fact as of any such date or omit to state a material fact necessary in order to make the statements contained therein, taken as a whole, not materially misleading in light of the circumstances under which such statements were made. As of the First Amendment Effective Date, to the best knowledge of Holdings and of the Borrower, the information include in the Beneficial Ownership Certification provided on or prior to the First Amendment Effective Date to any Lender in connection with this Agreement is true and correct in all respects.

(b)The Budget and estimates and information of a general economic nature or general industry nature prepared by or on behalf of the Borrower or any of its representatives and that have been made available to any Lenders or the Administrative Agent in connection with the Transactions or the other transactions

contemplated hereby have been prepared in good faith based upon assumptions believed by the Borrower to be reasonable as of the date thereof (it being understood that actual results may vary materially from the Budget), as of the date such Budget and estimates were furnished to the Lenders and (with respect to any such Budget, estimates or information of a general economic nature or general industry nature provided prior to the Closing Date) as of the Closing Date.

8.9Financial Condition; Financial Statements.

(a)The Historical Financial Statements present fairly in all material respects the consolidated financial position of each of the Borrower and its consolidated Subsidiaries and Stone Energy and its consolidated Subsidiaries at the date of such information and for the period covered thereby and have been prepared in accordance with GAAP consistently applied except to the extent provided in the notes thereto, if any, subject, in the case of the unaudited financial information, to changes resulting from audit, normal year-end audit adjustments and to the absence of footnotes.

(b)As of the Closing Date (and after giving effect to the consummation of the Transactions), neither the Borrower nor any Restricted Subsidiary has any material Indebtedness (including Disqualified Stock), any material guarantee obligations, contingent liabilities, off balance sheet liabilities, partnership liabilities for taxes or unusual forward or long-term commitments that, in each case, are not reflected or provided for in the Historical Financial Statements or the pro forma financial statements referred to in Section 6.01(h), except as would not reasonably be expected to result in a Material Adverse Effect.

8.10Tax Matters. Except where the failure of which would not, individually or in the aggregate, be reasonably expected to have a Material Adverse Effect, (a) each of the Borrower and the Subsidiaries has filed all federal income Tax returns and all other Tax returns, domestic and foreign, required to be filed by it (including in its capacity as withholding agent) and has paid all Taxes payable by it that have become due, other than those (i) not yet delinquent or (ii) being contested in good faith by appropriate proceedings and as to which adequate reserves have been provided to the extent required by and in accordance with GAAP (or in the case of a Foreign Subsidiary, the comparable accounting principles in the relevant jurisdiction) and (b) the Borrower and each of the Subsidiaries have provided adequate reserves in accordance with GAAP (or in the case of a Foreign Subsidiary, the comparable accounting principles in the relevant jurisdiction) for all Taxes of the Borrower and the Subsidiaries not yet due and payable.

8.11Compliance with ERISA.

(a)Each Plan is in compliance with ERISA, the Code and any applicable Requirement of Law; no Reportable Event has occurred (or is reasonably likely to occur) with respect to any Plan; no Plan is “insolvent” (within the meaning of Section 4245 of ERISA) or in “reorganization” (within the meaning of Section 4245 of ERISA) (or is reasonably likely to be insolvent or in reorganization) or is in “endangered” or “critical” status (within the meaning of Section 432 of the Code or Section 305 of ERISA), and no written notice of any such insolvency, reorganization, or endangered or critical status has been given to the Borrower or, to the knowledge of the Borrower, any ERISA Affiliate; each Plan that is subject to Title IV of ERISA has satisfied the minimum funding standards (within the meaning of Section 412 of the Code or Section 302 of ERISA) applicable to such Plan, and there has been no determination that any such Plan is, or is expected to be, in “at risk” status (within the meaning of Section 303(i)(4) of ERISA); none of the Borrower or any ERISA Affiliate has incurred (or is reasonably likely to incur) any liability to or on account of a Plan pursuant to Section 409, 502(i), 502(l), 515, 4062, 4063, 4064, 4069, 4201 or 4204 of ERISA or Section 4971 or 4975 of the Code nor has the Borrower or, to the knowledge of the Borrower, any ERISA Affiliate, been notified in writing that it will incur any liability under any of the foregoing Sections with respect to any Plan; no proceedings have been instituted (or are

reasonably likely to be instituted) to terminate or to reorganize any Plan or to appoint a trustee to administer any Plan, and no written notice of any such proceedings has been given to the Borrower or, to the knowledge of the Borrower, any ERISA Affiliate; and no lien imposed under the Code or ERISA on the assets of the Borrower or any ERISA Affiliate exists (or is reasonably likely to exist) nor has the Borrower or, to the knowledge of the Borrower, any ERISA Affiliate been notified in writing that such a lien will be imposed on the assets of the Borrower or any ERISA Affiliate on account of any Plan, except to the extent that a breach of any of the representations or warranties in this Section 8.11(a) would not result, individually or in the aggregate, in an amount of liability that would be reasonably likely to have a Material Adverse Effect. No Plan (other than a Multiemployer Plan) has an Unfunded Current Liability that would, individually or when taken together with any other liabilities referenced in this Section 8.11(a), be reasonably likely to have a Material Adverse Effect. With respect to Plans that are Multiemployer Plans, the representations and warranties in this Section 8.11(a), other than any made with respect to (i) liability under Section 4201 or 4204 of ERISA or (ii) liability for “termination” or “reorganization” (within the meaning of Title IV of ERISA) of such Plans under ERISA, are made to the best knowledge of the Borrower.

(b)All Foreign Plans are in compliance with, and have been established, administered and operated in accordance with, the terms of such Foreign Plans and applicable law, except for any failure to so comply, establish, administer or operate the Foreign Plans as would not reasonably be expected to have a Material Adverse Effect. All contributions or other payments that are due with respect to each Foreign Plan have been made in full and there are no funding deficiencies thereunder, except to the extent any such events would not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect.

8.12Subsidiaries. Schedule 8.12 lists each Subsidiary of the Borrower (and the direct and indirect ownership interest of the Borrower therein), in each case existing on the Closing Date (after giving effect to the Transactions). Each Guarantor, Material Subsidiary and Unrestricted Subsidiary as of the Closing Date has been so designated on Schedule 8.12.

8.13Intellectual Property. The Borrower and each of the Restricted Subsidiaries own or have obtained valid rights to use all intellectual property, free from any burdensome restrictions, that is necessary for the operation of their respective businesses as currently conducted and as proposed to be conducted, except where the failure to obtain any such rights would not reasonably be expected to have a Material Adverse Effect. The operation of the respective businesses of the Borrower and each of the Restricted Subsidiaries, as currently conducted and as proposed to be conducted, do not infringe, misappropriate, violate or otherwise conflict with the proprietary rights of any third party have obtained all intellectual property, except as would not reasonably be expected to have a Material Adverse Effect.

8.14Environmental Laws. Except as would not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect:

(a)(i) the Borrower and each of the Subsidiaries and all Oil and Gas Properties are in compliance with all Environmental Laws; (ii) neither the Borrower nor any Subsidiary has received written notice of any Environmental Claim or any other liability under any Environmental Law; (iii) neither the Borrower nor any Subsidiary is conducting any investigation, removal, remedial or other corrective action pursuant to any Environmental Law at any location; and (iv) no underground storage tank or related piping, or any impoundment or disposal area containing Hazardous Materials has been used by the Borrower or any of its Subsidiaries or, to the knowledge of the Borrower, is located at, on or under any Oil and Gas Properties currently owned or leased by the Borrower or any of its Subsidiaries.

(b)Neither the Borrower nor any of the Subsidiaries has treated, stored, transported, released or disposed or arranged for disposal or transport for disposal of Hazardous Materials at, on, under or from any currently or formerly owned or leased Oil and Gas Properties or facility in a manner that would reasonably be expected to give rise to liability of the Borrower or any Subsidiary under Environmental Law.

8.15Properties.

(a)Each Credit Party has good and defensible title to the Borrowing Base Properties evaluated in the most recently delivered Reserve Report (other than those (i) in the case of the Initial Reserve Report, disposed of prior to the Closing Date and identified to the Administrative Agent in writing or, in the case of any Reserve Report delivered after the Closing Date, disposed of in compliance with Section 10.4 since delivery of such Reserve Report, (ii) leases that have expired in accordance with their terms and (iii) with title defects disclosed in writing to the Administrative Agent), and valid title to all its material personal properties, in each case, free and clear of all Liens other than Liens permitted by Section 10.2, except in each case where the failure to have such title would not reasonably be expected to have, individually or in the aggregate, a Material Adverse Effect. After giving full effect to the Liens permitted by Section 10.2, the Borrower or the Restricted Subsidiary specified as the owner owns the working interests and net revenue interests attributable to the Hydrocarbon Interests as reflected in the most recently delivered Reserve Report, and the ownership of such properties shall not in any material respect obligate the Borrower or such Restricted Subsidiary to bear the costs and expenses relating to the maintenance, development and operations of each such property in an amount in excess of the working interest of each property set forth in the most recently delivered Reserve Report that is not offset by a corresponding proportionate increase in the Borrower’s or such Restricted Subsidiary’s net revenue interest in such property.

(b)All material leases and agreements necessary for the conduct of the business of the Borrower and the Restricted Subsidiaries are valid and subsisting, in full force and effect, except to the extent that any such failure to be valid or subsisting would not reasonably be expected to have a Material Adverse Effect.

(c)The rights and properties presently owned, leased or licensed by the Credit Parties including all easements and rights of way, include all rights and properties necessary to permit the Credit Parties to conduct their respective businesses as currently conducted, except to the extent any failure to have any such rights or properties would not reasonably be expected to have a Material Adverse Effect.

(d)All of the properties of the Borrower and the Restricted Subsidiaries that are reasonably necessary for the operation of their businesses are in good working condition and are maintained in accordance with prudent business standards, except to the extent any failure to satisfy the foregoing would reasonably be expected to have a Material Adverse Effect.

8.16Solvency. On the Closing Date (after giving effect to the consummation of the Transactions (including the execution and delivery of this Agreement, the making of the Closing Date Loans and the use of proceeds of such Closing Date Loans on the Closing Date)), (i) the Borrower on a consolidated basis with its Restricted Subsidiaries will be Solvent and (ii) the Borrower does not intend to, and the Borrower does not believe that it or any of its Subsidiaries will, incur debts beyond its ability to pay such debts as they mature, taking into account the timing and amounts of cash to be received by it or any such Subsidiary and the timing and amounts of cash to be payable on or in respect of its debt or the debt of any such Subsidiary.

8.17Insurance. The properties of the Borrower and the Restricted Subsidiaries are insured in the manner contemplated by Section 9.3.

8.18Deposit Accounts; Securities Accounts; Commodities Accounts. Schedule 8.18 sets forth, as of the Closing Date, a true and complete list of all deposit accounts, securities accounts and commodities accounts of any Credit Party (including any Excluded Accounts on the Closing Date, which have been identified as such on Schedule 8.18).

8.19Creation of Liens. Upon the execution and delivery of the Security Documents in accordance herewith, the Liens granted and to be granted by any Credit Party to the Collateral Agent for the benefit of the Secured Parties, constitute validly created, and when the filing and recordation thereof with the appropriate filing or recording officers in each of the necessary jurisdictions has been completed, perfected and first priority Liens, subject only to Liens permitted to have priority under Section 10.2.

8.20Hedge Transactions. Schedule 8.20 sets forth, as of a reasonably recent date prior to the Closing Date, a true and complete list of all material commodity Hedge Transactions of each Credit Party, the material terms thereof (including the type, term, effective date, termination date and notional amounts or volumes), the net mark to market value thereof (as of the last Business Day of the most recent fiscal quarter preceding the Closing Date and for which a mark to market value is reasonably available), all credit support agreements relating thereto (including, to the extent permitted hereunder, any margin required or supplied) and the counterparty to each such agreement.

8.21Patriot Act; Sanctions; Anti-Corruption; Anti-Money Laundering.

(a)Each Credit Party is in compliance in all material respects with the material provisions of the Patriot Act, and the Borrower has provided to the Administrative Agent all information related to the Credit Parties (including but not limited to names, addresses and tax identification numbers (if applicable)) reasonably requested in writing by the Administrative Agent and mutually agreed to be required by the Patriot Act to be obtained by the Administrative Agent or any Lender.

(b)The Borrower has implemented and maintains in effect policies and procedures designed to ensure compliance by the Borrower, its Subsidiaries and their respective directors, officers, employees and agents with Anti-Corruption Laws, Anti-Money Laundering Laws and applicable Sanctions, and the Borrower, its Subsidiaries and their respective officers and directors and to the knowledge of the Borrower its employees and agents, are in compliance with Anti-Corruption Laws, Anti-Money Laundering Laws and applicable Sanctions in all material respects. None of (i) the Borrower, any Subsidiary or to the knowledge of the Borrower or such Subsidiary any of their respective directors, officers or employees, or (ii) to the knowledge of the Borrower, any agent of the Borrower or any Subsidiary that will act in any capacity in connection with or benefit from the credit facility established hereby, is a Sanctioned Person. No Borrowing or Letter of Credit, use of proceeds or other transaction contemplated by this Agreement will violate any Anti-Corruption Law, Anti-Money Laundering Laws or applicable Sanctions.

8.22No Material Adverse Effect. There has been no event or circumstance that has had or would reasonably be expected to have a Material Adverse Effect since December 31, 2017.

8.23Foreign Corrupt Practices Act. None of the Borrower or any of the Restricted Subsidiaries, nor, to the knowledge of the Borrower or any of the Restricted Subsidiaries, or any of their directors, officers, agents or employees has (a) used any corporate funds for any unlawful contribution, gift, entertainment or other unlawful expense relating to political activity, (b) made any direct or indirect unlawful payment to any government official or employee from corporate funds, (c) violated or is in violation of any provision of the U.S. Foreign Corrupt Practices Act of 1977 or the Bribery Act 2010 of the United Kingdom or similar law of the European Union or any European Union Member State or similar law of a jurisdiction in which the Borrower or any of the Restricted

Subsidiaries conduct their business and to which they are lawfully subject or (d) made any unlawful bribe, rebate, payoff, influence payment, kickback or other unlawful payment.

8.24Direct Benefit. The initial Borrowing hereunder and all additional Borrowings are for the direct benefit of the Borrower and its Restricted Subsidiaries. The Borrower and its Restricted Subsidiaries shall engage as an integrated group in the business of oil and gas exploration and related activities and certain other legal business purposes, and any benefits to the Borrower and its Restricted Subsidiaries is a benefit to all of them, both directly or indirectly, inasmuch as the successful operation and condition of the Borrower and its Restricted Subsidiaries is dependent upon the continued successful performance of the functions of the integrated group as a whole.

8.25Plan Assets; Prohibited Transactions. None of the Borrower or any of its Subsidiaries is an entity deemed to hold “plan assets” (within the meaning of the Plan Asset Regulations), and neither the execution, delivery nor performance of the transactions contemplated under this Agreement, including the making of any Loan and the issuance of any Letter of Credit hereunder, will give rise to a non-exempt prohibited transaction under Section 406 of ERISA or Section 4975 of the Code.

8.26Affected Financial Institutions. No Credit Party is an Affected Financial Institution.

Section 9.Affirmative Covenants.

The Borrower hereby covenants and agrees that on the Closing Date and thereafter, until the Total Commitment and each Letter of Credit have terminated (unless such Letters of Credit have been collateralized on terms and conditions reasonably satisfactory to each applicable Issuing Bank following the termination of the Total Commitment) and the Loans, the Swingline Loans and Unpaid Drawings, together with interest, fees and all other Obligations incurred hereunder (other than Hedging Obligations under Secured Hedge Transactions, Cash Management Obligations under Secured Cash Management Agreements or contingent indemnification obligations not then due and payable), are paid in full:

9.1Information Covenants. The Borrower will furnish (or in the case of Section 9.1(k), use commercially reasonable efforts to prepare and furnish) to the Administrative Agent (which shall promptly make such information available to the Lenders in accordance with its customary practice):

(a)Annual Financial Statements. Within five (5) Business Days after the date on which such financial statements are required to be filed with the SEC (after giving effect to any permitted extensions) (or, if such financial statements are not required to be filed with the SEC, on or before the date that is 105 days after the end of each such fiscal year), the audited consolidated balance sheets of the Borrower and the Subsidiaries and, if different, the Borrower and the Restricted Domestic Subsidiaries and, in each case as at the end of such fiscal year, and the related consolidated statements of operations, shareholders’ equity and cash flows for such fiscal year, setting forth comparative consolidated figures for the preceding fiscal years (or, in lieu of such audited financial statements of the Borrower and the Restricted Domestic Subsidiaries, a detailed reconciliation, reflecting such financial information for the Borrower and the Restricted Domestic Subsidiaries, on the one hand, and the Borrower and the Subsidiaries, on the other hand, reflecting adjustments necessary to eliminate the accounts of Unrestricted Subsidiaries (if any) and Restricted Subsidiaries that are not Restricted Domestic Subsidiaries (if any) from such consolidated financial statements) prepared in accordance with GAAP, and, except with respect to such reconciliation, certified by independent certified public accountants of recognized national standing whose opinion shall not be materially qualified with a “going concern” or like qualification or exception (other than with respect to, or resulting from, (x) the occurrence of the Maturity Date or the maturity date of the Junior Lien Notes, the EnVen Notes, any QuarterNorth Acquisition Debt, any Permitted Incremental Junior Lien Debt or any other

Permitted Additional Debt (or any Permitted Refinancing Indebtedness in respect of any of the foregoing) within one year from the date such opinion is delivered or (y) any potential inability to satisfy a Financial Performance Covenant on a future date or in a future period), together in any event, if the accounting firm is not restricted from providing such a certificate by its policies, with a certificate of such accounting firm stating that in the course of either (i) its regular audit of the business of the Borrower and its consolidated Subsidiaries, which audit was conducted in accordance with generally accepted auditing standards or (ii) performing certain other procedures permitted by professional standards, such accounting firm has obtained no knowledge of any Event of Default relating to a Financial Performance Covenant that has occurred and is continuing or, if in the opinion of such accounting firm such an Event of Default has occurred and is continuing, a statement as to the nature thereof. Notwithstanding the foregoing, the obligations in this Section 9.1(a) may be satisfied with respect to financial information of the Borrower and its consolidated Subsidiaries by furnishing (A) the applicable financial statements of any direct or indirect parent of the Borrower or (B) the Borrower’s (or any direct or indirect parent thereof), as applicable, Form 10-K filed with the SEC; provided that, with respect to each of clauses (A) and (B), (1) to the extent such information relates to a Parent Entity of the Borrower, such information is accompanied by consolidating information that explains in reasonable detail the differences between the information relating to such Parent Entity and its consolidated Subsidiaries, on the one hand, and the information relating to the Borrower and its consolidated Subsidiaries and the Borrower and its consolidated Restricted Domestic Subsidiaries on a standalone basis, on the other hand and (2) to the extent such information is in lieu of information required to be provided under the first sentence of this Section 9.1(a), such materials are accompanied by an opinion of an independent registered public accounting firm of recognized national standing, which opinion shall not be materially qualified with a “going concern” or like qualification or exception (other than with respect to, or resulting from, (x) the occurrence of the Maturity Date or the maturity date of the Junior Lien Notes, the EnVen Notes, any QuarterNorth Acquisition Debt, anyPermitted Incremental Junior Lien Debt or any other Permitted Additional Debt (or any Permitted Refinancing Indebtedness in respect of any of the foregoing) within one year from the date such opinion is delivered or (y) any potential inability to satisfy a Financial Performance Covenant on a future date or in a future period).

(b)Quarterly Financial Statements. Within five (5) Business Days after the date on which such financial statements are required to be filed with the SEC (after giving effect to any permitted extensions) with respect to each of the first three quarterly accounting periods in each fiscal year of the Borrower (or, if such financial statements are not required to be filed with the SEC, on or before the date that is 60 days after the end of each such quarterly accounting period), the consolidated balance sheets of the Borrower and the Subsidiaries and, if different, the Borrower and the Restricted Domestic Subsidiaries, in each case as at the end of such quarterly period and the related consolidated statements of operations, shareholders’ equity and cash flows for such quarterly accounting period and for the elapsed portion of the fiscal year ended with the last day of such quarterly period, and setting forth comparative consolidated figures for the related periods in the prior fiscal year or, in the case of such consolidated balance sheet, for the last day of the prior fiscal year (or, in lieu of such unaudited financial statements of the Borrower and the Restricted Domestic Subsidiaries, a detailed reconciliation reflecting such financial information for the Borrower and the Restricted Domestic Subsidiaries, on the one hand, and the Borrower and the Subsidiaries, on the other hand, reflecting adjustments necessary to eliminate the accounts of Unrestricted Subsidiaries (if any) and Restricted Subsidiaries that are not Restricted Domestic Subsidiaries (if any) from such consolidated financial statements), all of which shall be certified by a Financial Officer of the Borrower as fairly presenting in all material respects the financial condition, results of operations, shareholders’ equity and cash flows, of the Borrower and its consolidated Subsidiaries in accordance with GAAP, subject to changes resulting from audit and normal year-end audit adjustments and the absence of footnotes; provided that for the avoidance of doubt, the Borrower shall only be required to deliver the foregoing financial statements with respect to the fiscal quarter ended March 31, 2018, for the Borrower and its Subsidiaries (and if different, the Borrower and its Restricted Domestic Subsidiaries) without giving effect to the Transactions.

Notwithstanding the foregoing, the obligations in this Section 9.1(b) may be satisfied with respect to financial information of the Borrower and its consolidated Subsidiaries by furnishing (i) the applicable financial statements of any direct or indirect parent of the Borrower or (ii) the Borrower’s (or any direct or indirect parent thereof), as applicable, Form 10-Q filed with the SEC; provided that, with respect to each of clauses (i) and (ii), to the extent such information relates to a parent of the Borrower, such information is accompanied by consolidating information that explains in reasonable detail the differences between the information relating to such parent and its consolidated Subsidiaries, on the one hand, and the information relating to the Borrower and its consolidated Subsidiaries and the Borrower and its consolidated Restricted Domestic Subsidiaries on a standalone basis, on the other.

(c)Officer’s Certificates. At the time of the delivery of the financial statements provided for in Section 9.1(a) and Section 9.1(b), a certificate of a Financial Officer of the Borrower to the effect that no Default or Event of Default exists or, if any Default or Event of Default does exist, specifying the nature and extent thereof, which certificate shall set forth (i) beginning with the fiscal quarter ending September 30, 2018, the calculations required to establish whether the Borrower and its Restricted Domestic Subsidiaries were in compliance with a Financial Performance Covenant as at the end of such fiscal year or period, as the case may be, and (ii) a specification of any change in the identity of the Restricted Subsidiaries, Guarantors and Unrestricted Subsidiaries as at the end of such fiscal year or period, as the case may be, from the Restricted Subsidiaries, Guarantors and Unrestricted Subsidiaries, respectively, provided to the Lenders on the Closing Date or the most recent fiscal year or period, as the case may be.

(d)Notice of Default; Litigation; Beneficial Ownership Certification. Promptly after an Authorized Officer of the Borrower or any of the Restricted Subsidiaries obtains actual knowledge thereof, notice of (i) the occurrence of any Default or Event of Default, which notice shall specify the nature thereof, the period of existence thereof and what action the Borrower proposes to take with respect thereto, (ii) any litigation or governmental proceeding pending against the Borrower or any of the Subsidiaries that would reasonably be expected to be determined adversely and, if so determined, to result in a Material Adverse Effect and (iii) any change in the information provided in the Beneficial Ownership Certification delivered to such Lender that would result in a change to the list of beneficial owners identified in such certification.

(e)Environmental Matters. Promptly after obtaining actual knowledge of any one or more of the following environmental matters, unless such environmental matters would not, individually, or when aggregated with all other such matters, be reasonably expected to result in a Material Adverse Effect, notice of:

(i)any pending or threatened Environmental Claim against any Credit Party or any Oil and Gas Properties;

(ii)any condition or occurrence on any Oil and Gas Properties that (A) would reasonably be expected to result in noncompliance by any Credit Party with any applicable Environmental Law or (B) would reasonably be anticipated to form the basis of an Environmental Claim against any Credit Party or any Oil and Gas Properties;

(iii)any condition or occurrence on any Oil and Gas Properties that would reasonably be anticipated to cause such Oil and Gas Properties to be subject to any restrictions on the ownership, occupancy, use or transferability of such Oil and Gas Properties under any Environmental Law; and

(iv)the conduct of any investigation, or any removal, remedial or other corrective action in response to the actual or alleged presence, release or threatened release of any Hazardous Material on, at, under or from any Oil and Gas Properties.

All such notices shall describe in reasonable detail the nature of the claim, investigation, condition, occurrence or removal or remedial action and the response thereto.

(f)Other Information. (i) Promptly upon filing thereof, copies of any filings (including on Form 10-K, 10-Q or 8-K) or registration statements with, and reports to, the SEC or any analogous Governmental Authority in any relevant jurisdiction by the Borrower or any of the Subsidiaries (other than amendments to any registration statement (to the extent such registration statement, in the form it becomes effective, is delivered to the Administrative Agent), exhibits to any registration statement and, if applicable, any registration statements on Form S-8), (ii) copies of all financial statements, proxy statements, notices and reports that the Borrower or any of the Subsidiaries shall send to the holders of any publicly issued debt of the Borrower and/or any of the Subsidiaries, in each case in their capacity as such holders, lenders or agents (in each case to the extent not theretofore delivered to the Administrative Agent pursuant to this Agreement), (iii) with reasonable promptness, but subject to the limitations set forth in the last sentences of Section 9.2(a) and Section 13.6, such other information regarding the operations, business affairs and the financial condition of the Borrower or the Restricted Subsidiaries as the Administrative Agent on its own behalf or on behalf of any Lender (acting through the Administrative Agent) may reasonably request in writing from time to time and (iv) promptly following any request therefor, information and documentation reasonably requested by the Administrative Agent or any Lender for purposes of compliance with applicable “know your customer” and Anti-money Laundering Laws, including the Patriot Act and the Beneficial Ownership Regulation.

(g)Certificate of Authorized Officer – Hedge Transactions. Concurrently with any delivery of each Reserve Report, a certificate of an Authorized Officer of the Borrower, setting forth as of the last Business Day of the most recently ended fiscal year or period, as applicable, a true and complete list of all material commodity Hedge Transactions of the Borrower and each Credit Party, the material terms thereof (including the type, term, effective date, termination date and notional amounts or volumes), the net mark-to-market value thereof (as of the last Business Day of such fiscal year or period, as applicable and for which a mark-to-market value is reasonably available), any new credit support agreements relating thereto not listed on Schedule 8.20 or on any previously delivered certificate delivered pursuant to this clause (g), any margin required or supplied under any credit support document and the counterparty to each such agreement.

(h)Certificate of Authorized Officer – Gas Imbalances. Concurrently with any delivery of each Reserve Report, a certificate of an Authorized Officer of the Borrower, certifying that as of the last Business Day of the most recently ended fiscal year or period, as applicable, except as specified in such certificate, on a net basis, there are no gas imbalances, take or pay or other prepayments exceeding 2.5 Bcfe of Hydrocarbon volumes (stated on a gas equivalent basis) in the aggregate, with respect to the Credit Parties’ Oil and Gas Properties that would require any Credit Party to deliver Hydrocarbons either generally or produced from their Oil and Gas Properties at some future time without then or thereafter receiving full payment therefor.

(i)Certificate of Authorized Officer – Production Report and Lease Operating Statement. Concurrently with any delivery of each Reserve Report in connection with a Scheduled Redetermination, a certificate of an Authorized Officer of the Borrower, setting forth, for each calendar month during the then current fiscal year to date, the volume of production of Hydrocarbons and sales attributable to production of Hydrocarbons (and the prices at which such sales were made and the revenues derived from such sales) for each

such calendar month from the Borrowing Base Properties, and setting forth the related ad valorem, severance and production taxes and lease operating expenses attributable thereto for each such calendar month.

(j)Lists of Purchasers. At the time of the delivery of the financial statements provided for in Section 9.1(a), a certificate of an Authorized Officer of the Borrower setting forth a list of Persons purchasing Hydrocarbons from the Borrower or any other Credit Party who collectively account for at least 85% of the revenues resulting from the sale of all Hydrocarbons from the Borrower and such other Credit Parties during the fiscal year for which such financial statements relate.

(k)Budget. Within 105 days after the end of each fiscal year (beginning with (and 120 days in the case of) the fiscal year ending on or about December 31, 2018) of the Borrower or, if not delivered by the Borrower and requested in writing by the Administrative Agent and any Lender, as soon thereafter as is commercially reasonable, a reasonably detailed consolidated budget for the following fiscal year as customarily prepared by management of the Borrower (including a projected consolidated balance sheet of the Borrower and its Subsidiaries as of the end of the following fiscal year, the related consolidated statements of projected monthly cash flow and projected monthly income and a summary of the material underlying assumptions applicable thereto, and forecasts of anticipated capital expenditures) (collectively, the “Budget”), which Budget shall in each case be accompanied by a certificate of an Authorized Officer stating that such Budget has been prepared in good faith on the basis of the assumptions stated therein, which assumptions were believed to be reasonable at the time of preparation of such Budget, it being understood that actual results may vary from such Budget.

(l)Available Free Cash Flow Amount Certificate. Within ten (10) Business Days (or such later date as may be agreed to by the Administrative Agent in writing in its sole discretion) after the Sixth Amendment Effective Date and, thereafter, concurrently with any delivery of financial statements under Section 9.1(b) (commencing with the fiscal quarter ending June 30, 2021) and on or before sixty (60) days after the end of each fiscal year (commencing with the fiscal year ending December 31, 2021), a certificate of a Financial Officer in form and substance reasonably satisfactory to the Administrative Agent setting forth detailed calculations of the Available Free Cash Flow Amount for the most recently ended Applicable Period (including, with respect to each fiscal quarter ending December 31 of each year, unaudited financial statements necessary to support such calculations).

It is understood that (A) in the event that in respect of the Junior Lien Indenture, the EnVen Notes Indenture, any indenture or credit agreement in respect of any QuarterNorth Acquisition Debt, any indenture or credit agreement in respect of any Permitted Incremental Junior Lien Debt, or any indenture or credit agreement in respect of any Permitted Refinancing Indebtedness with respect thereto, such Indebtedness permits the Borrower, Holdings or any Parent Entity to report at Holdings’ or such Parent Entity’s level on a consolidated basis, such consolidated reporting at Holdings’ or such Parent Entity’s level in a manner consistent with that described in clauses (a) and (b) of this Section 9.1 for the Borrower (together with a reconciliation showing the adjustments necessary to determine compliance by the Borrower and its Restricted Domestic Subsidiaries with a Financial Performance Covenant) will satisfy the requirements of Section 9.1(a) or Section 9.1(b), as applicable, and (B) documents required to be delivered pursuant to Sections 9.1(a), Section 9.1(b) and Section 9.1(f) may be delivered electronically and if so delivered, shall be deemed to have been delivered on the date (1) on which the Borrower posts such documents, or provides a link thereto on the Borrower’s website on the Internet at the website address listed on Schedule 13.2 or (2) on which such documents are transmitted by electronic mail to the Administrative Agent; provided that: (a) upon written request by the Administrative Agent, the Borrower shall deliver paper copies of such documents delivered pursuant to Sections 9.1(a), 9.1(b), 9.1(c) and 9.1(f) to the Administrative Agent for further distribution to each Lender until a written request to cease delivering paper copies is given by the Administrative Agent and (b) the Borrower shall notify (which may be by facsimile or

electronic mail) the Administrative Agent of the posting of any such documents and provide to the Administrative Agent by electronic mail electronic versions (i.e., soft copies) of such documents. Each Lender shall be solely responsible for timely accessing posted documents or requesting delivery of paper copies of such documents from the Administrative Agent and maintaining its copies of such documents.

9.2Books, Records and Inspections.

(a)The Borrower will, and will cause each Restricted Subsidiary to, permit officers and designated representatives of the Administrative Agent or officers and designated representatives of the Majority Lenders (as accompanied by the Administrative Agent), to visit and inspect any of the properties or assets of the Borrower or such Restricted Subsidiary in whomsoever’s possession to the extent that it is within such party’s control to permit such inspection (and shall use commercially reasonable efforts to cause such inspection to be permitted to the extent that it is not within such party’s control to permit such inspection), and to examine the financial records of the Borrower and any such Restricted Subsidiary and discuss the affairs, finances, accounts and condition of the Borrower or any such Restricted Subsidiary with its and their officers and independent accountants therefor, in each case of the foregoing upon reasonable advance notice to the Borrower, all at such reasonable times and intervals during normal business hours and to such reasonable extent as the Administrative Agent or the Majority Lenders may desire (and subject, in the case of any such meetings or advice from such independent accountants, to such accountants’ customary policies and procedures); provided that, excluding any such visits and inspections during the continuation of an Event of Default (i) only the Administrative Agent on behalf of the Majority Lenders may exercise rights of the Administrative Agent and the Lenders under this Section 9.2, and (ii) only one such visit per fiscal year shall be at the Borrower’s expense; provided, further, that when an Event of Default exists, the Administrative Agent (or any of its representatives or independent contractors) or any representative of the Majority Lenders may do any of the foregoing at the expense of the Borrower at any time during normal business hours and upon reasonable advance notice. The Administrative Agent and the Majority Lenders shall give the Borrower the opportunity to participate in any discussions with the Borrower’s independent public accountants. Notwithstanding anything to the contrary in Section 9.1(f)(iii) or this Section 9.2, neither the Borrower nor any Restricted Subsidiary will be required to disclose, permit the inspection, examination or making copies or abstracts of, or discussion of, any document, information or other matter (A) that constitutes non-financial trade secrets or non-financial proprietary information, (B) in respect of which disclosure to the Administrative Agent or any Lender (or their respective representatives or contractors) is prohibited by any Requirement of Law or any binding agreement or (C) that is subject to attorney-client or similar privilege or constitutes attorney work product.

(b)The Borrower will, and will cause each of the Restricted Subsidiaries to, maintain financial records in accordance with GAAP.

9.3Maintenance of Insurance. The Borrower will, and will cause each Restricted Subsidiary to, at all times maintain in full force and effect, pursuant to self-insurance arrangements or with insurance companies that the Borrower believes (in the good faith judgment of the management of the Borrower) are financially sound and reputable at the time the relevant coverage is placed or renewed, insurance in at least such amounts (after giving effect to any self-insurance which the Borrower believes (in the good faith judgment of management of the Borrower) is reasonable and prudent in light of the size and nature of its business) and against at least such risks (and with such risk retentions) as the Borrower believes (in the good faith judgment of management of the Borrower) is reasonable and prudent in light of the size and nature of its business; and will furnish to the Administrative Agent, upon written request from the Administrative Agent, information presented in reasonable detail as to the insurance so carried. The Secured Parties shall be the additional insureds on any such liability insurance as their interests may appear and, if property insurance is obtained, the Collateral Agent shall be the

loss payee under any such property insurance; provided that, so long as no Event of Default has occurred and is then continuing, the Secured Parties will provide any proceeds of such property insurance to the Borrower to the extent that the Borrower undertakes to apply such proceeds to the reconstruction, replacement or repair of the property insured thereby or in a manner otherwise permitted hereunder. The Borrower shall deliver to the Administrative Agent within 45 Business Days following the Closing Date (or such later date as the Administrative Agent may reasonably agree), copies of insurance certificates evidencing the insurance required to be maintained by the Borrower and the Subsidiaries pursuant to this Section 9.3.

9.4Payment of Taxes. The Borrower shall, and shall cause each Restricted Subsidiary to, pay its obligations in respect of all Tax liabilities, assessments and governmental charges, before the same shall become delinquent or in default, except where (i) the amount or validity thereof is being contested in good faith by appropriate proceedings and the Borrower or a Subsidiary thereof has set aside on its books adequate reserves therefor in accordance with GAAP or (ii) the failure to make payment could not reasonably be expected, individually or in the aggregate, to result in a Material Adverse Effect.

9.5Consolidated Corporate Franchises. The Borrower will do, and will cause each Restricted Subsidiary to do, or cause to be done, all things necessary to preserve and keep in full force and effect its existence, corporate rights and authority, except to the extent that the failure to do so would not reasonably be expected to have a Material Adverse Effect; provided, however, that the Borrower and its Restricted Subsidiaries may consummate any transaction permitted under Section 10.3, 10.4 or 10.5.

9.6Compliance with Statutes, Regulations, Etc. The Borrower will, and will cause each Restricted Subsidiary to, comply with all Requirements of Law applicable to it or its property, including all governmental approvals or authorizations required to conduct its business, and to maintain all such governmental approvals or authorizations in full force and effect, in each case except where the failure to do so would not reasonably be expected to have a Material Adverse Effect. The Borrower will maintain in effect and enforce policies and procedures designed to ensure compliance by the Borrower, its Subsidiaries and their respective directors, officers, employees and agents with Anti-Corruption Laws, Anti-Money Laundering Laws and applicable Sanctions.

9.7ERISA.

(a)Promptly after the Borrower knows or has reason to know of the occurrence of any of the following events that, individually or in the aggregate (including in the aggregate such events previously disclosed or exempt from disclosure hereunder, to the extent the liability therefor remains outstanding), would be reasonably likely to have a Material Adverse Effect, the Borrower will deliver to the Administrative Agent a certificate of an Authorized Officer or any other senior officer of the Borrower setting forth details as to such occurrence and the action, if any, that the Borrower or such ERISA Affiliate is required or proposes to take, together with any notices (required, proposed or otherwise) given to or filed with or by the Borrower, such ERISA Affiliate, the PBGC, a Plan participant (other than notices relating to an individual participant’s benefits) or the Plan administrator with respect thereto: that a Reportable Event has occurred; that an accumulated funding deficiency has been incurred or an application is to be made to the Secretary of the Treasury for a waiver or modification of the minimum funding standard (including any required installment payments) or an extension of any amortization period under Section 412 of the Code with respect to a Plan; that a Plan having an Unfunded Current Liability has been or is to be terminated, reorganized, partitioned or declared insolvent under Title IV of ERISA (including the giving of written notice thereof); that a Plan has an Unfunded Current Liability that has or will result in a lien under ERISA or the Code; that proceedings will be or have been instituted to terminate a Plan having an Unfunded Current Liability (including the giving of written notice thereof); that a proceeding has been instituted against the

Borrower or an ERISA Affiliate pursuant to Section 515 of ERISA to collect a delinquent contribution to a Plan; that the PBGC has notified the Borrower or any ERISA Affiliate of its intention to appoint a trustee to administer any Plan; that the Borrower or any ERISA Affiliate has failed to make a required installment or other payment pursuant to Section 412 of the Code with respect to a Plan; or that the Borrower or any ERISA Affiliate has incurred or will incur (or has been notified in writing that it will incur) any liability (including any contingent or secondary liability) to or on account of a Plan pursuant to Section 409, 502(i), 502(l), 515, 4062, 4063, 4064, 4069, 4201 or 4204 of ERISA or Section 4971 or 4975 of the Code.

(b)Promptly following any request therefor, on and after the effectiveness of the Pension Act, the Borrower will deliver to the Administrative Agent copies of (i) any documents described in Section 101(k) of ERISA that the Borrower and any of its Subsidiaries may request with respect to any Multiemployer Plan and (ii) any notices described in Section 101(l) of ERISA that the Borrower and any of its Subsidiaries may request with respect to any Multiemployer Plan; provided that if the Borrower or any of its Subsidiaries has not requested such documents or notices from the administrator or sponsor of the applicable Multiemployer Plan, the Borrower or the applicable Subsidiaries shall promptly make a request for such documents or notices from such administrator or sponsor and shall provide copies of such documents and notices promptly after receipt thereof.

9.8Maintenance of Properties. The Borrower will, and will cause each of the Restricted Subsidiaries to, except in each case, where the failure to so comply would not reasonably be expected to result in a Material Adverse Effect (it being understood that this Section 9.8 shall not restrict any transaction otherwise permitted by Section 10.3, 10.4 or 10.5):

(a)operate its Oil and Gas Properties and other material properties or cause such Oil and Gas Properties and other material properties to be operated in a careful and efficient manner in accordance with the practices of the industry and in compliance with all applicable Contractual Requirements and all applicable Requirements of Law, including applicable proration requirements and Environmental Laws, and all applicable Requirements of Law of every other Governmental Authority from time to time constituted to regulate the development and operation of its Oil and Gas Properties and the production and sale of Hydrocarbons and other minerals therefrom;

(b)keep and maintain all property material to the conduct of its business in good working order and condition, ordinary wear and tear excepted, and preserve, maintain and keep in good repair, working order and efficiency (ordinary wear and tear excepted) all of its material Oil and Gas Properties and other material properties, including all equipment, machinery and facilities; and

(c)to the extent a Credit Party is not the operator of any property, the Borrower shall use reasonable efforts to cause the operator to comply with this Section 9.8.

9.9Transactions with Affiliates. The Borrower will conduct, and cause each of the Restricted Subsidiaries to conduct, all transactions involving aggregate payments or consideration in excess of $10,000,000 with any of its Affiliates (other than the Borrower and the Restricted Subsidiaries or any entity that becomes a Restricted Subsidiary as a result of such transaction) on terms that are substantially as favorable to the Borrower or such Restricted Subsidiary as it would obtain at the time in a comparable arm’s-length transaction with a Person that is not an Affiliate, as determined by the board of directors or managers of the Borrower or such Restricted Subsidiary in good faith; provided that the foregoing restrictions shall not apply to:

(a)the consummation of the Transactions, including the payment of Transaction Expenses;

(b)the issuance of Equity Interests of the Borrower (or any Parent Entity thereof) to the Co-Investors or the management of the Borrower (or any Parent Entity thereof) or any of its Subsidiaries;

(c)equity issuances, repurchases, retirements, redemptions or other acquisitions or retirements of Equity Interests by the Borrower (or any Parent Entity thereof) permitted under Section 10.6;

(d)the payment of indemnities and reasonable expenses incurred by the Co- Investors and their Affiliates in connection with management or monitoring or the provision of other services rendered to the Borrower (or any Parent Entity thereof) or any of its Subsidiaries;

(e)loans, advances and other transactions between or among the Borrower, any Subsidiary or any joint venture (excluding in any case any Unrestricted Subsidiary) (regardless of the form of legal entity) in which the Borrower or any Subsidiary has invested (and which Subsidiary or joint venture would not be an Affiliate of the Borrower or such Subsidiary, but for the Borrower’s or such Subsidiary’s ownership of Equity Interests in such joint venture or such Subsidiary) to the extent permitted under Section 10;

(f)employment and severance arrangements and health, disability and similar insurance or benefit plans between the Borrower (or any direct or indirect parent thereof) and the Subsidiaries and their respective directors, officers, employees or consultants (including management and employee benefit plans or agreements, subscription agreements or similar agreements pertaining to the repurchase of Equity Interests pursuant to put/call rights or similar rights with current or former employees, officers, directors or consultants and equity option or incentive plans and other compensation arrangements) in the ordinary course of business or as otherwise approved by the board of directors or managers of the Borrower (or any direct or indirect parent thereof);

(g)[Intentionally Blank];

(h)transactions pursuant to agreements in existence on the Closing Date and to the extent involving aggregate consideration in excess of $2,000,000 individually, set forth on Schedule 9.9 or any amendment thereto or arrangement similar thereto to the extent such an amendment or arrangement is not materially adverse, taken as a whole, to the Lenders in any material respect (as determined by the Borrower in good faith);

(i)Restricted Payments, redemptions, repurchases and other actions permitted under Section 10.6, and Section 10.7;

(j)without duplicating any payments made pursuant to Section 9.9(g) above, customary payments (including reimbursement of fees and expenses) by the Borrower and any of its Restricted Subsidiaries to the Co-Investors made for any financial advisory, financing, underwriting or placement services or in respect of other investment banking activities (including in connection with acquisitions or divestitures, whether or not consummated), which payments are approved by the majority of the members of the board of directors or managers or a majority of the disinterested members of the board of directors or managers of the Borrower (or any direct or indirect parent thereof), in good faith;

(k)any issuance of Equity Interests or other payments, awards or grants in cash, securities, Equity Interests or otherwise pursuant to, or the funding of, employment arrangements, equity options and equity ownership plans approved by the board of directors or board of managers of the Borrower (or any direct or indirect parent thereof);

(l)transactions with joint ventures for the purchase or sale of goods, equipment and services entered into in the ordinary course of business and in a manner consistent with prudent business practice followed by companies in the industry of the Borrower and its Subsidiaries;

(m)sales or conveyances of net profits interests for cash at Fair Market Value allowed under Section 10.4;

(n)the issuance, sale or transfer of Equity Interests of the Borrower to Holdings (or another Parent Entity) in connection with capital contributions by Holdings or such other Parent Entity to the Borrower;

(o)any transaction in respect of which the Borrower delivers to the Administrative Agent a letter addressed to the board of directors or managers of the Borrower from an accounting, appraisal or investment banking firm, in each case of nationally-recognized standing that is in the good faith determination of the Borrower qualified to render such letter, which letter states that such transaction is (i) fair, from a financial point of view, to the Borrower or such Restricted Subsidiary or (ii) on terms, taken as a whole, that are no less favorable to the Borrower or such Restricted Subsidiary, as applicable, than would be obtained in a comparable arm’s length transaction with a person that is not an Affiliate;

(p)transactions undertaken in good faith (as certified by a responsible financial or accounting officer of the Borrower) for the purpose of improving the consolidated tax efficiency of the Borrower, the Intermediate Entities, Holdings and the Subsidiaries and not for the purpose of circumventing any covenant set forth in this Agreement; and

(q)customary agreements and arrangements with oil and gas royalty trusts and master limited partnership agreements that comply with the affiliate transaction provisions of such royalty trust or master limited partnership agreement.

9.10End of Fiscal Years; Fiscal Quarters. The Borrower will, for financial reporting purposes, cause each of its, and each of its Restricted Subsidiaries’, fiscal years and fiscal quarters to end on dates consistent with past practice; provided, however, that the Borrower may, upon written notice to the Administrative Agent change the financial reporting convention specified above to any other financial reporting convention reasonably acceptable to the Administrative Agent, in which case the Borrower and the Administrative Agent will, and are hereby authorized by the Lenders to, make any adjustments to this Agreement that are necessary in order to reflect such change in financial reporting.

9.11Additional Guarantors, Grantors and Collateral.

(a)Subject to any applicable limitations set forth in the Guarantee or the Security Documents, the Borrower will cause (i) any direct or indirect Domestic Subsidiary (other than any Excluded Subsidiary) formed or otherwise purchased or acquired after the Closing Date (including pursuant to a Permitted Acquisition) and (ii) any Domestic Subsidiary of the Borrower that ceases to be an Excluded Subsidiary, in each case within 30 days from the date of such formation, acquisition or cessation, as applicable (or such longer period as the Administrative Agent may agree in its reasonable discretion) to execute (A) a supplement to the Guarantee, substantially in the form of Exhibit I thereto, in order to become a Guarantor, (B) a supplement to the Collateral Agreement, substantially in the form of Exhibit I thereto, in order to become a grantor and a pledgor thereunder and (C) a joinder to the Intercompany Note.

(b)Subject to any applicable limitations set forth in the Collateral Agreement, the Borrower will pledge, and, if applicable, will cause each other Subsidiary Guarantor (or Person required to become a

Subsidiary Guarantor pursuant to Section 9.11(a)) to pledge, to the Collateral Agent, for the benefit of the Secured Parties, (i) all of the Equity Interests (other than any Excluded Equity Interests) of each Subsidiary directly owned by the Borrower or any Subsidiary Guarantor (or Person required to become a Guarantor pursuant to Section 9.11(a)), in each case, formed or otherwise purchased or acquired after the Closing Date, within 30 days from the date of such formation or acquisition, as applicable (or such longer period as the Administrative Agent may agree in its reasonable discretion), pursuant to supplements to the Collateral Agreement substantially in the form of Exhibit I thereto and, (ii) except with respect to intercompany Indebtedness, all evidences of Indebtedness for borrowed money in a principal amount in excess of $20,000,000 (individually) that is owing to the Borrower or any Guarantor (or Person required to become a Guarantor pursuant to Section 9.11(a)) (which shall be evidenced by a promissory note), in each case pursuant to supplements to the Collateral Agreement substantially in the form of Exhibit I thereto.

(c)The Borrower agrees that all Indebtedness of the Borrower and each of its Restricted Subsidiaries that is owing to any Credit Party (or a Person required to become a Subsidiary Guarantor pursuant to Section 9.11(a)) shall be evidenced by the Intercompany Note, which promissory note shall be required to be pledged to the Collateral Agent, for the benefit of the Secured Parties, pursuant to the Collateral Agreement.

(d)On or before the sixtieth (60th) day after the Ninth Amendment Implementation Date (or such longer period as the Administrative Agent may agree in its reasonable discretion) and, thereafter, in connection with each redetermination (but not any adjustment) of the Borrowing Base, the Borrower shall review the applicable Reserve Report, if any, and the list of current Mortgaged Properties (as described in Section 9.14(c)), to ascertain whether the PV-10 of the Mortgaged Properties (calculated at the time of redetermination) meets the Collateral Coverage Minimum after giving effect to exploration and production activities, acquisitions, Dispositions and production. In the event that the PV-10 of the Mortgaged Properties (calculated at the time of redetermination) does not meet the Collateral Coverage Minimum, then the Borrower shall, and shall cause its Credit Parties to, grant, within 60 days of delivery of the certificate required under Section 9.14(c) (or such longer period as the Administrative Agent may agree in its reasonable discretion), to the Collateral Agent as security for the Obligations a first-priority Lien interest (subject to Liens permitted by Section 10.2) on additional Oil and Gas Properties not already subject to a Lien of the Security Documents such that, after giving effect thereto, the PV-10 of the Mortgaged Properties (calculated at the time of redetermination) meets the Collateral Coverage Minimum. All such Liens will be created and perfected by and in accordance with the provisions of the Security Documents, including, if applicable, any additional Mortgages. In order to comply with the foregoing, if any Restricted Subsidiary places a Lien on its property and such Subsidiary is not a Guarantor, then it shall become a Guarantor and comply with the provisions of Sections 9.11(a), (b) and (c).

(e)The Borrower will promptly (but in any event, within 5 Business Days) notify the Administrative Agent if the Borrower or any other Credit Party establishes a deposit account, securities account and commodities account in the name of the Borrower or any other Credit Party (other than any Excluded Accounts) after the Closing Date (or if any deposit account, securities account and commodities account in the name of the Borrower or any other Credit Party that was previously an Excluded Account ceases to be an Excluded Account), and the Borrower will, and will cause each other Credit Party to, in connection with any such deposit account, securities account and commodities account established by a Credit Party (other than Excluded Accounts, but only for so long as it is an Excluded Account) promptly, but in any event on or before the earlier of (x) 30 days after the establishment of such deposit account, securities account and commodities account (or by such later date as the Administrative Agent shall reasonably agree) or (y) the first date on which the funds in such deposit account, securities account and commodities account would exceed $1,000,000, enter into a Control Agreement with the Administrative Agent and the depositary bank, securities intermediary or commodities intermediary for such deposit account, securities account and commodities account, respectively, (other than an Excluded

Account), on terms reasonably satisfactory to the Administrative Agent; provided that, notwithstanding the foregoing, the Borrower shall not be required to deliver Control Agreements with respect to any deposit account, securities account or commodities account acquired in connection with the EnVen Merger until the date that is 60 days after the Ninth Amendment Implementation Date.

(f)Subject to any applicable limitations set forth in the Guarantee or the Security Documents, Holdings will (i) pledge all of the Equity Interests of the Borrower and each Intermediate Entity directly owned by Holdings that is formed or otherwise purchased or acquired after the Second Amendment Effective Date, within 30 days from the date of such formation or acquisition, as applicable (or such longer period as the Administrative Agent may agree in its reasonable discretion), pursuant to supplements to the Collateral Agreement substantially in the form of Exhibit I thereto, and (ii) cause any direct or indirect Intermediate Entity formed or otherwise purchased or acquired after the Second Amendment Effective Date, within 30 days from the date of such formation or acquisition, as applicable (or such longer period as the Administrative Agent may agree in its reasonable discretion) to execute (A) a supplement to the Guarantee, substantially in the form of Exhibit I thereto, in order to become a Guarantor, (B) a supplement to the Collateral Agreement, substantially in the form of Exhibit I thereto, in order to become a pledgor thereunder and (C) a joinder to the Intercompany Note. Notwithstanding anything to the contrary contained herein, each of Holdings and each Intermediate Entity shall only be required to pledge its Equity Interests in the Borrower (if Holdings or such Intermediate Entity directly owns any Equity Interest in the Borrower) or any other Person owned by Holdings or such Intermediate Entity that directly or indirectly owns an Equity Interest in the Borrower.

9.12Use of Proceeds.

(a)The Borrower will use the proceeds of the Closing Date Loans on the Closing Date to consummate the Transactions and the payments of Transaction Expenses. Following the Closing Date, the Borrower will use the proceeds of Loans for the acquisition, development and exploration of Oil and Gas Properties and for working capital and other general corporate purposes of the Borrower and its Restricted Subsidiaries (including Permitted Acquisitions and capital expenditures) and to make dividends and distributions to the holders of the Borrower’s Equity Interests to the extent permitted under this Agreement.

(b)The Borrower will use Swingline Loans and Letters of Credit for general corporate purposes, including to secure any surety and bonding requirements and to support deposits required under purchase agreements pursuant to which the Borrower or its Restricted Subsidiaries may acquire Oil and Gas Properties and other assets.

9.13Further Assurances.

(a)Subject to the applicable limitations set forth in the Security Documents, the Borrower will, and will cause each other Credit Party to, execute any and all further documents, financing statements, agreements and instruments, and take all such further actions (including the filing and recording of financing statements, fixture, filings, assignments of as- extracted collateral, mortgages, deeds of trust and other documents) that the Collateral Agent or the Required Lenders may reasonably request, in order to grant, preserve, protect and perfect the validity and priority of the security interests created or intended to be created by the applicable Security Documents, all at the expense of the Borrower and the Restricted Subsidiaries.

(b)The Borrower agrees that it will, or will cause its relevant Subsidiaries to, complete each of the actions described on Schedule 9.13(b) as soon as commercially reasonable and by no later than the date set forth in Schedule 9.13(b) with respect to such action or such later date as the Administrative Agent may reasonably agree.

(c)Notwithstanding anything herein to the contrary, if the Collateral Agent and the Borrower reasonably determine in writing that the cost of creating or perfecting any Lien on any property is excessive in relation to the benefits afforded to the Lenders thereby, then such property may be excluded from the Collateral for all purposes of the Credit Documents. In addition, notwithstanding anything to the contrary in this Agreement, the Collateral Agreement, or any other Credit Document, (i) the Administrative Agent may grant extensions of time for or waivers of the requirements of the creation or perfection of security interests in or the obtaining of title opinions or other title information, legal opinions, appraisals, flood insurance and surveys with respect to particular assets (including extensions beyond the Closing Date for the perfection of security interests in the assets of the Credit Parties on such date) where it reasonably determines, in consultation with the Borrower, that perfection or obtaining of such items is not required by law or cannot be accomplished without undue effort or expense by the time or times at which it would otherwise be required by this Agreement or the other Credit Documents, (ii) Liens required to be granted from time to time pursuant to this Agreement and the Security Documents shall be subject to exceptions and limitations set forth in the Security Documents and, to the extent appropriate in any applicable jurisdiction, as otherwise agreed between the Administrative Agent and the Borrower and (iii) the Administrative Agent and the Borrower may make such modifications to the Security Documents, and execute and/or consent to such easements, covenants, rights of way or similar instruments (and Administrative Agent may agree to subordinate the lien of any mortgage to any such easement, covenant, right of way or similar instrument or record or may agree to recognize any tenant pursuant to an agreement in a form and substance reasonably acceptable to the Administrative Agent), as are reasonable or necessary and otherwise permitted by this Agreement and the other Credit Documents.

9.14Reserve Reports.

(a)On or before each March 31st and September 30th of each year, commencing September 30, 2018, the Borrower shall furnish to the Administrative Agent a Reserve Report evaluating, as of the immediately preceding December 31st and June 30th, the Proved Reserves and the Proved Developed Reserves attributable to the Borrowing Base Properties of the Borrower and the Credit Parties located within the geographic boundaries of the United States of America (or the Outer Continental Shelf adjacent to the United States of America) that the Borrower desires to have included in any calculation of the Borrowing Base, together with such other reports, data and supplemental information, as may, from time to time, be reasonably requested by the Required Lenders. Each Reserve Report prepared as of December 31 shall be prepared by one or more Approved Petroleum Engineers. Each Reserve Report as of June 30 shall be prepared, at the sole election of the Borrower, (x) by one or more Approved Petroleum Engineers or (y) by or under the supervision of the engineers of the Borrower or a Restricted Subsidiary. Each Reserve Report shall be prepared using the then-current Bank Price Deck.

(b)In the event of an Interim Redetermination, the Borrower shall furnish to the Administrative Agent a Reserve Report prepared by one or more Approved Petroleum Engineers or prepared under the supervision of the engineers of the Borrower or a Restricted Subsidiary. For any Interim Redetermination pursuant to Section 2.14(b), the Borrower shall provide such Reserve Report with an “as of” date as required by the Administrative Agent, as soon as possible, but in any event no later than 30 days, in the case of any Interim Redetermination requested by the Borrower or 45 days, in the case of any Interim Redetermination requested by the Administrative Agent or the Lenders, following the receipt of such request.

(c)With the delivery of each Reserve Report, the Borrower shall provide to the Administrative Agent a Reserve Report Certificate from an Authorized Officer of the Borrower certifying that in all material respects:

(i)in the case of Reserve Reports prepared by or under the supervision of the engineers of the Borrower or a Restricted Subsidiary (other than December 31 Reserve Reports), such Reserve Report has been prepared, except as otherwise specified therein, in accordance with the procedures used in the immediately preceding December 31 Reserve Report or the Initial Reserve Report, if no December 31 Reserve Report has been delivered;

(ii)the information contained in the Reserve Report and any other information delivered in connection therewith is true and correct in all material respects;

(iii)except as set forth in an exhibit to such certificate, the Borrower or another Credit Party has good and defensible title to the Borrowing Base Properties evaluated in such Reserve Report (other than those (x) Disposed of in compliance with Section 10.4 since delivery of such Reserve Report, (y) leases that have expired in accordance with their terms and (z) with title defects disclosed in writing to the Administrative Agent) and such Borrowing Base Properties are free of all Liens except for Liens permitted by Section 10.2;

(iv)the amount of the “Borrowing Base” as determined in accordance with the provisions of the Junior Lien Indenture (or, any comparable defined term or calculation set forth in the Senior Notes Indenture, the EnVen Notes Indenture, any indenture or credit agreement in respect of any QuarterNorth Acquisition Debt, any indenture or credit agreement in respect of any Permitted Incremental Junior Lien Debt, any indenture or credit agreement in respect of Permitted Additional Debt that constitutes Material Indebtedness, or any indenture or credit agreement in respect of any Permitted Refinancing Indebtedness), together with supporting information and calculations in form and substance reasonably satisfactory to the Administrative Agent;

(v)none of the Borrowing Base Properties have been Disposed of since the date of the last Borrowing Base determination except those Borrowing Base Properties listed on such certificate as having been Disposed of; and

(vi)the certificate shall also attach, as schedules thereto, a list of all Borrowing Base Properties evaluated by such Reserve Report that are Collateral and demonstrating that the PV-10 of the Collateral (calculated at the time of delivery of such Reserve Report) meets the Collateral Coverage Minimum.

9.15Title Information.

(a)On or before the sixtieth (60th) day after the Ninth Amendment Implementation Date (or such longer period as the Administrative Agent may agree in its reasonable discretion) and, thereafter, on or before the delivery to the Administrative Agent of the certificate required under Section 9.14(c) (or such later date as the Administrative Agent may agree in its reasonable discretion), and from time to time upon the reasonable request of the Administrative Agent, the Borrower will deliver title information, in form and substance reasonably acceptable to the Administrative Agent and consistent with usual and customary standards for the geographic regions in which the Borrowing Base Properties are located, taking into account the size, scope and number of leases and wells of the Borrower and its Restricted Subsidiaries, covering enough of the Borrowing Base Properties, so that the Administrative Agent shall have received, together with title information previously delivered to the Administrative Agent, reasonably satisfactory title information on no less than 85% of the PV‑10 of the Proved Reserves included in the Reserve Report (and, if not included in the most recent Reserve Report, the Oil and Gas Properties included in the EnVenQuarterNorth AcquisitionReserve Report (if the QuarterNorth

Acquisition has been consummated)), after giving effect to exploration and production activities, acquisitions, Dispositions and production.

(b)If the Borrower has provided title information for additional properties under Section 9.15(a), the Borrower shall, within sixty (60) days of notice from the Administrative Agent that title defects or exceptions that are not permitted by Section 10.2 exist with respect to such additional properties, either (i) cure any such title defects or exceptions (including defects or exceptions as to priority) raised by such information, (ii) substitute acceptable Mortgaged Properties (with no title defects or exceptions except for Liens permitted by Section 10.2) having an equivalent value or (iii) deliver title information in form and substance reasonably acceptable to the Administrative Agent so that the Administrative Agent shall have received, together with title information previously delivered to the Administrative Agent, reasonably satisfactory title information on no less than 85% of the PV-10 of the Proved Reserves included in the Reserve Report (and, if not included in the most recent Reserve Report, the Oil and Gas Properties included in the EnVenQuarterNorth Acquisition Reserve Report (if the QuarterNorth Acquisition has been consummated)), after giving effect to exploration and production activities, acquisitions, Dispositions and production.

(c)If the Borrower is unable to cure any title defect requested by the Administrative Agent or the Lenders to be cured within the sixty (60) day period or the Borrower does not comply with the requirements to provide acceptable title information covering no less than 85% of the PV-10 of the Proved Reserves included in the Reserve Report (and, if not included in the most recent Reserve Report, the Oil and Gas Properties included in the EnVenQuarterNorth Acquisition Reserve Report (if the QuarterNorth Acquisition has been consummated)), after giving effect to exploration and production activities, acquisitions, Dispositions and production, such inability shall not be a Default, but instead the Administrative Agent shall have the right to exercise the following remedy in its sole discretion from time to time, and any failure to so exercise this remedy at any time shall not be a waiver as to future exercise of the remedy by the Administrative Agent. To the extent that the Administrative Agent is not satisfied with title to any Borrowing Base Property after the sixty (60) day period has elapsed, such unacceptable Borrowing Base Property shall not count towards the requirements of Section 9.11(d) and Section 9.15(a), and the Administrative Agent may send a notice to the Lenders proposing that the then outstanding Borrowing Base be reduced by an amount to be approved by the Required Lenders to cause the Borrower to be in compliance with the requirements of Section 9.11(d) and Section 9.15(a), after giving effect to exploration and production activities, acquisitions, Dispositions and production. After the then outstanding Borrowing Base has been reduced by an amount as approved by the Required Lenders, this new Borrowing Base shall become effective immediately after receipt by the Borrower of notice of such new Borrowing Base.

9.16Change in Business. The Borrower and its Restricted Subsidiaries, taken as a whole, will not fundamentally and substantively alter the character of their business, taken as a whole, from the business conducted by them on the Closing Date, the business of Industry Investments by the Borrower and its Restricted Subsidiaries and other business activities incidental, reasonably related or ancillary to any of the foregoing.

9.17Holdings and Intermediate Entity Covenant. Holdings covenants and agrees that on the Closing Date and thereafter, until the Total Commitment and each Letter of Credit have terminated (unless such Letters of Credit have been collateralized on terms and conditions reasonably satisfactory to the relevant Issuing Banks following the termination of the Total Commitment) and the Loans, the Swingline Loans and Unpaid Drawings, together with interest, fees and all other Obligations incurred hereunder (other than Hedging Obligations under Secured Hedge Transactions, Cash Management Obligations under Secured Cash Management Agreements or contingent indemnification obligations not then due and payable), are paid in full, unless the Majority Lenders shall otherwise consent in writing, Holdings will not, and will not permit any Intermediate Entity to, engage at any time in any business or business activity other than (i) ownership of the Equity Interests in the Borrower and

any Parent Entity of the Borrower, together with activities related thereto, (ii) performance of its obligations (if any) under and in connection with the Credit Documents, the Junior Lien Indenture, the EnVen Notes Indenture, any indenture or credit agreement in respect of any QuarterNorth Acquisition Debt, any indenture or credit agreement evidencing any Permitted Incremental Junior Lien Debt, and any indenture or credit agreement evidencing any Permitted Refinancing Indebtedness with respect to the Junior Lien Notes, the EnVen Notes, any QuarterNorth Acquisition Debt, any Permitted Incremental Junior Lien Debt, and the incurrence and performance of Indebtedness not prohibited by Section 10.1; provided that, the provisions of Section 2.14(e) shall apply in the event that the Borrower or any Subsidiary Guarantor guaranties any Indebtedness for borrowed money incurred by Holdings (as if such guaranty constituted Permitted Additional Debt hereunder), (iii) issuing, selling and redeeming its Equity Interests, (iv) paying taxes, (v) holding directors’ and shareholders’ meetings, preparing corporate and similar records and other activities (including the ability to incur fees, costs and expenses relating to such maintenance) required to maintain its corporate or other legal structure or to participate in tax, accounting or other administrative matters as a member of the consolidated group of the Credit Parties, (vi) preparing reports to, and preparing and making notices to and filings with, Governmental Authorities and to its holders of Equity Interests, (vii) receiving, and holding proceeds of, Restricted Payments from the Borrower and the Subsidiaries and distributing the proceeds thereof to the extent not prohibited by Section 9.9 or Section 10.6, (viii) activities in connection with the formation and maintenance of the existence of any Parent Entity (it being understood that notwithstanding anything to the contrary herein or in any Credit Document, there shall be no restriction on the formation of any Parent Entity), (ix) providing indemnification to officers and directors, (x) activities permitted hereunder or as otherwise required by Requirements of Law and (xi) activities incidental to the business or activities described in each foregoing clause of this Section 9.17.

9.18Keepwell. The Borrower hereby absolutely, unconditionally and irrevocably undertakes to provide such funds or other support as may be needed from time to time by each other Credit Party to honor all of its obligations under any Guarantee or any Hedge Agreement in respect of Hedging Obligations. The obligations of the Borrower under this Section 9.18 shall remain in full force and effect until payment in full of the Obligations and the termination of this Agreement. The Borrower intends that this Section 9.18 constitute, and this Section 9.18 shall be deemed to constitute, a “keepwell, support, or other agreement” for the benefit of each other Credit Party for all purposes of Section 1a(18)(A)(v)(II) of the Commodity Exchange Act.

9.19Minimum Hedge Covenant. Within ten (10) Business Days (or such later date as may be agreed to by the Administrative Agent in writing in its sole discretion) after the Sixth Amendment Effective Date and on or before the last day of each fiscal quarter thereafter (commencing with the fiscal quarter ending September 30, 2021) (each a “Minimum Hedging Compliance Date”), the Borrower and/or one or more of its Restricted Subsidiaries shall have entered into (and shall thereafter maintain) one or more Hedge Transactions that are direct swaps (including “collars” and any “three ways” to which EnVen or any of its Subsidiaries was a party as of November 7, 2022, but for the avoidance of doubt, not including any other “three ways”) with approved counterparties for the purpose of mitigating commodity price risk with respect to not less than the Minimum Quarterly Hedged Volume for each of the immediately following six (6) fiscal quarters. The Hedge Transactions entered into pursuant to this Section 9.19 shall be subject to Section 10.10.

9.20Separateness. The Borrower shall, and shall cause each of its Subsidiaries to:

(a)use commercially reasonable efforts to operate each Unrestricted Subsidiary (and cause each Unrestricted Subsidiary to operate) in such a manner as to make it reasonably apparent to all creditors of such Unrestricted Subsidiary that such Unrestricted Subsidiary is a legal entity separate and distinct from the Borrower or any Restricted Subsidiary and, as such, is solely responsible for its respective debts and other

obligations (including maintaining separate books of account, furnishing separate financial statements of Unrestricted Subsidiaries to creditors and potential creditors thereof);

(b)except to the extent permitted by this Agreement, not permit the Borrower or any Restricted Subsidiary to incur, assume, guarantee or be or become liable for any Indebtedness of any Unrestricted Subsidiary; and

(c)not permit any Unrestricted Subsidiary to purchase, acquire or own any Equity Interest in or any Indebtedness of the Borrower or any Restricted Subsidiary.

Section 10.Negative Covenants.

The Borrower hereby covenants and agrees that on the Closing Date and thereafter, until the Total Commitment and each Letter of Credit have terminated (unless such Letters of Credit have been collateralized on terms and conditions reasonably satisfactory to the relevant Issuing Banks following the termination of the Total Commitment) and the Loans, the Swingline Loans and Unpaid Drawings, together with interest, fees and all other Obligations incurred hereunder (other than Hedging Obligations under Secured Hedge Transactions, Cash Management Obligations under Secured Cash Management Agreements or contingent indemnification obligations not then due and payable), are paid in full:

10.1Limitation on Indebtedness. The Borrower will not, and will not permit any of the Restricted Subsidiaries to, create, incur, assume or suffer to exist any Indebtedness other than the following:

(a)Indebtedness arising under the Credit Documents (including pursuant to Sections 2.16 and any Permitted Refinancing Indebtedness incurred to Refinance such Indebtedness);

(b)Indebtedness (including Guarantee Obligations thereunder) in respect of the EnVen Notes and any fees, underwriting discounts, premiums and other costs and expenses incurred in connection with the foregoing, and any Permitted Refinancing Indebtedness issued or incurred to Refinance such Indebtedness so long as the maturity date therefore and the Weighted Average Life to Maturity is at least 180 days after the Maturity Date;

(c)Indebtedness (including Guarantee Obligations thereunder) in respect of the Junior Lien Notes and any fees, underwriting discounts, premiums and other costs and expenses incurred in connection with the foregoing, and any Permitted Refinancing Indebtedness issued or incurred to Refinance such Indebtedness so long as the maturity date therefore and the Weighted Average Life to Maturity is at least 180 days after the Maturity Date;

(d)Indebtedness of (i) the Borrower or any Guarantor owing to the Borrower or any Restricted Subsidiary; provided that any such Indebtedness owing by a Credit Party to a Restricted Subsidiary that is not a Guarantor shall (x) be evidenced by the Intercompany Note or (y) otherwise be outstanding on the Closing Date so long as such Indebtedness is evidenced by an intercompany note substantially in the form of Exhibit I or otherwise subject to subordination terms substantially identical to the subordination terms set forth in Exhibit I, in each case, to the extent permitted by Requirements of Law and not giving rise to material adverse tax consequences, (ii) any Restricted Subsidiary that is not a Guarantor owing to any other Restricted Subsidiary that is not a Guarantor and (iii) to the extent permitted by Section 10.5, any Restricted Subsidiary that is not a Guarantor owing to the Borrower or any Guarantor;

(e)Indebtedness in respect of any bankers’ acceptance, bank guarantees, letter of credit, warehouse receipt or similar facilities entered into in the ordinary course of business or consistent with past practice or industry practice (including in respect of workers compensation claims, health, disability or other employee benefits or property, casualty or liability insurance or self-insurance or other Indebtedness with respect to reimbursement-type obligations regarding workers compensation claims);

(f)subject to compliance with Section 10.5, Guarantee Obligations incurred by (i) Restricted Subsidiaries in respect of Indebtedness of the Borrower or other Restricted Subsidiaries that is permitted to be incurred under this Agreement (except that a Restricted Subsidiary that is not a Credit Party may not, by virtue of this Section 10.1(f) guarantee Indebtedness that such Restricted Subsidiary could not otherwise incur under this Section 10.1) and (ii) the Borrower in respect of Indebtedness of Restricted Subsidiaries that is permitted to be incurred under this Agreement; provided that (A) if the Indebtedness being guaranteed under this Section 10.1(f) is subordinated to the Obligations, such Guarantee Obligations shall be subordinated to the Guarantee of the Obligations on terms at least as favorable to the Lenders as those contained in the subordination of such Indebtedness and (B) no guarantee by any Restricted Subsidiary of any Permitted Additional Debt (or Indebtedness under clause (b) above) shall be permitted unless such Restricted Subsidiary shall have also provided a guarantee of the Obligations substantially on the terms set forth in the Guarantee;

(g)Guarantee Obligations (i) incurred in the ordinary course of business in respect of obligations of (or to) suppliers, customers, franchisees, lessors, licensees or sublicensees or (ii) otherwise constituting Investments permitted by Sections 10.5(d), (g), (h), (i), (q), (r) and (s);

(h)(i) Indebtedness (including Indebtedness arising under Capital Leases) incurred prior to or within 270 days following the acquisition, construction, lease, repair, replacement, expansion or improvement of assets (real or personal, and whether through the direct purchase of property or the Equity Interests of a Person owning such property, but excluding Hydrocarbon Interests) to finance the acquisition, construction, lease, repair, replacement expansion, or improvement of such assets; (ii) Indebtedness arising under Capital Leases, other than (A) Capital Leases in effect on the Closing Date and (B) Capital Leases entered into pursuant to subclause (i) above (provided that, in the case of each of the foregoing subclauses (i) and (ii), the Borrower shall be in Pro Forma Compliance immediately after giving effect to the incurrence of such Indebtedness (and the use of proceeds thereof)); and (iii) any Permitted Refinancing Indebtedness issued or incurred to Refinance any such Indebtedness;

(i)Indebtedness outstanding on the date hereof (provided that any Indebtedness that is in excess of $2,000,000 individually shall only be permitted under this clause (i) to the extent such Indebtedness is set forth on Schedule 10.1) and any Permitted Refinancing Indebtedness issued or incurred to Refinance such Indebtedness;

(j)Indebtedness in respect of Hedge Transactions of the Borrower or any Restricted Subsidiary, subject to the limitations set forth in Section 10.10;

(k)(i) Indebtedness of a Person or Indebtedness attaching to the assets of a Person that, in either case, becomes a Restricted Subsidiary (or is a Restricted Subsidiary that survives a merger with such Person or any of its Subsidiaries) or Indebtedness attaching to the assets that are acquired by the Borrower or any Restricted Subsidiary, in each case after the Closing Date as the result of a Permitted Acquisition; provided that:

(A)such Indebtedness existed at the time such Person became a Restricted Subsidiary or at the time such assets were acquired and, in each case, was not created in anticipation thereof,

(B)such Indebtedness is not guaranteed in any respect by the Borrower or any Restricted Subsidiary (other than any such Person that so becomes a Restricted Subsidiary or is the survivor of a merger with such Person or any of its Subsidiaries),

(C)(1) the Equity Interests of such Person is pledged to the Collateral Agent to the extent required under Section 9.11(b) and (2) such Person executes a supplement to each of the Guarantee, the Collateral Agreement and a joinder to the Intercompany Note, in each case to the extent required under Section 9.11; provided that the assets covered by such pledges and security interests may, at the option of the Borrower, to the extent permitted by Section 10.2, equally and ratably secure such Indebtedness assumed with the Secured Parties subject to intercreditor arrangements in form and substance reasonably satisfactory to the Administrative Agent; provided, further, that the requirements of this clause (C) shall not apply to any Indebtedness of the type that could have been incurred under Section 10.1(g), and

(D)immediately after giving effect to the assumption of any such Indebtedness, such acquisition and any related transactions, the Borrower shall be in Pro Forma Compliance;

(ii)any Permitted Refinancing Indebtedness incurred to Refinance such Indebtedness;

(l)(i) Indebtedness incurred to finance a Permitted Acquisition; provided that:

(A)(1) the Equity Interests of such Person acquired in such Permitted Acquisition, if any, is pledged to the Collateral Agent to the extent required under Section 9.11(b) and (2) such Person executes supplements to each of the Guarantee and the Collateral Agreement and a joinder to the Intercompany Note, in each case to the extent required under Section 9.11;

(B)immediately after giving effect to the incurrence of any such Indebtedness, such acquisition and any related transactions, the Borrower shall be in Pro Forma Compliance;

(C)the maturity of such Indebtedness is not earlier than, and no mandatory repayment or redemption (other than customary change of control or asset sale offers or upon any event of default) is required prior to, 180 days after the Maturity Date of any Facility hereunder (determined at the time of issuance or incurrence); and

(D)such Indebtedness is not guaranteed in any respect by the Borrower or any Subsidiary Guarantor except to the extent (1) such guarantee is permitted under Section 10.5 and (2) that after giving effect to the incurrence of any such Indebtedness, such acquisition and any related transactions, the Borrower shall be in Pro Forma Compliance;

(ii)any Permitted Refinancing Indebtedness incurred to Refinance such Indebtedness;

(m)Indebtedness of a Foreign Subsidiary or a Domestic Subsidiary that is not a Subsidiary Guarantor; provided that no Credit Party’s assets are used to secure any such Indebtedness, in principal amount, when aggregated with the outstanding principal amount of Indebtedness incurred pursuant to this clause (m), not to exceed, at the time of incurrence thereof, the greater of $20,000,000 and 1% of Adjusted Consolidated Net

Tangible Assets (measured as of the date of incurrence of such Indebtedness based on the financial statements most recently available prior to such date);

(n)Indebtedness in respect of performance bonds, bid bonds, appeal bonds, surety bonds and completion guarantees and similar obligations not in connection with money borrowed, in each case provided in the ordinary course of business or consistent with past practice, including those incurred to secure health, safety and environmental obligations in the ordinary course of business or consistent with past practice;

(o)(i) other Indebtedness; provided that the aggregate principal amount of outstanding Indebtedness incurred pursuant to this Section 10.1(o)(i) shall not at the time of incurrence thereof and immediately after giving effect thereto and the use of proceeds thereof on a Pro Forma Basis, exceed the greater of $50,000,000 and 2.5% of Adjusted Consolidated Net Tangible Assets (measured as of the date of incurrence of such Indebtedness based upon the financial statements most recently available prior to such date) and (ii) any Permitted Refinancing Indebtedness issued or incurred to Refinance such Indebtedness;

(p)(i) Indebtedness in respect of Permitted Additional Debt; provided that (x) after giving effect to the incurrence or issuance thereof and the use of proceeds therefrom, the Consolidated Total Debt to EBITDAX Ratio shall not be greater than 2.75 to 1.00, (y) no Default or Event of Default shall then exist or result therefrom, and (z) the Borrowing Base shall be adjusted as set forth in Section 2.14(e) and (ii) any Permitted Refinancing Indebtedness issued or incurred to Refinance such Indebtedness;

(q)Cash Management Obligations, Cash Management Services and other Indebtedness in respect of netting services, automatic clearing house arrangements, employees’ credit or purchase cards, overdraft protections and similar arrangements in each case incurred in the ordinary course of business;

(r)Indebtedness incurred in the ordinary course of business in respect of obligations of the Borrower or any Restricted Subsidiary to pay the deferred purchase price of goods or services or progress payments in connection with such goods and services;

(s)Indebtedness arising from agreements of the Borrower or any Restricted Subsidiary providing for indemnification, adjustment of purchase price or similar obligations, in each case assumed or entered into in connection with the Transactions, any Permitted Acquisitions, other Investments and the Disposition of any business, assets or Equity Interests not prohibited hereunder;

(t)Indebtedness of the Borrower or any Restricted Subsidiary consisting of (i) obligations to pay insurance premiums or (ii) obligations contained in firm transportation or supply agreements or other take or pay contracts, in each case arising in the ordinary course of business;

(u)Indebtedness representing deferred compensation to employees, consultants or independent contractors of the Borrower (or, to the extent such work is done for the Borrower or its Subsidiaries, any direct or indirect parent thereof) and the Restricted Subsidiaries incurred in the ordinary course of business;

(v)Indebtedness consisting of promissory notes issued by the Borrower or any Guarantor to current or former officers, managers, consultants, directors and employees (or their respective spouses, former spouses, successors, executors, administrators, heirs, legatees or distributees) to finance the purchase or redemption of Equity Interests of the Borrower (or any direct or indirect parent thereof) permitted by Section 10.6;

(w)Indebtedness consisting of obligations of the Borrower and the Restricted Subsidiaries under deferred compensation or other similar arrangements incurred by such Person in connection with the Transactions, Permitted Acquisitions or any other Investment permitted hereunder;

(x)Indebtedness associated with bonds or surety obligations required by Requirements of Law or by Governmental Authorities in connection with the Transactions and the operation of Oil and Gas Properties in the ordinary course of business;

(y)Indebtedness consisting of the undischarged balance of any Production Payment and Reserve Sales, subject to adjustment of the Borrowing Base as set forth in Section 2.14(g) to the extent required under Section 10.4(b);

(z)Indebtedness of the Borrower or any Restricted Subsidiary to any joint venture (regardless of the form of legal entity) that is not a Subsidiary arising in the ordinary course of business in connection with the Cash Management Services (including with respect to intercompany self-insurance arrangements) of the Borrower and its Restricted Subsidiaries;

(aa)Indebtedness incurred on behalf of, or Guarantee Obligations in respect of the Indebtedness of, joint ventures (regardless of the form of legal entity) that are not Subsidiaries in principal amount, when aggregated with the outstanding principal amount of Indebtedness incurred pursuant to this clause (aa), not to exceed, at the time of incurrence thereof, the greater of $30,000,000 and 1.5% of Adjusted Consolidated Net Tangible Assets (measured as of the date of incurrence of such Indebtedness based on the financial statements most recently available prior to such date);

(bb)(i) Indebtedness (including Guarantee Obligations thereunder) not otherwise permitted under this Section 10.1, provided that, (A) the aggregate stated principal amount of such Indebtedness shall not exceed the Maximum Incremental Junior Lien Debt Amount, (B) after giving effect to the incurrence or issuance thereof and the use of proceeds therefrom, the Consolidated Total Debt to EBITDAX Ratio shall not be greater than 2.00 to 1.00, provided, however, that the requirements of this clause (B) shall not apply if, after giving effect to the incurrence or issuance of such Indebtedness and the use of proceeds therefrom, the Outstanding Aggregate Junior Lien Debt Amount is less than $908,000,000, (C) the Borrowing Base then in effect shall be automatically and concurrently reduced by an amount equal to the product of (1)0.25 multiplied by (2) the principal amount of such Indebtedness in the manner contemplated by Section 2.14(e) as if such Indebtedness comprised Permitted Additional Debt, (D) no Default or Event of Default shall then exist or result therefrom, (E) such Indebtedness is not guaranteed by any direct or contingent obligor other than a Credit Party, (F) the covenants, events of default, guarantees and other terms of which (other than interest rate, fees, funding discounts and redemption or prepayment premiums and other pricing terms determined by the Borrower to be “market” rates, fees, discounts and premiums and other terms at the time of issuance or incurrence of any such Indebtedness), taken as a whole, are determined by the Borrower to be “market” terms on the date of issuance or incurrence and in any event are not materially adverse to the interests of the Lenders, taken as a whole, relative to the terms of the Junior Lien Indenture and the EnVen Notes Indenture, taken as a whole, and do not require the maintenance or achievement of any financial performance standards other than as a condition to taking specified actions; provided that a certificate of an Authorized Officer of the Borrower delivered to the Administrative Agent at least three (3) Business Days prior to the incurrence or issuance of such Indebtedness, together with a reasonably detailed description of the material terms and conditions of such Indebtedness or drafts of the documentation relating thereto, stating that the Borrower has determined in good faith that such terms and conditions satisfy the relevant criteria set forth above, as applicable, shall be conclusive evidence that such terms and conditions satisfy such relevant standard, (G) if such Indebtedness is subordinated in right of payment to the Obligations, the terms of

such Indebtedness provide for customary subordination of such Indebtedness to the Obligations, and (H) the maturity date and the Weighted Average Life to Maturity of such Indebtedness is at least 180 days after the Maturity Date and (ii) any Permitted Refinancing Indebtedness issued or incurred to Refinance such Indebtedness.

(cc)(i) Indebtedness (including Guarantee Obligations thereunder) incurred by the Borrower to consummate the QuarterNorth Acquisition and any fees, underwriting discounts, premiums and other costs and expenses incurred in connection with the foregoing, provided that, (A) the aggregate stated principal amount of such Indebtedness shall not exceed $650,000,000, (B) no Default or Event of Default shall then exist or result therefrom, (C) such Indebtedness is not guaranteed by any direct or contingent obligor other than a Credit Party, (D) the covenants, events of default, guarantees and other terms of which (other than interest rate, fees, funding discounts and redemption or prepayment premiums and other pricing terms determined by the Borrower to be “market” rates, fees, discounts and premiums and other terms at the time of issuance or incurrence of any such Indebtedness), taken as a whole, are determined by the Borrower to be “market” terms on the date of issuance or incurrence and in any event are not materially adverse to the interests of the Lenders, taken as a whole, relative to the terms of the Junior Lien Indenture and the EnVen Notes Indenture, taken as a whole, and do not require the maintenance or achievement of any financial performance standards other than as a condition to taking specified actions; provided that a certificate of an Authorized Officer of the Borrower delivered to the Administrative Agent at least three (3) Business Days prior to the incurrence or issuance of such Indebtedness, together with a reasonably detailed description of the material terms and conditions of such Indebtedness or drafts of the documentation relating thereto, stating that the Borrower has determined in good faith that such terms and conditions satisfy the relevant criteria set forth above, as applicable, shall be conclusive evidence that such terms and conditions satisfy such relevant standard, (E) if such Indebtedness is subordinated in right of payment to the Obligations, the terms of such Indebtedness provide for customary subordination of such Indebtedness to the Obligations, (F) the maturity date of such Indebtedness shall not be less than 364 days after the incurrence thereof, and (G) the QuarterNorth Acquisition shall have been consummated on or before the “End Date” (as defined in the QuarterNorth Acquisition Agreement as in effect on the Tenth Amendment Effective Date, which is May 31, 2024), provided that if the End Date is extended to a date that is not later than September 30, 2024 pursuant to Section 9.01(a)(ii)(A) of the QuarterNorth Acquisition Agreement (as in effect on the Tenth Amendment Effective Date), then the outside date for the consummation of the QuarterNorth Acquisition under this clause (G) shall be automatically extended to such extended “End Date”, and (ii) any Permitted Refinancing Indebtedness issued or incurred to Refinance such Indebtedness; provided that, for the avoidance of doubt, any incurrence of Indebtedness under this Section 10.1(cc) shall not cause an adjustment to the Borrowing Base pursuant to Section 2.14(e).

(dd)(cc) Indebtedness under the Whitney Term Loan Documents in an aggregate principal amount outstanding not exceeding $12,000,000; and

(ee)(dd) all premiums (if any), interest (including post-petition interest), fees, expenses, charges, and additional or contingent interest on obligations described in clauses (a) through (bb(cc)) above.

Notwithstanding any other provision of this Section 10.1, the maximum aggregate principal amount of outstanding Indebtedness that Restricted Subsidiaries that are not Subsidiary Guarantors permitted by this Section 10.1 shall not exceed $50.0 million at any time outstanding; provided, however, that any Restricted Foreign Subsidiary that is a special purpose vehicle established to finance a project for the acquisition, development, construction, expansion or improvement of the assets or properties relating to the Borrower’s and its Restricted Subsidiaries operations in the United Mexican States, the aggregate principal amount of outstanding Indebtedness permitted by Section 10.1(h) shall not exceed $350.0 million at any time outstanding.

10.2Limitation on Liens. The Borrower will not, and will not permit any of the Restricted Subsidiaries to, create, incur, assume or suffer to exist any Lien upon any property or assets of any kind (real or personal, tangible or intangible) of the Borrower or any Restricted Subsidiary, whether now owned or hereafter acquired, except:

(a)Liens arising under the Credit Documents to secure the Obligations (including Liens contemplated by Section 3.8);

(b)Permitted Liens;

(c)(x) Liens (including liens arising under Capital Leases to secure Capital Lease Obligations) securing Indebtedness of the Borrower or any Restricted Subsidiary permitted pursuant to Section 10.1(h); provided that (i) such Liens attach concurrently with or within 270 days after the acquisition, lease, repair, replacement, construction, expansion or improvement (as applicable) financed thereby, (ii) other than the property financed by such Indebtedness, such Liens do not at any time encumber any property, except for replacements thereof and accessions and additions to such property and the proceeds and the products thereof and customary security deposits and (iii) with respect to Capital Leases, such Liens do not at any time extend to or cover any assets (except for accessions and additions to such assets, replacements and products thereof and customary security deposits) other than the assets subject to such Capital Leases; provided that in each case individual financings provided by one lender may be cross collateralized to other financings provided by such lender (and its Affiliates), and (y) Liens on the assets of a Restricted Subsidiary that is not a Credit Party securing obligations of a Restricted Subsidiary that is not a Credit Party permitted pursuant to Section 10.1;

(d)Liens existing on the date hereof; provided that any Lien securing Indebtedness in excess of $10,000,000 individually or $20,000,000 in the aggregate (when taken together with all other Liens securing obligations outstanding in reliance on this clause (d) that are not listed on Schedule 10.2(d)) shall only be permitted to the extent such Lien is listed on Schedule 10.2(d);

(e)Liens to secure any refinancing, refunding, extension, renewal or replacement (or successive refinancings, refundings, extensions, renewals or replacements) as a whole, or in part, of any Indebtedness of the Borrower or any Restricted Subsidiary secured by any Lien permitted by this Section 10.2; provided, however, that (x) such new Lien shall be limited to all or part of the same type of property that secured the original Lien (plus improvements on and accessions to such property), (y) the Indebtedness secured by such Lien at such time is not increased to any amount greater than the sum of (i) the outstanding principal amount or, if greater, committed amount of the applicable Indebtedness at the time the original Lien became a Lien permitted hereunder, and (ii) an amount necessary to pay any fees and expenses, including premiums, related to such refinancing, refunding, extension, renewal or replacement and (z) on the date of the incurrence of the Indebtedness secured by such Liens, the grantors of any such Liens shall not be any different than the grantors of the Liens securing the debt being refinanced, refunded, extended, renewed or replaced;

(f)Liens existing on the assets of any Person that becomes a Restricted Subsidiary, or existing on assets acquired, pursuant to a Permitted Acquisition; provided that (i) if the Liens on such assets secure Indebtedness of the Borrower or any Restricted Subsidiary (including any Person that becomes a Restricted Subsidiary), such Indebtedness is permitted under Section 10.1(k) and (ii) such Liens attach at all times only to the same assets that such Liens (or upon or in after- acquired property that is (A) affixed or incorporated into the property covered by such Lien, (B) after-acquired property subject to a Lien securing Indebtedness permitted under Section 10.1(k), the terms of which Indebtedness require or include a pledge of after-acquired property (it being understood that such requirement shall not be permitted to apply to any property to which such requirement would not have applied but for such acquisition) and (C) the proceeds and products thereof) attached to, and to

the extent such Liens secure Indebtedness, secure only the same Indebtedness (or any Permitted Refinancing Indebtedness incurred to Refinance such Indebtedness) that such Liens secured, immediately prior to such Permitted Acquisition;

(g)Liens on the Equity Interests of any Person that becomes a Restricted Subsidiary pursuant to a Permitted Acquisition, or the assets of such a Restricted Subsidiary, in each case, to secure Indebtedness incurred pursuant to Section 10.1(l); provided that such Liens attach at all times only to the Equity Interests or assets of such Restricted Subsidiary and its Subsidiaries;

(h)Liens on property not constituting Collateral securing Indebtedness or other obligations (i) of the Borrower or a Restricted Subsidiary in favor of a Credit Party and (ii) of any Restricted Subsidiary that is not a Credit Party in favor of any Restricted Subsidiary that is not a Credit Party;

(i)Liens (i) of a collecting bank arising under Section 4-210 of the Uniform Commercial Code on items in the course of collection, (ii) attaching to commodity trading accounts or other commodity brokerage accounts incurred in the ordinary course of business and (iii) in favor of a banking institution arising as a matter of law encumbering deposits (including the right of set-off);

(j)Liens (i) on cash advances in favor of the seller of any property to be acquired in an Investment permitted pursuant to Section 10.5 to be applied against the purchase price for such Investment, and (ii) consisting of an agreement to Dispose of any property in a transaction permitted under Section 10.4, in each case, solely to the extent such Investment or Disposition, as the case may be, would have been permitted on the date of the creation of such Lien;

(k)Liens arising out of conditional sale, title retention, consignment or similar arrangements for sale or purchase of goods entered into by the Borrower or any of the Restricted Subsidiaries in the ordinary course of business permitted by this Agreement;

(l)Liens deemed to exist in connection with Investments in repurchase agreements permitted under Section 10.5;

(m)Liens encumbering reasonable customary initial deposits and margin deposits and similar Liens attaching to brokerage accounts incurred in the ordinary course of business and not for speculative purposes;

(n)Liens that are contractual rights of set-off (i) relating to the establishment of depository relations with banks not given in connection with the issuance or incurrence of Indebtedness, (ii) relating to pooled deposit or sweep accounts of the Borrower or any Restricted Subsidiary to permit satisfaction of overdraft or similar obligations incurred in the ordinary course of business of the Borrower and the Restricted Subsidiaries or (iii) relating to purchase orders and other agreements entered into with customers of the Borrower or any Restricted Subsidiary in the ordinary course of business;

(o)Liens solely on any cash earnest money deposits made by the Borrower or any of the Restricted Subsidiaries in connection with any letter of intent or purchase agreement permitted hereunder;

(p)Liens on insurance policies and the proceeds thereof securing the financing of the premiums with respect thereto;

(q)Liens in respect of Production Payments and Reserve Sales, subject to adjustment of the Borrowing Base pursuant to the Borrowing Base Adjustment Provisions to the extent required under Section

10.4(b); provided that such Liens attach at all times only to the Oil and Gas Properties from which the Production Payments and Reserve Sales have been conveyed;

(r)the prior right of consignees and their lenders under consignment arrangements entered into in the ordinary course of business;

(s)agreements to subordinate any interest of the Borrower or any Restricted Subsidiary in any accounts receivable or other proceeds arising from inventory consigned by the Borrower or any Restricted Subsidiary pursuant to an agreement entered into in the ordinary course of business;

(t)Liens on Equity Interests in a joint venture securing obligations of such joint venture so long as the assets of such joint venture do not constitute Collateral;

(u)Liens securing any Indebtedness or other obligations permitted by Section 10.1(m) and Section 10.1(x);

(v)Liens arising pursuant to Section 107(l) of the Comprehensive Environmental Response, Compensation and Liability Act, 42 U.S.C. § 9607(l), or other Environmental Law, unless such Lien (i) by action of the lienholder, or by operation of law, takes priority over any Liens arising under the Credit Documents on the property upon which it is a Lien, and (ii) materially impairs the use of the property covered by such Lien for the purposes for which such property is held;

(w)Liens on not more than $20,000,000 of deposits securing Hedging Obligations in respect of Hedge Agreements with counterparties other than Hedge Banks that were not entered into for speculative purposes;

(x)Junior Liens on the Collateral to secure the Junior Lien Notes, the EnVen Notes, any QuarterNorth Acquisition Debt, anyPermitted Incremental Junior Lien Debt, and any Permitted Refinancing Indebtedness in respect thereof;

(y)any amounts held by a trustee under any indenture or other debt agreement issued in escrow pursuant to customary escrow arrangements pending the release thereof, or under any indenture or other debt agreement pursuant to customary discharge, redemption or defeasance provisions;

(z)Liens on property (excluding property constituting Borrowing Base Properties, Equity Interests of the Borrower or its Subsidiaries pledged as Collateral, and deposit accounts, securities accounts and commodity accounts pledged as Collateral) securing Indebtedness permitted under Section 10.1(o); and

(aa)Liens securing Indebtedness pursuant to the Whitney Term Loan Documents.

10.3Limitation on Fundamental Changes. Except as permitted by Section 10.4 (other than Section 10.4(d)) or 10.5, the Borrower will not, and will not permit any of the Restricted Subsidiaries to, enter into any merger, consolidation or amalgamation, or liquidate, wind up or dissolve itself (or suffer any liquidation or dissolution), or Dispose of, all or substantially all its business units, assets or other properties, except that:

(a)any Subsidiary of the Borrower or any other Person may be merged, amalgamated or consolidated with or into the Borrower; provided that (i) the Borrower shall be the continuing or surviving Person or, in the case of a merger, amalgamation or consolidation with or into the Borrower, the Person formed by or surviving any such merger, amalgamation or consolidation (if other than the Borrower) shall be an entity

organized or existing under the laws of the United States, any state thereof, the District of Columbia or any territory thereof (the Borrower or such Person, as the case may be, being herein referred to as the “Successor Borrower”), (ii) the Successor Borrower (if other than the Borrower) shall expressly assume all the obligations of the Borrower under this Agreement and the other Credit Documents pursuant to a supplement hereto or thereto in form reasonably satisfactory to the Administrative Agent, (iii) no Borrowing Base Deficiency, Default or Event of Default has occurred and is continuing at the date of such merger, amalgamation or consolidation or would result from such consummation of such merger, amalgamation or consolidation, and (iv) if such merger, amalgamation or consolidation involves the Borrower and a Person that, prior to the consummation of such merger, amalgamation or consolidation, is not a Subsidiary of the Borrower (A) the Successor Borrower shall be in Pro Forma Compliance after giving effect to such merger, amalgamation or consolidation, (B) each Guarantor, unless it is the other party to such merger, amalgamation or consolidation or unless the Successor Borrower is the Borrower, shall have by a supplement to the Guarantee confirmed that its Guarantee shall apply to the Successor Borrower’s obligations under this Agreement, (C) each Subsidiary grantor and each Subsidiary pledgor, unless it is the other party to such merger, amalgamation or consolidation or unless the Successor Borrower is the Borrower, shall have by a supplement to the Credit Documents confirmed that its obligations thereunder shall apply to the Successor Borrower’s obligations under this Agreement, (D) each mortgagor of a Mortgaged Property, unless it is the other party to such merger or consolidation or unless the Successor Borrower is the Borrower, shall have by an amendment to or ratification of the applicable Mortgage confirmed that its obligations thereunder shall apply to the Successor Borrower’s obligations under this Agreement, (E) the Borrower shall have delivered to the Administrative Agent an officer’s certificate stating that such merger, amalgamation or consolidation and any supplements to the Credit Documents preserve the enforceability of the Guarantee and the perfection and priority of the Liens under the Security Documents, (F) if reasonably requested by the Administrative Agent, an opinion of counsel shall be required to be provided to the effect that such merger, amalgamation or consolidation does not violate this Agreement or any other Credit Document; provided, further, that if the foregoing are satisfied, the Successor Borrower (if other than the Borrower) will succeed to, and be substituted for, the Borrower under this Agreement and (G) such merger, amalgamation or consolidation shall comply with all the conditions set forth in the definition of the term “Permitted Acquisition” or is otherwise permitted under Section 10.5;

(b)any Subsidiary of the Borrower or any other Person may be merged, amalgamated or consolidated with or into any one or more Subsidiaries of the Borrower; provided that (i) in the case of any merger, amalgamation or consolidation involving one or more Restricted Subsidiaries, (A) a Restricted Subsidiary shall be the continuing or surviving Person or (B) the Borrower shall take all steps necessary to cause the Person formed by or surviving any such merger, amalgamation or consolidation (if other than a Restricted Subsidiary) to become a Restricted Subsidiary, (ii) in the case of any merger, amalgamation or consolidation involving one or more Guarantors, a Guarantor shall be the continuing or surviving Person or the Person formed by or surviving any such merger, amalgamation or consolidation (if other than a Guarantor) shall execute a supplement to the Guarantee, the Collateral Agreement and any applicable Mortgage, and a joinder to the Intercompany Note, each in form and substance reasonably satisfactory to the Collateral Agent in order for the surviving Person to become a Guarantor, and pledgor, mortgagor and grantor of Collateral for the benefit of the Secured Parties and to acknowledge and agree to the terms of the Intercompany Note, (iii) no Borrowing Base Deficiency, Default or Event of Default has occurred and is continuing on the date of such merger, amalgamation or consolidation or would result from the consummation of such merger, amalgamation or consolidation and (iv) if such merger, amalgamation or consolidation involves a Subsidiary and a Person that, prior to the consummation of such merger, amalgamation or consolidation, is not a Restricted Subsidiary of the Borrower, (A) the Borrower shall be in Pro Forma Compliance after giving effect to such merger, amalgamation or consolidation, (B) the Borrower shall have delivered to the Administrative Agent an officer’s certificate stating that such merger, amalgamation or consolidation and such supplements to any Credit Document preserve the enforceability of the Guarantee and the

perfection and priority of the Liens under the Collateral Agreement and (C) such merger, amalgamation or consolidation shall comply with all the conditions set forth in the definition of the term “Permitted Acquisition” or is otherwise permitted under Section 10.5;

(c)any Restricted Subsidiary that is not a Guarantor may (i) merge, amalgamate or consolidate with or into any other Restricted Subsidiary or (ii) Dispose of any or all of its assets (upon voluntary liquidation or otherwise) to the Borrower, a Guarantor or any other Restricted Subsidiary of the Borrower (provided that the Borrower shall, and cause any applicable Restricted Subsidiary to, comply with the provisions of Section 9.11 as applicable);

(d)any Subsidiary Guarantor may (i) merge, amalgamate or consolidate with or into any other Subsidiary Guarantor, (ii) merge, amalgamate or consolidate with or into any other Subsidiary which is not a Guarantor or Dispose of any or all of its assets (upon voluntary liquidation or otherwise) to any other Subsidiary that is not a Guarantor; provided that if such Subsidiary Guarantor is not the surviving entity, such merger, amalgamation or consolidation shall be deemed to be, and any such Disposition shall be, (A) an “Investment” and subject to the limitations set forth in Section 10.5 and (B) a “Disposition” and subject to the limitations set forth in Section 10.4(b); and (iii) Dispose of any or all of its assets (upon voluntary liquidation or otherwise) to the Borrower or any other Guarantor;

(e)any Restricted Subsidiary may liquidate or dissolve if (i) the Borrower determines in good faith that such liquidation or dissolution is in the best interests of the Borrower and is not materially disadvantageous to the Lenders and (ii) to the extent such Restricted Subsidiary is a Credit Party, any assets or business of such Restricted Subsidiary not otherwise Disposed of or transferred in accordance with Section 10.4 or 10.5, in the case of any such business, discontinued, shall be transferred to, or otherwise owned or conducted by, a Credit Party after giving effect to such liquidation or dissolution;

(f)the Borrower and its Restricted Subsidiaries may consummate the Transactions; and

(g)to the extent that no Borrowing Base Deficiency, Default or Event of Default then exists or would result from the consummation of such Disposition, the Borrower and the Restricted Subsidiaries may consummate a merger, dissolution, liquidation, consolidation or Disposition, the purpose of which is to effect a Disposition permitted pursuant to Section 10.4.

10.4Limitation on Sale of Assets. The Borrower will not, and will not permit any of the Restricted Subsidiaries to, (x) convey, sell, lease, sell and leaseback, assign, farm-out, transfer or otherwise dispose (in one transaction or in a series of transactions and whether effected pursuant to a division or otherwise) (each of the foregoing a “Disposition”) of any of its property, business or assets (including receivables and leasehold interests), whether now owned or hereafter acquired or (y) sell to any Person (other than the Borrower or a Guarantor) any shares owned by it of any Restricted Subsidiary’s Equity Interests, except that:

(a)the Borrower and the Restricted Subsidiaries may Dispose of (i) inventory and other goods held for sale, including Hydrocarbons, obsolete, worn out, used or surplus equipment, vehicles and other assets (other than accounts receivable) in the ordinary course of business (including equipment that is no longer necessary for the business of the Borrower or its Restricted Subsidiaries or is replaced by equipment of at least comparable value and use), (ii) Permitted Investments, and (iii) assets for the purposes of charitable contributions or similar gifts to the extent such assets are not material to the ability of the Borrower and its Restricted Subsidiaries, taken as a whole, to conduct its business in the ordinary course;

(b)the Borrower and the Restricted Subsidiaries may Dispose of any Oil and Gas Properties or any interest therein or the Equity Interests of any Restricted Subsidiary or of any Minority Investment owning Oil and Gas Properties or designate any Restricted Subsidiary as an Unrestricted Subsidiary (subject to the conditions set forth in the definition thereof) (and including, but without limitation, Dispositions in respect of Production Payments and Reserve Sales and in connection with net profits interests, operating agreements, farm-ins, joint exploration and development agreements and other agreements customary in the oil and gas industry for the purpose of developing such Oil and Gas Properties); provided that such Disposition is for Fair Market Value; provided, further, that if such Disposition of Oil and Gas Properties includes Borrowing Base Properties, or of any Equity Interests of any Restricted Subsidiary or Minority Investment owning Oil and Gas Properties involves Borrowing Base Properties, or any Restricted Subsidiary that owns Borrowing Base Properties is designated as an Unrestricted Subsidiary, in each case, included in the most recently delivered Reserve Report and the aggregate Borrowing Base Value of all such Borrowing Base Properties directly or indirectly Disposed of since the later of (i) the last Scheduled Redetermination Date and (ii) the last adjustment of the Borrowing Base made pursuant to Section 2.14(g) exceeds 500 of the then-effective Borrowing Base (or 7.500 of the then-effective Borrowing Base when aggregated with all terminations or creations of any off-setting positions in respect of any commodity hedge positions), then no later than two Business Days after the date of consummation of any such Disposition, the Borrower shall provide notice to the Administrative Agent of such Disposition and the Borrowing Base Properties so Disposed and the Borrowing Base shall be adjusted in accordance with the Borrowing Base Adjustment Provisions; provided, further, that to the extent that the Borrower is notified by the Administrative Agent that a Borrowing Base Deficiency could result from an adjustment to the Borrowing Base resulting from such Disposition, after the consummation of such Disposition(s), the Borrower shall have received net cash proceeds, or shall have cash on hand, sufficient to eliminate any such potential Borrowing Base Deficiency;

(c)the Borrower and the Restricted Subsidiaries may Dispose of property or assets to the Borrower or to a Restricted Subsidiary; provided that if the transferor of such property is a Credit Party (i) the transferee thereof must either be a Credit Party or (ii) such transaction is permitted under Section 10.5;

(d)to the extent constituting a Disposition, the Borrower and any Restricted Subsidiary may affect any transaction permitted by Section 10.2, 10.3, 10.5 or 10.6;

(e)the Borrower and the Restricted Subsidiaries may lease, sublease, license or sublicense (on a non-exclusive basis with respect to any intellectual property) real, personal or intellectual property in the ordinary course of business;

(f)Dispositions (including like-kind exchanges) of property (other than Borrowing Base Properties) to the extent that (i) such property is exchanged for credit against the purchase price of similar replacement property or (ii) the proceeds of such Disposition are applied to the purchase price of such replacement property, in each case under Section 1031 of the Code or otherwise;

(g)Dispositions of Hydrocarbon Interests to which no Proved Reserves are attributable and farm-outs of undeveloped acreage to which no Proved Reserves are attributable and assignments in connection with such farm-outs;

(h)Dispositions of Investments in joint ventures (regardless of the form of legal entity) to the extent required by, or made pursuant to, customary buy/sell arrangements between the joint venture parties set forth in joint venture arrangements and similar binding arrangements to the extent the same would be permitted under Section 10.5(i);

(i)Dispositions listed on Schedule 10.4(i) (each, a “Scheduled Disposition” and collectively, the “Scheduled Dispositions”);

(j)transfers of property (i) subject to a Casualty Event or in connection with any condemnation proceeding, in each case, with respect to Collateral, provided that the net cash proceeds of such Casualty Event or condemnation proceeding, if any, are received by the Borrower or a Subsidiary Guarantor or (ii) in connection with any Casualty Event or any condemnation proceeding, in each case with respect to property that does not constitute Collateral;

(k)Dispositions of accounts receivable (i) in connection with the collection or compromise thereof or (ii) to the extent the proceeds thereof are used to prepay any Loans then outstanding;

(l)the unwinding of any Hedge Transaction (subject to the terms of the Borrowing Base Adjustment Provisions);

(m)Dispositions of Oil and Gas Properties that are not Borrowing Base Properties, provided that if a Borrowing Base Deficiency then exists, the proceeds of any such Disposition shall be used to repay Loans or Cash Collateralize L/C Obligations;

(n)if no Default, Event of Default or Borrowing Base Deficiency then exists or would result therefrom, sales and other dispositions of Properties that are not regulated by Section 10.4(a) through (m) and having a fair market value not to exceed $25,000,000 during any 12-month period; and

(o)Dispositions of any asset between or among the Borrower and/or its Restricted Subsidiaries as a substantially concurrent interim Disposition in connection with an Investment otherwise permitted pursuant to Section 10.5 or a Disposition otherwise permitted pursuant to clauses (a) through (n) above.

Notwithstanding anything herein to the contrary, any direct or indirect transfer, conveyance or other disposition of Borrowing Base Properties and the Equity Interests of any Restricted Subsidiary or any Minority Investment owning Borrowing Base Properties (whether as a sale, lease, Investment, dividend or due to the issuance of Equity Interests by a Subsidiary Guarantor to a Person other than a Credit Party) shall be subject to Section 10.4(b).

10.5Limitation on Investments. The Borrower will not, and will not permit any of the Restricted Subsidiaries, to (i) purchase or acquire (including pursuant to any merger, consolidation or amalgamation with a person that is not a Wholly owned Subsidiary immediately prior to such merger, consolidation or amalgamation) any Equity Interests, evidences of Indebtedness or other securities of any other Person, (ii) make any loans or advances to or guarantees of the Indebtedness of any other person, or (iii) purchase or otherwise acquire (in one transaction or a series of related transactions) (x) all or substantially all of the property and assets or business of another Person or (y) assets constituting a business unit, line of business or division of such Person (each, an “Investment”), except:

(a)extensions of trade credit and purchases of assets and services (including purchases of inventory, supplies and materials) in the ordinary course of business;

(b)Investments in assets that constituted Permitted Investments at the time such Investments were made;

(c)loans and advances to officers, directors, employees and consultants of the Borrower (or any direct or indirect parent thereof) or any of its Restricted Subsidiaries (i) for reasonable and customary

business-related travel, entertainment, relocation and analogous ordinary business purposes (including employee payroll advances), (ii) in connection with such Person’s purchase of Equity Interests of the Borrower (or any direct or indirect parent thereof; provided that, to the extent such loans and advances are made in cash, the amount of such loans and advances used to acquire such Equity Interests shall be contributed to the Borrower in cash) and (iii) for purposes not described in the foregoing subclauses (i) and (ii); provided that the aggregate principal amount outstanding pursuant to subclause (iii) shall not exceed $10,000,000;

(d)(i) Investments existing on, or made pursuant to legally binding written commitments in existence on, the Closing Date as set forth on Schedule 10.5(d), (ii) Investments existing on the Closing Date of the Borrower or any Subsidiary in any other Subsidiary and (iii) any extensions, renewals or reinvestments thereof, so long as the amount of any Investment made pursuant to this clause (d) is not increased at any time above the amount of such Investment set forth on Schedule 10.5(d) (other than pursuant to an increase as required by the terms of any such Investment as in existence on the Closing Date and set forth on Schedule 10.5(d) as of the Closing Date);

(e)Investments received in connection with the bankruptcy or reorganization of suppliers or customers and in settlement of delinquent obligations of, and other disputes with, customers arising in the ordinary course of business or upon foreclosure with respect to any secured Investment or other transfer of title with respect to any secured Investment;

(f)Investments to the extent that payment for such Investments is made with Qualified Equity Interests;

(g)Investments (i) by the Borrower in any Guarantor or by any Guarantor in the Borrower, (ii) by any Restricted Subsidiary that is not a Guarantor in any other Restricted Subsidiary that is not a Guarantor, and (iii) by the Borrower or any Guarantor in any Restricted Subsidiary that is not a Guarantor, valued at the Fair Market Value (determined by the Borrower in good faith) of such Investment at the time each such Investment is made, in an aggregate amount outstanding pursuant to this Section 10.5(g)(iii) that, at the time such Investment is made, would not exceed the sum of (A) the greater of $50,000,000 and 2.5% of Adjusted Consolidated Net Tangible Assets (measured as of the date such Investment is made based upon the financial statements most recently available prior to such date), (B) [intentionally omitted], and (C) an amount equal to any repayments, interest, returns, profits, distributions, income and similar amounts actually received in cash in respect of any such Investment (which amount shall not exceed the amount of such Investment valued at the Fair Market Value of such Investment at the time such Investment was made);

(h)Investments constituting Permitted Acquisitions; provided that the aggregate amount of Permitted Acquisition Consideration of such Permitted Acquisitions made or provided by the Borrower or any Subsidiary Guarantor to acquire any Restricted Subsidiary that does not become a Subsidiary Guarantor or merge, consolidate or amalgamate into the Borrower or a Subsidiary Guarantor or any assets that shall not, immediately after giving effect to such Permitted Acquisition, be owned by the Borrower or a Subsidiary Guarantor, shall not exceed the sum of (i) the greater of $50,000,000 and 2.5% of Adjusted Consolidated Net Tangible Assets after giving effect to such Permitted Acquisitions, (ii) [intentionally omitted], and (iii) an amount equal to any repayments, interest, returns, profits, distributions, income and similar amounts actually received in cash in respect of any such Investment (which amount shall not exceed the amount of such Investment valued at the Fair Market Value of such Investment at the time such Investment was made);

(i)Investments (including but not limited to (i) Minority Investments and Investments in Unrestricted Subsidiaries, (ii) Investments in joint ventures (regardless of the form of legal entity) or similar Persons that do not constitute Restricted Subsidiaries, (iii) Investments in Subsidiaries that are not Credit Parties

and (iv) Investments in respect of royalty trusts and master limited partnerships), in each case, valued at the Fair Market Value (determined by the Borrower acting in good faith) of such Investment at the time each such Investment is made; provided that, in each case, after giving pro forma effect to the making of any such Investment, (A) no Default or Event of Default shall have occurred and be continuing, (B) the Borrower shall have Available Commitments of not less than 25% of the then effective Loan Limit (on a pro forma basis after giving effect to such Investment), (C) the Borrower is in compliance on a Pro Forma Basis with the Current Ratio, and (D) either (1) as of the most recently ended fiscal quarter for which Section 9.1 Financials are available after giving pro forma effect to any such Investment, the Consolidated Total Debt to EBITDAX Ratio is not greater than 1.75 to 1.00 and the aggregate amount of such Investments shall not exceed the Available Free Cash Flow Amount at the time made or (2) as of the most recently ended fiscal quarter for which Section 9.1 Financials are available after giving pro forma effect to any such Investment, the Consolidated Total Debt to EBITDAX Ratio is not greater than 1.00 to 1.00 (in which case, without regard to the Available Free Cash Flow Amount at the time made); further provided that intercompany current liabilities incurred in the ordinary course of business and consistent with past practices, in connection with the cash management operations of the Borrower and the Subsidiaries shall not be included in calculating any limitations in this paragraph at any time;

(j)Investments in the Oil and Gas Business made at any such time during which, after giving effect to the making of any such Investment on a Pro Forma Basis, (i) no Event of Default shall have occurred and be continuing and (ii) Liquidity is not less than 10% of the then effective Borrowing Base;

(k)Investments constituting non-cash proceeds of Dispositions of assets (to the extent non-cash proceeds are permitted in consideration of such Disposition by Section 10.4);

(l)subject to Section 10.6, Investments made to repurchase or retire Equity Interests of the Borrower or any direct or indirect parent thereof owned by any employee or any stock ownership plan or key employee stock ownership plan of the Borrower (or any direct or indirect parent thereof);

(m)Investments consisting of Restricted Payments permitted under Section 10.6;

(n)loans and advances to any direct or indirect parent of the Borrower in lieu of, and not in excess of the amount of, Restricted Payments to the extent permitted to be made to such parent in accordance with Section 10.6;

(o)Investments consisting of extensions of credit in the nature of accounts receivable or notes receivable arising from the grant of trade credit in the ordinary course of business, and Investments received in satisfaction or partial satisfaction thereof from financially troubled account debtors and other credits to suppliers in the ordinary course of business;

(p)Investments in the ordinary course of business consisting of endorsements for collection or deposit and customary trade arrangements with customers consistent with past practices;

(q)advances of payroll payments to employees, consultants or independent contractors or other advances of salaries or compensation to employees, consultants or independent contractors, in each case in the ordinary course of business;

(r)guarantee obligations of the Borrower or any Restricted Subsidiary of leases (other than Capital Leases) or of other obligations that do not constitute Indebtedness, in each case entered into in the ordinary course of business;

(s)Investments held by a Person acquired (including by way of merger or consolidation) after the Closing Date otherwise in accordance with this Section 10.5 to the extent that such Investments were not made in contemplation of or in connection with such acquisition, merger or consolidation and were in existence on the date of such acquisition, merger or consolidation;

(t)Investments in Industry Investments and in interests in additional Oil and Gas Properties and gas gathering systems related thereto or Investments related to farm-out, farm-in, joint operating, joint venture, joint development or other area of mutual interest agreements, other similar industry investments, gathering systems, pipelines or other similar oil and gas exploration and production business arrangements whether through direct ownership or ownership through a joint venture or similar arrangement;

(u)to the extent constituting Investments, the Transactions;

(v)Investments in Hedge Transactions of the Borrower or any Restricted Subsidiary permitted by Section 10.1 and Section 10.10;

(w)Investments consisting of Indebtedness, fundamental changes, Dispositions and Restricted Payments permitted under, respectively, Sections 10.1, 10.3, 10.4 and 10.6 (other than 10.6(c));

(x)in the case of the Borrower and its Restricted Subsidiaries, Investment consisting of (i) intercompany Indebtedness having a term not exceeding 364 days (inclusive of any roll-over or extensions of terms) and made in the ordinary course of business and (ii) intercompany current liabilities in connection with the cash management, tax and accounting operations of the Borrower and the Restricted Subsidiaries;

(y)Investments resulting from pledges and deposits under clauses (c), (d) and (e) of the definition of “Permitted Liens” and clauses (j), (o), (w) and (y) of Sections 10.2;

(z)advances in the form of a prepayment of expenses, so long as such expenses are being paid in accordance with customary trade terms of the Borrower or the relevant Restricted Subsidiary;

(aa)Investments consisting of licensing of intellectual property pursuant to joint marketing arrangements with other Persons in the ordinary course of business;

(bb)any Investment constituting a Disposition or transfer of any asset between or among the Borrower and/or its Restricted Subsidiaries as a substantially concurrent interim Disposition or transfer in connection with an Investment otherwise permitted pursuant to clauses (a) through (aa) above or in connection with a Disposition permitted pursuant to Section 10.4; and

(cc)Investments in Unrestricted Subsidiaries substantially all of whose business consists of engaging in the activities set forth in clause (c) of the definition of “Oil and Gas Business” and any business or activity relating to, arising from, or necessary, appropriate, incidental or ancillary to such activities, in an aggregate amount pursuant to this Section 10.5(cc) not exceeding $100,000,000, provided that, in each case, after giving pro forma effect to the making of any such Investment, (i) no Default or Event of Default shall have occurred and be continuing and (ii) the Borrower shall have Available Commitments of not less than 25% of the then effective Loan Limit (on a pro forma basis after giving effect to such Investment).

10.6Limitation on Restricted Payments. The Borrower will not directly or indirectly pay any dividend or make any other distribution (by reduction of capital or otherwise), whether in cash, property, securities or a combination thereof, with respect to any of its Equity Interests (other than dividends and distributions on Equity

Interests payable solely by the issuance of additional Qualified Equity Interests) or redeem, purchase, retire or otherwise acquire for value any of its Equity Interests or the Equity Interests of any Parent Entity or set aside any amount for any such purpose (other than through the issuance of additional Qualified Equity Interests), or permit any Restricted Subsidiary to purchase or otherwise acquire for consideration (except in connection with an Investment permitted under Section 10.5) any Equity Interests of the Borrower or any Parent Entity, now or hereafter outstanding (all of the foregoing, “Restricted Payments”); except that:

(a)the Borrower may (or may pay Restricted Payments to permit any Parent Entity thereof to) redeem in whole or in part any of its or a Parent Entity’s Equity Interests in exchange for another class of its (or such parent’s) Equity Interests or with proceeds from substantially concurrent equity contributions or issuances of new Equity Interests; provided that such new Equity Interests contain terms and provisions at least as advantageous to the Lenders in all material respects to their interests as those contained in the Equity Interests redeemed thereby, and the Borrower may pay Restricted Payments payable solely in the Equity Interests (other than Disqualified Stock not otherwise permitted by Section 10.1) of the Borrower;

(b)the Borrower may (i) (or may make Restricted Payments to permit any Parent Entity thereof to) redeem, acquire, retire or repurchase shares of its (or such Parent Entity’s) Equity Interests held by any present or former officer, manager, consultant, director or employee (or their respective Affiliates, estates, spouses, former spouses, successors, executors, administrators, heirs, legatees, distributees or immediate family members) of the Borrower and its Subsidiaries or any Parent Entity thereof, upon the death, disability, retirement or termination of employment of any such Person or otherwise in accordance with any equity option or equity appreciation rights plan, any management, director and/or employee equity ownership, benefit or incentive plan or agreement, equity subscription plan, employment termination agreement or any other employment agreements or equity holders’ agreement; provided that, non-discretionary repurchases, acquisitions, retirements or redemptions pursuant to the terms of any equity option or equity appreciation rights plan, any management, director and/or employee equity ownership, benefit or incentive plan or agreement, equity subscription plan, employment termination agreement or any other employment agreements or equity holders’ agreement, the aggregate amount of all cash paid in respect of all such Equity Interests so redeemed, acquired, retired or repurchased in any calendar year does not exceed the sum of (A) $20,000,000 (with unused amounts in any calendar year being carried over to succeeding calendar years subject to a maximum of $40,000,000 in any calendar year) plus (B) all net cash proceeds obtained by or contributed to the Borrower during such calendar year from the sales of Equity Interests to other present or former officers, consultants, employees, directors and managers in connection with any permitted compensation and incentive arrangements plus (C) all net cash proceeds obtained from any key-man life insurance policies received during such calendar year plus (D) the amount of any cash bonuses otherwise payable to members of management, directors or consultants of Holdings, any Parent Entity, the Borrower or its Subsidiaries in connection with the Transactions that are foregone in return for the receipt of Equity Interests; notwithstanding the foregoing, 100% of the unused amount of payments in respect of Section 10.6(b)(i) (before giving effect to any carry-forward described in clause (A) of the foregoing proviso) may be carried forward to the two immediately succeeding fiscal years (but not any other) and utilized to make payments pursuant to this Section 10.6(b)(i); and provided, further, that cancellation of Indebtedness owing to the Borrower or any Restricted Subsidiary from members of management of Holdings, any Parent Entity, the Borrower or its Restricted Subsidiaries in connection with a repurchase of Equity Interests of Holdings or any other Parent Entity will not be deemed to constitute a Restricted Payment for purposes of this Section 10.6; and (ii) pay Restricted Payments in an amount equal to withholding or similar Taxes payable or expected to be payable by any present or former employee, director, manager or consultant (or their respective Affiliates, estates or immediate family members) and any repurchases of Equity Interests in consideration of such payments including deemed repurchases in connection with the exercise of stock options so long as the amount of such payments does not exceed $10,000,000 in the aggregate;

(c)to the extent constituting Restricted Payments, the Borrower may make Investments permitted by Section 10.5;

(d)to the extent constituting Restricted Payments, the Borrower may enter into and consummate transactions expressly permitted by Section 10.3;

(e)the Borrower may repurchase Equity Interests of the Borrower (or any Parent Entity thereof) upon exercise of stock options or warrants if such Equity Interests represents all or a portion of the exercise price of such options or warrants;

(f)the Borrower may make and pay Restricted Payments to Holdings or any other Parent Entity of the Borrower:

(i)the proceeds of which will be used to pay (or to make Restricted Payments to allow Holdings or any other Parent Entity to pay): (A) with respect to any taxable period for which the Borrower and/or any of its Subsidiaries are members of a consolidated, combined, affiliated, unitary or similar income tax group for U.S. federal and/or applicable state or local income tax purposes of which a Parent Entity is the common parent, or for which the Borrower is a partnership or disregarded entity for U.S. federal income tax purposes that is wholly owned (directly or indirectly) by a C corporation for U.S. federal and/or applicable state or local income tax purposes, distributions to any Parent Entity of the Borrower in an amount not to exceed the amount of any U.S. federal, state and/or local income taxes that the Borrower and/or its Subsidiaries, as applicable, would have paid for such taxable period had the Borrower and/or its Subsidiaries, as applicable, been a stand-alone corporate taxpayer or a stand—alone corporate group, and (B) with respect to any taxable period ending after the Closing Date for which the Borrower is a partnership or disregarded entity for U.S. federal income tax purposes (other than a partnership or disregarded entity described in subclause (A)), distributions to any Parent Entity in an amount necessary to permit such Parent Entity to make a pro rata distribution to its equity holders such that each such equity holder receives an amount from such pro rata distribution sufficient to enable such equity holder to pay its U.S. federal, state and/or local income taxes (as applicable) attributable to its direct or indirect ownership of the Borrower and its Subsidiaries with respect to such taxable period (assuming that each such equity holder is subject to tax at the highest combined marginal federal, state, and/or local income tax rate applicable to any such equity holder for such taxable period and taking into account the deductibility of state and local income taxes for U.S. federal income tax purposes (and any limitations thereon), the alternative minimum tax, any cumulative net taxable loss of the Borrower for prior taxable periods ending after the Closing Date to the extent such loss is of a character that would allow such loss to be available to reduce taxes in the current taxable period (taking into account any limitations on the utilization of such loss to reduce such taxes and assuming such loss had not already been utilized) and the character (e.g., long-term or short-term capital gain or ordinary or exempt) of the applicable income);

(ii)the proceeds of which shall be used to allow any Parent Entity to pay its operating expenses incurred in the ordinary course of business and other corporate overhead costs and expenses (including administrative, legal, accounting and other professional costs and expenses) to the extent attributable to the ownership or operation of the Borrower, it being understood that 100% of the foregoing costs and expenses shall be deemed attributable to the ownership and operation of the Borrower at all times when Holdings owns no material assets other than the Equity Interests of the Borrower;

(iii)the proceeds of which shall be used by such Parent Entities to pay Restricted Payments contemplated by Section 10.6(b);

(iv)the proceeds of which shall be used to make Restricted Payments to allow any Parent Entity to pay fees and expenses related to any equity issuance or offering or debt issuance, incurrence or offering, Disposition or acquisition or investment transaction permitted by this Agreement, whether or not consummated;

(v)the proceeds of which shall be used to pay fees and expenses (including franchise or similar taxes) required to maintain its corporate existence, customary salary, bonus and other benefits payable to, and indemnities provided on behalf of, officers, employees and consultants of any Parent Entity, to the extent such salaries, bonuses, other benefits and indemnities are attributable to the ownership or operation of the Borrower and the Restricted Subsidiaries, it being understood that 100% of the foregoing costs and expenses shall be deemed attributable to the ownership and operation of the Borrower at all times when Holdings owns no material assets other than the Equity Interests of the Borrower; and

(vi)in the form of Equity Interests of the Borrower (other than Disqualified Stock not otherwise permitted by Section 10.1);

(g)the Borrower or any of the Restricted Subsidiaries may (i) pay cash in lieu of fractional shares in connection with any dividend, split or combination thereof or any Permitted Acquisition and (ii) so long as, after giving effect thereto on a Pro Forma Basis, (A) no Default or Event of Default shall have occurred and be continuing and (B) no Borrowing Base Deficiency exists, honor any conversion request by a holder of convertible Indebtedness and make cash payments in lieu of fractional shares in connection with any such conversion and may make payments on convertible Indebtedness in accordance with its terms;

(h)the Borrower may pay any dividends or distributions within 60 days after the date of declaration thereof, if at the date of declaration such payment would have complied with the provisions of this Agreement;

(i)so long as after giving pro forma effect to the making of any such Restricted Payment, together with any concurrent Restricted Payments being paid under Sections 10.6(j), (i) no Default or Event of Default shall have occurred and be continuing, (ii) the Borrower shall have Available Commitments of not less than 25% of the then effective Loan Limit (on a pro forma basis after giving effect to such Restricted Payment), (iii) the Borrower is in compliance on a Pro Forma Basis with the Current Ratio, and (iv) either (A) as of the most recently ended fiscal quarter for which Section 9.1 Financials are available after giving pro forma effect to any such Restricted Payment, the Consolidated Total Debt to EBITDAX Ratio is not greater than 1.75 to 1.00, and the aggregate amount of such Restricted Payments shall not exceed the Available Free Cash Flow Amount at the time made or (B) as of the most recently ended fiscal quarter for which Section 9.1 Financials are available after giving pro forma effect to any such Restricted Payment, the Consolidated Total Debt to EBITDAX Ratio is not greater than 1.00 to 1.00 (in which case, without regard to the Available Free Cash Flow Amount at the time made), then the Borrower may declare and pay additional Restricted Payments without limit in cash or otherwise to the holders of its or any Parent Entity’s Equity Interests; provided, that, in the case of any Restricted Payment in the form of assets other than cash, no such Restricted Payment shall be made if a Borrowing Base Deficiency would result from an adjustment to the Borrowing Base resulting from such Restricted Payment (unless the Borrower shall have cash on hand sufficient to eliminate any such potential Borrowing Base Deficiency (in which case, the Borrower shall eliminate any Borrowing Base Deficiency in accordance with Section 5.2(b)(ii)));

(j)[intentionally omitted]; and

(k)the Borrower may consummate the Transactions (and pay fees and expenses in connection therewith on or following the Closing Date) and make payments described in Sections 9.9(a), (f), (g), (h), (j) and (l) (subject to the conditions set out therein).

10.7Limitations on Debt Payments and Amendments.

(a)The Borrower will not, and will not permit any Restricted Subsidiary to prepay, repurchase or redeem or otherwise defease the Junior Lien Notes, the EnVen Notes, any QuarterNorth Acquisition Debt, anyPermitted Incremental Junior Lien Debt, or any Permitted Additional Debt (or any Permitted Refinancing Indebtedness in respect of any of the foregoing) (it being understood that (i) payments of regularly-scheduled cash interest in respect of the Junior Lien Notes, the EnVen Notes, any QuarterNorth Acquisition Debt, any Permitted Incremental Junior Lien Debt, or such Permitted Additional Debt and (ii) payments of regularly-scheduled amortization amounts in respect of the EnVen Notes, in each case, shall be permitted); provided, however, that the Borrower or any Restricted Subsidiary may prepay, repurchase, redeem or defease the Junior Lien Notes, the EnVen Notes, any QuarterNorth Acquisition Debt, anyPermitted Incremental Junior Lien Debt, any such Permitted Additional Debt or any Permitted Refinancing Indebtedness in respect of any of the foregoing (A) in exchange for or with the proceeds of any Permitted Refinancing Indebtedness, (B) by converting or exchanging the Junior Lien Notes, the EnVen Notes, any QuarterNorth Acquisition Debt, anyPermitted Incremental Junior Lien Debt, or any such Permitted Additional Debt to Qualified Equity Interests of the Borrower or any Parent Entity or with proceeds from a contemporaneous issuance of Qualified Equity Interests of the Borrower or any Parent Entity, or (C) so long as after giving pro forma effect to the making of any such prepayment, repurchase, redemption or defeasance, (1) no Default or Event of Default shall have occurred and be continuing, (2) the Borrower shall have Available Commitments of not less than 25% of the then effective Loan Limit (on a pro forma basis after giving effect to such prepayment, repurchase, redemption or defeasance), (3) the Borrower is in compliance on a Pro Forma Basis with the Current Ratio, and (4) either (a) as of the most recently ended fiscal quarter for which Section 9.1 Financials are available after giving pro forma effect to any such prepayment, repurchase, redemption or defeasance, the Consolidated Total Debt to EBITDAX Ratio is not greater than 1.75 to 1.00 (on a Pro Forma Basis after giving effect to such prepayment, repurchase, redemption or defeasance) and the aggregate amount of such prepayments, repurchases, redemptions or defeasances shall not exceed the Available Free Cash Flow Amount at the time made or (b) as of the most recently ended fiscal quarter for which Section 9.1 Financials are available after giving pro forma effect to any such prepayment, repurchase, redemption or defeasance, the Consolidated Total Debt to EBITDAX Ratio is not greater than 1.00 to 1.00 (on a Pro Forma Basis after giving effect to such prepayment, repurchase, redemption or defeasance) (in which case without regard to the Available Free Cash Flow Amount at the time made);

(b)The Borrower will not amend or modify the Junior Lien Notes, the Junior Lien Indenture, the EnVen Notes, the EnVen Notes Indenture, any indenture or credit agreement in respect of any QuarterNorth Acquisition Debt, any indenture or credit agreement in respect of any Permitted Incremental Junior Lien Debt, any indenture or credit agreement in respect of any Permitted Refinancing Indebtedness with respect to the Junior Lien Indenture, the EnVen Notes Indenture, any indenture or credit agreement in respect of any QuarterNorth Acquisition Debt, or any indenture or credit agreement in respect of any Permitted Incremental Junior Lien Debt that constitutes Material Indebtedness or the documentation governing any Permitted Additional Debt that constitutes Material Indebtedness or the terms applicable thereto, in each case, other than amendments or modifications that (A) would not be materially adverse to the Lenders (as determined in good faith by the Borrower), taken as a whole, or (B) otherwise comply with the definition of “Permitted Refinancing Indebtedness” that may be incurred to Refinance any such Indebtedness; provided that no such amendment or

modification shall delete or modify the conditions set forth in the definitions of “Permitted Additional Debt” or “Permitted Refinancing Indebtedness”, as applicable; and

(c)Notwithstanding the foregoing and for the avoidance of doubt, nothing in this Section 10.7 shall prohibit (i) the repayment or prepayment of intercompany subordinated Indebtedness owed among the Borrower and/or the Restricted Subsidiaries, in either case unless an Event of Default has occurred and is continuing and the Borrower has received a notice from the Collateral Agent instructing it not to make or permit the Borrower and/or the Restricted Subsidiaries to make any such repayment or prepayment or (ii) substantially concurrent transfers of credit positions in connection with intercompany debt restructurings so long as such Indebtedness is permitted by Section 10.1 after giving effect to such transfer; provided that in no event shall the Borrower be permitted to use, directly or indirectly, the proceeds of any Loans to prepay, repurchase, redeem or defease the Junior Lien Notes, the EnVen Notes, any QuarterNorth Acquisition Debt, any Permitted Incremental Junior Lien Debt, or any Permitted Additional Debt prior to the first anniversary of the Closing Date.

10.8Negative Pledge Agreements. The Borrower will not, and will not permit any of the Restricted Subsidiaries to, enter into or permit to exist any Contractual Requirement (other than this Agreement or any other Credit Document or any documentation in respect of secured Indebtedness otherwise permitted hereunder) that limits the ability of the Borrower or any Guarantor to create, incur, assume or suffer to exist Liens on property of such Person for the benefit of the Secured Parties with respect to the Obligations or under the Credit Documents; provided that the foregoing shall not apply to each of the following Contractual Requirements that:

(a)(i) exist on the Closing Date and (to the extent not otherwise permitted by this Section 10.8) are listed on Schedule 10.8 and (ii) to the extent Contractual Requirements permitted by subclause (i) are set forth in an agreement evidencing Indebtedness or other obligations, are set forth in any agreement evidencing any Permitted Refinancing Indebtedness incurred to Refinance such Indebtedness or obligation so long as such Permitted Refinancing Indebtedness does not expand the scope of such Contractual Requirement;

(b)are binding on a Restricted Subsidiary at the time such Restricted Subsidiary first becomes a Restricted Subsidiary of the Borrower, so long as such Contractual Requirements were not entered into solely in contemplation of such Person becoming a Restricted Subsidiary of the Borrower;

(c)represent Indebtedness permitted under Section 10.1 of a Restricted Subsidiary of the Borrower that is not a Guarantor so long as such Contractual Requirement applies only to such Subsidiary and its Subsidiaries;

(d)arise pursuant to agreements entered into with respect to any sale, transfer, lease or other Disposition permitted by Section 10.4 and applicable solely to assets under such sale, transfer, lease or other Disposition;

(e)are customary provisions in joint venture agreements and other similar agreements permitted by Section 10.5 and applicable to joint ventures or otherwise arise in agreements that restrict the Disposition or distribution of assets or property in oil and gas leases, joint operating agreements, joint exploration and/or development agreements, participation agreements and other similar agreements entered into in the ordinary course of the oil and gas exploration and development business;

(f)are negative pledges and restrictions on Liens in favor of any holder of Indebtedness permitted under Section 10.1, but solely to the extent any negative pledge relates to the property financed by or the subject of such Indebtedness;

(g)are customary restrictions on leases, subleases, licenses or asset sale agreements otherwise permitted hereby so long as such restrictions relate to the assets subject thereto;

(h)comprise restrictions imposed by any agreement relating to secured Indebtedness permitted pursuant to Section 10.1 to the extent that such restrictions apply only to the property or assets securing such Indebtedness;

(i)are customary provisions restricting subletting or assignment of any lease governing a leasehold interest of the Borrower or any Restricted Subsidiary;

(j)are customary provisions restricting assignment of any agreement entered into in the ordinary course of business;

(k)restrict the use of cash or other deposits imposed by customers under contracts entered into in the ordinary course of business;

(l)are imposed by Requirements of Law;

(m)exist under any documentation governing any Permitted Refinancing Indebtedness incurred to Refinance any Indebtedness but only to the extent such Contractual Requirement is not materially more restrictive, taken as a whole, than the Indebtedness being refinanced;

(n)customary net worth provisions contained in real property leases entered into by any Restricted Subsidiary of the Borrower, so long as the Borrower has determined in good faith that such net worth provisions would not reasonably be expected to impair the ability of the Borrower and the Restricted Subsidiaries to meet their ongoing obligation;

(o)are customary restrictions and conditions contained in the document relating to any Lien, so long as (i) such Lien is a Permitted Lien and such restrictions or conditions relate only to the specific asset subject to such Lien and (ii) such restrictions and conditions are not created for the purpose of avoiding the restrictions imposed by this Section 10.8;

(p)are restrictions imposed by any agreement relating to Indebtedness incurred pursuant to Section 10.1 or Permitted Refinancing Indebtedness in respect thereof, to the extent such restrictions are not materially more restrictive, taken as a whole, than the restrictions contained in the Credit Documents or documentation with respect to the Junior Lien Notes, the EnVen Notes, any QuarterNorth Acquisition Debt, or any Permitted Incremental Junior Lien Debt, as determined by the Borrower in good faith;

(q)are restrictions regarding licenses or sublicenses by the Borrower and the Restricted Subsidiaries of intellectual property in the ordinary course of business (in which case such restriction shall relate only to such intellectual property);

(r)are encumbrances or restrictions contained in an agreement or other instrument of a Person acquired by or merged or consolidated with or into the Borrower or any Restricted Subsidiary, or of an Unrestricted Subsidiary that is designated a Restricted Subsidiary, or that is assumed in connection with the acquisition of assets from such Person, in each case that is in existence at the time of such transaction (but not created in contemplation thereof), which encumbrance or restriction is not applicable to any Person, or the properties or assets of any Person, other than the Person and its Subsidiaries, or the property or assets of the Person and its Subsidiaries, so acquired or designated; and

(s)are encumbrances or restrictions imposed by any amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings of the contracts, instruments or obligations referred to in clauses (a) through (r) above; provided that such amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings are, in the good faith judgment of the Borrower’s board of directors, no more restrictive in any material respect with respect to such encumbrance and other restrictions taken as a whole than those prior to such amendment, modification, restatement, renewal, increase, supplement, refunding, replacement or refinancing.

10.9Limitation on Subsidiary Distributions. The Borrower will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create or otherwise cause or suffer to exist or become effective any consensual encumbrance or consensual restriction on the ability of any such Restricted Subsidiary to pay dividends or make any other distributions to the Borrower or any Restricted Subsidiary on its Equity Interests or with respect to any other interest or participation in, or measured by, its profits or transfer any property to the Borrower or any Restricted Subsidiary except (in each case) for such encumbrances or restrictions existing under or by reason of:

(a)contractual encumbrances or restrictions in effect on the Closing Date, including pursuant to the Credit Documents and any Hedging Obligations;

(b)the Junior Lien Notes, the Junior Lien Indenture, the EnVen Notes, the EnVen Notes Indenture, any indenture or credit agreement in respect of any QuarterNorth Acquisition Debt, any indenture or credit agreement in respect of any Permitted Incremental Junior Lien Debt, and, in each case, the related guarantees (and any Permitted Refinancing Indebtedness with respect thereto);

(c)purchase money obligations for property acquired in the ordinary course of business and Capital Lease Obligations that impose restrictions on transferring the property so acquired;

(d)any applicable Requirement of Law;

(e)any agreement or other instrument of a Person acquired by or merged or consolidated with or into the Borrower or any Restricted Subsidiary, or of an Unrestricted Subsidiary that is designated a Restricted Subsidiary, or that is assumed in connection with the acquisition of assets from such Person, in each case that is in existence at the time of such transaction (but not created in contemplation thereof), which encumbrance or restriction is not applicable to any Person, or the properties or assets of any Person, other than the Person and its Subsidiaries, or the property or assets of the Person and its Subsidiaries, so acquired or designated;

(f)contracts for the sale of assets, including customary restrictions with respect to a Subsidiary of the Borrower pursuant to an agreement that has been entered into for the sale or disposition of all or substantially all of the Equity Interests or assets of such Subsidiary;

(g)secured Indebtedness otherwise permitted to be incurred pursuant to Section 10.1 and Section 10.2 that limit the right of the debtor to dispose of the assets securing such Indebtedness;

(h)restrictions on cash or other deposits or net worth imposed by customers under contracts entered into in the ordinary course of business;

(i)other Indebtedness, Disqualified Stock or preferred stock of (i) Restricted Subsidiaries that are not Guarantors permitted to be incurred subsequent to the Closing Date pursuant to Section 10.1 so long as either (A) the provisions relating to such encumbrance or restriction contained in such Indebtedness are no less

favorable to the Borrower, taken as a whole, as determined by the board of directors of the Borrower in good faith, than the provisions contained in this Agreement as in effect on the Closing Date or (B) any such encumbrance or restriction contained in such Indebtedness does not prohibit (except upon a default or an event of default thereunder) the payment of dividends in an amount sufficient, as determined by the board of directors of the Borrower in good faith, to impair the ability of the Borrower to make scheduled payments of cash interest on the Loans when due or (ii) Foreign Subsidiaries as to such Foreign Subsidiaries and their Subsidiaries;

(j)customary provisions in joint venture agreements or agreements governing property held with a common owner and other similar agreements or arrangements relating solely to such joint venture or property;

(k)customary provisions contained in leases, sub-leases, licenses, sub-licenses or similar agreements, in each case, entered into in the ordinary course of business; and

(l)any encumbrances or restrictions imposed by any amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings of the contracts, instruments or obligations referred to in clauses (a) through (k) above; provided that such amendments, modifications, restatements, renewals, increases, supplements, refundings, replacements or refinancings are, in the good faith judgment of the Borrower’s board of directors, no more restrictive in any material respect with respect to such encumbrance and other restrictions taken as a whole than those prior to such amendment, modification, restatement, renewal, increase, supplement, refunding, replacement or refinancing.

10.10Hedge Transactions. The Borrower will not, and will not permit any Restricted Subsidiary to, enter into any Hedge Transactions with any Person other than:

(a)Hedge Transactions in respect of commodities entered into not for speculative purposes the net notional volumes for which (when aggregated with other commodity Hedge Transactions then in effect, other than puts, floors and basis differential swaps on volumes already hedged pursuant to other Hedge Transactions) do not exceed, as of the date the latest Hedge Transaction is entered into, 90% of the reasonably anticipated quarterly production of oil, natural gas and natural gas liquids, calculated separately, from the Credit Parties’ total Proved Developed Producing Reserves and 50% of the reasonably anticipated quarterly production of oil, natural gas and natural gas liquids, calculated separately, from the Credit Parties’ total Proved Developed Non-Producing Reserves; provided, that, with respect to Hedge Transactions for commodities the net notional volumes for which are in respect of reasonably anticipated production during any of the months of August through October of any year, in no event shall the Borrower or any Restricted Subsidiary enter into Hedge Transactions with respect to more than 65% of reasonably anticipated production of oil, natural gas and natural gas liquids, calculated separately, from the Credit Parties’ total Proved Developed Producing Reserves for any of such months (and in no event shall the Borrower or any Restricted Subsidiary enter into Hedge Transactions with respect to any of the reasonably anticipated quarterly production of oil, natural gas and natural gas liquids, calculated separately, from the Credit Parties’ total Proved Developed Non-Producing Reserves for any of such months), (provided further that, with respect to the amount of such reduction of permitted Hedge Transactions in respect of the months of August through October of any year, such amount may be used to increase amounts otherwise permitted during the remaining portion of each year), in each case, as forecast based upon the Initial Reserve Report or the most recent Reserve Report delivered pursuant to Section 9.14(a), as applicable for the forty-eight (48) month period from the date of creation of such hedging arrangement (the “Ongoing Hedges”). In addition to the Ongoing Hedges, in connection with a proposed Permitted Acquisition (a “Proposed Acquisition”), the Credit Parties may also enter into incremental Hedge Transactions with respect to the Credit Parties’ reasonably anticipated production of oil, natural gas and natural gas liquids, calculated separately, from the Credit Parties’

total Proved Reserves as forecast based upon the most recent Reserve Report having notional volumes not in excess of 90° o of the Credit Parties’ existing projected production prior to the consummation of such Proposed Acquisition (provided that the aggregate of all Hedge Transactions in respect of commodities shall not, in any event, exceed 90° o of the reasonably anticipated projected production of oil, natural gas and natural gas liquids, calculated separately, from the Credit Parties Proved Developed Producing Reserves after giving effect to the consummation of such Proposed Acquisition) for a period not exceeding 36 months from the date such hedging arrangement is created during the period between (i) the date on which such Credit Party signs a definitive acquisition agreement in connection with a Proposed Acquisition and (ii) the earliest of (A) the date of consummation of such Proposed Acquisition, (B) the date of termination of such Proposed Acquisition and (C) 120 days after the date of execution of such definitive acquisition agreement (or such longer period as to which the Administrative Agent may agree). However, all such incremental hedging contracts entered into with respect to a Proposed Acquisition must be terminated or unwound not later than the earlier of (1) if the Proposed Acquisition has not yet been consummated, 120 days (or such longer period to the extent approved in writing by the Administrative Agent) following the date on which such Credit Party executed such definitive acquisition agreement and (2) 30 days following the date such Proposed Acquisition is terminated, in each case, to the extent the aggregate notional volumes hedged in anticipation of such Proposed Acquisition exceed the volumes permitted for Ongoing Hedges. It is understood that commodity Hedge Transactions which may, from time to time, “hedge” the same volumes, but different elements of commodity risk thereof, shall not be aggregated together when calculating the foregoing limitations on notional volumes.

(b)Other Hedge Transactions (other than any Hedge Transactions in respect of equity or equity index swaps or options, bond or bond price or bond index swaps or options or forward bond or forward bond price or forward bond index transactions) entered into not for speculative purposes.

(c)It is understood that for purposes of this Section 10.10, the following Hedge Transactions shall not be deemed speculative or entered into for speculative purposes: (i) any commodity Hedge Transaction intended, at inception of execution, to hedge or manage any of the risks related to existing and/or reasonably anticipated projected Hydrocarbon production from reserves of the Borrower or its Restricted Subsidiaries (whether or not contracted) and (ii) any Hedge Transaction intended, at inception of execution, (A) to hedge or manage the interest rate exposure associated with any debt securities, debt facilities or leases (existing or reasonably anticipated) of the Borrower or its Restricted Subsidiaries, (B) to manage commodity portfolio exposure associated with changes in interest rates, (C) to hedge any exposure that the Borrower or its Restricted Subsidiaries may have to counterparties under other Hedge Transactions such that the combination of such Hedge Transactions is not speculative taken as a whole or (D) for foreign exchange or currency exchange management.

(d)For purposes of entering into or maintaining Ongoing Hedges under Section 10.10(a) or Hedge Transactions required by Section 9.19, reasonably anticipated projected Hydrocarbon production from the Credit Parties’ total Proved Reserves based upon the Initial Reserve Report or the most recent Reserve Report delivered pursuant to Section 9.14(a) (and, for purposes of the Hedge Transactions entered into pursuant to Section 9.19, the “most recent Reserve Report” shall refer to the Castex Acquisition Reserve Report), as applicable, shall be revised to account for any increase or decrease therein anticipated because of information obtained by Borrower or any other Credit Party subsequent to the publication of such Reserve Report including the Borrower’s or any other Credit Party’s internal forecasts of production decline rates for existing wells and additions to or deletions from anticipated future production from new wells and acquisitions coming on stream or failing to come on stream.

(e)Hedge Transactions required by Section 9.19.

10.11Financial Performance Ratios.

(a)Consolidated Total Debt to EBITDAX Ratio. The Borrower will not permit the Consolidated Total Debt to EBITDAX Ratio as of the last day of any Test Period ending on or after September 30, 2018, to be greater than 3.00 to 1.00.

(b)Current Ratio. The Borrower will not permit the Current Ratio as of the last day of any Test Period ending on or after September 30, 2018, to be less than 1.00 to 1.00.

For the purposes of calculating the Consolidated Total Debt to EBITDAX Ratio for the Test Periods ending on September 30, 2018, December 31, 2018 and March 31, 2019 pursuant to this Section 10.11, EBITDAX shall be deemed to equal (i) in the case of the first such Test Period, EBITDAX for the fiscal quarter ending September 30, 2018 multiplied by four (4), (ii) in the case of the second such Test Period, EBITDAX for the two fiscal quarter period ending December 31, 2018, multiplied by two (2) and (iii) in the case of the third such Test Period, EBITDAX for the three fiscal quarter period ending March 31, 2019, multiplied by four-thirds (4/3).

10.12Accounts. Other than Excluded Accounts and amounts permitted to be maintained therein from time to time, no Credit Party shall (a) establish or maintain or (b) deposit proceeds into, a deposit account, securities account or commodities account that is not subject to a Control Agreement, in each case, subject to the proviso in Section 9.11(e).

10.13Sanctions. The Borrower will not request any Borrowing or Letter of Credit, and the Borrower shall not use, and shall procure that its Subsidiaries and its or their respective directors, officers, employees and agents shall not use, the proceeds of any Borrowing or Letter of Credit (a) in furtherance of an offer, payment, promise to pay, or authorization of the payment or giving of money, or anything else of value, to any Person in violation of any Anti-Corruption Laws or Anti-Money Laundering Laws, (b) for the purpose of funding, financing or facilitating any activities, business or transaction of or with any Sanctioned Person, or in any Sanctioned Country, to the extent such activities, business or transaction would be prohibited by Sanctions if conducted by a corporation incorporated in the United States or in a European Union member state, or (c) in any manner that would result in the violation of any Sanctions applicable to any party hereto.

10.14Amendments to Organizational Documents. The Borrower will not, and will not permit any of its Restricted Subsidiaries to, amend or modify its organizational documents if such amendment or modification could, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect or could have a material adverse effect on the Administrative Agent, any Issuing Bank or any Lender.

Section 11.Events of Default.

Upon the occurrence of any of the following specified events (each an “Event of Default”):

11.1Payments. The Borrower shall (a) default in the payment when due of any principal of the Loans or (b) default, and such default shall continue for five or more days, in the payment when due of any interest on the Loans or any Unpaid Drawings, fees or of any other amounts owing hereunder or under any other Credit Document (other than any amount referred to in clause (a) above);

11.2Representations, Etc. Any representation, warranty or statement made or deemed made by any Credit Party herein or in any other Credit Document or any certificate delivered or required to be delivered

pursuant hereto or thereto shall prove to be untrue in any material respect on the date as of which made or deemed made;

11.3Covenants. Any Credit Party shall:

(a)default in the due performance or observance by it of any term, covenant or agreement contained in Section 9.1(d)(i), 9.5 (solely with respect to the Borrower), 9.19 or Section 10; or

(b)default in the due performance or observance by it of any term, covenant or agreement (other than those referred to in Section 11.1 or 11.2 or clause (a) of this Section 11.3) contained in this Agreement or any Security Document and such default shall continue unremedied for a period of at least 30 days after receipt of written notice thereof by the Borrower from the Administrative Agent;

11.4Default Under Other Agreements.

(a)The Borrower or any of the Restricted Subsidiaries shall (i) default in any payment with respect to any Material Indebtedness (other than the Indebtedness described in Section 11.1) beyond the period of grace, if any, provided in the instrument of agreement under which such Indebtedness was created or (ii) default in the observance or performance of any agreement or condition relating to any such Indebtedness or contained in any instrument or agreement evidencing, securing or relating thereto, or any other event shall occur or condition exist (other than (A) with respect to Indebtedness in respect of any Hedge Transactions, termination events or equivalent events pursuant to the terms of the corresponding Hedge Agreements under which such Hedge Transaction is entered into and (B) secured Indebtedness that becomes due as a result of a Disposition (including as a result of Casualty Event) of the property or assets securing such Indebtedness permitted under this Agreement), the effect of which default or other event or condition is to cause, or to permit the holder or holders of such Indebtedness (or a trustee or agent on behalf of such holder or holders) to cause, any such Indebtedness to become due or to be repurchased, prepaid, defeased or redeemed (automatically or otherwise), or an offer to repurchase, prepay, defease or redeem such Indebtedness to be made, prior to its stated maturity, unless (and only for so long as), in the case of each of the foregoing, such holder or holders shall have (or through its or their trustee or agent on its or their behalf) waived such default in a writing to the Borrower, or

(b)Without limiting the provisions of clause (a) above, any such default under any such Material Indebtedness shall cause such Material Indebtedness to be declared to be due and payable, or required to be prepaid other than by a regularly scheduled required prepayment or as a mandatory prepayment (and (i) with respect to Indebtedness in respect of any Hedging Obligations, other than due to a termination event or equivalent event pursuant to the terms of the Hedge Agreements under which the applicable Hedge Transaction was entered into and (ii) other than secured Indebtedness that becomes due as a result of a Disposition (including as a result of Casualty Event) of the property or assets securing such Indebtedness permitted under this Agreement), prior to the stated maturity thereof;

11.5Bankruptcy, Etc. The Borrower, any Guarantor or any Specified Subsidiary shall commence a voluntary case, proceeding or action concerning itself under (a) Title 11 of the United States Code entitled “Bankruptcy” or any other applicable insolvency, debtor relief, or debt adjustment law; or (b) in the case of any Foreign Subsidiary that is a Specified Subsidiary, any domestic or foreign law relating to bankruptcy, judicial management, insolvency, reorganization, administration or relief of debtors in effect in its jurisdiction of incorporation, in each case as now or hereafter in effect, or any successor thereto (collectively, the “Bankruptcy Code”); or an involuntary case, proceeding or action is commenced against the Borrower, any Guarantor or any Specified Subsidiary and the petition is not dismissed or stayed within 60 days after commencement of the case, proceeding or action, the Borrower, any applicable Guarantor or the applicable Specified Subsidiary consents to

the institution of such case, proceeding or action prior to such 60-day period, or any order of relief or other order approving any such case, proceeding or action is entered; or a custodian (as defined in the Bankruptcy Code), receiver, receiver manager, trustee, conservator, liquidator, examiner, rehabilitator, administrator, or similar person is appointed for, or takes charge of, the Borrower, any Guarantor or any Specified Subsidiary or all or any substantial portion of the property or business thereof; or the Borrower, any Guarantor or any Specified Subsidiary suffers any appointment of any custodian, receiver, receiver manager, trustee, conservator, liquidator, examiner, rehabilitator, administrator, or the like for it or any substantial part of its property or business to continue undischarged or unstayed for a period of 60 days; or the Borrower, any Guarantor or any Specified Subsidiary makes a general assignment for the benefit of creditors;

11.6ERISA.

(a)Any Plan shall fail to satisfy the minimum funding standard required for any plan year or part thereof or a waiver of such standard or extension of any amortization period is sought or granted under Section 412 of the Code; any Plan is or shall have been terminated or is the subject of termination proceedings under ERISA (including the giving of written notice thereof); an event shall have occurred or a condition shall exist in either case entitling the PBGC to terminate any Plan or to appoint a trustee to administer any Plan (including the giving of written notice thereof); any Plan shall have an accumulated funding deficiency (whether or not waived); the Borrower or any ERISA Affiliate has incurred or is likely to incur a liability to or on account of a Plan under Section 409, 502(i), 502(l), 515, 4062, 4063, 4064, 4069, 4201 or 4204 of ERISA or Section 4971 or 4975 of the Code (including the giving of written notice thereof); and

(b)there would result from any event or events set forth in clause (a) of this Section 11.6 the imposition of a lien, the granting of a security interest, or a liability, or the reasonable likelihood of incurring a lien, security interest or liability; and

(c)such lien, security interest or liability will or would be reasonably likely to have a Material Adverse Effect;

11.7Guarantee. The Guarantee or any material provision thereof shall cease to be in full force or effect (other than pursuant to the terms hereof and thereof) or any Guarantor or any other Credit Party shall assert in writing that any such Guarantor’s obligations under the Guarantee are not to be in effect or are not to be legal, valid and binding obligations (other than pursuant to the terms hereof or thereof);

11.8Security Documents. The Collateral Agreement, Mortgage or any other Security Document pursuant to which assets of the Borrower and the Credit Parties with an aggregate fair market value in excess of $50,000,000 are pledged as Collateral or any material provision thereof shall cease to be in full force or effect (other than pursuant to the terms hereof or thereof) or cease to have the priority specified by the Credit Documents, or any grantor thereunder or any other Credit Party shall assert in writing that any grantor’s obligations under the Collateral Agreement, the Mortgage or any other Security Document are not in effect or not legal, valid and binding obligations (other than pursuant to the terms hereof or thereof);

11.9Judgments. One or more monetary judgments or decrees shall be entered against the Borrower or any of the Restricted Subsidiaries involving a liability of $50,000,000 or more in the aggregate for all such judgments and decrees for the Borrower and the Restricted Subsidiaries (to the extent not paid or covered by insurance provided by a carrier not disputing coverage), which judgments are not discharged or effectively waived or stayed for a period of 60 consecutive days; or

11.10Change of Control. A Change of Control shall have occurred;

Then, and in any such event, and at any time thereafter, if any Event of Default shall then be continuing, the Administrative Agent shall, upon the written request of the Majority Lenders, by written notice to the Borrower, take any or all of the following actions, without prejudice to the rights of the Administrative Agent or any Lender to enforce its claims against the Borrower or any other Credit Party, except as otherwise specifically provided for in this Agreement (provided that, if an Event of Default specified in Section 11.5 shall occur with respect to the Borrower, the result that would occur upon the giving of written notice by the Administrative Agent as specified in clauses (a), (b), and (c) below shall occur automatically without the giving of any such notice): (a) declare the Total Commitment and Swingline Commitment terminated, whereupon the Commitment of each Lender and the Swingline Lender, as the case may be, shall forthwith terminate immediately and any fees theretofore accrued shall forthwith become due and payable without any other notice of any kind; (b) declare the principal of and any accrued interest and fees in respect of any or all Loans and any or all Obligations owing hereunder and thereunder to be, whereupon the same shall become, forthwith due and payable without presentment, demand, protest or other notice of any kind, all of which are hereby waived by the Borrower; and/or (c) demand cash collateral in respect of any outstanding Letter of Credit pursuant to Section 3.8(b) in an amount equal to the aggregate Stated Amount of all Letters of Credit issued and then outstanding. In addition, after the occurrence and during the continuance of an Event of Default, the Administrative Agent and the Lenders will have all other rights and remedies available at law and equity.

11.11Application of Proceeds. Any amount received by the Administrative Agent or the Collateral Agent from any Credit Party (or from proceeds of any Collateral) following any acceleration of the Obligations under this Agreement or any Event of Default with respect to the Borrower under Section 11.5 shall be applied:

First, to payment of that portion of the Obligations constituting fees, indemnities, expenses and other amounts (including fees, disbursements and other charges of counsel payable under Section 12.7 and amounts payable under Article II) payable to the Administrative Agent and/or Collateral Agent in such Person’s capacity as such;

Second, to payment of that portion of the Obligations constituting fees, indemnities and other amounts (other than principal, interest and Letter of Credit Fees) payable to the Lenders and the Issuing Banks (including fees, disbursements and other charges of counsel payable under Section 12.7) arising under the Credit Documents and amounts payable under Article II, ratably among them in proportion to the respective amounts described in this clause Second payable to them;

Third, to payment of that portion of the Obligations constituting accrued and unpaid Letter of Credit Fees and interest on the Loans and Unpaid Drawings, ratably among the Lenders and the Issuing Banks in proportion to the respective amounts described in this clause Third payable to them;

Fourth, (i) to payment of that portion of the Obligations constituting unpaid principal of the Loans, the Unpaid Drawings and Obligations then owing under Secured Hedge Transactions and the Secured Cash Management Agreements and (ii) to Cash Collateralize that portion of Letters of Credit Outstanding comprising the aggregate undrawn amount of Letters of Credit to the extent not otherwise Cash Collateralized by the Borrower pursuant to Section 3.8, ratably among the Lenders, the Issuing Banks, the Hedge Banks and the Cash Management Banks in proportion to the respective amounts described in this clause Fourth held by them; provided that (x) any such amounts applied pursuant to the foregoing clause (ii) shall be paid to the Administrative Agent for the ratable account of the applicable Issuing Bank to Cash Collateralize such Letters of Credit Outstanding, (y)subject to Section 3.8, amounts used to Cash Collateralize the aggregate undrawn amount of Letters of Credit pursuant to this clause Fourth shall be applied to satisfy drawings under such Letters of Credit as they occur and

(z) upon the expiration of any Letter of Credit, the pro rata share of Cash Collateral attributable to such expired Letter of Credit shall be distributed in accordance with this clause Fourth;

Fifth, to the payment of all other Obligations of the Credit Parties owing under or in respect of the Credit Documents that are due and payable to the Administrative Agent and the other Secured Parties on such date, ratably based upon the respective aggregate amounts of all such Obligations owing to the Administrative Agent and the other Secured Parties on such date; and

Last, the balance, if any, after all of the Obligations have been paid in full, to the Borrower or as otherwise required by Requirements of Law.

Subject to Section 3.8, amounts used to Cash Collateralize the aggregate undrawn amount of Letters of Credit pursuant to clause Fourth above shall be applied to satisfy drawings under such Letters of Credit as they occur. If any amount remains on deposit as Cash Collateral after all Letters of Credit have either been fully drawn or expired, such remaining amount shall be applied to the other Obligations, if any, in the order set forth above.

11.12Equity Cure.

(a)Notwithstanding anything to the contrary contained in this Section 11 or in any Credit Document, in the event that the Borrower fails to comply with either Financial Performance Covenant, then until the expiration of the tenth Business Day subsequent to the date the compliance certificate for calculating such Financial Performance Covenant is required to be delivered pursuant to Section 9.1(c) (the “Cure Deadline”), the Borrower shall have the right to cure such failure (the “Cure Right”) by receiving cash proceeds from an issuance of common Equity Interests (other than Disqualified Stock) as a cash capital contribution, and upon receipt by the Borrower of such cash proceeds (such cash amount being referred to as the “Cure Amount”) pursuant to the exercise of such Cure Right, such Financial Performance Covenant shall be recalculated giving effect to the following pro forma adjustments:

(i)EBITDAX or Consolidated Current Assets, as applicable, shall be increased, solely for the purpose of determining the existence of an Event of Default resulting from a breach of such Financial Performance Covenant with respect to any Test Period that includes the fiscal quarter for which the Cure Right was exercised and not for any other purpose under this Agreement, by an amount equal to the Cure Amount;

(ii)Consolidated Total Debt for such Test Period shall be decreased solely to the extent proceeds of the Cure Amount, if any, are actually applied to prepay any Indebtedness (provided that any such Indebtedness so prepaid shall be a permanent repayment of such Indebtedness and termination of commitments thereunder) included in the calculation of Consolidated Total Debt; and

(iii)if, after giving effect to the foregoing recalculations, the Borrower shall then be in compliance with the requirements of each Financial Performance Covenant, the Borrower shall be deemed to have satisfied the requirements of the Financial Performance Covenants as of the relevant date of determination with the same effect as though there had been no failure to comply therewith at such date, and the applicable breach or default of the Financial Performance Covenant that had occurred shall be deemed cured for the purposes of this Agreement; provided that (A) in each period of four consecutive fiscal quarters there shall be at least two fiscal quarters in which no Cure Right is exercised, (B) Cure Rights shall not be exercised more than five times during the

term of this Agreement, (C) each Cure Amount shall be no greater than the amount required to cause the Borrower to be in compliance with the applicable Financial Performance Covenant with respect to which the breach or default occurred (such amount, the “Necessary Cure Amount”), provided that if the Cure Right is exercised prior to the date financial statements are required to be delivered for such fiscal quarter, then the Cure Amount shall be equal to the amount reasonably determined by the Borrower in good faith that is required for purposes of complying such Financial Performance Covenant for such fiscal quarter (such amount, the “Expected Cure Amount”), (D) all Cure Amounts shall be disregarded for the purposes of any financial ratio determination under the Credit Documents other than for determining compliance with such Financial Performance Covenant, (E) no Lender or Issuing Bank shall be required to make any extension of credit hereunder during the 10 Business Day period referred to above, unless the Borrower shall have received the Cure Amount and (F) to the extent the Borrower exercises more than one Cure Right in any single fiscal quarter, such exercises shall be deemed to be a single exercise of a Cure Right.

(iv)Expected Cure Amount. Notwithstanding anything herein to the contrary, to the extent that the Expected Cure Amount is less than the Necessary Cure Amount, then not later than the applicable Cure Deadline, the Borrower must receive cash proceeds from issuance of Equity Interests (other than Disqualified Stock) or a cash capital contribution, which cash proceeds received by Borrower shall be equal to the shortfall between such Expected Cure Amount and such Necessary Cure Amount.

(v)Necessary Cure Amount. Notwithstanding anything herein to the contrary, to the extent the Borrower exercises a Cure Right during any Test Period for which the calculation of EBITDAX is to be annualized for the purposes of calculating the Consolidated Total Debt to EBITDAX Ratio, the Necessary Cure Amount shall be determined after giving effect to the annualization of EBITDAX in accordance with Section 10.11.

Section 12.The Agents

12.1Appointment.

(a)Each Lender hereby irrevocably designates and appoints the Administrative Agent as the agent of such Lender under this Agreement and the other Credit Documents and irrevocably authorizes the Administrative Agent, in such capacity, to take such action on its behalf under the provisions of this Agreement and the other Credit Documents and to exercise such powers and perform such duties as are expressly delegated to the Administrative Agent by the terms of this Agreement and the other Credit Documents, together with such other powers as are reasonably incidental thereto. The provisions of this Section 12 (other than Section 12.1(c) with respect to the Lead Arrangers and the Joint Bookrunners and Section 12.9 with respect to the Borrower) are solely for the benefit of the Agents and the Lenders, and the Borrower shall not have rights as third party beneficiary of any such provision. Notwithstanding any provision to the contrary elsewhere in this Agreement, the Administrative Agent shall not have any duties or responsibilities (except those expressly set forth herein) or any fiduciary relationship with the Collateral Agent, the Swingline Lender, any Issuing Bank, any Lender, any Bookrunner or any Lead Arranger (regardless of whether a Default has occurred and is continuing), and no implied covenants, functions, responsibilities, duties, obligations or liabilities shall be read into this Agreement or any other Credit Document or otherwise exist against the Administrative Agent. Without limiting the generality of the foregoing, (a) the Administrative Agent shall not be subject to any fiduciary or other implied duties,

(b)The Administrative Agent, the Swingline Lender, each Lender and each Issuing Bank hereby irrevocably designate and appoint the Collateral Agent as the agent with respect to the Collateral, and each

of the Administrative Agent, the Swingline Lender, each Lender and each Issuing Bank irrevocably authorizes the Collateral Agent, in such capacity, to take such action on its behalf under the provisions of this Agreement and the other Credit Documents and to exercise such powers and perform such duties as are expressly delegated to the Collateral Agent by the terms of this Agreement and the other Credit Documents, together with such other powers as are reasonably incidental thereto. Notwithstanding any provision to the contrary elsewhere in this Agreement, the Collateral Agent shall not have any duties or responsibilities (except those expressly set forth herein), or any fiduciary relationship with any of the Administrative Agent, the Swingline Lender, any Issuing Bank, any Lender, any Bookrunner or any Lead Arranger (regardless of whether a Default has occurred and is continuing), and no implied covenants, functions, responsibilities, duties, obligations or liabilities shall be read into this Agreement or any other Credit Document or otherwise exist against the Collateral Agent.

(c)Each of the Lead Arrangers, the Syndication Agents, the Documentation Agent and the Joint Bookrunners, each in its capacity as such, shall not have any obligations, duties or responsibilities under this Agreement but shall be entitled to all benefits of this Section 12.

12.2Delegation of Duties. The Administrative Agent and the Collateral Agent may each execute any of its duties under this Agreement and the other Credit Documents by or through agents, sub-agents, employees or attorneys-in-fact (each, a “Subagent”) and shall be entitled to advice of counsel concerning all matters pertaining to such duties; provided, however, that no such Subagent shall be authorized to take any action with respect to any Collateral unless and except to the extent expressly authorized in writing by the Administrative Agent. If any Subagent, or successor thereto, shall die, become incapable of acting, resign or be removed, all rights, powers, privileges and duties of such Subagent, to the extent permitted by law, shall automatically vest in and be exercised by the Administrative Agent until the appointment of a new Subagent. Neither the Administrative Agent nor the Collateral Agent shall be responsible for the negligence or misconduct of any Subagents selected by it in the absence of gross negligence or willful misconduct (as determined in the final judgment of a court of competent jurisdiction).

12.3Exculpatory Provisions. No Agent nor any of its officers, directors, employees, agents, attorneys-in-fact or Affiliates shall be (a) liable for any action lawfully taken or omitted to be taken by any of them under or in connection with this Agreement or any other Credit Document (except for its or such Person’s own gross negligence or willful misconduct, as determined in the final judgment of a court of competent jurisdiction, in connection with its duties expressly set forth herein) or (b) responsible in any manner to any of the Lenders or any participant for any recitals, statements, representations or warranties made by any of the Borrower, any other Credit Party or any officer thereof contained in this Agreement or any other Credit Document or in any certificate, report, statement or other document referred to or provided for in, or received by such Agent under or in connection with, this Agreement or any other Credit Document or for the value, validity, effectiveness, genuineness, enforceability or sufficiency of this Agreement or any other Credit Document (including, for the avoidance of doubt, in connection with the Administrative Agent’s reliance on any Electronic Signature transmitted by telecopy, emailed pdf., or any other electronic means that reproduces an image of an actual executed signature page), or, except with respect to any physical certificate or instrument representing Pledged Securities (as defined in the Collateral Agreement) in the possession of the Agent, the perfection or priority of any Lien or security interest created or purported to be created under the Security Documents or for any failure of the Borrower or any other Credit Party to perform its obligations hereunder or thereunder. No Agent shall be under any obligation to any Lender to ascertain or to inquire as to the observance or performance of any of the agreements contained in, or conditions of, this Agreement or any other Credit Document, or to inspect the properties, books or records of any Credit Party or any Affiliate thereof. The Collateral Agent shall not be under any obligation to the Administrative Agent, any Lender, the Swingline Lender or any Issuing Bank to ascertain or to inquire as to the observance or performance of any of the agreements contained in, or conditions of, this

Agreement or any other Credit Document, or to inspect the properties, books or records of any Credit Party. The Administrative Agent does not warrant or accept responsibility for, and shall not have any liability with respect to, the administration, submission or any other matter related to the rates in the definition of “LIBOR Rate” or with respect to any comparable or successor rate thereto, or replacement rate therefor.

12.4Reliance by Agents. The Administrative Agent and the Collateral Agent shall be entitled to rely, and shall be fully protected in relying, upon any writing, resolution, notice, consent, certificate, affidavit, letter, telecopy, telex or teletype message, statement, order or other document or instruction believed by it to be genuine and correct and to have been signed, sent or made by the proper Person or Persons and upon advice and statements of legal counsel (including counsel to the Borrower), independent accountants and other experts selected by the Administrative Agent or the Collateral Agent. The Administrative Agent may deem and treat the Lender specified in the Register with respect to any amount owing hereunder as the owner thereof for all purposes unless a written notice of assignment, negotiation or transfer thereof shall have been filed with the Administrative Agent. The Administrative Agent and the Collateral Agent shall be fully justified in failing or refusing to take any action under this Agreement or any other Credit Document unless it shall first receive such advice or concurrence of the Majority Lenders as it deems appropriate or it shall first be indemnified to its satisfaction by the Lenders against any and all liability and expense that may be incurred by it by reason of taking or continuing to take any such action. The Administrative Agent and the Collateral Agent shall in all cases be fully protected in acting, or in refraining from acting, under this Agreement and the other Credit Documents in accordance with a request of the Majority Lenders, and such request and any action taken or failure to act pursuant thereto shall be binding upon all the Lenders and all future holders of the Loans; provided that the Administrative Agent and Collateral Agent shall not be required to take any action that, in its opinion or in the opinion of its counsel, may expose it to liability or that is contrary to any Credit Document or applicable Requirements of Law. For purposes of determining compliance with the conditions specified in Section 6 and Section 7 on the Closing Date, each Lender that has signed this Agreement shall be deemed to have consented to, approved or accepted or to be satisfied with, each document or other matter required thereunder to be consented to or approved by or acceptable or satisfactory to a Lender unless the Administrative Agent shall have received notice from such Lender prior to the proposed Closing Date specifying its objection thereto.

12.5Notice of Default. Neither the Administrative Agent nor the Collateral Agent shall be deemed to have knowledge or notice of the occurrence of any Default or Event of Default hereunder unless the Administrative Agent or Collateral Agent, as applicable, has received notice from a Lender or the Borrower referring to this Agreement, describing such Default or Event of Default and stating that such notice is a “notice of default”. In the event that the Administrative Agent receives such a notice, it shall give notice thereof to the Lenders and the Collateral Agent. The Administrative Agent shall take such action with respect to such Default or Event of Default as shall be reasonably directed by the Majority Lenders; provided that unless and until the Administrative Agent shall have received such directions, the Administrative Agent may (but shall not be obligated to) take such action, or refrain from taking such action, with respect to such Default or Event of Default as it shall deem advisable in the best interests of the Lenders except to the extent that this Agreement requires that such action be taken only with the approval of the Majority Lenders, the Required Lenders or each individual lender, as applicable.

12.6Acknowledgements of Lenders and Issuing Banks.

(a)Each Lender and each Issuing Bank represents and warrants that (i) the Credit Documents set forth the terms of a commercial lending facility, (ii) it is engaged in making, acquiring or holding commercial loans and in providing other facilities set forth herein as may be applicable to such Lender or Issuing Bank, in each case in the ordinary course of business, and not for the purpose of purchasing, acquiring or holding any other

type of financial instrument (and each Lender and each Issuing Bank agrees not to assert a claim in contravention of the foregoing), (iii) it has, independently and without reliance upon the Administrative Agent, the Collateral Agent, any Lead Arranger, any Syndication Agent, any Documentation Agent or any other Lender or Issuing Bank, or any of the Related Parties of any of the foregoing, and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement as a Lender, and to make, acquire or hold Loans hereunder and (iv) it is sophisticated with respect to decisions to make, acquire and/or hold commercial loans and to provide other facilities set forth herein, as may be applicable to such Lender or such Issuing Bank, and either it, or the Person exercising discretion in making its decision to make, acquire and/or hold such commercial loans or to provide such other facilities, is experienced in making, acquiring or holding such commercial loans or providing such other facilities. Each Lender and each Issuing Bank also acknowledges that it will, independently and without reliance upon the Administrative Agent, any Lead Arranger, any Syndication Agent, any Documentation Agent or any other Lender or Issuing Bank, or any of the Related Parties of any of the foregoing, and based on such documents and information (which may contain material, non-public information within the meaning of the United States securities laws concerning the Borrower and its Affiliates) as it shall from time to time deem appropriate, continue to make its own decisions in taking or not taking action under or based upon this Agreement, any other Credit Document or any related agreement or any document furnished hereunder or thereunder.

(b)[Intentionally Omitted].

(c)

(i)Each Lender and each Issuing Bank hereby agrees that (x) if the Administrative Agent notifies such Lender or such Issuing Bank that the Administrative Agent has determined in its sole discretion that any funds received by such Lender or such Issuing Bank from the Administrative Agent or any of its Affiliates (whether as a payment, prepayment or repayment of principal, interest, fees or otherwise; individually and collectively, a “Payment”) were erroneously transmitted to such Lender or such Issuing Bank (whether or not known to such Lender or such Issuing Bank), and demands the return of such Payment (or a portion thereof), such Lender or such Issuing Bank shall promptly, but in no event later than one Business Day thereafter, return to the Administrative Agent the amount of any such Payment (or portion thereof) as to which such a demand was made in same day funds, together with interest thereon in respect of each day from and including the date such Payment (or portion thereof) was received by such Lender or such Issuing Bank to the date such amount is repaid to the Administrative Agent at the greater of the NYFRB Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation from time to time in effect, and (y) to the extent permitted by applicable law, such Lender or such Issuing Bank shall not assert, and hereby waives, as to the Administrative Agent, any claim, counterclaim, defense or right of set-off or recoupment with respect to any demand, claim or counterclaim by the Administrative Agent for the return of any Payments received, including without limitation any defense based on “discharge for value” or any similar doctrine. A notice of the Administrative Agent to any Lender or any Issuing Bank under this Section 12.6(c) shall be conclusive, absent manifest error.

(ii)Each Lender and each Issuing Bank hereby further agrees that if it receives a Payment from the Administrative Agent or any of its Affiliates (x) that is in a different amount than, or on a different date from, that specified in a notice of payment sent by the Administrative Agent (or any of its Affiliates) with respect to such Payment (a “Payment Notice”) or (y) that was not preceded or accompanied by a Payment Notice, it shall be on notice, in each such case, that an

error has been made with respect to such Payment. Each Lender and each Issuing Bank agrees that, in each such case, or if it otherwise becomes aware a Payment (or portion thereof) may have been sent in error, such Lender or such Issuing Bank shall promptly notify the Administrative Agent of such occurrence and, upon demand from the Administrative Agent, it shall promptly, but in no event later than one Business Day thereafter, return to the Administrative Agent the amount of any such Payment (or portion thereof) as to which such a demand was made in same day funds, together with interest thereon in respect of each day from and including the date such Payment (or portion thereof) was received by such Lender or such Issuing Bank to the date such amount is repaid to the Administrative Agent at the greater of the NYFRB Rate and a rate determined by the Administrative Agent in accordance with banking industry rules on interbank compensation from time to time in effect.

(iii)The Borrower and each other Credit Party hereby agrees that (x) in the event an erroneous Payment (or portion thereof) are not recovered from any Lender or any Issuing Bank that has received such Payment (or portion thereof) for any reason, the Administrative Agent shall be subrogated to all the rights of such Lender or such Issuing Bank with respect to such amount and (y) an erroneous Payment shall not pay, prepay, repay, discharge or otherwise satisfy any Obligations owed by the Borrower or any other Credit Party.

(iv)Each party’s obligations under this Section 12.6(c) shall survive the resignation or replacement of the Administrative Agent or any transfer of rights or obligations by, or the replacement of, a Lender or an Issuing Bank, the termination of the Commitments or the repayment, satisfaction or discharge of all Obligations under any Credit Document.

12.7Indemnification. The Lenders severally agree to indemnify the Administrative Agent and the Collateral Agent, each in its capacity as such (to the extent not reimbursed by the Credit Parties and without limiting the obligation of the Credit Parties to do so), ratably according to their respective portions of the Commitments or Loans, as applicable, outstanding in effect on the date on which indemnification is sought (or, if indemnification is sought after the date upon which the Commitments shall have terminated and the Loans shall have been paid in full, ratably in accordance with their respective portions of the Total Exposure in effect immediately prior to such date), from and against any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind whatsoever that may at any time occur (including at any time following the payment of the Loans) be imposed on, incurred by or asserted against the Administrative Agent or the Collateral Agent in any way relating to or arising out of the Commitments, this Agreement, any of the other Credit Documents or any documents contemplated by or referred to herein or therein or the transactions contemplated hereby or thereby or any action taken or omitted by the Administrative Agent or the Collateral Agent under or in connection with any of the foregoing (including, for the avoidance of doubt, any amount required to be paid by the Borrower under Section 13.5(a)); provided that no Lender shall be liable to the Administrative Agent or the Collateral Agent for the payment of any portion of such liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements resulting from such Administrative Agent’s or the Collateral Agent’s, as applicable, gross negligence or willful misconduct as determined by a final judgment of a court of competent jurisdiction; provided, further, that no action taken in accordance with the directions of the Majority Lenders (or such other number or percentage of the Lenders as shall be required by the Credit Documents) shall be deemed to constitute gross negligence or willful misconduct for purposes of this Section 12.7. In the case of any investigation, litigation or proceeding giving rise to any liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind whatsoever that may at any time occur (including at any time following the payment of the Loans), this Section 12.7 applies whether any such investigation, litigation or proceeding is brought by any Lender or any

other Person. Without limitation of the foregoing, each Lender shall reimburse the Administrative Agent and the Collateral Agent upon demand for its ratable share of any costs or out-of-pocket expenses (including attorneys’ fees) incurred by such Agent in connection with the preparation, execution, delivery, administration, modification, amendment or enforcement (whether through negotiations, legal proceedings or otherwise) of, or legal advice rendered in respect of rights or responsibilities under, this Agreement, any other Credit Document, or any document contemplated by or referred to herein, to the extent that such Agent is not reimbursed for such expenses by or on behalf of the Borrower; provided that such reimbursement by the Lenders shall not affect the Borrower’s continuing reimbursement obligations with respect thereto. If any indemnity furnished to any Agent for any purpose shall, in the opinion of such Agent, be insufficient or become impaired, such Agent may call for additional indemnity and cease, or not commence, to do the acts indemnified against until such additional indemnity is furnished; provided, in no event shall this sentence require any Lender to indemnify any Agent against any liability, obligation, loss, damage, penalty, action, judgment, suit, cost, expense or disbursement in excess of such Lender’s pro rata portion thereof; and provided further, this sentence shall not be deemed to require any Lender to indemnify any Agent against any liability, obligation, loss, damage, penalty, action, judgment, suit, cost, expense or disbursement resulting from such Agent’s gross negligence or willful misconduct. The agreements in this Section 12.7 shall survive the termination of this Agreement and the repayment of the Loans and payment of all other amounts payable hereunder.

12.8Agents in Its Individual Capacities. Each Agent and its Affiliates may make loans to, accept deposits from and generally engage in any kind of business with the Borrower and any other Credit Party as though such Agent were not an Agent hereunder and under the other Credit Documents. With respect to the Loans made by it, each Agent shall have the same rights and powers under this Agreement and the other Credit Documents as any Lender and may exercise the same as though it were not an Agent, and the terms “Lender” and “Lenders” shall include each Agent in its individual capacity.

12.9Successor Agents. Each of the Administrative Agent and Collateral Agent may at any time give notice of its resignation to the Lenders, the Swingline Lender, the Issuing Banks and the Borrower. If the Administrative Agent, Swingline Lender and/or Collateral Agent becomes a Defaulting Lender, then such Administrative Agent, Swingline Lender or Collateral Agent, may be removed as the Administrative Agent, Swingline Lender or Collateral Agent, as the case may be, at the reasonable request of the Borrower and the Required Lenders. Upon receipt of any such notice of resignation or removal, as the case may be, the Majority Lenders shall have the right, subject to the consent of the Borrower (not to be unreasonably withheld or delayed) so long as no Default under Section 11.1 or 11.5 is continuing, to appoint a successor, which shall be a bank with an office in the United States, or an Affiliate of any such bank with an office in the United States. If, in the case of a resignation of a retiring Agent, no such successor shall have been so appointed by the Majority Lenders and shall have accepted such appointment within 30 days after the retiring Agent gives notice of its resignation, then the retiring Agent may on behalf of the Lenders, the Swingline Lender and the Issuing Banks, appoint a successor Agent meeting the qualifications set forth above. Upon the acceptance of a successor’s appointment as the Administrative Agent or Collateral Agent, as the case may be, hereunder, and upon the execution and filing or recording of such financing statements, or amendments thereto, and such other instruments or notices, as may be necessary or desirable, or as the Majority Lenders may request, in order to continue the perfection of the Liens granted or purported to be granted by the Security Documents, such successor shall succeed to and become vested with all of the rights, powers, privileges and duties of the retiring (or retired) Agent, and the retiring Agent shall be discharged from all of its duties and obligations hereunder or under the other Credit Documents (if not already discharged therefrom as provided above in this Section 12.9). The fees payable by the Borrower (following the effectiveness of such appointment) to such Agent shall be the same as those payable to its predecessor unless otherwise agreed between the Borrower and such successor. After the retiring Agent’s resignation hereunder and under the other Credit Documents, the provisions of this Section 12 (including Section 12.7) and Section 13.5

shall continue in effect for the benefit of such retiring Agent, its Subagents and their respective Related Parties in respect of any actions taken or omitted to be taken by any of them while the retiring Agent was acting as an Agent.

Any resignation of any Person as Administrative Agent pursuant to this Section 12.9 shall also constitute its resignation as Swingline Lender.

12.10Withholding Tax. To the extent required by any applicable Requirement of Law, the Administrative Agent may withhold from any payment to any Lender an amount equivalent to any applicable withholding tax. If the Internal Revenue Service or any authority of the United States or other jurisdiction asserts a claim that the Administrative Agent did not properly withhold tax from amounts paid to or for the account of any Lender for any reason (including because the appropriate form was not delivered, was not properly executed, or because such Lender failed to notify the Administrative Agent of a change in circumstances that rendered the exemption from, or reduction of, withholding tax ineffective), such Lender shall indemnify the Administrative Agent (to the extent that the Administrative Agent has not already been reimbursed by any applicable Credit Party and without limiting the obligation of any applicable Credit Party to do so) fully for all amounts paid, directly or indirectly, by the Administrative Agent as Tax or otherwise, including penalties, additions to Tax and interest, together with all expenses incurred, including legal expenses, allocated staff costs and any out of pocket expenses. Each Lender hereby authorizes the Administrative Agent to set off and apply any and all amounts at any time owing to such Lender under this Agreement or any other Credit Document against any amount due to the Administrative Agent under this Section 12.10. For the avoidance of doubt, for purposes of this Section 12.10, the term “Lender” includes any Issuing Bank and any Swingline Lender.

12.11Security Documents and Collateral Agent under Security Documents and Guarantee. Each Secured Party hereby further authorizes the Administrative Agent or Collateral Agent, as applicable, on behalf of and for the benefit of Secured Parties, to be the agent for and representative of the Secured Parties with respect to the Collateral and the Security Documents. Subject to Section 13.1, without further written consent or authorization from any Secured Party, the Administrative Agent or Collateral Agent, as applicable, may (a) execute any documents or instruments necessary in connection with a Disposition of assets permitted by this Agreement, (b) release any Lien encumbering any item of Collateral that is the subject of such Disposition of assets or with respect to which Majority Lenders (or such other Lenders as may be required to give such consent under Section 13.1) have otherwise consented or (c) release any applicable Guarantor from the Guarantee in connection with such Disposition or with respect to which Majority Lenders (or such other Lenders as may be required to give such consent under Section 13.1) have otherwise consented. The Lenders and the Issuing Banks (including in their capacities as potential Cash Management Banks and potential Hedge Banks) irrevocably agree that (x) the Collateral Agent may, without any further consent of any Lender, enter into or amend any intercreditor agreement with the collateral agent or other representatives of the holders of Indebtedness that is permitted to be secured by a Lien on the Collateral that is permitted under this Agreement, (y) the Collateral Agent may rely exclusively on a certificate of an Authorized Officer of the Borrower as to whether any such other Liens are permitted and (z) any intercreditor agreement referred to in clause (x) above, entered into by the Collateral Agent, shall be binding on the Secured Parties. Furthermore, the Lenders and the Issuing Banks (including in their capacities as potential Cash Management Bank and potential Hedge Banks) hereby authorize the Administrative Agent and the Collateral Agent to subordinate any Lien on any property granted to or held by the Administrative Agent or Collateral Agent under any Credit Document to the holder of any Lien on such property that is permitted by clause (j) of the definition of “Permitted Liens” and clauses (c), (e) (with respect to Liens securing Indebtedness permitted under Section 10.1), (f), (j), (o), (p) and (t) of Section 10.2 or otherwise permitted to be senior to the Liens of Administrative Agent or Collateral Agent on such property; provided that prior to any such request, the Borrower shall have in each case delivered to the Administrative Agent a certificate of an Authorized Officer of the Borrower certifying that such subordination is permitted under this Agreement.

12.12Right to Realize on Collateral and Enforce Guarantee.

(a)Anything contained in any of the Credit Documents to the contrary notwithstanding, the Borrower, the Agents and each Secured Party hereby agree that (i) no Secured Party shall have any right individually to realize upon any of the Collateral or to enforce the Guarantee, it being understood and agreed that all powers, rights and remedies hereunder may be exercised solely by the Administrative Agent, on behalf of the Secured Parties in accordance with the terms hereof and all powers, rights and remedies under the Security Documents may be exercised solely by the Collateral Agent, and (ii) in the event of a foreclosure by the Collateral Agent on any of the Collateral pursuant to a public or private sale or other disposition, (x) the Collateral Agent or any Lender may be the purchaser or licensor of any or all of such Collateral at any such sale or other disposition and (y) the Collateral Agent, as agent for and representative of the Secured Parties, (but not any Lender or Lenders in its or their respective individual capacities unless the Majority Lenders shall otherwise agree in writing) shall, at the direction of the Majority Lenders, be entitled, for the purpose of bidding and making settlement or payment of the purchase price for all or any portion of the Collateral sold at any such public sale, to use and apply any of the Obligations as a credit on account of the purchase price for any collateral payable by the Collateral Agent at such sale or other disposition, as more particularly described in Section 12.12(b).

(b)The Secured Parties hereby irrevocably authorize the Collateral Agent to credit bid all or any portion of the Obligations (including by accepting some or all of the Collateral in satisfaction of some or all of the Obligations pursuant to a deed in lieu of foreclosure or otherwise) and in such manner purchase (either directly or through one or more acquisition vehicles) all or any portion of the Collateral (i) at any sale thereof conducted under the provisions of the Bankruptcy Code, including under Sections 363, 1123 or 1129 of the Bankruptcy Code, or any similar laws in any other jurisdictions, or (ii) at any other sale, foreclosure or acceptance of collateral in lieu of debt conducted by (or with the consent or at the direction of) the Collateral Agent (whether by judicial action or otherwise) in accordance with any applicable law. In connection with any such credit bid and purchase, the Obligations owed to the Secured Parties shall be entitled to be, and shall be, credit bid by the Collateral Agent at the direction of the Majority Lenders on a ratable basis (with Obligations with respect to contingent or unliquidated claims receiving contingent interests in the acquired assets on a ratable basis that shall vest upon the liquidation of such claims in an amount proportional to the liquidated portion of the contingent claim amount used in allocating the contingent interests) for the asset or assets so purchased (or for the equity interests or debt instruments of the acquisition vehicle or vehicles that are issued in connection with such purchase). In connection with any such bid (A) the Collateral Agent shall be authorized to form one or more acquisition vehicles and to assign any successful credit bid to such acquisition vehicle or vehicles (B) each of the Secured Parties’ ratable interests in the Obligations that were credit bid shall be deemed without any further action under this Agreement to be assigned to such vehicle or vehicles for the purpose of closing such sale, (C) the Collateral Agent shall be authorized to adopt documents providing for the governance of the acquisition vehicle or vehicles (provided that any actions by the Administrative Agent with respect to such acquisition vehicle or vehicles, including any disposition of the assets or equity interests thereof, shall be governed, directly or indirectly, by, and the governing documents shall provide for, control by the vote of the Majority Lenders or their permitted assignees under the terms of this Agreement or the governing documents of the applicable acquisition vehicle or vehicles, as the case may be, irrespective of the termination of this Agreement and without giving effect to the limitations on actions by the Majority Lenders contained in Section 13.1 of this Agreement), (D) the Collateral Agent on behalf of such acquisition vehicle or vehicles shall be authorized to issue to each of the Secured Parties, ratably on account of the relevant Obligations that were credit bid, interests, whether as equity, partnership, limited partnership interests or membership interests, in any such acquisition vehicle and/or debt instruments issued by such acquisition vehicle, all without the need for any Secured Party or acquisition vehicle to take any further action, and (E) to the extent that Obligations that are assigned to an acquisition vehicle are not used to acquire Collateral for any reason (as a result of another bid being higher or better, because the amount of

Obligations assigned to the acquisition vehicle exceeds the amount of Obligations credit bid by the acquisition vehicle or otherwise), such Obligations shall automatically be reassigned to the Secured Parties pro rata and the equity interests and/or debt instruments issued by any acquisition vehicle on account of such Obligations shall automatically be cancelled, without the need for any Secured Party or any acquisition vehicle to take any further action. Notwithstanding that the ratable portion of the Obligations of each Secured Party are deemed assigned to the acquisition vehicle or vehicles as set forth in clause (ii) above, each Secured Party shall execute such documents and provide such information regarding the Secured Party (and/or any designee of the Secured Party that will receive interests in or debt instruments issued by such acquisition vehicle) as the Administrative Agent may reasonably request in connection with the formation of any acquisition vehicle, the formulation or submission of any credit bid or the consummation of the transactions contemplated by such credit bid.

12.13Administrative Agent May File Proofs of Claim. In case of the pendency of any receivership, insolvency, liquidation, bankruptcy, reorganization, arrangement, adjustment, composition or other judicial proceeding, constituting an Event of Default under Section 11.5, the Administrative Agent (irrespective of whether the principal of any Loan shall then be due and payable as herein expressed or by declaration or otherwise and irrespective of whether the Administrative Agent shall have made any demand on the Borrower) shall be entitled and empowered, by intervention in such proceeding or otherwise:

(a)to file and prove a claim for the whole amount of the principal and interest owing and unpaid in respect of the Loans and all other Obligations that are owing and unpaid and to file such other documents as may be necessary or advisable in order to have the claims of the Lenders and the Administrative Agent (including any claim for the reasonable compensation, expenses, disbursements and advances of the Lenders and the Administrative Agent and their respective agents and counsel, to the extent due under Section 13.5) allowed in such judicial proceeding; and

(b)to collect and receive any monies or other property payable or deliverable on any such claims and to distribute the same;

and any custodian, receiver, assignee, trustee, liquidator, sequestrator or other similar official in any such judicial proceeding is hereby authorized by each Lender to make such payments to the Administrative Agent and, in the event that the Administrative Agent shall consent to the making of such payments directly to the Lenders, to pay to the Administrative Agent any amount due for the reasonable compensation, expenses, disbursements and advances of the Administrative Agent and its agents and counsel, to the extent due under Section 13.5.

Nothing contained herein shall be deemed to authorize the Administrative Agent to authorize or consent to or accept or adopt on behalf of any Lender any plan of reorganization, arrangement, adjustment or composition affecting the Indebtedness or the rights of any Lender or to authorize the Administrative Agent to vote in respect of the claim of any Lender in any such proceeding.

12.14Certain ERISA Matters.

(a)Each Lender (x) represents and warrants, as of the date such Person became a Lender party hereto, to, and (y) covenants, from the date such Person became a Lender party hereto to the date such Person ceases being a Lender party hereto, for the benefit of, the Administrative Agent and its respective Affiliates, and not, for the avoidance of doubt, to or for the benefit of the Borrower or any other Credit Party, that at least one of the following is and will be true:

(i)such Lender is not using “plan assets” (within the meaning of the Plan Asset Regulations) of one or more Plans in connection with the Loans, the Letters of Credit or the Commitments,

(ii)the transaction exemption set forth in one or more PTEs, such as PTE 84-14 (a class exemption for certain transactions determined by independent qualified professional asset managers), PTE 95-60 (a class exemption for certain transactions involving insurance company general accounts), PTE 90-1 (a class exemption for certain transactions involving insurance company pooled separate accounts), PTE 91-38 (a class exemption for certain transactions involving bank collective investment funds) or PTE 96-23 (a class exemption for certain transactions determined by in-house asset managers), is applicable with respect to such Lender’s entrance into, participation in, administration of and performance of the Loans, the Letters of Credit, the Commitments and this Agreement,

(iii)(A) such Lender is an investment fund managed by a “Qualified Professional Asset Manager” (within the meaning of Part VI of PTE 84-14), (B) such Qualified Professional Asset Manager made the investment decision on behalf of such Lender to enter into, participate in, administer and perform the Loans, the Letters of Credit, the Commitments and this Agreement, (C) the entrance into, participation in, administration of and performance of the Loans, the Letters of Credit, the Commitments and this Agreement satisfies the requirements of sub-sections (b) through (g) of Part I of PTE 84-14 and (D) to the best knowledge of such Lender, the requirements of subsection (a) of Part I of PTE 84-14 are satisfied with respect to such Lender’s entrance into, participation in, administration of and performance of the Loans, the Letters of Credit, the Commitments and this Agreement, or

(iv)such other representation, warranty and covenant as may be agreed in writing between the Administrative Agent, in its sole discretion, and such Lender.

(b)In addition, unless sub-clause (i) in the immediately preceding clause (a) is true with respect to a Lender or such Lender has provided another representation, warranty and covenant as provided in sub-clause (iv) in the immediately preceding clause (a), such Lender further (x) represents and warrants, as of the date such Person became a Lender party hereto, to, and (y) covenants, from the date such Person became a Lender party hereto to the date such Person ceases being a Lender party hereto, for the benefit of, the Administrative Agent and its Affiliates, and not, for the avoidance of doubt, to or for the benefit of the Borrower or any other Credit Party, that none of the Administrative Agent or any of its respective Affiliates is a fiduciary with respect to the Collateral or the assets of such Lender (including in connection with the reservation or exercise of any rights by the Administrative Agent under this Agreement, any Credit Document or any documents related to hereto or thereto)

(c)The Administrative Agent hereby informs the Lenders that it is not undertaking to provide investment advice, or to give advice in a fiduciary capacity, in connection with the transactions contemplated hereby, and that such Person has a financial interest in the transactions contemplated hereby in that such Person or an Affiliate thereof (i) may receive interest or other payments with respect to the Loans, the Letters of Credit, the Commitments, this Agreement or any other Credit Document, (ii) may recognize a gain if it extended the Loans, the Letters of Credit or the Commitments for an amount less than the amount being paid for an interest in the Loans, the Letters of Credit or the Commitments by such Lender or (iii) may receive fees or other payments in connection with the transactions contemplated hereby, the Credit Documents or otherwise, including structuring fees, commitment fees, arrangement fees, facility fees, upfront fees, underwriting fees, ticking fees,

agency fees, administrative agent or collateral agent fees, utilization fees, minimum usage fees, letter of credit fees, fronting fees, deal-away or alternate transaction fees, amendment fees, processing fees, term out premiums, banker’s acceptance fees, breakage or other early termination fees or fees similar to the foregoing.

Section 13.Miscellaneous

13.1Amendments, Waivers and Releases.

(a)Except as expressly set forth in this Agreement, neither this Agreement nor any other Credit Document, nor any terms hereof or thereof, may be amended, supplemented or modified except in accordance with the provisions of this Section 13.1. Subject to Section 2.18(a) and (b) and Section 13.1(d), the Majority Lenders may, or, with the written consent of the Majority Lenders, the Administrative Agent and/or the Collateral Agent shall, from time to time, (i) enter into with the relevant Credit Party or Credit Parties written amendments, supplements or modifications hereto and to the other Credit Documents for the purpose of adding any provisions to this Agreement or the other Credit Documents or changing in any manner the rights of the Lenders or of the Credit Parties hereunder or thereunder or (ii) waive in writing, on such terms and conditions as the Majority Lenders or the Administrative Agent and/or Collateral Agent, as the case may be, may specify in such instrument, any of the requirements of this Agreement or the other Credit Documents or any Default or Event of Default and its consequences; provided, however, that each such waiver and each such amendment, supplement or modification shall be effective only in the specific instance and for the specific purpose for which given; provided, further, that no such waiver and no such amendment, supplement or modification shall (A) forgive or reduce any portion of any Loan or reduce the stated rate (it being understood that only the consent of the Majority Lenders shall be necessary to waive any obligation of the Borrower to pay interest at the Default Rate or amend Section 2.8(d)), or forgive any portion, or extend the Maturity Date or the date for the payment, of the Loans or any interest or fee payable hereunder (other than as a result of waiving the applicability of any post-default increase in interest rates and any change due to a change in the Borrowing Base or Available Commitment), or extend the final expiration date of any Lender’s Commitment (provided that (1) any Lender, upon the request of the Borrower, may extend the final expiration date of its Commitment without the consent of any other Lender, including the Majority Lenders, (2) it is being understood that waivers or modifications of conditions precedent, covenants, Defaults or Events of Default shall not constitute an increase of the Commitments of any Lender, and (3) [intentionally omitted]) or extend the final expiration date of any Letter of Credit beyond the L/C Maturity Date, or increase the amount of the Commitment of any Lender (provided that any Lender, upon the request of the Borrower, may increase the amount of its Commitment without the consent of any other Lender, including the Majority Lenders), or make any Loan, interest, fee or other amount payable in any currency other than Dollars, in each case without the written consent of each Lender directly and adversely affected thereby, or (B) amend, modify or waive any provision of this Section 13.1 in a manner that would reduce the voting rights of any Lender, or reduce the percentages specified in the definitions of the terms “Majority Lenders”, “Required Lenders” or “Borrowing Base Required Lenders” (it being understood that, with the consent of the Majority Lenders, additional extensions of credit pursuant to this Agreement may be included in the determination of the Majority Lenders, Required Lenders and Borrowing Base Required Lender on substantially the same basis as the Loans and Commitments are included on the Closing Date), or amend any other provision of this Agreement that expressly provides that the consent of all Lenders or all affected Lenders is required, or consent to the assignment or transfer by the Borrower of its rights and obligations under any Credit Document to which it is a party (except as permitted pursuant to Section 10.3), in each case without the written consent of each Lender directly and adversely affected thereby, or (C) amend the provisions of Sections 5.3, 11.11 or 13.8 or any analogous provision of any Security Document, in a manner that would by its terms alter the pro rata sharing of payments required thereby, without the prior written consent of each Lender directly and adversely affected thereby, or (D) amend, modify or waive any provision of Section 12 without the written consent of the then-current Administrative Agent

and Collateral Agent, as applicable, or any other former or current Agent to whom Section 12 then applies in a manner that directly and adversely affects such Person, or (E) amend, modify or waive any provision of Section 3 with respect to any Letter of Credit without the written consent of each Issuing Bank to whom Section 3 then applies in a manner that directly and adversely affects such Person, or (F) amend, modify or waive any provisions hereof relating to Swingline Loans without the written consent of the Swingline Lender, or (G) release all or substantially all of the Guarantors under the Guarantee (except as expressly permitted by the Guarantee or this Agreement) without the prior written consent of each Lender, or (H) release all or substantially all of the Collateral under the Security Documents (except as expressly permitted by the Security Documents or this Agreement) or subordinate all or substantially all of the Collateral under the Security Documents to Liens securing Indebtedness for borrowed money, in each case, without the prior written consent of each Lender, or (I) amend Section 2.9 so as to permit Interest Period intervals greater than six months without regard to availability to Lenders, without the written consent of each Lender directly and adversely affected thereby, or (J) increase the Borrowing Base without the written consent of the Borrowing Base Required Lenders (other than Defaulting Lenders), decrease or maintain the Borrowing Base without the written consent of the Required Lenders or otherwise modify Section 2.14(b), (c), (d), (e), (f) or (g) if such modification would have the effect of increasing the Borrowing Base without the written consent of Borrowing Base Required Lenders (other than Defaulting Lenders); provided that a Scheduled Redetermination may be postponed by the Majority Lenders; provided, further, that the automatic reduction of the Borrowing Base pursuant to Section 2.14(e) may be waived by the Required Lenders, or (K) affect the rights or duties of, or any fees or other amounts payable to, any Agent under this Agreement or any other Credit Document without the prior written consent of such Agent. Any such waiver and any such amendment, supplement or modification shall apply equally to each of the affected Lenders and shall be binding upon the Borrower, such Lenders, the Administrative Agent and all future holders of the affected Loans. In the case of any waiver, the Borrower, the Lenders and the Administrative Agent shall be restored to their former positions and rights hereunder and under the other Credit Documents, and any Default or Event of Default waived shall be deemed to be cured and not continuing; it being understood that no such waiver shall extend to any subsequent or other Default or Event of Default or impair any right consequent thereon. In connection with the foregoing provisions, the Administrative Agent may, but shall have no obligations to, with the concurrence of any Lender, execute amendments, modifications, waivers or consents on behalf of such Lender whose consent is required hereunder.

(b)Without the consent of any Lender or Issuing Bank, the Credit Parties and the Administrative Agent or Collateral Agent may (in their respective sole discretion, or shall, to the extent required by any Credit Document) enter into any amendment, modification or waiver of any Credit Document, or enter into any new agreement or instrument, to effect the granting, perfection, protection, expansion or enhancement of any security interest in any Collateral or additional property to become Collateral for the benefit of the Secured Parties, or as required by local law to give effect to, or protect any security interest for the benefit of the Secured Parties, in any property or so that the security interests therein comply with applicable law or this Agreement or in each case to otherwise enhance the rights or benefits of any Lender under any Credit Document.

(c)Notwithstanding the foregoing, this Agreement may be amended (or amended and restated) with the written consent of the Majority Lenders, the Administrative Agent and the Borrower (i) to add one or more additional credit or debt facilities to this Agreement and to permit the extensions of credit from time to time outstanding thereunder and the accrued interest and fees in respect thereof to share ratably in the benefits of this Agreement and the other Credit Documents with the Loans and the Commitments and the accrued interest and fees in respect thereof and (ii) to include appropriately the Lenders holding such credit or debt facilities in any determination of the Majority Lenders, the Required Lenders and the Borrowing Base Required Lenders on substantially the same basis as the Lenders prior to such inclusion.

(d)Notwithstanding the foregoing, technical and conforming modifications to the Credit Documents may be made with the consent of the Borrower and the Administrative Agent (i) if such modifications are not adverse to the Lenders in any material respect or (ii) to the extent necessary (A) to integrate any Incremental Increase contemplated by Sections 2.16 or (B) to cure any ambiguity, omission, defect or inconsistency so long as, in each case with respect to this clause (B), the Lenders shall have received at least five Business Days’ prior written notice thereof and the Administrative Agent shall not have received, within five Business Days of the date of such notice to the Lenders, a written notice from the Majority Lenders stating that the Majority Lenders object to such amendment.

13.2Notices; Posting of Communications.

(a)Unless otherwise expressly provided herein, all notices and other communications provided for hereunder or under any other Credit Document shall be in writing (including by facsimile transmission). All such written notices shall be mailed, faxed or delivered to the applicable address, facsimile number or electronic mail address, and all notices and other communications expressly permitted hereunder to be given by telephone shall be made to the applicable telephone number, as follows:

(i)if to the Borrower, the Administrative Agent, the Collateral Agent, the Swingline Lender or any Issuing Bank, to the address, facsimile number, electronic mail address or telephone number specified for such Person on Schedule 13.2 or to such other address, facsimile number, electronic mail address or telephone number as shall be designated by such party in a notice to the other parties; and

(ii)if to any other Lender, to the address, facsimile number, electronic mail address or telephone number specified in its Administrative Questionnaire or to such other address, facsimile number, electronic mail address or telephone number as shall be designated by such party in a notice to the Borrower, the Administrative Agent, the Collateral Agent, the Swingline Lender and the Issuing Banks;

(iii)notices and other communications to the Lenders and any Issuing Bank hereunder may be delivered or furnished by using an Approved Electronic Platform (as defined below) pursuant to procedures approved by the Administrative Agent; provided that the foregoing shall not apply to (A) notices pursuant to Section 2 unless otherwise agreed by the Administrative Agent and the applicable Lender or (B) notices pursuant to Section 3 unless otherwise agreed by the Administrative Agent and the applicable Issuing Bank; and

(iv)the Administrative Agent or the Borrower may, in its discretion, agree to accept notices and other communications to it hereunder by electronic communications pursuant to procedures approved by it; provided that approval of such procedures may be limited to particular notices or communications.

All such notices and other communications shall be deemed to be given or made upon the earlier to occur of (A) actual receipt by the relevant party hereto and (B)(1) if delivered by hand or by courier, when signed for by or on behalf of the relevant party hereto; (2) if delivered by mail, three Business Days after deposit in the mails, postage prepaid; (3) if delivered by facsimile, when sent and receipt has been confirmed by telephone; (4) if delivered by electronic mail, when delivered; and (5) unless the Administrative Agent otherwise prescribes, notices or communications posted to an Approved Electronic Platform shall be deemed delivered when notification that such notice or communication is available and identifying the website address therefor has been

delivered by electronic mail; provided that notices and other communications to the Administrative Agent or the Lenders pursuant to Sections 2.3, 2.6, 2.9, 4.2 and 5.1 shall not be effective until received.

(b)Posting of Communications.

(i)Each Credit Party agrees that the Administrative Agent may, but shall not be obligated to, make any Communications available to the Lenders and the Issuing Banks by posting the Communications (as defined below) on IntraLinksTM, DebtDomain, SyndTrak, ClearPar or any other electronic platform chosen by the Administrative Agent to be its electronic transmission system (the “Approved Electronic Platform”).

(ii)Although the Approved Electronic Platform and its primary web portal are secured with generally-applicable security procedures and policies implemented or modified by the Administrative Agent from time to time (including, as of the Closing Date, a user ID/password authorization system) and the Approved Electronic Platform is secured through a per-deal authorization method whereby each user may access the Approved Electronic Platform only on a deal-by-deal basis, each of the Lenders, each of the Issuing Banks and each Credit Party acknowledges and agrees that the distribution of material through an electronic medium is not necessarily secure, that the Administrative Agent is not responsible for approving or vetting the representatives or contacts of any Lender that are added to the Approved Electronic Platform, and that there may be confidentiality and other risks associated with such distribution. Each of the Lenders, each of the Issuing Banks and each Credit Party hereby approves distribution of the Communications through the Approved Electronic Platform and understands and assumes the risks of such distribution.

(iii)THE APPROVED ELECTRONIC PLATFORM AND THE COMMUNICATIONS ARE PROVIDED “AS IS” AND “AS AVAILABLE”. THE APPLICABLE PARTIES (AS DEFINED BELOW) DO NOT WARRANT THE ACCURACY OR COMPLETENESS OF THE COMMUNICATIONS, OR THE ADEQUACY OF THE APPROVED ELECTRONIC PLATFORM AND EXPRESSLY DISCLAIM LIABILITY FOR ERRORS OR OMISSIONS IN THE APPROVED ELECTRONIC PLATFORM AND THE COMMUNICATIONS. NO WARRANTY OF ANY KIND, EXPRESS, IMPLIED OR STATUTORY, INCLUDING ANY WARRANTY OF MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE, NON-INFRINGEMENT OF THIRD PARTY RIGHTS OR FREEDOM FROM VIRUSES OR OTHER CODE DEFECTS, IS MADE BY THE APPLICABLE PARTIES IN CONNECTION WITH THE COMMUNICATIONS OR THE APPROVED ELECTRONIC PLATFORM. IN NO EVENT SHALL THE ADMINISTRATIVE AGENT, ANY LEAD ARRANGER, ANY DOCUMENTATION AGENT, ANY SYNDICATION AGENT OR ANY OF THEIR RESPECTIVE RELATED PARTIES (COLLECTIVELY, “APPLICABLE PARTIES”) HAVE ANY LIABILITY TO ANY CREDIT PARTY, ANY LENDER, ANY ISSUING BANK OR ANY OTHER PERSON OR ENTITY FOR DAMAGES OF ANY KIND, INCLUDING DIRECT OR INDIRECT, SPECIAL, INCIDENTAL OR CONSEQUENTIAL DAMAGES, LOSSES OR EXPENSES (WHETHER IN TORT, CONTRACT OR OTHERWISE) ARISING OUT OF ANY CREDIT PARTY’S OR THE ADMINISTRATIVE AGENT’S TRANSMISSION OF COMMUNICATIONS THROUGH THE INTERNET OR THE APPROVED ELECTRONIC PLATFORM.

(iv)“Communications” means, collectively, any notice, demand, communication, information, document or other material provided by or on behalf of any Credit Party pursuant to any Credit Document or the transactions contemplated therein which is distributed by the Administrative Agent, any Lender or any Issuing Bank by means of electronic communications pursuant to this Section, including through an Approved Electronic Platform.

(v)Each Lender and each Issuing Bank agrees that notice to it (as provided in the next sentence) specifying that Communications have been posted to the Approved Electronic Platform shall constitute effective delivery of the Communications to such Lender for purposes of the Credit Documents. Each Lender and each Issuing Bank agrees (A) to notify the Administrative Agent in writing (which could be in the form of electronic communication) from time to time of such Lender’s or such Issuing Bank’s (as applicable) email address to which the foregoing notice may be sent by electronic transmission and (B) that the foregoing notice may be sent to such email address.

(vi)Each of the Lenders, each of the Issuing Banks and each of the Credit Parties agrees that the Administrative Agent may, but (except as may be required by applicable law) shall not be obligated to, store the Communications on the Approved Electronic Platform in accordance with the Administrative Agent’s generally applicable document retention procedures and policies.

(vii)Nothing herein shall prejudice the right of the Administrative Agent, any Lender or any Issuing Bank to give any notice or other communication pursuant to any Credit Document in any other manner specified in such Credit Document.

13.3No Waiver; Cumulative Remedies. No failure to exercise and no delay in exercising, on the part of the Administrative Agent, the Collateral Agent or any Lender, any right, remedy, power or privilege hereunder or under the other Credit Documents shall operate as a waiver thereof, nor shall any single or partial exercise of any right, remedy, power or privilege hereunder preclude any other or further exercise thereof or the exercise of any other right, remedy, power or privilege. The rights, remedies, powers and privileges herein provided are cumulative and not exclusive of any rights, remedies, powers and privileges provided by Requirements of Law.

13.4Survival of Representations and Warranties. All representations and warranties made hereunder, in the other Credit Documents and in any document, certificate or statement delivered pursuant hereto or in connection herewith shall survive the execution and delivery of this Agreement and the making of the Loans hereunder.

13.5Expenses; Limitation of Liability; Indemnification.

(a)Payment of Expenses; Indemnification. The Borrower agrees (i) to pay or reimburse the Agents and the Lead Arrangers for all their reasonable and documented out-of-pocket costs and expenses incurred in connection with the preparation and execution and delivery of, and any amendment, waiver, supplement or modification to, this Agreement and the other Credit Documents and any other documents prepared in connection herewith or therewith, and the consummation and administration of the transactions contemplated hereby and thereby, including the reasonable fees, disbursements and other charges of Mayer Brown LLP, in its capacity as counsel to the Administrative Agent, one special energy counsel and one counsel in each appropriate local jurisdiction (excluding any allocated costs of in-house counsel), (ii) to pay or reimburse the Agents, each Issuing Bank, each Lead Arranger and each Lender for all of its reasonable and documented out-of-pocket costs and expenses incurred during any workout or restructuring, or negotiations in respect thereof, or in connection with the enforcement or preservation of any rights under this Agreement, the other Credit Documents and any such

other documents, in each case, whether before or after the occurrence of an Event of Default, including the reasonable fees, disbursements and other charges of one counsel, and one counsel in each appropriate local jurisdiction and one financial advisor to the Administrative Agent (unless there is an actual or perceived conflict of interest in which case each such Person may retain its own counsel or financial advisor), (iii) to pay, indemnify, and hold harmless each Lender, Issuing Bank, Lead Arranger and Agent from, any and all recording and filing fees and (iv) to pay, indemnify, and hold harmless each Lender, Issuing Bank, Lead Arranger, Syndication Agent, Documentation Agent, Joint Bookrunner and Agent and their respective Related Parties from and against any and all other liabilities, obligations, losses, damages, penalties, claims, demands, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever, whether or not such proceedings are brought by the Borrower, any of its Related Parties or any other third Person, including reasonable and documented fees, disbursements and other charges of one primary counsel for all such Persons, taken as a whole, and, if necessary, by a single firm of local counsel in each appropriate jurisdiction for all such Persons, taken as a whole (unless there is an actual or perceived conflict of interest in which case each such Person may, with the consent of the Borrower (not to be unreasonably withheld or delayed), retain its own counsel), with respect to (A) the execution, delivery, enforcement, performance and administration of this Agreement, the other Credit Documents and any such other documents and (B) any Loan or Letter of Credit or the use of the proceeds therefrom (including any refusal by any Issuing Bank to honor a demand for payment under a Letter of Credit if the documents presented in connection with such demand do not strictly comply with the terms of such Letter of Credit), including, without limitation, any of the foregoing relating to the violation of, noncompliance with or liability under, any Environmental Law (other than by such indemnified person or any of its Related Parties (other than any trustee or advisor)) or to any actual or alleged presence, release or threatened release of Hazardous Materials involving or attributable to the Borrower, any of its Subsidiaries or any of the Oil and Gas Properties (all the foregoing in this clause (iv), collectively, the “Indemnified Liabilities”); provided that the Borrower shall have no obligation hereunder to any Agent or any Lender or any of their respective Related Parties with respect to Indemnified Liabilities to the extent to have resulted from (x) the gross negligence or willful misconduct of the party to be indemnified or any of its Related Parties as determined by a final non-appealable judgment of a court of competent jurisdiction, (y) any material breach of any Credit Document by the party to be indemnified as determined by a final non-appealable judgment of a court of competent jurisdiction or (z) disputes, claims, demands, actions, judgments or suits not arising from any act or omission by the Borrower or its Affiliates, brought by an indemnified Person against any other indemnified Person (other than disputes, claims, demands, actions, judgments or suits involving claims against any Agent or any Lead Arranger, in each case, in its capacity as such). No Person entitled to indemnification under clause (iv) of this Section 13.5(a) shall be liable for any damages arising from the use by others of any information or other materials obtained through internet, electronic, telecommunications or other information transmission systems (including any Approved Electronic Platform) in connection with this Agreement, except to the extent that such damages have resulted from the willful misconduct or gross negligence of the party to be indemnified or any of its Related Parties (as determined by a court of competent jurisdiction in a final and non-appealable decision), nor (except solely as a result of the indemnification obligations of the Borrower or any of its Subsidiaries set forth above) shall any such Person, the Borrower or any of its Subsidiaries have any liability for any special, punitive, indirect or consequential damages (including, without limitation, any loss of profits, business or anticipated savings) relating to this Agreement or any other Credit Document or arising out of its activities in connection herewith or therewith (whether before or after the Closing Date). All amounts payable under this Section 13.5 shall be paid within ten (10) Business Days of receipt by the Borrower of an invoice relating thereto setting forth such expense in reasonable detail, accompanied, if requested by the Borrower, by reasonable supporting documentation. The agreements in this Section 13.5 shall survive the termination of this Agreement and the repayment of the Loans and payment of all other amounts payable hereunder. This Section 13.5 shall not apply with respect to any Taxes other than Taxes that represent liabilities, obligations, losses, damages, penalties, claims, demands, actions, judgments, suits, costs, expenses or

disbursements of any kind or nature whatsoever resulting from a non-Tax claim, which shall be governed exclusively by Section 5.4 and, to the extent set forth therein, Sections 2.10 and 3.5.

(b)Limitation of Liability. To the extent permitted by applicable law (i) the Borrower and any Credit Party shall not assert, and the Borrower and each Credit Party hereby waives, any claim against the Administrative Agent, the Collateral Agent, any Lead Arranger, any Syndication Agent, any Documentation Agent any Issuing Bank and any Lender, and any Related Party of any of the foregoing Persons (each such Person being called a “Lender-Related Person”) for any Liabilities arising from the use by others of information or other materials (including, without limitation, any personal data) obtained through telecommunications, electronic or other information transmission systems (including the Internet), and (ii) no party hereto shall assert, and each such party hereby waives, any Liabilities against any other party hereto, on any theory of liability, for special, indirect, consequential or punitive damages (as opposed to direct or actual damages) arising out of, in connection with, or as a result of, this Agreement, any other Credit Document, or any agreement or instrument contemplated hereby or thereby, the Transactions, any Loan or Letter of Credit or the use of the proceeds thereof; provided that, nothing in this Section 13.5(b) shall relieve the Borrower and each Credit Party of any obligation it may have to indemnify an Indemnitee, as provided in Section 13.5(a), against any special, indirect, consequential or punitive damages asserted against such Indemnitee by a third party.

(c)Payments. All amounts due under this Section 13.5 shall be payable promptly (but in any event no later than fifteen days) after written demand therefor.

13.6Successors and Assigns; Participations and Assignments.

(a)The provisions of this Agreement shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns permitted hereby (including any Affiliate of each Issuing Bank that issues any Letter of Credit), except that (i) except as expressly permitted by Section 10.3, the Borrower may not assign or otherwise transfer any of its rights or obligations hereunder without the prior written consent of the Administrative Agent and each Lender (and any attempted assignment or transfer by the Borrower without such consent shall be null and void) and (ii) no Lender may assign or otherwise transfer its rights or obligations hereunder except in accordance with this Section 13.6. Nothing in this Agreement, expressed or implied, shall be construed to confer upon any Person (other than the parties hereto, their respective successors and assigns permitted hereby (including any Affiliate of each Issuing Bank that issues any Letter of Credit), Participants (to the extent provided in clause (c) of this Section 13.6) and, to the extent expressly contemplated hereby, the Related Parties of each of the Administrative Agent, the Collateral Agent, each Issuing Bank and the Lenders and each other Person entitled to indemnification under Section 13.5) any legal or equitable right, remedy or claim under or by reason of this Agreement.

(b)(i) Subject to the conditions set forth in clause (b)(ii) below, any Lender may at any time assign to one or more assignees (other than Holdings, the Borrower, its Subsidiaries, any natural person (or holding company, investment vehicle or trust for, or owned and operated for the benefit of, a natural person), any Ineligible Institution or any Defaulting Lender) all or a portion of its rights and obligations under this Agreement (including all or a portion of its Commitments and the Loans (including participations in L/C Obligations or Swingline Loans) at the time owing to it) with the prior written consent of:

(A)the Borrower (not to be unreasonably withheld or delayed); provided that no consent of the Borrower shall be required for an assignment if an Event of Default under Section 11.1 or Section 11.5 has occurred and is continuing or in the case of an assignment to a Lender, an Affiliate of a Lender or an Approved Fund; and

(B)the Administrative Agent, the Swingline Lender and each Issuing Bank (in each case, not to be unreasonably withheld or delayed), provided that no consent of the Administrative Agent, the Swingline Lender or any Issuing Bank shall be required for an assignment of to a Lender (other than a Defaulting Lender), an Affiliate of a Lender or an Approved Fund.

(ii)Assignments shall be subject to the following additional conditions:

(A)except in the case of an assignment to a Lender, an Affiliate of a Lender or an Approved Fund or an assignment of the entire remaining amount of the assigning Lender’s Commitment or Loans, the amount of the Commitment or Loans of the assigning Lender subject to each such assignment (determined as of the date the Assignment and Acceptance with respect to such assignment is delivered to the Administrative Agent) shall not be less than $5,000,000 and increments of $1,000,000 in excess thereof, unless each of the Borrower, each Issuing Bank and the Administrative Agent otherwise consents (which consents shall not be unreasonably withheld or delayed); provided that no such consent of the Borrower shall be required if an Event of Default under Section 11.1 or Section 11.5 has occurred and is continuing; provided, further, that contemporaneous assignments to a single assignee made by Affiliates of Lenders and related Approved Funds shall be aggregated for purposes of meeting the minimum assignment amount requirements stated above;

(B)each partial assignment shall be made as an assignment of a proportionate part of all the assigning Lender’s rights and obligations under this Agreement;

(C)the parties to each assignment shall execute and deliver to the Administrative Agent an Assignment and Acceptance, together with a processing and recordation fee in the amount of $3,500; provided that the Administrative Agent may, in its sole discretion, elect to waive such processing and recordation fee in the case of any assignment; and

(D)the assignee, if it shall not be a Lender, shall deliver to the Administrative Agent an Administrative Questionnaire and applicable Tax forms (including those described in Sections 5.4(d), (e), (h) and (i), as applicable).

(iii)Subject to acceptance and recording thereof pursuant to clause (b)(iv) of this Section 13.6, from and after the effective date specified in each Assignment and Acceptance, the assignee thereunder shall be a party hereto and, to the extent of the interest assigned by such Assignment and Acceptance, have the rights and obligations of a Lender under this Agreement, and the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Acceptance, be released from its obligations under this Agreement (and, in the case of an Assignment and Acceptance covering all of the assigning Lender’s rights and obligations under this Agreement, such Lender shall cease to be a party hereto but shall continue to be entitled to the benefits of Sections 2.10, 2.11, 3.5, 5.4 and 13.5). Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this Section 13.6 shall be treated for purposes of this Agreement as a sale by such Lender of a participation in such rights and obligations in accordance with clause (c) of this Section 13.6.

(iv)The Administrative Agent, acting for this purpose as an agent of the Borrower, shall maintain at the Administrative Agent’s Office a copy of each Assignment and Acceptance delivered to it and a register for the recordation of the names and addresses of the Lenders, and the Commitments of, and principal amount (and stated interest amounts) of the Loans and L/C Obligations and any payment made by each Issuing Bank under any applicable Letter of Credit owing to, each Lender pursuant to the terms hereof from time to time (the “Register”). Further, the Register shall contain the name and address of the Administrative Agent and the lending office through which each such Person acts under this Agreement. The entries in the Register shall be conclusive absent manifest error, and the Borrower, the Administrative Agent, the Collateral Agent, each Issuing Bank and the Lenders shall treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement, notwithstanding notice to the contrary. The Register shall be available for inspection by the Borrower, the Collateral Agent, each Issuing Bank, the Swingline Lender and, solely with respect to itself, each other Lender, at any reasonable time and from time to time upon reasonable prior notice.

(v)Upon its receipt of a duly completed Assignment and Acceptance executed by an assigning Lender and an assignee, the assignee’s completed Administrative Questionnaire (unless the assignee shall already be a Lender hereunder), the processing and recordation fee referred to in clause (b) of this Section 13.6 (unless waived) and any written consent to such assignment required by clause (b) of this Section 13.6, the Administrative Agent shall accept such Assignment and Acceptance and record the information contained therein in the Register.

(c)(i) Any Lender may, without the consent of the Borrower, the Administrative Agent, any Swingline Lender or any Issuing Bank, sell participations to one or more banks, credit insurers, or other entities other than any Defaulting Lender, any Ineligible Institution (to the extent that the list of Ineligible Institutions has been made available to all Lenders), the Borrower or any Subsidiary of the Borrower (each, a “Participant”) in all or a portion of such Lender’s rights and obligations under this Agreement (including all or a portion of its Commitments and the Loans owing to it); providedthat (A) such Lender’s obligations under this Agreement shall remain unchanged, (B) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations and (C) the Borrower, the Administrative Agent, each Issuing Bank and the other Lenders shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under this Agreement. Any agreement or instrument pursuant to which a Lender sells such a participation shall provide that such Lender shall retain the sole right to enforce this Agreement and to approve any amendment, modification or waiver of any provision of this Agreement or any other Credit Document; provided that such agreement or instrument may provide that such Lender will not, without the consent of the Participant, agree to any amendment, modification or waiver described in clause (i) or (ii) of the second proviso of the second sentence of Section 13.1(a) that affects such Participant, provided that the Participant shall have no right to consent to any modification to the percentages specified in the definitions of the terms “Majority Lenders”, “Required Lenders” or “Borrowing Base Required Lenders”. Subject to clause (c)(ii) of this Section 13.6, the Borrower agrees that each Participant shall be entitled to the benefits of Sections 2.10, 2.11, 3.5 and 5.4 to the same extent as if it were a Lender (subject to the limitations and requirements of those Sections and Sections 2.12 and 13.7) as though it were a Lender and had acquired its interest by assignment pursuant to clause (b) of this Section 13.6). To the extent permitted by Requirements of Law, each Participant also shall be entitled to the benefits of Section 13.8(b) as though it were a Lender;provided such Participant agrees to be subject to Section 13.8(a) as though it were a Lender.

(ii)A Participant shall not be entitled to receive any greater payment under Section 2.10, 2.11, 3.5 or 5.4 than the applicable Lender would have been entitled to receive with respect to the participation sold to such Participant, unless the sale of the participation to such Participant is made with the Borrower’s prior written consent (which consent shall not be unreasonably withheld); providedthat the Participant shall be subject to the provisions in Section 2.12 as if it were an assignee under clauses (a) and (b) of this Section 13.6. Each Lender that sells a participation shall, acting solely for this purpose as a nonfiduciary agent of the Borrower, maintain a register on which it enters the name and address of each participant and the principal amounts (and related interest amounts) of each participant’s interest in the Loans or other obligations under this Agreement (the “Participant Register”). The entries in the Participant Register shall be conclusive, absent manifest error, and each party hereto shall treat each Person whose name is recorded in the Participant Register as the owner of such participation for all purposes of this Agreement notwithstanding any notice to the contrary. No Lender shall have any obligation to disclose all or any portion of the Participant Register to any Person (including the identity of any Participant or any information relating to a Participant’s interest in any commitments, loans, letters of credit or its other obligations under any Credit Document) except to the extent that such disclosure is necessary to establish that such commitment, loan, letter of credit or other obligation is in registered form under Section 5f.103-1(c) of the United States Treasury Regulations.

(d)Any Lender may, without the consent of the Borrower, the Swingline Lender, any Issuing Bank or the Administrative Agent, at any time pledge or assign a security interest in all or any portion of its rights under this Agreement to secure obligations of such Lender, including any pledge or assignment to secure obligations to a Federal Reserve Bank or any central bank having jurisdiction over such Lender, and this Section 13.6 shall not apply to any such pledge or assignment of a security interest; provided that no such pledge or assignment of a security interest shall release a Lender from any of its obligations hereunder or substitute any such pledgee or assignee for such Lender as a party hereto. In order to facilitate such pledge or assignment or for any other reason, the Borrower hereby agrees that, upon request of any Lender at any time and from time to time after the Borrower has made its initial borrowing hereunder, the Borrower shall provide to such Lender, at the Borrower’s own expense, a promissory note, substantially in the form of Exhibit H-1 or H-2, as the case may be, evidencing the Loans and Swingline Loans, respectively, owing to such Lender.

(e)Subject to Section 13.16, the Borrower authorizes each Lender to disclose to any Participant, secured creditor of such Lender or assignee of such Lender (each, a “Transferee”) and any prospective Transferee this Agreement and the other Credit Documents, information regarding the Loans and the Letters of Credit, and any and all financial information in such Lender’s possession concerning the Borrower and its Affiliates that has been delivered to such Lender by or on behalf of the Borrower and its Affiliates pursuant to this Agreement or that has been delivered to such Lender by or on behalf of the Borrower and its Affiliates in connection with such Lender’s credit evaluation of the Borrower and its Affiliates prior to becoming a party to this Agreement.

(f)The words “execution,” “signed,” “signature,” and words of like import in any Assignment and Acceptance shall be deemed to include electronic signatures or the keeping of records in electronic form, each of which shall be of the same legal effect, validity or enforceability as a manually executed signature or the use of a paper-based recordkeeping system, as the case may be, to the extent and as provided for in any applicable law, including the Federal Electronic Signatures in Global and National Commerce Act, the New York State Electronic Signatures and Records Act, or any other similar state laws based on the Uniform Electronic Transactions Act.

(g)Notwithstanding anything to the contrary contained herein, any Lender (a “Granting Lender”) may grant to a special purpose funding vehicle (a “SPV”), identified as such in writing from time to time by the Granting Lender to the Administrative Agent and the Borrower, the option to provide to the Borrower all or any part of any Loan that such Granting Lender would otherwise be obligated to make the Borrower pursuant to this Agreement; providedthat (i) nothing herein shall constitute a commitment by any SPV to make any Loan and (ii) if an SPV elects not to exercise such option or otherwise fails to provide all or any part of such Loan, the Granting Lender shall be obligated to make such Loan pursuant to the terms hereof. The making of a Loan by an SPV hereunder shall utilize the Commitment of the Granting Lender to the same extent, and as if, such Loan were made by such Granting Lender. Each party hereto hereby agrees that no SPV shall be liable for any indemnity or similar payment obligation under this Agreement (all liability for which shall remain with the Granting Lender). In furtherance of the foregoing, each party hereto hereby agrees (which agreement shall survive the termination of this Agreement) that, prior to the date that is one year and one day after the payment in full of all outstanding commercial paper or other senior indebtedness of any SPV, it shall not institute against, or join any other person in instituting against, such SPV any bankruptcy, reorganization, arrangement, insolvency or liquidation proceedings under the laws of the United States or any State thereof. In addition, notwithstanding anything to the contrary contained in this Section 13.6, any SPV may (A) with notice to, but without the prior written consent of, the Borrower and the Administrative Agent and without paying any processing fee therefor, assign all or a portion of its interests in any Loans to the Granting Lender or to any financial institutions (consented to by the Borrower and Administrative Agent) providing liquidity and/or credit support to or for the account of such SPV to support the funding or maintenance of Loans and (B) disclose on a confidential basis any non-public information relating to its Loans to any rating agency, commercial paper dealer or provider of any surety, guarantee or credit or liquidity enhancement to such SPV. This Section 13.6(g) may not be amended without the written consent of the SPV. Notwithstanding anything to the contrary in this Agreement, subject to the following sentence, each SPV shall be entitled to the benefits of Sections 2.10, 2.11, 3.5 and 5.4 to the same extent as if it were a Lender (subject to the limitations and requirements of Sections 2.10, 2.11, 3.5 and 5.4 as though it were a Lender), and Sections 2.12 and 13.7, and has acquired its interest by assignment pursuant to clause (b) of this Section 13.6. Notwithstanding the prior sentence, an SPV shall not be entitled to receive any greater payment under Section 2.10, 2.11, 3.5 or 5.4 than its Granting Lender would have been entitled to receive absent the grant to such SPV, unless such grant to such SPV is made with the Borrowers’ prior written consent (which consent shall not be unreasonably withheld or delayed).

(h)Notwithstanding anything to the contrary contained herein, any Lender may, at any time, assign all or a portion of its rights and obligations under this Agreement in respect of its Loans to an Affiliated Lender; provided that an Affiliated Lender shall make a representation and warranty to the assigning Lender that at the time of the assignment, the Affiliated Lender is not in possession of any material non-public information (within the meaning of United States securities laws) with respect to the Borrower and its Subsidiaries that has not been disclosed to such assigning Lender or the Lenders generally (other than because any such Lender has elected not to receive such material non-public information); provided further that, by its acquisition of Loans, an Affiliated Lender shall be deemed to have acknowledged and agreed that:

(i)it shall not have any right to (A) attend (including by telephone) any meeting or discussions (or portion thereof) among the Administrative Agent or any Lender to which representatives of the Borrower are not then present, (B) receive any information or material prepared by the Administrative Agent, the Collateral Agent or any Lender or any communication by or among Administrative Agent, the Collateral Agent and one or more Lenders, except to the extent such information or materials have been made available to the Borrower or its representatives (and in any case, other than the right to receive notices of prepayments and other administrative notices in respect of its Loans required to be delivered to Lenders pursuant to

Section 2), or (C) make or bring (or participate in, other than as a passive participant in or recipient of its pro rata benefits of) any claim, in its capacity as a Lender, against the Administrative Agent, the Collateral Agent or any other Lender with respect to any duties or obligations or alleged duties or obligations of such Agent or any other such Lender under the Credit Documents;

(ii)except with respect to any amendment, modification, waiver, consent or other action described in clause (i) of the second proviso of the second sentence of Section 13.1(a) or that alters an Affiliated Lender’s pro rata share of any payments given to all Lenders, the Loans held by an Affiliated Lender shall be disregarded in both the numerator and denominator in the calculation of any Lender vote (and shall be deemed to have been voted in the same percentage as all other applicable Lenders that are not Affiliated Lenders voted if necessary to give legal effect to this paragraph) under any Credit Document;

(iii)the aggregate principal amount of Loans held by Affiliated Lenders at the time of such assignment may not exceed 25% of the aggregate principal amount of all Loans outstanding at such time under this Agreement; and

(iv)any such Loans acquired by an Affiliated Lender may, with the consent of the Borrower, be contributed to the Borrower and exchanged for debt or equity securities that are otherwise permitted to be issued at such time (and such contribution and/or exchange shall be permitted hereunder notwithstanding the non-pro rata reduction and repayment of such Lender’s Loans and Commitments hereunder as a result thereof).

For the avoidance of doubt, assignments to Affiliated Institutional Lenders will be permitted hereunder and the foregoing limitations in this clause (h) shall not be applicable to Affiliated Institutional Lenders.

(i)Ineligible Institutions. The Borrower has delivered to the Administrative Agent on or prior the Closing Date a list of Ineligible Institutions, which list may be updated from to time by the Borrower in order to add one or more operational competitors of the Borrower to such list; provided that (A) in order to be effective, any such update must be provided in writing to the Administrative Agent at JPMDQ_Contact@jpmorgan.com (or such other address as the Administrative Agent (including any successor Administrative Agent) shall designate in writing to the Borrower) with confirmation of receipt requested, (B) such update shall not be effective until three (3) Business Days after receipt of written confirmation from the Administrative Agent, (C) notwithstanding anything to the contrary included in the original list of Ineligible Institutions or any such update to such list, no Affiliate of any specified Ineligible Institution shall be considered an Ineligible Institution unless Affiliates are expressly indicated in the original list or any such update and then only to the extent any such Affiliate is clearly identifiable solely on the basis of the similarity of its name to the specified Ineligible Institution, and (D) in no event shall any updates to the list of Ineligible Institutions provide for retroactive effect (and any statement to the contrary contained in any such update shall be disregarded and have no effect). The Administrative Agent shall have the right, and the Borrower hereby expressly authorizes the Administrative Agent, to (1) post the list of Ineligible Institutions provided by the Borrower and any updates thereto from time to time on the Approved Electronic Platform, including that portion of the Approved Electronic Platform that is designated for “public side” Lenders and/or (2) provide the list of Ineligible Institutions provided by the Borrower and any updates thereto to each Lender requesting the same. In the event that a Lender proposes to assign all or a portion of its Commitments and Loans in accordance with clause (b) of this Section 13.6 to an assignee, such Lender may request in writing to the Borrower (with a copy to the Administrative Agent) that the Borrower either provide the then-current list of Ineligible Institutions or confirm in writing that a specified proposed assignee is not an Ineligible Institution. In the event that the Borrower fails to respond or fails to provide the then-current list

or the requested confirmation within two (2) Business Days, then the specified proposed assignee shall be conclusively deemed not to be an Ineligible Institution. The Administrative Agent shall not be responsible or have any liability for, or have any duty to ascertain, inquire into, monitor or enforce, compliance with the provisions hereof relating to Ineligible Institutions. Without limiting the generality of the foregoing, the Administrative Agent shall not (a) be obligated to ascertain, monitor or inquire as to whether any assignee Lender or Participant or prospective assignee Lender or Participant is an Ineligible Institution or (b) have any liability with respect to or arising out of any assignment or participation of Commitments or Loans, or disclosure of confidential information, to any Ineligible Institution.

13.7Replacements of Lenders under Certain Circumstances.

(a)The Borrower shall be permitted to replace any Lender that (i) requests reimbursement for amounts owing pursuant to Section 2.10, 3.5 or 5.4 (other than Section 5.4(b)), (ii) is affected in the manner described in Section 2.10 and as a result thereof any of the actions described in such Section is required to be taken or (iii) becomes a Defaulting Lender, with a replacement bank, lending institution or other financial institution; providedthat (A) such replacement does not conflict with any Requirement of Law, (B) no Event of Default under Section 11.1 or 11.5 shall have occurred and be continuing at the time of such replacement, (C) the replacement bank or institution shall purchase, at par, all Loans and the Borrower shall pay all other amounts (other than any disputed amounts), pursuant to Section 2.10, 3.5 or 5.4, as the case may be) owing to such replaced Lender prior to the date of replacement, (D) the replacement bank or institution, if not already a Lender, and the terms and conditions of such replacement, shall be reasonably satisfactory to the Administrative Agent, (E) the replaced Lender shall be obligated to make such replacement in accordance with the provisions of Section 13.6(b) (providedthat the Borrower shall be obligated to pay the registration and processing fee referred to therein) and (F) any such replacement shall not be deemed to be a waiver of any rights that the Borrower, the Administrative Agent or any other Lender shall have against the replaced Lender.

(b)If any Lender (such Lender, a “Non-Consenting Lender”) has failed to consent to a proposed amendment, waiver, discharge or termination that pursuant to the terms of Section 13.1 requires the consent of all of the Lenders affected or the Required Lenders or the Borrowing Base Required Lenders and with respect to which the Majority Lenders shall have granted their consent, then provided no Event of Default then exists, the Borrower shall have the right (unless such Non-Consenting Lender grants such consent) to replace such Non-Consenting Lender by requiring such Non-Consenting Lender to assign its Loans and its Commitments hereunder to one or more assignees reasonably acceptable to the Administrative Agent; provided that: (i) all Obligations of the Borrower owing to such Non-Consenting Lender being replaced (other than principal and interest) shall be paid in full to such Non-Consenting Lender concurrently with such assignment, and (ii) the replacement Lender shall purchase the foregoing by paying to such Non-Consenting Lender a price equal to the principal amount thereof plus accrued and unpaid interest thereon. In connection with any such assignment, the Borrower, Administrative Agent, such Non-Consenting Lender and the replacement Lender shall otherwise comply with Section 13.6.

(c)Notwithstanding anything herein to the contrary, each party hereto agrees that any assignment pursuant to the terms of this Section 13.7 may be effected pursuant to an Assignment and Acceptance executed by the Borrower, the Administrative Agent and the assignee (or, to the extent applicable, an agreement incorporating an Assignment and Acceptance by reference pursuant to an Approved Electronic Platform as to which the Administrative Agent and such parties are participants) and that the Lender making such assignment need not be a party thereto.

13.8Adjustments; Set-off.

(a)If any Lender (a “benefited Lender”) shall at any time receive any payment in respect of any principal of or interest on all or part of the Loans made by it, or the participations in Letter of Credit Obligations held by it, or receive any collateral in respect thereof (whether voluntarily or involuntarily, by set-off, pursuant to events or proceedings of the nature referred to in Section 11.5, or otherwise), in a greater proportion than any such payment to or collateral received by any other Lender entitled thereto, if any, in respect of such other Lender’s Loans, or interest thereon, such benefited Lender shall (i) notify the Administrative Agent of such fact, and (ii) purchase for cash at face value from the other Lenders a participating interest in such portion of each such other Lender’s Loans, or shall provide such other Lenders with the benefits of any such collateral, or the proceeds thereof, as shall be necessary to cause such benefited Lender to share the excess payment or benefits of such collateral or proceeds ratably in accordance with the aggregate principal of and accrued interest on their respective Loans and other amounts owing them; provided, however, that, (A) if all or any portion of such excess payment or benefits is thereafter recovered from such benefited Lender, such purchase shall be rescinded, and the purchase price and benefits returned, to the extent of such recovery, but without interest and (B) the provisions of this paragraph shall not be construed to apply to (1) any payment made by the Borrower or any other Credit Party pursuant to and in accordance with the terms of this Agreement and the other Credit Documents, (2) any payment obtained by a Lender as consideration for the assignment of or sale of a participation in any of its Loans, Commitments or participations in Drawings to any assignee or participant or (3) any disproportionate payment obtained by a Lender as a result of the extension by Lenders of the maturity date or expiration date of some but not all Loans or Commitments or any increase in the Applicable Margin in respect of Loans or Commitments of Lenders that have consented to any such extension. Each Credit Party consents to the foregoing and agrees, to the extent it may effectively do so under Requirements of Law, that any Lender acquiring a participation pursuant to the foregoing arrangements may exercise against such Credit Party rights of set-off and counterclaim with respect to such participation as fully as if such Lender were a direct creditor of such Credit Party in the amount of such participation.

(b)After the occurrence and during the continuance of an Event of Default, in addition to any rights and remedies of the Lenders provided by Requirements of Law, each Lender shall have the right, without prior notice to the Borrower, any such notice being expressly waived by the Borrower to the extent permitted by applicable Requirements of Law, upon any amount becoming due and payable by the Borrower hereunder or under any Credit Document (whether at the stated maturity, by acceleration or otherwise) to set-off and appropriate and apply against such amount any and all deposits (general or special, time or demand, provisional or final), in any currency, and any other credits, indebtedness or claims, in any currency, in each case whether direct or indirect, absolute or contingent, matured or unmatured, at any time held or owing by such Lender or any branch or agency thereof to or for the credit or the account of the Borrower; provided that in the event that any Defaulting Lender shall exercise any such right of setoff, (x) all amounts so set off shall be paid over immediately to the Administrative Agent for further application in accordance with the provisions of Section 2.15(f) and, pending such payment, shall be segregated by such Defaulting Lender from its other funds and deemed held in trust for the benefit of the Administrative Agent, the Collateral Agent, the Issuing Banks, and the Lenders, and (y) the Defaulting Lender shall provide promptly to the Administrative Agent a statement describing in reasonable detail the Obligations owing to such Defaulting Lender as to which it exercised such right of set-off. Each Lender agrees promptly to notify the Borrower (and the Credit Parties, if applicable) and the Administrative Agent after any such set-off and application made by such Lender; provided that the failure to give such notice shall not affect the validity of such set-off and application.

13.9Counterparts; Electronic Execution.

(a)This Agreement may be executed in counterparts (and by different parties hereto on different counterparts), each of which shall constitute an original, but all of which when taken together shall

constitute a single contract. This Agreement and the other Credit Documents constitute the entire contract among the parties relating to the subject matter hereof and supersede any and all previous agreements and understandings, oral or written, relating to the subject matter hereof.

(b)Delivery of an executed counterpart of a signature page of (x) this Agreement, (y) any other Credit Document and/or (z) any document, amendment, approval, consent, information, notice (including, for the avoidance of doubt, any notice delivered pursuant to Section 13.2), certificate, request, statement, disclosure or authorization related to this Agreement, any other Credit Document and/or the transactions contemplated hereby and/or thereby (each an “Ancillary Document”) that is an Electronic Signature transmitted by telecopy, emailed pdf. or any other electronic means that reproduces an image of an actual executed signature page shall be effective as delivery of a manually executed counterpart of this Agreement, such other Credit Document or such Ancillary Document, as applicable. The words “execution,” “signed,” “signature,” “delivery,” and words of like import in or relating to this Agreement, any other Credit Document and/or any Ancillary Document shall be deemed to include Electronic Signatures, deliveries or the keeping of records in any electronic form (including deliveries by telecopy, emailed pdf. or any other electronic means that reproduces an image of an actual executed signature page), each of which shall be of the same legal effect, validity or enforceability as a manually executed signature, physical delivery thereof or the use of a paper-based recordkeeping system, as the case may be; providedthat nothing herein shall require the Administrative Agent to accept Electronic Signatures in any form or format without its prior written consent and pursuant to procedures approved by it; provided, further, without limiting the foregoing, (i) to the extent the Administrative Agent has agreed to accept any Electronic Signature, the Administrative Agent and each of the Lenders shall be entitled to rely on such Electronic Signature purportedly given by or on behalf of the Borrower or any other Credit Party without further verification thereof and without any obligation to review the appearance or form of any such Electronic signature and (ii) upon the request of the Administrative Agent or any Lender, any Electronic Signature shall be promptly followed by a manually executed counterpart. Without limiting the generality of the foregoing, the Borrower and each Credit Party hereby (A) agrees that, for all purposes, including without limitation, in connection with any workout, restructuring, enforcement of remedies, bankruptcy proceedings or litigation among the Administrative Agent, the Lenders, the Borrower and the Credit Parties, Electronic Signatures transmitted by telecopy, emailed pdf. or any other electronic means that reproduces an image of an actual executed signature page and/or any electronic images of this Agreement, any other Credit Document and/or any Ancillary Document shall have the same legal effect, validity and enforceability as any paper original, (B) the Administrative Agent and each of the Lenders may, at its option, create one or more copies of this Agreement, any other Credit Document and/or any Ancillary Document in the form of an imaged electronic record in any format, which shall be deemed created in the ordinary course of such Person’s business, and destroy the original paper document (and all such electronic records shall be considered an original for all purposes and shall have the same legal effect, validity and enforceability as a paper record), (C) waives any argument, defense or right to contest the legal effect, validity or enforceability of this Agreement, any other Credit Document and/or any Ancillary Document based solely on the lack of paper original copies of this Agreement, such other Credit Document and/or such Ancillary Document, respectively, including with respect to any signature pages thereto and (D) waives any claim against any Lender-Related Person for any Liabilities arising solely from the Administrative Agent’s and/or any Lender’s reliance on or use of Electronic Signatures and/or transmissions by telecopy, emailed pdf. or any other electronic means that reproduces an image of an actual executed signature page, including any Liabilities arising as a result of the failure of the Borrower and/or any Credit Party to use any available security measures in connection with the execution, delivery or transmission of any Electronic Signature.

13.10Severability. Any provision of this Agreement that is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability

without invalidating the remaining provisions hereof, and any such prohibition or unenforceability in any jurisdiction shall not invalidate or render unenforceable such provision in any other jurisdiction.

13.11Integration. This Agreement and the other Credit Documents represent the agreement of the Borrower, the Guarantors, the Collateral Agent, the Administrative Agent and the Lenders with respect to the subject matter hereof and thereof, and there are no promises, undertakings, representations or warranties by the Borrower, the Guarantors, any Agent nor any Lender relative to subject matter hereof not expressly set forth or referred to herein or in the other Credit Documents.

13.12GOVERNING LAW. THIS AGREEMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK.

13.13Submission to Jurisdiction; Waivers. Each party hereto hereby irrevocably and unconditionally:

(a)submits for itself and its property in any legal action or proceeding relating to this Agreement and the other Credit Documents to which it is a party, or for recognition and enforcement of any judgment in respect thereof, to the exclusive general jurisdiction of the courts of the State of New York and the courts of the United States of America for the Southern District of New York, in each case located in New York County, and appellate courts from any thereof;

(b)consents that any such action or proceeding shall be brought in such courts and waives any objection that it may now or hereafter have to the venue of any such action or proceeding in any such court or that such action or proceeding was brought in an inconvenient court and agrees not to plead or claim the same;

(c)agrees that service of process in any such action or proceeding may be effected by mailing a copy thereof by registered or certified mail (or any substantially similar form of mail), postage prepaid, to such Person at its address set forth on Schedule 13.2 at such other address of which the Administrative Agent shall have been notified pursuant to Section 13.2;

(d)agrees that nothing herein shall affect the right to effect service of process in any other manner permitted by Requirements of Law or shall limit the right to sue in any other jurisdiction;

(e)waives, to the maximum extent not prohibited by law, any right it may have to claim or recover in any legal action or proceeding referred to in this Section 13.13 any special, exemplary, punitive or consequential damages; and

(f)agrees that a final judgment in any action or proceeding shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by law.

Nothing in this Agreement or in any other Credit Document shall (i) affect any right that the Administrative Agent, any Issuing Bank or any Lender may otherwise have to bring any action or proceeding relating to this Agreement against the Borrower, any Credit Party or its properties in the courts of any jurisdiction, (ii) waive any statutory, regulatory, common law, or other rule, doctrine, legal restriction, provision or the like providing for the treatment of bank branches, bank agencies, or other bank offices as if they were separate juridical entities for certain purposes, including Uniform Commercial Code Sections 4-106, 4-A-105(1)(b), and 5-116(b), UCP 600Article 3 and ISP98 Rule 2.02, and URDG 758Article 3(a), or (iii) affect which courts have or do not have personal jurisdiction over the issuing bank or beneficiary of any Letter of Credit or any advising bank, nominated bank or assignee of proceeds thereunder or proper venue with respect to any litigation arising out of or relating to

such Letter of Credit with, or affecting the rights of, any Person not a party to this Agreement, whether or not such Letter of Credit contains its own jurisdiction submission clause.

13.14Acknowledgments. The Borrower hereby acknowledges and agrees that:

(a)it has been advised by counsel in the negotiation, execution and delivery of this Agreement and the other Credit Documents;

(b)(i) the credit facility provided for hereunder and any related arranging or other services in connection therewith (including in connection with any amendment, waiver or other modification hereof or of any other Credit Document) are an arm’s-length commercial transaction between the Borrower and the other Credit Parties, on the one hand, and the Administrative Agent, the Issuing Banks, the Lenders and the other Agents on the other hand, and the Borrower and the other Credit Parties are capable of evaluating and understanding and understand and accept the terms, risks and conditions of the transactions contemplated hereby and by the other Credit Documents (including any amendment, waiver or other modification hereof or thereof); (ii) in connection with the process leading to such transaction, each of the Administrative Agent, the other Agents, the Issuing Banks and the Lenders, is and has been acting solely as a principal and is not the financial advisor, agent or fiduciary for any of the Borrower, any other Credit Parties or any of their respective Affiliates, equity holders, creditors or employees or any other Person; (iii) none of the Administrative Agent, any other Agent, any Joint Bookrunner, any Lead Arranger, any Issuing Bank or any Lender has assumed or will assume an advisory, agency or fiduciary responsibility in favor of the Borrower or any other Credit Party with respect to any of the transactions contemplated hereby or the process leading thereto, including with respect to any amendment, waiver or other modification hereof or of any other Credit Document (irrespective of whether the Administrative Agent or any other Agent, any Joint Bookrunner, any Lead Arranger, any Issuing Bank or any Lender has advised or is currently advising any of the Borrower, the other Credit Parties or their respective Affiliates on other matters) and none of the Administrative Agent, any Agent, any Joint Bookrunner, any Lead Arranger, any Issuing Bank or any Lender has any obligation to any of the Borrower, the other Credit Parties or their respective Affiliates with respect to the transactions contemplated hereby except those obligations expressly set forth herein and in the other Credit Documents; (iv) the Administrative Agent and its Affiliates, each other Agent and each of its Affiliates, each Issuing Bank and each of its Affiliates and each Lender and its Affiliates may be engaged in a broad range of transactions that involve interests that differ from those of the Borrower and its respective Affiliates, and none of the Administrative Agent, any other Agent, any Issuing Bank or any Lender has any obligation to disclose any of such interests by virtue of any advisory, agency or fiduciary relationship; (v) neither it nor any of its Subsidiaries will assert any claim against the Administrative Agent, any Agent, any Joint Bookrunner, any Lead Arranger, any Issuing Bank or any Lender based on an alleged breach of fiduciary duty by any such Person in connection with this Agreement and the transactions contemplated hereby; and (vi) none of the Administrative Agent, any Agent, any Issuing Bank or any Lender has provided and none will provide any legal, accounting, regulatory or tax advice with respect to any of the transactions contemplated hereby (including any amendment, waiver or other modification hereof or of any other Credit Document) and the Borrower has consulted its own legal, accounting, regulatory and tax advisors to the extent it has deemed appropriate. The Borrower hereby waives and releases, to the fullest extent permitted by law, any claims that it may have against the Administrative Agent and each Agent with respect to any breach or alleged breach of agency or fiduciary duty; and

(c)no joint venture is created hereby or by the other Credit Documents or otherwise exists by virtue of the transactions contemplated hereby among the Lenders or among the Borrower, on the one hand, and any Lender, on the other hand.

13.15WAIVERS OF JURY TRIAL. THE BORROWER, EACH AGENT, EACH ISSUING BANK AND EACH LENDER HEREBY IRREVOCABLY AND UNCONDITIONALLY WAIVE TRIAL BY JURY IN ANY LEGAL ACTION OR PROCEEDING RELATING TO THIS AGREEMENT OR ANY OTHER CREDIT DOCUMENT AND FOR ANY COUNTERCLAIM THEREIN.

13.16Confidentiality. The Administrative Agent, each other Agent, any Issuing Bank, the Swingline Lender and each other Lender shall hold all information not marked as “public information” and furnished by or on behalf of the Borrower or any of its Subsidiaries in connection with such Lender’s evaluation of whether to become a Lender hereunder or obtained by such Lender, the Swingline Lender, the Administrative Agent, any Issuing Bank or such other Agent pursuant to the requirements of this Agreement (“Confidential Information”), confidential in accordance with its customary procedure for handling confidential information of this nature and in any event may make disclosure (a) as required or requested by any Governmental Authority, self-regulatory agency or representative thereof or pursuant to legal process or applicable Requirements of Law, (b) to such Lender’s or the Administrative Agent’s, any Issuing Bank’s or such other Agent’s attorneys, advisors, financial or business consultants, accountants, independent auditors, trustees, agents or Affiliates (and any Affiliate’s attorneys, professional advisors, independent auditors, trustees or agents), in each case who need to know such information in connection with the administration of the Credit Documents and are informed of the confidential nature of such information, (c) to an investor or prospective investor in a securitization that agrees its access to information regarding the Credit Parties, the Loans and the Credit Documents is solely for purposes of evaluating an investment in a securitization and who agrees to treat such information as confidential, (d) to a trustee, collateral manager, servicer, backup servicer, noteholder or secured party in connection with the administration, servicing and reporting on the assets serving as collateral for a securitization and who agrees to treat such information as confidential, (e) to a nationally recognized ratings agency that requires access to information regarding the Credit Parties, the Loans and Credit Documents in connection with ratings issued with respect to a securitization, (f) to the extent such Confidential Information becomes public other than by reason of disclosure by such Person in breach of this Agreement, (g) [intentionally omitted], (h) to any other party to this Agreement, (i) in connection with the exercise of any remedies hereunder or under any other Credit Document or any action or proceeding relating to this Agreement or any other Credit Document or the enforcement of rights hereunder or thereunder, or (j) subject to an agreement containing provisions substantially the same as those of this Section, to (i) any assignee of or Participant in, or any prospective assignee of or Participant in, any of its rights and obligations under this Agreement, or (ii) any actual or prospective party (or its advisors) to any swap, derivative or other transaction relating to the Borrower and its obligations; provided that unless specifically prohibited by applicable Requirements of Law, each Lender, the Administrative Agent, the Swingline Lender, any Issuing Bank and each other Agent shall endeavor to notify the Borrower (without any liability for a failure to so notify the Borrower) of any request made to such Lender, the Administrative Agent, any Issuing Bank or such other Agent, as applicable, by any governmental, regulatory or self-regulatory agency or representative thereof (other than any such request in connection with an examination of such Lender by such governmental agency) for disclosure of any such non-public information prior to disclosure of such information; provided further that in no event shall any Lender, the Administrative Agent, any Issuing Bank or any other Agent be obligated or required to return any materials furnished by the Borrower or any Subsidiary. In addition, each Lender, the Administrative Agent and each other Agent may provide Confidential Information to prospective Transferees or to any pledgee referred to in Section 13.6 or to prospective direct or indirect contractual counterparties in Hedge Agreements to be entered into in connection with Loans made hereunder as long as such Person is advised of and agrees to be bound by the provisions of this Section 13.16 or confidentiality provisions at least as restrictive as those set forth in the Section 13.16.

13.17Release of Collateral and Guarantee Obligations.

(a)The Lenders hereby irrevocably agree that the Liens granted to the Collateral Agent by the Credit Parties on any Collateral shall be automatically released (i) in full, as set forth in clause (b) below, (ii) upon the Disposition of such Collateral (including as part of or in connection with any other Disposition permitted hereunder) to any Person other than another Credit Party (other than Holdings), to the extent such Disposition is made in compliance with the terms of this Agreement (and the Collateral Agent may rely conclusively on a certificate to that effect provided to it by any Credit Party upon its reasonable request without further inquiry), (iii) to the extent such Collateral is comprised of property leased to a Credit Party, upon termination or expiration of such lease, (iv) if the release of such Lien is approved, authorized or ratified in writing by the Majority Lenders (or such other percentage of the Lenders whose consent may be required in accordance with Section 13.1), (v) to the extent the property constituting such Collateral is owned by any Guarantor, upon the release of such Guarantor from its obligations under the Guarantee in accordance with the second succeeding sentence and Section 5(g) of the Guarantee) and (vi) as required by the Collateral Agent to effect any Disposition of Collateral in connection with any exercise of remedies of the Collateral Agent pursuant to the Security Documents. Any such release shall not in any manner discharge, affect, or impair the Obligations or any Liens (other than those being released) upon (or obligations (other than those being released) of the Credit Parties in respect of) all interests retained by the Credit Parties, including the proceeds of any Disposition, all of which shall continue to constitute part of the Collateral except to the extent otherwise released in accordance with the provisions of the Credit Documents. Additionally, the Lenders hereby irrevocably agree that the Guarantors shall be released from the Guarantees upon consummation of any transaction permitted hereunder resulting in such Subsidiary ceasing to constitute a Restricted Subsidiary or otherwise becoming an Excluded Subsidiary. The Lenders hereby authorize the Administrative Agent and the Collateral Agent, as applicable, to execute and deliver any instruments, documents, and agreements necessary or desirable to evidence and confirm the release of any Guarantor or Collateral pursuant to the foregoing provisions of this paragraph, all without the further consent or joinder of any Lender. Any representation, warranty or covenant contained in any Credit Document relating to any such Collateral or Guarantor shall no longer be deemed to be repeated. In connection with any release hereunder, the Administrative Agent and Collateral Agent shall promptly (and the Lenders hereby authorize the Administrative Agent and Collateral Agent to) take such action and execute any such documents as may be reasonably requested by the Borrower and at the Borrower’s expense in connection with the release of any Liens created by any Credit Document in respect of such Subsidiary, property or asset.

(b)Notwithstanding anything to the contrary contained herein or any other Credit Document, when all Obligations (other than (i) Hedging Obligations in respect of any Secured Hedge Transactions, (ii) Cash Management Obligations in respect of any Secured Cash Management Agreements and (iii) any contingent or indemnification obligations not then due) have been paid in full in cash or equivalents thereof, all Commitments have terminated or expired and no Letter of Credit shall be outstanding that is not Cash Collateralized or back- stopped, upon request of the Borrower, the Administrative Agent and/or Collateral Agent, as applicable, shall (without notice to, or vote or consent of, any Secured Party) take such actions as shall be required to release its security interest in all Collateral, and to release all obligations under any Credit Document, whether or not on the date of such release there may be any (A) Hedging Obligations in respect of any Secured Hedge Transactions, (B) Cash Management Obligations in respect of any Secured Cash Management Agreements and (C) any contingent or indemnification obligations not then due. Any such release of Obligations shall be deemed subject to the provision that such Obligations shall be reinstated if after such release any portion of any payment in respect of the Obligations guaranteed thereby shall be rescinded or must otherwise be restored or returned upon the insolvency, bankruptcy, dissolution, liquidation or reorganization of the Borrower or any Guarantor, or upon or as a result of the appointment of a receiver, intervenor or conservator of, or trustee or similar officer for, the Borrower or any Guarantor or any substantial part of its property, or otherwise, all as though such payment had not been made.

13.18USA PATRIOT Act. The Agents and each Lender hereby notify the Borrower that pursuant to the requirements of the USA PATRIOT Act (Title III of Pub. L. 107-56 (signed into law October 26, 2001)) (the “Patriot Act”), it is required to obtain, verify and record information that identifies each Credit Party, which information includes the name and address of each Credit Party and other information that will allow such Agent and such Lender to identify each Credit Party in accordance with the Patriot Act.

13.19Payments Set Aside. To the extent that any payment by or on behalf of the Borrower is made to any Agent or any Lender, or any Agent or any Lender exercises its right of setoff, and such payment or the proceeds of such setoff or any part thereof is subsequently invalidated, declared to be fraudulent or preferential, set aside or required (including pursuant to any settlement entered into by such Agent or such Lender in its discretion) to be repaid to a trustee, receiver or any other party, in connection with any proceeding or otherwise, then (a) to the extent of such recovery, the obligation or part thereof originally intended to be satisfied shall be revived and continued in full force and effect as if such payment had not been made or such setoff had not occurred, and (b) each Lender severally agrees to pay to the Administrative Agent upon demand its applicable share of any amount so recovered from or repaid by any Agent, plus interest thereon from the date of such demand to the date such payment is made at a rate per annum equal to the applicable Overnight Rate from time to time in effect.

13.20Reinstatement. This Agreement shall continue to be effective, or be reinstated, as the case may be, if at any time payment, or any part thereof, of any of the Obligations is rescinded or must otherwise be restored or returned by the Administrative Agent or any other Secured Party upon the insolvency, bankruptcy, dissolution, liquidation or reorganization of the Borrower, or upon or as a result of the appointment of a receiver, intervenor or conservator of, or trustee or similar officer for, the Borrower or any substantial part of its property, or otherwise, all as though such payments had not been made.

13.21Disposition of Proceeds. The Security Documents contain an assignment by the Borrower and/or the Guarantors unto and in favor of the Collateral Agent for the benefit of the Lenders of all of the Borrower’s or each Guarantor’s interest in and to their as-extracted collateral in the form of production and all proceeds attributable thereto which may be produced from or allocated to the Mortgaged Property. The Security Documents further provide in general for the application of such proceeds to the satisfaction of the Obligations described therein and secured thereby. Notwithstanding the assignment contained in such Security Documents, until the occurrence of an Event of Default, (a) the Administrative Agent and the Lenders agree that they will neither notify the purchaser or purchasers of such production nor take any other action to cause such proceeds to be remitted to the Administrative Agent or the Lenders, but the Lenders will instead permit such proceeds to be paid to the Borrower and its Subsidiaries and (b) the Lenders hereby authorize the Administrative Agent to take such actions as may be necessary to cause such proceeds to be paid to the Borrower and/or such Subsidiaries.

13.22Collateral Matters; Hedge Agreements. The benefit of the Security Documents and of the provisions of this Agreement relating to any Collateral securing the Obligations shall also extend to and be available on a pro rata basis pursuant to terms agreed upon in the Credit Documents to any Person under, any Secured Hedge Transaction (including any Legacy Hedge Transaction) after giving effect to all netting arrangements in any Hedge Agreements under which such Secured Hedge Transaction was entered into and (c) any Secured Cash Management Agreement provided that, with respect to (x) each Legacy Hedge Transaction and (y) any other Secured Hedge Transaction or Secured Cash Management Agreement that remains secured after the Hedge Bank thereto or the Cash Management Bank thereunder is no longer a Lender or an Affiliate of a Lender, the provisions of Section 12 shall apply to the hedge provider under each applicable Legacy Hedge Transaction and shall also continue to apply to such Hedge Bank or Cash Management Bank in consideration of its benefits hereunder. Any hedge provider under any Legacy Hedge Transaction, any Hedge Bank and any Cash

Management Bank, as applicable, shall, if requested by the Administrative Agent, promptly execute and deliver to the Administrative Agent all such other documents, agreements and instruments reasonably requested by the Administrative Agent to evidence the continued applicability of the provisions of Section 12. No Person shall have any voting rights under any Credit Document solely as a result of the existence of obligations owed to it under any Legacy Hedge Transaction, any other Secured Hedge Transaction or Secured Cash Management Agreement.

13.23Agency of the Borrower for the Other Credit Parties. Each of the other Credit Parties hereby appoints the Borrower as its agent for all purposes relevant to this Agreement and the other Credit Documents, including the giving and receipt of notices and the execution and delivery of all documents, instruments and certificates contemplated herein and therein and all modifications hereto and thereto.

13.24Acknowledgement and Consent to Bail-In of Affected Financial Institutions. Notwithstanding anything to the contrary in any Credit Document or in any other agreement, arrangement or understanding among any such parties, each party hereto acknowledges that any liability of any Affected Financial Institution arising under any Credit Document may be subject to the Write-Down and Conversion Powers of the applicable Resolution Authority and agrees and consents to, and acknowledges and agrees to be bound by:

(a)the application of any Write-Down and Conversion Powers by the applicable Resolution Authority to any such liabilities arising hereunder which may be payable to it by any party hereto that is an Affected Financial Institution; and

(b)the effects of any Bail-In Action on any such liability, including, if applicable:

(i)a reduction in full or in part or cancellation of any such liability;

(ii)a conversion of all, or a portion of, such liability into shares or other instruments of ownership in such Affected Financial Institution, its parent entity, or a bridge institution that may be issued to it or otherwise conferred on it, and that such shares or other instruments of ownership will be accepted by it in lieu of any rights with respect to any such liability under this Agreement or any other Credit Document; or

(iii)the variation of the terms of such liability in connection with the exercise of the Write-Down and Conversion Powers of the applicable Resolution Authority.

13.25Acknowledgement Regarding Any Supported QFCs. To the extent that the Credit Documents provide support, through a guarantee or otherwise, for Hedge Agreements or any other agreement or instrument that is a QFC (such support “QFC Credit Support” and each such QFC a “Supported QFC”), the parties acknowledge and agree as follows with respect to the resolution power of the Federal Deposit Insurance Corporation under the Federal Deposit Insurance Act and Title II of the Dodd-Frank Wall Street Reform and Consumer Protection Act (together with the regulations promulgated thereunder, the “U.S. Special Resolution Regimes”) in respect of such Supported QFC and QFC Credit Support (with the provisions below applicable notwithstanding that the Credit Documents and any Supported QFC may in fact be stated to be governed by the laws of the State of New York and/or of the United States or any other state of the United States):

In the event a Covered Entity that is party to a Supported QFC (each, a “Covered Party”) becomes subject to a proceeding under a U.S. Special Resolution Regime, the transfer of such Supported QFC and the benefit of such QFC Credit Support (and any interest and obligation in or under such Supported QFC and such QFC Credit Support, and any rights in property securing such Supported QFC or such QFC Credit

Support) from such Covered Party will be effective to the same extent as the transfer would be effective under the U.S. Special Resolution Regime if the Supported QFC and such QFC Credit Support (and any such interest, obligation and rights in property) were governed by the laws of the United States or a state of the United States. In the event a Covered Party or a BHC Act Affiliate of a Covered Party becomes subject to a proceeding under a U.S. Special Resolution Regime, Default Rights under the Credit Documents that might otherwise apply to such Supported QFC or any QFC Credit Support that may be exercised against such Covered Party are permitted to be exercised to no greater extent than such Default Rights could be exercised under the U.S. Special Resolution Regime if the Supported QFC and the Credit Documents were governed by the laws of the United States or a state of the United States. Without limitation of the foregoing, it is understood and agreed that rights and remedies of the parties with respect to a Defaulting Lender shall in no event affect the rights of any Covered Party with respect to a Supported QFC or any QFC Credit Support.

13.26Judgment Currency. If, for the purposes of obtaining judgment in any court, it is necessary to convert a sum due hereunder or any other Credit Document in one currency into another currency, the rate of exchange used shall be that at which in accordance with normal banking procedures the Administrative Agent could purchase the first currency with such other currency on the Business Day preceding that on which final judgment is given. The obligation of the Borrower in respect of any such sum due from it to the Administrative Agent or any Lender hereunder or under the other Credit Documents shall, notwithstanding any judgment in a currency (the “Judgment Currency”) other than that in which such sum is denominated in accordance with the applicable provisions of this Agreement (the “Agreement Currency”), be discharged only to the extent that on the Business Day following receipt by the Administrative Agent or such Lender, as the case may be, of any sum adjudged to be so due in the Judgment Currency, the Administrative Agent or such Lender, as the case may be, may in accordance with normal banking procedures purchase the Agreement Currency with the Judgment Currency. If the amount of the Agreement Currency so purchased is less than the sum originally due to the Administrative Agent or any Lender from the Borrower in the Agreement Currency, the Borrower agrees, as a separate obligation and notwithstanding any such judgment, to indemnify the Administrative Agent or such Lender, as the case may be, against such loss. If the amount of the Agreement Currency so purchased is greater than the sum originally due to the Administrative Agent or any Lender in such Currency, the Administrative Agent or such Lender, as the case may be, agrees to return the amount of any excess to the Borrower (or to any other Person who may be entitled thereto under Applicable law).

[End of Credit Agreement]

EX-21.1

Exhibit 21.1

TALOS ENERGY INC. - LIST OF SUBSIDIARIES*
Company Name	Jurisdiction of Incorporation
ANRP (Talos DC), LLC	Delaware
Talos Energy LLC	Delaware
Talos Energy Offshore LLC	Delaware
Talos Energy Operating Company LLC	Delaware
Talos Energy Phoenix LLC	Delaware
Talos ERT LLC	Delaware
Talos Exploration LLC	Delaware
Talos Low Carbon Solutions LLC	Delaware
Talos Oil & Gas LLC	Delaware
Talos Petroleum LLC	Delaware
Talos Production Finance Inc.	Delaware
Talos Production Inc.	Delaware
Talos Resources LLC	Delaware
Talos Third Coast LLC	Delaware

* Each of the named subsidiaries is not necessarily a “significant subsidiary” as defined in Rule 1-02(w) of Regulation S-X, and Talos has several additional subsidiaries not named above. The unnamed subsidiaries, considered in the aggregate as a single subsidiary, would not constitute a “significant subsidiary” at the end of the year covered by this report.

EX-22.1

Exhibit 22.1

TALOS ENERGY INC. SUBSIDIARY GUARANTORS AND ISSUERS OF GUARANTEED SECURITIES
12.00% Second-Priority Senior Secured Notes due 2026 (“12.00% Notes”)
Legal Entity	Issuer	Guarantor	Jurisdiction of Formation
Talos Production Inc. (“Issuer”)	X		Delaware
Talos Energy Inc. (“Parent Guarantor”)		X	Delaware
ANRP (Talos DC), LLC		X	Delaware
CKB Petroleum, LLC		X	Delaware
Stone Energy Holding, L.L.C.		X	Delaware
Talos Energy LLC		X	Delaware
Talos Energy Holdings LLC		X	Delaware
Talos Energy International LLC		X	Delaware
Talos Energy Offshore LLC		X	Delaware
Talos Energy Operating Company LLC		X	Delaware
Talos Energy Phoenix LLC		X	Delaware
Talos Energy Ventures, LLC		X	Louisiana
Talos Energy Ventures GoM LLC		X	Delaware
Talos Energy Ventures Holdings LLC		X	Delaware
Talos ERT LLC		X	Delaware
Talos Exploration LLC		X	Delaware
Talos Finance Corporation		X	Delaware
Talos Gulf Coast LLC		X	Delaware
Talos Gulf Coast Offshore LLC		X	Delaware
Talos Gulf Coast Onshore LLC		X	Delaware
Talos International Holdings SCS		X	Luxembourg
Talos Oil and Gas LLC		X	Delaware
Talos Petroleum LLC		X	Delaware
Talos Production Finance Inc.		X	Delaware
Talos Resources LLC		X	Delaware
Talos Third Coast LLC		X	Delaware

The 12.00% Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by the Parent Guarantor and on a second-priority senior secured basis by each of the Issuer’s present and future direct or indirect wholly owned material subsidiaries that guarantees the Issuer’s bank credit facility.

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the following Registration Statements:

(1)Registration Statement (Form S-3 No. 333-231925) of Talos Energy Inc. and in the related Prospectus;

(2)Registration Statement (Form S-3 No. 333-248754) of Talos Energy Inc. and in the related Prospectus;

(3)Registration Statement (Form S-3 No. 333-255489) of Talos Energy Inc. and in the related Prospectus;

(4)Registration Statement (Form S-3 No. 333-265589) of Talos Energy Inc. and in the related Prospectus;

(5)Registration Statement (Form S-8 No. 333-225058) pertaining to the Talos Energy Inc. Long Term Incentive Plan; and

(6)Registration Statement (Form S-8 No. 333-256554) pertaining to the Talos Energy Inc. 2021 Long Term Incentive Plan

of our reports dated February 28, 2024, with respect to the consolidated financial statements and the financial statement schedules of Talos Energy Inc. and the effectiveness of internal control over financial reporting of Talos Energy Inc. included in this Annual Report (Form 10-K) of Talos Energy Inc. for the year ended December 31, 2023.

/s/ Ernst & Young LLP

Houston, Texas

February 28, 2024

EX-23.2

Exhibit 23.2

 

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We consent to (i) the inclusion in this Annual Report on Form 10-K of Talos Energy Inc. (the “Form 10-K”) of our report dated February 23, 2024, containing information relating to Talos Energy Inc.'s estimated reserves as of December 31, 2023, and (ii) all references to our firm in the Form 10-K and to the incorporation by reference of said report in the Registration Statement on Form S-3 (File No. 333-231925), Registration Statement on Form S-3 (File No. 333-248754), Registration Statement on Form S-3 (File No. 333-255489), Registration Statement on Form S-3 (File No. 333-265589), Registration Statement on Form S-8 of Talos Energy Inc. (File No. 333-225058) and Registration Statement on Form S-8 of Talos Energy Inc. (File No. 333-256554).

NETHERLAND, SEWELL & ASSOCIATES, INC.
By:	/s/ Richard B. Talley, Jr
	Richard B. Talley, Jr
	Chief Executive Officer

Houston, Texas

February 28, 2024

EX-31.1

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Timothy S. Duncan, certify that:

1.I have reviewed this Annual Report on Form 10-K of Talos Energy Inc. (“registrant”);

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

	/s/ Timothy S. Duncan
February 28, 2024	Timothy S. Duncan
	Chief Executive Officer and President (Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13A-14(A) AND RULE 15D-14(A)

OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

I, Sergio L. Maiworm, Jr., certify that:

1.I have reviewed this Annual Report on Form 10-K of Talos Energy Inc. (“registrant”);

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

	/s/ Sergio L. Maiworm, Jr.
February 28, 2024	Sergio L. Maiworm, Jr.
	Chief Financial Officer and Senior Vice President (Principal Financial Officer)

EX-32.1

Exhibit 32.1

CERTIFICATION OF

CHIEF EXECUTIVE OFFICER AND

CHIEF FINANCIAL OFFICER

UNDER SECTION 906 OF THE

SARBANES OXLEY ACT OF 2002, 18 U.S.C. § 1350

Pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and in connection with the accompanying Annual Report on Form 10-K of Talos Energy Inc. (the “Company”) for the year ended December 31, 2023 that is being filed concurrently with the Securities and Exchange Commission on the date hereof (the “Report”), Timothy S. Duncan, Chief Executive Officer of the Company, and Sergio L. Maiworm, Chief Financial Officer of the Company, each certify, to the best of his knowledge, that:

i.the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

ii.the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

February 28, 2024	/s/ Timothy S. Duncan
	Timothy S. Duncan
	Chief Executive Officer and President (Principal Executive Officer)
	/s/ Sergio L. Maiworm, Jr.
	Sergio L. Maiworm, Jr.
	Chief Financial Officer and Senior Vice President (Principal Financial Officer)

EX-97.1

Exhibit 97.1

TALOS ENERGY INC.
EXECUTIVE COMPENSATION CLAWBACK POLICY

This Executive Compensation Clawback Policy (this “Policy”) was recommended for approval by the Compensation Committee (the “Committee”) of the Board of Directors (the “Board”) of Talos Energy Inc. (the “Company”) and adopted by the Board, effective as of November 15, 2023 (the “Effective Date”). This Policy is intended to comply with the requirements of Section 10D of the Securities Exchange Act of 1934 (the “Exchange Act”) and the rules and regulations promulgated thereunder and Section 303A.14 of the New York Stock Exchange (“NYSE”) Listed Company Manual (collectively, the “Recovery Rules”) and shall be interpreted as such. Unless otherwise specified by the Board and permitted by the Recovery Rules, this Policy will be administered by the Committee (the “Administrator”).

1.Recovery. If the Company is required to prepare a Restatement, the Administrator shall take reasonably prompt action to recover the Excess Amount, if any, from the Covered Executives. The Company must recover all Excess Amounts from the Covered Executives unless, after exercising a normal due process review of all the relevant facts and circumstances and taking all steps required by Exchange Act Rule 10D-1 and any applicable exchange listing standard, the Committee determines that recovery would be impracticable and one of the following conditions is met:

a.The direct expense paid to a third party to assist in enforcing the Policy would exceed the amount to be recovered. Before coming to this conclusion, the Company must make a reasonable attempt to recover such Excess Amount, document such reasonable attempt(s) to recover, and provide documentation to NYSE to the extent required.

b.Recovery would likely cause an otherwise tax-qualified retirement plan, under which benefits are broadly available to employees of the Company, to fail to meet the requirements of Section 401(a)(13) or 411(a) of the Internal Revenue Code (the “Code”) and applicable regulations issued thereunder.

2.Administration. The Administrator shall have full authority to administer, amend or terminate this Policy. The Administrator shall, subject to the provisions of this Policy, make such determinations and interpretations and take such actions in connection with this Policy as it deems necessary, appropriate or advisable. All determinations and interpretations made by the Administrator shall be final, binding and conclusive. Notwithstanding the foregoing, no amendment or termination of this Policy shall be effective if such amendment or termination would (after taking into account any actions taken by the Company contemporaneously with such amendment or termination) cause the Company to violate any federal securities laws, rules of the U.S. Securities and Exchange Commission (the “SEC”), or the rules of any national securities exchange or national securities association on which the Company’s securities are then listed. For the avoidance of doubt, the Administrator may consult with the Audit Committee of the Board (the “Audit Committee”), the Company’s chief financial officer, the Company’s chief accounting officer, and the Company’s general counsel, as applicable, as needed in order to properly administer and interpret any provision of this Policy.

3.Method of Recovery. Subject to applicable law, the Administrator may seek to recover Excess Amounts by (i) requiring a Covered Executive to repay such amount to the Company; (ii) offsetting a Covered Executive’s other compensation; or (iii) such other means or combination of means as the Administrator, in its sole discretion, determines to be appropriate. The Company shall use its best efforts to ensure that the method of recovery employed does not violate Section 409A of the Code and the applicable regulations issued thereunder but shall not be liable to any Covered Executive for any resulting liability thereunder. To the extent that a Covered Executive fails to repay all Excess Amounts to the Company as determined pursuant to this Policy, the Company shall take all actions reasonable and appropriate to recover such amount, subject to applicable law.

4.Acknowledgement by Executive Officers.The Administrator may provide notice to and seek written acknowledgement of this Policy from each Executive Officer; provided that the failure to provide such notice or obtain such acknowledgement shall not affect the applicability or enforceability of this Policy.

5.No Indemnification. Notwithstanding the terms of any of the Company’s organizational documents, any corporate policy or any contract, the Company shall not indemnify any Covered Executive against the loss of any Excess Amount.

6.Disclosures and Record Keeping. The Company shall (i) make all disclosures and filings with respect to this Policy and any actions taken to recover Excess Amounts thereunder required by any federal securities laws, SEC rules, or the rules of any national securities exchange or national securities association on which the Company’s securities are then listed and (ii) maintain all documents and records that are required by the applicable rules and forms of the SEC (including, without limitation, Rule 10D-1 under the Exchange Act and any applicable exchange listing standard.

7.Governing Law. The validity, construction, and effect of this Policy and any determinations relating to this Policy shall be construed in accordance with the laws of the State of Delaware without regard to its conflicts of laws principles.

8.Successors. This Policy shall be binding and enforceable against all Covered Executives and their beneficiaries, heirs, executors, administrators or other legal representatives.

9.Policy Not Exclusive Remedy. This Policy is in addition to (and not in lieu of) any right of repayment, forfeiture or off-set against any Covered Executive that may be available under applicable law or otherwise (whether implemented prior to or after adoption of this Policy). Nothing within this Policy is intended to limit any right of recovery of the Company pursuant to any other Company clawback or compensation recoupment policies or arrangements that may be in effect from time to time (“Other Recovery Policies”); provided, however, that if there is any conflict between this Policy and any Other Recovery Policies, this Policy shall control. The Administrator may, in its sole discretion and in the exercise of its business judgment, determine whether and to what extent additional action is appropriate to address the circumstances surrounding any Restatement to minimize the likelihood of any recurrence and to impose such other discipline as it deems appropriate.

10.Defined Terms. For purposes of this Policy, the following terms will have the meanings set forth below:

“Applicable Period” means the three completed fiscal years preceding the earlier of: (i) the date that the Audit Committee concludes, or reasonably should have concluded, that the Company is required to prepare a Restatement; or (ii) the date a court, regulator, or other legally authorized body directs the Company to prepare a Restatement. The Applicable Period shall be extended to include any transition period (that results from a change in the Company’s fiscal year) within or immediately following the three completed fiscal years described in the preceding sentence; provided, that a transition period between the last day of the Company’s previous fiscal year and the first day of its new fiscal year that comprises a period of nine to twelve months shall be deemed a completed fiscal year.

“Covered Executive” means an individual who has received an Excess Amount of Incentive-Based Compensation.

“Excess Amount” means the value of all Incentive-Based Compensation (calculated on a pre-tax basis) Received after October 2, 2023 by a person: (i) after beginning service as an Executive Officer; (ii) who served as an Executive Officer at any time during the performance period for that Incentive-Based Compensation; (iii) while the Company had a class of securities listed on a national securities exchange or national securities association; and (iv) during the Applicable Period, that exceeded the amount of Incentive-Based Compensation that otherwise would have been Received had the amount been determined based on the applicable Financial Performing Measures, as reflected in the Restatement, computed without regard to any taxes paid on such amounts. With respect to Incentive-Based Compensation based on stock price or total shareholder return (“TSR”), where the Excess Amount is not subject to mathematical recalculation directly from the information in a Restatement: (i) the amount will be based on a reasonable estimate made by the Administrator of the effect of the Restatement on the stock price or TSR upon which the Incentive-Based Compensation was received and (ii) the Company shall maintain documentation of the determination of that reasonable estimate and provide such documentation to the national securities exchange or national securities association on which the Company’s securities are listed at the time of the Restatement.

“Executive Officers” shall include the Company’s president, principal financial officer, principal accounting officer (or if there is no such accounting officer, the controller), any vice-president of the Company in charge of a principal business unit, division, or function (such as sales, administration, or finance), any other officer who performs a policy-making function, or any other person (including any executive officer of the Company’s controlled affiliates) who performs similar policy-making functions for the Company. For the avoidance of doubt, “policy-making function” is not intended to include policymaking functions that are not significant. Executive Officers shall include, at a minimum, executive officers identified pursuant to Item 401(b) of Regulation S-K. It is intended that those individuals identified as Executive Officers pursuant to the Policy will be consistent with those identified by the Board as “officers” pursuant to Rule 16a-1(f) promulgated pursuant to the Exchange Act.

“Financial Reporting Measure” means a measure that is determined and presented in accordance with the accounting principles used in preparing the Company’s financial statements (including “non-GAAP” financial measures, such as those appearing in earnings releases), and any measure that is derived wholly or in part from such measure. Stock price and TSR are Financial Reporting Measures. Examples of additional Financial Reporting Measures include, but are not limited to, measures based on revenues, net income, operating income, financial ratios, EBITDA, liquidity measures, free cash flow, and return measures (such as return on assets). For the avoidance of doubt, a Financial Reporting Measure need not be presented within the financial statements or included in a filing with the SEC to qualify as such.

“Incentive-Based Compensation” includes any compensation that is granted, earned, or vested based wholly or in part upon the attainment of a Financial Reporting Measure; however it does not include: (i) base salaries; (ii) discretionary cash bonuses; (iii) awards (either cash or equity) that are based upon subjective, strategic or operational standards; and (iv) equity awards that vest solely on the passage of time.

Incentive-Based Compensation is deemed “Received” in any Company fiscal period during which the Financial Reporting Measure specified in the Incentive-Based Compensation award is attained, even if the payment or grant of the Incentive-Based Compensation occurs after the end of that period.

“Restatement” means an accounting restatement of any of the Company’s financial statements due to the Company’s material noncompliance with any financial reporting requirement under U.S. securities laws, including any required accounting restatement to correct an error in previously issued financial statements that is material to the previously issued financial statements (often referred to as a “Big R” restatement), or that would result in a material misstatement if the error were corrected in the current period or left uncorrected in the current

period (often referred to as a “little r” restatement). As of the Effective Date (but subject to changes that may occur in accounting principles and rules following the Effective Date), a Restatement does not include situations in which financial statement changes did not result from material non-compliance with financial reporting requirements, such as, but not limited to retrospective: (i) application of a change in accounting principles; (ii) revision to reportable segment information due to a change in the structure of the Company’s internal organization; (iii) reclassification due to a discontinued operation; (iv) application of a change in reporting entity, such as from a reorganization of entities under common control; (v) adjustment to provision amounts in connection with a prior business combination; and (vi) revision for stock splits, stock dividends, reverse stock splits or other changes in capital structure.

Approved and Adopted November 15, 2023

EX-99.1

Exhibit 99.1

 

February 23, 2024

Mr. Floyd Bone

Talos Energy Inc.

333 Clay Street, Suite 3300

Houston, Texas 77002

Dear Mr. Bone:

In accordance with your request, we have audited the estimates prepared by Talos Energy Inc. (Talos), as of December 31, 2023, of the proved reserves and future revenue to the Talos interest in certain oil and gas properties located in Louisiana, Mississippi, Texas, and the Gulf of Mexico. It is our understanding that the proved reserves estimates shown herein constitute all of the proved reserves owned by Talos. We have examined the estimates with respect to reserves quantities, reserves categorization, future producing rates, future net revenue, and the present value of such future net revenue, using the definitions set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Rule 4-10(a). The estimates of reserves and future revenue have been prepared in accordance with the definitions and regulations of the SEC and, with the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas. We completed our audit on or about the date of this letter. This report has been prepared for Talos's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose.

The following table sets forth Talos's estimates of the net reserves and future net revenue, as of December 31, 2023, for the audited properties:

	Net Reserves			Future Net Revenue (M$)
	Oil	NGL	Gas		Present Worth
Category	(MBBL)	(MBBL)	(MMCF)	Total	at 10%
Proved Developed Producing	75,132.2	6,440.2	90,278.7	3,258,649.9	2,911,256.2
Proved Developed Non-Producing	23,092.3	3,517.1	51,544.1	420,646.5	388,794.0
Proved Undeveloped	12,590.1	2,015.5	38,048.3	296,899.8	198,768.0
Total Proved	110,814.6	11,972.8	179,871.1	3,976,196.2	3,498,818.3

Totals may not add because of rounding.

The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in millions of cubic feet (MMCF) at standard temperature and pressure bases.

When compared on a field-by-field basis, some of the estimates of Talos are greater and some are less than the estimates of Netherland, Sewell & Associates, Inc. (NSAI). However, in our opinion the estimates shown herein of Talos's reserves and future revenue are reasonable when aggregated at the proved level and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). Additionally, these estimates are within the recommended 10 percent tolerance threshold set forth in the SPE Standards. We are satisfied with the methods and procedures used by Talos in preparing the December 31, 2023, estimates of reserves and future revenue, and we saw nothing of an unusual nature that would cause us to take exception with the estimates, in the aggregate, as prepared by Talos.

 

 

Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves and future revenue included herein have not been adjusted for risk. Talos's estimates do not include probable or possible reserves that may exist for these properties, nor do they include any value for undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.

Prices used by Talos are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the period January through December 2023. For oil and NGL volumes, the average West Texas Intermediate spot price of $78.21 per barrel is adjusted by field for quality, transportation fees, and market differentials. For gas volumes, the average Henry Hub spot price of $2.637 per MMBTU is adjusted by field for energy content, transportation fees, and market differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $78.56 per barrel of oil, $18.77 per barrel of NGL, and $2.75 per MCF of gas.

Operating costs used by Talos are based on historical operating expense records. These costs include the per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred at and below the district and field levels. Operating costs used by Talos for certain assets have been reduced by expenditure reimbursements, as allowed under production handling agreements. Operating costs have been divided into field-level costs, per-well costs, and per-unit-of-production costs. The field-level costs are allocated by month among the proved reserves categories based on the proportionate share of total proved future net revenue. Estimates of proved developed producing reserves and revenue are consequently dependent on Talos completing the proved drilling and workover programs scheduled in this report. Headquarters general and administrative overhead expenses of Talos are included to the extent that they are covered under joint operating agreements for the operated properties. Capital costs used by Talos are based on authorizations for expenditure and actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and production equipment. Abandonment costs used are Talos's estimates of the costs to abandon the wells, platforms, and production facilities; these estimates do not include any salvage value for the lease and well equipment. Operating, capital, and abandonment costs are not escalated for inflation.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, estimates of Talos and NSAI are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans as provided to us by Talos, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing these estimates.

It should be understood that our audit does not constitute a complete reserves study of the audited oil and gas properties. Our audit consisted primarily of substantive testing, wherein we conducted a detailed review of all properties. In the conduct of our audit, we have not independently verified the accuracy and completeness of information and data furnished by Talos with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production. However, if in the course of our examination something came to our attention that brought into question the validity or sufficiency of any such information or data, we did not rely on such information or data until we had satisfactorily resolved our questions relating thereto or had independently verified such information or data. Our audit did not include a review of Talos's overall reserves management processes and practices.

We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, analogy, and reservoir modeling, that we considered to be appropriate and necessary to establish the conclusions set forth herein. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

 

Supporting data documenting this audit, along with data provided by Talos, are on file in our office. The technical persons primarily responsible for conducting this audit meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. Richard B. Talley, Jr., a Licensed Professional Engineer in the State of Texas, has been practicing consulting petroleum engineering at NSAI since 2004 and has over 5 years of prior industry experience. Edward C. Roy III, a Licensed Professional Geoscientist in the State of Texas, has been practicing consulting petroleum geoscience at NSAI since 2008 and has over 11 years of prior industry experience. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

		Sincerely,
		NETHERLAND, SEWELL & ASSOCIATES, INC.
		Texas Registered Engineering Firm F-2699
		By:	/s/ Eric J. Stevens
			Eric J. Stevens, P.E.
			President and Chief Operating Officer
By:	/s/ Richard B. Talley, Jr.	By:	/s/ Edward C. Roy III
	Richard B. Talley, Jr., P.E. 102425		Edward C. Roy III, P.G. 2364
	Chief Executive Officer		Vice President
Date Signed: February 23, 2024		Date Signed: February 23, 2024

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Document and Entity Information - USD ($)

12 Months Ended

Dec. 31, 2023

Feb. 21, 2024

Jun. 30, 2023

Cover [Abstract]

Document Type

10-K

Amendment Flag

false

Document Period End Date

Dec. 31, 2023

Document Fiscal Year Focus

2023

Document Fiscal Period Focus

FY

Trading Symbol

TALO

Title of 12(b) Security

Common Stock

Security Exchange Name

NYSE

Entity Registrant Name

Talos Energy Inc.

Document Annual Report

true

Document Transition Report

false

Entity Small Business

false

Entity Emerging Growth Company

false

ICFR Auditor Attestation Flag

true

Auditor Name

Ernst & Young LLP

Auditor Location

Houston, Texas

Auditor Firm ID

42

Entity Current Reporting Status

Yes

Entity Interactive Data Current

Yes

Entity Shell Company

false

Entity Incorporation, State or Country Code

DE

Entity File Number

001-38497

Entity Tax Identification Number

82-3532642

Entity Address, Address Line One

333 Clay Street

Entity Address, Address Line Two

Suite 3300

Entity Address, City or Town

Houston

Entity Address, State or Province

TX

Entity Address, Postal Zip Code

77002

City Area Code

713

Local Phone Number

328-3000

Entity Central Index Key

0001724965

Current Fiscal Year End Date

--12-31

Entity Filer Category

Large Accelerated Filer

Entity Common Stock, Shares Outstanding

158,632,597

Entity Well-known Seasoned Issuer

Yes

Entity Voluntary Filers

No

Entity Public Float

$ 1,493,763,437

Documents Incorporated by Reference

Portions of the registrant’s definitive proxy statement relating to the 2024 Annual Meeting of Stockholders are incorporated by reference into Part III of this report.

Document Financial Statement Error Correction Flag

false

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CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Current assets:
Cash and cash equivalents	$ 33,637	$ 44,145
Accounts receivable
Trade, net	178,977	150,598
Joint interest, net	79,337	54,697
Other, net	19,296	6,684
Assets from price risk management activities	36,152	25,029
Prepaid assets	64,387	84,759
Other current assets	10,389	1,917
Total current assets	422,175	367,829
Property and equipment:
Proved properties	7,906,295	5,964,340
Unproved properties, not subject to amortization	268,315	154,783
Other property and equipment	34,027	30,691
Total property and equipment	8,208,637	6,149,814
Accumulated depreciation, depletion and amortization	(4,168,328)	(3,506,539)
Total property and equipment, net	4,040,309	2,643,275
Other long-term assets:
Restricted cash	102,362	0
Assets from price risk management activities	17,551	7,854
Equity method investments	146,049	1,745
Other well equipment	54,277	25,541
Notes receivable, net	16,207	0
Operating lease assets	11,418	5,903
Other assets	5,961	6,479
Total assets	4,816,309	3,058,626
Current liabilities:
Accounts payable	84,193	128,174
Accrued liabilities	227,690	219,769
Accrued royalties	55,051	52,215
Current portion of long-term debt	33,060	0
Current portion of asset retirement obligations	77,581	39,888
Liabilities from price risk management activities	7,305	68,370
Accrued interest payable	42,300	36,340
Current portion of operating lease liabilities	2,666	1,943
Other current liabilities	48,769	60,359
Total current liabilities	578,615	607,058
Long-term liabilities:
Long-term debt	992,614	585,340
Asset retirement obligations	819,645	501,773
Liabilities from price risk management activities	795	7,872
Operating lease liabilities	18,211	14,855
Other long-term liabilities	251,278	176,152
Total liabilities	2,661,158	1,893,050
Commitments and contingencies
Stockholdersʼ Equity:
Preferred stock; $0.01 par value; 30,000,000 shares authorized and zero shares issued or outstanding as of December 31, 2023 and 2022, respectively	0	0
Common stock; $0.01 par value; 270,000,000 shares authorized; 127,480,361 and 82,570,328 shares issued as of December 31, 2023 and 2022, respectively	1,275	826
Additional paid-in capital	2,549,097	1,699,799
Accumulated deficit	(347,717)	(535,049)
Treasury stock, at cost; 3,400,000 and zero shares as of December 31, 2023 and 2022, respectively	(47,504)	0
Total stockholdersʼ equity	2,155,151	1,165,576
Total liabilities and stockholdersʼ equity	$ 4,816,309	$ 3,058,626

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CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares	Dec. 31, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	30,000,000	30,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value	$ 0.01	$ 0.01
Common stock, shares authorized	270,000,000	270,000,000
Common stock, shares issued	127,480,361	82,570,328
Treasury stock, common, shares	3,400,000	0

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CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenues:
Total revenues	$ 1,457,886	$ 1,651,980	$ 1,244,540
Operating expenses:
Lease operating expense	389,621	308,092	283,601
Production taxes	2,451	3,488	3,363
Depreciation, depletion and amortization	663,534	414,630	395,994
Write-down of oil and natural gas properties	0	0	18,123
Accretion expense	86,152	55,995	58,129
General and administrative expense	158,493	99,754	78,677
Other operating (income) expense	(52,155)	33,902	32,037
Total operating expenses	1,248,096	915,861	869,924
Operating income (expense)	209,790	736,119	374,616
Interest expense	(173,145)	(125,498)	(133,138)
Price risk management activities income (expense)	80,928	(272,191)	(419,077)
Equity method investment income (expense)	(3,209)	14,222	0
Other income (expense)	12,371	31,800	(6,988)
Net income (loss) before income taxes	126,735	384,452	(184,587)
Income tax benefit (expense)	60,597	(2,537)	1,635
Net income (loss)	$ 187,332	$ 381,915	$ (182,952)
Net income (loss) per common share:
Basic	$ 1.56	$ 4.63	$ (2.24)
Diluted	$ 1.55	$ 4.56	$ (2.24)
Weighted average common shares outstanding:
Basic	119,894	82,454	81,769
Diluted	120,752	83,683	81,769
Oil
Revenues:
Revenues	$ 1,357,732	$ 1,365,148	$ 1,064,161
Natural Gas
Revenues:
Revenues	68,034	227,306	130,616
NGL
Revenues:
Revenues	$ 32,120	$ 59,526	$ 49,763

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CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-in Capital	Accumulated Deficit	Treasury Stock [Member]
Balance at Dec. 31, 2020	$ 926,601	$ 813	$ 1,659,800	$ (734,012)
Balance, Shares at Dec. 31, 2020		81,279,989
Equity based compensation	20,165		20,165
Equity-based compensation tax withholdings	(3,161)		(3,161)
Equity-based compensation stock issuances		$ 6	(6)
Equity-based compensation stock issuances, shares		601,488
Net Income (Loss)	(182,952)			(182,952)
Balance at Dec. 31, 2021	760,653	$ 819	1,676,798	(916,964)
Balance, Shares at Dec. 31, 2021		81,881,477
Equity based compensation	27,611		27,611
Equity-based compensation tax withholdings	(4,603)		(4,603)
Equity-based compensation stock issuances		$ 7	(7)
Equity-based compensation stock issuances, shares		688,851
Net Income (Loss)	381,915			381,915
Balance at Dec. 31, 2022	$ 1,165,576	$ 826	1,699,799	(535,049)
Balance, Shares at Dec. 31, 2022	82,570,328	82,570,328
Treasury stock, common, shares	0
Equity based compensation	$ 25,008		25,008
Equity-based compensation tax withholdings	(7,459)		(7,459)
Equity-based compensation stock issuances		$ 11	(11)
Equity-based compensation stock issuances, shares		1,110,143
Issuance of common stock for acquisitions	832,198	$ 438	831,760
Issuance of common stock for acquisitions, Shares		43,799,890
Purchase of treasury stock, Shares					3,400,000
Purchase of treasury stock	(47,504)				$ (47,504)
Net Income (Loss)	187,332			187,332
Balance at Dec. 31, 2023	$ 2,155,151	$ 1,275	$ 2,549,097	$ (347,717)	$ (47,504)
Balance, Shares at Dec. 31, 2023	127,480,361	127,480,361
Treasury stock, common, shares	3,400,000				3,400,000

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CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Cash flows from operating activities:
Net income (loss)	$ 187,332	$ 381,915	$ (182,952)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
Depreciation, depletion, amortization and accretion expense	749,686	470,625	454,123
Write-down of oil and natural gas properties and other well equipment	0	0	23,729
Amortization of discount, premium and deferred financing costs	15,039	14,379	13,382
Equity-based compensation expense	12,953	15,953	10,992
Price risk management activities (income) expense	(80,928)	272,191	419,077
Net cash received (paid) on settled derivative instruments	(9,457)	(425,559)	(290,164)
Equity method investment (income) expense	3,209	(14,222)	0
Loss (gain) on extinguishment of debt	0	1,569	13,225
Settlement of asset retirement obligations	(86,615)	(69,596)	(67,988)
Gain (loss) on sale of assets	(66,115)	303	(687)
Changes in operating assets and liabilities:
Accounts receivable	20,352	14,927	(35,396)
Other current assets	7,066	(36,545)	(18,901)
Accounts payable	(60,401)	24,258	(6,261)
Other current liabilities	(96,960)	73,531	64,800
Other non-current assets and liabilities, net	(76,092)	(13,990)	14,409
Net cash provided by (used in) operating activities	519,069	709,739	411,388
Cash flows from investing activities:
Exploration, development and other capital expenditures	(561,434)	(323,164)	(293,331)
Proceeds from (cash paid for) acquisitions, net of cash acquired	17,617
Proceeds from (cash paid for) acquisitions, net of cash acquired		(3,500)	(5,399)
Proceeds from (cash paid for) sale of property and equipment, net	73,004	1,937	4,983
Contributions to equity method investees	(29,447)	(2,250)	0
Investment in intangible assets	(12,366)	0	0
Proceeds from sale of equity method investment	0	15,000	0
Net cash provided by (used in) investing activities	(512,626)	(311,977)	(293,747)
Cash flows from financing activities:
Issuance of senior notes	0	0	600,500
Redemption of senior notes	(30,000)	(18,184)	(356,803)
Proceeds from Bank Credit Facility	825,000	85,000	100,000
Repayment of Bank Credit Facility	(625,000)	(460,000)	(365,000)
Deferred financing costs	(11,775)	(189)	(27,833)
Other deferred payments	(1,545)	0	(7,921)
Payments of finance lease	(16,306)	(25,493)	(21,804)
Purchase of treasury stock	(47,504)	0	0
Employee stock awards tax withholdings	(7,459)	(4,603)	(3,161)
Net cash provided by (used in) financing activities	85,411	(423,469)	(82,022)
Net increase (decrease) in cash, cash equivalents and restricted cash	91,854	(25,707)	35,619
Cash, cash equivalents and restricted cash:
Balance, beginning of period	44,145	69,852	34,233
Balance, end of period	135,999	44,145	69,852
Supplemental non-cash transactions:
Capital expenditures included in accounts payable and accrued liabilities	114,972	105,773	45,761
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$ 130,313	$ 91,809	$ 68,891

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Pay vs Performance Disclosure - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pay vs Performance Disclosure
Net Income (Loss)	$ 187,332	$ 381,915	$ (182,952)

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

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Organization, Nature of Business and Basis of Presentation

12 Months Ended

Dec. 31, 2023

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization, Nature of Business and Basis of Presentation

Note 1 — Organization, Nature of Business and Basis of Presentation

Organization and Nature of Business

Talos Energy Inc. (the “Parent Company”) is a Delaware corporation originally incorporated on November 14, 2017. The Parent Company conducts all business operations through its operating subsidiaries, owns no operating assets and has no material operations, cash flows or liabilities independent of its subsidiaries. The Parent Company’s common stock is traded on The New York Stock Exchange under the ticker symbol “TALO.”

The Parent Company (including its subsidiaries, collectively “Talos” or the “Company”) is a technically driven independent exploration and production company focused on safely and efficiently maximizing long-term value through its operations, currently in the United States (“U.S.”) and offshore Mexico both through upstream oil and gas exploration and production and the development of low carbon solutions opportunities. The Company leverages decades of technical and offshore operational expertise in the acquisition, exploration and development of assets in key geological trends that are present in many offshore basins around the world. The Company is also utilizing its expertise to develop CCS projects to help reduce industrial emissions along the coast of the U.S. Gulf of Mexico.

Basis of Presentation and Consolidation

The Consolidated Financial Statements have been prepared in accordance with GAAP and include the accounts of the Parent Company and entities in which the Parent Company holds a controlling financial interest. Both majority-owned subsidiaries and any variable interest entity in which the Parent Company is the primary beneficiary are consolidated. All intercompany transactions have been eliminated. All adjustments are of a normal, recurring nature and are necessary to fairly present the financial position, results of operations and cash flows for the periods reflected herein.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities 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. Actual results could differ from those estimates.

Segments

The Company has two operating segments: (i) exploration and production of oil, natural gas and NGLs (“Upstream Segment”) and (ii) CCS (“CCS Segment”). The Upstream Segment is the Company’s only reportable segment. The legal entities included in the CCS Segment have been designated as unrestricted, non-guarantor subsidiaries of the Company for purposes of the Bank Credit Facility (as defined in Note 2 — Summary of Significant Accounting Policies) and indenture governing the senior notes. See additional information in Note 15 — Segment Information.

Recently Issued Accounting Standards

Segment Reporting — In November 2023, the Financial Accounting Standards Board (“FASB”) issued an update to the required disclosures for segment reporting. The update is intended to improve reportable segment disclosures, primarily through enhanced disclosures about significant segment expenses. The update will require public entities to disclose significant segment expenses that are regularly provided to the chief operating decision maker and included within segment profit and loss. The update is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024 on a retrospective basis. Early adoption is permitted. The Company is currently evaluating the effect of this update on the Company’s disclosures.

Tax Disclosures — In December 2023, the FASB issued an update which expands disclosures in an entity’s income tax rate reconciliation table and regarding cash taxes paid both in the U.S. and foreign jurisdictions. The update is effective for annual periods beginning after December 15, 2024 on a prospective basis. However, retrospective application in all periods presented is permitted. The Company is currently evaluating the effect of this update on the Company’s disclosures.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2023

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Summary of Significant Accounting Policies

Note 2 — Summary of Significant Accounting Policies

Overview of Significant Accounting Policies

Cash and Cash Equivalents — The Company presents cash as “Cash and cash equivalents” on the Company’s Consolidated Balance Sheets. The Company considers all cash, money market funds and highly liquid investments with an original maturity of three months or less as cash and cash equivalents. Cash and cash equivalents are carried at cost, which approximates fair value.

Accounts Receivable and Allowance for Expected Credit Losses — Accounts receivable are stated at the historical carrying amount net of an allowance for expected credit losses. At each reporting period, the recoverability of material receivables is assessed using historical data, current market conditions and reasonable and supported forecasts of future economic conditions to determine their expected collectability. A loss-rate methodology is used to estimate the allowance for expected credit losses to be accrued on material receivables to reflect the net amount to be collected. As of December 31, 2023 and 2022, the Company had allowances of $8.8 million and $10.7 million, respectively, presented net in accounts receivable on the Consolidated Balance Sheets.

Price Risk Management Activities — The Company uses commodity price derivatives to manage fluctuating oil and natural gas market risks. The Company periodically enters into commodity derivative contracts, which may require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes.

Commodity derivatives are recorded on the Consolidated Balance Sheets at fair value with settlements of such contracts and changes in the unrealized fair value recorded in earnings each period. Realized gains and losses on the settlement of commodity derivatives and changes in their unrealized gains and losses are reported in “Price risk management activities income (expense)” on the Consolidated Statements of Operations. The Company classifies cash flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows are considered an integral part of the Company’s oil and natural gas operations, they are classified as cash flows from operating activities. The Company does not enter into derivative agreements for trading or other speculative purposes.

The commodity derivative’s fair value reflects the Company’s best estimate with priority based upon exchange or over-the-counter quotations. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, the Company then utilizes other valuation techniques or models to estimate market values. These modeling techniques require the Company to make estimations of future prices, price correlation, market volatility and liquidity. The Company’s actual results may differ from its estimates, and these differences can be favorable or unfavorable.

Prepaid Assets — Prepaid assets primarily represent prepaid subscriptions, insurance, progress payments for well equipment and deposits with the Office of Natural Resources Revenue (“ONRR”). The progress payments made for well equipment relate to long lead time items which the Company has not taken title to as of period end. The deposits with ONRR represent the Company’s estimated federal royalties payable within thirty days of the production date. On a monthly basis, the Company adjusts the deposit based on actual royalty payments remitted to the ONRR.

Accounting for Oil and Natural Gas Activities — The Company follows the full cost method of accounting for oil and natural gas exploration and development activities. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the internal costs directly related to acquisition, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and assessed for impairment on a quarterly basis through a ceiling test calculation as discussed below.

Capitalized costs associated with proved reserves are amortized on a country-by-country basis over the life of the total proved reserves using the unit of production method, computed quarterly. Conversely, capitalized costs associated with unproved properties and related geological and geophysical costs, exploration wells currently drilling and capitalized interest are initially excluded from the amortizable base. The Company transfers unproved property costs into the amortizable base when properties are determined to have proved reserves or when the Company has completed an unproved properties evaluation resulting in an impairment. The Company evaluates each of these unproved properties individually for impairment at least annually. Additionally, the amortizable base includes future development costs, dismantlement, restoration and abandonment costs, net of estimated salvage values, and geological and geophysical costs incurred that cannot be associated with specific unproved properties or prospects in which the Company owns a direct interest. The Company capitalizes overhead costs that are directly related to exploration, acquisition and development activities.

The Company’s capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10%, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. Generally, any costs in excess of the ceiling are recognized as a non-cash “Write-down of oil and natural gas properties” on the Consolidated Statements of Operations and an increase to “Accumulated depreciation, depletion and amortization” on the Company’s Consolidated Balance Sheets. The expense may not be reversed in future periods, even though higher oil, natural gas and NGL prices may subsequently increase the ceiling. The Company performs this ceiling test calculation each quarter. In accordance with the SEC rules and regulations, the Company utilizes SEC Pricing when performing the ceiling test. The Company also holds prices and costs constant over the life of the reserves, even though actual prices and costs of oil and natural gas are often volatile and may change from period to period.

Under the full cost method of accounting for oil and natural gas operations, assets whose costs are currently being depreciated, depleted or amortized are assets in use in the earnings activities of the enterprise and do not qualify for capitalization of interest cost. Investments in unproved properties for which exploration and development activities are in progress and other major development projects that are not being currently depreciated, depleted or amortized are assets qualifying for capitalization of interest costs.

When the Company sells or conveys interests in oil and natural gas properties, the Company reduces its oil and natural gas reserves for the amount attributable to the sold or conveyed interest. The Company treats sales proceeds on non-significant sales as reductions to the cost of the Company’s oil and natural gas properties. The Company does not recognize a gain or loss on sales of oil and natural gas properties, unless those sales would significantly alter the relationship between capitalized costs and proved reserves.

Other Property and Equipment — Other property and equipment is recorded at cost and consists primarily of leasehold improvements, office furniture and fixtures and computer hardware. Acquisitions and betterments are capitalized; maintenance and repairs are expensed as incurred. Depreciation is provided using the straight-line method over estimated useful lives of three to ten years.

Restricted Cash — Any cash that is legally restricted from use is classified as restricted cash. If the purpose of restricted cash relates to acquiring a long-term asset, liquidating a long-term liability, or is otherwise unavailable for a period longer than one year from the balance sheet date, the restricted cash is included in other long-term assets. Otherwise, restricted cash is included in other current assets in the Consolidated Balance Sheets. The Company acquired funds held in escrow to be used for future plugging and abandonment (“P&A”) obligations assumed through the EnVen Acquisition (as defined in Note 3 — Acquisitions and Divestitures). These escrow accounts required deposits of approximately $100.0 million, which was fully funded by EnVen (as defined in Note 3 — Acquisitions and Divestitures) prior to the consummation of the acquisition. This is reflected as “Restricted Cash” within “Other long-term assets” on the Consolidated Balance Sheets.

Equity Method Investments — The Company generally accounts for investments under the equity method of accounting when it exercises significant influence over the entity’s operating and financial policies but does not hold a controlling financial interest in the entity. The voting percentage that is presumed to provide an investor with the required level of influence necessary to apply the equity method of accounting varies depending on the nature of the investee. For investments in common stock, in-substance common stock, a limited liability company or partnership that does not maintain specific ownership accounts for each investor, a voting percentage of 20% or more is generally presumed to demonstrate significant influence. For investments in a limited partnership or unincorporated joint venture and a limited liability company or partnership that maintains a specific ownership account for each investor, a voting percentage of 3-5% or more is generally presumed to demonstrate significant influence. Equity method accounting for interests in limited partnerships is generally appropriate unless the interest is so minor that the investor has virtually no influence (less than 3%).

In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for the Company’s proportionate share of earnings, losses, contributions and distributions. Investments accounted for using the equity method are reflected as “Equity method investments” on the Consolidated Balance Sheets. The equity in earnings of an investee is reflected in “Equity method investment income (expense)” on the Consolidated Statement of Operations. The gain or loss from the full or partial sale of an equity method investment is presented in the same line item in which the Company reports the equity in earnings of the investee.

The Company assesses equity method investments for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred if the loss is deemed to be other-than-temporary. When the loss is deemed to be other-than-temporary, the carrying value of the equity method investment is written down to fair value. The impairment charge is included as a component of the Company’s share of the earning or losses of the investee. No impairment charges have been recorded during the years ended December 31, 2023, 2022 and 2021.

Other Well Equipment — Other well equipment primarily represents the cost of equipment to be used in the Company’s oil and natural gas drilling and development activities such as drilling pipe, tubulars and certain wellhead equipment. When well equipment is supplied to wells, the cost is capitalized in oil and gas properties, and if such property is jointly owned, the proportionate costs will be reimbursed by third party participants.

Notes Receivable, net — The Company holds two notes receivable with an aggregate face value of $66.2 million acquired by the Company as part of the EnVen Acquisition (as defined herein), which consist of commitments from the sellers of oil and natural gas properties related to the costs associated with P&A obligations (the “P&A Notes Receivable”). The P&A Notes Receivable are recorded at a discounted value, being accreted to their principal amounts and presented as such, net of related cumulative estimated credit losses, on the accompanying Consolidated Balance Sheets. The Company estimates the current expected credit losses related to its P&A Notes Receivable using the probability of default method based on the long-term credit ratings of the counterparties of the notes, which are currently considered “investment grade.”

Leases — At inception, contracts are reviewed to determine whether the agreement contains a lease. To the extent an arrangement is determined to include a lease, it is classified as either an operating or a finance lease, which dictates the pattern of expense recognition in the income statement. Operating leases are reflected as “Operating lease assets,” “Current portion of operating lease liabilities” and “Operating lease liabilities” on the Consolidated Balance Sheets. Finance leases are included in “Property and equipment,” “Other current liabilities” and “Other long-term liabilities” on the Consolidated Balance Sheets.

A right-of-use (“ROU”) asset representing our right to use an underlying asset for the lease term and a lease liability representing our obligation to make lease payments arising from the lease are recognized on the Consolidated Balance Sheets for all leases, regardless of classification. The ROU asset is initially measured as the present value of the lease liability adjusted for any payments made prior to lease commencement, including any initial direct costs incurred and incentives received. Lease liabilities are initially measured at the present value of future minimum lease payments, excluding variable lease payments, over the lease term. As most of our leases do not provide an implicit rate, the Company generally uses an incremental borrowing rate based on the estimated rate of interest for collateralized borrowing over a similar term of the lease payments at commencement date.

The Company has elected to account for lease and non-lease components in its contracts as a single lease component for all asset classes except for our leased floating production vessel class. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. The Company has elected, as an accounting policy, not to record leases with terms of twelve months or less (i.e., short-term) on the Consolidated Balance Sheets. See Note 5 — Leases for additional information.

Debt Issuance Costs — The Company presents debt issuance costs associated with revolving line-of-credit arrangements as a reduction of the carrying value of long-term debt.

Asset Retirement Obligations — The Company has obligations associated with the retirement of its oil and natural gas wells and related infrastructure. The Company has obligations to plug wells when production on those wells is exhausted, when the Company no longer plans to use them or when the Company abandons them. The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount to replace, remove or retire the associated assets.

In estimating the liability associated with its asset retirement obligations, the Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate. Changes in estimate represent changes to the expected amount and timing of payments to settle its asset retirement obligations. Typically, these changes result from obtaining new information about the timing of its obligations to plug and abandon oil and natural gas wells and the costs to do so. After initial recording, the liability is increased for the passage of time, with the increase being reflected as “Accretion expense” on the Company’s Consolidated Statements of Operations. If the Company incurs an amount different from the amount accrued for asset retirement obligations, the Company recognizes the difference as an adjustment to proved properties.

Decommissioning Obligations — Certain counterparties in divestiture transactions or third parties in existing leases that have filed for bankruptcy protection or undergone associated reorganizations may not be able to perform required abandonment obligations. The Company may be held jointly and severally liable for the decommissioning of various facilities and related wells. The Company accrues losses associated with decommissioning obligations when such losses are probable and reasonably estimable. When there is a range of possible outcomes, the amount accrued is the most likely outcome within the range. If no single outcome within the range is more likely than the others, the minimum amount in the range is accrued. These accruals may be adjusted as additional information becomes available. In addition, when decommissioning obligations are reasonably possible, the Company discloses an estimate for a possible loss or range of loss (or a statement that such an estimate cannot be reasonably made). See Note 14 — Commitments & Contingencies for additional information.

Share-Based Compensation — Certain of the Company’s employees participate in its equity-based compensation plan. The Company measures all employee equity-based compensation awards at fair value on the date awards are granted to its employees.

The fair value of the stock-based awards is determined at the date of grant and is not remeasured for awards classified as equity unless the award is modified. Liability classified awards are remeasured at each reporting period. The Company records share-based compensation, net of actual forfeitures, for the restricted stock units (“RSUs”) and performance share units (“PSUs”) in “General and administrative expense” on the Consolidated Statements of Operations, net of amounts capitalized to oil and gas properties. See Note 10 — Employee Benefits Plans and Share-Based Compensation for additional information.

RSUs — Share-based compensation is based on the market price of the Company’s common stock on the grant date and recognized over the requisite service period using the straight-line method.

PSUs with Market Based Conditions — Share-based compensation is based on the grant date fair value determined using a Monte Carlo valuation model for awards with a market condition and recognized over the requisite service period using the straight-line method. Estimates used in the Monte Carlo valuation model are considered highly-complex and subjective. The number of shares of common stock issuable upon vesting ranges from zero to 200% of the number of PSUs granted based on the Company’s total shareholder return (“TSR”). Share-based compensation related to PSUs with a market condition are recognized as the requisite service period is fulfilled, even if the market condition is not achieved.

PSUs with Performance Based Conditions — Share-based compensation is based on the market price of the Company’s common stock on the grant date and recognized over the requisite service period using the straight-line method for awards with a performance condition. The Company recognizes compensation cost for awards with performance conditions if and when the Company concludes that it is probable that the performance condition will be achieved. The Company reassesses the probability of vesting at each reporting period for awards with performance conditions and adjusts compensation cost based on its probability assessment. The Company recognizes a cumulative catch-up adjustment for such changes in its probability assessment in subsequent reporting periods, using the grant date fair value of the award whose terms reflect the updated probable performance condition (which could be either a reversal or increase in expense). The number of shares of common stock issuable upon vesting ranges from zero to 200% of the number of PSUs granted based on a metric associated with the Company’s own operations or activities.

Revenue Recognition — Revenues are recorded based from the sale of oil, natural gas and NGL quantities sold to purchasers. The Company records revenues from the sale of oil, natural gas and NGLs based on quantities of production sold to purchasers under short-term contracts (less than twelve months) at market prices when delivery to the customer has occurred, title has transferred, prices are fixed and determinable and collection is reasonably assured. This occurs when production has been delivered to a pipeline or when a barge lifting has occurred. The Company recognizes transportation costs as a component of lease operating expense when it is the shipper of the product. Each unit of product typically represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Production Handling Fees — The Company presents certain reimbursements for costs from certain third parties as a reduction of “Lease operating expense” on the Consolidated Statements of Operations.

ONRR Federal Royalty Refund — Included within “Other operating (income) expense” on the Consolidated Statements of Operations is income from the Company’s multi-year federal royalty refund claim from the ONRR. The Company records income when a refund is filed and its collection is reasonably assured.

Income Taxes — The Company records current income taxes based on estimates of current taxable income and provides for deferred income taxes to reflect estimated future income tax payments and receipts. The impact to changes in tax laws are recorded in the period the change is enacted. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. The Company classifies all deferred tax assets and liabilities, along with any related valuation allowance, as long-term on the Consolidated Balance Sheets.

The realization of deferred tax assets depends on recognition of sufficient future taxable income during periods in which those temporary differences are deductible. The Company reduces deferred tax assets by a valuation allowance when, based on estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The deferred tax asset estimates are subject to revision, either up or down, in future periods based on new facts or circumstances. In evaluating the Company’s valuation allowances, the Company considers cumulative book losses, the reversal of existing temporary differences, the existence of taxable income in carryback years, tax planning strategies and future taxable income for each of its taxable jurisdictions, the latter two of which involve the exercise of significant judgment. Changes to the Company’s valuation allowances could materially impact its results of operations.

The Company’s policy is to classify interest and penalties associated with underpayment of income taxes as “Interest expense” and “General and administrative expense” on the Consolidated Statements of Operations, respectively.

Income (Loss) Per Share — Basic net income per common share (“EPS”) is computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted EPS includes the impact of RSUs, PSUs and outstanding warrants. See Note 12 — Income (Loss) Per Share for additional information.

Fair Value Measure of Financial Instruments — Financial instruments generally consist of cash and cash equivalents, accounts receivable, commodity derivatives, accounts payable and debt. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to the highly liquid nature of these instruments.

Current fair value accounting standards define fair value, establish a consistent framework for measuring fair value and stipulate the related disclosure requirements for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis. These standards also clarify fair value is an exit price, presenting the amount that would be received to sell an asset or paid to transfer a liability, in an orderly transaction between market participants. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value depending on the degree to which they are observable as follows:

•Level 1 – Inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

•Level 2 – Inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial statement.

•Level 3 – Inputs to the valuation methodology are unobservable (little or no market data), which require the reporting entity to develop its own assumptions and are significant to the fair value measurement.

Assets and liabilities measured at fair value are based on one or more of three valuation techniques. The valuation techniques are as follows:

•Market Approach – Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.

•Cost Approach – Amount that would be required to replace the service capacity of an asset (replacement cost).

•Income Approach – Techniques to convert expected future cash flows to a single present value amount based on market expectations (including present value techniques, option-pricing and excess earnings models).

Authoritative guidance on financial instruments requires certain fair value disclosures to be presented. The estimated fair value amounts have been determined using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

Variable Interest Entities — Upon inception of a contractual agreement, the Parent Company performs an assessment to determine whether the arrangement contains a variable interest in a legal entity and whether that legal entity is a variable interest Entity (“VIE”). The Parent Company assesses all aspects of its interests in an entity and uses judgment when determining if it is the primary beneficiary. The primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. Other qualitative factors that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. A reassessment of the primary beneficiary conclusion is conducted when there are changes in the facts and circumstances related to a VIE. See Note 7 — Equity Method Investments for additional information.

Concentration of Credit Risk

Consisting principally of cash and cash equivalents, accounts receivable and commodity derivatives, the Company is subject to concentrated financial instruments credit risk.

Cash and cash equivalents balances are maintained in financial institutions, which at times, exceed federally insured limits. The Company monitors the financial condition of these institutions and has not experienced losses on these accounts.

Commodity derivatives are entered into with registered swap dealers, all of which participate in the Company’s senior reserve-based revolving credit facility (the “Bank Credit Facility”). The Company monitors the financial condition of these institutions and has not experienced losses due to counterparty default on these instruments.

The Company markets the majority of its oil and natural gas production, and substantially all of its revenues are attributable to the U.S. The majority of the Company’s oil, natural gas and NGL production is sold to customers under short-term (less than 12 months) contracts at market-based prices. The Company’s customers consist primarily of major oil and natural gas companies, well-established oil and pipeline companies and independent oil and gas producers and suppliers. The Company performs ongoing credit evaluations of its customers and provide allowances for probable credit losses when necessary.

The percent of consolidated revenue of major customers, those whose total represented 10% or more of the Company’s oil, natural gas and NGL revenues, was as follows:

	Year Ended December 31,
	2023			2022			2021
Shell Trading (US) Company		54	%		44	%		45	%
Valero Energy Corporation		21	%		23	%	**
Chevron Products Company	**				11	%		29	%

** Less than 10%

The loss of a major customer could have material adverse effect on the Company in the short term. However, the Company believes it would be able to obtain other customers to market its oil, natural gas and NGL production.

Cash, Cash Equivalents and Restricted Cash

The following table provides a reconciliation of the amount of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheets to the total of the same such amounts shown in the Consolidated Statement of Cash Flows (in thousands):

	Year Ended December 31,
	2023		2022
Cash and cash equivalents	$	33,637	$	44,145
Restricted cash included in Other long-term assets		102,362		—
Total cash, cash equivalent and restricted cash	$	135,999	$	44,145

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Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2023

Business Combinations [Abstract]

Acquisitions and Divestitures

Note 3 — Acquisitions and Divestitures

Business Combinations

Acquisitions qualifying as business combinations are accounted for under the acquisition method of accounting, which requires, among other items, that assets acquired and liabilities assumed be recognized on the Consolidated Balance Sheets at their fair values as of the acquisition date.

EnVen Acquisition — On September 21, 2022, the Company executed a merger agreement to acquire EnVen Energy Corporation (“EnVen”), a private operator in the Deepwater U.S. Gulf of Mexico (the “EnVen Acquisition,” and such agreement, the “EnVen Merger Agreement”). On February 13, 2023, the Company completed the EnVen Acquisition for consideration consisting of (i) $207.3 million in cash, (ii) 43.8 million shares of the Company’s common stock valued at $832.2 million and (iii) the effective settlement of an accounts receivable balance of $8.4 million. No gain or loss was recognized on settlement as the payable was effectively settled at the recorded amount. The cash payment was partially funded with borrowings under the Bank Credit Facility.

The following table summarizes the purchase price (in thousands except share and per share data):

Talos common stock		43,799,890
Talos common stock price per share(1)	$	19.00
Common stock value	$	832,198
Cash consideration	$	207,313
Settlement of preexisting relationship	$	8,388
Total purchase price	$	1,047,899

(1)Represents the closing price of the Company’s common stock on February 13, 2023, the date of the closing of the EnVen Acquisition.

The following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed based on their fair values on February 13, 2023 (in thousands):

Current assets	$	243,571
Property and equipment		1,455,347
Other long-term assets:
Restricted cash		100,753
Notes receivable, net		14,844
Other long-term assets		48,899
Current liabilities:
Current portion of long-term debt		(33,234	)
Current portion of asset retirement obligations		(7,079	)
Other current liabilities		(124,347	)
Long-term liabilities:
Long-term debt		(233,836	)
Asset retirement obligations		(251,779	)
Deferred tax liabilities		(150,264	)
Other long-term liabilities		(14,976	)
Allocated purchase price	$	1,047,899

The fair values determined for accounts receivable, accounts payable and other current assets and most current liabilities were equivalent to the carrying value due to their short-term nature. Assumed debt was valued based on observable market prices.

The fair value of proved oil and natural gas properties as of the acquisition date is based on estimated proved oil, natural gas and NGL reserves and related discounted future net cash flows incorporating market participant assumptions. Significant inputs to the valuation include estimates of future production volumes, future operating and development costs, future commodity prices, and a weighted average cost of capital discount rate. When estimating the fair value of proved and unproved properties, additional risk adjustments were applied to proved developed non-producing, proved undeveloped, probable and possible reserves to reflect the relative uncertainty of each reserve class. These inputs are classified as Level 3 unobservable inputs, including the underlying commodity price assumptions which are based on the five-year NYMEX forward strip prices, escalated for inflation thereafter, and adjusted for price differentials.

The fair value of asset retirement obligations is determined by calculating the present value of estimated future cash flows related to the liabilities. The Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate.

The Company incurred approximately $21.8 million of acquisition-related costs in connection with the EnVen Acquisition exclusive of severance expense, of which $12.8 million was recognized during the year ended December 31, 2023 and $9.0 million was recognized during the year ended December 31, 2022 and reflected in general and administrative expense on the Consolidated Statements of Operations. Additionally, the Company incurred $25.3 million in severance expense in connection with the EnVen Acquisition for the year ended December 31, 2023. See Note 10 — Employee Benefit Plans and Share-Based Compensation for additional discussion.

The following table presents revenue and net income (loss) attributable to the EnVen Acquisition for the period from February 13, 2023 to December 31, 2023 (in thousands):

	Year Ended December 31, 2023
Revenue	$	423,624
Net income (loss)	$	85,622

Pro Forma Financial Information (Unaudited) — The following supplemental pro forma financial information (in thousands, except per common share amounts), presents the consolidated results of operations for the years ended December 31, 2023 and 2022 as if the EnVen Acquisition had occurred on January 1, 2022. The unaudited pro forma information was derived from historical statements of operations of the Company and EnVen adjusted to include (i) depletion expense applied to the adjusted basis of the oil and natural gas properties acquired, (ii) interest expense to reflect borrowings under the Bank Credit Facility and to adjust the amortization of the premium of the 11.75% Notes (as defined in Note 8 — Debt), (iii) general and administrative expense adjusted for transaction related costs incurred (including severance), (iv) other income (expense) to adjust the accretion of the discount on the P&A Notes Receivable and (v) weighted average basic and diluted shares of common stock outstanding from the issuance of 43.8 million shares of common stock to EnVen. Supplemental pro forma earnings for the year ended December 31, 2022 were adjusted to include $65.1 million of general and administrative expenses, of which $16.3 million were incurred during the year ended December 31, 2022. Supplemental pro forma earnings for the year ended December 31, 2023 were adjusted to exclude $65.1 million of general and administrative expenses. This information does not purport to be indicative of results of operations that would have occurred had the EnVen Acquisition occurred on January 1, 2022, nor is such information indicative of any expected future results of operations (in thousands, except for the per share data).

	Year Ended December 31,
	2023		2022
Revenue	$	1,509,929	$	2,355,215
Net income (loss)	$	217,537	$	425,995
Basic net income (loss) per common share	$	1.74	$	3.37
Diluted net income (loss) per common share	$	1.73	$	3.34

Subsequent Event

QuarterNorth Acquisition — On January 13, 2024, the Company executed a merger agreement to acquire QuarterNorth Energy Inc. (“QuarterNorth,” and such acquisition, the “QuarterNorth Acquisition”), a privately-held U.S. Gulf of Mexico exploration and production company. The QuarterNorth Acquisition is expected to close during the first quarter of 2024. Consideration for the QuarterNorth Acquisition primarily consists of (i) approximately $964.9 million in cash, (ii) the amount of net unrestricted cash of QuarterNorth as of December 31, 2023 and (iii) 24.8 million shares of the Company’s common stock.

Divestiture

Mexico Divestiture — On September 27, 2023, the Company closed the sale of a 49.9% equity interest in its subsidiary, Talos Energy Mexico 7, S. de R.L. de C.V. (“Talos Mexico”) to Zamajal, S.A. de C.V., a wholly owned subsidiary of Grupo Carso, for $74.9 million in cash consideration with an additional $49.9 million contingent on first oil production from the Zama Field (the “Mexico Divestiture”). The contingent consideration will be recognized when regular commercial production from the Zama Field becomes probable. Talos Mexico, through its wholly owned subsidiary, holds a 17.4% unitized interest in the Zama Field.

As a result of the Mexico Divestiture, Talos Mexico was deconsolidated on September 27, 2023 and is now accounted for as an equity method investment. Total assets derecognized included $112.3 million of unproved properties associated with exploration and appraisal activities in Block 7 located in the shallow waters off the coast of Mexico’s Tabasco state. The fair value of the Company’s retained equity method investment in Talos Mexico was $107.6 million. The determination of fair value was based on the implied fair value of Talos Mexico. The implied fair value of Talos Mexico was based on the transaction price of the Mexico Divestiture, which was an orderly transaction between market participants. A gain of $66.2 million was recognized on the Mexico Divestiture during the year ended December 31, 2023 which is included in “Other operating (income) expense” on the Consolidated Statements of Operations.

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2023

Oil and Gas Property [Abstract]

Property, Plant and Equipment

Note 4 — Property, Plant and Equipment

Proved Properties

The Company’s interests in oil and natural gas proved properties are located in the United States, primarily in the Gulf of Mexico deep and shallow waters. During 2023, 2022 and 2021, the Company’s ceiling test computations did not result in a write-down of its U.S. oil and natural gas properties. At December 31, 2023, its ceiling test computation was based on SEC pricing of $78.56 per Bbl of oil, $2.75 per Mcf of natural gas and $18.77 per Bbl of NGLs.

Unproved Properties

Unproved capitalized costs of oil and natural gas properties excluded from amortization relate to unevaluated properties associated with acquisitions, leases awarded in the U.S. Gulf of Mexico federal lease sales, certain geological and geophysical costs, expenditures associated with certain exploratory wells in progress and capitalized interest.

During the year ended December 31, 2023, the Company derecognized $112.3 million of unproved properties associated with the exploration and appraisal activities in Block 7 located in the shallow waters off the coast of Mexico’s Tabasco state. See Note 3 — Acquisitions and Divestitures for additional discussion.

During the year ended December 31, 2021, the Company’s evaluation of unproved property located offshore Mexico resulted in a non-cash impairment of $18.1 million presented as “Write-down of oil and natural gas properties” on the Consolidated Statements of Operations. The non-cash impairment was primarily attributable to the Company’s operations in offshore Mexico in Block 31 associated with the Company’s non-consent of the proposed appraisal plan during the fourth quarter of 2021.

The following table sets forth a summary of the Company’s oil and natural gas property costs not being amortized at December 31, 2023, by the year in which such costs were incurred (in thousands):

			Year Ended December 31,
	Total		2023		2022		2021		2020 and Prior
Acquisition United States	$	249,799	$	229,216	$	—	$	—	$	20,583
Exploration United States		18,516		10,108		1,299		2,295		4,814
Total unproved properties, not subject to amortization	$	268,315	$	239,324	$	1,299	$	2,295	$	25,397

The excluded costs will be included in the amortization base as properties are evaluated and proved reserves are established or impairment is determined. The unproved costs will be excluded from the amortization base until the Company has made a determination as to the existence of proved reserves. The Company currently estimates these costs will be transferred to the amortization base over eight years.

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Leases

12 Months Ended

Dec. 31, 2023

Leases [Abstract]

Leases

Note 5 — Leases

The Company has operating leases principally for office space, drilling rigs, compressors and other equipment necessary to support the Company’s operations. Additionally, the Company has a finance lease related to the use of the Helix Producer I (the “HP-I”), a dynamically positioned floating production facility that interconnects with the Phoenix Field through a production buoy. The HP-I is utilized in the Company’s oil and natural gas development activities and the ROU asset was capitalized and included in proved property and depleted as part of the full cost pool. Once items are included in the full cost pool, they are indistinguishable from other proved properties. The capitalized costs within the full cost pool are amortized over the life of the total proved reserves using the unit-of-production method, computed quarterly. Costs associated with the Company’s leases are either expensed or capitalized depending on how the underlying asset is utilized.

In November 2022, the Company exercised its option to extend the lease of the HP-I through June 1, 2024. The extension resulted in a remeasurement of the lease liability to $166.3 million and corresponding adjustment to proved property.

The lease costs described below are presented on a gross basis and do not represent the Company’s net proportionate share of such amounts. A portion of these costs have been or may be billed to other working interest owners. The Company’s share of these costs is included in property and equipment, lease operating expense or general and administrative expense, as applicable. The components of lease costs were as follows (in thousands):

	Year Ended December 31,
	2023			2022		2021
Finance lease cost - interest on lease liabilities	$	14,476		$	7,558	$	11,453
Operating lease cost, excluding short-term leases(1)		4,883			2,281		2,706
Short-term lease cost(2)		117,132			55,072		38,472
Variable lease cost(3)		2,888			1,450		1,356
Variable and fixed sublease income		(482	)		—		—
Total lease cost	$	138,897		$	66,361	$	53,987

(1)Operating lease cost reflect a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis.

(2)Short-term lease costs are reported at gross amounts and primarily represent costs incurred for drilling rigs, most of which are short-term contracts not recognized as a ROU asset and lease liability on the Consolidated Balance Sheets.

(3)Variable lease costs primarily represent differences between minimum payment obligations and actual operating charges incurred by the Company related to its long-term leases.

The present value of the fixed lease payments recorded as the Company’s ROU asset and liability, adjusted for initial direct costs and incentives were as follows (in thousands):

	Year Ended December 31,
	2023		2022
Operating leases:
Operating lease assets	$	11,418	$	5,903
Current portion of operating lease liabilities	$	2,666	$	1,943
Operating lease liabilities		18,211		14,855
Total operating lease liabilities	$	20,877	$	16,798
Finance leases:
Proved properties	$	166,261	$	166,261
Other current liabilities	$	17,834	$	16,306
Other long-term liabilities		131,230		149,064
Total finance lease liabilities	$	149,064	$	165,370

The table below presents the lease maturity by year as of December 31, 2023 (in thousands). Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the Consolidated Balance Sheets.

	Operating Leases			Finance Leases
2024	$	4,748		$	30,782
2025		4,716			30,782
2026		4,803			30,782
2027		4,708			30,782
2028		4,610			30,782
Thereafter		4,584			43,608
Total lease payments	$	28,169		$	197,518
Imputed interest		(7,292	)		(48,454	)
Total lease liabilities	$	20,877		$	149,064

The table below presents the weighted average remaining lease term and discount rate related to leases:

	Year Ended December 31,
	2023			2022			2021
Weighted average remaining lease term:
Operating leases	5.9 years			6.4 years			7.4 years
Finance leases	6.4 years			7.4 years			1.4 years
Weighted average discount rate:
Operating leases		10.8	%		11.8	%		11.9	%
Finance leases		9.2	%		9.2	%		21.9	%

The table below presents the supplemental cash flow information related to leases (in thousands):

	Year Ended December 31,
	2023			2022		2021
Operating cash outflow from finance leases	$	14,476		$	7,181	$	11,453
Operating cash outflow from operating leases	$	6,318		$	3,722	$	3,864
ROU assets obtained in exchange for new finance lease liabilities	$	—		$	166,261	$	—
ROU assets obtained in exchange for new operating lease liabilities(1)	$	12,971		$	474	$	1,020
Remeasurement of lease liability arising from modification of ROU asset(2)	$	(5,124	)	$	—	$	—

(1)See EnVen Acquisition in Note 3 — Acquisitions and Divestitures.

(2)Lease termination accounted for as a lease modification based on the modified lease term. The termination did not take effect contemporaneously with the effective date of the modification.

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Financial Instruments

12 Months Ended

Dec. 31, 2023

Financial Instruments [Abstract]

Financial Instruments

Note 6 — Financial Instruments

As of December 31, 2023 and 2022, the carrying amounts of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximate their fair values because they are highly liquid or due to the short-term nature of these instruments.

Debt Instruments

The following table presents the carrying amounts, net of discount and deferred financing costs, and estimated fair values of the Company’s debt instruments (in thousands):

	December 31, 2023				December 31, 2022
	Carrying Amount		Fair Value		Carrying Amount			Fair Value
12.00% Second-Priority Senior Secured Notes – due January 2026	$	601,353	$	655,130	$	590,132		$	674,542
11.75% Senior Secured Second Lien Notes – due April 2026	$	234,221	$	233,410	$	—		$	—
Bank Credit Facility – matures March 2027	$	190,100	$	200,000	$	(4,792	)	$	—

The carrying value of the senior notes are adjusted for discount, premium and deferred financing costs. Fair value is estimated (representing a Level 1 fair value measurement) using quoted secondary market trading prices and, where such prices are not available, other observable (Level 2) inputs are used such as quoted prices for similar liabilities in the active markets.

The carrying amount of the Company’s bank credit facility, as amended and restated (the “Bank Credit Facility”), is presented net of deferred financing costs. The fair value of the Bank Credit Facility is estimated based on the outstanding borrowings under the Bank Credit Facility since it is secured by the Company’s reserves and the interest rates are variable and reflective of market rates (representing a Level 2 fair value measurement).

Oil and Natural Gas Derivatives

The Company attempts to mitigate a portion of its commodity price risk and stabilize cash flows associated with sales of oil and natural gas production. The Company is currently utilizing oil and natural gas swaps and costless collars. Swaps are contracts where the Company either receives or pays depending on whether the oil or natural gas floating market price is above or below the contracted fixed price. Costless collars consist of a purchased put option and a sold call option with no net premiums paid to or received from counterparties. Typical collar contracts require payments by the Company if the NYMEX average closing price is above the ceiling price or payments to the Company if the NYMEX average closing price is below the floor price.

In connection with the EnVen Acquisition, the Company assumed oil and natural gas collar contracts that combine a two-way collar with a short put that holds an exercise price below the floor price (“three-way collar”). In these contracts, when the NYMEX average closing price is below the floor price, the Company receives the difference between the NYMEX average closing price and the floor price, capped at the difference between the floor price and the short put price.

The following table presents the impact that derivatives, not designated as hedging instruments, had on its Consolidated Statements of Operations (in thousands):

	Year Ended December 31,
	2023			2022			2021
Net cash received (paid) on settled derivative instruments	$	(9,457	)	$	(425,559	)	$	(290,164	)
Unrealized gain (loss)(1)		90,385			153,368			(128,913	)
Price risk management activities income (expense)	$	80,928		$	(272,191	)	$	(419,077	)

(1)Includes $1.4 million gain from the unrealized derivative instruments acquired from the EnVen Acquisition for the year ended December 31, 2023.

The following tables reflect the contracted average daily volumes and weighted average prices under the terms of the Company's derivative contracts as of December 31, 2023:

Swap Contracts
Production Period	Settlement Index	Volumes		Swap Price
Crude oil:		(Bbls)		(per Bbl)
January 2024 – December 2024	NYMEX WTI CMA		16,859	$	74.30
January 2025 – December 2025	NYMEX WTI CMA		7,734	$	73.80
Natural gas:		(MMBtu)		(per MMBtu)
January 2024 – December 2024	NYMEX Henry Hub		18,716	$	3.41
January 2025 – December 2025	NYMEX Henry Hub		13,712	$	3.92

Two-Way Collar Contracts
Production Period	Settlement Index	Volumes		Floor Price		Ceiling Price
Crude oil:		(Bbls)		(per Bbl)		(per Bbl)
January 2024 – December 2024	NYMEX WTI CMA		1,497	$	70.00	$	79.32
Natural gas:		(MMBtu)		(per MMBtu)		(per MMBtu)
January 2024 – December 2024	NYMEX Henry Hub		10,000	$	4.00	$	6.90

Three-Way Collar Contracts
Production Period	Settlement Index	Volumes		Short Put Price		Floor Price		Ceiling Price
Crude oil:		(Bbls)		(per Bbl)		(per Bbl)		(per Bbl)
January 2024 – March 2024	NYMEX WTI CMA		3,200	$	57.27	$	70.00	$	98.01

The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands):

	December 31, 2023
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas derivatives	$	—	$	53,703		$	—	$	53,703
Liabilities:
Oil and natural gas derivatives		—		(8,100	)		—		(8,100	)
Total net asset (liability)	$	—	$	45,603		$	—	$	45,603

	December 31, 2022
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas derivatives	$	—	$	32,883		$	—	$	32,883
Liabilities:
Oil and natural gas derivatives		—		(76,242	)		—		(76,242	)
Total net asset (liability)	$	—	$	(43,359	)	$	—	$	(43,359	)

Financial Statement Presentation

Derivatives are classified as either current or non-current assets or liabilities based on their anticipated settlement dates. Although the Company has master netting arrangements with its counterparties, the Company presents its derivative financial instruments on a gross basis in its Consolidated Balance Sheets. The following table presents the fair value of derivative financial instruments as well as the potential effect of netting arrangements on the Company's recognized derivative asset and liability amounts (in thousands):

	December 31, 2023				December 31, 2022
	Assets		Liabilities		Assets		Liabilities
Oil and natural gas derivatives:
Current	$	36,152	$	7,305	$	25,029	$	68,370
Non-current		17,551		795		7,854		7,872
Total gross amounts presented on balance sheet		53,703		8,100		32,883		76,242
Less: Gross amounts not offset on the balance sheet		8,100		8,100		32,883		32,883
Net amounts	$	45,603	$	—	$	—	$	43,359

Credit Risk

The Company is subject to the risk of loss on its financial instruments as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. The Company has entered into International Swaps and Derivative Association agreements with counterparties to mitigate this risk. The Company also maintains credit policies with regard to its counterparties to minimize overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the regular monitoring of counterparties’ credit exposures; (iii) the use of contract language that affords the Company netting or set off opportunities to mitigate exposure risk; and (iv) potentially requiring counterparties to post cash collateral, parent guarantees, or letters of credit to minimize credit risk. The Company’s assets and liabilities from commodity price risk management activities at December 31, 2023 represent derivative instruments from nine counterparties; all of which are registered swap dealers that have an “investment grade” (minimum Standard & Poor’s rating of BBB- or better) credit rating, and eight of which are parties under the Company’s Bank Credit Facility. The Company enters into derivatives directly with these counterparties and, subject to the terms of the Company’s Bank Credit Facility, is not required to post collateral or other securities for credit risk in relation to the derivative activities. Had the Company’s counterparties failed to perform under existing commodity derivative contracts the maximum loss at December 31, 2023 would have been $45.6 million.

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Equity Method Investments

12 Months Ended

Dec. 31, 2023

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments

Note 7 — Equity Method Investments

The following table presents the Company’s investments in unconsolidated affiliates by segment for the periods indicated below. The Company accounts for these investments using the equity method of accounting.

	Ownership Interest at			Year Ended December 31,
	December 31, 2023			2023		2022
Upstream:
Talos Energy Mexico 7, S. de R.L. de C.V		50.1	%	$	107,259	$	—
SP 49 Pipeline LLC		33.3	%		861		374
CCS:
Bayou Bend CCS LLC		25.0	%		28,183		1,371
Harvest Bend CCS LLC		65.0	%		9,746		—
Coastal Bend CCS LLC		50.0	%		—		—
Total Equity Method Investments				$	146,049	$	1,745

Talos Energy Mexico 7, S. de R.L. de C.V.

See Note 3 – Acquisitions and Divestitures for additional information on the deconsolidation of Talos Mexico. There is $66.0 million positive basis difference related to this investment, which will be amortized on a units of production method once regular commercial production from the Zama Field commences.

Bayou Bend CCS LLC

On March 8, 2022, the Company made a $2.3 million cash contribution for a 50% membership interest in Bayou Bend CCS LLC (“Bayou Bend”). Bayou Bend has a CCS site that is in the early stages of development located offshore Jefferson County, Texas, near the Beaumont and Port Arthur, Texas industrial corridor. In May 2022, the Company sold a 25% membership interest to Chevron U.S.A. Inc. (“Chevron”) for upfront cash consideration of $15.0 million. The Company recognized a $13.9 million gain on the partial sale of its investment in Bayou Bend during the year ended December 31, 2022, which is included in “Equity method investment income (expense)” on the Consolidated Statement of Operations. Chevron also agreed to fund up to $10.0 million of contributions to Bayou Bend on the Company’s behalf, which was fully funded by the first quarter of 2023. The Bayou Bend investment was increased with an offsetting gain as the capital carry was funded by Chevron. The Company recognized an $8.6 million and $1.4 million gain during the years ended December 31, 2023 and 2022, respectively, on the funding of the capital carry of its investment in Bayou Bend. This gain is included in “Equity method investment income (expense)” on the Consolidated Statements of Operations.

Effective March 1, 2023, Chevron became the operator of Bayou Bend. During March 2023, Bayou Bend expanded its storage footprint through the acquisition of onshore acreage in Chambers and Jefferson Counties, Texas located within the Houston Ship Channel, Beaumont and Port Arthur region.

VIE Disclosures

VIE and Primary Beneficiary Determination — Talos Mexico, Bayou Bend, Harvest Bend CCS LLC (“Harvest Bend”), and Coastal Bend CCS LLC (“Coastal Bend”) were each determined to be a VIE. Neither Talos Mexico, Bayou Bend, Harvest Bend, nor Coastal Bend had sufficient equity at risk to finance their respective activities without additional subordinated financial support. The Company is not the primary beneficiary of these VIE’s due to the governance structure of these entities. The most significant activities of these entities are jointly controlled by the owners. The level of the Company’s economic interest in Harvest Bend is not indicative of the amount of power held.

Financings — All of the Company’s VIE’s have historically been funded through equity contributions from owners.

Maximum Exposure — The Company’s maximum exposure to loss as result of its involvement with VIE’s is the carrying amount of each investment.

Nature of Risks — Talos Mexico holds a working interest in the unitized Zama Field. In March 2023, Petróleos Mexicanos submitted the Zama Unit Development Plan (“UDP”) to Mexico’s governmental agency for approval and the UDP received approved in June 2023. An Integrated Project Team (“IPT”) was formed in March 2023 to pool the talents and competencies of all companies participating in the development of the Zama Field. The IPT reports to the Zama Unit Operating Committee, which includes representatives from each of the participating companies. Final Investment Decision (“FID”) is expected following completion and final review of the front-end engineering and design (“FEED”), project financing and final approvals. Achieving FID is a crucial stage and marks the beginning of the engineering and construction stage, where project contractors proceed with procuring material and beginning the construction. Availability of equipment and unexpected construction hurdles could delay the start of oil and gas production. Even though an IPT exists, teamwork could remain a challenge. There is also a risk that the project will not be completed within the budget and timeline, which ultimately could have an adverse impact on the net present value of the project.

The successful development of our CCS projects is dependent on various economic, regulatory, operational and technical factors. The failure to satisfy, wholly or in a significant measure, any of such factors could have a material adverse impact on the Company’s business, results of operations and financial condition. For example, successful development of CCS projects in the United States requires compliance with stringent and varied regulatory schemes including obtaining Class VI well permits that are applicable to subsurface injection of CO2 for geologic sequestration. Locating a suitable source of anthropogenic CO2 and reaching suitable agreements to capture that CO2 is crucial. Infrastructure to transport CO2 between the source and CCS project sites is also required. In project areas with existing CO2 transportation pipelines, reaching an agreement on CO2 transportation with operators of such pipelines will be necessary. Inability to reach a suitable agreement may render a project uneconomic or impracticable. Separately, if no CO2 pipelines exist in proposed project areas, or if existing pipelines do not extend to one or more of the Company’s project sites, conversion of existing pipelines or construction of new pipelines or lateral connections will be required, which may render one or more projects uneconomic. Given the capital-intensive nature of CCS projects, project finance plays a critical role in accelerating the development of the Company’s projects. If the Company is unable to obtain acceptable financing for its CCS projects, then it could result in significant delays in the development and construction of such projects. Lastly, the development of CCS projects is incentivized by tax credits provided under Section 45Q of the Internal Revenue Code of 1986, as amended. The Company’s inability to benefit from such tax credits could prevent the development of the Company’s projects.

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Debt

12 Months Ended

Dec. 31, 2023

Debt Disclosure [Abstract]

Debt

Note 8 — Debt

A summary of the detail comprising the Company’s debt and the related book values for the respective periods presented is as follows (in thousands):

	Year Ended December 31,
	2023			2022
12.00% Second-Priority Senior Secured Notes – due January 2026	$	638,541		$	638,541
11.75% Senior Secured Second Lien Notes – due April 2026		227,500			—
Bank Credit Facility – matures March 2027		200,000			—
Total debt, before discount, premium and deferred financing cost		1,066,041			638,541
Unamortized discount, premium and deferred financing cost, net		(40,367	)		(53,201	)
Total debt		1,025,674			585,340
Less: Current portion of long-term debt		33,060			—
Long-term debt	$	992,614		$	585,340

12.00% Second-Priority Senior Secured Notes

The 12.00% Second-Priority Senior Secured Notes due 2026 (the “12.00% Notes”) were issued pursuant to an indenture dated January 4, 2021 and the first supplemental indenture dated January 14, 2021 between the Parent Company (the “Parent Guarantor”), Talos Production Inc. (the “Issuer”), and certain of the Issuer's subsidiaries (the “Subsidiary Guarantors” and, together with the Parent Guarantor, the “Guarantors”) and Wilmington Trust, National Association, as trustee and collateral agent. The 12.00% Notes rank pari passu in right of payment and constitute a single class of securities for all purposes under the indentures. The 12.00% Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by the Parent Guarantor and on a second-priority senior secured basis by each of the Subsidiary Guarantors and will be unconditionally guaranteed on the same basis by certain of the Issuer’s future subsidiaries. The 12.00% Notes are secured on a second-priority basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 12.00% Notes mature January 15, 2026 and have interest payable semi-annually each January 15 and July 15.

The Company may redeem all or a portion of the 12.00% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest if redeemed during the period commencing on January 15 of the years set forth below:

Period	Redemption Price
2023		106.000	%
2024		103.000	%
2025 and thereafter		100.000	%

The indenture governing the 12.00% Notes applies certain limitations on the Company’s ability and the ability of its subsidiaries to, among other things, (i) incur, assume or guarantee additional indebtedness or issue certain convertible or redeemable equity securities; (ii) create liens to secure indebtedness; (iii) pay distributions on equity interests, repurchase equity securities or redeem junior lien, unsecured or subordinated indebtedness; (iv) make investments; (v) restrict distributions, loans or other asset transfers from Talos Production Inc.’s restricted subsidiaries; (vi) consolidate with or merge with or into, or sell substantially all of Talos Production Inc.’s properties to, another person; (vii) sell or otherwise dispose of assets, including equity interests in subsidiaries; and (viii) enter into transactions with affiliates. The 12.00% Notes contain customary quarterly and annual reporting, financial and administrative covenants. The Company was in compliance with all debt covenants at December 31, 2023.

The Issuer initiated a notes consent solicitation on October 21, 2022, to obtain the requisite holders’ consent to certain amendments to the indenture governing the Issuer’s 12.00% Notes to permit the incurrence of indebtedness in respect of the 11.75% Senior Secured Second Lien Notes due 2026 of EnVen (the “Notes Consent Solicitation”). The Notes Consent Solicitation expired on October 27, 2022, with holders of 95.8% of the aggregate principal amount of the 12.00% Notes outstanding consenting. As a result, the Issuer entered into a second supplemental indenture to the base indenture on October 27, 2022, which became effective upon its execution. The Issuer offered holders of the 12.00% Notes consideration equal to 50 basis points times the principal amount of the 12.00% Notes held by such consenting holder (“Consent Fee”). On February 13, 2023, the Issuer paid the Consent Fee of approximately $3.1 million in the aggregate in connection with the EnVen Acquisition.

During the year ended December 31, 2022, the Company repurchased $11.5 million of the 12.00% Notes. The debt repurchases resulted in a loss on extinguishment of debt for the year ended December 31, 2022 of $1.6 million, which is presented as “Other income (expense)” on the Consolidated Statements of Operations.

Subsequent Event — On January 23, 2024, the Company issued a conditional notice to redeem in full the 12.00% Notes at a redemption price of 103.00% of the principal amount thereof, plus accrued and unpaid interest to, but excluding, the redemption date, in accordance with the 12.00% Notes indenture. The 12.00% Notes were redeemed on February 7, 2024 for $662.4 million utilizing the net proceeds from the Debt Offering (as defined below).

11.75% Senior Secured Second Lien Notes

On February 13, 2023, in conjunction with the closing of the EnVen Acquisition, the Company assumed EnVen’s 11.75% Senior Secured Second Lien Notes due 2026 (the “11.75% Notes”) with a principal amount of $257.5 million. The 11.75% Notes mature on April 15, 2026 and interest accrues and is to be paid semi-annually in cash in arrears on April 15th and October 15th of each year. The indenture governing the 11.75% Notes requires the redemption of $15.0 million of the principal amount outstanding at par value on April 15th and October 15th of each year.

The Company may redeem all or a portion of the 11.75% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest if redeemed during the period commencing on February 15 of the years set forth below:

Period	Redemption Price
2023		105.875	%
2024		102.938	%
2025 and thereafter		100.000	%

The 11.75% Notes are governed by an indenture by and among Energy Ventures GoM LLC, EnVen Finance Corporation as co-issuers, the guarantors party thereto and Wilmington Trust, National Association as trustee and collateral agent, dated as of April 15, 2021 (“11.75% Notes Indenture”). Talos Production Inc. and certain of its subsidiaries entered into a supplemental indenture to the 11.75% Notes Indenture which, inter alia, provides for the assumption of the indebtedness in respect of the 11.75% Notes by Talos Production Inc., as well as guarantees of such indebtedness by certain subsidiaries of Talos Production Inc., as contemplated by the terms of the 11.75% Notes Indenture.

The 11.75% Notes Indenture 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 Talos Production Inc. subsidiaries’ ability to pay dividends, create liens, and sell certain assets.

Subsequent Event — On January 26, 2024, the Company issued a conditional notice to redeem in full the 11.75% Notes at a redemption price of 102.938% of the principal amount thereof, plus accrued and unpaid interest to, but excluding, the redemption date, in accordance with the 11.75% Notes Indenture. The Company irrevocably deposited funds with the trustee sufficient to satisfy and discharge the 11.75% Notes Indenture and the 11.75% Notes until redeemed on April 15, 2024 with the funds deposited with the trustee and elected to satisfy and discharge the 11.75% Notes Indenture in accordance with its terms and the 11.75% Notes trustee acknowledged such discharge and satisfaction. The Company deposited $247.5 million with the trustee on February 7, 2024 utilizing the net proceeds from the Debt Offering.

11.00% Second-Priority Senior Secured Notes

On January 13, 2021, the Company redeemed $347.3 million aggregate principal amount of the 11.00% Second-Priority Senior Secured Notes due 2022 (the “11.00% Notes”) at 102.75% plus accrued and unpaid interest using the proceeds from the issuance of the 12.00% Notes. The debt redemption resulted in a loss on extinguishment of debt of $13.2 million for the year ended December 31, 2021, which is included in “Other income (expense)” on the Consolidated Statements of Operations.

7.50% Senior Notes

The 7.50% Senior Notes due 2022 matured on May 31, 2022 and were redeemed at an aggregate principal of $6.1 million plus accrued and unpaid interest.

Bank Credit Facility

The Company maintains a Bank Credit Facility with a syndicate of financial institutions. The Bank Credit Facility provides for the determination of the borrowing base based on the Company’s proved producing reserves and a portion of the Company's proved undeveloped reserves. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter of each year. On December 23, 2022, the Company entered into the Incremental Agreement and Ninth Amendment to Credit Agreement (the “Ninth Amendment”). The Ninth Amendment, among other things, (i) extended the maturity date of the Bank Credit Facility from November 12, 2024 to March 31, 2027, (ii) increased the borrowing base from $1.1 billion to $1.5 billion and (iii) increased commitments from $806.3 million to $965.0 million, in each case went into effect upon the closing of the EnVen Acquisition and the occurrence of certain events related thereto. On June 9, 2023, the borrowing base decreased from $1.5 billion to $1.1 billion and commitments were reaffirmed at $965.0 million as part of the biannual determination.

The Bank Credit Facility no longer bears interest at the applicable London InterBank Offered Rate plus the applicable margin. Interest under the Bank Credit Facility accrues at the Company’s option either at an alternate base rate (“ABR”) plus the applicable margin (“ABR Loans”), an adjusted term secured overnight financing rate (“SOFR”) plus the applicable margin (“Term Benchmark Loans”) or adjusted daily simple SOFR plus the applicable margin (“RFR Loans”). The ABR is based on the greater of (a) the prime rate, (b) a federal funds rate plus 0.5% or (c) the adjusted term SOFR for a one-month interest period plus 1.00%. The adjusted term SOFR is equal to the term SOFR for each applicable tenor (e.g., one-month, three-months, six-months, and twelve-months) calculated and published by the CME Group Inc. plus 0.10%. The adjusted daily simple SOFR is equal to the overnight SOFR calculated and published by the Federal Reserve Bank of New York plus 0.10%. In addition, the Company is obligated to pay a commitment fee on the unutilized portion of the commitments. The pricing grid below shows the applicable margin for Term Benchmark Loans, RFR Loans and ABR Loans as well as the commitment fee rate, in each case based upon the applicable borrowing base utilization percentage:

Borrowing Base Utilization Percentage	Utilization	Term Benchmark Loans and RFR Loans	ABR Loans	Commitment Fee Rate
Level 1	< 25%	2.75%	1.75%	0.38%
Level 2	≥ 25% < 50%	3.00%	2.00%	0.38%
Level 3	≥ 50% < 75%	3.25%	2.25%	0.50%
Level 4	≥ 75% < 90%	3.50%	2.50%	0.50%
Level 5	≥ 90%	3.75%	2.75%	0.50%

The Bank Credit Facility has certain debt covenants, the most restrictive of which is that the Company must maintain a Consolidated Total Debt to EBITDAX Ratio (as defined in the Bank Credit Facility) of no greater than 3.00 to 1.00 calculated each quarter utilizing the most recent twelve months to determine EBITDAX. The Company must also maintain a current ratio no less than 1.00 to 1.00 each quarter. Under the Bank Credit Facility, unutilized commitments are included in current assets in the current ratio calculation. The Bank Credit Facility is secured by, among other things, mortgages covering at least 85.0% of the oil and natural gas assets of the Company. The Bank Credit Facility is fully and unconditionally guaranteed by the Company and certain of its wholly-owned subsidiaries.

As of December 31, 2023, the Company's borrowing base was $1,075.0 million with total commitments of $965.0 million. Additionally, no more than $250.0 million of the Company’s borrowing base can be used as letters of credit with current commitments at $150.0 million. The amount the Company is able to borrow with respect to the borrowing base is subject to compliance with the financial covenants and other provisions of the Bank Credit Facility. The Company was in compliance with all debt covenants at December 31, 2023. As of December 31, 2023, the Company had outstanding borrowings at a weighted average interest rate of 8.26%. See Note 14 — Commitments and Contingencies for the amount of letters of credit issued under the Bank Credit Facility as of December 31, 2023.

Subsequent Event — On January 13, 2024, the Company entered into the Tenth Amendment to Credit Agreement (the “Tenth Amendment”). The Tenth Amendment, among other things, (i) permits the incurrence of additional indebtedness in order to fund the QuarterNorth Acquisition, with such indebtedness excluded from any reduction of the borrowing base that would otherwise result from such incurrence, and (ii) reaffirms the borrowing base at $1.1 billion effective upon closing of the QuarterNorth Acquisition.

Limitation on Restricted Payments Including Dividends

The Company has not historically declared or paid any cash dividends on its capital stock. However, to the extent the Company determines in the future that it may be appropriate to pay a special dividend or initiate a quarterly dividend program, the Company’s ability to pay any such dividends to its stockholders may be limited to the extent its consolidated subsidiaries are limited in their ability to make distributions to the Parent Company, including the significant restrictions that the agreements governing the Company’s debt impose on the ability of its consolidated subsidiaries to make distributions and other payments to the Parent Company. With respect to entities accounted for under the equity method, the Company’s primary equity method investee as of December 31, 2023 did not have any undistributed earnings.

The Bank Credit Facility contains restrictions on the ability of Talos Production Inc. to transfer funds to the Parent Company in the form of cash dividends, loans or advances. The Bank Credit Facility restricts distributions and other payments to the Parent Company, subject to certain baskets and other exceptions described therein including the payment of operating expense incurred in the ordinary course of business and for income taxes attributable to its ownership in Talos Production Inc. Under the Bank Credit Facility, general distributions and other restricted payments may be made to the Company so long as after giving pro forma effect to the making of any such restricted payment (i) no default or event of default has occurred and is continuing; (ii) available commitments exceed 25% of the then effective loan limit; (iii) the pro forma current ratio of 1.0 to 1.0 is satisfied; and (iv) either (A) the Consolidated Total Debt to EBITDAX Ratio (as defined in the Bank Credit Facility) is not greater than 1.75 to 1.00 and the aggregate amount of such restricted payments does not exceed the Available Free Cash Flow Amount (as defined in the Bank Credit Facility) at the time made or (B) the Consolidated Total Debt to EBITDAX Ratio is not greater than 1.00 to 1.00.

In addition, the indenture governing the 12.00% Notes restricts the Company’s consolidated subsidiaries from, directly or indirectly, among other things, declaring or paying any dividend on account of their equity securities, subject to certain limited exceptions described in the indenture. Such exceptions include, among other things, if (i) no default has occurred or would occur as a result thereof, (ii) immediately after giving effect to such transaction on a pro forma basis, the issuer could incur $1.00 of additional indebtedness in compliance with a fixed charge coverage ratio of 2.25 to 1.00, (iii) the ratio of the issuer’s total debt to EBITDA ratio is not greater than 3.00 to 1.00, and (iii) if payments pursuant to such transaction, together with the aggregate amount of certain other restricted payments, is less than the cumulative credit permitted under the indenture.

The indenture governing the 11.75% Notes contains a similar restriction on the Company and its consolidated subsidiaries’ ability to declare or pay dividends, subject to exceptions which include, among other things, (i) subject to no default or event of default having occurred or continuing, dividends in an aggregate amount not to exceed the greater of $25 million and 2.5% of Adjusted Consolidated Net Tangible Assets, (ii) dividends or distributions to any parent company to make payments, in lieu of issuing fractional shares in connection with share dividends, share splits, reverse share splits, mergers, consolidations, amalgamations or other business combinations and in connection with the exercise of warrants, options or other securities convertible into or exchangeable for equity interests of the Company.

At December 31, 2023, restricted net assets of the Company’s consolidated subsidiaries exceeded 25%.

Subsequent Event — Debt Offering

On February 7, 2024, the Company closed an upsized offering (the “Debt Offering”) for the sale of $1,250.0 million in aggregate principal amount of second-priority senior secured notes, consisting of $625.0 million aggregate principal amount of second-priority senior secured notes due 2029 and $625.0 million aggregate principal amount of second-priority senior secured notes due 2031 (collectively, the “New Senior Notes”), in a private offering to eligible purchasers that is exempt from registration under the Securities Act. The net proceeds from the Debt Offering (i) are expected to fund a portion of the cash consideration for the pending QuarterNorth Acquisition, (ii) funded the redemption of all of the outstanding 12.00% Notes and all of the outstanding 11.75% Notes discussed above (the “Redemptions”), and (iii) paid premiums, fees and expenses related to the Redemptions and the issuance of the New Senior Notes. The Company intends to use any remaining net proceeds for general corporate purposes, which may include the repayment of a portion of the outstanding borrowings under the Bank Credit Facility.

An aggregate of $340.0 million principal amount of the New Senior Notes will be subject to a “special mandatory redemption” in the event that the transactions contemplated by the QuarterNorth Merger Agreement are not consummated on or before May 31, 2024 (or up to September 30, 2024 solely in the event the parties require additional time to satisfy certain requirements under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, pursuant to the terms of the QuarterNorth Merger Agreement), or if we notify the trustee of the New Senior Notes that we will not pursue the consummation of the QuarterNorth Acquisition.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2023

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Note 9 — Asset Retirement Obligations

The asset retirement obligations included in the Consolidated Balance Sheets in current and non-current liabilities, and the changes in that liability were as follows (in thousands):

	Year Ended December 31,
	2023			2022
Balance, beginning of period	$	541,661		$	434,006
Obligations assumed(1)		258,858			—
Obligations incurred		14,199			1,140
Obligations settled		(86,615	)		(69,596	)
Obligations divested		(19,448	)		(1,572	)
Accretion expense		86,152			55,995
Changes in estimate(2)		102,419			121,688
Balance, end of period	$	897,226		$	541,661
Less: Current portion		77,581			39,888
Long-term portion	$	819,645		$	501,773

(1)Assumed in connection with the EnVen Acquisition. See further discussion in Note 3 — Acquisitions and Divestitures.

(2)Changes in estimate were primarily due to an increase in estimated service costs. Additionally, increases for the year ended December 31, 2023 due to the acceleration of estimated settlement date.

At December 31, 2023, the Company has (1) restricted cash of $102.4 million inclusive of interest earned to date, held in escrow and (2) the P&A Notes Receivable with an aggregate face value of $66.2 million to settle future asset retirement obligations. These assets are discussed in Note 2 — Summary of Significant Accounting Policies.

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Employee Benefits Plans and Share-Based Compensation

12 Months Ended

Dec. 31, 2023

Share-Based Payment Arrangement [Abstract]

Employee Benefits Plans and Share-Based Compensation

Note 10 — Employee Benefits Plans and Share-Based Compensation

EnVen Acquisition Severance

The following table summarizes severance accrual activity in connection with the EnVen Acquisition included in “Other current liabilities” and “Other long-term liabilities” on the Consolidated Balance Sheets as of December 31, 2023 (in thousands):

Severance accrual at December 31, 2022	$	—
Accrual additions		25,348
Benefit payments		(19,054	)
Severance accrual at December 31, 2023		6,294
Less: Current portion at December 31, 2023		6,190
Long-term portion at December 31, 2023	$	104

The above table includes involuntary termination benefits that are being provided pursuant to a one-time benefit arrangement that is being spread over the future service period through the termination date. Involuntary termination benefits are also being provided pursuant to contractual termination benefits required by the terms of existing employee agreements. Pursuant to the EnVen Merger Agreement, a rabbi trust was established and funded with $14.5 million at closing to pay a portion of future severance benefits associated with the contractual termination benefits. As of December 31, 2023, the rabbi trust held $3.7 million in assets of which $3.3 million and $0.4 million are included in “Other current assets” and “Other assets,” respectively, on the Consolidated Balance Sheets and both of which are included in the severance accrual at December 31, 2023 listed above. The assets of the rabbi trust are available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Severance costs are reflected in “General and administrative expense” on the Consolidated Statement of Operations.

Long Term Incentive Plans

On May 11, 2021, the Company’s stockholders approved the Talos Energy Inc. 2021 Long Term Incentive Plan (the “2021 LTIP”), which had previously been approved by the board of directors of the Company. No further awards will be granted under the Talos Energy Inc. Long Term Incentive Plan (the “2018 LTIP”) (together with the 2021 LTIP, the “LTIP Plans”).

The 2021 LTIP provides for potential grants of: (i) incentive stock options qualified as such under U.S. federal income tax laws (“ISOs”), (ii) stock options that do not qualify as ISOs (together with ISOs, “Options”), (iii) stock appreciation rights, (iv) restricted stock awards, (v) RSUs, (vi) awards of vested stock, (vii) dividend equivalents, (viii) other share-based or cash awards and (ix) substitute awards. Employees, non-employee directors and consultants of the Company and its affiliates are eligible to receive awards under the 2021 LTIP. The 2021 LTIP authorizes the Company to grant awards of up to 8,639,415 shares of the Company’s common stock, subject to the share counting and share recycling provisions of the 2021 LTIP.

Restricted Stock Units – Employees — RSUs granted to employees under the LTIP Plans primarily vest ratably over an approximate three year period subject to such employee’s continued service through each vesting date. Upon vesting, each RSU represents a contingent right to receive one share of common stock. The total unrecognized share-based compensation expense related to these RSUs at December 31, 2023 was approximately $19.0 million, which is expected to be recognized over a weighted average period of 1.7 years.

Restricted Stock Units – Non-employee Directors — RSUs granted to non-employee directors under the LTIP Plans vested approximately one year following the date of grant, subject to such non-employee director’s continued service through the vesting date. Upon vesting, these RSUs represent a contingent right to receive one share of common stock for each RSU for 60%, and cash for the remaining 40%. The total unrecognized share-based compensation expense related to these RSUs at December 31, 2023 was approximately $0.1 million, which is expected to be recognized over a weighted average period of 0.2 years. Of the unrecognized share-based compensation expense, $0.1 million relates to liability awards and will be subsequently remeasured at each reporting period.

The following table summarizes RSU activity:

	Restricted Stock Units			Weighted Average Grant Date Fair Value
Unvested RSUs at December 31, 2020		1,652,988		$	13.73
Granted		1,102,038		$	13.11
Vested		(669,832	)	$	15.01
Forfeited		(101,995	)	$	12.46
Unvested RSUs at December 31, 2021		1,983,199		$	13.02
Granted		2,297,465		$	13.23
Vested		(967,269	)	$	14.14
Forfeited		(97,891	)	$	14.34
Unvested RSUs at December 31, 2022(1)		3,215,504		$	12.79
Granted		1,154,541		$	16.24
Vested		(1,730,959	)	$	11.97
Forfeited		(332,725	)	$	14.52
Unvested RSUs at December 31, 2023(1)		2,306,361		$	14.89

(1)As of December 31, 2023 and 2022, 26,975 and 25,257, respectively, of the unvested RSUs were accounted for as liability awards in “Accrued liabilities” on the Consolidated Balance Sheet.

The Company considers its intent and ability to settle awards in cash or shares in determining whether to classify the awards as equity or as a liability. Certain awards granted during the year ended December 31, 2021 were originally classified as liability awards; however, these awards became equity-classified awards upon stockholder approval of the 2021 LTIP. The aggregate amount of compensation cost related to these awards is determined by the fair value of the award on the modification date.

Performance Share Units – Employees — PSUs granted to employees under the LTIP Plans represent the contingent right to receive one share of common stock. However, the number of shares of common stock issuable upon vesting ranges from zero to 200% of the target number of PSUs granted. The total unrecognized share-based compensation expense related to these PSUs at December 31, 2023 was approximately $8.7 million, which is expected to be recognized over a weighted average period of 1.7 years.

The following table summarizes PSU activity:

	Performance Share Units			Weighted Average Grant Date Fair Value
Unvested PSUs at December 31, 2020		834,172		$	25.46
Granted		586,995		$	18.96
Vested		(391,308	)	$	39.43
Forfeited		(14,400	)	$	18.48
Unvested PSUs at December 31, 2021		1,015,459		$	16.41
Granted(1)		629,666		$	23.73
Vested(2)		(14,474	)	$	13.05
Forfeited		(16,486	)	$	17.48
Cancelled		(975,564	)	$	16.42
Unvested PSUs at December 31, 2022		638,601		$	23.66
Granted(3)		595,394		$	18.76
Forfeited		(217,346	)	$	21.28
Unvested PSUs at December 31, 2023		1,016,649		$	21.30

(1)There were 314,833 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute total shareholder return (“TSR”) over a three-year performance period. An additional 314,833 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2022 drill program over a three-year performance period.

(2)The performance period for the relative TSR awards ended on December 31, 2022. The payout on these awards was 0% based on actual performance over the performance period as certified by the Compensation Committee of the Company’s Board of Directors in early 2023. Since these awards were legally forfeited they will again be available for new awards under the recycling provisions of the 2021 LTIP.

(3)There were 297,697 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute TSR over a three-year performance period. An additional 297,697 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2023 drill program over a three-year performance period.

Certain awards granted during the year ended December 31, 2021 were originally classified as liability awards; however, these awards became equity-classified awards upon stockholder approval of the 2021 LTIP. The following table summarizes the assumptions used in the Monte Carlo simulations to calculate the fair value of the relative or absolute TSR PSUs granted and modified at the date indicated:

	2023									2022						2021
	Grant			Grant			Grant			Grant			Grant			Modification			Grant
	December 1			July 1			March 5			September 20			March 5			May 11			March 8
Expected term (in years)		2.1			2.5			2.8			2.3			2.8			2.6			2.8
Expected volatility		61.9	%		66.2	%		73.1	%		74.3	%		82.2	%		80.9	%		78.3	%
Risk-free interest rate		4.4	%		4.6	%		4.5	%		3.9	%		1.6	%		0.3	%		0.3	%
Dividend yield		—	%		—	%		—	%		—	%		—	%		—	%		—	%
Fair value (in thousands)	$	12		$	173		$	6,165		$	621		$	8,668		$	9,715		$	11,129

Modification — During March 2022, the outstanding PSUs held by certain executive officers that were awarded in 2020 and 2021 were cancelled and, in connection with this cancellation, 1,147,352 of RSUs were granted (the “Retention RSUs”). The Retention RSUs will vest ratably each year over two years, generally contingent upon continued employment through each such date. The cancellation of the PSUs along with the concurrent grant of the Retention RSUs are accounted for as a modification. The incremental cost of $9.7 million will be recognized prospectively over the modified requisite service period. Additionally, the remaining unrecognized grant or modification date fair value of the original PSUs will be recognized over the original remaining requisite service period.

Share-based Compensation Costs

Share-based compensation costs associated with RSUs, PSUs and other awards are reflected as “General and administrative expense” on the Consolidated Statements of Operations, net amounts capitalized to “Proved Properties” on the Consolidated Balance Sheets. Because of the non-cash nature of share-based compensation, the expensed portion of share-based compensation is added back to net income in arriving at “Net cash provided by operating activities” on the Consolidated Statements of Cash Flows.

The following table presents the amount of costs expensed and capitalized (in thousands):

	Year Ended December 31,
	2023		2022		2021
Share-based compensation costs	$	25,236	$	28,280	$	20,560
Less: Amounts capitalized to oil and gas properties		12,283		12,327		9,568
Total share-based compensation expense	$	12,953	$	15,953	$	10,992

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Income Taxes

12 Months Ended

Dec. 31, 2023

Income Tax Disclosure [Abstract]

Income Taxes

Note 11 — Income Taxes

Income Tax Expense (Benefit)

The components of income tax expense (benefit) were as follows (in thousands):

	Year Ended December 31,
	2023			2022		2021
Current income tax expense (benefit):
United States	$	76		$	1,375	$	(5	)
Mexico		31			432		(993	)
Total current income tax expense (benefit)	$	107		$	1,807	$	(998	)
Deferred income tax expense (benefit):
United States	$	(60,704	)	$	659	$	(1,067	)
Mexico		—			71		430
Total deferred income tax expense (benefit)	$	(60,704	)	$	730	$	(637	)
Total income tax expense (benefit)	$	(60,597	)	$	2,537	$	(1,635	)

A reconciliation of income tax expense (benefit) computed at the U.S. federal statutory tax rate to the Company’s income tax expense (benefit) is as follows (in thousands, except percentages):

	Year Ended December 31,
	2023			2022			2021
Income tax expense (benefit) at the federal statutory tax rate	$	26,614		$	80,735		$	(38,763	)
State income taxes		1,748			1,591			(674	)
Impact of foreign operations		13,539			15,657			(11,920	)
Effect of change in state rate		—			—			2,008
Prior year taxes		1,184			(2,920	)		486
Change in valuation allowance		(106,815	)		(96,537	)		45,547
Other permanent differences		3,133			4,011			1,681
Total income tax expense (benefit)	$	(60,597	)	$	2,537		$	(1,635	)
Effective tax rate		(47.81	)%		0.66	%		0.89	%

The Company’s effective tax rate for the year ended December 31, 2023 differed from the federal statutory rate of 21.0% primarily due to a non-cash tax benefit of $106.8 million related to the release of the valuation allowance for its deferred tax assets offset with permanent differences and state income tax expense.

The Company’s effective tax rate for the years ended December 31, 2022 and 2021 differed from the federal statutory rate of 21.0% primarily due to recording a full valuation allowance against its federal, state and foreign deferred tax assets.

Deferred Tax Assets and Liabilities

Net deferred tax assets (liabilities) reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of deferred tax assets and liabilities were as follows (in thousands):

	Year Ended December 31,
	2023			2022
Deferred tax assets:
Federal net operating loss	$	147,252		$	159,257
Foreign tax loss carryforward		509			44,462
State net operating loss		24,840			24,787
Tax credits		107			107
Interest expense carryforward		46,414			23,262
Asset retirement obligations		190,248			115,848
Derivatives		—			9,273
Other well equipment		1,317			1,891
Accrued bonus		5,050			5,863
Share-based compensation		5,172			5,296
Operating lease liabilities		4,427			3,669
Finance lease liabilities		31,607			32,559
Other		3,383			7,142
Total deferred tax assets		460,326			433,416
Valuation allowance		(23,697	)		(129,105	)
Total deferred tax assets, net	$	436,629		$	304,311
Deferred tax liabilities:
Oil and gas properties	$	512,918		$	302,602
Operating lease assets		2,421			1,323
Derivatives		9,670			—
Prepaid		3,847			2,530
Total deferred tax liabilities		528,856			306,455
Net deferred tax liability	$	(92,227	)	$	(2,144	)

Net Operating Loss

The table below presents the details of the Company’s net operating loss carryovers as of December 31, 2023 (in thousands):

	Amount		Expiration Year
Federal net operating losses	$	452,393	2035 - 2037
Federal net operating losses	$	248,807	Unlimited
Foreign tax loss carryforward	$	1,696	2025 - 2032
State net operating losses	$	125,958	2025 - 2037
State net operating losses	$	277,930	Unlimited

As of December 31, 2023, the Company had U.S. federal net operating loss carryforwards (“NOLs”) of approximately $701.2 million, all of which are subject to limitation under Section 382 of the IRC. IRC Section 382 provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, against future U.S. taxable income in the event of a change in ownership. If not utilized, such carryforwards would begin to expire at the end of 2035.

Valuation Allowance

The Company recorded a valuation allowance of $23.7 million and $129.1 million as of December 31, 2023 and 2022, respectively. Deferred income tax assets and liabilities are recorded related to NOLs and temporary differences between the book and tax basis of assets and liabilities expected to produce tax deductions and income in the future. The realization of these assets depends on recognition of sufficient future taxable income in specific tax jurisdictions in which those temporary differences or NOLs relate.

In assessing the need for a valuation allowance, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized using available positive and negative evidence, including future reversals of temporary differences, tax-planning strategies and future taxable income, to estimate whether sufficient future taxable income will be generated to permit use of deferred tax assets. A significant piece of objective negative evidence evaluated is the cumulative loss incurred over recent years. Such objective negative evidence limits the Company’s ability to consider other subjective positive evidence.

At December 31, 2022, the Company maintained a valuation allowance related to federal, state and foreign deferred tax assets, as there was insufficient positive evidence to overcome the substantial negative evidence of being in a cumulative loss position. At December 31, 2023, the Company is no longer in a cumulative loss position and reached the conclusion that it is appropriate to release the valuation allowance against its federal deferred tax assets due to the sustained positive operating performance and the availability of expected future taxable income. The Company’s remaining valuation allowance primarily relates to various state operating loss carryforwards.

Uncertain Tax Positions

The table below sets forth the beginning and ending balance of the total amount of unrecognized tax benefits. None of the unrecognized benefits would impact the effective tax rate if recognized. While amounts could change during the next 12 months, the Company does not anticipate having a material impact on its financial statements.

Balances in the uncertain tax positions are as follows (in thousands):

	Year Ended December 31,
	2023		2022		2021
Total unrecognized tax benefits, beginning balance	$	835	$	696	$	648
Increases in unrecognized tax benefits as a result of:
Tax positions taken during a prior period		154		100		21
Tax positions taken during the current period		—		39		27
Total unrecognized tax benefits, ending balance	$	989	$	835	$	696

The Company recognizes interest and penalties related to uncertain tax positions as “Interest Expense” and “General and administrative expense” on the Consolidated Statements of Operations, respectively.

Years Open to Examination

The 2020 through 2023 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 income tax returns of the Company for years ending on or before December 31, 2019 are closed, except to the extent of any NOL carryover balance.

EnVen Acquisition

On February 13, 2023, the Company completed the EnVen Acquisition, which is further discussed in Note 3 —Acquisitions and Divestitures. The Company recognized a net deferred tax liability of $150.3 million in its purchase price allocation as of the acquisition date to reflect differences between tax basis and the fair value of EnVen’s assets acquired and liabilities assumed. The deferred tax balance is based on preliminary calculations and on information available to management at the time such estimates were made.

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Income (Loss) Per Share

12 Months Ended

Dec. 31, 2023

Earnings Per Share [Abstract]

Income (Loss) Per Share

Note 12 — Income (Loss) Per Share

Basic earnings per common share is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted earnings per common share includes the impact of RSUs, PSUs and outstanding warrants. The warrants expired unexercised on February 28, 2021.

The following table presents the computation of the Company’s basic and diluted income (loss) per share were as follows (in thousands, except for the per share amounts):

	Year Ended December 31,
	2023		2022		2021
Net income (loss)	$	187,332	$	381,915	$	(182,952	)
Weighted average common shares outstanding — basic		119,894		82,454		81,769
Dilutive effect of securities		858		1,229		—
Weighted average common shares outstanding — diluted		120,752		83,683		81,769
Net income (loss) per common share:
Basic	$	1.56	$	4.63	$	(2.24	)
Diluted	$	1.55	$	4.56	$	(2.24	)
Anti-dilutive potentially issuable securities excluded from diluted common shares		1,353		865		1,709

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Related Party Transactions

12 Months Ended

Dec. 31, 2023

Related Party Transactions [Abstract]

Related Party Transactions

Note 13 — Related Party Transactions

Apollo Funds and Riverstone Funds

On February 3, 2012, Talos Energy LLC completed a transaction with funds and other alternative investment vehicles managed by Apollo Management VII, L.P. and Apollo Commodities Management, L.P., with respect to Series I (“Apollo Funds”), and entities controlled by or affiliated with Riverstone Energy Partners V, L.P. (“Riverstone Funds”) and members of management pursuant to which the Talos Energy LLC received a private equity capital commitment. On January 3, 2022, the Apollo Funds ceased being a beneficial owner of more than five percent of the Company’s common stock. On July 5, 2023, the Riverstone Funds ceased being a beneficial owner of more than five percent of the Company’s common stock.

Whistler Acquisition Settlement

On August 31, 2018, the Company acquired Whistler Energy II, LLC from Whistler Energy II Holdco, LLC, an affiliate of the Apollo Funds. A settlement agreement related to a dispute regarding the decommissioning obligation of a Deepwater well was executed in September 2021. For the year ended December 31, 2021, the Company recognized a $4.4 million gain resulting from the settlement which is reflected in “Other income (expense)” on the Company’s Consolidated Statements of Operations.

Registration Rights Agreements

2018 Registration Rights Agreement — On May 10, 2018, the Company entered into a registration rights agreement (the “2018 Registration Rights Agreement”) with certain of the Apollo Funds and the Riverstone Funds, certain funds controlled by Franklin Advisers, Inc. (“Franklin”) and certain clients of MacKay Shields LLC (“MacKay Shields”), relating to the registered resale of the Company’s common stock owned by such parties on such date. Subsequently, the 2018 Registration Rights Agreement was amended to add additional affiliates of the Riverstone Funds as parties to the agreement and provide such parties with customary registration rights with respect to the Company’s Series A Convertible Preferred Stock issued to these parties at the closing of an acquisition on February 28, 2020.

The 2018 Registration Rights Agreement provided that registration rights would terminate with respect to Franklin and MacKay Shields in the event that either Franklin or MacKay Shields ceased to beneficially own 5% or more of the then outstanding shares of the Company’s common stock. Additionally, the 2018 Registration Rights Agreement provided that registration rights would otherwise terminate at such time as there were no registrable securities outstanding. The 2018 Registration Rights Agreement terminated on July 5, 2023 as there were no registrable securities outstanding.

The Company agreed to bear all of the expenses incurred in connection with any offer and sale, while the selling stockholders will be responsible for paying underwriting fees, discounts and selling commissions. The Company incurred fees of nil, nil, and $0.7 million for the fiscal years ended December 31, 2023, 2022 and 2021, respectively.

2022 Registration Rights Agreement — In connection with the Company’s entry into the EnVen Merger Agreement on September 21, 2022 to acquire EnVen, the Company entered into a registration rights agreement (the “2022 Registration Rights Agreement”) with Adage Capital Partners, L.P. (“Adage”) and affiliated entities of Bain Capital, LP (“Bain”). Pursuant to the 2022 Registration Rights Agreement, the Company grants to Adage and Bain certain demand, “piggy-back” and shelf registration rights with respect to the shares of the Company’s common stock to be received by such entities in the EnVen Acquisition, subject to certain customary thresholds and conditions. Adage and Bain held approximately 2.3% and 12.2%, respectively, of the Company’s outstanding shares of common stock as of December 31, 2023 based on SEC beneficial ownership reports filed by each of Adage and Bain.

Additionally, the Company agreed to pay certain expenses of the parties incurred in connection with the exercise of their rights under such agreement and to indemnify them for certain securities law matters in connection with any registration statement filed pursuant thereto. The Company did not incur any fees for the fiscal year ended December 31, 2023.

Amended and Restated Stockholders’ Agreement and Related Agreements

On May 10, 2018, the Company entered into a Stockholders’ Agreement (the “Stockholders’ Agreement”) by and among the Company and the other parties thereto. On February 24, 2020, the Company and the other parties thereto amended the Stockholders’ Agreement to, among other things, add additional affiliates of the Riverstone Funds (or one or more of its designated affiliates) as parties to the Stockholders’ Agreement and provided ownership of the Series A Convertible Preferred Stock would, prior to the conversion thereof on March 20, 2020, count towards certain stock ownership requirements on an as converted basis to retain the Riverstone Funds rights to nominate directors to the board of directors.

On March 29, 2022, the Company and other parties thereto, entered into the Amended and Restated Stockholders’ Agreement, in connection with the termination of the Apollo Funds’ rights thereunder and the resignation of certain members of the Company's Board of Directors (the “Amended and Restated Stockholders’ Agreement”). The Amended and Restated Stockholders’ Agreement, among other things, (i) terminated the rights of the Apollo Funds under the Stockholders’ Agreement and (ii) eliminated the requirement that the board of directors consist of ten members.

In connection with the closing of the EnVen Acquisition, the Company and the Riverstone Funds terminated the Amended and Restated Stockholders’ Agreement and Mr. Robert M. Tichio resigned from the Company’s Board of Directors pursuant to a shareholder support agreement dated as of September 21, 2022 requiring the Riverstone Funds to, among other things, approve the EnVen Merger Agreement and the proposed business combination. In connection with the termination of the Amended and Restated Stockholders’ Agreement, the Company and the Riverstone Funds entered into a letter agreement, dated February 13, 2023, pursuant to which the parties thereto agreed to execute and deliver such additional documents and take all such further action as may be reasonably necessary to cause the Amended and Restated Stockholders’ Agreement to be terminated without any further force and effect.

Legal Fees

The Company has engaged the law firm Vinson & Elkins L.L.P. (“V&E”) to provide legal services. An immediate family member of William S. Moss III, the Company’s Executive Vice President and General Counsel and one of its executive officers, is a partner at V&E. For the years ended December 31, 2023, 2022 and 2021, the Company incurred fees of approximately $3.3 million, $4.8 million, and $3.1 million, respectively, of which $0.8 million, $1.3 million, and $0.2 million were payable at each respective balance sheet date for legal services performed by V&E.

Slim Family

Carlos Slim Helú, Carlos Slim Domit, Marco Antonio Slim Domit, Patrick Slim Domit, María Soumaya Slim Domit, Vanessa Paola Slim Domit and Johanna Monique Slim Domit (collectively, the “Slim Family”) are beneficiaries of a Mexican trust which in turn owns all of the outstanding voting securities of Control Empresarial de Capitales S.A. de C.V. (“Control Empresarial” together with the Slim Family, the “Slim Family Office”). Control Empresarial, a sociedad anónima de capital variable organized under the laws of the United Mexican States, is a holding company with portfolio investments in various companies. Control Empresarial and the Slim Family became related parties on November 7, 2023 when they accumulated greater than ten percent of the Company’s outstanding shares of common stock. Control Empresarial held approximately 12.2% of the Company’s outstanding shares of common stock as of December 31, 2023 based on SEC beneficial ownership reports filed by Control Empresarial. The Slim Family own a majority stake in Grupo Carso, which indirectly has an ownership interest in Talos Mexico. See Note 3 – Acquisitions and Divestitures for additional information. The Company had no related party receivable from affiliates of the Slim Family as of December 31, 2023.

Subsequent Event — In connection with the January Equity Offering (defined below), Control Empresarial increased their holding to approximately 21.9% of the Company’s outstanding shares of common stock as of the closing of the January Equity Offering based on SEC beneficial ownership reports filed by Control Empresarial. See Note 17 – Subsequent Events for additional information.

In connection with the Debt Offering in February 2024, the Company consummated a firm commitment debt offering consisting of $1,250.0 million in aggregate principal amount of second-priority senior secured notes in a private offering to eligible purchasers that was exempt from registration under the Securities Act. In connection with the Debt Offering, and after expressing a non-binding indication of interest after commencement of the offering, entities and/or persons related to the Slim Family Office purchased an aggregate principal amount of $312.5 million of such notes from the initial purchasers of such offering. In connection with such transaction, the Company expects to pay Inbursa, a banking institution controlled by the Slim Family Office an advisory fee of approximately $2.7 million. See Note 8 – Debt for additional information regarding the Debt Offering.

Equity Method Investments

The Company had a $5.5 million related party receivable from various equity method investments as of December 31, 2023. This is reflected as “Other, net” within “Accounts Receivable” on the Consolidated Balance Sheets. See Note 7 – Equity Method Investments for additional information on the Company’s equity method investments.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2023

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Note 14 — Commitments and Contingencies

Legal Proceedings and Other Contingencies

From time to time, the Company is involved in litigation, regulatory examinations and administrative proceedings primarily arising in the ordinary course of business in jurisdictions in which the Company does business. Although the outcome of these matters cannot be predicted with certainty, the Company’s management believes none of these matters, either individually or in the aggregate, would have a material effect upon the Company’s financial position; however, an unfavorable outcome could have a material adverse effect on the Company’s results from operations for a specific interim period or year.

On March 23, 2022, the Company entered into a settlement agreement to receive $27.5 million to resolve previously pending litigation, which was filed on October 23, 2017, against a third-party supplier related to quality issues. As part of the settlement agreement, the Company released all of its claims in the litigation. The settlement is reflected as “Other income (expense)” on the Consolidated Statements of Operations.

In June 2019, David M. Dunwoody, Jr., former President of EnVen, filed a lawsuit against EnVen in Texas District Court alleging that the circumstances of his resignation entitled him to the severance payments and benefits under his employment agreement dated as of November 6, 2015 as a resignation for “Good Reason.” In September 2021, the trial court entered a judgment in favor or Mr. Dunwoody, inclusive of Mr. Dunwoody’s legal fees and interest. EnVen filed a Notice of Appeal in December 2021. The litigation was assumed as part of the EnVen Acquisition. In April 2023, the appellate court affirmed the trial court’s judgment. The Company filed a petition for review with the Texas Supreme Court on August 2, 2023, which was denied on January 26, 2024. As Of December 31, 2023, the Company has recorded $14.3 million as “Other current liabilities” on the Consolidated Balance Sheets related to the litigation.

Performance Obligations

Regulations with respect to the Company's operations govern, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells, removal of facilities in the U.S. Gulf of Mexico and certain obligations under the production sharing contracts with Mexico.

As of December 31, 2023, the Company had secured performance bonds from third party sureties totaling $1.4 billion. The cost of securing these bonds is reflected as “Interest expense” on the Consolidated Statements of Operations. Additionally, as of December 31, 2023, the Company had secured letters of credit issued under its Bank Credit Facility totaling $10.8 million. Letters of credit that are outstanding reduce the available revolving credit commitments. See Note 8 — Debt for further information on the Bank Credit Facility.

The table below summarizes the Company’s total minimum commitments associated with vessel commitments, purchase obligations and other miscellaneous commitments as of December 31, 2023 (in thousands):

	2024		2025		2026		2027		Thereafter		Total
Vessel Commitments(1)	$	13,216	$	—	$	—	$	—	$	—	$	13,216
Committed purchase orders(2)		3,083		—		—		—		—		3,083
Other commitments(3)		3,991		327		—		—		—		4,318
Total	$	20,290	$	327	$	—	$	—	$	—	$	20,617

(1)Includes vessel commitments the Company will utilize for certain Deepwater well intervention, drilling operations and decommissioning activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs.

(2)Includes committed purchase orders to execute planned future drilling activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs.

(3)Includes commitments associated with the Company’s CCS Segment relating to an equity funding obligation and payments required under a sequestration agreement.

Decommissioning Obligations

The Company, as a co-lessee or predecessor-in-interest in oil and natural gas leases located in the U.S. Gulf of Mexico, is in the chain of title with unrelated third parties either directly or by virtue of divestiture of certain oil and natural gas assets previously owned and assigned by our subsidiaries. Certain counterparties in these divestiture transactions or third parties in existing leases have filed for bankruptcy protection or undergone associated reorganizations and may not be able to perform required abandonment obligations. Regulations or federal laws could require the Company to assume such obligations. The Company reflects such costs as “Other operating (income) expense” on the Consolidated Statements of Operations.

The decommissioning obligations included are in the Consolidated Balance Sheets as “Other current liabilities” and “Other long-term liabilities”, and the changes in that liability were as follows (in thousands):

	Year Ended December 31,
	2023			2022			2021
Balance, beginning of period	$	54,269		$	24,336		$	—
Additions		266			8,900			21,056
Changes in estimate		11,613			22,658			—
Reimbursements due from third parties		—			—			3,280
Settlements		(50,584	)		(1,625	)		—
Balance, end of period	$	15,564		$	54,269		$	24,336
Less: Current portion		3,280			42,069			3,756
Long-term portion	$	12,284		$	12,200		$	20,580

Although it is reasonably possible that the Company could receive state or federal decommissioning orders in the future or be notified of defaulting third parties in existing leases, the Company cannot predict with certainty, if, how or when such orders or notices will be resolved or estimate a possible loss or range of loss that may result from such orders. However, the Company could incur judgments, enter into settlements or revise its opinion regarding the outcome of certain notices or matters, and such developments could have a material adverse effect on its results of operations in the period in which the amounts are accrued and its cash flows in the period in which the amounts are paid.

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Segment Information

12 Months Ended

Dec. 31, 2023

Segment Reporting [Abstract]

Segment Information

Note 15 — Segment Information

The Company’s operations are managed through two operating segments: (i) Upstream Segment and (ii) CCS Segment. The Upstream Segment is the Company’s only reportable segment. The Company’s chief operating decision-maker (“CODM”) is the President and Chief Executive Officer, who reviews operating results to make decisions about allocating resources and assessing performance for the entire company. A reportable segment is an operating segment that meets materiality thresholds. The 10% test, as prescribed by the segment reporting accounting guidance, are based on the reported measures of revenue, profit, and assets that are used by the CODM to assess performance and allocate resources. The CCS Segment currently does not meet any of the reportable segment quantitative thresholds. The profit or loss metric used to evaluate segment performance is Adjusted EBITDA, which is defined by the Company as net income (loss) plus interest expense; income tax expense (benefit); depreciation, depletion, and amortization; accretion expense; non-cash write-down of oil and natural gas properties; transaction and other (income) expenses; decommissioning obligations; the net change in the fair value of derivatives (mark to market effect, net of cash settlements and premiums related to these derivatives); (gain) loss on debt extinguishment; non-cash write-down of other well equipment; and non-cash equity-based compensation expense.

Corporate general and administrative expense include certain shared costs such as finance, accounting, tax, human resources, information technology and legal costs that are not directly attributable to each of operating segment. A portion of these expenses are allocated based on the percentage of employees dedicated to each operating segment. The remaining expenses are included in the reconciliation of reportable segment Adjusted EBITDA to consolidated pre-tax net income (loss) as an unallocated corporate general and administrative expense. The accounting policies of the segments are the same as those described in the summary of significant accounting policies.

The Company’s CODM does not review assets by segment as part of the financial information provided and therefore, no asset information is provided in the table below.

The following table presents selected segment information for the periods indicated (in thousands):

	Upstream		All Other(1)			Total
Revenues from External Customers:
Year Ended December 31, 2023	$	1,457,886	$	—		$	1,457,886
Year Ended December 31, 2022		1,651,980		—			1,651,980
Year Ended December 31, 2021		1,244,540		—			1,244,540
Equity in the Net Income (Loss) of Investees Accounted for by the Equity Method:
Year Ended December 31, 2023	$	120	$	(12,228	)	$	(12,108	)
Year Ended December 31, 2022		101		(1,166	)		(1,065	)
Year Ended December 31, 2021		—		—			—
Adjusted EBITDA:
Year Ended December 31, 2023	$	979,729	$	(22,883	)	$	956,846
Year Ended December 31, 2022	$	859,840	$	(12,786	)		847,054
Year Ended December 31, 2021		615,798		(4,782	)		611,016
Segment Expenditures:
Year Ended December 31, 2023	$	733,669	$	40,961		$	774,630
Year Ended December 31, 2022		452,674		2,778			455,452
Year Ended December 31, 2021		338,822		—			338,822

(1)The CCS Segment is included in the “All Other” category. The CCS Segment is an emerging business in the start-up phase of operations and the business that does not currently generate any revenues. The CCS Segment’s business activities are conducted through both wholly owned subsidiaries and equity method investments with industry partners. Equity method investments is a business strategy that enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed.

Reconciliations

The following table presents the reconciliations of Adjusted EBITDA to the Company’s consolidated totals (in thousands):

	Year Ended December 31,
	2023			2022			2021
Adjusted EBITDA:
Total for reportable segments	$	979,729		$	859,840		$	615,798
All other		(22,883	)		(12,786	)		(4,782	)
Unallocated corporate general and administrative expense		(6,128	)		(5,280	)		(4,542	)
Interest expense		(173,145	)		(125,498	)		(133,138	)
Depreciation, depletion and amortization		(663,534	)		(414,630	)		(395,994	)
Accretion expense		(86,152	)		(55,995	)		(58,129	)
Write-down of oil and natural gas properties		—			—			(18,123	)
Transaction and other (income) expenses(1)		33,295			34,513			(5,886	)
Decommissioning obligations(2)		(11,879	)		(31,558	)		(21,055	)
Derivative fair value gain (loss) (3)		80,928			(272,191	)		(419,077	)
Net cash (received) paid on settled derivative instruments (3)		9,457			425,559			290,164
Gain (loss) on extinguishment of debt		—			(1,569	)		(13,225	)
Non-cash write-down of other well equipment		—			—			(5,606	)
Non-cash equity-based compensation expense		(12,953	)		(15,953	)		(10,992	)
Income (loss) before income taxes	$	126,735		$	384,452		$	(184,587	)

(1)Transaction expenses includes $40.4 million and $9.0 million in costs related to the EnVen Acquisition, inclusive of $25.3 million and nil in severance expense for the years ended December 31, 2023 and 2022, respectively. See further discussion in Note 3 — Acquisition and Divestitures and Note 10 — Employee Benefits Plans and Share-Based Compensation. Other income (expense) includes other miscellaneous income and expenses that the Company does not view as a meaningful indicator of its operating performance. For the year ended December 31, 2023, the amount includes a $66.2 million gain on the Mexico Divestiture. See further discussion in Note 3 — Acquisitions and Divestitures. The amount includes a gain on the funding of the capital carry of the Company’s investment in Bayou Bend by Chevron of $8.6 million and $1.4 million for the year ended December 31, 2023 and 2022, respectively. Additionally, it includes a $13.9 million gain on the partial sale of its investment in Bayou Bend to Chevron for the year ended December 31, 2022. See further discussion in Note 7 — Equity Method Investments. For the year ended December 31, 2022, the amount includes $27.5 million gain as a result of the settlement agreement to resolve previously pending litigation that was filed in October 2017 that is further discussed in Note 14 — Commitments and Contingencies.

(2)Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Note 14 — Commitments and Contingencies for additional information on decommissioning obligations.

(3)The adjustments for the derivative fair value (gains) losses and net cash receipts (payments) on settled commodity derivative instruments have the effect of adjusting net loss for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because the Company does not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled.

The following table presents the reconciliation of Segment Expenditures to the Company’s consolidated totals (in thousands):

	Year Ended December 31,
	2023			2022			2021
Segment Expenditures:
Total reportable segments	$	733,669		$	452,674		$	338,822
All other		40,961			2,778			—
Change in capital expenditures included in accounts payable and accrued liabilities		(9,199	)		(60,011	)		28,258
Plugging & abandonment		(86,615	)		(69,596	)		(67,988	)
Decommissioning obligations settled		(50,584	)		(1,625	)		—
Investment in CCS intangibles and equity method investees		(40,946	)		(2,778	)		—
Other deferred payments		(1,545	)		—			(7,921	)
Insurance recovery proceeds		2,802			—			—
Non-cash well equipment transfers		(27,731	)		(6	)		1,086
Other		622			1,728			1,074
Exploration, development and other capital expenditures	$	561,434		$	323,164		$	293,331

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Supplemental Oil and Gas Disclosures (Unaudited)

12 Months Ended

Dec. 31, 2023

Extractive Industries [Abstract]

Supplemental Oil and Gas Disclosures (Unaudited)

Note 16 — Supplemental Oil and Gas Disclosures (Unaudited)

Capitalized Costs

Aggregate amounts of capitalized costs relating to oil, natural gas and NGL activities and the aggregate amount of related accumulated depletion and amortization as of the dates indicated are presented below (in thousands):

	Year Ended December 31,
	2023		2022		2021
Consolidated Entities:
Proved properties	$	7,906,295	$	5,964,340	$	5,232,480
Unproved oil and gas properties, not subject to amortization(1)		268,315		154,783		219,055
Total oil and gas properties		8,174,610		6,119,123		5,451,535
Less: Accumulated depletion		4,143,491		3,484,590		3,072,907
Net capitalized costs	$	4,031,119	$	2,634,533	$	2,378,628
Depletion and amortization rate (Per Boe)	$	27.23	$	18.95	$	16.71
Company's Share of Equity Investees:
Unproved oil and gas properties, not subject to amortization	$	56,579	$	—	$	—

(1)Amount includes $111.4 million and $110.3 million of unproved properties, not subject to amortization, related to the Company’s operations in offshore Mexico for the years ended December 31, 2022 and 2021, respectively.

Included in the depletable basis of proved oil and gas properties is the estimate of the Company’s proportionate share of asset retirement costs relating to these properties which are also reflected as “Asset retirement obligations” on the accompanying Consolidated Balance Sheets. See Note 9 — Asset Retirement Obligations for additional information.

Costs Incurred for Property Acquisition, Exploration and Development Activities

The following table reflects the costs incurred in oil, natural gas and NGL property acquisition, exploration and development activities during the years indicated (in thousands). Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to estimates during the year.

	Year Ended December 31,
	2023		2022		2021
Consolidated Entities:
Property acquisition costs:
Proved properties	$	951,703	$	—	$	210
Unproved properties, not subject to amortization		249,688		2,221		—
Total property acquisition costs		1,201,391		2,221		210
Exploration costs(1)		161,296		125,889		23,844
Development costs		805,148		541,512		245,058
Total costs incurred	$	2,167,835	$	669,622	$	269,112
Company's Share of Equity Investees:
Exploration costs	$	290	$	—	$	—

(1)Amount includes nil, $1.2 million and $6.6 million of exploration costs related to the Company’s operations in offshore Mexico for the years ended December 31, 2023, 2022 and 2021, respectively.

Estimated Quantities of Proved Oil, Natural Gas and NGL Reserves

The Company employs full-time experienced reserve engineers and geologists who are responsible for determining proved reserves in compliance with SEC guidelines. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and timing of development expenditures. The reserve data in the following tables only represent estimates and should not be construed as being exact. Engineering reserve estimates were prepared based upon interpretation of production performance data and subsurface information obtained from the drilling of existing wells. The Company’s Director of Reserves, internal reservoir engineers and geologists analyzed and prepared reserve estimates on all oil and natural gas fields. All of the Company’s proved oil, natural gas and NGL reserves are located in the U.S. Gulf of Mexico.

At December 31, 2023, 2022 and 2021, 100% of proved oil, natural gas and NGL reserves attributable to all of the Company’s oil and natural gas properties were estimated and compiled for reporting purposes by the Company’s reservoir engineers and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers and geologists.

The following table presents the Company’s estimated proved reserves at its net ownership interest:

	Oil (MBbls)			Gas (MMcf)			NGL (MBbls)			Oil Equivalent (MBoe)
Consolidated Entities:
Total proved reserves at December 31, 2020		109,307			257,208			10,858			163,033
Revision of previous estimates		13,619			8,979			5,137			20,252
Production		(16,159	)		(32,795	)		(1,875	)		(23,500	)
Extensions and discoveries		997			2,961			315			1,806
Total proved reserves at December 31, 2021		107,764			236,353			14,435			161,591
Revision of previous estimates		(5,625	)		(8,302	)		(2,002	)		(9,010	)
Production		(14,561	)		(32,215	)		(1,793	)		(21,723	)
Sales of reserves		(158	)		(7,625	)		—			(1,429	)
Extensions and discoveries		3,639			31,340			2,288			11,150
Total proved reserves at December 31, 2022		91,059			219,551			12,928			140,579
Revision of previous estimates		(6,308	)		(62,946	)		(1,283	)		(18,082	)
Production		(18,062	)		(26,194	)		(1,767	)		(24,195	)
Purchases of reserves		41,871			36,690			1,116			49,102
Extensions and discoveries		2,255			12,770			979			5,362
Total proved reserves at December 31, 2023		110,815			179,871			11,973			152,766
Total Proved Developed Reserves as of:
December 31, 2021		93,420			186,442			11,792			136,286
December 31, 2022		80,285			161,727			9,315			116,555
December 31, 2023		98,225			141,823			9,957			131,819
Total Proved Undeveloped Reserves as of:
December 31, 2021		14,344			49,911			2,643			25,305
December 31, 2022		10,774			57,824			3,613			24,024
December 31, 2023		12,590			38,048			2,016			20,947

During 2023, proved reserves increased by 12.2 MMBoe primarily due to a purchases of reserves of 49.1 MMBoe in connection with the EnVen Acquisition and 5.4 MMBoe of estimated proved reserves from extensions and discoveries primarily from evaluations of the Brutus Field in the Green Canyon core area. This increase was partially offset by a decrease of 24.2 MMBoe of production and a decrease of 18.1 MMBoe from revisions of previous estimates. The revisions were primarily due to a 13.5 MMBoe decrease in reserve volumes due to the decrease in SEC Pricing of $17.47 per Bbl of oil and $4.05 per Mcf of natural gas and an additional decrease in the Phoenix Field in the Green Canyon core area due to well performance.

During 2022, proved reserves decreased by 21.0 MMBoe primarily due to a decrease of 21.7 MMBoe of production. Additionally, there was a decrease of 9.0 MMBoe primarily due to timing of development of certain PUD locations to move beyond five years at the Phoenix Field in the Green Canyon core area and sales of reserves of 1.4 MMBoe primarily related to the Brushy Creek Field in the Shelf and Gulf Coast area. The decrease was partially offset by 11.2 MMBoe of estimated proved reserves from extensions and discoveries primarily from evaluations of the Pompano Field and the Ram Powell Field located in the Mississippi Canyon core area.

During 2021, proved reserves decreased by 1.4 MMBoe primarily due to a decrease of 23.5 MMBoe of production. The decrease was partially offset by revision to previous estimates of 20.3 MMBoe due to increase in commodity prices as well as 1.8 MMBoe of estimated proved reserves from extensions and discoveries primarily from an evaluation of Crown and Anchor Field located in the Mississippi Canyon core area.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil, Natural Gas and NGL Reserves

The following table reflects the standardized measure of discounted future net cash flows relating to the Company’s interest in proved oil, natural gas and NGL reserves (in thousands):

	Year Ended December 31,
	2023			2022			2021
Consolidated Entities:
Future cash inflows	$	9,425,055		$	10,674,896		$	8,496,005
Future costs:
Production		(3,090,491	)		(1,906,752	)		(1,868,818	)
Development and abandonment		(2,358,368	)		(1,873,453	)		(1,422,507	)
Future net cash flows before income taxes		3,976,196			6,894,691			5,204,680
Future income tax expense		(589,413	)		(1,114,409	)		(676,778	)
Future net cash flows after income taxes		3,386,783			5,780,282			4,527,902
Discount at 10% annual rate		(343,295	)		(1,411,834	)		(1,087,291	)
Standardized measure of discounted future net cash flows	$	3,043,488		$	4,368,448		$	3,440,611

Future cash inflows are computed by applying SEC Pricing to year-end quantities of proved reserves. The discounted future cash flow estimates do not include the effects of derivative instruments. See the following table for SEC Pricing used in determining the standardized measure:

	Year Ended December 31,
	2023		2022		2021
Oil price per Bbl	$	78.56	$	96.03	$	67.14
Natural gas price per Mcf	$	2.75	$	6.80	$	3.71
NGL price per Bbl	$	18.77	$	33.89	$	26.62

Future net cash flows are discounted at the prescribed rate of 10%. Actual future net cash flows may vary considerably from these estimates. Although the Company’s estimates of total proved reserves, development and abandonment costs and production rates were based on the best information available, the development and production of oil and gas reserves may not occur in the periods assumed. All estimated costs to settle asset retirement obligations associated with the Company’s proved reserves have been included in their calculation of development and abandonment of the standardized measure of discounted future net cash flows for each period presented. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, such estimated future net cash flow computations should not be considered to represent the Company’s estimate of the expected revenues or the current value of existing proved reserves.

Changes in Standardized Measure of Discounted Future Net Cash Flows

Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved oil, natural gas and NGL reserves are as follows (in thousands):

	Year Ended December 31,
	2023			2022			2021
Consolidated Entities:
Standardized measure, beginning of year	$	4,368,448		$	3,440,611		$	1,904,934
Sales and transfers of oil, net gas and NGLs produced during the period		(1,065,814	)		(1,340,400	)		(957,576	)
Net change in prices and production costs		(2,835,125	)		2,388,442			2,049,980
Changes in estimated future development and abandonment costs		(19,877	)		(84,391	)		(57,876	)
Previously estimated development and abandonment costs incurred		202,503			20,107			69,125
Accretion of discount		518,110			392,600			199,849
Net change in income taxes		357,321			(327,265	)		(391,834	)
Purchases of reserves		2,033,852			—			—
Sales of reserves		—			(5,218	)		—
Extensions and discoveries		90,244			202,239			45,485
Net change due to revision in quantity estimates		(484,423	)		(255,743	)		426,357
Changes in production rates (timing) and other		(121,751	)		(62,534	)		152,167
Standardized measure, end of year	$	3,043,488		$	4,368,448		$	3,440,611

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Subsequent Events

12 Months Ended

Dec. 31, 2023

Subsequent Events [Abstract]

Subsequent Events

Note 17 — Subsequent Events

QuarterNorth Acquisition

For additional Information, see the following:

•Note 3 — Acquisitions and Divestitures

•Note 8 — Debt

•Note 13 — Related Party Transactions

Equity Offering

On January 22, 2024, the Company closed an upsized underwritten public offering (the “January Equity Offering”) of 34.5 million shares of the Company’s common stock, resulting in net proceeds to the Company of approximately $388.5 million, after deducting underwriting discounts and commissions and before estimated offering expenses. The Company intends to use the net proceeds from the January Equity Offering to fund a portion of the cash consideration for the QuarterNorth Acquisition. However, the QuarterNorth Acquisition remains subject to certain conditions to closing. Pending the use of the proceeds of the January Equity Offering as described above, the Company may temporarily use all or a portion of such proceeds to reduce the borrowings outstanding under the Company’s Bank Credit Facility. In the event that the QuarterNorth Acquisition is not completed, the proceeds from the January Equity Offering will be used for general corporate purposes.

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Schedule I - Condensed Financial Information of Registrant (Parent Only)

12 Months Ended

Dec. 31, 2023

Condensed Financial Information Disclosure [Abstract]

Schedule I - Condensed Financial Information of Registrant (Parent Only)

Schedule I. Condensed Financial Information of Registrant

TALOS ENERGY INC. (PARENT ONLY)

BALANCE SHEETS

(In thousands, except share amounts)

	Year Ended December 31,
	2023			2022
ASSETS
Current assets:
Accounts receivable:
Other, net	$	100		$	—
Prepaid assets		221			169
Other current assets		19			36
Total current assets		340			205
Other long-term assets:
Investments in subsidiaries		2,246,908			1,168,053
Total assets	$	2,247,248		$	1,168,258
LIABILITIES AND STOCKHOLDERSʼ EQUITY
Current liabilities:
Accounts payable	$	316		$	249
Accrued liabilities		705			728
Other current liabilities		124			62
Total current liabilities		1,145			1,039
Long-term liabilities:
Other long-term liabilities		90,952			1,643
Total liabilities		92,097			2,682
Commitments and contingencies
Stockholdersʼ equity:
Preferred stock; $0.01 par value; 30,000,000 shares authorized and zero shares issued or outstanding as of December 31, 2023 and 2022, respectively		—			—
Common stock; $0.01 par value; 270,000,000 shares authorized; 127,480,361 and 82,570,328 shares issued as of December 31, 2023 and 2022, respectively		1,275			826
Additional paid-in capital		2,549,097			1,699,799
Accumulated deficit		(347,717	)		(535,049	)
Treasury stock, at cost; 3,400,000 and zero shares as of December 31, 2023 and 2022, respectively		(47,504	)		—
Total stockholdersʼ equity		2,155,151			1,165,576
Total liabilities and stockholdersʼ equity	$	2,247,248		$	1,168,258

TALOS ENERGY INC. (PARENT ONLY)

STATEMENTS OF OPERATIONS

(In thousands)

	Year Ended December 31,
	2023			2022			2021
Revenues:
Oil	$	—		$	—		$	—
Natural gas		—			—			—
NGL		—			—			—
Total revenues		—			—			—
Operating expenses:
Lease operating expense		—			—			—
Production taxes		—			—			—
Depreciation, depletion and amortization		—			—			—
Accretion expense		—			—			—
General and administrative expense	$	2,708		$	2,145		$	1,322
Other operating (income) expense		—			—			—
Total operating expenses		2,708			2,145			1,322
Operating income (expense)		(2,708	)		(2,145	)		(1,322	)
Interest expense		—			—			(5	)
Price risk management activities income (expense)		—			—			—
Equity method investment income (expense)		—			—			—
Other income (expense)		(1	)		(1	)		(2	)
Equity earnings (loss) from subsidiaries		128,888			385,968			(180,548	)
Net income (loss) before income taxes		126,179			383,822			(181,877	)
Income tax benefit (expense)		61,153			(1,907	)		(1,075	)
Net income (loss)	$	187,332		$	381,915		$	(182,952	)

TALOS ENERGY INC. (PARENT ONLY)

STATEMENTS OF CASH FLOWS

(In thousands)

	Year Ended December 31,
	2023			2022			2021
Cash flows from operating activities:
Net cash provided by (used in) operating activities	$	(1,836	)	$	(809	)	$	(876	)
Cash flows from investing activities:
Distributions from subsidiaries		49,340			809			879
Contributions to subsidiaries		—			—			(3	)
Net cash provided by (used in) investing activities		49,340			809			876
Cash flows from financing activities:
Purchase of treasury stock		(47,504	)		—			—
Net cash provided (used in) by financing activities		(47,504	)		—			—
Net increase (decrease) in cash and cash equivalents		—			—			—
Cash and cash equivalents:
Balance, beginning of period		—			—			—
Balance, end of period	$	—		$	—		$	—

TALOS ENERGY INC. (PARENT ONLY)

NOTES TO CONDENSED FINANCIAL STATEMENTS

December 31, 2023

Note 1 — Basis of Presentation

Pursuant to the rules and regulations of the SEC, the parent only condensed financial information of Talos Energy, Inc. do not reflect all of the information and notes normally included with financial statements prepared in accordance with GAAP. Therefore, these condensed financial statements should be read in conjunction with the consolidated financial statements and related notes included under Part IV, Item 15. Exhibits and Financial Statement Schedules in this Annual Report.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2023

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization, Nature of Business, Basis of Presentation and Consolidation

Organization and Nature of Business

Talos Energy Inc. (the “Parent Company”) is a Delaware corporation originally incorporated on November 14, 2017. The Parent Company conducts all business operations through its operating subsidiaries, owns no operating assets and has no material operations, cash flows or liabilities independent of its subsidiaries. The Parent Company’s common stock is traded on The New York Stock Exchange under the ticker symbol “TALO.”

The Parent Company (including its subsidiaries, collectively “Talos” or the “Company”) is a technically driven independent exploration and production company focused on safely and efficiently maximizing long-term value through its operations, currently in the United States (“U.S.”) and offshore Mexico both through upstream oil and gas exploration and production and the development of low carbon solutions opportunities. The Company leverages decades of technical and offshore operational expertise in the acquisition, exploration and development of assets in key geological trends that are present in many offshore basins around the world. The Company is also utilizing its expertise to develop CCS projects to help reduce industrial emissions along the coast of the U.S. Gulf of Mexico.

Basis of Presentation and Consolidation

The Consolidated Financial Statements have been prepared in accordance with GAAP and include the accounts of the Parent Company and entities in which the Parent Company holds a controlling financial interest. Both majority-owned subsidiaries and any variable interest entity in which the Parent Company is the primary beneficiary are consolidated. All intercompany transactions have been eliminated. All adjustments are of a normal, recurring nature and are necessary to fairly present the financial position, results of operations and cash flows for the periods reflected herein.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities 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. Actual results could differ from those estimates.

Segments

Segments

The Company has two operating segments: (i) exploration and production of oil, natural gas and NGLs (“Upstream Segment”) and (ii) CCS (“CCS Segment”). The Upstream Segment is the Company’s only reportable segment. The legal entities included in the CCS Segment have been designated as unrestricted, non-guarantor subsidiaries of the Company for purposes of the Bank Credit Facility (as defined in Note 2 — Summary of Significant Accounting Policies) and indenture governing the senior notes. See additional information in Note 15 — Segment Information.

Recently Issued Accounting Standards

Recently Issued Accounting Standards

Segment Reporting — In November 2023, the Financial Accounting Standards Board (“FASB”) issued an update to the required disclosures for segment reporting. The update is intended to improve reportable segment disclosures, primarily through enhanced disclosures about significant segment expenses. The update will require public entities to disclose significant segment expenses that are regularly provided to the chief operating decision maker and included within segment profit and loss. The update is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024 on a retrospective basis. Early adoption is permitted. The Company is currently evaluating the effect of this update on the Company’s disclosures.

Tax Disclosures — In December 2023, the FASB issued an update which expands disclosures in an entity’s income tax rate reconciliation table and regarding cash taxes paid both in the U.S. and foreign jurisdictions. The update is effective for annual periods beginning after December 15, 2024 on a prospective basis. However, retrospective application in all periods presented is permitted. The Company is currently evaluating the effect of this update on the Company’s disclosures.

Cash and Cash Equivalents

Cash and Cash Equivalents — The Company presents cash as “Cash and cash equivalents” on the Company’s Consolidated Balance Sheets. The Company considers all cash, money market funds and highly liquid investments with an original maturity of three months or less as cash and cash equivalents. Cash and cash equivalents are carried at cost, which approximates fair value.

Accounts Receivable and Allowance for Expected Credit Losses

Accounts Receivable and Allowance for Expected Credit Losses — Accounts receivable are stated at the historical carrying amount net of an allowance for expected credit losses. At each reporting period, the recoverability of material receivables is assessed using historical data, current market conditions and reasonable and supported forecasts of future economic conditions to determine their expected collectability. A loss-rate methodology is used to estimate the allowance for expected credit losses to be accrued on material receivables to reflect the net amount to be collected. As of December 31, 2023 and 2022, the Company had allowances of $8.8 million and $10.7 million, respectively, presented net in accounts receivable on the Consolidated Balance Sheets.

Price Risk Management Activities

Price Risk Management Activities — The Company uses commodity price derivatives to manage fluctuating oil and natural gas market risks. The Company periodically enters into commodity derivative contracts, which may require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a fixed quantity of oil or natural gas without the exchange of underlying volumes.

Commodity derivatives are recorded on the Consolidated Balance Sheets at fair value with settlements of such contracts and changes in the unrealized fair value recorded in earnings each period. Realized gains and losses on the settlement of commodity derivatives and changes in their unrealized gains and losses are reported in “Price risk management activities income (expense)” on the Consolidated Statements of Operations. The Company classifies cash flows related to derivative contracts based on the nature and purpose of the derivative. As the derivative cash flows are considered an integral part of the Company’s oil and natural gas operations, they are classified as cash flows from operating activities. The Company does not enter into derivative agreements for trading or other speculative purposes.

The commodity derivative’s fair value reflects the Company’s best estimate with priority based upon exchange or over-the-counter quotations. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, the Company then utilizes other valuation techniques or models to estimate market values. These modeling techniques require the Company to make estimations of future prices, price correlation, market volatility and liquidity. The Company’s actual results may differ from its estimates, and these differences can be favorable or unfavorable.

Prepaid Assets

Prepaid Assets — Prepaid assets primarily represent prepaid subscriptions, insurance, progress payments for well equipment and deposits with the Office of Natural Resources Revenue (“ONRR”). The progress payments made for well equipment relate to long lead time items which the Company has not taken title to as of period end. The deposits with ONRR represent the Company’s estimated federal royalties payable within thirty days of the production date. On a monthly basis, the Company adjusts the deposit based on actual royalty payments remitted to the ONRR.

Accounting for Oil and Natural Gas Activities

Accounting for Oil and Natural Gas Activities — The Company follows the full cost method of accounting for oil and natural gas exploration and development activities. Under the full cost method, substantially all costs incurred in connection with the acquisition, development and exploration of oil and natural gas reserves are capitalized. These capitalized amounts include the internal costs directly related to acquisition, development and exploration activities, asset retirement costs and capitalized interest. Under the full cost method, dry hole costs and geological and geophysical costs are capitalized into the full cost pool, which is subject to amortization and assessed for impairment on a quarterly basis through a ceiling test calculation as discussed below.

Capitalized costs associated with proved reserves are amortized on a country-by-country basis over the life of the total proved reserves using the unit of production method, computed quarterly. Conversely, capitalized costs associated with unproved properties and related geological and geophysical costs, exploration wells currently drilling and capitalized interest are initially excluded from the amortizable base. The Company transfers unproved property costs into the amortizable base when properties are determined to have proved reserves or when the Company has completed an unproved properties evaluation resulting in an impairment. The Company evaluates each of these unproved properties individually for impairment at least annually. Additionally, the amortizable base includes future development costs, dismantlement, restoration and abandonment costs, net of estimated salvage values, and geological and geophysical costs incurred that cannot be associated with specific unproved properties or prospects in which the Company owns a direct interest. The Company capitalizes overhead costs that are directly related to exploration, acquisition and development activities.

The Company’s capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10%, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. Generally, any costs in excess of the ceiling are recognized as a non-cash “Write-down of oil and natural gas properties” on the Consolidated Statements of Operations and an increase to “Accumulated depreciation, depletion and amortization” on the Company’s Consolidated Balance Sheets. The expense may not be reversed in future periods, even though higher oil, natural gas and NGL prices may subsequently increase the ceiling. The Company performs this ceiling test calculation each quarter. In accordance with the SEC rules and regulations, the Company utilizes SEC Pricing when performing the ceiling test. The Company also holds prices and costs constant over the life of the reserves, even though actual prices and costs of oil and natural gas are often volatile and may change from period to period.

Under the full cost method of accounting for oil and natural gas operations, assets whose costs are currently being depreciated, depleted or amortized are assets in use in the earnings activities of the enterprise and do not qualify for capitalization of interest cost. Investments in unproved properties for which exploration and development activities are in progress and other major development projects that are not being currently depreciated, depleted or amortized are assets qualifying for capitalization of interest costs.

When the Company sells or conveys interests in oil and natural gas properties, the Company reduces its oil and natural gas reserves for the amount attributable to the sold or conveyed interest. The Company treats sales proceeds on non-significant sales as reductions to the cost of the Company’s oil and natural gas properties. The Company does not recognize a gain or loss on sales of oil and natural gas properties, unless those sales would significantly alter the relationship between capitalized costs and proved reserves.

Other Property and Equipment

Other Property and Equipment — Other property and equipment is recorded at cost and consists primarily of leasehold improvements, office furniture and fixtures and computer hardware. Acquisitions and betterments are capitalized; maintenance and repairs are expensed as incurred. Depreciation is provided using the straight-line method over estimated useful lives of three to ten years

Restricted Cash

Restricted Cash — Any cash that is legally restricted from use is classified as restricted cash. If the purpose of restricted cash relates to acquiring a long-term asset, liquidating a long-term liability, or is otherwise unavailable for a period longer than one year from the balance sheet date, the restricted cash is included in other long-term assets. Otherwise, restricted cash is included in other current assets in the Consolidated Balance Sheets. The Company acquired funds held in escrow to be used for future plugging and abandonment (“P&A”) obligations assumed through the EnVen Acquisition (as defined in Note 3 — Acquisitions and Divestitures). These escrow accounts required deposits of approximately $100.0 million, which was fully funded by EnVen (as defined in Note 3 — Acquisitions and Divestitures) prior to the consummation of the acquisition. This is reflected as “Restricted Cash” within “Other long-term assets” on the Consolidated Balance Sheets.

Equity Method Investments

Equity Method Investments — The Company generally accounts for investments under the equity method of accounting when it exercises significant influence over the entity’s operating and financial policies but does not hold a controlling financial interest in the entity. The voting percentage that is presumed to provide an investor with the required level of influence necessary to apply the equity method of accounting varies depending on the nature of the investee. For investments in common stock, in-substance common stock, a limited liability company or partnership that does not maintain specific ownership accounts for each investor, a voting percentage of 20% or more is generally presumed to demonstrate significant influence. For investments in a limited partnership or unincorporated joint venture and a limited liability company or partnership that maintains a specific ownership account for each investor, a voting percentage of 3-5% or more is generally presumed to demonstrate significant influence. Equity method accounting for interests in limited partnerships is generally appropriate unless the interest is so minor that the investor has virtually no influence (less than 3%).

In applying the equity method of accounting, the investments are initially recognized at cost and subsequently adjusted for the Company’s proportionate share of earnings, losses, contributions and distributions. Investments accounted for using the equity method are reflected as “Equity method investments” on the Consolidated Balance Sheets. The equity in earnings of an investee is reflected in “Equity method investment income (expense)” on the Consolidated Statement of Operations. The gain or loss from the full or partial sale of an equity method investment is presented in the same line item in which the Company reports the equity in earnings of the investee.

The Company assesses equity method investments for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred if the loss is deemed to be other-than-temporary. When the loss is deemed to be other-than-temporary, the carrying value of the equity method investment is written down to fair value. The impairment charge is included as a component of the Company’s share of the earning or losses of the investee. No impairment charges have been recorded during the years ended December 31, 2023, 2022 and 2021.

Other Well Equipment

Other Well Equipment — Other well equipment primarily represents the cost of equipment to be used in the Company’s oil and natural gas drilling and development activities such as drilling pipe, tubulars and certain wellhead equipment. When well equipment is supplied to wells, the cost is capitalized in oil and gas properties, and if such property is jointly owned, the proportionate costs will be reimbursed by third party participants.

Notes Receivable, net

Notes Receivable, net — The Company holds two notes receivable with an aggregate face value of $66.2 million acquired by the Company as part of the EnVen Acquisition (as defined herein), which consist of commitments from the sellers of oil and natural gas properties related to the costs associated with P&A obligations (the “P&A Notes Receivable”). The P&A Notes Receivable are recorded at a discounted value, being accreted to their principal amounts and presented as such, net of related cumulative estimated credit losses, on the accompanying Consolidated Balance Sheets. The Company estimates the current expected credit losses related to its P&A Notes Receivable using the probability of default method based on the long-term credit ratings of the counterparties of the notes, which are currently considered “investment grade.”

Leases

Leases — At inception, contracts are reviewed to determine whether the agreement contains a lease. To the extent an arrangement is determined to include a lease, it is classified as either an operating or a finance lease, which dictates the pattern of expense recognition in the income statement. Operating leases are reflected as “Operating lease assets,” “Current portion of operating lease liabilities” and “Operating lease liabilities” on the Consolidated Balance Sheets. Finance leases are included in “Property and equipment,” “Other current liabilities” and “Other long-term liabilities” on the Consolidated Balance Sheets.

A right-of-use (“ROU”) asset representing our right to use an underlying asset for the lease term and a lease liability representing our obligation to make lease payments arising from the lease are recognized on the Consolidated Balance Sheets for all leases, regardless of classification. The ROU asset is initially measured as the present value of the lease liability adjusted for any payments made prior to lease commencement, including any initial direct costs incurred and incentives received. Lease liabilities are initially measured at the present value of future minimum lease payments, excluding variable lease payments, over the lease term. As most of our leases do not provide an implicit rate, the Company generally uses an incremental borrowing rate based on the estimated rate of interest for collateralized borrowing over a similar term of the lease payments at commencement date.

The Company has elected to account for lease and non-lease components in its contracts as a single lease component for all asset classes except for our leased floating production vessel class. Our lease terms may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that option. The Company has elected, as an accounting policy, not to record leases with terms of twelve months or less (i.e., short-term) on the Consolidated Balance Sheets. See Note 5 — Leases for additional information

Debt Issuance Costs

Debt Issuance Costs — The Company presents debt issuance costs associated with revolving line-of-credit arrangements as a reduction of the carrying value of long-term debt.

Asset Retirement Obligations

Asset Retirement Obligations — The Company has obligations associated with the retirement of its oil and natural gas wells and related infrastructure. The Company has obligations to plug wells when production on those wells is exhausted, when the Company no longer plans to use them or when the Company abandons them. The Company accrues a liability with respect to these obligations based on its estimate of the timing and amount to replace, remove or retire the associated assets.

In estimating the liability associated with its asset retirement obligations, the Company utilizes several assumptions, including a credit-adjusted risk-free interest rate, estimated costs of decommissioning services, estimated timing of when the work will be performed and a projected inflation rate. Changes in estimate represent changes to the expected amount and timing of payments to settle its asset retirement obligations. Typically, these changes result from obtaining new information about the timing of its obligations to plug and abandon oil and natural gas wells and the costs to do so. After initial recording, the liability is increased for the passage of time, with the increase being reflected as “Accretion expense” on the Company’s Consolidated Statements of Operations. If the Company incurs an amount different from the amount accrued for asset retirement obligations, the Company recognizes the difference as an adjustment to proved properties.

Decommissioning Obligations

Decommissioning Obligations — Certain counterparties in divestiture transactions or third parties in existing leases that have filed for bankruptcy protection or undergone associated reorganizations may not be able to perform required abandonment obligations. The Company may be held jointly and severally liable for the decommissioning of various facilities and related wells. The Company accrues losses associated with decommissioning obligations when such losses are probable and reasonably estimable. When there is a range of possible outcomes, the amount accrued is the most likely outcome within the range. If no single outcome within the range is more likely than the others, the minimum amount in the range is accrued. These accruals may be adjusted as additional information becomes available. In addition, when decommissioning obligations are reasonably possible, the Company discloses an estimate for a possible loss or range of loss (or a statement that such an estimate cannot be reasonably made). See Note 14 — Commitments & Contingencies for additional information.

Share-Based Compensation

Share-Based Compensation — Certain of the Company’s employees participate in its equity-based compensation plan. The Company measures all employee equity-based compensation awards at fair value on the date awards are granted to its employees.

The fair value of the stock-based awards is determined at the date of grant and is not remeasured for awards classified as equity unless the award is modified. Liability classified awards are remeasured at each reporting period. The Company records share-based compensation, net of actual forfeitures, for the restricted stock units (“RSUs”) and performance share units (“PSUs”) in “General and administrative expense” on the Consolidated Statements of Operations, net of amounts capitalized to oil and gas properties. See Note 10 — Employee Benefits Plans and Share-Based Compensation for additional information.

RSUs — Share-based compensation is based on the market price of the Company’s common stock on the grant date and recognized over the requisite service period using the straight-line method.

PSUs with Market Based Conditions — Share-based compensation is based on the grant date fair value determined using a Monte Carlo valuation model for awards with a market condition and recognized over the requisite service period using the straight-line method. Estimates used in the Monte Carlo valuation model are considered highly-complex and subjective. The number of shares of common stock issuable upon vesting ranges from zero to 200% of the number of PSUs granted based on the Company’s total shareholder return (“TSR”). Share-based compensation related to PSUs with a market condition are recognized as the requisite service period is fulfilled, even if the market condition is not achieved.

PSUs with Performance Based Conditions — Share-based compensation is based on the market price of the Company’s common stock on the grant date and recognized over the requisite service period using the straight-line method for awards with a performance condition. The Company recognizes compensation cost for awards with performance conditions if and when the Company concludes that it is probable that the performance condition will be achieved. The Company reassesses the probability of vesting at each reporting period for awards with performance conditions and adjusts compensation cost based on its probability assessment. The Company recognizes a cumulative catch-up adjustment for such changes in its probability assessment in subsequent reporting periods, using the grant date fair value of the award whose terms reflect the updated probable performance condition (which could be either a reversal or increase in expense). The number of shares of common stock issuable upon vesting ranges from zero to 200% of the number of PSUs granted based on a metric associated with the Company’s own operations or activities.

Revenue Recognition

Revenue Recognition — Revenues are recorded based from the sale of oil, natural gas and NGL quantities sold to purchasers. The Company records revenues from the sale of oil, natural gas and NGLs based on quantities of production sold to purchasers under short-term contracts (less than twelve months) at market prices when delivery to the customer has occurred, title has transferred, prices are fixed and determinable and collection is reasonably assured. This occurs when production has been delivered to a pipeline or when a barge lifting has occurred. The Company recognizes transportation costs as a component of lease operating expense when it is the shipper of the product. Each unit of product typically represents a separate performance obligation, therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Production Handling Fees

Production Handling Fees — The Company presents certain reimbursements for costs from certain third parties as a reduction of “Lease operating expense” on the Consolidated Statements of Operations.

ONRR Federal Royalty Refund

ONRR Federal Royalty Refund — Included within “Other operating (income) expense” on the Consolidated Statements of Operations is income from the Company’s multi-year federal royalty refund claim from the ONRR. The Company records income when a refund is filed and its collection is reasonably assured.

Income Taxes

Income Taxes — The Company records current income taxes based on estimates of current taxable income and provides for deferred income taxes to reflect estimated future income tax payments and receipts. The impact to changes in tax laws are recorded in the period the change is enacted. Deferred taxes represent the tax impacts of differences between the financial statement and tax bases of assets and liabilities and carryovers at each year end. The Company classifies all deferred tax assets and liabilities, along with any related valuation allowance, as long-term on the Consolidated Balance Sheets.

The realization of deferred tax assets depends on recognition of sufficient future taxable income during periods in which those temporary differences are deductible. The Company reduces deferred tax assets by a valuation allowance when, based on estimates, it is more likely than not that a portion of those assets will not be realized in a future period. The deferred tax asset estimates are subject to revision, either up or down, in future periods based on new facts or circumstances. In evaluating the Company’s valuation allowances, the Company considers cumulative book losses, the reversal of existing temporary differences, the existence of taxable income in carryback years, tax planning strategies and future taxable income for each of its taxable jurisdictions, the latter two of which involve the exercise of significant judgment. Changes to the Company’s valuation allowances could materially impact its results of operations.

The Company’s policy is to classify interest and penalties associated with underpayment of income taxes as “Interest expense” and “General and administrative expense” on the Consolidated Statements of Operations, respectively.

Income (Loss) Per Share

Income (Loss) Per Share — Basic net income per common share (“EPS”) is computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted EPS includes the impact of RSUs, PSUs and outstanding warrants. See Note 12 — Income (Loss) Per Share for additional information.

Fair Value Measure of Financial Instruments

Fair Value Measure of Financial Instruments — Financial instruments generally consist of cash and cash equivalents, accounts receivable, commodity derivatives, accounts payable and debt. The carrying amount of cash and cash equivalents, accounts receivable and accounts payable approximates fair value due to the highly liquid nature of these instruments.

Current fair value accounting standards define fair value, establish a consistent framework for measuring fair value and stipulate the related disclosure requirements for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis. These standards also clarify fair value is an exit price, presenting the amount that would be received to sell an asset or paid to transfer a liability, in an orderly transaction between market participants. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value depending on the degree to which they are observable as follows:

•Level 1 – Inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

•Level 2 – Inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial statement.

•Level 3 – Inputs to the valuation methodology are unobservable (little or no market data), which require the reporting entity to develop its own assumptions and are significant to the fair value measurement.

Assets and liabilities measured at fair value are based on one or more of three valuation techniques. The valuation techniques are as follows:

•Market Approach – Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.

•Cost Approach – Amount that would be required to replace the service capacity of an asset (replacement cost).

•Income Approach – Techniques to convert expected future cash flows to a single present value amount based on market expectations (including present value techniques, option-pricing and excess earnings models).

Authoritative guidance on financial instruments requires certain fair value disclosures to be presented. The estimated fair value amounts have been determined using available market information and valuation methodologies. Considerable judgment is required in interpreting market data to develop the estimates of fair value. The use of different assumptions or valuation methodologies may have a material effect on the estimated fair value amounts.

Variable Interest Entities

Variable Interest Entities — Upon inception of a contractual agreement, the Parent Company performs an assessment to determine whether the arrangement contains a variable interest in a legal entity and whether that legal entity is a variable interest Entity (“VIE”). The Parent Company assesses all aspects of its interests in an entity and uses judgment when determining if it is the primary beneficiary. The primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. Other qualitative factors that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. A reassessment of the primary beneficiary conclusion is conducted when there are changes in the facts and circumstances related to a VIE. See Note 7 — Equity Method Investments for additional information.

Concentration of Credit Risk

Concentration of Credit Risk

Consisting principally of cash and cash equivalents, accounts receivable and commodity derivatives, the Company is subject to concentrated financial instruments credit risk.

Cash and cash equivalents balances are maintained in financial institutions, which at times, exceed federally insured limits. The Company monitors the financial condition of these institutions and has not experienced losses on these accounts.

Commodity derivatives are entered into with registered swap dealers, all of which participate in the Company’s senior reserve-based revolving credit facility (the “Bank Credit Facility”). The Company monitors the financial condition of these institutions and has not experienced losses due to counterparty default on these instruments.

The Company markets the majority of its oil and natural gas production, and substantially all of its revenues are attributable to the U.S. The majority of the Company’s oil, natural gas and NGL production is sold to customers under short-term (less than 12 months) contracts at market-based prices. The Company’s customers consist primarily of major oil and natural gas companies, well-established oil and pipeline companies and independent oil and gas producers and suppliers. The Company performs ongoing credit evaluations of its customers and provide allowances for probable credit losses when necessary.

The percent of consolidated revenue of major customers, those whose total represented 10% or more of the Company’s oil, natural gas and NGL revenues, was as follows:

	Year Ended December 31,
	2023			2022			2021
Shell Trading (US) Company		54	%		44	%		45	%
Valero Energy Corporation		21	%		23	%	**
Chevron Products Company	**				11	%		29	%

** Less than 10%

The loss of a major customer could have material adverse effect on the Company in the short term. However, the Company believes it would be able to obtain other customers to market its oil, natural gas and NGL production.

Cash, Cash Equivalents and Restricted Cash

Cash, Cash Equivalents and Restricted Cash

The following table provides a reconciliation of the amount of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheets to the total of the same such amounts shown in the Consolidated Statement of Cash Flows (in thousands):

	Year Ended December 31,
	2023		2022
Cash and cash equivalents	$	33,637	$	44,145
Restricted cash included in Other long-term assets		102,362		—
Total cash, cash equivalent and restricted cash	$	135,999	$	44,145

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Schedule of Percent of Consolidated Revenue of Major Customers, Those Whose Total Represented 10% or More of Oil, Natural Gas and NGL Revenues

The percent of consolidated revenue of major customers, those whose total represented 10% or more of the Company’s oil, natural gas and NGL revenues, was as follows:

	Year Ended December 31,
	2023			2022			2021
Shell Trading (US) Company		54	%		44	%		45	%
Valero Energy Corporation		21	%		23	%	**
Chevron Products Company	**				11	%		29	%

** Less than 10%

Schedule of Cash and Cash Equivalents

The following table provides a reconciliation of the amount of cash, cash equivalents and restricted cash reported within the Consolidated Balance Sheets to the total of the same such amounts shown in the Consolidated Statement of Cash Flows (in thousands):

	Year Ended December 31,
	2023		2022
Cash and cash equivalents	$	33,637	$	44,145
Restricted cash included in Other long-term assets		102,362		—
Total cash, cash equivalent and restricted cash	$	135,999	$	44,145

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Acquisitions and Divestitures (Tables) - EnVen Energy Corporation

12 Months Ended

Dec. 31, 2023

Business Acquisition [Line Items]

Summary of Purchase Price

The following table summarizes the purchase price (in thousands except share and per share data):

Talos common stock		43,799,890
Talos common stock price per share(1)	$	19.00
Common stock value	$	832,198
Cash consideration	$	207,313
Settlement of preexisting relationship	$	8,388
Total purchase price	$	1,047,899

(1)Represents the closing price of the Company’s common stock on February 13, 2023, the date of the closing of the EnVen Acquisition.

Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed

The following table presents the final allocation of the purchase price to the assets acquired and liabilities assumed based on their fair values on February 13, 2023 (in thousands):

Current assets	$	243,571
Property and equipment		1,455,347
Other long-term assets:
Restricted cash		100,753
Notes receivable, net		14,844
Other long-term assets		48,899
Current liabilities:
Current portion of long-term debt		(33,234	)
Current portion of asset retirement obligations		(7,079	)
Other current liabilities		(124,347	)
Long-term liabilities:
Long-term debt		(233,836	)
Asset retirement obligations		(251,779	)
Deferred tax liabilities		(150,264	)
Other long-term liabilities		(14,976	)
Allocated purchase price	$	1,047,899

Summary Of Revenues And Net Income Attributable To Acquisition

The following table presents revenue and net income (loss) attributable to the EnVen Acquisition for the period from February 13, 2023 to December 31, 2023 (in thousands):

	Year Ended December 31, 2023
Revenue	$	423,624
Net income (loss)	$	85,622

Supplemental Proforma Information

This information does not purport to be indicative of results of operations that would have occurred had the EnVen Acquisition occurred on January 1, 2022, nor is such information indicative of any expected future results of operations (in thousands, except for the per share data).

	Year Ended December 31,
	2023		2022
Revenue	$	1,509,929	$	2,355,215
Net income (loss)	$	217,537	$	425,995
Basic net income (loss) per common share	$	1.74	$	3.37
Diluted net income (loss) per common share	$	1.73	$	3.34

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2023

Oil and Gas Property [Abstract]

Summary of Oil and Natural Gas Property Costs Not Being Amortized

The following table sets forth a summary of the Company’s oil and natural gas property costs not being amortized at December 31, 2023, by the year in which such costs were incurred (in thousands):

			Year Ended December 31,
	Total		2023		2022		2021		2020 and Prior
Acquisition United States	$	249,799	$	229,216	$	—	$	—	$	20,583
Exploration United States		18,516		10,108		1,299		2,295		4,814
Total unproved properties, not subject to amortization	$	268,315	$	239,324	$	1,299	$	2,295	$	25,397

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Leases (Tables)

12 Months Ended

Dec. 31, 2023

Leases [Abstract]

Components of Lease Costs

The components of lease costs were as follows (in thousands):

	Year Ended December 31,
	2023			2022		2021
Finance lease cost - interest on lease liabilities	$	14,476		$	7,558	$	11,453
Operating lease cost, excluding short-term leases(1)		4,883			2,281		2,706
Short-term lease cost(2)		117,132			55,072		38,472
Variable lease cost(3)		2,888			1,450		1,356
Variable and fixed sublease income		(482	)		—		—
Total lease cost	$	138,897		$	66,361	$	53,987

(1)Operating lease cost reflect a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis.

(2)Short-term lease costs are reported at gross amounts and primarily represent costs incurred for drilling rigs, most of which are short-term contracts not recognized as a ROU asset and lease liability on the Consolidated Balance Sheets.

Variable lease costs primarily represent differences between minimum payment obligations and actual operating charges incurred by the Company related to its long-term leases.

Schedule of ROU Asset and Liability, Adjusted for Initial Direct Costs and Incentives

The present value of the fixed lease payments recorded as the Company’s ROU asset and liability, adjusted for initial direct costs and incentives were as follows (in thousands):

	Year Ended December 31,
	2023		2022
Operating leases:
Operating lease assets	$	11,418	$	5,903
Current portion of operating lease liabilities	$	2,666	$	1,943
Operating lease liabilities		18,211		14,855
Total operating lease liabilities	$	20,877	$	16,798
Finance leases:
Proved properties	$	166,261	$	166,261
Other current liabilities	$	17,834	$	16,306
Other long-term liabilities		131,230		149,064
Total finance lease liabilities	$	149,064	$	165,370

Schedule of Lease Maturity

The table below presents the lease maturity by year as of December 31, 2023 (in thousands). Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the Consolidated Balance Sheets.

	Operating Leases			Finance Leases
2024	$	4,748		$	30,782
2025		4,716			30,782
2026		4,803			30,782
2027		4,708			30,782
2028		4,610			30,782
Thereafter		4,584			43,608
Total lease payments	$	28,169		$	197,518
Imputed interest		(7,292	)		(48,454	)
Total lease liabilities	$	20,877		$	149,064

Schedule of Weighted Average Remaining Lease Term and Discount Rate

The table below presents the weighted average remaining lease term and discount rate related to leases:

	Year Ended December 31,
	2023			2022			2021
Weighted average remaining lease term:
Operating leases	5.9 years			6.4 years			7.4 years
Finance leases	6.4 years			7.4 years			1.4 years
Weighted average discount rate:
Operating leases		10.8	%		11.8	%		11.9	%
Finance leases		9.2	%		9.2	%		21.9	%

Supplemental Cash Flow Information Related to Leases

The table below presents the supplemental cash flow information related to leases (in thousands):

	Year Ended December 31,
	2023			2022		2021
Operating cash outflow from finance leases	$	14,476		$	7,181	$	11,453
Operating cash outflow from operating leases	$	6,318		$	3,722	$	3,864
ROU assets obtained in exchange for new finance lease liabilities	$	—		$	166,261	$	—
ROU assets obtained in exchange for new operating lease liabilities(1)	$	12,971		$	474	$	1,020
Remeasurement of lease liability arising from modification of ROU asset(2)	$	(5,124	)	$	—	$	—

(1)See EnVen Acquisition in Note 3 — Acquisitions and Divestitures.

(2)Lease termination accounted for as a lease modification based on the modified lease term. The termination did not take effect contemporaneously with the effective date of the modification.

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Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2023

Financial Instruments [Abstract]

Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments

The following table presents the carrying amounts, net of discount and deferred financing costs, and estimated fair values of the Company’s debt instruments (in thousands):

	December 31, 2023				December 31, 2022
	Carrying Amount		Fair Value		Carrying Amount			Fair Value
12.00% Second-Priority Senior Secured Notes – due January 2026	$	601,353	$	655,130	$	590,132		$	674,542
11.75% Senior Secured Second Lien Notes – due April 2026	$	234,221	$	233,410	$	—		$	—
Bank Credit Facility – matures March 2027	$	190,100	$	200,000	$	(4,792	)	$	—

Schedule of Impact that Derivatives not Qualifying as Hedging Instruments in Condensed Consolidated Statements of Operations

The following table presents the impact that derivatives, not designated as hedging instruments, had on its Consolidated Statements of Operations (in thousands):

	Year Ended December 31,
	2023			2022			2021
Net cash received (paid) on settled derivative instruments	$	(9,457	)	$	(425,559	)	$	(290,164	)
Unrealized gain (loss)(1)		90,385			153,368			(128,913	)
Price risk management activities income (expense)	$	80,928		$	(272,191	)	$	(419,077	)

(1)Includes $1.4 million gain from the unrealized derivative instruments acquired from the EnVen Acquisition for the year ended December 31, 2023.

Schedule of Contracted Volumes and Weighted Average Prices and will Receive Under the Terms of Derivative Contracts

The following tables reflect the contracted average daily volumes and weighted average prices under the terms of the Company's derivative contracts as of December 31, 2023:

Swap Contracts
Production Period	Settlement Index	Volumes		Swap Price
Crude oil:		(Bbls)		(per Bbl)
January 2024 – December 2024	NYMEX WTI CMA		16,859	$	74.30
January 2025 – December 2025	NYMEX WTI CMA		7,734	$	73.80
Natural gas:		(MMBtu)		(per MMBtu)
January 2024 – December 2024	NYMEX Henry Hub		18,716	$	3.41
January 2025 – December 2025	NYMEX Henry Hub		13,712	$	3.92

Two-Way Collar Contracts
Production Period	Settlement Index	Volumes		Floor Price		Ceiling Price
Crude oil:		(Bbls)		(per Bbl)		(per Bbl)
January 2024 – December 2024	NYMEX WTI CMA		1,497	$	70.00	$	79.32
Natural gas:		(MMBtu)		(per MMBtu)		(per MMBtu)
January 2024 – December 2024	NYMEX Henry Hub		10,000	$	4.00	$	6.90

Three-Way Collar Contracts
Production Period	Settlement Index	Volumes		Short Put Price		Floor Price		Ceiling Price
Crude oil:		(Bbls)		(per Bbl)		(per Bbl)		(per Bbl)
January 2024 – March 2024	NYMEX WTI CMA		3,200	$	57.27	$	70.00	$	98.01

Summary of Additional Information Related to Financial Instruments Measured at Fair Value on Recurring Basis

The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands):

	December 31, 2023
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas derivatives	$	—	$	53,703		$	—	$	53,703
Liabilities:
Oil and natural gas derivatives		—		(8,100	)		—		(8,100	)
Total net asset (liability)	$	—	$	45,603		$	—	$	45,603

	December 31, 2022
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas derivatives	$	—	$	32,883		$	—	$	32,883
Liabilities:
Oil and natural gas derivatives		—		(76,242	)		—		(76,242	)
Total net asset (liability)	$	—	$	(43,359	)	$	—	$	(43,359	)

Schedule of Fair Value of Derivative Financial Instruments

The following table presents the fair value of derivative financial instruments as well as the potential effect of netting arrangements on the Company's recognized derivative asset and liability amounts (in thousands):

	December 31, 2023				December 31, 2022
	Assets		Liabilities		Assets		Liabilities
Oil and natural gas derivatives:
Current	$	36,152	$	7,305	$	25,029	$	68,370
Non-current		17,551		795		7,854		7,872
Total gross amounts presented on balance sheet		53,703		8,100		32,883		76,242
Less: Gross amounts not offset on the balance sheet		8,100		8,100		32,883		32,883
Net amounts	$	45,603	$	—	$	—	$	43,359

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Equity Method Investments (Tables)

12 Months Ended

Dec. 31, 2023

Equity Method Investments and Joint Ventures [Abstract]

Schedule of Equity Method Investments

The following table presents the Company’s investments in unconsolidated affiliates by segment for the periods indicated below. The Company accounts for these investments using the equity method of accounting.

	Ownership Interest at			Year Ended December 31,
	December 31, 2023			2023		2022
Upstream:
Talos Energy Mexico 7, S. de R.L. de C.V		50.1	%	$	107,259	$	—
SP 49 Pipeline LLC		33.3	%		861		374
CCS:
Bayou Bend CCS LLC		25.0	%		28,183		1,371
Harvest Bend CCS LLC		65.0	%		9,746		—
Coastal Bend CCS LLC		50.0	%		—		—
Total Equity Method Investments				$	146,049	$	1,745

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Debt (Tables)

12 Months Ended

Dec. 31, 2023

Debt Disclosure [Abstract]

Summary of Detail Comprising Debt and Related Book Values

A summary of the detail comprising the Company’s debt and the related book values for the respective periods presented is as follows (in thousands):

	Year Ended December 31,
	2023			2022
12.00% Second-Priority Senior Secured Notes – due January 2026	$	638,541		$	638,541
11.75% Senior Secured Second Lien Notes – due April 2026		227,500			—
Bank Credit Facility – matures March 2027		200,000			—
Total debt, before discount, premium and deferred financing cost		1,066,041			638,541
Unamortized discount, premium and deferred financing cost, net		(40,367	)		(53,201	)
Total debt		1,025,674			585,340
Less: Current portion of long-term debt		33,060			—
Long-term debt	$	992,614		$	585,340

Summary of Redemption Prices of 12.% and 11.75% Notes

The Company may redeem all or a portion of the 12.00% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest if redeemed during the period commencing on January 15 of the years set forth below:

Period	Redemption Price
2023		106.000	%
2024		103.000	%
2025 and thereafter		100.000	%

The Company may redeem all or a portion of the 11.75% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest if redeemed during the period commencing on February 15 of the years set forth below:

Period	Redemption Price
2023		105.875	%
2024		102.938	%
2025 and thereafter		100.000	%

Schedule of Pricing Grid for Borrowing Base Utilization Percentage

The pricing grid below shows the applicable margin for Term Benchmark Loans, RFR Loans and ABR Loans as well as the commitment fee rate, in each case based upon the applicable borrowing base utilization percentage:

Borrowing Base Utilization Percentage	Utilization	Term Benchmark Loans and RFR Loans	ABR Loans	Commitment Fee Rate
Level 1	< 25%	2.75%	1.75%	0.38%
Level 2	≥ 25% < 50%	3.00%	2.00%	0.38%
Level 3	≥ 50% < 75%	3.25%	2.25%	0.50%
Level 4	≥ 75% < 90%	3.50%	2.50%	0.50%
Level 5	≥ 90%	3.75%	2.75%	0.50%

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2023

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Asset Retirement Obligations

The asset retirement obligations included in the Consolidated Balance Sheets in current and non-current liabilities, and the changes in that liability were as follows (in thousands):

	Year Ended December 31,
	2023			2022
Balance, beginning of period	$	541,661		$	434,006
Obligations assumed(1)		258,858			—
Obligations incurred		14,199			1,140
Obligations settled		(86,615	)		(69,596	)
Obligations divested		(19,448	)		(1,572	)
Accretion expense		86,152			55,995
Changes in estimate(2)		102,419			121,688
Balance, end of period	$	897,226		$	541,661
Less: Current portion		77,581			39,888
Long-term portion	$	819,645		$	501,773

(1)Assumed in connection with the EnVen Acquisition. See further discussion in Note 3 — Acquisitions and Divestitures.

(2)Changes in estimate were primarily due to an increase in estimated service costs. Additionally, increases for the year ended December 31, 2023 due to the acceleration of estimated settlement date.

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Employee Benefits Plans and Share-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2023

Share-Based Payment Arrangement [Abstract]

Schedule Of Acquisition Severance Costs

The following table summarizes severance accrual activity in connection with the EnVen Acquisition included in “Other current liabilities” and “Other long-term liabilities” on the Consolidated Balance Sheets as of December 31, 2023 (in thousands):

Severance accrual at December 31, 2022	$	—
Accrual additions		25,348
Benefit payments		(19,054	)
Severance accrual at December 31, 2023		6,294
Less: Current portion at December 31, 2023		6,190
Long-term portion at December 31, 2023	$	104

Summary of Restricted Stock Units Activity

The following table summarizes RSU activity:

	Restricted Stock Units			Weighted Average Grant Date Fair Value
Unvested RSUs at December 31, 2020		1,652,988		$	13.73
Granted		1,102,038		$	13.11
Vested		(669,832	)	$	15.01
Forfeited		(101,995	)	$	12.46
Unvested RSUs at December 31, 2021		1,983,199		$	13.02
Granted		2,297,465		$	13.23
Vested		(967,269	)	$	14.14
Forfeited		(97,891	)	$	14.34
Unvested RSUs at December 31, 2022(1)		3,215,504		$	12.79
Granted		1,154,541		$	16.24
Vested		(1,730,959	)	$	11.97
Forfeited		(332,725	)	$	14.52
Unvested RSUs at December 31, 2023(1)		2,306,361		$	14.89

As of December 31, 2023 and 2022, 26,975 and 25,257, respectively, of the unvested RSUs were accounted for as liability awards in “Accrued liabilities” on the Consolidated Balance Sheet.

Summary of Performance Share Units Activity

The following table summarizes PSU activity:

	Performance Share Units			Weighted Average Grant Date Fair Value
Unvested PSUs at December 31, 2020		834,172		$	25.46
Granted		586,995		$	18.96
Vested		(391,308	)	$	39.43
Forfeited		(14,400	)	$	18.48
Unvested PSUs at December 31, 2021		1,015,459		$	16.41
Granted(1)		629,666		$	23.73
Vested(2)		(14,474	)	$	13.05
Forfeited		(16,486	)	$	17.48
Cancelled		(975,564	)	$	16.42
Unvested PSUs at December 31, 2022		638,601		$	23.66
Granted(3)		595,394		$	18.76
Forfeited		(217,346	)	$	21.28
Unvested PSUs at December 31, 2023		1,016,649		$	21.30

(1)There were 314,833 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute total shareholder return (“TSR”) over a three-year performance period. An additional 314,833 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2022 drill program over a three-year performance period.

(2)The performance period for the relative TSR awards ended on December 31, 2022. The payout on these awards was 0% based on actual performance over the performance period as certified by the Compensation Committee of the Company’s Board of Directors in early 2023. Since these awards were legally forfeited they will again be available for new awards under the recycling provisions of the 2021 LTIP.

(3)There were 297,697 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute TSR over a three-year performance period. An additional 297,697 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2023 drill program over a three-year performance period.

Summary of Assumptions Used to Calculate the Grant Date Fair Value of TSR PSUs Granted

The following table summarizes the assumptions used in the Monte Carlo simulations to calculate the fair value of the relative or absolute TSR PSUs granted and modified at the date indicated:

	2023									2022						2021
	Grant			Grant			Grant			Grant			Grant			Modification			Grant
	December 1			July 1			March 5			September 20			March 5			May 11			March 8
Expected term (in years)		2.1			2.5			2.8			2.3			2.8			2.6			2.8
Expected volatility		61.9	%		66.2	%		73.1	%		74.3	%		82.2	%		80.9	%		78.3	%
Risk-free interest rate		4.4	%		4.6	%		4.5	%		3.9	%		1.6	%		0.3	%		0.3	%
Dividend yield		—	%		—	%		—	%		—	%		—	%		—	%		—	%
Fair value (in thousands)	$	12		$	173		$	6,165		$	621		$	8,668		$	9,715		$	11,129

Schedule of Recognized Share Based Compensation Expense, Net

The following table presents the amount of costs expensed and capitalized (in thousands):

	Year Ended December 31,
	2023		2022		2021
Share-based compensation costs	$	25,236	$	28,280	$	20,560
Less: Amounts capitalized to oil and gas properties		12,283		12,327		9,568
Total share-based compensation expense	$	12,953	$	15,953	$	10,992

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2023

Income Tax Disclosure [Abstract]

Components of Income Tax Expense (Benefit)

The components of income tax expense (benefit) were as follows (in thousands):

	Year Ended December 31,
	2023			2022		2021
Current income tax expense (benefit):
United States	$	76		$	1,375	$	(5	)
Mexico		31			432		(993	)
Total current income tax expense (benefit)	$	107		$	1,807	$	(998	)
Deferred income tax expense (benefit):
United States	$	(60,704	)	$	659	$	(1,067	)
Mexico		—			71		430
Total deferred income tax expense (benefit)	$	(60,704	)	$	730	$	(637	)
Total income tax expense (benefit)	$	(60,597	)	$	2,537	$	(1,635	)

Summary of Reconciliation of Income Taxes Computed at U.S. Federal Statutory Tax Rate to Income Tax Expense (Benefit)

A reconciliation of income tax expense (benefit) computed at the U.S. federal statutory tax rate to the Company’s income tax expense (benefit) is as follows (in thousands, except percentages):

	Year Ended December 31,
	2023			2022			2021
Income tax expense (benefit) at the federal statutory tax rate	$	26,614		$	80,735		$	(38,763	)
State income taxes		1,748			1,591			(674	)
Impact of foreign operations		13,539			15,657			(11,920	)
Effect of change in state rate		—			—			2,008
Prior year taxes		1,184			(2,920	)		486
Change in valuation allowance		(106,815	)		(96,537	)		45,547
Other permanent differences		3,133			4,011			1,681
Total income tax expense (benefit)	$	(60,597	)	$	2,537		$	(1,635	)
Effective tax rate		(47.81	)%		0.66	%		0.89	%

Summary of Significant Components of Deferred Tax Assets and Liabilities

Net deferred tax assets (liabilities) reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. Significant components of deferred tax assets and liabilities were as follows (in thousands):

	Year Ended December 31,
	2023			2022
Deferred tax assets:
Federal net operating loss	$	147,252		$	159,257
Foreign tax loss carryforward		509			44,462
State net operating loss		24,840			24,787
Tax credits		107			107
Interest expense carryforward		46,414			23,262
Asset retirement obligations		190,248			115,848
Derivatives		—			9,273
Other well equipment		1,317			1,891
Accrued bonus		5,050			5,863
Share-based compensation		5,172			5,296
Operating lease liabilities		4,427			3,669
Finance lease liabilities		31,607			32,559
Other		3,383			7,142
Total deferred tax assets		460,326			433,416
Valuation allowance		(23,697	)		(129,105	)
Total deferred tax assets, net	$	436,629		$	304,311
Deferred tax liabilities:
Oil and gas properties	$	512,918		$	302,602
Operating lease assets		2,421			1,323
Derivatives		9,670			—
Prepaid		3,847			2,530
Total deferred tax liabilities		528,856			306,455
Net deferred tax liability	$	(92,227	)	$	(2,144	)

Summary of Net Operating Loss Carryovers

The table below presents the details of the Company’s net operating loss carryovers as of December 31, 2023 (in thousands):

	Amount		Expiration Year
Federal net operating losses	$	452,393	2035 - 2037
Federal net operating losses	$	248,807	Unlimited
Foreign tax loss carryforward	$	1,696	2025 - 2032
State net operating losses	$	125,958	2025 - 2037
State net operating losses	$	277,930	Unlimited

Summary of Balances In Uncertain Tax Positions

Balances in the uncertain tax positions are as follows (in thousands):

	Year Ended December 31,
	2023		2022		2021
Total unrecognized tax benefits, beginning balance	$	835	$	696	$	648
Increases in unrecognized tax benefits as a result of:
Tax positions taken during a prior period		154		100		21
Tax positions taken during the current period		—		39		27
Total unrecognized tax benefits, ending balance	$	989	$	835	$	696

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Income (Loss) Per Share (Tables)

12 Months Ended

Dec. 31, 2023

Earnings Per Share [Abstract]

Summary of Computation of Basic and Diluted Income (Loss) Per Share

The following table presents the computation of the Company’s basic and diluted income (loss) per share were as follows (in thousands, except for the per share amounts):

	Year Ended December 31,
	2023		2022		2021
Net income (loss)	$	187,332	$	381,915	$	(182,952	)
Weighted average common shares outstanding — basic		119,894		82,454		81,769
Dilutive effect of securities		858		1,229		—
Weighted average common shares outstanding — diluted		120,752		83,683		81,769
Net income (loss) per common share:
Basic	$	1.56	$	4.63	$	(2.24	)
Diluted	$	1.55	$	4.56	$	(2.24	)
Anti-dilutive potentially issuable securities excluded from diluted common shares		1,353		865		1,709

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2023

Commitments and Contingencies Disclosure [Abstract]

Summary of Total Minimum Commitments

The table below summarizes the Company’s total minimum commitments associated with vessel commitments, purchase obligations and other miscellaneous commitments as of December 31, 2023 (in thousands):

	2024		2025		2026		2027		Thereafter		Total
Vessel Commitments(1)	$	13,216	$	—	$	—	$	—	$	—	$	13,216
Committed purchase orders(2)		3,083		—		—		—		—		3,083
Other commitments(3)		3,991		327		—		—		—		4,318
Total	$	20,290	$	327	$	—	$	—	$	—	$	20,617

(1)Includes vessel commitments the Company will utilize for certain Deepwater well intervention, drilling operations and decommissioning activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs.

(2)Includes committed purchase orders to execute planned future drilling activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs.

(3)Includes commitments associated with the Company’s CCS Segment relating to an equity funding obligation and payments required under a sequestration agreement.

Summary of Decommissioning Obligations Included in Consolidated Balance Sheets

The decommissioning obligations included are in the Consolidated Balance Sheets as “Other current liabilities” and “Other long-term liabilities”, and the changes in that liability were as follows (in thousands):

	Year Ended December 31,
	2023			2022			2021
Balance, beginning of period	$	54,269		$	24,336		$	—
Additions		266			8,900			21,056
Changes in estimate		11,613			22,658			—
Reimbursements due from third parties		—			—			3,280
Settlements		(50,584	)		(1,625	)		—
Balance, end of period	$	15,564		$	54,269		$	24,336
Less: Current portion		3,280			42,069			3,756
Long-term portion	$	12,284		$	12,200		$	20,580

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2023

Segment Reporting [Abstract]

Summary of Information by Business Segment

The following table presents selected segment information for the periods indicated (in thousands):

	Upstream		All Other(1)			Total
Revenues from External Customers:
Year Ended December 31, 2023	$	1,457,886	$	—		$	1,457,886
Year Ended December 31, 2022		1,651,980		—			1,651,980
Year Ended December 31, 2021		1,244,540		—			1,244,540
Equity in the Net Income (Loss) of Investees Accounted for by the Equity Method:
Year Ended December 31, 2023	$	120	$	(12,228	)	$	(12,108	)
Year Ended December 31, 2022		101		(1,166	)		(1,065	)
Year Ended December 31, 2021		—		—			—
Adjusted EBITDA:
Year Ended December 31, 2023	$	979,729	$	(22,883	)	$	956,846
Year Ended December 31, 2022	$	859,840	$	(12,786	)		847,054
Year Ended December 31, 2021		615,798		(4,782	)		611,016
Segment Expenditures:
Year Ended December 31, 2023	$	733,669	$	40,961		$	774,630
Year Ended December 31, 2022		452,674		2,778			455,452
Year Ended December 31, 2021		338,822		—			338,822

(1)The CCS Segment is included in the “All Other” category. The CCS Segment is an emerging business in the start-up phase of operations and the business that does not currently generate any revenues. The CCS Segment’s business activities are conducted through both wholly owned subsidiaries and equity method investments with industry partners. Equity method investments is a business strategy that enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed.

Schedule of Reconciliation of Reportable Segment Information to the Company's Consolidated Totals

The following table presents the reconciliations of Adjusted EBITDA to the Company’s consolidated totals (in thousands):

	Year Ended December 31,
	2023			2022			2021
Adjusted EBITDA:
Total for reportable segments	$	979,729		$	859,840		$	615,798
All other		(22,883	)		(12,786	)		(4,782	)
Unallocated corporate general and administrative expense		(6,128	)		(5,280	)		(4,542	)
Interest expense		(173,145	)		(125,498	)		(133,138	)
Depreciation, depletion and amortization		(663,534	)		(414,630	)		(395,994	)
Accretion expense		(86,152	)		(55,995	)		(58,129	)
Write-down of oil and natural gas properties		—			—			(18,123	)
Transaction and other (income) expenses(1)		33,295			34,513			(5,886	)
Decommissioning obligations(2)		(11,879	)		(31,558	)		(21,055	)
Derivative fair value gain (loss) (3)		80,928			(272,191	)		(419,077	)
Net cash (received) paid on settled derivative instruments (3)		9,457			425,559			290,164
Gain (loss) on extinguishment of debt		—			(1,569	)		(13,225	)
Non-cash write-down of other well equipment		—			—			(5,606	)
Non-cash equity-based compensation expense		(12,953	)		(15,953	)		(10,992	)
Income (loss) before income taxes	$	126,735		$	384,452		$	(184,587	)

(1)Transaction expenses includes $40.4 million and $9.0 million in costs related to the EnVen Acquisition, inclusive of $25.3 million and nil in severance expense for the years ended December 31, 2023 and 2022, respectively. See further discussion in Note 3 — Acquisition and Divestitures and Note 10 — Employee Benefits Plans and Share-Based Compensation. Other income (expense) includes other miscellaneous income and expenses that the Company does not view as a meaningful indicator of its operating performance. For the year ended December 31, 2023, the amount includes a $66.2 million gain on the Mexico Divestiture. See further discussion in Note 3 — Acquisitions and Divestitures. The amount includes a gain on the funding of the capital carry of the Company’s investment in Bayou Bend by Chevron of $8.6 million and $1.4 million for the year ended December 31, 2023 and 2022, respectively. Additionally, it includes a $13.9 million gain on the partial sale of its investment in Bayou Bend to Chevron for the year ended December 31, 2022. See further discussion in Note 7 — Equity Method Investments. For the year ended December 31, 2022, the amount includes $27.5 million gain as a result of the settlement agreement to resolve previously pending litigation that was filed in October 2017 that is further discussed in Note 14 — Commitments and Contingencies.

(2)Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Note 14 — Commitments and Contingencies for additional information on decommissioning obligations.

(3)The adjustments for the derivative fair value (gains) losses and net cash receipts (payments) on settled commodity derivative instruments have the effect of adjusting net loss for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because the Company does not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled.

Reconciliation of Reportable Segment Expenditures

The following table presents the reconciliation of Segment Expenditures to the Company’s consolidated totals (in thousands):

	Year Ended December 31,
	2023			2022			2021
Segment Expenditures:
Total reportable segments	$	733,669		$	452,674		$	338,822
All other		40,961			2,778			—
Change in capital expenditures included in accounts payable and accrued liabilities		(9,199	)		(60,011	)		28,258
Plugging & abandonment		(86,615	)		(69,596	)		(67,988	)
Decommissioning obligations settled		(50,584	)		(1,625	)		—
Investment in CCS intangibles and equity method investees		(40,946	)		(2,778	)		—
Other deferred payments		(1,545	)		—			(7,921	)
Insurance recovery proceeds		2,802			—			—
Non-cash well equipment transfers		(27,731	)		(6	)		1,086
Other		622			1,728			1,074
Exploration, development and other capital expenditures	$	561,434		$	323,164		$	293,331

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Supplemental Oil and Gas Disclosures (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2023

Extractive Industries [Abstract]

Schedule of Capitalized Costs Related to Oil, Natural Gas and NGL Activities and Related Accumulated Depletion and Amortization

Aggregate amounts of capitalized costs relating to oil, natural gas and NGL activities and the aggregate amount of related accumulated depletion and amortization as of the dates indicated are presented below (in thousands):

	Year Ended December 31,
	2023		2022		2021
Consolidated Entities:
Proved properties	$	7,906,295	$	5,964,340	$	5,232,480
Unproved oil and gas properties, not subject to amortization(1)		268,315		154,783		219,055
Total oil and gas properties		8,174,610		6,119,123		5,451,535
Less: Accumulated depletion		4,143,491		3,484,590		3,072,907
Net capitalized costs	$	4,031,119	$	2,634,533	$	2,378,628
Depletion and amortization rate (Per Boe)	$	27.23	$	18.95	$	16.71
Company's Share of Equity Investees:
Unproved oil and gas properties, not subject to amortization	$	56,579	$	—	$	—

(1)Amount includes $111.4 million and $110.3 million of unproved properties, not subject to amortization, related to the Company’s operations in offshore Mexico for the years ended December 31, 2022 and 2021, respectively.

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

The following table reflects the costs incurred in oil, natural gas and NGL property acquisition, exploration and development activities during the years indicated (in thousands). Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligations resulting from changes to estimates during the year.

	Year Ended December 31,
	2023		2022		2021
Consolidated Entities:
Property acquisition costs:
Proved properties	$	951,703	$	—	$	210
Unproved properties, not subject to amortization		249,688		2,221		—
Total property acquisition costs		1,201,391		2,221		210
Exploration costs(1)		161,296		125,889		23,844
Development costs		805,148		541,512		245,058
Total costs incurred	$	2,167,835	$	669,622	$	269,112
Company's Share of Equity Investees:
Exploration costs	$	290	$	—	$	—

(1)Amount includes nil, $1.2 million and $6.6 million of exploration costs related to the Company’s operations in offshore Mexico for the years ended December 31, 2023, 2022 and 2021, respectively.

Schedule of Estimated Proved Reserves at Net Ownership Interest

The following table presents the Company’s estimated proved reserves at its net ownership interest:

	Oil (MBbls)			Gas (MMcf)			NGL (MBbls)			Oil Equivalent (MBoe)
Consolidated Entities:
Total proved reserves at December 31, 2020		109,307			257,208			10,858			163,033
Revision of previous estimates		13,619			8,979			5,137			20,252
Production		(16,159	)		(32,795	)		(1,875	)		(23,500	)
Extensions and discoveries		997			2,961			315			1,806
Total proved reserves at December 31, 2021		107,764			236,353			14,435			161,591
Revision of previous estimates		(5,625	)		(8,302	)		(2,002	)		(9,010	)
Production		(14,561	)		(32,215	)		(1,793	)		(21,723	)
Sales of reserves		(158	)		(7,625	)		—			(1,429	)
Extensions and discoveries		3,639			31,340			2,288			11,150
Total proved reserves at December 31, 2022		91,059			219,551			12,928			140,579
Revision of previous estimates		(6,308	)		(62,946	)		(1,283	)		(18,082	)
Production		(18,062	)		(26,194	)		(1,767	)		(24,195	)
Purchases of reserves		41,871			36,690			1,116			49,102
Extensions and discoveries		2,255			12,770			979			5,362
Total proved reserves at December 31, 2023		110,815			179,871			11,973			152,766
Total Proved Developed Reserves as of:
December 31, 2021		93,420			186,442			11,792			136,286
December 31, 2022		80,285			161,727			9,315			116,555
December 31, 2023		98,225			141,823			9,957			131,819
Total Proved Undeveloped Reserves as of:
December 31, 2021		14,344			49,911			2,643			25,305
December 31, 2022		10,774			57,824			3,613			24,024
December 31, 2023		12,590			38,048			2,016			20,947

Schedule of Standardized Measure of Discounted Future Net Cash Flows Related to Interest in Proved Oil, Natural Gas and NGL Reserves

The following table reflects the standardized measure of discounted future net cash flows relating to the Company’s interest in proved oil, natural gas and NGL reserves (in thousands):

	Year Ended December 31,
	2023			2022			2021
Consolidated Entities:
Future cash inflows	$	9,425,055		$	10,674,896		$	8,496,005
Future costs:
Production		(3,090,491	)		(1,906,752	)		(1,868,818	)
Development and abandonment		(2,358,368	)		(1,873,453	)		(1,422,507	)
Future net cash flows before income taxes		3,976,196			6,894,691			5,204,680
Future income tax expense		(589,413	)		(1,114,409	)		(676,778	)
Future net cash flows after income taxes		3,386,783			5,780,282			4,527,902
Discount at 10% annual rate		(343,295	)		(1,411,834	)		(1,087,291	)
Standardized measure of discounted future net cash flows	$	3,043,488		$	4,368,448		$	3,440,611

Schedule of Base Prices Used in Determining Standardized Measure

Future cash inflows are computed by applying SEC Pricing to year-end quantities of proved reserves. The discounted future cash flow estimates do not include the effects of derivative instruments. See the following table for SEC Pricing used in determining the standardized measure:

	Year Ended December 31,
	2023		2022		2021
Oil price per Bbl	$	78.56	$	96.03	$	67.14
Natural gas price per Mcf	$	2.75	$	6.80	$	3.71
NGL price per Bbl	$	18.77	$	33.89	$	26.62

Schedule of Principal Changes in Standardized Measure of Discounted Future Net Cash Flows

Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved oil, natural gas and NGL reserves are as follows (in thousands):

	Year Ended December 31,
	2023			2022			2021
Consolidated Entities:
Standardized measure, beginning of year	$	4,368,448		$	3,440,611		$	1,904,934
Sales and transfers of oil, net gas and NGLs produced during the period		(1,065,814	)		(1,340,400	)		(957,576	)
Net change in prices and production costs		(2,835,125	)		2,388,442			2,049,980
Changes in estimated future development and abandonment costs		(19,877	)		(84,391	)		(57,876	)
Previously estimated development and abandonment costs incurred		202,503			20,107			69,125
Accretion of discount		518,110			392,600			199,849
Net change in income taxes		357,321			(327,265	)		(391,834	)
Purchases of reserves		2,033,852			—			—
Sales of reserves		—			(5,218	)		—
Extensions and discoveries		90,244			202,239			45,485
Net change due to revision in quantity estimates		(484,423	)		(255,743	)		426,357
Changes in production rates (timing) and other		(121,751	)		(62,534	)		152,167
Standardized measure, end of year	$	3,043,488		$	4,368,448		$	3,440,611

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Organization, Nature of Business and Basis of Presentation - Additional Information (Details)	12 Months Ended
	Dec. 31, 2023 Segment
Basis Of Presentation And Schedule Of Accounting Policy [Line Items]
Date of incorporation	Nov. 14, 2017
Number of Operating Segments	2

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Summary of Significant Accounting Policies - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Summary Of Significant Accounting Policies [Line Items]
Allowance for expected credit losses	$ 8,800,000	$ 10,700,000
Impairment charges	0	$ 0	$ 0
EnVen Energy Corporation
Summary Of Significant Accounting Policies [Line Items]
Receivable with imputed interest, face amount	66,200,000
EnVen Energy Corporation | Future plugging and abanonment obligations
Summary Of Significant Accounting Policies [Line Items]
Escrow Deposit	$ 100,000,000
Minimum
Summary Of Significant Accounting Policies [Line Items]
Other property and equipment, estimated useful lives	3 years
Minimum | Performance Share Unit
Summary Of Significant Accounting Policies [Line Items]
Number of common stock issuable upon vesting, percentage range of PSUs granted	0.00%
Minimum | Performance Shares
Summary Of Significant Accounting Policies [Line Items]
Number of common stock issuable upon vesting, percentage range of PSUs granted	0.00%
Maximum
Summary Of Significant Accounting Policies [Line Items]
Other property and equipment, estimated useful lives	10 years
Maximum | Performance Share Unit
Summary Of Significant Accounting Policies [Line Items]
Number of common stock issuable upon vesting, percentage range of PSUs granted	200.00%
Maximum | Performance Shares
Summary Of Significant Accounting Policies [Line Items]
Number of common stock issuable upon vesting, percentage range of PSUs granted	200.00%
Measurement Input Discount Rate
Summary Of Significant Accounting Policies [Line Items]
Present value of future net revenues from proved reserves, discount rate	10.00%
Limited Partnership or Limited Liability Company Type Investment | Minimum
Summary Of Significant Accounting Policies [Line Items]
Equity method investment, ownership percentage	3.00%
Limited Partnership or Limited Liability Company Type Investment | Minimum | Common Stock
Summary Of Significant Accounting Policies [Line Items]
Equity method investment, ownership percentage	20.00%
Limited Partnership or Limited Liability Company Type Investment | Maximum
Summary Of Significant Accounting Policies [Line Items]
Equity method investment, ownership percentage	5.00%
Equity method investment, maximum required ownership percentage	3.00%

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Summary of Significant Accounting Policies - Schedule of Percent of Consolidated Revenue of Major Customers, Those Whose Total Represented 10% or More of Oil, Natural Gas and NGL Revenues (Details) - Sales Revenue - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Shell Trading (US) Company
Concentration Risk Line Items
Concentration risk, percentage	54.00%	44.00%	45.00%
Valero energy corporation
Concentration Risk Line Items
Concentration risk, percentage	21.00%	23.00%
Chevron Products Company
Concentration Risk Line Items
Concentration risk, percentage		11.00%	29.00%

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Summary of Significant Accounting Policies - Schedule of Percent of Consolidated Revenue of Major Customers, Those Whose Total Represented 10% or More of Oil, Natural Gas and NGL Revenues (Parenthetical) (Details) - Sales Revenue - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Valero energy corporation
Concentration Risk Line Items
Concentration risk, percentage	21.00%	23.00%
Valero energy corporation | Maximum
Concentration Risk Line Items
Concentration risk, percentage			10.00%
Chevron Products Company
Concentration Risk Line Items
Concentration risk, percentage		11.00%	29.00%
Chevron Products Company | Maximum
Concentration Risk Line Items
Concentration risk, percentage	10.00%

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Summary of Significant Accounting Policies - Schedule of Cash and Cash Equivalents (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Summary Of Significant Accounting Policies [Abstract]
Cash and cash equivalents	$ 33,637	$ 44,145
Restricted cash included in Other long-term assets	102,362	0
Total cash, cash equivalent and restricted cash	$ 135,999	$ 44,145	$ 69,852	$ 34,233

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Acquisitions and Divestitures - Business Combination - Additional Information (Details) - USD ($) $ in Thousands				12 Months Ended
	Jan. 13, 2024	Feb. 13, 2023	Sep. 21, 2022	Dec. 31, 2023	Dec. 31, 2022
EnVen Energy Corporation
Business Acquisition [Line Items]
Business acquisition, effective date		Feb. 13, 2023
Pro forma financial information				The following supplemental pro forma financial information (in thousands, except per common share amounts), presents the consolidated results of operations for the years ended December 31, 2023 and 2022 as if the EnVen Acquisition had occurred on January 1, 2022. The unaudited pro forma information was derived from historical statements of operations of the Company and EnVen adjusted to include (i) depletion expense applied to the adjusted basis of the oil and natural gas properties acquired, (ii) interest expense to reflect borrowings under the Bank Credit Facility and to adjust the amortization of the premium of the 11.75% Notes (as defined in Note 8 — Debt), (iii) general and administrative expense adjusted for transaction related costs incurred (including severance), (iv) other income (expense) to adjust the accretion of the discount on the P&A Notes Receivable and (v) weighted average basic and diluted shares of common stock outstanding from the issuance of 43.8 million shares of common stock to EnVen. Supplemental pro forma earnings for the year ended December 31, 2022 were adjusted to include $65.1 million of general and administrative expenses, of which $16.3 million were incurred during the year ended December 31, 2022. Supplemental pro forma earnings for the year ended December 31, 2023 were adjusted to exclude $65.1 million of general and administrative expenses.
Cash consideration		$ 207,313
Business Acquisition, Date of Acquisition Agreement			Sep. 21, 2022
Common stock value		832,198
Settlement of preexisting relationship		8,388
Supplemental pro forma earnings				$ 217,537	$ 425,995
EnVen Energy Corporation | 11.75% notes
Business Acquisition [Line Items]
Debt instrument interest rate				11.75%
EnVen Energy Corporation | Employee Severance
Business Acquisition [Line Items]
Aquisition severance cost				$ 25,300
EnVen Energy Corporation | Settlements Of Preexisting Relationship
Business Acquisition [Line Items]
Gain or loss recognized on settlement		$ 0
EnVen Energy Corporation | General and Administrative Expense
Business Acquisition [Line Items]
Cumulative transaction related costs				21,800
Acquisition, transaction related cost				12,800	9,000
EnVen Energy Corporation | General and Administrative Expense | Pro Forma
Business Acquisition [Line Items]
Acquisition, transaction related cost					16,300
EnVen Energy Corporation | General and Administrative Expense | Nonrecurring Adjustments
Business Acquisition [Line Items]
Supplemental pro forma earnings				$ (65,100)	$ 65,100
EnVen Energy Corporation | Common Stock
Business Acquisition [Line Items]
Aggregate shares issued		43,799,890
EnVen Energy Corporation | Common Stock | Pro Forma
Business Acquisition [Line Items]
Aggregate shares issued					43,800,000
QuarterNorth Energy, Inc. | Subsequent Event
Business Acquisition [Line Items]
Cash consideration	$ 964,900
Business Acquisition, Date of Acquisition Agreement	Jan. 13, 2024
QuarterNorth Energy, Inc. | Common Stock | Subsequent Event
Business Acquisition [Line Items]
Aggregate shares issued	24,800,000

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Acquisitions and Divestitures - Business Combination - Summary of Purchase Price (Details) - EnVen Energy Corporation $ / shares in Units, $ in Thousands	Feb. 13, 2023 USD ($) $ / shares shares
Business Acquisition [Line Items]
Talos common stock price per share | $ / shares	$ 19	[1]
Common stock value	$ 832,198
Cash consideration	207,313
Settlement of preexisting relationship	8,388
Total purchase price	$ 1,047,899
Common Stock
Business Acquisition [Line Items]
Talos common stock | shares	43,799,890

[1] Represents the closing price of the Company’s common stock on February 13, 2023, the date of the closing of the EnVen Acquisition.

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Acquisitions and Divestitures - Business Combination - Summary of Allocation of Purchase Price to Assets Acquired and Liabilities Assumed (Details) - EnVen Energy Corporation $ in Thousands	Feb. 13, 2023 USD ($)
Business Acquisition [Line Items]
Current assets	$ 243,571
Property and equipment	1,455,347
Restricted cash	100,753
Notes receivable, net	14,844
Other long-term assets	48,899
Current portion of long-term debt	(33,234)
Current portion of asset retirement obligations	(7,079)
Other current liabilities	(124,347)
Long-term debt	(233,836)
Asset retirement obligations	(251,779)
Deferred tax liabilities	(150,264)
Other long-term liabilities	(14,976)
Allocated purchase price	$ 1,047,899

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Acquisitions and Divestitures - Business Combination - Summary of Revenue and Net Income Attributable to Acquisition (Details) - EnVen Energy Corporation $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($)
Business Acquisition [Line Items]
Revenue	$ 423,624
Net income (loss)	$ 85,622

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Acquisitions and Divestitures - Business Combination - Summary of Supplemental Proforma Information (Details) - EnVen Energy Corporation - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Revenue	$ 1,509,929	$ 2,355,215
Net income (loss)	$ 217,537	$ 425,995
Basic net income (loss) per common share	$ 1.74	$ 3.37
Diluted net income (loss) per common share	$ 1.73	$ 3.34

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Acquisitions and Divestitures - Divestiture - Additional Information (Details) - USD ($) $ in Thousands		12 Months Ended
	Sep. 27, 2023	Dec. 31, 2023	Dec. 31, 2022
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Unproved oil and gas properties, not subject to amortization		$ 268,315	$ 154,783
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal, Statement of Income or Comprehensive Income [Extensible Enumeration]		Other Operating Income (Expense), Net
Talos Mexico
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Percentage of equity interests sold	49.90%
Sale of stock, consideration received on transaction	$ 74,900
Unproved oil and gas properties, not subject to amortization	112,300
Fair value of Company's retained equity method investment		$ 107,600
Talos Mexico | Earnout
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Sale of stock, consideration received on transaction	$ 49,900
Talos Mexico | Disposal Group, Held-for-Sale or Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal		$ 66,200
Zama Field | Talos Mexico
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Oil and gas ownership working interest		17.40%

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Property, Plant and Equipment - Additional Information (Details)	12 Months Ended
	Dec. 31, 2023 USD ($) $ / bbl $ / Mcf	Dec. 31, 2022 USD ($) $ / Mcf $ / bbl	Dec. 31, 2021 USD ($) $ / Mcf $ / bbl	Sep. 27, 2023 USD ($)
Property, Plant and Equipment [Line Items]
Write-down of oil and natural gas properties	$ 0	$ 0	$ 18,123,000
Total unproved properties, not subject to amortization	$ 268,315,000	$ 154,783,000
Anticipated timing of inclusion of costs in amortization calculation	The unproved costs will be excluded from the amortization base until the Company has made a determination as to the existence of proved reserves. The Company currently estimates these costs will be transferred to the amortization base over eight years.
Oil (MBbls)
Property, Plant and Equipment [Line Items]
SEC pricing | $ / bbl	78.56	96.03	67.14
Gas (MMcf)
Property, Plant and Equipment [Line Items]
SEC pricing | $ / Mcf	2.75	6.80	3.71
NGL (MBbls)
Property, Plant and Equipment [Line Items]
SEC pricing | $ / bbl	18.77	33.89	26.62
US
Property, Plant and Equipment [Line Items]
Write-down of oil and natural gas properties	$ 0	$ 0	$ 0
US | Oil (MBbls)
Property, Plant and Equipment [Line Items]
SEC pricing | $ / bbl	78.56
US | Gas (MMcf)
Property, Plant and Equipment [Line Items]
SEC pricing | $ / Mcf	2.75
US | NGL (MBbls)
Property, Plant and Equipment [Line Items]
SEC pricing | $ / bbl	18.77
Mexico
Property, Plant and Equipment [Line Items]
Write-down of oil and natural gas properties			18,100,000
Total unproved properties, not subject to amortization		$ 111,400,000	$ 110,300,000
Disposal Group, Disposed of by Sale, Not Discontinued Operations [Member] | Mexico | Zama prospect
Property, Plant and Equipment [Line Items]
Total unproved properties, not subject to amortization				$ 112,300

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Property, Plant and Equipment - Summary of Oil and Natural Gas Property Costs Not Being Amortized (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization	$ 268,315	$ 154,783
United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition	249,799
Exploration	18,516
Mexico
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization		111,400	$ 110,300
2023
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization	239,324
2023 | United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition	229,216
Exploration	$ 10,108
2022
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization		1,299
2022 | United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition		0
Exploration		$ 1,299
2021
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization			2,295
2021 | United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition			0
Exploration			$ 2,295
2020 and Prior
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Total unproved properties, not subject to amortization				$ 25,397
2020 and Prior | United States
Capitalized Costs Of Unproved Properties Excluded From Amortization [Line Items]
Acquisition				20,583
Exploration				$ 4,814

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Leases - Additional Information (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Nov. 30, 2022
Lease, Cost [Abstract]
Finance Lease, Liability, Statement of Financial Position [Extensible Enumeration]			Liabilities
Lease liability	$ 149,064	$ 165,370	$ 166,300

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Leases - Components of Lease Costs (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Lease, Cost [Abstract]
Finance lease cost - interest on lease liabilities		$ 14,476	$ 7,558	$ 11,453
Operating lease cost, excluding short-term leases	[1]	4,883	2,281	2,706
Short-term lease cost	[2]	117,132	55,072	38,472
Variable lease cost	[3]	2,888	1,450	1,356
Variable and fixed sublease income		(482)	0	0
Total lease cost		$ 138,897	$ 66,361	$ 53,987

[1] Operating lease cost reflect a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis.

[2] Short-term lease costs are reported at gross amounts and primarily represent costs incurred for drilling rigs, most of which are short-term contracts not recognized as a ROU asset and lease liability on the Consolidated Balance Sheets.

[3] Variable lease costs primarily represent differences between minimum payment obligations and actual operating charges incurred by the Company related to its long-term leases.

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Leases - Schedule of Right-of-Use Asset and Liability, Adjusted for Initial Direct Costs and Incentives (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Nov. 30, 2022
Operating leases:
Operating lease assets	$ 11,418	$ 5,903
Current portion of operating lease liabilities	$ 2,666	$ 1,943
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Current portion of operating lease liabilities	Current portion of operating lease liabilities
Operating lease liabilities	$ 18,211	$ 14,855
Total operating lease liabilities	20,877	16,798
Finance leases:
Proved property	$ 166,261	$ 166,261
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Proved properties	Proved properties
Other current liabilities	$ 17,834	$ 16,306
Finance Lease, Liability, Current, Statement of Financial Position [Extensible List]	Other current liabilities	Other current liabilities
Other long-term liabilities	$ 131,230	$ 149,064
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other long-term liabilities	Other long-term liabilities
Total finance lease liabilities	$ 149,064	$ 165,370	$ 166,300

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Leases - Schedule of Lease Maturity (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Nov. 30, 2022
Leases [Abstract]
Operating Leases, 2024	$ 4,748
Operating Leases, 2025	4,716
Operating Leases, 2026	4,803
Operating Leases, 2027	4,708
Operating Leases, 2028	4,610
Operating Leases, Thereafter	4,584
Operating Leases, Total lease payments	28,169
Operating Leases, Imputed interest	(7,292)
Total operating lease liabilities	20,877	$ 16,798
Finance Leases, 2024	30,782
Finance Leases, 2025	30,782
Finance Leases, 2026	30,782
Finance Leases, 2027	30,782
Finance Leases, 2028	30,782
Finance Leases, Thereafter	43,608
Finance Leases, Total lease payments	197,518
Finance Leases, Imputed interest	(48,454)
Total finance lease liabilities	$ 149,064	$ 165,370	$ 166,300

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Leases - Schedule of Weighted Average Remaining Lease Term and Discount Rate (Details)	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Weighted average remaining lease term:
Operating leases	5 years 10 months 24 days	6 years 4 months 24 days	7 years 4 months 24 days
Finance leases	6 years 4 months 24 days	7 years 4 months 24 days	1 year 4 months 24 days
Weighted average discount rate:
Operating leases	10.80%	11.80%	11.90%
Finance leases	9.20%	9.20%	21.90%

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Leases - Supplemental Cash Flow Information Related to Leases (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Lessee Cash Flow Information [Abstract]
Operating cash outflow from finance leases		$ 14,476	$ 7,181	$ 11,453
Operating cash outflow from operating leases		6,318	3,722	3,864
ROU assets obtained in exchange for new finance lease liabilities		0	166,261	0
ROU assets obtained in exchange for new operating lease liabilities	[1]	12,971	474	1,020
Remeasurement of lease liability arising from modification of ROU asset	[2]	$ 5,124	$ 0	$ 0

[1] See EnVen Acquisition in Note 3 — Acquisitions and Divestitures

[2] Lease termination accounted for as a lease modification based on the modified lease term. The termination did not take effect contemporaneously with the effective date of the modification.

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Financial Instruments - Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Carrying Amount	$ 1,025,674	$ 585,340
12.00% Second-Priority Senior Secured Notes - due January 2026
Debt Instrument [Line Items]
Carrying Amount	601,353	590,132
Fair Value	655,130	674,542
11.75% Senior Secured Second Lien Notes - due April 2026
Debt Instrument [Line Items]
Carrying Amount	234,221	0
Fair Value	233,410	0
Bank Credit Facility - matures March 2027
Debt Instrument [Line Items]
Carrying Amount	190,100
Fair Value	$ 200,000	0
Carrying Amount		$ (4,792)

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Financial Instruments - Schedule of Carrying Amounts and Estimated Fair Values of Financial Instruments (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
12.00% Second-Priority Senior Secured Notes - due January 2026
Debt Instrument [Line Items]
Debt instrument interest rate	12.00%	12.00%
Senior notes, maturity date	Jan. 15, 2026	Jan. 15, 2026
11.75% Senior Secured Second Lien Notes - due April 2026
Debt Instrument [Line Items]
Debt instrument interest rate	11.75%	11.75%
Senior notes, maturity date	Apr. 15, 2026	Apr. 15, 2026

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Financial Instruments - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) Counterparty
Concentration Risk [Line Items]
Credit risk, financial instruments	The Company is subject to the risk of loss on its financial instruments as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. The Company has entered into International Swaps and Derivative Association agreements with counterparties to mitigate this risk. The Company also maintains credit policies with regard to its counterparties to minimize overall credit risk. These policies require (i) the evaluation of potential counterparties’ financial condition to determine their credit worthiness; (ii) the regular monitoring of counterparties’ credit exposures; (iii) the use of contract language that affords the Company netting or set off opportunities to mitigate exposure risk; and (iv) potentially requiring counterparties to post cash collateral, parent guarantees, or letters of credit to minimize credit risk. The Company’s assets and liabilities from commodity price risk management activities at December 31, 2023 represent derivative instruments from nine counterparties; all of which are registered swap dealers that have an “investment grade” (minimum Standard & Poor’s rating of BBB- or better) credit rating, and eight of which are parties under the Company’s Bank Credit Facility. The Company enters into derivatives directly with these counterparties and, subject to the terms of the Company’s Bank Credit Facility, is not required to post collateral or other securities for credit risk in relation to the derivative activities. Had the Company’s counterparties failed to perform under existing commodity derivative contracts the maximum loss at December 31, 2023 would have been $45.6 million.
Maximum loss on commodity contracts | $	$ 45.6
Counterparty Risk Investment Grade
Concentration Risk [Line Items]
Number of counterparties description	all of which
Counterparty Risk Diversification
Concentration Risk [Line Items]
Number of counterparties | Counterparty	9

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Financial Instruments - Schedule of Impact that Derivatives not Qualifying as Hedging Instruments in Condensed Consolidated Statements of Operations (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative fair value gain (loss)		$ 80,928	$ (272,191)	$ (419,077)
Gain Loss on Derivative Instruments Unrealized Component
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative fair value gain (loss)	[1]	90,385	153,368	(128,913)
Commodity Contract
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative fair value gain (loss)		80,928	(272,191)	(419,077)
Commodity Contract | Gain Loss on Derivative Instruments Realized Component
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative fair value gain (loss)		$ (9,457)	$ (425,559)	$ (290,164)

[1] Includes $1.4 million gain from the unrealized derivative instruments acquired from the EnVen Acquisition for the year ended December 31, 2023.

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Financial Instruments - Schedule of Impact that Derivatives not Qualifying as Hedging Instruments in Condensed consolidated Statements of Operations (Parenthetical) (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative fair value gain (loss)		$ 80,928	$ (272,191)	$ (419,077)
Gain Loss on Derivative Instruments Unrealized Component
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative fair value gain (loss)	[1]	90,385	$ 153,368	$ (128,913)
Gain Loss on Derivative Instruments Unrealized Component | EnVen Energy Corporation [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative fair value gain (loss)		$ 1,400

[1] Includes $1.4 million gain from the unrealized derivative instruments acquired from the EnVen Acquisition for the year ended December 31, 2023.

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Financial Instruments - Schedule of Contracted Volumes and Weighted Average Prices and will Receive Under the Terms of Derivative Contracts (Details)	12 Months Ended
	Dec. 31, 2023 MMBTU $ / MMBTU $ / bbl Bcf bbl
Crude Oil | January 2024 - December 2024 | Swaps
Derivative [Line Items]
Settlement Index	NYMEX WTI CMA
Average Daily Volumes | bbl	16,859
Weighted Average Swap Price	74.30
Crude Oil | January 2024 - December 2024 | Collars
Derivative [Line Items]
Settlement Index	NYMEX WTI CMA
Average Daily Volumes | bbl	1,497
Weighted average put price	70
Weighted average call price	79.32
Crude Oil | January 2024 - March 2024 | Three Way Collar Contracts
Derivative [Line Items]
Settlement Index	NYMEX WTI CMA
Average Daily Volumes | Bcf	3,200
Weighted average put price | $ / MMBTU	70
Weighted average call price	98.01
Crude Oil | January 2024 - March 2024 | Three Way Collar Contracts | Short
Derivative [Line Items]
Short Put Price	57.27
Crude Oil | January 2025 - December 2025 | Swaps
Derivative [Line Items]
Settlement Index	NYMEX WTI CMA
Average Daily Volumes | bbl	7,734
Weighted Average Swap Price	73.80
Natural Gas | January 2024 - December 2024 | Swaps
Derivative [Line Items]
Settlement Index	NYMEX Henry Hub
Weighted Average Swap Price | $ / MMBTU	3.41
Average Daily Volumes | MMBTU	18,716
Natural Gas | January 2024 - December 2024 | Collars
Derivative [Line Items]
Settlement Index	NYMEX Henry Hub
Average Daily Volumes | MMBTU	10,000
Weighted average put price | $ / MMBTU	4
Weighted average call price | $ / MMBTU	6.9
Natural Gas | January 2025 - December 2025 | Swaps
Derivative [Line Items]
Settlement Index	NYMEX Henry Hub
Weighted Average Swap Price | $ / MMBTU	3.92
Average Daily Volumes | MMBTU	13,712

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Financial Instruments - Summary of Additional Information Related to Financial Instruments Measured at Fair Value on Recurring Basis (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Oil and Natural Gas Derivatives
Assets:
Oil and natural gas derivatives	$ 45,603	$ 0
Liabilities:
Oil and natural gas derivatives	0	(43,359)
Fair Value on Recurring Basis
Liabilities:
Total net asset (liability)	45,603	(43,359)
Fair Value on Recurring Basis | Oil and Natural Gas Derivatives
Assets:
Oil and natural gas derivatives	$ 53,703	$ 32,883
Derivative Asset, Statement of Financial Position [Extensible Enumeration]	Assets	Assets
Liabilities:
Oil and natural gas derivatives	$ (8,100)	$ (76,242)
Derivative Liability, Statement of Financial Position [Extensible Enumeration]	Liabilities	Liabilities
Fair Value on Recurring Basis | Level 1
Liabilities:
Total net asset (liability)	$ 0	$ 0
Fair Value on Recurring Basis | Level 1 | Oil and Natural Gas Derivatives
Assets:
Oil and natural gas derivatives	$ 0	$ 0
Derivative Asset, Statement of Financial Position [Extensible Enumeration]	Assets	Assets
Liabilities:
Oil and natural gas derivatives	$ 0	$ 0
Derivative Liability, Statement of Financial Position [Extensible Enumeration]	Liabilities	Liabilities
Fair Value on Recurring Basis | Level 2
Liabilities:
Total net asset (liability)	$ 45,603	$ (43,359)
Fair Value on Recurring Basis | Level 2 | Oil and Natural Gas Derivatives
Assets:
Oil and natural gas derivatives	$ 53,703	$ 32,883
Derivative Asset, Statement of Financial Position [Extensible Enumeration]	Assets	Assets
Liabilities:
Oil and natural gas derivatives	$ (8,100)	$ (76,242)
Derivative Liability, Statement of Financial Position [Extensible Enumeration]	Liabilities	Liabilities
Fair Value on Recurring Basis | Level 3
Liabilities:
Total net asset (liability)	$ 0	$ 0
Fair Value on Recurring Basis | Level 3 | Oil and Natural Gas Derivatives
Assets:
Oil and natural gas derivatives	$ 0	$ 0
Derivative Asset, Statement of Financial Position [Extensible Enumeration]	Assets	Assets
Liabilities:
Oil and natural gas derivatives	$ 0	$ 0
Derivative Liability, Statement of Financial Position [Extensible Enumeration]	Liabilities	Liabilities

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Financial Instruments - Schedule of Fair Value of Derivative Financial Instruments (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Price Risk Derivatives [Line Items]
Derivative Asset, Current	$ 36,152	$ 25,029
Derivative Asset, Noncurrent	17,551	7,854
Derivative Liability, Current	7,305	68,370
Derivative Liability, Noncurrent	795	7,872
Oil and Natural Gas Derivatives
Price Risk Derivatives [Line Items]
Derivative Asset, Current	36,152	25,029
Derivative Asset, Noncurrent	17,551	7,854
Total gross amounts presented on balance sheet, Assets	53,703	32,883
Gross amounts not offset on the balance sheet	8,100	32,883
Net Amounts	45,603	0
Derivative Liability, Current	7,305	68,370
Derivative Liability, Noncurrent	795	7,872
Total gross amounts presented on balance sheet, Liabilities	8,100	76,242
Gross amounts not offset on the balance sheet	8,100	32,883
Net Amounts	$ 0	$ 43,359

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Equity Method Investments - Schedule of Equity Method Investments (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Schedule of Equity Method Investments [Line Items]
Total equity method investments	$ 146,049	$ 1,745
Talos Energy Mexico 7, S. de R.L. de C.V | Upstream
Schedule of Equity Method Investments [Line Items]
Total equity method investments	$ 107,259	0
Equity method investment, ownership interest	50.10%
SP 49 Pipeline LLC | Upstream
Schedule of Equity Method Investments [Line Items]
Total equity method investments	$ 861	374
Equity method investment, ownership interest	33.30%
Bayou Bend CCS LLC | CCS
Schedule of Equity Method Investments [Line Items]
Total equity method investments	$ 28,183	1,371
Equity method investment, ownership interest	25.00%
Harvest Bend CCS LLC | CCS
Schedule of Equity Method Investments [Line Items]
Total equity method investments	$ 9,746	0
Equity method investment, ownership interest	65.00%
Coastal Bend CCS LLC | CCS
Schedule of Equity Method Investments [Line Items]
Total equity method investments	$ 0	$ 0
Equity method investment, ownership interest	50.00%

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Equity Method Investments - Additional Information (Details) - USD ($) $ in Thousands			1 Months Ended	12 Months Ended
	May 24, 2022	Mar. 08, 2022	May 31, 2022	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Schedule of Equity Method Investments [Line Items]
Equity method investment payment				$ 29,447	$ 2,250	$ 0
Proceeds from sale of equity method investment				0	15,000	$ 0
Equity Method Investee
Schedule of Equity Method Investments [Line Items]
Related party receivable				5,500
Talos Enrgy Mexico 7, S. de R.L. de C.V | Equity Method Investee | Variable Interest Entity, Not Primary Beneficiary
Schedule of Equity Method Investments [Line Items]
Equity method investment, basis difference				66,000
Bayou Bend CCS LLC | Equity Method Investment Income
Schedule of Equity Method Investments [Line Items]
Gain on partial disposal of investment					13,900
Bayou Bend CCS LLC | Equity Method Investment Income | Capital Carry
Schedule of Equity Method Investments [Line Items]
Gain on partial disposal of investment				$ 8,600	$ 1,400
Bayou Bend CCS LLC | Chevron U.S.A Inc
Schedule of Equity Method Investments [Line Items]
Equity method investment ownership percentage sold			25.00%
Proceeds from sale of equity method investment			$ 15,000
Capital carry contribution funded	$ 10,000
Bayou Bend CCS LLC | Equity Method Investee | Variable Interest Entity, Not Primary Beneficiary
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership interest		50.00%
Equity method investment payment		$ 2,300

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Debt - Summary of Detail Comprising Debt and Related Book Values (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Total debt, before discount, premium and deferred financing cost	$ 1,066,041	$ 638,541
Unamortized discount, premium and deferred financing cost, net	(40,367)	(53,201)
Total debt	1,025,674	585,340
Less: current portion of long-term debt	33,060	0
Long-Term Debt	992,614	585,340
Senior Notes | 12.00% Second-Priority Senior Secured Notes - due January 2026
Debt Instrument [Line Items]
Total debt, before discount, premium and deferred financing cost	638,541	638,541
Senior Notes | 11.75% Senior Secured Second Lien Notes - due April 2026
Debt Instrument [Line Items]
Total debt, before discount, premium and deferred financing cost	227,500	0
Bank Credit Facility | Bank Credit Facility - matures March 2027
Debt Instrument [Line Items]
Total debt, before discount, premium and deferred financing cost	$ 200,000	$ 0

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Debt - Summary of Detail Comprising Debt and Related Book Values (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Feb. 13, 2023	Jan. 14, 2021
11.75% Senior Secured Second Lien Notes - due April 2026
Debt Instrument [Line Items]
Debt instrument interest rate	11.75%	11.75%
Senior notes, maturity date	Apr. 15, 2026	Apr. 15, 2026
Senior Notes | 12.00% Second-Priority Senior Secured Notes - due January 2026
Debt Instrument [Line Items]
Debt instrument interest rate	12.00%	12.00%		12.00%
Senior notes, maturity date	Jan. 15, 2026	Jan. 15, 2026
Senior Notes | 11.75% Senior Secured Second Lien Notes - due April 2026
Debt Instrument [Line Items]
Debt instrument interest rate	11.75%	11.75%	11.75%
Senior notes, maturity date	Apr. 15, 2026	Apr. 15, 2026
Bank Credit Facility | Bank Credit Facility - matures March 2027
Debt Instrument [Line Items]
Bank credit facility, maturity date	Mar. 31, 2027	Mar. 31, 2027

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Debt - Additional information (Details) - USD ($)							12 Months Ended
	Feb. 13, 2023	Dec. 23, 2022	Oct. 27, 2022	Oct. 21, 2022	May 31, 2022	Jan. 13, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Jun. 09, 2023	Jan. 14, 2021
Debt Instrument [Line Items]
Gain (loss) on extinguishment of debt							$ 0	$ (1,569,000)	$ (13,225,000)
Debt instrument, face amount							$ 1,066,041,000	$ 638,541,000
DebtInstrument covenant description							The Bank Credit Facility has certain debt covenants, the most restrictive of which is that the Company must maintain a Consolidated Total Debt to EBITDAX Ratio (as defined in the Bank Credit Facility) of no greater than 3.00 to 1.00 calculated each quarter utilizing the most recent twelve months to determine EBITDAX.
Limitation on Restricted Payments Including Dividends, Description							The Company has not historically declared or paid any cash dividends on its capital stock. However, to the extent the Company determines in the future that it may be appropriate to pay a special dividend or initiate a quarterly dividend program, the Company’s ability to pay any such dividends to its stockholders may be limited to the extent its consolidated subsidiaries are limited in their ability to make distributions to the Parent Company, including the significant restrictions that the agreements governing the Company’s debt impose on the ability of its consolidated subsidiaries to make distributions and other payments to the Parent Company. With respect to entities accounted for under the equity method, the Company’s primary equity method investee as of December 31, 2023 did not have any undistributed earnings.The Bank Credit Facility contains restrictions on the ability of Talos Production Inc. to transfer funds to the Parent Company in the form of cash dividends, loans or advances. The Bank Credit Facility restricts distributions and other payments to the Parent Company, subject to certain baskets and other exceptions described therein including the payment of operating expense incurred in the ordinary course of business and for income taxes attributable to its ownership in Talos Production Inc. Under the Bank Credit Facility, general distributions and other restricted payments may be made to the Company so long as after giving pro forma effect to the making of any such restricted payment (i) no default or event of default has occurred and is continuing; (ii) available commitments exceed 25% of the then effective loan limit; (iii) the pro forma current ratio of 1.0 to 1.0 is satisfied; and (iv) either (A) the Consolidated Total Debt to EBITDAX Ratio (as defined in the Bank Credit Facility) is not greater than 1.75 to 1.00 and the aggregate amount of such restricted payments does not exceed the Available Free Cash Flow Amount (as defined in the Bank Credit Facility) at the time made or (B) the Consolidated Total Debt to EBITDAX Ratio is not greater than 1.00 to 1.00. In addition, the indenture governing the 12.00% Notes restricts the Company’s consolidated subsidiaries from, directly or indirectly, among other things, declaring or paying any dividend on account of their equity securities, subject to certain limited exceptions described in the indenture. Such exceptions include, among other things, if (i) no default has occurred or would occur as a result thereof, (ii) immediately after giving effect to such transaction on a pro forma basis, the issuer could incur $1.00 of additional indebtedness in compliance with a fixed charge coverage ratio of 2.25 to 1.00, (iii) the ratio of the issuer’s total debt to EBITDA ratio is not greater than 3.00 to 1.00, and (iii) if payments pursuant to such transaction, together with the aggregate amount of certain other restricted payments, is less than the cumulative credit permitted under the indenture.The indenture governing the 11.75% Notes contains a similar restriction on the Company and its consolidated subsidiaries’ ability to declare or pay dividends, subject to exceptions which include, among other things, (i) subject to no default or event of default having occurred or continuing, dividends in an aggregate amount not to exceed the greater of $25 million and 2.5% of Adjusted Consolidated Net Tangible Assets, (ii) dividends or distributions to any parent company to make payments, in lieu of issuing fractional shares in connection with share dividends, share splits, reverse share splits, mergers, consolidations, amalgamations or other business combinations and in connection with the exercise of warrants, options or other securities convertible into or exchangeable for equity interests of the Company. At December 31, 2023, restricted net assets of the Company’s consolidated subsidiaries exceeded 25%.Subsequent Event — Debt OfferingOn February 7, 2024, the Company closed an upsized offering (the “Debt Offering”) for the sale of $1,250.0 million in aggregate principal amount of second-priority senior secured notes, consisting of $625.0 million aggregate principal amount of second-priority senior secured notes due 2029 and $625.0 million aggregate principal amount of second-priority senior secured notes due 2031 (collectively, the “New Senior Notes”), in a private offering to eligible purchasers that is exempt from registration under the Securities Act. The net proceeds from the Debt Offering (i) are expected to fund a portion of the cash consideration for the pending QuarterNorth Acquisition, (ii) funded the redemption of all of the outstanding 12.00% Notes and all of the outstanding 11.75% Notes discussed above (the “Redemptions”), and (iii) paid premiums, fees and expenses related to the Redemptions and the issuance of the New Senior Notes. The Company intends to use any remaining net proceeds for general corporate purposes, which may include the repayment of a portion of the outstanding borrowings under the Bank Credit Facility.An aggregate of $340.0 million principal amount of the New Senior Notes will be subject to a “special mandatory redemption” in the event that the transactions contemplated by the QuarterNorth Merger Agreement are not consummated on or before May 31, 2024 (or up to September 30, 2024 solely in the event the parties require additional time to satisfy certain requirements under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, pursuant to the terms of the QuarterNorth Merger Agreement), or if we notify the trustee of the New Senior Notes that we will not pursue the consummation of the QuarterNorth Acquisition.
EnVen Energy Corporation
Debt Instrument [Line Items]
Business Acquisition, Effective Date of Acquisition	Feb. 13, 2023
Minimum
Debt Instrument [Line Items]
Restricted net assets, subsidiaries exceeded							25.00%
11.00% Second-Priority Senior Secured Notes - due April 2022
Debt Instrument [Line Items]
Debt instrument, redemption price, percentage						102.75%
11.75% Senior Secured Second Lien Notes - due April 2026
Debt Instrument [Line Items]
Debt instrument maturity date							Apr. 15, 2026	Apr. 15, 2026
Debt instrument, interest rate, stated percentage							11.75%	11.75%
11.75% Senior Secured Second Lien Notes - due April 2026 | Maximum | Restrictions which limit the payment of dividends
Debt Instrument [Line Items]
Dividends							$ 25,000,000
Percentage of adjusted consolidated net tangible assets							2.50%
7.50% Senior Notes – due May 2022
Debt Instrument [Line Items]
Debt instrument maturity date					May 31, 2022
Debt instrument, interest rate, stated percentage					7.50%
Debt instrument redemption, description								The 7.50% Senior Notes due 2022 matured on May 31, 2022 and were redeemed at an aggregate principal of $6.1 million plus accrued and unpaid interest.
Debt instrument, face amount					$ 6,100,000
12.00% Second-Priority Senior Secured Notes - due January 2026
Debt Instrument [Line Items]
Fixed Charge Coverage Ratio Satisfied With Incurrence Of Additional Indebtedness Amount							$ 1
Date of Second Supplemental Indenture			Oct. 27, 2022
12.00% Second-Priority Senior Secured Notes - due January 2026 | Maximum | Restrictions which limit the payment of dividends
Debt Instrument [Line Items]
Consolidated total debt to EBITDAX ratio							3
Debt instrument fixed charge coverage ratio							2.25
Bank Credit Facility - matures March 2027
Debt Instrument [Line Items]
Credit facility, maximum borrowing capacity							$ 1,075,000,000
Bank credit facility, description							The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter of each year. On December 23, 2022, the Company entered into the Incremental Agreement and Ninth Amendment to Credit Agreement (the “Ninth Amendment”). The Ninth Amendment, among other things, (i) extended the maturity date of the Bank Credit Facility from November 12, 2024 to March 31, 2027, (ii) increased the borrowing base from $1.1 billion to $1.5 billion and (iii) increased commitments from $806.3 million to $965.0 million, in each case went into effect upon the closing of the EnVen Acquisition and the occurrence of certain events related thereto. On June 9, 2023, the borrowing base decreased from $1.5 billion to $1.1 billion and commitments were reaffirmed at $965.0 million as part of the biannual determination.
Percentage of mortgage covering oil and natural gas assets							85.00%
Line of Credit Facility, Commitments							$ 965,000,000
Bank Credit Facility - matures March 2027 | Letter of Credit
Debt Instrument [Line Items]
Line of Credit Facility, Commitments							$ 150,000,000
Bank Credit Facility - matures March 2027 | Adjusted Daily Simple Secured Overnight Financing Rate [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate							0.10%
Bank Credit Facility - matures March 2027 | Base Rate Federal Funds [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate							0.50%
Bank Credit Facility - matures March 2027 | One Month Adjusted Term Secured Overnight Financing Rate [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate							1.00%
Bank Credit Facility - matures March 2027 | Adjusted Term Secured Overnight Financing Rate [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate							0.10%
Bank Credit Facility - matures March 2027 | Minimum
Debt Instrument [Line Items]
Debt instrument covenant current ratio.							1
Bank Credit Facility - matures March 2027 | Maximum
Debt Instrument [Line Items]
Consolidated total debt to EBITDAX ratio							3
Bank Credit Facility - matures March 2027 | Maximum | Letter of Credit
Debt Instrument [Line Items]
Line of Credit Facility, Commitments							$ 250,000,000
Bank Credit Facility
Debt Instrument [Line Items]
Line of credit facility, Dividend restrictions							The Bank Credit Facility restricts distributions and other payments to the Parent Company, subject to certain baskets and other exceptions described therein including the payment of operating expense incurred in the ordinary course of business and for income taxes attributable to its ownership in Talos Production Inc. Under the Bank Credit Facility, general distributions and other restricted payments may be made to the Company so long as after giving pro forma effect to the making of any such restricted payment (i) no default or event of default has occurred and is continuing; (ii) available commitments exceed 25% of the then effective loan limit; (iii) the pro forma current ratio of 1.0 to 1.0 is satisfied; and (iv) either (A) the Consolidated Total Debt to EBITDAX Ratio (as defined in the Bank Credit Facility) is not greater than 1.75 to 1.00 and the aggregate amount of such restricted payments does not exceed the Available Free Cash Flow Amount (as defined in the Bank Credit Facility) at the time made or (B) the Consolidated Total Debt to EBITDAX Ratio is not greater than 1.00 to 1.00.
Line of Credit Facility, Commitments										$ 965,000,000
Bank Credit Facility | Restrictions which limit the payment of dividends
Debt Instrument [Line Items]
Percentage of commitments exceeding the effective loan limit							25.00%
Bank Credit Facility | Pro Forma
Debt Instrument [Line Items]
Debt instrument maturity date		Mar. 31, 2027
Bank Credit Facility | Minimum
Debt Instrument [Line Items]
Credit facility, maximum borrowing capacity										1,100,000,000
Bank Credit Facility | Minimum | Restrictions which limit the payment of dividends
Debt Instrument [Line Items]
Pro Forma Current Ratio							1
Bank Credit Facility | Minimum | Pro Forma
Debt Instrument [Line Items]
Credit facility, maximum borrowing capacity		$ 1,100,000,000
Line of Credit Facility, Commitments		806,300,000
Bank Credit Facility | Maximum
Debt Instrument [Line Items]
Credit facility, maximum borrowing capacity										$ 1,500,000,000
Bank Credit Facility | Maximum | Restrictions which limit the payment of dividends
Debt Instrument [Line Items]
Consolidated total debt to EBITDAX ratio							1
Bank Credit Facility | Maximum | Pro Forma
Debt Instrument [Line Items]
Credit facility, maximum borrowing capacity		1,500,000,000
Line of Credit Facility, Commitments		$ 965,000,000
Bank Credit Facility | Maximum | Restricted payments does not exceed the available free cash flow amount | Restrictions which limit the payment of dividends
Debt Instrument [Line Items]
Consolidated total debt to EBITDAX ratio							1.75
Enven Second Lien Notes
Debt Instrument [Line Items]
Debt instrument maturity date	Apr. 15, 2026
Enven Second Lien Notes | EnVen Energy Corporation
Debt Instrument [Line Items]
Debt instrument, face amount	$ 257,500,000
Level 1 | Term Benchmark Loans and RFR Loan
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate							2.75%
Level 1 | Alternate Base Rate
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate							1.75%
Level 2 | Term Benchmark Loans and RFR Loan
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate							3.00%
Level 2 | Alternate Base Rate
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate							2.00%
Senior Notes | 11.00% Second-Priority Senior Secured Notes - due April 2022
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage						11.00%
Debt instrument, repurchase amount						$ 347,300,000
Senior Notes | 11.00% Second-Priority Senior Secured Notes - due April 2022 | Other Income (Expense)
Debt Instrument [Line Items]
Gain (loss) on extinguishment of debt									$ (13,200,000)
Senior Notes | 11.75% Senior Secured Second Lien Notes - due April 2026
Debt Instrument [Line Items]
Debt instrument maturity date							Apr. 15, 2026	Apr. 15, 2026
Debt instrument frequency of periodic payment	The indenture governing the 11.75% Notes requires the redemption of $15.0 million of the principal amount outstanding at par value on April 15th and October 15th of each year.
Debt instrument, interest rate, stated percentage	11.75%						11.75%	11.75%
Debt instrument redemption, description							The Company may redeem all or a portion of the 11.75% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest if redeemed during the period commencing on February 15 of the years set forth below:
Debt instrument, face amount							$ 227,500,000	$ 0
Senior Notes | 12.00% Second-Priority Senior Secured Notes - due January 2026
Debt Instrument [Line Items]
Debt instrument, redemption price, percentage				12.00%
Debt instrument maturity date							Jan. 15, 2026	Jan. 15, 2026
Debt instrument frequency of periodic payment							semi-annually
Debt instrument payment terms							semi-annually each January 15 and July 15
Debt instrument, interest rate, stated percentage							12.00%	12.00%			12.00%
Debt instrument redemption, description							The Company may redeem all or a portion of the 12.00% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest if redeemed during the period commencing on January 15 of the years set forth below
Debt instrument, face amount							$ 638,541,000	$ 638,541,000
Notes Solicitation Consents Fee Consideration	$ 3,100,000
Debt instrument, repurchase amount								11,500,000
Senior Notes | 12.00% Second-Priority Senior Secured Notes - due January 2026 | Other Income (Expense)
Debt Instrument [Line Items]
Gain (loss) on extinguishment of debt								(1,600,000)
Senior Notes | Enven Second Lien Notes
Debt Instrument [Line Items]
Debt instrument, periodic payment, principal	$ 15,000,000
Line of Credit [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Borrowing Capacity, Description							The Bank Credit Facility provides for the determination of the borrowing base based on the Company’s proved producing reserves and a portion of the Company's proved undeveloped reserves.
Line of Credit [Member] | Bank Credit Facility - matures March 2027
Debt Instrument [Line Items]
Weighted average interest rate							8.26%
Debt instrument, face amount							$ 200,000,000	$ 0
Notes Solicitation Consent [Member] | 12.00% Second-Priority Senior Secured Notes - due January 2026
Debt Instrument [Line Items]
Amount of notes consents received from notes consent solicitation			95.80%
Notes Solicitation Consents Fee Consideration, Basis Points			0.50%
Notes Solicitation Consent Permit Enven Senior Notes Indebtedness | Enven Second Lien Notes | EnVen Energy Corporation
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage				11.75%

XML

Debt - Subsequent Event (Details) - USD ($) $ in Millions						12 Months Ended
	Feb. 07, 2024	Jan. 26, 2024	Jan. 23, 2024	Jan. 13, 2024	Oct. 21, 2022	Dec. 31, 2023	Feb. 13, 2023	Dec. 31, 2022	Jan. 14, 2021
12.00% Second-Priority Senior Secured Notes - due January 2026 | Senior Notes
Debt Instrument [Line Items]
Debt instrument redemption, description						The Company may redeem all or a portion of the 12.00% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest if redeemed during the period commencing on January 15 of the years set forth below
Debt instrument, interest rate, stated percentage						12.00%		12.00%	12.00%
Debt instrument, redemption price, percentage					12.00%
12.00% Second-Priority Senior Secured Notes - due January 2026 | Subsequent Event
Debt Instrument [Line Items]
Debt instrument redemption, description			On January 23, 2024, the Company issued a conditional notice to redeem in full the 12.00% Notes at a redemption price of 103.00% of the principal amount thereof, plus accrued and unpaid interest to, but excluding, the redemption date, in accordance with the 12.00% Notes indenture. The 12.00% Notes were redeemed on February 7, 2024 for $662.4 million utilizing the net proceeds from the Debt Offering (as defined below).
Debt instrument, redemption price, percentage			103.00%
12.00% Second-Priority Senior Secured Notes - due January 2026 | Subsequent Event | Senior Notes
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage			12.00%
12.00% Second-Priority Senior Secured Notes - due February 2023 | Subsequent Event
Debt Instrument [Line Items]
Redemption of Senior secured notes	$ 662.4
Eleven Point Seven Five Percent Senior Secured Second Lien Notes Due April Two Thousand Twenty Six [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage						11.75%		11.75%
Eleven Point Seven Five Percent Senior Secured Second Lien Notes Due April Two Thousand Twenty Six [Member] | Senior Notes
Debt Instrument [Line Items]
Debt instrument redemption, description						The Company may redeem all or a portion of the 11.75% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of principal amount) plus accrued and unpaid interest if redeemed during the period commencing on February 15 of the years set forth below:
Debt instrument, interest rate, stated percentage						11.75%	11.75%	11.75%
Eleven Point Seven Five Percent Senior Secured Second Lien Notes Due April Two Thousand Twenty Six [Member] | Subsequent Event
Debt Instrument [Line Items]
Debt instrument redemption, description		On January 26, 2024, the Company issued a conditional notice to redeem in full the 11.75% Notes at a redemption price of 102.938% of the principal amount thereof, plus accrued and unpaid interest to, but excluding, the redemption date, in accordance with the 11.75% Notes Indenture. The Company irrevocably deposited funds with the trustee sufficient to satisfy and discharge the 11.75% Notes Indenture and the 11.75% Notes until redeemed on April 15, 2024 with the funds deposited with the trustee and elected to satisfy and discharge the 11.75% Notes Indenture in accordance with its terms and the 11.75% Notes trustee acknowledged such discharge and satisfaction. The Company deposited $247.5 million with the trustee on February 7, 2024 utilizing the net proceeds from the Debt Offering.
Debt instrument, redemption price, percentage		102.938%
Funds deposited with trustee	247.5
Eleven Point Seven Five Percent Senior Secured Second Lien Notes Due April Two Thousand Twenty Six [Member] | Subsequent Event | Senior Notes
Debt Instrument [Line Items]
Debt instrument, interest rate, stated percentage		11.75%
Bank Credit Facility - matures March 2027
Debt Instrument [Line Items]
Bank credit facility, description						The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter of each year. On December 23, 2022, the Company entered into the Incremental Agreement and Ninth Amendment to Credit Agreement (the “Ninth Amendment”). The Ninth Amendment, among other things, (i) extended the maturity date of the Bank Credit Facility from November 12, 2024 to March 31, 2027, (ii) increased the borrowing base from $1.1 billion to $1.5 billion and (iii) increased commitments from $806.3 million to $965.0 million, in each case went into effect upon the closing of the EnVen Acquisition and the occurrence of certain events related thereto. On June 9, 2023, the borrowing base decreased from $1.5 billion to $1.1 billion and commitments were reaffirmed at $965.0 million as part of the biannual determination.
Credit facility, maximum borrowing capacity						$ 1,075.0
Bank Credit Facility - matures March 2027 | Subsequent Event
Debt Instrument [Line Items]
Bank credit facility, description				On January 13, 2024, the Company entered into the Tenth Amendment to Credit Agreement (the “Tenth Amendment”). The Tenth Amendment, among other things, (i) permits the incurrence of additional indebtedness in order to fund the QuarterNorth Acquisition, with such indebtedness excluded from any reduction of the borrowing base that would otherwise result from such incurrence, and (ii) reaffirms the borrowing base at $1.1 billion effective upon closing of the QuarterNorth Acquisition.
Bank Credit Facility - matures March 2027 | Subsequent Event | Pro Forma
Debt Instrument [Line Items]
Credit facility, maximum borrowing capacity				$ 1,100.0
Second Priority Senior Secured Notes | Subsequent Event
Debt Instrument [Line Items]
Debt instrument, face amount	1,250.0
Second-Priority Senior Secured Notes Due 2029 | Subsequent Event
Debt Instrument [Line Items]
Debt instrument, face amount	625.0
Second-Priority Senior Secured Notes Due 2031 | Subsequent Event
Debt Instrument [Line Items]
Debt instrument, face amount	625.0
New Senior Notes | Subsequent Event | Debentures Subject to Mandatory Redemption
Debt Instrument [Line Items]
Debt instrument, face amount	$ 340.0

XML

Debt - Summary of Redemption Prices of 12.00% and 11.75% Notes (Details)			12 Months Ended
	Jan. 26, 2024	Jan. 23, 2024	Dec. 31, 2023
12.00% Second-Priority Senior Secured Notes - due January 2026 | Debt Instrument, Redemption, Period Three
Debt Instrument, Redemption [Line Items]
Debt instrument, redemption price, percentage			106.00%
12.00% Second-Priority Senior Secured Notes - due January 2026 | Debt Instrument, Redemption, Period Four
Debt Instrument, Redemption [Line Items]
Debt instrument, redemption price, percentage			103.00%
12.00% Second-Priority Senior Secured Notes - due January 2026 | Debt Instrument, Redemption, Period After Five
Debt Instrument, Redemption [Line Items]
Debt instrument, redemption price, percentage			100.00%
12.00% Second-Priority Senior Secured Notes - due January 2026 | Subsequent Event
Debt Instrument, Redemption [Line Items]
Debt instrument, redemption price, percentage		103.00%
11.75% Senior Secured Second Lien Notes - due April 2026 | Debt Instrument, Redemption, Period Three
Debt Instrument, Redemption [Line Items]
Debt instrument, redemption price, percentage			105.875%
11.75% Senior Secured Second Lien Notes - due April 2026 | Debt Instrument, Redemption, Period Four
Debt Instrument, Redemption [Line Items]
Debt instrument, redemption price, percentage			102.938%
11.75% Senior Secured Second Lien Notes - due April 2026 | Debt Instrument, Redemption, Period After Five
Debt Instrument, Redemption [Line Items]
Debt instrument, redemption price, percentage			100.00%
11.75% Senior Secured Second Lien Notes - due April 2026 | Subsequent Event
Debt Instrument, Redemption [Line Items]
Debt instrument, redemption price, percentage	102.938%

XML

Debt - Schedule of Pricing Grid for Borrowing Base Utilization Percentage (Details)	12 Months Ended
	Dec. 31, 2023
Level 1
Debt Instrument [Line Items]
Commitment fee percentage	0.38%
Level 1 | Term Benchmark Loans and RFR Loan
Debt Instrument [Line Items]
Basis Spread on Variable Rate	2.75%
Level 1 | Alternate Base Rate
Debt Instrument [Line Items]
Basis Spread on Variable Rate	1.75%
Level 2
Debt Instrument [Line Items]
Commitment fee percentage	0.38%
Level 2 | Term Benchmark Loans and RFR Loan
Debt Instrument [Line Items]
Basis Spread on Variable Rate	3.00%
Level 2 | Alternate Base Rate
Debt Instrument [Line Items]
Basis Spread on Variable Rate	2.00%
Level 3
Debt Instrument [Line Items]
Commitment fee percentage	0.50%
Level 3 | Term Benchmark Loans and RFR Loan
Debt Instrument [Line Items]
Basis Spread on Variable Rate	3.25%
Level 3 | Alternate Base Rate
Debt Instrument [Line Items]
Basis Spread on Variable Rate	2.25%
Level 4
Debt Instrument [Line Items]
Commitment fee percentage	0.50%
Level 4 | Term Benchmark Loans and RFR Loan
Debt Instrument [Line Items]
Basis Spread on Variable Rate	3.50%
Level 4 | Alternate Base Rate
Debt Instrument [Line Items]
Basis Spread on Variable Rate	2.50%
Level 5
Debt Instrument [Line Items]
Commitment fee percentage	0.50%
Level 5 | Term Benchmark Loans and RFR Loan
Debt Instrument [Line Items]
Basis Spread on Variable Rate	3.75%
Level 5 | Alternate Base Rate
Debt Instrument [Line Items]
Basis Spread on Variable Rate	2.75%
Maximum [Member] | Level 1
Debt Instrument [Line Items]
Utilization	25.00%
Maximum [Member] | Level 2
Debt Instrument [Line Items]
Utilization	50.00%
Maximum [Member] | Level 3
Debt Instrument [Line Items]
Utilization	75.00%
Maximum [Member] | Level 4
Debt Instrument [Line Items]
Utilization	90.00%
Minimum [Member] | Level 2
Debt Instrument [Line Items]
Utilization	25.00%
Minimum [Member] | Level 3
Debt Instrument [Line Items]
Utilization	50.00%
Minimum [Member] | Level 4
Debt Instrument [Line Items]
Utilization	75.00%
Minimum [Member] | Level 5
Debt Instrument [Line Items]
Utilization	90.00%

XML

Asset Retirement Obligations - Schedule of Asset Retirement Obligations (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligation Disclosure [Abstract]
Balance, beginning of period		$ 541,661	$ 434,006
Obligations assumed	[1]	258,858	0
Obligations incurred		14,199	1,140
Obligations settled		(86,615)	(69,596)
Obligations divested		(19,448)	(1,572)
Accretion expense		86,152	55,995	$ 58,129
Changes in estimate	[2]	102,419	121,688
Balance, end of period		897,226	541,661	$ 434,006
Less: Current portion		77,581	39,888
Long-term portion		$ 819,645	$ 501,773

[1] Assumed in connection with the EnVen Acquisition. See further discussion in Note 3 — Acquisitions and Divestitures.

[2] Changes in estimate were primarily due to an increase in estimated service costs. Additionally, increases for the year ended December 31, 2023 due to the acceleration of estimated settlement date.

XML

Asset Retirement Obligations (Additional Information) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Restricted cash	$ 102,362	$ 0
EnVen Energy Corporation
Receivable with imputed interest, face amount	66,200
Future Plugging and Abanonment Obligations
Restricted cash	$ 102,400

XML

Employee Benefits Plans and Share-Based Compensation - Additional Information (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Mar. 31, 2022	Dec. 31, 2023		Dec. 31, 2022		Dec. 31, 2021	Feb. 13, 2023
Employee Severance [Member] | TALOEnven Energy Corporation [Member]
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Asset, Held-in-Trust		$ 3.7					$ 14.5
Asset, Held-in-Trust, Current		3.3
Asset, Held-in-Trust, Noncurrent		$ 0.4
Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Unvested restricted stock units and award, granted		1,154,541		2,297,465		1,102,038
Share-Based Payment Arrangement, Plan Modification, Incremental Cost		$ 9.7
Performance Shares
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Contingent Right Upon Vesting to Receive Common Stock		1
Share-based compensation expense recognized period		1 year 8 months 12 days
Share-based compensation expense unrecognized		$ 8.7
Unvested restricted stock units and award, granted		595,394	[1]	629,666	[2]	586,995
Performance Shares | Minimum
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Rights, Percentage		0.00%
Performance Shares | Maximum
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Rights, Percentage		200.00%
Executive Officer | Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Unvested restricted stock units and award, granted	1,147,352
Long Term Incentive Plan
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Share-Based Compensation authorized to grant		8,639,415
Long Term Incentive Plan | Performance Shares
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Description of method used to calculate fair value		Monte Carlo simulations
Long Term Incentive Plan | Employees | Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Period		3 years
Contingent Right Upon Vesting to Receive Common Stock		1
Share-based compensation expense recognized period		1 year 8 months 12 days
Share-based compensation expense unrecognized		$ 19.0
Long Term Incentive Plan | Non-employee Directors | Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Period		1 year
Share-based compensation expense recognized period		2 months 12 days
Contingent Right Upon Vesting to Receive Common Stock Percentage		60.00%
Contingent Right Upon Vesting to Receive Cash Percentage		40.00%
Share-based compensation expense liabilities		$ 0.1
Share-based compensation expense unrecognized		$ 0.1

[1] There were 297,697 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute TSR over a three-year performance period. An additional 297,697 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2023 drill program over a three-year performance period.

[2] There were 314,833 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute total shareholder return (“TSR”) over a three-year performance period. An additional 314,833 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2022 drill program over a three-year performance period.

XML

Employee Benefits Plans and Share-Based Compensation - Schedule Of Acquisition Severance Costs (Details) - Taloenven Energy Corporation Member - Employee Severance $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($)
Acquisition Severance Costs Line Items
Severance accrual at December 31, 2022	$ 0
Accrual additions	25,348
Benefit payments	(19,054)
Severance accrual at December 31, 2023	6,294
Less: Current portion at December 31, 2023	6,190
Long-term portion at December 31, 2023	$ 104

XML

Employee Benefits Plans and Share-Based Compensation - Schedule of Restricted Stock and Performance Share Units Activity (Details) - $ / shares	12 Months Ended
	Dec. 31, 2023		Dec. 31, 2022		Dec. 31, 2021
Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Unvested beginning of the period	3,215,504	[1]	1,983,199		1,652,988
Granted	1,154,541		2,297,465		1,102,038
Vested	(1,730,959)		(967,269)		(669,832)
Forfeited	(332,725)		(97,891)		(101,995)
Unvested end of the period	2,306,361	[1]	3,215,504	[1]	1,983,199
Unvested weighted average grant date fair value, beginning of the period	$ 12.79	[1]	$ 13.02		$ 13.73
Unvested weighted average grant date fair value, granted	16.24		13.23		13.11
Unvested weighted average grant date fair value, vested	11.97		14.14		15.01
Unvested weighted average grant date fair value, forfeited	14.52		14.34		12.46
Unvested weighted average grant date fair value, end of the period	$ 14.89	[1]	$ 12.79	[1]	$ 13.02
Performance Shares
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Unvested beginning of the period	638,601		1,015,459		834,172
Granted	595,394	[2]	629,666	[3]	586,995
Vested			(14,474)	[4]	(391,308)
Forfeited	(217,346)		(16,486)		(14,400)
Cancelled			(975,564)
Unvested end of the period	1,016,649		638,601		1,015,459
Unvested weighted average grant date fair value, beginning of the period	$ 23.66		$ 16.41		$ 25.46
Unvested weighted average grant date fair value, granted	18.76	[2]	23.73	[3]	18.96
Unvested weighted average grant date fair value, vested			13.05	[4]	39.43
Unvested weighted average grant date fair value, forfeited	21.28		17.48		18.48
Unvested weighted average grant date fair value, Cancelled			16.42
Unvested weighted average grant date fair value, end of the period	$ 21.3		$ 23.66		$ 16.41

[1] As of December 31, 2023 and 2022, 26,975 and 25,257, respectively, of the unvested RSUs were accounted for as liability awards in “Accrued liabilities” on the Consolidated Balance Sheet.

[2] There were 297,697 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute TSR over a three-year performance period. An additional 297,697 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2023 drill program over a three-year performance period.

[3] There were 314,833 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute total shareholder return (“TSR”) over a three-year performance period. An additional 314,833 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2022 drill program over a three-year performance period.

[4] The performance period for the relative TSR awards ended on December 31, 2022. The payout on these awards was 0% based on actual performance over the performance period as certified by the Compensation Committee of the Company’s Board of Directors in early 2023. Since these awards were legally forfeited they will again be available for new awards under the recycling provisions of the 2021 LTIP.

XML

Employee Benefits Plans and Share-Based Compensation - Schedule of Restricted Stock and Performance Share Units Activity (Parenthetical) (Details) - shares	12 Months Ended
	Dec. 31, 2023		Dec. 31, 2022		Dec. 31, 2021	Dec. 31, 2020
Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Granted	1,154,541		2,297,465		1,102,038
Unvested RSUs	2,306,361	[1]	3,215,504	[1]	1,983,199	1,652,988
Performance Shares
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Granted	595,394	[2]	629,666	[3]	586,995
Unvested RSUs	1,016,649		638,601		1,015,459	834,172
Maximum | Performance Shares
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Rights, Percentage	200.00%
Minimum | Performance Shares
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Rights, Percentage	0.00%
Absolute Total Shareholder Return Award | Performance Shares
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Granted	297,697		314,833
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Period	3 years		3 years
Return On Drilling Program Award
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Share-Based Compensation Arrangement by Share-Based Payment Award, Award Vesting Period	3 years		3 years
Return On Drilling Program Award | Performance Shares
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Granted	297,697		314,833
Relative Total Shareholder Return Award | Performance Shares
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Share based payment payout percentage			0.00%
Accrued Liabilities | Restricted Stock Units
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Unvested RSUs	26,975		25,257

[1] As of December 31, 2023 and 2022, 26,975 and 25,257, respectively, of the unvested RSUs were accounted for as liability awards in “Accrued liabilities” on the Consolidated Balance Sheet.

[2] There were 297,697 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute TSR over a three-year performance period. An additional 297,697 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2023 drill program over a three-year performance period.

[3] There were 314,833 PSUs granted that are eligible to vest based on continued employment and the Company’s annualized absolute total shareholder return (“TSR”) over a three-year performance period. An additional 314,833 PSUs were granted and are eligible to vest based on continued employment and the Company’s return on the wells included in the 2022 drill program over a three-year performance period.

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Employee Benefits Plans and Share-Based Compensation - Summary of Assumptions Used to Calculate the Grant Date Fair Value (Details) - Performance Shares - USD ($) $ in Thousands	Dec. 01, 2023	Jul. 01, 2023	Mar. 05, 2023	Sep. 20, 2022	Mar. 05, 2022	May 11, 2021	Mar. 08, 2021
Grant Date December 1, 2023
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Expected term (in years)	2 years 1 month 6 days
Expected volatility	61.90%
Risk-free interest rate	4.40%
Dividend yield	0.00%
Fair value (in thousands)	$ 12
Grant Date July 1, 2023
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Expected term (in years)		2 years 6 months
Expected volatility		66.20%
Risk-free interest rate		4.60%
Dividend yield		0.00%
Fair value (in thousands)		$ 173
Grant Date March 5, 2023
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Expected term (in years)			2 years 9 months 18 days
Expected volatility			73.10%
Risk-free interest rate			4.50%
Dividend yield			0.00%
Fair value (in thousands)			$ 6,165
Grant Date September 20, 2022
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Expected term (in years)				2 years 3 months 18 days
Expected volatility				74.30%
Risk-free interest rate				3.90%
Dividend yield				0.00%
Fair value (in thousands)				$ 621
Grant Date March 5, 2022
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Expected term (in years)					2 years 9 months 18 days
Expected volatility					82.20%
Risk-free interest rate					1.60%
Dividend yield					0.00%
Fair value (in thousands)					$ 8,668
Grant Date May 11, 2021
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Expected term (in years)						2 years 7 months 6 days
Expected volatility						80.90%
Risk-free interest rate						0.30%
Dividend yield						0.00%
Fair value (in thousands)						$ 9,715
Grant Date March 8, 2021
Share Based Compensation Arrangement By Share Based Payment Award Line Items
Expected term (in years)							2 years 9 months 18 days
Expected volatility							78.30%
Risk-free interest rate							0.30%
Dividend yield							0.00%
Fair value (in thousands)							$ 11,129

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Employee Benefits Plans and Share-Based Compensation - Schedule of Recognized Share Based Compensation Expense, Net (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-Based Payment Arrangement [Abstract]
Share-based compensation costs	$ 25,236	$ 28,280	$ 20,560
Less: Amounts capitalized to oil and gas properties	12,283	12,327	9,568
Share-Based Payment Arrangement, Expense	$ 12,953	$ 15,953	$ 10,992

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Income Taxes - Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Current income tax expense (benefit)
United States	$ 76	$ 1,375	$ (5)
Mexico	31	432	(993)
Total current income tax expense (benefit)	107	1,807	(998)
Deferred income tax expense (benefit)
United States	(60,704)	659	(1,067)
Mexico	0	71	430
Total deferred income tax expense (benefit)	(60,704)	730	(637)
Total income tax expense (benefit)	$ (60,597)	$ 2,537	$ (1,635)

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Income Taxes - Summary of Reconciliation of Income Taxes Computed U.S.Federal Statutory Tax Rate To Income Tax Expense (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Income tax expense (benefit) at the federal statutory tax rate	$ 26,614	$ 80,735	$ (38,763)
State income taxes	1,748	1,591	(674)
Impact of foreign operations	13,539	15,657	(11,920)
Effect of change in state rate	0	0	2,008
Prior year taxes	1,184	(2,920)	486
Change in valuation allowance	(106,815)	(96,537)	45,547
Other permanent differences	3,133	4,011	1,681
Total income tax expense (benefit)	$ (60,597)	$ 2,537	$ (1,635)
Effective tax rate	(47.81%)	0.66%	0.89%

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Income Taxes - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Feb. 13, 2023
Income Tax Disclosure [Line Items]
Federal statutory rate	21.00%	21.00%	21.00%
Income tax benefit (expense)	$ 60,597	$ (2,537)	$ 1,635
Operating loss carryforwards limitation on use	As of December 31, 2023, the Company had U.S. federal net operating loss carryforwards (“NOLs”) of approximately $701.2 million, all of which are subject to limitation under Section 382 of the IRC. IRC Section 382 provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, against future U.S. taxable income in the event of a change in ownership. If not utilized, such carryforwards would begin to expire at the end of 2035.
Valuation allowance	$ 23,697	$ 129,105
Valuation allowance, commentary	In assessing the need for a valuation allowance, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized using available positive and negative evidence, including future reversals of temporary differences, tax-planning strategies and future taxable income, to estimate whether sufficient future taxable income will be generated to permit use of deferred tax assets. A significant piece of objective negative evidence evaluated is the cumulative loss incurred over recent years. Such objective negative evidence limits the Company’s ability to consider other subjective positive evidence.
EnVen Energy Corporation
Income Tax Disclosure [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities				$ 150,264
Earliest Tax Year
Income Tax Disclosure [Line Items]
Income tax examination, Year	2020
Latest Tax Year
Income Tax Disclosure [Line Items]
Income tax examination, Year	2023
Federal
Income Tax Disclosure [Line Items]
Operating loss carryforwards	$ 701,200
State
Income Tax Disclosure [Line Items]
Deferred tax assets, valuation allowance expense (benefit)	$ (106,800)
Internal Revenue Code | Federal | Capital loss carryforward
Income Tax Disclosure [Line Items]
Operating loss carryforwards expiration year	2035

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Income Taxes - Summary of Significant Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Deferred tax assets:
Federal net operating loss	$ 147,252	$ 159,257
Foreign tax loss carryforward	509	44,462
State net operating loss	24,840	24,787
Tax credits	107	107
Interest expense carryforward	46,414	23,262
Asset retirement obligations	190,248	115,848
Derivatives	0	9,273
Other well equipment	1,317	1,891
Accrued bonus	5,050	5,863
Share-based compensation	5,172	5,296
Operating lease liabilities	4,427	3,669
Finance lease liabilities	31,607	32,559
Other	3,383	7,142
Total deferred tax assets	460,326	433,416
Valuation allowance	(23,697)	(129,105)
Total deferred tax assets, net	436,629	304,311
Deferred tax liabilities:
Oil and gas properties	512,918	302,602
Operating lease assets	2,421	1,323
Derivatives	9,670	0
Prepaid	3,847	2,530
Total deferred tax liabilities	528,856	306,455
Net deferred tax liability	$ (92,227)	$ (2,144)

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Income Taxes - Summary of Net Operating Loss Carryovers (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($)
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards limitation on use	As of December 31, 2023, the Company had U.S. federal net operating loss carryforwards (“NOLs”) of approximately $701.2 million, all of which are subject to limitation under Section 382 of the IRC. IRC Section 382 provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, against future U.S. taxable income in the event of a change in ownership. If not utilized, such carryforwards would begin to expire at the end of 2035.
Federal
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 701,200
Federal | Minimum
Operating Loss Carryforwards [Line Items]
Net operating losses, Expiration year	2035
Federal | Maximum
Operating Loss Carryforwards [Line Items]
Net operating losses, Expiration year	2037
Federal | 2035 - 2037
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 452,393
Federal | Unlimited Expiration Year
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 248,807
Operating loss carryforwards limitation on use	Unlimited
Foreign | Minimum
Operating Loss Carryforwards [Line Items]
Net operating losses, Expiration year	2025
Foreign | Maximum
Operating Loss Carryforwards [Line Items]
Net operating losses, Expiration year	2032
Foreign | 2025 - 2032
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 1,696
State | Minimum
Operating Loss Carryforwards [Line Items]
Net operating losses, Expiration year	2025
State | Maximum
Operating Loss Carryforwards [Line Items]
Net operating losses, Expiration year	2037
State | Unlimited Expiration Year
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 277,930
Operating loss carryforwards limitation on use	Unlimited
State | 2025 - 2037
Operating Loss Carryforwards [Line Items]
Net operating losses carryforward, Amount	$ 125,958

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Income Taxes - Summary of Balances In Uncertain Tax Positions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Uncertainties [Abstract]
Total unrecognized tax benefits, beginning balance	$ 835	$ 696	$ 648
Tax positions taken during a prior period	154	100	21
Tax positions taken during the current period	0	39	27
Total unrecognized tax benefits, ending balance	$ 989	$ 835	$ 696

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Income (Loss) Per Share - Summary of Computation of Basic and Diluted Income (Loss) Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Earnings Per Share [Abstract]
Net Income (Loss)	$ 187,332	$ 381,915	$ (182,952)
Weighted average common shares outstanding — basic	119,894	82,454	81,769
Dilutive effect of securities	858	1,229	0
Weighted average common shares outstanding — diluted	120,752	83,683	81,769
Basic	$ 1.56	$ 4.63	$ (2.24)
Diluted	$ 1.55	$ 4.56	$ (2.24)
Anti-dilutive potentially issuable securities excluded from diluted common shares	1,353	865	1,709

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Related Party Transactions - Additional Information (Details) - USD ($) $ in Thousands				1 Months Ended	12 Months Ended
	Feb. 07, 2024	Feb. 13, 2023	Sep. 21, 2022	Aug. 31, 2018	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Jan. 22, 2024
Related Party Transaction [Line Items]
General and administrative expense					$ 158,493	$ 99,754	$ 78,677
Stockholders agreement date					May 10, 2018
Stockholders agreement amendment date					Feb. 24, 2020
Amended restated stockholders agreement termination date		Feb. 13, 2023
Amended restated stockholders agreement date					Mar. 29, 2022
Second Priority Senior Secured Notes | Subsequent Event
Related Party Transaction [Line Items]
Debt Instrument, Face Amount	$ 1,250,000
Franklin or MacKay Shields | Scenario Plan
Related Party Transaction [Line Items]
Registration rights cease, beneficial ownership less than 5%						5.00%
Slim Family
Related Party Transaction [Line Items]
Related party receivable					$ 0
Investment, Identifier [Axis]: Slim Family Office
Related Party Transaction [Line Items]
Debt Instrument, Face Amount	312,500
Secondary Offering Expenses
Related Party Transaction [Line Items]
General and administrative expense					0	$ 0	700
2022 Registration Rights Agreement | Secondary Offering Expenses
Related Party Transaction [Line Items]
General and administrative expense					0
EnVen Energy Corporation
Related Party Transaction [Line Items]
Business Acquisition, Date of Acquisition Agreement			Sep. 21, 2022
Vinson & Elkins L.L.P.
Related Party Transaction [Line Items]
General and administrative expense					3,300	4,800	3,100
Legal fees payable					$ 800	$ 1,300	200
Beneficial Owner | Adage
Related Party Transaction [Line Items]
Stock ownership percentage					2.30%
Beneficial Owner | BainCapitalLpMember
Related Party Transaction [Line Items]
Stock ownership percentage					12.20%
Beneficial Owner | Slim Family
Related Party Transaction [Line Items]
Stock ownership percentage					12.20%
Beneficial Owner | Slim Family | Subsequent Event
Related Party Transaction [Line Items]
Stock ownership percentage								21.90%
Equity Method Investee
Related Party Transaction [Line Items]
Related party receivable					$ 5,500
Nonrelated Party [Member] | Banco Inbursa [Member] | Subsequent Event
Related Party Transaction [Line Items]
advisory fee	$ 2,700
Whistler Energy II Holdco LLC [Member] | Apollo Funds | Whistler Energy II, LLC
Related Party Transaction [Line Items]
Business Acquisition, Date of Acquisition Agreement				Aug. 31, 2018
Whistler Energy II Holdco LLC [Member] | Apollo Funds | Whistler Energy II, LLC | Other Operating (Income) Expense
Related Party Transaction [Line Items]
Gain (Loss) related to decommissioning obligation settlement							$ 4,400

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Commitments and Contingencies - Additional Information (Details) - USD ($) $ in Millions		12 Months Ended
	Mar. 23, 2022	Dec. 31, 2023
Loss Contingencies [Line Items]
Gain (Loss) Related to Litigation Settlement, Total	$ 27.5
EnVen Energy Corporation | Dunwoody [Member] | Other Current Liabilities | Judicial ruling
Loss Contingencies [Line Items]
Litigation settlement, amount awarded to other party		$ 14.3
Surety Bond
Loss Contingencies [Line Items]
Surety performance bonds outstanding		1,400.0
Bank Credit Facility | Letter of Credit
Loss Contingencies [Line Items]
Letters of credit outstanding amount		$ 10.8

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Commitments and Contingencies - Summary of Total Minimum Commitments (Details) $ in Thousands	Dec. 31, 2023 USD ($)
Contractual Obligation [Line Items]
2024	$ 20,290
2025	327
2026	0
2027	0
Thereafter	0
Total	20,617
Vessel Commitments
Contractual Obligation [Line Items]
2024	13,216	[1]
2025	0	[1]
2026	0	[1]
2027	0	[1]
Thereafter	0	[1]
Total	13,216	[1]
Committed Purchase Orders
Contractual Obligation [Line Items]
2024	3,083	[2]
2025	0	[2]
2026	0	[2]
2027	0	[2]
Thereafter	0	[2]
Total	3,083	[2]
Other Commitments
Contractual Obligation [Line Items]
2024	3,991	[3]
2025	327	[3]
2026	0	[3]
2027	0	[3]
Thereafter	0	[3]
Total	$ 4,318	[3]

[1] Includes vessel commitments the Company will utilize for certain Deepwater well intervention, drilling operations and decommissioning activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs.

[2] Includes committed purchase orders to execute planned future drilling activities. These commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will be billed for their working interest share of such costs.

[3] Includes commitments associated with the Company’s CCS Segment relating to an equity funding obligation and payments required under a sequestration agreement.

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Commitments and Contingencies - Summary of Decommissioning Obligations Included in Consolidated Balance Sheets (Details) - Decommissioning Abandonment Obligations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Loss Contingencies [Line Items]
Balance, beginning of period	$ 54,269	$ 24,336	$ 0
Additions	266	8,900	21,056
Changes in estimate	11,613	22,658	0
Reimbursements due from third parties	0	0	3,280
Settlements	(50,584)	(1,625)	0
Balance, end of period	15,564	54,269	24,336
Other Current Liabilities
Loss Contingencies [Line Items]
Less: Current portion	3,280	42,069	3,756
Other Noncurrent Liabilities
Loss Contingencies [Line Items]
Long-term portion	$ 12,284	$ 12,200	$ 20,580

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Segment Information - Additional Information (Details)	12 Months Ended
	Dec. 31, 2023 Segment
Segment Reporting [Abstract]
Number of operating segments	2
Segment reporting, no asset information [true false]	true

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Segment Information- Summary of information by Business Segment (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022		Dec. 31, 2021
Segment Reporting Information Line Items
Revenues from External Customers		$ 1,457,886	$ 1,651,980		$ 1,244,540
Equity in the Net Income (Loss) of Investees Accounted for by the Equity Method		(3,209)	14,222		0
Operating Segments [Member]
Segment Reporting Information Line Items
Revenues from External Customers		1,457,886	1,651,980		1,244,540
Equity in the Net Income (Loss) of Investees Accounted for by the Equity Method		(12,108)	(1,065)		0
Adjusted EBITDA		956,846	847,054		611,016
Segment Expenditures		774,630	455,452		338,822
Operating Segments [Member] | Upstream
Segment Reporting Information Line Items
Revenues from External Customers		1,457,886	1,651,980		1,244,540
Equity in the Net Income (Loss) of Investees Accounted for by the Equity Method		120	101		0
Adjusted EBITDA		979,729	859,840		615,798
Segment Expenditures		733,669	452,674		338,822
Operating Segments [Member] | All Other
Segment Reporting Information Line Items
Revenues from External Customers	[1]	0	0		0
Equity in the Net Income (Loss) of Investees Accounted for by the Equity Method		(12,228)	(1,166)	[1]	0	[1]
Adjusted EBITDA		(22,883)	(12,786)	[1]	(4,782)	[1]
Segment Expenditures	[1]	$ 40,961	$ 2,778		$ 0

[1] The CCS Segment is included in the “All Other” category. The CCS Segment is an emerging business in the start-up phase of operations and the business that does not currently generate any revenues. The CCS Segment’s business activities are conducted through both wholly owned subsidiaries and equity method investments with industry partners. Equity method investments is a business strategy that enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed.

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Segment Information - Schedule of Reconciliation of Reportable Segment Information to the Company's Consolidated Totals (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022		Dec. 31, 2021
Segment Reporting Information Line Items
General and Administrative Expense		$ 158,493	$ 99,754		$ 78,677
Interest expense		(173,145)	(125,498)		(133,138)
Depreciation, depletion and amortization		(663,534)	(414,630)		(395,994)
Write-down of oil and natural gas properties		0	0		18,123
Derivative fair value gain (loss)		80,928	(272,191)		(419,077)
Gain (loss) on extinguishment of debt		0	(1,569)		(13,225)
Non-cash equity-based compensation expense		12,953	15,953		10,992
Income (loss) before income taxes		126,735	384,452		(184,587)
Operating Segments
Segment Reporting Information Line Items
Adjusted EBITDA		956,846	847,054		611,016
Segment Reconciling Items
Segment Reporting Information Line Items
Interest expense		(173,145)	(125,498)		(133,138)
Depreciation, depletion and amortization		(663,534)	(414,630)		(395,994)
Accretion expense		(86,152)	(55,995)		(58,129)
Write-down of oil and natural gas properties		0	0		(18,123)
Transaction and other (income) expenses	[1]	33,295	34,513		(5,886)
Decommissioning Obligations	[2]	(11,879)	(31,558)		(21,055)
Derivative fair value gain (loss)	[3]	80,928	(272,191)		(419,077)
Net cash (received) paid on settled derivative instruments	[3]	9,457	425,559		290,164
Gain (loss) on extinguishment of debt		0	(1,569)		(13,225)
Non-cash write-down of other well equipment		0	0		(5,606)
Non-cash equity-based compensation expense		(12,953)	(15,953)		(10,992)
Corporate Non Segment
Segment Reporting Information Line Items
General and Administrative Expense		(6,128)	(5,280)		(4,542)
Reportable segment | Operating Segments
Segment Reporting Information Line Items
Adjusted EBITDA		979,729	859,840		615,798
All Other | Operating Segments
Segment Reporting Information Line Items
Adjusted EBITDA		$ (22,883)	$ (12,786)	[4]	$ (4,782)	[4]

[1] Transaction expenses includes $40.4 million and $9.0 million in costs related to the EnVen Acquisition, inclusive of $25.3 million and nil in severance expense for the years ended December 31, 2023 and 2022, respectively. See further discussion in Note 3 — Acquisition and Divestitures and Note 10 — Employee Benefits Plans and Share-Based Compensation. Other income (expense) includes other miscellaneous income and expenses that the Company does not view as a meaningful indicator of its operating performance. For the year ended December 31, 2023, the amount includes a $66.2 million gain on the Mexico Divestiture. See further discussion in Note 3 — Acquisitions and Divestitures. The amount includes a gain on the funding of the capital carry of the Company’s investment in Bayou Bend by Chevron of $8.6 million and $1.4 million for the year ended December 31, 2023 and 2022, respectively. Additionally, it includes a $13.9 million gain on the partial sale of its investment in Bayou Bend to Chevron for the year ended December 31, 2022. See further discussion in Note 7 — Equity Method Investments. For the year ended December 31, 2022, the amount includes $27.5 million gain as a result of the settlement agreement to resolve previously pending litigation that was filed in October 2017 that is further discussed in Note 14 — Commitments and Contingencies.

[2] Estimated decommissioning obligations were a result of working interest partners or counterparties of divestiture transactions that were unable to perform the required abandonment obligations due to bankruptcy or insolvency. See Note 14 — Commitments and Contingencies for additional information on decommissioning obligations.

[3] The adjustments for the derivative fair value (gains) losses and net cash receipts (payments) on settled commodity derivative instruments have the effect of adjusting net loss for changes in the fair value of derivative instruments, which are recognized at the end of each accounting period because the Company does not designate commodity derivative instruments as accounting hedges. This results in reflecting commodity derivative gains and losses within Adjusted EBITDA on an unrealized basis during the period the derivatives settled.

[4] The CCS Segment is included in the “All Other” category. The CCS Segment is an emerging business in the start-up phase of operations and the business that does not currently generate any revenues. The CCS Segment’s business activities are conducted through both wholly owned subsidiaries and equity method investments with industry partners. Equity method investments is a business strategy that enables us to achieve favorable economies of scale relative to the level of investment and business risk assumed.

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Segment Information - Schedule of Reconciliation of Reportable Segment Information to the Company's Consolidated Totals (Details) (Parenthetical) - USD ($) $ in Millions		12 Months Ended
	Mar. 23, 2022	Dec. 31, 2023	Dec. 31, 2022
Segment Reporting Information Line Items
Gain (Loss) Related to Litigation Settlement, Total	$ 27.5
Employee Severance | EnVen Energy Corporation
Segment Reporting Information Line Items
Aquisition severance cost		$ 25.3
Operating Segments
Segment Reporting Information Line Items
Gain (Loss) Related to Litigation Settlement, Total			$ 27.5
Operating Segments | Bayou Bend
Segment Reporting Information Line Items
Gain on partial disposal of investment			13.9
Operating Segments | Capital Carry | Bayou Bend
Segment Reporting Information Line Items
Gain on partial disposal of investment		8.6	1.4
Operating Segments | Talos Mexico
Segment Reporting Information Line Items
Disposal group, not discontinued operation, gain (loss) on disposal		66.2
Operating Segments | EnVen Energy Corporation
Segment Reporting Information Line Items
Transaction and other income (expenses)		40.4	9.0
Operating Segments | Employee Severance | EnVen Energy Corporation
Segment Reporting Information Line Items
Aquisition severance cost		$ 25.3	$ 0.0

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Segment Information - Reconciliation of Reportable Segment Expenditures (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information Line Items
Plugging & abandonment	$ 86,615	$ 69,596	$ 67,988
Other deferred payments	(1,545)	0	(7,921)
Exploration, development and other capital expenditures	561,434	323,164	293,331
Operating Segments | Reportable segment
Segment Reporting Information Line Items
Segment Expenditures	733,669	452,674	338,822
Operating Segments | All Other
Segment Reporting Information Line Items
Segment Expenditures	40,961	2,778	0
Segment Reconciling Items
Segment Reporting Information Line Items
Change in capital expenditures included in accounts payable and accrued liabilities	(9,199)	(60,011)	28,258
Plugging & abandonment	(86,615)	(69,596)	(67,988)
Decommissioning obligations settled	(50,584)	(1,625)	0
Investment in CCS intangibles and equity method investees	(40,946)	(2,778)	0
Other deferred payments	(1,545)	0	(7,921)
Insurance recovery proceeds	2,802	0	0
Non-cash well equipment transfers	(27,731)	(6)	1,086
Other	$ 622	$ 1,728	$ 1,074

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Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Capitalized Costs Related to Oil, Natural Gas and NGL Activities and Related Accumulated Depletion and Amortization (Details) $ in Thousands	Dec. 31, 2023 USD ($) $ / Boe	Dec. 31, 2022 USD ($) $ / Boe	Dec. 31, 2021 USD ($) $ / Boe
Reserve Quantities [Line Items]
Proved properties	$ 7,906,295	$ 5,964,340
Unproved oil and gas properties, not subject to amortization	268,315	154,783
Consolidated Entities [Member]
Reserve Quantities [Line Items]
Proved properties	7,906,295	5,964,340	$ 5,232,480
Unproved oil and gas properties, not subject to amortization	268,315	154,783	219,055
Total oil and gas properties	8,174,610	6,119,123	5,451,535
Less: Accumulated depletion	4,143,491	3,484,590	3,072,907
Net capitalized costs	$ 4,031,119	$ 2,634,533	$ 2,378,628
Depletion and amortization rate (Per Boe) | $ / Boe	27.23	18.95	16.71
Equity Method Investee [Member]
Reserve Quantities [Line Items]
Unproved oil and gas properties, not subject to amortization	$ 56,579	$ 0	$ 0

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Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Capitalized Costs Related to Oil, Natural Gas and NGL Activities and Related Accumulated Depletion and Amortization (Parenthetical) (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items]
Unproved properties, not subject to amortization	$ 268,315	$ 154,783
Mexico
Capitalized Costs Relating To Oil And Gas Producing Activities By Geographic Area [Line Items]
Unproved properties, not subject to amortization		$ 111,400	$ 110,300

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Supplemental Oil and Gas Disclosures (Unaudited) - Additional Information (Details)	12 Months Ended
	Dec. 31, 2023 MMBoe $ / Mcf $ / bbl	Dec. 31, 2022 MMBoe $ / Mcf $ / bbl	Dec. 31, 2021 MMBoe $ / Mcf $ / bbl
Reserve Quantities [Line Items]
Audited percentage of proved oil, natural gas and NGL reserves attributable to all of oil and natural gas properties	100.00%	100.00%	100.00%
Proved Developed and Undeveloped Reserve, Net (Energy), Period Increase (Decrease)	12.2	(21)	(1.4)
Sales of reserves		1.4
Decrease of production	24.2	21.7	23.5
Revision to previous estimates	(18.1)	(9)	20.3
Estimated proved reserves from extensions and discoveries	5.4	11.2	1.8
Prescribed rate of discounted future net cash flows	10.00%
Oil (MBbls)
Reserve Quantities [Line Items]
SEC pricing | $ / bbl	78.56	96.03	67.14
Gas (MMcf)
Reserve Quantities [Line Items]
SEC pricing | $ / Mcf	2.75	6.80	3.71
EnVen Energy Corporation
Reserve Quantities [Line Items]
Purchase of reserve	49.1
Pricing and Well Performance [Member]
Reserve Quantities [Line Items]
Revision to previous estimates	(13.5)
SEC Pricing [Member] | Oil (MBbls)
Reserve Quantities [Line Items]
SEC pricing | $ / bbl	(17.47)
SEC Pricing [Member] | Gas (MMcf)
Reserve Quantities [Line Items]
SEC pricing | $ / Mcf	(4.05)

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Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Costs Incurred in Oil, Natural Gas and NGL Property Acquisition, Exploration and Development Activities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Equity Method Investee [Member]
Property acquisition costs:
Exploration costs	$ 290	$ 0	$ 0
Consolidated Entities [Member]
Property acquisition costs:
Proved properties	951,703	0	210
Unproved properties, not subject to amortization	249,688	2,221	0
Total property acquisition costs	1,201,391	2,221	210
Exploration costs	161,296	125,889	23,844
Development costs	805,148	541,512	245,058
Total costs incurred	$ 2,167,835	$ 669,622	$ 269,112

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Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Costs Incurred in Oil, Natural Gas and NGL Property Acquisition, Exploration and Development Activities (Parenthetical) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Mexico
Costs Incurred Oil And Gas Property Acquisition Exploration And Development Activities [Line Items]
Exploration costs	$ 0.0	$ 1.2	$ 6.6

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Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Estimated Proved Reserves at Net Ownership Interest (Details)	12 Months Ended
	Dec. 31, 2023 MBoe MMBoe MMBbls MMcf	Dec. 31, 2022 MBoe MMBoe MMBbls MMcf	Dec. 31, 2021 MBoe MMBoe MMBbls MMcf
Reserve Quantities [Line Items]
Revision to previous estimates | MMBoe	(18.1)	(9)	20.3
Production | MMBoe	(24.2)	(21.7)	(23.5)
Sales of reserves | MMBoe		(1.4)
Extensions and discoveries | MMBoe	5.4	11.2	1.8
Oil (MBbls)
Reserve Quantities [Line Items]
Total proved reserves, beginning balance	91,059	107,764	109,307
Revision of previous estimates	(6,308)	(5,625)	13,619
Production	(18,062)	(14,561)	(16,159)
Sales of reserves		(158)
Purchases of reserves	41,871
Extensions and discoveries	2,255	3,639	997
Total proved reserves, ending balance	110,815	91,059	107,764
Total proved developed reserves	98,225	80,285	93,420
Total proved undeveloped reserves	12,590	10,774	14,344
Gas (MMcf)
Reserve Quantities [Line Items]
Total proved reserves, beginning balance | MMcf	219,551	236,353	257,208
Revision of previous estimates | MMcf	(62,946)	(8,302)	8,979
Production | MMcf	(26,194)	(32,215)	(32,795)
Sales of reserves | MMcf		(7,625)
Purchases of reserves	36,690
Extensions and discoveries | MMcf	12,770	31,340	2,961
Total proved reserves, ending balance | MMcf	179,871	219,551	236,353
Total proved developed reserves | MMcf	141,823	161,727	186,442
Total proved undeveloped reserves | MMcf	38,048	57,824	49,911
NGL (MBbls)
Reserve Quantities [Line Items]
Total proved reserves, beginning balance	12,928	14,435	10,858
Revision of previous estimates	(1,283)	(2,002)	5,137
Production	(1,767)	(1,793)	(1,875)
Sales of reserves		0
Purchases of reserves	1,116
Extensions and discoveries	979	2,288	315
Total proved reserves, ending balance	11,973	12,928	14,435
Total proved developed reserves	9,957	9,315	11,792
Total proved undeveloped reserves	2,016	3,613	2,643
Oil Equivalent (MBoe)
Reserve Quantities [Line Items]
Purchases of reserves	49,102
Total proved reserves, beginning balance | MBoe	140,579	161,591	163,033
Revision to previous estimates | MBoe	(18,082)	(9,010)	20,252
Production | MBoe	(24,195)	(21,723)	(23,500)
Sales of reserves | MBoe		(1,429)
Extensions and discoveries | MBoe	5,362	11,150	1,806
Total proved reserves, ending balance | MBoe	152,766	140,579	161,591
Total proved developed reserves | MBoe	131,819	116,555	136,286
Total proved undeveloped reserves | MBoe	20,947	24,024	25,305

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Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Standardized Measure of Discounted Future Net Cash Flows Related to Interest in Proved Oil, Natural Gas and NGL Reserves (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Extractive Industries [Abstract]
Future cash inflows	$ 9,425,055	$ 10,674,896	$ 8,496,005
Future costs:
Production	(3,090,491)	(1,906,752)	(1,868,818)
Development and abandonment	(2,358,368)	(1,873,453)	(1,422,507)
Future net cash flows before income taxes	3,976,196	6,894,691	5,204,680
Future income tax expense	(589,413)	(1,114,409)	(676,778)
Future net cash flows after income taxes	3,386,783	5,780,282	4,527,902
Discount at 10% annual rate	(343,295)	(1,411,834)	(1,087,291)
Standardized measure of discounted future net cash flows	$ 3,043,488	$ 4,368,448	$ 3,440,611	$ 1,904,934

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Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Base Prices Used in Determining Standardized Measure (Details)	12 Months Ended
	Dec. 31, 2023 $ / bbl $ / Mcf	Dec. 31, 2022 $ / Mcf $ / bbl	Dec. 31, 2021 $ / Mcf $ / bbl
Oil
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
SEC pricing	78.56	96.03	67.14
Natural Gas
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
SEC pricing | $ / Mcf	2.75	6.80	3.71
NGL
Discounted Future Net Cash Flows Relating To Proved Oil And Gas Reserves [Line Items]
SEC pricing	18.77	33.89	26.62

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Supplemental Oil and Gas Disclosures (Unaudited) - Schedule of Principal Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Extractive Industries [Abstract]
Standardized measure, beginning of year	$ 4,368,448	$ 3,440,611	$ 1,904,934
Sales and transfers of oil, net gas and NGLs produced during the period	(1,065,814)	(1,340,400)	(957,576)
Net change in prices and production costs	(2,835,125)	2,388,442	2,049,980
Changes in estimated future development and abandonment costs	(19,877)	(84,391)	(57,876)
Previously estimated development and abandonment costs incurred	202,503	20,107	69,125
Accretion of discount	518,110	392,600	199,849
Net change in income taxes	357,321	(327,265)	(391,834)
Purchases of reserves	2,033,852	0	0
Sales of reserves	0	(5,218)	0
Extensions and discoveries	90,244	202,239	45,485
Net change due to revision in quantity estimates	(484,423)	(255,743)	426,357
Changes in production rates (timing) and other	(121,751)	(62,534)	152,167
Standardized measure, end of year	$ 3,043,488	$ 4,368,448	$ 3,440,611

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Subsequent Events (Details) - Subsequent Event [Member] - QuarterNorth Energy, Inc. [Member] - Underwritten Public Offering [Member] $ in Millions	Jan. 22, 2024 USD ($) shares
Subsequent Event [Line Items]
Share of common stock | shares	34,500,000
Net proceeds after deducting underwriting discounts and commissions | $	$ 388.5

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Schedule I - Balance Sheets (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Accounts receivable
Other, net	$ 19,296	$ 6,684
Prepaid assets	64,387	84,759
Other current assets	10,389	1,917
Total current assets	422,175	367,829
Other long-term assets:
Investments in subsidiaries	146,049	1,745
Total assets	4,816,309	3,058,626
Current liabilities:
Accounts payable	84,193	128,174
Accrued liabilities	227,690	219,769
Other current liabilities	48,769	60,359
Total current liabilities	578,615	607,058
Long-term liabilities:
Other long-term liabilities	251,278	176,152
Total liabilities	2,661,158	1,893,050
Commitments and contingencies
Stockholdersʼ Equity:
Preferred stock; $0.01 par value; 30,000,000 shares authorized and zero shares issued or outstanding as of December 31, 2023 and 2022, respectively	0	0
Common stock; $0.01 par value; 270,000,000 shares authorized; 127,480,361 and 82,570,328 shares issued as of December 31, 2023 and 2022, respectively	1,275	826
Additional paid-in capital	2,549,097	1,699,799
Accumulated deficit	(347,717)	(535,049)
Treasury stock, at cost; 3,400,000 and zero shares as of December 31, 2023 and 2022, respectively	(47,504)	0
Total stockholdersʼ equity	2,155,151	1,165,576	$ 760,653	$ 926,601
Total liabilities and stockholdersʼ equity	4,816,309	3,058,626
Parent
Accounts receivable
Other, net	100	0
Prepaid assets	221	169
Other current assets	19	36
Total current assets	340	205
Other long-term assets:
Investments in subsidiaries	2,246,908	1,168,053
Total assets	2,247,248	1,168,258
Current liabilities:
Accounts payable	316	249
Accrued liabilities	705	728
Other current liabilities	124	62
Total current liabilities	1,145	1,039
Long-term liabilities:
Other long-term liabilities	90,952	1,643
Total liabilities	92,097	2,682
Commitments and contingencies
Stockholdersʼ Equity:
Preferred stock; $0.01 par value; 30,000,000 shares authorized and zero shares issued or outstanding as of December 31, 2023 and 2022, respectively	0	0
Common stock; $0.01 par value; 270,000,000 shares authorized; 127,480,361 and 82,570,328 shares issued as of December 31, 2023 and 2022, respectively	1,275	826
Additional paid-in capital	2,549,097	1,699,799
Accumulated deficit	(347,717)	(535,049)
Treasury stock, at cost; 3,400,000 and zero shares as of December 31, 2023 and 2022, respectively	(47,504)	0
Total stockholdersʼ equity	2,155,151	1,165,576
Total liabilities and stockholdersʼ equity	$ 2,247,248	$ 1,168,258

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Schedule I - Balance Sheets (Details) (Paranthetical) - $ / shares	Dec. 31, 2023	Dec. 31, 2022
Condensed Balance Sheet Statements, Captions [Line Items]
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Preferred Stock, Shares Authorized	30,000,000	30,000,000
Preferred Stock, Shares Issued	0	0
Preferred Stock, Shares Outstanding	0	0
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common Stock, Shares Authorized	270,000,000	270,000,000
Common Stock, Shares, Issued	127,480,361	82,570,328
Treasury stock, common, shares	3,400,000	0
Parent Company [Member]
Condensed Balance Sheet Statements, Captions [Line Items]
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Preferred Stock, Shares Authorized	30,000,000	30,000,000
Preferred Stock, Shares Issued	0	0
Preferred Stock, Shares Outstanding	0	0
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common Stock, Shares Authorized	270,000,000	270,000,000
Common Stock, Shares, Issued	127,480,361	82,570,328
Treasury stock, common, shares	3,400,000	0

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Schedule I - Statements of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenues [Abstract]
Total revenues	$ 1,457,886	$ 1,651,980	$ 1,244,540
Operating Expenses [Abstract]
Lease operating expense	389,621	308,092	283,601
Production taxes	2,451	3,488	3,363
Depreciation, depletion and amortization	663,534	414,630	395,994
Accretion expense	86,152	55,995	58,129
General and administrative expense	158,493	99,754	78,677
Other operating (income) expense	52,155	(33,902)	(32,037)
Total operating expenses	(1,248,096)	(915,861)	(869,924)
Operating income (expense)	209,790	736,119	374,616
Interest expense	(173,145)	(125,498)	(133,138)
Price risk management activities income (expense)	80,928	(272,191)	(419,077)
Equity method investment income (expense)	(3,209)	14,222	0
Other income (expense)	12,371	31,800	(6,988)
Net income (loss) before income taxes	126,735	384,452	(184,587)
Income tax benefit (expense)	60,597	(2,537)	1,635
Net income (loss)	187,332	381,915	(182,952)
Parent
Revenues [Abstract]
Total revenues	0	0	0
Operating Expenses [Abstract]
Lease operating expense	0	0	0
Production taxes	0	0	0
Depreciation, depletion and amortization	0	0	0
Accretion expense	0	0	0
General and administrative expense	2,708	2,145	1,322
Other operating (income) expense	0	0	0
Total operating expenses	2,708	2,145	1,322
Operating income (expense)	(2,708)	(2,145)	(1,322)
Interest expense	0	0	(5)
Price risk management activities income (expense)	0	0	0
Equity method investment income (expense)	0	0	0
Other income (expense)	(1)	(1)	(2)
Equity earnings (loss) from subsidiaries	128,888	385,968	(180,548)
Net income (loss) before income taxes	126,179	383,822	(181,877)
Income tax benefit (expense)	61,153	(1,907)	(1,075)
Net income (loss)	187,332	381,915	(182,952)
Oil
Revenues [Abstract]
Revenues	1,357,732	1,365,148	1,064,161
Oil | Parent
Revenues [Abstract]
Revenues	0	0	0
Natural Gas
Revenues [Abstract]
Revenues	68,034	227,306	130,616
Natural Gas | Parent
Revenues [Abstract]
Revenues	0	0	0
NGL
Revenues [Abstract]
Revenues	32,120	59,526	49,763
NGL | Parent
Revenues [Abstract]
Revenues	$ 0	$ 0	$ 0

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Schedule I - Statements of Cash Flows (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Cash flows from operating activities:
Net cash provided used in operating activities	$ 519,069	$ 709,739	$ 411,388
Cash flows from investing activities:
Net cash provided by (used in) investing activities	(512,626)	(311,977)	(293,747)
Cash flows from financing activities:
Purchase of treasury stock	(47,504)	0	0
Net cash provided by (used in) financing activities	85,411	(423,469)	(82,022)
Net increase (decrease) in cash, cash equivalents and restricted cash	91,854	(25,707)	35,619
Cash, cash equivalents and restricted cash:
Balance, beginning of period	44,145	69,852	34,233
Balance, end of period	135,999	44,145	69,852
Parent
Cash flows from operating activities:
Net cash provided used in operating activities	(1,836)	(809)	(876)
Cash flows from investing activities:
Distributions from subsidiaries	49,340	809	879
Contributions to Subsidiaries	0	0	(3)
Net cash provided by (used in) investing activities	49,340	809	876
Cash flows from financing activities:
Purchase of treasury stock	(47,504)	0	0
Net cash provided by (used in) financing activities	(47,504)	0	0
Net increase (decrease) in cash, cash equivalents and restricted cash	0	0	0
Cash, cash equivalents and restricted cash:
Balance, beginning of period	0	0	0
Balance, end of period	$ 0	$ 0	$ 0