10-Q

Three Months Ended March 31,

Depreciation, depletion and amortization

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended March 31, 2026


☐	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

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, a 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 is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

As of April 28, 2026, the registrant had 166,925,818 shares of common stock, $0.01 par value per share, outstanding.

Table of Contents

TABLE OF CONTENTS


		Page
GLOSSARY		3
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		5
	PART I — FINANCIAL INFORMATION
Item 1.	Financial Statements	7
	Condensed Consolidated Balance Sheets	7
	Condensed Consolidated Statements of Operations	8
	Condensed Consolidated Statements of Changes in Stockholders’ Equity	9
	Condensed Consolidated Statements of Cash Flows	10
	Notes to Condensed Consolidated Financial Statements	11
	Note 1 — Organization, Nature of Business and Basis of Presentation	11
	Note 2 — Acquisitions and Divestitures	12
	Note 3 — Property, Plant and Equipment	12
	Note 4 — Leases	12
	Note 5 — Financial Instruments	13
	Note 6 — Equity Method Investments	15
	Note 7 — Debt	15
	Note 8 — Asset Retirement Obligations	16
	Note 9 — Employee Benefits Plans and Share-Based Compensation	17
	Note 10 — Income Taxes	17
	Note 11 — Income (Loss) Per Share	18
	Note 12 — Related Party Transactions	18
	Note 13 — Commitments and Contingencies	19
	Note 14 — Segment Information	20
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	31
Item 4.	Controls and Procedures	31
	PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	32
Item 1A.	Risk Factors	32
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	32
Item 3.	Defaults Upon Senior Securities	32
Item 4.	Mine Safety Disclosures	32
Item 5.	Other Information	32
Item 6.	Exhibits	33
	Signatures	35

Table of Contents

GLOSSARY

The following are abbreviations and definitions of certain terms commonly used in the oil and natural gas industry and frequently used in our periodic reports filed with the U.S. Securities and Exchange Commission:

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.

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

Deepwater — Water depths of more than 600 feet.

Developed acres — Acreage that is allocated or assignable to producing wells or wells capable of production.

Dry well — An exploratory or development well that is not a productive well.

DOI — U.S. Department of Interior.

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.

MBopd — One thousand barrels of oil 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.

Table of Contents

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, discounted at 10% annually, of estimated future revenues to be generated from the production of proved reserves determined in accordance with SEC guidelines, net of estimated production costs, future development costs, and abandonment 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 costs, production costs, abandonment costs, 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%.

Table of Contents

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

The information in this Quarterly Report on Form 10-Q (this “Quarterly 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 Quarterly 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 Quarterly Report, the words “will,” “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “potential,” “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. Examples of forward-looking statements include, but are not limited to, statements about:

•

business strategy;

•

estimated or recoverable resources and reserves;

•

drilling prospects, inventories, projects and programs;

•

our ability to replace the reserves that we produce through drilling, acquisitions, recompletions or enhanced recovery;

•

financial strategy, borrowing base under our credit agreement, availability of financing sources, including availability under our credit facility, liquidity position and capital required for our development program, acquisitions and other capital expenditures;

•

realized oil and natural gas prices;

•

changes in tariffs, trade barriers, price and exchange controls and other regulatory requirements including such changes that may be implemented by the current or future administrations or foreign governments, and the impact of such policies on us, our customers and suppliers and the global economic environment;

•

volatility in the political, legal and regulatory environments where we currently or in the future may operate;

•

risks related to future mergers and acquisitions, including the risk that we may fail to realize the expected benefits of any such transaction;

•

timing, restrictions and amount of future production of oil, natural gas and NGLs, including changes in supply caused by OPEC or the war in Iran and any related impact on global oil prices, available resources, and domestic oil production;

•

our hedging strategy and results;

•

future drilling plans;

•

availability of pipeline connections and other infrastructure on economic terms;

•

competition, government regulations, including financial assurance requirements, 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 and the anticipated post-acquisition performance of the Company;

•

future leasehold or business acquisitions on desired terms;

•

costs of developing, acquiring or abandoning 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;

•

estimates of future income taxes;

Table of Contents

•

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

•

our strategy, timeline and results with respect to our minority investment in the Zama asset;

•

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

•

anticipated capital efficiency, margin enhancement and organizational improvements and additional cash flow;

•

our ability to obtain surety bonds on commercially reasonable terms; expected collateral requirements under existing or future surety agreements and market factors impacting the availability of surety bonds;

•

the amount of collateral required to be posted from time to time in our hedging transactions, letters of credit, surety bonds and other secured debt;

•

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

•

plans, objectives, expectations and intentions contained in this Quarterly 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; foreign wars and conflicts, including the lack of a resolution to the war in Ukraine and ongoing hostilities in Israel and the Middle East, such as the war in Iran, and their impact on commodity markets; the impact of any pandemic and governmental measures related thereto; lack of necessary infrastructure, transportation and storage capacity as a result of oversupply, government and regulations; political risks, including a global trade war or the impact of any prolonged federal government shutdown or lapse in federal appropriations that could disrupt our operations and future drilling plans and opportunities; lack of availability of drilling and production equipment and services; adverse weather events, including tropical storms, hurricanes, winter storms and loop currents; cybersecurity threats and incidents; elevated 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 and future discoveries and prospects; geologic risk; drilling and other operating risks; well control risk; regulatory changes, including the impact of financial assurance requirements; changes in U.S. trade and labor policies, including the imposition of increased tariffs and the resulting consequences; 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; and the other risks discussed in Part I, Item 1A. “Risk Factors” of Talos Energy Inc.’s Annual Report on Form 10-K for the year ended December 31, 2025 (the “2025 Annual Report”) and Part II, Item 1A. “Risk Factors” of this Quarterly Report.

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 used by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions upward or downward 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 Quarterly 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 Quarterly Report.

Table of Contents

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

TALOS ENERGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share amounts)


	March 31, 2026			December 31, 2025
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	386,367		$	362,809
Accounts receivable, net		341,329			323,058
Assets from price risk management activities		21,748			54,420
Prepaid assets		80,748			83,080
Other current assets		17,277			17,939
Total current assets		847,469			841,306
Property and equipment:
Proved properties		10,760,143			10,621,012
Unproved properties, not subject to amortization		468,673			480,555
Other property and equipment		22,669			22,643
Total property and equipment		11,251,485			11,124,210
Accumulated depreciation, depletion and amortization		(7,061,977	)		(6,686,575	)
Total property and equipment, net		4,189,508			4,437,635
Other long-term assets:
Restricted cash		76,586			76,181
Assets from price risk management activities		4,299			—
Equity method investments		44,774			112,382
Other well equipment		47,937			49,307
Notes receivable, net		20,138			19,636
Operating lease assets		8,703			9,214
Other assets		33,306			6,396
Total assets	$	5,272,720		$	5,552,057
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	108,697		$	92,979
Accrued liabilities		205,090			290,223
Accrued royalties		73,528			59,768
Current portion of asset retirement obligations		112,962			112,489
Liabilities from price risk management activities		127,180			6,708
Accrued interest payable		20,140			48,972
Current portion of operating lease liabilities		3,699			3,657
Other current liabilities		55,670			29,925
Total current liabilities		706,966			644,721
Long-term liabilities:
Long-term debt		1,227,461			1,226,189
Asset retirement obligations		1,252,059			1,219,639
Liabilities from price risk management activities		2,232			—
Operating lease liabilities		10,992			11,956
Other long-term liabilities		198,191			281,429
Total liabilities		3,397,901			3,383,934
Commitments and contingencies (Note 13)
Equity:
Talos Energy Inc. stockholdersʼ equity:
Preferred stock; $0.01 par value; 30,000,000 shares authorized and zero shares issued or outstanding as of March 31, 2026 and December 31, 2025, respectively		—			—
Common stock; $0.01 par value; 270,000,000 shares authorized; 189,589,004 and 188,530,052 shares issued as of March 31, 2026 and December 31, 2025, respectively		1,896			1,885
Additional paid-in capital		3,297,535			3,296,643
Accumulated deficit		(1,174,565	)		(918,400	)
Treasury stock, at cost; 22,676,655 and 20,015,369 shares as of March 31, 2026 and December 31, 2025, respectively		(250,347	)		(212,144	)
Total Talos Energy Inc. stockholders' equity		1,874,519			2,167,984
Noncontrolling interest		300			139
Total equity		1,874,819			2,168,123
Total liabilities and equity	$	5,272,720		$	5,552,057

See accompanying notes.

Table of Contents

TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)


	Three Months Ended March 31,
	2026			2025
Revenues:
Oil	$	407,998		$	440,723
Natural gas		52,903			52,735
NGL		11,409			19,601
Total revenues		472,310			513,059
Operating expenses:
Lease operating expense		129,035			127,805
Production taxes		43			114
Depreciation, depletion and amortization		230,384			280,716
Impairment of oil and natural gas properties		145,018			—
Accretion expense		34,939			30,894
General and administrative expense		40,970			34,615
Other operating (income) expense		11,347			(4,536	)
Total operating expenses		591,736			469,608
Operating income (expense)		(119,426	)		43,451
Interest expense		(39,178	)		(40,927	)
Price risk management activities income (expense)		(173,547	)		(15,853	)
Equity method investment income (expense)		6,670			(490	)
Other income (expense)		4,185			3,860
Net income (loss) before income taxes		(321,296	)		(9,959	)
Income tax benefit (expense)		65,292			91
Net income (loss)	$	(256,004	)	$	(9,868	)
Net income (loss) attributable to noncontrolling interest		161			—
Net income (loss) attributable to Talos Energy Inc.	$	(256,165	)	$	(9,868	)

Net income (loss) per share attributable to common stockholders:
Basic	$	(1.52	)	$	(0.05	)
Diluted	$	(1.52	)	$	(0.05	)
Weighted average common shares outstanding:
Basic		168,381			180,192
Diluted		168,381			180,192

See accompanying notes.

Table of Contents

TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

STOCKHOLDERS’ EQUITY

(In thousands, except share amounts)

(Unaudited)


	Talos Energy Inc. Stockholders' Equity
	Common Stock		Additional Paid-In Capital			Accumulated Deficit			Common Stock Held in Treasury			Total Stockholders' Equity			Noncontrolling Interest		Total Equity
Balance at December 31, 2024	$	1,874	$	3,274,626		$	(424,110	)	$	(92,685	)	$	2,759,705		$	—	$	2,759,705
Equity-based compensation		—		5,932			—			—			5,932			—		5,932
Equity-based compensation tax withholdings		—		(2,385	)		—			—			(2,385	)		—		(2,385	)
Equity-based compensation stock issuances		8		(8	)		—			—			—			—		—
Purchase of treasury stock		—		—			—			(22,068	)		(22,068	)		—		(22,068	)
Net income (loss)		—		—			(9,868	)		—			(9,868	)		—		(9,868	)
Balance at March 31, 2025	$	1,882	$	3,278,165		$	(433,978	)	$	(114,753	)	$	2,731,316		$	—	$	2,731,316

Balance at December 31, 2025	$	1,885	$	3,296,643		$	(918,400	)	$	(212,144	)	$	2,167,984		$	139	$	2,168,123
Equity-based compensation		—		6,768			—			—			6,768			—		6,768
Equity-based compensation tax withholdings		—		(5,865	)		—			—			(5,865	)		—		(5,865	)
Equity-based compensation stock issuances		11		(11	)		—			—			—			—		—
Purchase of treasury stock		—		—			—			(38,203	)		(38,203	)		—		(38,203	)
Net income (loss)		—		—			(256,165	)		—			(256,165	)		161		(256,004	)
Balance at March 31, 2026	$	1,896	$	3,297,535		$	(1,174,565	)	$	(250,347	)	$	1,874,519		$	300	$	1,874,819


Common Stock Share Activity	Issued		Held in Treasury			Outstanding
Balance at December 31, 2024		187,434,908		(7,417,385	)		180,017,523
Equity-based compensation stock issuances		725,896		—			725,896
Purchase of treasury stock		—		(2,288,273	)		(2,288,273	)
Balance at March 31, 2025		188,160,804		(9,705,658	)		178,455,146

Balance at December 31, 2025		188,530,052		(20,015,369	)		168,514,683
Equity-based compensation stock issuances		1,058,952		—			1,058,952
Purchase of treasury stock		—		(2,661,286	)		(2,661,286	)
Balance at March 31, 2026		189,589,004		(22,676,655	)		166,912,349

See accompanying notes.

Table of Contents

TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Three Months Ended March 31,
	2026			2025
Cash flows from operating activities:
Net income (loss)	$	(256,004	)	$	(9,868	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion, amortization and accretion expense		265,323			311,610
Impairment of oil and natural gas properties		145,018			—
Amortization of deferred financing costs and original issue discount		1,966			1,830
Equity-based compensation expense		5,336			4,141
Price risk management activities (income) expense		173,547			15,853
Net cash received (paid) on settled derivative instruments		(22,470	)		5,167
Equity method investment (income) expense		(6,670	)		490
Settlement of asset retirement obligations		(21,869	)		(9,752	)
Loss (gain) on sale of assets		(6	)		(16	)
Changes in operating assets and liabilities:
Accounts receivable		(13,048	)		32,038
Other current assets		2,995			(2,136	)
Accounts payable		20,363			1,075
Other current liabilities		(41,589	)		(83,294	)
Other non-current assets and liabilities, net		(78,891	)		1,103
Net cash provided by (used in) operating activities		174,001			268,241
Cash flows from investing activities:
Exploration, development and other capital expenditures		(152,422	)		(129,003	)
Payments for acquisitions, net of cash acquired		—			(14,845	)
Proceeds from (cash paid for) sale of property and equipment, net		13,177			540
Proceeds from sale of equity method investment		49,665			—
Net cash provided by (used in) investing activities		(89,580	)		(143,308	)
Cash flows from financing activities:
Deferred financing costs		(6,918	)		—
Other deferred payments		(4,255	)		(4,949	)
Payments of finance lease		(5,217	)		(4,769	)
Purchase of treasury stock		(38,203	)		(17,291	)
Employee stock awards tax withholdings		(5,865	)		(2,385	)
Net cash provided by (used in) financing activities		(60,458	)		(29,394	)

Net increase (decrease) in cash, cash equivalents and restricted cash		23,963			95,539
Cash, cash equivalents and restricted cash:
Balance, beginning of period		438,990			214,432
Balance, end of period	$	462,953		$	309,971

Supplemental non-cash transactions:
Capital expenditures included in accounts payable and accrued liabilities	$	50,242		$	72,711
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	57,741		$	58,636

See accompanying notes.

Table of Contents

TALOS ENERGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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, innovative, independent energy company focused on maximizing long-term value through our oil and gas exploration and production (“Upstream”) business in the United States (“U.S.”) Gulf of America and offshore Mexico. The Company’s activities are primarily concentrated in the Deepwater (i.e., water depths of more than 600 feet) area of the U.S. Gulf of America. The Company leverages decades of technical and offshore operational expertise to acquire, explore, and produce assets in key geological trends while maintaining a focus on safe and efficient operations, environmental responsibility and community impact.

Basis of Presentation and Consolidation

The Condensed Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC regarding interim financial reporting. Accordingly, certain information and disclosures normally included in complete financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) have been condensed or omitted pursuant to such rules and regulations. In the opinion of management, these financial statements include all adjustments, which unless otherwise disclosed, are of a normal recurring nature, necessary for a fair presentation of the financial position, results of operations, cash flows and changes in equity for the periods presented. The results for interim periods are not necessarily indicative of results for the entire year. The unaudited financial statements and related notes included in this Quarterly Report should be read in conjunction with the Company’s audited Consolidated Financial Statements and accompanying notes included in the 2025 Annual Report.

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 and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

Segments

The Company has one operating segment: our exploration and production of oil, natural gas and NGLs (“Upstream Segment”). The Company's Upstream Segment is currently the only reportable segment being managed on a consolidated basis. See additional information in Note 14 — Segment Information.

Summary of Significant Accounting Policies

The Company has provided a discussion of its significant accounting policies, estimates and judgments in Note 2 – Summary of Significant Accounting Policies included in the accompanying Notes to Consolidated Financial Statements in the 2025 Annual Report. The Company has not changed any of its significant accounting policies from those described in our 2025 Annual Report.

Recently Issued Accounting Standards Not Yet Adopted

Disaggregation of Income Statement Expenses — As disclosed in the Notes to Consolidated Financial Statements of the Company’s 2025 Annual Report, in November 2024, the FASB issued new disclosure guidance relating to the disaggregation of income statement expenses. The Company continues to evaluate the disclosure requirements, which is effective for annual reporting periods beginning after December 15, 2026 and interim reporting periods beginning after December 15, 2027.

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 Condensed Consolidated Balance Sheets to the total of the same such amounts shown in the Condensed Consolidated Statements of Cash Flows (in thousands):



	March 31, 2026		December 31, 2025
Cash and cash equivalents	$	386,367	$	362,809
Restricted cash included in Other long-term assets		76,586		76,181
Total cash, cash equivalent and restricted cash	$	462,953	$	438,990

Table of Contents

Accounts Receivable

The following table provides the components of “Accounts receivable, net” as presented on the Condensed Consolidated Balance Sheets (in thousands):


	March 31, 2026		December 31, 2025
Trade	$	250,447	$	166,793
Joint interest		73,833		132,527
Other		17,049		23,738
Total accounts receivable, net	$	341,329	$	323,058

Note 2 — Acquisitions and Divestitures

Asset Acquisitions

Acquisitions accounted for as asset acquisitions require, among other items, the cost of the acquisition to be allocated to the assets acquired and liabilities assumed based on relative fair value basis.

Acquisition of Incremental Working Interest in Monument Oil Discovery — On March 7, 2025, the Company completed the acquisition of an additional 8.3% non-operated working interest in the Monument oil discovery in the Deepwater U.S. Gulf of America located on certain Walker Ridge lease blocks for $14.8 million, substantially all of which was allocated to its proved properties. An additional aggregate $6.3 million of contingent payments will be recognized upon the achievement of certain milestones defined in the agreement. This incremental acquisition brings the Company’s total non-operated working interest in the Monument oil discovery to 29.7%.

Divestitures

During the three months ended March 31, 2026, the Company sold a portion of its equity method investment in Talos Energy Mexico 7, S. de R.L. de C.V. (“Talos Mexico”). See Note 6 – Equity Method Investments for additional information.

Note 3 — Property, Plant and Equipment

Proved Properties

Capitalized oil and natural gas 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. The Company performs this ceiling test calculation each quarter utilizing SEC pricing.

The Company’s ceiling test computation resulted in an impairment of its U.S. oil and natural gas properties during the three months ended March 31, 2026 of $145.0 million. The non-cash impairment is reflected as “Impairment of oil and natural gas properties” on the Condensed Consolidated Statements of Operations and an increase to “Accumulated depreciation, depletion and amortization” on the Company’s Condensed Consolidated Balance Sheets. At March 31, 2026, the Company’s ceiling test computation was based on SEC pricing of $63.17 per Bbl of oil, $3.97 per Mcf of natural gas and $18.50 per Bbl of NGLs. No impairments were recorded during the three months ended March 31, 2025.

Because the ceiling calculation uses trailing twelve-month first day of the month average commodity prices, the effect of increases and decreases in period-over-period prices can significantly impact the ceiling limitation calculation. In addition, other factors that impact the ceiling limitation calculation include, but are not limited to, incremental proved reserves that may be added each period, revisions to previous reserve estimates, capital expenditures, operating costs, depletion expense, and all related tax effects. Depending on fluctuations in these factors, including price changes, the Company may incur ceiling test impairments in future quarters.

Note 4 — Leases

The Company has operating leases principally for office space, drilling rigs and other equipment necessary to support the Company’s operations. Costs associated with the Company’s leases are either expensed or capitalized depending on how the underlying asset is utilized. Additionally, the Company has a finance lease and the right-of-use (“ROU”) asset was capitalized and included in proved properties and is being depleted as part of the full cost pool.

Table of Contents

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):


	Three Months Ended March 31,
	2026			2025
Finance lease costs - interest on lease liabilities	$	2,478		$	2,927
Operating lease costs, excluding short-term leases(1)		903			1,075
Short-term lease costs(2)		35,106			40,113
Variable lease costs(3)		670			667
Variable and fixed sublease income		(397	)		(397	)
Total lease costs	$	38,760		$	44,385

(1)

Operating lease costs 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 and well intervention vessels, most of which are short-term contracts not recognized as a ROU asset and lease liability on the Condensed Consolidated Balance Sheets. The short-term operating lease costs incurred during the periods presented are not necessarily indicative of the Company’s future short-term lease costs and obligations, as it routinely executes short-term contracts for the use of drilling rigs to support its drilling activities. Short-term lease costs for drilling rigs can vary significantly based on the timing of the drilling program. Market conditions can also contribute to the volatility and variability of short-term drilling rig lease costs.

(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 lease liability, adjusted for initial direct costs and incentives were as follows (in thousands):


	March 31, 2026		December 31, 2025
Operating leases:
Operating lease assets	$	8,703	$	9,214

Current portion of operating lease liabilities	$	3,699	$	3,657
Operating lease liabilities		10,992		11,956
Total operating lease liabilities	$	14,691	$	15,613

Finance leases:
Proved properties	$	166,261	$	166,261

Other current liabilities	$	21,964	$	21,473
Other long-term liabilities		84,460		90,169
Total finance lease liabilities	$	106,424	$	111,642

The table below presents the supplemental cash flow information related to leases (in thousands):


	Three Months Ended March 31,
	2026		2025
Operating cash outflow from finance leases	$	2,478	$	2,927
Operating cash outflow from operating leases	$	1,306	$	1,484

Note 5 — Financial Instruments

As of March 31, 2026 and December 31, 2025, 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):


	March 31, 2026				December 31, 2025
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
9.000% Second-Priority Senior Secured Notes	$	614,834	$	653,188	$	614,058	$	649,425
9.375% Second-Priority Senior Secured Notes	$	612,627	$	662,188	$	612,131	$	656,250

Table of Contents

The carrying values of the 9.000% Second-Priority Secured Senior Notes due 2029 and 9.375% Second-Priority Senior Secured Notes due 2031 (together, the “Senior Notes”) are adjusted for discount 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. See Note 7 — Debt for the maturity dates of the Company’s Senior Notes.

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.

The following table presents the impact that derivatives, not designated as hedging instruments, had on its Condensed Consolidated Statements of Operations (in thousands):


	Three Months Ended March 31,
	2026			2025
Net cash received (paid) on settled derivative instruments	$	(22,470	)	$	5,167
Unrealized gain (loss)		(151,077	)		(21,020	)
Price risk management activities income (expense)	$	(173,547	)	$	(15,853	)

The following tables reflect the contracted average daily volumes and weighted average prices under the terms of the Company's derivative contracts as of March 31, 2026:


Swap Contracts
Production Period	Settlement Index	Volumes		Swap Price
Crude oil:		(Bbls)		(per Bbl)
April 2026 – December 2026	NYMEX WTI CMA		8,858	$	66.35
January 2027 – June 2027	NYMEX WTI CMA		4,000	$	73.75
Natural gas:		(MMBtu)		(per MMBtu)
April 2026 – December 2026	NYMEX Henry Hub		26,073	$	3.74


Two-Way Collar Contracts
Production Period	Settlement Index	Volumes		Floor Price		Ceiling Price
Crude oil:		(Bbls)		(per Bbl)		(per Bbl)
April 2026 – December 2026	NYMEX WTI CMA		19,887	$	61.37	$	74.29
January 2027 – June 2027	NYMEX WTI CMA		9,972	$	60.01	$	75.39

The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands):


	March 31, 2026
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas derivatives	$	—	$	26,047		$	—	$	26,047
Liabilities:
Oil and natural gas derivatives		—		(129,412	)		—		(129,412	)
Total net asset (liability)	$	—	$	(103,365	)	$	—	$	(103,365	)


	December 31, 2025
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas derivatives	$	—	$	54,420		$	—	$	54,420
Liabilities:
Oil and natural gas derivatives		—		(6,708	)		—		(6,708	)
Total net asset (liability)	$	—	$	47,712		$	—	$	47,712

Table of Contents

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 Condensed 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):


	March 31, 2026				December 31, 2025
	Assets		Liabilities		Assets		Liabilities
Oil and natural gas derivatives:
Current	$	21,748	$	127,180	$	54,420	$	6,708
Non-current		4,299		2,232		—		—
Total gross amounts presented on balance sheet		26,047		129,412		54,420		6,708
Less: Gross amounts not offset on the balance sheet		26,047		26,047		6,708		6,708
Net amounts	$	—	$	103,365	$	47,712	$	—

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 March 31, 2026 represent derivative instruments from eight 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 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.

Note 6 — Equity Method Investments

As of March 31, 2026 and December 31, 2025, the Company's ownership interest in Talos Mexico was 20.0% and 50.1%, respectively, and the carrying amount of its investment was $44.8 million and $112.4 million, respectively. As of March 31, 2026 and December 31, 2025, the carrying amount of the investment includes a positive basis difference of $26.3 million and $66.0 million, respectively. Talos Mexico is a variable interest entity and the Company's maximum exposure to loss as a result of its involvement with Talos Mexico is the carrying amount of its investment.

On March 25, 2026, the Company sold an additional 30.1% equity interest in Talos Mexico to Zamajal, S.A. de C.V., a subsidiary of Grupo Carso, S.A.B. de C.V. (“Carso”), for $49.7 million in cash consideration with an additional $33.1 million payment contingent on first oil production from the Zama Field (the “Incremental Mexico Equity Sale”). The $20.4 million initial fair value of the contingent consideration related to the Incremental Mexico Equity Sale has been recognized as a long-term asset and included in “Other assets” as presented on the Condensed Consolidated Balance Sheets. The Company recognized a $6.8 million gain on the Incremental Mexico Equity Sale, which is included in “Equity method investment income (expense)” on the Condensed Consolidated Statements of Operations. See Note 12 — Related Party Transactions for additional information on Carso.

The Company will receive $83.0 million in additional payments contingent upon the Zama Field reaching first oil production. Of this amount, $49.9 million is associated with the initial Talos Mexico equity sale that closed on September 27, 2023 as discussed in Note 3 – Acquisitions and Divestitures included in the accompanying Notes to Consolidated Financial Statements in the 2025 Annual Report, and the remainder is associated with the Incremental Mexico Equity Sale.

Note 7 — 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):


	Maturity Date	March 31, 2026			December 31, 2025
9.000% Second-Priority Senior Secured Notes	February 1, 2029	$	625,000		$	625,000
9.375% Second-Priority Senior Secured Notes	February 1, 2031		625,000			625,000
Revolving credit facility	January 20, 2030		—			—
Total debt, before discount and deferred financing cost			1,250,000			1,250,000
Unamortized discount and deferred financing cost, net			(22,539	)		(23,811	)
Total debt(1)		$	1,227,461		$	1,226,189

(1)

As of March 31, 2026, the Company was in compliance with all debt covenants.

Table of Contents

Revolving Reserve-based Credit Facility

The Company maintains a bank credit facility with a syndicate of financial institutions. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter of each year based on a proved reserves report that the Company delivers to the administrative agent of its bank credit facility.

On January 20, 2026, the Parent Company, Talos Production Inc., a Delaware corporation and wholly owned subsidiary of the Company (“Talos Production”), and certain other direct and indirect subsidiaries of the Company and Talos Production entered into the Amended and Restated Credit Agreement (the “A&R Credit Agreement”) among the Company, Talos Production, as Borrower, JPMorgan Chase Bank, N.A., as administrative agent (the “Administrative Agent”), the issuing banks, the lenders party thereto, and the other persons from time to time party thereto. The A&R Credit Agreement amended and restated in its entirety the prior credit agreement, dated as of May 10, 2018 (as amended, the “Prior Credit Agreement”), by and among the Company, Talos Production, as Borrower, JPMorgan Chase Bank, N.A., as administrative agent, the issuing banks, the lenders party thereto, and the other persons party thereto.

The A&R Credit Agreement has an initial borrowing base and total commitments of $700.0 million (with a letter of credit facility with a $250 million sublimit), subject to redetermination by the lenders at least semi-annually during the second quarter and fourth quarter of each year. The maturity date of the A&R Credit Agreement is the earlier of (i) January 20, 2030 and (ii) November 2, 2028 (the 91st day prior to the earliest stated maturity date of the 9.000% Second-Priority Senior Secured Notes due 2029 (the “9.000% Notes”), (or any Permitted Refinancing Indebtedness with respect thereto)), if such notes (or such Permitted Refinancing Indebtedness) have not been refinanced, redeemed, or repaid in full on or prior to such 91st day.

Interest accrues at Talos Production’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”). 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 and six-months) calculated and published by the CME Group Inc. The adjusted daily simple SOFR is equal to the overnight SOFR calculated and published by the Federal Reserve Bank of New York. In addition, Talos Production is obligated to pay a commitment fee on the unutilized portion of the commitments. The applicable margin and the commitment fee rate are calculated based upon the utilization levels as a percentage of unused lender commitments then in effect.

The A&R Credit Agreement includes certain conditions to borrowings, representations and warranties and events of default customary for financings of its type and size. The A&R Credit Agreement also limits the Company’s, Talos Production’s and their respective subsidiaries’ ability to, among other things, incur additional indebtedness, grant liens on any assets, pay dividends or make certain restricted payments, make certain investments, consummate certain asset sales, make certain payments on indebtedness, and merge, consolidate or engage in other fundamental changes. The A&R Credit Agreement has certain customary affirmative and negative covenants, including that Talos Production must maintain a Consolidated Total Debt to EBITDAX Ratio (as defined in the A&R Credit Agreement) of no greater than to 3.00 to 1.00 calculated each quarter utilizing the most recent twelve months to determine EBITDAX. Talos Production must also maintain a current ratio no less than 1.00 to 1.00 each quarter. Under the A&R Credit Agreement, 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 proved oil and natural gas assets of the Company and is fully and unconditionally guaranteed by the Company and certain of its wholly-owned subsidiaries.

Note 8 — Asset Retirement Obligations

The asset retirement obligations included in the Condensed Consolidated Balance Sheets in current and non-current liabilities, and the changes in that liability were as follows (in thousands):


Asset retirement obligations at December 31, 2025	$	1,332,128
Obligations incurred		6,235
Obligations settled		(21,869	)
Accretion expense		34,939
Changes in estimate		13,588
Asset retirement obligations at March 31, 2026	$	1,365,021
Less: Current portion at March 31, 2026		112,962
Long-term portion at March 31, 2026	$	1,252,059

At March 31, 2026, the Company has (1) restricted cash of $76.6 million held in escrow and (2) two notes receivable with an aggregated face value of $66.2 million to settle future asset retirement obligations.

Table of Contents

Note 9 — Employee Benefits Plans and Share-Based Compensation

Long Term Incentive Plans

Restricted Stock Units (“RSUs”) — The following table summarizes RSU activity under the Amended and Restated Talos Energy Inc. 2021 Long Term Incentive Plan (the “A&R LTIP”) for the three months ended March 31, 2026:


	Restricted Stock Units			Weighted Average Grant Date Fair Value
Unvested RSUs at December 31, 2025		4,595,755		$	10.25
Granted		2,061,530		$	13.13
Vested		(1,573,067	)	$	10.76
Forfeited		(233,511	)	$	10.40
Unvested RSUs at March 31, 2026		4,850,707		$	11.30

Performance Share Units (“PSUs”) — The following table summarizes PSU activity under the A&R LTIP for the three months ended March 31, 2026:


	Performance Share Units			Weighted Average Grant Date Fair Value
Unvested PSUs at December 31, 2025		1,114,299		$	10.02
Granted(1)(2)		558,399		$	16.68
Forfeited		(16,781	)	$	11.07
Unvested PSUs at March 31, 2026		1,655,917		$	12.26

(1)

Eligible to vest based on continued employment and the relative annualized total shareholder return (“TSR”) of the Company as compared to a peer group over a three-year performance period, as modified by the Company’s absolute annualized TSR over the same performance period.

(2)

Excludes 279,197 strategic PSUs awarded which vest over a three-year performance period, subject to continued employment of the recipients and the achievement of strategic measures. At the end of the performance period, and based on the Company’s ultimate performance, the Compensation Committee of the Board of Directors (the “Compensation Committee”) has discretion to determine the number of shares of common stock issuable, ranging from zero to 200% of the target number of PSUs awarded. Due to this level of discretion, the Company recognizes stock-based compensation expense over the requisite service period based on the estimated fair value at each reporting date until the grant date. In the period in which the grant occurs, the cumulative compensation cost will be adjusted to the fair value at the date of the grant.

The following table summarizes the assumptions used in the Monte Carlo simulations to calculate the fair value of the TSR PSUs granted at the date indicated:


	March 5, 2026
Expected term (in years)		2.8
Expected volatility		47.8	%
Risk-free interest rate		3.5	%
Dividend yield		—	%

Share-based Compensation Costs

Share-based compensation costs associated with RSUs and PSUs are reflected as “General and administrative expense,” on the Condensed Consolidated Statements of Operations, net of amounts capitalized to “Proved properties,” on the Condensed Consolidated Balance Sheets.

The following table presents the amount of costs expensed and capitalized (in thousands):


	Three Months Ended March 31,
	2026		2025
Share-based compensation costs	$	7,081	$	5,940
Less: Amounts capitalized to oil and gas properties		1,745		1,799
Total share-based compensation expense	$	5,336	$	4,141

Note 10 — Income Taxes

The Company is a corporation that is subject to U.S. federal, state and local and non-U.S. income taxes.

For the three months ended March 31, 2026, the Company recognized an income tax benefit of $65.3 million for an effective tax rate of 20.3%. The Company’s effective tax rate for this period is different than the U.S. federal statutory income tax rate of 21% primarily due to state and local income taxes offset with a change in valuation allowance.

For the three months ended March 31, 2025, the Company recognized an income tax benefit of $0.1 million for an effective tax rate of 0.9%. The Company’s effective tax rate for this period is different than the U.S. federal statutory income tax rate of 21% primarily due to permanent differences.

Table of Contents

The Company evaluates and updates the estimated annual effective income tax rate on a quarterly basis based on current and forecasted operating results and tax laws. Consequently, based upon the mix and timing of the Company’s actual earnings compared to annual projections, the effective tax rate may vary quarterly and may make quarterly comparisons not meaningful. The quarterly income tax provision is generally comprised of tax expense on income or benefit on loss at the most recent estimated annual effective tax rate. The tax effect of discrete items is recognized in the period in which they occur at the applicable statutory rate.

Deferred income tax assets and liabilities are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce deductions and income in the future. The deferred tax asset estimates are subject to revision, either up or down, in future periods based on new facts or circumstances. 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. In evaluating the Company’s valuation allowance, the Company considers cumulative losses, the reversal of existing temporary differences, the existence of taxable income in carryback years, tax optimization planning and future taxable income for each of its taxable jurisdictions. The Company assesses the realizability of its deferred tax assets quarterly, and changes to the Company’s assessment of its valuation allowance in future periods could materially impact its results of operations. The Company’s valuation allowance primarily relates to accruals for asset retirement obligations. A net deferred tax liability of $86.1 million and $156.7 million is included in “Other long-term liabilities” on the Condensed Consolidated Balance Sheets as of March 31, 2026 and December 31, 2025, respectively.

Note 11 — 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 and PSUs.

The following table presents the computation of the Company’s basic and diluted income (loss) per share attributable to common stockholders (in thousands, except for the per share amounts):


	Three Months Ended March 31,
	2026			2025
Net income (loss) attributable to Talos Energy Inc.	$	(256,165	)	$	(9,868	)

Weighted average common shares outstanding — basic		168,381			180,192
Dilutive effect of securities		—			—
Weighted average common shares outstanding — diluted		168,381			180,192

Net income (loss) per share attributable to common stockholders:
Basic	$	(1.52	)	$	(0.05	)
Diluted	$	(1.52	)	$	(0.05	)
Anti-dilutive potentially issuable securities excluded from diluted common shares		5,431			3,528

Note 12 — Related Party Transactions

Slim Family and Affiliates

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 held approximately 24.7% of the Company’s outstanding shares of common stock as of March 31, 2026 based on SEC beneficial ownership reports filed by Control Empresarial and the Company’s total outstanding shares of common stock as of that date.

The Company has a cooperation agreement with Control Empresarial that limits additional acquisitions of the Company’s voting securities by Control Empresarial if such acquisitions would result in ownership exceeding 25.0%, subject to specified exceptions. The agreement was amended on December 8, 2025 to extend its term through December 16, 2026, subject to early termination provisions. A discussion of the agreement is included in the Notes to the Consolidated Financial Statements in the 2025 Annual Report.

The Slim Family own a majority stake in Carso. Carso, through its subsidiary, has an ownership interest in Talos Mexico. See Note 6 – Equity Method Investments for additional information on Talos Mexico. At March 31, 2026 and December 31, 2025, the Company had a $2.8 million receivable from Carso related to advisory services the Company provided in connection with the Lakach Deepwater natural gas field off Mexico’s southeastern coast near Veracruz. This amount is reflected in “Accounts receivable, net” on the Condensed Consolidated Balance Sheets for both periods.

Table of Contents

Equity Method Investments

The Company had a $0.1 million and $0.7 million related party receivable from Talos Mexico as of March 31, 2026 and December 31, 2025, respectively. These amounts are reflected in “Accounts receivable, net” on the Condensed Consolidated Balance Sheets.

Note 13 — Commitments and Contingencies

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, and removal of facilities in the U.S. Gulf of America.

As of March 31, 2026, the Company had outstanding performance bonds from third party sureties totaling $1.5 billion. The ongoing cost of maintaining these bonds is reflected as “Interest expense” on the Condensed Consolidated Statements of Operations. Additionally, as of March 31, 2026, the Company had letters of credit issued under its bank credit facility totaling $97.4 million. Letters of credit that are outstanding reduce the available revolving credit commitments.

The Company has arrangements with its surety providers that establish limits on the aggregate amount of collateral the Company may be required to post, subject to annual collateral funding commitments. These arrangements also require the Company to incur minimum annual expenditures for plugging and abandonment activities of $90.0 million for each of the three years beginning January 1, 2026 and $45.0 million for each of the two years beginning January 1, 2029.

The table below outlines the estimated collateral funding commitments under the arrangements as of March 31, 2026 (in thousands):


Period	Collateral Funding Commitments
Remaining 2026	$	41,660
2027		42,672
2028		43,178
2029		42,112
2030		35,222
Thereafter		46,759
Total	$	251,603

The collateral funding commitments may be secured by cash or letters of credit which will reduce the Company’s liquidity. Collateral funded with cash will be reflected as “Restricted cash” within the Condensed Consolidated Balance Sheets. The collateral funding commitments, and ultimately any posted cash collateral, will be reduced as plugging and abandonment activities are completed and underlying surety bonds are released.

Firm Transportation Commitments

The Company has firm transportation agreements in place with pipeline carriers for future transportation of oil and gas production wherein the Company is obligated to transport minimum monthly volumes or pay for any deficiencies. As of March 31, 2026, the future minimum transportation payments under the Company’s commitments total approximately $42.1 million for years 2026 through 2030. Our production is currently expected to exceed the minimum monthly volume in the periods provided in the agreements.

Legal Proceedings and Other Contingencies

From time to time, the Company is involved in litigation, disputes related to our business, 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.

Other than as described below, during the three months ended March 31, 2026, there were no material developments to those matters discussed in the Notes to the Consolidated Financial Statements in the 2025 Annual Report:

Table of Contents

By virtue of the Company’s consummation of an acquisition in March 2024 as discussed in Note 3 – Acquisitions and Divestitures included in the accompanying Notes to Consolidated Financial Statements in the 2025 Annual Report, Talos is defending a lawsuit brought by a contractor concerning amounts allegedly owed for drilling operations at several locations in the Gulf of America. The lawsuit alleges that the contractor is entitled under Louisiana Law to certain statutory liens and payment. While the Company disputes the contractor’s liens and damages claims, the Company and the plaintiff expect to settle the lawsuit with a $14.3 million payment by the Company, in exchange for a release of the liens and a full liability release by the plaintiff. The accrued settlement payment is reflected as a component of “Other operating (income) expense” on the Condensed Consolidated Statements of Operations and “Other current liabilities” on the Condensed Consolidated Balance Sheets.

Decommissioning Obligations

Decommissioning in the U.S. is governed by both federal and state laws and regulations. The Company, as a co-lessee or predecessor-in-interest in oil and natural gas leases located in the U.S. Gulf of America, 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. Both federal and state laws and regulations could require the Company to assume such obligations. The Company reflects such costs as “Other operating (income) expense” on the Condensed Consolidated Statements of Operations.

The decommissioning obligations included are in the Condensed Consolidated Balance Sheets as “Other current liabilities” and “Other long-term liabilities”, and the changes in that liability were as follows (in thousands):


Decommissioning Obligations at December 31, 2025	$	22,145
Additions		150
Changes in estimate		12
Settlements		(59	)
Decommissioning Obligations at March 31, 2026	$	22,248
Less: Current portion at March 31, 2026		5,158
Long-term portion at March 31, 2026	$	17,090

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 14 — Segment Information

The chief operating decision maker (“CODM”) is currently the President and Chief Executive Officer and Chief Financial Officer. 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.

Table of Contents

The following table presents selected segment information (in thousands):


	Three Months Ended March 31, 2026			Three Months Ended March 31, 2025
	Upstream			Upstream
Revenues from external customers	$	472,310		$	513,059
Significant expenses:
Direct operating and maintenance(1)		(114,704	)		(125,567	)
Workover(1)		(14,331	)		(2,238	)
Adjusted general and administrative expense(2)		(34,012	)		(30,310	)
Net cash received (paid) on settled derivative instruments		(22,470	)		5,167
Interest expense		(39,178	)		(40,927	)
Other segment items:
Other(3)		(8,827	)		8,118
Depreciation, depletion and amortization		(230,384	)		(280,716	)
Impairment of oil and natural gas properties		(145,018	)		—
Accretion expense		(34,939	)		(30,894	)
Mark-to-market derivative fair value gain (loss)		(151,077	)		(21,020	)
Equity-based compensation expense		(5,336	)		(4,141	)
Equity method investment income (expense)		6,670			(490	)
Income tax benefit (expense)		65,292			91
Net income (loss)		(256,004	)		(9,868	)

Segment Expenditures	$	140,874		$	127,604

(1)

Component of lease operating expense.

(2)

Includes general and administrative expense less transaction expenses and equity-based compensation.

(3)

For the three months ended March 31, 2026, primarily includes an accrual for a legal settlement as further discussed in Note 13 — Commitments and Contingencies offset by interest income. For the three months ended March 31, 2025, primarily includes interest income and other miscellaneous operating income.

Reconciliations

The following table presents the reconciliation of Segment Expenditures to the Company’s consolidated totals (in thousands):


	Three Months Ended March 31,
	2026			2025
Segment Expenditures:
Total reportable segments	$	140,874		$	127,604
Change in capital expenditures included in accounts payable and accrued liabilities		34,479			12,839
Plugging & abandonment		(21,869	)		(9,752	)
Decommissioning obligations settled		(59	)		(278	)
Deferred payments		(301	)		(536	)
Other		(702	)		(874	)
Exploration, development and other capital expenditures	$	152,422		$	129,003

Table of Contents

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Unless otherwise indicated or the context otherwise requires, references in this Quarterly Report to “us,” “we,” “our,” “Talos” or the “Company” are to Talos Energy Inc. and its wholly-owned subsidiaries.

The following discussion and analysis of our financial condition and results of operations is based on, and should be read in conjunction with, our Condensed Consolidated Financial Statements and notes thereto in Part I, Item 1. “Financial Statements” of this Quarterly Report, as well as our audited Consolidated Financial Statements and the notes thereto in our 2025 Annual Report and the related Management’s Discussion and Analysis of Financial Condition and Results of Operations included in Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our 2025 Annual Report.

Our Business

We are a technically driven, innovative, independent energy company focused on safely maximizing long-term value through our oil and gas exploration and production (“Upstream”) business in the United States (“U.S.”) Gulf of America and offshore Mexico. We leverage decades of technical and offshore operational expertise to acquire, explore, and produce assets in key geological trends while maintaining a focus on safe and efficient operations, environmental responsibility and community impact.

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.

Operational Update

Cardona — We successfully drilled and completed the Cardona well in late 2025. Production commenced in early 2026, with the well flowing to our Pompano facility. Talos is the operator and holds a 65% working interest.

CPN — We successfully drilled the CPN well and finished well completion operations in the first quarter of 2026, with first production from the well expected in the third quarter of 2026. Talos is the operator and holds a 65% working interest.

Monument — Drilling operations have commenced and continuous drilling and completion activities are planned throughout 2026. First production is expected between 20-30 MBoepd gross and remains on track to commence by late 2026. Monument is a large Wilcox oil discovery in Walker Ridge blocks 271, 272, 315, and 316. Monument is being developed as a subsea tie-back to the Shenandoah production facility in Walker Ridge with committed firm capacity of 20 MBblpd. Talos holds a 29.7% non-operated working interest.

Recent Developments

The following encompasses recent developments since the filing of our 2025 Annual Report:

Incremental Mexico Equity Sale — On December 16, 2024, we entered into an agreement to sell an additional 30.1% equity interest in Talos Mexico to Zamajal, S.A. de C.V., a subsidiary of Grupo Carso, S.A.B. de C.V., for $49.7 million in cash consideration with an additional $33.1 million payment contingent on first oil production from the Zama Field (the “Incremental Mexico Equity Sale”). The Incremental Mexico Equity Sale closed on March 25, 2026. See Part I, Item 1. “Financial Statements — Note 6 — Equity Method Investments” for additional information. We will receive $83.0 million in additional payments contingent upon the Zama Field reaching first oil production, of which $49.9 million is associated with the original Talos Mexico equity sale that closed on September 27, 2023, and the remainder is associated with the Incremental Mexico Equity Sale.

Lease Sale — The Big Beautiful Gulf 1 lease sale was held by BOEM on December 10, 2025. As of April 1, 2026, we have been awarded all of the eleven lease blocks for which we were the highest bidder.

Share Repurchase Program — During the three months ended March 31, 2026, we repurchased approximately 2.7 million shares for $38.2 million exclusive of broker commissions under our share repurchase program, which was previously authorized by our Board of Directors (the “Board”). On April 27, 2026, our Board authorized a $157.3 million increase to the previously approved limit of the share repurchase program, increasing the amount remaining under the authorized program to $200.0 million. See “Liquidity and Capital Resources — Share Repurchase Program” for additional information.

Table of Contents

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

No material events, such as acquisitions or divestitures, affected the comparability of our financial condition and results of operations for the periods presented herein. Management does not currently expect any material factors to affect the comparability of our future financial condition or results of operations.

Known Trends and Uncertainties

The following known trends and uncertainties were discussed under Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2025 Annual Report:

•

Volatility in Oil, Natural Gas and NGL Prices

•

Inflation of Cost of Goods, Services and Personnel

•

Impairment of Oil and Natural Gas Properties

•

Financial Assurance Requirements

•

Financial Assurance Market Outlook

•

Deepwater Operations

•

Oil Spill Response Plan

•

Hurricanes, Tropical Storms, Winter Storms and Loop Currents

•

Future Offshore Leasing

•

Update on National Marine Fisheries Service’s Gulf of America Revised Biological Opinion

See Part II, Item 1A “Risk Factors” of this Quarterly Report and Part II, Item 1A. “Risk Factors” in our 2025 Annual Report for additional information regarding our risk factors.

Except as discussed below, there have been no material developments to known trends and uncertainties discussed in our 2025 Annual Report:

Volatility in Oil, Natural Gas and NGL Prices — Historically, the markets for oil and natural gas have been volatile. As such, oil, natural gas and NGL prices have been, and are expected to continue to be, subject to wide fluctuations. The ongoing military conflict in Iran, which began in February 2026, has heightened geopolitical risk in key global energy markets and contributed to increased volatility in oil and gas commodity prices. The conflict has resulted in disruptions and constraints on maritime transit, supply chains, and energy infrastructure in the Middle East, including in and around the Strait of Hormuz, a critical chokepoint for global oil and liquefied natural gas shipments. These developments have led to elevated risk premiums in energy commodity prices and greater short‑term price uncertainty, causing global crude oil prices to surpass $100 per Bbl. Sustained or escalating disruptions to global supply chains, shipping routes, or energy infrastructure could materially affect global supply‑demand balances and contribute to continued volatility or increases in commodity prices. In addition, heightened market volatility may influence customer demand, counterparty credit risk, and broader macroeconomic conditions. The duration and ultimate resolution of the conflict, as well as the extent of any further disruptions, remain uncertain. We continue to monitor geopolitical developments and their potential impact on commodity prices, offshore operations, and global energy markets, but cannot predict with assurance the nature, timing, or magnitude of any future effects on our business, financial condition, or results of operations.

Our revenues, cash flow, profitability, access to capital, capital expenditures, and liquidity are directly influenced by commodity prices. We use hedging instruments as part of our risk management strategy to reduce the impact of near-term price volatility, mitigate downside exposure, and allow for participation in favorable commodity price movements during periods of higher prices. We also anticipate continuing to operate our business in a volatile market by prioritizing high-return development projects, focusing on cost control measures, and maintaining a strong balance sheet to provide financial, operational and capital spending flexibility under a range of price scenarios. We continue to monitor commodity price trends closely and will modify our plans within our strategy as appropriate. See Part I, Item 1. “Financial Statements — Note 5 — Financial Instruments” for additional information regarding our commodity derivative positions as of March 31, 2026.

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.

Inflation of Cost of Goods, Services and Personnel — The war in Iran has triggered inflationary pressures in the global economy. The federal funds rate target range is currently set at 3.50% to 3.75%, where it was left unchanged at the U.S. Federal Reserve’s latest meeting. Future changes to the benchmark interest rate remain uncertain in light of geopolitical conditions and expected changes to the membership of the Federal Reserve Board of Governors.

Table of Contents

Impact of Prolonged Increases in Tariffs —We continue to monitor changes in global trade policies, including tariff increases, and the impact on our business while evaluating actions to mitigate the impact on our business, results of operations, and financial condition. The imposition of additional or any prolonged increases in global tariffs could have a material impact on our financial condition and results of operations in fiscal year 2026 and beyond.

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. As a result of our ceiling test computations, an impairment of our U.S. oil and natural gas properties was recorded during the three months ended March 31, 2026 of $145.0 million. No impairment was recorded during the three months ended March 31, 2025. At March 31, 2026 our ceiling test computation was based on SEC pricing of $63.17 per Bbl of oil, $3.97 per Mcf of natural gas and $18.50 per Bbl of NGLs. See Part I, Item 1. “Financial Statements — Note 3 — Property, Plant and Equipment” for additional information.

Because the ceiling calculation uses trailing twelve-month first day of the month average commodity prices, the effect of increases and decreases in period-over-period prices can significantly impact the ceiling limitation calculation. In addition, other factors that impact the ceiling limitation calculation include, but are not limited to, incremental proved reserves that may be added each period, revisions to previous reserve estimates, capital expenditures, operating costs, depletion expense, and all related tax effects. Depending on fluctuations in these factors, including price changes, we may incur ceiling test impairments in future quarters.

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” included in our 2025 Annual Report. 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.

Financial Assurance Rule Update — On March 9, 2026, BOEM published a new proposed rule entitled “Risk Management and Financial Assurance for OCS Lease and Grant Obligations.” The proposed rule reverts to BOEM’s former policy of considering the financial strength of co-owners and predecessors in title when determining whether supplemental financial assurance is required, and revises the credit rating threshold used for evaluating the financial health of lessees and grantees from BBB- to BB- (S&P Global Ratings) or Baa3 to Ba3 (Moody’s Investor Service Inc.). BOEM, however, retains the discretion to require financial assurance and/or issue liability orders where appropriate, including if it determines there is a substantial risk of nonperformance of an interest holder’s decommissioning liabilities for which the predecessor is not liable.

While we anticipate that BOEM’s proposed rule, if finalized in its current form, would reduce the amount of financial assurance required from certain lessees as compared to the previous rule, the final version and timing of adoption of BOEM’s proposed rule remain uncertain. Any future requirements to provide additional or replacement financial assurances under future regulatory actions or rules could require significant use of our capital or restrict liquidity and could materially and adversely affect our financial condition, cash flows, liquidity, and results of operations.

See Part I, Items 1 and 2. “Business and Properties — Government Regulation — BOEM Financial Assurance Requirements” and Part I, Item 1A. “Risk Factors — We may not be able to obtain sufficient surety bonds on reasonably acceptable terms to conduct our business” in our 2025 Annual Report for further background on BOEM’s financial assurance requirements.

Update on National Marine Fisheries Service’s Gulf of America Revised Biological Opinion — In August 2024, the federal district court for the District of Maryland vacated the 2020 Biological Opinion issued by the National Marine Fisheries Service (“NMFS”), related to oil and gas activities in the Gulf of America. On May 20, 2025, NMFS published a new Biological Opinion for the Gulf of America oil and gas program, superseding and replacing all prior biological opinions relating to the program. Two lawsuits were filed opposing the new Biological Opinion, one by several environmental groups (Sierra Club, the Center for Biological Diversity, Friends of the Earth and Turtle Island Restoration Network) who filed in the federal district court for the District of Maryland, and the other by the State of Louisiana, the American Petroleum Institute and Chevron U.S.A. Inc. who filed in the Western Louisiana District Court. On February 20, 2026, the Western Louisiana District Court remanded without vacatur NMFS’ 2025 Biological Opinion, declaring that the Rice’s whale jeopardy finding and the Reasonable and Prudent Alternative are arbitrary, capricious and contrary to law. NMFS is required to complete the remand within 185 days of the Western Louisiana District Court’s order. As a result of the remand, the intervenors in the lawsuit filed in the District of Maryland have sought to stay the litigation pending completion of the remand order. The court has not yet ruled on this motion. At this time, it is uncertain how NMFS will address the Western Louisiana District Court’s findings and the effect this will have on the pending lawsuits.

Table of Contents

Results of Operations

Revenue

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):


	Three Months Ended March 31,
	2026		2025		Change
Revenues:
Oil	$	407,998	$	440,723	$	(32,725	)
Natural gas		52,903		52,735		168
NGL		11,409		19,601		(8,192	)
Total revenues	$	472,310	$	513,059	$	(40,749	)

Production Volumes:
Oil (MBbls)		5,740		6,144		(404	)
Natural gas (MMcf)		9,693		12,214		(2,521	)
NGL (MBbls)		639		900		(261	)
Total production volume (MBoe)		7,994		9,080		(1,086	)

Daily Production Volumes by Product:
Oil (MBblpd)		63.8		68.3		(4.5	)
Natural gas (MMcfpd)		107.7		135.7		(28.0	)
NGL (MBblpd)		7.1		10.0		(2.9	)
Total production volume (MBoepd)		88.8		100.9		(12.1	)

Average Sale Price Per Unit:
Oil (per Bbl)	$	71.08	$	71.73	$	(0.65	)
Natural gas (per Mcf)	$	5.46	$	4.32	$	1.14
NGL (per Bbl)	$	17.85	$	21.78	$	(3.93	)
Price per Boe	$	59.08	$	56.50	$	2.58
Price per Boe (including realized commodity derivatives)	$	56.27	$	57.07	$	(0.80	)

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


	Three Months Ended March 31, 2026 vs 2025
	Price			Volume			Total
Revenues:
Oil	$	(3,746	)	$	(28,979	)	$	(32,725	)
Natural gas		11,059			(10,891	)		168
NGL		(2,507	)		(5,685	)		(8,192	)
Total revenues	$	4,806		$	(45,555	)	$	(40,749	)

Three Months Ended March 31, 2026 and 2025 Volumetric Analysis — Production volumes decreased by 12.1 MBoepd to 88.8 MBoepd. This decrease is primarily attributable to a 6.3 MBoepd decline at the Brutus field, driven by a high-rate gas recompletion, where the well has declined as expected and will be sidetracked to a deeper target in the upcoming Brutus rig program, as well as a 3.7 MBoepd decrease at the Galapagos field primarily related to a shut-in due to a failure of the surface-controlled subsurface safety valve at the Genovesa well. We expect the Genovesa well to return to production in the third quarter of 2026 following completion of a planned workover. These decreases were partially offset by increases of 3.5 MBoepd related to incremental production at our Sunspear field.

Table of Contents

Operating Expenses

Lease Operating Expense

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


	Three Months Ended March 31,
	2026		2025
Lease operating expenses	$	129,035	$	127,805
Lease operating expenses per Boe	$	16.14	$	14.08

Three Months Ended March 31, 2026 and 2025 — Lease operating expense was relatively flat for the three months ended March 31, 2026 compared to the same period in 2025.

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):

Three Months Ended March 31, 2026 and 2025 — Depreciation, depletion and amortization (“DD&A”) expense for the three months ended March 31, 2026 decreased by approximately $50.3 million, or 18%. This decrease was primarily driven by decreased production volumes of 12.1 MBoepd discussed above as well as a decrease of $2.10 per Boe, or 7%, in the depletion rate on our proved oil and natural gas properties. The decreased production volumes and change in DD&A rate between periods caused DD&A expense to decrease by $33.5 million and $16.9 million, respectively.

General and Administrative Expense

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


	Three Months Ended March 31,
	2026		2025
General and administrative expense	$	40,970	$	34,615
General and administrative expense per Boe	$	5.13	$	3.81

Three Months Ended March 31, 2026 and 2025 — General and administrative expense for the three months ended March 31, 2026 increased by approximately $6.4 million, or 18%, primarily driven by higher employee related costs compared to the same period in 2025.

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):


	Three Months Ended March 31,
	2026			2025
Accretion expense	$	34,939		$	30,894
Impairment of oil and natural gas properties	$	145,018		$	—
Other operating (income) expense	$	11,347		$	(4,536	)
Interest expense	$	39,178		$	40,927
Price risk management activities (income) expense	$	173,547		$	15,853
Equity method investment (income) expense	$	(6,670	)	$	490
Other (income) expense	$	(4,185	)	$	(3,860	)
Income tax (benefit) expense	$	(65,292	)	$	(91	)

Three Months Ended March 31, 2026 and 2025 —

Impairment of oil and natural gas properties — During the three months ended March 31, 2026, we recorded a $145.0 million impairment of our oil and natural gas properties. The impairment is a result of our ceiling test evaluation as described in Part I, Item 1. “Financial Statements — Note 3 — Property, Plant and Equipment.”

Table of Contents

Other Operating (Income) Expense — During the three months ended March 31, 2026, we agreed to settle a lawsuit for $14.3 million. See Part I, Item 1. “Financial Statements — Note 13 — Commitments and Contingencies” for additional information.

Price Risk Management Activities — The expense of $173.5 million for the three months ended March 31, 2026 consists of $151.1 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $22.4 million in cash settlement losses. The expense of $15.9 million for the three months ended March 31, 2025 consists of $21.0 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $5.2 million in cash settlement gains.

These unrealized gains or 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 Condensed Consolidated Statements of Operations at the end of each reporting period. As a result of the derivative contracts we have on our anticipated production volumes through June 2027, we expect these activities to continue to impact net income (loss) based on fluctuations in market prices for oil and natural gas. See Part I, Item 1. “Financial Statements — Note 5 — Financial Instruments.”

Equity Method Investment (Income) Expense — During the three months ended March 31, 2026, we recorded equity income of $6.7 million, which includes a $6.8 million gain on the Incremental Mexico Equity Sale.

Income Tax (Benefit) Expense — During the three months ended March 31, 2026, we recorded $65.3 million of income tax benefit compared to $0.1 million of income tax benefit during the three months ended March 31, 2025. See Part I, Item 1. “Financial Statements — Note 10 — Income Taxes” for additional information.

Supplemental Non-GAAP Measure

EBITDA, Adjusted EBITDA and Adjusted EBITDA attributable to Talos Energy Inc.

“EBITDA,” “Adjusted EBITDA” and “Adjusted EBITDA attributable to Talos Energy Inc.” 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, Adjusted EBITDA and Adjusted EBITDA attributable to Talos Energy Inc. 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) attributable to Talos Energy Inc. plus net income (loss) attributable to noncontrolling interest, plus interest expense, income tax benefit (expense), depreciation, depletion and amortization, and accretion expense.

•

Adjusted EBITDA — EBITDA plus non-cash impairment 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 impairment of other well equipment and non-cash equity-based compensation expense.

•

Adjusted EBITDA attributable to Talos Energy Inc. — Adjusted EBITDA, less adjustments for noncontrolling interest.

Table of Contents

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):


	Three Months Ended March 31,
	2026			2025
Net income (loss) attributable to Talos Energy Inc.	$	(256,165	)	$	(9,868	)
Net income (loss) attributable to noncontrolling interest		161			—
Net income (loss)		(256,004	)		(9,868	)
Interest expense		39,178			40,927
Income tax (benefit) expense		(65,292	)		(91	)
Depreciation, depletion and amortization		230,384			280,716
Accretion expense		34,939			30,894
EBITDA		(16,795	)		342,578
Impairment of oil and natural gas properties		145,018			—
Transaction and other (income) expenses(1)		8,605			(4,579	)
Decommissioning obligations(2)		162			(157	)
Derivative fair value (gain) loss(3)		173,547			15,853
Net cash received (paid) on settled derivative instruments(3)		(22,470	)		5,167
Non-cash equity-based compensation expense		5,336			4,141
Adjusted EBITDA		293,403			363,003
Less: adjustment for noncontrolling interest		196			—
Adjusted EBITDA attributable to Talos Energy Inc.	$	293,207		$	363,003

(1)

For the three months ended March 31, 2026, transaction expenses were not material. Other income (expense) includes other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the three months ended March 31, 2026, it includes a $14.3 million litigation settlement accrued as an expense offset by a $6.8 million gain on the Incremental Mexico Equity Sale. See Part I, Item 1. “Financial Statements — Note 13 — Commitments and Contingencies” for additional information on the litigation settlement and “Financial Statements — Note 6 — Equity Method Investments” for additional information on the Incremental Mexico Equity Sale. For the three months ended March 31, 2025, neither transaction expenses nor other income (expense) were material.

(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 I, Item 1. “Financial Statements — Note 13 — 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, operating costs, working capital, debt service, share repurchases, future collateral payments and for general corporate purposes. The cost of borrowing under our bank credit facility is influenced by changes in the federal funds rate. As interest rates increase, it becomes more expensive to borrow money while interest rate cuts make it less expensive to borrow money.

Our bank credit facility currently has a borrowing base of $700.0 million. Our available liquidity (cash plus available capacity under the bank credit facility) was $989.0 million as of March 31, 2026. Letters of credit that are outstanding reduce the available bank credit commitments. The next redetermination of our borrowing base is expected in the second quarter of 2026. The borrowing base in reserve-based lending, which is influenced by banking regulations and guidelines, is a dynamic figure subject to regular redeterminations. Changes in reserve estimations (e.g., lower production forecasts or reduced proved reserves), downward adjustments to the lender's internal price deck (i.e., commodity price expectations) and ongoing production can lead to a reduction in the borrowing base, impacting available liquidity under our bank credit facility.

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. See Part I, Item 1. “Financial Statements — Note 7 — Debt” for additional information.

Table of Contents

Capital and Other Expenditures — The following is a table of our capital expenditures, excluding acquisitions, for the three months ended March 31, 2026 (in thousands):


U.S. drilling & completions	$	68,925
Asset management(1)		16,051
Seismic and G&G, land, capitalized G&A and other		33,970
Total capital expenditures		118,946
Plugging & abandonment		21,869
Decommissioning obligations settled(2)		59
Total capital and other expenditures	$	140,874

(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 I, Item 1. “Financial Statements — Note 13 — Commitments and Contingencies.”

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 the remaining portion of our 2026 capital spending program of $500.0 million to $550.0 million and plugging & abandonment and decommissioning obligations of $100.0 million to $130.0 million. However, our ability to (i) generate sufficient cash flows from operations, (ii) obtain future borrowings under the Bank Credit Facility, and (iii) 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 various operating and economic conditions, many 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 take additional future actions on an opportunistic basis. To address further changes in the financial 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.

Surety Agreements and Collateral Requirements — We entered into arrangements (“CFSAs”) with our surety providers toward the end of 2025. The CFSAs require us to post agreed upon amounts of collateral through July 1, 2031. The collateral requirements may be secured by cash or letters of credit which will reduce our liquidity. See Part I, Item 1. “Financial Statements — Note 13 — Commitments and Contingencies” for additional information.

Share Repurchase Program — The Board initially approved a share repurchase program of $100.0 million on March 20, 2023, with subsequent approval of increases in share repurchase capacity of $150.0 million on July 22, 2024 and approximately $42.5 million on March 25, 2025, for a total aggregate repurchase capacity of approximately $292.5 million. Approximately $42.7 million is remaining under the authorized program as of March 31, 2026. During the three months ended March 31, 2026, we repurchased approximately 2.7 million shares for $38.2 million excluding broker commissions. On April 27, 2026, our Board authorized an increase of $157.3 million to the previously approved limit increasing the amount remaining under the authorized program to $200.0 million. Since March 2023, in aggregate, we have repurchased 22.7 million shares for approximately $249.8 million excluding broker commissions. The share repurchase program has no set term limits. All repurchased shares are held in treasury.

Repurchases of stock 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.

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


	Three Months Ended March 31,
	2026			2025
Operating activities	$	174,001		$	268,241
Investing activities	$	(89,580	)	$	(143,308	)
Financing activities	$	(60,458	)	$	(29,394	)

Operating Activities — Cash flow from operating activities decreased $94.2 million in the three months ended March 31, 2026 compared to the corresponding period in 2025. Key drivers of cash flow from operating activities are commodity prices, production volumes and operating costs. The change between periods is largely attributable to a $40.7 million decrease in revenues due to a decrease in production volumes between periods as discussed above under the subsection entitled “— Results of Operations.” During the three months ended March 31, 2026, $22.5 million of cash was paid to settle expired commodity derivative instruments compared to $5.2 million of cash received for the corresponding period in 2025. Additionally, settlement of asset retirement obligations increased $12.1 million between the current period and the corresponding period in 2025.

Table of Contents

Investing Activities — Cash flow used in investing activities decreased $53.7 million in the three months ended March 31, 2026 compared to the corresponding period in 2025. This is primarily due to $49.7 million in cash consideration generated from the Incremental Mexico Equity Sale during three months ended March 31, 2026. Capital expenditures increased $23.4 million due to project timing between the current period and the corresponding period in 2025. During the three months ended March 31, 2025, we completed the acquisition of an incremental working interest in the Monument oil discovery in the Deepwater U.S. Gulf of America located on certain Walker Ridge lease blocks for $14.8 million compared to no acquisition payments during the three months ended March 31, 2026. Additionally, proceeds from the sale of property and equipment increased $12.6 million between the current period and the corresponding period in 2025.

Financing Activities — Cash flow used in financing activities increased $31.1 million in the three months ended March 31, 2026 compared to the corresponding period in 2025. During the three months ended March 31, 2026, we repurchased $38.2 million of our common stock through our share repurchase program compared to $17.3 million in the corresponding period in 2025. See subsection entitled “— Liquidity and Capital Resources — Share Repurchase Program” for additional information. Additionally, we incurred $6.9 million of deferred financing costs during the three months ended March 31, 2026 in connection with an amended and restated credit agreement that was executed on January 20, 2026. See Part I, Item 1. “Financial Statements — Note 7 — Debt” for additional information.

Overview of Debt Instruments

9.000% Second-Priority Senior Secured Notes — due February 2029 — The 9.000% Second-Priority Senior Secured Notes due 2029 (the “9.000% Notes”) were issued pursuant to an indenture dated February 7, 2024, by and among the Company, Talos Production Inc. (the “Issuer”), the subsidiary guarantors party thereto (together with the Company, the “Guarantors”) and Wilmington Trust, National Association, as trustee and collateral agent. The 9.000% Notes were offered and sold to qualified institutional buyers pursuant to the exemptions from registration provided by Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. 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 rank equally in right of payment with all of the Issuer’s and the Guarantors’ existing and future senior obligations, are senior in right of payment to any obligations of the Issuer and the Guarantors future debt that is, by its term, expressly subordinated in right of payment to the 9.000% Notes and, to the extent of the value of the collateral, are effectively senior to all existing and future unsecured obligations of the Issuer and the Guarantors (other than the Company) and any future obligations of the Issuer and the Guarantors that are secured by the collateral on a junior-priority basis. The 9.000% Notes are effectively pari passu with all of the Issuer’s and the Guarantors’ existing and future obligations that are secured by the collateral on a second-priority basis including the 9.375% Notes (as defined below) and are effectively junior to any existing and future obligations of the Issuer and the Guarantors that are secured by the collateral on a senior-priority basis to the 9.000% Notes including indebtedness under the Bank Credit Facility. The 9.000% Notes mature on February 1, 2029 and have interest payable semi-annually each February 1 and August 1, commencing August 1, 2024. See Part I, Item 1. “Financial Statements — Note 7 — Debt” for additional information.

9.375% Second-Priority Senior Secured Notes — due February 2031 — The 9.375% Second-Priority Senior Secured Notes due 2031 (the “9.375% Notes” and, together with the 9.000% Notes, the “Senior Notes”) were issued pursuant to an indenture dated February 7, 2024, by and among the Company, the Issuer, the Guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent. The 9.375% Notes were offered and sold to qualified institutional buyers pursuant to the exemptions from registration provided by Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. 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 rank equally in right of payment with all of the Issuer’s and the Guarantors’ existing and future senior obligations, are senior in right of payment to any obligations of the Issuer and the Guarantors future debt that is, by its term, expressly subordinated in right of payment to the 9.375% Notes and, to the extent of the value of the collateral, are effectively senior to all existing and future unsecured obligations of the Issuer and the Guarantors (other than the Company) and any future obligations of the Issuer and the Guarantors that are secured by the collateral on a junior-priority basis. The 9.375% Notes are effectively pari passu with all of the Issuer’s and the Guarantors’ existing and future obligations that are secured by the collateral on a second-priority basis including the 9.000% Notes and are effectively junior to any existing and future obligations of the Issuer and the Guarantors that are secured by the collateral on a senior-priority basis to the 9.375% Notes including indebtedness under the Bank Credit Facility. The 9.375% Notes mature on February 1, 2031 and have interest payable semi-annually each February 1 and August 1, commencing August 1, 2024. See Part I, Item 1. “Financial Statements — Note 7 — Debt” for additional information.

Revolving Reserve-based Credit Facility — matures January 2030 — We maintain a bank credit facility with a syndicate of financial institutions. The borrowing base is redetermined by the lenders at least semi-annually during the second quarter and fourth quarter of each year based on a proved reserves report that we deliver to the administrative agent of the bank credit facility. See Part I, Item 1. “Financial Statements — Note 7 — Debt” for additional information.

Table of Contents

Material Cash Requirements — We have various contractual obligations in the normal course of our operations. Some of these obligations may be reflected in our accompanying Condensed Consolidated Financial Statements, while other obligations, such as certain operating leases and capital commitments, are not reflected on our accompanying Condensed Consolidated Financial Statements. There have been no material changes to our contractual obligations since those reported in our 2025 Annual Report.

Performance Obligations — As of March 31, 2026, we had outstanding performance bonds totaling $1.5 billion primarily related to plugging and abandonment of wells and removal of facilities in the U.S. Gulf of America. Additionally, we had outstanding letters of credit issued under our bank credit facility totaling $97.4 million. Letters of credit that are outstanding reduce the available revolving credit commitments. See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2025 Annual Report subsection entitled “— Known Trends and Uncertainties — Financial Assurance Requirements” and “— Known Trends and Uncertainties — Financial Assurance Market Outlook” for additional information on BOEM’s supplemental bonding requirements and the potential lack of surety bond capacity to comply with BOEM’s financial assurance requirements, which could have a material adverse effect on our business, properties, results of operations and financial condition.

Critical Accounting Estimates

There have been no changes to our critical accounting estimates from those disclosed in our 2025 Annual Report under Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies and Estimates.”

Recently Adopted Accounting Standards

None.

Recently Issued Accounting Standards

No accounting standards were issued during the quarterly period ended March 31, 2026 that were material to us. In addition, information on Recently Issued Accounting Standards that could potentially impact our consolidated financial statements and related disclosures is incorporated by reference to Part I, Item 1. “Financial Statements — Note 1 — Organization, Nature of Business and Basis of Presentation.”

Item 3. Quantitative and Qualitative Disclosures About Market Risk

For information regarding our exposures to certain market risks, refer to Part II, Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” in our 2025 Annual Report. There have been no material changes from the disclosures presented in our 2025 Annual Report regarding our exposures to certain market risks.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

Our management, with the participation of our principal executive officer and principal financial officer, have 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 Quarterly Report. Based on such evaluation, our principal executive officer and principal financial officer have concluded that as of March 31, 2026, our disclosure controls and procedures were effective at a reasonable assurance level.

Our disclosure controls and procedures are designed at a reasonable assurance level to ensure that the 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 the SEC, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures.

Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting identified in management's evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the quarter ended March 31, 2026 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Table of Contents

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

There have been no additional material developments with respect to the information previously reported under Part I, Item 3. “Legal Proceedings” of our 2025 Annual Report.

Item 1A. Risk Factors

Our business is subject to a variety of risks and uncertainties. These risks are described elsewhere in this Quarterly Report, including in Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” above, or in our other filings with the SEC, including Part I, Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2025. You should carefully consider the risks and other cautionary statements described in this Quarterly Report, our 2025 Annual Report and the risk factors and other cautionary statements contained in our other SEC filings, which could materially affect our business, financial condition or future results. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or future results. There have been no material changes in our risk factors from those described in our 2025 Annual Report.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table sets forth information with respect to our repurchase of shares of common stock during the three months ended March 31, 2026 (in thousands, except for the share and per share amounts):


Period	Total Number of Shares Purchased		Average Price Paid		Total Number of Shares Purchased as Part of Publicly Announced Program(1)		Approximate Dollar Values of Shares that May Yet be Purchased Under the Program
January 1, 2026 - January 31, 2026		—	$	—		—	$	80,889
February 1, 2026 - February 28, 2026		178,200	$	11.98		178,200	$	78,755
March 1, 2026 - March 31, 2026		2,483,086	$	14.52		2,483,086	$	42,713
Total		2,661,286	$	14.35		2,661,286

(1)

Refer to Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Share Repurchase Program” for additional information regarding our authorized share repurchase program.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

During the three months ended March 31, 2026, 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 of Regulation S-K.

Table of Contents

Item 6. Exhibits


Exhibit Number		Description

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		Certificate of Amendment to the 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 May 23, 2024).

3.3		Certificate of Designations of Series A Junior Participating Preferred Stock 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 October 1, 2024).

3.4		Certificate of Elimination of Certificate of Designations of Series A Junior Participating Preferred Stock 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 December 17, 2024).

3.5		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 February 7, 2024, by and among Talos Production Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee (9.000% Senior Notes). (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).

4.2		First Supplemental Indenture, dated as of March 4, 2024, by and among Talos Production Inc., each of the guarantors party thereto and Wilmington Trust, National Association, as trustee and as collateral agent (9.000% Senior Notes) (incorporated by reference to Exhibit 4.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on March 5, 2024).

4.3		Indenture, dated as of February 7, 2024, by and among Talos Production Inc., the Guarantors named therein and Wilmington Trust, National Association, (9.375% Senior 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 February 7, 2024).

4.4		First Supplemental Indenture, dated as of March 4, 2024, by and among Talos Production Inc., each of the guarantors party thereto and Wilmington Trust, National Association, as trustee and as collateral agent (9.375% Senior 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 March 5, 2024).

4.5		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).

4.6		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).

10.1#		Amended and Restated Credit Agreement, dated as of January 20, 2026, 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 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 22, 2026).

10.2†*		Form of Amended and Restated Talos Energy Inc. 2021 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement (Directors).

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.

101.INS*		Inline XBRL Instance.

101.SCH*		Inline XBRL Taxonomy Extension Schema With Embedded Linkbase Documents.

104*		Cover Page Interactive Date File (Embedded within the Inline XBRL document and included in Exhibit 101).

Table of Contents


*		Filed herewith.
**		Furnished herewith.
#		Certain schedules and exhibits to this agreement have been omitted in accordance with Instruction 4 of Item 1.01 of Current Report on Form 8-K and Item 601(a)(5) of Regulation S-K. A copy of any omitted schedule and/or exhibit will be furnished to the Securities and Exchange Commission on request.
†		Identifies management contracts and compensatory plans or arrangements.

Table of Contents

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:	May 5, 2026	By:	/s/ Zachary B. Dailey
			Zachary B. Dailey
			Executive Vice President and Chief Financial Officer