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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 June 30, 2026

OR

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

For the transition period from to

Commission File Number: 001-38497

Talos Energy Inc.

(Exact Name of Registrant as Specified in its Charter)

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

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

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

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

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 July 28, 2026, the registrant had 166,965,468 shares of common stock, $0.01 par value per share, outstanding.

Table of Contents

TABL E 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 | 11
| Notes to Condensed Consolidated Financial Statements | 12
| Note 1 — Organization, Nature of Business and Basis of Presentation | 12
| Note 2 — Acquisitions and Divestitures | 13
| Note 3 — Property, Plant and Equipment | 14
| Note 4 — Leases | 14
| Note 5 — Financial Instruments | 15
| Note 6 — Equity Method Investments | 17
| Note 7 — Debt | 18
| Note 8 — Asset Retirement Obligations | 20
| Note 9 — Employee Benefits Plans and Share-Based Compensation | 20
| Note 10 — Income Taxes | 21
| Note 11 — Income (Loss) Per Share | 22
| Note 12 — Related Party Transactions | 22
| Note 13 — Commitments and Contingencies | 23
| Note 14 — Segment Information | 24
| Note 15 — Subsequent Events | 27
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 28
Item 3. | Quantitative and Qualitative Disclosures About Market Risk | 39
Item 4. | Controls and Procedures | 39
| PART II — OTHER INFORMATION |
Item 1. | Legal Proceedings | 40
Item 1A. | Risk Factors | 40
Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds | 41
Item 3. | Defaults Upon Senior Securities | 41
Item 4. | Mine Safety Disclosures | 41
Item 5. | Other Information | 41
Item 6. | Exhibits | 42
| Signatures | 44

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GLOS SARY

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.

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Proved reserves — Proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

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

PV-10 — The present value, 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%.

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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 recoverable resources, reserves and future production;
•
drilling prospects, inventories, projects, and programs for both operated and non-operated assets;
•
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 and project financing options, 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, such as the Coulomb and Na Kika Acquisition (as defined below), including the risk that we may fail to complete such transaction on the terms contemplated or at all, and/or to realize the expected benefits of any such transaction;
•
timing, 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 exploring, 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;

5

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•
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 financial assurance instruments, including 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, and government 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”), Part II, Item 1A. “Risk Factors” in our Quarterly Report on Form 10-Q for the three months ended March 31, 2026, 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.

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PART I—FINANCI AL INFORMATION

Item 1. Financial Statements

TALOS ENERGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share amounts)

| June 30, 2026 |  | December 31, 2025 |
| (Unaudited) |  |  |
ASSETS |  |  |  |
Current assets: |  |  |  |
Cash and cash equivalents | $ | 577,587 |  | $ | 362,809 |
Accounts receivable, net |  | 330,349 |  |  | 323,058 |
Assets from price risk management activities |  | 28,834 |  |  | 54,420 |
Prepaid assets |  | 141,832 |  |  | 83,080 |
Other current assets |  | 17,118 |  |  | 17,939 |
Total current assets |  | 1,095,720 |  |  | 841,306 |
Property and equipment: |  |  |  |
Proved properties |  | 10,912,984 |  |  | 10,621,012 |
Unproved properties, not subject to amortization |  | 447,034 |  |  | 480,555 |
Other property and equipment |  | 22,878 |  |  | 22,643 |
Total property and equipment |  | 11,382,896 |  |  | 11,124,210 |
Accumulated depreciation, depletion and amortization |  | (7,291,346 | ) |  | (6,686,575 | )
Total property and equipment, net |  | 4,091,550 |  |  | 4,437,635 |
Other long-term assets: |  |  |  |
Restricted cash |  | 76,997 |  |  | 76,181 |
Equity method investments |  | 44,661 |  |  | 112,382 |
Other well equipment |  | 61,517 |  |  | 49,307 |
Notes receivable, net |  | 20,653 |  |  | 19,636 |
Operating lease assets |  | 8,345 |  |  | 9,214 |
Other assets |  | 33,836 |  |  | 6,396 |
Total assets | $ | 5,433,279 |  | $ | 5,552,057 |
LIABILITIES AND EQUITY |  |  |  |
Current liabilities: |  |  |  |
Accounts payable | $ | 87,837 |  | $ | 92,979 |
Accrued liabilities |  | 225,214 |  |  | 290,223 |
Accrued royalties |  | 99,237 |  |  | 59,768 |
Current portion of asset retirement obligations |  | 153,225 |  |  | 112,489 |
Liabilities from price risk management activities |  | 27,504 |  |  | 6,708 |
Accrued interest payable |  | 49,181 |  |  | 48,972 |
Current portion of operating lease liabilities |  | 3,872 |  |  | 3,657 |
Other current liabilities |  | 33,427 |  |  | 29,925 |
Total current liabilities |  | 679,497 |  |  | 644,721 |
Long-term liabilities: |  |  |  |
Long-term debt |  | 1,228,764 |  |  | 1,226,189 |
Asset retirement obligations |  | 1,240,920 |  |  | 1,219,639 |
Operating lease liabilities |  | 10,051 |  |  | 11,956 |
Other long-term liabilities |  | 240,891 |  |  | 281,429 |
Total liabilities |  | 3,400,123 |  |  | 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 June 30, 2026 and December 31, 2025, respectively |  | — |  |  | — |
Common stock; $0.01 par value; 270,000,000 shares authorized; 189,641,450 and 188,530,052 shares issued as of June 30, 2026 and December 31, 2025, respectively |  | 1,896 |  |  | 1,885 |
Additional paid-in capital |  | 3,305,983 |  |  | 3,296,643 |
Accumulated deficit |  | (1,024,898 | ) |  | (918,400 | )
Treasury stock, at cost; 22,676,655 and 20,015,369 shares as of June 30, 2026 and December 31, 2025, respectively |  | (250,347 | ) |  | (212,144 | )
Total Talos Energy Inc. stockholders' equity |  | 2,032,634 |  |  | 2,167,984 |
Noncontrolling interest |  | 522 |  |  | 139 |
Total equity |  | 2,033,156 |  |  | 2,168,123 |
Total liabilities and equity | $ | 5,433,279 |  | $ | 5,552,057 |

See accompanying notes.

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TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)

| Three Months Ended June 30, |  | Six Months Ended June 30, |
| 2026 |  | 2025 |  | 2026 |  | 2025 |
Revenues: |  |  |  |  |  |  |  |
Oil | $ | 620,768 |  | $ | 373,195 |  | $ | 1,028,766 |  | $ | 813,918 |
Natural gas |  | 31,040 |  |  | 39,415 |  |  | 83,943 |  |  | 92,150 |
NGL |  | 13,005 |  |  | 12,111 |  |  | 24,414 |  |  | 31,712 |
Total revenues |  | 664,813 |  |  | 424,721 |  |  | 1,137,123 |  |  | 937,780 |
Operating expenses: |  |  |  |  |  |  |  |
Lease operating expense |  | 155,683 |  |  | 136,971 |  |  | 284,718 |  |  | 264,776 |
Production taxes |  | 103 |  |  | 130 |  |  | 146 |  |  | 244 |
Depreciation, depletion and amortization |  | 229,369 |  |  | 269,706 |  |  | 459,753 |  |  | 550,422 |
Impairment of oil and natural gas properties |  | — |  |  | 223,881 |  |  | 145,018 |  |  | 223,881 |
Accretion expense |  | 35,908 |  |  | 32,046 |  |  | 70,847 |  |  | 62,940 |
General and administrative expense |  | 44,626 |  |  | 39,430 |  |  | 85,596 |  |  | 74,045 |
Other operating (income) expense |  | 902 |  |  | (3,851 | ) |  | 12,249 |  |  | (8,387 | )
Total operating expenses |  | 466,591 |  |  | 698,313 |  |  | 1,058,327 |  |  | 1,167,921 |
Operating income (expense) |  | 198,222 |  |  | (273,592 | ) |  | 78,796 |  |  | (230,141 | )
Interest expense |  | (39,162 | ) |  | (40,811 | ) |  | (78,340 | ) |  | (81,738 | )
Price risk management activities income (expense) |  | 30,549 |  |  | 86,855 |  |  | (142,998 | ) |  | 71,002 |
Equity method investment income (expense) |  | (113 | ) |  | (186 | ) |  | 6,557 |  |  | (676 | )
Other income (expense) |  | 5,230 |  |  | 5,371 |  |  | 9,415 |  |  | 9,231 |
Net income (loss) before income taxes |  | 194,726 |  |  | (222,363 | ) |  | (126,570 | ) |  | (232,322 | )
Income tax benefit (expense) |  | (44,837 | ) |  | 36,426 |  |  | 20,455 |  |  | 36,517 |
Net income (loss) | $ | 149,889 |  | $ | (185,937 | ) | $ | (106,115 | ) | $ | (195,805 | )
Net income (loss) attributable to noncontrolling interest |  | 222 |  |  | — |  |  | 383 |  |  | — |
Net income (loss) attributable to Talos Energy Inc. | $ | 149,667 |  | $ | (185,937 | ) | $ | (106,498 | ) | $ | (195,805 | )
Net income (loss) per share attributable to common stockholders: |  |  |  |  |  |  |  |
Basic | $ | 0.90 |  | $ | (1.05 | ) | $ | (0.64 | ) | $ | (1.10 | )
Diluted | $ | 0.88 |  | $ | (1.05 | ) | $ | (0.64 | ) | $ | (1.10 | )
Weighted average common shares outstanding: |  |  |  |  |  |  |  |
Basic |  | 166,980 |  |  | 177,404 |  |  | 167,677 |  |  | 178,791 |
Diluted |  | 170,085 |  |  | 177,404 |  |  | 167,677 |  |  | 178,791 |

See accompanying notes.

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TA LOS 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 March 31, 2025 | $ | 1,882 |  | $ | 3,278,165 |  | $ | (433,978 | ) | $ | (114,753 | ) | $ | 2,731,316 |  | $ | — |  | $ | 2,731,316 |
Equity-based compensation |  | — |  |  | 6,316 |  |  | — |  |  | — |  |  | 6,316 |  |  | — |  |  | 6,316 |
Equity-based compensation tax withholdings |  | — |  |  | (14 | ) |  | — |  |  | — |  |  | (14 | ) |  | — |  |  | (14 | )
Purchase of treasury stock |  | — |  |  | — |  |  | — |  |  | (32,668 | ) |  | (32,668 | ) |  | — |  |  | (32,668 | )
Net income (loss) |  | — |  |  | — |  |  | (185,937 | ) |  | — |  |  | (185,937 | ) |  | — |  |  | (185,937 | )
Balance at June 30, 2025 | $ | 1,882 |  | $ | 3,284,467 |  | $ | (619,915 | ) | $ | (147,421 | ) | $ | 2,519,013 |  | $ | — |  | $ | 2,519,013 |
Balance at March 31, 2026 | $ | 1,896 |  | $ | 3,297,535 |  | $ | (1,174,565 | ) | $ | (250,347 | ) | $ | 1,874,519 |  | $ | 300 |  | $ | 1,874,819 |
Equity-based compensation |  | — |  |  | 8,528 |  |  | — |  |  | — |  |  | 8,528 |  |  | — |  |  | 8,528 |
Equity-based compensation tax withholdings |  | — |  |  | (80 | ) |  | — |  |  | — |  |  | (80 | ) |  | — |  |  | (80 | )
Net income (loss) |  | — |  |  | — |  |  | 149,667 |  |  | — |  |  | 149,667 |  |  | 222 |  |  | 149,889 |
Balance at June 30, 2026 | $ | 1,896 |  | $ | 3,305,983 |  | $ | (1,024,898 | ) | $ | (250,347 | ) | $ | 2,032,634 |  | $ | 522 |  | $ | 2,033,156 |

Common Stock Share Activity | Issued |  | Held in Treasury |  | Outstanding |
Balance at March 31, 2025 |  | 188,160,804 |  |  | (9,705,658 | ) |  | 178,455,146 |
Equity-based compensation stock issuances |  | 40,869 |  |  | — |  |  | 40,869 |
Purchase of treasury stock |  | — |  |  | (3,838,670 | ) |  | (3,838,670 | )
Balance at June 30, 2025 |  | 188,201,673 |  |  | (13,544,328 | ) |  | 174,657,345 |
Balance at March 31, 2026 |  | 189,589,004 |  |  | (22,676,655 | ) |  | 166,912,349 |
Equity-based compensation stock issuances |  | 52,446 |  |  | — |  |  | 52,446 |
Balance at June 30, 2026 |  | 189,641,450 |  |  | (22,676,655 | ) |  | 166,964,795 |

See accompanying notes.

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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 |  | — |  |  | 12,248 |  |  | — |  |  | — |  |  | 12,248 |  |  | — |  |  | 12,248 |
Equity-based compensation tax withholdings |  | — |  |  | (2,399 | ) |  | — |  |  | — |  |  | (2,399 | ) |  | — |  |  | (2,399 | )
Equity-based compensation stock issuances |  | 8 |  |  | (8 | ) |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Purchase of treasury stock |  | — |  |  | — |  |  | — |  |  | (54,736 | ) |  | (54,736 | ) |  | — |  |  | (54,736 | )
Net income (loss) |  | — |  |  | — |  |  | (195,805 | ) |  | — |  |  | (195,805 | ) |  | — |  |  | (195,805 | )
Balance at June 30, 2025 | $ | 1,882 |  | $ | 3,284,467 |  | $ | (619,915 | ) | $ | (147,421 | ) | $ | 2,519,013 |  | $ | — |  | $ | 2,519,013 |
Balance at December 31, 2025 | $ | 1,885 |  | $ | 3,296,643 |  | $ | (918,400 | ) | $ | (212,144 | ) | $ | 2,167,984 |  | $ | 139 |  | $ | 2,168,123 |
Equity-based compensation |  | — |  |  | 15,296 |  |  | — |  |  | — |  |  | 15,296 |  |  | — |  |  | 15,296 |
Equity-based compensation tax withholdings |  | — |  |  | (5,945 | ) |  | — |  |  | — |  |  | (5,945 | ) |  | — |  |  | (5,945 | )
Equity-based compensation stock issuances |  | 11 |  |  | (11 | ) |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Purchase of treasury stock |  | — |  |  | — |  |  | — |  |  | (38,203 | ) |  | (38,203 | ) |  | — |  |  | (38,203 | )
Net income (loss) |  | — |  |  | — |  |  | (106,498 | ) |  | — |  |  | (106,498 | ) |  | 383 |  |  | (106,115 | )
Balance at June 30, 2026 | $ | 1,896 |  | $ | 3,305,983 |  | $ | (1,024,898 | ) | $ | (250,347 | ) | $ | 2,032,634 |  | $ | 522 |  | $ | 2,033,156 |

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 |  | 766,765 |  |  | — |  |  | 766,765 |
Purchase of treasury stock |  | — |  |  | (6,126,943 | ) |  | (6,126,943 | )
Balance at June 30, 2025 |  | 188,201,673 |  |  | (13,544,328 | ) |  | 174,657,345 |
Balance at December 31, 2025 |  | 188,530,052 |  |  | (20,015,369 | ) |  | 168,514,683 |
Equity-based compensation stock issuances |  | 1,111,398 |  |  | — |  |  | 1,111,398 |
Purchase of treasury stock |  | — |  |  | (2,661,286 | ) |  | (2,661,286 | )
Balance at June 30, 2026 |  | 189,641,450 |  |  | (22,676,655 | ) |  | 166,964,795 |

See accompanying notes.

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TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

| Six Months Ended June 30, |
| 2026 |  | 2025 |
Cash flows from operating activities: |  |  |  |
Net income (loss) | $ | (106,115 | ) | $ | (195,805 | )
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: |  |  |  |
Depreciation, depletion, amortization and accretion expense |  | 530,600 |  |  | 613,362 |
Impairment of oil and natural gas properties |  | 145,018 |  |  | 223,881 |
Amortization of deferred financing costs and original issue discount |  | 3,862 |  |  | 3,695 |
Equity-based compensation expense |  | 11,745 |  |  | 8,544 |
Price risk management activities (income) expense |  | 142,998 |  |  | (71,002 | )
Net cash received (paid) on settled derivative instruments |  | (96,616 | ) |  | 38,482 |
Equity method investment (income) expense |  | (6,557 | ) |  | 676 |
Settlement of asset retirement obligations |  | (40,571 | ) |  | (38,249 | )
Loss (gain) on sale of assets |  | 1,564 |  |  | (16 | )
Changes in operating assets and liabilities: |  |  |  |
Accounts receivable |  | (11,096 | ) |  | 63,863 |
Other current assets |  | (57,931 | ) |  | 24,361 |
Accounts payable |  | 333 |  |  | (2,451 | )
Other current liabilities |  | 3,631 |  |  | (9,244 | )
Other non-current assets and liabilities, net |  | (46,228 | ) |  | (40,219 | )
Net cash provided by (used in) operating activities |  | 474,637 |  |  | 619,878 |
Cash flows from investing activities: |  |  |  |
Exploration, development and other capital expenditures |  | (254,037 | ) |  | (276,149 | )
Payments for acquisitions, net of cash acquired |  | (3,125 | ) |  | (14,845 | )
Proceeds from (cash paid for) sale of property and equipment, net |  | 15,027 |  |  | 687 |
Contributions to equity method investees |  | — |  |  | (1,996 | )
Proceeds from sale of equity method investments |  | 49,665 |  |  | — |
Net cash provided by (used in) investing activities |  | (192,470 | ) |  | (292,303 | )
Cash flows from financing activities: |  |  |  |
Deferred financing costs |  | (7,349 | ) |  | — |
Other deferred payments |  | (4,548 | ) |  | (10,172 | )
Payments of finance lease |  | (10,528 | ) |  | (9,616 | )
Purchase of treasury stock |  | (38,203 | ) |  | (54,736 | )
Employee stock awards tax withholdings |  | (5,945 | ) |  | (2,399 | )
Net cash provided by (used in) financing activities |  | (66,573 | ) |  | (76,923 | )
Net increase (decrease) in cash, cash equivalents and restricted cash |  | 215,594 |  |  | 250,652 |
Cash, cash equivalents and restricted cash: |  |  |  |
Balance, beginning of period |  | 438,990 |  |  | 214,432 |
Balance, end of period | $ | 654,584 |  | $ | 465,084 |
Supplemental non-cash transactions: |  |  |  |
Capital expenditures included in accounts payable and accrued liabilities | $ | 59,974 |  | $ | 48,926 |
Supplemental cash flow information: |  |  |  |
Interest paid, net of amounts capitalized | $ | 57,618 |  | $ | 59,769 |

See accompanying notes.

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TALOS ENERGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Not e 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 area of the U.S. Gulf of America, which the Company defines as water depths of more than 600 feet. 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):

| June 30, 2026 |  | December 31, 2025 |
Cash and cash equivalents | $ | 577,587 |  | $ | 362,809 |
Restricted cash included in Other long-term assets |  | 76,997 |  |  | 76,181 |
Total cash, cash equivalent and restricted cash | $ | 654,584 |  | $ | 438,990 |

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Accounts Receivable

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

| June 30, 2026 |  | December 31, 2025 |
Trade | $ | 250,993 |  | $ | 166,793 |
Joint interest |  | 67,673 |  |  | 132,527 |
Other |  | 11,683 |  |  | 23,738 |
Total accounts receivable, net | $ | 330,349 |  | $ | 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. As of June 30, 2026, an additional $3.2 million contingent payment will be recognized upon the achievement of certain milestones defined in the agreement. This incremental acquisition brought the Company’s total non-operated working interest in the Monument oil discovery to 29.7%.

Subsequent Events — On July 22, 2026, the Company entered into a definitive agreement to farm into the Block 29 development offshore Mexico. The Company will acquire a 50% working interest for a contingent $30.0 million payment at final investment decision, a cash carry of up to $20.0 million on the next exploration well, and reimbursement of certain pre-closing costs (the “Offshore Mexico Farm-In Transaction”).

Additionally, on July 29, 2026, the Company entered into agreements to acquire an 80% operated working interest in an early-phase offshore Honduras project and related seismic evaluation (the “Honduras Transaction”). The Company closed on a 45% working interest and assumed operatorship. The acquisition of the remaining 35% working interest is subject to Honduran regulatory approval. Consideration for the Honduras Transactions includes a reimbursement of sunk costs, a seismic carry, and a contingent discovery bonus.

Pending Acquisition

On June 30, 2026, the Company and a third party entered into a purchase and sale agreement (“Shell Purchase Agreement”) with Shell Offshore Inc. (“Shell”) to acquire certain oil and gas properties and related assets in the Mississippi Canyon area of the Gulf of America, including interests in the Na Kika and Coulomb Deepwater producing assets (the “PSA Assets”). The Shell Purchase Agreement has an economic effective date of July 1, 2025, and is subject to customary purchase price adjustments and closing conditions.

Pursuant to the Shell Purchase Agreement, the Company expects to acquire an undivided 50% interest in the PSA Assets comprising a 50% working interest and operatorship in the Coulomb Field as well as a 25% working interest in the BP-operated Na Kika platform and related Kepler, Ariel, Fourier and Herschel Fields (collectively, the “Coulomb and Na Kika Acquisition”). Shell’s working interests in the Kepler, Ariel, Fourier and Herschel Fields were subject to a preferential purchase right held by BP, which BP waived.

The Company’s share of the unadjusted cash purchase price is $850.0 million. Concurrently with entry into the Shell Purchase Agreement, the Company deposited $42.5 million into escrow, which will be credited against the purchase price payable at closing. The escrow deposit is reflected as “Prepaid assets” on the Condensed Consolidated Balance Sheets. Assuming the Coulomb and Na Kika Acquisition closes on September 1, 2026, the Company estimates that its cash consideration payable at closing will range between $407.5 million and $457.5 million after customary purchase price adjustments and application of the deposit paid at signing. The Company expects to fund the closing cash consideration with a portion of the net proceeds from its offering of the 8.000% Notes, as defined in Note 7 — Debt, together with cash on hand.

The Shell Purchase Agreement also provides for (i) a price-based upside sharing arrangement and a commitment of 100% of oil volumes through December 31, 2027 via a crude oil purchase agreement with a Shell affiliate, (ii) a 1.25% overriding royalty interest granted to Shell for production from certain new leases utilizing the Na Kika platform that may be entered into in the future, (iii) contingent payments to Shell of up to $10.0 million if certain future events occur related to third-party production handling agreements at the Na Kika platform and (iv) Talos to provide financial assurance for future abandonment obligations.

Divestitures

During the six months ended June 30, 2026, the Company sold a portion of its equity method investment in Talos Energy Mexico 7, S. de R.L. de C.V. (“TEM 7”). See Note 6 – Equity Method Investments for additional information.

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Subsequent Event — On July 15, 2026, the Company divested a wholly-owned subsidiary holding non-core, gas-weighted and predominantly non-operated Shelf and Gulf Coast properties pursuant to a purchase and sale agreement. The total consideration received for the transaction was approximately $22.6 million, inclusive of liabilities divested and $31.5 million cash paid to the buyer.

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 six months ended June 30, 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. The Company did no t record an impairment during the three months ended June 30, 2026. At June 30, 2026, the Company’s ceiling test computation was based on SEC pricing of $71.93 per Bbl of oil, $3.91 per Mcf of natural gas and $18.63 per Bbl of NGLs. By comparison, during both the three and six months ended June 30, 2025, the Company recorded an impairment of $223.9 million.

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.

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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 June 30, |  | Six Months Ended June 30, |
| 2026 |  | 2025 |  | 2026 |  | 2025 |
Finance lease costs - interest on lease liabilities | $ | 2,385 |  | $ | 2,848 |  | $ | 4,863 |  | $ | 5,775 |
Operating lease costs, excluding short-term leases(1) |  | 903 |  |  | 1,081 |  |  | 1,806 |  |  | 2,156 |
Short-term lease costs(2) |  | 791 |  |  | 29,995 |  |  | 35,897 |  |  | 70,108 |
Variable lease costs(3) |  | 670 |  |  | 667 |  |  | 1,340 |  |  | 1,334 |
Variable and fixed sublease income |  | (403 | ) |  | (396 | ) |  | (800 | ) |  | (793 | )
Total lease costs | $ | 4,346 |  | $ | 34,195 |  | $ | 43,106 |  | $ | 78,580 |

(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):

| June 30, 2026 |  | December 31, 2025 |
Operating leases: |  |  |  |
Operating lease assets | $ | 8,345 |  | $ | 9,214 |
Current portion of operating lease liabilities | $ | 3,872 |  | $ | 3,657 |
Operating lease liabilities |  | 10,051 |  |  | 11,956 |
Total operating lease liabilities | $ | 13,923 |  | $ | 15,613 |
Finance leases: |  |  |  |
Proved properties | $ | 166,261 |  | $ | 166,261 |
Other current liabilities | $ | 22,472 |  | $ | 21,473 |
Other long-term liabilities |  | 78,641 |  |  | 90,169 |
Total finance lease liabilities | $ | 101,113 |  | $ | 111,642 |

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

| Six Months Ended June 30, |
| 2026 |  | 2025 |
Operating cash outflow from finance leases | $ | 4,863 |  | $ | 5,775 |
Operating cash outflow from operating leases | $ | 2,611 |  | $ | 2,969 |

Subsequent Event — On July 1, 2026, the Company entered into a 365-day minimum commitment vessel contract for approximately $160.0 million. The Company plans to utilize the vessel for certain Deepwater drilling and completion operations commencing in mid-2027. Other joint owners, to the extent they elect to participate, will be billed for their working interest share of such costs.

Note 5 — Financial Instruments

As of June 30, 2026 and December 31, 2025, the carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair values because they are highly liquid or due to the short-term nature of these instruments.

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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):

| June 30, 2026 |  | December 31, 2025 |
| Carrying Amount |  | Fair Value |  | Carrying Amount |  | Fair Value |
9.000% Second-Priority Senior Secured Notes | $ | 615,629 |  | $ | 651,313 |  | $ | 614,058 |  | $ | 649,425 |
9.375% Second-Priority Senior Secured Notes | $ | 613,135 |  | $ | 656,713 |  | $ | 612,131 |  | $ | 656,250 |

The carrying values of the 9.000% Second-Priority Senior Secured Notes due 2029 and 9.375% Second-Priority Senior Secured Notes due 2031 (together, the “Senior Notes”) are adjusted for 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 June 30, |  | Six Months Ended June 30, |
| 2026 |  | 2025 |  | 2026 |  | 2025 |
Net cash received (paid) on settled derivative instruments | $ | (74,146 | ) | $ | 33,315 |  | $ | (96,616 | ) | $ | 38,482 |
Unrealized gain (loss) |  | 104,695 |  |  | 53,540 |  |  | (46,382 | ) |  | 32,520 |
Price risk management activities income (expense) | $ | 30,549 |  | $ | 86,855 |  | $ | (142,998 | ) | $ | 71,002 |

The following tables reflect the contracted average daily volumes and weighted average prices under the terms of the Company's derivative contracts as of June 30, 2026:

Swap Contracts |
Production Period | Settlement Index | Volumes |  | Swap Price |
Crude oil: |  | (Bbls) |  | (per Bbl) |
July 2026 – December 2026 | NYMEX WTI CMA |  | 3,842 |  | $ | 65.03 |
January 2027 – June 2027 | NYMEX WTI CMA |  | 4,000 |  | $ | 73.75 |
Natural gas: |  | (MMBtu) |  | (per MMBtu) |
July 2026 – December 2026 | NYMEX Henry Hub |  | 28,342 |  | $ | 3.64 |

Two-Way Collar Contracts |
Production Period | Settlement Index | Volumes |  | Floor Price |  | Ceiling Price |
Crude oil: |  | (Bbls) |  | (per Bbl) |  | (per Bbl) |
July 2026 – December 2026 | NYMEX WTI CMA |  | 20,326 |  | $ | 60.90 |  | $ | 72.83 |
January 2027 – June 2027 | NYMEX WTI CMA |  | 13,972 |  | $ | 62.16 |  | $ | 76.71 |
Natural gas: |  | (MMBtu) |  | (per MMBtu) |  | (per MMBtu) |
January 2027 – March 2027 | NYMEX Henry Hub |  | 35,000 |  | $ | 3.51 |  | $ | 5.00 |

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

| June 30, 2026 |
| Level 1 |  | Level 2 |  | Level 3 |  | Total |
Assets: |  |  |  |  |  |  |  |
Oil and natural gas derivatives | $ | — |  | $ | 28,834 |  | $ | — |  | $ | 28,834 |
Liabilities: |  |  |  |  |  |  |  |
Oil and natural gas derivatives |  | — |  |  | (27,504 | ) |  | — |  |  | (27,504 | )
Total net asset (liability) | $ | — |  | $ | 1,330 |  | $ | — |  | $ | 1,330 |

| 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 |

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):

| June 30, 2026 |  | December 31, 2025 |
| Assets |  | Liabilities |  | Assets |  | Liabilities |
Oil and natural gas derivatives: |  |  |  |  |  |  |  |
Current | $ | 28,834 |  | $ | 27,504 |  | $ | 54,420 |  | $ | 6,708 |
Total gross amounts presented on balance sheet |  | 28,834 |  |  | 27,504 |  |  | 54,420 |  |  | 6,708 |
Less: Gross amounts not offset on the balance sheet |  | 24,210 |  |  | 24,210 |  |  | 6,708 |  |  | 6,708 |
Net amounts | $ | 4,624 |  | $ | 3,294 |  | $ | 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 June 30, 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. Had the Company’s counterparties failed to perform under existing commodity derivative contracts, the maximum loss at June 30, 2026 would have been $4.6 million.

Note 6 — Equity Method Investments

As of June 30, 2026 and December 31, 2025, the Company's ownership interest in TEM 7 was 20.0% and 50.1%, respectively, and the carrying amount of its investment was $44.7 million and $112.4 million, respectively. As of June 30, 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. TEM 7 is a variable interest entity and the Company's maximum exposure to loss as a result of its involvement with TEM 7 is the carrying amount of its investment.

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On March 25, 2026, the Company sold an additional 30.1% equity interest in TEM 7 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 as of June 30, 2026. 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 of contingent payments upon the Zama Field reaching first oil production. Of this amount, $49.9 million is associated with the initial TEM 7 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 has not yet been recognized in the Company’s financial statements, 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 | June 30, 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 deferred financing cost |  |  | 1,250,000 |  |  | 1,250,000 |
Unamortized deferred financing cost, net |  |  | (21,236 | ) |  | (23,811 | )
Total debt(1) |  | $ | 1,228,764 |  | $ | 1,226,189 |

(1)
As of June 30, 2026, the Company was in compliance with all debt covenants.

Subsequent Event — 8.000% Second-Priority Senior Secured Notes due July 2034

Talos Production Inc. (“Talos Production” or “Issuer”), a Delaware corporation and wholly-owned subsidiary of the Company, issued $800.0 million 8.000% Second-Priority Senior Secured Notes due 2034 (the “8.000% Notes”) pursuant to an indenture dated July 13, 2026, by and among the Parent Company, Talos Production Inc., the subsidiary guarantors party thereto (together with the Parent Company, the “8.000% Notes Guarantors”) and Wilmington Trust, National Association, as trustee and collateral agent (“Trustee”). The 8.000% 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 8.000% Notes rank equally in right of payment with all of the Issuer’s and the 8.000% Notes Guarantors’ existing and future senior obligations, are senior in right of payment to any obligations of the Issuer and the 8.000% Notes Guarantors’ future debt that is, by its term, expressly subordinated in right of payment to the 8.000% 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 8.000% Notes Guarantors (other than the Company) and any future obligations of the Issuer and the 8.000% Notes Guarantors that are secured by the collateral on a junior-priority basis. The 8.000% Notes are effectively pari passu with all of the Issuer’s and the 8.000% Notes Guarantors’ existing and future obligations that are secured by the collateral on a second-priority basis including the 9.375% Second-Priority Senior Secured Notes due 2031 and are effectively junior to any existing and future obligations of the Issuer and the 8.000% Notes Guarantors that are secured by the collateral on a senior-priority basis to the 8.000% Notes including indebtedness under the bank credit facility. The 8.000% Notes mature on July 15, 2034 and have interest payable semi-annually each January 15 and July 15, commencing January 15, 2027.

If (1) the consummation of the Coulomb and Na Kika Acquisition does not occur on or before December 31, 2026, (2) the Company delivers a notice to the Trustee that the Company will not pursue the consummation of the Coulomb and Na Kika Acquisition, or (3) BP exercises its preferential purchase right with respect to Shell’s interests in the Na Kika platform and related Kepler, Ariel, Fourier and Herschel Fields, then Talos Production will be required to redeem $175.0 million aggregate principal amount of the 8.000% Notes then outstanding, at a redemption price equal to 100% of the principal amount of the 8.000% Notes to be redeemed, plus accrued and unpaid interest on the 8.000% Notes being redeemed, if any, to, but excluding, the special mandatory redemption date. Effective as of July 20, 2026, BP formally waived its preferential purchase right.

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At any time prior to July 15, 2029, Talos Production may redeem up to 40% of the principal amount of the 8.000% Notes with the net proceeds from certain equity offerings at a redemption rate of 108.00% of the principal amount plus accrued and unpaid interest. At any time prior to July 15, 2029, Talos Production may also redeem some or all of the 8.000% Notes, plus a “make-whole premium,” together with accrued and unpaid interest, if any, to, but excluding, the date of redemption. Thereafter, Talos Production may redeem all or a portion of the 8.000% Notes in whole at any time or in part from time to time at the following redemption prices (expressed as percentages of the principal amount) plus accrued and unpaid interest if redeemed during the period commencing on July 15 of the years set forth below:

Period |  | Redemption Price |
2029 |  |  | 104.000 | %
2030 |  |  | 102.000 | %
2031 and thereafter |  |  | 100.000 | %

Subsequent Event — Redemption of 9.000% Second-Priority Senior Secured Notes due February 2029

On July 13, 2026, the Company redeemed all $625.0 million aggregate principal amount of the 9.000% Second-Priority Senior Secured Notes due 2029 at 104.500% plus accrued and unpaid interest using the net proceeds from the issuance of the 8.000% Notes.

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, and certain other direct and indirect subsidiaries of both the Parent Company and Talos Production entered into the Amended and Restated Credit Agreement (as it may be amended, supplemented, waived or otherwise modified from time to time, the “A&R Credit Agreement”) among the Parent 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 Parent 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 matures on January 20, 2030 and has an initial borrowing base and total commitments of $700.0 million (with a letter of credit facility with a $250.0 million sublimit).

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 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 of 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.

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On June 30, 2026, contemporaneously with execution of the Shell Purchase Agreement, the Parent Company, Talos Production, and certain other direct and indirect subsidiaries of both the Parent Company and Talos Production entered into the Borrowing Base Redetermination Agreement, Incremental Agreement, and First Amendment to Amended and Restated Credit Agreement (the “First Amendment”). The First Amendment, among other things, permits the incurrence of additional indebtedness in order to fund the Coulomb and Na Kika Acquisition, with such indebtedness excluded from any reduction of the borrowing base that would otherwise result from such incurrence, and reaffirms the borrowing base at $700.0 million as part of the biannual redetermination of the borrowing base, effective upon closing of the First Amendment. The First Amendment also (i) provides for a borrowing base increase from $700.0 million to $850.0 million and (ii) provides for an increase in the letter of credit sublimit from $250.0 million to $300.0 million, in each case, subject to and effective upon the consummation of the Coulomb and Na Kika Acquisition.

Subsequent Event — On July 22, 2026, the Company entered into the Second Amendment to the A&R Credit Agreement (the “Second Amendment”), which provides additional financing flexibility for costs associated with the Offshore Mexico Farm-In Transaction. The Second Amendment also increases, solely with respect to qualifying investments in Phoenix-Durango Offshore Company, S. de R.L. de C.V. made before December 31, 2027, the maximum Consolidated Total Debt to EBITDAX Ratio applicable to investments made without regard to Available Free Cash Flow from 1.25 to 1.50.

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 |  | (40,571 | )
Accretion expense |  | 70,847 |
Changes in estimate |  | 25,506 |
Asset retirement obligations at June 30, 2026 | $ | 1,394,145 |
Less: Current portion at June 30, 2026 |  | 153,225 |
Long-term portion at June 30, 2026 | $ | 1,240,920 |

At June 30, 2026, the Company has (1) restricted cash of $77.0 million held in escrow and (2) two notes receivable with an aggregated face value of $66.2 million to settle future asset retirement obligations.

Note 9 — Employee Benefits Plans and Share-Based Compensation

The Second Amended and Restated Talos Energy Inc. 2021 Long Term Incentive Plan (the “A&R LTIP”) became effective on June 4, 2026 and authorizes the Company to grant awards of up to 16,939,415 shares of the Company’s common stock, subject to the share recycling and adjustment provisions of the A&R LTIP. The A&R LTIP also extends the term of the plan to June 4, 2036.

The A&R LTIP provides for potential grants of: (i) incentive stock options qualified as such under U.S. federal income tax laws (“ISOs”), (ii) stock options that do not qualify as ISOs, (iii) stock appreciation rights, (iv) restricted stock awards, (v) restricted stock units, (vi) awards of vested stock, (vii) dividend equivalents, (viii) other share-based or cash awards and (ix) substitute awards. Employees, non-employee directors and other service providers of the Company and its affiliates are eligible to receive awards under the A&R LTIP.

Long Term Incentive Plans

Restricted Stock Units (“RSUs”) — The following table summarizes RSU activity under the A&R LTIP for the six months ended June 30, 2026:

| Restricted Stock Units |  | Weighted Average Grant Date Fair Value |
Unvested RSUs at December 31, 2025 |  | 4,595,755 |  | $ | 10.25 |
Granted |  | 2,119,949 |  | $ | 13.18 |
Vested |  | (1,598,070 | ) | $ | 10.79 |
Forfeited |  | (299,821 | ) | $ | 10.58 |
Unvested RSUs at June 30, 2026 |  | 4,817,813 |  | $ | 11.34 |

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Performance Share Units (“PSUs”) — The following table summarizes PSU activity under the A&R LTIP for the six months ended June 30, 2026:

| Performance Share Units |  | Weighted Average Grant Date Fair Value |
Unvested PSUs at December 31, 2025 |  | 1,114,299 |  | $ | 10.02 |
Granted(1)(2) |  | 561,609 |  | $ | 16.68 |
Forfeited |  | (16,781 | ) | $ | 11.07 |
Unvested PSUs at June 30, 2026 |  | 1,659,127 |  | $ | 12.27 |

(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 280,802 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 June 30, |  | Six Months Ended June 30, |
| 2026 |  | 2025 |  | 2026 |  | 2025 |
Share-based compensation costs | $ | 8,669 |  | $ | 6,362 |  | $ | 15,750 |  | $ | 12,302 |
Less: Amounts capitalized to oil and gas properties |  | 2,260 |  |  | 1,959 |  |  | 4,005 |  |  | 3,758 |
Total share-based compensation expense | $ | 6,409 |  | $ | 4,403 |  | $ | 11,745 |  | $ | 8,544 |

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 June 30, 2026, the Company recognized an income tax expense of $44.8 million for an effective tax rate of 23.0%. 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 and a change in valuation allowance.

For the three months ended June 30, 2025, the Company recognized an income tax benefit of $36.4 million for an effective tax rate of 16.4%. 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 recording a valuation allowance on its U.S. federal deferred tax assets.

For the six months ended June 30, 2026, the Company recognized an income tax benefit of $20.5 million for an effective tax rate of 16.2%. 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 and a change in the valuation allowance.

For the six months ended June 30, 2025, the Company recognized an income tax benefit of $36.5 million for an effective tax rate of 15.7%. 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 recording a valuation allowance on its U.S. federal deferred tax assets.

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.

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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 $133.4 million and $156.7 million is included in “Other long-term liabilities” on the Condensed Consolidated Balance Sheets as of June 30, 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 June 30, |  | Six Months Ended June 30, |
| 2026 |  | 2025 |  | 2026 |  | 2025 |
Net income (loss) attributable to Talos Energy Inc. | $ | 149,667 |  | $ | (185,937 | ) | $ | (106,498 | ) | $ | (195,805 | )
Weighted average common shares outstanding — basic |  | 166,980 |  |  | 177,404 |  |  | 167,677 |  |  | 178,791 |
Dilutive effect of securities |  | 3,105 |  |  | — |  |  | — |  |  | — |
Weighted average common shares outstanding — diluted |  | 170,085 |  |  | 177,404 |  |  | 167,677 |  |  | 178,791 |
Net income (loss) per share attributable to common stockholders: |  |  |  |  |  |  |  |
Basic | $ | 0.90 |  | $ | (1.05 | ) | $ | (0.64 | ) | $ | (1.10 | )
Diluted | $ | 0.88 |  | $ | (1.05 | ) | $ | (0.64 | ) | $ | (1.10 | )
Anti-dilutive potentially issuable securities excluded from diluted common shares |  | 2 |  |  | 4,616 |  |  | 2,717 |  |  | 4,072 |

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 24.2% of the Company’s outstanding shares of common stock as of June 30, 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 a majority ownership interest in TEM 7. See Note 6 – Equity Method Investments for additional information on TEM 7. At June 30, 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. At June 30, 2026, the Company also had a $4.2 million receivable from Carso related to the Incremental Mexico Equity Sale. These amounts are reflected in “Accounts receivable, net” on the Condensed Consolidated Balance Sheets for both periods.

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Subsequent Event — In connection with the offering of the 8.000% Notes, entities and/or persons related to the Slim Family Office purchased an aggregate principal amount of $150.0 million of such notes from the initial purchasers of the offering. In connection with the offering, the Company agreed to pay an advisory fee of approximately $0.9 million to Inbursa, a banking institution controlled by the Slim Family. See Note 7 – Debt for additional information regarding the issuance of 8.000% Notes.

Equity Method Investments

The Company had a $0.3 million and $0.7 million related party receivable from TEM 7 as of June 30, 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 June 30, 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 June 30, 2026, the Company had letters of credit issued under its bank credit facility totaling $95.7 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 June 30, 2026 (in thousands):

Period | Collateral Funding Commitments |
Remaining 2026 | $ | 41,638 |
2027 |  | 42,661 |
2028 |  | 43,166 |
2029 |  | 42,101 |
2030 |  | 35,212 |
Thereafter |  | 46,749 |
Total | $ | 251,527 |

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 June 30, 2026, the future minimum transportation payments under the Company’s commitments total approximately $40.2 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.

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Other than as described below, during the six months ended June 30, 2026, there were no material developments to those matters discussed in the Notes to the Consolidated Financial Statements in the 2025 Annual Report:

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 defended a lawsuit brought by a contractor concerning amounts allegedly owed for drilling operations at several locations in the Gulf of America. The lawsuit alleged that the contractor was entitled under Louisiana Law to certain statutory liens and payment. While the Company disputed the contractor’s liens and damages claims, the Company and the plaintiff settled the lawsuit during the three months ended June 30, 2026 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 settlement, which was previously accrued, is reflected as a component of “Other operating (income) expense” on the Condensed Consolidated Statements of Operations for the six months ended June 30, 2026.

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 are included 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 |  | 151 |
Changes in estimate |  | 226 |
Settlements |  | (280 | )
Decommissioning Obligations at June 30, 2026 | $ | 22,242 |
Less: Current portion at June 30, 2026 |  | 4,543 |
Long-term portion at June 30, 2026 | $ | 17,699 |

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.

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

| Three Months Ended June 30, |
| 2026 |  | 2025 |
| Upstream |
Revenues from external customers | $ | 664,813 |  | $ | 424,721 |
Significant expenses: |  |  |  |
Direct operating and maintenance(1) |  | (140,720 | ) |  | (133,741 | )
Workover(1) |  | (14,963 | ) |  | (3,230 | )
Adjusted general and administrative expense(2) |  | (36,873 | ) |  | (34,364 | )
Net cash received (paid) on settled derivative instruments |  | (74,146 | ) |  | 33,315 |
Interest expense |  | (39,162 | ) |  | (40,811 | )
Other segment items: |  |  |  |
Other(3) |  | 2,881 |  |  | 8,429 |
Depreciation, depletion and amortization |  | (229,369 | ) |  | (269,706 | )
Impairment of oil and natural gas properties |  | — |  |  | (223,881 | )
Accretion expense |  | (35,908 | ) |  | (32,046 | )
Mark-to-market derivative fair value gain (loss) |  | 104,695 |  |  | 53,540 |
Equity-based compensation expense |  | (6,409 | ) |  | (4,403 | )
Equity method investment income (expense) |  | (113 | ) |  | (186 | )
Income tax benefit (expense) |  | (44,837 | ) |  | 36,426 |
Net income (loss) |  | 149,889 |  |  | (185,937 | )

(1)
Component of lease operating expense.
(2)
Includes general and administrative expense less transaction expenses and equity-based compensation.
(3)
Primarily includes interest income offset by transaction expenses and other miscellaneous operating expenses.

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

| Six Months Ended June 30, |
| 2026 |  | 2025 |
| Upstream |
Revenues from external customers | $ | 1,137,123 |  | $ | 937,780 |
Significant expenses: |  |  |  |
Direct operating and maintenance(1) |  | (255,424 | ) |  | (259,308 | )
Workover(1) |  | (29,294 | ) |  | (5,468 | )
Adjusted general and administrative expense(2) |  | (70,885 | ) |  | (64,674 | )
Net cash received (paid) on settled derivative instruments |  | (96,616 | ) |  | 38,482 |
Interest expense |  | (78,340 | ) |  | (81,738 | )
Other segment items: |  |  |  |
Other(3) |  | (5,946 | ) |  | 16,547 |
Depreciation, depletion and amortization |  | (459,753 | ) |  | (550,422 | )
Impairment of oil and natural gas properties |  | (145,018 | ) |  | (223,881 | )
Accretion expense |  | (70,847 | ) |  | (62,940 | )
Mark-to-market derivative fair value gain (loss) |  | (46,382 | ) |  | 32,520 |
Equity-based compensation expense |  | (11,745 | ) |  | (8,544 | )
Equity method investment income (loss) |  | 6,557 |  |  | (676 | )
Income tax benefit (expense) |  | 20,455 |  |  | 36,517 |
Net income (loss) |  | (106,115 | ) |  | (195,805 | )

(1)
Component of lease operating expense.
(2)
Includes general and administrative expense less transaction expenses and equity-based compensation.
(3)
Primarily includes a litigation settlement offset by interest income.

Reconciliations

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

| Six Months Ended June 30, |
| 2026 |  | 2025 |
Segment Expenditures: |  |  |  |
Total reportable segments | $ | 272,315 |  | $ | 282,508 |
Change in capital expenditures included in accounts payable and accrued liabilities |  | 24,747 |  |  | 36,624 |
Plugging & abandonment |  | (40,571 | ) |  | (38,249 | )
Decommissioning obligations settled |  | (280 | ) |  | (628 | )
Investment in TEM 7 |  | — |  |  | (1,996 | )
Deferred payments |  | (594 | ) |  | (1,083 | )
Other |  | (1,580 | ) |  | (1,027 | )
Exploration, development and other capital expenditures | $ | 254,037 |  | $ | 276,149 |

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Note 15 — Subsequent Events

Divestiture of Shelf and Gulf Coast Non-core Properties

See Note 2 — Acquisitions and Divestitures for additional information.

Offshore Mexico Farm-In Transaction

See Note 2 — Acquisitions and Divestitures for additional information.

Honduras Transaction

See Note 2 — Acquisitions and Divestitures for additional information.

Vessel Contract

See Note 4 — Leases for additional information.

Issuance of 8.000% Notes

See Note 7 — Debt for additional information.

Redemption of 9.000% Notes

See Note 7 — Debt for additional information.

Credit Agreement Second Amendment

See Note 7 — Debt for additional information.

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

Unless otherwise indicated or the context requires otherwise, references in this Quarterly Report to “us,” “we,” “our,” “Talos,” or the “Company” refer to Talos Energy Inc. and its subsidiaries. References to “Parent Company” refer to Talos Energy Inc.

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

Genovesa — During the fourth quarter of 2025, we temporarily shut-in production from the Genovesa well, which ties back to the non-operated Na Kika facility, due to a failure of the surface-controlled subsurface safety valve. We successfully completed the Genovesa workover and returned the well to production late in the second quarter of 2026.

Monument — As recently announced by the operator, the first Monument development well was successfully drilled to its total measured depth of 32,250 feet and encountered approximately 250 feet of net pay confirming pre-drill expectations. Drilling is set to commence on the second development well followed by completion operations on both wells. First oil is expected by late 2026.

Daenerys — The Daenerys appraisal well was spud on July 1, 2026, and operations are progressing according to plan. Results are expected by year-end 2026.

Recent Developments

The following encompasses recent developments since the filing of our Quarterly Report on Form 10-Q for the three months ended March 31, 2026.

Pending Coulomb and Na Kika Acquisition — On June 30, 2026, we entered into a purchase and sale agreement to acquire certain oil and gas properties and related assets in the Mississippi Canyon area of the Gulf of America, including interests in the Na Kika and Coulomb Deepwater producing assets for cash consideration of $850.0 million (net to Talos), subject to customary purchase price adjustments (the “Coulomb and Na Kika Acquisition”). The Coulomb and Na Kika Acquisition is expected to close by the end of 2026. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for additional information.

Credit Agreement Amendments — On June 30, 2026, we entered into the Borrowing Base Redetermination Agreement, Incremental Agreement, and First Amendment to Amended and Restated Credit Agreement (the “First Amendment”). The First Amendment, among other things, reaffirms the borrowing base at $700.0 million as part of the biannual redetermination of the borrowing base, effective upon closing of the First Amendment. The First Amendment also provides for a borrowing base increase from $700.0 million to $850.0 million subject to and effective upon the consummation of the Coulomb and Na Kika Acquisition. On July 22, 2026, contemporaneously with entry into the farm-in transaction discussed below, we entered into a second amendment to our Amended and Restated Credit Agreement (the “Second Amendment”). See Part I, Item 1. “Financial Statements — Note 7 — Debt” for additional information regarding the First Amendment and Second Amendment.

8.000% Second-Priority Senior Secured Notes due July 2034 — The $800.0 million 8.000% Second-Priority Senior Secured Notes due 2034 (the “8.000% Notes”) were issued pursuant to an indenture dated July 13, 2026, by and among the Parent Company, Talos Production Inc., as issuer of the 8.000% Notes (“Talos Production” or “Issuer”), the subsidiary guarantors party thereto (together with the Parent Company, the “8.000% Notes Guarantors”) and Wilmington Trust, National Association, as trustee and collateral agent. See Part I, Item 1. “Financial Statements — Note 7 — Debt” for additional information.

The proceeds from the notes were used to pay related offering fees and expenses and to fund the redemption of all of the outstanding 9.000% Second-Priority Senior Secured Notes due 2029 (the “9.000% Notes”). We intend to use any remaining proceeds to fund a portion of the cash consideration for our pending Coulomb and Na Kika Acquisition.

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Redemption of 9.000% Notes — On July 13, 2026, we redeemed all $625.0 million aggregate principal amount of the 9.000% Notes at 104.500% plus accrued and unpaid interest using the proceeds from the issuance of the 8.000% Notes.

Shelf and Gulf Coast Non-Core Properties Divestment — On July 15, 2026, we divested a wholly-owned subsidiary holding non-core, gas weighted and predominantly non-operated Shelf and Gulf Coast properties pursuant to a purchase and sale agreement. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for additional information.

Offshore Mexico Farm-In Transaction — On July 22, 2026, we entered into a definitive agreement to farm into the Block 29 development located in the Salinas-Sureste Basin in the southern Gulf of Mexico, operated by a Repsol, S.A. subsidiary (the “Offshore Mexico Farm-In Transaction”). The partners expect to progress the project toward a final investment decision in 2027. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for additional information.

Honduras Transaction — On July 29, 2026, we entered into agreements to acquire an 80% operated working interest in an early-phase offshore Honduras project and related seismic evaluation (the “Honduras Transaction”) that provides us access to more than 4 million gross acres. We have closed on a 45% working interest and assumed operatorship. The acquisition of the remaining 35% working interest is subject to approval by Honduras's Secretaría de Energía, which is expected within approximately 90 days. Consideration for the Honduras Transactions includes a reimbursement of sunk costs, a seismic carry, and a contingent discovery bonus. An initial three-dimensional seismic campaign is planned for the second half of 2026.

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 or 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, other than the Coulomb and Na Kika Acquisition and the debt refinancing discussed above.

Known Trends and Uncertainties

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 — Oil, natural gas and NGL prices have been, and are expected to continue to be, volatile. The war in Iran, which began in February 2026, has increased geopolitical risk in global energy markets and contributed to volatility in oil and gas prices. The war has also disrupted maritime transit, supply chains and energy infrastructure in the Middle East, including in and around the Strait of Hormuz, a key route for global oil and liquefied natural gas shipments. Diplomatic negotiations have further contributed to uncertainty in global energy markets. While certain actions have supported improved market access and the partial resumption of trade and shipping activity, the timing and extent of any sustained normalization of production, exports, transportation networks and related supply chains remain uncertain. Any deterioration in diplomatic efforts, renewed geopolitical tensions or continued disruptions to trade routes, supply chains or energy infrastructure could affect global supply-demand balances and contribute to further volatility in commodity prices. Such volatility could also affect customer demand, counterparty credit risk and broader macroeconomic conditions. We cannot predict 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 June 30, 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 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 recent changes to the membership of the Federal Reserve Board of Governors.

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.

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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 six months ended June 30, 2026 of $145.0 million. No impairment was recorded during the three months ended June 30, 2026. At June 30, 2026 our ceiling test computation was based on SEC pricing of $71.93 per Bbl of oil, $3.91 per Mcf of natural gas and $18.63 per Bbl of NGLs. During both the three and six months ended June 30, 2025, we recorded an impairment of $223.9 million. 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. At this time, it is uncertain how NMFS will address the Western Louisiana District Court’s findings. As a result of the remand, the intervenors in the lawsuit filed in the District of Maryland sought to stay the litigation pending completion of the remand order. On March 31, 2026, The Endangered Species Committee (“ESC”), comprised of the Secretary of the Interior, the Secretary of Agriculture, the Secretary of the Army, the Chair of the Council of Economic Advisers, the Administrator of the Environmental Protection Agency, and the Administrator of the National Oceanic and Atmospheric Administration, held a public meeting to address the Secretary of War’s national security finding that it was necessary to exempt Gulf of America oil and gas activities from requirements of the Endangered Species Act. By unanimous vote, the ESC exempted oil and gas activities in the Gulf of America from Section 7 consultation and Section 7(a)(2) requirements pursuant to section 7(h) of the Endangered Species Act. On June 24, 2026, the District of Maryland’s federal district court judge issued a decision from the bench to dismiss the challenge to the 2025 Biological Opinion on the basis that it is moot given the ESC’s exemption decision. On the same day, the Maryland court judge issued a written order dismissing the plaintiffs’ case without prejudice for lack of subject-matter jurisdiction. Several separate lawsuits have been filed challenging the ESC’s exemption decision and the underlying national security finding. At this time, the ultimate impact of the ESC decision is uncertain.

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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.

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 June 30, |  |  |  | Six Months Ended June 30, |  |  |
| 2026 |  | 2025 |  | Change |  | 2026 |  | 2025 |  | Change |
Revenues: |  |  |  |  |  |  |  |  |  |  |  |
Oil | $ | 620,768 |  | $ | 373,195 |  | $ | 247,573 |  | $ | 1,028,766 |  | $ | 813,918 |  | $ | 214,848 |
Natural gas |  | 31,040 |  |  | 39,415 |  |  | (8,375 | ) |  | 83,943 |  |  | 92,150 |  |  | (8,207 | )
NGL |  | 13,005 |  |  | 12,111 |  |  | 894 |  |  | 24,414 |  |  | 31,712 |  |  | (7,298 | )
Total revenues | $ | 664,813 |  | $ | 424,721 |  | $ | 240,092 |  | $ | 1,137,123 |  | $ | 937,780 |  | $ | 199,343 |
Production Volumes: |  |  |  |  |  |  |  |  |  |  |  |
Oil (MBbls) |  | 6,241 |  |  | 5,824 |  |  | 417 |  |  | 11,981 |  |  | 11,968 |  |  | 13 |
Natural gas (MMcf) |  | 9,799 |  |  | 11,806 |  |  | (2,007 | ) |  | 19,492 |  |  | 24,020 |  |  | (4,528 | )
NGL (MBbls) |  | 655 |  |  | 703 |  |  | (48 | ) |  | 1,294 |  |  | 1,603 |  |  | (309 | )
Total production volume (MBoe) |  | 8,529 |  |  | 8,494 |  |  | 35 |  |  | 16,523 |  |  | 17,574 |  |  | (1,051 | )
Daily Production Volumes by Product: |  |  |  |  |  |  |  |  |  |  |  |
Oil (MBblpd) |  | 68.6 |  |  | 64.0 |  |  | 4.6 |  |  | 66.2 |  |  | 66.1 |  |  | 0.1 |
Natural gas (MMcfpd) |  | 107.7 |  |  | 129.7 |  |  | (22.0 | ) |  | 107.7 |  |  | 132.7 |  |  | (25.0 | )
NGL (MBblpd) |  | 7.2 |  |  | 7.7 |  |  | (0.5 | ) |  | 7.1 |  |  | 8.9 |  |  | (1.8 | )
Total production volume (MBoepd) |  | 93.7 |  |  | 93.3 |  |  | 0.4 |  |  | 91.3 |  |  | 97.1 |  |  | (5.8 | )
Average Sale Price Per Unit: |  |  |  |  |  |  |  |  |  |  |  |
Oil (per Bbl) | $ | 99.47 |  | $ | 64.08 |  | $ | 35.39 |  | $ | 85.87 |  | $ | 68.01 |  | $ | 17.86 |
Natural gas (per Mcf) | $ | 3.17 |  | $ | 3.34 |  | $ | (0.17 | ) | $ | 4.31 |  | $ | 3.84 |  | $ | 0.47 |
NGL (per Bbl) | $ | 19.85 |  | $ | 17.23 |  | $ | 2.62 |  | $ | 18.87 |  | $ | 19.78 |  | $ | (0.91 | )
Price per Boe | $ | 77.95 |  | $ | 50.00 |  | $ | 27.95 |  | $ | 68.82 |  | $ | 53.36 |  | $ | 15.46 |
Price per Boe (including realized commodity derivatives) | $ | 69.25 |  | $ | 53.92 |  | $ | 15.33 |  | $ | 62.97 |  | $ | 55.55 |  | $ | 7.42 |

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 June 30, 2026 vs 2025 |  | Six Months Ended June 30, 2026 vs 2025 |
| Price |  | Volume |  | Total |  | Price |  | Volume |  | Total |
Revenues: |  |  |  |  |  |  |  |  |  |  |  |
Oil | $ | 220,852 |  | $ | 26,721 |  | $ | 247,573 |  | $ | 213,964 |  | $ | 884 |  | $ | 214,848 |
Natural gas |  | (1,672 | ) |  | (6,703 | ) |  | (8,375 | ) |  | 9,181 |  |  | (17,388 | ) |  | (8,207 | )
NGL |  | 1,721 |  |  | (827 | ) |  | 894 |  |  | (1,186 | ) |  | (6,112 | ) |  | (7,298 | )
Total revenues | $ | 220,901 |  | $ | 19,191 |  | $ | 240,092 |  | $ | 221,959 |  | $ | (22,616 | ) | $ | 199,343 |

Three Months Ended June 30, 2026 and 2025 Volumetric Analysis — Production volumes increased by 0.4 MBoepd to 93.7 MBoepd. This increase is primarily attributable to 4.1 MBoepd of incremental production at our Sunspear Field. This increase was partially offset by a 3.5 MBoepd decline at the Brutus Field, primarily 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.

Six Months Ended June 30, 2026 and 2025 Volumetric Analysis — Production volumes decreased by 5.8 MBoepd to 91.3 MBoepd. This decrease is primarily attributable to a 4.9 MBoepd decline at the Brutus Field, driven by factors mentioned above, as well as a 1.5 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 completed the Genovesa workover and returned the well to production late in the second quarter of 2026. These decreases were partially offset by an increase of 3.8 MBoepd related to incremental production at our Sunspear Field.

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Operating Expenses

Lease Operating Expense

The following table highlights lease operating expense items in total and on a cost per Boe production basis. 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 June 30, |  | Six Months Ended June 30, |
| 2026 |  | 2025 |  | 2026 |  | 2025 |
Lease operating expenses | $ | 155,683 |  | $ | 136,971 |  | $ | 284,718 |  | $ | 264,776 |
Lease operating expenses per Boe | $ | 18.25 |  | $ | 16.13 |  | $ | 17.23 |  | $ | 15.07 |

Three Months Ended June 30, 2026 and 2025 — Lease operating expense for the three months ended June 30, 2026 increased by approximately $18.7 million, or 14%. This was primarily due to an increase in major well workover expenses at the Galapagos Field to return the Genovesa well to production compared to the same period in 2025.

Six Months Ended June 30, 2026 and 2025 — Lease operating expense for the six months ended June 30, 2026 increased by approximately $19.9 million, or 8%. This was primarily due to an increase in major well workover expenses at the Galapagos Field to return the Genovesa well to production 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 June 30, |  | Six Months Ended June 30, |
| 2026 |  | 2025 |  | 2026 |  | 2025 |
Depreciation, depletion and amortization | $ | 229,369 |  | $ | 269,706 |  | $ | 459,753 |  | $ | 550,422 |

Three Months Ended June 30, 2026 and 2025 — Depreciation, depletion and amortization (“DD&A”) expense for the three months ended June 30, 2026 decreased by approximately $40.3 million, or 15%. This decrease was primarily driven by a decrease of $4.90, or 15%, in the depletion rate on our proved oil and natural gas properties. The change in DD&A rate between periods caused DD&A expense to decrease by $41.8 million.

Six Months Ended June 30, 2026 and 2025 — DD&A expense for the six months ended June 30, 2026 decreased by approximately $90.7 million, or 16%. This decrease was primarily driven by a decrease of $3.49, or 11%, in the depletion rate on our proved oil and natural gas properties, as well as decreased production volumes of 5.8 MBoepd discussed above. The change in DD&A rate and decreased production volumes between periods caused DD&A expense to decrease by $57.7 million and $32.8 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 June 30, |  | Six Months Ended June 30, |
| 2026 |  | 2025 |  | 2026 |  | 2025 |
General and administrative expense | $ | 44,626 |  | $ | 39,430 |  | $ | 85,596 |  | $ | 74,045 |
General and administrative expense per Boe | $ | 5.23 |  | $ | 4.64 |  | $ | 5.18 |  | $ | 4.21 |

Three Months Ended June 30, 2026 and 2025 — General and administrative expense for the three months ended June 30, 2026 increased by approximately $5.2 million, or 13%, primarily driven by higher legal expenses related to a lawsuit we are defending brought by plaintiffs that held warrants in a company we acquired in March 2024. See Part IV, Item 15. “Exhibits and Financial Statement Schedules — Note 15 — Commitments and Contingencies in our 2025 Annual Report for additional information. Additionally, there was an increase in non-cash equity-based compensation compared to the same period in 2025.

Six Months Ended June 30, 2026 and 2025 — General and administrative expense for the six months ended June 30, 2026 increased by approximately $11.6 million, or 16%, primarily driven by higher employee related costs, including non-cash equity-based compensation, compared to the same period in 2025. Additionally, there was an increase in legal expenses related to the lawsuit described above.

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Miscellaneous

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

| Three Months Ended June 30, |  | Six Months Ended June 30, |
| 2026 |  | 2025 |  | 2026 |  | 2025 |
Accretion expense | $ | 35,908 |  | $ | 32,046 |  | $ | 70,847 |  | $ | 62,940 |
Impairment of oil and natural gas properties | $ | — |  | $ | 223,881 |  | $ | 145,018 |  | $ | 223,881 |
Other operating (income) expense | $ | 902 |  | $ | (3,851 | ) | $ | 12,249 |  | $ | (8,387 | )
Interest expense | $ | 39,162 |  | $ | 40,811 |  | $ | 78,340 |  | $ | 81,738 |
Price risk management activities (income) expense | $ | (30,549 | ) | $ | (86,855 | ) | $ | 142,998 |  | $ | (71,002 | )
Equity method investment (income) expense | $ | 113 |  | $ | 186 |  | $ | (6,557 | ) | $ | 676 |
Other (income) expense | $ | (5,230 | ) | $ | (5,371 | ) | $ | (9,415 | ) | $ | (9,231 | )
Income tax (benefit) expense | $ | 44,837 |  | $ | (36,426 | ) | $ | (20,455 | ) | $ | (36,517 | )

Three Months Ended June 30, 2026 and 2025 —

Impairment of oil and natural gas properties — During the three months ended June 30, 2026, we did not record an impairment of our oil and natural gas properties. During the three months ended June 30, 2025, we recorded a $223.9 million impairment of our oil and natural gas properties. See Part I, Item 1. “Financial Statements — Note 3 — Property, Plant and Equipment.” for additional information.

Price Risk Management Activities — The income of $30.5 million for the three months ended June 30, 2026 consists of $104.6 million in non-cash gains from the increase in the fair value of our open derivative contracts partially offset by $74.1 million in cash settlement losses. The income of $86.9 million for the three months ended June 30, 2025 consists of $53.5 million in non-cash gains from the increase in the fair value of our open derivative contracts and $33.3 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.”

Income Tax (Benefit) Expense — During the three months ended June 30, 2026, we recorded $44.8 million of income tax expense compared to $36.4 million of income tax benefit during the three months ended June 30, 2025. See Part I, Item 1. “Financial Statements — Note 10 — Income Taxes” for additional information.

Six Months Ended June 30, 2026 and 2025 —

Impairment of oil and natural gas properties — During the six months ended June 30, 2026, we recorded a $145.0 million impairment of our oil and natural gas properties. During the six months ended June 30, 2025, we recorded a $223.9 million impairment of our oil and natural gas properties. See Part I, Item 1. “Financial Statements — Note 3 — Property, Plant and Equipment.” for additional information.

Other Operating (Income) Expense — During the six months ended June 30, 2026, we settled 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 $143.0 million for the six months ended June 30, 2026 consists of $46.4 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $96.6 million in cash settlement losses. The income of $71.0 million for the six months ended June 30, 2025 consists of $32.5 million in non-cash gains from the increase in the fair value of our open derivative contracts and $38.5 million in cash settlement gains.

Equity Method Investment (Income) Expense — During the six months ended June 30, 2026, we recorded equity income of $6.6 million, which includes a $6.8 million gain on the sale of an additional 30.1% equity interest in Talos Energy Mexico 7, S. de R.L. de C.V. (“TEM 7” and the “Incremental Mexico Equity Sale”). See Part I, Item 1. “Financial Statements — Note 6 – Equity Method Investments for additional information.

Income Tax (Benefit) Expense — During the six months ended June 30, 2026, we recorded $20.5 million of income tax benefit compared to $36.5 million of income tax benefit during the six months ended June 30, 2025. See Part I, Item 1. “Financial Statements — Note 10 — Income Taxes” for additional information.

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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.

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

| Three Months Ended June 30, |  | Six Months Ended June 30, |
| 2026 |  | 2025 |  | 2026 |  | 2025 |
Net income (loss) attributable to Talos Energy Inc. | $ | 149,667 |  | $ | (185,937 | ) | $ | (106,498 | ) | $ | (195,805 | )
Net income (loss) attributable to noncontrolling interest |  | 222 |  |  | — |  |  | 383 |  |  | — |
Net income (loss) |  | 149,889 |  |  | (185,937 | ) |  | (106,115 | ) |  | (195,805 | )
Interest expense |  | 39,162 |  |  | 40,811 |  |  | 78,340 |  |  | 81,738 |
Income tax (benefit) expense |  | 44,837 |  |  | (36,426 | ) |  | (20,455 | ) |  | (36,517 | )
Depreciation, depletion and amortization |  | 229,369 |  |  | 269,706 |  |  | 459,753 |  |  | 550,422 |
Accretion expense |  | 35,908 |  |  | 32,046 |  |  | 70,847 |  |  | 62,940 |
EBITDA |  | 499,165 |  |  | 120,200 |  |  | 482,370 |  |  | 462,778 |
Impairment of oil and natural gas properties |  | — |  |  | 223,881 |  |  | 145,018 |  |  | 223,881 |
Transaction and other (income) expenses(1) |  | 1,344 |  |  | (773 | ) |  | 9,949 |  |  | (5,352 | )
Decommissioning obligations(2) |  | 215 |  |  | 76 |  |  | 377 |  |  | (81 | )
Derivative fair value (gain) loss(3) |  | (30,549 | ) |  | (86,855 | ) |  | 142,998 |  |  | (71,002 | )
Net cash received (paid) on settled derivative instruments(3) |  | (74,146 | ) |  | 33,315 |  |  | (96,616 | ) |  | 38,482 |
Non-cash equity-based compensation expense |  | 6,409 |  |  | 4,403 |  |  | 11,745 |  |  | 8,544 |
Adjusted EBITDA |  | 402,438 |  |  | 294,247 |  |  | 695,841 |  |  | 657,250 |
Less: adjustment for noncontrolling interest |  | 258 |  |  | — |  |  | 454 |  |  | — |
Adjusted EBITDA attributable to Talos Energy Inc. | $ | 402,180 |  | $ | 294,247 |  | $ | 695,387 |  | $ | 657,250 |

(1)
For the three and six months ended June 30, 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 six months ended June 30, 2026, it includes a $14.3 million litigation settlement 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 June 30, 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, acquisitions, operating costs, working capital, debt service, share repurchases, future collateral payments and 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 $1,181.9 million as of June 30, 2026. Letters of credit that are outstanding reduce the available bank credit commitments. The next redetermination of our borrowing base is expected in the fourth quarter of 2026. As discussed above under the subsection entitled “— Recent Developments,” the borrowing base and commitments will be increased to $850.0 million upon closing of the Coulomb and Na Kika Acquisition. 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.

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Capital and Other Expenditures — The following is a table of our capital expenditures, excluding acquisitions, for the six months ended June 30, 2026 (in thousands):

U.S. drilling & completions | $ | 154,219 |
Asset management(1) |  | 29,203 |
Seismic and G&G, land, capitalized G&A and other |  | 48,042 |
Total capital expenditures |  | 231,464 |
Plugging & abandonment |  | 40,571 |
Decommissioning obligations settled(2) |  | 280 |
Total capital and other expenditures | $ | 272,315 |

(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, approximately $42.5 million on March 25, 2025, and $157.3 million on April 27, 2026 for a total aggregate repurchase capacity of approximately $449.8 million. Approximately $200.0 million is remaining under the authorized program as of June 30, 2026. We did not repurchase any shares during the three months ended June 30, 2026 because SEC rules prohibit companies from conducting share buybacks while in possession of material, non-public information, such as undisclosed merger and acquisition negotiations or significant material agreements. During the six months ended June 30, 2026, we repurchased approximately 2.7 million shares for $38.2 million excluding broker commissions. 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):

| Six Months Ended June 30, |
| 2026 |  | 2025 |
Operating activities | $ | 474,637 |  | $ | 619,878 |
Investing activities | $ | (192,470 | ) | $ | (292,303 | )
Financing activities | $ | (66,573 | ) | $ | (76,923 | )

Operating Activities — Cash flow from operating activities decreased $145.2 million in the six months ended June 30, 2026 compared to the corresponding period in 2025. Key drivers of cash flow from operating activities are commodity prices, production volumes and operating costs as presented and discussed under the subsection entitled “— Results of Operations.”

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The change between periods is primarily attributable to a $139.8 million increase in cash from earnings after non-cash items, as presented in the Condensed Consolidated Statements of Cash Flows under Part I, Item 1. “Financial Statements.” This increase was more than offset by a $147.6 million unfavorable decrease in cash due to changes in working capital accounts. Working capital at any specific point in time is subject to many variables, including commodity prices, production volumes, and the timing of cash receipts and payments.

Additionally, during the six months ended June 30, 2026, $96.6 million of cash was paid to settle expired commodity derivative instruments compared to $38.5 million of cash received for the corresponding period in 2025.

Investing Activities — Cash flow used in investing activities decreased $99.8 million in the six months ended June 30, 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 the six months ended June 30, 2026. Capital expenditures decreased $22.1 million due to project timing between the current period and the corresponding period in 2025. D uring the six months ended June 30, 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 and made a $3.1 million project milestone payment related to this acquisition during the six months ended June 30, 2026. Additionally, proceeds from the sale of property and equipment increased $14.3 million between the current period and the corresponding period in 2025.

Financing Activities — Cash flow used in financing activities decreased $10.4 million in the six months ended June 30, 2026 compared to the corresponding period in 2025. During the six months ended June 30, 2026, we repurchased $38.2 million of our common stock through our share repurchase program compared to $54.7 million in the corresponding period in 2025. See subsection entitled “— Liquidity and Capital Resources — Share Repurchase Program” for additional information. Additionally, we incurred $7.3 million of deferred financing costs during the six months ended June 30, 2026 primarily in connection with an a mended 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

8.000% Second-Priority Senior Secured Notes — due July 2034 — The 8.000% Notes were issued pursuant to an indenture dated July 13, 2026, by and among the Parent Company, the Issuer, the 8.000% Notes Guarantors and Wilmington Trust, National Association, as trustee and collateral agent. The 8.000% 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 8.000% 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 8.000% Notes rank equally in right of payment with all of the Issuer’s and the 8.000% Notes Guarantors’ existing and future senior obligations, are senior in right of payment to any obligations of the Issuer and the 8.000% Notes Guarantors’ future debt that is, by its term, expressly subordinated in right of payment to the 8.000% 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 8.000% Notes Guarantors (other than the Company) and any future obligations of the Issuer and the 8.000% Notes Guarantors that are secured by the collateral on a junior-priority basis. The 8.000% Notes are effectively pari passu with all of the Issuer’s and the 8.000% Notes Guarantors’ existing and future obligations that are secured by the collateral on a second-priority basis including the 9.375% Second-Priority Senior Secured Notes due 2031 and are effectively junior to any existing and future obligations of the Issuer and the 8.000% Notes Guarantors that are secured by the collateral on a senior-priority basis to the 8.000% Notes including indebtedness under the bank credit facility. The 8.000% Notes mature on July 15, 2034 and have interest payable semi-annually each January 15 and July 15, commencing January 15, 2027.

9.000% Second-Priority Senior Secured Notes — due February 2029 — On July 13, 2026, we redeemed the entire outstanding aggregate principal amount of the 9.000% Notes using the proceeds from the issuance of the 8.000% Notes. See Part I, Item 1. “Financial Statements — Note 7 — Debt” for more information.

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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 8.000% Notes, the “Senior Notes”) were issued pursuant to an indenture dated February 7, 2024, by and among the Parent Company, the Issuer, the subsidiary guarantors party thereto (the “9.375% Notes Guarantors”) 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 9.375% Notes Guarantors’ existing and future senior obligations, are senior in right of payment to any obligations of the Issuer and the 9.375% Notes 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 9.375% Notes Guarantors (other than the Company) and any future obligations of the Issuer and the 9.375% Notes 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 9.375% Notes Guarantors’ existing and future obligations that are secured by the collateral on a second-priority basis including the 8.000% Notes and are effectively junior to any existing and future obligations of the Issuer and the 9.375% Notes 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.

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.

As of June 30, 2026, there were no material changes to our contractual obligations from those disclosed in our 2025 Annual Report, except that if the Coulomb and Na Kika Acquisition closes on September 1, 2026, we estimate cash consideration payable at closing will range from $407.5 million to $457.5 million, after customary purchase price adjustments and application of the deposit paid at signing. See the subsection entitled “— Recent Developments” for additional information regarding the definitive agreement to acquire Deepwater properties. Subsequent to June 30, 2026, the following material changes occurred:

•
The $800.0 million 8.000% Notes were issued and the 9.000% Notes were redeemed as discussed under the subsection entitled “— Recent Developments.” As a result, our long-term material cash requirements and contractual obligations disclosed in our 2025 Annual Report have been modified by extending the maturity of the refinanced indebtedness from February 2029 to July 2034. Our remaining estimated interest payments associated with our debt is now $796.7 million compared to $525.5 million disclosed in our 2025 Annual Report primarily due to the increased term of the notes and increased principal outstanding, partially offset by the lower coupon rate. The refinancing transaction created an immediate increase in near-term cash requirements during July 2026 to fund the redemption of the 9.000% Notes.
•
We entered into a 365-day minimum commitment vessel contract for approximately $160.0 million. We plan to utilize the vessel for certain Deepwater drilling and completion operations commencing in mid-2027. Other joint owners, to the extent they elect to participate, will be billed for their working interest share of such costs.
•
In connection with the divestiture of one of our wholly-owned subsidiaries discussed under the subsection entitled “— Recent Developments,” we made a $31.5 million payment to the buyer.

Performance Obligations — As of June 30, 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 $95.7 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.

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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 June 30, 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 Qualitat ive 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 June 30, 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 June 30, 2026 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II – OTHE R INFORMATION

Item 1. Legal Proceedings

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.

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. Except as described below and elsewhere in this Quarterly Report, there have been no material changes in our risk factors from those described in our 2025 Annual Report.

Risks Related to the Pending Transactions

We may not consummate the pending transactions, including the Coulomb and Na Kika Acquisition or the Offshore Mexico Farm-In Transaction on the terms currently contemplated or at all.

We may not consummate various pending transactions on the timeline and terms currently contemplated or at all. For example, the Coulomb and Na Kika Acquisition is subject to the satisfaction of customary closing conditions. These conditions include, but are not limited to, (i) the expiration or termination of any applicable waiting period, or any extension thereof, under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and (ii) the absence of any injunction or other order or applicable law preventing or making illegal the consummation of the Coulomb and Na Kika Acquisition. Neither we nor Shell can predict when, or if, these conditions will be satisfied. If any of these conditions are not satisfied or waived prior to the “Outside Date,” as such term is defined in the Shell Purchase Agreement, it is possible that the Coulomb and Na Kika Acquisition may be terminated. Although Talos Ocho Energy LLC, a Delaware limited liability company (“Talos Ocho”) and RE Fund V Holdco II Infrastructure, LLC, a Delaware limited liability company (“RE Fund” and together with Talos Ocho, the “Buyers”) have agreed with Shell to use commercially reasonable efforts, subject to certain limitations, to promptly complete the Coulomb and Na Kika Acquisition, these and other conditions to the completion of the Coulomb and Na Kika Acquisition may fail to be satisfied. In addition, satisfying the conditions to and completion of the Coulomb and Na Kika Acquisition may take longer, and could cost more, and require additional borrowings, than we currently expect. If additional borrowings are required to consummate the Coulomb and Na Kika Acquisition, our total debt and leverage will be greater than currently anticipated, and our availability under our bank credit facility will be reduced by a corresponding amount.

If (i) the consummation of the Coulomb and Na Kika Acquisition does not occur on or before the Outside Date, or (ii) prior thereto, the Company notifies the trustee that it will not pursue the consummation of the Coulomb and Na Kika Acquisition, the Company will be required to redeem $175.0 million aggregate principal amount of the 8.000% Notes then outstanding on a pro rata basis at a redemption price equal to 100% of the principal amount of the notes to be redeemed, plus accrued and unpaid interest to, but excluding, the special mandatory redemption date; provided that the Company shall not be required to effect more than one special mandatory redemption.

Additionally, the Offshore Mexico Farm-In Transaction is subject to approval by Mexico’s Secretaría de Energía and the National Anti-trust Commission of Mexico. There can be no assurance that closing conditions will be satisfied or that pending transactions, including the Coulomb and Na Kika Acquisition or Offshore Mexico Farm-In Transaction (collectively, the “Pending Transactions”) will be consummated on the terms currently contemplated or at all.

Failure to complete the Pending Transactions on the terms currently contemplated or at all could have a material adverse effect on our results of operations, cash flows and financial position.

If the Pending Transactions are not completed for any reason, including as a result of failure to obtain all requisite regulatory approvals, or if certain expectations with respect to the Pending Transactions are not fully realized (due to reasons including, but not limited to, material inaccuracies in underlying assumptions regarding future reserve and production estimates that could materially affect the benefits expected from these transactions), we may be materially adversely affected and, without realizing any of the benefits of having completed such Pending Transactions on the terms currently contemplated, we would be subject to a number of risks, including the following:

•
we may experience negative reactions from the financial markets;

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•
we may experience negative reactions from our customers, distributors, suppliers, vendors, landlords, joint venture partners and other business partners;
•
we may still be required to pay certain significant costs relating to the Pending Transactions, such as legal, accounting, and financial advisor fees;
•
with respect to the Coulomb and Na Kika Acquisition, under certain circumstances, Shell may be entitled to receive the deposit (an interest-bearing amount equal to 5% of the aggregate unadjusted purchase price, with our share being $42.5 million) as liquidated damages pursuant to the Shell Purchase Agreement;
•
matters relating to the Pending Transactions (including integration planning) require substantial commitments of time and resources by our management, which may result in the distraction of our management from ongoing business operations and pursuing other opportunities that could be beneficial to us; and
•
litigation related to any failure to complete the Pending Transactions or related to any enforcement proceeding commenced against us to perform our obligations pursuant to each transaction agreement.

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

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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

None.

Item 3. Defaults Upo n Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

During the three months ended June 30, 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.

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Item 6. Exhibits

Exhibit Number |  | Description
2.1# |  | Purchase and Sale Agreement, dated as of June 30, 2026, by and among Shell Offshore Inc., Talos Ocho Energy LLC, and RE Fund V Holdco II Infrastructure, LLC (incorporated by reference to Exhibit 2.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on June 30, 2026).
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 4.1 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 4.3 hereto) (incorporated by reference to Exhibit 4.4 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 7, 2024).
4.7 |  | Indenture, dated as of July 13, 2026, by and among Talos Production Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee (8.000% 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 July 13, 2026).
4.8 |  | Form of 8.000% Second-Priority Senior Secured Note due 2034 (included as Exhibit A in Exhibit 4.7 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 July 13, 2026).
10.1† |  | Second Amended and Restated Talos Energy Inc. 2021 Long Term Incentive Plan (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.'s Form 8-K (File No. 001-38497) filed with the SEC on June 9, 2026).
10.2 |  | Borrowing Base Redetermination Agreement, Incremental Agreement, and First Amendment to Amended and Restated Credit Agreement, dated as of June 30, 2026, by and among Talos Energy Inc., Talos Production Inc., each other Credit Party, JPMorgan Chase Bank, N.A., as Administrative Agent, and each Lender party thereto. (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on June 30, 2026).
10.3 |  | Second Amendment to Amended and Restated Credit Agreement, dated as of July 22, 2026, by and among Talos Energy Inc., Talos Production Inc., each other Credit Party, JPMorgan Chase Bank, N.A., as Administrative Agent, and each Lender party thereto.(incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on July 27, 2026).
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.

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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 Data File (Embedded within the Inline XBRL document and included in Exhibit 101).

* |  | 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.

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SIGNA TURES

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: | August 4, 2026 | By: | /s/ Zachary B. Dailey
|  |  | Zachary B. Dailey
|  |  | Executive Vice President and Chief Financial Officer

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