QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2025
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 30, 2025, the registrant had 174,658,018 shares of common stock, $0.01 par value per share, outstanding.
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 SEC as defined below:
Barrel or Bbl — One stock tank barrel, or 42 United States gallons liquid volume.
Boe —One barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate.
BOEM — Bureau of Ocean Energy Management.
BSEE — Bureau of Safety and Environmental Enforcement.
Boepd —Barrels of oil equivalent per day.
Btu —British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water one degree Fahrenheit.
CCS —Carbon capture and sequestration.
Completion —The installation of permanent equipment for the production of oil or natural gas.
Deepwater —Water depths of more than 600 feet.
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.
MBbls —One thousand barrels of crude oil or other liquid hydrocarbons.
MBblpd —One thousand barrels of crude oil or other liquid hydrocarbons per day.
MBoe —One thousand barrels of oil equivalent.
MBoepd —One thousand barrels of oil equivalent per day.
Mcf —One thousand cubic feet of natural gas.
Mcfpd —One thousand cubic feet of natural gas per day.
MMBoe —One million barrels of oil equivalent.
MMBtu —One million British thermal units.
MMcf —One million cubic feet of natural gas.
MMcfpd —One million cubic feet of natural gas per day.
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.
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.
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.
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%.
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,” “forecast,” “may,” “objective,” “plan” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on our current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. These forward-looking statements are based on management’s current belief, based on currently available information, as to the outcome and timing of future events. Forward-looking statements may include statements about:
•
business strategy;
•
estimated or recoverable resources and reserves;
•
drilling prospects, inventories, projects and programs;
•
our ability to replace the reserves that we produce through drilling and acquisitions;
•
financial strategy, borrowing base under our Bank Credit Facility, availability of financing sources, liquidity 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 Trump Administration, 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 in connection with the U.S. and Mexican presidential administrations, as well as administrations of countries where we may choose to do business in the future;
•
risks related to future mergers and acquisitions, including the risk that we may fail to realize the expected benefits of any such transaction;
•
timing and amount of future production of oil, natural gas and NGLs;
•
our hedging strategy and results;
•
future drilling plans;
•
availability of pipeline connections on economic terms;
•
competition, government regulations, including financial assurance requirements, and legislative and political developments;
•
our ability to obtain permits and governmental approvals;
•
pending legal, governmental or environmental matters;
•
our marketing of oil, natural gas and NGLs;
•
our integration of acquisitions and the anticipated post-acquisition performance of the Company;
•
future leasehold or business acquisitions on desired terms;
•
costs of developing 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;
•
our estimates and forecasts of the timing, number, profitability and other results of wells we expect to drill and other exploration activities;
our strategy with respect to our investment in the Zama asset;
•
uncertainty regarding our future operating results and our future revenues and expenses;
•
our ability to obtain surety bonds on commercially reasonable terms;
•
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; the lack of a resolution to foreign wars and conflicts and their impact on commodity markets; the impact of any pandemic and governmental measures related thereto; lack of transportation and storage capacity as a result of oversupply, government and regulations; lack of availability of drilling and production equipment and services; adverse weather events, including tropical storms, hurricanes, winter storms and loop currents; cybersecurity threats; inflation and the impact of central bank policy in response thereto; environmental risks; failure to find, acquire or gain access to other discoveries and prospects or to successfully develop and produce from our current discoveries and prospects; geologic risk; drilling and other operating risks; well control risk; regulatory changes, 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; risks to our industry and business operations associated with legal challenges by non-governmental organizations (“NGOs”) and other groups; recent and pending management changes; and the other risks discussed in Part II, Item 1A. “Risk Factors” of this Quarterly Report; Part I, Item 1A. “Risk Factors” of Talos Energy Inc.’s Annual Report on Form 10-K for the year ended December 31, 2024 (the “2024 Annual Report”); and Part II, Item 1A. “Risk Factors” of Talos Energy Inc.’s Quarterly Report on Form 10-Q for the period ended March 31, 2025 both of which were previously filed with the SEC.
Reserve engineering is a process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify upward or downward revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.
Should one or more of the risks or uncertainties described herein occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this 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.
Accumulated depreciation, depletion and amortization
(5,966,167
)
(5,191,865
)
Total property and equipment, net
4,746,835
5,215,274
Other long-term assets:
Restricted cash
75,174
106,260
Assets from price risk management activities
14,834
253
Equity method investments
112,589
111,269
Other well equipment
65,381
58,306
Notes receivable, net
18,669
17,748
Operating lease assets
10,379
11,294
Other assets
10,196
12,008
Total assets
$
5,924,702
$
6,191,795
LIABILITIES AND STOCKHOLDERSʼ EQUITY
Current liabilities:
Accounts payable
$
105,355
$
117,055
Accrued liabilities
302,604
326,913
Accrued royalties
66,300
77,672
Current portion of asset retirement obligations
127,959
97,166
Liabilities from price risk management activities
10,027
6,474
Accrued interest payable
49,016
49,084
Current portion of operating lease liabilities
3,823
3,837
Other current liabilities
47,042
44,854
Total current liabilities
712,126
723,055
Long-term liabilities:
Long-term debt
1,223,736
1,221,399
Asset retirement obligations
1,093,114
1,052,569
Liabilities from price risk management activities
10,055
3,537
Operating lease liabilities
13,776
15,489
Other long-term liabilities
352,882
416,041
Total liabilities
3,405,689
3,432,090
Commitments and contingencies (Note 13)
Stockholdersʼ equity:
Preferred stock; $0.01 par value; 30,000,000 shares authorized and zero shares issued or outstanding as of June 30, 2025 and December 31, 2024, respectively
—
—
Common stock; $0.01 par value; 270,000,000 shares authorized; 188,201,673 and 187,434,908 shares issued as of June 30, 2025 and December 31, 2024, respectively
1,882
1,874
Additional paid-in capital
3,284,467
3,274,626
Accumulated deficit
(619,915
)
(424,110
)
Treasury stock, at cost; 13,544,328 and 7,417,385 shares as of June 30, 2025 and December 31, 2024, respectively
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
Note 1 — Organization, Nature of Business and Basis of Presentation
Organization and Nature of Business
Talos Energy Inc. (the “Parent Company”) is a Delaware corporation originally incorporated on November 14, 2017. The Parent Company conducts all business operations through its operating subsidiaries, owns no operating assets and has no material operations, cash flows or liabilities independent of its subsidiaries. The Parent Company’s common stock is traded on The New York Stock Exchange under the ticker symbol “TALO.”
The Parent Company (including its subsidiaries, collectively “Talos” or the “Company”) is a technically driven, innovative independent energy company focused on maximizing long-term value through our oil and gas exploration and production (“Upstream”) business in the United States (“U.S.”) Gulf of America and offshore Mexico. The Company 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 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 2024 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
From January 1, 2024 through March 18, 2024, the Company had two operating segments: (i) exploration and production of oil, natural gas and NGLs (“Upstream Segment”) and (ii) CCS (“CCS Segment”). Both segments were reportable based on the Company’s measure of segment profit or loss for the year ended December 31, 2024. With the sale of the CCS business during 2024, 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 2024 Annual Report. The Company has not changed any of its significant accounting policies from those described in our 2024 Annual Report.
Recently Adopted Accounting Standards
Segment Reporting — In November 2023, the Financial Accounting Standards Board (“FASB”) issued an update to the required disclosures for segment reporting to improve reportable segment disclosures, primarily through enhanced disclosures about significant segment expenses that are regularly reported to the chief operating decision maker (“CODM”) and included within segment profit and loss. The disclosure guidance became effective for annual periods in 2024; became effective for interim periods in 2025; and was applied retrospectively for all prior periods presented in the financial statements. The enhanced segment disclosures are included in Note 14 — Segment Information. The Company determined that the measure of segment profit or loss closest to GAAP was net income (loss).
Recently Issued Accounting Standards Not Yet Adopted
Tax Disclosures — In December 2023, the FASB issued an update which expands disclosures in an entity’s income tax rate reconciliation table for specific categories and regarding cash taxes paid both in the U.S. and foreign jurisdictions. The tabular rate reconciliation will require both percentages and dollars. Currently, there is an option to present the table in either percentages or dollars. The update is effective for annual periods beginning after December 15, 2024 on a prospective basis. However, retrospective application in all periods presented is permitted. Adoption will only impact the Company’s income tax disclosures with no impacts to results of operations, cash flows and financial condition.
Disaggregation of Income Statement Expenses— As disclosed in the Notes to Consolidated Financial Statements of the Company’s 2024 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, 2025
December 31, 2024
Cash and cash equivalents
$
357,287
$
108,172
Restricted cash included in Current assets
32,623
—
Restricted cash included in Other long-term assets
75,174
106,260
Total cash, cash equivalent and restricted cash
$
465,084
$
214,432
Note 2 — Acquisitions and Divestitures
Acquisitions — Business Combinations
Acquisitions qualifying as business combinations are accounted for under the acquisition method of accounting, which requires, among other items, that assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date.
QuarterNorth Acquisition — On March 4, 2024, the Company completed the acquisition of QuarterNorth Energy Inc. (“QuarterNorth”), a privately-held U.S. Gulf of America exploration and production company (the “QuarterNorth Acquisition,” and the merger agreement related thereto, the “QuarterNorth Merger Agreement”) for consideration consisting of (i) $1,247.4 million in cash and (ii) 24.3 million shares of the Company’s common stock valued at $322.6 million. The cash payment was partially funded with a January 2024 underwritten public offering (the “January Equity Offering”) of 34.5 million shares of the Company’s common stock, borrowings under the Company's senior reserve-based revolving credit facility (the “Bank Credit Facility”), the 9.000% Second-Priority Senior Secured Notes due 2029 and 9.375% Second-Priority Senior Secured Notes due 2031 (together, the “Senior Notes”). The January Equity Offering generated net proceeds of $387.7 million after deducting underwriting discounts of $15.1 million and offering expenses of $0.8 million.
The Company incurred approximately $21.6 million of acquisition-related costs in connection with the QuarterNorth Acquisition exclusive of severance expense, of which $0.3 million and $19.1 million were recognized in the three and six months ended June 30, 2024. These costs were reflected in “General and administrative expense” on the Condensed Consolidated Statements of Operations except for $4.9 million of fees associated with an unutilized bridge loan that was included in “Interest expense” on the Condensed Consolidated Statements of Operations during the six months ended June 30, 2024. Additionally, the Company incurred $8.1 million and $22.3 million in severance expense in connection with the QuarterNorth Acquisition for the three and six months ended June 30, 2024.
The following table presents revenue and net income attributable to the QuarterNorth Acquisition for the three months ended June 30, 2024 and the period from March 4, 2024 to June 30, 2024:
Pro Forma Financial Information (Unaudited) — The following supplemental pro forma financial information (in thousands, except per common share amounts), presents the condensed consolidated results of operations for the three and six months ended June 30, 2024 as if the QuarterNorth Acquisition had occurred on January 1, 2023. The unaudited pro forma information was derived from historical statements of operations of the Company and QuarterNorth adjusted to include (i) depletion expense applied to the adjusted basis of the oil and natural gas properties acquired, (ii) interest expense to reflect borrowings under the Bank Credit Facility and Senior Notes, (iii) general and administrative expense adjusted for transaction related costs incurred (including severance), (iv) weighted average basic and diluted shares of common stock outstanding from the issuance of 24.3 million shares of common stock as partial consideration for the QuarterNorth Acquisition and (v) weighted average basic and diluted shares of common stock outstanding from the issuance of 34.5 million shares of common stock from the January Equity Offering that partially funded the cash portion of the QuarterNorth Acquisition. Supplemental pro forma earnings for the three and six months ended June 30, 2024 were adjusted to exclude $6.5 million and $31.5 million of general and administrative expenses. This information does not purport to be indicative of results of operations that would have occurred had the QuarterNorth Acquisition occurred on January 1, 2023, nor is such information indicative of any expected future results of operations.
Three Months Ended June 30, 2024
Six Months Ended June 30, 2024
Revenue
$
549,165
$
1,106,366
Net income (loss)
$
17,522
$
(92,937
)
Basic net income (loss) per common share
$
0.10
$
(0.51
)
Diluted net income (loss) per common share
$
0.10
$
(0.51
)
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 Working Interest in Monument Oil Discovery — The Company executed two separate definitive agreements to acquire a collective 21.4% non-operated working interest in the Monument oil discovery (“Monument Project”) in the deepwater U.S. Gulf of America located on certain Walker Ridge lease blocks. Cash consideration totaling $20.2 million, after customary closing adjustments, was paid on the closing dates of July 31, 2024 and August 2, 2024 with $24.4 million of additional cash consideration paid periodically in installments beginning January 1, 2025 through April 1, 2026. The Company allocated $42.6 million to proved properties. The carrying amount for the deferred cash consideration of $13.6 million is included in “Other current liabilities” on the Condensed Consolidated Balance Sheets at June 30, 2025.
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 Project for $14.8 million, substantially all of which was allocated to proved properties. An additional aggregate $6.3 million of contingent payments will be recognized upon the achievement of certain milestones defined in the agreement.
Subsequent Event — On July 22, 2025, the Company completed the acquisition of an additional 75.2% and 50% working interest in U.S. Gulf of America Mississippi Canyon blocks 108 and 110, respectively, for $33.7 million of cash paid at closing. The Company currently owns an interest in and operates these developed and producing blocks. As part of this acquisition of additional interests in Mississippi Canyon blocks 108 and 110, the Company also acquired an incremental 33.3% ownership in SP 49 Pipeline LLC.
Divestitures
Talos Low Carbon Solutions Divestiture— On March 18, 2024, the Company entered into a definitive agreement relating to and subsequently completed the sale of its wholly owned subsidiary, Talos Low Carbon Solutions LLC to TotalEnergies E&P USA, Inc. for a purchase price of $125.0 million plus customary reimbursements and adjustments, combined totaling approximately $142.0 million (the “TLCS Divestiture”). The TLCS Divestiture included the Company’s entire CCS business including its equity investments in three projects along the U.S. Gulf Coast: Bayou Bend CCS LLC, Harvest Bend CCS LLC, and Coastal Bend CCS LLC. During the six months ended June 30, 2024, the Company recognized a gain of $86.9 million on the TLCS Divestiture, which is presented as “Other operating income (expense)” on the Condensed Consolidated Statements of Operations. As of June 30, 2025 and December 31, 2024, $11.5 million and $9.7 million of contingent payments are included in “Other current assets,” respectively, on the Condensed Consolidated Balance Sheets.
The Company incurred approximately $6.1 million of costs in connection with the TLCS Divestiture exclusive of severance expense, which was recognized during the six months ended June 30, 2024 and reflected in “General and administrative expense” on the Condensed Consolidated Statements of Operations. Additionally, the Company incurred $3.7 million in severance expense in connection with the TLCS Divestiture for the six months ended June 30, 2024.
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 computations resulted in an impairment of its U.S. oil and natural gas properties during both the three and six months ended June 30, 2025 of $223.9 million. The non-cash impairment is reflected as “Impairment of oil and natural gas properties” on the Condensed Consolidated Statements of Operations and an increase to “Accumulated depreciation, depletion and amortization” on the Company’s Condensed Consolidated Balance Sheets. At June 30, 2025, the Company’s ceiling test computation was based on SEC pricing of $70.41 per Bbl of oil, $3.24 per Mcf of natural gas and $21.58 per Bbl of NGLs. No impairments were recorded during the three and six months ended June 30, 2024.
It is probable that another ceiling test impairment could be recorded in the near term should the 12-month average trailing commodity prices decline as compared to the commodity prices used in prior quarters.
Note 4 — Leases
The Company has operating leases principally for office space, drilling rigs, compressors 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 property and is being depleted as part of the full cost pool.
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,
2025
2024
2025
2024
Finance lease costs - interest on lease liabilities
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):
The table below presents the supplemental cash flow information related to leases (in thousands):
Six Months Ended June 30,
2025
2024
Operating cash outflow from finance leases
$
5,775
$
6,644
Operating cash outflow from operating leases
$
2,969
$
2,639
ROU assets obtained in exchange for new operating lease liabilities(1)
$
—
$
1,909
(1)
See QuarterNorth Acquisition in Note 2 — Acquisitions and Divestitures.
Note 5 — Financial Instruments
As of June 30, 2025 and December 31, 2024, the carrying amounts of cash and cash equivalents, restricted cash, accounts receivable and accounts payable approximate their fair values because they are highly liquid or due to the short-term nature of these instruments.
Debt Instruments
The following table presents the carrying amounts, net of discount and deferred financing costs, and estimated fair values of the Company’s debt instruments (in thousands):
June 30, 2025
December 31, 2024
Carrying Amount
Fair Value
Carrying Amount
Fair Value
9.000% Second-Priority Senior Secured Notes – due February 2029
$
612,562
$
640,625
$
611,135
$
640,619
9.375% Second-Priority Senior Secured Notes – due February 2031
$
611,174
$
640,800
$
610,264
$
635,750
The carrying value of the Senior Notes are adjusted for discount and deferred financing costs. Fair value is estimated (representing a Level 1 fair value measurement) using quoted secondary market trading prices and, where such prices are not available, other observable (Level 2) inputs are used such as quoted prices for similar liabilities in the active markets.
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,
2025
2024
2025
2024
Net cash received (paid) on settled derivative instruments
$
33,315
$
(17,518
)
$
38,482
$
(21,012
)
Unrealized gain (loss)
53,540
19,820
32,520
(63,748
)
Price risk management activities income (expense)
$
86,855
$
2,302
$
71,002
$
(84,760
)
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, 2025:
The following tables provide additional information related to financial instruments measured at fair value on a recurring basis (in thousands):
June 30, 2025
Level 1
Level 2
Level 3
Total
Assets:
Oil and natural gas derivatives
$
—
$
76,330
$
—
$
76,330
Liabilities:
Oil and natural gas derivatives
—
(20,082
)
—
(20,082
)
Total net asset (liability)
$
—
$
56,248
$
—
$
56,248
December 31, 2024
Level 1
Level 2
Level 3
Total
Assets:
Oil and natural gas derivatives
$
—
$
33,739
$
—
$
33,739
Liabilities:
Oil and natural gas derivatives
—
(10,011
)
—
(10,011
)
Total net asset (liability)
$
—
$
23,728
$
—
$
23,728
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, 2025
December 31, 2024
Assets
Liabilities
Assets
Liabilities
Oil and natural gas derivatives:
Current
$
61,496
$
10,027
$
33,486
$
6,474
Non-current
14,834
10,055
253
3,537
Total gross amounts presented on balance sheet
76,330
20,082
33,739
10,011
Less: Gross amounts not offset on the balance sheet
20,082
20,082
10,011
10,011
Net amounts
$
56,248
$
—
$
23,728
$
—
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, 2025 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, 2025 would have been $56.2 million.
Note 6 — Equity Method Investments
The Company accounts for its investments in unconsolidated affiliates using the equity method of accounting. The Company's primary investment is Talos Energy Mexico 7, S. de R.L. de C.V (“Talos Mexico”). As of June 30, 2025 and December 31, 2024, the Company's ownership interest in Talos Mexico was 50.1% and the carrying amount of its investment was $111.7 million and $110.2 million, respectively. Talos Mexico is a variable interest entity and the Company's maximum exposure to loss as a result of its involvement with Talos Mexico is the carrying amount of its investment.
On December 16, 2024, the Company entered into an agreement to sell an additional 30.1% equity interest in Talos Mexico to Zamajal, S.A. de C.V. (“Zamajal”), 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 contingent on first oil production from the Zama Field (the “Incremental Mexico Equity Sale”). The Incremental Mexico Equity Sale is expected to close during 2025 upon the satisfaction of customary closing conditions and the receipt of all regulatory approvals. After consummation of the Incremental Mexico Equity Sale, Talos Mexico, which currently holds a 17.4% interest in the Zama field, will be owned 20.0% by the Company and 80.0% by Zamajal. While the Company anticipates the Incremental Mexico Equity Sale will close in 2025, there can be no assurance that all of the conditions to closing, including obtaining necessary regulatory approvals, will be satisfied. See Note 12 — Related Party Transactions for additional information on Carso.
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):
June 30, 2025
December 31, 2024
9.000% Second-Priority Senior Secured Notes – due February 2029
$
625,000
$
625,000
9.375% Second-Priority Senior Secured Notes – due February 2031
625,000
625,000
Bank Credit Facility – matures March 2027
—
—
Total debt, before discount and deferred financing cost
1,250,000
1,250,000
Unamortized discount and deferred financing cost, net
(26,264
)
(28,601
)
Total debt(1)
$
1,223,736
$
1,221,399
(1)
As of June 30, 2025, the Company was in compliance with all debt covenants.
Bank Credit Facility
The Company maintains the 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. As of June 30, 2025, the borrowing base and commitments were $925.0 million; however, the commitments were subject to an availability cap as discussed in the Company’s 2024 Annual Report.
Subsequent Event — On August 4, 2025, the Company entered into the Borrowing Base Redetermination Agreement and Twelfth Amendment to Credit Agreement (the “Twelfth Amendment”). The Twelfth Amendment, among other things, (i) decreased both the borrowing base and commitments to $700.0 million and (ii) removed the $50.0 million cap on the amount of unrestricted cash that may be deducted in the calculation of consolidated total debt (used to calculate the Consolidated Total Debt to EBITDAX ratio under the Bank Credit Facility) if, as of the applicable date of determination, each lender’s total exposure is $0.
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, 2024
$
1,149,735
Obligations incurred
14,114
Obligations settled
(38,249
)
Accretion expense
62,940
Changes in estimate
32,533
Asset retirement obligations at June 30, 2025
$
1,221,073
Less: Current portion at June 30, 2025
127,959
Long-term portion at June 30, 2025
$
1,093,114
At June 30, 2025, the Company has (1) restricted cash of $107.8 million held in escrow and (2) two notes receivable with an aggregated face value of $66.2 million to settle future asset retirement obligations. A discussion of these assets is included in the accompanying Notes to the Consolidated Financial Statements in the 2024 Annual Report.
Note 9 — Employee Benefits Plans and Share-Based Compensation
Long Term Incentive Plans
Restricted Stock Units (“RSUs”) — The following table summarizes RSU activity under the Amended and Restated Talos Energy Inc. 2021 Long Term Incentive Plan (the “A&R LTIP”):
Restricted Stock Units
Weighted Average Grant Date Fair Value
Unvested RSUs at December 31, 2024
3,542,435
$
12.83
Granted
2,923,747
$
8.78
Vested
(1,031,802
)
$
14.44
Forfeited
(308,772
)
$
10.19
Unvested RSUs at June 30, 2025
5,125,608
$
10.35
Performance Share Units (“PSUs”) — The following table summarizes PSU activity under the A&R LTIP:
Performance Share Units
Weighted Average Grant Date Fair Value
Unvested PSUs at December 31, 2024
649,666
$
15.27
Granted(1)
961,442
$
9.74
Forfeited
(202,276
)
$
12.10
Unvested PSUs at June 30, 2025
1,408,832
$
11.95
(1)
There were 783,861 PSUs granted that are 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. The remaining PSUs granted are eligible to vest based on continued employment and the achievement of certain stock-price hurdles over a three-year performance period.
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:
May 7, 2025
March 10, 2025
Expected term (in years)
2.7
2.8
Expected volatility
51.7
%
52.4
%
Risk-free interest rate
3.7
%
3.8
%
Dividend yield
—
%
—
%
Share-based Compensation Costs
Share-based compensation costs associated with RSUs, PSUs and other awards are reflected as “General and administrative expense,” on the Condensed Consolidated Statements of Operations, net 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,
2025
2024
2025
2024
Share-based compensation costs
$
6,362
$
4,954
$
12,302
$
9,569
Less: Amounts capitalized to oil and gas properties
1,959
2,164
3,758
4,025
Total share-based compensation expense
$
4,403
$
2,790
$
8,544
$
5,544
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, 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 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 three months ended June 30, 2024, the Company recognized an income tax benefit of $1.0 million for an effective tax rate of -8.6%. The Company’s effective tax rate is different than the U.S. federal statutory income tax rate of 21% primarily due to a non-cash income tax benefit recognized in the Company’s state deferred tax liability.
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 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, 2024, the Company recognized an income tax benefit of $22.6 million for an effective tax rate of 18.4%. The Company’s effective tax rate is different than the U.S. federal statutory income tax rate of 21% primarily due to permanent differences.
The Company evaluates and updates the estimated annual effective income tax rate on a quarterly basis based on current and forecasted operating results and tax laws. Consequently, based upon the mix and timing of the Company’s actual earnings compared to annual projections, the effective tax rate may vary quarterly and may make quarterly comparisons not meaningful. The quarterly income tax provision is generally comprised of tax expense on income or benefit on loss at the most recent estimated annual effective tax rate. The tax effect of discrete items is recognized in the period in which they occur at the applicable statutory rate.
Deferred income tax assets and liabilities are recorded related to net operating losses and temporary differences between the book and tax basis of assets and liabilities expected to produce deductions and income in the future. The deferred tax asset estimates are subject to revision, either up or down, in future periods based on new facts or circumstances. The Company reduces deferred tax assets by a valuation allowance when, based on estimates, it is more likely than not that a portion of those assets will not be realized in a future period. In evaluating the Company’s valuation allowance, the Company considers cumulative losses, the reversal of existing temporary differences, the existence of taxable income in carryback years, tax optimization planning and future taxable income for each of its taxable jurisdictions. The Company assesses the realizability of its deferred tax assets quarterly, and changes to the Company’s assessment of its valuation allowance in future periods could materially impact its results of operations. For the three months ended June 30, 2025, the Company determined that it can no longer rely on forecasts of taxable income to support realizability of its deferred tax assets and recorded a valuation allowance of $20.0 million as a discrete, non-cash expense. The change in assessment is due to an accumulation of losses experienced in the most recent financial statement periods.The Company’s valuation allowance primarily relates to accruals for asset retirement obligations. A net deferred tax liability of $229.1 million and $266.6 million is included in “Other long-term liabilities” on the Condensed Consolidated Balance Sheets as of June 30, 2025 and December 31, 2024, respectively.
On July 4, 2025, the One Big Beautiful Bill Act (“OBBBA”) was signed into law. The OBBBA contains a broad range of changes to U.S. federal income tax laws and makes permanent or modifies certain provisions of the Tax Cuts and Jobs Act. The Company is currently evaluating the effects of the OBBBA on its effective tax rate and cash tax position, but the Company does not expect that the OBBBA will have a material impact on its financial statements. Because the OBBBA was signed into law after the close of the second quarter, its impacts are not included in the Company’s operating results for the three and six months ended June 30, 2025.
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 were as follows (in thousands, except for the per share amounts):
Three Months Ended June 30,
Six Months Ended June 30,
2025
2024
2025
2024
Net income (loss)
$
(185,937
)
$
12,381
$
(195,805
)
$
(100,058
)
Weighted average common shares outstanding — basic
177,404
183,564
178,791
171,027
Dilutive effect of securities
—
128
—
—
Weighted average common shares outstanding — diluted
177,404
183,692
178,791
171,027
Net income (loss) per common share:
Basic
$
(1.05
)
$
0.07
$
(1.10
)
$
(0.59
)
Diluted
$
(1.05
)
$
0.07
$
(1.10
)
$
(0.59
)
Anti-dilutive potentially issuable securities excluded from diluted common shares
4,616
1,549
4,072
2,169
Note 12 — Related Party Transactions
2022 Registration Rights Agreement
On September 21, 2022, the Company entered into a registration rights agreement (the “2022 Registration Rights Agreement”) with Adage Capital Partners, L.P. and affiliated entities of Bain Capital, LP, a discussion of which is included in the accompanying Notes to the Consolidated Financial Statements in the 2024 Annual Report. There have been no changes to the 2022 Registration Rights Agreement since the filing of the Company’s 2024 Annual Report.
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 24.9% of the Company’s outstanding shares of common stock as of June 30, 2025 based on SEC beneficial ownership reports filed by Control Empresarial.
On December 16, 2024, the Company entered into a cooperation agreement (“Cooperation Agreement”) with Control Empresarial, a discussion of which is included in the Notes to the Consolidated Financial Statements in the 2024 Annual Report. There have been no changes to the Cooperation Agreement since the filing of the Company’s 2024 Annual Report. The Cooperation Agreement expires December 16, 2025, but is subject to early termination upon the occurrence of certain events described in the Cooperation Agreement.
The Slim Family own a majority stake in Carso. Carso, through its subsidiary, has an ownership interest in Talos Mexico. See Note 6 – Equity Method Investments for additional information on Talos Mexico. The Company had a $2.7 million and $2.3 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 as of June 30, 2025 and December 31, 2024, respectively. These amounts are reflected as “Other, net” within “Accounts Receivable” on the Condensed Consolidated Balance Sheets.
Equity Method Investments
The Company had a $1.2 million and $0.7 million related party receivable from Talos Mexico as of June 30, 2025 and December 31, 2024, respectively. These amounts are reflected as “Other, net” within “Accounts Receivable” 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, 2025, the Company had secured performance bonds from third party sureties totaling $1.5 billion. The cost of securing these bonds is reflected as “Interest expense” on the Condensed Consolidated Statements of Operations. Additionally, as of June 30, 2025, the Company had secured letters of credit issued under its Bank Credit Facility totaling $42.8 million. Letters of credit that are outstanding reduce the available revolving credit commitments.
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, 2025, the future minimum transportation payments under the Company’s commitments total approximately $47.6 million for years 2025 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.
Decommissioning Obligations
Decommissioning in the U.S. is governed by both federal and state laws and regulations. In federal waters, decommissioning is governed by federal laws and regulations, while decommissioning in state waters falls under state laws and regulations. Louisiana, Alabama and Mississippi state waters extend three nautical miles from their respective shorelines; however, Texas state waters extend approximately nine nautical miles from its shoreline. The Company, as a co-lessee or predecessor-in-interest in oil and natural gas leases located in the U.S. Gulf of America, is in the chain of title with unrelated third parties either directly or by virtue of divestiture of certain oil and natural gas assets previously owned and assigned by our subsidiaries. Certain counterparties in these divestiture transactions or third parties in existing leases have filed for bankruptcy protection or undergone associated reorganizations and may not be able to perform required abandonment obligations. Both federal and state laws and regulations could require the Company to assume such obligations. The Company reflects such costs as “Other operating (income) expense” on the Condensed Consolidated Statements of Operations.
The decommissioning obligations included are in the Condensed Consolidated Balance Sheets as “Other current liabilities” and “Other long-term liabilities”, and the changes in that liability were as follows (in thousands):
Decommissioning Obligations at December 31, 2024
$
20,002
Changes in estimate
(81
)
Settlements
(628
)
Decommissioning Obligations at June 30, 2025
$
19,293
Less: Current portion at June 30, 2025
7,953
Long-term portion at June 30, 2025
$
11,340
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.
QuarterNorth Registration Rights Agreement
In connection with the Company’s entry into the QuarterNorth Merger Agreement, on March 4, 2024, the Company entered into a registration rights agreement (the “QNE Registration Rights Agreement”) with certain stockholders of QuarterNorth (collectively, the “RRA Holders”). Pursuant to the QNE Registration Rights Agreement, the Company granted the RRA Holders certain demand, “piggy-back” and shelf registration rights with respect to the shares of the Company’s common stock received in connection with the QuarterNorth Acquisition, subject to certain customary thresholds and conditions. There have been no amendments to the QNE Registration Rights Agreement since the filing of the Company’s 2024 Annual Report.
Note 14 — Segment Information
The Company’s operations were managed through two operating segments through March 18, 2024: (i) the Upstream Segment and (ii) the CCS Segment, both of which were reportable for the year ended December 31, 2024. The CCS Segment was divested in March 2024.
The CODM is an executive committee comprised of the President and Chief Executive Officer, General Counsel, Chief Financial Officer, and Head of Operations. Previously, the CODM was the executive management team comprised of the General Counsel, Chief Financial Officer, and Head of Operations, each of whom served as interim Co-President, managing the Office of the Interim Chief Executive Officer (the “Office of the Interim CEO”). The Office of the Interim CEO dissolved effective March 1, 2025 when the Company's President and Chief Executive Officer took office.
Prior to the divestment of the CCS Segment, corporate general and administrative expense included certain shared costs such as finance, accounting, tax, human resources, information technology and legal costs that were not directly attributable to each operating segment. These shared expenses were fully allocated to each operating segment. Segment accounting policies are the same as those described in Note 2 – Summary of Significant Accounting Policies included in the accompanying Notes to Consolidated Financial Statements in the 2024 Annual Report.
The Company’s CODM does not review assets by segment as part of the financial information provided and therefore, no asset information is provided in the table below.
The following table presents selected segment information (in thousands):
Six Months Ended June 30, 2025
Upstream
Revenues from external customers
$
937,780
Significant expenses:
Lease operating expense:
Direct operating and maintenance
(259,308
)
Workover
(5,468
)
Adjusted general and administrative expense(1)
(64,674
)
Net cash received (paid) on settled derivative instruments
38,482
Interest expense
(81,738
)
Other segment items:
Other(2)
16,547
Depreciation, depletion and amortization
(550,422
)
Impairment of oil and natural gas properties
(223,881
)
Accretion expense
(62,940
)
Mark-to-market derivative fair value gain (loss)
32,520
Equity-based compensation expense
(8,544
)
Equity method investment income (loss)
(676
)
Income tax benefit (expense)
36,517
Net income (loss)
(195,805
)
Segment Expenditures
$
282,508
(1)
Includes general and administrative expense less transaction expenses and equity-based compensation.
(2)
Primarily includes interest income and other miscellaneous operating income.
The following table presents selected segment information (in thousands):
Three Months Ended June 30, 2024
Upstream
CCS(1)
Total
Revenues from external customers
$
549,165
$
—
$
549,165
Significant expenses:
Lease operating expense:
Direct operating and maintenance
(146,136
)
—
(146,136
)
Workover
(11,174
)
—
(11,174
)
Adjusted general and administrative expense(2)
(35,600
)
—
(35,600
)
Net cash received (paid) on settled derivative instruments
(17,518
)
—
(17,518
)
Interest expense
(48,982
)
—
(48,982
)
Other segment items:
Other(3)
(5,904
)
796
(5,108
)
Depreciation, depletion and amortization
(259,091
)
—
(259,091
)
Accretion expense
(30,732
)
—
(30,732
)
Mark-to-market derivative fair value gain (loss)
19,820
—
19,820
Equity-based compensation expense
(2,790
)
—
(2,790
)
Equity method investment income (loss)
(456
)
—
(456
)
Income tax benefit (expense)
1,963
(980
)
983
Net income (loss)
12,565
(184
)
$
12,381
(1)
The CCS Segment was an emerging business in the start-up phase of operations and the business did not generate any revenues.
(2)
Includes general and administrative expense less transaction expenses and equity-based compensation. Corporate overhead allocated to the Upstream Segment was $20.1 million.
(3)
Primarily includes transaction expenses for the Upstream Segment and transaction expenses for the CCS Segment. Transaction expenses include severance expense, costs related to the QuarterNorth Acquisition and costs related to the TLCS Divestiture. See further discussion in Note 2 — Acquisition and Divestitures for additional information.
The following table presents selected segment information (in thousands):
Six Months Ended June 30, 2024
Upstream
CCS(1)
Total
Revenues from external customers
$
979,097
$
—
$
979,097
Significant expenses:
Lease operating expense:
Direct operating and maintenance
(245,405
)
—
(245,405
)
Workover
(47,083
)
—
(47,083
)
Adjusted general and administrative expense(2)
(62,985
)
(1,919
)
(64,904
)
Net cash received (paid) on settled derivative instruments
(21,012
)
—
(21,012
)
Interest expense
(99,621
)
(206
)
(99,827
)
Other segment items:
Other(3)
(30,981
)
(8,991
)
(39,972
)
Depreciation, depletion and amortization
(474,709
)
(46
)
(474,755
)
Accretion expense
(57,635
)
—
(57,635
)
Mark-to-market derivative fair value gain (loss)
(63,748
)
—
(63,748
)
Equity-based compensation expense
(5,497
)
(47
)
(5,544
)
Gain on TLCS Divestiture(4)
—
86,940
86,940
Equity method investment income (loss)
(540
)
(7,970
)
(8,510
)
Gain (loss) on extinguishment of debt
(60,256
)
—
(60,256
)
Income tax benefit (expense)
33,489
(10,933
)
22,556
Net income (loss)
(156,886
)
56,828
$
(100,058
)
Segment Expenditures
$
290,812
$
17,519
$
308,331
(1)
The CCS Segment was an emerging business in the start-up phase of operations and the business did not generate any revenues.
(2)
Includes general and administrative expense less transaction expenses and equity-based compensation. Corporate overhead allocated to the Upstream Segment and CCS Segment was $34.9 million and $0.4 million, respectively.
(3)
Primarily includes transaction expenses for the Upstream Segment and transaction expenses for the CCS Segment. Transaction expenses include severance expense, costs related to the QuarterNorth Acquisition and costs related to the TLCS Divestiture. See further discussion in Note 2 — Acquisition and Divestitures for additional information.
(4)
See further discussion in Note 2 — Acquisitions and Divestitures for additional information.
Reconciliations
The following table presents the reconciliation of Segment Expenditures to the Company’s consolidated totals (in thousands):
Six Months Ended June 30,
2025
2024
Segment Expenditures:
Total reportable segments
$
282,508
$
308,331
Change in capital expenditures included in accounts payable and accrued liabilities
36,624
35,140
Plugging & abandonment
(38,249
)
(50,128
)
Decommissioning obligations settled
(628
)
(3,328
)
Investment in Talos Mexico
(1,996
)
(2,108
)
Investment in CCS intangibles and equity method investees
—
(17,519
)
Deferred payments
(1,083
)
(1,235
)
Other
(1,027
)
17
Exploration, development and other capital expenditures
$
276,149
$
269,170
Note 15 — Subsequent Events
Acquisition of Incremental Working Interest in Mississippi Canyon Blocks
See Note 2 — Acquisitions and Divestitures for additional information.
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Unless otherwise indicated or the context otherwise requires, references in this Quarterly Report to “us,” “we,” “our,” “Talos” or the “Company” are to Talos Energy Inc. and its wholly-owned subsidiaries.
The following discussion and analysis of our financial condition and results of operations is based on, and should be read in conjunction with, our Condensed Consolidated Financial Statements and notes thereto in Part I, Item 1. “Financial Statements” of this Quarterly Report, as well as our audited Consolidated Financial Statements and the notes thereto in our 2024 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 2024 Annual Report.
Our Business
We are 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. 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 have historically focused our operations in the U.S. Gulf of America because of our deep experience and technical expertise in the basin, which maintains favorable geologic and economic conditions, including multiple reservoir formations, comprehensive geologic and geophysical databases, extensive infrastructure and an attractive and robust asset acquisition market. Additionally, we have access to state-of-the-art three-dimensional seismic data, some of which is aided by new and enhanced reprocessing techniques that have not been previously applied to our current acreage position. We use our broad regional seismic database and our reprocessing efforts to generate an inventory of high-quality prospects, which we believe greatly improves our development and exploration success. The application of our extensive seismic database, coupled with our ability to effectively reprocess this seismic data, allows us to both optimize our organic drilling program and better evaluate a wide range of business development opportunities, including acquisitions and collaborative arrangement opportunities, among others.
From January 1, 2024 through March 18, 2024, we had two operating segments: (i) exploration and production of oil, natural gas and NGLs (“Upstream Segment”) and (ii) CCS (“CCS Segment”). Both segments were reportable based on the Company’s measure of segment profit or loss for the year ended December 31, 2024. With the sale of our CCS business during 2024, the Company's Upstream Segment is currently the only reportable segment being managed on a consolidated basis.
Significant Developments
The following significant developments have occurred since the filing of our Quarterly Report on Form 10-Q for the period ended March 31, 2025.
Operational Updates — Late in the second quarter of 2025, we achieved first production from the Sunspear well. Shortly thereafter, an early failure of the surface-controlled subsurface safety valve was identified. As a precautionary measure, the well was shut in and will require intervention. Following the completion of drilling operations at the Daenerys well, the West Vela drillship will be mobilized to perform the necessary remediation. We expect Sunspear to return to production in October 2025. Additionally, late in the second quarter of 2025, we also achieved first production from the Katmai West #2 well.
Twelfth Amendment to Bank Credit Facility — On August 4, 2025, we entered into the Borrowing Base Redetermination Agreement and Twelfth Amendment to Credit Agreement (the “Twelfth Amendment”). The Twelfth Amendment, among other things, (i) decreased both the borrowing base and commitments to $700.0 million and (ii) removed the $50.0 million cap on the amount of unrestricted cash that may be deducted in the calculation of consolidated total debt (used to calculate the Consolidated Total Debt to EBITDAX ratio under the Bank Credit Facility) if, as of the applicable date of determination, each lender’s total exposure is $0.
Acquisition of Incremental Working Interest in Mississippi Canyon Blocks — On July 22, 2025, the Company completed the acquisition of an additional 75.2% and 50% working interest in U.S. Gulf of America Mississippi Canyon blocks 108 and 110, respectively, for $33.7 million of cash paid at closing. The Company currently owns an interest in and operates these developed and producing blocks. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures”for additional information.
Enhanced Corporate Strategy — On June 17, 2025, we announced an enhanced corporate strategy designed to position the Company as a leading pure-play offshore exploration and production company. The strategy is built on three key pillars. The first pillar targets increased annualized cash flow by improving our existing operations through capital efficiency, margin enhancement, commercial opportunities and general organizational improvements. The second pillar focuses on growth through high-margin organic projects and selective deepwater acquisitions. The third pillar aims to build a long-lived and scaled portfolio in the U.S. Gulf of America and potentially other conventional offshore basins.
Share Repurchase Program — During the three months ended June 30, 2025, we repurchased 3.8 million shares for $32.6 million exclusive of broker commissions under our share repurchase program, which was previously authorized by our Board of Directors, resulting in $145.4 million available under the share repurchase program. See “Liquidity and Capital Resources — Share Repurchase Program” for additional information.
Chief Financial Officer Transition — On May 16, 2025, Sergio L. Maiworm, Jr. informed the Board of Directors that he was resigning from his position as Executive Vice President and Chief Financial Officer of the Company, effective as of June 27, 2025. In connection with and following Mr. Maiworm’s resignation, effective as of June 28, 2025, Gregory Babcock was appointed as Interim Chief Financial Officer to serve until a permanent Chief Financial Officer is appointed by the Board of Directors.
Factors Affecting the Comparability of our Financial Condition and Results of Operations
The following items affect the comparability of our financial condition and results of operations for periods presented herein and could potentially continue to affect our future financial condition and results of operations.
QuarterNorth Acquisition— On March 4, 2024, we acquired QuarterNorth Energy Inc. (“QuarterNorth”), a private operator in the Deepwater U.S. Gulf of America (the “QuarterNorth Acquisition”). See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures”for additional information.
Planned Downtime — We are vulnerable to downtime events impacting the transportation, gathering and processing of production. We produce the Phoenix Field through the Helix Producer I (“HP-I”) that is operated by Helix Energy Solutions Group, Inc (“Helix”). Helix is required to disconnect and dry-dock the HP-I every two to three years for inspection as required by the U.S. Coast Guard, during which time we are unable to produce the Phoenix Field. The next dry-dock is scheduled for the first half of 2027 with a projected shut-in period of approximately 45 days.
During the three months ended June 30, 2024, Helix dry-docked the HP-I. After conducting sea trials, production resumed in mid-June, resulting in a total shut-in period of 52 days. The shut-in resulted in an estimated deferred production of approximately 4.8 MBoepd and 2.4 MBoepd for the three and six months ended June 30, 2024, respectively, based on production rates prior to the shut-in.
Known Trends and Uncertainties
We are navigating through various evolving external factors that create uncertainty and volatility in the operating environment, including, but not limited to, volatility in energy prices and inflation due to geopolitical dynamics, increased tariffs and their impact on costs of goods and services, legal challenges related to the industry, and planned and unplanned downtime. These factors, and any changes to these factors, among others, could have a material adverse impact on our future revenues and overall profitability. See Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2024 Annual Report for further discussion of Known Trends and Uncertainties, and, Part II, Item 1A “Risk Factors” of this Quarterly Report and Part II, Item 1A. “Risk Factors” in our 2024 Annual Report for additional information regarding our Risk Factors. There have been no material changes to the following topical trends and uncertainties discussed in our 2024 Annual Report:
• Deepwater Operations
• Oil Spill Response Plan
• Hurricanes, Tropical Storms, Winter Storms and Loop Currents
The following provides an update to known trends and uncertainties discussed in our 2024 Annual Report.
Volatility in Oil, Natural Gas and NGL Prices —Historically, the markets for oil, natural gas and NGLs have been volatile. Oil, natural gas and NGL prices are subject to wide fluctuations in supply and demand. Our revenue, profitability, access to capital and future rate of growth depends upon the price we receive for our sales of oil, natural gas and NGL production.
During the period January 1, 2025 through June 30, 2025, the daily spot prices for NYMEX WTI crude oil ranged from a high of $80.73 per Bbl to a low of $58.50 per Bbl, and the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of $9.86 per MMBtu to a low of $2.65 per MMBtu. The price the Company realizes on natural gas sales is based on the MMBtu content of such natural gas. We convert MMBtu sales volumes to Mcf volumes for reporting purposes using Btu per Mcf factors per third party natural gas processing plant statements. 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 we realize for any commodity that we produce will generally approximate current market prices in the geographic region of production. We hedge a portion of our commodity price risk to mitigate the impact of price volatility on our business. See Part I, Item 1. “Financial Statements — Note 5 — Financial Instruments” for additional information regarding our commodity derivative positions as of June 30, 2025.
On July 8, 2025, the U.S. Energy Information Administration (“EIA”) published its short-term energy outlook. An increase in the geopolitical risk premium has led the EIA to raise its forecast for crude oil prices over the second half of 2025 primarily attributable to hostilities over Iran’s nuclear program that escalated in mid-June with Israeli and U.S. attacks against Iranian nuclear facilities. The potential for higher oil prices over the second half of this year reflects the importance of the Strait of Hormuz to global oil supply. Concerns among market participants about its potential closure caused a temporary spike in oil prices and volatility in June 2025. Although the geopolitical risk premiums have risen, the EIA still anticipates that global oil inventories will grow significantly over their forecast period and put downward pressure on oil prices. For example, OPEC Plus is in the process of fully restoring 2.2 million barrels per day of voluntary cuts made in November 2023. The EIA expects the NYMEX WTI spot prices to average $65.22 per barrel in 2025 and $54.82 per barrel in 2026. Uncertainty around the status of ongoing trade negotiations between the U.S. and its trading partners could weigh heavily on oil prices going forward.
The EIA expects the Henry Hub price to average around $3.70 per MMBtu in 2025 and $4.40 per MMBtu in 2026. This forecasted price increase reflects the expectation that natural gas production will fall slightly in 2026, while liquefied natural gas (“LNG”) exports continue to increase. As such, the EIA expects LNG demand and natural gas production to be key drivers of price in the coming months. For example, LNG exports may be disrupted if tropical storms hit along the Gulf Coast, which could result in more U.S. inventories and lower natural gas prices than expected.
Inflation and Macroeconomic Pressures — Due to the cyclical nature of the oil and gas industry, fluctuating demand for oilfield goods and services can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increase. However, during periods of commodity price declines, corresponding reductions in oilfield costs typically do not adjust downward as quickly as oil prices decline.
Inflation may also result in increases to the costs of our oilfield goods, services and personnel, which would in turn cause our capital expenditures and operating costs to rise. Inflation may also result in higher interest rates, which could have the effects of raising the cost of capital and depressing economic growth, either or both of which could hurt our business.
In June 2025, the U.S. Federal Reserve (the “Federal Reserve”) left its benchmark interest rate unchanged at a range of 4.25%-4.50%. The Federal Reserve is navigating a complex economic landscape, balancing the potential impact of President Trump’s trade policies, particularly tariffs, with concerns about inflation and unemployment. In July 2025, the Federal Reserve left its benchmark interest rate unchanged for a fifth straight time. Future changes to the benchmark interest rate remain uncertain.
Impact of Prolonged Increases in Tariffs —We continue to monitor the rapid 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. On April 2, 2025, President Donald Trump signed an executive order setting a 10% baseline tariff on imports, with higher rates for countries running trade surpluses with the U.S. By April 9, 2025, a follow-up order paused most of the higher reciprocal tariffs for 90 days. On July 7, 2025, President Trump extended the tariff modifications through August 1, 2025. Public statements from members of the Trump Administration and President Trump, himself, have indicated the negotiations are continuing with various foreign nations, although an extension of the tariff modification deadline beyond the August 1, 2025 deadline cannot be predicted with certainty at this time. Any prolonged increases in global tariffs could have a material impact on our financial condition and results of operations in fiscal year 2025 and beyond.
Impairment of Oil and Natural Gas Properties — Under the full cost method of accounting, the “ceiling test” under SEC rules and regulations specifies that evaluated and unevaluated properties’ capitalized costs, less accumulated amortization and related deferred income taxes (the “Full Cost Pool”), should be compared to a formulaic limitation (the “Ceiling”) each quarter on a country-by-country basis. If the Full Cost Pool exceeds the Ceiling, an impairment must be recorded. As a result of the Company’s ceiling test computations, an impairment of its U.S. oil and natural gas properties was recorded during both the three and six months ended June 30, 2025 of $223.9 million. At June 30, 2025 our ceiling test computation was based on SEC pricing of $70.41 per Bbl of oil, $3.24 per Mcf of natural gas and $21.58 per Bbl of NGLs. No impairments were recorded during the three and six months ended June 30, 2024. See Part I, Item 1. “Financial Statements — Note 3 — Property, Plant and Equipment” for additional information.
If the unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the period beginning July 1, 2024 and ending June 1, 2025 used in the determination of the SEC pricing was 10% lower, resulting in $63.37 per Bbl of oil, $2.95 per Mcf of natural gas and $19.60 per Bbl of NGLs, while all other factors remained constant, our oil and natural gas properties would have been further impaired by approximately an additional $691.6 million assuming all other factors remained constant.
There is a significant degree of uncertainty with the assumptions used to estimate the present value offuture net cash flows from estimated production of proved oil and gas reservesdue to, but not limited to the risk factors referred to in Part I, Item 1A. “Risk Factors” included in our 2024 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.
Update on Financial Assurance Rule — Effective June 29, 2024, BOEM adopted a final rule which significantly increases the amount of new supplemental financial assurance required from certain lessees and grant holders conducting operations on the Outer Continental Shelf (“OCS”). The final rule adopted a three-year phased compliance period to fully comply with BOEM’s supplemental financial assurance demands. The final rule was challenged in the U.S. District Court for the Western District of Louisiana (the “Western Louisiana District Court”) by multiple oil and gas industry groups and the States of Mississippi, Louisiana and Texas and the Western Louisiana District Court granted a stay of the litigation while the agency pursues efforts to suspend, revise, or rescind the final rule. The Western Louisiana District Court’s order temporarily limits BOEM’s full implementation of the final rule by limiting BOEM’s ability to seek supplemental financial assurance to cases of sole liability properties and certain non-sole liability properties that are held by owners who are not financially strong, as described in the final rule, and that have no co-owners or predecessors who are financially strong.
On May 2, 2025, the Department of the Interior (“DOI”) announced its intent to revise and develop a new rule that is consistent with the Trump Administration’s 2020 proposed rule on financial assurance. The specific substance and timing of a revised rule cannot be predicted at this time. However, we anticipate that the new revised rule will revert to BOEM’s decades-long policy of considering the financial strength of both co-owners and predecessors in title when determining whether supplemental financial assurance is required and may reduce the credit rating required under the current final rule for financial assurance waivers. In light of these expectations, we anticipate the amount we would be required to bond under the revised rule would be significantly less than under the final rule.
Regardless of the status of the final rule or a new revised rule, BOEM stated it will continue to require operators on the OCS to provide financial assurance in instances where BOEM determines there is a substantial risk of nonperformance of the interest holder’s decommissioning liabilities.
Financial Assurance Market Outlook — As a result of a number of surety companies leaving the offshore surety market due in part to adverse developments in restructurings and bankruptcies of companies operating in the OCS, there continues to be significant uncertainty in the current market availability of surety bonds for projects and companies operating in the OCS. As such, we may not be able to obtain new surety bonds on commercially reasonable terms or maintain existing bonding without posting collateral. Moreover, under our surety agreements, surety companies have the right to demand collateral. If we are required to provide collateral in the form of cash or letters of credit under our Bank Credit Facility, our liquidity position could be significantly impacted. We cannot predict how much collateral, if any, we may be required to provide.
Recent Challenges to Federal Offshore Leasing Program — Gulf of America federal lease sales are conducted pursuant to Five-Year Leasing Programs under the U.S. Outer Continental Shelf Lands Act, as amended (“OCSLA”). U.S. federal offshore oil and gas lease sales have been, and may continue to be, subject to numerous challenges, delays, and moratoriums which may curtail our ability to seek additional new federal leases and may delay or prevent us from bidding on and obtaining new federal offshore leases or developing existing leases. In January 2023, BOEM released its Supplemental Environmental Impact Statement (“SEIS”) related to Lease Sales 259 and 261. In March 2023, BOEM held and announced the results of Lease Sale 259, in which we and QuarterNorth, which we acquired in 2024, were awarded leases on a total of eight blocks. In December 2023, BOEM held and announced the results of Lease Sale 261, in which we and QuarterNorth were awarded leases on a total of seventeen blocks.
Six environmental organizations filed a lawsuit in March 2023 in the U.S. District Court for the District of Columbia seeking to cancel Lease Sale 259 on the basis that BOEM violated its statutory obligation to adequately evaluate the lease sale’s environmental impacts. Plaintiffs argued that the SEIS was deficient in several respects. In March 2025, the court agreed with plaintiffs that BOEM’s SEIS was deficient with respect to its evaluation of greenhouse gas emissions and harms to Rice’s whales but disagreed with plaintiffs regarding other alleged deficiencies. The court requested additional briefing from the parties regarding appropriate remedy. The current ruling leaves open the status of the leases awarded under Lease Sale 259 and we cannot predict the ultimate outcome of this lawsuit. It is possible that, pending the outcome of this litigation, the validity of leases awarded under Lease Sale 259 could be challenged and our ability to develop these leases could be significantly delayed until such legal challenges are resolved. Additionally, an adverse outcome in this lawsuit could potentially result in subsequent challenges to our lease awards under Lease Sale 261. Any actions to restrict, delay or prohibit the oil and natural gas exploration, development and production activities of existing oil and gas leases on the OCS could adversely impact the offshore oil and gas industry and have a material adverse effect on our business, financial condition or results of operations.
Future Offshore Leasing — Pursuant to OCSLA, the President may withdraw from disposition any of the unleased lands of the OCS. On January 6, 2025, former President Biden issued two memoranda under OCSLA that withdrew approximately 625 million acres of the U.S. OCS, including the Eastern Planning Area of the Gulf of America from being considered for new oil or natural gas leases, including for exploration, development and production. However, the Western and Central Planning Areas in the Gulf of America were not included in President Biden’s withdrawal.
On January 20, 2025, President Trump issued an Executive Order revoking President Biden’s memoranda and the U.S. Secretary of the Interior subsequently issued an order directing the DOI to “take all actions available to expedite the leasing of the OCS for oil and gas exploration and production.” Both President Biden’s and President Trump’s actions described above with respect to OCSLA have been challenged in federal district courts and the future of both actions remains undecided. On April 18, 2025, the Secretary of the Interior directed BOEM to initiate steps to develop a new schedule for offshore oil and gas lease sales in the OCS, which, once finalized, will be the 11th National OCS Program replacing the current 2024-2029 National OCS Program that includes just three lease sales in the Gulf of America. On April 30, 2025, BOEM published a Federal Register notice requesting information and comments on the preparation of the 11th National OCS Program. The comment period closed on June 16, 2025. We cannot determine when the 11th National OCS Program will be finalized, or how many lease sales will be scheduled.
On June 27, 2025, BOEM published a Federal Register Notice of Availability of the Proposed Notice of Sale for Gulf of America OCS Oil and Gas Lease Sale 262, the first lease sale included in the 2024-2029 National OCS Program, to be held on December 10, 2025. BOEM expects to publish the Final Notice of Sale for Sale 262 in the Federal Register at least 30 days prior to the December 10, 2025 lease sale date.
The One Big Beautiful Bill Act (“OBBBA”), signed into law by President Trump on July 4, 2025, mandates that the BOEM conduct at least two offshore lease sales annually, of a minimum of 80 million acres (if available) in the Central and Western Gulf of America Planning Areas for the next 15 years, with at least one of these lease sales to be held by December 15, 2025. The OBBBA reduces the royalty rate for Gulf of America leases acquired at these sales back to a minimum of 12.5% (pre-Inflation Reduction Act rates) but not greater than 16.67%.
Executive, judicial and/or administrative action resulting in the withdrawal of OCS areas from consideration for new leasing activities or delays in scheduling OCS lease sales, particularly if such actions affect the Western and Central Planning Areas of the Gulf of America in which we currently or seek to operate, could have a material adverse effect on our ability to obtain new OCS leases and develop new assets, as well as negatively impact our financial condition and results of operations.
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. The vacatur was initially effective December 20, 2024, but was later extended to May 21, 2025. On May 20, 2025, NMFS published its new Biological Opinion for the Gulf of America oil and gas program, superseding and replacing all prior biological opinions relating to the program. On the same day, 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. Both lawsuits seek declaratory and injunctive relief. The outcome of these challenges remains uncertain at this time.
On a related matter, in April 2019, NMFS listed the Rice’s whale as endangered under the Endangered Species Act. In July 2023, NMFS proposed to designate approximately 28,300 square miles of the Gulf of America as critical habitat for the Rice’s whale pursuant to a settlement agreement in a lawsuit. On July 3, 2025, an amended settlement agreement was filed with the U.S. District Court for the District of Columbia, which further extends the deadline for NMFS to publish its final rule designating critical habitat for the Rice’s whale to no later than July 15, 2027.
How We Evaluate Our Operations
We use a variety of financial and operational metrics to assess the performance of our operations, including:
•
production volumes;
•
realized prices on the sale of oil, natural gas and NGLs, including the effect of our commodity derivative contracts;
•
lease operating expenses;
•
capital expenditures; and
•
Adjusted EBITDA, which is discussed under “—Supplemental Non-GAAP Measure” below.
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. Revenues are presented in thousands, except per unit data.
Three Months Ended June 30,
Six Months Ended June 30,
2025
2024
Change
2025
2024
Change
Revenues:
Oil
$
373,195
$
507,408
$
(134,213
)
$
813,918
$
900,629
$
(86,711
)
Natural gas
39,415
26,060
13,355
92,150
49,758
42,392
NGL
12,111
15,697
(3,586
)
31,712
28,710
3,002
Total revenues
$
424,721
$
549,165
$
(124,444
)
$
937,780
$
979,097
$
(41,317
)
Production Volumes:
Oil (MBbls)
5,824
6,303
(479
)
11,968
11,476
492
Natural gas (MMcf)
11,806
10,081
1,725
24,020
18,740
5,280
NGL (MBbls)
703
703
—
1,603
1,335
268
Total production volume (MBoe)
8,494
8,686
(192
)
17,574
15,934
1,640
Daily Production Volumes by Product:
Oil (MBblpd)
64.0
69.3
(5.3
)
66.1
63.1
3.0
Natural gas (MMcfpd)
129.7
110.8
18.9
132.7
103.0
29.7
NGL (MBblpd)
7.7
7.7
(0.0
)
8.9
7.3
1.6
Total production volume (MBoepd)
93.3
95.5
(2.2
)
97.1
87.5
9.6
Average Sale Price Per Unit:
Oil (per Bbl)
$
64.08
$
80.50
$
(16.42
)
$
68.01
$
78.48
$
(10.47
)
Natural gas (per Mcf)
$
3.34
$
2.59
$
0.75
$
3.84
$
2.66
$
1.18
NGL (per Bbl)
$
17.23
$
22.33
$
(5.10
)
$
19.78
$
21.51
$
(1.73
)
Price per Boe
$
50.00
$
63.22
$
(13.22
)
$
53.36
$
61.45
$
(8.09
)
Price per Boe (including realized commodity derivatives)
$
53.92
$
61.21
$
(7.29
)
$
55.55
$
60.13
$
(4.58
)
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, 2025 vs 2024
Six Months Ended June 30, 2025 vs 2024
Price
Volume
Total
Price
Volume
Total
Revenues:
Oil
$
(95,653
)
$
(38,560
)
$
(134,213
)
$
(125,323
)
$
38,612
$
(86,711
)
Natural gas
8,887
4,468
13,355
28,347
14,045
42,392
NGL
(3,586
)
—
(3,586
)
(2,763
)
5,765
3,002
Total revenues
$
(90,352
)
$
(34,092
)
$
(124,444
)
$
(99,739
)
$
58,422
$
(41,317
)
Three Months Ended June 30, 2025 and 2024 Volumetric Analysis — Production volumes decreased by 2.2 MBoepd to 93.3 MBoepd. The decrease was primarily due to 7.6 MBoepd well performance and natural production declines. Additionally, there was 3.1 MBoepd in deferred production resulting from maintenance and third party infrastructure downtime primarily attributable to our Green Canyon core area. These decreases were partially offset by an increase of approximately 4.8 MBoepd in deferred production resulting from third party downtime associated with the HP-1 dry dock in our Phoenix Field in the corresponding period in 2024. Additionally, there was 3.8 MBoepd of production from the recompletion of one of our operated Brutus wells, which commenced initial production in July 2024.
Six Months Ended June 30, 2025 and 2024 Volumetric Analysis — Production volumes increased by 9.6 MBoepd to 97.1 MBoepd. The increase was primarily due to 11.3 MBoepd in production from the oil and natural gas assets acquired in the QuarterNorth Acquisition that closed in early March 2024. Additionally, production volumes increased 5.3 MBoepd from the recompletion of one of our operated Brutus wells, which commenced initial production in July 2024 as well as 2.4 MBoepd in deferred production resulting from third party downtime associated with the HP-1 dry dock in our Phoenix Field in the corresponding period in 2024. These increases were partially offset by a decrease of 8.6 MBoepd due to well performance and natural production declines as well as 2.5 MBoepd in deferred production resulting from maintenance and third party infrastructure downtime.
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,
2025
2024
2025
2024
Lease operating expenses
$
136,971
$
157,310
$
264,776
$
292,488
Lease operating expenses per Boe
$
16.13
$
18.11
$
15.07
$
18.36
Three Months Ended June 30, 2025 and 2024 —Lease operating expense for the three months ended June 30, 2025 decreased by approximately $20.3 million, or 13%. This was due to an $18.9 million decrease in facility and workover expenses primarily related to the HP-1 at the Phoenix Field and major well workover expenses at Garden Banks 506 Field compared to the same period in 2024.
Six Months Ended June 30, 2025 and 2024 — Lease operating expense for the six months ended June 30, 2025 decreased by approximately $27.7 million, or 9%. This was due to a $36.8 million decrease in facility and workover expenses primarily related to the HP-1 and major well workover expenses at the Phoenix Field and the Garden Banks 506 Field compared to the same period in 2024. This was partially offset by a $10.7 million increase in direct lease operating expenses due to the QuarterNorth Acquisition that closed in late first quarter of 2024.
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,
2025
2024
2025
2024
Depreciation, depletion and amortization
$
269,706
$
259,091
$
550,422
$
474,755
Three Months Ended June 30, 2025 and 2024 —Depreciation, depletion and amortization (“DD&A”) expense for the three months ended June 30, 2025 increased by approximately $10.6 million, or 4%. This increase was primarily driven by an increase of $1.98 per Boe, or 7%, in the depletion rate on our proved oil and natural gas properties partially offset by a reduction in production volumes. The change in the DD&A rate between periods caused DD&A expense to increase by $16.8 million and decreased production volumes caused DD&A expense to decrease by $5.7 million.
Six Months Ended June 30, 2025 and 2024 — DD&A expense for the six months ended June 30, 2025 increased by approximately $75.7 million, or 16%. This was due to increased production volumes of 9.6 MBoepd discussed above. Additionally, there was an increase of $1.54 per Boe, or 5%, in the depletion rate on our proved oil and natural gas properties due to an increase in our proved properties primarily related to the assets acquired as part of the QuarterNorth Acquisition, which is further discussed in Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures.” Increased production volumes and the change in the DD&A rate between periods caused DD&A expense to increase by $48.7 million and $27.1 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 for the Upstream Segment. The information below provides the financial results and an analysis of significant variances in these results (in thousands, except per Boe data):
Three Months Ended June 30,
Six Months Ended June 30,
2025
2024
2025
2024
Upstream Segment
$
39,430
$
49,043
$
74,045
$
107,115
CCS Segment
—
(796
)
—
10,973
Total general and administrative expense
$
39,430
$
48,247
$
74,045
$
118,088
Upstream general and administrative expense per Boe
$
4.64
$
5.65
$
4.21
$
6.72
Three Months Ended June 30, 2025 and 2024 — General and administrative expense for the three months ended June 30, 2025 decreased by approximately $8.8 million, or 18%. This decrease was primarily driven by Upstream Segment transaction costs, severance costs and additional general and administrative expenses incurred in 2024 relating to the QuarterNorth Acquisition of $12.0 million or $1.42 per Boe. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for additional information. This decrease was partially offset by a $3.8 million increase in consulting fees and an increase in non-cash equity-based compensation of $1.6 million compared to the same period in 2024. See Part I, Item 1. “Financial Statements — Note 9 — Employee Benefits Plans and Share-Based Compensation” for additional information.
Six Months Ended June 30, 2025 and 2024 — General and administrative expense for the six months ended June 30, 2025 decreased by approximately $44.0 million, or 37%. This decrease was primarily driven by Upstream Segment transaction costs, severance costs and additional general and administrative expenses incurred in 2024 relating to the QuarterNorth Acquisition of $42.7 million or $2.43 per Boe. Additionally, there was a decrease in the CCS Segment transaction costs, severance costs and expenses of $11.0 million due to the divestiture of our CCS business. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for additional information. This decrease was partially offset by a $4.8 million increase in consulting fees. Additionally, there was an increase in non-cash equity-based compensation of $3.0 million compared to the same period in 2024. See Part I, Item 1. “Financial Statements — Note 9 — Employee Benefits Plans and Share-Based Compensation” for additional information.
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,
2025
2024
2025
2024
Accretion expense
$
32,046
$
30,732
$
62,940
$
57,635
Impairment of oil and natural gas properties
$
223,881
$
—
$
223,881
$
—
Other operating (income) expense
$
(3,851
)
$
(1,061
)
$
(8,387
)
$
(87,104
)
Interest expense
$
40,811
$
48,982
$
81,738
$
99,827
Price risk management activities (income) expense
$
(86,855
)
$
(2,302
)
$
(71,002
)
$
84,760
Equity method investment (income) expense
$
186
$
456
$
676
$
8,510
Other (income) expense
$
(5,371
)
$
(4,164
)
$
(9,231
)
$
51,732
Income tax (benefit) expense
$
(36,426
)
$
(983
)
$
(36,517
)
$
(22,556
)
Three Months Ended June 30, 2025 and 2024 —
Impairment of 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. The impairment is a result of our ceiling test evaluation as described in Part I, Item 1. “Financial Statements — Note 3 — Property, Plant and Equipment.”
Interest Expense— During the three months ended June 30, 2025, we recorded $40.8 million of interest expense compared to $49.0 million during the three months ended June 30, 2024. The change is primarily due to a $7.2 million decrease in interest expense related to the Bank Credit Facility as a result of paying off all borrowings under our Bank Credit Facility balance prior to December 31, 2024. “Financial Statements — Note 7 — Debt” for additional information.
Price Risk Management Activities — 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. The income of $2.3 million for the three months ended June 30, 2024 consists of $19.8 million in non-cash gains from the increase in the fair value of our open derivative contracts offset by $17.5 million in cash settlement losses.
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 December 2026, 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, 2025, we recorded $36.4 million of income tax benefit compared to $1.0 million of income tax benefit during the three months ended June 30, 2024. The income tax benefit recorded during the three months ended June 30, 2025 is primarily due to current year activity offset by the impact of recording a valuation allowance on our U.S. federal deferred tax assets. See additional information in Part I, Item 1. “Financial Statements — Note 10 — Income Taxes.”
Six Months Ended June 30, 2025 and 2024 —
Accretion Expense — During the six months ended June 30, 2025, we recorded $62.9 million of accretion expense compared to $57.6 million during the six months ended June 30, 2024. The change is primarily the result of a $3.4 million increase in accretion associated with the asset retirement obligations assumed as part the QuarterNorth Acquisition. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures.”
Impairment of 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. The impairment is a result of our ceiling test evaluation as described in Part I, Item 1. “Financial Statements — Note 3 — Property, Plant and Equipment.”
Other Operating (Income) Expense — During the six months ended June 30, 2024, we recognized a gain of $86.9 million due to the sale of our wholly owned subsidiary, Talos Low Carbon Solutions LLC to TotalEnergies E&P USA, Inc. (the “TLCS Divestiture”). See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for additional information.
Interest Expense — During the six months ended June 30, 2025, we recorded $81.7 million of interest expense compared to $99.8 million during the six months ended June 30, 2024. The change is primarily due to a $12.3 million decrease in interest expense as a result of paying off all borrowings under our Bank Credit Facility balance prior to December 31, 2024. See Part I, Item 1. “Financial Statements — Note 7 — Debt” for additional information. Additionally, there was a decrease of $4.9 million of fees associated with an unutilized bridge loan during the corresponding period in 2024. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for additional information.
Price Risk Management Activities — 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. The expense of $84.8 million for the six months ended June 30, 2024 consists of $63.8 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $21.0 million in cash settlement losses.
Equity Method Investment (Income) Expense — During the six months ended June 30, 2024, we recorded equity losses of $8.9 million primarily attributable to the CCS Segment offset by an $0.4 million equity method income attributable to the Upstream Segment.
Other (Income) Expense — During the six months ended June 30, 2024, we recorded a $60.3 million loss on extinguishment of debt in conjunction with the redemption of the 12.00% Second-Priority Senior Secured Notes due 2026 (the “12.00% Notes”) and 11.75% Senior Secured Second Lien Notes due 2026 (the “11.75% Notes”). See Part I, Item 1. “Financial Statements — Note 7 — Debt” for additional information.
Income Tax (Benefit) Expense — During the six months ended June 30, 2025, we recorded $36.5 million of income tax benefit compared to $22.6 million of income tax benefit during the six months ended June 30, 2024. The income tax benefit is primarily due to current year activity offset by the impact of recording a valuation allowance on our U.S. federal deferred tax assets. See additional information on the valuation allowance as described in Part I, Item 1. “Financial Statements — Note 10 — Income Taxes.”
Supplemental Non-GAAP Measure
EBITDA and Adjusted EBITDA
“EBITDA” and “Adjusted EBITDA” are non-GAAP financial measures used to provide management and investors with (i) additional information to evaluate, with certain adjustments, items required or permitted in calculating covenant compliance under our debt agreements, (ii) important supplemental indicators of the operational performance of our business, (iii) additional criteria for evaluating our performance relative to our peers and (iv) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. EBITDA and Adjusted EBITDA have limitations as analytical tools and should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP or as alternatives to net income (loss), operating income (loss) or any other measure of financial performance presented in accordance with GAAP.
We define these as the following:
•
EBITDA — Net income (loss) plus interest expense, income tax 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.
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,
2025
2024
2025
2024
Net income (loss)
$
(185,937
)
$
12,381
$
(195,805
)
$
(100,058
)
Interest expense
40,811
48,982
81,738
99,827
Income tax (benefit) expense
(36,426
)
(983
)
(36,517
)
(22,556
)
Depreciation, depletion and amortization
269,706
259,091
550,422
474,755
Accretion expense
32,046
30,732
62,940
57,635
EBITDA
120,200
350,203
462,778
509,603
Impairment of oil and natural gas properties
223,881
—
223,881
—
Transaction and other (income) expenses(1)
(773
)
6,629
(5,352
)
(42,528
)
Decommissioning obligations(2)
76
4,182
(81
)
5,037
Derivative fair value (gain) loss(3)
(86,855
)
(2,302
)
(71,002
)
84,760
Net cash received (paid) on settled derivative instruments(3)
33,315
(17,518
)
38,482
(21,012
)
(Gain) loss on debt extinguishment
—
—
—
60,256
Non-cash equity-based compensation expense
4,403
2,790
8,544
5,544
Adjusted EBITDA
$
294,247
$
343,984
$
657,250
$
601,660
(1)
For the three and six months ended June 30, 2024, transaction expenses included $9.3 million and $37.4 million, respectively, in costs related to the QuarterNorth Acquisition, inclusive of $8.1 million and $22.3 million, respectively, in severance expense. For the six months ended June 30, 2024, transaction expenses include $9.0 million in costs related to the TLCS Divestiture, inclusive of $3.7 million in severance expense. See further discussion in Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures.” 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, 2024, the amount included a gain of $86.9 million related to the TLCS Divestiture. See further discussion in Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures.”
(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 (as defined herein). Our primary uses of cash are for capital expenditures, working capital, debt service, share repurchases, and for general corporate purposes. The cost of borrowing under our Bank Credit Facility 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.
As a result of the Twelfth Amendment, our Bank Credit Facility currently has a borrowing base of $700.0 million. Giving effect to the borrowing base reduction under the Twelfth Amendment, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $1,014.5 million as of June 30, 2025. Our liquidity has increased since December 31, 2024 due to a higher cash balance offset by reduced borrowing capacity under the Bank Credit Facility. Letters of credit that are outstanding reduce the available revolving credit commitments. The next redetermination of our borrowing base is expected in the fourth quarter of 2025. 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.
Capital Expenditures — The following is a table of our capital expenditures, excluding acquisitions, for the six months ended June 30, 2025 (in thousands):
U.S. drilling & completions
$
192,189
Asset management(1)
16,579
Seismic and G&G, land, capitalized G&A and other
32,867
Total capital expenditures
241,635
Plugging & abandonment
38,249
Decommissioning obligations settled(2)
628
Investment in Mexico
1,996
Total
$
282,508
(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 2025 capital spending program of $490.0 million to $530.0 million and plugging & abandonment and decommissioning obligations of $100.0 million to $120.0 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.
Share Repurchase Program — Since the Board initially approved a share repurchase program of $100.0 million on March 20, 2023, the Board has approved increases in share repurchase capacity of $150.0 million on July 22, 2024 and approximately $42.5 million on March 25, 2025, for a total aggregate repurchase capacity of approximately $292.5 million, with approximately $145.4 million remaining under the authorized program as of June 30, 2025. During the three and six months ended June 30, 2025, we repurchased approximately 3.8 million and 6.1 million shares for $32.6 million and $54.6 million, respectively, exclusive of broker commissions. Since the inception of our share repurchase program in March 2023, we have repurchased an aggregate of 13.5 million shares under our authorized program for a total principal amount of $147.1 million. 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) by type of activity, for the following periods (in thousands):
Six Months Ended June 30,
2025
2024
Operating activities
$
619,878
$
385,790
Investing activities
$
(292,303
)
$
(1,062,845
)
Financing activities
$
(76,923
)
$
683,221
Operating Activities — Cash flows from operating activities favorably changed $234.1 million in the six months ended June 30, 2025 compared to the corresponding period in 2024. 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. There was an $86.4 million increase due to changes in working capital accounts largely related to a $60.8 million inflow attributable to accounts receivable between the current period and the corresponding period in 2024 due to a reduction in joint interest receivables and lower commodity prices for trade receivables. There was a $59.5 million increase due to changes in derivative settlements. Net cash received on derivative instruments were $38.5 million during the six months ended June 30, 2025 compared to net cash paid on derivative instruments of $21.0 million during the corresponding period in 2024. Also contributing to the increase in cash flows between periods was a reduction in general and administrative expenses of $44.0 million primarily related to transaction costs for the QuarterNorth Acquisition and the TLCS Divestiture. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for additional information. Additionally, there was a decrease in settlements of asset retirement obligations of $11.9 million.
Investing Activities — Cash used in investing activities changed $770.5 million in the six months ended June 30, 2025 compared to the corresponding period in 2024. This is primarily due to $916.0 million in cash paid for acquisitions, net of cash acquired, related to the QuarterNorth Acquisition offset by cash proceeds of $142.0 million received from the TLCS Divestiture during the corresponding period in 2024. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for additional information on the QuarterNorth Acquisition and TLCS Divestiture. Additionally, capital expenditures decreased $7.0 million.
Financing Activities — Cash flows related to financing activities changed $760.1 million in the six months ended June 30, 2025 compared to the corresponding period in 2024. During the six months ended June 30, 2024, the issuance of the Senior Notes in February 2024 generated $1,222.6 million after deferred financing costs. The net proceeds from the Senior Notes funded the $897.1 million redemption of the 12.00% Notes and the 11.75% Notes and partially funded the cash portion of the QuarterNorth Acquisition as discussed in our 2024 Annual Report. Additionally, on January 17, 2024, we entered into an underwritten public offering of 34.5 million shares of our common stock to partially fund the cash portion of the QuarterNorth Acquisition, which generated net proceeds of $387.7 million. During the six months ended June 30, 2025, we repurchased $54.7 million of our common stock through our share repurchase program compared to $39.3 million in the corresponding period in 2024. See subsection entitled “— Liquidity and Capital Resources — Share Repurchase Program” for additional information. Furthermore, the Bank Credit Facility had no activity during the six months ended June 30, 2025 compared to net borrowings of $25.0 million during the corresponding period in 2024. During the six months ended June 30, 2025, we had deferred payments of $10.2 million primarily related to our acquisition of a 21.4% non-operated working interest in the Monument Project. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for additional information.
Overview of Debt Instruments
9.000% Second-Priority Senior Secured Notes — due February 2029 — The 9.000% Second-Priority Senior Secured Notes due 2029 (the “9.000% Notes”)were issued pursuant to an indenture dated February 7, 2024, by and among the Company, Talos Production Inc. (the “Issuer”), the subsidiary guarantors party thereto (together with the Company, the “Guarantors”) and Wilmington Trust, National Association, as trustee and collateral agent. The 9.000% Notes were offered and sold to qualified institutional buyers pursuant to the exemptions from registration provided by Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. The 9.000% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 9.000% Notes rank equally in right of payment with all of the Issuer’s and the Guarantors’ existing and future senior obligations, are senior in right of payment to any obligations of the Issuer and the Guarantors future debt that is, by its term, expressly subordinated in right of payment to the 9.000% Notes and, to the extent of the value of the collateral, are effectively senior to all existing and future unsecured obligations of the Issuer and the Guarantors (other than the Company) and any future obligations of the Issuer and the Guarantors that are secured by the collateral on a junior-priority basis. The 9.000% Notes are effectively pari passu with all of the Issuer’s and the Guarantors’ existing and future obligations that are secured by the collateral on a second-priority basis including the 9.375% Notes (as defined below) and are effectively junior to any existing and future obligations of the Issuer and the Guarantors that are secured by the collateral on a senior-priority basis to the 9.000% Notes including indebtedness under the Bank Credit Facility. The 9.000% Notes mature on February 1, 2029 and have interest payable semi-annually each February 1 and August 1, commencing August 1, 2024. See Part I, Item 1. “Financial Statements — Note 7 — Debt” for additional information.
9.375% Second-Priority Senior Secured Notes — due February 2031 — The 9.375% Second-Priority Senior Secured Notes due 2031 (the “9.375% Notes” and, together with the 9.000% Notes, the “Senior Notes”)were issued pursuant to an indenture dated February 7, 2024, by and among the Company, the Issuer, the Guarantors party thereto and Wilmington Trust, National Association, as trustee and collateral agent. The 9.375% Notes were offered and sold to qualified institutional buyers pursuant to the exemptions from registration provided by Rule 144A under the Securities Act and to certain non-U.S. persons in accordance with Regulation S under the Securities Act. The 9.375% Notes are secured on a second-priority senior secured basis by liens on substantially the same collateral as the collateral securing the Issuer’s existing first-priority obligations under its Bank Credit Facility. The 9.375% Notes rank equally in right of payment with all of the Issuer’s and the Guarantors’ existing and future senior obligations, are senior in right of payment to any obligations of the Issuer and the Guarantors future debt that is, by its term, expressly subordinated in right of payment to the 9.375% Notes and, to the extent of the value of the collateral, are effectively senior to all existing and future unsecured obligations of the Issuer and the Guarantors (other than the Company) and any future obligations of the Issuer and the Guarantors that are secured by the collateral on a junior-priority basis. The 9.375% Notes are effectively pari passu with all of the Issuer’s and the Guarantors’ existing and future obligations that are secured by the collateral on a second-priority basis including the 9.000% Notes and are effectively junior to any existing and future obligations of the Issuer and the Guarantors that are secured by the collateral on a senior-priority basis to the 9.375% Notes including indebtedness under the Bank Credit Facility. The 9.375% Notes mature on February 1, 2031 and have interest payable semi-annually each February 1 and August 1, commencing August 1, 2024.See Part I, Item 1. “Financial Statements — Note 7 — Debt” for additional information.
Bank Credit Facility — matures March 2027 — We maintain Bank Credit Facility. 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 our Bank Credit Facility. As discussed above under “— Significant Developments,” both the borrowing base and commitments were reduced as part of the latest semi-annual redetermination process. See Part I, Item 1. “Financial Statements — Note 7 — Debt”for additional information.
We have various contractual obligations in the normal course of our operations. Some of these obligations may be reflected in our accompanying Condensed Consolidated Financial Statements, while other obligations, such as certain operating leases and capital commitments, are not reflected on our accompanying Condensed Consolidated Financial Statements. There have been no material changes to our contractual obligations since those reported in our 2024 Annual Report except for (i) purchase obligations increased from $40.7 million to $78.3 million through 2026 primarily due to increased committed purchase orders to execute planned future drilling activities and (ii) an executed vessel commitment that will result in an additional gross commitment of $42.9 million through 2026.
Performance Obligations — As of June 30, 2025, we had secured 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 secured letters of credit issued under our Bank Credit Facility totaling $42.8 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 2024 Annual Report subsection entitled “— Known Trends and Uncertainties — Financial Assurance Requirements” and “— Known Trends and Uncertainties — Financial Assurance Market Outlook” for additional information on BOEM’s supplemental bonding requirements and the potential lack of surety bond capacity to comply with BOEM’s financial assurance requirements, which could have a material adverse effect on our business, properties, results of operations and financial condition.
Critical Accounting Estimates
There have been no changes to our critical accounting estimates from those disclosed in our 2024 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
Information on Recently Adopted Accounting Standards that impacted 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.”
Recently Issued Accounting Standards
No accounting standards were issued during the quarterly period ended June 30, 2025 that were material to us. In addition, information on Recently Issued Accounting Standards that could potentially impact our consolidated financial statements and related disclosures is incorporated by reference to Part I, Item 1. “Financial Statements — Note 1 —Organization, Nature of Business and Basis of Presentation.”
Item 3. Quantitative and Qualitative Disclosures About Market Risk
For information regarding our exposures to certain market risks, refer to Part II, Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” in our 2024 Annual Report. There have been no material changes from the disclosures presented in our 2024 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, 2025, 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, 2025 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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 2024 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 7. “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, 2024. You should carefully consider the risks and other cautionary statements described in this Quarterly Report, our 2024 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. Other than as set forth below, there have been no material changes in our risk factors from those described in our 2024 Annual Report or our other recent SEC filings, including our Quarterly Report on Form 10-Q for the quarter ended March 31, 2025.
Lower oil and natural gas prices and other factors have resulted in, and may in the future result in additional, ceiling test impairments and other impairments of our asset carrying values.
We use the full cost method of accounting for our oil and gas operations. Accordingly, we capitalize the costs to acquire, explore for and develop oil and gas properties. Under the full cost method of accounting, our capitalized costs are limited to a ceiling based on the present value of future net revenues from proved reserves, computed using a discount factor of 10 percent, plus the lower of cost or estimated fair value of unproved oil and natural gas properties not being amortized less the related tax effects. Any costs in excess of the ceiling are recognized as a non-cash “Impairment of oil and natural gas properties” on the condensed consolidated statements of operations and an increase to “Accumulated depreciation, depletion and amortization” on our condensed consolidated balance sheets. An impairment of oil and gas properties does not impact cash flows from operating activities, but does reduce net income. The risk that we are required to impair the carrying value of oil and gas properties increases when oil and natural gas prices are low or volatile. In addition, impairments may occur if we experience substantial downward adjustments to our estimated proved reserves or our undeveloped property values, or if estimated future development costs increase. Volatility in commodity prices, poor conditions in the global economic markets and other factors could cause us to record additional impairments of our oil and natural gas properties and other assets in the future, and incur additional charges against future earnings. For both the three and six months ended June 30, 2025, the Company recorded an impairment of $223.9 million. Any required impairments could materially affect the quantities and present value of our reserves, which could adversely affect our business, results of operations and financial condition.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following table sets forth information with respect to our repurchase of shares of common stock during the three months ended June 30, 2025 (in thousands, except for the share and per share amounts):
Period
Total Number of Shares Purchased
Average Price Paid
Total Number of Shares Purchased as Part of Publicly Announced Program(1)
Approximate Dollar Values of Shares that May Yet be Purchased Under the Program
April 1, 2025- April 30, 2025
—
$
—
—
$
178,001
May 1, 2025- May 31, 2025
2,040,277
$
8.23
2,040,277
$
161,209
June 1, 2025 - June 30, 2025
1,798,393
$
8.76
1,798,393
$
145,448
Total
3,838,670
$
8.48
3,838,670
(1)
Refer to Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Share Repurchase Program” for additional information regarding our authorized share repurchase program.
During the three months ended June 30, 2025, 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.
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 6, 2025
By:
/s/ Gregory Babcock
Gregory Babcock
Vice President, Chief Accounting Officer and Interim Chief Financial Officer
