10-Q

Three Months Ended March 31,

Depreciation, depletion and amortization

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

TALOS ENERGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(In thousands, except share amounts)


	March 31, 2025			December 31, 2024
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	202,950		$	108,172
Accounts receivable:
Trade, net		242,729			236,694
Joint interest, net		86,992			133,562
Other, net		42,500			34,002
Assets from price risk management activities		28,272			33,486
Prepaid assets		82,840			77,487
Other current assets		22,507			35,980
Total current assets		708,790			659,383
Property and equipment:
Proved properties		9,954,822			9,784,832
Unproved properties, not subject to amortization		569,881			587,238
Other property and equipment		35,089			35,069
Total property and equipment		10,559,792			10,407,139
Accumulated depreciation, depletion and amortization		(5,472,580	)		(5,191,865	)
Total property and equipment, net		5,087,212			5,215,274
Other long-term assets:
Restricted cash		107,021			106,260
Assets from price risk management activities		12,968			253
Equity method investments		110,779			111,269
Other well equipment		66,034			58,306
Notes receivable, net		18,203			17,748
Operating lease assets		10,703			11,294
Other assets		10,855			12,008
Total assets	$	6,132,565		$	6,191,795
LIABILITIES AND STOCKHOLDERSʼ EQUITY
Current liabilities:
Accounts payable	$	107,358		$	117,055
Accrued liabilities		274,446			326,913
Accrued royalties		80,770			77,672
Current portion of asset retirement obligations		118,713			97,166
Liabilities from price risk management activities		22,032			6,474
Accrued interest payable		20,291			49,084
Current portion of operating lease liabilities		3,684			3,837
Other current liabilities		45,482			44,854
Total current liabilities		672,776			723,055
Long-term liabilities:
Long-term debt		1,222,553			1,221,399
Asset retirement obligations		1,071,074			1,052,569
Liabilities from price risk management activities		16,500			3,537
Operating lease liabilities		14,642			15,489
Other long-term liabilities		403,704			416,041
Total liabilities		3,401,249			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 March 31, 2025 and December 31, 2024, respectively		—			—
Common stock; $0.01 par value; 270,000,000 shares authorized; 188,160,804 and 187,434,908 shares issued as of March 31, 2025 and December 31, 2024, respectively		1,882			1,874
Additional paid-in capital		3,278,165			3,274,626
Accumulated deficit		(433,978	)		(424,110	)
Treasury stock, at cost; 9,705,658 and 7,417,385 shares as of March 31, 2025 and December 31, 2024, respectively		(114,753	)		(92,685	)
Total stockholdersʼ equity		2,731,316			2,759,705
Total liabilities and stockholdersʼ equity	$	6,132,565		$	6,191,795

TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except per share amounts)

(Unaudited)


	Three Months Ended March 31,
	2025			2024
Revenues:
Oil	$	440,723		$	393,221
Natural gas		52,735			23,698
NGL		19,601			13,013
Total revenues		513,059			429,932
Operating expenses:
Lease operating expense		127,805			135,178
Production taxes		114			544
Depreciation, depletion and amortization		280,716			215,664
Accretion expense		30,894			26,903
General and administrative expense		34,615			69,841
Other operating (income) expense		(4,536	)		(86,043	)
Total operating expenses		469,608			362,087
Operating income (expense)		43,451			67,845
Interest expense		(40,927	)		(50,845	)
Price risk management activities income (expense)		(15,853	)		(87,062	)
Equity method investment income (expense)		(490	)		(8,054	)
Other income (expense)		3,860			(55,896	)
Net income (loss) before income taxes		(9,959	)		(134,012	)
Income tax benefit (expense)		91			21,573
Net income (loss)	$	(9,868	)	$	(112,439	)

Net income (loss) per common share:
Basic	$	(0.05	)	$	(0.71	)
Diluted	$	(0.05	)	$	(0.71	)
Weighted average common shares outstanding:
Basic		180,192			158,490
Diluted		180,192			158,490

TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN

STOCKHOLDERS’ EQUITY

(In thousands, except share amounts)

(Unaudited)


	Common Stock				Additional Paid-In			Accumulated			Treasury Stock					Total Stockholdersʼ
	Shares Issued		Par Value		Capital			Deficit			Shares		Amount			Equity
Balance at December 31, 2023		127,480,361	$	1,275	$	2,549,097		$	(347,717	)		3,400,000	$	(47,504	)	$	2,155,151
Equity-based compensation		—		—		4,646			—			—		—			4,646
Equity-based compensation tax withholdings		—		—		(5,520	)		—			—		—			(5,520	)
Equity-based compensation stock issuances		977,485		10		(10	)		—			—		—			—
Issuance of common stock for acquisitions (Note 2)		24,349,452		243		322,387			—			—		—			322,630
Issuance of common stock		34,500,000		345		387,372			—			—		—			387,717
Net income (loss)		—		—		—			(112,439	)		—		—			(112,439	)
Balance at March 31, 2024		187,307,298	$	1,873	$	3,257,972		$	(460,156	)		3,400,000	$	(47,504	)	$	2,752,185

Balance at December 31, 2024		187,434,908	$	1,874	$	3,274,626		$	(424,110	)		7,417,385	$	(92,685	)	$	2,759,705
Equity-based compensation		—		—		5,932			—			—		—			5,932
Equity-based compensation tax withholdings		—		—		(2,385	)		—			—		—			(2,385	)
Equity-based compensation stock issuances		725,896		8		(8	)		—			—		—			—
Purchase of treasury stock		—		—		—			—			2,288,273		(22,068	)		(22,068	)
Net income (loss)		—		—		—			(9,868	)		—		—			(9,868	)
Balance at March 31, 2025		188,160,804	$	1,882	$	3,278,165		$	(433,978	)		9,705,658	$	(114,753	)	$	2,731,316

TALOS ENERGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)


	Three Months Ended March 31,
	2025			2024
Cash flows from operating activities:
Net income (loss)	$	(9,868	)	$	(112,439	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion, amortization and accretion expense		311,610			242,567
Amortization of deferred financing costs and original issue discount		1,830			2,598
Equity-based compensation expense		4,141			2,754
Price risk management activities (income) expense		15,853			87,062
Net cash received (paid) on settled derivative instruments		5,167			(3,494	)
Equity method investment (income) expense		490			8,054
Loss (gain) on extinguishment of debt		—			60,256
Settlement of asset retirement obligations		(9,752	)		(27,907	)
Loss (gain) on sale of assets		(16	)		—
Loss (gain) on sale of business		—			(86,940	)
Changes in operating assets and liabilities:
Accounts receivable		32,038			8,020
Other current assets		(2,136	)		(5,818	)
Accounts payable		1,075			10,707
Other current liabilities		(83,294	)		(65,249	)
Other non-current assets and liabilities, net		1,103			(23,745	)
Net cash provided by (used in) operating activities		268,241			96,426
Cash flows from investing activities:
Exploration, development and other capital expenditures		(129,003	)		(146,077	)
Payments for acquisitions, net of cash acquired		(14,845	)		(916,045	)
Proceeds from (cash paid for) sale of property and equipment, net		540			—
Contributions to equity method investees		—			(17,519	)
Proceeds from sales of businesses		—			141,997
Net cash provided by (used in) investing activities		(143,308	)		(937,644	)
Cash flows from financing activities:
Issuance of common stock		—			387,717
Issuance of senior notes		—			1,250,000
Redemption of senior notes		—			(897,116	)
Proceeds from Bank Credit Facility		—			670,000
Repayment of Bank Credit Facility		—			(545,000	)
Deferred financing costs		—			(25,505	)
Other deferred payments		(4,949	)		(672	)
Payments of finance lease		(4,769	)		(4,324	)
Purchase of treasury stock		(17,291	)		—
Employee stock awards tax withholdings		(2,385	)		(5,520	)
Net cash provided by (used in) financing activities		(29,394	)		829,580

Net increase (decrease) in cash, cash equivalents and restricted cash		95,539			(11,638	)
Cash, cash equivalents and restricted cash:
Balance, beginning of period		214,432			135,999
Balance, end of period	$	309,971		$	124,361

Supplemental non-cash transactions:
Capital expenditures included in accounts payable and accrued liabilities	$	72,711		$	101,794
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	58,636		$	55,224

TALOS ENERGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

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

Organization and Nature of Business

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

The Parent Company (including its subsidiaries, collectively “Talos” or the “Company”) is a technically driven, innovative independent energy company focused on maximizing long-term value through our oil and gas exploration and production (“Upstream”) business in the United States (“U.S.”) Gulf of America and offshore Mexico. The Company 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 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. The Company continues to evaluate the impact of this new disclosure requirement.

Disaggregation of Income Statement Expenses — As disclosed in the in the Notes to Consolidated Financial Statements of our 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):



	March 31, 2025		December 31, 2024
Cash and cash equivalents	$	202,950	$	108,172
Restricted cash included in Other long-term assets		107,021		106,260
Total cash, cash equivalent and restricted cash	$	309,971	$	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 $18.8 million was recognized during the three months ended March 31, 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 three months ended March 31, 2024. Additionally, the Company incurred $14.2 million in severance expense in connection with the QuarterNorth Acquisition for the three months ended March 31, 2024.

The following table presents revenue and net income attributable to the QuarterNorth Acquisition for the period from March 4, 2024 to March 31, 2024:


Revenue	$	43,949
Net income (loss)	$	6,749

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 months ended March 31, 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 months ended March 31, 2024 were adjusted to exclude $25.0 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 March 31, 2024
Revenue	$	557,201
Net income (loss)	$	(110,459	)
Basic net income (loss) per common share	$	(0.60	)
Diluted net income (loss) per common share	$	(0.60	)

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 amounts for the deferred cash consideration of $14.3 million and $4.0 million are included in “Other current liabilities” and “Other long-term liabilities,” respectively, on the Condensed Consolidated Balance Sheets at March 31, 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.

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. A gain of $100.4 million was recognized related to TLCS Divestiture during the year ended December 31, 2024, which reflects a gain of $86.9 million recognized upon the close of the TLCS Divestiture during the three months ended March 31, 2024 and an incremental $13.5 million gain recognized during the three months ended September 30, 2024 related to certain contingent payments. The gain on the TLCS Divestiture is presented as “Other operating income (expense)” on the Condensed Consolidated Statements of Operations. As of March 31, 2025 and December 31, 2024, $10.5 million and $9.7 million of the 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 three months ended March 31, 2024 and is 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 three months ended March 31, 2024.

Note 3 — Property, Plant and Equipment

Proved Properties

During the three months ended March 31, 2025 and 2024, the Company’s ceiling test computations did not result in a write-down of its U.S. oil and natural gas properties. At March 31, 2025, the Company’s ceiling test computation was based on SEC pricing of $74.52 per Bbl of oil, $2.78 per Mcf of natural gas and $21.19 per Bbl of NGLs. It is reasonably possible that a 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 March 31,
	2025			2024
Finance lease costs - interest on lease liabilities	$	2,927		$	3,372
Operating lease costs, excluding short-term leases(1)		1,075			897
Short-term lease costs(2)		40,113			12,652
Variable lease costs(3)		667			616
Variable and fixed sublease income		(397	)		(359	)
Total lease costs	$	44,385		$	17,178

(1)

Operating lease costs reflect a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a straight-line basis.

(2)

Short-term lease costs are reported at gross amounts and primarily represent costs incurred for drilling rigs and well intervention vessels, most of which are short-term contracts not recognized as a ROU asset and lease liability on the Condensed Consolidated Balance Sheets. The short-term operating lease costs incurred during the periods presented are not indicative of the Company’s current short-term lease obligations, which are approximately $54.7 million as of March 31, 2025, or its future short-term lease costs and obligations, as it routinely enters into short-term contracts for the use of drilling rigs to support its drilling activities.

(3)

Variable lease costs primarily represent differences between minimum payment obligations and actual operating charges incurred by the Company related to its long-term leases.

The present value of the fixed lease payments recorded as the Company’s ROU asset and lease liability, adjusted for initial direct costs and incentives were as follows (in thousands):


	March 31, 2025		December 31, 2024
Operating leases:
Operating lease assets	$	10,703	$	11,294

Current portion of operating lease liabilities	$	3,684	$	3,837
Operating lease liabilities		14,642		15,489
Total operating lease liabilities	$	18,326	$	19,326

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

Other current liabilities	$	20,037	$	19,589
Other long-term liabilities		106,424		111,641
Total finance lease liabilities	$	126,461	$	131,230

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


	Three Months Ended March 31,
	2025		2024
Operating cash outflow from finance leases	$	2,927	$	3,372
Operating cash outflow from operating leases	$	1,484	$	1,217

ROU assets obtained in exchange for new operating lease liabilities(1)	$	—	$	1,601

(1)

See QuarterNorth Acquisition in Note 2 — Acquisitions and Divestitures.

Note 5 — Financial Instruments

As of March 31, 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):


	March 31, 2025				December 31, 2024
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
9.000% Second-Priority Senior Secured Notes – due February 2029	$	611,840	$	643,625	$	611,135	$	640,619
9.375% Second-Priority Senior Secured Notes – due February 2031	$	610,713	$	637,588	$	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 March 31,
	2025			2024
Net cash received (paid) on settled derivative instruments	$	5,167		$	(3,494	)
Unrealized gain (loss)		(21,020	)		(83,568	)
Price risk management activities income (expense)	$	(15,853	)	$	(87,062	)

The following tables reflect the contracted average daily volumes and weighted average prices under the terms of the Company's derivative contracts as of March 31, 2025:


Swap Contracts
Production Period	Settlement Index	Volumes		Swap Price
Crude oil:		(Bbls)		(per Bbl)
April 2025 – December 2025	NYMEX WTI CMA		26,069	$	72.61
January 2026 – June 2026	NYMEX WTI CMA		11,989	$	65.93
Natural gas:		(MMBtu)		(per MMBtu)
April 2025 – December 2025	NYMEX Henry Hub		51,618	$	3.45
January 2026 – December 2026	NYMEX Henry Hub		23,699	$	3.85


Two-Way Collar Contracts
Production Period	Settlement Index	Volumes		Floor Price		Ceiling Price
Crude oil:		(Bbls)		(per Bbl)		(per Bbl)
January 2026 – December 2026	NYMEX WTI CMA		9,000	$	60.00	$	68.50

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


	March 31, 2025
	Level 1		Level 2			Level 3		Total
Assets:
Oil and natural gas derivatives	$	—	$	41,240		$	—	$	41,240
Liabilities:
Oil and natural gas derivatives		—		(38,532	)		—		(38,532	)
Total net asset (liability)	$	—	$	2,708		$	—	$	2,708


	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):


	March 31, 2025				December 31, 2024
	Assets		Liabilities		Assets		Liabilities
Oil and natural gas derivatives:
Current	$	28,272	$	22,032	$	33,486	$	6,474
Non-current		12,968		16,500		253		3,537
Total gross amounts presented on balance sheet		41,240		38,532		33,739		10,011
Less: Gross amounts not offset on the balance sheet		31,256		31,256		10,011		10,011
Net amounts	$	9,984	$	7,276	$	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 March 31, 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 March 31, 2025 would have been $10.0 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 March 31, 2025 and December 31, 2024, the Company's ownership interest in Talos Mexico was 50.1% and the carrying amount of its investment was $109.9 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):


	March 31, 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		(27,447	)		(28,601	)
Total debt(1)	$	1,222,553		$	1,221,399

(1)

As of March 31, 2025, the Company was in compliance with all debt covenants.

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		9,337
Obligations settled		(9,752	)
Accretion expense		30,894
Changes in estimate		9,573
Asset retirement obligations at March 31, 2025	$	1,189,787
Less: Current portion at March 31, 2025		118,713
Long-term portion at March 31, 2025	$	1,071,074

At March 31, 2025, the Company has (1) restricted cash of $107.0 million held in escrow and (2) two notes receivable with an aggregated face value of $66.2 million to settle future asset retirement obligations. 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”) for the three months ended March 31, 2025:


	Restricted Stock Units			Weighted Average Grant Date Fair Value
Unvested RSUs at December 31, 2024		3,542,435		$	12.83
Granted		2,901,549		$	8.79
Vested		(1,008,647	)	$	14.56
Forfeited		(32,738	)	$	10.91
Unvested RSUs at March 31, 2025		5,402,599		$	10.35

Performance Share Units (“PSUs”) — The following table summarizes PSU activity under the A&R LTIP for the three months ended March 31, 2025:


	Performance Share Units		Weighted Average Grant Date Fair Value
Unvested PSUs at December 31, 2024		649,666	$	15.27
Granted(1)		939,244	$	9.76
Unvested PSUs at March 31, 2025		1,588,910	$	12.01

(1)

There were 761,663 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:


	March 10, 2025
Expected term (in years)		2.8
Expected volatility		52.4	%
Risk-free interest rate		3.8	%
Dividend yield		—	%
Fair value (in thousands)	$	8,371

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 March 31,
	2025		2024
Share-based compensation costs	$	5,940	$	4,615
Less: Amounts capitalized to oil and gas properties		1,799		1,861
Total share-based compensation expense	$	4,141	$	2,754

Note 10 — Income Taxes

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

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

For the three months ended March 31, 2024, the Company recognized an income tax benefit of $21.6 million for an effective tax rate of 16.1%. 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. The Company’s valuation allowance primarily relates to various state operating loss carryforwards. A net deferred tax liability of $266.8 million and $266.6 million is included in “Other long-term liabilities” on the Condensed Consolidated Balance Sheets as of March 31, 2025 and December 31, 2024, respectively.

Note 11 — Income (Loss) Per Share

Basic earnings per common share is computed by dividing net income (loss) attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be antidilutive, diluted earnings per common share includes the impact of RSUs and PSUs.

The following table presents the computation of the Company’s basic and diluted income (loss) per share were as follows (in thousands, except for the per share amounts):


	Three Months Ended March 31,
	2025			2024
Net income (loss)	$	(9,868	)	$	(112,439	)

Weighted average common shares outstanding — basic		180,192			158,490
Dilutive effect of securities		—			—
Weighted average common shares outstanding — diluted		180,192			158,490

Net income (loss) per common share:
Basic	$	(0.05	)	$	(0.71	)
Diluted	$	(0.05	)	$	(0.71	)
Anti-dilutive potentially issuable securities excluded from diluted common shares		3,528			2,789

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. (“Adage”) and affiliated entities of Bain Capital, LP (“Bain”), 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. Bain held approximately 8.5% of the Company’s outstanding shares of common stock as of March 31, 2025 based on SEC beneficial ownership reports filed by Bain. Adage is no longer a beneficial owner of more than five percent of the Company’s common stock based on their last SEC beneficial ownership report filed in February 2024.

Slim Family and Affiliates

Carlos Slim Helú, Carlos Slim Domit, Marco Antonio Slim Domit, Patrick Slim Domit, María Soumaya Slim Domit, Vanessa Paola Slim Domit and Johanna Monique Slim Domit (collectively, the “Slim Family”) are beneficiaries of a Mexican trust which in turn owns all of the outstanding voting securities of Control Empresarial de Capitales S.A. de C.V. (“Control Empresarial” together with the Slim Family, the “Slim Family Office”). Control Empresarial held approximately 24.4% of the Company’s outstanding shares of common stock as of March 31, 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 $2.5 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 March 31, 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 $0.6 million and $0.7 million related party receivable from Talos Mexico as of March 31, 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 March 31, 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 March 31, 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 March 31, 2025, the future minimum transportation payments under the Company’s commitments total approximately $44.9 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

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. Regulations or federal laws 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		(157	)
Settlements		(278	)
Decommissioning Obligations at March 31, 2025	$	19,567
Less: Current portion at March 31, 2025		4,104
Long-term portion at March 31, 2025	$	15,463

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 for the three months ended March 31, 2025 (in thousands):


	Upstream
Revenues from external customers	$	513,059
Significant expenses:
Lease operating expense:
Direct operating and maintenance		(125,567	)
Workover		(2,238	)
Adjusted general and administrative expense(1)		(30,310	)
Net cash received (paid) on settled derivative instruments		5,167
Interest expense		(40,927	)
Other segment items:
Other(2)		8,118
Depreciation, depletion and amortization		(280,716	)
Accretion expense		(30,894	)
Mark-to-market derivative fair value gain (loss)		(21,020	)
Equity-based compensation expense		(4,141	)
Equity method investment income (loss)		(490	)
Income tax benefit (expense)		91
Net income (loss)		(9,868	)

Segment Expenditures	$	127,604

(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 for the three months ended March 31, 2024 (in thousands):


	Upstream			CCS(1)			Total
Revenues from external customers	$	429,932		$	—		$	429,932
Significant expenses:
Lease operating expense:
Direct operating and maintenance		(99,269	)		—			(99,269	)
Workover		(35,909	)		—			(35,909	)
Adjusted general and administrative expense(2)		(27,385	)		(1,919	)		(29,304	)
Net cash received (paid) on settled derivative instruments		(3,494	)		—			(3,494	)
Interest expense		(50,639	)		(206	)		(50,845	)
Other segment items:
Other(3)		(25,077	)		(9,787	)		(34,864	)
Depreciation, depletion and amortization		(215,618	)		(46	)		(215,664	)
Accretion expense		(26,903	)		—			(26,903	)
Mark-to-market derivative fair value gain (loss)		(83,568	)		—			(83,568	)
Equity-based compensation expense		(2,707	)		(47	)		(2,754	)
Gain on TLCS Divestiture(4)		—			86,940			86,940
Equity method investment income (loss)		(84	)		(7,970	)		(8,054	)
Gain (loss) on extinguishment of debt		(60,256	)		—			(60,256	)
Income tax benefit (expense)		31,526			(9,953	)		21,573
Net income (loss)		(169,451	)		57,012		$	(112,439	)

Segment Expenditures	$	143,848		$	17,519		$	161,367

(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 $14.8 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):


	Three Months Ended March 31,
	2025			2024
Segment Expenditures:
Total reportable segments	$	127,604		$	161,367
Change in capital expenditures included in accounts payable and accrued liabilities		12,839			34,262
Plugging & abandonment		(9,752	)		(27,907	)
Decommissioning obligations settled		(278	)		(3,506	)
Investment in CCS equity method investees		—			(17,519	)
Proceeds from the sale of equipment		540			—
Non-cash well equipment transfers		(1,459	)		—
Deferred payments		(536	)		(672	)
Other		45			52
Exploration, development and other capital expenditures	$	129,003		$	146,077

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 2024 Annual Report.

Appointment of President and Chief Executive Officer — Effective March 1, 2025, Mr. Paul Goodfellow was appointed President and Chief Executive Officer, principal executive officer and as an executive member of the Board.

Acquisition of Incremental Working Interest in Monument Oil Discovery — On March 7, 2025, the Company completed the acquisition of an incremental 8.3% working interest in the Monument oil discovery in the U.S. Gulf of America located on certain Walker Ridge lease blocks. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for more information.

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 more information.

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 March 31, 2025, the daily spot prices for NYMEX WTI crude oil ranged from a high of $80.73 per Bbl to a low of $66.31 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 $2.93 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 MMBtu 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 March 31, 2025.

Recent developments in U.S. trade policy and oil production have led to a significant drop in crude oil prices during April. On April 2, 2025, President Trump signed an Executive Order announcing 10% tariffs on imports from all countries, with higher tariffs initially imposed on some countries. On April 3, 2025, OPEC Plus announced that some countries will start production increases in May 2025 that were originally set for July 2025. Following these announcements, crude oil prices fell sharply. On April 10, 2025, the U.S. Energy Information Administration (“EIA”) published its short-term energy outlook, with expectations that prices for crude oil and other commodities will continue to experience significant volatility as market participants assess the effects of trade policies. The EIA expects global oil inventories will increase starting in the middle of 2025 as OPEC Plus members unwind production cuts, production grows in non-OPEC countries, and oil demand growth slows. The effect that new or additional tariffs will have on global economic activity and associated oil demand is still highly uncertain and could weigh heavily on crude oil prices going forward. The implementation of energy-sector sanctions on Russia and Iran, as well as the wind down of Chevron’s Venezuela oil exports, have increased crude oil price volatility in the short term while markets and trade patterns adjust. The EIA expects the NYMEX WTI spot prices to average $63.88 per barrel in 2025 and $57.48 per barrel in 2026 and Henry Hub price to average around $4.27 per MMBtu in 2025 and $4.60 per MMBtu in 2026.

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 March 2025, the U.S. Federal Reserve (the “Fed”) left its benchmark interest rate unchanged at a range of 4.25%-4.50% although the Fed indicated it still anticipates reducing borrowing costs by half a percentage point by the end of 2025 in the context of slowing economic growth and, eventually, a downturn in inflation. 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. 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. The recent tariffs may increase inflation in the near term, lead to slower growth for the U.S. economy and increase the probability of a U.S. recession.

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. For the three months ended March 31, 2025 and 2024, we did not recognize an impairment based on the ceiling test computations. At March 31, 2025 our ceiling test computation was based on SEC pricing of $74.52 per Bbl of oil, $2.78 per Mcf of natural gas and $21.19 per Bbl of NGLs.

If the unweighted average first-day-of-the-month commodity price for crude oil or natural gas for the period beginning April 1, 2024 and ending March 1, 2025 used in the determination of the SEC pricing was 10% lower, resulting in $67.01 per Bbl of oil, $2.53 per Mcf of natural gas and $19.16 per Bbl of NGLs, while all other factors remained constant, our oil and natural gas properties would have been impaired by approximately $610.0 million assuming all other factors remained constant.

There is a significant degree of uncertainty with the assumptions used to estimate the present value of future net cash flows from estimated production of proved oil and gas reserves due to, but not limited to the risk factors referred to in Part I, Item 1A. “Risk Factors” included in our 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.

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.

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 “District Court”) by multiple oil and gas industry groups and the States of Mississippi, Louisiana and Texas and the District Court granted a stay of the litigation while the agency pursues efforts to suspend, revise, or rescind the final rule. The 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 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, the first of which is expected to be held by the end of 2025. We cannot determine when the 11th National OCS Program will be initiated, or how many lease sales will be scheduled.

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.

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.

Results of Operations

Revenue

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


	Three Months Ended March 31,
	2025		2024		Change
Revenues:
Oil	$	440,723	$	393,221	$	47,502
Natural gas		52,735		23,698		29,037
NGL		19,601		13,013		6,588
Total revenues	$	513,059	$	429,932	$	83,127

Production Volumes:
Oil (MBbls)		6,144		5,173		971
Natural gas (MMcf)		12,214		8,659		3,555
NGL (MBbls)		900		632		268
Total production volume (MBoe)		9,080		7,248		1,832

Daily Production Volumes by Product:
Oil (MBblpd)		68.3		56.8		11.5
Natural gas (MMcfpd)		135.7		95.2		40.5
NGL (MBblpd)		10.0		6.9		3.1
Total production volume (MBoepd)		100.9		79.6		21.3

Average Sale Price Per Unit:
Oil (per Bbl)	$	71.73	$	76.02	$	(4.29	)
Natural gas (per Mcf)	$	4.32	$	2.74	$	1.58
NGL (per Bbl)	$	21.78	$	20.59	$	1.19
Price per Boe	$	56.50	$	59.32	$	(2.82	)
Price per Boe (including realized commodity derivatives)	$	57.07	$	58.84	$	(1.77	)

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


	Three Months Ended March 31, 2025 vs 2024
	Price			Volume		Total
Revenues:
Oil	$	(26,313	)	$	73,815	$	47,502
Natural gas		19,296			9,741		29,037
NGL		1,070			5,518		6,588
Total revenues	$	(5,947	)	$	89,074	$	83,127

Three Months Ended March 31, 2025 and 2024 Volumetric Analysis — Production volumes increased by 21.3 MBoepd to 100.9 MBoepd. The increase was primarily due to 22.8 MBoepd of production from the oil and natural gas assets acquired in the QuarterNorth Acquisition that closed in early March 2024 as well as 6.8 MBoepd of production from the recompletion of one of our operated Brutus wells, which commenced initial production in July 2024. Additionally, there was 2.0 MBoepd in deferred production resulting from third party infrastructure downtime primarily from our Lobster Field in the corresponding period in 2024. These increases were partially offset by a decrease of approximately 8.3 MBoepd due to well performance and natural production declines.

Operating Expenses

Lease Operating Expense

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


	Three Months Ended March 31,
	2025		2024
Lease operating expenses	$	127,805	$	135,178
Lease operating expenses per Boe	$	14.08	$	18.65

Three Months Ended March 31, 2025 and 2024 — Lease operating expense for the three months ended March 31, 2025 decreased by approximately $7.4 million, or 5%. This was primarily related to a $30.8 million decrease in workover expenses at the Phoenix Field and Garden Banks 506 Field compared to the same period in 2024. This was partially offset by a $16.9 million increase in direct lease operating expenses due to the QuarterNorth Acquisition that closed in late first quarter of 2024. Additionally, there was a $4.6 million decrease in production handling fees related to reimbursements for costs from certain third parties related to our historical operations.

Depreciation, Depletion and Amortization

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

Three Months Ended March 31, 2025 and 2024 — Depreciation, depletion and amortization expense for the three months ended March 31, 2025 increased by approximately $65.1 million, or 30%. This increase was primarily driven by the increased production volumes of 21.3 MBoepd discussed above and to a lesser extent an increase of $1.14 per Boe, or 4% in the depletion rate on our proved oil and natural gas properties. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for further discussion.

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 March 31,
	2025		2024
Upstream Segment	$	34,615	$	58,072
CCS Segment		—		11,769
Total general and administrative expense	$	34,615	$	69,841

Upstream general and administrative expense per Boe	$	3.81	$	8.01

Three Months Ended March 31, 2025 and 2024 — General and administrative expense for the three months ended March 31, 2025 decreased by approximately $35.2 million, or 50%. 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 $30.7 million or $3.38 per Boe. Additionally, there was a decrease in the CCS Segment transaction costs, severance costs and expenses of $11.8 million due to the divestiture of our CCS business. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for further discussion.

Miscellaneous

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


	Three Months Ended March 31,
	2025			2024
Accretion expense	$	30,894		$	26,903
Other operating (income) expense	$	(4,536	)	$	(86,043	)
Interest expense	$	40,927		$	50,845
Price risk management activities (income) expense	$	15,853		$	87,062
Equity method investment (income) expense	$	490		$	8,054
Other (income) expense	$	(3,860	)	$	55,896
Income tax (benefit) expense	$	(91	)	$	(21,573	)

Three Months Ended March 31, 2025 and 2024 —

Accretion Expense — During the three months ended March 31, 2025, we recorded $30.9 million of accretion expense compared to $26.9 million during the three months ended March 31, 2024. The change is primarily the result of a $3.1 million increase in accretion associated with the asset retirement obligations assumed as part of the QuarterNorth Acquisition in early March 2024. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures.”

Other Operating (Income) Expense — During the three months ended March 31, 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.”

Interest Expense — During the three months ended March 31, 2025, we recorded $40.9 million of interest expense compared to $50.8 million during the three months ended March 31, 2024. The change is primarily due to a $5.1 million decrease in interest expense related to the Bank Credit Facility as a result of lower borrowings compared to the corresponding period in 2024. See Part I, Item 1. “Financial Statements — Note 7 — Debt” for more 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 more information.

Price Risk Management Activities — The expense of $15.9 million for the three months ended March 31, 2025 consists of $21.0 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $5.2 million in cash settlement gains. The expense of $87.1 million for the three months ended March 31, 2024 consists of $83.6 million in non-cash losses from the decrease in the fair value of our open derivative contracts and $3.5 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.”

Equity Method Investment (Income) Expense — During the three months ended March 31, 2024, we recorded equity losses of $8.1 million primarily related to our CCS Segment.

Other (Income) Expense — During the three months ended March 31, 2025, we had $3.9 million of other income compared to $55.9 million in other expense for the three months ended March 31, 2024. The change is primarily a result of a $60.3 million loss on extinguishment of debt from 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”) during the three months ended March 31, 2024.

Income Tax (Benefit) Expense — During the three months ended March 31, 2025, we recorded $0.1 million of income tax benefit compared to $21.6 million of income tax benefit during the three months ended March 31, 2024. The income tax benefit recorded during the three months ended March 31, 2025 is primarily due to current year activity offset by the impact from permanent differences. See additional information 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 write-down of oil and natural gas properties, transaction and other (income) expenses, decommissioning obligations, the net change in the fair value of derivatives (mark to market effect, net of cash settlements and premiums related to these derivatives), (gain) loss on debt extinguishment, non-cash write-down of other well equipment and non-cash equity-based compensation expense.

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


	Three Months Ended March 31,
	2025			2024
Net income (loss)	$	(9,868	)	$	(112,439	)
Interest expense		40,927			50,845
Income tax (benefit) expense		(91	)		(21,573	)
Depreciation, depletion and amortization		280,716			215,664
Accretion expense		30,894			26,903
EBITDA		342,578			159,400
Transaction and other (income) expenses(1)		(4,579	)		(49,157	)
Decommissioning obligations(2)		(157	)		855
Derivative fair value (gain) loss(3)		15,853			87,062
Net cash received (paid) on settled derivative instruments(3)		5,167			(3,494	)
(Gain) loss on debt extinguishment		—			60,256
Non-cash equity-based compensation expense		4,141			2,754
Adjusted EBITDA	$	363,003		$	257,676

(1)

For the three months ended March 31, 2024, transaction expenses included $28.1 million in costs related to the QuarterNorth Acquisition, inclusive of $14.2 million in severance expense and $9.8 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 three months ended March 31, 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.

Our Bank Credit Facility currently has a borrowing base of $925.0 million but is subject to an $800.0 million availability cap. As of March 31, 2025, our available liquidity (cash plus available capacity under the Bank Credit Facility) was $960.2 million or $1,085.2 million inclusive of the $125.0 million availability cap requiring certain lender approval. Letters of credit that are outstanding reduce the available revolving credit commitments. If oil prices remain at current levels or we are unable to replace proved reserves either through acquisitions or new drilling activity, our borrowing base will likely be reduced at our next redetermination which is expected in the second quarter of 2025 and our available liquidity may be negatively impacted unless offset by cash generated from our operating activities.

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 three months ended March 31, 2025 (in thousands):


U.S. drilling & completions	$	89,228
Asset management(1)		9,537
Seismic and G&G, land, capitalized G&A and other		18,809
Total capital expenditures		117,574
Plugging & abandonment		9,752
Decommissioning obligations settled(2)		278
Total	$	127,604

(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 $500.0 million to $540.0 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 $178.0 million remaining under the authorized program as of March 31, 2025. During the three months ended March 31, 2025, we repurchased approximately 2.3 million shares for $22.0 million exclusive of broker commissions. Since the inception of our share repurchase program in March 2023, we have repurchased an aggregate of 9.7 million shares under our authorized program for a total principal amount of $114.5 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):


	Three Months Ended March 31,
	2025			2024
Operating activities	$	268,241		$	96,426
Investing activities	$	(143,308	)	$	(937,644	)
Financing activities	$	(29,394	)	$	829,580

Operating Activities — Cash flows from operating activities changed $171.8 million in the three months ended March 31, 2025 compared to the corresponding period in 2024 primarily attributable to an increase from revenues and a decrease in lease operating expense of $90.5 million. We had a decrease from general and administrative expenses of $35.2 million primarily related to transaction costs for QuarterNorth Acquisition and the TLCS Divestiture. See Part I, Item 1. “Financial Statements — Note 2 — Acquisitions and Divestitures” for additional information. There was also a decrease in settlements of asset retirement obligations of $18.2 million. Additionally, there were $5.2 million of net cash settlement receipts on derivative instruments during the three months ended March 31, 2025 compared to $3.5 million in net cash settlement payments during the corresponding period in 2024.

Investing Activities — Cash used in investing activities changed $794.3 million in the three months ended March 31, 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 $17.1 million and contributions to equity method investees decreased of $17.5 million.

Financing Activities — Cash flows related to financing activities changed $859.0 million in the three months ended March 31, 2025 compared to the corresponding period in 2024. During the three months ended March 31, 2025, we cash settled $17.3 million of our common stock repurchased through our share repurchase program. See subsection entitled “— Liquidity and Capital Resources — Share Repurchase Program” for additional information. During the three months ended March 31, 2024, the issuance of the Senior Notes in February 2024 generated $1,224.5 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, which generated net proceeds of $387.7 million after deducting underwriting discounts of $15.1 million and offering expenses of $0.8 million. The net proceeds from this equity offering partially funded the cash portion of the QuarterNorth Acquisition. Furthermore, the Bank Credit Facility had net borrowings of $125.0 million during the corresponding period in 2024.

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 more 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 more information.

Bank Credit Facility — matures March 2027 — We maintain a Bank Credit Facility with a syndicate of financial institutions (the “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. See Part I, Item 1. “Financial Statements — Note 7 — Debt” for more information.

Material Cash Requirements

We have various contractual obligations in the normal course of our operations. Some of these obligations may be reflected in our accompanying Condensed Consolidated Financial Statements, while other obligations, such as certain operating leases and capital commitments, are not reflected on our accompanying Condensed Consolidated Financial Statements. There have been no material changes to our contractual obligations since those reported in our 2024 Annual Report except for purchase obligations increased from $40.7 million to $85.1 million through 2026 primarily due to increased committed purchase orders to execute planned future drilling activities.

Performance Obligations — As of March 31, 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 March 31, 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 March 31, 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 March 31, 2025 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II – OTHER INFORMATION

Item 1. Legal Proceedings

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

Tariffs and other trade measures could adversely affect our results of operations, financial position and cash flows.

In April 2025, the U.S. government announced a baseline tariff of 10% on products from all countries and an additional individualized reciprocal tariff on the countries with which the United States has the largest trade deficits. As a result of the new administration’s trade policy, tariffs have increased and may continue to increase our material input costs. We may not be able to adequately mitigate the impact of these increased costs. The imposition of further tariffs by the United States on a broader range of imports, further retaliatory trade measures taken in response to additional tariffs or a global recession could increase costs in our supply chain or reduce demand for oil and natural gas, which would adversely affect our results of operations. The ultimate impact of these trade measures on our business operations and financial results is uncertain and may be affected by various factors, including whether and when such trade measures are implemented, the timing when such measures may become effective, and the amount, scope or nature of such trade measures, and our ability to execute strategies to mitigate the negative impacts.

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

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table sets forth information with respect to our repurchase of shares of common stock during the three months ended March 31, 2025:


Period	Total Number of Shares Purchased		Average Price Paid per Share		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 (in thousands)
January 1, 2025- January 31, 2025		—	$	—		—	$	157,486
February 1, 2025- February 28, 2025		—	$	—		—	$	157,486
March 1, 2025 - March 31, 2025		2,288,273	$	9.61		2,288,273	$	178,001
Total		2,288,273	$	9.61		2,288,273

(3)

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 $178.0 million remaining under the authorized program as of March 31, 2025. During the three months ended March 31, 2025, we repurchased approximately 2.3 million shares for $22.0 million exclusive of broker commissions. Since the inception of our share repurchase program in March 2023, we have repurchased an aggregate of 9.7 million shares under our authorized program for a total principal amount of $114.5 million. The share repurchase program has no set term limits. All repurchased shares are held in treasury.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.


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)


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


Exhibit Number		Description
2.1#		Agreement and Plan of Merger, dated as of September 21, 2022, by and among Talos Energy Inc., Talos Production Inc., Tide Merger Sub I Inc., Tide Merger Sub II LLC, Tide Merger Sub III LL, BCC EnVen Investments, L.P. and EnVen Energy Corporation (incorporated by reference to Exhibit 2.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on September 22, 2022).

2.2#		Agreement and Plan of Merger, dated as of January 13, 2024, by and among Talos Energy Inc., QuarterNorth Energy Inc., Compass Star Merger Sub Inc. and the Equityholder Representatives named therein (incorporated by reference to Exhibit 2.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 16, 2024).

3.1		Second Amended and Restated Certificate of Incorporation of Talos Energy Inc. (incorporated by reference to Exhibit 3.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023).

3.2		Certificate of Amendment to the Second Amended and Restated Certificate of Incorporation of Talos Energy Inc. (incorporated by reference to Exhibit 3.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on May 23, 2024).

3.3		Certificate of Designations of Series A Junior Participating Preferred Stock of Talos Energy Inc. (incorporated by reference to Exhibit 3.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on October 1, 2024).

3.4		Second Amended and Restated Bylaws of Talos Energy Inc. (incorporated by reference to Exhibit 3.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 14, 2023).

4.1		Indenture, dated as of February 7, 2024, and by and among Talos Production Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee, pursuant to which the 2029 Notes were issued. (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 7, 2024).

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

4.3		Indenture, dated as of February 7, 2024, and by and among Talos Production Inc., the Guarantors named therein and Wilmington Trust, National Association, as trustee, pursuant to which the 2031 Notes were issued. (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 7, 2024).

4.4		First Supplemental Indenture, dated as of March 4, 2024, by and among Talos Production Inc., each of the guarantors party thereto and Wilmington Trust, National Association, as trustee and as collateral agent (9.375% Senior Notes) (incorporated by reference to Exhibit 4.3 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on March 5, 2024).

4.5		Form of 9.000% Second-Priority Senior Secured Note due 2029 (included as Exhibit A to Exhibit 4.4 hereto) (incorporated by reference to Exhibit 4.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 7, 2024).

4.6		Form of 9.375% Second-Priority Senior Secured Note due 2031 (included as Exhibit A in Exhibit 4.5 hereto) (incorporated by reference to Exhibit 4.4 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 7, 2024).

4.7		Registration Rights Agreement, dated as of January 4, 2021, by and among Talos Production Inc., the Guarantors named therein and J.P. Morgan Securities LLC, as representative of the initial purchasers of the 2026 Notes (incorporated by reference to Exhibit 4.3 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 8, 2021).

4.8		Registration Rights Agreement, dated as of January 14, 2021, by and among Talos Production Inc., the Guarantors named therein and J.P. Morgan Securities LLC, as representative of the initial purchasers of the 2026 Notes (incorporated by reference to Exhibit 4.4 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on January 14, 2021).

4.9		Registration Rights Agreement, dated September 21, 2022, by and among Talos Energy Inc. and the Persons listed on Schedule A thereto (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on September 22, 2022).

4.10		Registration Rights Agreement, dated as of March 4, 2024, by and among Talos Energy Inc. and each of the persons listed on Schedule A thereto (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on March 5, 2024).

4.11		Rights Agreement, dated as of October 1, 2024, between Talos Energy Inc. and Computershare Trust Company, N.A., as Rights Agent (including the form of Certificate of Designations of Series A Junior Participating Preferred Stock attached thereto as Exhibit A, the form of Right Certificate attached thereto as Exhibit B and the Summary of Rights to Purchase Preferred Shares attached thereto as Exhibit C) (incorporated by reference to Exhibit 4.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on October 1, 2024).


10.1†*		Form of Amended and Restated Talos Energy Inc. 2021 Long Term Incentive Plan Performance Share Unit Grant Notice and Performance Share Unit Agreement (Stock Price Hurdle).

10.2†		Offer Letter Agreement by and between the Company and Paul Goodfellow, effective February 2, 2025. (incorporated by reference to Exhibit 10.1 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 3, 2025).

10.3†		Participation Agreement pursuant to Talos Energy Operating Company LLC Amended and Restated Executive Severance Plan. (incorporated by reference to Exhibit 10.2 to Talos Energy Inc.’s Form 8-K (File No. 001-38497) filed with the SEC on February 3, 2025).

31.1*		Certification of Chief Executive Officer of Talos Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2*		Certification of Chief Financial Officer of Talos Energy Inc. pursuant to Rule 13a-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1**		Certification of Chief Executive Officer and Chief Financial Officer of Talos Energy Inc. pursuant to 18 U.S.C. § 1350, as adopted pursuant to the Sarbanes-Oxley Act of 2002.

101.INS*		Inline XBRL Instance.

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

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


*		Filed herewith.
**		Furnished herewith.
†		Identifies management contracts and compensatory plans or arrangements.
#		The exhibits and schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K and will be provided to the SEC upon request.


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


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


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


		Page
GLOSSARY		3
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS		5
	PART I — FINANCIAL INFORMATION
Item 1.	Financial Statements	7
	Condensed Consolidated Balance Sheets	7
	Condensed Consolidated Statements of Operations	8
	Condensed Consolidated Statements of Changes in Stockholders’ Equity	9
	Condensed Consolidated Statements of Cash Flows	10
	Notes to Condensed Consolidated Financial Statements	11
	Note 1 — Organization, Nature of Business and Basis of Presentation	11
	Note 2 — Acquisitions and Divestitures	12
	Note 3 — Property, Plant and Equipment	14
	Note 4 — Leases	14
	Note 5 — Financial Instruments	15
	Note 6 — Equity Method Investments	16
	Note 7 — Debt	17
	Note 8 — Asset Retirement Obligations	17
	Note 9 — Employee Benefits Plans and Share-Based Compensation	17
	Note 10 — Income Taxes	18
	Note 11 — Income (Loss) Per Share	19
	Note 12 — Related Party Transactions	19
	Note 13 — Commitments and Contingencies	19
	Note 14 — Segment Information	20
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	33
Item 4.	Controls and Procedures	34
	PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	35
Item 1A.	Risk Factors	35
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	35
Item 3.	Defaults Upon Senior Securities	35
Item 4.	Mine Safety Disclosures	35
Item 5.	Other Information	36
Item 6.	Exhibits	37
	Signatures	39


		Talos Energy Inc.

Date:	May 5, 2025	By:	/s/ Sergio L. Maiworm, Jr.
			Sergio L. Maiworm, Jr.
			Chief Financial Officer and Executive Vice President