Talos Energy Announces First Quarter 2024 Operational and Financial Results

Rhea-AI Summary

Talos Energy Inc. announced its operational and financial results for Q1 2024, with 79.6 MBoe/d production, revenue of $429.9 million, net loss of $112.4 million, and adjusted EBITDA of $267.5 million. The company reduced debt by $225 million, refinanced notes, and awarded deepwater blocks. Talos closed the QuarterNorth acquisition and TLCS sale, achieving synergies and reducing interest rates. The company's drilling program aims to increase reserves and generate free cash flow.

Positive

• Talos achieved record production volumes of 79.6 MBoe/d in Q1 2024, meeting the high end of guidance.

• The company reduced debt by $225 million since the QuarterNorth acquisition, achieving a leverage ratio of 1.0x ahead of schedule.

• Refinanced $865 million in 2026 notes, extending maturities and significantly reducing interest rates.

• Awarded 17 deepwater blocks in the U.S. Gulf of Mexico, expanding the company's portfolio.

• Signed and closed the sale of TLCS to TotalEnergies for $148 million, reinforcing financial position.

• First quarter revenue of $429.9 million driven by solid realized prices for oil, NGLs, and natural gas.

Negative

• Net loss of $112.4 million reported for Q1 2024, with adjusted net loss of $20.9 million.

• General and Administrative expenses for the first quarter were $27.4 million.

• Lease operating expenses totaled $135.2 million, or $18.65 per Boe in Q1 2024.

• CCS expenses for the first quarter 2024 reached $9.9 million.

• Upstream capital expenditures for plugging and abandonment totaled $31.4 million in Q1 2024.

Insights

Financial Analyst

The announced first quarter results by Talos Energy Inc. reflect a company in the midst of significant operational changes, with key financial metrics that will undoubtedly influence investor perceptions. The record production volumes near the high end of their guidance showcase operational efficiency, a positive sign for potential investors. However, the reported net loss of $112.4 million, chiefly from a diluted share perspective, which can be concerning, is mitigated when considering the $20.9 million adjusted net loss that excludes CCS investments, painting a more nuanced picture of the company's core operations. The strategic sale of TLCS to TotalEnergies and the significant debt reduction improve the company's financial flexibility, which is important for withstanding volatile market conditions and investing in future growth projects. The reduced leverage ratio to 1.0x is particularly notable, as it indicates a healthier balance sheet. Moreover, the refinanced $865 million in notes and reduced interest rates could result in lower future interest expenses, contributing to improved net income margins and, potentially, share price appreciation over time. The proactive capital management moves suggest that Talos is positioning itself for long-term sustainability rather than short-term gains.

Energy Sector Analyst

The operational highlights, particularly the QuarterNorth acquisition, could have a transformative impact on Talos's production profile and cash flow generation capabilities going forward. The strategic nature of the acquisition, focusing on oil-weighted deepwater assets, is aligned with the broader industry trend of prioritizing high-margin assets. The expeditious progress on integration and realization of synergies could lead to operational efficiencies and cost savings that enhance profitability. In the context of the energy sector, Talos's focus on a balanced mix of low-risk and high-impact projects as part of its drilling program, positions it well to navigate the cyclical nature of commodity prices while pursuing reserve additions. The increased debt reduction target from $400 million to approximately $550 million reflects a commitment to maintaining a strong balance sheet, a strategy that resonates well within a sector known for its capital intensity and economic sensitivity.

Market Research Analyst

The operational updates, including the early commencement of production from the Venice and Lime Rock fields and the favorable performance of the Green Canyon and Mississippi Canyon areas, point to healthy operational dynamics. However, investors should balance this with the planned downtime for maintenance which may impact production volumes temporarily. The sale of the low carbon solutions branch and the resulting debt repayment demonstrate not only a streamlining of Talos's business focus but also an ability to execute on strategic divestitures at multiples that reward shareholders. The updated guidance for 2024, including an expected increase in average production and a higher target debt reduction, builds an optimistic outlook for the company's future performance. Investors should consider the ability of the management to execute on these targets as a barometer for future stock performance, particularly within the volatile oil and gas market.

HOUSTON, May 6, 2024 /PRNewswire/ -- Talos Energy Inc. ("Talos" or the "Company") (NYSE: TALO) today announced its operational and financial results for fiscal quarter ended March 31, 2024. Talos also provided second quarter 2024 production guidance and reiterated its operational and financial guidance for the full year 2024. 

Key Highlights

• Production of 79.6 thousand barrels of oil equivalent per day ("MBoe/d") (71% oil, 80% liquids) is at the high end of Talos's first quarter 2024 guidance range.
• Closed QuarterNorth Energy Inc. ("QuarterNorth") acquisition earlier than expected and progressing integration activities as planned.
• Completed the sale of Talos Low Carbon Solutions LLC ("TLCS") to TotalEnergies E&P USA, Inc. ("TotalEnergies") for approximately $148 million, which included Talos's entire Carbon Capture & Sequestration ("CCS") business.
• Achieved run-rate synergies from QuarterNorth acquisition and the TLCS sale of approximately $20 million in the first two months.
• Reduced debt by $225 million since closing the QuarterNorth acquisition, achieving a leverage ratio of 1.0x ahead of schedule.
• Refinanced approximately $865 million in 2026 notes, extending maturities and reducing interest rates on Talos's bonds by 275-300 basis points.
• Awarded 17 deepwater blocks comprising 95,000 gross acres in the U.S. Gulf of Mexico Outer Continental Shelf Federal Lease Sale 261.
• Sustained combined gross production rates of over 18 MBoe/d from the Venice and Lime Rock fields since starting production ahead of schedule in late December 2023.

First Quarter Summary

• Revenue of $429.9 million, driven by realized prices (excluding hedges) of $76.01 per barrel for oil, $20.59 per barrel for natural gas liquids ("NGLs"), and $2.74 per thousand cubic feet ("Mcf") for natural gas.
• Net Loss of $112.4 million, or $0.71 Net Loss per diluted share, and Adjusted Net Loss* of $20.9 million, or $0.13 Adjusted Net Loss per diluted share*, excluding CCS investments.
• Adjusted EBITDA* of $267.5 million, excluding CCS investments.
• Upstream capital expenditures of $112.4 million.
• Net cash provided by operating activities of $96.4 million.
• Adjusted Free Cash Flow* of $77.7 million, excluding CCS investments and TLCS sale proceeds.

Talos President and Chief Executive Officer Tim Duncan stated, "Talos had an extremely active first quarter and achieved solid execution across our business with production near the high end of our guidance range, representing record volumes. After completing two important transactions, we further repositioned the Company with capital market transactions that strengthened our credit profile. Our QuarterNorth acquisition, which closed one month earlier than scheduled, adds scale and high-margin oil-weighted production to our portfolio and is expected to generate sustainable free cash flow. I'm also very proud of the Talos team for their intense focus and dedication as the integration progresses smoothly and we work to realize the expected synergies by year-end 2024. We signed and concurrently closed the sale of TLCS, crystallizing a 2x multiple of invested capital for our shareholders. We used the proceeds to immediately repay borrowings under our credit facility. By the end of the first quarter, we repaid over $225 million in borrowings and ended the quarter with a leverage ratio of 1.0x, earlier than anticipated.

"Talos's drilling program is underway, balancing a mix of low-risk and high-impact projects that could provide a material increase to our reserves. Projects for the second half of 2024 are in final preparations to execute upon rig delivery, including further appraisal of the Katmai discovery and drilling the high-impact Daenerys prospect. We remain focused on our strategic priorities to generate substantial free cash flow and have increased our total debt reduction target from $400 million to approximately $550 million in 2024."

Footnotes:

*See "Supplemental Non-GAAP Information" for details and reconciliations of GAAP to non-GAAP financial measures.

RECENT DEVELOPMENTS AND OPERATIONS UPDATE

QuarterNorth Acquisition: On March 4, 2024, Talos closed the previously announced acquisition of QuarterNorth. We expect the strategic transaction of oil-weighted deepwater assets and related infrastructure to enhance Talos's ability to consistently generate substantial free cash flow while expanding its portfolio of growth opportunities. Integration is on track as Talos works to realize the expected synergies from the combination by year-end 2024. Talos's full year 2024 operational and financial guidance includes ten months of contributions from the acquired assets.

TLCS Divestiture: On March 18, 2024, Talos signed and completed the sale of TLCS to TotalEnergies for approximately $148 million, including the retention of $6 million of related cash, realizing approximately a 2.0x multiple on invested capital and an internal rate of return exceeding 100%. Talos used the proceeds from the sale to immediately repay borrowings under its Credit Facility. Talos may realize additional future cash payments upon achievement of certain milestones at the Harvest Bend or Coastal Bend projects or upon a subsequent sale of these projects by TotalEnergies.

Outer Continental Shelf Federal Lease Sale 261: Talos acquired 17 leases covering 95,000 gross acres, with 12-15 potential drilling locations already identified on that acreage. Most locations are near existing Talos infrastructure, allowing for tie-back to Company facilities.

Capital Markets Transactions: In January 2024, Talos issued $1,250 million in second lien notes, which were used to refinance approximately $865 million in 2026 second lien notes, extending maturities to the end of the decade and reducing interest rates on Talos's bonds by 275-300 basis points. In addition, Talos closed an underwritten public offering of Talos's common stock with net proceeds of approximately $388.0 million, which was used to fund the QuarterNorth transaction.

Exploration and Production Updates:

Katmai: Talos expects to commence drilling the Katmai West #2 well in the third quarter of 2024 to further appraise the field, potentially adding significant reserves. First quarter 2025 modifications to the host facility, Tarantula, will increase capacity from 27 MBoe/d to 35 MBoe/d, which will be constrained relative to the full rate capacity of the Katmai wells, allowing for extended flat production. Talos will hold a 50% working interest in Katmai. Talos is the 100% owner and operator of the Tarantula facility.

Daenerys: Talos expects to drill the Daenerys exploration well, a high-impact subsalt project, that will evaluate the Miocene section and carries a gross unrisked recoverable resource potential between 100 – 300 MMBoe. Talos has a 30% working interest in the initial test well. The prospect is part of a broader farm-in transaction that was executed in 2023 with a combined approximately 23,000 gross acres in the Walker Ridge area.

Lobster: Talos successfully drilled through the BUL-1 and Tex-Mex-E sand in the Lobster Field in the first quarter of 2024. The well is being completed as a waterflood (down-hole water injection) well and is expected to increase the hydrocarbon recovery of the existing producing wells in the prolific BUL-1 field pay. Production is expected to increase by over 2 MBoe/d gross in the next 12-18 months. Talos owns a 67% working interest.

Claiborne: The Claiborne #1 well, operated by Beacon Offshore Energy LLC, recently reinstated production in April 2024. Talos holds a 25% working interest.

Planned Downtime Updates: Following the deferral of planned drydock maintenance into the second quarter 2024, Talos mobilized the HP-1 vessel to shore for regulatory required maintenance in April. The vessel is expected to resume production in June. Talos expects the drydock to result in 5.0 – 6.0 MBoe/d of deferred production in the second quarter 2024. Talos's operational and financial guidance includes downtime estimates for the HP-1 drydock.

FIRST QUARTER  2024 RESULTS

Key Financial Highlights:

($ thousands, except per share and per Boe amounts)	Three Months Ended March 31, 2024
Total revenues	$	429,932
Net Income (Loss)	$	(112,439)
Net Income (Loss) per diluted share	$	(0.71)
Adjusted Net Income (Loss) excluding CCS*	$	(20,942)
Adjusted Net Income (Loss) excluding CCS per diluted share*	$	(0.13)
Adjusted EBITDA excluding CCS*	$	267,548
Adjusted EBITDA excluding CCS and hedges*	$	271,042
Upstream Capital Expenditures	$	112,435

Production

Production for the first quarter 2024 was 79.6 MBoe/d and was 71% oil and 80% liquids.

	Three Months Ended March 31, 2024
Oil (MBbl/d)		56.8
Natural Gas (MMcf/d)		95.2
NGL (MBbl/d)		6.9
Total average net daily (MBoe/d)		79.6

 

	Three Months Ended March 31, 2024
	Production			% Oil			% Liquids			% Operated
Green Canyon Area		24.0			81	%		88	%		90	%
Mississippi Canyon Area		42.6			73	%		82	%		83	%
Shelf and Gulf Coast		13.0			47	%		58	%		57	%
Total average net daily (MBoe/d)		79.6			71	%		80	%		81	%

 

	Three Months Ended March 31, 2024
Average realized prices (excluding hedges)(1)
Oil ($/Bbl)	$	76.01
Natural Gas ($/Mcf)	$	2.74
NGL ($/Bbl)	$	20.59
Average realized price ($/Boe)	$	59.32
Average NYMEX prices
WTI ($/Bbl)	$	77.50
Henry Hub ($/MMBtu)	$	2.15

Lease Operating & General and Administrative Expenses

Total lease operating expenses for the first quarter 2024, inclusive of workover, maintenance and insurance costs, were $135.2 million, or $18.65 per Boe. Excluding workover expenses associated with the stimulation campaign, total lease operating expenses were $98.6 million, or $13.60 per Boe. Most of the 2024 projected workover expense is expected in the first half 2024. 

General and Administrative expenses for the first quarter, adjusted to exclude CCS expenses, one-time transaction-related costs, and non-cash equity-based compensation, were $27.4 million, or $3.78 per Boe.

($ thousands, except per Boe amounts)	Three Months Ended March 31, 2024
Lease Operating Expenses	$	135,178
Lease Operating Expenses per Boe	$	18.65
Lease Operating Expenses excluding workover	$	98,578
Lease Operating Expenses excluding workover per Boe	$	13.60
Adjusted General & Administrative Expenses excluding CCS*	$	27,386
Adjusted General & Administrative Expenses excluding CCS per Boe*	$	3.78

Capital Expenditures

Upstream capital expenditures for the first quarter 2024, excluding plugging and abandonment and settled decommissioning obligations, totaled $112.4 million.

($ thousands)	Three Months Ended March 31, 2024
U.S. drilling & completions	$	44,081
Asset management(1)		24,982
Seismic and G&G, land, capitalized G&A and other		43,372
Total Upstream Capital Expenditures	$	112,435

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

CCS expenses for the first quarter 2024 totaled $9.9 million, which is included in Talos's reported Adjusted EBITDA^* figure. CCS capital expenditures for the first quarter 2024 totaled $17.5 million.

($ thousands)	Three Months Ended March 31, 2024
CCS Investments
CCS Expenses	$	9,872
CCS Capital Expenditures		17,519
Total CCS Investments	$	27,391

Plugging & Abandonment Expenses

Upstream capital expenditures for plugging and abandonment and settled decommissioning obligations for the first quarter 2024 totaled $31.4 million.

	Three Months Ended March 31, 2024
Plugging & Abandonment and Decommissioning Obligations Settled(1)	$	31,413

__________________________
(1)	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.

Liquidity and Leverage

At March 31, 2024, Talos had approximately $650.2 million of liquidity, with $640.0 million undrawn on its credit facility and approximately $21.0 million in cash, less approximately $10.8 million in outstanding letters of credit. On March 31, 2024, Talos had $1,575.0 million in total debt. Net Debt^* was $1,554.0 million. Net Debt to Pro Forma Last Twelve Months ("LTM") Adjusted EBITDA^* was 1.0x.

OPERATIONAL & FINANCIAL GUIDANCE UPDATES

For the second quarter 2024, Talos expects average daily production of 93.0 - 96.0 MBoe/d (70% oil), which includes the impact of 5.0 – 6.0 MBOE/D from the planned HP-I drydock and a full quarter contribution from QuarterNorth.

Talos's reiterates its full year 2024 operational and financial guidance and continues to expect average daily production of 89.0 - 95.0 MBoe/d (71% oil).

Talos increased its target debt reduction amount to $550 million from the previous $400 million.

The following summarizes Talos's previously disclosed full-year 2024 operational and production guidance.

		FY 2024
($ Millions, unless highlighted):		Low			High
Production	Oil (MMBbl)		23.4			24.7
	Natural Gas (Mcf)		40.0			44.2
	NGL (MMBbl)		2.5			2.7
	Total Production (MMBoe)		32.6			34.8
	Avg Daily Production (MBoe/d)		89.0			95.0
Cash Expenses	Cash Operating Expenses(1)(2)(4)*	$	510		$	530
	Workovers	$	45		$	55
	G&A(2)(3)*	$	100		$	110
Capex	Upstream Capital Expenditures(5)	$	570		$	600
P&A Expenditures	P&A, Decommissioning	$	90		$	100
Interest	Interest Expense(6)	$	175		$	185

(1) Includes Lease Operating Expenses and Maintenance.

(2) Includes insurance costs.

(3) Excludes non-cash equity-based compensation and transaction and other expenses.

(4) Includes reimbursements under production handling agreements.

(5) Excludes acquisitions.

(6) Includes cash interest expense on debt and finance lease, surety charges and amortization of deferred financing costs and original issue discounts.

*Due to the forward-looking nature a reconciliation of Cash Operating Expenses and G&A to the most directly comparable GAAP measure could not reconciled without unreasonable efforts.

HEDGES

The following table reflects contracted volumes and weighted average prices the Company will receive under the terms of its derivative contracts as of May 7, 2024. The table includes derivative instruments assumed as part of the QuarterNorth acquisition:

	Instrument Type	Avg. Daily Volume			W.A. Swap			W.A. Sub- Floor			W.A. Floor			W.A. Ceiling
Crude – WTI		(Bbls)			(Per Bbl)			(Per Bbl)			(Per Bbl)			(Per Bbl)
April - June 2024	Fixed Swaps		43,522		$	75.13		---			---			---
	Collar		1,000		---			---			$	70.00		$	75.00
	Long Puts		4,000		---			---			$	70.00		---
	Short Puts		1,000		---			$	60.00		---			---
July - September 2024	Fixed Swaps		38,011		$	75.40		---			---			---
	Collar		1,000		---			---			$	70.00		$	75.00
	Long Puts		4,000		---			---			$	70.00		---
	Short Puts		1,000		---			$	60.00		---			---
October - December 2024	Fixed Swaps		38,674		$	76.07		---			---			---
	Collar		1,000		---			---			$	70.00		$	75.00
	Long Puts		4,000		---			---			$	70.00		---
	Short Puts		1,000		---			$	60.00		---			---
January - March 2025	Fixed Swaps		32,000		$	72.52		---			---			---
	Collar		3,000		---			---			$	65.00		$	84.35
April - June 2025	Fixed Swaps		21,000		$	73.12		---			---			---
July - September 2025	Fixed Swaps		14,000		$	74.04		---			---			---
October - December 2025	Fixed Swaps		12,000		$	74.08		---			---			---
Natural Gas – HH NYMEX		(MMBtu)			(Per MMBtu)			(Per MMBtu)			(Per MMBtu)			(Per MMBtu)
April - June 2024	Fixed Swaps		38,407		$	3.04		---			---			---
	Collar		10,000		---			---			$	4.00		$	6.90
	Long Puts		13,660		---			---			$	2.90		---
July - September 2024	Fixed Swaps		30,000		$	2.82		---			---			---
	Collar		10,000		---			---			$	4.00		$	6.90
	Long Puts		13,660		---			---			$	2.90		---
October - December 2024	Fixed Swaps		35,000		$	2.85		---			---			---
	Collar		10,000		---			---			$	4.00		$	6.90
	Long Puts		13,660		---			---			$	2.90		---
January - March 2025	Fixed Swaps		60,000		$	3.68		---			---			---
April - June 2025	Fixed Swaps		35,000		$	3.51		---			---			---
July - September 2025	Fixed Swaps		30,000		$	3.58		---			---			---
October - December 2025	Fixed Swaps		30,000		$	3.58		---			---			---

CONFERENCE CALL AND WEBCAST INFORMATION 

Talos will host a conference call, which will be broadcast live over the internet, on Tuesday, May 7, 2024 at 10:00 AM Eastern Time (9:00 AM Central Time). Listeners can access the conference call through a webcast link on the Company's website at: https://www.talosenergy.com/investor-relations/events-calendar/default.aspx. Alternatively, the conference call can be accessed by dialing (800) 836-8184 (North American toll-free) or (646) 357-8785 (international). Please dial in approximately 15 minutes before the teleconference is scheduled to begin and ask to be joined into the Talos Energy call. A replay of the call will be available one hour after the conclusion of the conference until May 14, 2024 and can be accessed by dialing (888) 660-6345 and using access code 98377#. For more information, please refer to the First Quarter 2024 Earnings Presentation available under Presentations and Filings on the Investor Relations section of Talos's website.

ABOUT TALOS ENERGY

Talos Energy (NYSE: TALO) is a technically driven, innovative, independent energy company focused on maximizing long-term value through its Upstream Exploration & Production business in the United States Gulf of Mexico 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. For more information, visit www.talosenergy.com.

INVESTOR RELATIONS CONTACT

Clay Jeansonne
investor@talosenergy.com  

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENT

The information in this communication includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended (the "Securities Act"), and Section 21E of the Securities Exchange Act of 1934, as amended (the "Exchange Act"). All statements, other than statements of historical fact included in this communication regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this communication, the words "will," "could," "believe," "anticipate," "intend," "estimate," "expect," "project," "forecast," "may," "objective," "plan" and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Forward-looking statements are based on management's current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. These forward-looking statements are based on our current beliefs, based on currently available information, as to the outcome and timing of future events. Forward-looking statements may include statements about: business strategy; recoverable resources and reserves; drilling prospects, inventories, projects and programs; our ability to replace the reserves that we produce through drilling and property acquisitions; financial strategy, liquidity and capital required for our development program and other capital expenditures; realized oil and natural gas prices; risks related to future mergers and acquisitions and/or to realize the expected benefits of any such transaction timing and amount of future production of oil, natural gas and NGLs; our hedging strategy and results; future drilling plans; availability of pipeline connections on economic terms; competition, government regulations, including new financial assurance requirements, and legislative and political developments; our ability to obtain permits and governmental approvals; pending legal, governmental or environmental matters; our marketing of oil, natural gas and NGLs; our integration of acquisitions, including the QuarterNorth acquisition, and the anticipated performance of the combined company; future leasehold or business acquisitions on desired terms; costs of developing properties; general economic conditions, including the impact of continued inflation and associated changes in monetary policy; political and economic conditions and events in foreign oil, natural gas and NGL producing countries and acts of terrorism or sabotage; credit markets; volatility in the political, legal and regulatory environments ahead of the upcoming domestic and foreign presidential elections; estimates of future income taxes; our estimates and forecasts of the timing, number, profitability and other results of wells we expect to drill and other exploration activities; our ongoing strategy with respect to our Zama asset; uncertainty regarding our future operating results and our future revenues and expenses; impact of new accounting pronouncements on earnings in future periods; and plans, objectives, expectations and intentions contained in this communication that are not historical.  These forward-looking statements are subject to numerous risks and uncertainties, most of which are difficult to predict and many of which are beyond our control. These risks include, but are not limited to, commodity price volatility; global demand for oil and natural gas; the ability or willingness of OPEC and other state-controlled oil companies to set and maintain oil production levels and the impact of any such actions; the lack of a resolution to the war in Ukraine and increasing hostilities in Israel and the Middle East, and their impact on commodity markets; the impact of any pandemic and governmental measures related thereto; lack of transportation and storage capacity as a result of oversupply, government and regulations; the effect of a possible U.S. government shutdown and resulting impact on economic conditions and delays in regulatory and permitting approvals; lack of availability of drilling and production equipment and services; adverse weather events, including tropical storms, hurricanes, winter storms and loop currents; cybersecurity threats; sustained inflation and the impact of central bank policy in response thereto; environmental risks; failure to find, acquire or gain access to other discoveries and prospects or to successfully develop and produce from our current discoveries and prospects; geologic risk; drilling and other operating risks; well control risk; regulatory changes; the uncertainty inherent in estimating reserves and in projecting future rates of production; cash flow and access to capital; the timing of development expenditures; potential adverse reactions or competitive responses to our acquisitions and other transactions; the possibility that the anticipated benefits of our acquisitions are not realized when expected or at all, including as a result of the impact of, or problems arising from, the integration of acquired assets and operations; and the other risks discussed in "Risk Factors" of our Annual Report on Form 10-K for the year ended December 31, 2023 and Part II, Item 1A. "Risk Factors" of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2024, each filed with the SEC.  Should any risks or uncertainties occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. All forward-looking statements, expressed or implied, included in this communication are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this communication.

PRODUCTION ESTIMATES 

Estimates for our future production volumes are based on assumptions of capital expenditure levels and the assumption that market demand and prices for oil and gas will continue at levels that allow for economic production of these products. The production, transportation, marketing and storage of oil and gas are subject to disruption due to transportation, processing and storage availability, mechanical failure, human error, adverse weather conditions such as hurricanes, global political and macroeconomic events and numerous other factors. Our estimates are based on certain other assumptions, such as well performance, which may vary significantly from those assumed. Therefore, we can give no assurance that our future production volumes will be as estimated.

RESERVE INFORMATION

Reserve engineering is a process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions upward or downward of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered. In addition, we use the term "gross unrisked resource potential" in this release, which is not a measure of "reserves" prepared in accordance with SEC guidelines or permitted to be included in SEC filings. These resource estimates are inherently more uncertain than estimates of reserves prepared in accordance with SEC guidelines.

USE OF NON-GAAP FINANCIAL MEASURES 

This release includes the use of certain measures that have not been calculated in accordance with U.S. generally acceptable accounting principles (GAAP) such as, but not limited to, EBITDA, Adjusted EBITDA,  LTM Adjusted EBITDA, Pro Forma LTM Adjusted EBITDA, Net Debt, Net Debt to LTM Adjusted EBITDA, Net Debt to Pro Forma LTM Adjusted EBITDA, Adjusted Free Cash Flow and Leverage, Adjusted EBITDA excluding hedges, Adjusted EBITDA excluding CCS, Adjusted EBITDA excluding CCS and hedges, Adjusted EBITDA Free Cash Flow excluding CCS, Adjusted Net Income (Loss) excluding CCS. Non-GAAP financial measures have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Reconciliations for non-GAAP measure to GAAP measures are included at the end of this release.

Talos Energy Inc. Consolidated Balance Sheets (In thousands, except share amounts)
	March 31, 2024			December 31, 2023
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	21,001		$	33,637
Accounts receivable:
Trade, net		248,892			178,977
Joint interest, net		143,801			79,337
Other, net		16,652			19,296
Assets from price risk management activities		18,753			36,152
Prepaid assets		75,776			64,387
Other current assets		16,036			10,389
Total current assets		540,911			422,175
Property and equipment:
Proved properties		9,268,050			7,906,295
Unproved properties, not subject to amortization		654,906			268,315
Other property and equipment		34,440			34,027
Total property and equipment		9,957,396			8,208,637
Accumulated depreciation, depletion and amortization		(4,383,970)			(4,168,328)
Total property and equipment, net		5,573,426			4,040,309
Other long-term assets:
Restricted cash		103,360			102,362
Assets from price risk management activities		5,355			17,551
Equity method investments		108,036			146,049
Other well equipment		63,507			54,277
Notes receivable, net		16,619			16,207
Operating lease assets		12,676			11,418
Other assets		10,494			5,961
Total assets	$	6,434,384		$	4,816,309
LIABILITIES AND STOCKHOLDERSʼ EQUITY
Current liabilities:
Accounts payable	$	136,833		$	84,193
Accrued liabilities		272,231			227,690
Accrued royalties		71,007			55,051
Current portion of long-term debt		—			33,060
Current portion of asset retirement obligations		71,799			77,581
Liabilities from price risk management activities		74,033			7,305
Accrued interest payable		21,106			42,300
Current portion of operating lease liabilities		3,543			2,666
Other current liabilities		46,310			48,769
Total current liabilities		696,862			578,615
Long-term liabilities:
Long-term debt		1,533,952			992,614
Asset retirement obligations		1,037,533			819,645
Liabilities from price risk management activities		3,747			795
Operating lease liabilities		18,271			18,211
Other long-term liabilities		391,834			251,278
Total liabilities		3,682,199			2,661,158
Commitments and contingencies
Stockholdersʼ equity:
Preferred stock; $0.01 par value; 30,000,000 shares authorized and zero shares issued or outstanding as of March 31, 2024 and December 31, 2023, respectively		—			—
Common stock; $0.01 par value; 270,000,000 shares authorized; 187,307,298 and 127,480,361 shares issued as of March 31, 2024 and December 31, 2023, respectively		1,873			1,275
Additional paid-in capital		3,257,972			2,549,097
Accumulated deficit		(460,156)			(347,717)
Treasury stock, at cost; 3,400,000 and 3,400,000 shares as of March 31, 2024 and December 31, 2023, respectively		(47,504)			(47,504)
Total stockholdersʼ equity		2,752,185			2,155,151
Total liabilities and stockholdersʼ equity	$	6,434,384		$	4,816,309

 

Talos Energy Inc. Consolidated Statements of Operations (In thousands, except per share amounts) (Unaudited)
	Three Months Ended March 31,
	2024			2023
Revenues:
Oil	$	393,221		$	292,694
Natural gas		23,698			20,183
NGL		13,013			9,705
Total revenues		429,932			322,582
Operating expenses:
Lease operating expense		135,178			81,362
Production taxes		544			606
Depreciation, depletion and amortization		215,664			147,323
Accretion expense		26,903			19,414
General and administrative expense		69,841			63,187
Other operating (income) expense		(86,043)			2,838
Total operating expenses		362,087			314,730
Operating income (expense)		67,845			7,852
Interest expense		(50,845)			(37,581)
Price risk management activities income (expense)		(87,062)			58,937
Equity method investment income (expense)		(8,054)			7,443
Other income (expense)		(55,896)			6,666
Net income (loss) before income taxes		(134,012)			43,317
Income tax benefit (expense)		21,573			46,543
Net income (loss)	$	(112,439)		$	89,860
Net income (loss) per common share:
Basic	$	(0.71)		$	0.85
Diluted	$	(0.71)		$	0.84
Weighted average common shares outstanding:
Basic		158,490			105,634
Diluted		158,490			106,950

 

Talos Energy Inc. Consolidated Statements of Cash Flows (In thousands) (Unaudited)
	Three Months Ended March 31,
	2024			2023
Cash flows from operating activities:
Net income (loss)	$	(112,439)		$	89,860
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion, amortization and accretion expense		242,567			166,737
Amortization of deferred financing costs and original issue discount		2,598			4,148
Equity-based compensation expense		2,754			3,938
Price risk management activities (income) expense		87,062			(58,937)
Net cash received (paid) on settled derivative instruments		(3,494)			(12,323)
Equity method investment (income) expense		8,054			(7,443)
Loss (gain) on extinguishment of debt		60,256			—
Settlement of asset retirement obligations		(27,907)			(10,113)
Loss (gain) on sale of business		(86,940)			—
Changes in operating assets and liabilities:
Accounts receivable		8,020			36,821
Other current assets		(5,818)			7,735
Accounts payable		10,707			(4,894)
Other current liabilities		(65,249)			(116,637)
Other non-current assets and liabilities, net		(23,745)			(36,035)
Net cash provided by (used in) operating activities		96,426			62,857
Cash flows from investing activities:
Exploration, development and other capital expenditures		(146,077)			(103,962)
Proceeds from (cash paid for) acquisitions, net of cash acquired		(916,045)			17,617
Contributions to equity method investees		(17,519)			(12,835)
Investment in intangible assets		—			(7,796)
Proceeds from sales of businesses		141,997			—
Net cash provided by (used in) investing activities		(937,644)			(106,976)
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			275,000
Repayment of Bank Credit Facility		(545,000)			(110,000)
Deferred financing costs		(25,505)			(11,346)
Other deferred payments		(672)			—
Payments of finance lease		(4,324)			(3,987)
Purchase of treasury stock		—			(25,173)
Employee stock awards tax withholdings		(5,520)			(7,378)
Net cash provided by (used in) financing activities		829,580			117,116
Net increase (decrease) in cash, cash equivalents and restricted cash		(11,638)			72,997
Cash, cash equivalents and restricted cash:
Balance, beginning of period		135,999			44,145
Balance, end of period	$	124,361		$	117,142
Supplemental non-cash transactions:
Capital expenditures included in accounts payable and accrued liabilities	$	101,794		$	174,597
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	55,224		$	40,988

SUPPLEMENTAL NON-GAAP INFORMATION 

Certain financial information included in our financial results are not measures of financial performance recognized by accounting principles generally accepted in the United States, or GAAP. These non-GAAP financial measures may not be viewed as a substitute for results determined in accordance with GAAP and are not necessarily comparable to non-GAAP measures which may be reported by other companies. In addition, we believe that non-GAAP measures excluding CCS are a meaningful measure of financial performance that can be used by investors, analysts and management in evaluating the performance of our "go-forward" business after giving effect to our CCS divestiture during the first quarter of 2024, and will assist such readers of our financial statements in considering the results of this business in comparative periods.

Reconciliation of General and Administrative Expenses to Adjusted General and Administrative Expenses Excluding CCS

We believe the presentation of Adjusted General and Administrative Expenses excluding CCS provides management and investors with (i) important supplemental indicators of the operational performance of our business, (ii) additional criteria for evaluating our performance relative to our peers and (iii) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. Adjusted General & Administrative Expenses excluding CCS has limitations as an analytical tool 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:

General and Administrative Expenses. General and Administrative Expenses generally consist of costs incurred for overhead, including payroll and benefits for our corporate staff, costs of maintaining our headquarters, costs of managing our production operations, bad debt expense, equity-based compensation expense, audit and other fees for professional services and legal compliance. A portion of these expenses are allocated based on the percentage of employees dedicated to each operating segment.

($ thousands)	Three Months Ended March 31, 2024
Reconciliation of General & Administrative Expenses to Adjusted General & Administrative Expenses excluding CCS:
Total General and administrative expense	$	69,841
CCS Segment		(1,965)
Transaction and other (income) expenses(1)		(37,783)
Non-cash equity-based compensation expense		(2,707)
Adjusted General & Administrative Expenses excluding CCS	$	27,386

__________________________
(1)	Transaction expenses includes $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 divestiture of TLCS, inclusive of $3.7 million in severance expense for the three months ended March 31, 2024.

Reconciliation of Net Income (Loss) to EBITDA, Adjusted EBITDA and Adjusted EBITDA Excluding CCS

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

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

Adjusted EBITDA. EBITDA plus non-cash write-down of oil and natural gas properties, transaction and other (income) expenses, decommissioning obligations, derivative fair value (gain) loss, net cash receipts (payments) on settled derivatives, (gain) loss on debt extinguishment, non-cash write-down of other well equipment and non-cash equity-based compensation expense.

Adjusted EBITDA excluding hedges. We have historically provided as a supplement to—rather than in lieu of—Adjusted EBITDA including hedges, provides useful information regarding our results of operations and profitability by illustrating the operating results of our oil and natural gas properties without the benefit or detriment, as applicable, of our financial oil and natural gas hedges. By excluding our oil and natural gas hedges, we are able to convey actual operating results using realized market prices during the period, thereby providing analysts and investors with additional information they can use to evaluate the impacts of our hedging strategies over time.

Adjusted EBITDA excluding CCS. Adjusted EBITDA plus equity method investment loss, general and administrative expense, other operating expenses (income), other income, and non-cash equity-based compensation expense attributable to CCS.

The following tables present a reconciliation of the GAAP financial measure of Net Income (loss) to EBITDA, Adjusted EBITDA, Adjusted EBITDA excluding hedges for each of the periods indicated (in thousands):

	Three Months Ended
($ thousands)	March 31, 2024			December 31, 2023			September 30, 2023			June 30, 2023
Reconciliation of Net Income (Loss) to Adjusted EBITDA:
Net Income (loss)	$	(112,439)		$	85,898		$	(2,103)		$	13,677
Interest expense		50,845			44,295			45,637			45,632
Income tax expense (benefit)		(21,573)			(5,081)			(15,865)			6,892
Depreciation, depletion and amortization		215,664			183,058			163,359			169,794
Accretion expense		26,903			22,722			21,256			22,760
EBITDA		159,400			330,892			212,284			258,755
Transaction and other (income) expenses(1)		(49,157)			5,504			(64,321)			3,513
Decommissioning obligations(2)		855			2,425			7,972			741
Derivative fair value (gain) loss(3)		87,062			(94,596)			98,802			(26,197)
Net cash received (paid) on settled derivative instruments(3)		(3,494)			1,017			(6,313)			8,162
Loss on extinguishment of debt		60,256			—			—			—
Non-cash equity-based compensation expense		2,754			3,873			393			4,749
Adjusted EBITDA		257,676			249,115			248,817			249,723
Add: Net cash (received) paid on settled derivative instruments(3)		3,494			(1,017)			6,313			(8,162)
Adjusted EBITDA excluding hedges	$	261,170		$	248,098		$	255,130		$	241,561

__________________________
(1)	Transaction expenses includes $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 divestiture of TLCS, inclusive of $3.7 million in severance expense for the three months ended March 31, 2024, $0.9 million in costs related to the EnVen Energy Corporation ("EnVen") Acquisition, inclusive of $0.5 million in severance expense for the three months ended December 31, 2023, $1.5 million in costs related to the EnVen Acquisition, inclusive of $0.9 million in severance expense for the three months ended September 30, 2023 and $2.7 million in costs related to the EnVen acquisition, inclusive of $1.4 million in severance expense for the three months ended June 30, 2023. Other income (expense) includes restructuring expenses, cost saving initiatives and other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the three months ended March 31, 2024, the amount includes a gain of $86.9 million related to the divestiture of TLCS. For the three months ended September 30, 2023, the amount includes a $66.2 million gain on the divestiture of 49.9% equity interest in our subsidiary, Talos Energy Mexico 7, S. de R.L. de C.V. to Zamajal, S.A. de C.V., a wholly owned subsidiary of Grupo Carso.
(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 and are included in "Other operating (income) expense" on our consolidated statements of operations.
(3)	The adjustments for the derivative fair value (gain) loss and net cash receipts (payments) on settled derivative instruments have the effect of adjusting net income (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.

($ thousands, except per Boe amounts)	Three Months Ended March 31, 2024
Reconciliation of Adjusted EBITDA to Adjusted EBITDA excluding CCS:
Adjusted EBITDA	$	257,676
CCS Costs:
Equity method investment loss		7,970
General and administrative expense		1,965
Other operating expense		(11)
Other income		(5)
Non-cash equity-based compensation expense		(47)
Adjusted EBITDA excluding CCS		267,548
Add: Net cash paid on settled derivative instruments(1)		3,494
Adjusted EBITDA excluding CCS and hedges	$	271,042
Production:
Boe(2)		7,248
Adjusted EBITDA excluding CCS margin and Adjusted EBITDA excluding CCS and hedges margin:
Adjusted EBITDA excluding CCS per Boe(2)	$	36.91
Adjusted EBITDA excluding CCS and hedges per Boe(1)(2)	$	37.40

__________________________
(1)	The adjustments for the derivative fair value (gain) loss and net cash receipts (payments) on settled derivative instruments have the effect of adjusting net income (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.
(2)	One Boe is equal to six Mcf of natural gas or one Bbl of oil or NGLs based on an approximate energy equivalency. This is an energy content correlation and does not reflect a value or price relationship between the commodities.

Reconciliation of Adjusted EBITDA to Adjusted Free Cash Flow Excluding CCS and Reconciliation of Net Cash Provided by Operating Activities to Adjusted Free Cash Flow Excluding CCS

"Adjusted Free Cash Flow excluding CCS" before changes in working capital provides management and investors with (i) important supplemental indicators of the operational performance of our business, (ii) additional criteria for evaluating our performance relative to our peers and (iii) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. Adjusted Free Cash Flow excluding CCS has limitations as an analytical tool 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:

Capital Expenditures and Plugging & Abandonment. Actual capital expenditures and plugging & abandonment recognized in the quarter, inclusive of accruals.

Interest Expense. Actual interest expense per the income statement.

Talos did not pay any cash income taxes in the period, therefore cash income taxes have no impact to the reported Adjusted Free Cash Flow before changes in working capital number.

($ thousands)	Three Months Ended March 31, 2024
Reconciliation of Adjusted EBITDA to Adjusted Free Cash Flow excluding CCS (before changes in working capital):
Adjusted EBITDA	$	257,676
Upstream capital expenditures		(112,435)
Plugging & abandonment		(27,907)
Decommissioning obligations settled		(3,506)
CCS capital expenditures		(17,519)
Interest expense(1)		(45,970)
Adjusted Free Cash Flow (before changes in working capital)		50,339
CCS capital expenditures		17,519
CCS Costs:
Equity method investment loss		7,970
General and administrative expense		1,965
Other operating expense		(11)
Other income		(5)
Non-cash equity-based compensation expense		(47)
Adjusted Free Cash Flow excluding CCS (before changes in working capital)	$	77,730

__________________________
(1)	Interest expense excludes $4.9 million in fees associated with the unutilized bridge loan that we do not view as a meaningful indicator of our operating performance.

($ thousands)	Three Months Ended March 31, 2024
Reconciliation of Net Cash Provided by Operating Activities to Adjusted Free Cash Flow excluding CCS (before changes in working capital):
Net cash provided by operating activities(1)	$	96,426
(Increase) decrease in operating assets and liabilities		76,085
Upstream capital expenditures(2)		(112,435)
Decommissioning obligations settled		(3,506)
CCS capital expenditures		(17,519)
Transaction and other (income) expenses(3)		37,783
Decommissioning obligations(4)		855
Amortization of deferred financing costs and original issue discount		(2,598)
Income tax benefit		(21,573)
Other adjustments		(3,179)
Adjusted Free Cash Flow (before changes in working capital)		50,339
CCS capital expenditures		17,519
CCS Costs:
Equity method investment loss		7,970
General and administrative expense		1,965
Other operating expense		(11)
Other income		(5)
Non-cash equity-based compensation expense		(47)
Adjusted Free Cash Flow excluding CCS (before changes in working capital)	$	77,730

__________________________
(1)	Includes settlement of asset retirement obligations.
(2)	Includes accruals and excludes acquisitions.
(3)	Transaction expenses includes $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 divestiture of TLCS, inclusive of $3.7 million in severance expense for the three months ended March 31, 2024. Other income (expense) includes restructuring expenses, cost saving initiatives and other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the three months ended March 31, 2024, the amount includes a gain of $86.9 million related to the divestiture of TLCS.
(4)	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.

Reconciliation of Net Income to Adjusted Net Income (Loss) and Adjusted Earnings per Share and to Adjusted Net Income (Loss) excluding CCS and Adjusted Earnings per Share excluding CCS

"Adjusted Net Income (Loss)" and "Adjusted Earnings per Share" are to provide management and investors with (i) important supplemental indicators of the operational performance of our business, (ii) additional criteria for evaluating our performance relative to our peers and (iii) supplemental information to investors about certain material non-cash and/or other items that may not continue at the same level in the future. Adjusted Net Income (Loss) and Adjusted Earnings per Share have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP or as an alternative to net income (loss), operating income (loss), earnings per share or any other measure of financial performance presented in accordance with GAAP.

Adjusted Net Income (Loss). Net income (loss) plus accretion expense, transaction related costs, derivative fair value (gain) loss, net cash receipts (payments) on settled derivative instruments and non-cash equity-based compensation expense.

Adjusted Earnings per Share. Adjusted Net Income (Loss) divided by the number of common shares.

	Three Months Ended March 31, 2024
($ thousands, except per share amounts)				Basic per Share			Diluted per Share
Reconciliation of Net Income (Loss) to Adjusted Net Income (Loss) excluding CCS:
Net Income (loss)	$	(112,439)		$	(0.71)		$	(0.71)
Transaction and other (income) expenses(1)		(49,157)		$	(0.31)		$	(0.31)
Decommissioning obligations(2)		855		$	0.01		$	0.01
Derivative fair value loss(3)		87,062		$	0.55		$	0.55
Net cash received on paid derivative instruments(3)		(3,494)		$	(0.02)		$	(0.02)
Unutilized bridge loan fees		4,875		$	0.03		$	0.03
Non-cash income tax benefit		(21,573)		$	(0.14)		$	(0.14)
Loss on extinguishment of debt		60,256		$	0.38		$	0.38
Non-cash equity-based compensation expense		2,754		$	0.02		$	0.02
Adjusted Net Income (Loss)(4)	$	(30,861)		$	(0.19)		$	(0.19)
CCS Costs:
Equity method investment loss		7,970		$	0.05		$	0.05
General and administrative expense		1,965		$	0.01		$	0.01
Other operating expense		(11)		$	(0.00)		$	(0.00)
Other income		(5)		$	(0.00)		$	(0.00)
Adjusted Net Income (Loss) excluding CCS(4)	$	(20,942)		$	(0.13)		$	(0.13)
Weighted average common shares outstanding at March 31, 2024:
Basic		158,490
Diluted		158,490

__________________________
(1)	Transaction expenses includes $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 divestiture of TLCS, inclusive of $3.7 million in severance expense for the three months ended March 31, 2024. Other income (expense) includes restructuring expenses, cost saving initiatives and other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. For the three months ended March 31, 2024, the amount includes a gain of $86.9 million related to the divestiture of TLCS.
(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.
(3)	The adjustments for the derivative fair value (gain) loss and net cash receipts (payments) on settled derivative instruments have the effect of adjusting net income (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 Net Income (Loss) on an unrealized basis during the period the derivatives settled.
(4)	The per share impacts reflected in this table were calculated independently and may not sum to total adjusted basic and diluted EPS due to rounding.

Reconciliation of Total Debt to Net Debt and Net Debt to LTM Adjusted EBITDA

We believe the presentation of Net Debt, LTM Adjusted EBITDA, Net Debt to LTM Adjusted EBITDA and Net Debt to Pro Forma LTM Adjusted EBITDA is important to provide management and investors with additional important information to evaluate our business. These measures are widely used by investors and ratings agencies in the valuation, comparison, rating and investment recommendations of companies.

Net Debt. Total Debt principal minus cash and cash equivalents.

Net Debt to LTM Adjusted EBITDA. Net Debt divided by the LTM Adjusted EBITDA.

($ thousands)	March 31, 2024
Reconciliation of Net Debt:
9.000% Second-Priority Senior Secured Notes – due February 2029	$	625,000
9.375% Second-Priority Senior Secured Notes – due February 2031		625,000
Bank Credit Facility – matures March 2027		325,000
Total Debt		1,575,000
Less: Cash and cash equivalents		(21,001)
Net Debt	$	1,553,999
Calculation of LTM Adjusted EBITDA:
Adjusted EBITDA for three months period ended June 30, 2023	$	249,723
Adjusted EBITDA for three months period ended September 30, 2023		248,817
Adjusted EBITDA for three months period ended December 31, 2023		249,115
Adjusted EBITDA for three months period ended March 31, 2024		257,676
LTM Adjusted EBITDA	$	1,005,331
Acquired Assets Adjusted EBITDA:
Adjusted EBITDA for three months period ended June 30, 2023	$	95,707
Adjusted EBITDA for three months period ended September 30, 2023		161,427
Adjusted EBITDA for three months period ended December 31, 2023		129,063
Adjusted EBITDA for period January 1, 2024 to March 4, 2024		99,490
LTM Adjusted EBITDA from Acquired Assets	$	485,687
Pro Forma LTM Adjusted EBITDA	$	1,491,018
Reconciliation of Net Debt to Pro Forma LTM Adjusted EBITDA:
Net Debt / Pro Forma LTM Adjusted EBITDA(1)	1.0x

__________________________
(1)	Net Debt / Pro Forma LTM Adjusted EBITDA figure excludes the Finance Lease. Had the Finance Lease been included, Net Debt / Pro Forma LTM Adjusted EBITDA would have been 1.1x.

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SOURCE Talos Energy

FAQ

What was Talos Energy's production rate in Q1 2024?

Talos Energy achieved a production rate of 79.6 thousand barrels of oil equivalent per day (MBoe/d) in Q1 2024.

How much debt did Talos Energy reduce since the QuarterNorth acquisition?

Talos Energy reduced debt by $225 million since the QuarterNorth acquisition, achieving a leverage ratio of 1.0x ahead of schedule.

What was Talos Energy's revenue in Q1 2024?

Talos Energy reported revenue of $429.9 million in Q1 2024.

What was Talos Energy's net loss in Q1 2024?

Talos Energy reported a net loss of $112.4 million in Q1 2024.

What were Talos Energy's adjusted EBITDA and adjusted free cash flow in Q1 2024?

Talos Energy reported adjusted EBITDA of $267.5 million and adjusted free cash flow of $77.7 million in Q1 2024.