Talos Energy Announces Third Quarter 2023 Operational and Financial Results

Rhea-AI Summary

Talos Energy Inc. announces its operational and financial results for Q3 2023. Highlights include production of 63.7 MBoe/d, revenue of $383.1 million, net loss of $2.1 million, adjusted net income of $18.6 million, adjusted EBITDA of $248.8 million, and capital expenditures of $194.6 million. Talos is making progress on Lime Rock and Venice discoveries and has signed an exploration agreement with Repsol. The Talos Mexico transaction with Grupo Carso has been closed.

Positive

• Production of 63.7 MBoe/d, inclusive of impacts from intermittent shut-ins
• Revenue of $383.1 million driven by realized prices
• Adjusted net income of $18.6 million
• Adjusted EBITDA of $248.8 million
• Capital expenditures of $194.6 million
• Progress on Lime Rock and Venice discoveries
• Exploration agreement signed with Repsol
• Talos Mexico transaction closed with Grupo Carso

Negative

• None.

HOUSTON, Nov. 6, 2023 /PRNewswire/ -- Talos Energy Inc. ("Talos" or the "Company") (NYSE: TALO) today announced its operational and financial results for fiscal quarter ended September 30, 2023.

Third Quarter 2023 Highlights:          

• Production of 63.7 thousand barrels of oil equivalent per day ("MBoe/d") (76% oil, 83% liquids), inclusive of 2.4 MBoe/d of impacts from sustained loop currents requiring intermittent shut-ins of Talos's HP-1 floating production unit and associated infrastructure, as well as additional downtime.
• Revenue of $383.1 million, driven by realized prices (excluding hedges) of $80.75 per barrel for oil, $17.02 per barrel for natural gas liquids ("NGLs"), and $2.81 per thousand cubic feet ("Mcf") for natural gas.
• Net Loss of $2.1 million, or $0.02 Net Loss per diluted share, and Adjusted Net Income* of $18.6 million, or $0.15 Adjusted Net Income per diluted share*.
• Adjusted EBITDA* of $248.8 million and Upstream Adjusted EBITDA* of $255.2 million.
• Capital expenditures of $194.6 million, inclusive of plugging and abandonment and Carbon Capture & Sequestration ("CCS").
• Net cash provided by operating activities of $65.7 million.
• Adjusted Free Cash Flow* of $8.5 million, excluding the $74.85 million cash received at closing of the partial sale in Talos Energy Mexico 7, S. de R.L. de C.V. ("Talos Mexico") to an affiliate of Grupo Carso.

Talos President and Chief Executive Officer Timothy S. Duncan commented: "During the third quarter, we were pleased with the advancements we made on several aspects of our business. Our operations team is working hard on our Lime Rock and Venice discoveries, which are expected to come online as scheduled in early 2024. We have recently signed an important exploration agreement with Repsol, where we are pooling resources with the goal of developing an inventory of impactful wells that could be tied to existing Talos infrastructure. Additionally, we closed the Talos Mexico transaction with Grupo Carso and are encouraged about growing our partnership and progressing Zama toward FID and first oil. Our CCS portfolio continues to receive strong endorsement from the industry, as we welcomed Equinor as a partner with a 25% interest in Bayou Bend following its purchase from Carbonvert. Lastly, at Harvest Bend, we have several EPA Class VI permit applications in process."

Duncan continued: "Weather-related disruptions in the Gulf of Mexico typically impact our production and drilling operations during the third quarter of the year. This quarter, we experienced production downtime related to sustained loop currents in the Green Canyon area which impacted the floating production unit in our Phoenix Field. However, our oil-weighted assets continued to deliver strong realizations, with a netback margin of close to $45 per barrel of oil equivalent. As that production is restored and new developments are added, we look forward to positive momentum as we close out the year."

RECENT DEVELOPMENTS AND OPERATIONS UPDATE

Drilling Joint Venture: In November 2023, Talos and an affiliate of Repsol entered into a 50/50 partnership to conduct a seismic reprocessing project covering approximately 400,000 gross acres, of which 96,500 acres are under lease by Talos, in the deepwater Green Canyon and Atwater Valley areas of the U.S. Gulf of Mexico. The joint venture aims to identify future subsea tie-back exploitation and exploration prospects in the area using Talos's Neptune facility as the host platform.

Mexico Divestiture: In September 2023, Talos announced the closing of the sale of a 49.9% equity interest in Talos Mexico to an affiliate of Grupo Carso. Talos received $74.85 million in cash at closing, with an additional $49.90 million due upon first production, for an aggregate price of $124.75 million. Talos Mexico, now owned 50.1% by Talos and 49.9% by Grupo Carso, holds a 17.4% unitized interest in the Zama project.

Exploration and Production Updates:

Lime Rock and Venice: Completion, construction, and subsea installation operations for Talos's Lime Rock and Venice discoveries remain on track. The Company anticipates first production by early 2024 from both wells, which will be tied-backed to the Talos-owned and operated Ram Powell facility. Talos owns a 60% working interest in both wells.

Non-Operated Updates: Drilling of the Marmalard well, operated by Murphy Oil Corporation, was recently completed, finding pay sands in both field targets, and will be moving to completion operations in an effort to achieve first production in early 2024. Talos holds an 11.4% working interest. The Odd Job subsea pump project, operated by Kosmos Energy, intended to sustain long-term production from the field, continues to progress and remains on track to be in service by mid-2024. Talos holds a 17.5% working interest.

Downtime Updates: During the third quarter 2023, sustained loop currents requiring intermittent shut-ins of Talos's HP-1 floating production unit and associated infrastructure impacted production by approximately 2.4 MBoe/d for the quarter, or 0.8 MBoe/d for the full year 2023. On Talos's operated Neptune facility, Talos continues to work on optimization efforts, including new chemical treatments and topside modifications, expected to be completed in the fourth quarter 2023. The Claiborne #1 well, operated by Beacon Offshore Energy LLC, was shut-in early in the third quarter 2023, impacting production by approximately 1.2 MBoe/d. The operator is planning a rig intervention for the fourth quarter 2023 to reinstate production in the first quarter of 2024. Talos holds a 25.25% working interest.

TLCS Updates:

Stratigraphic Wells: The Bayou Bend CCS partnership expects to spud the Talos-operated offshore stratigraphic well during the fourth quarter 2023. As previously announced, the partnership also expects to drill a Chevron-operated onshore stratigraphic well in the first half 2024. Talos Low Carbon Solutions ("TLCS") also intends to drill its first stratigraphic wells at its Harvest Bend CCS and Coastal Bend CCS projects in 2024. 

Class VI Permits: TLCS's first EPA Class VI permit application filed in August 2023 for its Harvest Bend CCS project received administrative completeness status in October 2023. This first step of the EPA's permitting process determines that the permit application contains all required information. The next step is technical review. In October 2023, TLCS filed its second Class VI permit application for two additional wells at its Harvest Bend CCS project. TLCS aims to file additional Class VI permit applications in 2024 for its Bayou Bend CCS, Harvest Bend CCS,  and Coastal Bend CCS projects. 

Capital Raise: Talos continues to explore a capital raise in TLCS. The Company will provide further updates when available.

THIRD QUARTER 2023 RESULTS

Key Financial Highlights:

($ thousands, except per share and per BOE amounts)	Three Months Ended September 30, 2023
Total revenues	$	383,135
Net Loss	$	(2,103)
Net Loss per diluted share	$	(0.02)
Adjusted Net Income*	$	18,565
Adjusted Net Income per diluted share*	$	0.15
Adjusted EBITDA*	$	248,817
Adjusted EBITDA excluding hedges*	$	255,130
Upstream Adjusted EBITDA*	$	255,228
Upstream Adjusted EBITDA excluding hedges*	$	261,541
Capital Expenditures (including Plug & Abandonment)	$	194,638
Upstream Adjusted EBITDA Margin:
Upstream Adjusted EBITDA per Boe*	$	43.59
Upstream Adjusted EBITDA excluding hedges per Boe*	$	44.67

 

Production

Production was 63.7 MBoe/d for the third quarter 2023 and was 76% oil and 83% liquids.

	Three Months Ended September 30, 2023
Average net daily production volumes
Oil (MBbl/d)		48.4
Natural Gas (MMcf/d)		65.3
NGL (MBbl/d)		4.4
Total average net daily (MBoe/d)		63.7

 

	Three Months Ended September 30, 2023
	Production			% Oil			% Liquids			% Operated
Average net daily production volumes by Core Area (MBoe/d)
Green Canyon Area		20.8			84	%		90	%		87	%
Mississippi Canyon Area		31.1			80	%		87	%		72	%
Shelf and Gulf Coast		11.8			50	%		60	%		60	%
Total average net daily (MBoe/d)		63.7			76	%		83	%		75	%

 

Lease Operating & General and Administrative Expenses

Total lease operating expenses, inclusive of workover and maintenance and insurance costs for the quarter, were $103.5 million or $17.69/Boe. Upstream General and Administrative expenses* for the quarter, excluding non-cash equity-based compensation, was $20.7 million, or $3.54/Boe. Upstream General and Administrative expenses* is shown inclusive of $1.7 million in transaction-related expenses.

($ thousands, except per BOE amounts)	Three Months Ended September 30, 2023			Per Boe
Lease Operating Expenses	$	103,548		$	17.69
Upstream General & Administrative Expenses (excluding non-cash equity-based compensation)*	$	20,711		$	3.54

 

Capital Expenditures

Upstream capital expenditures, including plugging and abandonment and settled decommissioning obligations, totaled $180.5 million for the third quarter 2023.

($ thousands)	Three Months Ended September 30, 2023			Nine Months Ended September 30, 2023
Upstream Capital Expenditures
U.S. drilling & completions	$	85,239		$	317,900
Mexico appraisal & exploration		94			291
Asset management(1)		20,949			81,677
Seismic and G&G, land, capitalized G&A and other		12,448			48,493
Total Upstream Capital Expenditures		118,730			448,361
Plugging & Abandonment		23,414			71,097
Decommissioning Obligations Settled(2)		38,368			40,415
Total Upstream	$	180,512		$	559,873

(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.

 

CCS expenses totaled $5.0 million for the third quarter 2023, which is accounted for in the Company's reported Adjusted EBITDA* figure. CCS capital expenditures totaled $14.1 million for the third quarter 2023, which mainly includes investments in Bayou Bend and funding for general ongoing operations.

($ thousands)	Three Months Ended September 30, 2023			Nine Months Ended September 30, 2023
CCS Investments
CCS Expenses	$	5,045		$	13,562
CCS Capital Expenditures		14,126			37,183
Total CCS Investments	$	19,171		$	50,745

 

Liquidity and Leverage

At September 30, 2023, Talos had approximately $752.9 million of liquidity, with $750.0 million undrawn on its credit facility and approximately $13.6 million in cash, less approximately $10.8 million in outstanding letters of credit.

On September 30, 2023, Talos had $1,096.0 million in total debt. Net Debt* was $1,082.4 million. Net Debt to Pro Forma Last Twelve Months ("LTM") Adjusted EBITDA* was 1.1x.

Footnotes:

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

OPERATIONAL & FINANCIAL GUIDANCE UPDATES

For the fourth quarter 2023, Talos expects average daily production of 66.5 - 68.5 MBoe/d.

		Fourth Quarter 2023
		Low			High
Production	Oil (MMBbl)		4.5			4.6
	Natural Gas (Mcf)		7.2			7.4
	NGL (MMBbl)		0.4			0.4
	Total Production (MMBoe)		6.1			6.3
	Avg Daily Production (MBoe/d)		66.5			68.5

 

For the full year 2023, Talos's average daily production per day is projected toward the low end of the current guidance of 66.0 - 71.0 MBoe/d given the fourth quarter 2023 production guidance update,

Cash operating expenses and general and administrative expenses are expected towards the low end of the current range of $410 - $430 million and $90 - $95 million, respectively.

Overall, capital expenditures, inclusive of plugging and abandonment, settled decommissioning obligations, and CCS Investments are projected to be in line with the current total guidance range. Specifically, Upstream capital expenditures are expected towards the low end of the current guided range of $650 - $675 million and CCS Investments are projected at or below the low end of the current range of $70 - $90 million. Plugging and abandonment and decommissioning spending for the full year 2023 is now estimated to be $120 - $130 million.

Note: 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 November 6, 2023:

	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)
October - December 2023	Fixed Swaps		12,000		$	75.25		---			---			---
October - December 2023	Collar		7,826		---			---			$	67.76		$	86.40
October - December 2023	3-Way Collar		9,200		---			$	51.86		$	65.11		$	109.25
January - March 2024	Fixed Swaps		18,000		$	73.98		---			---			---
January - March 2024	Collar		3,000		---			---			$	70.00		$	83.67
January - March 2024	3-Way Collar		3,200		---			$	57.27		$	70.00		$	98.01
April - June 2024	Fixed Swaps		21,500		$	73.86		---			---			---
April - June 2024	Collar		1,000		---			---			$	70.00		$	75.00
July - September 2024	Fixed Swaps		13,000		$	75.48		---			---			---
July - September 2024	Collar		1,000		---			---			$	70.00		$	75.00
October - December 2024	Fixed Swaps		12,000		$	74.65		---			---			---
October - December 2024	Collar		1,000		---			---			$	70.00		$	75.00
January - March 2025	Fixed Swaps		10,000		$	71.97		---			---			---
April - June 2025	Fixed Swaps		6,000		$	75.28		---			---			---
July - September 2025	Fixed Swaps		6,000		$	75.28		---			---			---
October - December 2025	Fixed Swaps		6,000		$	75.28		---			---			---
Natural Gas – HH NYMEX		(MMBtu)			(Per MMBtu)			(Per MMBtu)			(Per MMBtu)			(Per MMBtu)
October - December 2023	Fixed Swaps		20,000		$	4.22		---			---			---
October - December 2023	Collar		10,000		---			---			$	5.25		$	8.46
January - March 2024	Fixed Swaps		25,000		$	3.48		---			---			---
January - March 2024	Collar		10,000		---			---			$	4.00		$	6.90
April - June 2024	Fixed Swaps		25,000		$	3.33		---			---			---
April - June 2024	Collar		10,000		---			---			$	4.00		$	6.90
July - September 2024	Fixed Swaps		10,000		$	3.52		---			---			---
July - September 2024	Collar		10,000		---			---			$	4.00		$	6.90
October - December 2024	Fixed Swaps		10,000		$	3.52		---			---			---
October - December 2024	Collar		10,000		---			---			$	4.00		$	6.90
January - March 2025	Fixed Swaps		20,000		$	4.14		---			---			---
April - June 2025	Fixed Swaps		10,000		$	3.91		---			---			---
July - September 2025	Fixed Swaps		10,000		$	3.91		---			---			---
October - December 2025	Fixed Swaps		10,000		$	3.91		---			---			---

 

CONFERENCE CALL AND WEBCAST INFORMATION 

Talos will host a conference call, which will be broadcast live over the internet, on Tuesday, November 7, 2023 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 (888) 348-8927 (U.S. toll-free), (855) 669-9657 (Canada toll-free) or (412) 902-4263 (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 November 14, 2023 and can be accessed by dialing (877) 344-7529 and using access code 4883529.

ABOUT TALOS ENERGY

Talos Energy (NYSE: TALO) is a technically driven, innovative, independent energy company focused on safely and efficiently maximizing long-term value through its Upstream Exploration & Production and Low Carbon Solutions businesses. We currently operate in the United States ("U.S.") and offshore Mexico. We leverage decades of technical and offshore operational expertise to acquire, explore, and produce assets in key geological trends while developing opportunities to reduce industrial emissions through carbon capture and storage projects along the U.S. Gulf Coast. For more information, visit www.talosenergy.com.

INVESTOR RELATIONS CONTACT
investor@talosenergy.com

CAUTIONARY STATEMENT ABOUT FORWARD-LOOKING STATEMENTS

The information in this communication includes "forward-looking statements" within the meaning of the Securities Act of 1933, as amended (the "Securities Act"), and 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. Forward-looking statements may include statements about: business strategy; reserves and prospective storage resources; drilling prospects, inventories, projects and programs; our ability to replace the reserves 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; timing and amount of future production of oil, natural gas and NGLs; our hedging strategy and results; future drilling and CCS plans; availability of pipeline connections on economic terms; competition, government regulations and legislative and political developments; the timing of, and our ability to obtain, permits and governmental approvals; pending legal, governmental or environmental matters; our marketing of our products; our integration of acquisitions, including EnVen, and future 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, including embargoes, hostilities and acts of terrorism or sabotage; credit markets; estimates of future income taxes; our estimates and forecasts of the timing, number, profitability and other results of wells we expect to drill and other exploration activities; the success of our CCS opportunities, including as a result of the associated permitting process, our access to capital to finance such opportunities, the timing and amount of revenues therefrom and potential future customers; the uncertainty inherent in estimating subsurface storage resources and utilization capacity in our CCS projects; 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. Examples of such 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 the Middle East, and their impact on certain commodity markets; lack of transportation and storage capacity as a result of oversupply, government and regulations; lack of availability of drilling and production equipment and services; adverse weather events, including tropical storms, hurricanes, winter storms and loop currents; cybersecurity threats; sustained inflation and the impact of governmental 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; risks associated with permitting for—and access to capital to finance—our CCS opportunities; technological innovations and scientific developments; physical and transition risks associated with climate change; increased attention to ESG and sustainability-related matters; risks that the Company may face regarding potentially conflicting anti-ESG initiatives from certain U.S. state or other governments; and the other risks discussed in Part I, Item 1A. "Risk Factors"  of Talos Energy Inc.'s Annual Report on Form 10-K for the year ended December 31, 2022 and in Part II, Item 1A. "Risk Factors" of Talos Energy Inc.'s Quarterly Report on Form 10-Q for the period ended March 31, 2023 , each as filed with the SEC.

Reserve engineering is a process of estimating underground accumulations of oil, natural gas and NGLs that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify upward or downward revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil, natural gas and NGLs that are ultimately recovered.

Should 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.

 

Talos Energy Inc. Consolidated Balance Sheets (In thousands, except share amounts)
	September 30, 2023			December 31, 2022
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	13,631		$	44,145
Accounts receivable:
Trade, net		181,384			150,598
Joint interest, net		93,798			54,697
Other, net		10,744			6,684
Assets from price risk management activities		11,497			25,029
Prepaid assets		86,077			84,759
Other current assets		14,457			1,917
Total current assets		411,588			367,829
Property and equipment:
Proved properties		7,691,828			5,964,340
Unproved properties, not subject to amortization		267,297			154,783
Other property and equipment		33,795			30,691
Total property and equipment		7,992,920			6,149,814
Accumulated depreciation, depletion and amortization		(3,985,613)			(3,506,539)
Total property and equipment, net		4,007,307			2,643,275
Other long-term assets:
Restricted cash		101,760			—
Assets from price risk management activities		4,550			7,854
Equity method investments		141,682			1,745
Other well equipment inventory		44,643			25,541
Notes receivable, net		15,805			—
Operating lease assets		12,313			5,903
Other assets		13,452			6,479
Total assets	$	4,753,100		$	3,058,626
LIABILITIES AND STOCKHOLDERSʼ EQUITY
Current liabilities:
Accounts payable	$	125,557		$	128,174
Accrued liabilities		205,095			219,769
Accrued royalties		54,092			52,215
Current portion of long-term debt		33,109			—
Current portion of asset retirement obligations		69,288			39,888
Liabilities from price risk management activities		55,042			68,370
Accrued interest payable		30,536			36,340
Current portion of operating lease liabilities		2,859			1,943
Other current liabilities		54,221			60,359
Total current liabilities		629,799			607,058
Long-term liabilities:
Long-term debt		1,018,774			585,340
Asset retirement obligations		747,560			501,773
Liabilities from price risk management activities		8,981			7,872
Operating lease liabilities		18,888			14,855
Other long-term liabilities		267,036			176,152
Total liabilities		2,691,038			1,893,050
Commitments and contingencies
Stockholdersʼ equity:
Preferred stock; $0.01 par value; 30,000,000 shares authorized and zero shares issued or outstanding as of September 30, 2023 and December 31, 2022		—			—
Common stock; $0.01 par value; 270,000,000 shares authorized; 127,480,361 and 82,570,328 shares issued as of September 30, 2023 and December 31, 2022, respectively		1,275			826
Additional paid-in capital		2,541,906			1,699,799
Accumulated deficit		(433,615)			(535,049)
Treasury stock, at cost; 3,400,000 and zero shares as of September 30, 2023 and December 31, 2022, respectively		(47,504)			—
Total stockholdersʼ equity		2,062,062			1,165,576
Total liabilities and stockholdersʼ equity	$	4,753,100		$	3,058,626

 

Talos Energy Inc. Consolidated Statements of Operations (In thousands, except per share amounts) (Unaudited)
	Three Months Ended September 30,						Nine Months Ended September 30,
	2023			2022			2023			2022
Revenues:
Oil	$	359,404		$	295,585		$	995,081		$	1,078,800
Natural gas		16,871			68,360			53,383			181,747
NGL		6,860			13,183			24,463			49,232
Total revenues		383,135			377,128			1,072,927			1,309,779
Operating expenses:
Lease operating expense		103,548			81,760			286,075			229,156
Production taxes		600			955			1,813			2,670
Depreciation, depletion and amortization		163,359			92,323			480,476			295,174
Accretion expense		21,256			13,179			63,430			42,400
General and administrative expense		24,888			25,289			121,257			70,742
Other operating (income) expense		(57,287)			(366)			(55,172)			12,142
Total operating expenses		256,364			213,140			897,879			652,284
Operating income (expense)		126,771			163,988			175,048			657,495
Interest expense		(45,637)			(29,265)			(128,850)			(91,531)
Price risk management activities income (expense)		(98,802)			114,180			(13,668)			(231,133)
Equity method investment income (expense)		(2,493)			991			2,938			14,599
Other income (expense)		2,193			692			10,450			31,991
Net income (loss) before income taxes		(17,968)			250,586			45,918			381,421
Income tax benefit (expense)		15,865			(121)			55,516			(2,256)
Net income (loss)	$	(2,103)		$	250,465		$	101,434		$	379,165
Net income (loss) per common share:
Basic	$	(0.02)		$	3.03		$	0.86		$	4.60
Diluted	$	(0.02)		$	2.99		$	0.85		$	4.54
Weighted average common shares outstanding:
Basic		124,103			82,576			118,459			82,406
Diluted		124,103			83,818			119,262			83,438

 

Talos Energy Inc. Consolidated Statements of Cash Flows (In thousands) (Unaudited)
	Nine Months Ended September 30,
	2023			2022
Cash flows from operating activities:
Net income (loss)	$	101,434		$	379,165
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion expense		543,906			337,574
Amortization of deferred financing costs and original issue discount		11,247			10,614
Equity-based compensation expense		9,080			11,677
Price risk management activities (income) expense		13,668			231,133
Net cash received (paid) on settled derivative instruments		(10,474)			(368,483)
Equity method investment (income) expense		(2,938)			(14,599)
Settlement of asset retirement obligations		(71,097)			(60,304)
(Gain) loss on sale of assets		(66,115)			390
Changes in operating assets and liabilities:
Accounts receivable		3,821			23,783
Other current assets		(12,992)			(28,576)
Accounts payable		(30,063)			16,677
Other current liabilities		(89,511)			(6,682)
Other non-current assets and liabilities, net		(57,155)			6,559
Net cash provided by (used in) operating activities		342,811			538,928
Cash flows from investing activities:
Exploration, development and other capital expenditures		(438,506)			(209,592)
Proceeds from (cash paid for) acquisitions, net of cash acquired		17,617			(3,500)
Proceeds from (cash paid for) sale of property and equipment, net		66,183			1,690
Contributions to equity method investees		(29,372)			(2,250)
Proceeds from sale of equity method investments		—			15,000
Investment in intangible assets		(7,796)			—
Net cash provided by (used in) investing activities		(391,874)			(198,652)
Cash flows from financing activities:
Redemption of senior notes		(15,000)			(6,060)
Proceeds from Bank Credit Facility		675,000			35,000
Repayment of Bank Credit Facility		(460,000)			(350,000)
Deferred financing costs		(11,775)			(211)
Other deferred payments		(841)			—
Payments of finance lease		(12,117)			(19,764)
Purchase of treasury stock		(47,504)			—
Employee stock awards tax withholdings		(7,454)			(4,603)
Net cash provided by (used in) financing activities		120,309			(345,638)
Net increase (decrease) in cash, cash equivalents and restricted cash		71,246			(5,362)
Cash, cash equivalents and restricted cash:
Balance, beginning of period		44,145			69,852
Balance, end of period	$	115,391		$	64,490
Supplemental non-cash transactions:
Capital expenditures included in accounts payable and accrued liabilities	$	90,688		$	78,191
Supplemental cash flow information:
Interest paid, net of amounts capitalized	$	108,931		$	89,187

 

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.

Reconciliation of General and Administrative Expenses to Upstream General and Administrative Expenses

We believe the presentation of Upstream General and Administrative Expenses excluding non-cash equity-based compensation provides management and investors with (i) important supplemental indicators of the operational performance of our core upstream 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. Upstream General & Administrative Expenses 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 general and administrative expenses, 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 consists 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.

Upstream General and Administrative Expenses. Upstream general and administrative expenses consist of general and administrative expenses for the Upstream Segment.

($ thousands)	Three Months Ended September 30, 2023
Reconciliation of General & Administrative Expenses to Upstream General & Administrative Expenses (excluding non-cash equity-based compensation):
Total General and administrative expense	$	24,888
CCS Segment		(2,472)
Unallocated corporate		(1,362)
Non-cash equity-based compensation expense		(343)
Upstream General & Administrative Expenses (excluding non-cash equity-based compensation)	$	20,711

 

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

"EBITDA," "Adjusted EBITDA" and "Upstream Adjusted EBITDA" 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 Upstream 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 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 inventory 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.

Upstream Adjusted EBITDA. 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 and unallocated corporate costs.

We also present Adjusted EBITDA excluding hedges and Upstream Adjusted EBITDA excluding hedges as a percentage of revenue and on a per barrel of oil equivalent basis, respectively, to further analyze our business, which are outlined below:

Adjusted EBITDA Margin and Upstream Adjusted EBITDA Margin. Adjusted EBITDA divided by Revenue, as a percentage. It is also defined as Upstream Adjusted EBITDA divided by the total production volume, expressed in Boe, in the period, and described as dollar per Boe. We believe the presentation of Adjusted EBITDA margin is important to provide management and investors with information about how much we retain in Adjusted EBITDA terms as compared to the revenue we generate and how much per barrel of Upstream Adjusted EBITDA we generate after accounting for certain operational and corporate costs.

The following tables present a reconciliation of the GAAP financial measure of Net Income (loss) to EBITDA, Adjusted EBITDA, Adjusted EBITDA excluding hedges, Adjusted EBITDA Margin and Adjusted EBITDA Margin excluding hedges, and Upstream Adjusted EBITDA, Upstream Adjusted EBITDA excluding hedges, Upstream Adjusted EBITDA Margin, and Upstream Adjusted EBITDA Margin excluding hedges for each of the periods indicated (in thousands, except for Boe, $/Boe and percentage data):

	Three Months Ended
($ thousands)	September 30, 2023			June 30, 2023			March 31, 2023			December 31, 2022
Reconciliation of Net Income (Loss) to Adjusted EBITDA:
Net Income (loss)	$	(2,103)		$	13,677		$	89,860		$	2,750
Interest expense		45,637			45,632			37,581			33,967
Income tax expense (benefit)		(15,865)			6,892			(46,543)			281
Depreciation, depletion and amortization		163,359			169,794			147,323			119,456
Accretion expense		21,256			22,760			19,414			13,595
EBITDA		212,284			258,755			247,635			170,049
Transaction and other (income) expenses(1)		(64,321)			3,513			22,009			4,343
Decommissioning obligations(2)		7,972			741			741			21,005
Derivative fair value (gain) loss(3)		98,802			(26,197)			(58,937)			41,058
Net cash received (paid) on settled derivative instruments(3)		(6,313)			8,162			(12,323)			(57,076)
Loss on extinguishment of debt		—			—			—			1,569
Non-cash equity-based compensation expense		393			4,749			3,938			4,276
Adjusted EBITDA		248,817			249,723			203,063			185,224
Add: Net cash (received) paid on settled derivative instruments(3)		6,313			(8,162)			12,323			57,076
Adjusted EBITDA excluding hedges	$	255,130		$	241,561		$	215,386		$	242,300
Revenue:
Revenue - Operations		383,135			367,210			322,582			342,201
Adjusted EBITDA margin and Adjusted EBITDA excl hedges margin:
Adjusted EBITDA divided by - Total revenue incl hedges (%)		66	%		67	%		65	%		65	%
Adjusted EBITDA divided by - Total revenue (%)		67	%		66	%		67	%		71	%

(1)	For the three months ended September 30, 2023, transaction expenses include $1.5 million in costs related to the EnVen Acquisition, inclusive of $0.9 million in severance expense. For the three months ended June 30, 2023, transaction expenses include $2.7 million in costs related to the EnVen Acquisition, inclusive of $1.4 million in severance expense. For the three months ended March 31, 2023, transaction expenses include $35.2 million in costs related to the EnVen Acquisition, inclusive of $22.6 million in severance expense. Transaction expenses are included in "General and administrative expense" on our consolidated statements of operations. 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 September 30, 2023, it includes a $66.2 million gain on the Mexico divestiture. For the three months ended March 31, 2023, it includes a $8.6 million gain on the funding of the capital carry of its investment in Bayou Bend by Chevron that is included in "Equity method investment income (expense)" on our consolidated statements of operations.
(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 September 30, 2023
Reconciliation of Adjusted EBITDA to Upstream Adjusted EBITDA:
Adjusted EBITDA	$	248,817
CCS and Corporate Unallocated Costs:
Equity method investment loss		2,611
General and administrative expense		3,835
Other operating expense		127
Other income		(5)
Transaction and other income (expenses)(1)		(106)
Non-cash equity-based compensation expense		(51)
Upstream Adjusted EBITDA		255,228
Add: Net cash paid on settled derivative instruments(2)		6,313
Upstream Adjusted EBITDA excluding hedges	$	261,541
Production:
Boe(3)		5,855
Upstream Adjusted EBITDA margin and Upstream Adjusted EBITDA excl hedges margin:
Upstream Adjusted EBITDA per Boe(3)	$	43.59
Upstream Adjusted EBITDA excl hedges per Boe(2)(3)	$	44.67

(1)	Transaction and other income (expense) includes other miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance.
(2)	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.
(3)	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 and Reconciliation of Net Cash Provided by Operating Activities to Adjusted Free Cash Flow

"Adjusted Free Cash Flow" 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 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 September 30, 2023
Reconciliation of Adjusted EBITDA to Adjusted Free Cash Flow (before changes in working capital):
Adjusted EBITDA	$	248,817
Upstream capital expenditures		(118,730)
Plugging & abandonment		(23,414)
Decommissioning obligations settled		(38,368)
CCS capital expenditures		(14,126)
Interest expense		(45,637)
Adjusted Free Cash Flow (before changes in working capital)	$	8,542
($ thousands)	Three Months Ended September 30, 2023
Reconciliation of Net Cash Provided by Operating Activities to Adjusted Free Cash Flow (before changes in working capital):
Net cash provided by operating activities(1)	$	65,728
(Increase) decrease in operating assets and liabilities		126,248
Upstream capital expenditures(2)		(118,730)
Decommissioning obligations settled		(38,368)
CCS capital expenditures		(14,126)
Transaction and other (income) expenses(3)		1,859
Decommissioning obligations(4)		7,972
Amortization of deferred financing costs and original issue discount		(3,618)
Income tax benefit		(15,865)
Other adjustments		(2,558)
Adjusted Free Cash Flow (before changes in working capital)	$	8,542

(1)	Includes settlement of asset retirement obligations.
(2)	Includes accruals and excludes acquisitions.
(3)	The transaction expenses include $1.5 million in costs related to the EnVen Acquisition, inclusive of $0.9 million in severance expense. Other income (expenses) includes miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance.
(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

"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 September 30, 2023
($ thousands, except per share amounts)				Basic per Share			Diluted per Share
Reconciliation of Net Loss to Adjusted Net Income:
Net Loss	$	(2,103)		$	(0.02)		$	(0.02)
Transaction and other (income) expenses(1)		(64,321)		$	(0.52)		$	(0.51)
Decommissioning obligations(2)		7,972		$	0.06		$	0.06
Derivative fair value loss(3)		98,802		$	0.80		$	0.79
Net cash received on paid derivative instruments(3)		(6,313)		$	(0.05)		$	(0.05)
Non-cash income tax benefit		(15,865)		$	(0.13)		$	(0.13)
Non-cash equity-based compensation expense		393		$	0.00		$	0.00
Adjusted Net Income(4)	$	18,565		$	0.15		$	0.15
Weighted average common shares outstanding at September 30, 2023:
Basic		124,103
Diluted		124,964

(1)	The transaction expenses include $1.5 million in costs related to the EnVen Acquisition, inclusive of $0.9 million in severance expense. Other income (expenses) includes miscellaneous income and expenses that we do not view as a meaningful indicator of our operating performance. It includes a $66.2 million gain on the Mexico divestiture.
(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, and Net Debt to 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)	September 30, 2023
Reconciliation of Net Debt:
12.00% Second-Priority Senior Secured Notes – due January 2026	$	638,541
11.75% Senior Secured Second Lien Notes – due April 2026		242,500
Bank Credit Facility – matures March 2027		215,000
Total Debt		1,096,041
Less: Cash and cash equivalents		(13,631)
Net Debt	$	1,082,410
Calculation of LTM Adjusted EBITDA:
Adjusted EBITDA for three months period ended December 30, 2022	$	185,224
Adjusted EBITDA for three months period ended March 31, 2022		203,063
Adjusted EBITDA for three months period ended June 30, 2023		249,723
Adjusted EBITDA for three months period ended September 30, 2023		248,817
LTM Adjusted EBITDA	$	886,827
Acquired Assets Adjusted EBITDA:
Adjusted EBITDA for three months period ended December 31, 2022		73,891
Adjusted EBITDA for the period January 1, 2023 to February 13, 2023		33,120
LTM Adjusted EBITDA from Acquired Assets	$	107,011
Pro Forma LTM Adjusted EBITDA	$	993,838
Reconciliation of Net Debt to Pro Forma LTM Adjusted EBITDA:
Net Debt / Pro Forma LTM Adjusted EBITDA(1)	1.1x

(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 1.2x.

 

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SOURCE Talos Energy

FAQ

What are the highlights of Talos Energy's Q3 2023 results?

The highlights include production of 63.7 MBoe/d, revenue of $383.1 million, net loss of $2.1 million, adjusted net income of $18.6 million, adjusted EBITDA of $248.8 million, and capital expenditures of $194.6 million.

What were the realized prices for Talos Energy's products?

The realized prices were $80.75 per barrel for oil, $17.02 per barrel for natural gas liquids (NGLs), and $2.81 per Mcf for natural gas.

What progress has Talos Energy made on its Lime Rock and Venice discoveries?

Talos Energy's operations team is working on the Lime Rock and Venice discoveries, which are expected to come online in early 2024.

Has Talos Energy signed any exploration agreements?

Yes, Talos Energy has signed an exploration agreement with Repsol, pooling resources to develop an inventory of impactful wells tied to existing Talos infrastructure.

Has the Talos Mexico transaction with Grupo Carso been closed?

Yes, the Talos Mexico transaction with Grupo Carso has been closed.